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SUBSTANTIATION STUDY Tarnița–Lăpuștești Pumped-Storage Hydropower Plant

Bucharest,2019

National Commission for Strategy and Prognosis

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Table of Contents

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1. General information on the investment objective 4 1.1 Designation of the investment objective 4 1.2 Project site 4 1.3 Investment beneficiary 4 1.4 Substantiation study elaborator 4 1.5 Investment duration 4 1.6 Recitals 4 1.7 State of the electricity sector in Romania 5 1.8 Opportunity and need to implement theTarnița-Lăpuștești PSHPproject 9 2.State of pumped-storage hydropower plants withinworld energy 12 2.1 Presentation of the PSHP sector 12 2.2 SWOT analysis of apumped-storage hydropower plant 17 2.3 Economy of storing electricity in PSHPs 17 2.4 PSHP role in the provision of system services 18 3. Electricity market 21 3.1 Electricity trading platforms in Europe 21 3.1.1 The Scandinavian electricity market 21 3.1.2 The French electricity market 21 3.1.3 The German electricity market 22 3.2 The Romanian electricity market 23 3.2.1 Market organization and electricity price formation 23 3.2.2.Centralized market of technological system services 26 3.2.3 Technological system services 28 3.3 Electricity consumption forecast 30 3.4 Provision of system services 33 3.5 Tarnița-Lăpuștești PSHP sustainability 35 4. Main technical, financial and contractual characteristics of the project 37 4.1 Tarnița-Lăpuștești PSHP project history 37 4.2 Conclusions of the studies concerningTarnița-Lăpuștești PSHP 38 4.3 Project descriptionwithin the context of Someș river hydropower setup 42 4.4 Technical, legal data, supporting studies, workloads 49 5. Investment assessment 83 5.1. Identifying the investment and defining the objectives 83 5.2. General estimate 83 5.3Cost-investments comparison in PSHP projects worldwide 84 5.4. Option analysis 84 5.5. Working assumptions 87

6.Studies and analyses on the project implementation method, updated version, 2018 data

91

6.1 Differences between PPPsand traditional public procurements 91 6.1.1 Current context 91 6.1.2 Traditional public procurement method 92 6.1.3 Public-Private Partnership 94 6.2 Project economic efficiency presented via a cost-benefit analysis 96 6.2.1 General approach 96 6.2.2 Analysis time frame (reference period) 97 6.2.3 Basic assumptions 97

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6.2.4 Quantification of economic benefits 99 6.2.5 Analysis ofnon-monetized induced socio-economic benefits 100 6.2.6 Calculation of the project economic performance indicators 101 6.3 “Value for money” analysis in both cases 102 6.3.1 Introduction 102 6.3.2 Financial model 104 6.3.3 Financial analysis results of the PPP Scenario 106 6.3.4 Financial analysis results of the 100% Government Financing Scenario 108 6.3.5 Sensitivity analysis 110 6.4 Option recommended by the study elaborator and its advantages 112 6.5 Risk distribution structure for each option, quantification of risks and allotment alternatives among the contracting parties, risk management function

115

6.5.1 Identification and quantification of risks 115 6.5.2 Risk allocation between the Public Partner and the Private Partner 119 6.6 Project generic possibility of mobilizing the financial resources required to cover costs (project sustainability degree)

123

6.7 Pricing and charging system 126 6.8 Main contractual stages 127 6.9 Main activities carried out during each contractual stage/period 127 6.10 Project income presentation 130 6.11 Penalty system 131 6.12 PPP contract termination and termination payments 132

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1. General information on the investment objective 1.1. Designation of the investment objective

“Tarnița-Lapuștești Pumped-Storage Hydropower Plant (PSHP”. 1.2. Site

The investment objective is located in Cluj county, around 30 km upstream from Cluj-Napoca municipality, along Someșul Cald river valley, within the left slope of the existing Tarniţa reservoir. 1.3. Investment holder:Ministry of Energy 1.4. Investment beneficiary: Ministry of Energy 1.4. Substantiation study elaborator:CNSP (National Commission for Strategy and Prognosis) 1.5. Investment duration: 60months 1.6. Recitals

Energy is an area of strategic importance in the sense that providing it at reasonable prices influences a country’s economic competitiveness, internal production capacity and political force. Energy supply security impacts upon a nation’s well-being, whereas changes in energy pricing impact upon the distribution of well-being at a national level. And, last but not least, another aspect depending on a sound energy supply is a country’s defense capability. Romania 2018-2030 Energy Strategy stipulates: “The vision of Romania’s Energy Strategy is to produce growth across the energy sector against o background of sustainability. The energy sector development is a step within Romania’s development process. The strategy underlines the urgent need to implement theTarnița-Lăpuștești PSHP project By building the two nuclear power units and maintaining an upward trend of production capacities from intermittent renewable sources, the construction of a high-capacity pumped-storage hydropower plant is mandatory for the power system stability. (National Energy Strategy 2018-2030) Drawing up the presentSubstantiation Studytook into account the following conditionalities and financial advantages provided by the Public Private Partnership law: - estimated investment value – 1 billion Euro (estimate); - one-stage investment; - PPP contract period – 30 years, 5 of which covering financial closure, design and execution; - annual availability-based payment – 50 million Euro; - discount for bringing the execution deadline forward – 100 million Euro/year.

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1.7. State of the electricity sector in Romania

Romania meets the first energy securityrequirement,possessing energy resources that secure an energy mix with an installed capacity of approx. 24,700 MW(Transelectrica-2018). The cautious utilization of these resourcesprovide the security and stability of the Romanian Power System (RPS),as well as a way to overcome critical phases.

Distributed among state-owned enterprisesand private companies, the installed capacitywithin SEN appears as follows: • SC HidroelectricaSA company has an installed capacity of 6444MW;when the hydraulicity level is favorable,it can reach a production peak of 3,500-4000 MW. This ideal case can occur a few hours over the course of one year comprising 8760 hours. In reality,Hidroelectrica may rely on an average value of 2,000 MW, covering 25-30% of the annual electricity production, also providing 80-85% system services • Complexul Energetic Oltenia, the second largest producer in Romania, with an installed capacity of 3240 MW, may reach a production peak, under ideal conditions, of 3000 MW, but only over the course of a few days,circumstances rendered not by a possible coal shortage, but effectively by the technical conditions.CE Oltenia estimatean average and consistent operating capacity falling within the 1650-1700 MW range. • SC Nuclearelectrica SAcompany, with an installed capacity of 1400 MW divided into two nuclear power units700MWeach, is the producer with the highest operating consistency, under nominal operating conditions.Notwithstanding downtime periods of one reactor or the other for specific servicing, or any incident cases, Cernavodă nuclear power plant handles the band supply of the amount of energy it has been designed for, without being influenced by external or technical factors, as is the case of hydropower, coal-based energy or in the sector of intermittent renewable energies. The nuclear energy production capacities account for an additional safety net in securing the internal energy consumption. By having Cernavodă units 3 and 4 commissioned, SN Nuclearelectrica SA’s internal market share may reach around 35%, which would cause a decrease in the consumption of hydrocarbons in the energy sector and regulate any electricity deficitsunder nominal operating conditions. • The producers relying on renewable wind and solar power, biomass and micro hydroelectric power plants have reached acapacity of 5,000 MW, split among wind farms with a capacity of 3,000 de MW, photovoltaic panels with a total capacity of 1300 MW, micro hydroelectric power plants with around 400 MW and biomass-powered plants with a cumulated capacity of 120 MW (ANRE 2017 Report). There are days when the intermittent wind and solar power exceeds 2,000 MW as generated, while there are also days when no more than a few tenths of MW are produced. In percentages, renewable energy accounts every year for around 10-15 % of total electricity produced in Romania. • The two power plants belonging to the two natural gas producers, Romgaz and Petrom, namely the Iernut and Brazi power plants, also contribute with around 400 MW and 800 MW, respectively, to theinstalled capacityof the energy system.To these one may add the production capacities of ELCEN and the few, still operationalcombined heat and power plants, which contribute with around 3,000 MW.

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2018 installed capacity Installed capacity (MW) Available capacity (MW) Total 24,738 22,256 Hydroelectric power plants 6731 6368 Nuclear power plants 1413 1413 Thermoelectric plants 12,059 10256 Wind power plants 3030 2944 Photovoltaic power stations 1375 1176 Biomass-powered plants 130 99 (Source: Transelectrica-2018)

The transmission system operator (TSO) and the distribution operators provide the transportation, the distribution, as well as the priority dispatch of electricity produced from renewable sources, for all producers of energy from renewable sources, regardless of their capacity, based on transparent and non-discriminating criteria, with the possibility to change notifications during the business day, according to the methodology approved by ANRE.

In 2017, Romania’s electricity production decreased by approximately 4% as opposed to the 2016 level, which determined an increase of electricity imports and a decrease of energy exports.In 2017,Romania produced 63,64TWh, 2.5 TWhless than in 2016, as indicated by the National Institute of Statistics data. The decrease was caused by the lower production levels of hydroelectric power plants, which generated in 2017 14.7 TWh, nearly 5 TWhless than the 2016 figure.On the other hand, the production of thermoelectric plants was 5.7% higher, reaching 28 TWh.The wind power production increased by 10.2%, up to 7.4 TWh, whereas solar power stations generated 1.9 TWh, a 2% increase as opposed to 2016.

The final electricity consumption in 2017 was 54.6 TWh, 0.219 TWhbelow that of the previous year. In 2017, importsincreased by 2.4%, up to 3.6 TWh, whereas exports were 23.7% lower, amounting to 6.5 TWh,all of which indicated a positive balance.

In comparison with 2016, the wind power production in 2017 increased by 0.8 TWh, while being 0.3 TWh higher in comparison with 2015. The most visible difference appears between the production values obtained in 2017 and 2010, respectively, the solar power production only reaching 0.3 TWh during the latter year.

The capacity of the Romanian network to take over wind power is only 3,038 MW, the 13th overall in Europe. In terms of photovoltaic solar energy production, Romania’s production in 2017 was 1.9 TWh, making it the 8th overall in Europe.

The TSO (transmission system operator), Transelectrica SA, coordinates the power flows within RPS by controlling the dispatchable production units. Although dispatching entails additional costs for producers, it allows balancing RPS under extreme circumstancesout of the total available gross capacity of around 24,500 MW, 3,000 MW are non-dispatchable. Romania’s average consumption oscillates daily between 6,000 and 8,500 MWh, with 9,000 MWh peaks during searing summer days and the record level of 10,000 MWh during the winter freezing days; the 2017 mean value was around 7300MWh.

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Fig.1.1. Electricity transmission grid

Historically speaking,RPSenjoyed an accelerated development during the 1950-1989 period, when it also became interconnected with the neighboring energy systems. After 1990, the effort to secure operation at high safety and quality standards allowed the RPS integrationinto UCPTE - theEuropean Union’s energy system. This step provided support for policies designed to integrate Balkan electricity markets within theEuropean single market and the access of domestic energy producers and suppliers to the European market. With the energy market liberalization and the integration of renewable intermittent, wind and solar power sources, the role of the network and the quality of electricity have become more important, creating market opportunities for electricity storage systems.

The technical evolution of the energy sector in Romania might encounter medium- and long-term difficulties due to the fact that the electricity market is affected by shortages in terms of infrastructure, lacking electricity storage capacities, unlike the natural gas market, which benefits from such capacities.

According to the fundamental objectives of the Energy Strategy, the energy sector development is directlyproportionate to the implementation of strategic investment projects of national interest. In Romania’s Energy Strategy 2018-2030, the following objectives are considered strategic investments of national interest: 1. The completion of Units 3 and 4 of Cernavodă NPP (nuclear power plant); 2. The construction of Tarnița-Lăpuștești Pumped-Storage Hydropower Plant; 3. The construction of the 600 MW Unit at Rovinari; 4. The construction of Turnu-Măgurele-Nicopole Hydrotechnical Complex.

The fulfillment of strategic objectives entails a thorough knowledge of energy sector reality, supported by a proper understanding of the international context and the technological, economic and geopolitical trends. Romania’s Energy Strategy 2018-2030 also provides: “Ch.III.3.The construction of Tarnița-Lăpuștești Pumped-Storage Hydropower Plant”.Given the fact that, by the year 2030, the technological mix within Romania’s electricity production system will see an increased share of the nuclear energy and renewable

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source energy sector, there is a need for capacities that are able to ensure flexibility for the energy system.

For 2030, there are prospects on the development of additional energy storage technologies, as well, such as batteries, which do not currently enjoy sufficient technological maturity to be implemented. Consequently, it is mandatory to build storage capacities with a power of 1,000 MW, in Tarnița-Lăpuștești PSHP, able to step in in order to balance the system over 4 to 6-hour intervals.”

The literature considers electricity storage “the 6th dimension” of an energy system, next to: (1)energy sources,(2)production,(3)transmission, (4)distribution and(5)consumption.

Depending on the design and characteristics, the storage of electricity secures the supply at times of high demand (for example, due to seasonal variations) and contributes to the operation of the electricity market, ensuring short-term flexibility. The internal electricity market requires electricity storage in order to advance,a fantastic indicator in that respect being the evolution of the natural gas market, where storage holds a fundamental role,ensuring the flexibility of market services and natural gas price stability.

The role of a PSHP on the electricity market entails purchasing electricity at low prices when demand for electricity is low and, therefore, prices are low (generally, at night and in weekends), storing this electricity until a relevant time and selling it when demand for electricity and prices are high, during load peak periods.

The permanent balancing of variable demand with generation continuity requires the presence and maintenance, at specific costs,of reserve capacities within the system, intended to permanently cover demand, whereas the rapid reserves are also ensured by the existence of a pumped-storage hydropower plant. Fig.1.2.Forecast of electricity production by resource

(Source – Energy Strategy 2018-2050)

EVOLUTION OF ELECTRICITY PRODUCTION BY PRIMARY ENERGY SOURCE

Nuclear Renewable Coal

Hydrocarbons

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1.8. Opportunity and need to implement the Tarnița-Lăpuștești PSHP project

The development of energy storage capacities has a key role in allowing EU countries to produce electricity from intermittent renewable sources.The storage of electricity provides a high degree of flexibility of and balance for the network, as well as back-up for the integration of intermittent renewable energies within RPS.

Fig.1.3.Reversible operation of turbine/pump hydroaggregates

As far as the domestic situation is concerned, one may improve the management of

transmission and distribution networks,reduce costs and enhance efficiency. These are means to facilitate the introduction on the market of renewable energy sources, accelerate the electricity network decarburization, improve electricity transmission and distribution security and efficiency (with decreases in unscheduled loop flows, network congestions, voltage and frequency variations), stabilize the market via electricity pricing, while also guaranteeing a greater electricity supply security.

Romania’s Energy Strategy mentions that “For 2030, there are prospects on the development of additional energy storage technologies, as well, which do not currently enjoy sufficient technological maturity to be implemented.

Consequently, it is mandatory to build storage capacities with a power of 1,000 MW, in Tarnița-Lăpuștești PSHP, able to step in in order to balance the system over 4 to 6-hour intervals.”

The layout studies and the drawing-based studiesfor the construction of a pumped-storage hydropower plantin Romania have been carried out as of the ‘70s; at the time, the aspects considered were the need to cover the load peak, the continuous increase of energy demand and the commissioning of Cernavodă NPP units 1-5, which were not able to optimally cover the consumption requirements during the entire 24-hour running time, the nighttime consumption being, thus, lower by around 2500-3000 MW, on average.

Turbinees Turbinees

Pumps Pumps

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Fig.1.4.Manner in which a PSHP optimizes the operation of nuclear power plants (source: EDF)

The only viable, highly effective solution is to build in Romania a high water drop pumped-storage hydropower plant, which pumps water from a lower reservoir into an upper reservoir during low load periods (at night and in weekends), consuming via pumping any excess electricity and generating electricity during high and peak load periods,a plant which is available to RPS and replaces, in relation to this system service, gas-powered power plants,costly in terms of the fuel used, and hydropower plants, which produce current at nominal rates.

The opportunity and necessity to implement the project of Tarnița-Lăpuștești Pumped-Storage Hydropower Plant (PSHP) rely on the following advantages and functions, secured for the national power system by apumped-storage hydropower plant:

• increasing the safety level of RPS in the context of its operation as part of UCTE • electricitytransfer from low load to peak load; • electricity market arbitration • short-term failure reserve; • secondary reserve and tertiary reserve • the frequency-power adjustment and the spinning reserve; • reactive power reserve provision and RPS voltage regulation; • interconnection-based exchange within UCTE; • RPS restart - black start capability - thecapacity to restore network interconnections in

case of a power outage • Implementation and management within RPS of intermittent renewable electricity

sources while ensuring optimum conditions for installing a capacity in excess of4000 MW in wind power plants.

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Fig.1.5.Synoptic diagram ofTarnița-Lăpuștești PSHP project

(Source: ISPH - Institute of Hydroelectric Studies and Design) The presence of Tarnița-Lăpuștești Pumped-Storage Hydropower Plant (PSHP) within

RPS shall optimize the operation ofthermoelectric plants and allow certain hydroelectric power plants currently used to regulate RPS to operate in an optimal and consistent manner, the main reference in that respect being Porțile de Fier IHP (hydropower plant). Fig.1.6. Goldisthal PSHP,1060 MW (4x265MW)-Germany

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2.State of pumped-storage hydropower plants within world energy 2.1. Current state in the PSHP field

PSHPs are used for the industrial storage of electricity and account for nearly 99% of the storage capacity worldwide.

“Pumped-storage hydropower plants are incredibly efficient. In the world of the future, which we envision populated with renewable energy sources in order to obtain 20%, 30% or 50% of the electricity provided by the current technological generation, we need pumped-storage hydropower plants to store electricity. It is a fantastic opportunity and, in fact, the chance to have clean energy at the lowest possible cost” (statement given by Steven Chu, the American Secretary of Energy, in September 2009)

On top of a strong increase of investments in wind and solar power plants in recent years, balancing the market has become essential, all the more that coal-powered units are only able to promptly offset wind and solar radiation intermittence to a small extent.

Power plants using conventional electricity sources, particularly those that rely on coal, are accompanied by increased costs due to the fact that they cannot operate at a continuous pace and, during downtimes, they cannot provide technological system services, either, given their long start-up duration and quite elevated costs.

The main categories of producers with rapid response to balancing requirements are hydroelectric power plants, gas-powered units and, in particular, pumped-storage hydropower plants, essential in balancing demand and supply.

In Europe, there is, basically, no country which, under favorable geophysical conditions, has not built at least one pumped-storage hydropower plant, available forTSO to provide the safety of the domestic energy system,including our immediate neighbors:Serbia,Bulgaria and Ukraine,the exception being Romania, which has wasted, technically speaking, approx. 20-25 years in the field of electricity storage. Fig.2.1.PSHP construction trend in OECD countries, as opposed to theUSA

Source:Power Eng

Pumped-storage hydropower plants have been an integral part of the European energy system for approx. 100 years. Worldwide, the major investments in pumped-storage

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hydropower plants took place in the ‘70s and the ‘80s,coupled with investments in nuclear capacities.

In 2017, the status of the capacity installed within PSHPs was as follows: Tab.2.1. Capacities installed in PSHPs of industrialized states(Source: the consultant)

Country Installed capacity (GW)

China 32

Japan 28.3

The USA 22.6

Spain 8

Italy 7.5

Germany 7

India 6.8

Switzerland 6.4

France 5.8

Austria 3.5

Portugal 2.6

UK 2.7

The document entitled “EU Water Framework Directive–2007” mentions:“Energy

storage and pumped-storage hydropower plants have a special place within the European Energy System. They provide system services in the form of power reserves and frequency control. The need for pumped-storage hydropower plants will visibly increase in the future.

The reasons are, on the one hand, the growing power demands in Europe, with peak increases during the summer, given the use of air conditioning, and, on the other hand, the expansion of renewable energy capacities, wind power plants and photovoltaic power stations; in terms of power balance, pumped-storage hydropower plants and energy storage are ideal in that respect and ahead of any other solutions.” Fig.2.2. Worldwide evolution of PSHP installed capacity, 1930-2020

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The energy-related paradigm shift by waiving fossil fuels and the European Union’s rapid energy transition towards intermittent and unpredictable electricity-producing renewable sources may become an external security risk for Romania unless it adapts in time.

The European Council adopted, on December 18, 2017, a position on a directive promoting the use of energy from renewable sources across the entire EU, ensuring the member states that, upon dispatching electricity-producing plants, transmission and distribution operators priorities production facilities that use renewable energy sources, insofar as the safe operation of the domestic power grid allows it and based on transparent and non-discriminating criteria.

The European Community has undertaken to fulfill the objective that at least 27% of the total energy consumption shall come from renewable sources by 2030.

This directive, in line with the European Council decisions from October 2014, confirm the mandatory objective and set forth the framework and proper tools for fulfillment.

The European countries that have successfully combined the development of electricity production from unpredictable and intermittent renewable sourceswith pumped-storage hydropower plants managed not only to decrease reliance on fossil fuel imports, but also to ensure and guarantee the security of electricity supply for their citizensunder more difficult technical conditions of those renewable sources.

Electricity storage shall play a key role in the future, as it will allow the EU to develop electricity production from renewable sources. Nowadays, the EU enjoys 27,500 MW(IRENA-2018)of PSHP installed capacity; only Malta, Cyprus, Hungary, Holland (geophysically unfavorable countries) do not possess pumped-storage hydropower plants, whereas Romania does possess adequate natural conditions and a pumped-storage hydropower plant project, which has been studies for approx. 40 years.

In order to solve the electricity storage issue, Holland has drawn up the complex project of an “energy island”, a pumped-storage hydropower plant of around 1500 MW built off-shore, while Hungary has identified a location near the Ukrainian border and has already completed the feasibility study for a pumped-storage hydropower plant of around 1200 MW. Fig.2.3. The energy island

Source: KEMA Laboratories

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The 50-year experience in the design, construction and operation of pumped-storage hydropower plants recommends that 10-15% of theinstalled capacityof a mixed energy system should comprise pumped-storage hydropower plants. Japan currently has 14% of its total capacity installed in pumped-storage hydropower plants and a massive investment program in the field.

Fig.2.4. Japan’s recommendation on the percentage of PSHPs installed within the energy mix

(The consultant’s source)

Mention should be made of Germany’s energy policy, called “the energy transition”, which consists in compensating the total closure of nuclear energy producers with the vast development of on- and off-shore wind power. This energy policy is likely to generate a series of issues in the electricity supply, not only for Germany, but also for its neighbors, such as:

• wind poweris random and unpredictable in nature, Germany’s import requirements might increase over the following years and issues might disturb on the European energy market;

• the automatic function of disengaging the wind turbines if the RPS frequency changesmay lead to incidents within Germany’s domestic power grid, with negative effects upon all the interconnected countries.

• A study conducted in April 2014 byRheinisch-Westfälische Technische Hochschule Aachen(RWTH) University clearly shows that, by 2050, Germany has to reach, from the7000 MW currently installed in its pumped-storage hydropower plants, to around 25,000 MW.RWTH experts analyzed the role of pumped-storage hydropower plants in two scenarios, one with 60% renewable energy in 2030 and another one, with 80% renewable energy in 2050. For the2030 time frame,the conclusion was that 15,000 MW (for 60% renewable

energy) are required, practically double the current capacity, over the next 15 years. For the 2050 time frame, the conclusion indicated a requirement of 23-25,000 MW

„We obviously need more storage capacities for the energy transition. And we must now create adequate economic conditions, as well. The electrical storage requirements should be prioritized, as they are the only energy storage systems and, in addition to that, they also bring valuable contributions of the power grid. We must adapt the framework-conditions so as

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to adequately remunerate this added value, as well”, Stephan Kohler, the president of Deutsche Energie-Agentur (DENA) Management Board, stated in 2014.

The countries where intermittent renewable energy sources (wind and solar) account for more than 15% of their installed capacity realize that storing energy by means of PSHPs is the only RPS balancing and strengthening solution.

The greater the extent by which the percentage of intermittent renewable sourcesexceeds 15% of the total installed capacity, the greater the need for energy storage.

When the various energy storage technologies are compared, pumped storage becomes the winning technology in terms of cost, performance, scale, reliability and flexibility in adaptation to various market conditions.

A currently operational pumped-storage hydropower plant has two income sources: • On the balancing market, it purchases energy at a low costduring night time/weekend hours and sells it at a competitive price when energy demand is higher • Income from system services

Storage also provides a series of other functions not providing income sources, but with an economic value. A “non-income” benefit is the improvement of operating efficiency of thermoelectric and nuclear plants, meaning less start-ups and shutdowns during nominal operation. The planners of utility companies acknowledge the economy of this streamlining. Fig.2.5.PSHP development in Europe and worldwide

341

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312 11 5

177,4142

25,81,8 5,3 2,3

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Lume Operaționale În construcție Contractate Anunțate În reparație

CHEAP în lume

Nr. CHEAP Putere instalată (GW)

169151

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60,350,2

8 0,5 1,34 0,240

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Lume Operaționale În construcție Contractate Anunțate În reparație

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Nr. CHEAP Putere instalată (GW)

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Contracted

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Under repair

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PSHP worldwide

PSHP in Europe

PSHP no.

Installed capacity (GW)

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2.2.SWOT analysis of a pumped-storage hydropower plant a) Strengths

The operating costs of a pumped-storage hydropower plant are low in comparison to those of other power plants and a PSHP has a long service life, of approx. 80-100 years. PSHPs can have an installed capacity of 1000-3000 MW and a rapid response time, of a few seconds, in relation to the installed capacity. Efficiency is approximately 75-80%. Pumped-storage plants are immune to oil, gas or coal price increases and do not require fuel imports. b) Weaknesses

One disadvantage is design dependence upon location geomorphology. For the most part, geological limitations make certain constructions difficult. c)Opportunities

The development of PSHPs ensures the implementation within RPS of wind power capacities with a ratio of 1 MW (pumped storage) to 5-6 MW (wind farms).As such, it would take a pumped-storage capacity of approx. 2000 MW to ensure the maximum development of Romania’s wind power potential. Moreover, the higher the water drop, the smaller the volume of the lower and upper reservoirs,with a lowered impact upon the environment, as well. d) Threats

Considering the geological constraints, there are limited prospects of pumped-storage hydropower plant projects in Romania. There is a lack of technical expertise for the design, construction and operation of this type of power plants. 2.3. Economy of storing electricity in PSHPs

When energy production exceeds demand,the additional electricity produced no longer has social value, the opportunity price being zero. If this additional production were stored, the costs taken into account are the capital cost and running cost of the pumped-storage plant. The cost required by a pumped-storage plant to produce peak energy is 15-20 % of the production cost of a gas turbine and approx. 50% of the production costs of a coal-powered plant.

Electricity storage is economic when the marginal cost of the generated electricity is higher than thecost of storing the energy consumed during the actual storage process. This matter is commercially settled using the ratio between the on-peak energy price and the off-peak (low load - at night and in weekends) energy price.

The existence of a pumped-storage hydropower plant within RPS allows optimizing the operation of the thermoelectric and nuclear power plants. Thermoelectric and nuclear power plants are cost-effective when they operate at a constant loading coefficient while using a standard load. The storage of water in the upper reservoir of the pumped-storage hydropower plant makes it possible to efficiently generate electricity at peak load, without changing the mode of operation of thermoelectric plants, less receptive to load alterations.

Pumped-storage hydropower plants have turned out to be very efficient in the transmission of large amounts of low-cost electricity produced outside the peak hours, to be subsequently distributed at higher prices during peak load and high demand periods.

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Moreover, a pumped-storage hydropower plant provides a rapid response to any changes in electricitydemand that might occur after an incident of a system power plant, facilitating the decrease of electricity supply delivery interruptions. In emergency cases (for instance, a total voltage drop caused by a major incident), numerous power plants require a powerful consumer in order to resume generation and restore power across the system. Pumped-storage hydropower plants are well-adapted so as to be used as such emergency power sources, as they can be activated in a matter of seconds.

The “upper reservoir” principle provided by a pumped-storage hydropower plant (PSHP) is currently the only industrial-grade storage system for the electricity surplus produced nuclear and thermoelectric plants outside the peak hours, which can also integrate intermittent and unpredictable wind and solar power plants within the energy system.

Within a national power system, pumped-storage hydropower plants meet the requirements concerning the amounts and quality indicators of the electricity produced and increase the operational safety levels of the entire system.

The functions of pumped-storage plants, essential for a system, can be defined as static and dynamic, as follows:

• The static (scheduled) functionis defined as the scheduling of electricity production and transfer

• The dynamic (non-scheduled) functionensuresthe system services, such as frequency and power offset (the primary and the secondary reserves) and the “black start” facility In Romania, the greatest obstacle against the decision to invest in a PSHP project does

not involve technology, but the lack of certain market mechanisms, able to ascertain, also from a financial point of view, the storage value of electricity and the offsetting of system services. The British experience in the area can indicate two pumped-storage plants, Ffestiniog and Dinorwig (1900 MW), which have been rendering on a yearly basis profits of around 100-150 million sterling pounds for approx. 50 years, since they were commissioned.

Pumped-storage hydropower plants do not create energy by transforming energy resources, they are only able to store energy during low load periods and release it during high load periods. The operation of pumped-storage hydropower plants consists, basically, in a combination of hydro-technology (the existence of two reservoirs, the use of water for pumping and generation etc.) with thermal and nuclear technologies (the use of capacity excess, during low load intervals, for pumping).

The rapid changes in terms of economy, technology and in the regulations of energy markets have brought forward pressures upon RPS, upon the electricity transmission infrastructure, as well as unforeseen imports of electricity from neighboringcountries, at very steep prices!RPS could be effectively supported by electricity storage. 2.4.PSHP role in the provision of system services

If the security of an energy system is understood as maintaining and improving the

reliability and capacity levels, the role of pumped-storage hydropower plants is vital for the RPS security.

Moreover, for the 2030 time frame, a model was drawn up concerning the impact of certain stress factors upon the RPS capacity to cover the demand in terms of electricity and technological system services and the RPS capacity to maintain export levels and to secure the imports required by operation under safe conditions

pg. 19

The results of modeling under stress conditions for the 2030 time frame, for the winter periods (temperatures below -20°C, massive snowfalls), indicate that Romania might require imports over brief periods of time (around 25 – 35 GWh over 24 hours, representing approx. approx. 15% of the mean daily consumption requirements (ANRE Report-2017)

Electricity storage shall thus become a key element of the European“Super Grid” concept, which relies on the development of pumped-storage plants in the Alps and the Scandinavian regions, plants that are to play a major role for the said “European Super Grid” concept.

Pumped-storage hydropower plants are vital for the future of Romania’s energy system. Romania’s energy strategy includes the construction Tarnița-Lăpușteștipumped-storage hydropower plant, with an installed capacity of 1,000 MW,added to the commissioning of the two additional nuclear power units (units 3 and4, that is 1400MWin addition to the current 1499MW) and the integration of wind and solar power plants in RPS.

Pumped-storage is the only commercially tested technology available for scale electricity storage within an energy system. The contribution of Tarnița-Lăpuștești PSHPto RPS 1. It supports the adequacy of thepower system=>adequacy = the capacity of the power

system to permanently meet the consumers’ power and energy requirements, taking into account the removals from service of system elements, both the scheduled ones and those reasonably expected to take place as unscheduled events.

2. Primary reserve = the primary reserve has to be automatically and fully mobilized within 30s, at a quasi-stationary frequency deviation of ± 200 mHz from the set point valueand shall remain operational over a duration of at least 15 minutes if the said deviation persists. All the electricity producers are bound to ensure primary regulationaccording to Transelectrica’srequest, via their own dispatchable units or via collaboration with other producers. The primary reserve has to be distributed as evenly as possible within RPS. The producers’ tenders in terms of production shall take into account the mandatory nature of maintaining the primary reserve available, in accordance with the technical performance of each generator unit

3. Secondary reserve = the Secondary reserve is the reserve which, if the RPS frequency and/or balance deviates from the set point value, can be fully mobilized within no more than 15 minutes. The secondary reserve is designed to contribute to the restoration of the primary reserve and bring back the RPS frequency and balance to the set point value. Transelectrica sets forth, both in order to schedule and plan the operation of units, as well as for the dispatching process, the necessary secondary reserve and its distribution per unit. The producers ensure, within the limits of the units’ technical characteristics, the secondary reserve as per Transelectrica’s requests.

4. Fast tertiary reserve = the fast tertiary reserve (the “minute” reserve)is intended to ensure the quick restoration (within 15 min.) of the secondary reserve and take part in the regulation of the preset RPS frequency and balance. The “minute” reserve is provided as a spinning reserve or a fast tertiary reserve. The “minute” reserve is fed by the producers, as per Transelectrica’s instructions, over the requested duration.

pg. 20

5. The spinning reserve (the availability of increasing the generation power by increasing revolutions, if RPS so requires)

6. The non-spinning reserve (additional power that can be delivered to RPS) 7. The flexible reserve =𝑅𝑅𝑓𝑓 =(𝛤𝛤𝑤𝑤ind)2+(𝛤𝛤solar)2 8. Load curve monitoring -adequacy 9. Load curve flattening 10. The black-out service =the rapid restoration of RPS operation is performed using

voltage sources, which can be: • self-starting generator units; • generator units assigned to own services; • generator units assigned to a single consumption area; • interconnections with neighboringpower systems

11. Dispatchable consumer = consumer whose consumed power can be altered at the request of the Transmission System Operator

12. Enhancing RPS safety levels

According to the final project, Tarmita-Lăpuștești PSHP shall have an installed capacity of 1000 MW between 4 reversible motor-generator units, with a power of 250MWeach, shall produce 1625 GWh/year of electricity and consume through pumping 2132 GWh/year, with a current ratio of 0.76,similar worldwide to that of the most modern pumped-storage hydropower plants in operation.

The investment shall ensure approx. 3000-4000 jobs on construction sites, for a construction period, and around100 permanent jobs for the operation and maintenance activities, subsequent to start-up.

For comparison purposes, Nuclearelectrica, with its 1400 MW of installed capacity, across a single platform (Cernavodă), has 1,950 employees (SER 2018-2050)

The recent global interest in resuming investments in pumped-storage plants has stemmed from the following aspects:

• a reassessment of the system and electricity storage services in countries that intensely develop their wind and solar power potential (China,Germany, India, the USA, Spain, Portugal,etc.)

• the arbitration function on the balancing market, which entails purchasing electricity at low costs at times when electricity demand is low (off-peak) and storing and selling it when electricity demand, along with prices, are high (on-peak)

• the changes that occur in the energy field due to fuel prices, particularly the shutting down of gas-powered plants, which were traditionally ensuring the load peak, impose the development of pumped-storage capacities.

• By supplying power when and where it is needed, the pumped-storage plant facilitates a more responsive energy market.

• Another reason for developingPSHPs is the reaction speed of this type of power plants, which is mere seconds. The wind power capacities and solar power plants, in particular, can have sudden start-ups and shutdowns,causing technical issued within RPS. Thermoelectric plants are unable to respond as fast as hydroelectric power plants and pumped-storage plants in “spot” start-up cases, with synchronization within seconds and maximum power in under one minute. The reaction of thermoelectric plants takes between 2 and 8 hours!

pg. 21

From a historical perspective, being present for more than 100 years in the energy sector, pumped-storage plants have a stable reputation and an excellent response in the following main areas:

• financially, they are cost-effective, they reduce electricity costs by using the electricity produced outside the peak hours, when the price is low.

• reversible hydropower equipment items have low O&M costs and can frequently run over extended periods of time, 40-50 years, also having lifespan of at least 80-100 yearsfrom a PSHP constructive standpoint.

• pumped-storage plants provide support to RPS in enhancing supply reliability, as well as offsetting availability variations and fluctuations of intermittent renewable sources, such as wind and solar power; they maintain and increase power quality, frequency and voltage.

3. Electricity market

3.1. Electricity trading platforms in Europe

3.1.1. The Scandinavian electricity market The Scandiavian power exchange, comprising Norway, Sweden, Finland and

Denmark, administer the following electricity markets: a) The physical market, comprising: the spot/day-ahead market (Elspot) and the balancing market (Elbas); b) The financial market, comprising: the market of “forward” and „futures” contracts (Eltermin) and the market of option contracts (Eloption).

The day-ahead market, represents the environment where electricity is transacted “one day ahead” of the day when the physical delivery takes place. On the Nord Pool exchange, tendering is bilateral (sale and purchase tenders). The tenders comprise price-quantity pairs, and the spot market price is calculated at the intersection of the curves built upon sale and purchase tenders. The spot market is the place to trade hourly contracts. If any congestions occur in the network among geographic regions, the market fragmentation mechanism is deployed and regional prices emerge as a result. The electricity amounts traded on Nord Pool financial market have reached 500 ÷ 1000 TWh. Elbas electricity market hosts the trading of electricity once the trading session on the spot market has been completed.

The contracts transacted on the financial market (“futures” and “forward”) are concluded in order to cover the risk of unfavorable price evolutions of electricity transactions on the physical market. These contractsare concluded over a 4-year period. 3.1.2. The French electricity market

The management of the French electricity market is handled by Powernext, a capital investment company holding the tittle of Multilateral Negotiation System and pursuing the following objectives:

• Setting forth a short- and medium-term reference price of electricity by means of a regulated and secured market;

• Fulfilling a major role in the creation and streamlining of the European electricity market.

pg. 22

The trading process within Powernext is conducted on a daily basis, 7 days a week and also during public holidays. LCH Clearnet, the main Clearing House in Europe and a subsidiary of Euronext, guarantees the security of transactions, being a broker between purchasers and sellers with a guarantee deposit adjusted on a daily basis, as per the positions gained. The submission of structured tenders, either with no more than 64 power-price pairs, for each of the 24 time slots (simple tenders), or comprising standardises blocks limited to an amount not exceeding 25 MW / block (the block generically called “1 – 4” covers the 100 – 400 a.m. interval and the “5 – 8” one covers the 500 – 800 a.m. interval, and so on) starts on the Wednesday in the week prior to the trade day and ends at 1100 on the trade day.

The mechanism designed to set forth the price follows the linear interpolation principle, used both for simple and block tenders. To that end, block tenders are converted into simple tenders, with one clearing price set forth for each time slot. A block tender can be fully accepted or dismissed. 3.1.3. The German electricity market

The German exchange EEX – European Energy Exchange, manages two markets: • the physical market (the spot market); • thefinancial market (the market of “futures” contracts).

The EEX Spot Market provides two different trading platforms: one platform for trading via private bidding, for hourly contracts and block contracts, and another platform for continuous trading, in connection with the opening and closing of bids for off-peak and on-peak energy contracts.

Trading via private bidding (the trading sessions is completed at 1200 a.m. – the day before) relies on buy-in and sales tenders in relation to hourly contracts and block contracts for the following day.

Setting forth the price relies on the trading system, meaning that clearing prices are calculated during the bidding, after all the sales and buy-in tenders have been received over a preset period. The amount of demand and supply shall correspond to the clearing price.

In continuous trading, each tender received is checked in terms of feasibility. The tender register is open, which means thatthe price limits and tendered quantities are visible. If there are no network congestions, a single price shall be set forth for the entire country and for each hourly bid.

Fig.3.1. Electricity prices in European Union Countries in 2017

Source: Eurelectric

taxes and levies Network Energy

pg. 23

If any congestions should occur across the network, it is allowed to form different

price areas using the market fragmentation mechanism. The price of electricity on the electricity market is influenced by the following factors: • The evolution of fuel prices; • Sustainable development measures; • Limited interconnection capacities; • Levies; • The regulation measures of the sector. Pursuant to the Kyoto Protocol on thedecrease of greenhouse gas emissions and the

EU Directive, the European Union Emissions Trading System was created to reduce CO2 emissions, based on “carbon credits”, which led to an electricity price increase. One ton of CO2 sells for around 20 EUR. 3.2.The Romanian electricity market 3.2.1. Market organization and electricity price formation

The electricity market is an economic concept expressing the sum of sales – buy-in transactions carried out within a predetermined geographic area. Its main function is to correlate production with consumption, via demand and supply,via the materialization of sales and purchase contracts. Romania has undertaken to liberalize its electricity market, on the grounds that safety of supply to consumers and, implicitly, the energy system safety shall increase with the development of a coherent electricity market, where the players may benefit from the advantages of the level playing field.

According to the documents on the accession to the EU, the electricity sector in Romania needs to comply with the community directives and resolutions, as well as take steps, get organized, develop and implement procedures and a legal framework for regulatory purposes, which are harmonized and designed to provide the results mentioned in such directives.

The electricity sectorcurrently comprises the following components: • production – a competitive component • transmission and distribution – a regulated component • supply – a competitive component

The price of electricity for each of these items has both regulated and competitive components.

pg. 24

Fig.3.2. Electricity price composition

ANR-Regulatory Authority for Energy; RES-renewable energy sources; CHP-combined heat and power plant. Source: ANRE-2016

The electricity price comprises the electricity production price (competitive component) andthe related levies (regulated component). The electricity transmission price comprises the transmission fee and the price of system services, both regulated. The electricity distribution price comprises the distribution tariff, as a regulated component. The supply price comprises the renewable sources supply and promotion margin (competitive component) and the related levies (VAT and other levies). Considered, until not long ago, merely a service provided to consumers by the supplying units, electricity is seen, in the context of the privatization of utility companies, a commodity which is, as any other product, subject to certain quality parameters, intended to optimally meet the consumers’ requirements.

Fig.3.3. Market shares in 2017 - main producers

Source: ANRE/CE Oltenia

The electricity delivered in a certain point of a three-phase alternating current power grid is characterized by the following quality parameters:

• supply voltage;

VAT Other taxes Other levies Supply security Energy efficiency ANR & market Concession fees The nuclear sector Social aspects RES and CHP

OTHERS

pg. 25

• frequency; • the unbalance degree of the three-phase system of voltages; • the voltage waveform deformation degree; • the continuity of supply.

The Wholesale Electricity Market represents the organized framework where electricity is purchased by suppliers from producers or other suppliers, in order to resell it or for their own consumption, as well as by network operators in order to secure their own technological consumption. The following parties have access to the wholesale electricity market for trading purposes:

• electricity producers and autoproducers; • suppliers • network operators.

The transactions on the wholesale electricity market focus on the sale and purchase of: • electricity; • technological system services.

Fig.3.4. Electricity price components

Source: Natura 2000/ANRE-Feb.2018

The players on the wholesale electricity market are Romanian or foreign legal entities, licensed parties, which registered as:

• participants to DAM(the day-ahead market); • participants tothe balancing market; • participants to bids; • parties in charge with the balancing processes. The wholesale energy market comprises the following specific markets:

Electricity bill VAT

0.078394

Excise duties 0.004 Cogeneration

0.012

Green certificates 0.0456

System services 0.013

Extraction from the grid 0.015

Addition to the grid 0.001

Distribution

Consumed energy 0.18

■ Consumed energy ■Distribution■ Addition to the grid ■ Extraction from the grid ■ System services ■ green certificates ■ Cogeneration ■ Excise duties ■ VAT

pg. 26

• Day-Ahead Market (DAM/PZU) • Intra-Day Market (PI) • Centralized Market with double continuous negotiation for Electricity Bilateral

Contracts (PCCB-NC) • Centralized Market for Electricity Bilateral Contracts (PCCB) • Centralized Market for Universal Service (PCSU) • Electricity market for large consumers • Day Ahead Market for Natural Gas • Centralized Market for Natural Gas • Green Certificates Market

Fig.3.5. Contract-based electricity market in 2017

Source:Complexul Energetic Oltenia 3.2.2.Centralized market of technological system services

The provision of a sufficient amount of Technological System Servicesavailable to the Transmission System Operator (TSO) and the Distribution Operators, respectively, is usually handled by means of non-discriminating market mechanisms – bids over specified periodsand/orbilateral contracts.

Ensuring the primary regulation and maintaining the primary reserve availability are mandatory for all the electricity producers, in accordance with the provisions of theElectricity Transmission Grid Technical Code (CTRET)

Producers that contractedTechnological System Services (secondary reserve and tertiary reserve) are bound to make available on the Balancing Marketat least the electricity amounts corresponding to the volumes of contracted technological system services.

MARKET FOR BILATERAL CONTRACTS RETAIL MARKET

DAY-AHEAD MARKET

BALANCING MARKET

pg. 27

The Centralized Market for Technological System Services (PCSST) is intended to maintain the safe operation of the national power system. This market has the following characteristics:

• it is centralized and operated by TSO(the transmission system operator) • the trading is periodic (on a yearly, monthly etc. basis). • it isoptional; • itis conducted with the participation of energy groups qualified to provide

Technological System Services made available by TSO; • in order to deliver Technological System Services, the energy groups are selected

based on the marginal price principle; • it enables secondary reserves, fast tertiary reserves and slow tertiary reserves (primary

regulation is mandatory and free of charge); • the amounts of energy purchased are set forth by TSO, depending on technical

regulations; • the amounts purchased are tendered only on the balancing market.

The operation of the Centralized Market for Technological System Services relies on the technical provisions in theElectricity Transmission Grid Technical Code and the provisions in theWholesale Electricity Market Commercial Code. The Commercial Code sets forth the rules and procedures for the purchase of:

• secondary and tertiary reserves; • reactive power for voltage adjustment; • othertechnological system services defined by theElectricity Transmission Grid

Technical Code; • electricity intended to cover technical losses within power grids.

The Secondary and Tertiary Reserves, the Reactive power for voltage adjustment within the electricity transmission grid, as well as the Technological System Services are exclusively purchasedby TSO, whereas the electricity intended to cover technical losses within power gridsis purchased by the network operator.

In order to purchase secondary and tertiary reserves, the following steps are taken: • TSOpurchases from EM (the electricity market) participants, during each buy-in

period, secondary, fast tertiary and slow tertiary reserves; • TSO sets forth the buy-in periods for the secondary and tertiary regulation, which can

be continuous per year, season, month, week or day. The buy-in period can be limited to days or dispatching intervals, during the respective period, that is business or non-business days, public holidays, hours or intervals of other nature. The buy-in periods can be different for different regulation reserves;

• TSO sets forth the amounts of regulation reserves that need to be purchased during the respective buy-in period;

• TSO publishes the amounts of secondary or tertiary reserves that need to be purchased, in due time, prior to the respective buy-in period; EM participants are bound tender to TSOthe secondary and tertiary reserves. Based on

the rules and procedures elaborated by TSO, EM participants submit aggregate tenders for the dispatchable units and consumptions. If the tender provided to the EM participants fails to cover the secondary and tertiary reserve requirements, TSO shall request

• that additional quantities be tendered, depending on their technical capabilities. This request byTSOis binding upon the EM participants.

pg. 28

• TSOmay conclude bilateral contracts, for the management of internal congestions, for fast and slow tertiary reserves, with EM participants, during the reserve contracting period, under the conditions provided by the Commercial Code. When purchasing reactive power for voltage adjustment, the following shall be

considered: • TSOpurchases for electricity producers or distributors, for each buy-in period, the

reactive power amount required to adjust voltage, produced in the secondary range, separately for inductive reactive power and the capacitive reactive power;

• The amount of reactive power for voltage adjustment, requested by TSOand produced in the primary range, is not subject to fees or charges;

• TSOsets forth the buy-in periods for reactive power required to adjust voltage, which can be continuous or set per year, season, month, week or day. The buy-in period can be limited to dispatching days and intervals during the respective period;

• TSOmay set forth different buy-in periods for the inductive and capacitive reactive power required to adjust voltage;

• TSO publishes theamount of inductive and capacitive reactive powerrequired to adjust voltage duringthe buy-in period, within adequate deadlines prior to thebuy-in period;

• Electricity producers are bound to tender toTSO theinductive and capacitive reactive power reserve;

• The producers submit binding tenders for several units or dispatchable consumptions, as per theTSO rules and procedures;

• When the producers’ binding tender failsto meet the reactive power reserve requirements, TSOmay request that additional quantities of reactive power reserve be tendered, depending on their technical capabilities. This request by TSO is binding upon the producers. When purchasing other technological services, the following shall be considered:

• TSOmay purchase other technological services per buy-in period; • TSO determines thequantities and types of Technological System Services required; • TSO sets forth the purchase-related rules and procedures; • If the submitted tenders are not sufficient, TSOshall request that additional tenders, of

a binding nature, be submitted. In the process of purchasing electricity in order to offset technical losses within power

grids, the following shall be considered: • The electricity required to offset technical losses within power grids shall be

purchased by each individual network operator, during each trading interval; • The purchase of electricity required to offset technical losses within power grids shall

make use of public tendering procedures orDAM procedures; • The network operator sets forth the buy-in periods for the electricity required to offset

technical losses within power grids, which can be continuous per year, season, month, week or day. Abuy-in periodcan be limited to dispatchable days or intervals;

• The network operator determines the energy amount required to offset technical losses within power grids and necessary during the buy-in period;

• The amount of electricity shall be published and purchased by means of public tendering procedures;

• The tendering rules and proceduresshall be set forth bythe network operator. 3.2.3.Technological system services

pg. 29

These services are purchased, based on specific contracts, from producers, at the request of Transelectrica SA, in order to maintain the safe operation levels of the power system and the quality of the transmitted energy within the parameters imposed by the regulations in force. The main components of these services are: a)Technological system servicesused to ensure frequency stability: • the primary frequency regulation reserve (defined as the automatic, decentralized regulation of a static nature), assigned among a large number of generator units intended to ensure the fast correction, within 30 seconds, of differences between production and consumption, at a frequency close to theset point value. The primary reservemust be automatically and fully mobilized within 30s, at a quasi-stationary frequency deviation of ± 200 mHz from the set point value (50Hz) and remain operational over a duration of at least 15 minutes if the said deviation persists.

All the electricity producers are bound to ensure primary regulation according to Transelectrica’s request, via their own dispatchable units or via collaboration with other producers.

The primary reserve has to be distributed as evenly as possible within RPS. The producers’ tenders in terms of production shall take into account the mandatory

nature of maintaining the primary reserve available, in accordance with the technical performance of each generator unit. • the secondary frequency-power regulation reserve (defined as the automatic, centralized frequency regulation (exchange power with frequency correction) in order to bring frequency / exchange power to the set point values within 15 minutes.

The Secondary reserve is the reserve which, if the RPS frequency and/or balance deviates from the set point value, can be fully mobilized within no more than 15 minutes. The secondary reserve is designed to contribute to the restoration of the primary reserve and bring back the RPS frequency and balance to the preset value. Transelectrica sets forth, both in order to schedule and plan the operation of units, as well as for the dispatching process, the necessary secondary reserve and its distribution per unit. The producers ensure, within the limits of the units’ technical characteristics, the secondary reserve as per Transelectrica’s requests. • the power reserve corresponding to the tertiary regulation,comprising:

o The fast tertiary reserve (the “minute” reserve) is intended to ensure the quick restoration (within 15 min.) of the secondary reserve and take part in the regulation of the preset RPS frequency and balance. The “minute” reserve is provided as a spinning reserve or a fast tertiary reserve. The “minute” reserve is fed by the producers, as per Transelectrica’s instructions, over the requested duration.

o The slow tertiary reserve, intended to restore the “minute” and ensure a production-consumption balance if any deviations from the preset program should occur. The slow tertiary reserveis fed by the producers, as per Transelectrica’s instructions, over the requested duration.

b) Technological system services used to ensure voltage stability • voltage regulation using reactive energy; • the capacity to provide the start-up service required to restore RPS; • active energy to cover the losses within the electricity transmission grid (RET).

Voltage stability is performed under the coordination of Transelectrica,which takes part in the process with its own regulation equipment, by the producers, Transelectrica and the consumers. Voltage stability at border nodes is performed in collaboration with the TSOs of the neighboringpower systems. At the request of Transelectrica, the producers are bound to

pg. 30

ensure the production/absorption of reactive power by the generator units,as per the RET connection requirements.

Transelectrica, the distributors and the consumers connected to RET have to offset their reactive power consumption/production from their own grid. Reactive power exchanges between RET and the distribution networks or consumers connected to RET may be allowed provided that they do not negatively affect the safe operation of RPS.

Reactive power exchanges between RET and distribution networks or consumers connected to RET, which negatively affect the business run by the respective partners, may be carried out pursuant to agreements concluded among these parties. c)Technological system services used to make sure RPS operation is restored in cases of voltage drop triggered by extended faults or a system total failure

The rapid restoration of RPS operation shall be performed using voltage sources, which can be: • self-starting generator units; • generator units assigned to own services; • generator units assigned to a single consumption area; • interconnections with neighboringpower systems.

The voltage sources shall make it possible to re-feed the auxiliary services of the generator unitsthat were not separated to support own services, as well as of the power plants and stations included in restoration circuits. The participation of generator unitsto the restoration of RPS operation is ensured via the connection setup and/or the RPS operation restoration plan, depending on the RPS requirements. Producers must make sure that, in each power plant, at least one generator unit is separated in order to support own services.

Transelectrica SA purchasestechnological system services from the electricity generating companies under a procedure regulated by ANRE. Practically,Transelectrica re-invoices the entire amount of system services purchased from producers (except for the active energy component covering the RET losses) to the ANRE-licensed electricity suppliers that benefit from such services in the end. 3.3.Electricity consumption forecast

The pace displayed by the economic development and the use of existing capacities in the best possible manner is a factor that influences the production of electricity. The electricity consumption forecast is one main function of electricity distribution and supply operators. Electricity in Romania cannot be stored in an efficient manner, at a large scale (in relation to the produced quantity), which means that, for distribution and supply operators, estimating demand is an all-important factor in the process of managing transactions in a relatively reasonable manner.

After 1989, Romaniaentered a process of transition from the former centralized economy to a market economy. Losing about one decade’s worth of development, Romaniaeventually regained its 1991 performance level in 2000. After 2000, when the focus started shifting to the private sector and reforms of the taxation system for companies, actual economic growth began.

Fig.3.6. Electricity production evolutionfrom 1971 to 1989

pg. 31

Source – stiri-economice.ro

Until 1989, the electricity consumption in Romania showed a slow, but consistent annual increase. The economic evolution in Romania after 1990was strongly influenced by the effect associated to the period of transition to a market economy. The economic reforms required to replace the centralized economy mechanisms with those present on a free market and the introduction of energy efficiency principles in all activities initially led to a severe recession, with similar effects upon all the countries in the region.

Romania is currently engaged, to a significant extent, in efforts to resume the economic growth it had reachedin 2008, as the decline of the 2009-2010 years has been nearly fully overcome. Between 2016 and 2018, all the macroeconomic indicators appeared to be in line with the requirements imposed by the Maastricht Treaty, with a stabilized inflation rate and a relatively stable exchange rate.

In Romania, economic growth and the energy consumption have been decoupled since 1998, whereas the energy intensity of the economy, measured by means of the primary energy consumption per gross domestic product unit, has significantly decreased. After the major energy consumption and economy contractions from the 1990s, the GDP increased by 53% during the 2000-2011 interval, whereas the energy demand has remained nearly constant. This was largely due to the structural adjustments of the economy towards higher added value of production and services and the significant increase of energy efficiency across industries.

Energy production during the 1971-189 interval (billion kWh)

Total energy production Energy from renewable sources

pg. 32

Fig. 3.7. Evolution of Romania’s GDP from 1950 to 2015

Source:Groningen University, Holland-2016

In economic theory, the most relevant indicator used in order to emphasize economic growth is the gross domestic product (GDP),correlated with theenergy consumption;In recent years, an electricity consumption trend has been noticed, also supporting the GDP increase.

Fig.3.8. GDPevolution vs. energy consumption evolution

Source: Capital,INS (National Institute of Statistics),Transelectrica

The scenarios considered for the electricity forecast calculation:

GDP (million USD)

Communist period Transition period

Recovery and pre-EU accession

period Financial crisis

Post- crisis period

Foreign debt peak in 1981 – 11 mil. USD

Full payment of the foreign debt at the cost ofthe starvation of the population

THE LINK BETWEEN ENERGY CONMPTION AND ECONOMIC EVOLUTION WAS SEVERED

If, during the first crisis years, the electricity consumption was a good indicator of economic evolution, in recent years, the two indicators are completely different

Source: Capital, INS, Transelectrica calculation

pg. 33

• the consumption growth rate; • the electricity exchange with other systems; • the installation of new production capacities and removing existing ones from use.

These scenarios are intended to: • assess the flexibility of development solutions as opposed to several possible evolutions; • provide criteria for later adjustments to the development plan as per the system evolutions.

The Ministry of Energy estimates in the National Strategy that energy production shall increase by 17.5% by 2030, meaning a significant progress of the electricity production over the next 15 years, from 56.8 MWh in 2017 to 72.77 MWh in 2030.

The reference scenario in the Transelectrica report (RET Development Plan 2017-2027) estimates a moderate increase for the penetration of renewable energy sources and new production technologies. The data obtained until November 2017 forecast an electricity net consumption mean annual increase of around 2.5%.

Fig.3.9. Electricity consumption in Romania 2009-2017

Source: entsoe.eu

The energy mix shall remain balanced, as follows: Fig.3.10. Electricity production forecast

2017 2020 2025 2030 2035 2040 2045 2050PRODUCTIA DE ENERGIE PE TIP DE SURSĂ [TWh] 63 69 72 77 83 84 85 86Nuclear 11.5 11.5 11.4 17.4 23.2 23.2 23.2 23.2Apă 14.4 15.8 17.5 17.6 17.6 17.6 17.6 17.6Eolian & solar 8.5 8.8 9.6 10.5 11.4 12.3 13.1 14.0Carbune 17.3 17.5 17.8 15.8 14.9 14.9 14.9 14.9Petrol 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4Gaz 10.2 14.0 14.5 14.5 14.5 15.0 15.0 15.0Biomasă 0.4 0.9 0.9 0.9 0.9 0.9 0.9 0.9

Nuclear [%] 18.3 16.7 15.8 22.5 28.0 27.5 27.2 26.9Apă [%] 23.0 22.9 24.3 22.8 21.2 20.9 20.7 20.5Eolian & solar [%] 13.5 12.7 13.3 13.6 13.7 14.6 15.4 16.3Cărbune [%] 27.5 25.4 24.7 20.5 18.0 17.7 17.5 17.3Petrol [%] 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5Gaz [%] 16.3 20.3 20.1 18.8 17.5 17.8 17.6 17.4Biomasă [%] 0.7 1.3 1.2 1.1 1.1 1.0 1.0 1.0

PRODUCTIE ENERGIE ELECTRICA 2017-2050 [TWh]

PONDEREA RESURSELOR ENERGETICE IN PRODUCTIA DE ENERGIE ELECTRICA 2017-2050 [%]

Electricity consumption in Romania

ELECTRICITY PRODUCTION

SHARE OF ENERGY RESOURCES IN ELECTRICITY PRODUCTION

Nuclear Water Wind & Solar Coal Oil Gas Biomass

Nuclear [%] Water [%] Wind & Solar [%] Coal [%] Oil [%] Gas [%] Biomass [%]

pg. 34

Source:Energy Strategy 2018-2030

The CNR–CME (WEC (World Energy Council) Romanian National Committee) document, entitled “Observations on Romania’s Energy Strategy 2016-2030 with a view to 2050”, states: The electricity market has to take into account, in a balanced and optimized manner, the entire resource mix, where coal is the central energy elements, which should cover at least 30% of the market. In this context, Romania needs to implement, as part of the electricity market, a component relying on a “capacity mechanism”, able to secure the financial resources required to maintain in proper operating conditions the coal-based energy-producing capacities and have then run efficiently during periods when the production of electricity from renewable sources cannot secure the necessary production according to the installed capacity levels. 3.4. Provision of system services

In general, hydroelectric power plants are intended to cover a part of the peak area on the load diagram, but also in the lower area of the load diagram.

For a non-storageHP (hydropower plant): regardless of the hydrologic nature of thetributary flow rate (rainy, normal or rainless years), the optimum operation of this plant lies in the lower area.For a storage-based HP, operating in the upper area is more beneficial, as it limits losses and a higher price can be obtained. Also beneficial is for the power plant, even if it uses storage, to operate in the base area of the load diagram, as well, since it runs at its installed capacity (maximum power).

With their technical and economic features (elasticity, reliability, low cost price),hydroelectric power plantsare set-ups quite useful in covering particularly the upper areas of the scheduled load diagram and efficiently rendering system dynamic and kinematic services.

In Romania, the power requirements for secondary regulation are also facilitated by eight large hydroelectric power plants: Porţile de Fier I, Stejarul, Corbeni, Ciunget, Gâlceag, Şugag, Mărişelu and Retezat; their total installed capacity is 2845 MW, of which a full range of 400-550 MW is reserved for this regulation. The primary regulation range available in the HP (approx. 115 participating power plants, with an installed capacity of around 6000 MW) totals around 350 MW. The electricity production of hydropower plants, generically called hydropower, has plenty of particularities affecting the operation of the entire RPS.

The brief start-up time and high loading/unloading speed of hydro-aggregates ensures the flexible operation of hydroelectric power plants which are not the main suppliers of technological system services, covering nearly 80%.Another flexibility-related aspect in the operation of hydropower plants is their role in profiling the daily load (consumption) curve.

Electrical load variation over a specified duration,usually one day (24 hours) is called Load curveand represents the energy that has to be allotted to the power system consumers. If the amount of energy requested by consumers is higher or lower than the energy amount delivered by the producers, voltage and frequency disturbances occur within the grid, endangering the operation of consumers and leading to significant failures thereof.

The amount of power delivered (energy produced) has to be, at any time, equal to the amount of power (energy) consumed. To make this possible, the load curve has been divided into several consumption areas:

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• the base area – it is the area that has to be permanently covered; here, energy producers are thermoelectric plants and nuclear power plants (power plants with low start-up/shutdown flexibility, with continuous operation, usually constant power – NPPs, TEPs (thermoelectric plant), combined heat and power plant, TEPs with condensation units, HPs along water courses);

• the area of variable powers–power plants run intermittently (with interruptions) and, even during operation, power can be variable. The closer the inclusion area is to the peak, the shorter the daily running duration. Other power plants can cover the area of variable powers:

• in the semi-peak area - condensation electric power plants; • inthe peak area - gas turbine power plants.

HPs operate efficiently in the peak area if they are also storage-based plants; HPs along water courses operate efficiently in the base area of the load diagram. Fig.3.11. 24-h load diagram: A-base area; B-semi-peak area; C-peak area.

Thermoelectric plants have a much higher loading/unloading speed than hydroelectric power plants, which places their optimal operation in the base area of the load curve, the peak and intermediate areas of the consumption curve being mainly coveredby hydroelectric power plants. This is possible by means of the cascade set-ups benefitting from at least daily regulation. The differences between the peak area and the nigh time low load (the least loaded area of the curve) vary depending on the season and fall around the 2000-2500 MW value. 3.5.Sustainability of Tarnița-Lăpuștești PSHP

The role of a PSHP is to cover a part of the load diagram peak area, while consuming in the base area of the load diagram.Moreover, it ensures the technological system services for the production and transmission processes, services which are elements required to guarantee the quality, security and cost-effectiveness of electricity supply at the bus-barslocated at the intersection of the transmission system with the distribution system, elements relying on:

• the service quality concept, associated to maintaining within acceptable limits the voltage and frequency levels in delivery points.

• the security concept, related to supply continuity. • the cost-effectiveness concept, related to the supply of electricity at a minimum

cost.

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In August 2018, the Global Market Insights consulting company published a report on the global trends of PSHP development, showing that by 2024, the total global market of PSHPs will exceed 350 billion euro investments and 200 GW cumulative installation.

The report analyzes PSHP technology by region and system, - open loop, closed loop and innovative technologies, by considering the major market players, the prefigured policies and projects.

The report identifies various market forces involved in PSHP development for each region:

In the USA, the two main market forces are the rising demand for grid storage technologies and rising demand for a more enduring energy mix, i.e. the development of wind and solar power capabilities

In Europe, the market is favored by the support of government storage policies, while the regulations against emissions become increasingly harsher.

In the Asia-Pacific region, the two main driving forces are the significant increase of energy demand in the future, the energy security and the reliability of energy supply.

By issuing the ORDINANCE no. 28 of 28 August 2014 “regarding measures for the development of the infrastructure for electricity storage and balancing of the Romanian Power System, by the construction and operation with pumped hydro-power plants with an installed capacity exceeding 15 MW”, the Romanian Government address the private investments in the construction and operation of PSHPs, overtly declaring: “PSHPs are objectives of national interest and public utility” (art.3)

Fig. 3.12.Increase of investments in PSHPs worldwide

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Source: GMI

The development of the electricity generation capabilities using renewable sources and their integration in the RPS has been and will be enabled, to a great extent, by the structure of electricity production in Romania, respectively by the existence of the fuel mix. To ensure the system’s adequacy and the safe coverage of the electricity demand, the RPS should include a specific (outgoing) output (power) ensured by power plants, significantly higher than the input at the outgoing peak. Furthermore, the system operator should always have available an operational reserve able to adjust the balance at the continuous load variations and at the activation of the largest electricity generator unit in the system. These variations have increased considerably in the wake of the explosive growth of renewable resource-based electricity production, given that the availability of these energy manufacturers is limited and the production is uncontrollable, the associated reserve capacity being absolutely necessary to ensure the system adequacy.

The level of the losses in the grid network is influenced by the distance between the production plants and the consumption plants, i.e. by the manner in which load coverage is shared at the generator units existing in the system and the volume and destination of international energy exchanges. From this point of view, in the country’s Central and NW areas, Complexul Energetic Hunedoara S.A. is the only large electricity producer, with a total cumulative installation (installed capacity) of 1225 MW.

The project “4M – Market Coupling” for the coupling of the markets of the Czech Republic, Slovakia, Hungary and Romania, launched in 2014, will drive an increase of the cross-border flow at Romania’s Western border, with positive implications from the point of view of the electricity source found near the exchange interface. The increase of the border interconnection capacity on Romania’s Western interface, linked with the reduction of losses in the Power Transmission Grid, which are proportional with the distance between producers and consumers, require all the more so, prospectively, that the area should include a significant production and storage capability

4. Main technical, financial and contractual characteristics of the project

Romania is the only European country that, while having geo-morphological conditions particularly favorable for the construction and operation of pumped-storage hydropower plants, does not have such a plant, despite that there has been interest in this ever since 1975; this type of plant has been and continues to be imperatively necessary for the RPS.

Given the high degree of uncertainty regarding the evolution of the electricity demand, of the fuel prices on the international market, of the environmental requirements, etc., over time various PSHP construction scenarios have been analyzed, by considering the co-generation electricity and thermal power consumption forecasts on the long term.

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Furthermore, the sector dynamic regarding the diversification of primary energy resources, the sector reengineering and modernization, the advanced technologies of electric and thermal power products have also been considered.

4.1. Tarnița-Lăpuștești PSHP project history

Period Activities

1975 - 1985 ISPH performs analyses, site surveys and drawing-based studies for a PSHP-type project

1985 - 1988

Choice of the current site (existence of downstream reservoir and of the consumption unit).

1988 - 1994

Inquiries (call to tender) for the main energy equipment of Tarnița-Lăpuștești PSHP are analyzed, as received from world-reputed competitors in the sector, like Ansaldo GIE (Italy), Toshiba (Japan), Alsthom-Neyrpic (France), Hitachi (Japan), Mitsubishi (Japan).

1993

I.S.P.H. and GEOTEC draft the Geotechnical and hydro-geological investigation.

I.S.P.H. drafts the Economic Assessment Study for the PSHP functions in the RPS.

I.S.P.H. completes the pre-feasibility study for Tarnița – Lăpuștești PSHP, equipment version 4 x 250 MW. The study was endorsed by the Ministry of the Environment.

1994 I.S.P.H. drafts the Feasibility Study for the Pumped Hydropower Storage Plant (PSHP) Tarnița – Lăpuștești, equipment version 4 x 250 MW.

1995

Drafting of the documentation studies regarding the energy equipment and the manner of use, of operation.

Drafting of the Tender Books for equipment.

1999 - 2000

Based on a grant from the Japanese government, the Specialized Institute Electric Power Development Co. (E.P.D.C.) of Japan conducted a study based on the technical data of the previous documentations drafted by I.S.P.H., a study drawn up together with Toshiba.

2003 I.S.C.E. and I.S.P.H. drafted a pre-feasibility study for the construction of a PSHP at Tarnița – Lăpuștești, wherein they analyzed a possibility of

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equipment with three generator units, each at 330 MW.

2007

The consultant IPA/ Verbund/ Poyry develops a feasibility study in the World Bank SEEREM program of 2005, financed by IBRD.

The analysis is based on the previous solutions and the setup proposed by I.S.P.H. and E.P.D.C., with small changes helpful for the execution of the objective.

2008 I.S.P.H. updated the feasibility study, according to Government Decision 28/2008 (on the contents of feasibility studies for projects on public funding).

2009 The Romanian Government approved a Memorandum regarding the performance of the investment project Tarnița-Lăpuștești Pumped-Storage Hydropower Plant, a memorandum which is no longer legally effective.

2010

A consultant (consortium) was hired for the preparation of the process to attract investors; the consortium leader was Deloitte Consultanta S.R.L. The consortium also include Banca Comercială Română and HydroChina ZhongNan, and the subcontractors were Mușat&Asociații Sparl, Herbert Smith, Knight Piesold and Tempo Advertising. In February 2014, the contract made with this consortium expired and it was not extended by the contracting parties.

2013

The Romanian government approved a number of memos on the execution of the investment objective Tarnița-Lăpuștești Pumped-Storage Hydropower Plant, the baseline acts being the Memorandum of 4 September 2013, Memorandum of 16 October 2013 and Memorandum of 31 July 2014.

In November, based on the Memos approved by the Government, the project company HIDRO TARNIȚA S.A. was established, for the implementation of the Project.

2014

In March, I.S.P.H. updated the Feasibility Study they had drafted in 2008, from the point of view of the technical solutions, of the requirements in the clearances they obtained and of the cost estimates.

In July, HIDROELECTRICA S.A. sold to HIDRO TARNIȚA S.A. the investment in progress, including the technical, economic and other kind of documentations drafted for the substantiation, facilitation, approval, authorization, award and performance of the projects, as well as the clearances and permits obtained for the project with the transfer agreement of Hidroelectrica.

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4.2. Conclusions of the studies concerning Tarnița-Lăpuștești PSHP

The objective of constructing a pumped-storage high hydropower plant has been a priority concern of the specialist teams of the Romanian Power System (RPS) ever since 1975.

Thus, in 1975 – 1985, the Institute of Hydroelectric Studies and Design drafted site land surveys, site surveys and drawing-based studies for the construction of pumped-storage hydropower plants in Romania, considering:

• the necessity to cover the load peak; • the ever rising energy demand; • the possibility of energy exchange with the European energy systems; • the commissioning of the nuclear units at NPP Cernavodă(5 x 700MW).

A number of sites in our country were analyzed; of these, approx. 17 sites favorable to the construction of the pumped-storage hydropower plant were selected.

In 1993, I.S.P.H. drafted the pre-feasibility study for Tarnița – Lăpuștești PSHP, which laid down the technical specifications for constructions and for the electrical-mechanical equipment and analyzed the economic efficiency of the setup, by using the economic input of the assessment of the main functions held by PSHP in the RPS. In this stage of design, the work received the access agreement of the Ministry of the Environment.

The “Pre-feasibility Study” drafted by I.S.P.H. in December 1993 pointed out the technical and economic necessity of constructing in the Romanian Power System a pumped-storage setup, with weekly compensation (with 2 days off per week) and with a cumulative installation of 4 x 250 MW, the higher reservoir having a volume of 10 mil. m3 of water. The “Pre-feasibility study” also analyzed the 1000 MW option in two s500 MW-stages (2 x 500 MW), an options that turned out more economical given that the time between the stages is only 2 years.

In 1994, I.S.P.H. drafted the “Feasibility Study for the Tarnița – Lăpuștești Pumped-Storage Hydropower Plant (PSHP)”, based both on the technical-economic version selected in the pre-feasibility study – equipment version 4 x 250 MW in two 500MW-stages (2 x 500 MW), and on the equipment offers received from the above-mentioned potential suppliers.

In 1999 – 2000 the Specialized Institute Electric Power Development Co. (E.P.D.C.) of Japan, under a grant from the Japanese government, drafted a study based on the technical data of the previous documentations drafted by I.S.P.H., a study made together with Toshiba, which rekindled the interest in the design of a pumped-storage hydropower plant at Tarnița – Lăpuștești.

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4.2.1. Conclusions of the EPDC study.

The study drafted by EPDC for PSHP Tarnița proposes the alternative with the upper reservoir on the Lăpuștești plateau of the left side of the river Someșul Cald.

The proposed alternative describes the main parameters of total head, pumping and turbination flow rates at the plant, similar with those in the feasibility study drafted by I.S.P.H. – S.A. in 1994 and approved by CONEL (National Electricity Company).

The study shows that the optimum level for the construction of Tarnița-Lăpuștești PSHP is 1,000 MW with an operating capacity of 5 hours, uninterrupted; it is preferable that the work be commissioned as soon as possible. If the project performance is divided in two stages (stage I – generator units 1 and 2), from the point of view of the financial analysis it is recommended that stage II (generator units 3 and 4) be completed after 2 years.

The study by EPDC provides that two of the four generator units in the plant should be at a variable speed, which would allow the efficiency of the automated control function for the Romanian power system frequency. The study by EPDC considers that the Tarnița-Lăpuștești PSHP project is technical feasible and it is a very favorable site from an economic point of view, owing to the morphology and geologic structure of the left side, as well as to the existence of the lower reservoir.

In the year 2000, a recommendation was forwarded to the Romanian Government and CONEL, regarding the priority facilitation of this investment for the maximum cumulative installation of 1000 MW, which would be maintainable in terms of economic-financial efficiency, by cooperation with the neighboring countries and, also, by the regulations regarding the revenues earned from the services this plant could generated in the national power system or in the power systems of the neighboring countries. Other arguments shown in the EPDC study in favor of the approach of the construction of Tarnița-Lăpuștești PSHP and its commissioning in 2010 are the following:

• reduction of the natural gas consumption, which means import; 1000 MW in PSHP replaces 2000 MW capacities in gas turbines

• reduction of greenhouse gas emissions, owing to the replacement of gas turbines (if the project Tarnița-Lăpuștești PSHP were not achieved, its role would be taken over by a gas-turbine power plant and there would be emissions of approx. 682,000 t CO2 per year and 34.10 x 106 t CO2 in 50 years in the atmosphere);

• the use of renewable energy resources, by the increase of the energy production in the classic hydropower plants provided with large reservoirs (their exploitation at levels as high as possible);

• it fits in the development strategy for the Romanian power system and in the strategy for the integration in UCPTE, both by the system services, and by the reduction of fuel consumption in the thermal-power plants to deliver the energy required for water pumping in the upper reservoir, during the low load times;

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• there are no issues of population displacement at the project site

4.2.2.Conclusions from the IPA/Verbund study:

The preliminary studies regarding the development of the electricity market in Romania and South-East Europe have shown that a reasonable dimension of the pumped-storage Tarnița project would be an installed capacity ranging between 500 MW and 1000 MW. Since the assessment of the electricity market development trend for the next 20 years is difficult, the decision was made to approach a two-stage project.

The power plant housed in the cavern will be equipped with two sets of pump-turbines, each of them having a power of 250 MW and each set having its own hydraulic circuit (pressure tunnel, plant housed in cavern, escape tunnel). A staged solution was proposed, so as to allow a flexible adaptation of the project to the market conditions of South-East Europe.

Following Romania’s accession to the UCTE, the transmission interconnection with the neighboring countries will increase, and the functioning of the SE Europe market will improve significantly the economic market conditions across the region.

All these factors could allow the proposed pumped-storage plant to reach higher levels of income, owing to the potential existence of a higher requirement of system flexibility (peak energy and auxiliary services).

4.2.3.Conclusions from the Study drafted by ISPH in 2008

The comparative analysis of the alternatives studied in this project has shown that the alternative with the best indicators is the one called “Alternative II- A”, which provides for the performance of the works in 7 years, and the achievement of the objective in two stages, equipping with 4 x 250 MW classic reversible generator units, with partial commissioning (2 generator units) at the end of the fifth year.

4.2.4.Conclusions from the study drafted by Deloitte in 2010

In general, the Deloitte study stated:

For Romania, the hydropower potential is a long-term alternative for the development of the energy sector, given the limited resources of raw energy materials, as well as the need to obtain inexpensive energy that does not generate greenhouse gas.

The Tarnița-Lăpuștești PSHP project is essential in the context of a continuously rising portfolio of uncontrollable production, which requires the installation of additional offsetting

pg. 43

(balancing) capabilities, which will be remunerated on markets of technological systems services, markets of capacities, but also on the balancing market.

The power plant would be a strategic provider of energy / system services in the NW of Romania, an area facing a shortage in the generation of electric power.

PSHP Tarnița-Lăpuștești would become an important provider of system services in Romania and, possibly, in several neighboring countries.

4.2.5. Conclusions from the Study drafted by ISPH in 2014

The feasibility study verified and approved the conclusions of the previous studies and improved the initial project, by adopting a two-line solution for the high pressure tunnel, which would also allow the project staging

Comparison of the relevant studies for the Tarnița –Lăpuștești PSHP project

Description FS EPDC 1999

4x250 MW

FS ISCE-2003

4x250MW

FS ISPH 2008

4x250MW

FS ISPH 2014

4x250 MW

(thousand euro) (thousand euro) (thousand euro) (thousand euro)

Total constructions 154,700 313,000 510,849 446,759

Total equipment 260,700 308,000 316,778 369,954

Power exhaustion 75,000 83,000 135,000 149,200

Technical design and assistance 48,800 33,000 50,373 50,517

Other costs 60,800 108,000 151,000 130,200

TOTAL INVESTMENT 600,000 845,000 1,164,000 1,150,500

Comparison FS EPDC-Japan FS ISCE FS ISPH 2008 FS ISPH 2014

Best site Tarnița-Lăpuștești

Tarnița-Lăpuștești

Tarnița-Lăpuștești

Tarnița-Lăpuștești

Installed capacity (MW) 1000 1000 1000 1000

Reversible pump-turbine equipment

Francis Francis Francis Francis

pg. 44

Pump exercise (cycle) weekly weekly weekly weekly

Upper reservoir Lăpuștești –level mNNR (maximum normal retention level)

1085 1085 1085 1085

Lower reservoir Tarnița –level mNNR

521.5 521.5 521.5 521.5

Height of upper reservoir 45 45 40 40

Dam level-mNNR 1088 1088 1086.5 1086.5

Storage capacity –million cubic meters

10 10 10 10

Intake – ‘polygon’ tupe – pcs 1 1 1 2

Underground plant (m) L=157, l=22, H=45

L=120 l=23, H=47

L=120 l=23, H=48

L=120 l=23, H=48

Transformer room L=126, l=15, H=20

L=117 l=19, H=25

L=117 l=19,H=48

L=117,l=19,H=48

High pressure tunnelne–meters 1100 1100 1100 2 fire x 1100

High pressure tunnel diameter -meters

6 6 6 4.3

Escape tunnel -meters 2 x1350 2 x1350 2 x1350 2 x1350

Escape tunnel diameter -meters 6.2 6.2 6.2 6.2

4.3 Project description within the context of Someș river hydropower setup

The previous studies considered several sites (approx. 17) and the optimal alternative for the PSHP was selected in the county Cluj, at approx. 30 km from the city of Cluj – Napoca, on the left side of the Someșul Cald valley, next to the Tarnița reservoir, which is the lower reservoir, and to the locality Lăpuștești, found on the same-name plateau, at the altitude of 1030 – 1090 MASAL.

Mainly, the setup plan includes a higher reservoir, the Lăpuștești reservoir which needs to be executed, and an existing lower reservoir – the Tarnița reservoir. The volume of the lower reservoir is 74 million cubic meters, with a live storage of 15 million cubic meters – above the

pg. 45

minimum operating altitude of 514 MASL, hence usable for the pumped-storage plant – 521 MASL being the level of normal retention.

The advantages of the site are given by:

Parameter U.M. Value

• NNR higher reservoir (Lăpuşteşti reservoir) MASL 1,086.00

• Level of center of gravity (Lăpuşteşti reservoir) MASL 1,071.00

• Minimum level of higher reservoir (Lăpuşteşti reservoir) MASL 1,053.50

• NNR lower reservoir (Tarniţa reservoir) MASL 521.50

• Level of center of gravity (Tarniţa reservoir) MASL 518.00

• Minimum level of energy exploitation (Tarniţa reservoir) MASL 514.00

• Higher reservoir volume (Lăpuşteşti reservoir) million m3

10.00

• Maximum gross head (1086-514) m 572.00

• Mean gross head (1086-521.50) m 564.50

• Minimum gross head (1053.50-521.50) m 532.00

• Maximum turbine flow (turbination flow) m3/s 4 x 53

• Maximum flow rate at pumping m3/s 4 x 38

• Equipment: 4 reversible pump-turbine generator units:

in generator system

in engine system

MVA

MW

4 x 280

4 x 250

• Installed capacity MW 1.000

• Pump exercise (cycle) weekly

Mean rainfall in Romania mm/year 637

Mean rainfall in the area mm/year 900

Mean evaporation in the area mm/an 500

pg. 46

• the existence of the lower reservoir – the Tarniţa reservoir with NNR = 521.50 MASL and NmE (minimum level of exploitation) = 514.00 MASL; (reduction of investment costs by 30%)

• existence of the Lăpuşteşti plateau at an average altitude of 1070 MASL on the left side of the Someșul Cald river, adjacent to the existing Tarniţa reservoir; this plateau is appropriate for the execution of the upper reservoir (Lăpuşteşti reservoir);

• the possibility to obtain a mean gross head of 564.5 m between the upper reservoir and the lower reservoir, which allows the reduction of the upper reservoir volume

4.3.1. Main object of the PSHP

The Tarnița – Lăpuștești PSHP projects has the following main objects:

1) Upper reservoir (Lăpuşteşti reservoir) with a volume of 10 million m3 found on the Lăpuşteşti plateau (NNR 1086.00 MASL) and obtained by digging and embankments, so that the volume of the diggings should be close, in terms of value, with the volume of the dam embankments;

Fig.4.1 Lăpuștești plateau

Fig.4.2. Tarnița Reservoir

2) Lower reservoir (Tarniţa reservoir) with a live storage of 15 million m3 of the total 70 million m3, an existing objective, found on the Someșul Cald river at the thalweg level 441.00 MASL and made from the Tarnița dam from double curvature reinforced concrete (NNR at the altitude of 521.50 MASL and minimum level of exploitation 514.00 MASL);

3) Power plant, an underground construction placed on the left side of the Tarniţa reservoir, made from the machine room and the transformer cavern, with access and connecting tunnels in between, tunnels for aspirators, valve shafts, cable tunnels and access for operating personnel. Electric-mechanical equipment 4 reversible generator units, each of them at 250 MW.

pg. 47

Fig.4.3. Layout -Reversible pump-turbine generator unit

Source:Andritz

4) Branching, representing the works of hydraulic transmission between the upper reservoir and the plant and between the plant and the lower reservoir, including:

the high pressure tunnel (2 lines), underground construction at 45° between the upper reservoir and the plant building (Length:2 lines x 1096 m; Diameter Ø = 4.30 m);

the low pressure tunnels (2 lines), underground constructions required for the evacuation of water passed through the turbine and the intake of the pumped water (Length: 2 lines x 1,325 m; D, Ø = 6.20 m).

4.3.2. Functional characteristics

Since this is a hydropower plant, the PSHP has high maneuverability and, thus, is able to respond promptly to the load fluctuations. The period of operation in turbination conditions depends on the duration of the load peak period and on the consumption during the day.

The period of operation in pumping conditions depends on the duration of the low load period during the night and in the non-working days. The gap of this period of operation (pump – turbine condition) has determined the volume of the upper reservoir (10 million m3).

The flow rate of the hydro aggregate is different in turbine-working conditions as compared with the one in the pumping conditions. To prevent hydraulic shocks in the pumping conditions, caused by some dysfunctionalities that may occur in the source of nuclear, thermal, wind power, the turbine- pump aggregate should be equipped with the capability of adjusting the absorbed power.

pg. 48

Fig.4.4. Synoptic plan of Tarnița-Lăpuștești PSHP

Source: ISPH

4.3.3. General context of the site and operation of the Tarnița-Lăpuștești PSHP

4.3.3.1.Hydropower setup of the Someş river

The Someș catchment area is represented by a cascade of hydropower plants executed in 8 steps, including 5 dams, 8 hydropower plants and more than 30 km of main and secondary penstocks. The water volume accumulated in the 5 reservoirs amounts to approx. 290 million m3.

The 8 hydropower plants have an installed capacity of 300 MW and they generate electric power of 534 million KWh, in an average water year. The first step in the cascade is the dam with the Fântânele Reservoir and Mărişelu Hydropower Plant.

The Fântânele Dam is found on Someşul Cald, downstream the locality Beliş, at the meeting with the Bătrâna creek on the left side and upstream the meeting with Valea Rea on the right side. The access to the dam, from Cluj, is possible from the National Road (DN) Cluj-Huedin and then by a commune road: Huedin-Calatele-Beliş-Fântânele-Albac, or by the road Cluj-Gilău-Tarniţa-Mărişelu-Fântânele-Beliş. The dam is 92 m high, and it is made from rockfills with reinforced concrete apron on the upstream face. The Fântânele reservoir has a total volume of approx. 213 million m3, which allows the multi-annual regulation of an average

pg. 49

flow rate of approx. 12m3/s, the generation of electric power, while also offering protection from high waters. Flow rate processing is performed in the Mărişelu underground plant.

Fig. 4.5.Fântânele Reservoir

Source: Hidroelectrica

The underground Mărișelu hydropower plant-is placed at approx. 300 m upstream the meeting of Someșul Cald with Lesu creek, the main access being ensured by a single-path auto tunnel.

The plant is equipped with 3 hydro aggregates, actuated by Romanian-manufactured Francis turbines, with a uniform power of 75 MW, ensuring the production of an annual energy of 390 GWh and enabling the supply of system services within optimal parameters.

By the 220 kV power substation, the generated energy is delivered to the Romanian power system. The Marișelu hydropower plant was designed to operate in the load peak hours of the RPS; the water processed through the turbines therein is discharged in the Tarnița reservoir by an underground escape tunnel in which the flow occurs with the free surface, the discharge occurring at an altitude higher than the normal retention level of the Tarnița reservoir (NNR = 521.50 MASL);

We note that, at present, Marișelu HPP is able to provide system services and that the following aspects are defined in the Fântânele reservoir:

warning levels – levels below which, usually, no commercial offer can be made;

safety levels – levels that need to be maintained for the safety of the RPS;

pg. 50

Fig.4.6. Machine room at the Marișelu Power Plant

Source: Hidroelectrica

The Tarnița Reservoir (live storage of the reservoir, Vu = 14.6 million m3) is the second as size and importance, after the Fântânele reservoir; its role is to take over the area differences during high water periods (for the remaining part of the year, it is very low) and to satisfy practically continuously the water requirements downstream, with a quasi-constant water flow rate, Q ~ 9 m3/s (servitude flow rate of at least 6.0 m3/s on the river Someșul Mic in the Cluj-Napoca segment and approx. 3.0 m3/s the necessary drinking and industrial water downstream flow rate

Fig.4.7. Tarnița Reservoir

Source Hydropower Plant Tarnița

pg. 51

We note that the Tarnița hydropower plant needs to operate mandatorily at a 2-day interval (exceptionally at 3 days), to ensure the utilities; this operation is necessary for:

• the existing low live storage in the Someşul Cald reservoir, downstream Tarnița, which is usually exploited between 440.50 and 441.00 MASL (NNR) ;

• the avoidance of silting of the Gilău reservoir, which supplies water to the Cluj-Napoca city water plant, as well as to other localities downstream.

Since the water flow rates in the Someșul Rece catchment area and in the Iara catchment area are derived from the Fântânele and Tarnița reservoirs, practically the Tarnița reservoir ensures the flow rate of 9.0 m3/s, the reservoirs downstream having only the purpose of regulating the flow rate processed by the Tarnița Hydropower Plant, downstream there is no additional flow rate input. The Tarnița Hydropower Plant was designed to operate in the RPS load peak hours; it generated approx. 80 GWh/year, at the normal retention level NNR =521.5MASL The reservoirs and plants downstream the Tarniţa Hydropower Plant cannot be influenced negatively by the existence of Lăpuștești PSHP; practically, they will have the same conditions of operation as they do now.

The functioning of the hydro aggregates in pumping and turbine processing conditions was analyzed, for the various alternatives of exploitation, further differentiated from the point of view of energy efficiency, according to the energy efficiency criterion of the PSHP (recovery coefficient, a = turbined energy/ energy used at pumping), used for the spalized studies. In these operating conditions, at the functioning with all the hydroaggregates, of the Lăpuștești PSHP, the lower level variations in the Tarnița reservoir lead to negligible energy losses, less than 1GWh/year.

The Someşul Cald Hydropower Setup, the third step in the cascade, includes mainly the dam and the reservoir, as well as the hydropower plant. The Someşul Cald dam, placed on the river Someşul Cald, is a gravity retaining dam made from concrete, with a height of 33.5 m and a crest-of-wave length of approx. 130 m. The Someşul Cald reservoir, with a total volume of approx. 7.5 million m3, is also a source of water supply to the Gilău treatment plant, which supplies drinking and industrial water to the city of Cluj-Napoca.

The Someșul Cald Hydropower Plant is a plant at the foot of the dam, with a buried infrastructure of the hydraulic circuit; it is above ground solely at the level of the machine room. It is equipped with a Kaplan vertical axis generator unit of 12 MW. The operating regime depends on the operating conditions of the Tarnița plant, the capacity of attenuation of the Someșul Cald reservoir being low.

The feasibility studies analyzed the influence of the operation of Tarnița – Lăpuștești PSHP on the system existing on Someșul Cald and the necessity of the coordination, while operating, with the hydropower plants Marișelu, Tarnița, Someșul Cald, Gilău 1, 2, Floreşti 1, 2, Cluj 1, with all the technical-economic implications following therefrom.

pg. 52

The commissioning of Tarnița –Lăpuștești PSHP may take over some of the system responsibilities currently conducted by Marinescu Hydropower Plant, and the water volumes, kept at present in the Fântânele reservoir for system services, will be usable especially for the generation of day energy and they will yield benefits on the whole cascade, by the use of the additionally generated energy and by the supply of water. As regards the other functions: flow rate regulations, high water attenuation, there are no important changes, should the Lăpuștești PSHP be commissioned, because this type of setup does not consume water and does not interfere with the hydrology of the area.

4.3.3.2. Conclusions

The occurrence of PSHP Tarniţa – Lăpușteștihas little influence on the functioning of Someşul hydropower cascade. The consideration of an optimization and tandem operation of Tarnița Hydropower Plant is absolutely necessary, depending on PSHP Tarnița-Lăpușteștiexploitation levels.

As regards the losses in the system, owing to the operation of Tarniţa – Lăpuștești PSHP, they are localized at the Tarnița Hydropower Plant; they are caused by the exploitation of the Tarnița reservoir at levels slightly lower than those at present and they are assessed at maximum 1.0 GWh/year, which is negligible when compared with the benefits Tarniţa – Lăpuștești PSHP generates for the RPS.

Fig.4.8. Single-line diagram of the Someș-Marișelu Hydroelectric Setup and the site of the PSHP

Between the altitude of 900.00 MASL (Fântânele) and the one of 441.00 MASL (Tarniţa), the hydropower potential was set up in two steps of fall (head) Mărişelu HPP and Tarniţa HPP, with the following main characteristics

TARNIȚALĂPUȘT

Fântânele

Marișelu HPP Tarniț

TARNIȚA

GILĂU I FLORESTI

FLORESTI

GILĂ

SOMEȘUL

LEGEND Plan of setup in operation SC

TarnițaLăpuștești PSHP – new

pg. 53

Table 4.1

Parameters CHE Mărişelu

CHE Tarniţa

Upstream altitude (NNR) (MASL) 991.00 521.50

Downstream altitude (MASL) 521.50 441.00

Gross head (m) 469.50 80.50

Average intake flow (m3/s) 12.7 14.9

Installed flow rate (m3/s) 60.0 68.0

Installed capacity (MW) 220.0 45.0

Annual mean energy production (GWh/year)

390.0 80.0

Equipment (number and type of generator units)

3 x Francis 2 x Francis

Year of commissioning 1977 1974

Reservoir live storage (million m3) 200 15

Downstream Tarniţa HPP, between the altitudes of 441.00 MASL and 362.00 MASL, 6 steps of head (5 HPPs and 1 SHPP (small hydropower plant) with the following main characteristics:

Parameters

HPP

Someşul Cald

HPP

Gilău I

HPP

Gilău II

HPP

Floreşti I

HPP

Floreşti II

SHPP

Cluj I

Upstream altitude (MASL)

441.00 420.00 405.00 389.50 374.00 347.30

Downstream altitude (MASL)

420.00 405.00 389.50 374.00 367.00 341.60

Gross head (m) 21.00 15.00 15.50 15.50 7.00 5.70

pg. 54

Installed flow rate (m3/s)

70.00 60.00 60.00 60.00 27.00 24.00

Installed capacity (MW)

12.00 6.90 6.90 6.90 1.30 0.94

Annual mean energy production (GWh/year)

19.40 11.60 12.20 12.20 5.20 3.80

Equipment (no. and type of generator units)

1 KVB 13÷21

1 KVB 6÷15

2 EOS/1100

1 KVB 6÷15

2 EOS/1100

1 KVB 6÷15

2 EOS/1100

6 EOS/1100

6 EOS/1100

Year of commissioning

1983 1977 1986 1987 1986 1988

Specialized calculations show that the invested capital is fully recovered in all the analyzed alternatives. The final choice of the constructive solution needs to consider also the method of entry in the system for the pumped-storage hydropower plant, as well as the latest evolutions of the 400kW grid in the area, of the energy market and of the energy services.

Fig.4.9. Tarnița power plant and dam

Source: Hidroelectrica

The investment site is spread across the administrative territory of four communes in the Cluj county, namely: Râșca, Căpușu Mare, Mărișel and Gilău, for the most part outside of the built-up areas.

pg. 55

4.4 Technical, legal data, supporting studies, workloads

a) Area and site

The pumped-storage hydropower plant is placed in county Cluj, at approx. 30 km from the locality Cluj-Napoca, on the valley of the river Someșul Cald, left side adjacent to the existing Tarnița reservoir and near the locality Lăpuștești found on the plateau of the flank, at an altitude difference of approx. 550 m from the maximum level of the Tarnița reservoir. The investment objective is near the existing Tarnița hydropower plant setup.

b)Legal status of the land to be occupied

SC INTER PROIECT SRL Cluj-Napoca drafted the “Regional Urban Planning Tarniţa – Lăpuşeşti PSHP – objective of national interest”. This town planning/land use planning documentation was accepted by the beneficiary and received from the Cluj County Council – the Favorable Endorsement of the Chief Architect no. 27 / 21.12.2012.

At the time of the drafting (September 2012) and at the level of detail specific to such a documentation, the following aspects were noted:

• the investment is to be conducted on the administrative territory of the communes Râşca, Căpuşu Mare, Mărişel and Gilău of Cluj County, mostly on the outside of the built-up areas;

• the use of the land affected by the investment is diverse: forests, areas with vegetation (bushwood and thornbush, forest land), agricultural (grazing land, grass land, arable land), other (non-productive, water, roads);

• the said land is both under public ownership and under private ownership.

The task of identifying the properties and the owners of the said land, regardless of the category of use, belongs to the beneficiary. As regards the land included in the national forestry estate, the documentation for the withdrawal from forestry use shall specify precisely their sites (forestry district/ production unit/ management unit). The feasibility study drafted by ISPH in 2008 for Tarniţa – Lăpuşeşti PSHP included amendments by the above mentioned regional planning.

The amendments to the feasibility study resulted both in the wake of the discussions with the Town Planning and Land Management Commission in the Cluj County Council and in the wake of the discussions with various endorsing authorities.

The drafting party considers that the changes to the feasibility study are meant to correlate it with the situation on site, but also to optimize the spatial spread of the investment objectives, for their optimum integration in the indicated area.

pg. 56

These amendments had an impact on the values of the land areas required for the execution of the objective and they are the following:

• the FS proposed that, at the tail of the Tarnița reservoir, up to the altitude of 550 MASL, a stockpile (a dump) should be set up for the excavated rock required for the execution of the under- and above-ground constructions, with a total volume of approx. 600,000 m3; this would have meant that both the county road and Someșul Cald be diverted; the latter by channeling through an approx. 210m long tunnel with a diameter of 3.9m – the Regional Planning proposes that the permanent stockpile be transformed in a provisory rock storage zone with an area of 47,352 sqm. Later, the rock will be used for road coating or for other purposes.

• the 600,000 m3 of rock will not be entirely in the dump at the same time, because the site’s storage capacity is approx. 250,000 m3. As the overburden is stored in the stockpile, it needs to be evacuated and used for road coating or other purposes, according to the opportunities at hand. In the end, the zone will be restored to its classification.

• the two dumps on the Lăpuștești plateau were to be set up at the north, respectively north-east of the upper reservoir, thus altering an important area, including by the clearing of a significant forest area – the Regional Planning would provide that the two dumps be brought together in a single one, with an area of 585,154 sqm, and repositioned on the valley of the Fărcașa creek, for the purpose of reducing to the minimum the destruction of the existing forestry estate. The volume of dumped overburden will be approx. 2,400,000 m3 The valley ensures favorable conditions for the integration of the dump in the mountain landscape, according to a specialized study.

• the 2014 FS of ISPH included the execution of the connecting road between the lower reservoir (Tarnița) and the upper reservoir (Lăpuștești) via a new side road, which, apart from the toilsome execution, would have also included the clearing of the forest – the Regional Planning stipulated the rehabilitation/modernization of the existing forest road currently connecting the two zones, thus avoiding the forest clearing. The above-mentioned urban planning/land development documentation shows that the

total land area required for the execution of the investment is 205.07 ha.

By category of use, the area is divided as follows:

• forests.......................................................................16.13 ha; • vegetation areas........................................................3.91 ha; • agricultural................................................................148.25 ha; • other...........................................................................36.78 ha.

The area necessary to be occupied permanently 100.798 ha, the area to be occupied temporarily 104.271 ha.

Owing to the hydro-power setup of the investment, most of its objectives will be placed outside built-up areas. Nevertheless, some constructions may only be erected in the built-up area, so the introduction of the following zones in the built-up area is proposed:

• dam keeper house 5,000 sqm;

pg. 57

• dam keeper house and repairs and maintenance unit 8,000 sqm; • technical unit 30,595 sqm.

Therefore, the resulting permanent land in the built-up area amounts to 43,595 sqm

Given that the execution of the investment requires at least 7 years, a provisional built-up area is proposed, for the site management, which will include the following zones:

• process (technological) platform (Lăpuștești plateau and the power plant) 44,000 sqm • site management (Lăpuștești settlement) 22,500 sqm • lower intake process (technological) platform 11,226 sqm

The resulting temporary occupied built-up area is 77,726 sqm

At the completion of the investment, by the beneficiary’s care, a regional urban planning will be undertaken and will assign a new function to the areas occupied with the site management (process platforms or social organizations.). The same documentation or a higher documentation (General Urban Planning) will also study the opportunity of keeping these zones in the built-up area.

Name of the zone Total permanent temporary

Higher reservoir dump 632,506 632,506

Lower reservoir dump 585,154 585,154

Lower provisional dump 47,352 47,352

Company accommodation 13,000 13,000

Dam keeper house 5,000 5,000

Repairs and maintenance units 8,000 8,000

Process (technological) platform 44,000 44,000

Lăpuștești plateau 25,000 25,000

Power plant 19,000 19,000

Technical unit 30,595 30,595

Higher reservoir 617,284 617,284

Water surface area 385,502 385,502

Dam 231,782 231,782

Site management 60,350 60,350

Lăpuștești settlement 22,500 22,500

pg. 58

Marișel settlement 37,850 37,850

Dealu Mare Crushing Plant 124,420 124,420

Lower intake process platform 11,226 11,226

Dealu Mare crushing aggregate pit 135,214 135,214

Green shelter belt 34,996 34,996

Roads in the regulated area (Regional Urban Planning)

347,100 347,100

TOTAL sqm 2,050,691 1,007,979 1,042,712

TOTAL ha 205,069 100,798 104,271

c) Support studies

Topographic surveys-for the topographic studies, maps at the scales 1 : 25,000; 1 : 10,000 and topographic site plans at the scales 1 : 1,000 and 1 : 500 were used.

Geotechnical investigations-The investigations performed in 1991-1994 for the Tarnița – Lăpuștești PSHP sought to clarify the geologic data for the site of the Lăpuștești upper catchment area, the pressure node and the construction materials. The set-up plan for this work provides for:

• The Lăpuștești upper reservoir; • The Tarnița-Lăpuștești pressure node.

For the power plant, a survey tunnel was built, with a length of approx. 400 m toward the zone of the cavern; for the other objects, investigative (survey) drilling and sampling for laboratory tests were performed.

Geological surveys-performed for Tarnița – Lăpuștești PSHP – sought to clarify the geological data for the site of the Lăpuștești upper catchment area, the pressure node and the construction materials. For the power plant itself a geological survey tunnel was executed – 400m long. The geotechnical characterization of the rock complex in the site of the upper catchment area and of the pressure node was conducted according to the geotechnical and geo-physical characterization in situ and in the laboratory, as well as by the assimilation of values obtained on geotechnically tested similar rocks in Someș-Marișel hydro-power reservoir.

The surveys showed that, in the area of the set-up, the developing geological systems belong to the Gilău crystalline formations and Muntele Mare granite, which are also crossed by andesite intrusions originating in the eruptive Neogene structures. The quaternary deposits have a limited development, with large thicknesses on the plateaus (colluvium) and on the gentle slopes (diluvium). Sometimes, there is no diluvium on the abrupt flanks.

pg. 59

General geological data – In the area of the set-up, the developing geological formations belong to the Gilău crystalline and Muntele Mare granite, in turn crossed by andesite intrusion from the eruptive Neogene structures. The quaternary deposits have a limited development, with large thicknesses on the plateaus (colluvium) and on the gentle sloping flanks (diluvium). At times, there is no diluvium on the abrupt flanks.

The area’s general structure and tectonics-In the crystalline-granite contact zone, the structure shows tectonic accidents generators of limited extension faults. The main tectonic system has a W-E orientation which is overlapped by a second one, with a NW-SE orientation, practically parallel to the general structure of the zone.

Current physical-geological phenomena – In the plateau areas, where the upper catchment area is found, there are no signs of landslides or of recontouring of the colluvial formations. On the high slopes, there are local phenomena of dislodgement of the removed rock material.

Seismic intensity of the zone-According to S.R.11100/1 – 93 – Romania seismic zoning, the site is in grade 6 area of macro-seismic intensity on the MSK scale. According to the regulation P100 – 1/2006, the study area is in the zone matched by a peak value of ground acceleration, for earthquake design, ag for earthquakes, with the average return period (average return interval) ARP = 100 years, ag = 0.08 g and a (corner) control period Tc of the response range Tc = 0.7 sec.

Construction materials-For the execution of the Lăpuștești upper reservoir area, the removed rock materials from the reservoir premises up to the altitude of 1,055 MASL will be used. Specific rock tests were performed on this material (colluvium, altered and non-altered rock). The results of these tests promoted the conclusion that the upper reservoir deposits are optimal for implementation and, in the phase of execution, test tracks are to be set up. The nearest source of crushing aggregates for concrete in the zone is the Dealu Mare granite massif, at approx. 6 km from Lăpuștești, at the same altitude with the upper reservoir. The granite in the Dealu Mare site is of the Muntele Mare type, being made from a quartz-feldspar mass in which muscovite lamellas can be seen.

The laboratory tests conducted on the crushing aggregates led to the conclusion that the Muntele Mare granite can be used as a support layer, connecting layer and filter (screen) at the asphalt concrete covers, for the upper sealing layers. The calculation of reserves showed a live storage (working volume) of more than 1.5 million m3. The sand, which is rather missing from the area, can be obtained by the braking and crushing of some types. Alluvial sand can be obtained from the Aușeu gravel pit found on Crișul Repede at approx. 120 m from the site of the upper catchment area.

Lăpuștești Reservoir (Upper Reservoir) The Lăpuşteşti reservoir is found on the Lăpuștești plateau on the left bank of the Tarniţa reservoir and at approx. 2 km East from the same-name village. Previous studies indicated the reservoir’s site and the position in plane

pg. 60

according to the existing geo-morphological conditions. Following the studies conducted over time, the option with an accumulated volume of 10 million m3 of water was shown as being the most reasonable one from a technical-economic point of view, being also the most frequently used worldwide at the cumulative installation and the related fall (head).

pg. 61

Fig.4.10. Plan view of the Lăpuștești upper reservoir

Source: ISPH

The upper part of the Lăpuşteşti hill is in the form of a plateau, the maximum altitude of the land being approx. 1086,00 MASL. The plateau is bordered by:

• at the south of the plateau, the land descends toward the Someş river valley; • at the west, the Mărăşeni creek; • at the east, the site is limited by the Fărcaşa valley, a valley where the excess

excavated volume will be piled; • at the north, there are two valley whose creeks flow in the Râșca stream.

Constructive solution-From a constructive point of view, this higher reservoir is executed as a mixed solution (cut-and-fill). The earthworks seek optimal compensation, i.e. the material resulting from the useful excavations should be used in the construction of the reservoir’s contour dams. There are three types of sections:

• with rockfills upstream and colluviums downstream; • with rockfills alone; • completely in the cut.

In cross-section, the dam has heights of up to 40m with the upstream slope 1:1,8, and the downstream slope 1:2,80, with 6m berms at the altitude 1070.00 MASL and 1055,00 MASL.

The upstream prisms and the south side of the dam will be made from rockfills either from altered rock or from whole rock of high geotechnical quality, draining and drained, laid on the properly prepared foundation rock. The downstream part is executed from colluvium inside which two draining layers are specified, at the altitudes of 1055.00 MASL and 1070.00 MASL and a draining prism at the downstream foot The sealing of the upstream face and of

Land limit according to Regional Urban Planning Access hole and measuring weir Dam house

Access tunnel

High pressure tunnel line 1

High pressure tunnel line 2

Intake valve house

To the dump

Road of connection to the crown

Access ramp to the reservoir

Overflow discharger

Ditches

Crown altitude

Access tunnel

Longitudinal downstream drain

pg. 62

the reservoir bottom is made with a 16cm-thick bituminous concrete cover, executed in 3 layers, on a support layer of keystone. Between the two prisms (compacted rockfills upstream and colluvium downstream), a quasi-vertical, 3m-thick drain is specified. The role of this layer is twofold:

• drains downstream the prism from rockfills; • prevents the rise of the piezometric level in the earthy material of the downstream

prism. This drain of crushing aggregates will discharge in the draining cushion at the base.

The water will be drained from the reservoir landtake through the drain network existing under the bitumen coat, driven through the perimeter collector to the inspection tunnels and then eliminated outside the works, on the adjacent valleys. Two draining elements are specified on the reservoir bottom:

• a system of 300mm D pipes placed at a distance of 20m, which discharges in the perimeter collector;

• a system of 50mm D pipes placed in the support layer of the asphalt carpet, which also discharges in the perimeter collector. The length of the perimeter collector is 2380.00 m, and access is possible through 5

inspection tunnel with a total length of 680.00 m.

The reservoir is provided with a safety overflow evacuator, in the event where the water continues to be pumped in the reservoir above the maximum level of normal operation and the level detector does not turn off the pumps automatically.

The funnel spillway discharges in the Fărcaş creek which, in turn, flows in the Tarniţa reservoir.

The high water spillway was sized for a flow rate equal with the pumped one: 152.00 m3/s. The result was a funnel spillway with an approx. 45.00m high tower and a 23.00m diameter of the funnel, followed by a horizontal tunnel of approx. 178.00m, laid out in a trench excavated in rock. At the end of the pipe, there is a trampoline/thrower, for the purpose of clearing the spray/jet impact zone.

The main characteristics of the upper reservoir:

• Live storage (working volume) - 10 million m3 • Crown axis length - 2715.00 m • Crown altitude -1086.50 MASL • NNR - 1086.00 MASL • Minimum level of exploitation - 1053.50 MASL • Volume at the minimum level of exploitation - 0.35 million m3 • Minimum altitude of reservoir bottom level - 1052.00 MASL • Surface of reservoir bottom - 234.00 thousand sqm • Reservoir surface at the altitude of 1086.50 MASL - 388,75 thousand sqm • Volume of excavations in the colluvium - 3050.00 thousand m3

pg. 63

• Volume of excavations in altered rock - 1869.00 thousand m3 • Volume of excavations in the bedding rock - 1717.00 thousand m3 • Rockfills - 2587.00 thousand m3 • Colluvial fills - 1747.00 thousand m3 • Filters - 623.20 thousand m3 • Cover support - 210.00 thousand m3 • Surface of the watertight facing - 433.00 thousand sqm • Width at the crown - 7.00 m • Upstream slope - 1:1.8 • Downstream slope - 1:1.8/1:2.8 with 6.00 berms • Dump volume - 2369.60 thousand m3

In the phase I of execution of the upper reservoir, the excavated material will be transported in the dump. When phase II and phase III are approached, the setting surface relating to phase I will be prepared in parallel. After this is finished, the execution of the high water spillway will be started, so that the fill operations are not stalled. The material excavated in the second and third phase will be transported directly in the phase I dam zone. The resulting excess material (2369.60 thousand m3) will be deposited in a dump at the east of the upper reservoir, a site in accordance with the “Tarnița – Lăpuștești PSHP Regional Urban Planning”.

Branching-The drafting of the project was based on maps and topographic surveys, geological reports, hydrological data and studies regarding the effects of non-permanent movements in the case of set-ups equipped with reversible aggregates (pump-turbine).

The initial construction solution was reanalyzed, optimized, and the following changes were included in the ISPH FS of 2014, as compared with the ISPH FS of 2008:

• two polygonal intakes were adopted, for the Lăpuşteşti upper reservoir, with a screen inlet speed decreased at 1m/s;

• the valve house equipped with cut-off plate in wet pit was abandoned and the solution with butterfly valves mounted in two caverns excavated on the route of the high pressure tunnel was adopted;

• instead of a tunnel with a Di= 6.00 m, the solution with two lines Di= 4.30 m is adopted.

pg. 64

Fig.4.11. Plan view high pressure branching

Source: ISPH

The following aspects were considered:

• the pit for the cut-off plates, with a considerable height of approx. 80 m, would have had to be executed for half of the height in excavation and for the other half embedded in the dam structure;

• the solution of execution of the pit in two different environments could raise operating problems, the co-operation with the dam filling could have negative effects on the pit (displacements that would block the valves) and unequal compaction at the dam;

• the caverns for the butterfly-valves will be used in the excavation of the inclined tunnel for the handling of the drilling machine at full section (this technology has been used successfully in Switzerland in a similar work);

• the solution is best fit for staging (2 groups commissioned in 5 years), because, on the second line, with a butterfly valve and blind mounted in the valve house on the horizontal tunnel, work can be performed on the mounting of sheeting and anti-corrosive protection in the years 5 and 6;

• in the operation, the existence of a single line of high pressure tower leads to the interruption of the functioning for all the groups, in the event where an intervention on the globe valves or on the tunnel sheeting were necessary;

• no significant additional costs appeared, the difference between one line and two lines being, theoretically, of approx. 2% of the total investment. The optimum solution, from a technical-economic point of view and from the

standpoint of the execution, includes two lines of the sheeted high pressure tunnel with Di = 4.30 m and two lines of concrete low pressure tunnel with Di = 6.20 m.

UPPER RESERVOIR

LĂPUȘTEȘTI INTAKES

Tunnel and permanent access

High pressure tunnel Line 1

To Tarnița-Lăpuștești PSHP

High pressure tunnel Line 2

INTAKE VALVE HOUSE

pg. 65

Fig.4.12. Longitudinal section higher reservoir and high pressure tunnels

Source: ISPH

High pressure branching –

The Lăpuștești water intakes 2 intakes are specified, placed in the upper reservoir in a sump below the bottom level of the Lăpuşteşti upper reservoir. The role of the intakes is to ensure both the inlet of water in the branch at the operation of the power plant groups as turbines, and at the discharge of the water pumped from the Tarnița reservoir, in the upper reservoir.

The upper intakes are polygonal with vertical screens, without cleaning device; they can be inspected only at the full drainage of the upper reservoir. The connections with the high pressure tunnels have a Di = 4.30 m. Maximum water speed in screens at the turbine processing is 1 m/s.

The Lăpuștești intake valve house intake valves stop the access of the water in the high pressure branching in case of failure and its drying for control, overhauls and repairs. The intake valve house has two caverns, one for each branching line, connected by an access tunnel. The first cavern of the valve house, on the direction of entry from the surface, is the one on line 2 of the high pressure branching. On each of the two lines, the valve house is equipped with two butterfly valves. The access to the valve house occurs in the approach and access tunnel specified at the upper side of the two inclined sections of the high pressure branching. During the exploitation, the largest parts of the butterfly valves on line 1 can be removed, if they require technical services possible solely at the surface by the access tunnel between the two caverns of the valves, then, by using the traveling crane the operating

Minimum level of exploitation 1086.00

Lăpuștești intake

Natural land Min. level of

exploitation

Asphalt concrete facing

rockfills

Natural land line

unaltered rock line

APPROACH AND PERMANENT ACCESS TUNNEL

Intake valve house

To Tarnița-Lăpuștești PSHP

pg. 66

equipment in the line 2 cavern is crossed and then the access tunnel is crossed up to the surface.

High pressure tunnels – have 2 lines ensuring water transport on two protected tunnels between the upper reservoir and the underground power plant. The length of each line of the high pressure branching is 1096 m. Between the intake pit with H = 46 m and the Lăpuștești intake valve house, on a length of 245 m, the two tunnels are horizontal, following then sections sloping with 450 from the horizontal, each with a length of 790 m. Between the sloping sections and the power plant, there are the approx. 60m horizontal sections, which include the feeder. Following the energy-economic calculations, the economic diameter of the high pressure tunnels is 4.30 m.

Fig. 4.13. Profile of high pressure branching tunnels – cross-section

Source: ISPH

Geologically speaking, high pressure tunnels are found in quartz-micaceous slates, and the excavations are to be conducted according to the existing technologies of mechanized excavation and applied to these types of works. From the tunnel of access to the power plant

HIGH PRESSURE BRANCHING

Type section

EXCAVATION CONTOUR

SHEETING

BCH 15 CONCRETE

HIGH PRESSURE BRANCHING

Type section

VEHICLE EXCAVATED CONTOUR

BACH 15 CONCRETE SHEETING

pg. 67

an approach tunnel with be made at the base of the sloping sections. Through the approach and access tunnel at the altitude of 1000 MASL the horizontal tunnels toward the intake pits, the sheeting launch and their concreting will also be performed.

Low pressure branch

Downstream surge chambers To limit the spread of the non-permanent movement occurring on the non-sheeted low pressure branching following the actions in the power plant, as well as to ensure the necessary water volumes until the beginning of the permanent flow conditions of the low pressure branching, it is necessary to place downstream the plant a surge chamber on each of the two tunnels. Hydraulic calculations indicated to cylindrical surge chambers, each of which with the following configuration:

• between the roof of the low pressure tunnel (446.20 MASL) and the altitude of 492.00 MASL – a lower connection pit with Di = 5.40 m;

• between the altitudes 492.00 MASL and 547.15 MASL – a higher pit with Di = 16.00 m, acting as a lower chamber between the altitudes of the minimum downstream level = 514.00 MASL and 492.00 MASL and upper room between the NNR altitudes = 521.50 MASL and 547.15 MASL. A 160m horizontal air level starts from the roof of the upper pit, communicating with

the cable chamber associated with the power plant. The surge chambers are executed from the air level by downward excavations and they have a reinforced concrete coating.

Fig. 4.14. Surge chamber cross-section and low pressure tunnel profile

Source: ISPH

GENERAL

Air level

To the cable chamber

Max. level Tarnița reservoir

NNR Tarnița reservoir

BCH 15 CONCRETE

A-A SECTION

Overbreak

BCH 15 CONCRETE

Anchors

UPP

ER S

ECTI

ON

C

ON

NEC

TIO

N P

IT

SHEETING

To aspirators LOW PRESSURE TUNNEL

To Tarnița intake

Mesh

with shotcrete

Mesh with shotcrete

pg. 68

Low pressure tunnels-They transport water on two concrete tunnels between the power plant and the Tarnița reservoir having the roles of:

• escape tunnel if the aggregates in the power plant operate as turbines; • aspiration tunnel if the aggregates in the power plant operate as pumps.

Each tunnel has a length of 1,325 m between the downstream surge chamber and the discharge. The longitudinal slope is at 4.50 % toward the power plant, between the altitudes 503.00 MASL on the bottom support of the tunnel to the Tarnița intake and 440.00 MASL on the tunnel bottom support to the downstream surge chamber. The energy-economic calculations pointed to an internal diameter of 6.20 m. The tunnels will be approached from the “Power Plant” front and they may be executed with a drilling machine at full section, through an approach tunnel (L = 330 m) starting from the tunnel of access to the power plant. The tunnels can be executed partially also from the “Tarnița intake” work site through the valve shaft in the valve houses from the discharge in the Tarnița reservoir. To ensure independent access during the exploitation. For each of the two lines of low pressure tunnel, for overhauls and repairs, a second access tunnel was specified L = 510 m, from the zone of the transformer caverns where the cut-off plates are also placed downstream the power plant for the second low-pressure tunnel found downstream the first low pressure tunnel. Both access tunnels have watertight gates. The slope and gauge of the approach and access tunnels to the 2 watertight gates allow vehicle access for the transport of the overburden resulting from the excavations and of the concrete for the permanent coating, as well as the access of machines and equipment for maintenance and service activities at the low pressure tunnels and downstream the power plant.

Low pressure tunnels have a permanent reinforced concrete coating of constant thickness. Depending on the type of rock, the burden it puts on the permanent coating, the quantity of reinforcement included in the concrete varies. The aspirator zones, the zone of valves downstream the power plant, the zones of connection with the downstream chambers, for connection with the valve pit at the discharge, as well as the zones of the watertight gates to the surge chambers are sheeted.

In the bottom level of the tunnels, a metallic pipe with Di =50 cm is required for the pumped draining of the tunnel. The technology of execution is known, since it is currently applied in similar works in the country and abroad.

The Tarnița discharge valve houses One per tunnel of the low pressure branching. Their role is to close the access of water from the Tarnița downstream reservoir in the low pressure tunnels, for their drying for the purpose of overhauls and repairs. The discharge valve houses are “wet pit” type, each equipped with a cut-off plate and a cofferdam. The rooms for the mechanisms handling the plates and cofferdams are placed in the underground, for safer operation in winter. Wet pits have a height of 23 m and a gauge allowing the approach of the low pressure tunnels from the Tarnița site, without impact on the exploitation

pg. 69

of the Tarnița reservoir. The technology of execution of the wet pit is the one applied in similar works.

Fig.4.15. Plan view- discharge in the lower reservoir

Source: ISPH

Discharges in the Tarnița reservoir are hydrotechnical works having the following functions:

• discharges as such, at the operation of the power plant in conditions of water turbine processing

• intakes where the aggregates in the power plant operate in pumping conditions. Discharges are placed below the minimum exploitation level of 514.00 MASL of the

Tarnița reservoir guard to avoid the pull of air on the tunnel at the operation as aspiration tunnel. Discharges are each equipped with a 100 sqm screen. The sections of low pressure tunnel between the downstream valve pits and the discharges, as well as the discharges will be executed solely after the level in the Tarnița reservoirs drops below 503.00 MASL, which is the level of the bottom foot of the discharges. The discharges in the Tarnița reservoir shall be executed solely after the low-pressure tunnels are fully concreted between the plates – cofferdams placed downstream the Tarnița – Lăpuștești PSHP and the wet pits of the valve houses at the discharge, with the associated valves and watertight gates installed and ready to be handled promptly at any moment.

For the equipment of the set-up objects, pipes and sheeting in line with the European performance requirements were specified, the materials and technological processes being in accordance with the most recent standards. According to the diagram, water is sampled from

Tarnița reservoir

Land limit according to Regional Urban Planning

pg. 70

the lower reservoir (Tarnița) through a deep-water intake and pumped in the upper reservoir (Lapuștești) wherefrom it is taken (again through a deep-water intake) and turbine processed through 4 (four) reversible vertical aggregates, each of them with 250MW power at the terminals.

From the point of view of the pipes and sheeting, the optimum analyzed option proposes that the hydraulic circuit layout on the high pressure zone should be executed with two upper intakes, two parallel penstocks (internal diameter Ø4300 mm), each provided with a feeder placed in the power plant zone, transporting the water to the 4 vertical reversible aggregates (each with Pi= 250 MW). After the turbine processing, water is taken at each of the 4 aggregates on 4 lines, metallic sheeting (central zone – transformer cavern), with variable sections (from 3200 x 3500 mm² to 3200 x 4700 mm²), placed between the power plant and the suction valve house. The aspirators’ valves are encased cut-off plates.

The following is specified beyond the valves of the aspirators: sheeting for transition from rectangular section to circular section (internal diameter Ø6200 mm), line sheeting and two connection parts, the circuit going on 2 circular lines (internal diameter Ø 6200 mm), which make the junction with each of the 2 surge chambers. In the area of the surge chambers, two of the approach windows are provided with metallic watertight gates, at the section of 2.0 x 2.0 m², for the purpose of enabling the inspection of the penstock tunnel when performing the maintenance activities.

Downstream the surge chambers, the low pressure tunnel transports water to the zone of the lower intake valve house (Lapuștești). The zone of the lower intake valve house is provided with linear sheeting (internal diameter Ø6200 mm), reducer sheeting and sheeting for transition from the circular section to the rectangular one, to enable the connection with the sheeting of the cut-off plates at the Tarnița intake.

No pipes and sheeting were specified at the two reservoirs, because the upper reservoir (Lapuștești) does not have natural flow input, so it does not require a bottom discharge, and the lower reservoir (Tarnița) is an already existing reservoir.

The high-pressure branching is provided with sheeting for each of the 2 parallel hydraulic circuits placed between the upper reservoir and the power plant, i.e.:

• upper intake sheeting (Lăpuștești): • vertical sheeting equipping the upper intake pit (internal diameter Ø4500 mm ÷ Ø4300

mm) - 2 units, one per intake; • intake sheeting - intake valve house: linear sheeting equipping the hydraulic axis

between the upper intake (internal diameter Ø4300 mm) and reducer sheeting (Ø4300 mm/ Ø4600 mm) in the intake cavern - 2 units, one per circuit;

• pressure tunnel sheeting (internal diameter Ø4300 mm): sloped sheeting, total length 790 m - 2 units, one per circuit;

• reversible vertical group feeders – 2 units, one per circuit. The low pressure branching is specified with the following sheeting:

pg. 71

• sheeting in surge chamber area: • sheeting at power plant-transformer cavern (4 units), with variable section (from 3200

x 3500 mm² to 3200 x 4700 mm²), between the power plant and the aspirator valve house and sheeting of transition from rectangular section to circular section (4 units), placed upstream and downstream the aspirator valve house;

• sheeting transformer cavern - chamber: linear sheeting and connection sheeting (2 units), between the aspirator valve house and the surge chambers;

• watertight gates, placed on the approach windows from the surge chamber area • sheeting at lower intake (Tarnița): • linear sheeting (internal diameter Ø6200 mm); • reductive sheeting; • sheeting for transition from the circular section to the rectangular section, to enable the

connection of the cut-off plate sheeting from the lower intake. Power plant – the optimization of the mechanical and electric wiring diagram led to

the concentration of all the pieces of equipment in two caverns, the one of the machines room and the one of the transformers. The upstream globe valves are placed in the machines cavern, right ahead of the turbines, and the downstream cut-off plates are placed in the transformer cavern on the corridor in front of the transformer boxes, in insulated pits.

Therefore, the power plant includes:

a) The machine room cavern is 120m long, 23m wide and 45m high. The length is required by the positioning of the 4 binary reversible groups, with 250MW unit power, with 23m distance between the axes and mounting platform with a length of approximately 33m, placed at one of the ends of the power plant where the main access tunnel to the power plant reaches, both with the bottom established directly on the rock.

The cavern width is given by the turbine gauge, the space for the globe valves and the space required for the mechanical annexes, as well as by the diameter of the generators and the space for the electrical annexes.

The cavern height is required by the level of the aspirators, turbine, generator and by the height of the transport of parts by the traveling crane (transformer, aggregate rotor).

The reinforced concrete structure of the power plant has massive elements (bottom plates (inverts), walls, tanks, aggregate bottoms) and infrastructure platforms; plain frames, beams and platforms for the superstructure.

The machine room is linked with two travelling cranes with 200/50t hook effort. Travelling cranes are supported on the structural frame independent from one of the power plant, with an opening of approx. 16 m.

pg. 72

Fig.4.16. Cross section of central cavern and transformer cavern

Source: ISPH

The level of the turbine axis is 444.00 MASL and of the machine room 458,00 MASL, where the mounting platform can also be found. The electric extensions are placed along the central cavern on the downstream wall, above the level of the machine room and they include: control room, group panel and internal service room, storage batteries, server room, training room, locker rooms, restrooms, offices, stairs at both ends.

b) The transformer cavern is 117m long, 19m wide and 22m high.

The length is given by the positioning of the 400kV step-up transformers near the groups in the power plant and of the 110/15.75 kV and 110/20 kV transformers placed at the end of the power plant from the main access.

The width of the cavern is given by the dimensions of the 400kV transformer boxes and of the corridor for their transport to the boxes. The height of the cavern is given by the necessary space, along the vertical line of the transformers, the space above the transformers where the 400kV, 110kV stations are placed, as well as for those of 24kV and 15.75 kV and the ancillary service transformers. Above them, there is a 5tf single beam. The main access tunnel between the two caverns is placed at and end of the machine room, with a width of 12m and it ensures the transport of the transformers on rails from the machine room, where they are unloaded from the trailer, by using the travelling crane, and they are rotated in the position of insertion in the boxes of the transformer room.

The tunnel is 35m long and it has a 100sqm section; it continues the main access to the level of the machine room. There are 4 connecting tunnels between the set and the

POWER PLANT CAVERN

TRANSFORMER CAVERN

TRAVELLING CRANE

CONTROL ROOM

ELECTRIC SUBSTATIONS

ENCLOSED BAR TUNNEL

Prestressed anchors

MACHINE ROOM

pg. 73

transformer at the level of the generators, ensuring the connection between the generators and the transformers.

There are 4 tunnels of the aspirators and they cross under the transformer cavern.

The pits of the aspirator valves are placed in the corridor of the transformer cavern, near each aspirator.

The secondary connecting tunnel joins the two caverns at the opposite end of the mounting platform, ensuring the evacuation in case of fire.

The main access tunnel goes in the underground from the left shore of the Tarnița reservoir and it discharges on the mounting platform for the power plant, crossing the transformer cavern. It is approx. 1070m long, with a very mild curve with a range of 500m and with a 10% slope. The section is 50 sqm and it ensures the transport of the parts with the largest gauge (transformers, feeders, generator rotor).

The cable chamber ensures the transmission of energy at the voltage of 110kV, 20kV, the personnel’s secondary access, fresh air, as well as the evacuation of harmful gas and of smoke from failures. It is adequately compartmentalized and it also has a water spray fire extinguishing system. It is approximately 850m long up to the level of the exterior platform on the shore of the Tarnița lake, placed at 530 MASL.

Architecture part -The power plant cavern hosts the infrastructure, the superstructure and the globe valves. The transformer cavern is meant for the electric areas and cut-off (inlet) plates.

The characteristic levels of the power plant infrastructure are laid out in accordance with the technological and operating easements, being given directly by the equipment and electrical-mechanical systems gauges, as follows: the level of aspirators/ the level of valves/ the level of turbines/ the level of generators.

The following elements are laid out at the superstructure: machine room level and two levels of extensions toward the transformer cavern, and in the transformer cavern there are two important levels: the level of 280 MVA transformers and 25 MVA transformers and the level of the substations, as well as the access to the cable chamber.

The indoor spaces of this power plant will be finished with enduring materials with an aspect in line with the function of the spaces. More special finishes will be selected for the machine room:

• bottom covering made from stone boards; • veneers on the facing walls especially made from composite aluminum boxes, phenol

resin boards, ceramic boxes; • ceilings made from aluminum sheet boards mounted by clipping on a metal support

structure for panels impermeable to infiltrations, mounted toward the roof.

pg. 74

In the machine room, the lighting will be studied together with the finishing solutions, to create an environment matching the requirements of an underground working space. The lighting will be strictly functional and in line with the rules in force for the process areas in the remaining power plant unit.

Constructions annexes (extensions) to the power plant-At the entry of the main access tunnel and of the cable chamber (secondary access), as well as on the platforms adjacent to the upper and lower reservoir, the buildings to be created will be in line with the operation of the power plant and of the reservoirs.

Technical unit at the entry of the main access tunnel; on the platform of the main access, at the entry in the main access tunnel, the following spaces are required: labor protection training room/ steering set/ administrative offices / construction maintenance workshops (for dams, underground tunnels, roads) / locker rooms, restrooms-pantry / storage areas, pumps and oil, gasoline, Diesel oil tanks.

For these features to be laid out on the platform at the entry of the main access tunnel, in a construction adjacent to the slope and to the portal, while retaining the possibility of access to the gallery, a construction incorporated with the portal is proposed, according to the parameters required at the site, with vertical arrangement of the mentioned spaces, even surpassing the upper level of the portal. The construction will adhere to the site requirements and to the natural character of the zone, without harmful impact on the natural environment. The construction materials will be in line with the functional requirements and with the position in the region.

Technical unit at the entry of the secondary access tunnel -This construction will have a ground floor and floor at the tunnel portal. At this tunnel, access will be exclusively pedestrian access crossing through this construction. Furthermore, the possibility to evacuate the cable flows and the ventilation piping will be created. The required spaces are: access hallways/ access stairs/ Diesel set/ transformer station/ maintenance area/ 20kV and 0.4kV substation/ failure mode pump 6kV substation/ lighting and power panels/ valve rooms/ ventilation plant/ failure mode ventilation/ 400kV substation.

Dam keeper house higher reservoir-In the building placed on the platform adjacent to the upper reservoir, the electric equipment for the reservoir bottom discharge valves and water intake valves will be placed. Therefore, spaces are required for:

• a 20/0.4 kV transformer station on the building ground floor; • 20 kV substation with 6 indoor pre-fabricated metal bays 24 kV, 630A; • a 20/0,4 kV, 400 kVA power transformer, indoor mounting; • control room; • a Diesel service set 150 kW; • operating room, also including the measuring and control device rooms; • living quarters with the necessary extensions.

pg. 75

Dam keeper house lower reservoir-In the building placed on the platform adjacent to the lower reservoir, the required spaces will be:

• a 20/0.4 kV transformer station on the house ground floor; • 20 kV substation with 6 indoor pre-fabricated metal bays 24 kV, 630A; • a 20/0,4 kV, 400 kVA power transformer, for supply to consumers; • control room; • dam operating room, also including the measuring and control device rooms; • living quarters with the necessary extensions.

The calculation of the investments for these objects was made in accordance with the experience relating to this type of works and it was assessed at approx. 800euro/sqm spread area.

The equipment part-The equipment for the constructions is:

• Permanent indoor equipment;

• Permanent outdoor equipment.

Sanitary and firefighting equipment-For the above-ground constructions, the source of drinking water is given by the dug wells. Waste water is discharged through the exterior sewer networks to compact treatment plants. Waste water is collected in an automatic plant and pumping will ensure their evacuation in an emissary.

For the firefighting water (sprayed or by using indoor hydrants), a pumping station is specified – to ensure the suction of water from the cooling water tank at the cable chamber and deliver it through the pipe mounted in the cable chamber to a fire water tank placed on the flank.

Ventilation equipment-The stipulated equipment ensures the optimum environment for the technological processes, it evacuates the harmful emissions, it feeds minimum fresh air flow rate required for the people, it evacuates the ignition products after a fire is extinguished (smoke). The following aspects are specified:

• Overall mechanical ventilation of the two caverns (transformer and machine room); • Mechanical ventilation for the storage battery rooms and restrooms; • Mechanical operating and failure mode ventilation at the cable chamber; • Mechanical operating and failure mode ventilation at the transformer boxers and oil

management unit. The fresh air intake is found at the entry of the cable chamber where the fans and the

heater battery are placed. Fresh air reaches the underground power plant through a compartment of the cable chamber.

In the ventilation plant of the underground cavern, fresh air is mixed with recirculated air and transferred in the indoor ventilation equipment by using a fan mounted in the ventilation plant. The wet air of the underground plant exists freely through the whole section

pg. 76

of the main access tunnel. The harmful air of the storage battery rooms is exhausted through a channel provided in a compartment of the cable chamber. The related fan is mounted in the construction at the entry of the cable chamber. The equipment for the failure mode ventilation exhaust the burnt products (smoke) resulting from fire extinguishing at the transformer boxes, from the roof of the plant (fire at the generator), at the oil handling unit or at the cable chamber.

Electric equipment-The following was specified: electric heating equipment / regular and safety lighting equipment/ power equipment/ weak current equipment/ lightning arrester / outdoor networks.

Regular lighting is obtained with lighting fixtures equipped with fluorescent or incandescent lamps, depending on the room category and destination. They are controlled from the switches and contactors mounted at the access to the rooms. Tunnel lighting is possible with watertight lighting fixtures, and the supply and control circuits are executed with cable laid on consoles fixed to the tunnel walls. Power supply occurs from the internal service panels; for the above-ground constructions – from the transformer stations in the area.

The emergency (safety) lighting equipment is type 2 and it will be made from lighting fixtures equipped with incandescent, regular or sealed lamps, depending on the room destination.

The power equipment ensures the feeding of engines, three-phase outlets, electric consumers in the mechanical and electric workshops, laboratories. The power equipment is fed from the power panel. For the above-ground buildings, lightning arrester is required, executed with down conductor (wire) made from zinced steel strip. The down elements will be linked to grounding outlets specified for this purpose.

Outdoor electric equipment ensures the outdoor lighting of the stations and platforms from the zones of access in the tunnels. Outdoor lighting will be executed by using lighting fixtures installed on poles. Furthermore, power consumers from the outdoor platforms will be fed – as they are specified on the equipment side. For the heating of the above-ground constructions, thermal power plants (electric boilers) and outdoor thermal grid were specified.

Mechanical systems and equipment- the option with Pi = 1000 MW (4 groups, each at 250 MW) was analyzed, for a staged execution: in a first (5-year) phase, the execution of two groups and in a second (2-year) phase the execution of the other two groups. The water is taken from the upper reservoir from a deep water intake and pumped in the upper reservoir, wherefrom it is taken also by a deep water intake and processed for electricity through the four vertical reversible hydro-aggregates.

Mechanical equipment has been specified at the high pressure branching (intake and intake valve house), at the power plant and at the low pressure branching (intake and intake valve house). Mechanical equipment has not been specified for the two dams, because the

pg. 77

Tarniţa is present, and the upper reservoir does not have natural flow input – so bottom discharge equipment is not necessary. High performance mechanical equipment, manufactured in line with state-of-the-art technology, was specified for the objectives of the set-up.

High-pressure branching

Intake-On each line, the intake in the upper reservoir is equipped with a coarse bar, vertical, polygonal, fixed screen, designed in a way that will allow water flow in both directions, with minimum load losses and without perturbing phenomena. The surface of the two screens was obtained from the condition that the water speed in turbine processing conditions should not exceed 1.0 m/s. The opening between the bars is 250 mm.

Intake valve house-The intake valve houses, one per line of penstock, are cavern houses with access through an underground tunnel. The following hydro-mechanical equipment has been specified in each valve house:

• Butterfly valves with a diameter of 4600 mm and pressure 100 m.c.a.2 units. • Electric traveler 50 tf – 15.0 m with control from the ground 1 pc.

Butterfly valves equipment - Two butterfly valves in succession for the closing of the high pressure penstock in case of overhauls and pairs or in the event of failure at the globe valves in the power plant. The downstream valve is a working element, the upstream valve is a safety element actuated in case of fault at the working valve or for the latter’s service. The butterfly valve equipment has the following main sub-units:

• working butterfly valve; • safety butterfly valve; • hydraulic actuation equipment including four servo-engines, two pumping groups,

control cabinet and actuation circuit made from pipes and fixtures • the bypass valve equipment, including pipes, fixture and electrically actuated flow

control valve; • the upstream connecting section provided with reinforcing neck connection for the

bypass pope, intake for pressure measurement; • intermediate, removable section, provided with connection for the by-pass pipe, intake

for pressure measurement, connection for the air pipe, mounting equalized and inspection hole;

• downstream connecting section provided with connection for the bypass pipe, air vents and inspection hole.

• electric travelling crane 50 tf - 15 m, handling the mechanical and electric equipment in the valve house, during the mounting and the operation, at service and repairs.

• Back-up electric generator set-To ensure power supply for the consumers at the upper reservoir in the event of main power failure, a 150kW back-up generator set was specified.

pg. 78

Power plant -Four binary pump-turbine machine coupled with generator-engine, with installed capacity of 250MW, were specified for the power plant.

Pump-turbine technical characteristics:

Type Reversible Francis with vertical shaft

Number of pump-turbines 4

Net head in turbine processing conditions

maximum nominal minimum

570 m 540 m 520 m

Maximum flow in turbine processing conditions*

53 m3/s

Maximum power at coupling

260 MW

Pump head

maximum nominal minimum

580 m 560 m 540 m

Maximum flow in pumping conditions*

38 m3/s

Maximum input (power)*

258 MW

Rotor characteristic diameter* 3800 mm

Nominal number of turns* 600 rpm

Back-pressure*

70 m

* The values of these parameters are indicative; they are to be established and guaranteed by the supplier of the reversible pump-turbine equipment.

The reversible pump-turbine unit will be provided with:

• rotating speed controller and control equipment: • pressure oil unit; • water, oil and compressed air systems within the limit of the aggregate; • mounting tools, devices and verifiers; • measuring and control devices, including the equipment for the measuring of the

operating parameters at the hydraulic machine (pressures, flows).

pg. 79

Fig.4.17. Selection of the type of turbine according to flow rate and head

Valve in front of the reversible unit-for the protection of the hydraulic machine, the prevention of water leaks when the hydro-aggregate is stationary, as well as for the drop of the water level below the rotor for pump starting, a globe valve was specified for the inlet of each hydro-aggregate; this globe valve has hydraulic actuation.

The valves are placed in the same cavern with the hydro-aggregates, being handled with the travelling crane from the power plant, through the mounting gaps specifically specified in the boards delineating the process levels of the power plant. Technical characteristics of the globe valve:

• Nominal (rated) diameter 2000 mm

• Maximum pressure 770 mWc

• Test pressure 1155 mWc

• Actuation hydraulic, with water

• Debit nominal 53 m3/s

• Opening time 20-120 s

• Closing time 20-120 s

• Sealing (tightening) double direction

Aspirator valve -to insulate from downstream each reversible set, for service and repairs or in case of failure, a cut-off plate was specified in each hydraulically actuated case. The valves are placed in the power transformer cavern found at approx. 63 m from the power plant cavern.

pg. 80

The handling of the valves, both at the closing and at the opening, is conditioned by the closed off position of the globe valve on the inlet of the related turbine. Technical characteristics of cut-off plate:

• Internal diameter opening 3200 mm

• Internal diameter height 4700 mm

• Design pressure 100 mWc

• Actuating system with hydraulic servo-motor

Auxiliary mechanical equipment-the following auxiliary mechanical equipment was specified for the power plant:

• cooling water equipment;

• high and low pressure compressed air equipment;

• oil handling unit; dewatering equipment;

• aspirator and high and low pressure tunnel discharge equipment, including the equipment for the filling of the high pressure tunnel;

• equipment for the evacuation of water from the power plant in case of failure.

Lifting equipment-For the handling of the mechanical and electric equipment in the power plant, two electrically actuated travelling cranes of 200/50 tf – 16 m were specified. The two travelling cranes will be coupled for the handling of the equipment weighing more than the lifting capacity of a crane and they will operate independently for the handling of the other equipment in the power plant. For the handling of the encased cut-off plates, a travelling crane with electric hoist was specified.

Measuring equipment balance levels, flows, degree of screen clogging – For the measuring and transmission to the power plant control room of the water levels in the upper and lower reservoir, of the degree of clogging of the screens at the intakes and for the identification of the pump-turbine operating parameters, adequate equipment was specified, in accordance with the requirements.

Back-up electric generator set -To ensure power supply to the vital consumers of the power plant, in case of main power drop, a back-up electric generator set, with the power of 2000 kVA, was specified.

pg. 81

Fig.4.18 Reversible pump-turbine set in operation

Source: Voith

Low pressure branching

Intake -The intake in the lower reservoir is equipped with fine bar, sloped, fixed screen, designed to allow water flow in both directions with minimum load loss and no perturbing phenomena. The screen is provided with a cleaning device. Technical characteristics:

• Type fine bar, sloped at 70º • Area 100 sqm • Opening between the bars 120 mm

Valve house-One valve house is specified per penstock line, including a wet pit wherein a cut-off plate (working element) and a cofferdam (cut-off plate service element) are installed and an above-ground cavern equipped with their actuation systems. Technical characteristics of the cut-off plate system in wet pit:

• Internal diameter opening 3700 mm • Internal diameter height 5500 mm • Design pressure 25 mWc • Cut-off plate actuation hydraulic, with pressure oil • Cofferdam actuation electromechanical

The valve will operate in fully open position, both in turbine processing conditions and in pumping conditions or fully closed, ensuring that water access to the low pressure tunnel is stopped, both for the performance of maintenance operations and for situations of failure. The cofferdam will ensure the insulation – from the reservoir – of the valve, for the performance of brief maintenance operations or, together with the valve, it will ensure the drying of the low pressure tunnel in case of interventions (overhaul or repairs).

pg. 82

The valve closes under its own weight, in the stream or in balanced water and it will open, the first 100mm below the load and then in balanced water, and the cofferdam will be handled in equalized pressures (by embedded bypass), both at the closing and at the opening.

Electric equipment and connection to the RPS-The Tarnița – Lăpușteşti pumped-storage hydro-power plant (PSHPP) is an underground power plant, equipped with 4 reversible aggregates at constant speed 4 x 250MW, 15.75kV The electric equipment to be installed in the Tarnița – Lăpușteşti plant are:

• four reversible, constant-speed groups; • the electric devices at the terminals of the reversible groups; • the power transformer of unit (15.75/400 kV) and of supply to the auxiliary unit

services and general services of the power plant; • medium-voltage (6 and 20 kV ) and high-voltage (110 and 400 kV) electric cables; • medium-voltage (6 and 20kV) and high-voltage (110kV) electric substations; • ancillary equipment (grounding, travelling crane, etc.); • power equipment for supply to the ancillary direct current and alternating current

services at the groups and for general power plant services; • electric equipment for control, protection and automation at the groups and the power

plant; • the measuring equipment for electric and non-electric parameters (temperatures,

levels, flow rates, etc.); • ancillary secondary circuit equipment (diagnosis, protection at the break of the pipe,

fire warning, communications, etc.). The connection of the Tarnița – Lăpuștești PSHP to the system was established by a

connection survey drafted by ISPE Bucureşti in October 2012.

The connection survey analyzed the possibility of connecting the Tarnița – Lăpuștești PSHP to the system:

• connection by overhead power line 400 kV PSHP Tarnița – Gădălin; • connection by overhead power line 400 kV PSHP Tarnița – Mintia.

For the above-mentioned option the following aspects were analyzed:

• sizing of lines and transformer units in the options with N and N-1 operating elements; • level of power losses in permanent operating conditions (RMB), losses calculated for

both operating conditions of the groups (turbine-generator and pump-engine); • conditions of grid stability following the power plant’s connection to the system; • conditions of transitional stability, laying down: • critical time of short-circuit removal, for the stability of the electric power plants in the

zone; • identification of the critical time at the three-phase short-circuits at 400 kV, for both

operating conditions of the power plant; • protections of synchronous electric machines against elimination of synchronism; • participation of the PSHP units to the adjustment of the voltage in the zone; • analysis of short-circuit stress.

pg. 83

Given the above-mentioned analyses, in the conditions of the development of power lines and sources in the system in the years 2018-2022, the following option for the connection of the Tarnița-Lăpuștești PSHP to the system has been shown to be optimal:

• execution of a 400kV substation at the PSHP; • the execution of a double circuit OPL (overhead power line) of approx. 158 km to the

Mintia 400kV substation, for which the potential route has been analyzed and is feasible;

• the execution of a double circuit 400kV OPL of approx. 74 km to the Gădălin 400 kV substation. The medium- and high-voltage electric equipment installed in the power plant -

The Tarnița – Lăpuștești PSHP is an underground power-plant, made from:

• the main cavern (machine room) where the four reversible groups and their extensions are installed (115 x 23 x 45 m);

• the transformer cavern, where the four block transformers and the other 110/15.75 kV and 110/ 20 kV transformers are installed;

• the transformer cavern is linked with the main cavern through a 12m wide and 35m long tunnel;

• the connecting tunnels between the reversible groups and the block transformers, tunnels wherein the enclosed bars of 15.75 kV, 12 kA for the evacuation of input/output power and the enclosed bars of 15.75 kV, 2.5 kA for the launch of reversible set in engine mode are found;

• the secondary connecting tunnel between the two caverns, placed at the opposite end of the mounting platform. This tunnel ensures the evacuation of the operating personnel in case of fire;

• the main access tunnel, with a length of approx. 1070 m, is used for the underground transport of all the pieces of equipment and materials, as well as for the access of people.

• the approx. 800m long cable chamber is used for the mounting of 400 kV, 110 kV, 20 kV, 6 kV cables and of the secondary circuit cables. This tunnel is the back-up route for the evacuation of the operating personnel.

Reversible generator-engine groups =The groups are installed in the power plant, in accordance with the two-stage breakdown of the mounting of the 4 reversible groups. Each reversible generator-engine set is driven by a reversible pump-turbine hydraulic machine. The reversible set is three-phase, synchronous alternating current machine, with vertical axis, delivered with all the functional annex equipment, i.e.:

• the electric machine as such, made from: • stator (fixed coil) (casing, magnetic circuit, windings, etc.); • rotor (shaft, magnetic circuit, poles with operating windings, damper winding, etc.); • radial bearing and bearer and clamping star; • radial-axial bearing and bearer and clamping star; • system of attachment in the structural frame;

pg. 84

• the static type of excitation system includes: • dry transformer drive, 15.75 kV, 1500 kVA; • rectifying system, with thyristors; • paths of current for the connection of the transformer drive to the set terminals,

including the switch and protection devices; • the direct current switchgear; • the de-energizing system; • the automatic voltage controller; • the ancillary equipment of the reversible set: • the ventilation equipment, for both operating conditions; the ventilation occurs in

closed circuit, by the use of electric engine actuated fans; • the equipment for the cooling of ventilation air cu air-water cooling; • thermal control system with flat and cylindrical thermal resistance elements; • the electric, mechanical braking system and rotor lifting system; • the detection and extinguishing equipment for fire at the generator-rotor; • vibration measuring and supervision system; • gap measuring and monitoring system; • heater equipment for the reversible set during stationary periods; • pressure oil injection equipment for the axial bearing; • equipment for cooling of oil for radial and axial-radial bearings in oil-water coolers; • set starting system in engine mode, variable frequency equipment, including: • the 110/15.75 kV mains transformer; • the main starting equipment, with thyristors; • the switchgear and protection devices on the mains circuit; • the cabinets with the automation devices for the starting equipment; • the enclosed connecting bars between the variable frequency system and the reversible

groups (15.75 kV, 2.5 kA); • rotary transducer, for supply of the turbine rotary controller; • automation and warning system for the operating processes, in all the possible

operating conditions, with the possibility of computer monitoring and management of any equipment;

• a set of tools, devices, verifiers (TDV) for mounting and repairs, including the devices for rotor and stator handling in the power plant;

• a set of wear and spare parts, to be delivered with the set scope of supply; • technical documentation on packaging, transport, storage, mounting, tests,

commissioning, exploitation, maintenance, etc.

The main technical characteristics calculated for generator-engine reversible set:

• nominal power operating as generator 280 MVA; • nominal power operating as engine 250 MW; • nominal voltage 15.75 kV; • nominal frequency 50 Hz; • nominal rotating speed in line with turbine speed; • power factor (generator/engine) 0.9/0.98;

pg. 85

• moment of inertia min. 3500 tm2; • insulating class (stator – rotor) F; • rotor diameter approx. 4520 mm; • stator diameter (no coolers) approx. 6800 mm; • shaft length approx. 11600 mm; • reversible set total weight approx. 730 t;

Maximum temperature limits:

• stator winding 100˚ C; • rotor winding 100˚ C; • iron core 100˚ C; • slip rings 90˚ C; • bearings 45˚ C.

The generator is delivered in sub-units, with the maximum gauge for railways or with oversized parts, but not exceeding the loads and overall dimensions for public roads.

The stator is mounted on the mounting platform of the power plant. The stator stacks are packed on the mounting platform. The stator windings will be mounted also here in the slots.

The rotor is assembled on the power plant mounting platform (rotor hub, magnetic core, rotor poles).

The assembled stator and rotor are transported and mounted in the power plant, by using the travelling cranes.

Electric equipment at the terminals of the reversible groups

At the terminals of the reversible set, the following electric devices are mounted:

• 15.75 kV, 12,000/5/5/5/5 A current transformers, installed at the main terminals, in enclosed connection bars and at the neutral terminals, in the null (neutral) boxes;

• 15.75/√3 /0.1/√3 /0.1/√3 /0.1/3 kV voltage transformers, mounted in the enclosed bars for the connection with the block transformer;

• single-phase enclosed 15.75 kV, 12,000 A bars, mounted between the terminals of the reversible set and the terminals of the 280 MVA transformer. These high intensity enclosed bars allow derivations in enclosed bars, again, for:

• the connection of the set auxiliary service transformer of 2500 kVA 15.75/0.4 kV; • the connection of the 1500 kVA, 15.75/0.4 kV transformer drive; • the connection to the general actuating bars with the variable frequency a changer; • the short-circuit devices for the electric braking of the reversible set; • the connecting gear (switches, circuit breakers) on the reversible set start circuit in

engine mode (equipment with variable frequency a changer); • the 15.75 kV, 75 (100)/5/5/5A current transformers, mounted on the connection of the

transformer drives (of auxiliary services) for the set;

pg. 86

• the 2500 kVA, 15.75/0.4 kV auxiliary service transformers, mounted at the terminals of the reversible set, including the switchgear on the medium- and low-voltage side;

• connection with the 15.75 kV disconnecting switches that invert the phases for the transition of the set from generator mode to engine operating conditions.

The 280 MVA power transformers and the other power transformers mounted in the underground power plant -Four 280MVA block transformers are mounted in the power plant, in four separate boxes, found in the transformer cavern. The 280 MVA transformers are three-phase, with copper windings, oil insulation, for mounting in an underground area; the oil is cooled with oil-water coolers. The main technical characteristics of the 280 MVA transformer are:

• transformer type TTUS-OFNF; • nominal power 280 MVA; • number of windings 2;

Nominal voltages:

• high voltage 400 kV; • low voltage 5.75 kV; • load adjustment on the high voltage side ±8 x 1.56%; • group of connections YNd-11; • impedance voltage 15.5 %.

Apart from the 280 MVA block transformers, the following elements will also be installed in the transformer cavern:

• two power transformers of 25 MVA, 110/15,75 kV, for supply to the two variable frequency start changers;

• a power transformer of 10 MVA, 110/20 kV, for electric supply to the 20kV substation. Each of the above-mentioned transformers is installed in separate boxes, provided with

concrete tanks able to retain approx. 20% of the oil volume in the related transformer, the remaining 80% of the transformer oil being collected in a central tank (waste oil tank).

The set auxiliary service transformers (2500 kVA) and transformer drives (1500 kVA), including back-up transformers for auxiliary and drive services, are dry transformers, with the LV and HV coiling in resin. Auxiliary service transformers for the set (2500 kVA) are mounted near the tank of the reversible sets, the connection between the enclosed 15.75kV, 12kA busbars and the auxiliary service 2500kVA transformer being made in an enclosed busbar. Transformer drives (1500 kVA) are installed near the terminals of the sets. In all the boxes of the transformers of 400/15.75 kV, 110/15.75 kV 110/20 kV, fire detection equipment and sprayed water fire extinguishing equipment are specified.

pg. 87

400 kV switching substation -According to the project for the connection to the system, the Tarnița – Lăpuștești PSHP is connected to the RPS by two 400kV overhead lines, double circuit:

• OPL 400 kV double circuit PSHP – Mintia, • OPL 400 kV double circuit PSHP – Gădălin.

At the Tarnița -Lăpușteşti PSHP, a 400kV substation is specified, with double busbars, placed on an above-ground platform, made from 9 enclosed bays, with SF6 (GIS), for the connection of the four 400kV lines, of the 4 reversible set blocks – 280MVA transformer and a transverse busbar bay and busbar measure.

In the underground, another 400kV substation will be mounted, to include 4 enclosed (metal-clad) SF6 insulated, GIS bays, equipped with switch, disconnector with earthing switch, instrument transformers and earthing switch.

The connections between the 280MVA power transformers and the 400kV substation in SF6 are made in enclosed 400kV busbars, and the connections between the underground 400kV substation and the above-ground 400kV substation are made in 400kV cables.

The roles of the underground 400kV substation are the following:

• connection to the substation bars of the reversible set blocks - step-up transformer;

• evacuation to the RPS of the power generated by the blocks in the generator mode;

• supply from the RPS for the blocks operating in engine mode;

• synchronization of the reversible groups with the RPS;

• measuring the power and energy debited/used by each reversible set.

For each 400kV bay, local control cabinets and electric protection cabinets with digital protective terminals have been specified.

110 kV substations-At the Tarnița – Lăpuștești PSHP, the 110 kV substation has the following roles:

• feeding electricity to the engine mode (pumping) start equipment with static frequency changer;

• feeding electricity to the 20kV substation in the power plant.

Given the very high power of the reversible groups and the high mass of the engine and pump rotors, the engine mode start of the reversible set requires a power of approx. 18 – 22 MW, which can be ensured from the RPS at 110 kV.

pg. 88

The 110kV substation has 5 bays equipped with switches and a voltage measuring bay (2 OPL 110 kV, 2 transformers 25MVA, 1 transformer 10MVA). The 110 kV substation has indoor enclosed SF6, GIS bays, placed in the underground, above the boxes of the 25 MVA and 10 MVA transformers.

The connections between the 110kV substation from the power plant and the 110kV system substation are made through an underground power line of 110 kV double circuit. For each 100kV bay, local control cabinets and electric protection cabinets were specified, with digital protective terminals.

400kV cables -The connections between the SF6 (Sulfur hexafluoride) 400kV underground substation and the SF6 400kV above-ground substation are made in single-phase 400kV cables, in trefoil formation, support by pre-fabricated metal constructions on the cable chamber. The terminal boxes of the 400kV cables placed in the 400kV (GIS) substations in the underground and above-ground are insulated in SF6.

The main technical characteristics of the 400 kV cables are:

• type of cable single-phase, dry insulation;

• nominal voltage between phases 400 kV;

• maximum operating voltage 420 kV;

• power transmitted on the circuit 560 MVA;

• short-circuit power 20 000 MVA;

• single-phase short-circuit current 12 kA;

• short-circuit duration 1s;

• operating (working) mode continuous;

• neutral of the 400 kV grid grounded;

• wire material copper;

20kV and 6kV substations-A 20kV, indoor substation is specified, with double busbar system, placed in the underground, in the transformer cavern, above the 280MVA transformer boxes, with the following features:

• ensure electricity for the general services of the power plant;

• ensure electricity for the 0.4kV internal services of the set during the start-up of the power plant;

pg. 89

• ensure back-up supply for set energizing;

• ensure electricity for the internal services of the above-ground 400kV substation.

Given the importance of the 20kV substation for the electricity supply to the internal and general 0.4kV services, the following supply is ensured:

• from the local 20kV system, from the existing 20kV d.c. OPL, Mărişelu - Tarnița;

• from the 110 kV grid, through the 110/20kV, 10MVA power transformer;

• from the 2000kVA electric generator set connected to the above-ground 6kV substation busbars, placed at the entry of the cable chamber.

A 20kV, above-ground substation is specified, placed at the entry of the cable chamber; its purpose is to ensure the required electricity for the technical unit at the entry of the cable chamber and the 6kV above-ground substation.

A 6kV, above-ground substation is also specified, placed at the entry of the cable chamber. This substation ensures the supply to the failure mode electrical pumps; the 2000kVA electric generator set is also connected on its busbars.

The 20kV substations and the 6kV substation are made with pre-fabricated, metal, indoor closed bays resistant to open arc, with SF6 switch. IN the secondary circuit compartments of the bays at the 20kV and 6kV substations, digital protective terminals were specified.

Outdoor electric equipment.The objects exterior to the underground power plant are:

The electric equipment at the entry of the cable chamber-The cable chamber is used at the mounting of the 400, 110, 20, 6kV power cable circuits and secondary circuits. It is also used for:

• safety evacuation route for the operating personnel;

• route for the introduction of fresh air for ventilation, via ventilation tubes of an adequate size;

• smoke evacuation route, through special piping.

The ventilation of the cable chamber (hot air ventilation) occurs through fan sets mounted at the entry of the cable chamber. At the entry of the cable chamber , a technical unit is specified, which also include a 20/0.4kV transformer station, including:

• a 20 kV substation with prefabricated 24kV, 630A metallic bays (two 20kV OPL bays, two 630kVA and 1600kVA transformer bays, 1 connecting bay to the 20kV substation in the underground, 1 instrument bay + surge protector);

pg. 90

• a 630kVA, 20/0.4 kV power transformer mounted indoors;

• a 6kV substation with 10 prefabricated 7.2kV, 630A metal bays (two 400kVA and 1600kVA transformer bays, 1 bay for connection to Diesel set, 1 instrument may, six 6kV consumer feeder bays);

• a 1600kVA, 6/20kV power transformer, mounted indoors;

• prefabricated metal cabinets equipped with switchgear for 0.4kV consumers (fans, heater batteries, valve solenoids for cable chamber firefighting water, tunnel lighting and technical unit, rectifiers, etc.);

• a prefabricated metal cabinet with 24V direct current switchgear. The same cabinet includes the 24V storage battery with gel electrolyte and the storage battery charging rectifier;

• a back-up electric generator set, actuated by a Diesel engine; its generator is connected to the busbars of the 6kV substation and through the 1600kVA, 6/20kV transformer this back-up generator set can feed the 20kV substation at the entry of the cable chamber and the 20kV substation in the underground power plant;

• the 20kV, 6kV and 0.4kV cables feeding the consumers;

• the switchgear on the equipment side (lighting, power take offs, etc.)

• the control cabinets of the 110kV connecting substations;

• the grounding equipment for the technical unit (vertical rods made from zinc-coated pipe, connecting strips made from zinc coated steel, connections with the underground power plant, made from zinc coated strips mounted on the cable chamber, indoor grounding belts, connections to the devices).

Electric equipment at the entry of the main access tunnel -The main access tunnel is the access route for the transport of the construction materials required for the execution of the power plant, of the equipment and its mounting materials and a main access route for the working and operating personnel. The main access tunnel allows the evacuation of air from the power plant (fresh air intake and smoke exhaust piping are specified on the cable chamber). At the entry of the main access tunnel, a technical unit including a 20/0.4kV transformer station is also specified, to include:

• a 20kV substation, with 6 prefabricated indoor metal bays of 20 kV, 630 A (2 OPL bays, one 630kVA transformer bay, 1 instrument bay, 1 surge protector bay, 1 back-up bay);

• one 630kVA, 20/0.4kV power transformers, mounted indoors;

pg. 91

• prefabricated metal cabinets, equipped with switchgear for 0.4kV consumers (access tunnel and technical unit lighting, heating and technical unit power take offs, workshops, etc.);

• the 20kV and 0.4kV cables for supply to the consumers and secondary circuit cables;

• the switch cabinets on the equipment side (PIL, PF);

• the technical unit grounding equipment (outdoor earth outlet, indoor earth belts, connecting strips, etc.).

Electric equipment at the upper reservoir -The following elements are installed at the upper reservoir:

• cut-off plates for the bottom discharge of the reservoir;

• cut-off plates in wet pit and cofferdams for the penstock water intake.

The electric equipment at intake valves of upper reservoir is: -the electric supply, control equipment, signaling of intake cofferdams, made up from:

• supply, control and signaling cabinet for flat cofferdam from the intake; • cofferdam limit switches, used in the control and signaling equipment; • electric equipment at the actuating hoist of the cofferdam; • 0.4kV supply cables and control and signaling cables; • the supply, control and signaling equipment for the intake valve, made up from: • electric supply, control and signaling cabinet for intake cut-off plate; • limit switches for the valve, used in the valve control and automation circuits; • electric part included in the pumping set for the hydraulic actuation of the valve

(engines, level transducers, valve solenoids, limit switches, etc.); • 0.4kV supply cables and control and signaling cables; • grounding equipment from the valve house (earth outlet, indoor earthing belts,

connections to equipment, etc.).

The electric equipment for upper reservoir bottom discharge valves is: -the electric supply, control and signaling equipment for upper reservoir discharge valves, made up from:

pg. 92

• electric supply, control and signaling cabinet for bottom discharge cut-off plates; • position switches for bottom discharge valves, used in the valve control and

automation equipment; • electric part included in the pumping set for the hydraulic actuation of the valves

(electric engines, level transducers, valve solenoids, limit switches, etc.); • 0.4kV supply cables and control and signaling cables; • grounding equipment from the valve house (earth outlet, indoor earthing belts,

connections to equipment, etc.); • valve house hoisting machine electric equipment.

At the upper reservoir, the “dam keeper house” is specified, which includes:

• a 20/0.4kV transformer station on the building ground floor, including: • 20kV substation, with six 24kV, 630A prefabricated indoor metal bays (two 20kV

OPL bays, 1 transformer bay, 1 instrument bay + surge protectors, 1 back-up bay); • one 20/0.4kV, 400kVA power transformer, mounted indoors; • 0.4kV prefabricated metal switch cabinets to feed the consumers at the bottom

discharge and intake; • 24 Vdc prefabricated metal switch cabinet, wherein the storage battery and the battery

charge rectifier are also installed; • a control and automation cabinet for the transformer station and for the two valve

houses. This cabinet gathers all the pieces of information and controls from the valve houses and transformer station, transmitted through fiber optic to the power plant and. therefrom, to the dispatch unit;

• a back-up 150kV Diesel set, mounted in a separate room, connected to the 0.4kV busbars in the transformer station;

• 20kV and 0.4kV power cables and control and signaling cables; • earth outlet to the transformer station (outdoor earth outlet, indoor earthing belts,

connecting strips, connections with the earth outlets from the two valve houses, etc.); • dam operating (exploitation) room, also including the room of the measuring and

control devices; • living quarters (accommodation) with the necessary extensions.

Electric equipment at the lower reservoir (Tarnița Reservoir)-At the lower reservoir (existing Tarnița lake), the following elements are specific:

• intake valve house (one valve house per penstock); • screen cleaning device; • dam keeper house.

The electric equipment at each of the two lower reservoir intake valve houses is:

a) the supply, control and signaling equipment for intake cofferdams, made up from: • supply, control and signaling cabinet for cofferdam; • cofferdam limit switches; • electric equipment at the cofferdam actuating hoist;

pg. 93

• 0.4kV supply cables and control and signaling cables;

b) the electric supply, control and signaling equipment for intake valve, made up from: • electric supply, control and signaling cabinet for lower reservoir intake valve; • valve limit switches, limit switches used in the valve control and automation circuits; • electric part associated with the pumping set for the hydraulic actuation of the valve

(engines, level transducers, valve solenoids, limit switch); • 0.4kV supply cables and control and signaling cables; • grounding equipment from the valve house; • electric equipment associated with the hoisting machine in the valve house.

c) The electric supply and control equipment associated with the screen cleaning devices is made up from:

• power supply box for the screen cleaning device; • control and automation equipment for the screen cleaning device; • limit switches; • electric actuating engines for the screen cleaning device; • supply (feeder) and control cables.

At the lower reservoir, the “dam keeper’s house” is specified, to include:

• a 20/0.4kV transformer station on the ground floor of the dam house, including: 20kV substation, with 6 prefabricated 24kV, 630A metal bays (two 20kV OPL bays, 1 transformer bay, 1 instrument bay + surge protectors, 1 back-up bay);

• one 400 kVA, 20/0.4 kV power transformer, to feed the consumers; • 0.4kV prefabricated metal switch cabinets to feed the consumers from the intake

(valve house + screen cleaning device); • 24 Vdc prefabricated metal switch cabinet, wherein the storage battery and the battery

charge rectifier are also installed; • a control and automation cabinet for the transformer station and for the two valve

houses of the intakes. This cabinet gathers all the pieces of information and controls from the transformer station and from the valve houses for the water intakes; such information and controls are sent by fiber optic to the underground power plant and, therefrom, to the dispatch unit;

• one 125kVA back-up Diesel set, mounted in a separate room, connected to the 0.4kV busbars in the transformer station;

• 20kV and 0.4kV power cables and control and signaling cables from the transformer station;

• the earth outlet in the transformer station, outlet connected with the earth equipment from the intake valve houses;

• dam operating (exploitation) room, also including the measuring and control device room;

• living quarters with the necessary rooms.

pg. 94

MCDs-measuring and control devices-The purpose of the monitoring of construction behavior is to know the condition, stability and functionality of the constructions in relation to the project, based on an MCD schedule and on a schedule of direct observations. The behavior of the structures shall be monitored throughout all the phases of their useful life – execution, energizing, operation – as well as in the wake of special events, such as exceptional loads, accidents, failure events, etc.

The behavior parameters proposed for the special monitoring and the types of MCDs at the upper reservoir:

• settling of dam filling pack, by vertical settlement joints and of the crown of this construction, by benchmark measurements; dam settling will be measured at the execution, by vertical settlement joints, to be decommissioned during the exploitation;

• the evolution of the upstream hydrostatic load of the dam, by measuring the water levels at the rod and at the remote gauging station;

• levels of permeability through body of reservoir dams, with piezometric drills and on the zone exterior to the reservoir, by measurements in hydro-geological drills; both the piezometric and the hydro-geological drills will be equipped with piezometric sensors;

• flows drained in perimeter inspection tunnel and drain from the upstream foot of the dam, with spillways; the spillways will be equipped with flow rate meter sensors;

• the relative displacements between the perimeter tunnel sections, with dilatometeric clamps;

• readings from all the remote meters will be collected by using an automatic acquisition station. Hydro-power plant and the transformer cavern:

• water level in the sump of dewatering pumps, by measurements at the rod; • temperature in the power-plant cavern, by measurements at the temperature

transducers; • the distortions of the cavern rock and the unit stress states, by measurements at

telerockmeters, total pressure cells and hardware dynamometers; • the tilts of the power plant poles, by measurements at the teleclinometers; • the power plant and access tunnel settlements, by measurement at the benchmarks; • measures from all remote meters will be collected by using an automatic acquisition

station. Low pressure branching:

• absolute distortions of the flank surface, on three references directions, by micro-triangulation and benchmark measurements.

Behavior parameters monitored by the measuring and control device on construction object

Lăpuștești upper reservoir

pg. 95

• levels of water, levels and flow rates of infiltrations, compaction, relative rod displacements of rod, remote gauging station, spillways, benchmarks, compaction joints, piezometric and hydro-geological drills, dilatometric clamps

• the hydro-power plant and the transformer cavern levels, temperature, unit stresses, rock distortions, slopes, rod settlement, temperature transducers, total pressure cells, dynamometers, telerockmeters, teleclinometers, benchmarks

Low pressure branching

• flank distortions, topographic benchmarks and micro-triangulation The monitored parameters are, mainly, the levels of retention and infiltration water,

the distortions and the states of stresses. The same above-mentioned table shows the types of measuring and control devices monitoring, by measurement, the construction behavior parameters. For the equipping with measuring and control devices, the specific technical laws in force at the drafting of this documentation were considered.

Site and social organization-The construction-mounting works for the objectives at the Tarnița – Lăpuștești PSHP in the zone of the existing Tarnița reservoir are, administratively speaking, in the Cluj county. The access to the zone is ensured via the road existing on the outline of the Tarnița – Mărișelu reservoir, at the altitude of 530 MASL, an asphalt road involving some resizing for the transport of the heavy duty equipment with a 55m convoy and approx. 30m minimum steering circle.

The criteria on which the general organization layout relied are:

• the mandatory positioning of the set-up object (reservoir, branching, power plant) with the established working points;

• the existing sources of construction materials in the zone; • the existing access roads; • the volumes of scheduled works, according to the general schedule, for compliance

with the established 7-year duration of execution; • the technical-administrative and organizational requirements for the working process

platforms; • the necessary amount of materials to be supplied.

For the execution of all the objectives of the set-up, a main group of sites in the Tarnița settlement is proposed, to include:

• site 1 (“Upper reservoir”) is located on the centralised platform at the 1050 MASL level;

• site 2 (“Power plant”) is located on the centralised platform at the 530 MASL level. Technological organization – the main workloads comprised in the work are:

• Surface excavations 3,265,000 m3; • Surface rock excavations 3,700,000 m3; • Underground excavations 560,000 m3; • Filling materials 5,200,000 m3;

pg. 96

• Surface concrete 16,000 m3; • Underground concrete 192,000 m3; • Riprap made of asphalt concrete 433,000 sqm; • Injections 12,000 ton; • Drainages 2,400 ml.

The main quantities of materials to be placed as part of the work are: • Reinforcing bars 15,000 ton; • Metallic profiles 2,000 ton; • Black iron plate 72 ton; • Pipes – pipelines 210 ton; • Cement 57,000 ton; • Electrical cables 8.6 km; • Timber 7,400 m3; • Sand 150,000 m3; • Gravel 400,000 m3; • Cladding 19,000 ton;

For the continuous supply of construction sites and project sites with materials, machinery, tools, equipment, etc., modernizing Gârbau central warehouse has been proposed.

The stagings shall be fitted with items that are critical for the construction of the objective and ensuring optimal conditions under which the main works should take place. The following categories of works have been foreseen:

• administrative spaces, offices; • open and closed material depots; • special depots for safekeeping mildly flammable materials; • scaffolds, ramps, gradient planes; • FPS (fire prevention and suppression) sheds; • constructions and installations of general use: roads, rolling tracks, power grids, water-

supply network, fencing, etc. Social organization – In the area intended for site management works one shall

execute provisional constructions set to accommodate and serve construction workers and the technical and administrative staff. The manpower requirements and dynamics are determined by the C&A (construction and assembly) value schedule and the worker’s annual productivity.

The spaces required to accommodate the population of construction sites, as well as the spaces covering social and cultural needs, have been determined as per the norms in force or using indicators resulted from similar works, designed by ISPH and executed by domestic construction firms. The organization diagram proposes setting up the following camps:

• Mărișelu Camp – the platform at the junction of Someșul Cald rivulet with Leșu rivulet;

• Lăpuștești Camp – the platform in the vicinity of Lăpuștești village and the Upper Reservoir, at the 1050 MASL level;

• Tarnița Camp – on the site of the former camp set up for the Tarnița dam execution. The camps have been sized based on the strict necessities, keeping in mind the

manpower requirements, in accordance with the structure stipulated by the rules in force.

pg. 97

Roads – The roads allow the transportation of materials and machinery during the set-up deployment phase, and the access of motor vehicle for intervention and actual operation within the facility objectives. The access roads were designed taking into account the use of the existing road network and the lowest possible occupation of new land areas.

The ISPH FS (feasibility study) provided the construction of the linking road between the lower reservoir (Tarnița lake) and the upper reservoir (Lăpuștești), by means of a new coastal road which, in addition to the toilsome execution, would have required deforestation – as per the Regional Town Planning, the agreement was to rehabilitate/modernize the existing forest road, which currently links the two areas, thus avoiding any deforestation. Access to the energy investment objectives uses roads, as the area hosting the site of these works does cannot accommodate railroad transportation of the materials and machinery required to execute the works and, later on, of the equipment the facility is to be outfitted with.

The access of motor vehicles in the facility area is provided by national road DN1 Cluj-Oradea or Transilvania A3 motorway, up to Gilău locality, from where one can reach the site by taking DJ (county road) 107.

For the works to be executed on the crest, in Lăpuşteşti area, access is ensured by the same DN1 Cluj-Oradea, via Căpuș locality, along DJ 108 C1 which links all the way to Râșca locality, followed by the route of DC (township road) Râșca-Lăpuștești one can take in order to reach the highlands where the upper reservoir is to be set up. The road connection between the lower part of the investment, located at the 530 MASL level, and the upper part, represented by Lăpuștești highlands, is provided by two routes:

• the road stemming, at the tale of Tarnița lake, from DJ 107 P and following the outline on the left side of Tarnița lake up to the intersection with Fărcașa rivulet, from where, by taking a (hardly passable) forest road, one can reach Lăpuștești (the route has been changed in comparison with the 2008 FS);

• the road stemming, in the Mărișelu Camp area, from DJ107 P and reaching Lapuștești village, from where, by taking a local road, one can reach Lăpuștești highlands (the upper reservoir). The access of motor vehicles and pedestrians to the underground power plant shall be

possible through an access gallery which opens into Tarnița work site, on local road. The cable gallery provides a second access path to the underground constructions. Access to the investment objectives shall require the construction of following new roads 20.6-km long:

• Access road to the power plant (cat. I service road L=1.50 km); • Access road to the cable and outlet gallery (cat. II service road L=1.30 km) • Access road to Lăpuștești camp (cat. I service road L=2.50 km); • Road following the outline of upper lake (cat. I service road L=2.50 km); • Road of crown and climbing and descending arms (cat. II L=5.00 km); • Access road to the upper quarry (cat. I service road L=0.60 km); • Access arms to the upper quarry (cat. II service road L=1.40 km); • Access road to the waste dump and access arms (cat. I service road L=1.80 km); • Service road (cat. II service road L=4.00 km);

Access to the investment objectives shall require revamping the following roads approx. 75-km long:

• Access road to the upper reservoir (cat. I service road L=8.00 km) • Revamping of DM (municipal road)-Lăpuștești camp. Township road L=6.00 km • Revamping of road Rîșca-Fântânele Dam. Township road L=6.75 km • Revamping of road Fântânele Dam.-quarry + steps (cat. I service road L=3.10km)

pg. 98

• Revamping of DM-Risca Township road L=6.00 km • Revamping and consolidation of road Gârbîu train station Tarnița Dam - Someșul

Cald waste dump – national road + county road + offices L=45,00km Access to the objective shall use roads. Forecasts include the construction of new

roads – 29.6 km, concurrently with setting up 66.85 existing km for increased traffic. Current state of the utilities and the consumption analysis:

Water supply - In regard to Lăpuștești locality, there is a partially implemented project on the supply of water to the area. In the area of Gilău township beaches - Tarnița lake there is, currently as a project to be later on implemented, a system designed to supply water to the touristic area. Running water is supplied particularly from a number of drilled wells.

Electricity supply – The built-up areas of townships are linked to the existing power grid of the area. The electrification degree of these townships is approximately 100%, particularly due to the presence of hydroelectric power plants in the area. Mărişelu HP is the starting point of the Cluj-Florești-Mărișelu 220 kV power circuit and another 110 kV power circuit. The local current 20 kV and 0.4 kV power grids supply the constructions in the area.

Natural gas supply – The analysed area does not host any natural gas supply network. Household and meal heating is done either with electrical appliances or gas bottles.

Sewer network – The analyzed area does not host any publicsewer network, the drainage of household waste water being handled, at best, by septic tanks. Gilău township local government has started the implementation of a project focused on building a sewer network in the touristic area of Gilău township.

Carrying out the investment shall lead to the fulfillment of some of the strategic environmental objectives set forth at a national, regional or local level. The main objectives (*) pursued, as well as some of the efforts intended to facilitate their fulfillment: * air quality improvement

• the PSHP commissioning shall help increase the share of renewable energy sources within the total electricity production;

• construction of new roads intended to bypass inhabited areas; • modernization of existing roads;

* preventing erosion • implementation of measures intended to consolidate surfaces that might be prone to

such phenomena; * sustainable management of forest-covered areas

• a selection of sites that would only require limited deforestations; • reintroduction of temporarily occupied lands into the natural landscape;

* preservation of the quality of water sources • setting up a protection areas around the upper reservoir, similar to the one set up for

Tarnița lake; • monitoring Tarnița lake water quality more frequently during the execution of the

works; • implementation of technologies designed to avoid the occurrence of accidental water

pollution events; • setting up a perimeter watch system around the quarry and the waste dump, for the

treatment of waters prior to their discharge into natural emissaries; • assessment of the potential the gangue deposited in the waste dump has to generate

acid waters;

pg. 99

• all the facilities that can generate used household waters shall be fitted with micro waste water treatment plants or scoopable tanks;

• elaboration of a plan for the containment of accidental pollution events; *waste management

• decreasing gangue amounts to be deposited at the waste dump; • the use of gangue for setting up local roads in the area; • the collection, storage and disposal of all categories of waste generated during the

performance of the works shall comply with the provisions of the law; • the waste dump area shall go through the greening process using the best practices in

the field; * prevention / decrease of soil and underground water pollution

• the use of adequate blasting techniques inside the quarry; • implementing an efficient system designed to identify, isolate and remedy any

accidental soil pollution case; * mitigation of the impact upon the natural and built-up environments

• selection of optimal sites; • using minimum technological requirements to reduce the spread of occupied areas; • bypassing inhabited areas in order to optimize access routes; • reintroduction into the natural landscape – upon the completion of works – of

temporarily occupied areas; * life quality enhancement

• creation of new jobs for the local communities in the vicinity; • implementation of active measures intended to increase the number of skilled staff; • setting up new roads in order to extend the current infrastructure; • creation of tourism-intensifying foundations.

Considering that the above-mentioned actions are means to fulfill the relevant

environmental objectives, according to the environmental report, the proposed investment entirely fulfills and meets the environmental protection objectives and requirements. 5. Investment assessment 5.1. Identifying the investment and defining the objectives

The ISPH study of 2014 was elaborated in order to adapt the Romanian energy-related potential to the European Union’s requirements and align it to Romania’s National Energy Strategy. Building a pumped-storage hydropower plant will create, in addition to contributions to covering the domestic load peak, the possibility to export peak energy to third party markets, as well as to provide system services on the domestic and external markets so as to ensure an increased quality level of the energy supplied to consumers. 5.2. General estimate

The general estimate in ISPH 2014 feasibility study on the costs required to build Tarnița–Lăpuștești PSHP contains the following values, by chapter:

pg. 100

COSTS Thousand Euro CH. 1 Land acquisition and planning costs 14,470 CH. 2 Costs required to secure the necessary utilities 186,955 CH. 3 Design and technical assistance costs 50,517 CH. 4 Basic investment costs 780,767 CH. 5 Other expenses 113,359 CH. 6 Costs for technological trials, tests and start-up 4,913 General Total 1,150,981

The General Estimate of the investment was calculated in the ISPH 2014 Feasibility

Study, in the form of two assumptions, namely: A) global investment cost TOTAL GENERAL ESTIMATE: 1,150.981 thousand € of which C&A: 709,276 thousand € B) investment minus the value of the 400 kV power plant and connection to RPS (184,513 thousand €) TOTAL GENERAL ESTIMATE: 966,468 thousand € of which C&A: 563,948 thousand €

The execution of the works is set to take place over a 7-year period, with a two-stage commissioning:

• stage I with start-up for 2 hydro-aggregates at the end of the 5th year; • stage II with start-up of 2 more hydro-aggregates at the end of the 7th year.

Financial planning of the works by year of execution:

Year Stage I Stage II

Total 1 2 3 4 5 6 7

% 10 15 18 22 16 11 8 100 Total General Estimate (thousand €) 115,098 172,647 207,177 253,216 184,157 126,608 92,079 1,150,981

General Estimate minus the 400 kV power plant and connection to RPS (thousand €)

96,647 144,970 173,964 212,623 154,635 106,311 77,317 966,468

5.3. Cost-investments comparison in PSHP projects

Investment costs of pumped-storage hydropower plants worldwide No. Project designation Country Installed

capacity Total investment cost

Cost/Installed MW

Start-up year

- MW Thousand Euro Thousand Euro - 1 Siah Bishe Iran 1000 400,000 400 2013 2 Cisokan Indonesia 1040 615,000 591 2018 3 Alqueva Portugal 240 167,000 696 2012 4 Avce Slovenia 185 120,000 649 2009 5 Feldsee Austria 70.4 50,000 715 2009 6 Huizhou China 2400 900,000 375 2011 7 Kopswerk 2 Austria 450 400,000 888 2008 8 Lima South-Africa 1470 770,000 525 2015 10 Limberg 2 Austria 480 365,000 760 2011

pg. 101

11 Tehri India 1000 368,000 368 2013 12 Xilongchi China 1200 500,000 416 2009 13 Zhanghewan China 1020 210,000 200 2009 14 Goldisthal Germany 1060 600,000 566 2004 15 Yixing China 1000 490,000 490 2008 16 Liyang China 1500 900,000 600 2016 17 Nant de Drance Switzerland 900 800,000 880 2016 18 Jixi China 1800 900,000 500 2015 19 Grimsel 3 Switzerland 660 550,000 833 2016 20 Atdorf Germany 1400 1,200,000 857 2018 21 Reisseck 2 Austria 430 335,000 779 2014 22 Dniester Ukraine 2268 720,000 317 2012 23 Ingula South-Africa 1350 600,000 444 2013 24 Tarnița (no connection) Romania 1000 1,000,000 1000 2025 5.4. Option analysis

Considering the high degree of uncertainty concerning the evolution of demand for electricity, of the prices of fuel on the international markets, of the environmental requirements, etc., the “Solution study for placing the PSHP operation on the load curve with a view to the development of RPS and a regional electricity market”, conducted by ISPE-Bucharest (Institute for Power Studies and Engineering), analysed various execution scenarios, keeping in mind the long-term electricity consumption forecasts. In the end, the Tarnița-Lăpuștești PSHP project facility has the following hydropower and constructive parameters:

Parameter M.U. Value • NRL (normal retention level) upper reservoir (Lăpuşteşti storage) MASL 1,086.00 • Weight centre level (Lăpuşteşti storage) MASL 1,071.00 • Minimum level upper reservoir (Lăpuşteşti storage) MASL 1,053.50 • NNR lower reservoir (Tarniţa storage) MASL 521.50 • Weight centre level (Tarniţa storage) MASL 518.00 • Minimum energy operating level (Tarniţa storage) MASL 514.00 • Volume upper reservoir (Lăpuşteşti storage) mil. m3 10.00 • Gross water drop (1086-514) m 572.00 • Mean water drop (1086-521.50) m 564.50 • Minimum water drop (1053.50-521.50) m 532.00 • Maximum flow rate during turbination m3/s 4 x 53 • Maximum flow rate during pump operation m3/s 4 x 38 • Outfitting: 4 reversible pump-turbine unit :

- under “generator” running conditions - under “motor” running conditions

MVA MW

4 x 280 4 x 250

• Installed capacity MW 1,000 • Pumping cycle weekly • Energy produced under “generator” running conditions GWh/year 1,649 • Energy consumed under “pump” running conditions GWh/year 2,103 • Current ratio 0.78 • f/P (frequency-power) secondary regulation hMW 9,16,300 • Fast tertiary reserve hMW 4,108,650 • Dispatchable consumption system service hMW 2,352,000

pg. 102

Due to high maneuverability and the possibility to operate during pumping or turbination, this pumped-storage hydropower plant provides the following services for RPS:

• it improves the operating mode of the large units within Cernavodă NPP and of fossil fuel-powered condensation electric power plants and combined heat and power plants via the transfer of electricity from low load to peak load;

• it contributes to the frequency-power regulation; • it secures the fast tertiary reserve; • it secures the short-term failure reserve; • it ensures optimal conditions for the operation of wind power plants, etc.; • it provides reactive power and operation in offsetting mode, making sure that the

electricity quality standards are complied with; • it optimizes the RPS participation in the single electricity market, increasing the global

safety levels of RPS, • it provides the possibility to operate RPS under superior technical and economic

conditions. The option proposed as part of the substantiation study provides that the works

be executed over 5 years. The financial analysis was conducted for this technically and economically updated version.

The PSHP parameters were determined and Lăpuşteşti lake was sized taking into

account the following assumptions: • The operation of the PSHP as a peak load power plant within RPS; • Operation for frequency-power regulation with Pi (installed capacity) = 1,000 MW; • Operation as a short-term failure reserve power plant; • Weekly pumping cycle, with 2 non-business days (the upper lake is fully filled up, via

pumping, during non-business days and the Sunday-to-Monday night, then emptied via turbination during business days, at peak hours and partially refilled during low load hours). Keeping in mind where Tarniţa–Lăpuşteşti PSHP is placed on the load curve (acc. to

the ISPE Study), a simulation of the average one-week operation (suggestive of an average year over a multi-year period) was carried out, with the following operating mode:

The total number of pumping/turbination hours a week is: Number of pumping hours:

• number of pumping hours with 2 pumps/week: 30 h; • number of pumping hours with 3 pumps/week: 36 h; • number of pumping hours with 4 pumps/week: 6 h; • total number of pumping hours/week: 72 h.

Number of turbination hours: • number of turbination hours with 2 turbines/week: 8 h; • number of turbination hours with 3 turbines/week: 40 h; • total number of pumping turbination/week: 48 h.

Taking into this information and the fact that the upper reservoir has to go through a complete filling-emptying cycle over the course of one week, the amounts of energy consumed and produced were calculated:

pg. 103

• pumped energy / week 42.93 GWh; • total pumped energy / year 2,103.33 GWh; • produced energy / week 33.66 GWh; • total produced energy / year 1,649.46 GWh. The main hydropower parameters of Tarniţa – Lăpuşteşti PSHP are: • Installed capacity (Pi) 1,000 MW; • Pumping cycle weekly; • Energy amount produced as a generator unit 1,649,457 MWh/year; • Energy amount consumed running as a pump 2,103,328 MWh/year; • Current ratio 0.78% Volume of system services

The main characteristics the estimation of system service volumes relied on are: ● Installed capacity by unit, under turbine operating mode = 250.0 MW; ● Installed capacity by unit, under pump operating mode = 250.0 MW; ● Secondary regulation range, by unit (turbine operating mode) = 137.5 MW; ● Fast tertiary reserve range, by unit (turbine operating mode) = 243.7 MW; ● Dispatchable consumption range, by unit (pump operating mode) = 250.0 MW;

In correlation with the estimated running hours, in both generator and pump operating

modes, and based on the technical characteristics, the maximum available volume of system services was estimated, namely:

• f/P secondary regulation 916,300 hMW; • Fast tertiary reserve 4,108,650 hMW; • Dispatchable consumption* 2,352,000 hMW;

Given the fact that, as per the provisions in the Commercial Code and the Technical

Code of RET (Electricity Transmission Grid), PSHP can also provide the“Dispatchable consumption” system service, in addition to the secondary regulation and the fast tertiary reserve, the estimation of this system service was calculated, as well (Dispatchable consumption: a place of consumption where the consumed power can be altered at the Transmission System Operator’s request) 5.5. Working assumptions

The goal of the financial analysis is to calculate the financial performance of the investment proposed over the reference period and determine the best financing structure for it. The financial analysis is a methodology which uses income and expenditure to assess investment projects. The analysis results are presented as project financial performance indicators:

• benefit-cost ratio (BCR); • updated net income (VNA); • internal rate of return (IRR). These indicators show the capacity of net incomes to cover investment costs,

regardless of the funding avenues for such investments. The PSHP financial efficiency was

pg. 104

calculated using the methods recommended by international financial bodies and employed worldwide.

The methodology employed relies on the influence of the time factor upon monetary flows by means of the discount rates applied. The calculations were done for discount rate values within 3 ÷ 10 % range.

Several financial analysis versions were performed, for the year 2018:

Assumption A: Total investment value = 1,150,981 thousand € Assumption B: Total investment value does not comprise the 400 kV power plant and the connection to RPS = 966,468 thousand € + 33,532 (increases due to inflation and various costs incurred after 2014) = 1,000,000 thousand €, as an estimate

Calculation assumptions: • estimated investment value – 1 billion Euro; • single-stage investment; • PPP contract term – 30 years, of which 5 years for financial closure, design and

execution; • annual availability-based payment – 50 million Euro; • discount for bringing the execution deadline forward – 100 million Euro/year. • average selling price of energy produced under deficit – 61.0 €/MWh; • average purchase price of energy consumed for pumping under surplus – 14.7 €/MWh;

The system services were assessed in line with the regulated tariffs (ANRE Decision from 2014), namely:

• for Secondary regulation: 13.7 Euro/hMW • for the Fast tertiary reserve: 6.8 Euro/hMW • for the Dispatchable consumption: 6.8 Euro/hMW (a place of consumption where the

consumed power can be altered at the Transmission System Operator’s request) Income forecast (estimates based on current prices)

System service Minimum price Maximum price

Quantity Minimum income

Maximum income

Secondary regulation 13.7Euro/hMW 16 Euro/hMW 916,300 12,553,310 14,660,800 Fast tertiary regulation 6.8 Euro/hMW 8 Euro/hMW 4,108,650 27,938,820 32,869,200 Dispatchable consumption

6.8 Euro/hMW 11 Euro/hMW 2,352,000 15,993,600 29,172,000

Electricity production 45 Euro/MWh 61 Euro/MWh 1,650,000 74,250,000 100,650,000 Electricity consumption 14,7Euro/MWh 25 Euro/MWh 2,103,000 (30,914,199) (52,575,000) Total income 130,735,730 177,352,000 Total expenditure (30,914,199) (52,575,000) Total general 99,821,531 124,777,000

Basic financial model (indicative estimates of the Debt vs. Equity assessment) Variants minimum maximum Minimum/maximum income (GPI=gross possible income) 99,821,531 124,777,000 Annual O&M cost (0.7 % investment value – recommended in ISPH FS)

7,000,000 7,000,000

NOI (net operating income) - O&M cost 92,821,531 117,717,000 Debt Coverage Ratio - DCR (desirable, 1.4-1.5) 1.5 1.4

pg. 105

NOI: DCR=Annual Debt Service (ADS) 61,881,021 84,076,430 ADS:loan recovery coefficient (K = 0.103 for 6% interest, 15-year pay back) =Debt

600,076,650

816,276,005

Loan (may be borrowed from banks) about 600,000,000

about 816,000,000

NOI-ADS = cash flow before taxes -CFBT 30,940,510 33,641,570 11.CFBT: rate of return on equity-(RRE-desirable, 18% ) 172,000,000 187,000,000 Estimated total investment (Equity + debt) 772 mil. Euro 1,003 mil. Euro

The analysis of the presented financial model very clearly emphasizes that, at the

maximum income estimate (124,777,000), under a DCR of 1.4, a bank loan of around EUR 820,000,000 can be obtained, over a 15-year period, with 6% interest, that is approx. 80% of the investment.

The equity value is around 187-200 mil. Euro, meaning approx. 18-20% of the investment, which provides an annual Return of Equity of 18%, 3-4 times higher than the bank interest.

Fig.5.1. Evolution of EM (electricity market) and DAM over the 2012 -2016 interval

(Giga Energy 2017 study)

6. Studies and analyses on the project implementation method 6.1. Differences between PPPs and traditional public procurements

6.1.1. Current context In order to set forth the relative merits of the project development alternative methods, the method employed as part of the substantiation study relied on comparing the project

Price with EM deficitDAM pricePrice with EM surplus

pg. 106

development costs in a PPP scenario with the project development costs in traditional public procurements. RO03 INGB 0000 9999 0533 5760 Concerning the potential project funding, as part of LIOP (Large Infrastructure Operational Programme) 2014-2020 or other programmes benefitting from community funds, the current and projected medium-term context is the following: The project is able to generate financial revenues. The financial analysis results (see the

sections below) indicate the fact that the financial return on total equity is positive and, therefore, the financing gap rate would be significant, entailing an elevated share of public contribution (co-financing). All these aspects make accessing non-reimbursable funds unlikely for the project in question, considering the characteristics presented in the current study.

Taking into account the subsequent operational programme (2021-2027) and the financial envelope distribution, it is unlikely to benefit from full project funding under these circumstances, given the high capital costs and the project particular aspects (the positive financial return).

Therefore, the projects which are not likely to benefit from non-reimbursable European funds and are undertaken by the Romanian government as priority projects will only find two methods of implementation, namely: funds provided by the state budget or a public-private partnership.

Consequently, considering the identified limitations, two possible avenues for funding the project implementation have been determined:

1) a public procurement procedure, for design services and construction works, for the completion of already commenced works and, subsequently, for maintenance and operation contracts receiving funding from the state budget;

2) a procedure for design services and construction works required to finalize works under a public-private partnership, a partnership pursuant to which the private partner, following the completion of the remaining construction works, shall operate the PSHP assets.

Analyzing the option of the traditional public procurement procedure, for design services and construction works, we realize that committing such expenditure from the state budget would have us increase the budget burden and the budget deficit to levels that exceed Romania’s commitments made to the European Union. Therefore, this alternative, although on the table, is merely a pseudo-alternative considered only to comply with the laws in force. Regarding the public-private partnership, keeping in mind the arguments listed above on the budget burden and the budget deficit, we took into account (as per Emergency Ordinance no. 39/2018 on the public-private partnership) the following aspects: Art. 10. - The financing of investments made under public-private partnership contracts can be provided, as the case may be:

a) in full, from the financial resources provided by the private partner; or or b) from financial resources provided by the private partner, together with the public partner. The options above shall take into account the budget deficit, which is affected by the availability-based payments (according to Emergency Ordinance no. 39/2018 on the public-private partnership). Art. 14. -

pg. 107

(1) Through the public-private partnership contract, the public partner will be able to transfer or establish, in favor of the project company, the right to collect and use - for the project implementation - rates from the beneficiaries of the good / assets or public service constituting the object of the public contract. The types of rates and value thereof are governed by the law. (2) The project revenues resulting from the project company’s rates collection shall be supplemented with the public partner's payment obligations to the project company or the private partner, as the case may be, according to the provisions of the public-private partnership contract. The project revenues resulting from the collection of rates shall be supplemented with the public partner’s payment obligations, so that they should provide a reasonable profit to the Private Partner. In order for the investor, as per Emergency Ordinance no. 39/2018, to be able to secure a reasonable profit and for the tariffs associated to the levy to be reasonable and affordable, the contract term stipulated was 25 years, 20 of which would be reserved for operation. Art. 33. - (1) The term of the public-private partnership contract shall be determined mainly according to the repayment period of the investments to be made by the project company and subject to the method of funding these investments. (2) The term shall be established in a manner that would: a) avoid the artificial limitation of competition; b) ensure a reasonable profit for the respective field, by making use of the goods/assets and operating the public service under the project; c) ensure a reasonable and affordable price for the services under the project, to be paid by the beneficiaries of those services. Selecting either option shall resort to an analysis (substantiation study) which should indicate whether implementing the project under a PPP procedure is, from an economic standpoint, more efficient than implementing the project as a classic public procurement. The sections below present the differences between the two procurement options, as well as a brief overview of the methodology employed, according to the international standards, to determine the opportunity of implementing a project under a PPP procedure, commonly known as the “Value for Money” analysis (analysis on the economic and financial benefits), based on previous studies and those drawn up for the present substantiation study. 6.1.2. Traditional public procurement method In the field of infrastructure, depending on the specific infrastructure a public authority intends to build/rehabilitate, the public authority shall take into account Decision no. 1/ 2018 on the approval of general and specific requirements for certain categories of procurement contracts, pertaining to investment objectives financed from public funds. Implementation can be made through one of two methods:

1) A single public procurement procedure - the launch of a public procurement procedure for design services, technical execution project and execution works.

2) Two public procurement procedures. - the launch of a public procurement procedure for design services, technical execution project, followed by the launch of a public procurement procedure for execution works as per the technical execution project.

pg. 108

The second option offers, however, the most remote perspective in terms of implementation, in relation to the critical need to implement, a need which would also have to observe the commitments related to the implementation period made to the European Union. For Tarnița-Lăpuștești PSHP construction project, in the case of the traditional method (a public procurement regime), the comparison was made in relation to the contractual conditions, according to Decision no. 1/2018 for the approval of the general and specific conditions for certain categories of procurement contracts specific to the investment objectives financed from public funds reserved for design and construction. This method is, at the same time, the closest to the PPP structure (given that the design risk is taken over, in both scenarios, by the contractor) and is used for generic purposes by the Ministry of Energy in procurement procedures for design and construction of energy infrastructure, mainly used in the case of large infrastructure works with a severely delayed implementation. a) The design and construction stage

o several design and construction contracts would be awarded, following bidding procedures, for various investment components, within the budget allotted for the project;

o considering the historical database, the period from launch to contract awarding lasts approximately 12 months

o a fixed nominal price for the planned design and construction period, but only for the initially planned construction stage;

o the procedures for awarding public procurement contracts are initiated on condition of securing a financing source. In this case, we are dealing with the state budget;

o the payments are made depending on the progress of works and require, therefore, public funds that are sufficient to carry out the design and construction stage, which might lead to a limited availability of funds for works that are required as part of other public projects; in short, there is pressure exerted upon the budget and the budget deficit over a complicated period of time, in terms of observing the commitments to the European Commission, also in regard to the budget deficit;

o unlike the option under a PPP regime, the risks pertaining to the interface among the various parties involved in the project are borne by the contracting authority.

o the Contractor shows no interest in executing works that are sustainable, easily and ideally maintainable from a cost perspective.

b) The maintenance and operation stage

o the maintenance and operation works would be purchased separately from the works in the construction stage / direct labor operations, depending on the yearly allotted budget, and not necessarily based on performance criteria;

o in the case of maintenance and operation works, pursuant to the purchase of these services and the work itself, the public procurement procedure takes place and may lead to gaps and delays in the performance of such works. No long-term strategy is taken into account that would correlate with the initial design stage.

o as the case may be, the payments are made depending on the progress of works or are comprised in the ME (Ministry of Energy) budget in regard to works carried out by oneself; even if the decision to make and conceive other investments (in terms of scope, schedule, technical specifications) is made by the contracting authority, the maintenance of the respective road sections may not take place based on technical optimization grounds, but on grounds related to prioritizing the use of available funds, in case there are projects with immediate or more pressing investment requirements.

pg. 109

c) Financing

o the financing source would be the state budget and, therefore, any loan would ultimately be contracted at a state level, the costs being immediately recorded in the public sector balance sheet, thus contributing to a budget deficit increase;

o significant funding needs of the contracting authority, particularly during the actual investment execution stage;

o in order to make the payments related to the construction works, the maintenance activities, etc., the contracting authority requires a high amount of loans, which leads to an elevated debt level for the Romanian Government; on the other hand, if the project runs under a PPP, the payment requirements are broken down into periodic installments distributed over the exploitation stage according to the PPP contract, therefore, only after the PSHP operation has begun, will they directly depend on the private partner’s performance, reflected in the level of services provided to the users.

6.1.3. Public-Private Partnership According to Emergency Ordinance no. 39/2018 on the public-private partnership, “the public-private partnership mechanism features the following main elements:” a) “cooperation between the public partner and the private partner for the purpose of implementing a public project;” The Ministry of Energy makes available a project and a well-established location for the execution of the works. The project and the execution works will be carried out as per the provisions of the law and the technical regulations valid in Romania. During the contract term, the income from the sale of electricity and the public partner’s participation shall account for the only form of income by means of which the private partner will recover the investment and secure profit. There will be permanent assurances that the private partner, during the operation period stipulated in the contract, will maintain the electricity production within certain parameters, based on defined performance criteria defined in the contract. b) “the relatively long duration of carrying out contractual relations, in excess of 5 years, that would allow the private partner to recover the investment and secure a reasonable profit;” 25-year proposed contract term. This stage will be preceded by stage 2, as one shall take into account the period of time and the works depreciation period, estimated at approximately 50 years, according to the Catalogue with the classification and normal operating durations of fixed assets, dated 30.11.2004, approved by the Romanian Government as per Decision no. 2139/2004 from November 30, 2004. This would undoubtedly secure a profit for the private partner, proportionate to the undertaken risks. c) project financing, primarily from private funds and, as the case may be, by pooling the private and the public funds; Project financing, primarily from private funds, given the absence of any other form of funding at present. This financing need emerges from a dire need to execute a new PSHP, as demand practically fails to be matched by the project funding availability from non-reimbursable European funds or the state budget. d) “fulfillment of the purpose pursued by the public partner and the private partner The public partner must execute this PSHP, as an absolute requirement, and can only do this at present with the help of a private partner. The private partner, by means of the long contract term, shall fulfill their objective as far as securing a profit is concerned.

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e) distribution of risks between the public partner and the private partner, depending on each contracting party’s capacity to assess, manage and contain a particular risk. The substantiation study intends to produce a risk matrix, to be discussed in detail over the period of competitive dialogue with the parties that chose to take part in the dialogue. In the case of the PPP contract, the private partner is bound to secure road construction and financing from their own resources (75%), without the direct implication of the public authority. Since the current data analysis indicates the fact that income from electricity production will be sufficient to cover all the capital, funding and maintenance costs, there will be no need for a depreciation-contributing payment, covered by the Government. Nevertheless, the project company/private partner providing the service will generate profits, to be distributed to equity providers and will thus generate a cash flow back to the public authority in the form of income tax. Although there clearly are, across the entire economy, other potential effects caused by the project upon the collection of taxes, it was assumed that these effects are generally specific to both purchasing methods and, therefore, unable to generate differences between the two. The model compares the net cash flows in the case of PSC (Construction Trade Association) and PPP, expressed as total NPV of the total cash flows, for each cost category. Therefore, the significant differences between purchasing under a PPP and the traditional public procurement method consist in:

o the responsibility of conducting the maintenance and operation works belongs to the same company in charge with the design and construction, which leads to streamlining these two activities during the project life span;

o the private partner is a project company (designated in the literature “Special Purpose Vehicle” - SPV) whose objective is to fulfill the obligations deriving from the contract;

o the funding of this company is non-recourse or limited recourse and exclusively relies on the future estimated cash flows to be obtained from the activity conducted by this company for the sole purpose of implementing the contract and used to reimburse the funds made available (equity plus the contracted loan);

o the involvement of the project company’s shareholders is generally limited to funding the project company by way of contributions to the share capital and shareholder loans;

o the actual design, construction, operation and maintenance activities are conducted by subcontractors, project company affiliates, which issue performance bonds in favor of the project company;

o the payments to the private partner are made exclusively based upon and depending on the availability and the quality of the services rendered during the contract term, construction quality being thus secured based on the commercial interest; as a consequence, when the PPP contract is signed, the PSHP use and maintenance costs are known, unlike the traditional public procurement procedure, where decisions on the performance of operation and maintenance activities are made at future points in time, after the infrastructure has already been set up, thus resulting for a PPP a much higher cost predictability than in the case of a project carried out as a classic purchase;

o most risks are allotted to the private partner, the rule being that the public partner shall exclusively bear the risks expressly allotted to them according to the contract.

o in comparison with the traditional purchase process, the private partner’s financing costs are higher in the case of a PPP project; on the other hand, the purchase of electricity production services under a PPP, as opposed to the purchase of distinct contracts for electricity production and supply (broken down via the construction of several, lower-power PSHPs), will, accordingly, lead to a high level of risk transfer,

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and savings, to and for the private partner, which can translate in bidding with prices deemed competitive by the contracting authority, as well as in the existence of adequate incentives for the private partner to perform the contract within the contractual deadlines and costs set forth (otherwise their capacity to reimburse the loan being jeopardized due to the lack of income and the project fails to advance to the exploitation stage within the deadlines set forth with the contracting authority and the financers), which would also make it possible to obtain the intended economic and social benefits.

o considering the focus laid upon the private partner’s performance in providing services during the entire operational stage of the project, as per the nature of PPP contracts, it is essential to pay attention to the investment end user.

Beyond these differences, determining advantages in favor of either of the two options makes use of an economic and financial analysis, known in the literature as “Value for Money” (chapter 5.3.). 6.2. Project economic efficiency presented via a cost-benefit analysis 6.2.1. General approach The economic analysis intends to estimate the impact of the project and its contribution to economic growth at a regional and national level. This is achieved from the perspective of the entire society (municipality, region or country), not only from the infrastructure owner’s perspective. The project has a national, and even a cross-border impact. The financial analysis is deemed a starting point for drawing up the socioeconomic analysis. In order to determine the socioeconomic indicators, certain adjustments need to be carried out in relation to the variables employed in the financial analysis. The main recommendations concerning the harmonized analysis of electricity production projects refer to the following elements:

o General elements: assessment techniques, the transfer of benefits, the management of unquantifiable impact, capital update and transfer, decisional criteria, the project analysis period, future risk and sensitivity assessment, the marginal cost of public funds, the value surplus for electricity consumers, the management of indirect socioeconomic effects;

o Environmental costs; o The capital investment costs and indirect impact (including the capital costs required

to implement the project, the maintenance, operation and management costs, the residual value).

6.2.2. Analysis time frame (reference period) The reference period is understood as the maximum number of years for which forecasts are drawn up as part of the economic and financial analysis. The forecasts on future developments of the project have to be formulated for a suitable period in relation to the

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duration for which the project is economically useful. The choice of the reference period may have quite a significant effect upon the project financial and economic indicators. In more concrete terms, the reference period selected will influence the calculation of the main indicators of the cost-benefit analysis and may also affect the amount of the co-financing rate (in the case of projects with community funding). For most infrastructure projects, the reference period is at least 20 years, whereas the same period for productive investments is approximately 10 years. The average life span of a PSHP is at least 50 years. Consequently, in order to outline in the most relevant manner possible the project implementation socioeconomic impact, the economic analysis shall be performed over a 50-year time frame, which includes the project implementation period (7 years). On the other hand, the project financial profitability analyses shall be carried out over a 32-year period and shall include the same investment implementation period (7 years). 6.2.3. Basic assumptions The main goal of the economic analysis is to assess whether the benefits of the project exceed its costs and whether or not promoting it is a worthy effort. The analysis was elaborated from the perspective of the entire society, not only from the project beneficiaries’ standpoint and, in order to register the entire range of economic effects, the analysis includes elements with direct monetary, such as the construction and maintenance costs and the savings from the costs required to operate vessels and motor vehicles, as well as elements without a direct market value, such as an increase of area recognition, which might also attract other investors in the future, and the environmental impact. All the effects are financially quantified (that is, they receive a monetary value) so as to allow making a consistent comparison between costs and benefits within the project, and then added up in order to determine its net benefits. Thus, one may determine if the project is desirable and implementing it is worth the effort. Nevertheless, it is important to accept the fact that not all the effects of the project can be financially quantified, in other words, not all socioeconomic effects can be attributed a monetary value. The year 2018 is taken as a reference point, being the point when the cost-benefit analysis was drawn up. Therefore, all the costs and benefits are updated in relation to the real prices of 2018. The reference period used in 50 years. Likewise, these assumptions were adopted in accordance with the European rules, as they are depicted in ‘Guide to cost-benefit analysis of investment projects’ – “Evaluation Unit - DG Regional Policy”, the European Commission. The performance indicators used for the revamping works were the Net Present Value (discounted benefits minus discounted costs) and the Yield Level (the benefit/cost rate). The latter expresses the updated benefits in relation to the invested capital monetary unit. In the end, results are also expressed as the Internal Rate of Return: the discount rate for which the Net Present Value would be zero.

Economic Internal Rate of Return

The calculation of the Project Internal Rate of Return (EIRR) relies on the assumptions below:

o All the incremental costs and benefits are expressed in real 2018 prices, in Euro;

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o EIRR is calculated for a 50-year duration of the Project. It includes the investment period (the first seven years, conventionally marked by years 0-6), as well as the operation period, until year 50 (effectively, year 2067);

o The economic viability of the Project is assessed by comparing EIRR with the actual Economic Opportunity Cost of Capital (EOCC). The EOCC value used in the analysis is 5.5%. Therefore, the Project is considered economically feasible if EIRR is higher than or equal to 5.5%, a requirement which corresponds to obtaining an improper benefit/cost ratio.

Investment scheduling

In terms of scheduling, the investment was assumed to take place over a five-year period, corresponding to analysis years 0-6, according to the Project Master Schedule.

Economic benefits

The socioeconomic analysis took into consideration only some of the monetary components with a direct influence. In order to determine these benefits, the same incremental analysis concept was applied, namely the benefits are estimated as part of the difference between the “with project” and the “without project” cases. The socioeconomic impact pursued by means of implementation pertains to enhancing access to the community resources and activities, but also in regard to the direct positive effects upon the users and the community. The indicators used to estimate the capacity of the project to fulfill these objectives are: o the benefitting population and the electricity providers; o the direct impact upon users, in the form of a decreased general cost; o the (positive) impact upon local and regional development; o an increase of employment opportunities within the project area of influence; o the degree of acceptability by the population; o the rate of return indicators; o other positive factors difficult to identify or quantify. The table below presents the basic assumptions of the economic analysis, the quantified costs and benefits, as well as the project result and project economic efficiency rating indicators. Table 6-1. Basic assumptions, quantified measures and result indicators of the economic analysis

Category Indicator Description Basic assumptions Economic discount rate EOCC 5.5% Costs discount year 2018 Costs reference year 2018 Analysis period, of which 50 years Construction 5 years 2019-2025 Operation 43 years 2025-2068 Exchange rate Lei/Euro 4.66

Economic costs CapEx Investment cost/capital expenditure OpEx Maintenance and operation costs/operational expenditure

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Category Indicator Description

Quantified economic benefits

Benefits from a decrease of negative effects upon the environment

Benefits from electricity production and supply Benefits from avoiding damages caused by floods Benefits from creating temporary and permanent jobs Tourism-related benefits Benefits from the increase of budget revenues

Result indicators EIRR Economic Internal Rate of Return ENPV Economic Net Present Value BCR Benefit/Cost ratio

6.2.4. Quantification of economic benefits The Economic Analysis assesses the economic feasibility of the project based on the socioeconomic benefits generated at a regional and national level. Considering the complexity and magnitude of the investment project, identifying and monetizing the induced economic benefits is a complex and difficult process. The following categories of induced socioeconomic categories shall be assessed:

o Social benefits

o Benefits from induced activities The summary of the social benefits to be monetized is presented below:

Table 6-2. Quantified economic benefits

A. Social benefits B. Benefits from induced activities

A.1 Benefits from a decrease of negative effects upon the environment

B.1 Benefits from an increase of region recognition

A.2 Benefits from creating temporary and permanent jobs

B.2 Benefits from the increase of budget revenues

Only a part of the economic and social benefits can be quantified (monetized). These are:

o Benefits from creating temporary and permanent jobs

o Benefits from the increase of budget revenues

A. Assessment of social benefits

Forecast of benefits from the creation of temporary and permanent jobs The impact shall be felt at a regional and national level. It is difficult to provide an exact estimate of the positive effects generated upon the employment level. In order to avoid the overestimation of this category of benefits, the assessment shall strictly focus on the number of jobs generated within the Administrator’s and the Contractor’s structures. As such, the estimates for the recommended technical solution (the PSHP construction) are:

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o During the execution phase: 5000 jobs * 7500 lei gross salary

o During the operation phase: 300 jobs * 7500 lei gross salary (for the year 2019, according to the NCP (National Commission of Prognosis) forecasts The categories of jobs held are the following:

o During the execution phase: skilled workers, technical, economic, administrative and supervisory staff

o During the operation phase: skilled workers for maintenance works and operation, technicians, engineers, accountants, biologists

The total non-present value of the benefits from the creation of jobs is 57.1 million Euro during the first seven years, to which 12.1 million Euro are added during the operation years.

B. Assessment of benefits from induced activities

The emergence of Tarnița-Lăpuștești PSHP shall have a major impact upon the economic activities in the area of influence. It is believed that the impact shall be felt locally, nationwide, as well as at a European level. Only some of the economic benefits from induced activities can be quantified (monetized). Forecast of benefits from income taxation The direct income assessed as part of the financial analysis shall be subject to direct taxation. As such, the State Budget revenues shall increase. The taxation rate is estimated to be 32% (comprising VAT, corporate tax, turnover tax, other taxes). The total present value of these economic benefits ranges between 500 and 605 million Euro, depending on the prices the electricity produced is to be sold at. Below you may find the summary of the socioeconomic benefits, assessed as part of the cost/benefit analysis. The major share is held by the benefits from the creation of jobs, the benefits from a decreased number of negative effects upon environment, as well as the benefits brought along by increased revenues to the State Budget. 6.2.5. Analysis of non-monetized induced socio-economic benefits This section analyses the current data in terms of direct and indirect social and environmental benefits associated to the production and supply of electricity, which were not in the previous section. The coverage of the data available for this section is deficient. The economic impacts are generally calculated from the measures associated to investments in infrastructure, facilities and business-related activities. Direct formal benefits Some of the business activities dealing with electricity production and supply are evident. They include electricity providers/dealers and direct consumers. Other benefits are less obvious, for instance, street lighting in a certain region can be improved as electricity is purchased at a more affordable price. Such benefits are not located in the close vicinity of the PSHP, but gain directly from the activities generated by the PSHP. Direct impacts (benefits) include the initial round of expenditure and hiring generated by the activity sectors directly related to the PSHP. Direct impacts do not contain a multiplier effect; in other words, they do not include any other additional “round” of expenditure for the economy. Data of this kind tends to be the most solid. Indirect formal benefits

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All the business ventures in the region of the PSHP construction will consume electricity. With a better service coverage of the area, their number may grow. Included here are enterprises the provide goods and services to the companies located near the PSHP construction area. Business activity is also generated by enterprises whose dealings are directly related to the PSHP existence and operation (such as food, clothing, shelters, fuels, etc.) by means of the people directly involved in the activities and business dealings related to the PSHP operation. These business activities focus on the PSHP operation and develop the local economy by generating sales, personal income and creating new jobs. The sales stemming from business generated by the PSHP operation create within the economy additional expenses from other enterprises and/or households, thus multiplying the economic benefits. These rounds of expenses (economic impacts) are measured as direct, indirect and business-induced sales, personal income and the creation of new jobs in the local economy. The indirect economic benefits can be substantial. Similarly, we should not neglect the significant development potential of the residential segment, with the construction of private dwellings or bed & breakfast facilities (boarding houses). Data on the indirect and induced benefits are generally inaccurate, less solid than the data collected on direct benefits. Most of the data collected comes from the analysis of specific local investments, showing an inconsistent use of multipliers and certain evidence of multiple counting. In the absence of accurate data on the results of these activities, these indicators cannot be summed up in order to produce larger-scale diagrams. In any case, the trend is clear and points to substantial benefits, with investment/benefits ratios of 1:10 or higher. Multiplier effect The multiplier effect generated by the project implementation can be associated to the following variables:

o Sustainable economic growth induced by the Project implementation;

o Exogenous benefits emerged following an improvement of the social setting in the Project area of influence

o Other factors difficult to quantify and identify.

6.2.6. Calculation of the project economic performance indicators In terms of rating the investment rate of return, for a 5.5% capital economic discount rate (the discount rate), the following economic cost-effectiveness indicators were calculated:

o Economic Internal Rate of Return (EIRR)

o Economic Net Present Value (ENPV)

o Benefit/Cost ratio (BCR). Two scenarios were calculated, one for the case in which the electricity production

achieved (or consumed) shall be sold (or purchased) at the minimum market prices, and one for the case in which the electricity produced is sold at the maximum market prices.

Table 6-3. Project rate of return indicators Main parameters and indicators Values for minimum

prices Values for maximum prices

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Social discount rate (%) 5.5% 5.5% Economic Internal Rate of Return (EIRR) 19.97% 22.09% Economic Net Present Value (ENPV) 1.55 billion Euro 1.89 billion Euro Benefit/cost ratios (BCR) 2.82 3.22 The economic analysis of the project indicates the investment opportunity, with a positive ENPV, but also its beneficial effect upon the local economy, more significant than the economic and social costs it entails, whereas the benefits/cost ratio is higher than 1, whether or not the sale of electricity demands minimum or maximum prices. In regard to the project Economic Internal Rate of Return, it ranges between 19.97% and 22.09%, values that are higher than the 5.5% social discount rate. This aspect reflects the investment yield from an economic standpoint. The positive effects upon users and the society are obvious, leading to the conclusion that the promoting the project is worth the effort. The requirements imposed to the three economic indicators for a project to become economically viable are:

o positive ENPV; o EIRR higher than or equal to the s social discount rate (5%); o BCR higher than 1.

Analyzing the values of economic indicators, we find out that the project is economically viable. The economic indicators have adequate values, given the economic benefits generated the implementation of the project. 6.3. “Value for money” analysis in both cases

6.3.1. Introduction Determining the advantages in favor of either option makes use an economic and financial analysis, widely known in the literature as the “Value for Money”. Choosing either option resorts to an analysis revealing whether the implementation of the project under a concession/PPP is more efficient from an economic standpoint than having it implemented as a classical public procurement. In order to determine the relative merits of the project development alternative methods, the method approached as part of the substantiation study relied on comparing the project development costs under a PPP with the project development costs under traditional public procurements. In the case of traditional procurements, private companies employed for large-scale infrastructure projects are remunerated during the construction period, which usually lasts a limited number of years. Therefore, public authorities need to secure sufficient budgetary resources to finance the entire construction over a relatively brief period of time. In cases when the available funding is insufficient, projects can be divided into several sections which are assigned during different years, depending on the availability of funds, the construction of the entire infrastructure being consequently assigned over a greater number of years. On the other hand, in public-private partnerships, the private partner is, usually, the party that should finance the entire construction, its expenditure being subsequently reimbursed by the public partner or the users during the operational period of the contract, which lasts, as a rule, up to 20-25 years or, quite often, up to 30 years. This will allow the

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public partner to immediately order the commencement of construction works for the entire infrastructure and thus expedite the completion and materialization of all the benefits resulting from the infrastructure as a whole. According to the applicable legal provisions and the international practices in the field, in order to determine whether the procurement under a concession procedure of the PSHP design, funding, construction, operation and maintenance activities is able to secure the “Value for Money” for the contracting authority, two different scenarios were compared: the first is the traditional public procurement, the second being the PPP option. Consequently, a comparison was made between the estimated payments (including the anticipated risk values) for both procurement options, from the public authority’s perspective, based on the net present value (the discounted cash flow method). As part of the traditional public procurement scenario, assessments were made for the planning, construction, maintenance and operation costs in the case of a procurement in line with the procedures provided by the national legislation on the procurement of a contract for works and as per the contractual conditions (engineering and construction agreement), followed by the Ministry of Energy carrying out operation and maintenance activities, directly and/or by means of specialized contractors selected as per the same procurement procedures. As part of the concession/PPP scenario, assessments were made for the payments made by the statutory undertaker (to be used by the statutory undertaker to cover the planning, construction, maintenance, operation and financing costs), without the public authority being required to make any availability-based payments (a fixed annual amount). On the other hand, the project company, which operates as a statutory undertaker, shall generate profits to be later on distributed to the shareholders and, with them, a cash flow back to the public sector in the form of corporate taxes. The activities taken into account for the “Value for Money” analysis included, in particular, the planning/design activity (in terms of execution details) related to the PSHP project, the actual construction (keeping in mind the planned time period provided in the draft concession contract), the PSHP maintenance and operation works until the contract term expiration. Depending on the project bidding method, the profile of cash distributions is projected differently in time for each of the two possible options. The flows of payments in the case of a project awarded as per the traditional procurement procedures are elevated during the construction period and significantly lowered during the maintenance and operation period, depending on the costs pertaining to these activities (numerous times, they are sized depending on the available budget, without necessarily reflecting the real needs). The flows of payments in the case of a project awarded under a concession/PPP rely on the availability level of the infrastructure set forth in the contract and consist in amounts paid during the first years – the construction phase. When analyzing the option of implementing an investment project under a PPP/concession versus a traditional procurement, a fundamental instrument in determining the best option takes the form of the financial model based on which the net benefit (“Value for Money”) is to be determined. For each of the two procurement options, one shall secure all the cash flows, including all the costs and revenues generated by the project. Given that the profile of the payments made as part of the two options is different, as well as the fact that the analysis also includes an extended period of time (30 years), the methodology used to compare the two project implementation options relies on the so-called net present value (NPV), which is practically the current value of all the cash flows planned for the subsequent 30 years of the project. The assessment based on the net present value represents a standard

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assessment in the case of project-based financing structures (“project finance”), in the absence of which comparing the analyzed project implementation options would not be able to produce results that are critical in selecting the best implementation option. In order to make it possible to compare the procurement options, considering the different distribution of the payments in time, depending on the respective procurement option, all the relevant payment sources from both procurement options (including the expected monetary values of the relevant risks) were compared based on the Net Present Value (NPV). Taking into consideration that the “Value for Money” analysis relies on comparing all the costs generated by the project, in both the traditional procurement option and the procurement option under a PPP/concession, the financing costs, as well, are included in the formulated estimates. Since discussions with potential finance providers represent a long-term process at the end of which the financing terms and conditions in their final form shall be set forth, the “Value for Money” analysis took place by studying several assumptions concerning the financing terms, and the results obtained were positive in each analyzed scenario. 6.3.2. Financial model The main objective of the financial analysis is the calculation of the project financial performance indicators (its profitability). This analysis is carried out from the infrastructure Administrator’s perspective (the perspective of the private partner in the PPP scenario or that of the Ministry of Energy in the scenario which sees the project implemented exclusively from public budgetary sources). The financial analysis used as input data the income that can be obtained from the sale of electricity and data on the technical assessments concerning the investment cost, while also being underpinned by the technical regulations in force in Romania. The cost/benefit analysis relies on the principle of comparing the costs of the proposed project alternatives within the current setting. The theoretical model applied is the DCF – Discounted Cash Flow – model, which quantifies the difference between the benefits and the costs generated by the project during its period of operation, adjusting this difference with a discount factor, an operation that is required in order to “align” a future value to the reference year of the costs assessment. The cost/benefit analysis is carried out using constant prices, for the analysis reference year – 2018, made equivalent to the reference year with discounted costs. Therefore, all the costs are expressed in 2018 constant prices. The discount rates used to estimate the Project rate of return were 5% for the financial analysis and 5.5% for the socioeconomic analysis, respectively. In order to discount the prices at the reference year – 2018, the data used was provided by Eurostat and concerned the inflation rate evolution for the reference currency (Euro). The project financial analysis model shall analyze the consolidated and incremental cash flow generated by the project, as per the estimates of investment costs and maintenance costs generated by the implementation of the project, assessed over the entire analysis period. The indicators employed in the financial analysis are:

o The Financial Net Present Value of the project; o The Financial Internal Rate of Return of the project; o The Benefit/Cost Ratio; and o The Cumulative Cash Flow.

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The Financial Net Present Value (VNAF) represents the value that results by deducting the present value of the projected costs of an investment from the present value of the projected benefits. The Financial Internal Rate of Return (RIRF) represents the discount rate in relation to which a flow of costs and benefits expressed in monetary units has a discounted value of zero. The internal rate of return is compared to reference rates in order to assess the performance of the proposed project. The Benefit/Cost Ratio (BCR) emphasizes the extent to which the project benefits cover its costs. If this ratio has proper values, the project does not generate sufficient benefits and requires (additional) funding. The Cumulative Cash Flow represents the total monetary amount of the annual resulted treasury cash flows over the entire analyzed time frame. The above-mentioned performance indicators shall be determined both for the PPP Scenario, as well as for the Scenario with project implementation exclusively from public budgetary sources. The value of the total capital investment is 1 billion EURO, scheduled over a 5-year period, with staging percentages aligned to the investment master schedule. The following staging of the capital expenditure was taken into consideration:

Year 1 11% Year 2 22% Year 3 26% Year 4 28% Year 5 13%

The analysis time frame of the financial analysis shall be 30 years, the first 5 of which being reserved for the design and execution phase, whereas the following 25 years for operation. As such, during the first execution year only 11% of the total investment (110 million Euro) shall be made, as the largest part of the capital expenditure shall be subsequently made during years two, three and four, namely 760 million Euro (76% of the total sum). During the fifth and final year, the other investments shall be made, as well, amounting to 130 million Euro (or 13% of the total sum). Therefore, the time frame of the projected costs and revenues generated by the Project implementation is 30 years, of which the analysis years 1-5 represent the design, construction and execution period, whereas the subsequent 25 years are the period of operation under a public-private partnership (PPP). According to the law, the public partner may cover no more than 25% of the project value, whereas the private partner shall cover at least the remaining 75% of the project value. In terms of cost sharing, we assumed in the reference scenario that the public partner shall cover 20% of the investment costs – except for the operating costs, whereas the private partner shall cover 80% of the project costs. The discount rate used by the financial analysis to estimate the Investment Project financial yield was 5%. This percentage was identified as falling within a reasonable range in relation to representative sample groups of similar projects from the European Economic Area. In order to estimate the economic rate of return when also considering the project implications and impact from a socioeconomic point of view, one shall use the 5.5% rate in the calculation of performance indicators. The discount rate increase is due to additional risks considered, given that the project directly touches environmental issues.

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Therefore, we considered that an investment is profitable from a financial and economic standpoint, respectively, if it displays an internal rate of return higher than the adopted discount rate; the same applies if the net present value is positive and the ratio between benefits (discounted income obtained by the investor) and costs is improper. Concerning the operating costs of Tarnița-Lăpuștești PSHP, the estimated costs over the entire period are around 110 million Euro, as per the present value, with 7 million Euro during the first operation year, set to increase by 3% a year. Additionally, replacement costs of 10% of the investment value were included, applicable after 13 years of operation. Estimations were made for the financial income categories below, generated by the investment implementation, income that is collected exclusively by the private partner during the performance period of the public private partnership. These are estimated to reach, under nominal conditions, a value ranging between 3.63 billion Euro (sale of electricity at minimum prices) and 4.42 billion Euro (sale of electricity at maximum prices) during the entire operation period. The present value of the income ranges between 1.56 billion Euro and 1.90 billion Euro.

Mention should be made that the values presented regarding the amount of electricity produced are estimated data, valid for the years 2017 – 2018, calculated under normal conditions, data that was not indexed with consumer-price indices or salary growth indices.

6.3.3. Financial analysis results of the PPP Scenario Table 6-5.1 Financial Internal Rate of Return Calculation – PPP Scenario, at minimum prices

Analysis year

Operation year Receipts

Direct financial income

Public contribution Expenditures Investment

cost

Operation and maintenance costs

Replacement costs Net cash flow Cumulative cash

flow

2019 21262296 0 21262296 110000000 110000000 -88737704 -88737704.00 2020 40499611.4 0 40499611.43 220000000 220000000 -179500388.6 -268238092.57 2021 45583978.2 0 45583978.23 260000000 260000000 -214416021.8 -482654114.34 2022 46752798.2 0 46752798.19 280000000 280000000 -233247201.8 -715901316.15 2023 102943253 0 102943253.5 130000000 130000000 -27056746.52 -742958062.67 2024 1 117389167 78212859.08 39176308.32 7000000 0 7000000 110389167.4 -632568895.27 2025 2 114033860 76723090.34 37310769.83 7210000 0 7210000 106823860.2 -525745035.09 2026 3 110795765 75261698.14 35534066.51 7426300 0 7426300 103369464.6 -422375570.44 2027 4 107670110 73828141.99 33841968.1 7649089 0 7649089 100021021.1 -322354549.36 2028 5 104652337 72421891.66 32230445.81 7878561.67 0 7878561.67 96773775.81 -225580773.55 2029 6 101738090 71042427.06 30695662.68 8114918.52 0 8114918.52 93623171.22 -131957602.33 2030 7 98923202.4 69689237.97 29233964.45 8358366.076 0 8358366.076 90564836.35 -41392765.98 2031 8 96203694.8 68361823.92 27841870.91 8609117.058 0 8609117.058 87594577.77 46201811.79 2032 9 93575761.5 67059693.94 26516067.53 8867390.57 0 8867390.57 84708370.9 130910182.69 2033 10 91035764.1 65782366.43 25253397.65 9133412.287 0 9133412.287 81902351.8 212812534.49 2034 11 88580223.9 64529368.98 24050854.9 9407414.655 0 9407414.655 79172809.23 291985343.72 2035 12 86205814.2 63300238.14 22905576.1 9689637.095 0 9689637.095 76516177.15 368501520.86 2036 13 83909353.7 62094519.32 21814834.38 56045579.21 0 35947461.91 20098117.3 27863774.49 396365295.35 2037 14 81687799.3 60911766.57 20776032.74 10279735.99 0 10279735.99 71408063.32 467773358.67 2038 15 79538240.3 59751542.45 19786697.85 10588128.07 0 10588128.07 0 68950112.22 536723470.90 2039 16 77457892 58613417.83 18844474.14 10905771.92 0 10905771.92 66552120.05 603275590.95 2040 17 75444090 57496971.77 17947118.23 11232945.07 0 11232945.07 64211144.93 667486735.88 2041 18 73494284.9 56401791.36 17092493.55 11569933.43 0 11569933.43 61924351.49 729411087.37 2042 19 71606036.8 55327471.52 16278565.29 11917031.43 0 11917031.43 59689005.38 789100092.75 2043 20 69777010.4 54273614.92 15503395.51 12274542.37 0 12274542.37 57502468.07 846602560.82 2044 21 68004970.4 53239831.78 14765138.58 12642778.64 0 12642778.64 55362191.72 901964752.54 2045 22 66287776.5 52225739.75 14062036.75 13022062 0 13022062 53265714.49 955230467.04 2046 23 64623379.7 51230963.75 13392415.95 13412723.86 0 13412723.86 51210655.84 1006441122.88 2047 24 63009817.7 50255135.87 12754681.86 13815105.58 0 13815105.58 49194712.15 1055635835.03 2048 25 61445211.2 49297895.19 12147316.05 14229558.75 0 14229558.75 47215652.5 1102851487.53 Total 2404131591 1567333500 836798091 1301280103 1000000000 281181986 20098117.3 7410823388 6508808769.50

Financial Internal Rate of Return of the Total Investment (FIRR/C) 19.88% Financial Net Present Value of the Total Investment (VANF/C) 1527250673.07

Benefits / Capital Cost Ratio (BCR) 1.85

pg. 122

2140 46 47

103 117 114 111 108 105 102 99 96 94 91 89 86 84 82 80 77 75 73 72 70 68 66 65 63 61

110,0130,0

7,0 7,2 7,4 7,6 7,9 8,1 8,4 8,6 8,9 9,1 9,4 9,7

56,0

10,3 10,6 10,9 11,2 11,6 11,9 12,3 12,6 13,0 13,4 13,8 14,2

-950,00

-450,00

50,00

550,00

1050,00

1550,00

2050,00

-$200

-$150

-$100

-$50

$0

$50

$100

$150

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Todays EUR (millions)

Valoarea prezenta a veniturilor Valoarea prezenta a costurilorValoarea prezenta neta cumulata

In the assumption of having the project financed through a PPP mechanism, if the electricity production is sold at the lowest market prices, over a 30-year analysis time frame the expected yield of the investment is positive, of around 20%, whereas the discounted cumulative net cash flow becomes positive as of the 8th operation year. Figure 6-1.1. Net discounted cash flow – PPP Scenario, at minimum prices

Table 6-5.2 Financial Internal Rate of Return Calculation – PPP Scenario, at maximum prices

Analysis year

Operation year Receipts

Direct financial income

Public contribution Expenditures Investment

cost

Operation and maintenance costs

Replacement costs Net cash flow Cumulative cash

flow

2019 21262296 0 21262296 88000000 88000000 0 0 -66737704 -66737704 2020 40499611.4 0 40499611.4 167619047.6 167619047.6 0 0 -127119436 -193857140.2 2021 45583978.2 0 45583978.2 188662131.5 188662131.5 0 0 -143078153 -336935293.5 2022 46752798.2 0 46752798.2 193499622.1 193499622.1 0 0 -146746824 -483682117.4 2023 102943253 0 102943253 85561057.38 85561057.38 0 0 17382196.1 -466299921.3 2024 1 134356716 95180408.12 39176308.3 5484683.165 0 5484683.165 0 128872033 -337427888 2025 2 130678218 93367447.97 37310769.8 5380213.01 0 5380213.01 0 125298005 -212129883.2 2026 3 127123087 91589020.39 35534066.5 5277732.762 0 5277732.762 0 121845354 -90284529.05 2027 4 123686436 89844467.62 33841968.1 5177204.519 0 5177204.519 0 118509231 28224702.15 2028 5 120363590 88133144.43 32230445.8 5078591.099 0 5078591.099 0 115284999 143509701.3 2029 6 117150081 86454417.87 30695662.7 4981856.031 0 4981856.031 0 112168225 255677925.8 2030 7 114041632 84807667.05 29233964.5 4886963.535 0 4886963.535 0 109154668 364832593.8 2031 8 111034154 83192282.92 27841870.9 4793878.515 0 4793878.515 0 106240275 471072869.1 2032 9 108123736 81607668 26516067.5 4702566.544 0 4702566.544 0 103421169 574494038.1 2033 10 105306634 80053236.23 25253397.6 4612993.848 0 4612993.848 0 100693640 675187678.1 2034 11 102579268 78528412.68 24050854.9 4525127.298 0 4525127.298 0 98054140.3 773241818.4 2035 12 99938209.5 77032633.39 22905576.1 4438934.397 0 4438934.397 0 95499275.1 868741093.5 2036 13 97380179.5 75565345.14 21814834.4 47984052.03 0 4354383.266 43629668.76 49396127.5 918137221 2037 14 94902038 74126005.23 20776032.7 4271442.632 0 4271442.632 0 90630595.3 1008767816 2038 15 92500779.2 72714081.32 19786697.9 4190081.82 0 4190081.82 0 88310697.4 1097078514 2039 16 90173525.3 71329051.2 18844474.1 4110270.738 0 4110270.738 0 86063254.6 1183141768 2040 17 87917520.8 69970402.61 17947118.2 4031979.867 0 4031979.867 0 83885541 1267027309 2041 18 85730126.6 68637633.03 17092493.6 3955180.25 0 3955180.25 0 81774946.3 1348802256 2042 19 83608814.8 67330249.55 16278565.3 3879843.483 0 3879843.483 0 79728971.4 1428531227 2043 20 81551164.1 66047768.6 15503395.5 3805941.703 0 3805941.703 0 77745222.4 1506276449 2044 21 79554854.5 64789715.87 14765138.6 3733447.575 0 3733447.575 0 75821406.9 1582097856 2045 22 77617662.8 63555626.04 14062036.7 3662334.288 0 3662334.288 0 73955328.5 1656053185 2046 23 75737458.6 62345042.69 13392416 3592575.54 0 3592575.54 0 72144883.1 1728198068 2047 24 73912199.9 61157518.07 12754681.9 3524145.529 0 3524145.529 0 70388054.4 1798586122 2048 25 72139929 59992612.96 12147316.1 3457018.948 0 3457018.948 0 68682910.1 1867269032 Total 2744149950 1907351859 836798091 876880917.7 723341858.6 109909390.4 43629668.76 1867269032 20357594768

Financial Internal Rate of Return of the Total Investment (FIRR/C) 22.01% Financial Net Present Value of the Total Investment (VANF/C) 1867269032.32

Benefits / Capital Cost Ratio (BCR) 3.13

Income present value Net cumulative present value

Present value of costs

pg. 123

In the assumption of having the project financed through a PPP mechanism, if the electricity production is sold at the highest market prices, over a 30-year analysis time frame the expected yield of the investment is positive, of around 22%, whereas the discounted cumulative net cash flow becomes positive as of the 4th operation year. Figure 6-1.2.Net discounted cash flow – PPP Scenario, at minimum prices

6.3.4. Financial analysis results of the 100% Government Financing Scenario Table 6-6.1.Financial Internal Rate of Return Calculation – 100% public financing Scenario, at minimum prices

Analysis year

Operation year Receipts

Direct financial income

Public contribution Expenditures Investment

cost

Operation and maintenance costs

Replacement costs Net cash flow Cumulative cash

flow

2019 0 0 0 110000000 110000000 0 0 -110000000 -110000000 2020 0 0 0 209523809.5 209523809.5 0 0 -209523810 -319523809.5 2021 0 0 0 235827664.4 235827664.4 0 0 -235827664 -555351473.9 2022 0 0 0 241874527.6 241874527.6 0 0 -241874528 -797226001.5 2023 0 0 0 106951321.7 1069513217 0 0 -106951322 -904177323.2 2024 1 78212859.

78212859.08 0 5484683.165 0 5484683.165 0 72728176 -831449147.3

2025 2 76723090.34 76723090.34 0 5380213.01 0 5380213.01 0 71342877 -760106270 2026 3 75261698.14 75261698.14 0 5277732.762 0 5277732.762 0 69983965 -690122304.6 2027 4 73828141.99 73828141.99 0 5177204.519 0 5177204.519 0 68650937 -621471367.1 2028 5 72421891.66 72421891.66 0 5078591.099 0 5078591.099 0 67343301 -554128066.6 2029 6 71042427.06 71042427.06 0 4981856.031 0 4981856.031 0 66060571 -488067495.5 2030 7 69689237.97 69689237.97 0 4886963.535 0 4886963.535 0 64802274 -423265221.1 2031 8 68361823.92 68361823.92 0 4793878.515 0 4793878.515 0 63567945 -359697275.7 2032 9 67059693.94 67059693.94 0 4702566.544 0 4702566.544 0 62357127 -297340148.3 2033 10 65782366.43 65782366.43 0 4612993.848 0 4612993.848 0 61169373 -236170775.7 2034 11 64529368.98 64529368.98 0 4525127.298 0 4525127.298 0 60004242 -176166534 2035 12 63300238.14 63300238.14 0 4438934.397 0 4438934.397 0 58861304 -117305230.3 2036 13 62094519.32 62094519.32 0 4798405203 0 4354383.266 43629668.76 14110467 -103194763 2037 14 60911766.57 60911766.57 0 4271442.632 0 4271442.632 0 56640324 -46554439.06 2038 15 59751542.45 59751542.45 0 419008182 0 4190081.82 0 55561461 9007021.565 2039 16 58613417.83 58613417.83 0 4110270.738 0 4110270.738 0 54503147 6351016&65 2040 17 57496971.77 57496971.77 0 4031979.867 0 4031979.867 0 53464992 116975160.6 2041 18 56401791.36 56401791.36 0 3955180.25 0 3955180.25 0 52446611 169421771.7 2042 19 55327471.52 55327471.52 0 3879843.483 0 3879843.483 0 51447628 220869399.7 2043 20 54273614.92 54273614.92 0 3805941.703 0 3805941.703 0 50467673 271337072.9 2044 21 53239831.78 53239831.78 0 3733447.575 0 3733447.575 0 49506384 320843457.1 2045 22 52225739.75 52225739.75 0 3662334.288 0 3662334.288 0 48563405 369406862.6 2046 23 51230963.75 51230963.75 0 3592575.54 0 3592575.54 0 47638388 417045250.8 2047 24 50255135.87 50255135.87 0 3524145.529 0 3524145.529 0 46730990 463776241.2 2048 25 49297895.19 49297895.19 0 3457018.948 0 3457018.948 0 45840876 509617117.4 Total 1567333500 1567333500 0 1057716382 904177323.2 109909390.4 43629668.76 509617117 -5459508122

Financial Internal Rate of Return of the Total Investment (FIRR/C) 8.65% Financial Net Present Value of the Total Investment (VANF/C) 509617117.39

Benefits / Capital Cost Ratio (BCR) 1.48

2140 46 47

103134131127124120117114111108105103100 97 95 93 90 88 86 84 82 80 78 76 74 72

88,0

168 189 193

85,6

5,5 5,4 5,3 5,2 5,1 5,0 4,9 4,8 4,7 4,6 4,5 4,4

48,0

4,3 4,2 4,1 4,0 4,0 3,9 3,8 3,7 3,7 3,6 3,5 3,5

-950,00

50,00

1050,00

2050,00

-$200

-$100

$0

$100

Valoarea prezentă a veniturilor Valoarea prezentă a costurilor

Valoarea Netă Prezentă cumulată

Income present value

Net cumulative present value

Present value of costs

pg. 124

In the assumption of having the project financed exclusively from budgetary sources, over a 30-year analysis time frame (the first 5 reserved for project implementation and the following 25 for operation), the expected investment yield with electricity sold at minimum prices is around 8.65%, considerably lower than the yield of the PPP option. Figure 6-1.1. Financial net present flow – 100% public financing Scenario, at minimum prices

Table 6-6.1.Financial Internal Rate of Return Calculation – 100% public financing Scenario, at maximum prices

Analysis year

Operation year Receipts

Direct financial income

Public contribution Expenditures Investment

cost

Operation and maintenance costs

Replacement costs Net cash flow Cumulative cash

flow

2019 0 0 0 110000000 110000000 0 0 -110000000 -110000000 2020 0 0 0 209523810 209523810 0 0 -209523809.5 -319523810 2021 0 0 0 235827664 235827664 0 0 -235827664.4 -555351474 2022 0 0 0 241874528 241874528 0 0 -241874527.6 -797226002 2023 0 0 0 106951322 106951322 0 0 -106951321.7 -904177323 2024 1 95180408.1 95180408.1 0 5484683.17 0 5484683.165 0 89695724.96 -814481598 2025 2 93367448 93367448 0 5380213.01 0 5380213.01 0 87987234.96 -726494363 2026 3 91589020.4 91589020.4 0 5277732.76 0 5277732.762 0 86311287.63 -640183076 2027 4 89844467.6 89844467.6 0 5177204.52 0 5177204.519 0 84667263.1 -555515813 2028 5 88133144.4 88133144.4 0 5078591.1 0 5078591.099 0 83054553.33 -472461259 2029 6 86454417.9 86454417.9 0 4981856.03 0 4981856.031 0 81472561.84 -390988697 2030 7 84807667 84807667 0 4886963.54 0 4886963.535 0 79920703.51 -311067994 2031 8 83192282.9 83192282.9 0 4793878.52 0 4793878.515 0 78398404.4 -232669590 2032 9 81607668 81607668 0 4702566.54 0 4702566.544 0 76905101.46 -155764488 2033 10 80053236.2 80053236.2 0 4612993.85 0 4612993.848 0 75440242.38 -80324245.7 2034 11 78528412.7 78528412.7 0 4525127.3 0 4525127.298 0 74003285.39 -6320960.28 2035 12 77032633.4 77032633.4 0 4438934.4 0 4438934.397 0 72593699 66272738.72 2036 13 75565345.1 75565345.1 0 47984052 0 4354383.266 43629668.76 27581293.11 93854031.83 2037 14 74126005.2 74126005.2 0 4271442.63 0 4271442.632 0 69854562.6 163708594.4 2038 15 72714081.3 72714081.3 0 4190081.82 0 4190081.82 0 68523999.5 232232593.9 2039 16 71329051.2 71329051.2 0 4110270.74 0 4110270.738 0 67218780.46 299451374.4 2040 17 69970402.6 69970402.6 0 4031979.87 0 4031979.867 0 65938422.74 365389797.1 2041 18 68637633 68637633 0 3955180.25 0 3955180.25 0 64682452.78 430072249.9 2042 19 67330249.5 67330249.5 0 3879843.48 0 3879843.483 0 63450406.07 493522656 2043 20 66047768.6 66047768.6 0 3805941.7 0 3805941.703 0 62241826.9 555764482.9 2044 21 64789715.9 64789715.9 0 3733447.58 0 3733447.575 0 61056268.29 616820751.2 2045 22 63555626 63555626 0 3662334.29 0 3662334.288 0 59893291.76 676714042.9 2046 23 62345042.7 62345042.7 0 3592575.54 0 3592575.54 0 58752467.15 735466510.1 2047 24 61157518.1 61157518.1 0 3524145.53 0 3524145.529 0 57633372.54 793099882.6 2048 25 59992613 59992613 0 3457018.95 0 3457018.948 0 56535594.01 849635476.6 Total 1907351859 1907351859 0 1057716382 904177323 109909390.4 43629668.76 849635476.6 -700545509

Financial Internal Rate of Return of the Total Investment (FIRR/C) 10.94% Financial Net Present Value of the Total Investment (VANF/C) 879735157.06

Benefits / Capital Cost Ratio (BCR) 1.86

0 0 0 0 0 78 77 75 74 72 71 70 68 67 66 65 63 62 61 60 59 57 56 55 54 53 52 51 50 49

110

210236242

107

5,5 5,4 5,3 5,2 5,1 5,0 4,9 4,8 4,7 4,6 4,5 4,448,0

4,3 4,2 4,1 4,0 4,0 3,9 3,8 3,7 3,7 3,6 3,5 3,5

-950,00

-450,00

50,00

550,00

1050,00

-$300

-$200

-$100

$0

$100Todays EUR(millions)

Valoarea prezenta a veniturilor valoarea prezenta a costurilorIncome present value Present value of costs

pg. 125

In the assumption of having the project financed exclusively from budgetary sources, over a 30-year analysis time frame (the first 5 reserved for project implementation and the following 25 for operation), the expected investment yield with the produced electricity sold at the maximum market prices is around 10.9%, considerably lower than the yield of the PPP option, in both situations. Figure 6-2.2. Financial net present flow – 100% public financing Scenario, at maximum prices

We may conclude that the PPP option is optimum in either of the 2 situations. 6.3.5. Sensitivity analysis

The sensitivity analysis allows identifying those critical project variables and

represents a tool for measuring the manner in which their variation (as in their decrease or increase) has an impact upon the financial and economic performance of the project implemented under a public-private partnership. For example, the way in which a negative variation of the electricity produced influences the collected income.

As indicated by table 6.7, the most significant effects upon the project rate of return are caused by a decrease in the amount of electricity produced.

As such, the analysis carried out indicates that the non-completion of the first constructions within the first 5 years and the non-commencement of their operation decrease the amount of revenues, in addition to the loss of the 100-million Euro premium from the state, which will also lower the rate of return from 19.9% to 14%, in the option of selling electricity at minimum prices, as well as lower the rate of return from 22% to 16%, in the option of selling the electricity produced at the maximum prices available on the market.

A less significant impact upon the rate of return is the electricity production capacity decrease during the years marked by harsh drought. A decrease of energy production by 10% will translate into a rate of return decrease from 16% to 13.9%.

On the other hand, the impact produced by a decrease of the state contribution share from 20% to 10%, as support to carry out the investment, causes a rate of return drop of approximately 2pp, whether the electricity production is sold at minimum or maximum prices.

Last, but not least, the sensitivity analysis indicates that, following the analysis of the impact made by the availability-based payments, the non-allocation of availability-based amounts, while seemingly not leading to a negative net present value, does lower the rates of return by more than 4pp.

0 0 0 0 0 95 93 92 90 88 86 85 83 82 80 79 77 76 74 73 71 70 69 67 66 65 64 62 61 60

110

210236242

107

5,5 5,4 5,3 5,2 5,1 5,0 4,9 4,8 4,7 4,6 4,5 4,448,0

4,3 4,2 4,1 4,0 4,0 3,9 3,8 3,7 3,7 3,6 3,5 3,5

-950,00

-450,00

50,00

550,00

1050,00

-$300

-$200

-$100

$0

$100Todays EUR (millions)

Valoarea prezenta a veniturilor Valoarea prezenta a costurilorIncome present value Present value of costs

pg. 126

Table 6-7. Scenarios tested during the sensitivity analysis Variables Change of explanatory

variables Influence upon the rate of return

Projected Impact

Non-allocation of availability-based amounts

Non-completion of construction within 5 years

Minus 6 p.p. for the entire period

Very significant

Amount of energy produced during the 30 years of operation

A 10p.p. decrease as opposed to the reference scenario

Minus 2 p.p. only for the operation period Moderate

State participation share decrease

A 10p.p. decrease as opposed to the reference scenario

Minus 2 p.p. for the entire period Moderate

Non-allocation of availability-based amounts and annual premiums

Minus 4 p.p. for the entire period Significant

Since the only source of operating income is represented by income from electricity production, we also analyzed the possible minimum threshold of the sales-generated income for which the rate of return would be zero, as well as the threshold at which the private partner would fail to cover their costs from the discounted incomes and obtain a reasonable profit, as in a rate of return in excess of 5.5%, so that the investment should be attractive. Table 6-8. Scenarios on the evolution of the rate of return Rate of return for the entire period Estimated annual

income 2024-2043 BASELINE SCENARIO, at minimum prices 16.07% 2744.15 Income -10% decrease 13.89% 2469.735 Income -20% decrease 11.68% 2195.32 Income -30% decrease 9.43% 1920.905 Income -40% decrease 7.81% 1728.814 Income -50% decrease 4.64% 1372.075

As such, based on the data on the evolution of estimated incomes, it is visible that, for the private partner to be able to have a reasonable rate of return, the income obtained from energy production may actually diminish, during the analyzed period, by up to 40%, leaving the rate of return in excess of 5.5%, as we have assumed from the early stages of this analysis, whereas electricity is sold on the market at the maximum given prices and the state provides the availability-based premium and the annual premiums. At the same time, a decrease by more than 10% of the incomes produced by sales of electricity renders the project unprofitable (the private partner no longer manages to recover their investment), whereas electricity is sold at the minimum market prices and the private partner does receives neither the availability-based amounts, nor the annual premiums from the public partner. Nevertheless, if an increase by 10% from the reference scenario does occur in terms of transmitted quantity, a significant increase of the rate is noticeable. Still, even in the pessimistic scenario, the project under a PPP remains profitable, provided that a 10% income decrease takes place and no other additional payments from the state are received.

pg. 127

Figure 6-3. Scenarios on the evolution of income from freight traffic during the operation period, at maximum prices

6.4. Option recommended by the study elaborator and its advantages Since the state of the electricity market is unpredictable, and the private partner might have to sell their electricity production at the lowest market prices, two scenarios were drawn up. A pessimistic one, in which, over the entire investment period, the private partner sells the entire amount of electricity at the lowest market prices, and an optimistic scenario, in which the private partner manages to sell that electricity at the highest market price. The tables below present the financial model results for the two working assumptions on funding and operating the investment objective.

16,07%13,89%

11,68%9,43%

7,81%

4,64%

0

500

1000

1500

2000

2500

3000

0,00% 2,00% 4,00% 6,00% 8,00% 10,00% 12,00% 14,00% 16,00% 18,00%

CUM

ULA

TIVE

INCO

ME

EXPECTED RATE OF RETURN

0

20

40

60

80

100

120

140

160

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

Million Euro

Venituri din vanzari la preturi minime Venituri sc.-10% Venituri sc.-20%Venituri sc.-30% Venituri sc.-40% Venituri sc.-50%Income from sales at minimum prices Income -30% decrease

Income -10% decrease Income -40% decrease

Income -20% decrease Income -50% decrease

pg. 128

Table 6-9.1. Summary of financial analysis results for the two project funding assumptions, the pessimistic option Scenario I – PPP

minimum prices

Investment, maintenance, operation and replacement costs (Euro) Total non-

present value Total present

%

Investment expenditure

80000000 675510278 85.31%

Maintenance and operation costs

255214850 113824258 14.37%

Replacement costs

100000000 2502706 0.32%

Total costs 1155214850 791837242 100.00% Financial revenues Total non-

present value Total present

%

Electricity production

3639423193 1567333500 65.19%

Public contribution

1543293600 836798091 34.81%

Total revenues 5182716793 2404131591 100.00% Financial profitability indicators

Total Investment Financial Internal Rate of Return (FIRR)

19.88%

Total Investment Financial Net Present Value (FNPV)

1527250673

Capital Benefits/Cost Ratio (BCR) 1.85 Expected yield 84.75%

Scenario II - public funding

minimum prices

Investment, maintenance, operation and replacement costs (Euro) Total non-

present value Total present value

%

Investment expenditure

1000000000.00 904177323.2 85.48%

Maintenance and operation costs

255214850.3 109909390.4 10.39%

Replacement costs

100000000 43629668.76 4.12%

Total costs 1355214850.25 1057716382.36 100.00%

Financial revenues Total non-

present value Total present value

%

Electricity production

3639423193 1561670858.20 65.19%

Public contribution

0.00 0.00 34.81%

Total revenues 1567333499.75 1561670858.20 100.00% Financial profitability indicators

Total Investment Financial Internal Rate of Return (FIRR)

8.65%

Total Investment Financial Net Present Value (FNPV)

509617117.39

Capital Benefits/Cost Ratio (BCR) 1.48 Expected yield 48.18%

The expected yield in the PPP scenario, the pessimistic option, is approximately 20%, provided there is a 20% public contribution to the investment expenditure. However, in the assumption of implementing the project exclusively from budgetary public sources, for a 30-year analysis time frame (5 of which correspond to the execution phase and 25 to the operation period) the investment financial yield is much lower (Financial Internal Rate of Return), that is only 8.69%. As far as the optimistic scenario is concerned, the yield expected for the PPP scenario is 22%, even under conservative estimates regarding the expected increase of the electricity price, but also the public contribution to the investment expenditure (20%). On the other hand, in the assumption of implementing the project under the same conditions, but fully from public budgetary sources, for a 30-year analysis time frame the financial yield of the investment is much lower, that is 10.64%. Therefore, the recommended project implementation and operation option is a PPP mechanism, in both the pessimistic and the optimistic case, an option set to secure an optimum operation of the PSHP, the related project assets and activities included.

pg. 129

Table 6-9.2. Summary of financial analysis results for the two project funding assumptions, the pessimistic scenario Scenario I – PPP

minimum prices

Investment, maintenance, operation and replacement costs (Euro) Total non-

present value Total present

%

Investment expenditure

80000000 675510278 85.31%

Maintenance and operation costs

255214850.3 113824258 14.37%

Replacement costs

100000000 2502706 0.32%

Total costs 1155214850 791837242 100.00% Financial revenues Total non-

present value Total present

%

Electricity production

4428962052 1907351859 79.34%

Public contribution

1543293600 836798091 34.81%

Total revenues 5972255652 2744149950 114.14% Financial profitability indicators

Total Investment Financial Internal Rate of Return (FIRR)

22.01%

Total Investment Financial Net Present Value (FNPV)

1867269032

Capital Benefits/Cost Ratio (BCR) 3.13 Expected yield 212.94%

Scenario II - public funding

minimum prices

Investment, maintenance, operation and replacement costs (Euro) Total non-

present value Total present value

%

Investment expenditure

1000000000.00 904177323.2 85.48%

Maintenance and operation costs

255214850.25 109909390.36 10.39%

Replacement costs

100000000.00 43629668.76 4.12%

Total costs 1355214850.25 1057716382.36 100.00%

Financial revenues Total non-

present value Total present value

%

Electricity production

4428962052.02 1907351859.00 100.00%

Public contribution

0.00 0.00 0.00%

Total revenues 4428962052.02 1907351859.00 100.00% Financial profitability indicators

Total Investment Financial Internal Rate of Return (FIRR)

10.64%

Total Investment Financial Net Present Value (FNPV)

849635476.64

Capital Benefits/Cost Ratio (BCR) 1.80 Expected yield 80.33%

130

At the same time, there are additional benefits resulted from using the concession/PPP method, the most significant of them being: o The payment-structuring method facilitates carrying out the projects that require

significant capital costs and could otherwise not be covered by the state budget. o The public authority receives the given benefits at a lower cost and more efficient and

more innovative services provided by the private sector. o The private sector takes responsibility for most of the Project risks. o The projects under a Concession/PPP encourage a long-term approach regarding the

creation and management of public sector assets, whereas the latter retains the final right of ownership over the assets created.

o The public sector obtains economic and financial benefits (“value for money”) from providing the services pertaining to those assets, including maintenance and replacement during the lifespan, which are rendered by the private sector at the required standard, at the lowest economic cost in the long run. The private sector, which is responsible for creating the assets, is also responsible for maintaining them in the long run, which leads to a quality increase of public sector assets.

o If the concessionaire fails to comply with the minimum performance standards stipulated in the concession contract, they shall be liable to pay financial penalties.

o In terms of project implementation efficiency, statistic, the international practice revealed that there is a much higher probability for the projects undertaken under a concession/PPP to fall within the initially set forth implementation budgets and schedules, the assumption of risks by the private sector and the control over the project finance providers being decisive elements in that respect, as opposed to the traditional public procurement projects.

In conclusion, analyzing the results of the calculations made for a 30-year time frame, it is recommended to carry out the project under a public-private partnership. 6.5. Risk distribution structure for each option, quantification of risks and

allotment alternatives among the contracting parties, based on the risk management capacity

6.5.1. Identification and quantification of risks In general, risk is extremely difficult to detect and measured due to events that feature a high level of uncertainty. The most widely used method is estimating the statistical probability for a negative event to occur, and subsequently associating to it a measurable cost. Assessing the risk and the scoring form an important phase in the risk management process, as it consists in determining the quantitative / qualitative value of the risk associated to a concrete situation and to acknowledged threats. The quantitative assessment of risk requires calculating two components of risk: the scale of potential loss (the impact), on the one hand, and the occurrence likelihood of the respective loss, on the other hand. In order to assess the risks the project in question is subject to, we compiled a risk matrix, analyzing the probability and severity of the consequences that can manifest following the materialization of several risk categories, presented in the picture below.

p. 131

Figure 6-4. Structure of identified risks

Based on the estimation of the impact of approximately 77 expected risks, placed within the above-mentioned six categories (the table below), and the association of the probabilities pertaining to each risk, the following aspects were identified:

o The market risk and the operating risk are the most significant risks an investment project may face.

o The great majority of risks are found in the category of moderate-to-low impact. o The mean impact value is 0.198 o The average probability of the analyzed risks is 0.353, which places the project within

the moderate-to-low risk range, or a range of risks with very low occurrence likelihood.

o The most significant risks may originate from the area of market risks, the greatest influence – if they do materialize – coming, for instance, from demand for electricity produced, increased competition from other electricity providers, increased competition from other means of producing electricity.

o Additionally, from the area of operating risks, a major influence may be exerted by exceeding operating costs / the need to extend maintenance works.

Table 6-10. Risk matrix Risk Impact Probability Estimated

risk Rating Value Rating Value

1.

Con

stru

ctio

n ph

ase

risk

1 The current structure is inadequate Negligible 0.05 Likely 0.5 0.025 2 Construction site conditions Negligible 0.05 Unlikely 0.1 0.005 3 Obtaining the required permits –

political opposition Moderate 0.2 Very likely 0.7 0.140

4 The environment and cleaning works after clearing the site

Low 0.1 Remotely likely

0.3 0.030

5 Deficient project design Moderate 0.2 Unlikely 0.1 0.020 6 Size and complexity of PSHP works Negligible 0.05 Unlikely 0.1 0.005

Construction phase risk

Financial risk

Governance risk - sponsor

Systemic risks

Market risk

Operation – performance risks

Probability

p. 132

7 Delays in commencing the works Moderate 0.2 Very likely 0.7 0.140 8 Prices of materials and raw materials Low 0.1 Likely 0.5 0.050 9 Testing the construction (acceptance) Moderate 0.2 Unlikely 0.1 0.020 10 Lifespan (of the PSHP) Negligible 0.05 Unlikely 0.1 0.005 11 Technological risk Low 0.1 Very likely 0.7 0.070

2. F

inan

cial

risk

12 Quality/price ratio Low 0.1 Remotely likely

0.3 0.030

13 Interest rates before allocating the project

Low 0.1 Remotely likely

0.3 0.030

14 Project duration Low 0.1 Likely 0.5 0.050 15 Cash flow verification Moderate 0.2 Remotely

likely 0.3 0.060

16 Additional funding requirements Negligible 0.05 Remotely likely

0.3 0.015

17 Liquidity Moderate 0.2 Remotely likely

0.1 0.020

18 Maturity degree (of the loans) Moderate 0.2 Remotely likely

0.3 0.060

19 Existence of institutional investors Low 0.1 Remotely likely

0.3 0.030

20 Currency risk Negligible 0.05 Remotely likely

0.3 0.015

21 Amount of public contribution Negligible 0.05 Unlikely 0.1 0.005 22 Advance payment of the public grant Moderate 0.2 Unlikely 0.1 0.020 23 The public partner’s

bankruptcy/default Negligible 0.05 Unlikely 0.1 0.005

24 The private partner operates with very high leverage ratios

Moderate 0.2 Remotely likely

0.3 0.060

3. Governance / sponsor risks

25 Sponsor Negligible 0.05 Unlikely 0.1 0.005 26 Partnership agreement Low 0.1 Remotely

likely 0.3 0.030

27 Changes in the private partner’s executive management orshareholding

Negligible 0.05 Likely 0.5 0.025

29 Private partners with several roles in the project

Low 0.1 Remotely likely

0.3 0.030

30 Fraud / Corruption Moderate 0.2 Remotely likely

0.3 0.060

31 Project complexity Moderate 0.2 Likely 0.5 0.100 32 Moral hazard Moderate 0.2 Unlikely 0.1 0.020 33 The reputation created by electricity

consumers, PSHP customers Negligible 0.05 Likely 0.5 0.025

34 The network created – the contribution of the project to the general development of the area

High 0.4 Very likely 0.7 0.280

35 Renegotiation (of contracts) High 0.4 Remotely likely

0.3 0.120

4. O

pera

tion

– pe

rfor

man

ce

risks

36 Project management Moderate 0.2 Remotely likely

0.3 0.060

37 Inputs (price, quality, availability) Low 0.1 Remotely likely

0.3 0.030

38 Changes in output specifications Moderate 0.2 Remotely likely

0.3 0.060

p. 133

39 Flexibility Low 0.1 Remotely likely

0.3 0.030

40 Maintenance - reconstruction Moderate 0.2 Remotely likely

0.3 0.060

41 Security Catastrophic 0.8 Remotely likely

0.3 0.240

42 Bankruptcy (of the contractor or the subcontractor)

High 0.4 Remotely likely

0.3 0.120

43 Technical wear and tear or innovation High 0.4 Likely 0.5 0.200 44 Market test (benchmarking) Low 0.1 Likely 0.5 0.050 45 Staff expenditure Low 0.1 Remotely

likely 0.3 0.030

47 Delivery Negligible 0.05 Unlikely 0.1 0.005 48 Competence and know-how levels High 0.4 Likely 0.5 0.200 49 Monitoring Low 0.1 Unlikely 0.1 0.010 50 Subcontracting Moderate 0.2 Remotely

likely 0.3 0.060

51 Bias-generated costs Moderate 0.2 Likely 0.5 0.100 52 Operational income below targets Moderate 0.2 Likely 0.5 0.100 53 Faults of ITC systems High 0.4 Remotely

likely 0.3 0.120

5. Market risk

54 Market Low 0.1 Unlikely 0.1 0.010

55 Electricity demand Negligible 0.2 Unlikely 0.1 0.020 56 Demand (based on tariffs /business

income ) Low 0.1 Remotely

likely 0.3 0.030

57 Alternative services offer Moderate 0.1 Likely 0.5 0.050 58 Lack of experience Moderate 0.2 Remotely

likely 0.3 0.060

59 Selection criteria Moderate 0.2 Likely 0.5 0.100 60 Tenderers’ pre-eligibility standards Moderate 0.2 Likely 0.5 0.100 61 Abnormal offer Moderate 0.2 Likely 0.5 0.100 62 Appeal (litigation) High 0.4 Very likely 0.7 0.280 63 Industrial relations and critics from the

civil society High 0.4 Likely 0.5 0.200

64 Approvals High 0.4 Very likely 0.7 0.280 65 Procedural High 0.4 Very likely 0.5 0.200 66 Changes in the legislative framework

and government policies Moderate 0.4 Likely 0.5 0.200

67 Regulation High 0.4 Likely 0.5 0.200 68 Fiscal code changes Moderate 0.2 Remotely

likely 0.3 0.060

69 Contractual Low 0.1 Remotely likely

0.3 0.030

70 Corruption Moderate 0.2 Likely 0.5 0.100

6. S

yste

mic

71 Force majeure Catastrophic 0.8 Remotely likely

0.3 0.240

72 Country risk Low 0.1 Remotely likely

0.3 0.030

73 Political Moderate 0.2 Likely 0.5 0.100 74 Demographic changes Low 0.05 Unlikely 0.1 0.005

p. 134

Impact: [X VALUE],

Prob.: [Y VALUE]

0,000,100,200,300,400,500,600,700,800,901,00

0,00 0,10 0,20 0,30 0,40 0,50 0,60 0,70 0,80 0,90 1,00

Likely

Figure 6-5. Risk analysis results

o Impact: 0.198

o Probability: 0.353

o Mean risk value: 0.078

6.5.2. Risk allocation between the Public Partner and the Private Partner The table below presents a possible method to allocate the project risks, namely to share them between the public partner and the private one. Nevertheless, the final allocation of risks shall be established following negotiations with the investors. The general approach of this issue relies on the logic of the principle that risk should be allocated to the entity (the Public Partner or the Private Partner) best suited to contain it. The risk matrix compiled comprises the following categories: I. The design and execution risk (11 risks) II. The financial risk (13 risks) III. The governance risk (10 risks) IV. The operating risk (17 risks) V. The market risk (17 risks)

75 Hydrologic High 0.4 Very likely 0.7 0.280 76 Inflation Low 0.1 Likely 0.5 0.050 77 Economic recession Moderate 0.2 Remotely

likely 0.3 0.060

Total 0.198 0.35 0.0782

Almost certain

Unlikely Negligible Moderate Catastrophic

Almostcertain Very likely Likely Remotely likely Unlikely

Negligible Low Moderate High Catastrophic

Probability

Yellow – Low risk Grey – Moderate risk Green – Significant risk Red – High risk

p. 135

VI. The systemic risk (7 risks) Table 6-11. Quantification and allocation of risks

Risk sharing Estimated risk

Value, thousand Euro

Private partner

Public partner

Risk Private partner

Common

Public partner

Probability

Impact

1. C

onst

ruct

ion

phas

e ris

k

1 The current structure is inadequate

X 0.05 0.5 0.025 21836 17469 4367

2 Construction site conditions X 0.05 0.1 0.005 4367 3494 873

3 Obtaining the required permits – political opposition

X 0.2 0.7 0.14 122283 97826 24457

4 The environment and cleaning works after clearing the site

X 0.1 0.3 0.03 26203 26203 0

5 Deficient project design X 0.2 0.1 0.02 17469 17469 0

6 Size and complexity of PSHP works

X 0.05 0.1 0.005 4367 0 4367

7 Delays in commencing the works

X 0.2 0.7 0.14 122283 122283 0

8 Prices of materials and raw materials X 0.1 0.5 0.05 43672 34938 8734

9 Testing the construction (acceptance)

X 0.2 0.1 0.02 17469 13975 3494

10 Lifespan (of the PSHP) X 0.05 0.1 0.005 4367 0 4367

11 Technological risk X 0.1 0.7 0.07 61141 48913 12228

2. F

inan

cial

risk

12 Quality/price ratio X 0.1 0.3 0.03 26203 0 26203 13 Interest rates

before allocating the project

X 0.1 0.3 0.03 26203 20963 5241

14 Project duration X 0.1 0.5 0.05 43672 34938 8734

15 Cash flow verification X 0.2 0.3 0.06 52407 41925 10481

16 Additional funding requirements

X 0.05 0.3 0.015 13102 10481 2620

17 Liquidity X 0.2 0.1 0.02 17469 17469 0

18 Maturity degree (of the loans) X 0.2 0.3 0.06 52407 52407 0

p. 136

19 Existence of institutional investors

X 0.1 0.3 0.03 26203 20963 5241

20 Currency risk X 0.05 0.3 0.015 13102 13102 0

21 Amount of public contribution X 0.05 0.1 0.005 4367 3494 873

22 Advance payment of the public grant X 0.2 0.1 0.02 17469 0 17469

23 The public partner’s bankruptcy/default

X 0.05 0.1 0.005 4367 4367 0

24 The private partner operates with very high leverage ratios

X 0.2 0.3 0.06 52407 41925 10481

3. G

over

nanc

e –

spon

sor r

isk

25 Sponsor X 0.05 0.1 0.005 4367 0 4367 26 Partnership

agreement X 0.1 0.3 0.03 26203 26203 0

27 Changes in the private partner’s executive management orshareholding

X 0.05 0.5 0.025 21836 17469 4367

29 Private partners with several roles in the project

X 0.1 0.3 0.03 26203 26203 0

30 Fraud / Corruption X 0.2 0.3 0.06 52407 41925 10481

31 Project complexity X 0.2 0.5 0.1 87345 69876 17469

32 Moral hazard X 0.2 0.1 0.02 17469 13975 3494

33 The reputation created by electricity consumers, PSHP customers

X 0.05 0.5 0.025 21836 21836 0

34 The network created – the contribution of the project to the general development of the area

X 0.4 0.7 0.28 244565 0 244565

35 Renegotiation (of contracts) X 0.4 0.3 0.12 104814 83851 20963

4.

Ope

ratin

g –

perf

orm

ance

risk

s

36 Project management X 0.2 0.3 0.06 52407 52407 0

37 Inputs (price, quality, availability)

X 0.1 0.3 0.03 26203 26203 0

38 Changes in output specifications X 0.2 0.3 0.06 52407 0 52407

39 Flexibility X 0.1 0.3 0.03 26203 20963 5241

p. 137

40 Maintenance - reconstruction X 0.2 0.3 0.06 52407 52407 0

41 Security X 0.8 0.3 0.24 209627 167702 41925

42 Bankruptcy (of the contractor or the subcontractor)

X 0.4 0.3 0.12 104814 104814 0

43 Technical wear and tear or innovation

X 0.4 0.5 0.2 174689 139752 34938

44 Market test (benchmarking) X 0.1 0.5 0.05 43672 43672 0

45 Staff expenditure X 0.1 0.3 0.03 26203 26203 0

47 Delivery X 0.05 0.1 0.005 4367 0 4367

48 Competence and know-how levels X 0.4 0.5 0.2 174689 174689 0

49 Monitoring X 0.1 0.1 0.01 8734 0 8734 50 Subcontracting X 0.2 0.3 0.06 52407 52407 0

51 Bias-generated costs X 0.2 0.5 0.1 87345 87345 0

52 Operational income below targets

X 0.2 0.5 0.1 87345 87345 0

53 Faults of ITC systems X 0.4 0.3 0.12 104814 83851 20963

5. M

arke

t ris

k

54 Market X 0.1 0.1 0.01 8734 6988 1747

55 Electricity demand X 0.2 0.1 0.02 17469 0 17469 56 Demand (based on

tariffs /business income )

X 0.1 0.3 0.03 26203 20963 5241

57 Alternative services offer X 0.1 0.5 0.05 43672 43672 0

58 Lack of experience X 0.2 0.3 0.06 52407 41925 10481

59 Selection criteria X 0.2 0.5 0.1 87345 69876 17469

60 Tenderers’ pre-eligibility standards

X 0.2 0.5 0.1 87345 0 87345

61 Abnormal offer X 0.2 0.5 0.1 87345 0 87345 62 Appeal

(litigation) X 0.4 0.7 0.28 244565 195652 48913

63 Industrial relations and critics from the civil society

X 0.4 0.5 0.2 174689 174689 0

64 Approvals X 0.4 0.7 0.28 244565 195652 48913

65 Procedural X 0.4 0.5 0.2 174689 139752 34938

66 Changes in the legislative X 0.4 0.5 0.2 174689 0 174689

p. 138

framework and government policies

67 Regulation X 0.4 0.5 0.2 174689 174689 0

68 Fiscal code changes X 0.2 0.3 0.06 52407 52407 0

69 Contractual X 0.1 0.3 0.03 26203 20963 5241

70 Corruption X 0.2 0.5 0.1 87345 69876 17469

6. S

yste

mic

71 Force majeure X 0.8 0.3 0.24 209627 167702 41925

72 Hydrologic X 0.1 0.3 0.28 244565 195652 48913

73 Country risk X 0.2 0.5 0.03 26203 26203 0

74 Political X 0.05 0.1 0.1 87345 87345 0

75 Demographic changes X 0.4 0.7 0.005 4367 3494 873

76 Inflation X 0.1 0.5 0.05 43672 34938 8734

77 Economic recession X 0.2 0.3 0.06 52407 41925 10481

TOTAL 5.033.8 3.763.5 1.270.2

The daily value of the estimated risks is 13.8 million Euro, representing approximately 1.38% of the initial investment total value. In the assumption of project funding from public budgetary sources, this risk would be entirely covered by the State. In the hypothesis of funding the project via a PPP mechanism, 74.76% of the total value of risks would be transferred to the Private Partner, whereas the remaining value of 25.24% would be allocated to the Public Partner. 6.6. Project generic possibility of mobilizing the financial resources required

to cover costs (project sustainability degree) The investment financial sustainability analysis assesses the extent to which the project shall be sustainable, in terms of annual financial flows, but also of the cumulative financial flows over the entire analysis period. The cost flows correspond to the “With Project” option. Considering the fact that the entire analysis was carried out based on two scenarios, one which is pessimistic and an optimistic one, the tables below display the project sustainability analysis, by comparing the expenditure flows (investment, operating and maintenance costs) with the receipt flows (direct revenues, availability-based payments, as well as other revenue sources), in the two cases. Table 6-12.1.Investment financial sustainability analysis (PPP Scenario), at minimum prices

Analysis year

Operation year Receipts

Direct financial revenues

Payments made by the public partner

Expenditures Investment

Operation, maintenance and replacement

Net cash flow Cumulative cash flow

p. 139

2019

Des

ign

and

exec

utio

n 21262296 0 21262296 110000000 110000000 -88737704 -88737704

2020 404996114 0 40499611.43 220000000 220000000 -179500388.6 -268238093

2021 455839782 0 45583978.23 260000000 260000000 -214416021.8 -482654114

2022 467527982 0 46752798.19 280000000 280000000 -233247201.8 -715901316

2023 102943253 0 102943253.5 130000000 130000000 -27056746.52 -742958063

2024 1 M

aint

enan

ce a

nd o

pera

tion

117389167 78212859.1 39176308.32 7000000 0 7000000 110389167.4 -632568895

2025 2 114033860 76723090.3 37310769.83 7210000 0 7210000 106823860.2 -525745035

2026 3 110795765 752616981 35534066.51 7426300 0 7426300 103369464.6 -422375570

2027 4 107670110 73828142 338419681 7649089 0 7649089 100021021.1 -322354549

2028 5 104652337 724218917 32230445.81 7878561.67 0 7878561.67 96773775.81 -225580774

2029 6 101738090 71042427.1 30695662.68 8114918.52 0 8114918.52 93623171.22 -131957602

2030 7 9892320Z4 69689238 29233964.45 8358366,076 0 8358366.076 90564836.35 -41392766

2031 8 96203694.8 68361823.9 27841870.91 8609117.058 0 8609117.058 87594577.77 46201811.79

2032 9 93575761 5 67059693.9 26516067.53 8867390.57 0 8867390.57 84708370.9 13091018Z7

2033 10 91035764.1 65782366,4 25253397.65 913341Z287 0 9133412.287 81902351.8 212812534.5

2034 11 88580223.9 64529369 24050854.9 9407414.655 0 9407414.655 79172809.23 291985343.7

2035 12 86205814.2 633002381 22905576,1 9689637.095 0 9689637.095 76516177.15 368501520i 9

2036 13 83909353.7 62094519.3 21814834.38 56045579.21 0 56045579.21 27863774.49 396365295.4

2037 14 81687799.3 60911766,6 20776032.74 10279735.99 0 10279735.99 71408063.32 4677733587

2038 15 7953824Q3 5975154Z4 19786697.85 10588128.07 0 10588128.07 68950112.22 53672347Q9

2039 16 77457892 58613417.8 18844474.14 10905771.92 0 10905771.92 66552120.05 603275591

2040 17 75444090 574969718 17947118.23 11232945.07 0 11232945.07 64211144.93 667486735.9

2041 18 73494284.9 564017914 17092493.55 11569933.43 0 11569933.43 61924351.49 729411087.4

2042 19 71606036,8 553274715 16278565.29 11917031.43 0 11917031.43 59689005.38 78910009Z8

2043 20 69777010.4 542736149 15503395.51 12274542.37 0 12274542.37 57502468.07 846602560.8

2044 21 68004970.4 53239831 8 14765138.58 12642778.64 0 12642778.64 55362191.72 90196475Z5

2045 22 66287776l5 52225739.7 14062036.75 13022062 0 13022062 53265714.49 955230467

2046 23 64623379.7 51230963.8 13392415.95 13412723.86 0 13412723.86 51210655.84 1006441123

2047 24 63009817.7 50255135.9 12754681.86 13815105.58 0 13815105.58 49194712.15 1055635835

2048 25 614452112 49297895.2 12147316.05 14229558.75 0 14229558.75 47215652.5 1102851488

Total 2404131591 1567333500 836798091 1301280103 1000000000 301280103.3 7410823388 6508808769

Financial Internal Rate of Return of the Total Investment (FIRR/C) 19.88%

Financial Net Present Value of the Total Investment (VANF/C) 1527250673.07

Benefits / Capital Cost Ratio (BCR) 1.85

p. 140

Figure 6-6.1. Net cash flow (annual total and cumulative annual total), at minimum prices

In the pessimistic scenario, the Cumulative cash flow becomes positive as of the 13th analysis year (the 8th year of operation) – from this year on, the private investor shall obtain positive (cumulative) net financial incomes. Practically, they shall have to finance the investment from own sources during the first 7 years of operation. As such, if the electricity production is going to be sold at minimum prices, the sustainability analysis concludes that the investment shall be recovered (it shall have depreciated as of the 23rd year of operation, in terms of net cumulative financial flow – see section 6.3.3), which would hardly make the project attractive for investors, under the working assumptions formulated in this study, but achievable, nonetheless. Table 6-42.2. Investment financial sustainability analysis (PPP Scenario), at maximum prices

Analysis year

Operation year Receipts

Direct financial revenues

Payments made by the public partner

Expenditures Investment

Operation, maintenance and replacement

Net cash flow Cumulative cash flow

2019

Des

ign

and

exec

utio

n 21262296 0 21262296 88000000 88000000 0 -66737704 -66737704

2020 40499611.4 0 40499611.43 167619047.6 167619047.6 0 -127119436.2 -193857140

2021 45583978.2 0 45583978.23 188662131.5 188662131.5 0 -143078153.3 -336935293

2022 46752798.2 0 46752798.19 193499622.1 193499622.1 0 -146746823.9 -483682117

2023 102943253 0 102943253.5 85561057.38 85561057.38 0 17382196.1 -466299921

2024 1

Mai

nten

ance

and

ope

ratio

n

134356716 95180408.1 39176308.32 5484683.165 0 5484683.165 128872033.3 -337427888

2025 2 130678218 93367448 37310769.83 5380213.01 0 5380213.01 125298004.8 -212129883

2026 3 127123087 91589020.4 35534066.51 5277732.762 0 5277732.762 121845354.1 -90284529.1

2027 4 123686436 89844467.6 33841968.1 5177204.519 0 5177204.519 118509231.2 28224702.15

2028 5 120363590 88133144.4 32230445.81 5078591.099 0 5078591.099 115284999.1 143509701.3

2029 6 117150081 86454417.9 30695662.68 4981856.031 0 4981856.031 112168224.5 255677925.8

2030 7 114041632 84807667 29233964.45 4886963.535 0 4886963.535 109154668 364832593.8

2031 8 111034154 83192282.9 27841870.91 4793878.515 0 4793878.515 106240275.3 471072869.1

2032 9 108123736 81607668 26516067.53 4702566.544 0 4702566.544 103421169 574494038.1

2033 10 105306634 80053236.2 25253397.65 4612993.848 0 4612993.848 100693640 675187678.1

2034 11 102579268 78528412.7 24050854.9 4525127.298 0 4525127.298 98054140.29 773241818.4

-800

-300

200

700

1200

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Fluxul net de numerar

Fux de numerar cumulat

Net cash flow Cumulative cash flow

p. 141

2035 12 99938209.5 77032633.4 22905576.1 4438934.397 0 4438934.397 95499275.1 868741093.5

2036 13 97380179.5 75565345.1 21814834.38 47984052.03 0 47984052.03 49396127.49 918137221

2037 14 94902038 74126005.2 20776032.74 4271442.632 0 4271442.632 90630595.34 1008767816

2038 15 92500779.2 72714081.3 19786697.85 4190081.82 0 4190081.82 88310697.35 1097078514

2039 16 90173525.3 71329051.2 18844474.14 4110270.738 0 4110270.738 86063254.61 1183141768

2040 17 87917520.8 69970402.6 17947118.23 4031979.867 0 4031979.867 83885540.97 1267027309

2041 18 85730126.6 68637633 17092493.55 3955180.25 0 3955180.25 81774946.34 1348802256

2042 19 83608814.8 67330249.5 16278565.29 3879843.483 0 3879843.483 79728971.35 1428531227

2043 20 81551164.1 66047768.6 15503395.51 3805941.703 0 3805941.703 77745222.42 1506276449

2044 21 79554854.5 64789715.9 14765138.58 3733447.575 0 3733447.575 75821406.88 1582097856

2045 22 77617662.8 63555626 14062036.75 3662334.288 0 3662334.288 73955328.5 1656053185

2046 23 75737458.6 62345042.7 13392415.95 3592575.54 0 3592575.54 72144883.1 1728198068

2047 24 73912199.9 61157518.1 12754681.86 3524145.529 0 3524145.529 70388054.4 1798586122

2048 25 72139929 59992613 12147316.05 3457018.948 0 3457018.948 68682910.07 1867269032

Total 2744149950 1907351859 836798091 876880917.7 723341858.6 153539059.1 1867269032 20357594768

Financial Internal Rate of Return of the Total Investment (FIRR/C) 22.01%

Financial Net Present Value of the Total Investment (VANF/C) 1867269032.32

Benefits / Capital Cost Ratio (BCR) 3.13

Figure 6-7.2. Net cash flow (annual total and cumulative annual total), at maximum prices

In the optimistic case, the cumulative cash flow becomes positive as of the 9th analysis year (the 4th year of operation) – from this year on, the private investor shall obtain positive (cumulative) net financial incomes. Practically, they shall have to finance the investment from own sources during the first 3 years of operation. The sustainability analysis concludes that the investment shall be recovered (it shall have depreciated as of the 14th year of operation, in terms of net cumulative financial flow – see section 6.3.3), which would hardly make the project attractive for investors, under the working assumptions formulated in this study.

-500

0

500

1000

1500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Flux de numerar net Flux de numerar cumulatNet cash flow Cumulative cash flow

p. 142

6.7. Tariffs and charging system Setting the tariffs may be left among the private partner’s duties, who shall consider the proposal that the tenderer should be responsible for the charging strategy and management. Following the market analysis and based on the current controlling and operating methods for PSHPs in Romania, the following possible expected tariffs were identified, both minimum and maximum and both for production and consumption. These tariffs, in order to have the data discounted, were subject to a 3% increase, following the exact method applied to costs.

SYSTEM SERVICE MINIMUM

PRICE MAXIMUM PRICE

QUANTITY

SECONDARY REGULATION 13.7EURO/HMW 16 EURO/HMW 916,300 FAST TERTIARY REGULATION 6.8 EURO/HMW 8 EURO/HMW 4,108,650 DISPATCHABLE CONSUMPTION 6.8 EURO/HMW 11 EURO/HMW 2,352,000 ELECTRICITY PRODUCTION 45 EURO/MWH 61 EURO/MWH 1,650,000 ELECTRICITY CONSUMPTION 14.7 EURO/MWH 25 EURO/MWH 2,103,000

The system services were assessed in line with the regulated tariffs in force (2014

ANRE Decision).

6.8. Main contractual stages In order to implement the public-private partnership contract, the project company is set up according to the provisions of Law no. 31/1990, republished, as subsequently amended and supplemented. The public partner’ cash contribution to the share capital of the project company shall be the minimum amount provided by legislation in force. It may be increased by the Romanian government during the performance of the contract, as per an agreement between the contracting parties. The PPP contract is structured into two main stages, as follows:

o the design and execution period is 60 months from the contract signing date,

o the operating stage, lasting 32 years from the contract signing date, for the already completed assets (as the case may be), and for the rest of the project, from the completion dates of various stages.

If the completion of the design and execution period is marked by delays, the private partner shall pay the public partner a fine corresponding to the one-year share of the delay period, the total annual fine amounting to 100 million Euro. The public partner’s share to the financing required to carry out the investment, represented by financial resources different than non-reimbursable external funds and the national contribution specific to such funds, shall not exceed, according to GEO no. 39/2018 on public-private partnerships, art. 12. par. (2), 25% of the total investment value. The risk of subpar operating revenues shall call for either availability-based payments or an extension to the contract term, in the event that, at the end of such term, the private partner has not managed to obtain the expected profit. The availability-based payments shall be calculated based on the results of activities carried out during the preliminary period, representing cash receipts and expenditure of the private partner, which will be entered in their financial model.

p. 143

The projected value of the investment may be amended depending on the evolution of technologies in the field. In this case, the private investor may increase their financing share and shall either agree or disagree with the public partner regarding the latter increasing their financing input, as well. 6.9. Main activities carried out during each contractual stage/period

Preliminary period

During the preliminary period, the following categories of activities shall take place:

a) Land investigations and design activities

The land studies are to be conducted by a specialized entity under the control of both parties to the PPP contract – the public partner and the private partner, whereas the amounts due to it shall be paid by both parties, in equal proportions, to ensure impartiality in the performance of its activities. The project preparation activities shall include:

1) The expert valuation of all the constructions carried out, 2) Obtaining Town Planning Certificates from county councils Elaboration of the documentations required to obtain the permits and agreements provided

in the Town Planning Certificates Elaboration of the documentation required to obtain the building permit technical

documentation (DTAC), Elaboration of the technical projects (TPs) and the detailed execution plan (DDE) for all

the objectives pertaining to this investment objective Elaboration of the studies provided by the procedure required to obtain the environmental

permit and the water rights permit, namely: a) Environmental Impact Study (EIS) Appropriate Assessment (AA) Assessment of Impacts on Water Bodies (SEICA) Climate change study

The public partner shall take all steps to expropriate any additional lands, including lands for site management and connections to utility networks or road and railway transportation networks. The plans for additional expropriations have already been drawn up and shall be inspected during the phase when the technical project and the detailed execution plan are drawn up. The public partner shall deliver the site after having made an inventory of all the existing items and assessing the works previously carried out per item, taking into account the fact that some of them were built more than 40 years ago and require particular management, the current investment objective being currently under the management of S.C. Hidro-Tarnița S.A. (a company constituted in November 2013).

b) Activities performed to obtain funding for the entire project

At the time of concluding the PPP contract, the private partner shall have secured private funding in order to carry out the activities of the preliminary stage. Considering the contract objectives resulted from the dialogue stage and the land investigations conducted during the preliminary stage, a fixed firm construction price shall be

p. 144

set forth by applying the adjustment mechanism based on these aspects, at the end of this period, whereas funds from financers would subsequently be obtained in that respect. Therefore, chronologically speaking, the activities directly aimed at obtaining funding are to be carried out during the preliminary period, after the previously mentioned land investigations have been performed, and shall focus on supplying the construction price resulted by applying the adjustment algorithm. The funding conditions were initially established by the public partner in order to better compare the tenders, and were taken into account and included as such in the winning tenderer’s financial model. The financing structure of the entire project shall be set up as part of a competitive funding that is to take place according to the rules provided in the PPP contract and will aid in setting forth the effective financing costs provided by the financial markets at that time. Competitive financing is a process in the performance of which the funds required to implement the project are to be obtained at the most convenient available financing cost, under current market conditions. The procedure will be carried out by the private partner, under the public partner’s supervision. The procedure shall comply with the principles and practices of project funding on the European market and shall secure a fair and transparent competition among the financing sources available on the European market in the area of funding electricity production projects. At the end of the financing procedure, subsequent to the existence of an agreement regarding the financing structure, the financing contracts for the entire project shall be signed between the private partner and the financers. The procedure applied in order to sign the financing contracts, that is to initially draw the funds based on the financing contracts, is generically called the financial closure procedure. Considering that the candidates’ tenders shall rely on the financial hypotheses taken into account, the PPP contract includes a detailed procedure which comprises the mechanism for adjusting the availability-based payment in relation to the differences in funding costs between the costs presumed by the public partner and the costs actually resulted from the competitive financing process. The general purpose of the adjustment procedure is that the amount of the availability-based payment be adjusted in such a manner that any change in the costs related to external funding, when placing the initial hypotheses of the public partner in relation to the actual funding conditions, valid on the financial closure date, should not lead to a profit increase for the private partner and any savings achieved should be transferred to the contracting authority. This adjustment procedure will provide assurances that the contracting authority and the private partner will not find themselves, at the time of the financial closure, on inferior or superior positions, in terms of project financial balance, than those at the time of the final bid.

c) Construction activities

In parallel with the activities mentioned at letters a) and b) above, the private partner shall commence during the preliminary period actual construction activities. The preliminary period shall be finalized when the private partner has obtained funds for the objective. The financial closure shall take place within 3 months from the PPP contract signing date, with the possibility to extend this period by 1 additional month. To the extent to which the availability-based payment would increase after the preliminary period, the public partner is entitled to terminate the PPP contract.

p. 145

Moreover, if the private partner fails to obtain funding for the entire project, the PPP contract shall be terminated. The construction period

The design and execution period is 60 months from the contract signing date. The operation period

The operation period, lasting up to 30 years, commences on the contract signing date, for the already completed assets (as the case may be), and for the rest of the project, from the completion dates of various stages. The private partner’s obligation to render operation services under a public-private partnership comprises all the activities required to permanently render a fully functional and high quality objective for electricity consumers. The private partner must demonstrate frequently, during the contract term, that the operation and maintenance requirements are met. If the personnel should fail to meet the requirements stipulated for an activity of this kind, they shall be liable to pay penalties according to the provisions of section 6.12. 6.10. Project income presentation

Income from electricity supply The income estimates for the project implementation period stemmed from the

assumption that the private partner, in order to maximize their income, shall finalize the construction within 5 years, so that they may receive the availability-based amount of 100 million Euro from the state.

o Income from electricity supply = Total annual capacity * electricity price, from which we subtract Total annual consumption * electricity price, as follows:

SYSTEM SERVICE MINIMUM PRICE

MAXIMUM PRICE

QUANTITY

SECONDARY REGULATION 13.7EURO/HMW 16 EURO/HMW 916,300 FAST TERTIARY REGULATION 6.8 EURO/HMW 8 EURO/HMW 4,108,650 DISPATCHABLE CONSUMPTION 6.8 EURO/HMW 11 EURO/HMW 2,352,000 ELECTRICITY PRODUCTION 45 EURO/MWH 61 EURO/MWH 1,650,000 ELECTRICITY CONSUMPTION 14.7 EURO/MWH 25 EURO/MWH 2,103,000

The average annual income estimated to be obtained over the entire 2024-2048 period

may vary between 1.567 billion Euro and 1.907 billion Euro, for the said period, depending on the electricity selling and purchasing price, respectively. The prices taken into account for the two scenarios were indexed on an annual basis with a 3% inflation rate. For each year, the income dynamics are presented in the images below, in accordance with the two scenarios. Figure 6-7.1. Evolution of non-present financial income, as per the pessimistic scenario, million Euro

p. 146

Figure 6-7.2.Evolution of non-present financial income, as per the optimistic scenario, million Euro

6.11. Penalty system

The payment mechanism of the PPP contract contains provisions which entitle the public partner to charge and receive penalties from the private partner. Three types of penalties that can be incurred are stipulated:

o first of all, penalties can be applied if one or several assets are non-functional o second, penalties can be applied when the private partner fails to fulfill their

obligations stipulated in the contract (non-fulfillment of serviceability according to the contract provisions),

o finally, the public partner can apply penalties if the project is not fully functional or entails considerable works which are yet to be completed.

0

50

100

150

200

250

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

100 103 106 109 112 116 119 123 126 130 134 138 142 147 151 156 160 165 170 175 180 186 191 197 203

0

50

100

150

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2025

2026

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2028

2029

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2031

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2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

121125129133137141145149154158163168173178184189195201207213219226233240247

p. 147

The penalty system is conceived in a manner that encourages the private partner to carry out the necessary maintenance works with as few electricity production disruptions as possible – the longer the impairment of end users, the higher the penalties the private partner has to pay to the public partner. The longer the electricity production partial shutdown, the higher the penalty. The private partner shall observe the requested level of the service, both in relation to the end users (the consumers) and the public partner, otherwise the latter is entitled to charge and receive penalties from private partner. The service rendering obligations consist in the management, operation and maintenance of the investment objective, based on the following two categories:

o non-compliances regarding the performance requirements, which affect the users’ safety;

o non-compliances regarding the performance requirements, which do not affect the users’ safety.

In most cases, the private partner benefits from a time interval to remedy the non-compliance case occurred, before being subject to “service points” applied for each day in which the respective non-compliance remains unsettled. The more serious the non-compliance, the higher the number of service points applied. As part of the PSHP management, operation and management activities, one may reasonably expect the occurrence of cases in which the private partner, for various reasons, is unable to fulfill, in full or in due time, all their obligations without causing the use of a very significant level of resources likely to lead to excessive costs being borne by the public partner, and such a conservative approach would not bring economic and financial benefits for the latter. Consequently, the principle employed is to allow the private partner to “accrue” a certain number of service points each month, up to the threshold beyond which financial penalties start being incurred, representing for them a “red flag” and an incentive to promptly rectify any non-compliances, otherwise ending up incurring the said penalties. At the same time, in order to deter any attempt the private partner might make to overlook the fulfillment of their obligations, once the respective threshold has been reached, the amount of deductions shall progressively increase, as the number of accrued points increases, as well. The deduction point value is an element of the tender and has to be proposed by each candidate preselected during the bidding procedure, all of them being provided with a range between 100 and 120 units. The value quoted by the wining tenderer should be the maximum one, 120 units, and should be included as such among the contract provisions. The deduction mechanism shall beconceived on grounds that, if a facility is unavailable over a certain period of time, the deductions shall be calculated so as to eliminate any payments that would have been allotted for the respective assets over the relevant period of time. Moreover, the PPP contract contains provisions according to which, in the case of long-lasting infringement-type events (a case equivalent to the accrual of a certain number of penalty points), the public partner may initiate the contract termination procedure by fault of the private partner. 6.12. PPP contract termination and termination payments

a) Termination by fault of the public partner

p. 148

If the PPP contract is terminated by fault of the public partner, they shall pay indemnify the private partner, and the amount payable as indemnification shall allow the latter:

• to reimburse the amounts they owe at the time to financers as per the main financing contracts;

• to recover the amounts invested in the project by the private partner’s shareholders (minus any possible amounts already recovered);

• to pay any possible costs incurred with the termination of subcontracts by the private partner following the termination of PPP contract (for instance, the termination of the design and construction contract and/or the operation and maintenance contract);

• to ensure the rate of return for the amounts invested by the private partner at the time. b) Contract termination following the termination for convenience by the public partner

If the PPP contract comes to an end following the termination for convenience by the public partner, they shall pay the private partner aindemnification equivalent to the amount payable in case of termination by fault of the public authority.

c) Termination on grounds of force majeure If the PPP contract comes to an end following a force majeure event, the public partner shall indemnify the private partner, and the amount payable as indemnification shall allow the latter to reimburse the amounts owed at the time by the private partner to financers as per the main financing contracts.