The 10-Year Development Plan of the Power Transmission Grid (RET) (2018 – 2027)”

Directorate

NOTE regarding the approval by the Shareholders’ General Assembly of ”The 10-year development plan of the power transmission grid (RET) (2018 – 2027)”

I. Generalities

”The Development Plan for the Power Transmission Grid 2018-2027" (hereinafter referred to as PDRET) was drawn up by the National Power Grid Company Transelectrica SA in accordance with article 35 para. (1) and para. (2) of the Law on Power and Natural Gas 123/2012, with later amendments and additions, according to which ”the transmission system operator must prepare 10-year investment and development plans of the power transmission grid, in accordance with the current state and the future evolution of power consumption and the sources, including power import and export”.

II. Justification According to the competences and attributions established by the Law on Power and Natural Gas 123/2012, with later amendments and additions, the RET Technical Code and the Conditions attached to License 161 for Power Transmission and System Service Provision, the National Power Grid Company Transelectrica SA carries out the planning activity on the development of the Power Transmission Grid (RET). In this regard, the National Power Grid Company Transelectrica SA draws up every two years a RET Development Plan for the following 10 successive years, a document that is subject to the approval of the decision-makers.

The Development Plan is a comprehensive presentation of the aspects related to the functioning of the power transmission grid, integrated in the context of the National Power System and the power market, intended for power market customers, regulatory bodies and decision-makers in the power sector. The paper includes information on the power generation and consumption sectors, the characteristics and performance of the power transmission grid, and other useful information to assess existing or potential market opportunities.

The content of the PDRET, the conditions and principles for its elaboration, the source and structure of the data used and the criteria applied in the elaboration of the plan are in accordance with the provisions of Chapter IV of the Technical Code of the power transmission grid, approved by ANRE Order 20/2004, with later amendments and additions , and with the principles established by ENTSO-E for the elaboration of the community-level development plan TYNDP - Ten Year Network Development Plan.

Also, the elaboration of the RET Development Plan every two years is in line with the National Power Grid Company Transelectrica SA’s obligation to participate, as a member of the ENTSO-E European transmission system operators’ association, by drawing up the document Ten Year Network Development Plan (TYNDP).

Provisions of art. 8 para. (10) of Regulation (CE) (EC) 714/2009 regard this aspect. They are provisions on conditions for access to the grid for cross-border power exchanges (Regulation 714/2009), which provide that ENTSO-E adopts and publishes, every two years, a community-level grid development plan, which includes the modelling of the integrated grid, a development scenario, an European assessment of production capability adequacy and an assessment of system flexibility, based on national investment plans, taking into account regional investment plans.

On 04.04.2018, through address 11429, the National Power Grid Company Transelectrica SA has submitted PDRET to the Romanian Energy Regulatory Authority (ANRE) for approval. Subsequently, ANRE approved PDRET by Decision 1604/05.10.2018, issued in accordance with the provisions of art. 35 para. (3) of the Law on Power and Natural Gas 123/2012, with later amendments and additions, and in accordance with the provisions of art. 5 para. (1) letter d) and art. 9 para. (1) letter v) from Emergency Ordinance 33/2007 on the organization and functioning of ANRE, approved with amendments and additions by Law 160/2012, with later amendments and additions, with certain obligations for the Company, as set out in the annex. Article 2 of ANRE Decision 1604/2018 stipulates the following: ”Within 90 days of the communication of this decision, the National Power Grid Company Transelectrica SA shall send to ANRE the decision of the Shareholders’ General Assembly approving the Development Plan provided for in art. 1”. III. Proposals In view of the above, in accordance with art. 2 of the ANRE Decision 1604/05.10.2018, as well as art. 14, para. 2, letter n) of the Articles of association, we propose the following to the Shareholders’ General Assembly: - approval of the ”Development Plan of the power transmission grid 2018-2027”.

Directorate,

Chairman,

Adrian - Constantin RUSU

Members,

Andreea Georgiana Adrian-Mircea Viorel Constantin FLOREA TEODORESCU VASIU SARAGEA

2/3

Visas:

UMA Director

Gheorghe ȘTIRBU

DEMDRET Director

Ștefan ȚIBULIAC

DDRET Manager

Daniela BOLBORICI

DGCRIR Director

Bogdan Toncescu

DJC Director

Radu Cernov

3/3

PTG Development Plan for 2018 – 2027

Responsible for the works: Oana Raluca Mânicuță Electricity grids expert

Opinion no. 30/2018 of TESC Transelectrica

Approved, Directorate:

Chairman Member Member Member Member

Adrian Constantin Constantin Viorel Adrian Mircea Andreea Georgiana RUSU SARAGEA VASIU TEODORESCU FLOREA

Table of Contents Annexes ______6 Abbreviations ______7 1. Purpose and objectives of the Ten-year PTG development plan ______9 2. European integration of the power transmission grid planning ______10 2.1. Correlating the European Ten-Year Network Development Plan (TYNDP) with the National ten- year power transmission grid development plan ______10 2.2. Priorities in the energy infrastructure sector ante and post 2020 – Projects of Common Interest (PCI) ______13 2.3. Overview of the benefits brought by the PTG development projects included in TYNDP 2016 _ 14 3. Legislative and regulatory framework ______16 3.1. Primary legislation ______16 3.2. Secondary legislation ______20 4. Principles and methodologies used in drafting the PTG development plan ______23 4.1. Principles applied in drafting the PTG development plan ______23 4.2. Methodologies/analyses used in drafting the PTG development plan ______23 5. Analysis of the current situation of PTG and associated infrastructure for the period of 2016- 2017______25 5.1. Power generation capacities ______25 5.2. System adequacy at peak load ______26 5.3. Internal electricity transmission capacities and interconnections with other systems ______32 5.4. Loading factor of PTG elements ______36 5.4.1. Summer of 2017 ______36 5.4.2. Winter of 2016-2017 ______38 5.4.3. Conclusions regarding the domestic grid load ______40 5.4.3.1. SEP section (summer of 2017) ______40 5.4.3.2. WEP section (winter of 2016-2017) ______41 5.4.4. The total and bilateral transmission capacities on borders ______41 5.4.4.1. Calculated/estimated net exchange capacities ______42 5.4.4.2. Maximum net transfer capacities ______44 5.4.4.3. Monthly net transfer capacities ______46 5.4.4.4. Factors that influence the non-guaranteed maximum capacity values and the annual and monthly fixed exchange capacities ______46 5.4.4.5. Graphic representation of the influences over the fixed NTC in 2014-2017 ______48 5.4.4.6. Graphic representation of NTC profiles and exchange programs ______51 5.5. The admissible voltage level, voltage control in PTG nodes, reactive power compensation, voltage quality ______52 5.6. Power losses in sections specific to the load curve and annual electricity in the PTG ______55 5.7. Short-circuit current level in PTG nodes ______58 5.8. Inspection of PTG under steady-state and transient stability conditions ______59 5.8.1. Inspection of PTG under steady-state stability conditions ______59 5.8.1.1. Calculation assumptions ______59 5.8.1.2. Results of steady-state stability analyses ______61

5.8.1.3. Analysis of NPS characteristic sections in terms of steady-state stability conditions ______63 5.8.2. Transient stability and potential improvement measures ______64 5.8.2.1. Methodology and calculation assumptions ______64 5.8.2.2. Conducted analyses ______65 5.8.2.3. Weak points identified and potential improvement measures ______66 5.9. Continuity level of the electricity transmission service ______66 5.10. The operative dispatching management system – EMS/SCADA-NPD ______72 5.11. Ancillary services ______74 5.12. Electricity metering systems and electricity quality monitoring systems ______77 5.13. Telecommunications system ______78 6. Security of installations and crisis management ______80 7. Environmental protection related to PTG ______81 7.1. Environmental impact of transmission grids ______81 7.2. Legal requirements applicable to the environmental aspects generated by the Company's activity ______82 7.3. Measures taken to reduce the PTG impact on the environment in 2018-2027 ______85 8. Technical status of power transmission and distribution grids ______87 8.1. Technical status of the power transmission grid______87 8.2. Technical status of the power distribution grid ______103 9. Scenarios regarding the NPS evolution into perspective – timeframe 2018-2022-2027 _____ 106 9.1. General principles for building scenarios ______106 9.2. Scenarios regarding the evolution of the electricity demand in the NPS ______107 9.3. Scenarios regarding the power exchange balance ______110 9.4. Scenarios regarding the evolution of generation facilities ______110 9.5. NPS generation facilities adequacy analysis in the 2018-2022-2027 period ______114 9.6. NPS load coverage by generating units – cases analyzed for the verification of the PTG adequacy ______118 10. Perspective analysis of PTG operation regimes ______120 10.1. Analysis of steady-state regimes ______121 10.1.1. Analysis of the Dobrogea area ______124 10.1.2. Analysis of the Dobrogea and Moldova areas ______125 10.1.3. Analysis of the Moldova area ______128 10.1.4. Analysis of the northern Transylvania area ______128 10.1.5. Analysis of the South-West area ______129 10.1.6. Analysis of the northern Transylvania, Moldova and northern Banat areas, called the North-South section ______131 10.1.7. Analysis on the supply of the municipality of Bucharest ______132 10.1.8. Opportunity to replace the active conductor on certain 220 kV OHLs, from a 400 mm2 section to a 450 mm2 section ______133 10.1.9. Analysis of the impact over the NPS of the delay/postponement of the commissioning deadline of projects set forth in the 2016-2025 PTG development plan and included in the BAR ______134 10.2. Loading degree of PTG elements ______137 10.3. Voltage level, voltage control and reactive power compensation ______137

10.4. PTG power losses in sections specific to the load curve ______138 10.5. Short-circuit loads ______140 10.6. Inspection of the PTG under steady-state stability conditions ______141 10.6.1. Results of steady-state stability analyses – mid term ______141 10.6.2. Results of steady-state stability analyses – long term ______142 10.7. Transient stability and protection measures in PTG nodes ______147 10.8. Conclusions regarding PTG operation regimes in perspective ______151 11. PTG asset maintenance strategy for the following ten years ______154 11.1. PTG facilities' maintenance strategy ______154 11.1.1. General maintenance issues as part of Asset Management ______154 11.1.2. PTG facilities' maintenance schedule (electric substations and lines) ______159 11.2. Maintenance strategy for electricity quality metering and monitoring systems ______163 12. Fixed asset development strategy ______164 12.1. Evolutions determining the need to develop fixed assets ______164 12.2. PTG development strategy ______166 12.2.1. Needs to enhance the PTG determined by the NPS evolution in the 2018-2027 period ______166 12.2.2. Uncertainties concerning the NPS evolution and settlement thereof in the PTG development plan _____ 169 12.2.3. PTG facilities' development, refurbishment/modernization program ______171 12.2.4. Estimation of benefit indicators specific to PTG projects ______184 12.2.5. Priority technical solutions ______185 12.3. PTG associated systems ______186 12.3.1. Development strategy for the EMS/SCADA-NPD dispatcher management system ______186 12.3.2. Metering system and electricity quality monitoring system development strategy ______189 12.3.3. Telecommunications system development strategy ______194 12.3.4. Critical infrastructure protection development strategy ______195 12.3.5. CNTEE Transelectrica SA's strategy in terms of research and innovation ______196 12.3.5.1. Current and future challenges for the transmission system operators (TSOs) ______196 12.3.5.2. Objectives of the research and innovation strategy ______197 12.3.5.3. Challenges regarding asset management for transmission system operators (TSOs) ______199 12.3.5.4. Advantages of applying Smart Grid concepts and standards ______200 13. Assessment of investment expenditures for the development of the PTG ______202 14. Sources of funding ______205 14.1. CNTEE Transelectrica SA's revenues ______205 14.2. Funding sources for the development of infrastructures operated by the Company ______205 15. Analysis directions for the next stage ______209 Bibliography ______210

Annexes

Annex A Building cases and analyzing operational regimes for the PTG reference design Annexes B Analysis of current PTG operational regimes Annex B-1 Demand in substations Annex B-2 PTG components Annex B-3 PTG equipment loading – SMP 2017 Annex B-4 PTG equipment loading – WEP 2016-2017 Annex B-5 Voltage rates in PTG substations – SMP 2017 Annex B-6 Voltage rates in PTG substations – WEP 2016-2017 Annex B-7 Currents and short-circuit powers – 2017 Annex B-8 Overview of qualification of groups and suppliers for the provision of ancillary services Annexes C Forecast of electricity generation/demand balance for the period 2018-2027 Annex C-1 Forecast of electricity consumption per zone during the period 2018-2027 Annex C-2 Evolution of the electricity generation facilities (not published) Annex C-3 Groups' loads in specific sectors (not published) Annexes D Analysis of the steady-state stability Tables 1.1-1.6 – Analysis of the steady-state stability – MT Tables 2.1-2.6 – Analysis of the steady-state stability – LT Annexes E PTG maintenance strategy Annex E-1 Schedule of OHL maintenance and maintenance expenditures (not published) Annex E-2 Schedule of substation maintenance and maintenance expenditures (not published) Annexes F Fixed asset development strategy Annex F-1 Unit costs used at evaluating the cost of PTG development projects (not published) Annex F-2 Schedule of investment expenditures (not published) Annex F-3 Monitoring projects from the PTG development plan – 2016 and 2018 editions Annex F-4 Presenting the benefits pursued by the investment projects Annex G PTG elements loading – 2018, 2022, 2027 Annex H CNTEE TRANSELECTRICA SA's strategy in terms of research and Annex H-1 innovation Annex H-2 Options in terms of research within CNTEE Transelectrica SA General objectives pertaining to TEL key interest fields for structuring presentation Annex H-3 sessions of concepts, solutions, technologies and equipment Annex H-4 Structure of specific groups and objectives related to the research and innovation Annex H-5 strategy SMART GRID reference architecture specific to CNTEE Transelectrica SA List of main systems that are part of the "Smart Grid" standard and the correspondence number from the "Smart Grid" architectures

Abbreviations

AGC Automatic Generation Control FA Functional Assembly ANRE National Energy Regulatory Authority AT Autotransformer TCA Technical Connection Approval ARB Asset Regulatory Base BC Bucking Coil CCCPP Combined-Cycle Cogeneration Power Plant WPP Wind Power Plant PVPP Photovoltaic Power Plant CHPP Central Heating and Power Plant HPP Hydroelectric Power Plant SPHPP Storage Pump-Hydroelectric Power Plant NPP Nuclear Power Plant OTC Own Technical Consumption (Joule and Corona losses, internal service consumptions) SPP Steam Power Plant GC Green Certificates NPD National Power Dispatcher TPD Territorial Power Dispatcher BDBF Backup Device for Breaker Failures EMS/SCADA Energy Management System/Supervisory Control and Data Acquisition System ENTSO-E European Network of Transmission System Operators for Electricity SNL Summer Night Low OHL Over-Head Power Line LW Live Work SSL Steady-State Stability Limits MV Medium Voltage OMEPA Operator for electricity metering that is circulated on the wholesale market OPCOM S.C. OPCOM S.A. – Operator of the power market in Romania TSO Transmission System Operator GEO Government Energy Ordinance MP Maintenance Plan AOP Annual Outage Plan PCI Project of Common Interest DBP Differential Busbar Protection Ci Installed Capacity PMU Phase Measurement Unit NREAP National Renewable Energy Action Plan SOP-IEC Sectoral Operational Program – Increase of Economic Competitiveness BRP Balance Responsible Parties PSS Power System Stabilizer AR Automatic Reset RDR Reference Design Regime

PDG Power Distribution Grid RES Renewable Energy Sources PTG Power Transmission Grid RK Capital Repair BAR Basic Average Regime RTU Remote Terminal Unit CCS Command and Control System SECI Southeast European Cooperative Initiative Sn Apparent Rated Power T Transformer CT Current Transformer MT Mid-term (5-10 years) LT Long term (over 10 years) Transelectrica C.N.T.E.E. "Transelectrica" S.A. DF Dispatchable Facilities SMP Summer Morning Peak WEP Winter Evening Peak

1. Purpose and objectives of the Ten-year PTG development plan In accordance with the competencies and attributions established in the Electricity and Natural Gas Act no. 123/2012, as subsequently amended and supplemented, and with the Specific conditions associated to License no. 161 for the provision of the electricity transmission service, the system service and for managing the balancing market, the National Power Grid Company "Transelectrica" – S.A. plans the development of the PTG, taking into account the current stage and the forecasted development of demand, the generation units pool and the electricity exchanges, and drafts a biennial Development plan for the next 10 successive years and submits it for approval to ANRE and the grid owner. The Development plan was based on the Strategies and Policies of the Romanian Government, the objectives of the new policy of the European Union for Competitive and Secure Energy and on studies issued by CNTEE Transelectrica SA. The planning of the PTG development pursues the following objectives: a. Operational safety of the NPS and electricity transmission at quality levels suited for the conditions set forth in the Technical PTG Code and the Performance standard for the electricity transmission service and system services; b. PTG development so that the grid is well-designed for the transmission of electricity forecasted to be generated, consumed, imported, exported and shipped; c. Increasing the interconnection capacity of power grids; d. Sustainability by integrating energy from renewable sources in the grid and by transmitting the energy generated from renewable energy sources to the main demand centers; e. Integrating and operating the internal energy market; f. Ensuring applicants non-discriminatory access to the public power grid, as per the conditions set forth by the applicable legislation; g. Minimizing investment expenditures when selecting PTG development solutions. Main objectives of the PTG Development plan The PTG development plan is a public document which presents the main aspects pertaining to the current situation and the forecasted development of the PTG within the NPS for the following ten years. This document is made available by CNTEE Transelectrica SA for all stakeholders in order to facilitate: – access to information pertaining to the current and future capability of the transmission grid to satisfy user requirements and public interest, taking into consideration the objectives of the national energy strategy and policy and the applicable legislation; – creation of conditions to correlate actions/investments between the TSO and market participants, in the mid and long term, which may impact the NPS safety performances; – access to information pertaining to the zonal opportunities for PTG connection and PTG usage, based on the consumption evolution forecasts and generation capacities; – access to information pertaining to the evolution of energy exchange capacities with neighboring systems in the context of the European internal electricity market; – the reserve level in the NPS necessary to ensure that the electricity generation and transmission on peak load meet the demand; – necessary resources for the PTG development and their sources.

2. European integration of the power transmission grid planning

2.1. Correlating the European Ten-Year Network Development Plan (TYNDP) with the National ten-year power transmission grid development plan As a cooperation group between European TSOs, ENTSO-E aims to promote the completion and operation of the internal electricity market and the cross-border trade, as well as to ensure an optimal management, a coordinated operation and a healthy technical evolution of the European power transmission grid. In accordance with Article 8 of Regulation (EC) No 714/2009, the "Ten-Year Network Development Plan" – TYNDP is drafted and adopted at ENTSO-E level. This plan is drafted and published once every two years and it is a non-mandatory ten-year network development plan at community level, which includes a two-yearly evaluation of the adequacy of the pan- European power system. The European TYNDP plan must consider the integrated model of the European network, it must develop scenarios and evaluate the system resilience. The evaluation regarding the generation sources covers the general capacity of the power system to meet the existing electricity demand and the demand forecasted for the following five years, as well as over a period between five and 15 years from the date of conducting said evaluation. The European evaluation is based on the national evaluations issued by each Transmission System Operator individually. Six regional groups have been created within ENTSO-E (Figure 2.1) which aim to analyze and complete the European network development plan.

Figure 2.1 – ENTSO-E regions (source: ENTSO-E) CNTEE Transelectrica SA is part of the following Regional groups: Continental Central East and Continental South East. The scenarios analyzed within TYNDP 2016 [16] were based on the national policies and on fulfilling the energy targets of the European Union for 2020/2030/2050:

 for the 2020 timescale:  "Best Estimate Scenario of Expected Progress" – based on the data provided by TSOs.  for the 2030 timescale:  Vision 1 "Slowest Progress" and Vision 3 "National Green Transition" are based on the data provided by TSOs.  Vision 2 "Constrained Progress" and Vision 4 "European Green Revolution" are based on the hypothesis of fulfilling the energy policies of the European Union. The scenarios analyzed within TYNDP 2018 [30] were based on the national policies and on fulfilling the energy targets of the European Union for 2020/2030/2050:  for the 2020 and 2025 timescale:  "Best Estimate Scenario" – based on the data provided by TSOs.  for the 2030 timescale:  "Sustainable Transition (ST)" – based on the data provided by TSOs.  "Distributed Generation (GT)" – based on the hypothesis of fulfilling the energy policies of the European Union.  "EUCO 30 – External Scenario" – based on a European Commission scenario which pursues the fulfillment of older 2030 targets set forth by the European Council in 2014, but also includes the efficiency target of 30%.  for the 2040 timescale (for the transition towards 2050):  "Sustainable Transition (ST)" – based on the "Sustainable Transition (ST)" 2030 scenario.  "Distributed Generation (GT)" – based on the "Distributed Generation (GT)" 2030 scenario.  "Global Climate Action (GCA)" – based on the "Sustainable Transition (ST)" 2030 scenario. The 2040 scenarios have been used for identifying new development projects for the European transmission network and the 2025 and 2030 scenarios have been used for estimating the benefits of the projects included in TYNDP 2018. In the context of integrating European markets, the benefits of the projects of European interest have been assessed within ENTSO-E based on electricity market research studies, using input provided by all members (forecasted hourly load, evolution of the power plants park, standard generation costs per plant type, forecasted meteorological data, etc.), as well as based on analyses on power circulations estimating the increase in the interconnection capacity which might be achieved by carrying out these projects. A simulation was developed for each Vision, which allowed identifying directions on which the largest differences occur between electricity marginal costs, thus developing estimations regarding the predominant directions of future flows between states. Where the existing grid capacity is insufficient, the grid development is recommended. The "ENTSO-E Guideline for Cost Benefit Analysis of Grid Development Projects" methodology [22] sets forth the selection criteria for the Projects of Common Interest (PCI) at

European level and the evaluation criteria of projects/investments costs and benefits in order to draft the Regional Investment Plans and the ten-year development plan of ENTSO-E; these criteria are based on the strategic energy objectives of the European Union: ensuring competitiveness of EU economy, ensuring a sustainable development of the energy sector, increasing the security of supply: ► Benefits: GTC – Increasing the cross-border capacity (MW) B1. Security of supply with electricity (MWh) B2. Social and economic welfare (€) B3. RES integration (MWh) B4. Minimizing electricity losses (€) B5. Reducing CO2 emissions (kt) B6. System resilience/security (++/--) B7. Flexibility (++/--) ► Costs: C1. Total cost of the project (€) S.1. Environmental impact (km) S.2. Social impact (km) According to the ENTSO-E procedures and criteria, the Ten-Year Network Development Plan (TYNDP) 2016 issued by ENTSO-E as per Commission Regulation no. 714/2009, included as Projects of Common Interest the following investment clusters, which can also be found in the current edition of the Development plan – 2018-2027: Project 138 "Black Sea Corridor" . Smardan-Gutinas 400 kV d.c. OHL; . Cernavoda-Stalpu 400 kV d.c. OHL, with an input/output circuit in Gura Ialomitei; Project 144 "Mid Continental East Corridor" . Resita (RO)-Pancevo (Serbia) 400 kV d.c. OHL; . Portile de Fier-Resita 400 kV OHL and extending the Resita 220/110 kV substation by building a new 400 kV substation; . Converting the Resita-Timisoara-Sacalaz-Arad 220 kV OHL d.c. to 400 kV, including the construction of the Timisoara and Sacalaz 400 kV substations. The above-mentioned projects are integrated in the harmonized effort of all European Transmission System Operators (TSOs) to develop cross-European networks and to ensure their interoperability. The internal scenarios analyzed within the National PTG development plan have been correlated with the scenarios developed at European and regional level within ENTSO-E in the context of drafting the European 10-year network development plan. The ENTSO-E plan includes projects of European interest, of which some have the status of PCI, with a higher impact on the system; the regional plans also include projects only of regional interest, and the national plans also include projects with a smaller impact on other systems, but necessary at national level. The three planning levels are coordinated via the modus operandi, thus the resulting plans are coherent.

2.2. Priorities in the energy infrastructure sector ante and post 2020 – Projects of Common Interest (PCI) Regulation (EU) No. 347/2013 of the European Parliament and of the Council on the cross- European energy infrastructure proposes a set of measures for fulfilling the respective EU objectives, such as: integration and operation of the internal energy market, ensuring energy security in the EU, promoting and developing energy efficiency and renewable energy sources and promoting the interconnection of power grids. Regulation (EU) no. 347/2013 identified, for 2020 and after this period, a number of 12 priority cross-European corridors and sectors which cover the electricity and gas networks, as well as the transmission infrastructure for oil and carbon dioxide. Romania is part of the priority corridor no. 3 related to electricity – "North-South electricity interconnections in Central Eastern and South Eastern Europe" ("NSI East Electricity"): interconnections and internal lines in the North-South and East-West directions for completing the internal market and integrating the generation from renewable energy sources. Involved Member States: Bulgaria, Czech Republic, Germany, Greece, Croatia, Italy, Cyprus, Hungary, Austria, Poland, Romania, Slovenia, Slovakia. Regulation (EU) no. 347/2013 defines the selection and evaluation criteria of PCI eligibility to be included by the European Commission on the next lists of the Union; the draft projects on electricity transmission and storage must be part of the most recent ten-year power grid development plan drafted by ENTSO-E. Via the "Communication on achieving a 10% electricity interconnection target; Making Europe's electricity grid fit for 2020", the European Commission presented the interconnection level for 2014 and 2020 after implementing the current PCIs. Currently, the 7% value of the interconnection capacity presented in Romania's Country report, European semester 2017, has been computed by the interconnection target group established by the European Commission, using the data provided by CNTEE Transelectrica SA for the half-yearly adequacy report Winter outlook 2016-2017. The 7% value resulted by dividing the import NTC value (1.4 GW) to the net generation capacity value (20.23 GW), values considered for 11.01.2017 at 19:00 CET. By constructing the interconnection with Serbia in 2018, Romania's interconnection level would increase from the current 7% level to over 9%, thus getting closer to the 10% target. In terms of fulfilling the interconnections target of 15% for 2030, this objective is intended to be fulfilled mainly by implementing PCIs and carrying out other PTG development projects included in the PTG development plan for 2018-2027. Considering the contribution to the implementation of the European Union's strategic priorities on the cross-European energy infrastructure, Project 138 "Black Sea Corridor" and Project 144 "Mid Continental East Corridor" have been included by the European Commission on the third European list of Projects of Common Interest (PCIs), in the priority corridor no. 3 related to electricity – "North-South electricity interconnections in Central Eastern and South Eastern Europe" ("NSI East Electricity"): interconnections and internal lines in the North-South and East-West directions for completing the internal market and integrating the generation from renewable energy sources.

2.3. Overview of the benefits brought by the PTG development projects included in TYNDP 2016 Project 138 "Black Sea Corridor"

The "Black Sea Corridor" project is part of the priority corridor related to electricity: "North- South electricity interconnections in Central Eastern and South Eastern Europe (NSI East Electricity)" and aims to enhance the electricity transmission corridor along the Black Sea coast (Romania-Bulgaria) and between the coast and the rest of Europe. This project has a significant contribution by increasing the interconnection capacity between Romania and Bulgaria and by strengthening the infrastructure which will support the power flow transmission between the Black Sea coast and the North Sea/Atlantic Ocean coast within the implementation of the European Union's strategic priorities on the cross-European energy infrastructure – a mandatory condition for fulfilling the objectives of the energy and climate policy. The implementation of this project will also enhance the integration of the regional and European energy market, which will further allow for increased exchanges in the area. The development of intermittent renewable energy sources will be made possible by the grid's capacity to transmit the energy generated from renewable energy sources from Southeastern Europe towards the main demand centers and storage sites located in Central and Northern Europe respectively. The results of the cost-benefit analysis carried out for Project 138, as per the ENTSO-E CBA methodology [23] within TYNDP 2016, are presented in Table 2.3.1*): Table 2.3.1*) (source TYNDP 2016) Investment Substation Substation no. (TYNDP Project description 1 2 2014) New 400 kV d.c. OHL between the existing Cernavoda and Stalpu 273 Cernavoda Stalpu substations with an input/output circuit in the Gura Ialomitei 400 kV substation; length: 159 km. New 400 kV d.c. OHL (with one circuit equipped) between the 275 Smardan Gutinas existing Smardan and Gutinas substations; length: 140 km. Extending the Stalpu 220/110 kV substation by building the 400/110 715 Stalpu - kV, 1x250MVA substation.

∆GTC ∆GTC Direction Direction S1 S2 Scenario RO→BG BG→RO Environmental impact (km) Social impact (km) (MW) (MW) 2020 1,200 1,000 Negligible or less than 15 Negligible or less than 15 km 2030 1,350 800 km

B1 B4 B5 B2 B3 B4 SoS Losses CO Scenario SEW RES Losses 2 (MWh/yea (M€/year) emissions (M€/year) (GWh/year) (GWh/year) r) (kT/year) 2020 - 60±10 <10 50±25 2±1 700±100 Vision 1 – 2030 - 80±10 <10 25±25 1±2 1,100±200 Vision 2 – 2030 - 50±10 <10 125±25 6±1 700±100 Vision 3 – 2030 - 40±10 30±10 -125±25 -8±2 -900±100 Vision 4 – 2030 - 270±40 140±30 -150±25 -10±2 -900±100

*) The information presented in the table have been approved by the European Commission and ACER Project 144 "Mid Continental East Corridor" The "Mid Continental East Corridor" project is part of the priority related to electricity – North- South electricity interconnections in Central Eastern and South Eastern Europe ("NSI East Electricity") and leads to the increase in exchange capacity on the borders between Romania, Hungary and Serbia; it intensifies the North-South European corridor from the northeastern part of Europe towards the southeastern part of Europe, through Romania, thus allowing a stronger integration of markets and an increased security of supply in the southeastern part of Europe. The results of the cost-benefit analysis carried out for Project 144, as per the ENTSO-E CBA methodology [23] within TYNDP 2016, are presented in Table 2.3.2*): Table 2.3.2*) (source TYNDP 2016) Investment Substation no. (TYNDP Substation 1 Project description 2 2014) New 400 kV d.c. OHL between the existing Resita (Romania) and Pancevo Resita 238 Pancevo (Serbia) substations; length: 131 km (63 km in RO and 68 (RS) (RO) km in RS). Portile de New 400 kV s.c. OHL between the existing Portile de Fier 400 kV 269 Resita Fier substation and the new Resita 400 kV substation; length: 116 km. Timisoara- Converting the Resita-Timisoara-Sacalaz-Arad 220 kV d.c. OHL to 270 Resita Sacalaz- 400 kV Arad Extending the Resita 220/110 kV substation by building the new 701 Resita - Resita 400/220/110 kV, 1x250MVA+1x400 MVA substation. Replacing the Timisoara 220/110 kV substation by building the new 704 Timisoara - 400/220/110 kV, 2x250MVA+1x400MVA substation.

∆GTC ∆GTC S1 S2 Scenario Direction Direction Environmental impact Social impact (km) RO→RS, HU (MW) RS, HU→RO (MW) (km) 2020 950 500 Negligible or less than 15 15-50 2030 950 750 km

B1 B4 B5 B2 B3 B4 SoS Losses CO Scenario SEW RES Losses 2 (MWh/yea (M€/year) emissions (M€/year) (GWh/year) (GWh/year) r) (kT/year) 2020 - 50±10 <10 25±25 1±1 900±50 Vision 1 – 2030 - 90±10 <10 325±32 17±2 1,700±300 Vision 2 – 2030 - 60±10 <10 125±25 6±1 1,100±200 Vision 3 – 2030 - <10 30±10 75±25 4±2 ±100 Vision 4 – 2030 - 60±40 120±20 75±25 5±2 -400±100 *) The information presented in the table have been approved by the European Commission and ACER The information and data presented above for Projects 138 and 144 is part of the latest edition of the ten-year network development plan TYNDP 2016 – approved edition, drafted by ENTSO-E pursuant to Article 8 of Regulation (EC) No 714/2009. As of the update of the PTG development plan – 2018-2027 drafted by CNTEE Transelectrica SA, the future edition of the ENTSO-E TYNDP 2018 is undergoing public consultation.

3. Legislative and regulatory framework

3.1. Primary legislation The main regulatory acts which regulate the Romanian energy sector and have a major impact on the PTG development are the following:  Electricity and Natural Gas Act no. 123/2012, as subsequently amended and supplemented;  Law no. 220/2008 on the promotion system for energy generated from renewable sources, as subsequently amended and supplemented by GEO no. 24/2017;  Law no. 199/2000 on the efficient use of energy, republished, as subsequently amended and supplemented;  Law no. 255/2010 on the expropriation on grounds of public interest necessary for the completion of objectives of national, regional and local interest;  Law no. 220/2013 amending and supplementing Law no. 255/2010 on the expropriation on grounds of public interest necessary for the completion of objectives of national, regional and local interest;  Government Decision no. 557/2016 on the management of risk types; With respect to the development of the transmission grid, the Electricity and Natural Gas Act no. 123/2012 stipulates the following:

"Article 35 Development plans (1) The Transmission System Operator has to elaborate ten-year network investment and development plans in line with the current status and future evolution of the electricity demand and energy sources, including energy import and export. (2) The development plans mentioned in paragraph (1) include methods for financing and carrying out investments pertaining to power grids, also considering the plans for development and systemizing the territory crossed by the grids, whilst complying with environmental protection norms. (3) The plans mentioned in paragraph (1) are subject to ANRE approval......

Article 36 Obligations of the transmission system operator ... (7) The transmission system operator carries out the following main activities: a) ensures the long-term capability of the transmission grid to meet the reasonable electricity transmission demand and operates, maintains, rehabilitates and develops the transmission grid under economic conditions in order to ensure its safety, reliability and efficiency, whilst complying with the environmental protection norms; b) guarantees the adequate means to fulfill the public service obligations; c) contributes to the fulfillment of safety of supply by ensuring adequate transmission capacities and maintaining their reliability; ......

(11) Expenses related to modifying electricity transmission facilities, as a result of the connection of new users or changes in the initial power features of existing users, including expenses related to releasing sites, are covered according to the applicable legislation......

Article 37 Attributions of the transmission grid owner in case of transmission system operators which manage a power transmission grid

(1) If a transmission system operator manages a power transmission grid, the transmission grid owner: a) cooperates with the transmission system operator in order to fulfill its attributions, providing all relevant information both to the operator and to ANRE, which monitors the information exchange between the transmission system operator and the owner; b) finances and/or gives their permission regarding the financing method of investments in the power transmission grid, set forth by the transmission system operator and approved in advance by ANRE, which must carry out consultations with both the owner and with other stakeholders; c) is liable for the transmission grid assets, exception being made for the liability pertaining to the transmission system operator's attributions; d) issues warranties for facilitating the financing of potential grid expansions, exception being made for investments for which they agreed to be financed by any other stakeholder, including by the transmission system operator, as per the provisions set forth in letter b)."

The legal framework regulating the Romanian energy sector has underwent significant changes according to the progress of the sector reform process. As of January 1st, 2007, Romania was accepted as Member State of the European Union and the EU legislation and regulations in the field are assimilated into Romanian legislation. The main European regulations impacting the TSO's PTG planning activities are:  Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC;  Regulation (EC) no. 714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border exchanges in electricity and repealing Regulation (EC) no. 1228/2003;  Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006 concerning measures to safeguard security of electricity supply and infrastructure investment;  Council Regulation (EU, EURATOM) No. 617/2010 of 24 June 2010 concerning the notification to the Commission of investment projects in energy infrastructure within the European Union and repealing Regulation (EC) No. 736/96;  Council Regulation (EU, Euratom) No. 833/2010 of 21 September 2010 implementing Council Regulation (EU, Euratom) No. 617/2010 concerning the notification to the Commission of investment projects in energy infrastructure within the European Union;  Regulation (EU) No. 347/2013 of the European Parliament and of the Council of 17 April 2013 on guidelines for trans-European energy infrastructure and repealing Decision No. 1364/2006/EC and amending Regulations (EC) No. 713/2009, (EC) No. 714/2009 and (EC) No. 715/2009;

The Third Internal Energy Market Package (including Directive 2009/72/EC, Regulation (EC) No. 713/2009 and Regulation (EC) No. 714/2009), entered into force in March 2011, stipulates the European energy cooperation requirements aiming to develop the infrastructure and cross-border exchanges. Articles 4 and 5 of Regulation (EC) No. 714/2009 set forth the constitution of ENTSO-E as a cooperation group between European TSOs, with the aim to promote the completion and operation of the internal electricity market and the cross-border trade, as well as to ensure an optimal management, a coordinated operation and a healthy technical evolution of the European power transmission grid. Article 8 (3) b) foresees that ENTSO-E adopts a non-mandatory ten-year network development plan at community level (the grid development plan at community level), including a two-yearly European evaluation of the adequacy of generation capacities. The grid development plan at community level, as per the provisions of Article 8 (10) of the Regulation, includes the simulation of the integrated market, the development scenario, a European evaluation regarding the adequacy of generation capacities, as well as the system flexibility assessment, based on national investment plans, considering the regional investment plans. The European plan must consider the integrated model of the European network, it must develop scenarios and evaluate the system resilience. A current priority of the European Union is the reduction of carbon emissions and encouragement of renewable energy consumption. The legislative package on climate changes and renewable energies published on 23.01.2008 provides that 20% of the community consumption to be covered from renewable energy sources by 2020. In Romania, Law no. 220/2008 on the promotion system for energy generated from renewable sources, republished, as subsequently amended and supplemented, sets forth, among other measures for promoting energy generated from renewable sources, the priority of these generators in terms of the access to public electrical grids and transmission grids: "Article 9 (1) The transmission system operator and distribution operators must guarantee the transmission and distribution of the electricity generated from renewable energy sources, ensuring the reliability and security of power grids.

(2) Generators of electricity from renewable energy sources are connected to the power grid according to the Regulation on the connection of users to the public electricity grids, issued pursuant to Article 11 (2) g) of Law no. 13/2007 on electricity, as subsequently amended and supplemented.

(3) Investments carried out by transmission and/or distribution operators based on the provisions of paragraph (2) are deemed regulated assets, recognized in this regard by ANRE...... "

Law no. 220/2008 has been amended and supplemented by the provisions of GEO no. 24/2017 modifying the rules of operation for the green certificates support scheme. The most significant changes are the following: - Changing the calculation formula for the mandatory annual quota for the acquisition of green certificates: - The annual static quantity of green certificates is calculated in order to ensure the demand for all green certificates issued to generators of electricity from renewable

energy sources. The static quantity is a fixed number which shall be revised once every two years, starting with 2018. The mandatory annual quota for the acquisition of green certificates is established by ANRE, considering the static quantity of green certificates and the final electricity demand estimated for the following year, without exceeding the average impact on the invoice to the electricity end consumers amounting to 11.1 euro/MWh. ANRE Order no. 27/2017 establishing the estimated mandatory annual quota for the acquisition of green certificates for the period between 01.04.2017 and 31.12.2017 set the quota at 0.358 green certificates/MWh. - Extending the period of validity of green certificates from 12 months to 31.03.2032; - Green certificates trading: - Starting with 01.09.2017, green certificates may be traded either on centralized anonymous markets for green certificates (spot or long term), or on the centralized energy market supported by the State aid scheme, the market on which electricity is sold in association with green certificates related to the electricity quantity traded. - From the entry into force of GEO no. 24/2017 and until 31.03.2032, the trading value of green certificates changes and shall range between: . A minimum trading value of 29.4 euro/certificate, and . A maximum trading value of 35 euro/certificate. According to Law no. 123/2012 (Articles 3-66), the power transmission grid is deemed to be of national interest and strategic significance and as such, a great part of its assets is publicly owned by the state. The legal framework regulating the status of the public patrimony and concession conditions thereof is embodied by Law no. 213/1998 on public property and its regime, as subsequently amended, and GEO no. 54/2006 on the regime of concession agreements for assets publicly owned by the state. The European Union established a unitary approach on the energy infrastructure protection ("Critical infrastructure protection in the fight against terrorism" adopted by the EC in 2004). The Green Paper on the European Program for Critical Infrastructure Protection (EPCIP – COM (2005) 576 final) has been drafted at EU level; this document identifies the transmission grid as a critical infrastructure. Given the significance of the energy security for the overall national security, CNTEE Transelectrica SA fully concentrates on implementing legislation related to the integrated security systems for the protection of classified information and the critical infrastructure: 1. Law no. 333 of 08.07.2003 on the guarding of objectives, goods, values and protection of persons; 2. Government Decision no. 301 of 11.04.2012 (approving the methodological instructions for enforcing Law no. 333/2003 on the guarding of objectives, goods, values and protection of persons); 3. Government Decision no. 781 of 25.07.2002 on the protection of official confidential information; 4. Law no. 182 of 12.04.2002 on the protection of classified information; 5. Government Decision no. 585 of 13.06.2002, approving the National standards for the protection of classified information in Romania; 6. Government Decision no. 718 of 13.07.2011, approving the National strategy on the protection of critical infrastructures;

3.2. Secondary legislation The secondary legislation in the field includes regulatory instruments mandatory for the participants in the energy sector, so it would operate coordinately and synchronized. The following regulations represent secondary legislation with an impact on the PTG development and exploitation: – PTG Technical Code – Revision I, approved by ANRE Order no. 20/2004, amended and supplemented by ANRE Order no. 35/2004; – Technical distribution grid code, approved by ANRE Order no. 128/2008; – Commercial code of the wholesale electricity market, approved by ANRE Order no. 25/2004; – Code for Electricity Metering, approved by ANRE Order no. 103/01.07.2015; – Commission Regulation No. 1222/2015 of 24 July 2015 establishing a guideline on capacity allocation and congestion management and Commission Regulation (EU) No. 2016/1719 of 26 September 2016 establishing a guideline on forward capacity allocation (CACM); – Commission Regulation (EU) No. 2016/1719 of 26 September 2016 establishing a guideline on forward capacity allocation (FCA); – Commission Regulation (EU) No. 631/2016 of 14 April 2016 establishing a network code on requirements for grid connection of generators (RfG); – Commission Regulation (EU) No. 2016/1388 of 17 August 2016 establishing a Network Code on Demand Connection (DCC); – Commission Regulation (EU) No. 2016/1447 of 26 August 2016 establishing a network code on requirements for grid connection of high voltage direct current systems and direct current- connected power park modules (HVDC); – Commission Regulation (EU) No. 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (OS); – Commission Regulation (EU) No. 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing; – Commission Regulation (EU) No. 2017/2196 of 24 November 2017 establishing a network code on electricity emergency and restoration; – Licenses and permits: CNTEE Transelectrica SA operates based on the specific conditions provided in License no. 161/2000 for the provision of the electricity transmission and system services and for the management of the balancing market, amended by ANRE Decision no. 802 of 18.05.2016; – Regulation for users' connection to public electricity grids, approved by ANRE Order no. 59/2013; – ANRE Order no. 63/2014 amending and supplementing the Regulation for users' connection to public electricity grids, approved by ANRE Order no. 59/2013; – Methodology establishing the fees for the users' connection to public electricity grids, approved by ANRE Order no. 11/2014; – ANRE Order no. 87/2014 amending and supplementing the Methodology establishing the fees for the users' connection to public electricity grids, approved by ANRE Order no. 11/2014;

– Maintenance management and organization regulation – approved by ANRE Order no. 96/18.10.2017; – Performance standard for the electricity transmission service and system services, approved by ANRE Order no. 12/30.03.2016; – Performance standard for the power distribution service, approved by ANRE Order no. 11/2016; – ANRE Order no. 49/22.06.2017 amending and supplementing the Performance standard for electricity distribution services, approved by Order no. 11/2016 of the ANRE President; – Orders and decisions for the regulation of tariffs for monopoly activities (transmission and distribution) as well as for the electricity generated on the regulated market; – Methodology establishing the tariffs for the electricity transmission service, approved by Order no. 53/2013 of the ANRE President; – ANRE Order no. 16/2017 amending and supplementing the Methodology establishing the tariffs for the electricity transmission service, approved by Order no. 53/2013 of the ANRE President; – Order no. 45/2017 approving the Methodology establishing the tariffs for the system service; – Regulation on solutions to connect users to public electricity grids, approved by Order no. 102/01.07.2015 of the ANRE President; – Operational procedure "Mechanism of counterbalancing the effects of using power transmission grids for electricity transits between transmission system operators", approved by Order no. 6/11.02.2010 of the ANRE President; – Order no. 29/2013 of the ANRE President amending and supplementing the Technical norm "Technical requirements to connect wind power plants to the public electrical grids" approved by Order no. 51/03.04.2010 of the ANRE President; – Order no. 30/2013 of the ANRE President amending and supplementing the Technical norm "Technical requirements to connect photovoltaic power plants to the public electrical grids"; – Order no. 32/2013 of the ANRE President approving the Regulation on programming dispatchable generation units and consumers; – Order no. 60/2013 of the ANRE President approving the introduction of rules on the balancing market; – PE 134/1995 "Standard on the methodology to calculate short-circuit currents in over 1 kV voltage power grids"; – PE 026-92 "Standard for designing the national power system"; – ANRE Decision no. 1424/21.10.2006 approving the "Standard on the methodology and elements for the computation of power facilities' operational security", code: NTE 005/06/00; – Order no. 660/2004 of the Minister of Economy and Commerce approving the Guide for the identification of critical infrastructure elements in the economy; – Decision no. 1349 of 27.10.2010 on the collection, transmission, distribution and protection of classified information; – Order no. 1226/2010 of the Ministry of Economy, Commerce and Business Environment, updated by Order no. 175/12.02.2015 of the Minister of Economy, Commerce and Tourism approving the "Instructions regarding the access of Romanian and/or foreign citizens to the objectives, sectors and locations with high significance for the protection of secret

information belonging to the State/special sectors of economic operators subordinated/under the authority or coordination of the Ministry of Economy, Commerce and Tourism." – List with information categories classified as STATE SECRET, broken down into levels of security, drafted or held by CNTEE Transelectrica SA, its SUBSIDIARIES and BRANCHES, as well as the timeframe for keeping this information within their respective levels of security. – List with information categories classified as OFFICIAL SECRET, drafted or held by CNTEE Transelectrica SA, its SUBSIDIARIES and BRANCHES. – Guide for the classification of information within CNTEE Transelectrica SA, P.I.C2. – Internal norms on the protection of classified information within CNTEE Transelectrica SA, P.I.C.1, registered under no. 21611/15.06.2017.

4. Principles and methodologies used in drafting the PTG development plan

4.1. Principles applied in drafting the PTG development plan The development of the PTG aims at maintaining the quality of the transmission and system services, as well as the operational safety of the national power system, under economic efficiency conditions in accordance with the applicable regulations and the standards jointly undertaken at European level by the TSOs associated within ENTSO-E. CNTEE Transelectrica SA develops and upgrades the power transmission grid under economic conditions in order to ensure its adequacy to the necessities occurred as a result of the evolution of the NPS: – the evolution of demand; – creation of new generation groups; – evolution of the demand for cross-border electricity exchanges; – degree of wear and tear and obsolescence of the transmission equipment; – decommissioning of certain generation capacities; – changes in dominant power flows in the grid. If a necessity to develop the PTG is identified, the solutions are selected on the grounds of a cost- benefit analysis based on the assessment of certain specific technical and economic indicators. Technically speaking, considering the uncertainties regarding the evolution of the system and the economic framework, robust and flexible solutions are sought which would accommodate several possible scenarios, thus diminishing the risks. Each project considers reducing the environmental impact based on the most recent technological performances accessible and the applicable legislation. Several strategic directions are also sought, which aim at increasing the effectiveness and efficiency of the service provided:  carrying out maintenance based on PTG reliability;  implementing new, efficient technologies;  promoting remote management of Transelectrica substation facilities;  ensuring an adequate infrastructure according to the development level of the electricity market;  promoting solutions that lead to a reduction in PTG losses;  reduction of PTG congestions. The PTG development also considers the requirements and priorities set out by the National Energy Strategy and Policy [2], [4]. These represent determining references for identifying priority directions and for forecasting the evolution trends in the energy sector which are considered during planning.

4.2. Methodologies/analyses used in drafting the PTG development plan

The drafting of the PTG development plan implies undergoing the following analysis stages:  Forecast of electricity demand in the NPS as a whole for the analyzed period;

 Forecast of electricity demand and (active and reactive) power levels on specific sections of the load curve (load peak and off-load in winter and summer seasons), territorially and for each substation;  Forecasts of electric energy and power import/export/transit;  Estimation of the availability of generation capacities, considering the programs for dismantling, rehabilitation and installation of new groups;  Drafting balances of active and reactive powers on PTG nodes and NPS power areas in the specific sections of the load curve;  Analysis of PTG operation regimes in the reference period: o power flows in specific sections of the load curve, in average and extreme regimes; o PTG power losses; o ensuring the voltage stability and compliance with the minimum and maximum admissible limits in PTG nodes via existing control solutions and means and their development; o short-circuit current and power limits and values in PTG nodes; o analysis and securing the steady-state stability reserves and the transient stability in the NPS operation;  Evaluating the technical condition of facilities in the power transmission grid;  Evaluating the significance of transmission substations;  Computing the reliability indicators for PTG nodes;  Establishing the actions and reinforcements (new projects) necessary to ensure the grid's adequacy and meeting the standard performances of the transmission service;  Establishing optimal technical and economic solutions to upgrade and develop the PTG as well as measures to reduce the environmental impact;  Establishing priorities and programs to carry out PTG and related infrastructure modernization/development works;  Identifying potential sources of financing for the investments included in the PTG development plan. The methodology for building cases and analyzing operational regimes for the PTG reference design is presented in Annex A.

5. Analysis of the current situation of PTG and associated infrastructure for the period of 2016-2017 5.1. Power generation capacities Grouped by the primary power source, the following generating units operate in the NPS: hydroelectric, traditional coal- or gas-based thermoelectric (with and without combined heat and power generation), nuclear, wind, photovoltaic and biomass-based thermoelectric power plants. Hence: - the largest generating units in the system are the 707 MW Cernavoda nuclear units (the second unit was commissioned in August 2007); - the installed capacity of the hydroelectric units varies from values smaller than 1 MW up to 194.4 MW (the installed power after rehabilitating the Portile de Fier I HPP); - the traditional thermo-electric power generating units with a wide variation range of the installed unit power: from a few MWs for some units of the autogenerators, to 330 MWs in installed capacity of the lignite-fired power units in the Rovinari and Turceni power plants; - wind power plants with unit capacities smaller than 1-3 MW have been installed, however by aggregating a large number of such groups we obtain wind power plants (WPPs) that can reach hundreds of MWs. A wind power plant with an installed capacity of 600 MW is connected to the Tariverde 400kV substation; at the moment of completion, this was considered the largest terrestrial wind power plant in Europe. - The total installed capacity of WPPs at the end of 2017 was 3,030 MW, while the installed power of PVPPs reached the value of 1,375 MW at the end of 2017; - also, at the end of the year 2017, the installed capacity of biomass power plants amounted 130 MW; - The total high-efficiency electrical capacity, having the final accreditation at the date of 29.05.2017 amounted to 1,528 MW, out of which 1,501 MW was eligible for the cogeneration support scheme. Table 5.1.1 presents information regarding the electricity production structure, broken down into fuel type and installed capacities of power plants. As of 01.01.2018, the installed capacity in the NPS amounted to 24,738 MW, with 24 MW larger than the one installed as of 01.01.2017, a very small increase mainly determined by the evolution of renewable source installed capacities (wind power plants – increased by 5 MW, photovoltaic power plants – increased by 4 MW). Table 5.1.1 Installed capacity* Plant type [MW] 01.01.2016 01.01.2017 01.01.2018 TOTAL 24,541 24,714 24,738 Coal 6,435 6,240 6,240 Hydrocarbons 5,562 5,792 5,789 Nuclear 1,413 1,413 1,413 Hydro 6,731 6,744 6,761 Wind 2,978 3,025 3,030 Photovoltaic 1,301 1,371 1,375 Biomass 121 129 130

* The decommissioned units that have been in a rehabilitation state for a period longer than a year as well as the ones that have been in a preservation state are not included. The units that are conducting technological trials required for commissioning are included. 5.2. System adequacy at peak load After the average gross domestic demand rose between 2000 and 2008, with the exception of 2002, with values between 0.42% and 4.47%, in 2009 the gross domestic demand decreased by 8.3% compared to 2008, due to the financial crisis. The monthly decreases were in the range of 3.5% – 14.0% compared to the similar period of 2008. In the months of October-November 2009, the decrease in demand slowed down, and in December the growth trend resumed. Furthermore, 2010 registered an increased net consumption of 5.4% (4.8% gross consumption) compared to 2009, and in 2011 the gross consumption increased by 3.7% compared to 2010. Starting with 2012, the average gross demand started to decline again, decreasing by 1.5% compared to 2011 and by 4.4% in 2013 compared to 2012. Starting with 2014, the average gross domestic demand registered a positive trend, rising by average values between 0.7% - 2.3% compared to the previous years. Figure 5.2.1 presents the evolution of the average gross demand, based on the data provided by generators. These values can be found in the monthly and annual reports of CNTEE Transelectrica SA. Some of the data from www.transelectrica.ro is operative data in contrast to the data from the reports which contains the generator statements.

Variatia consumului mediu brut anual in perioada 2000 - 2017 (MWh/h)

7200 6947 7000 6871 6852 6770 6768 6800 6750 6720 6641 6606 6591

6600 6485 6467

2,3 2,3 % 3,7 3,7 % 6400 6341 1,5 %

1,9 1,9 % 6301 0,7 0,7 %

6241 % -1,5

2,0 2,0 %

2,4 2,4 % 4,8 4,8 %

6200 1,9 %

2,3 2,3 % -4,4 % -4,4 [MWh/h] 5999 5974

6000 1,6 1,6 %

5835 % -8,3 4,5 4,5 %

5800 2,8 2,8 %

5600 % -0,4

5400

5200 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Figure 5.2.1

The maximum value of the gross instantaneous demand in 2017 was 160 MW higher in comparison with the maximum value of 2016, and 452 MW higher when compared with the peak demand of 2015. Thus, the maximum gross demand, amounting to 9,931 MWh, was registered on 10.01.2017, in the 19:00-19:59 interval. The minimum gross demand (4,383 MWh) was registered on 05.06.2017 in the 06:00-06:59 interval (Pentecost) (Figure 5.2.2 – Instantaneous values on thewww.transelectrica.ro website, the Consumption-Generation-Balance section).

Evolutia consumului (MWh/h) mediu, minim si maxim in anii 2015 - 2017

10000 9931

8000 9771 9479

6000

[MWh/h]

6768 6947

4000 6720

4177 4383

2000 4117

0 2015 2016 2017 medii anuale minime anuale maxime anuale (citiri la ore fixe)

Figure 5.2.2

Figure 5.2.3 By analyzing the evolution of the net demand for 2010-2017, illustrated in Figure 5.2.3, we see that between 2010 and 2011 the net demand rose by 1,554 GWh, and between 2012 and 2013 it decreased by 2,133 GWh. Between 2014 and 2017, we see an increase from 53,290 GWh in 2014 to 56,768 GWh in 2017.

The physical electricity exchanges with neighboring systems (CET hours) are, at any given time, the sum of the actual exports and imports based on the contracts between the electricity market participants, to which we add the technical exchanges that are generated by the loop circulations between interconnected systems, together with the exchanges for frequency control (Figure 5.2.4 and 5.2.5).

Figure 5.2.4 – Electricity exchanges on the borders in 2016

Variatia importului, exportului si a soldului schimburilor de energie cu vecinii in perioada 2009-2017 (valori medii anuale)

1000 800 600 518 336 364 400 271 312 261 204 155 164 200 29 0

[MWh/h] -200 -217 -230 -283 -400 -333 -331 -600 -490 -554 -537 -553 -541 -571 -695 -800 -768 -813 -832 -1000 -968 -932 2009 2010 2011 2012 2013 2014 2015 2016 2017

export import sold schimburi

Figure 5.2.5

The exchanges at NPS level maintained a constant export balance in each year, with the exception of 2012, when the electricity export was lower than the import, resulting in a net import. On the other hand, 2017 concluded with a net export of 331 MWh. The production of the systems' generating units need to constantly cover the demand and the import/export balance. With respect to the structure of primary resources used for electricity generation, in 2009 there was an accentuated decrease of the coal and hydrocarbons power plants' contribution (generation decreased by 16% and 19% respectively compared to 2008) required to cover the demand. In 2010, the contribution of the coal and hydrocarbons power plants was even lower, decreased by 5% and 8% respectively compared to 2009; this was due to an improved hydro component and an increased generation of hydro power plants, which rose by 30% compared to the previous year. In 2011 together with the accentuated increase of the contribution of wind power plants, from 0.5% from the total generation in 2010, to 2% from the total generation in 2011, we notice an increase in thermoelectric generation (coal: from 36% in 2010 to 42% in 2011; hydrocarbons: from 11% in 2010 to 13% in 2011), as a result of a drastic decrease of the hydro generation in 2011, by 10% compared to 2010. In 2010, the production of wind power plants rose by 39% compared to 2009, corelated with an increase of the installed capacity to 323 MW. In 2012, we see a significant increase in the contribution of wind power plants (5% of the total generation in 2012) compared to 2011 (2% of the total generation). In 2013, we see the same increasing trend in the contribution of wind power plants (8% of the total generation in 2013) compared to 2012 (5% of the total generation). Following the 5% increase in hydro generation, the share of thermoelectric generation decreased (coal: from 40% in 2012 to 30% in 2013, particularly lignite). In 2014, the gross domestic demand had a monthly variation between -2.6% and +5.4% compared to similar months of 2013. Overall 2014 registered a 1.9% increase of the gross domestic demand compared to 2013, while generation registered an 10.6% increase. Furthermore, the contribution of wind power plants maintained its upward trend in 2014, reaching a value of 9.56% of the total production compared to 2013. We can also see that the share of photovoltaic electricity rose by 2.52% following an increase of the installed capacity in this type of power plants. In 2015, the gross domestic demand registered an average growth of 2.0% compared to 2014. The resource mix structure did not suffer any significant changes when compared to 2014, thus: the nuclear generation registered a slight decrease (0.26%), as well as hydro (3.88%), the increases being registered for coal (0.02%), biomass (0.02%), photovoltaic (0.53%), wind (1.21%) and hydrocarbons (2.37%). The decrease in hydro generation has also been influenced by the low debit of the Danube river, having a value of 4,905 mc/s in 2015, compared to 6,024 mc/s in 2014. In 2016, the gross domestic demand had an average growth of 0.7% compared to 2015. The resource mix structure did not suffer any significant changes when compared to 2015; comparing each resource share, we see the following: the nuclear generation registered a slight decrease (0.24%), as well as coal (3.01%), wind (0.54%), biomass (0.10%), photovoltaic (0.23%), while slight increases were registered in the hydro generation (3.00%) and hydrocarbons (1.12%). The increased hydrocarbons generation was due to the entry into force of the "The Network code for the National Gas Transmission System", which obligates natural gas grid users to nominate the injected/extracted quantities in/from the transmission grid, which led to ensuring the necessary gas quantities for the

29 operation of the hydrocarbons power plants. On the other hand, the hydro generation registered an increase following a higher mobilization of the tertiary reserve for the balancing market, in order to ensure the generation-demand-exchange power balance, as a result of system services. Considering that the renewable resources generation is very volatile (it may present large generation variations from one dispatching interval to another (of over 1,000 MW), or even within the same interval), the wind power plants NPS integration was mostly facilitated by the actual Romanian generation structure, especially due to the hydro power plants generation, because these power plants have a high loading speed and can successfully absorb the wind power plants' generated variation. The generation structure is presented in Table 5.2.1 and Figure 5.2.6. Table 5.2.1 anul 2017 anul 2016 [GWh] [MW] [%] [GWh] [MW] [%] TOTAL PRODUCTIE, din care: 63748 7277 100.0 64472 7340 100.0 Centrale pe carbune, din care: 17154 1958 26 16091 1832 25 lignit 15645 1786 24 14417 1641 22 huila- huila 1509 172 2 1674 191 3 hidrocarburi 10803 1233 17 9959.8 1134 15 ape 14608 1668 23 18272 2080 28 nuclear 11509 1314 18 11286 1285 18 eoliana 7403 845 12 6590 750 10 biomasa 401 46 1 453 52 1 fotovoltaica 1870 213 3 1820 207 3

In 2017, the generation variation broken down on resource types had registered increased values ranging from 0.11% (for photovoltaic generated electricity) and 1.95% respectively (for fossil fuel- coal electricity) in comparison with 2016. Significant increases have been registered in terms of hydrocarbons generation (1.5%) as well as wind (1.39%) and nuclear generation respectively (0.54%). On the other hand, the biomass generation decreased (0.11%) as well as hydro generation (5.42%). The important decrease of hydro generated electricity was due to a lower hydro component registered on interior rivers in 2017, as well as on the Danube river; 2017 was a dry year compared to 2016, which was a normal one.

Structura pe resurse primare [GWh;%] a productiei brute de energie electrica in anul 2017 eoliana; biomasa; fotovoltaica; 7403; 12% 401; 1% 1870; 3% carbune; 17154; 26% nuclear; 11509; 18%

lignit; 15645; 24%

huila; 1509; 2% ape; 14608; 23% hidrocarburi; 10803; 17%

Structura pe resurse primare [GWh;%] a productiei brute de energie electrica in anul 2016 biomasa; eoliana; fotovoltaica; nuclear; 453; 1% 6590; 10% 1820; 3% 11286; 18% carbune; 16091; 25%

lignit; 14417; 22%

huila; 1674; 3% ape; 18272; 28% hidrocarburi; 9960; 15%

Figure 5.2.6

Figure 5.2.7 *the following are included: HPPs, WPPs, PVPPs and biomass power plants

Figure 5.2.7 shows the evolution of the net generation between 2010 and 2017; we can see that the energy generated by the Cernavoda NPP was almost constant in this period. Starting with 2014, the renewable energy sources generation surpassed the one generated in fossil fuel power plants. Table 5.2.2 shows that, in terms of system adequacy, determined according to the ENTSO-E Guidelines for Yearly Statistics and Adequacy Retrospect – 2017 version, the NPS net available capacity was sufficient for covering the peak load from December 2016 together with the export, under conditions of operational security of the NPS. The value of the remaining capacity in December 2016 represented approximately 22% of the total net available capacity in the NPS.

Table 5.2.2 Net available power in the NPS – the 3rd Wednesday of No. December 2016 – 12 o'clock RO (11:00 CET) [MW]

1 Hydroelectric power plants 6,405 2 Nuclear power plants 1,300 3 Conventional thermoelectric power plants 8,186 4 Renewable energy sources (wind, photovoltaic, biomass) 4,384 5 Other power plants 0 6 Net generation capacity [6=1+2+3+4+5] 20,275 7 Unavailable power (Temporary reductions + preservations) 3,673 8 Scheduled repairs in power plants 1,086 9 Accidental repairs in power plants 1,271 10 Power reserve for system services 1,714 11 Net ensured available power [11=6-(7+8+9+10)] 12,531 12 Internal demand 8,056 13 Demand deviation compared to the maximum monthly demand 696 Remaining capacity (without considering the exchanges with 14 4,475 other systems) [14=11-12] Power exchange with other systems 15 Import 207 16 Export 607 17 Import-export balance [17=15-16] -400 Remaining capacity (considering the exchanges with other 18 4,075 systems) [18=14+17]

5.3. Internal electricity transmission capacities and interconnections with other systems The power transmission grid consists of all lines, electric substations together with their support, control and protection elements, as well as the interconnected power equipment.

According to the Electricity and Natural Gas Act no. 123/2012, as subsequently amended and supplemented, the power transmission grid (PTG) is defined as the electric grid of national and strategic interest with a nominal voltage higher than 110 kV. The PTG provides interconnection between generators, distribution grids, large consumers and the neighboring power systems. The transmission grid is the tool that allows the TSO to technically provide the services stated in the object of activity of CNTEE Transelectrica SA according to the provisions of the PTG technical code and the conditions associated with the license for the provision of electricity transmission, system services and for the management of the balancing market.

Sibiu Sud

Figure 5.3 Power Transmission Grid – October 2017 LEGEND: - 110 kV OHL: - 220 kV OHL: - 400 kV OHL: ( : operates at 220 kV : Nadab-Oradea 400kV OHL, in progress) - 750 kV OHL:

Table 5.3.1 presents a summary of the PTG structure, according to ANRE Decision no. 802/2016 for amending License no. 161 for the provision of electricity transmission, system services and for the management of the balancing market; Annex B-2 (lines, transformers, coils) presents the PTG elements in detail: lines, transformers, coils that CNTEE Transelectrica SA operates as grantee, owner or based on other legal grounds, according to the license.

CNTEE Transelectrica SA operates all the interconnection lines, including the 110 kV ones. As illustrated in Table 5.3.1, the power transmission system consists of: overhead power lines (OHLs) with a nominal voltage of 750 kV, 400 kV, 220 kV, 110 kV, and substations having a maximum voltage of 750 kV, 400 kV and 220 kV.

Table 5.3.1 PTG facilities SUBSTATIONS Transformation units Apparent Voltage Subst OHL >=100 MVA nominal power [kV] ations [km] T/AT T/AT [no.] [no.] [MVA] 750 1 2 1,250 3,108 2 500 400 38 20 400 4,915.2* 31 250 2 400 220 42 81 200 3,875.64 1 100 110 0 0 0 40.418 TOTAL 81 139 36,100 8,834.4 *) The total value of the 400 kV OHL from 2016 included the 59.2 km Oradea Sud-Nadab OHL Note: the line length is divided based on the constructive voltage.

The total length of the power transmission grid is 8,834.4 km, out of which the interconnection lines have a length of 426.9 km. The power lines and substations that make up the national transmission system were mostly built in the 1960-1980 period, at that period's technological level. An ample refurbishment and modernization plan was started and is ongoing in the transmission substations, ca. 56% (45 substations) out of the total 81 substations being already refurbished. The refurbishment works continued in significant substations of the PTG in order to increase the performance of the service and to comply with the applicable norms; implementation works for the command-control-protection system in certain substations, works for upgrading the protection systems, as follows: – in 2015: the Tulcea Vest 400/110/20 kV substation, extension of the Cernavoda 400 kV substation – stage 1 – bucking coils replacement, replacing a 25 MVA 110/10 kV transformer with a 40 MVA transformer in the Fundeni 220/110 kV substation and upgrading the control-protection system in the Tihau 220/110/20 kV substation; – in 2016: the following works have been completed:  Bucuresti Sud substation: New 63 MVA, 110/10 kV Trafo 1  Fundeni substation: New 40 MVA, 110/10 kV Trafo 3  Gheorgheni substation: New 25 MVA, 110/20 kV Trafo 1  Gradiste substation: New 25 MVA, 110/20 kV Trafo 2

 Raureni substation: New 200 MVA, 220/110 kV AT  Ungheni substation: New 200 MVA, 220/110 kV AT 2  Vetis substation: modernization of the control-protection system  The Isalnita-Craiova Nord 220 kV OHL circuit 1, replacing active conductors with other active conductor with a higher transmission capacity (ACSS type, S = 558 mm2, Ol/Al, Iproeb manufacturing) – in 2017: refurbishment works have been conducted in the Campia Turzii 220; 110/20 kV substation and the Tihau 220/110 kV substation – primary equipment; AT 200 MVA have been replaced in the Craiova Nord 220/110 kV and Pestis 220/110 kV substations; transformers T1 and T2 2x16 MVA have been replaced in the Vetis 220/110/20 kV substation; a SCADA system upgrade was performed in the Constanta Nord substation. The ongoing major maintenance works have been completed and the following have been analyzed, verified and approved: design themes, technical expertise, tender books for design and execution, documents of approval for the repair and maintenance works (DARM) and feasibility studies for the investment component (FS), tender documents (TD) for major maintenance projects included in the annual PTG maintenance programs. The subject matter of these activities were projects currently being designed or that are in the procurement procedure and ongoing contracts respectively, as follows:  Substations – analysis of the condition of the PTG equipment which has exceeded its normal lifetime.  OHLs – design documentation: "RK Roman Nord-Suceava 400 kV OHL"; "RK Gutinas- Focsani Vest 220 kV OHL"; "RK Bucuresti Sud-Pelicanu 400 kV OHL"; "RC Isalnita- Gradiste 220kV OHL"; "RC Tantareni-Urechesti 400kV OHL"; RC Isaccea-Tulcea Vest 400 kV OHL; RC Filesti-Lacu Sarat 220 kV OHL; RC CNE-Constanta Nord 400 kV OHL st. 1-66; RC CNE Cernavoda-Gura Ialomitei 400 kV OHL circ.1 st. 1-64; "Major maintenance of Tihau-Baia Mare 3 220 kV OHL"; "Major maintenance of Cluj Floresti- Alba Iulia: Cluj Floresti-Campia Turzii: Iernut-Campia Turzii 220 kV d.c."; "Major maintenance of Retezat-Hasdat 400(220) kV OHL".  OHL - works execution: "RK Dumbrava-Stejaru 220 kV OHL"; "Major maintenance Fantanele-Gheorgheni 220 kV OHL"; " Major maintenance Stejaru-Gheorgheni 220 kV OHL"; "RC Bradu-Stuparei 220 kV OHL".  Transformers: "Insulation rehabilitation by oil treatment at the 200 MVA AT1 in Hasdat substation"; Measurement and special expertise at the transformation unit, RC of the 250 MVA Trafo 2 in the Smardan 400/110/20 kV. New interconnection lines have been completed (Nadab-Beckescsaba, for the Hungarian border), other are in progress (Resita-Pancevo, for the Serbian border). The investments made to date allowed maintaining, under proper conditions, the dispatch managed infrastructure and the electricity market infrastructure: the national optical fiber network, the EMS-SCADA monitoring and management system, the metering system of the electricity quantities traded on the wholesale market, IT trading and settlement platforms. The modernization program of the entire network is underway, in accordance with the highest European standards using modernization and refurbishment works for the most important electric substations of the PTG, as well as developing the transmission capacity over interconnection lines.

The modernization/refurbishment works done have always aimed to adopt equipment at the technical level of the respective period, which allowed the choice of a simplified connection scheme for the substations. The newly installed transformers and autotransformers from refurbished substations are characterized by improved operational parameters and constructive solutions without control units or one-phase units, which increases operational security and significantly reduces maintenance costs, the negative environmental impact and grid losses.

5.4. Loading factor of PTG elements The PTG elements loading factor analysis is carried out per reference design regime, for each studied period: winter of 2016-2017 [7] and summer of 2017 [6]. The regimes are characterized by covering the demand and the balance with a probable generation structure and were computed for a network topology according to the Annual Program for equipment outages, following some investment works in CNTEE Transelectrica SA facilities. The unavailability of some transformation units, following their failure, was also taken into account. In the load flow solution, the substation demand, metered in the stage specific to demand – SEP (summer evening peak load) and WEP (winter night peak load) is the one taken into account. It should be noted that the loads of grid elements vary in operation because of the continuous change of the demand and generation structure and level, as well as due to the planned and accidental outages. This can lead to very distinct loads on grid elements. The analyses results presented below are taken from the biannual studies for operational scheduling of NPS operation in the winter of 2016-2017 [7] and summer of 2017 [6]:

5.4.1. Summer of 2017 The analysis of the load factor of PTG equipment in the summer of 2017 [6] is carried out for a generation of ca. 96% of the WPP installed capacity and with the following features: - The Razboieni-Roman Nord 110 kV OHL, the Vatra-Targu Frumos 110 kV OHL and the Barlad- Glavanesti 110 kV OHL are maintained in operation; - The Ostrov-Zatna-Lebada-Lunca-Lacu Sarat 110 kV OHL circuits 1 and 2 will be disconnected; - The refurbishment of the Suceava 110 kV substation is in progress over the course of several months; - The refurbishment of the Dumbrava substation: each AT of the Dumbrava 220/110 kV substation was decommissioned one at a time; - The Basarabi-Baltagesti 110 kV OHL is disconnected; The following are operational: - The Harsova-Topolog 110 kV OHL with a derivation in Cismeaua Noua, disconnected in the Harsova substation; - The Baia-Mihai Viteazu 110 kV OHL with a derivation in Fantanele, disconnected in the Baia substation; - The Stejaru-Mihai Viteazu 110 kV OHL disconnected in the Mihai Viteazu substation; - Refurbishment of the Medgidia Sud substation, with the Medgidia Sud 400/110 kV T1 decommissioned; - The Fundeni-Obor 110 kV UPL, c2 equipped with a new conductor; - New 110 kV substations: Liviu Rebreanu, Academia Militara, Parc Drumul Taberei;

- The new Bucuresti Centru substation: The Panduri 110 kV UPL is in operation, the Bucuresti Nord UPL is put on standby (same status it had in the winter of 2016-2017), the Centru 110 kV CT is connected; - The Salaj 110 kV CT is connected, the Vulcan-Salaj 110 kV UPL is disconnected; - The Panduri-Cotroceni 110 kV UPL is disconnected; - The Pajura substation: The Baneasa 110 kV UPL is in operation, the Timpuri Noi 110 kV UPL is put on standby. - The Arges Sud-Jiblea, Valea Danului-Cornetu 110 kV OHLs, with a derivation in Gura Lotrului are in operation; - The Urechesti 220/110 kV AT will be in operation and the Targu Jiu Nord 220/110 kV AT is put on standby. - The Vascau 110 kV CT and the loop Salonta-Ch. Cris 110 kV OHL are in operation; the Beius and Brad 110 kV OHLs are in operation on B1-110 kV; the Sudrigiu and Virfurile 110 kV OHLs are in operation on B2–110 kV; - The Nadab-Oradea Sud 400 kV OHL is not yet completed and commissioned; - The consumer Cuptoare (Otelu Rosu) which is supplied from the Iaz 110 kV substation is stopped, currently in insolvency; - The consumers Otelarie Resita (supplied from the Resita 220 kV substation) and Otelarie Hunedoara (supplied from the Hasdat/Pestis 220 kV substation) are in operation; - In the Hasdat substation, the Hasdat 220/110 kV AT2 is unavailable. In conclusion, c1 and c2 from the Hasdat 110 kV OHL are connected in Laminoare substation and the 110 kV CT is disconnected; c1 and c2 from the Pestis 110 kV OHL are maintained in operation. Thus, the Hasdat area will be looped with the Pestis and Mintia areas. The Simeria-Calan 110 kV OHL is connected in Calan; - The refurbishment of the Campia Turzii substation is completed and the Campia Turzii 220/110 kV AT is commissioned; - The Campia Turzii 110 kV area will be operating in a loop with the Alba Iulia area; the service will operate with a single Alba Iulia 220/110 kV AT together with the Alba Iulia 110 kV CT connected;

The calculation took into account a generation of 2,790 MW in wind power plants (ca. 96% of the total installed capacity) and a photovoltaic generation of 0 MW. The export balance was 1,250 MW. In the steady-state regime, the power flows through PTG equipment (400kV, 220kV lines, 400/220kV AT, 400/110kV T, 220/110kV AT) are below the thermal limits of the conductors or below the nominal power of the transformation units and are shown in Annex B-3, Tables 1-5, Diagrams 1-5. In terms of the line load compared to the natural power, we see that in the analyzed steady-state regime, the 400 kV OHLs are loaded below their natural power (Pnat=450-500 MW) with a proportion of ca. 83% of the total OHL. The most loaded 400 kV lines are:  The Tulcea Vest-Isaccea 400 kV OHL (ca. 900 MW)  The Smardan-Gutinas 400 kV OHL (ca. 675 MW)  The Cernavoda-Pelicanu 400 kV OHL (ca. 645 MW)  The Gura Ialomitei-Bucuresti Sud 400 kV OHL (ca. 630 MW)

In the analyzed stationary regimes, the 220 kV OHLs are loaded below the natural power (Pnat = 120 MW) in a proportion of approximately 90% from the total OHL. The most loaded 220 kV lines are:

 The Urechesti-Targu Jiu 220 kV OHL (ca. 240 MW)  The Targu Jiu-Paroseni 220 kV OHL (ca. 235 MW)  The Portile de Fier-Resita 220 kV OHL c1, c2 (ca. 205 MW)  The Paroseni-Baru Mare 220 kV OHL (ca. 200 MW) The AT and T loading (% of Sn) is summarized in Table 5.4.1, and the load of 400 kV and 220 kV lines (% of Iadm) is summarized in Table 5.4.2. The number of required transformation units that need to be running was determined based on the verification calculus for the N-1 criteria, also taking into account the reduction of OTC.

Table 5.4.1

AT 220/110 kV T 400/110 kV AT 400/220 kV loading loading Regime loading (%Sn) (%Sn) (%Sn)

maximu average maximu average maximu average m m m SEP 2017 70 35 62 26 81 39

Table 5.4.2

400 kV Lines 220 kV Lines (%I ) (%I ) Regime adm adm maximu maximu average average m m SEP 2017 81 24 63 22 5.4.2. Winter of 2016-2017 The analysis of the load factor of the PTG equipment for the winter of 2016-2017 [7] is carried out for a network with the following features: - the Razboieni-Roman Nord, Vatra-Tg. Frumos and Barlad-Glavanesti 110 kV OHLs are in operation; - the Ostrov-Zatna-Lebada-Lunca-Lacu Sarat 110 kV OHL circuits 1 and 2 are disconnected from the Ostrov substation; - The refurbishment of the Suceava 110 kV substation is in progress over the course of several months; - the Basarabi-Baltagesti 110 kV OHL is disconnected. - The following are operational: o the Harsova-Topolog 110 kV line with a derivation in Cismeaua Noua, disconnected from the Harsova substation; o the Baia-Mihai Viteazu 110 kV line with a derivation in Fantanele, disconnected from the Baia substation; o the Stejaru-Mihai Viteazu 110 kV line disconnected in the Stejaru substation; - refurbishment of the Medgidia Sud substation: o The Medgidia Sud 400/110 kV T1 is decommissioned; - The Bucuresti Centru substation (new): The Panduri 110 kV UPL is in operation, the Bucuresti Nord UPL is put on standby;

- The Pajura substation: the Baneasa 110 kV UPL is in operation, the Timpuri Noi 110 kV UPL is put on standby. - the Arges Sud-Jiblea and Valea Danului-Cornetu 110 kV lines with a derivation in Gura Lotrului are in operation; - the Poiana Lacului-Cazanesti 110 kV line is put on standby in Poiana Lacului; - the Pojaru-Berbesti 110 kV line is put stand by in Pojaru; - Refurbishment of the Bradu substation: o Only one 400/220 kV AT is in operation in the Bradu substation (AT4) due to the refurbishment works from that substation; o The Pitesti Sud 220/110 kV AT is decommissioned, the service will be ensured with both 220/110 kV ATs in the Bradu substation. - The Vascau 110 kV CT and the Salonta-Chisinau Cris 110 kV OHL loop are in operation; - The Nadab-Oradea Sud 400 kV OHL is not yet completed and commissioned; - The consumer Cuptoare (Otelu Rosu) which is supplied from the Iaz 220 kV substation is stopped. - The consumers Otelarie Resita (supplied from the Resita 220 kV substation) and Otelarie Hunedoara (supplied from the Hasdat/Pestis 220 kV substation) are in operation; - In the Hasdat 220 kV substation, the Hasdat 220/110 kV AT2 is unavailable. In conclusion, c1 and c2 from the Hasdat 110 kV OHL are connected in Laminoare substation and 110 kV CT is disconnected. The Pestis 110 kV OHL c1 and c2 are maintained in operation. Thus, the Hasdat area will be looped with the Pestis and Mintia areas. The Simeria-Calan 110 kV OHL is connected in Calan; - The refurbishment of the Campia Turzii substation is completed and the Campia Turzii 220/110 kV AT is commissioned; - The Campia Turzii 110 kV area will be operating in a loop with the Alba Iulia area; the service will operate with a single Alba Iulia 220/110 kV AT; - the Tauni-Blaj 110kV line is kept disconnected.

The calculation took into account a generation of 2,835 MW in wind power plants (approx. 98% of the total installed capacity) and a photovoltaic generation of 0 MW. The export balance amounted to 800 MW. In steady-state regimes, the power flows through PTG equipment (400kV, 220kV lines, 400/220kV AT, 400/110kV T, 220/110kV AT) are below the thermal limits of the conductors or below the nominal power of the transformers and are shown in Annex B-4, Tables 1-5, Diagrams 1- 5. From the point of view of line loading in relation to natural power, the following may be observed: In the analyzed steady-state regimes, some 400 kV OHLs are loaded over their natural power (Pnat= 450-500 MW), while the remaining of ca. 81% of the 400 kV lines are loaded under the natural power. The most loaded 400 kV lines are:  the Tulcea Vest-Isaccea 400 kV line (ca. 922 MW)  the Gutinas-Smardan 400 kV line (ca. 701 MW)  the Pelicanu-Cernavoda 400 kV line (ca. 625 MW)  the Bucuresti Sud-Gura Ialomitei 400 kV line (ca. 595 MW)

 the Iernut-Sibiu Sud 400 kV line (ca. 517 MW)  the Domnesti-Bucuresti Sud 400 kV line (ca. 515 MW)  the Bucuresti Sud-Pelicanu 400 kV line (ca. 503 MW)  the Tulcea Vest-Tariverde 400 kV line (ca. 501 MW)

In the analyzed stationary regimes, the 220 kV OHLs are loaded below the natural power (Pnat = 120 MW), in a proportion of approximately 86% from the total OHL. The most loaded 220 kV lines with a flow higher than their natural power are:  the Baru Mare-Hasdat 220 kV line (ca. 248 MW)  the Portile de Fier-Resita 220 kV line c1, c2 (ca. 242 MW)  the Paroseni-Baru Mare 220 kV line (ca. 222 MW)  the Urechesti-Targu Jiu 220 kV line (ca. 219 MW)  the Bucuresti Sud-Fundeni 220 kV line c1, c2 (ca. 216 MW) The AT and T loading (% of Sn) is summarized in Table 5.4.3.

The load of 400 kV and 220 kV lines (% of Iadm) is summarized in Table 5.4.4.

Table 5.4.3

Load Load Load 400/220kV(%Sn) AT 220/110kV (%Sn) AT 400/110kV (%Sn) T Regime maximu maxim maxim average average average m um um WEP 75 42 64 28 80 41 2016/2017

Table 5.4.4

220kV line load 400kV line load (%I ) adm (%I ) Regime adm maximu maxim average average m um WEP 82 26 74 25 2016/2017

5.4.3. Conclusions regarding the domestic grid load 5.4.3.1. SEP section (summer of 2017) – The 400 kV lines are operating in a proportion of approx. 83% load under their natural power. Taking into account an increased WPP generation, the most loaded 400 kV lines are: the Tulcea Vest-Isaccea 400 kV OHL, the Smardan-Gutinas 400 kV OHL, the Cernavoda-Pelicanu 400 kV OHL and the Gura Ialomitei-Bucuresti Sud 400 kV OHL. – The 220 kV lines are operating in a proportion of approx. 90% load under their natural power. The most loaded 220 kV lines are: the Urechesti-Targu Jiu 220 kV OHL, the Targu Jiu-Paroseni 220 kV OHL, the Paroseni-Baru Mare 220 kV OHL and the Portile de Fier-Resita 220 kV OHL c1, c2.

– The degree of usage of the PTG in the complete scheme is low in relation to the value of the line transmission capacity (long term Iadm) and to Sn of transformation units. However, the PTG usage degree is not an indicator of the operational security of the NPS. The operational security status of the NPS (according to the definitions provided in the PTG code) is the operational status in which the following criteria are met: safety criteria (N-1), steady-state stability and the conditions for transient stability. – The regime which generated the above-mentioned results (SEP 2017 section) is characterized by a maximum WPP generation (approx. 96% of the total installed capacity) which can be discharged whilst complying with the N-1 criterion in the PTG and PDG, in complete scheme and for the analyzed demand section and export balance. The curtailment is required in order to avoid congestions in the 110 kV Dobrogea PDG. There have been periods in actual operation where the generation of wind power plants was nearing the total installed power, but below 96% of the total installed capacity. In terms of operational schemes with equipment withdrawn from operation, these must be carried out in periods with reduced forecasted generation, so that no WPP generated power reduction measures are necessary. In case of accidental outages, curtailment procedures would be applied to the generated power, however these types of operational regimes were not present in the analyzed period.

5.4.3.2. WEP section (winter of 2016-2017) – The 400 kV lines are operating in a proportion of approx. 81% load under their natural power. The most loaded 400 kV lines are: the Tulcea Vest-Isaccea 400 kV OHL, the Gutinas-Smardan 400 kV OHL, the Bucuresti Sud-Gura Ialomitei 400 kV OHL and the Pelicanu-Cernavoda 400 kV OHL. – The 220 kV lines are operating in a proportion of approx. 86% load under their natural power. The most loaded 220 kV lines are: the Portile de Fier-Resita 220 kV OHL circ. 1 and circ. 2, the Urechesti-Targu Jiu 220 kV OHL, the Baru Mare-Hasdat 220 kV OHL and the Paroseni-Baru Mare 220 kV OHL. – The PTG usage degree in the complete scheme is low in relation to the value of the line transmission capacity (long term Iadm) and to Sn of transformation units. However, the PTG usage degree is not an indicator of the operational security of the NPS. The operational security status of the NPS (according to the definitions provided in the PTG code) is the operational status in which the following criteria are met: safety criteria (N-1), steady-state stability and the conditions for transient stability. – The regime which generated the above-mentioned results (WEP 2016-2017 section) illustrates a situation valid for the hypothesis considered in terms of the proposed balance, the considered demand section, as well as the maximum admissible generation of wind power plants complying with the N-1 criterion in PTG and PDG for the complete scheme (without outages). The results of the load flow solution indicate that in the complete scheme, whilst complying with the N-1 criterion, the electricity generation corresponding to the WPP installed power in the Harsova-Medgidia area (approx. 311 MW) cannot be discharged. The maximum admissible power which can be generated in WPPs from this area amounts to 250 MW.

5.4.4. The total and bilateral transmission capacities on borders

5.4.4.1. Calculated/estimated net exchange capacities In the management of congestions generated by cross-border exchanges, CNTEE Transelectrica SA applies the provisions stipulated in the following national legislation, operational procedures and international conventions with neighboring TSOs (MAVIR, EMS, ESO EAD): - Electricity and Natural Gas Act no. 123/2012, as subsequently amended and supplemented; - Commercial code approved by ANRE Order no. 25/22.10.2004; - PTG technical code approved by ANRE Order no. 20/27.08.2004, amended and supplemented by ANRE Order no. 35/06.12.2004; - Policy no. 4 from the ENTSO-E Operation Manual; - Methodology for determining and harmonizing net transmission capacities (NTC), approved by ANRE Opinion no. 16 of 29.07.2010; - Operational agreements for interconnection lines concluded with the neighboring TSOs; - Bilateral agreements of NTC border allocation, concluded with the neighboring TSOs; C.N.T.E.E. Transelectrica S.A. has the obligation to determine the net transmission capacities' (NTC) values, to reach an agreement on this matter with the neighboring TSOs and to send them to the NTC capacity market for them to be allocated at an annual, monthly, daily and intra-daily level. CNTEE Transelectrica SA calculates the following types of net transmission capacities (NTC), taking into account the main aim of NTC optimization as well as taking into consideration outage schedules combined with meeting the N-1 safety criterion:

a) Non-guaranteed maximum annual NTCs

a.1. The maximum net transfer capacity (NTC) that is not guaranteed in the NPS synchronous interconnection interface is calculated seasonally for the next season. The annual maximum NTC values for the next year are calculated according to the winter season model. The calculations are made for a normal topology, also considering the commissioning values significant for NTC, which will take place in the relevant period. Different variations of generation and the most favorable exchange scenarios will be taken into account, with the aim to simultaneously reach more limitations in all directions and to maximize exchanges in the Romanian interconnection interface. a.2. The total exchange capacity between Romania and the European interconnected network are calculated and allocated on borders taking into account the considered exchange scenarios. The N-1 criterion is checked and the limits imposed by the equipment and the operation protection/automation controls are determined, taking into account the prevention/post-failure measures. A transmission reliability margin (TRM) will be kept on the interconnections in order to allow the mutual aid of the systems at European level by activating the primary control in case of incidents and for the accommodation of regime deviations from the modeled average regimes. According to what has been agreed with the partners, for the calculation of the coordinated net exchange capacity which can be added in Romania's interface, the TRM value is set to 100 MW per border, which leads to the values of 300/400 MW for the export/import Romanian interface. The maximum annual NTC values are indicative and not guaranteed; these are not supplied to the NTC market and are used only for the estimation of the maximum possible exchange volume.

For some borders, the maximum annual bilateral NTC values are used to define a monthly allocation cap, harmonized with the partner (C.N.T.E.E Transelectrica S.A – MAVIR).

b) Fixed annual and monthly NTCs According to the bilateral agreements concluded with the interconnection partners (MAVIR – Hungary, EMS – Serbia, ESO EAD – Bulgaria), CNTEE Transelectrica SA provides fixed bilateral NTCs for commercial use, which can be used simultaneously in the same export/import direction, with transfer reliability margins (TRM) agreed in bilateral agreements, without endangering the system security: – Fixed annual NTCs (=annual ATCs), guaranteed for all annual coordinated repair programs agreed in the NPS and the interconnection; – Fixed monthly NTCs, guaranteed for monthly planned repair programs in the NPS and the interconnection. Considering: – the necessity to supply fixed annual NTCs prior to the preparation of the NPS' annual outage plan and the coordinated outage plans in the interconnection, – the outage rescheduling during the year, – the uncertainties related to the key points production forecast affecting the NTC values (HPP Portile de Fier + Djerdap, etc.) and related to the compliance with commissioning deadlines. Fixed annual NTCs are estimated considering: . The current and previous years’ experience on simultaneous repair programs carried out on the interconnection and the exchange possibilities: the lowest fixed monthly NTC values achieved; . Additional calculations, performed only if the following are provided: – refurbishment programs in the next year that may lead to significantly lower fixed NTC values; – significant commissioning (interconnection lines and substations, etc.) between the annual NTC estimation and the start of the following year, which can lead to an increase in NTC values. Fixed monthly NTCs on borders are calculated on a monthly basis applying the calculation methodology developed within CNTEE Transelectrica SA – the National Power Dispatcher, based on ENTSO-E recommendations on the interdependent exchanges in looped grids: Bilateral NTCs are determined coordinately by calculating composite NTCs in the NPS interconnection interface and other interfaces jointly used with partners, a principle agreed upon with all partners. For each month, CNTEE Transelectrica SA calculates and supplies fixed NTC border values for the energy market in the previous months, which can be simultaneously used in the entire NPS interconnection interface under safety conditions, considering: . The forecasted exchanges, the fixed annual NTCs, the source/destination uncertainty and the possibility of successive reallocations, the netting elimination, the joint use of interfaces; . Repair programs for the relevant month; generation and demand forecast; . Automation status, prevention/post-failure operative measures.

The monthly NTC calculation is done for sub-periods as low as week and day, based on the outage schedules in the relevant month, thus the obtained NTC values are also adequate for the weekly, daily and intra-daily allocation. The historical situation of commercial congestions generated by electricity cross-border exchanges can be found on C.N.T.E.E. Transelectrica's website www.transelectrica.ro/web/tel/355 where the annual congestion reports can be found.

5.4.4.2. Maximum net transfer capacities Maximum net transfer capacities in 2010-2017:

2010 2011 2012 2013 2014 2015 Winter Summer 2016-2017 of 2017 Maximum non-guaranteed NTCs*) (forecast) [MW]

RO 1,900 2,050 2,400 2,300 2,700 2,750 2,650 2,250 export RO 1,900 2,100 2,300 2,100 2,300 2,700 2,200 2,050 import RO->HU 1,100 700 700 800 900 1,350 1,100 1,100 HU->RO 600 700 700 700 800 1,000 600-800 950 RO->RS 600 700 800 700 800 950 850 600 RS->RO 300P- 500 600 550 600 800 600-500 400 RO->BG D1600A600 600 700 650 800 350 550 450 BG->RO 600 600 800 550 600 750 750-550 400 RO->UA 300 200 200 150 200 100 150 100 UA->RO 400 400 300 300 300 150 250-350 300 *) Source: Seasonal studies for operational scheduling, Chapter 3.5 https://www.transelectrica.ro/web/tel/380

For the winter of 2016-2017 the NTC maximum values were determined for the basis regime with/without SPP Mintia and different scenarios (amounting to 3) of simultaneous exchange with partners: exp1/ exp2/ exp3/ exp3- Scenarios imp1 imp2 imp3 M NTC**) R3 R3 R3 R3-M Export RO 2,350 2,650 2,150 1,550 Import RO 2,200 2,200 2,100 RO->HU 850 1,100 1,100 750

HU->RO 600 800 900 RO->RS 750 850 650 550 RS->RO 600 500 600 RO->BG 650 550 300 200 BG->RO 750 550 400 RO->UA 100 150 100 50 UA->RO 250 350 200 **) Source: Seasonal studies for operational scheduling, Chapter 3.5 https://www.transelectrica.ro/web/tel/380

For the summer of 2017 the NTC maximum values were determined for the basis regime in different scenarios (amounting to 7) of simultaneous exchange with partners:

Scenarios exp1/ exp2/ exp3/ exp4/ exp5/ exp6/ exp7/ imp1 imp2 imp3 imp4 imp5 imp6 imp7 Export RO 2,050 2,000 2,200 2,150 2,150 2,250 1,950 Import RO 1,950 2,000 1,850 2,000 2,050 RO->HU 800 800 1,000 1,100 1,050 1,100 850 HU->RO 700 700 650 800 950 RO->RS 750 600 650 600 700 600 700 RS->RO 500 400 550 400 400 RO->BG 400 500 450 300 300 450 300 BG->RO 500 600 400 500 400 RO->UA 100 100 100 150 100 100 100 UA->RO 250 300 250 300 300 Source: Seasonal studies for operational scheduling, Chapter 3.5 https://www.transelectrica.ro/web/tel/380

5.4.4.3. Monthly net transfer capacities

Maximum values of harmonized fixed monthly NTC profiles [MW] 2010 2011 2012 2013 2014 2015 2016 2017 RO export 1,400 1,575 1,550 1,550 1,650 1,650 1,700 1,700 RO import 1,300 1,650 1,500 1,500 1,700 2,100 2,150 2,450 RO->HU 500 550 450 650 700 700 700 700 HU->RO 600 700 600 650 700 700 700 700 RO->RS 550 650 700 600 700 700 700 700 RS->RO 300 300 350 500 600 800 800 800 RO->BG 300 325 350 200 200 400 300 300 BG->RO 200 300 350 250 300 400 300 300 RO->UA 50 50 50 100 50 100 100 300 UA->RO 200 350 200 100 100 200 550 650 Source: Seasonal studies for operational scheduling, Chapter 3.5 https://www.transelectrica.ro/web/tel/380 Depending on the update of data regarding carrying out outage schedules, if significant changes arise, the guaranteed NTC values are recalculated and harmonized at sub-period level. Additional capacities can be allocated in the joint daily and intra-daily auctions for the borders with Hungary, Bulgaria and Serbia.

5.4.4.4. Factors that influence the non-guaranteed maximum capacity values and the annual and monthly fixed exchange capacities

The analysis regarding the NTC influence factors, which are maximum non-guaranteed values, is based on results and conclusions generated by the seasonal studies for NPS operational scheduling, namely Chapter 3.5 of the study. https://www.transelectrica.ro/web/tel/380 The following factors have significantly influenced the annual maximum exchange capacities from the NPS and of the annual and monthly fixed exchange capacities from 2010-2017:

 Alteration of the current limit on the Portile de Fier-Djerdap 400 kV OHL: – the summer current limit reduction in Djerdap to 1300 A from 2011, having a negative effect on the export capacity in the summer period. For example, in the summer of 2017 the non-guaranteed maximum export capacity was reduced by 400 MW when compared to the winter of 2016-2017.  The decrease in European level exchange volumes generated by the economic recession (2009-2011) which lead to a reduction of the NPS North-South parallel circulations, having a positive effect on the export and import capacity of the NPS.  The change in the export-import structure on the interconnection (higher import in Hungary) leading to a higher utilization of the Romanian-Hungarian interconnecting OHL, with a positive

effect on the export NTCs.  The commissioning of the wind power plants in the south-eastern part of the country increased the export contribution of the Isaccea-Rahman-Dobrudja 400 kV axis and the Isaccea- Stupina-Varna 400 kV axis, with a positive effect over the export capacity. The NTC export value on the Romanian interface depends on the WPP generation in the Dobrogea area. This conclusion is based on the comparative analysis of regimes with different WPP generations, regimes which were analyzed within seasonal studies for NPS operational scheduling;  The operation with generation in the Iernut SPP and low deficit in the northern area, which leads to the increase of the import NTC.

 The operation without generation in the Mintia SPP determines a higher loading of the Portile de Fier-Resita-Timisoara-Arad axis and may lead to a significant export NTC reduction on the Hungarian border and in the Romanian interface (ca. 600 MW in the winter of 2016-2017). The maximum monthly net fixed transfer capacities are lower compared with the maximum indicative values, from various reasons: - Considering certain scenarios of simultaneous exchanges between several partners over joint multilateral interfaces and back to back allocations over several borders, which leads to a preferential request of certain NPS borders; - The development of PTG maintenance programs which required the outage of some significant lines in the PTG and the external grid in the winter period. For example, the outage of the Gadalin-Iernut 400 kV OHL in the winter of 2016-2017 for fixing the effects on equipment of severe weather conditions; the maximum generation levels in certain power plants and areas, significantly different from the values considered in the calculation of the maximum seasonal NTC, for example in thermal power plants from the Oltenia area and/or the HPP from the Olt hydro structure; - The generation level of wind power plants of 1,000-1,500 MW was different from the values considered for the calculation of the maximum seasonal NTC; - The variation of the exchange structure with interconnection partners and the parallel circulations. The NTC values in the Romanian interface may vary throughout the year, under the influence of factors such as:

 The outage of interconnection and internal lines influencing the NTC values;  The seasonal temperature difference, leading to: – conversion to reduced summer controls for certain overload protections in Serbia between April/May-September/October, with a negative impact on the export NTC; – higher admissible thermal limit currents on various lines in the NPS and the external grid, which positively influence the values of import and export NTC in November-February. The thermal limit currents are higher in the winter season as they correspond to a smaller temperature. The quantification of the temperature's own effect is difficult to accomplish due to the overlapping with several other influence factors. For example, the temperature effect may be altered/amplified by the fact that in the winter season less outages occur. Such a sensitivity analysis of each factor is not performed within the NTC determination process as it does not lead to NTC maximization. . Key power plants generation: Portile de Fier and Djerdap HPPs, particularly in the summer period, Iernut SPP in the winter period, Mintia SPP.

In previous years, the monthly fixed NTC values variation range in the NPS interconnection interface was reduced due to the following reasons:

. The increase of the WPP installed capacity from the south-eastern area of the NPS, which leads to a better use of the 400 kV OHL interconnection from Dobrogea; . The export-import structure change on the interconnection leading to a higher use of the Romanian-Hungarian interconnection OHL, with a positive effect on the export NTC and the reduction of the north-south parallel circulations, with a positive effect over the import and export NTC; . Operation with generation in the Iernut SPP and a reduced deficit in the northern area in the winter period had a positive effect over the import NTC; . The improvement of the coordination of the significant outage programs (the lines that have an influence over the NTC are stated in paragraph 5.4.4.5) between the interconnection partners, meaning that all the works need to be executed over the duration of a single line outage period that has influence on the interconnection, thus avoiding other outage periods; . Specific operation schemes implementation at interconnection partners level in case of outages with a significant effect or high parallel circulations. For the winter of 2016-2017 in particular we can observe the following influences with respect to the non-guaranteed maximum NTC values: – Operation with high generation in the Dobrogea WPP determines an increase in the Dobrogea interconnection OHL and limits the NTC to the Rahman-Dobrudja 400 kV OHL triggering and the Stupina-Varna 400 kV OHL to the limit required by the Varna automation. – The over 600 MW increase in export towards Bulgaria can determine the reduction of the total NTC in the Romanian interface; the reduction of the export quota towards Bulgaria (due to the agreement upon minimum values set by Bulgaria) facilitated a significant increase in the total export NTC in the Romanian interface and the NTC on other borders. – If a large export quota is directed towards Hungary, the export NTC is also limited by the tripping of a circuit in the Portile de Fier-Resita 220 kV OHL d.c. and the loading of the second circuit; considering the rapid reduction possibilities of Portile de Fier HPP generation, the possibility of short time operation with one circuit from the Portile de Fier-Resita loaded up to the thermal limit current at 20° and 120% load of CT. – The operation without generation in the Mintia SPP determines a higher loading of Portile de Fier- Resita-Timisoara-Arad axis and may lead to a significant export NTC reduction on the Hungarian border (by 350 MW) and in the Romanian interface (by 600 MW). – An import structure with higher values from Bulgaria and Serbia determines an increase in the total NTC value in the NPS interface. The import limitation set by the Bulgarian partner cannot be compensated by a similar increase of the import from Hungary and Ukraine, which has a much more significant impact over the northern part of the NPS.

5.4.4.5. Graphic representation of the influences over the fixed NTC in 2014-2017

In the following graphs the NTC profile representation indicates the equipment which has the greatest influence over the NTC values on the Romanian interface in case of an outage. The

48 reduction of NTC values is not generated only by the outages of Romanian interconnection lines or other internal PTG equipment, but also by other internal equipment of the interconnecting TSO.

Deficit zona de Nord Limitare deficit zona de Nord + + productie in CTE Iernut productie in CTE Iernut LEA BG 1c Resita-Timisoara Sibiu Sud-Tantareni Tantareni.-Sibiu Sud AT1 Iernut LEA UA-SK LEA RS si BA LEA RS Rosiori-Vetis

A.Iulia-Mintia Tantareni- Kozlodui1+2 LEA RS Arad-Timisoara Arad-Mintia LEA HU-UA St.Tihau AT3 Arad Rosiori-Mukacevo LEA RS. Iernut-Sibiu Sud AT3 Arad Gadalin-Rosiori

Arad-Mintia LEA BG+ BG-RS 1c Portile de Portile de Fier-Urechesti Fier-Resita LEA UA si PdFier-Djerdap LEA HU-RS. Arad-Mintia / Mintia-Sibiu Sud Arad-Timisoara /1c Resita-Tim. Urechesti.- Tantareni-Koz.1+2 Tg.Jiu

LEA BG-TR 1c Portile de Fier- LEA BG si BG-MK LEA RS Resita LEA BG Reglaje de vara protectii in RS Productie mica in CHE Portile de Fier + Djerdap

Profil NTC ferme import / export - 2017 - MW 2500 LEA 400 kV Rosiori-Mukacevo 2000

AT 400/220 kV Rosiori 1500

LEA 400 kV Rosiori-Mukacevo LEA 220 kV Alba Iulia-Mintia LEA 400 kV Portile de Fier-Djerdap 1000 LEA 400 kV Arad-Mintia LEA 400 kV LEA 400 kV Rosiori-Mukacevo Arad-Mintia LEA 400 kV Iernut-Gadalin LEA 400 kV Iernut-Sibiu Sud 500 LEA 400 kV Iernut-Gadalin LEA 400 kV Iernut-Sibiu Sud Import LEA 400 kV Iernut-Sibiu Sud 0 ian.-17 feb.-17 mar.-17 apr.-17 mai-17 iun.-17 iul.-17 aug.-17 sept.-17 oct.-17 nov.-17 dec.-17 Export OHL 400 kV RS LEAL 400 kV Arad-Mintia -500 LEA 400 kV HU-RS -1000

-1500 LEA 220 kV Resita-Timisoara 1c LEA 220 kV LEA 400 kV RS-BG Portile de Fier-Resita 1 c. LEA 220 kV Resita-Timisoara 1c. -2000

-2500

5.4.4.6. Graphic representation of NTC profiles and exchange programs

Next, we can see the NTC profiles in the NPS interface, harmonized with the partners, as well as the exchange programs for the years 2014-2017 (at the 3:00 CET night off-peak and the morning peak from 11:00 CET we obtained 4 curves expressing the degree of use of the NTC in these relevant moments of the day). From the graphical representations we see that for the Romanian interface there is an approx. 85- 90% allocation degree of export NTC values when compared to the import ones for 2014-2015. In 2016 and 2017, the export NTC values allocation degree significantly decreased compared to the previous years of 2014 and 2015.

MW Valori NTC ferme agreate import / export si programe de schimb 2017 2500

2000 1500 import 1000 500

0 ian.-17 feb.-17 mar.-17 apr.-17 mai-17 iun.-17 iul.-17 aug.-17 sept.-17 oct.-17 nov.-17 dec.-17

-500 export

-1000

-1500

-2000

-2500 NTC IMPORT NTC EXPORT Program export noapte (03:00 CET) Program import noapte (03:00 CET) Program export zi (11:00 CET) Program import zi (11:00 CET)

5.5. The admissible voltage level, voltage control in PTG nodes, reactive power compensation, voltage quality The NPS voltage level for a certain demand section is controlled with the following reactive offset means:  Synchronous generators, by controlling the voltage at the terminals by using the reactive power range (primary or secondary) from the P-Q flowchart;  Hydraulic assemblies in synchronous condenser regime;  Synchronous condenser;  U-Q automatic control facilities from PTG 400 kV nodes, using the reactive power range from the P-Q diagram of classic power plants or renewable source-based power plants;  Bucking coils;  Operation plots of system and block transformation units;  Capacitor banks. As a fallback measure, in some off-peak load cases, certain 400 kV and 220 kV lines are set to hot spare only after it is checked that their disconnection does not affect the NPS safety (the N-1 criterion is respected). For the permanent regime analyses we consider the primary reactive power range at generators modeled at the terminals (the secondary range is taken into account only for the steady-state stability analyses). Annexes B-5 and B-6 present the voltage values calculated in the 400 kV and 220 kV substations, managed by CNTEE Transelectrica SA, for the summer of 2017 and for the winter of 2016-2017 respectively.

In order to maintain the voltage values within the admissible voltage range, the necessity of maintaining the operation of the bucking coils from the following 400 kV substations was determined through calculations in the peak load regime of the summer of 2017: Cernavoda (one BC), Tantareni (two BCs), Urechesti and Rosiori, and in the winter of 2016-2017 regime the bucking coils from Cernavoda (one BC), Tantareni (two BCs), Urechesti and Rosiori were maintained in operation. In the off-peak load regime, it was determined through calculations that it is necessary to maintain the operation of all bucking coils from 400 kV substations (Arad and Smardan 400 kV BC unavailable). For voltage control it is required to also use other control means: plots change in the transformation units, operation of synchronous generators in capacitive regime. Table 5.5.1. presents the active and reactive power values (balanced) which transited PTG –> EDG, determined on the 110 kV busbar of the 220/110 kV autotransformers and 400/110 kV transformers.

Table 5.5.1 Balanced transit PTG –>PDG Regime P MW Winter of 2016/2017 WEP 3,934 Summer of 2017 SMP 3,616

The consumers that are supplied directly from the PTG represent approx. 91.89% from the total active power demand in the SEP 2017 section and 92.78% from the total active power demand in the WEP 2016-2017 section.

Means of voltage control in the PTG – changes in the last 5 years The automatic secondary voltage control in the PTG is currently conducted at the busbars of the Stupina, Rahman, Tariverde, Brazi Vest, Gura Ialomitei 400 kV substations and the Brazi Vest and Lotru 220 kV substations. The bucking coil from the Arad 400 kV substation is unavailable from 29.06.2017, the one from the Smardan 400 kV substation from 09.01.2017 and the one from the Bucuresti Sud 400 kV substation from January 2017. Three new 100 MVAr, 400 kV bucking coils will be purchased and installed in the Arad 400/220/110 kV, Smardan 400/110 kV and Bucuresti Sud 400/220/110 kV substations to replace the unavailable ones (please see Chapter 12.2.3). The replacement of the one-phase bucking coils having a capacity of 180 (3x60) MVAr from the Cernavoda 400 kV interconnection substation with new 100 MVAr three-phase bucking coils.

Voltage quality in the PTG The "Performance standard for the electricity transmission service and system services" drafted by ANRE entered into force on 30.03.2016. The current Romanian regulations (the Performance standard and the PTG code) obliges the Transmission System Operator to monitor and report the compliance with the power quality standard in its own grid. This activity is conducted in compliance with the procedure "Computation method and reporting on Transelectrica's performance indicators, in line with the performance standard for the electricity transmission service and system services", TEL code 30.12 – in order to evaluate and comply with the electricity quality requirements in the Company's own substations and to identify sources of disturbances. According to CEER (Council of European Energy Regulators – 2001) and EURELECTRIC (2006), the aspects related to electricity quality are classified as follows:  Voltage quality – with respect to the voltage technical features;  Continuity of power supply – with respect to the continuity of supply to consumers;  Commercial quality – with regard to the commercial relations between suppliers, between distributors and users respectively, in terms of providing various services. With respect to the voltage quality monitoring in PTG nodes, CNTEE Transelectrica SA adopts an electricity quality monitoring strategy both via an electricity quality monitoring system managed by the OMEPA metering branch, which was put into service in April 2011, and via a voltage curve quality oversight program, on-demand or at the request of NPD (temporary metering), in CNTEE Transelectrica SA substations, by using 5 mobile analyzers. The centralized quality monitoring system of CNTEE Transelectrica SA monitors the electricity quality in 41 points on the PTG/PDG interface, at major consumers premises and at the wind power plants directly connected to the PTG. The temporary metering aimed to conduct simultaneous quality measurements in several neighboring substations, for the purposes of determining the disruptive consumer and the vulnerability area. In 2015, CNTEE Transelectrica SA has taken the following measures in order to improve the voltage quality of the system:  Commissioning of the voltage control using the full control possibility of the power plants connected in 8 substations. Permanently monitoring the operation of these voltage control loops;

 Modernizing the quality analyzers used in order to comply with current standards' requirements (EN 50160) and to ensure maintenance of the entire electricity quality monitoring system;  Adding certain requirements and penalties with respect to the compliance with the voltage curve quality requirements to the connection approvals1 and the operational agreements/contracts;  Performing measurements before and after the connection of major consumers and potential disruptors connected to Transelectrica's 110 kV substations or to the PTG;  Performing electricity quality measurements at the commissioning of any wind or photovoltaic power plant and conditioning the technical conformity certificate issuance by the compliance with the limits imposed by the applicable standards and technical norms;  Increasing the number of nodes with permanent monitoring. In 2015, there were a total number of 73 measurement points integrated in the permanent monitoring system, out of which 10 were interface points in connection with other PDG analysis systems. In the following years, the portable electricity quality analyzers will be replaced with class A analyzers;  Introducing a new requirement in the technical norms on the connection of generating units: all wind (WPP) and photovoltaic (PVPP) dispatchable power plants must be capable of being monitored in terms of electricity quality with class A equipment2, mandatorily over the performance trial period and optionally for their integration in the grid operator's monitoring systems where the power plants are connected: in the PTG – if wind and photovoltaic power plants are connected in the PTG; or in the PDG – if the wind and photovoltaic power plants are connected in the PDG. From the monitoring over one year of operation, it is noted that the monitored WPPs and PVPPs do not introduce disturbances in the grid; the plants are maintained within the limits allowed by the Performance Standard.

5.6. Power losses in sections specific to the load curve and annual electricity in the PTG The level of power losses is a result of a combination of factors: power circulations resulted from the territorial repartition of demand and generation, grid equipment performance, meteorological factors, NPS voltages level. The electricity losses increase in relation to the amount of transmitted electricity, to the distance between the power-generating facilities and the demand facilities. They decrease in relation to the increased grid voltage and when the atmospheric moisture is low, but can increase when the atmospheric moisture is high. The electricity grid losses (own technological consumption – OTC) are the result of: - the Joule effect, which consists in heat loses generated by the electricity passing through electrical lines conductors and coil and transformer copper windings; - capacitive losses through insulation of live elements;

1 ANRE Order no. 51/2009, amended and supplemented via ANRE Order no. 29/2013 order, ANRE Order no. 30/2013: the performance standard for the electricity transmission service and system services approved by ANRE Order no. 12/30.03.2016.

2 SR EN 61000-4-30 standard, NTI-TEL-M-002-2011 technical norm.

- iron component losses generated by Foucault and Hysteresis currents; - electrical discharge losses generated by the air ionization around conductors operating at high voltage. The volume and structure of the losses is continually changing, depending on the generation and load from each substation, the grid configuration changes following maintenance works or grid incidents and the voltage values changes in substations. Table 5.6.1 presents the calculated values of the own technological consumption for the 2016 SMP and 2016-2017 WEP sections, for the total NPS and broken down on each PTG equipment type: 220 kV and 400 kV lines and system T, AT and bucking coils respectively. The losses calculated for the entire modeled grid (including the 110 kV distribution grid), DPtotal(400-220-110kV), are presented for each specific section. The total PTG losses (DPPTG) represent the sum of the total losses (Joule and Corona) on transmission lines (DP400-220 kV OHL), in transformation units (DPtrafo) and in coils (DPcoils). DPCorona represents the share of Corona losses included in losses calculated for the 400 kV and 220 kV lines (are included in DP400-220 kV OHL).

Table 5.6.1

PTG DP

DPPTG / Year Section DPtotal(400-220-110kV) DPPTG DP400-220 kV OHL DPCorona DPtrafo DPcoils Pentry.PTG MW MW MW MW MW MW % 2016-2017 WEP 385 249 222 56 21 6 3.87% 2016 SMP 256 173 149 30 18 6 3.29%

Table 5.6.2 presents, per specific section, the structure of the power transmitted through the PTG, broken down on the sources delivering directly in PTG, the import from neighboring systems and power injected from the PDG. Table 5.6.2

Pintr in RET Pintr Pgen.RET/Pgen An Palier Pgenerata in RET Aport REDRET (*) interconex SEN(**)

MW MW MW %Pintr RET MW %Pintr RET % 2016-2017 VSI 6437 100 5352 83.15% 985 15.30% 65.68% 2016 VDV 5253 0 4419 84.12% 834 15.88% 60.38% (*) net values; (**) gross values We see the predominance of active power sources directly delivering in the PTG (83.15%) from the total transmitted power, compared to the power contribution from the PDG which represents 15.30%, for the WEP 2016-2017 section and 84.12% PTG sources compared to the power contribution from the PDG, which represents 15.88% for the 2016 SMP section.

Figure 5.6 presents the evolution of the annual own technological consumption values in the PTG.

Figure 5.6 The grid losses are mostly influenced by the distance between the power-generating facilities and the demand facilities, therefore by the way in which the existing groups are distributed in order to cover the load and the volume and destination of international exchanges. The figure above presents a favorable situation based on the structure of generation and balance in 2007 and 2008, which led to a decrease of the OTC share in the transmitted energy in comparison to the long-term trend. Starting with 2014, the OTC share in the transmitted energy constantly decreased.

The main factors that lead to the decreasing OTC in 2016 compared to 2015 were: - the increased generation in power plants with an influence over the OTC reduction: OMV Petrom CCCPP – by 10.6%, from 2,557 GWh to 2,827 GWh, impoundment hydropower plants – by 4.9%, from 2,572 GWh to 2,697 GWh (for plants directly delivering in the PTG) and by 12%, from 7,092 GWh to 7,946 GWh (at NPS level), as well as the decreased generation in power plants with an influence over the OTC increase: coal power plants located in the Oltenia surplus area – by 10.9%, from 12,718 GWh to 11,336 GWh (for plants

directly delivering in the PTG) and by 14.3%, from 16,207 GWh to 14,176 GWh (at NPS level); powerplants which deliver into the Dobrogea surplus area: WPP – by 5.9%, from 3,072 GWh to 2,890 GWh (for plants directly delivering in the PTG) and Cernavoda NPP – by 3.1%, from 10,694 GWh to 10,367 GWh; - the 0.2% decrease in the PTG energy contour input; – the increase in the export balance on the Bulgarian border, located in a surplus area, from 3,974 GWh in 2015 to 4,141 GWh in 2016, which facilitated the discharge of the generation from the Oltenia deficit area with lower losses; – the increase in the import balance on the Ukrainian border, located in a deficit area, from 685 GWh in 2015 to 820 GWh in 2016, positively influenced the PTG losses by reducing the long- distance energy transmission; – the decrease in the export balance on the Ukrainian border, located in a deficit area, from 1,109 GWh in 2015 to 370 GWh in 2016, positively influenced the PTG losses by reducing the long- distance energy transmission. CNTEE Transelectrica SA has the permanent goal of reducing losses in the grid design and scheduling stages, as well as in the real time operation. The main measures applied are: the grid voltage level control correlated with atmospheric conditions and the purchase of modern equipment with superior efficiency in terms of specific losses. Starting with 2011, nodal cost centers have been introduced in order to obtain information with respect to the OTC expenditure allocation for each PTG node in order to identify investment opportunities.

5.7. Short-circuit current level in PTG nodes The maximum value of earthed three-phase, one-phase and two-phase short-circuit currents in the 220-400 kV PTG nodes of the NPS are calculated according to PE 134/1995 "Standard on the methodology to calculate short-circuit currents in power grids of voltage over 1 kV"; this edition had the main goal to classify this specification in the provisions of the International Electrotechnical Commission. The values of the short-circuit currents in PTG nodes are used to: . examine the existing facilities and determine the stage in which the equipment with unsatisfactory short-circuit performance should be replaced; . design the new facilities according to the dynamic and thermal necessities that can occur in the grid; . determine the protection controls via relays and system automations; . determine the influence of high voltage lines on the telecommunication lines and currents via substation socket outlets; . recommendations for PTG measures in order to maintain the short-circuit demands below the values admitted by the existing facilities; . set the necessary performances of equipment and apparatus which are to be assimilated in the NPS. The design calculation of the equipment and apparatus from electric facilities, of the earth outlets and protections of telecommunication lines is conducted for the maximum operational regime. The hypotheses for the calculation of the maximum short-circuit currents, according to the revised PE 134/1995 and ENTSO-E recommendations, are the following:

o all 400 kV, 220 kV and 110 kV lines and busbar couplings from the NPS are connected; o all 400 kV interconnection lines between the NPS and the neighboring power systems are connected; o all high voltage (400 kV, 220 kV, 110 kV) transformers and autotransformers are in operation on median plot and their neutral is rigidly earthed; o all groups are operational; o all bucking coils and synchronous compensators are in operation; o previous permanent regimes are not taken into account; o consumers' loads are not taken into consideration at any voltage level; o under the initial regime, the system is perfectly balanced; o transient phenomena are disregarded. The short-circuit values of PTG substations are presented in Annex B7.

5.8. Inspection of PTG under steady-state and transient stability conditions 5.8.1. Inspection of PTG under steady-state stability conditions For all the sections, the interconnected operation of the NPS with ENTSO-E power systems was considered. Calculations have been performed for schemes with N and N-1 operational elements, in balance hypotheses corresponding to the summer peak section and winter peak section respectively, in the calculation scheme with the maximum duration of the analyzed time intervals (respective semester), with the verification of the N-1 criterion. For each of these schemes, the steady-state stability conditions were verified in the long-term scheme in case of tripping of an element in the area affecting the section and whilst complying with the safety criterion. Under the regimes where the rated reserve is met in the section, but grid voltages or current flows on grid elements were outside the rated limits, the admissible power Padm in the section is established under the last regime where restrictions related to the voltage level and grid element loading limits are complied with.

The set values correspond to the unavailability cases described for each regime and to a structure of units forecasted for the relevant period. These values change in case additional line unavailabilities occur within the NPS or if the system operates with a different distribution of generated powers. The changes are analyzed during the daily scheduling of the NPS operational regimes.

5.8.1.1. Calculation assumptions According to the Technical transmission grid code, the cross-zonal power transmission grid must ensure a steady-state stability reserve of minimum 20% within a configuration of N operational elements and of minimum 8% with N-1 operational elements. Currently, the following regions in the NPS are designated as characteristic sections, in terms of steady-state stability (Figure 5.8): Section S1 – Oltenia region, delimited by the following power lines:

o Slatina-Bucuresti Sud 400 kV OHL; o Urechesti-Domnesti 400 kV OHL; o Tantareni-Bradu 400 kV OHL; o Tantareni-Sibiu 400 kV OHL; o Tantareni-Kozlodui 400 kV OHL (d.c.); o Portile de Fier-Djerdap 400 kV OHL; o Portile de Fier-Resita 220 kV OHL (d.c.); o Targu Jiu-Urechesti 220 kV OHL; o Craiova-Turnu Magurele 220 kV OHL. Section S2 (East of the Iernut-Sibiu-Tantareni-Slatina axis), delimited by the following power lines: o Urechesti-Domnesti 400 kV OHL; o Slatina-Bucuresti Sud 400 kV OHL; o Brasov-Sibiu 400 kV OHL; o Tantareni-Bradu 400 kV OHL; o Isaccea-Dobrudja 400 kV OHL; o Varna-Isaccea 400 kV OHL; o Iernut-Ungheni 220 kV OHL (d.c.); o Craiova-Turnu Magurele 220 kV OHL; o Iernut-CIC 110 kV OHL (d.c); o Iernut-Tarnaveni 110 kV OHL (d.c) o Sibiu Nord-Copsa Mica 110 kV OHL; o Fagaras-Hoghiz 110 kV OHL. Section S3 – region of Moldova, Dobrogea and a part of Muntenia, delimited by the following power lines: o Brasov-Gutinas 400 kV OHL; o Bucuresti Sud-Pelicanu 400 kV OHL; o Bucuresti Sud-Gura Ialomitei 400 kV OHL; o Rahman-Dobrudja 400 kV OHL; o Stupina-Varna 400 kV OHL; o Gheorghieni-Stejaru 220 kV OHL; o Dragos Voda-Slobozia Sud 110 kV OHL.

Section S4 – Northern Transilvania region, delimited by the following power lines: o Sibiu-Iernut 400 kV OHL; o Rosiori-Mukacevo 400 kV OHL; o Gheorghieni-Stejaru 220 kV OHL; o Cluj Floresti-Alba Iulia 220 kV OHL; o Nadab-Oradea Sud 400 kV OHL. Section S5 – Moldova region, delimited by the following power lines: o Brasov-Gutinas 400 kV OHL; o Smardan-Gutinas 400 kV OHL; o Barbosi-Focsani 220 kV OHL; o Gheorghieni-Stejaru 220 kV OHL.

Section S6 – the region of Dobrogea and a part of Muntenia, delimited by the following power lines: o Smardan-Gutinas 400 kV OHL; o Barbosi-Focsani 220 kV OHL; o Bucuresti Sud-Pelicanu 400 kV OHL; o Bucuresti Sud-Gura Ialomitei 400 kV OHL; o Rahman-Dobrudja 400 kV OHL; o Stupina-Varna 400 kV OHL; o Dragos Voda-Slobozia Sud 110 kV OHL.

The calculation for all sections was conducted under the basic regime, in a configuration where the Nadab-Oradea Sud 400 kV OHL is not commissioned.

Figure 5.8 Characteristic sections for the NPS steady-state stability analyses

5.8.1.2. Results of steady-state stability analyses

The results' summary of the analyses performed for the last four analysis seasons is presented as follows:

Table 5.8.1 for the 2015-2016 winter section Surplus [MW] Deficit [MW] No. Section Element that generated the threshold value Pres st. st Padm Pres st. st Padm Tripping of the Portile de Fier-Resita 220 kV 1 S 1 4,520 2,280 - - OHL (d.c.) Tripping of the Craiova Nord-Turnu Magurele 2 S 2 - - 3,380 2,170 220 kV OHL 3 S 3 - - 590 490 Tripping of the Brasov-Gutinas 400 kV OHL 4 S 4 - - 1,260 1,000 Tripping of the Sibiu Sud-Iernut 400 kV OHL 5 S 5 - - 930 630 Tripping of the Smardan-Gutinas 400 kV OHL 6 S 6 4,860 2,980 Tripping of the Smardan-Gutinas 400 kV OHL

Table 5.8.2 for the 2016 summer section Surplus [MW] Deficit [MW] No. Section Element that generated the threshold value Pres st. st Padm Pres st. st Padm 5,7101 Tripping of the Portile de Fier-Resita 220 kV ) 3,4401) OHL (d.c.) 1 S 1 - - 4,2601 2,6602) ) 1,8501 Tripping of the Craiova Nord-Turnu Magurele 2 S 2 - - 3,5101) ) 220 kV OHL 3 S 3 - - 1,1101) 9201) Tripping of the Brasov-Gutinas 400 kV OHL 1,0102 4 S 4 - - 1,2502) Tripping of the Mukacevo-Rosiori 400 kV OHL ) 8801) 8001) Tripping of the Brasov-Gutinas1) 400 kV OHL, 5 S 5 - - 8702) 3302) Smardan-Gutinas2) 400 kV OHL 4,5002 6 S 6 2,9402) Tripping of the Smardan-Gutinas 400 kV OHL ) 1) without WPP generation; 2) with WPP generation.

Table 5.8.3 for the 2016-2017 winter section Surplus [MW] Deficit [MW] No. Section Element that generated the threshold value Pres st. st Padm Pres st. st Padm 5,4802 Tripping of the Portile de Fier-Resita 220 kV 1 S 1 2,6502) - - ) OHL (d.c.) 2,3201 Tripping of the Urechesti-Domnesti 400 kV OHL 2 S 2 - - 3,1601) ) 3 S 3 - - 5301) 5201) Tripping of the Brasov-Gutinas 400 kV OHL 4 S 4 - - 1,2802) 8802) Tripping of the Iernut-Gadalin 400 kV OHL 5 S 5 - - 8601) 8501) Tripping of the Brasov-Gutinas1) 400 kV OHL,

Surplus [MW] Deficit [MW] No. Section Element that generated the threshold value Pres st. st Padm Pres st. st Padm 6202) 5102) Smardan-Gutinas2) 400 kV OHL 4,8502 6 S 6 3,0602) Tripping of the Smardan-Gutinas 400 kV OHL )

Table 5.8.4 for the 2017 summer section Surplus [MW] Deficit [MW] No. Section Element that generated the threshold value Pres st. st Padm Pres st. st Padm 5,6002 Tripping of the Portile de Fier-Resita 220 kV 1 S 1 2,2002) - - ) OHL (d.c.) 2,6001 Tripping of the Sibiu-Brasov 400 kV OHL 2 S 2 - - 3,7701) ) 3 S 3 - - 1,1401) 9601) Tripping of the Brasov-Gutinas 400 kV OHL 4 S 4 - - 1,1702) 8202) Tripping of the Sibiu-Iernut 400 kV OHL Tripping of the Roman Nord-Bacau Sud1) 400 kV 8401) 7601) 5 S 5 - - OHL, Tripping of the Smardan-Gutinas2) 400 kV 9302) 4402) OHL 4,8002 6 S 6 2,9202) Tripping of the Smardan-Gutinas2) 400 kV OHL )

The admitted limit flows on PTG elements must range between the deficit/surplus values determined by the steady-state stability calculation.

5.8.1.3. Analysis of NPS characteristic sections in terms of steady-state stability conditions Section S1 The results' analysis shows that the value with rated reserve amounts to 4,260 MW (determined in the 2016 summer regime with WPP generation), and the value of the minimum admissible power related to the section (S1 Oltenia) amounts to 2,200 MW (determined in the 2017 summer regime with WPP generation). Limits are recorded upon tripping of the Portile de Fier-Resita 220 kV OHL (d.c.), this being the most restrictive case. For a transit of over 1,990 MW, the maximum admissible current of the CT is exceeded on the Urechesti-Targu Jiu 220 kV OHL. Section S2 The rated reserve power in S2 amounts to ca. 3,160 MW (determined in the 2016-2017 winter regime), and the value of the minimum admissible power amounts to 1,850 MW (determined in the 2016 summer regime), a value over which the rated voltage is exceeded. The limits are recorded upon tripping of the Craiova Nord-Turnu Magurele 220 kV OHL. Section S3 The rated reserve power in S3 amounts to ca. 530 MW (determined in 2016-2017 winter regime) and 490 MW respectively (determined in the 2015-2016 winter regime). The limits are recorded

63 upon tripping of the Brasov-Gutinas 400 kV OHL under S3 deficit regime (without WPP generation). The construction of new lines and the restructuring of the 400 kV grid in the Dobrogea area are needed. Section S4 The rated reserve power in S4 corresponding to grid voltages and current flows on grid elements beyond the rated limits is of ca. 1,170 MW (determined in the 2017 summer regime), and the value of the minimum admissible power amounts to 820 MW (determined in the 2017 summer regime). Both limits are recorded upon tripping of the Sibiu Sud-Iernut 400 kV OHL.

Section S5 The most restrictive value of the rated reserve power amounted to 840 MW (determined in the 2017 summer regime, without WPP generation), achieved upon tripping of the Roman Nord-Suceava 400 kV OHL. The value of the minimum admissible power amounts to 330 MW (determined in the 2016 summer regime, with WPP generation), coinciding with the tripping of the Smardan-Gutinas 400 kV OHL. Section S6 The most restrictive value of the rated reserve power amounted to 4,500 MW (determined in the 2016 summer regime), achieved upon tripping of the Smardan-Gutinas 400 kV OHL. The value of the minimum admissible power amounts to 2,920 MW (determined in the 2017 summer regime), coinciding with the tripping of the Smardan-Gutinas 400 kV OHL, a value over which the 100% value of the CT current on the Filesti-Barbosi 220 kV OHL is exceeded.

Weak points identified in the PTG in terms of steady-state stability

Congestions occur in the S3 and S6 sections: – upon tripping of the Smardan-Gutinas 400 kV OHL, determined by the overload on the Barbosi-Filesti 220 kV OHL; – upon outage of the Brasov-Gutinas 400 kV OHL, determined by the overload on the Barbosi- Filesti 220 kV OHL.

The identified congestions lead to imposing admissible powers through the characteristic sections below the rated reserve power for steady-state stability (P8% or P20%).

5.8.2. Transient stability and potential improvement measures 5.8.2.1. Methodology and calculation assumptions

The biannual studies for operational scheduling of the NPS operation for the period 2016-2017 conducted transient stability analyses, aiming to: – verify the transient stability in areas with large power plants which might affect the NPS and interconnection stability and integrity (Portile de Fier, Cernavoda); – identify dangerous fault points and scenarios; – identify outages significant to the stability of an area, the NPS and the interconnection; – identify outages which require generation restrictions;

– determine restrictions and conditionings necessary to ensure the NPS and the interconnection stability and integrity conditions, including the ones regarding the coordination of outage schedules and preventive operative measures in the interconnected grid; – verify the logic and efficiency of system automations; – ensure the dynamic behavior of wind power plants and the effect of the increased wind generation over the Dobrogea groups' stability; – verify stability in the interconnection section of the NPS and identify the stability and actuating limits for system automations. The verification of transient stability and system automations was conducted for the interconnected operation of the NPS with the synchronous Continental Europe grid via the Portile de Fier-Djerdap 400 kV OHL, the Tantareni-Kozlodui 400 kV OHL circ. 1, the Rahman-Dobrudja 400 kV OHL, the Stupina-Varna 400 kV OHL, the Arad-Sandorfalva 400 kV OHL, the Nadab- Bekescsaba 400 kV OHL and the Rosiori-Mukacevo 400 kV OHL. The verification of the transient stability was conducted on grid operational schemes which included the outages provided in the Annual Outage Plan (AOP), necessary for the NPS refurbishment works in the respective period. The NPS dynamic model included the latest data on the modernization of the groups' control systems and the commissioning of new or refurbished groups. The permanent regime model for the external system was based on data provided by transmission system operators within the ENTSO-E specialized workgroup. The generators from Serbia, Montenegro, Bulgaria, Hungary, Ukraine – Burshtyn Island, Macedonia, Greece, Albania, Slovakia, Bosnia and Herzegovina, Slovenia, Croatia and Turkey were dynamically modeled, while the rest of the interconnected grid were modeled in a more simplified way. Depending on the purpose of the analyses, simulations were made for: – the maximum number of operational groups in power plants from the analyzed area, loaded up to their nominal power, with different WPP generation scenarios (0-100% of the installed capacity); – the long-term operation scheme, different schemes with 1-2 decommissioned elements in the NPS and the interconnection (Portile de Fier, Cernavoda areas); – different hypotheses on the exchanges between the NPS and the interconnection. Depending on the purpose of the analyses, different scenarios were considered related to a fault with metallic three-phase short-circuit on the busbar, line or (auto)transformer, isolated by correctly actuating the protections and breakers via differential busbar protection and distance protectors with remote protection, if any, or differential line or (auto)transformer protections. Calculations were conducted with and without actuating the system automations. The dynamic simulation software EUROSTAG version 5.1 was used.

5.8.2.2. Conducted analyses

The studies for operational scheduling of the NPS operation for the period 2016-2017 conducted transient stability analyses, including:

. Verifying the stability of groups in the Cernavoda area with installed wind generation in the NPS forecasted for the respective period, identifying the possibility to grant 1-2 outages in the Dobrogea area and the potential generation restrictions necessary in the complete scheme and in schemes with PTG unavailabilities, evaluating the analysis sensitivity to the load section, the effect of implementing voltage control at WPP level;

. Verifying the stability of the groups in the Portile de Fier area, as well as the interconnection, verifying the logic and efficiency of system automations, identifying potential generation restrictions in schemes with two decommissioned elements. The analyses were conducted for average load peak and off-peak regimes in different hypotheses regarding the balance on the synchronous interconnection 400 kV OHLs of the NPS.

5.8.2.3. Weak points identified and potential improvement measures . Cernavoda area: • In the peak load section and operating with 2 units in the Cernavoda NPP, the outage of a 400 kV OHL from Cernavoda or from the area may lead to the need to limit the WPP generation in order to maintain the transient stability of units from the Cernavoda NPP and the area in the event of an isolated three-phase short-circuit without delay, which leads to a configuration with reduced capacity to discharge the WPP generation from the Dobrogea area or from an area which includes Dobrogea and one or all areas of Gura Ialomitei, Lacu Sarat and Smardan, Rahman, Stupina; • In the off-peak load section and operating with 2 units in the Cernavoda NPP, a need may occur to limit the WPP generation in the Tulcea area, even in the complete scheme, in order to maintain the transient stability of units from the Cernavoda NPP and the area in the event of an isolated three-phase short-circuit without delay, which leads to a regime which highly deviates from the short term stability limits and which is instable in the mid-term. WPP generation restrictions for schemes with one decommissioned element are more relevant in the night low section compared to the peak load section; • Prolonged time for eliminating faults in the Isaccea and Smardan substations. We highlight the need to consolidate the PTG in the Dobrogea area and the area surplus discharge section, including from the 110 kV grid. Connecting the Bulgaria interconnection 400 kV OHL from this area in the Medgidia Sud 400/110 kV substation and building a new Gutinas- Smardan 400 kV OHL d.c. allows for the avoidance of increases in frequency and generation restriction number, assuming that the WPP installed capacity will continue to rise. The Isaccea 400 kV and Smardan 400/110 kV substations should be refurbished with priority. . Portile de Fier area: • There are schemes including 2 simultaneous outages in the Portile de Fier + Djerdap and interconnection node, given that certain fault scenarios might endanger the transient stability of the area and the interconnection, requiring the coordination of outages with the generation in the Portile de Fier and Djerdap HPP and with the surplus from interconnection sections. The measures for improving the stability of groups from the Portile de Fier and interconnection area are the following: constructing the Portile de Fier-Resita-Timisoara-Arad 400 kV axis and constructing a new Serbia interconnection 400 kV OHL.

5.9. Continuity level of the electricity transmission service The continuity in operation represents one of the quality parameters of the transmission and system services. The assessment of the safety level in ensuring the service provided in a certain PTG point, under normal operational conditions, is an important prerequisite in order to ensure an efficient

66 transmission service by CNTEE Transelectrica SA and for the good operation of energy market itself. In terms of continuity of supply, the transmission service performance indicators, as defined in the current PTG technical code, are reported to ANRE periodically.

Average interruption time (AIT) Performance parameter which is calculated as follows: EN TMI  8760 60  EC [minutes/year] or EN TMI  8784 60  EC [minutes/year] in leap years Where: EN is the energy not delivered due to interruptions in the transmission service [MWh/year], EC is the net annual demand in the power system (without the own technological consumption) [MWh/year].

Severity indicator (SI) Transmission service performance parameter, which estimates (based on the yearly average time of interruption – AIT) the average duration of an interruption in the transmission service: TMI IS  NI [minutes/interruption] where NI is the yearly number of PTG incidents, accompanied by interruptions in consumer supply.

System minutes (SM) indicator Transmission service performance parameter, which estimates the yearly average duration of an interruption in relation to the annual demand peak: EN[MWh / an] 60 MS  PV [MW] [system minutes] Where: EN is the energy not delivered due to interruptions in the transmission service [MWh/year] PV is the annual demand peak [MW]. Table 5.9.1 and Figure 5.9.1 summarize these parameters for the 2012-2016 period.

Table 5.9.1 PTG performance indicators Year 2012 2013 2014 2015 2016 Average time of interruption [minutes/year] 1.53 0.35 0.82 0.36 2.11 Severity indicator [minutes/interruption] 0.06 0.03 0.034 0.03 0.10 System minutes indicator [system minutes] 0.75 0.29 0.59 0.27 1.54

2.5 2.11

2 1.53 1.54 1.5

0.82 1 0.75 0.59 0.36 0.5 0.35 0.29 0.27 0.06 0.10 0.03 0.034 0.03 0 2012 2013 2014 2015 2016

Timpul mediu de întrerupere [minute/an] Indicatorul de severitate [minute/întrerupere] Indicatorul "minute sistem" [minute sistem]

Figure 5.9.1 NPS performance indicators

The evolution of the severity (SI), system minutes (SM) and average interruption time (AIT) indicators is random; the indicators mainly reflect the number of incidents related to the energy not delivered to consumers. Therefore, in 2016 we had a total number of incidents 5% lower compared with 2015, but the energy not delivered rose compared to 2015. The average time of interruption in 2016 rose compared to 2015, as well as the NPS severity indicator. The main causes leading up to these results have generally been unfavorable meteorological conditions (rain with lightning and storms), grown out vegetation, increased level of the hydro component in river structures. CNTEE Transelectrica SA reports the performance indicators to ANRE, in line with the requirements set forth by the "Performance standard for the electricity transmission service and system services", approved by the National Energy Regulatory Authority (ANRE) Order no. 12/2016. According to this standard, information regarding the transmission service is reported: PTG management and operation, service continuity, quantified via performance indicators presented in the table below. Table 5.9.2 Indicator 2012 2013 2014 2015 2016  Average time unavailability of OHLs and transformers/autotransformers  OHL – TOTAL line unavailability 203.3 114.52 142.59 184.63 186.79 [hours/year] Unscheduled (accidental) 24.72 11.44 27.97 36.68 16.88 Scheduled 178.58 103.08 114.62 147.95 169.91  Transformers/autotransformers – TOTAL 190.35 171.58 112.18 155.01 204.29

Indicator 2012 2013 2014 2015 2016 transformer unavailability [hours/year] Unscheduled (accidental) 9 3.27 8.52 8.9 4.91 Scheduled 181.35 168.31 103.66 146.11 199.38  Number of incidents 609 473 527 574 548  Energy not delivered to users/energy not 137.44 30.89 82.51 38.36 224.69/2 generated in power plants due to long term 64.70 interruptions [MWh]  Number of incidents involving undelivered 21 12 24 14 28 energy  Average interruption time to users/average 1.53 0.35 0.82 0.36 2.11/2.49 time of interruption in power plants AIT [minutes/year]

After an upward evolution in 2013-2015, in 2016 we see a decrease in unscheduled interruptions indicators. For scheduled interruptions in power lines, after a decrease in 2013, we see an increase in the average time of interruption in the 2013-2016 period. For transformers and autotransformers, we see an increase in the average time of interruption in the 2014-2016 period, compared to the downward evolution from the previous period. The evolution of these indicators is explained by maintenance works with a prolonged period of time for the compliance of transformers and power lines with technical parameters (12 works), due to the equipment age, and by investment works for replacing large transformation units according to the investment plan. Measures: correlating the maintenance programs with the investment programs in order to reduce the equipment outage duration, analyses and expertise for transformation units and overhead power lines with an exceeded rated lifetime, which are still in operation until ensuring the replacement conditions and major repair works, achieving provisional technologies, using intervention beams, using mobile bays, multispectral inspections with fast and punctual interventions. Regarding the service continuity indicators (ENS and AIT), the values recorded in 2016 have been decisively influenced by a single incident which had a significant negative impact over indicators. On 01.06.2016, between 15:58 and 16:33, as a result of very high temperatures, grown out vegetation in the month of May, increased hydro component in the structures on the Olt, Arges and Dambovita rivers and the accidental outage of the Bradu-Arefu 220 kV OHL, in the areas of Valcea and Arges counties a series of successive engagements occurred in the electricity transmission and distribution grid, which led to an interruption in the electricity supply of the northern areas of the two counties; the interruption also influenced the industrial areas of the Ramnicu Valcea, Curtea de Arges and Campulung Muscel municipalities. The affected users were consumers (industrial and domestic) and power plants. This incident had the largest impact over the ENS indicator. The incident resulted in the failure to deliver a ca. 135.49 MWh quantity of electricity to consumers (ca. 60% of the total annual ENS to consumers) and the failure to generate a ca. 209.90 MWh quantity of electricity (ca. 79% of the total annual ENS to generators). Considering the causes of this incident, the propagation of the triggering incident from the PTG at PDG level, as well as the size of consequences quantified via the ENS indicator, in order to attribute the energy not

69 supplied to operators involved in the triggering and propagation of the incident, the companies CNTEE Transelectrica SA, CEZ Distribuție and SPEEH Hidroelectrica conducted a common analysis report. The status of the ENS indicator in 2016, recalculated by excluding the aforementioned incident, is the following: ENS to consumers – 89.20 MWh (compared to 224.69 MWh with the inclusion of the incident), ENS to generators – 54.80 MWh (compared to 264.70 MWh with the inclusion of the incident). The status of the AIT indicator in 2016, recalculated by excluding the energy not supplied as a result of the aforementioned incident, is the following: AIT to consumers – 0.84 min (compared to 2.11 min with the inclusion of the incident), AIT to generators – 0.52 min (compared to 2.49 min with the inclusion of the incident). The causes of the ENS and AIT indicators' evolution are: - Technical wear and tear of equipment under normal operational conditions; - Extreme nature events.

Measures to improve the ENS and AIT indicators: - Reanalyzing the technical design conditions of facilities, considering the weather and climate changes: o Revision of the design standard for OHLs, NTI-TEL 003/04: Standard on the construction of overhead power lines with voltage levels over 1000 V. o Analysis, via modern computing programs, of the structural capability of PTG overhead power lines in order to improve the NPS operational capacity under safety and stability conditions. Verifications consist of the analysis via computing programs, in line with the most modern design concepts. Therefore, the computing program allows a 3D modelling of the entire OHL structure, also including elements related to the land's topography, and offer the full range of functionalities necessary for the verification and analysis of an overhead power line, such as: . structural analysis of all the line's elements (towers, isolator chains, conductors); . simulations regarding the behavior of the overhead power line in different scenarios (special weather conditions, mechanical or electrical overloads, etc.); . establishing preventive measures necessary for increasing operational safety; . upgrading and adapting existing overhead power lines to new conditions (weather, loads); . electric and magnetic field calculations; . calculation regarding the transmission capacity of OHLs. - Replacing worn out equipment with efficient ones, within the maintenance and investment program. In order to evaluate the service continuity indicators in a certain PTG point, in line with the provisions of the PTG technical code, it is necessary to determine the safety indicators calculated for each PTG node [12]. The calculation of these indicators quantifies the service continuity level that the PTG may provide, at the level of substation busbars pertaining to the PTG from the relevant area. The PTG technical code requires the calculation of the following indicators for each PTG node: (a) average interruption duration; (b) average number of interruptions followed by repairs; (c) average number of interruptions followed by maneuvers.

Knowing the service continuity indicators on PTG busbars, the indicators of continuity in user delimitation points can be calculated, by taking into consideration the reliability indicators related to the connection of each user (client), which defines the continuity in operation provided by power grids connecting the PTG substations and the actual connection point. The calculation of safety indicators enables both the grid operator and the users to assess the influence of the relevant node connection to the PTG (by determining the related safety level), as well as the influence of the node's own connection and of equipment reliability parameters (by determining the inherent safety level). These elements are used during the stage of establishing the optimal solutions for grid development and user connection to the grid. The safety indicators determined for each substation owned by CNTEE Transelectrica SA are the following: - success and failure probability; - annual average interruption duration (hours/year); - average number of long-term interruptions (eliminated by repairs); - maximum number of long-term interruptions (eliminated by repairs); - average number of interruptions eliminated by maneuvers; - maximum number of interruptions eliminated by maneuvers; - maximum duration of an interruption. The analysis results [12] show the following: - The substations' refurbishments as provided in the analyzed stages lead to an improvement in the safety node indicators for all substations subject to refurbishment. If the substation subject to refurbishment is a source node for other substations, improved indicator values are seen for this substation as well. - For the double-bar and transfer bar 400 kV and 220 kV substations subject to refurbishment where the transfer bar was disposed of, the improvement is obvious in the number of interruptions and average failure times, the maximum interruption time staying the same, with deviations above or below. - Generally speaking, for substations not subject to refurbishment, a change in the indicators may be noted as a result of the associated change in safety. Thus, the effect of the refurbishment of neighboring substations represents to a certain extent, in all cases, a reduction in the number of interruptions; however, as the line parameters, in particular their repair times, stayed the same as the ones provided in the NTE 005 PE 005/06/00, the maximum interruption durations remain high. A sensitivity analysis was conducted regarding the incurred risk level. Therefore, for all analyzed stages, for a maximum interruption duration, the calculations have been carried out with a completion probability of 10% and 5% respectively. In terms of continuity in service provision, it is to be specified that, for substations not refurbished/modernized, keeping the indicators close to the values required by European standards is achieved at increased costs due to the necessary preventive and corrective maintenance works. The indicators will be improved, particularly in terms of interruption duration (average and maximum), by refurbishing the lines and substations and by reducing the fault remedy duration using high performance management technologies and systems.

5.10. The operative dispatching management system – EMS/SCADA-NPD In order to monitor and manage the NPS, CNTEE Transelectrica SA uses a complex EMS/SCADA-type process information system, specific for dispatching management. This system acquires and processes data in real time, necessary for the real time monitorization and operational management of the NPS, including remote control under safety conditions for actuator elements in refurbished substations. The system is logistically supported by a complex communications network, as well as the PTG substation modernization and refurbishment process. Therefore, in 2001, CNTEE Transelectrica SA started the construction of the entire technical infrastructure to support the efficient management of the transmission system and the NPS, which also included the EMS/SCADA system (installed in 2003 and fully operational in 2005, after the testing period), the communication lines and optical fiber telecommunications equipment, the modernization of substations and the metering system dedicated to the wholesale market. The telecommunications network is based on the existing regional optical fiber infrastructure (ca. 5,800 km), with OPGW and OPUG technology and 36 optical fibers. Information is transmitted using an SDH-type telecommunications network with a 2.5 Gbps capacity with ring technology and 10 physical rings. This ring technology, as well as the SDH-type equipment, ensure the redundancy of information transmitted through the telecommunications network. Where the physical infrastructure does not allow the construction of optical rings, radial connections of optical fiber have been constructed using SDH equipment, which ensure a transmission capacity of 155 Mbps (STM1). Collecting the EMS/SCADA signals from substations is carried out via equipment in the main SDH telecommunications network. In locations where there is no access to the optical fiber infrastructure, radio connections are used via equipment with a maximum capacity of 4 x E1 (4 x 2Mbps), and where no radio connections can be used, CNTEE Transelectrica SA uses classical leased telecommunication lines or even satellite connections in order to transmit data to the TPD/CPD. CNTEE Transelectrica SA further extends this telecommunications infrastructure by installing OPGW and OPUG-type protection conductors with optical fiber core on 220 kV and 400 kV overhead power lines (ca. 4,000 km are completed in this way). The national optical fiber network also includes, in addition to the internal OPGW network, the optical interconnections with neighboring electricity companies from Hungary, Bulgaria and Serbia, as well as metropolitan optical connections and optical connections with other companies/internal operators. The EMS/SCADA-NPD system is supplied and implemented by the company AREVA (currently ALSTOM). This system is designed and developed based on the e-Terra Control Platform version 2.2, a version released in the year of putting into service (2003). The system is hierarchically structured, as follows: - Central Power Dispatcher (CPD); - Reserve Dispatcher (RD) that has redundant communication links with the CPD; - Five territorial dispatching centers (TPDs) across the country;

- An Emergency Dispatching Center (EDC) in another location, aiming to ensure the operational management of the NPS in the event of a disaster at the CPD location. The EDC runs the same software as the CPD; - Two interfaces similar to the ones from the TPD for the AGC function (automated secondary control of frequency – exchange power) related to the CPD and the Emergency Dispatching Center. All TPDs are physically connected to the CPD/RD via a redundant communication network. The same 2 Mbps connection types also exist in each TPD for the operation under conditions similar with the EDC location. All signals in substations are transmitted to the Territorial Power Dispatching Centers, exception being made for the power plants participating in the automated secondary frequency control and the lines interconnecting with neighbors, which, for security reasons, are transmitted to the 2 interfaces similar to the ones in the territorial dispatchers. Therefore, the interconnection substations and power plants with AGC groups communicate directly with the Central Power Dispatcher. Once it reaches the Territorial Dispatchers, the information is retransmitted to the Central Power Dispatcher via E1- type connections, using the main network. The application for the balancing market runs on a separate and dedicated information platform. Each server and work station are equipped with the latest version of HP software packages available at the time of the order. The EMS/SCADA-NPD system ensures the main specific functions: data acquisition, monitoring, events signaling and management, energy management, secondary load-frequency control, optimization and security of the national power system operation, remote control of equipment, archiving as well as a complex software environment for training dispatchers. At the same time, it represents the automation system at the upper level of a subsystem hierarchy. The central EMS/SCADA system exchanges information with regional control systems, generators' control systems, automation and control systems from substations, market systems as well as external systems, forming a compound global operational structure. For this redundant server system with dedicated functionalities, access, control and system security mechanisms are provided. The system equipment, the servers and the concentrators are synchronized via GPS. The data exchange with systems from the interconnected grid and ENTSO-E coordination centers is also ensured via the 2 ENTSO-E information nodes connected to the common grid of the interconnection, the Electronic Highway (EH), in line with the requirements provided by the ENTSO-E operation standards. The common (single) ENTSO-E system for awareness and signaling – EAS was also implemented. The hardware equipment of the current EMS/SCADA system, the associated communication equipment as well as the conceptual development level of software applications are outdated, being at the limit of their capacities of ensuring operational support for the TSO in terms of the NPS operational management. Maintaining them under appropriate operational conditions is carried out at increasingly high costs, considering that manufacturers have discontinued this equipment and the software updates are becoming more and more difficult to carry out, given that in time, numerous versions have been released which accentuate the degree of incompatibility with the current one. Currently, a system hardware and software rehabilitation project are undergoing, in order to increase and ensure the operational capacity until the acquisition and installation of a new system in the course of the following 5-6 years.

To the same extent, the data interface between the constituent systems is based on outdated technologies. IT and communications equipment and technologies have progressed to a significant extent since putting the EMS/SCADA system into service (started in 2003, when the testing period was initiated) and since the development of interfaces with generators', substations' and ENTSO-E's equipment. Fundamentally, the current systems' interconnections use serial telemetry and file exchanges, while technologies have evolved to telemetry based on IP technologies and the integration of this type of systems.

5.11. Ancillary services In order to provide ancillary services, CNTEE Transelectrica SA uses its own resources (functional services provided) and the ancillary services provided by suppliers against remuneration or based on an obligation provided in the PTG technical code. Ancillary services ensure the release of certain reserves from the system (secondary control, fast tertiary reserve and slow tertiary reserve, capacity reserve), necessary for the safe operation of the NPS under the necessary electricity quality conditions. Ancillary services are provided by PTG users and are used by Transelectrica in order to ensure: . the compensation for the load variation in the NPS, namely the frequency and NPS balance control; . the compensation for the differences from the NPS groups operational program, namely maintaining active power reserve capacities; . PTG voltage control; . restoring the operation of the NPS after a total or zonal breakdown.

Ancillary services are carried out with the following resources: . primary frequency control systems of generating units; . automated secondary load-frequency control system; . power reserves; . local voltage control systems; . automated systems for isolating on own services and auto-starting of groups in order to restore the operation of the NPS after a total or zonal breakdown; . dispatchable consumers that decrease their load or may be disconnected at Transelectrica's request. CNTEE Transelectrica SA provides the system service for all NPS components, paying, per MWh, a tariff regulated by ANRE for the reserve quantities purchased under regulated regime; the Company also holds auctions for covering the differences between the quantities necessary and the ones regulated by ANRE, paying the auction clearing price per MWh for each time frame and reserve type. The regulated tariff for the system service is established in line with the "Methodology for determining the tariffs for the system services" developed by ANRE, which takes into consideration the generators' justified costs, while complying with the quality standards provided in the PTG technical code. This covers expenditures with ancillary and functional system services, as well as with operating the balancing market.

According to the provisions of the PTG technical code, the ancillary services suppliers are qualified by Transelectrica through specific procedures. These procedures also include possibilities to grant limited exceptions in order to comply with qualification requirements. PTG users which were qualified to this effect may conclude ancillary services supply contracts. The status of the groups' and suppliers' qualification for the execution of ancillary services for 2017 is shown in Annex B-8. During 2012-2017, ancillary services were procured both under regulated, and under competitive regime (auctions) in order to cover the needs. The status of purchase and fulfilment of ancillary services during 2012-2017 is shown below:

Year 2012

Number of

situations in which

Service type UM the requested service was not

provided

Necessary Regulated Contracted Accrued Accrued the from contract Accrued the from necessary Secondary regulation MWh 3,507,500 3,156,750 3,304,115 2,713,293 82.12% 77.36% - range Fast tertiary reserve MWh 7,905,600 6,324,480 7,019,187 5,259,502 74.93% 66.53% - Slow tertiary reserve MWh 6,045,600 3,022,800 4,846,317 3,668,640 75.70% 60.68% - Reactive energy hMVAr 15,920 15,920 15,920 15,920 100% 100% - Primary control MWh 509,472 - 100% - reserve* * as per ENTSO-E regulations - E (58 MWh)

Year 2013

Number of

situations in which

Service type UM the requested ued ued service was not

provided

Necessary Regulated Contracted Accrued Accrued the from contract Accr the from necessary Secondary regulation 3,499,00 MWh 3,121,380 3,167,320 3,124,232 98.64% 89.29% - range 0 7,884,00 Fast tertiary reserve MWh 6,307,200 6,307,200 6,289,129 99.71% 79.77% - 0 6,132,00 Slow tertiary reserve MWh 4,267,144 5,274,794 5,264,671 99.81% 85.86% - 0 Reactive energy hMVAr 15,920 15,920 15,920 15,920 100% 100% - Primary control MWh 525,600 - 100% - reserve* * as per ENTSO-E regulations - E (60 MWh)

Year 2014

Number of

situations in which

Service type UM the requested service was not

provided

Necessary Regulated Contracted Accrued Accrued the from contract Accrued the from necessary Secondary regulation 3,756,00 MWh 1,662,940 3,607,950 3,586,381 99.40% 95.48% - range 0 6,337,20 Fast tertiary reserve MWh 700,800 5,792,491 5,768,300 99.58% 91.02% - 0 6,453,86 Slow tertiary reserve MWh 6,453,860 6,453,860 6,447,839 99.91% 99.91% - 0 Reactive energy hMVAr 15,920 13,715 13,715 13,715 100% 86.15% - Primary control MWh 499,320 - 100% - reserve* * as per ENTSO-E regulations - E (57 MWh)

Year 2015

Number of

situations in

Service type UM which the requested service

was not provided

Necessary Regulated Contracted Accrued Accrued the from contract Accrued the from necessary Secondary regulation 3,988,70 3,903,93 MWh 767,310 3,891,079 99.67% 97.55% - range 0 5 6,408,10 6,142,92 Fast tertiary reserve MWh 480,890 6,127,188 99.74% 95.62% - 0 0 7,655,92 7,358,32 Slow tertiary reserve MWh 6,304,000 7,351,514 99.91% 96.02% - 0 0 Reactive energy hMVAr 15,223 15,223 15,223 15,223 100% 100% - Primary control MWh 499,320 - 100% - reserve* * as per ENTSO-E regulations - E (57 MWh)

Year 2016

Number of

situations in

Service type UM which the requested service

was not provided

Necessary Regulated Contracted Accrued Accrued the from contract Accrued the from necessary Secondary regulation 3,966,70 3,966,70 MWh 175,680 3,958,198 99.79% 99.79% - range 0 0 6,360,95 6,360,89 Fast tertiary reserve MWh 175,680 6,347,988 99.80% 99.80% - 0 0 6,537,60 6,537,60 Slow tertiary reserve MWh 4,775,040 6,511,710 99.60% 99.60% - 0 0 Reactive energy hMVAr 18,047 18,047 18,047 18,047 100% 100% - Primary control MWh 562,176 - 100% - reserve* * as per ENTSO-E regulations - E (64 MWh)

Year 2017

Number of

situations in

Service type UM which the requested service

was not provided

Necessary Regulated Contracted Accrued Accrued the from contract Accrued the from necessary Secondary regulation 3,960,30 3,960,24 MWh 123,360 3,939,488 99.81% 99.47% - range 0 0 6,117,65 6,117,65 Fast tertiary reserve MWh 175,200 6,077,904 98.93% 99.35% - 0 0 6,468,00 6,467,28 Slow tertiary reserve MWh 4,417,440 6,423,330 99.67% 99.31% - 0 0 Reactive energy hMVAr 16,070 16,070 16,070 16,070 100% 100% - At the request submitted on the grounds of the dispatching license, the primary control reserve was ensured, which is mandatory for all dispatchable groups in line with the obligations provided in the PTG technical code and ENTSO-E regulations on operational security and frequency and balance control. The primary reserve requested from generators complied with the requirement related to a repartition as uniform as possible, while the minimum total value amounted to 57 MW in 2015 and 64 MW in 2016 respectively, in line with the obligations of the NPS within the ENTSO-E interconnected system. The requested primary control reserve was complied with within the daily operational scheduling. During 2013-2017, CNTEE Transelectrica SA purchased no capacity reserves.

5.12. Electricity metering systems and electricity quality monitoring systems

The OMEPA metering branch is a distinct organizational entity at Company level and fulfills the function of Metering Operator at the level of wholesale energy markets. Within CNTEE Transelectrica SA, the OMEPA metering branch fulfills the function of electricity metering operator, electricity quality monitoring operator and metrology operator. The OMEPA metering branch is responsible for the activity of electricity metering and electricity quality monitoring, which is carried out both at the central point, and on site via the operational metering system services of the branch. The OMEPA metering branch is the administrator of the Code for Electricity Metering within CNTEE Transelectrica SA and is responsible with the way in which the provisions within the Code are complied with. The activity is structured on four main pillars:  managing the remote metering system for the wholesale electricity market;  local management of local metering systems;  electricity quality monitoring;  managing the metrology laboratory of CNTEE Transelectrica SA.

The "data metering and aggregation operator" function on wholesale energy markets, carried out by the OMEPA metering branch within Transelectrica, is responsible with the following:

 remote metering of metering points from the "A" category (as per the Code for Electricity Metering) and "B" category for internal services in Transelectrica's substations;  back-up remote metering of interconnection lines (110-220-400 kV);  local metering of metering points for computing and verifying the active and reactive power balances per voltage level in substations;  collecting and aggregating measured data for the wholesale energy market;  validating data for the metering points in which Transelectrica owns metering equipment;  managing the wholesale energy market participants, a function which is performed by OMEPA for the additional purpose of their registration for metering points and own aggregation formulas, with bilateral confirmation;  conducting the physical balance in the NPS;  collecting monthly data from distribution operators that participate in the "bonus type support scheme for promoting the high efficiency generation".

The OMEPA metering branch operates and manages CNTEE Transelectrica SA's metrology laboratory for initial and periodical metrological verifications of electricity meters. The activity carried out by the OMEPA metering branch within metrology laboratories ensures the Company's autonomy regarding its own needs for metrological verifications. The OMEPA metering branch manages and operates the integrated system for electricity quality with fixed quality analyzers, and also owns portable equipment and specialized and attested personnel for monitoring electricity quality parameters. According to the provisions of the regulatory framework, the OMEPA metering branch measures the electricity quality in Transelectrica's substations as well as for users who own WPPs/PVPPs connected to public electricity grids, in order to verify their compliance with the parameters according to the values accepted in the PTG technical code and the applicable electricity quality standards.

5.13. Telecommunications system The telecommunications network represents a basic element of the information system, over which IT services and applications can be implemented and developed to serve end users. Therefore, the concept and implementation of a proper design of the telecommunications network determines the network's capacity to support the implementation of various services and applications required in the Company's activities. In terms of the communications infrastructure, CNTEE Transelectrica SA holds one of the largest national optical fiber networks (approximately 5,800 km) with great data transmission capacity. The largest part of the optical fiber infrastructure is built on the electricity transmission infrastructure, the optical fiber cable being included in the power line protection conductor (OPGW). The OPGW optical fiber infrastructure includes, as communication nodes, the high voltage substations (220 kV and 400 kV) and allows the connection of the country's main power objectives, namely the most important power plants. In addition to CNTEE Transelectrica SA's telecommunications needs, it can also provide for requests from different clients who wish to use the optical fiber network.

The national optical fiber network includes the internal OPGW optical network, the optical fiber interconnections with neighboring electricity companies from Hungary, Bulgaria and Serbia, as well as metropolitan optical fiber connections and optical fiber connections with other companies/internal operators. The optical fiber network allowed CNTEE Transelectrica SA to install specific telecommunications systems, which together form a modern telecommunications network which provides all data-voice-video services necessary for the operation as transmission system operator in the electricity sector. The following were constructed based on the optical fiber network: communications networks which serve the National Dispatcher, systems for securing the Company's and transformer substations' sites, as well as the operative IP telephony. Surplus optical fiber communications capacities are used, via the SC Teletrans SA subsidiary, for the provision of telecommunications services to third parties. The current telecommunications system is based firstly on the Company's own infrastructure, and secondly on communications capacities leased from communication service providers. A microwave-based infrastructure is also used, which ensures operative data-voice communications for the system operator, the electricity metering operator and the balancing market operator. In certain situations where the optical fiber network is unavailable or it is necessary to ensure the redundancy of communications, the Company uses carrier waves systems (PLC) installed on power transmission lines, which ensure the low frequency communications related to the transmissions of equipment for process data acquisition from substations and thermal/hydro/nuclear power plants, remote protection signals on transmission lines, as well as interfacing the Company's private telecommunications system with public systems of other operators.

6. Security of installations and crisis management

In the current international context marked by an escalation of terrorism, in particular in democratic EU states, Romania's country risk must be considered from the national security perspective, as potential target of terrorist attacks. The effects a terrorist attack may have on CNTEE Transelectrica SA's objectives, from the shutdown of power supply in small areas (remote localities) to the disturbance of the entire NPS with disastrous repercussions both for the population, and the economy as a whole, PTG facilities operated by CNTEE Transelectrica SA might be a target for possible terrorist attacks. Furthermore, the Romanian society has witnessed an increase in crimes – both theft, and break-ins in computer networks. In the light of the above, within its organizational structure CNTEE Transelectrica SA has created a unit responsible with crisis management and the protection of objectives designated as national/European critical infrastructures, in line with the legal tasks, namely with: a. Emergency ordinance no. 98/03.11.2010 on the identification, designation and protection of critical infrastructures; b. Emergency ordinance no. 21/15.04.2004 on the National Crisis Management System, approved by Law no. 15/28.02.2005; c. Law no. 329/08.07.2004 approving EO no. 25/2004 amending and supplementing EO no. 88/2001 on incorporating, organizing and operating community public services for emergency situations; d. Law no. 481/08.11.2004 on civil protection; e. Law no. 307/12.07.2006 on the defense against fire as well as the subsequent provisions of law; f. GD no. 718/2011 on the National strategy for the protection of critical infrastructures.

In this regard, CNTEE Transelectrica SA ensured personnel a complex professional training for carrying out tasks derived from legal obligations; the Company has instructed, via competent institutions, a total of 9 security liaison officers in order to cover the necessity to draft the Operator Security Plans (OSP) on site for each national critical infrastructure (NCI) operated by the Company. This complex staff structure, operationally coordinated by the NCI security liaison officer at Company level, also ensures the fulfillment of other objectives at branch level, namely the enforcement, assessment, revision and testing of all OSPs. Therefore, the main missions of the structure responsible with security and crisis management are: 1. Drafting, enforcing, assessment, revision and testing of all OSPs for each NCI operated by the Company; 2. Organizing and coordinating the crisis management activity (civil protection and fire prevention and extinction).

7. Environmental protection related to PTG

7.1. Environmental impact of transmission grids Power transmission grids have a certain negative impact on the environment during their entire lifetime, starting with the "construction-assembly" stage (Table 7.1), further to the "operation- maintenance" stage (Table 7.2), to the final "shutdown" stage. Table 7.1 Significant impacts determined by construction-assembly activities of CNTEE Transelectrica SA facilities

Type of impact Manifestations (effects) Physical  opening of new access routes, soil uncovering and excavations  impact on flora (by deforestation) and fauna (by fragmentation of the wild life habitat)  land occupation with site organization activities, including warehouses  generating waste deposits (metals, ceramic materials, glass, plastic materials, electrical insulation oil, concrete, rubble, packaging, etc.) Chemical  using various chemical products (paints, solvents, reagents, etc.)  soil and water pollution by accidental spillage of oil and other chemical substances from the equipment  flue gas emissions (COx, SOx, NOx, COV, dust) from heating facilities or transportation means  sulphur hexafluoride emissions due to equipment leakages Sonorous  noise made by the operation of equipment and transportation means Social and  disturbance of social activities, including relocations of the economic population

Table 7.2 Significant impacts determined by operation-maintenance activities of CNTEE Transelectrica SA facilities Type of Manifestations (effects) impact Physical  land occupation with OHL routes and substation perimeters  systematic deforestation of vegetation  impact on wild life habitat  obstacles in bird routes  possible accidents resulting in burns or electrocution  sound and light effects of the corona phenomenon

Type of Manifestations (effects) impact  disturbances of radio and television systems  influences on telecommunications facilities or other power grids when crossing each other or in the vicinity of each other  effects of the electromagnetic field on living beings

Visual  impact on the landscape Sonorous  noises made by the operation and vibration of PTG elements  noises made by the corona phenomenon (in very high voltage OHLs) or by the operation of equipment and motor vehicle transportation means Psychologic  fear induced by the PTG surroundings and its visual and sound al effects Chemical  soil and water pollution by accidental spillage of oil and other chemical substances  air pollution by emissions from thermal facilities, motor vehicles, accumulator batteries, sulphur hexafluoride  generation of ozone and azote oxides by the corona effect at high voltage Mechanical  possible danger of collision with aircrafts  danger of fall in the vicinity or crossing of roads, railroads, waterways, buildings, etc.  fire danger as a result of insulation deterioration or accidental contact of conductors with objects or dry vegetation

7.2. Legal requirements applicable to the environmental aspects generated by the Company's activity

The main national regulations on environmental protection, applicable to the environmental aspects generated by the PTG activity are the following:  GEO no. 195/2005 on the environmental protection, as subsequently amended and supplemented; Law no. 265/2006 approving GEO no. 195/2005 on the environmental protection;  Order no. 135/2010 of the Minister for the Environment and Forests approving the Methodology for applying the assessment of the impact on the environment of public and private projects;  Government Decision no. 445/2009 on the assessment of the impact of certain public and private projects on the environment;  Government Decision no. 1.076/2004 setting forth the procedure to carry out environmental assessment for plans and programs;  Order no. 1.798/2007 of the Ministry for the Environment and Sustainable Development approving the environmental permit issuance procedure;

 Order no. 175/2005 of the Ministry of Economy and Commerce on the procedure to report data concerning environmental protection by industrial companies, as subsequently amended and supplemented;  Order no. 1918/2009 of the Ministry of Economy amending Order no. 175/2005 of the Ministry of Economy and Commerce; Law no. 107/1996 – the Waters Act, as subsequently amended and supplemented;  Government Decision no. 173/2000 regulating the control and management regimes of polychlorinated biphenyls and other similar compounds, as subsequently amended and supplemented;  Government Decision no. 188/2002 approving norms regarding the conditions of unloading wastewaters in the aquatic environment, as subsequently amended and supplemented; Law no. 13/1993 on Romania's adhesion to the Convention on the Conservation of European Wildlife and Natural Habitats, adopted in Bern on 19 September 1979;  Order no. 1193/2006 of the Ministry of Public Health approving the Standards on the limited exposure of the general population to electromagnetic fields from 0 Hz to 300 GHz;  Law no. 249/2015 on the management of packages and packaging waste;  Government Decision no. 235/2007 on the management of waste oil;  Law no. 211/2011 on the treatment of waste;  Government Decision no. 5/2015 on electric and electronic equipment waste;  Law no. 89/2000 on the ratification of the Agreement on the Conservation of African- Eurasian Migratory Waterbirds, adopted in The Hague in 1995;  Law no. 360/2003 on the regime of chemical substances and preparations classified as dangerous, as subsequently amended and supplemented;  Law no. 105/2006 approving GEO no. 196/2005 on the environment fund;  Law no. 104/2011 on the ambient air quality;  Order no. 119/2014 of the Ministry of Health approving the Hygiene and public health norms for the population's life environment;  Government Decision no. 856/2002 on keeping record of waste and the waste list, including waste classified as dangerous, as subsequently amended and supplemented;  Government Decision no. 124/2003 on the prevention, reduction and control of environmental pollution with asbestos, as subsequently amended and supplemented;  Government Decision no. 170/2004 on used tire management;  Government Decision no. 349/2005 on the storage of waste;  Government Decision no. 322/2013 on the restrictions to use certain dangerous substances in electric and electronic equipment;  Government Decision no. 321/2005 on the management of environmental noise, as subsequently amended and supplemented;  Law no. 59/2016 on the control of risks of major accidents involving hazardous substances;  Government Decision no. 1.403/2007 on the recovery of areas where the soil, subsoil and terrestrial ecosystems were adversely affected;  Government Decision no. 1.408/2007 on means to investigate and evaluate soil and subsoil pollution;  Government Decision no. 1.132/2008 on the regimes of batteries and accumulators and waste batteries and accumulators;  Law no. 278/2013 on industrial emissions;

 GEO no. 196/2005 on the environmental protection, as subsequently amended and supplemented;  GEO no. 57/2007 on the regime of nature protection areas, conservation of natural habitats, wild flora and fauna, as subsequently amended and supplemented by GEO no. 154/2008;  Order no. 462/1993 of the Ministry of Water, Forests and Environmental Protection for the approval of the Technical conditions for atmosphere protection and Methodological standards on determination of atmospheric polluting agent emissions generated by stationary sources;  Order no. 278/1997 of the Ministry of Water, Forests and Environmental Protection on the framework methodology for drafting plans to prevent and fight against accidental pollution while using potentially polluting water;  Order no. 662/2006 of the Ministry of Environment and Water Management on the Procedure approval, permit issuance competences and water management authorizations;  Order no. 1026/2009 of the Ministry of Environment approving the conditions of drafting the environmental report, the environmental impact report, the environmental balance sheet, the layout report, the security report and the adequate evaluation study;  Order no. 19/2010 of the Minister for the Environment and Forests approving the Methodological guide pertaining to the adequate evaluation of potential effects of plans or projects on nature protected areas of community interest;  Order no. 794/2012 of the Minister for the Environment and Forests on the procedure to report data on packages and packaging waste;  Recommendation no. 110/2004 of the Berne Convention Standing Committee on minimizing adverse effects of above-ground electricity transmission facilities (power lines) on birds.

Due to Romania's membership to the EU, European regulations apply in our country without being transposed into the national legislation. The main European regulations applicable to CNTEE Transelectrica SA's activity are the following: Regulation (EU) No. 517/2014 of the European Parliament and of the Council of 16 April 2014 on fluorinated greenhouse gases and repealing Regulation (EC) No. 842/2006 – Regulation (EC) No. 1907/2006 of the European Parliament and of the Council of 18 December 2006 concerning the Registration, Evaluation, Authorization and Restriction of Chemicals (REACH), establishing a European Chemicals Agency, amending Directive 1999/45/EC and repealing Council Regulation (EEC) No. 793/93 and Commission Regulation (EC) No. 1488/94 as well as Council Directive 76/769/EEC and Commission Directives 91/155/EEC, 93/67/EEC, 93/105/EC and 2000/21/EC – Regulation (EC) No. 1272/2008 of the European Parliament and of the Council of 16 December 2008 on classification, labelling and packaging of substances and mixtures, amending and repealing Directives 67/548/EEC and 1999/45/EC, and amending Regulation (EC) No. 1907/2006, as subsequently amended – Commission Implementing Regulation (EU) No. 2015/2066 of 17 November 2015 establishing, pursuant to Regulation (EU) No. 517/2014 of the European Parliament and of the Council, minimum requirements and the conditions for mutual recognition for the certification of natural persons carrying out installation, servicing, maintenance, repair or decommissioning of electrical switchgear containing fluorinated greenhouse gases or recovery of fluorinated greenhouse gases from stationary electrical switchgear

The main international regulations applicable to the environmental management system are the standard from the ISO 14001 and 19011 series.

Pursuant to the national environment legislation harmonized with the EU legislation, the operation of the power transmission grids is allowed only based on environment and water management permits. An "environment permit for plans and programs", an "environment agreement" and a "water management permit" are required for constructing new objectives or for changing the existing ones via construction and assembly works that change the objective specifications or capacity. These documents are issued by the environment authorities based on the substantiation documentation issued by the beneficiary. The process for obtaining these development permits is much longer for objectives that require expropriation of land and for those that have a cross-border impact (OHLs, undersea cables). In the following period, given Romania's accession to the EU and the PTG interconnected operation with similar systems within ENTSO-E, additional measures are required to reduce the negative environmental impact generated by the PTG construction, maintenance and operation and to obtain environmental and water management permits and authorizations.

7.3. Measures taken to reduce the PTG impact on the environment in 2018-2027 The measures established by the environment protection authorities must be implemented as a priority, both the ones provided in the "conformity programs" that set up environment/water management permit issuance requirements, and those resulted from the periodical verifications conducted in the Company's sites by regulatory and monitoring authorities; The Environment management system will be further improved and it will be kept up to date with the requirements of the ISO 14001:2015 standard; The documentation on investment and maintenance works will include a special chapter on environmental protection with legal requirements, environmental aspects and impacts and measures/actions for eliminating/reducing the environmental impact, which will be outlined physically and value-wise. These measures will be presented in the form of an "Environment Management Plan" that will include environment impact reducing and environment factor monitoring actions both during demolition, construction, operation/maintenance, as well as during shutdown. An estimation of the necessary funds will be made for each action and the necessary recordings will be mentioned. General investment/maintenance estimates will include expenditures for environmental protection. CNTEE Transelectrica SA's service and work providers will be further evaluated considering the legal environmental protection requirements and environment management standard requirements; Environmental management will be further improved, particularly the management of waste and wastewater resulted from the Company's activities; Special attention will be paid to improving oil management by drafting an oil report per substation, as well as collecting and capitalizing on waste oils under environmentally-safe conditions via authorized firms;

The Company will continue monitoring the quality of wastewater disposed of in substations and will undertake corrective measures in order to ensure compliance of their parameters with the maximum limits admissible on disposal; The Company will continue monitoring the electromagnetic field parameters, in particular in OHLs from populated areas, and will continue measuring/monitoring noise at substation boundaries; In order to continually improve the Company's environmental performances, it must make use of all possible information sources and experience exchanges in the field of environment protection with national and international partners; In order to ensure the external communication in the field, the Company shall draft a Chapter regarding environmental protection in its Annual Report. All measures aimed at reducing the environmental impact are included in the Environment management program, approved on a yearly basis at Company level.

8. Technical status of power transmission and distribution grids 8.1. Technical status of the power transmission grid Facilities' lifetime a. Overhead power lines Table 8.1 – OHL lifetime Categorie LEA 110 kV 220 kV 400 kV 750 kV TOTAL Perioda PIF Lungime % din total Lungime % din total Lungime % din total Lungime % din total Lungime % din total (km) categorie (km) categorie (km) categorie (km) categorie (km) categorie 1960-1979 8,9 0,22% 3764,3 97,1% 3613,67 73,5% - 0 7387 83,6% 1980-1999 29,1 0,72% 61,1 1,6% 1150,07 23,4% 3,11 1 1243 14,1% 2000-2017 2,42 0,06% 50,3 1,3% 151,5 3,1% - 0 204 2,3%

83.6% of all overhead power lines have been commissioned between 1960 and 1979, 14.1% have been commissioned between 1980 and 1999 and ca. 2.3% have been commissioned after 2000. We observe a small percentage of commissionings conducted after 2000.

The OHL degree of use, presented in Table 8.2 below, represents the ratio between the actual lifetime and the expected total lifetime of OHLs (48 years). Table 8.2 Commissioning OHL category period 110 kV 220 kV 400 kV 750 kV 1960-1979 110.42% 95.97% 95.43% - Degree of use 1980-1999 61.21% 75.00% 69.63% 64.58% (%) 2000-2017 8.33% 18.18% 16.62% - Note: Constructive voltage levels of OHLs have been taken into account If the same OHL includes towers designed for different constructive voltage levels, the lowest voltage level has been considered. The degree of use per OHL category has been computed as weighted average with the lengths of the lines.

b. Transformers and autotransformers: Table 8.3 – Transformer/autotransformer commissionings Perioada Puterea aparenta a trafo [MVA] TOTAL PIF 10 16 20 25 40 63 100 200 250 400 500 1250 [MVA] % 66 buc. 1960-1979 6 16 1 6 2 - 1 31 1 2 - - 21 7916 MVA Numar 53 buc. Trafo 1980-1999 - 11 - 13 3 - - 13 11 - - 2 22 8471 MVA [buc] 99 buc. 2000-2017 2 6 - 6 4 2 - 38 19 20 2 - 57 21902 MVA

Ca. 21% of the total installed power of transformers/autotransformers has been commissioned between 1960 and 1979, 22% has been commissioned between 1980 and 1999 and 57% after 2000.

The degree of use of transformers/autotransformers, presented in Table 8.4 below, represents the ratio between their actual lifetime and their expected total lifetime (24 years). Table 8.4 – Degree of use of transformers/autotransformers Perioada Puterea aparenta a trafo [MVA] PIF 10 16 20 25 40 63 100 200 250 400 500 1250 1960-1979 182,64 176,04 229 179,17 183,33 - 171 178,63 158 181,25 - - Numar Trafo 1980-1999 - 130,3 - 136,86 127,78 - - 136,86 119,7 - - 131,25 [%] 2000-2017 12,5 19,44 - 11,11 26,04 20,83 - 31,47 37,94 41,66 50,69 -

Note: The degree of use has been computed as arithmetical mean between the degree of use of each (auto)transformer.

Maintenance program Table 8.5 presents the completion degree of the maintenance program per type of works: Table 8.5 – Completion degree of the maintenance program per type of works Program Program completion in completion in Maintenance program 2016 2017 [%] [%] Capital repairs (RK) 43 62 Major 46 64 Common repairs (RC) 48 65 Accidental interventions (IA) 58 82 Technical inspections (IT) 92 99 Special works (LS) 83 75 Minor Materials 42 76 29 79 Common repairs as a result of minor 85 89 maintenance works (RCT) Technical review works (RT) 96 97 Total 66 74

Table 8.6 presents the completion degree of the maintenance program per type of facility:

Table 8.6 – Completion degree of the maintenance program per type of facility Program completion in 2016 Program completion in

[%] 2017 [%] Substations 75 77 OHLs 53 70 Transformers/autotransformers 86 81 Buildings 64 50 Total 66 74

The maintenance program registered a completion rate of 74% in value terms in 2017, compared to the 66% value registered in the previous year.

The highest degree of completion was registered in the minor maintenance sector, namely 79% compared to the program, while the major maintenance program (RK and RC) has registered a degree of completion of 64%. The operational security of the PTG was mainly ensured via the minor preventive maintenance works (IT, RT) with a degree of completion of over 90% – more precisely, the repair works resulted from the minor preventive maintenance activities (RCT) have registered a degree of completion of 89%. The minor preventive maintenance is scheduled on a yearly basis pursuant to the Preventive maintenance regulation in PTG facilities and equipment (NTI-TEL-R-001) and aims at preventing more complex failures with significant consequences on PTG facilities. This type of maintenance also directly reduces the need for accidental interventions (IA); 82% of the allocated amount was used in 2017. Major maintenance (RK, RC) is carried out based on agreements concluded following competitive procurement procedures. In order to increase the degree of completion of major maintenance works, the following measures can be considered, inter alia:  periodical update of maintenance programs, considering the contracted values;  a better correlation of outages for maintenance and investment purposes;  simplifying the process needed to obtain permits and for payment of taxes necessary to commence works;  using simplified procurement procedures.

The technical condition of the power transmission grid is also reflected in the statistics of the incidents occurred in its component equipment. Table 8.7 presents the evolution of the number of incidents. Table 8.7 – Number of PTG incidents Facilities 2010 2011 2012 2013 2014 2015 2016 2017 OHLs 46 44 72 45 55 85 102 85 Substations 770 561 537 428 472 489 447 461 Total PTG 816 605 609 473 527 574 549 546

Compared to 2016, in 2017 we see an increase in the total number of accidental events occurred at the substations' busbars, as well as a decrease in the number of accidental events occurred on the lines as a result of external actions (as per NTE 004/05/00 – impact/contact with conductors, objects fallen on facilities, theft, etc.) Out of the total of 85 OHL incidents, 40% were due to events caused by bad weather/meteorological phenomena, and out of the total of 461 substation incidents, 6% were due to the same causes.

In 2017, CNTEE Transelectrica SA ordered the study "Analysis of the technical condition of the PTG equipment and facilities" [24] which has the following objectives:  Drafting a unitary methodology for the assessment of the technical condition of PTG electrical equipment and facilities – developing a methodology to evaluate the technical

status of PTG primary equipment (power transformers, shunt reactors, breakers, separators, current transformers, voltage transformers, overvoltage surge protective devices) and PTG high-voltage electrical facilities (overhead power lines) based on pre-set criteria;  Implementing the proposed methodology by using a software application owned by the Provider or an Excel sheet in order to assess, by way of example, the technical status of a breaker and a power transformer from each PTG substation (a computation example);  Establishing the main requirements for the procurement of a software application for the analysis of the technical condition of PTG primary equipment (power transformers, shunt reactors, breakers, separators, current transformers, voltage transformers, overvoltage surge protective devices) and PTG high-voltage electrical facilities (overhead power lines). The methodology and its related software application shall allow the assessment of the degree of wear and tear of PTG electrical equipment and facilities, more precisely the substantiation of decisions to undertake maintenance and modernization works, estimating the following benefits:  reducing the number of accidental events;  preventing the degradation of OHL and substation equipment with significant consequences on the safe operation of the power system;  optimizing the operational and maintenance costs;  increasing the operational safety of the NPS;  reducing the economic and social costs for not providing electricity.

Methodology to determine the technical condition of PTG equipment and facilities managed by CNTEE Transelectrica SA Knowing that Asset Management (AM) represents ca. 20-30% of the capital expenditures of a transmission company used for operation, it is a necessity to optimize them without hindering the availability of the transmission grid. In order to reduce costs and improve the grid's reliability, any transmission company must optimize its maintenance strategy and maximize its investment costs over the lifetime of critical assets and components (functional assemblies and subassemblies). Therefore, at the beginning of the assets' useful life, AM concentrates on routine maintenance works (such as time-based maintenance – TBM); afterwards, the asset is subject to rehabilitations, refurbishments and finally to replacement, as a result of its wear and tear and obsolescence. Knowing the factors that lead to wear and tear, electricity transmission companies must optimize AM by applying maintenance strategies focused on a step-wise approach, moving from MBT to condition-based maintenance (CBM) and reliability-focused maintenance (RFM) and from the risk- based analysis (RBA) to risk-based maintenance (RBM). Figure 8.1 presents the "Lifetime" of an asset and the activities undertaken during each phase of its lifetime/lifecycle.

Figure 8.1. Asset lifetime and activities necessary in each phase

When applying condition-based maintenance, the computation of technical status indicators per component is essential in order to detect critical system components and ensuring the system's reliability. Based on the asset status/health indicators and the assessment of critical cases, and also considering the overall significance of the asset in the grid, the Company's management takes decisions and allocates funds either for maintenance or replacement, considering both the financial constraints and the requests of stakeholders. Within CNTEE Transelectrica SA, Asset Management (AM) includes: registering/accounting of assets, planning systems for refurbishments, maintenance, diagnosis, offline monitoring, asset control, information systems and databases containing the assets' history, as well as real time data obtained via SCADA and online asset monitoring. The power transmission system assets management process requires additional instruments for management decisions, in order to select the best option from a set of alternative options. This can be regarded as a continuous decision-making process based on technical, economic and social information. This decision-making process is a step by step process on three separate levels, as shown in Figure 8.2 below.

Figure 8.2. Decision-making process for asset management in the power transmission system

The PTG asset management is usually comprised of three main steps:  Asset level (assessment of the technical condition of each piece of primary equipment and device, overhead power line);  Grid level (taking into account the technical condition of the relevant PTG assets, risks of fault and implications for the PTG operational security, etc.);  Corporate level (taking into account the technical conditions of components, risks of fault, performances of the power transmission system, costs, the Company's policy regarding maintenance and investments, contractual undertakings, etc.);

Criteria for determining the technical condition of PTG primary high-voltage equipment

The determination of the technical condition of equipment, high-voltage devices and overhead power lines may be carried out based on the following main criteria:  constructive particularities which influence the lifetime of the equipment/device (asset);  status and operational parameters which describe the current technical condition of the asset and its classification in one of the following status categories: good/acceptable/poor/unacceptable;  technical limits and criteria of classifying the asset in one of the above-mentioned technical status categories;  classification of tests/measurements/checks/analyses necessary for the assessment of the current technical condition;  the asset's age;  asset's operation and maintenance history;  criteria for establishing technical and general status indexes for the relevant asset;  proposals for operation and maintenance measures depending on the asset's current technical status category;

 methodology to evaluate the asset's passage from one status to another and to predict the timeframe until the execution of a certain type of maintenance work or asset replacement work, etc. If one of the tests returns a value which is deemed unacceptable, the asset's general status will be automatically declared as unacceptable.

Input data for determining the technical condition

The evaluation of the technical condition of equipment, high-voltage devices and overhead power lines may be carried out based on the processing of the following input data:  operational and status parameters;  time development of operational parameters and comparing these with the parameters/limits pre-set in the technical assessment procedures;  operational behavior (incidents, damages, voltage dips, etc.);  the age of the equipment considering the year of manufacturing, date of commissioning, capital repairs, refurbishment etc. and the wear and tear and obsolescence;  the overall significance of the equipment/device or OHL in the PTG and NPS;  maintenance costs, etc. Algorithms for evaluating the technical status index of primary equipment Specific algorithms can be used for evaluating the technical status index of PTG primary equipment and devices or high-voltage overhead power lines respectively. The results of each analysis/measurement/check are compared with the limit values set in the technical procedure and are then classified in four status categories (good, acceptable, poor, unacceptable). A status score is then allocated. When establishing the global technical status index of primary equipment and devices, we also consider their operational history and age, as the wear and tear degree might impact decisions on keeping them in operation. Depending on the scores allocated, the total technical status score of primary equipment and devices is determined; this indicator allows prioritizing the equipment as well as determining the nature and urgency of the maintenance needed, depending on their current technical condition. Knowing the technical status index of each primary equipment from the substation, we can determine the overall substation index, which might represent an important criterion for prioritizing the refurbishment and maintenance works.

In order to test the methodology using the consultant's software application, a database for testing has been created for the asset management within CNTEE Transelectrica SA; this database consists of 80 power transformers, 81 breakers and 54 110 kV-400 kV overhead power lines.

The Information System for Asset Management processed the information from the database and established the current technical status index for 80 power transformers from the total of 139 managed by Transelectrica (one from each substation), as shown in Table 8.8 below.

Table 8.8 List of 80 power transformers from the database evaluated by the Information System, with status score No./Manufacturi Construction Factory Equip Technical

No. Equipment name Score Substation

ng year type name . type status 1 Autotransformer, AT3 143176/2016 ATUS-OFAF EPC PT 81.14 good BRADU 400 MVA 2 AT 200 MVA 9417/2015 ATUS-OFAF Retrasib PT 81.14 good CAMPIA TURZII 3 Autotransformer. AT1 142701/2009 ATUS - OFAF EPC PT 75.12 good ISALNITA 231/121/10.5 kV 4 Transformer, T1 104642/1980 TTUS-NS EPC PT 74.79 acceptable DRAGANESTI 110/20kV -OLT 5 Transformer, TRAFO2 140838/1997 TTUS-OFAF EPC PT 74.63 acceptable SMARDAN 400/121/20kV 6 AT 4 400 MVA 339044/2006 OFAF Siemens PT 71.66 acceptable BUCURESTI- SUD 7 Trafo 250 MVA 142652/2008 TTUS-OFAF EPC PT 71.43 acceptable ROMAN NORD 8 AT 220/110/10.5kV 200 67503/1970/R04 ATUS-OFAF EPC PT 71.18 acceptable FOCSANI MVA VEST 9 TRAFO 400/110 KV 142651/2007 OFAF EPC PT 70.44 acceptable BACAU SUD 250 MVA 10 Autotransformer, AT4 339042/2005 2ARZ400000- Siemens PT 70.29 acceptable MINTIA 400/220/20kV 420 11 Autotransformer, AT 142592/2007 ATUS-OFAF EPC PT 68.72 acceptable PAROSENI 220/110kV 12 Autotransformer, AT1 24703/1965 ATUS-FS EPC PT 68.67 acceptable PESTIS 220/110/10.5kV 13 Autotransformer, AT1 83913/72R05/197 ATUS-OFAF EPC PT 68.26 acceptable FILESTI 220/110/10.5kV 2 14 Autotransformer, AT2 97746/1977 ATUS-FS EPC PT 67.55 acceptable GHIZDARU 220/110/10kV 15 Autotransformer, AT4 9205/2010 ATUS-OFAF Retrasib PT 67.01 acceptable LACU SARAT 400/231/22 kV 16 AT3 400 MVA 339043/2005 OFAF Siemens PT 66.95 acceptable BRAZI VEST 17 Autotransformer, 9486/2016 ATUS-ONAF EPC PT 66.00 acceptable RAURENI AT 231/121/20 kV 18 AT2 200 MVA 220/110 96243/1975 ATUS-FS EPC PT 65.78 acceptable F.A.I. kV 19 AT5 400 MVA 8329846/2005 TCP335T ABB PT 65.38 acceptable GUTINAS 400/220/20 kV 20 Transformer, 97969/1977 TTUS-NS EPC PT 63.81 acceptable GURA Trafo1-16MVA IALOMITEI 21 Transformer, TRAFO2 3247PG18509/20 TC2454E-OFAF AREVA, PT 62.51 acceptable TARIVERDE 250MVA 400/110/20 09 France kV 22 Autotransformer, 55622/1991 ATUS-FS EPC PT 62.03 acceptable MOSTISTEA AT 220/110/10 kV 23 Transformer, 9344/2013 TTUS-OFAF Retrasib PT 61.47 acceptable TULCEA T1 250 MVA VEST 400/121/20 kV 24 Autotransformer, AT5 8674248/2006 ATUS - OFAF ABB PT 59.53 acceptable SIBIU SUD 400 MVA 400/220/20 kV 25 Autotransformer, AT3 40079/1966/RK20 ATUS-FS EPC PT 59.50 acceptable TR. 200 MVA, 220/110/10.5 04 MAGURELE kV 26 AT 200 MVA, 65999/1969 ATUS-OFAF EPC PT 59.06 acceptable SUCEAVA 220/110/10.5 kV (R2002)

No./Manufacturi Construction Factory Equip Technical

No. Equipment name Score Substation

ng year type name . type status 27 Transformer, Trafo2 30N081216.02/20 TTUS-OFAF Siemens PT 58.66 acceptable BRASOV 250 MVA 400/121/20 11 kV 28 Transformer, Trafo2- 96811/1976 TTUS-NS EPC PT 58.58 acceptable GURA 16MVA 110/20 kV IALOMITEI 29 Autotransformer, AT1 94794/1974 ATUS-FS EPC PT 57.77 acceptable CRAIOVA 220/110/10.5kV NORD 30 Autotransformer, AT1- 8329806/2004 TCP335T Sweden PT 57.33 acceptable SLATINA 400 MVA 400/231/2 2 400/220 kV 31 Autotransformer, AT3- 142432/2005 ATUS-OFAF EPC PT 57.33 acceptable SLATINA 200 MVA 400/220 231/121/10.5kV 32 Transformer, Trafo2 9182/2010 TTUS-FS OFAF Retrasib PT 57.00 acceptable ORADEA SUD 250 MVA 400/121/20 kV 33 Autotransformer, AT 85765/1972 ATU-FS EPC PT 56.75 acceptable URECHESTI 400 MVA-UP 400/231/22 kV- 34 Autotransformer, AT4 96565/1975 ATUS-FS EPC PT 56.67 acceptable BRADU 400 MVA-UP 400/231/22 kV- 35 Autotransformer, AT1 95915/1974 ATUS-FS EPC PT 56.60 acceptable IAZ 200 MVA 220/110kV/10.5 kV 36 Transformer, T4 119548/2000 TTUS-FS EPC PT 56.00 acceptable DRAGANESTI 250 MVA 400/110 kV -OLT 37 AT1 200 MVA 95428/1974 ATUS-FS EPC PT 55.82 acceptable DUMBRAVA 220/110/10.5 kV 38 ATUS-OFAF 9181/2010 ATUS-OFAF PT 55.18 acceptable GHEORGHIEN 200/200/60 MVA I 39 Autotransformer, AT 71903/1970 ATUS-FS EPC PT 54.67 acceptable BARU MARE 200 MVA 220/110 kV 40 Autotransformer, AT2 95385/1974 ATUS-FS EPC PT 54.62 acceptable TIMISOARA 200 MVA 220/110/10.5 KV 41 Autotransformer, AT1 C-0476D/ 2010 ATUS-ODAF EFACEC PT 54.00 acceptable BARBOSI 200 MVA, 231/121/10.5 SA kV 42 Transformer, Trafo4 140433/1993 TTUS-FS EPC PT 53.54 acceptable GURA 250 MVA 400/110 kV IALOMITEI 43 Autotransformer, AT 101716/1980 ATUS-FS EPC PT 53.54 acceptable CALAFAT 200 MVA 220/110/10.5kV 44 Autotransformer, AT 339041/2005 2ARZ 400000- Siemens PT 53.54 acceptable ROSIORI 400 MVA 400/220/20 420 kV 45 Autotransformer, AT 97062/1977 ATUS-FS EPC PT 53.20 acceptable CETATE 200 MVA 220/110/10.5 kV 46 Autotransformer, AT1 94403/1973 ATUS-FS EPC PT 52.80 acceptable RESITA 200 MVA 220/110kV/10.5kV 47 Autotransformer, AT1 96723/1976 ATUS-FS EPC PT 52.61 acceptable STALPU 200 MVA, 220/110/10kV 48 Transformer, TRAFO1 104128/1981 TTUS-OFAF EPC PT 51.96 acceptable CONSTANTA

No./Manufacturi Construction Factory Equip Technical

No. Equipment name Score Substation

ng year type name . type status 250 MVA 400/110 kV N 49 Autotransformer, AT 142477/2005 ATUS-FS EPC PT 51.56 acceptable PITESTI SUD 200 MVA 220/110kV 50 AT 200 MVA, 220/110 9194/2010 ATUS-OFAF Retrasib PT 51.56 acceptable SALAJ kV 51 Autotransformer, AT 74397/2010 ATUS-FS EPC PT 51.56 acceptable SARDANESTI 220/110kV 52 Transformer, Trafo2 99821/1979 TTUS-FS EPC PT 51.56 acceptable PELICANU 250 MVA 400/110 kV 53 Transformer, Trafo2 107780/1995 TTUS-FS EPC PT 51.05 acceptable DOMNESTI 250 MVA 400/110 kV 54 Trafo7 250 MVA 114543/1985 TTUS-FS EPC PT 51.05 acceptable CLUJ EST 400/110/20 kV 55 AT1 200 MVA 220/110 62689/1969 ATUS-FS 0 PT 48.94 poor BAIA MARE 3 kV 56 Transformer, AT1 95002/1974 ATUS-FS EPC PT 48.13 poor UNGHENI 200 MVA 220/110KV 57 Autotransformer, AT 114786/1984 ATUS-FS EPC PT 48.13 poor FANTANELE 200 MVA 220/110 kV 58 Autotransformer, AT2 98978/1978 ATUS-FS EPC PT 48.13 poor SACALAZ 200 MVA 220/110KV 59 Transformer, TRAFO1 104127/1981 TTUS-FS EPC PT 48.13 poor MEDGIDIA 250 MVA SUD 400/110/20kV 60 Autotransformer, AT1 88554/1973 ATUS-FS EPC PT 47.45 poor HASDAT 200 MVA 220/110/10.5kV 61 Autotransformer, AT2 105791-81/1981 ATUS-FS EPC PT 46.34 poor TELEAJEN 220/110/10 kV 62 Autotransformer, AT2 141925/2004 AMUS-OFAF EPC PT 46.00 poor PORTILE DE 500 MVA 400/220kV- FIER UP, phase T 63 Autotransformer, AT 106288/1982 ATUS-FS EPC PT 46.00 poor TG. JIU NORD 200 MVA 220/110/10.5 kV 64 Autotransformer, AT2 79398/1984 ATUS-FS EPC PT 45.61 poor TR. SEVERIN 200 MVA220/110/10.5 EST kV 65 Autotransformer, AT1 97061/1977 ATUS-FS EPC PT 45.45 poor ALBA IULIA 200 MVA 220/110 kV 66 AT 200 MVA 64588/1969/R01 ATUS-OFAF EPC PT 44.79 poor MUNTENI 220/110/10.5kV 67 Transformer, Trafo2 110726/1982 TTU-NS EPC PT 43.58 poor STALPU 110/20kV 68 Autotransformer, AT2 99380/1978 ATUS-OFAF- EPC PT 43.50 poor TARGOVISTE 200 MVA 220/110 kV UP 69 Autotransformer, AT 114785 / 1984 ATUS-FS EPC PT 43.00 poor STUPAREI 200 MVA 220/110/10.5 kV 70 Transformer, Trafo1 95640/1974 TTUS-FS EPC PT 42.86 poor MOSTISTEA 110/20 kV 71 AT2 200 MVA 96340/1975 ATUS-FS EPC PT 41.76 poor CLUJ 220/110/10.5 kV FLORESTI 72 Autotransformer, AT1 52701/1967 ATUS EPC PT 41.25 poor AREF 200 MVA 220/110 kV 73 Transformer, Trafo2 103378/1980 TTUS-FS EPC PT 40.57 poor MOSTISTEA 110/20kV

No./Manufacturi Construction Factory Equip Technical

No. Equipment name Score Substation

ng year type name . type status 74 Autotransformer, AT1 95003/1974 ATUS-FS EPC PT 40.56 poor TARGOVISTE 200 MVA 220/110kV 75 Autotransformer, AT 96780/2000 ATU-OFAF EPC PT 36.73 poor ARAD 400 MVA 400/220/20kV-UP 76 AT 200 MVA 101717/1980 ATUS-FS EPC PT 36.01 poor VETIS 220/110/10.5kV 77 AT1 200 MVA 76421/1971 ATUS-FS EPC PT 33.01 poor TIHAU 220/110kV 78 Transformer, Trafo1 96809/1976 TTU-NS EPC PT 32.04 poor STALPU 110/20kV 79 Autotransformer, AT1 101715/1979 ATUS-FS EPC PT 28.68 poor GRADISTE 200 MVA 220/110/10.5kV 80 Autotransformer, AT3 96574/1976 ATUS-OFAF EPC PT 23 poor Portile de Fier 400/231/22kV-UP

The software application can detect unacceptable statuses which are not granted status scores, if: a) at least one parameter does not correspond to the limits provided by the technical status evaluation criteria (the standards); b) at least one mandatory parameter to be measured has no measurement data according to the pre-set test category (technical review tests); c) at least one parameter has incorrectly filled in or incorrectly measured data; d) the lifetime of the equipment exceeded the maximum lifetime pre-set in technical documents approved by CNTEE Transelectrica SA (e.g. 50 years for power transformers, 40 years for breakers).

Data for 81 110kV, 220 kV and 400 kV breakers with oil or SF6 insulation has been loaded and processed in the application (from the Excel forms received from CNTEE Transelectrica SA branches), as presented in Table 8.9 below.

Table 8.9 List of 81 high-voltage breakers from the database evaluated by the Information System, with status score Equi No. No./Manufacturing Construction Factory Technical

Equipment name p. Score Substation

year type name status

type 1 Breaker, 110kV AT1- 35119676/2011 3AP1FG 145 Siemens I 70.5 acceptable GRADISTE 200MVA 2 Breaker, MUKACEVO 1HSB0507009/2005 LTB-420E2 ABB I 67.5 acceptable ROSIORI OHL 400 kV 3 Breaker, 110 kV Darste 888092/2011 GT CB1 CG Electric I 67.5 acceptable BRASOV Systems Hungary ZRT 4 Breaker, 220 kV AT1 1HSB0902009/2009 LTB 245 E1 ABB I 67.5 acceptable GHEORGHIEN I 5 Breaker, 400kV T1 HA2278636/2012 ELK3-SP3 ABB-SW I 65.5 acceptable STUPINA 6 Breaker, 400kV Trafo1 123581 0010 GL 316-420kV AREVA-Fr I 65.5 acceptable TARIVERDE 01/2009 7 Breaker 35114353/2010 3AP1 FI SIEMENS I 65.5 acceptable CALAFAT 8 Breaker 220 kV Coupling 35142368/2016 3AP1 F1 245 SIEMENS I 65 acceptable TIHAU 1-4 9 Breaker, I9M 400 kV 17960/2016 3AP2 FI SIEMENS I 65 acceptable CERNAVODA

Equi No. No./Manufacturing Construction Factory Technical

Equipment name p. Score Substation

year type name status

type 10 Breaker 35111207/2009 3AP1 FI Siemens I 65 acceptable TG. JIU NORD 11 Breaker, 220 kV AT 35102265/2008 3AP1FI 245 Siemens I 65 acceptable STUPAREI 12 SF6 circuit-breaker, 1961560010/2016 GL316 Alstom I 65 acceptable CLUJ EST TRAFO 7 13 Breaker I IERNUT 220 35139043/2015 3AP1 FI SIEMENS I 65 acceptable CIMPIA kV OHL TURZII 14 Breaker, Portile de Fier 1 35119489/2011 3AP1FI SIEMENS I 65 acceptable CETATE

15 Breaker, AT 200 MVA/ 35116337/2010 3AP1 - FI I 65 acceptable SARDANESTI 220 kV 16 Breaker, I 8DQ - 0 Trafo 3029000131 - 08 DB10 SIEMENS I 65 acceptable GURA 4 IALOMITEI 17 Breaker, 110 kV TRAFO 3008781/14/2003 GL 311 F1 ALSTOM I 65 acceptable SALAJ 1 -25 MVA 18 Breaker, 220 kV 40006823/2006 SB6m NMG I 62.5 acceptable CLUJ AT1-200 MVA FLORESTI 19 Breaker, Craiova N1 220 IHSB0803I54/2008 LTB 245 E1 ABB I 62.5 acceptable ISALNITA kV bay 20 Breaker, 400 kV Trafo 1 143013 0100 05 / GL316 Alstom I 62.5 acceptable TULCEA 2014 VEST 21 Breaker, 220 kV AT1 1HSB0833139/2008 LTB245E1 ABB I 62.5 acceptable PESTIS 22 Breaker, 220 kV 1HSB0722011/2007 LTB 420 E2 ABB I 62.5 acceptable CALEA Coupling 41, I41 ARADULUI 23 Breaker, 400 kV BC 119522-0020- GL 316 AREVA I 62.5 acceptable SUCEAVA 01/2009 24 Breaker, 220 kV AT 27069184-86- GL 314-245kV AREVA I 62.5 acceptable PAROSENI 88/2006 25 Breaker, Lotru 1 1138190010/2005 GL314 AREVA I 62.5 acceptable SIBIU SUD 26 Breaker 400 kV Slatina 35093146/2006 3AP2 F1 Siemens I 62.5 acceptable BUCURESTI- SUD 27 Breaker, 400 kV Trafo1 1HSB01129022/201 LTB 420E2 ABB I 62.5 acceptable RAHMAN 1 28 Breaker I 220 kV AT1 1HSB01310005- LTB-245E1 ABB I 62.5 acceptable BARBOSI 13/2013 Sweden 29 Breaker, LEA 220 kV 6939-41-43/2008 GL 314 AREVA I 62.5 acceptable BAIA MARE 3 Tihau France 30 Breaker, 400 kV I12 AT1 1HSB0436006/2004 HPL 420B2 ABB I 62.5 acceptable SLATINA 400/220 31 Breaker, 220 kV Suceava 120036.0010.03/20 RESORT AREVA – I 62.5 acceptable F.A.I. 08 FRANCE 32 Breaker, 400 kV Coupling 35099714A/2007 3AP2FI Siemens I 59.53 acceptable NADAB 12 33 Breaker, Brasov 400 kV T-1HSB01139196 LTB 420 E2 ABB I 59.5 acceptable BRADU bay A/ 34 Breaker Rosiori 400 kV 1HSB00934261/200 LTB420E2 ABB I 59.5 acceptable GADALIN OHL 9 Ludvika 35 Breaker, AT3 400 kV 1241630011- GL 316 Alstom I 59.5 acceptable LACU SARAT 03/2009 36 Breaker, Cernavoda 400 8659326/2002 LTB 420E2- ABB I 58.6 acceptable CONSTANTA kV NPP 420kV NORD 37 Breaker, Beckescsaba 400 35077815/2003 3 AP2 FI SIEMENS I 57.5 acceptable ORADEA SUD kV OHL 38 Breaker I AT1 220 kV 1HSB0514031 / LTB 245 E1 ABB – I 57.5 acceptable FUNDENI 2005 Sweden 39 Breaker, 400 kV AT-1 40003733/2005 420 MHMe- VA Tech I 57.5 acceptable IERNUT 400/220kV 2Yh

Equi No. No./Manufacturing Construction Factory Technical

Equipment name p. Score Substation

year type name status

type 40 Breaker, I AT3 400/220 5950156/2005 GIS TOSHIBA I 57.5 acceptable BRAZI VEST kV 41 Breaker, 220 kV 8665981/2003 LTB 245 E1 ABB I 57 acceptable PITESTI SUD AT 200 MVA 42 Breaker, 400 kV 8422967C/2000 HPL420-B2 ABB I 57 acceptable TINTARENI KOSLODUI 1 EST 43 Breaker, I1M, 400 kV IHSB052009/2005 LTB-420-F2- ABB I 57 acceptable GUTINAS Median 1 400 kV 44 Breaker, 400kV AT3 K35015853/1997 3AQ2E1-400kV SIEMENS I 57 acceptable MINTIA 45 Breaker, I AT1 220 kV 113818-0010- GL 314 AREVA I 57 acceptable TARGOVISTE 03/09053108/09053 T&D 110/09053112/2005 FRANCE 46 Breaker I AT2 220 kV 8683 6/31 ABB I 57 acceptable TR. MAGURELE 47 Breaker 220 kV Coupling 1123950010/2004 GL 314 Alstom I 51.96 poor VETIS 1-4 48 Breaker, 220 kV AT 401309/1984/1984 IO-400kV EPC I 49 poor MUNTENI 49 Breaker, 220 kV 149215/1970 IO-220kV EPC I 48.5 poor TR. SEVERIN AT1-200 MVA EST 50 Breaker, 400 kV Tulcea 401631/1985 IO-400kV EPC I 48.5 poor ISACCEA Vest 51 Breaker, 400 kV Trafo2 85003/1970 HPF-516q/8E ALSTOM I 48.5 poor DARSTE 400/110kV 52 Breaker, 110 kV 418318/1995 IO-110kV EPC I 43 poor ROMAN Trafo 250 MVA NORD 53 Breaker, 400 kV Slatina 417476/1991 IO-400kV EPC I 43 poor DRAGANESTI -OLT 54 Breaker, 110 kV FILIASI 418369/1995 H14 EPC I 43 poor CRAIOVA NORD 55 Breaker, 220 kV 393831/1978 IO-220kV EPC I 41.5 poor SACALAZ TIMISOARA 56 Breaker, 220 kV Gutinas 400576/1983 IO-400kV EPC I 41.5 poor FOCSANI VEST 57 Breaker, 400kV Bucuresti 394579/1978 IO-400kV EPC I 41.5 poor PELICANU Sud 58 Breaker, 400 kV Trafo1 400013/1981 IO-400kV EPC I 41.5 poor DOMNESTI 59 Breaker, 220kV Iernut1 400578/1972 IO-220kV EPC I 41.5 poor UNGHENI 60 Breaker, 220kV AT1 400008/1982 IO-220kV EPC I 41.5 poor AREF 61 Breaker, 400 kV CTf 403218/1987 IO-400kV EPC I 41.5 poor SMARDAN 62 Breaker, 220 kV Trafo1 393731/1977 IO-245 EPC I 41.5 poor OTELARIE Pestis 63 Breaker, 220 kV Stejaru 391329/1974 IO-220kV EPC I 40.5 poor DUMBRAVA 64 Breaker, 220 kV Tr. 393188/1977 IO-220kV EPC I 40.5 poor GHIZDARU Magurele 65 Breaker, 220kV AT1 152800/1970 IO-220kV EPC I 40.5 poor HASDAT 66 Breaker, 220 kV Sacalaz 390061/1973 IO-220kV EPC I 40.5 poor ARAD 67 Breaker, 110 kV Trafo 395083/1980 IO-110kV EPC I 40.5 poor BACAU SUD 400/110 kV 250 MVA 68 Breaker, 220kV AT1 391715/T/1974 IO-220kV EPC I 40.5 poor IAZ 69 Breaker, 400 kV AA/01872500101/1 FXT16-400kV ALSTOM I 40.5 poor PORTILE DE AT3-400 MVA 999 FIER 70 Breaker, 220 kV RESITA 159898/1971 IO-220kV EPC I 40.5 poor TIMISOARA 1

Equi No. No./Manufacturing Construction Factory Technical

Equipment name p. Score Substation

year type name status

type 71 Breaker, 110 kV 393321/1977 IO-110kV EPC I 40.5 poor MEDGIDIA Medgidia1 SUD 72 Breaker, 220 kV Lacu 112/199/1966 DELLE-220kV DELLE I 40.5 poor FILESTI Sarat 73 Breaker, 22 0kV 391156/1973 IO-220kV EPC I 40.5 poor RAURENI AT 200 MVA 74 Breaker, 220 kV K-31239762/1991 3AQ1-EE SIEMENS I 40.5 poor FANTANELE AT 220/110 kV 75 Breaker, 110 kV Sebes2 393107/1976 IO-110kV EPC I 40.5 poor ALBA IULIA 76 Breaker, 110 kV 3952248/1980 IO-110kV EPC I 40.5 poor MOSTISTEA Gurbanesti 77 Breaker, 400 kV Portile 8425446A/1999 HPL420-1B ABB I 40 poor URECHESTI de Fier 78 Breaker, 220 kV AT1 145814/1970 IO-220kV EPC I 37.5 poor RESITA 79 Breaker, 220 kV Coupling 400426/1982 IO-220kV EPC I 36.16 poor TELEAJEN 1-3 80 Breaker, 110 kV Rm. 392198/1975 IO-110kV EPC I 35.16 poor STALPU Sarat Simileasca

81 Breaker, 220 kV AT 392945/1976 IO-220kV EPC I 30.16 poor BARU MARE

Data for 54 high-voltage overhead power lines out of a total of 154 has been uploaded in the database of the Information System (shown in Table 8.11 below), out of which 2 have a status score resulted from the measurements taken during the technical expertise. The two lines are Gura Ialomitei-Cernavoda 2 400 kV OHL (technical status score of 62.25, Table 8.11) and Cernavoda-Constanta Nord 400 kV OHL respectively (technical status score of 62.61, Table 8.11). Considering either the lack of data, the fact that the data is presented in a way that is incompatible with the expert system and the standards on which the algorithms are based on (for instance the degree of degradation of the anti-corrosive protection: the standard indicates a percentage of the surface, while the Excel table was filled in with: "Compliant"), or the fact that the actual lifetime is higher than the set limit lifetime (50 years), the system indicates an unacceptable status (with no status score).

Table 8.10 List of 52 OHLs from the database evaluated by the Information System, with unacceptable status (with no status score)

100

101

Table 8.11 List of overhead power lines from the database of the Information System for which the technical status indexes have been determined (Excel table provided by the Information System)

102

8.2. Technical status of the power distribution grid Distribution operators (DSO) – represented by ACUE (Federation of Associations of Energy Utility Companies) have contracted a Consultant responsible with the drafting of the study "Assessment and monitoring of Romanian distribution grids" between September 2016 and April 2017 [25]. This study presents the current situation of power distribution grids and offers a full overview over their performances and current asset condition. In order to meet this demand, the following objectives have been set during the first phase of the study: • Assessment of the distribution grids' status – carrying out the general evaluation of the Romanian power distribution grids' status (distribution lines, transformer substations, etc.) – both at national, and at individual level for each DSO • Comparative analysis with other jurisdictions • Collecting data and analyzing a new performance monitoring system Distribution service performance level Monitoring, measuring and reporting on the continuity of supply in the power distribution grid are important instruments for the comparison of the performances between different companies and for identifying the areas where certain improvements are needed. Two of the most frequently used key performance indicators (KPIs) are: ▪ SAIDI: System Average Interruption Duration Index for each client, measured in minutes; ▪ SAIFI: System Average Interruption Frequency Index for each client. Similar to the situation in other European countries, Romania faces significant differences between Distribution System Operators in terms of the general features of the grid – for instance: the service area (the serviced area varies between 5.300 km2 and 34.000 km2), the number of clients, the density of consumers (varies from 25 consumers/km2 to 223 consumers/km2), the length of the grid (two of the DSOs have a total grid length almost twice as large as the average of the other six DSOs), the ratio between clients in rural areas and clients in urban areas (50% versus 16% of clients located in the rural area), etc. These structural differences contribute to the occurrence of variations in the performances registered by the respective Distribution System Operators. Differences between the DSOs can also be seen in terms of the regulated asset base. For instance, the transformer substations (HV/MV, MV/MV): three DSOs own and operate over 200 transformer substations (TSs), one of which owning a whopping 250 TSs. On the other hand, one DSO owns less than half, namely 106 TSs. Similarly, the number of MV/LV transformation posts (TP) varies between 10,900 and almost half of this number, namely 5,900. Supply points (SP) vary between 235 for one DSO and 16 for another. These significant differences also have an impact on the performance of each distribution grid. Status of the distribution grids and assets It is worth mentioning that the asset base of operators is generally outdated, with a significant proportion (over 58%) of assets being older than 35 years. Differences can also be seen in terms of the rehabilitation or replacement of assets. According to the data provided by DSOs, half of the transformer substations (HV/MV, MV/MV) have been rehabilitated in the last 10 years. The percentage of rehabilitated transformer substations (TSs) varies between 18% for one DSO and over 60% for another DSO. Other assets, such as TPs, have been rehabilitated and/or renewed in a much smaller proportion. For this asset type, the average

103 rehabilitation proportion in the last 10 years is only 15%, with a 7%-34% variation between operators. At European level, the analysis of SAIDI causes due to incidents occurred at different voltage levels has shown that the "medium voltage level (MV)" has an overwhelming contribution. This analysis highlights that almost 75% of SAIDI represents the result of interruptions in the MV grid. The same pattern has also been noted in Romania. For SAIDI, the study shows that in Romania, the average contribution to this indicator corresponds with the European average (e.g. approx. 75% of the SAIDI contribution comes from MV grids). For SAIFI, the most significant contribution comes again from MV grids, although in this case the average contribution in Romania (almost 86%) exceeds the European average. Romania regularly monitors the continuity of supply at each voltage level of the distribution grid and records every interruption. In Romania there are 10 major categories (groups) defined for classifying the causes of faults; each category is further divided in subcategories (subgroups) which contribute to the definition of a higher granularity in interpreting the fault. In line with the data collected, the most frequent cause of MV lines incidents is "the poor quality of the materials"; within the group, the most faults are allocated to the "technical depreciation of materials, under standard conditions or at the end of the lifecycle" subgroup. The different performances of DSOs, reflected via SAIDI and SAIFI, can be explained both in terms of the differences mentioned above, and due to the different approaches of distribution operators in establishing the precise number of affected clients in each troubleshooting phase. Asset management; new performance indicators According to the study results, a large majority of the Romanian distribution grids' assets are nearing the end of their standard lifecycle; therefore, operators should consider alternative investment strategies for replacing these outdated assets. For some of these assets, the operational lifetime can be extended in a secure and reliable way, while others must necessarily be replaced. The risk-based approach regarding the technical status helps in prioritizing and optimizing the capital investment portfolios. Grids' degree of automation; Smart Metering Systems The development of Smart Grids is currently at an early stage in Romania. Considering the data provided by distribution companies, the study assessed the implementation level of a number of measures for implementing the Smart Grid. This includes the HV lines' integration in SCADA, the registration level of distribution grid elements in GIS and the automation degree and its influence on the grid's performance levels. Effectively, the average integration level of high-voltage lines in SCADA integrated substations is approx. 72%, varying between a minimum value of 47% and a maximum value of almost 90%. Recommendations of phase 1:  Improving the current reporting: - Establishing a clearly defined reporting methodology (SAIDI, SAIFI, AIT and ENS). - Independent evaluation of the reporting process  Introducing new reporting metrics: - Introducing the technical status and the grid risk indicator will promote good practices in terms of asset management and will ensure that the DSOs' investments represent the correct value for the money spent by the consumer.

104

- Implementing Smart Grids, starting from measures that aim at decarbonization, decentralization (of generation) and digitalization of the energy sector.  Revising cost recognition mechanisms: - Introducing a financial incentive plan for each performance – the grid performance, better (or worse) than initially agreed and the objectives initially decided upon, shall be rewarded or penalized. - Revising the "unconventional" expenditures regime – introducing an incentive associated with unconventional expenditures. Phase 2 of the study "Assessing and monitoring the Romanian distribution grids" is currently in progress; this study analyzes the following objectives: • Assessing the current state of power distribution grids; • Methodology for establishing new investments; • Estimating future investments necessary in the distribution grid.

105

9. Scenarios regarding the NPS evolution into perspective – timeframe 2018- 2022-2027

9.1. General principles for building scenarios Considering that the separation of the generation, supply, transmission and distribution sectors has introduced a high degree of uncertainty for the TSO regarding the future evolution of generation and demand, the grid's operational regimes are analyzed for a basic scenario, as well as several alternative scenarios. The scenarios used in the analysis of the PTG development requirements are drafted by CNTEE Transelectrica SA based on the available information provided by the responsible Ministry, the forecast institutes, the PTG users, other stakeholders and European TSOs. The basic scenario represents the demand and balance forecast and their coverage by generation capacities; this is the best forecast available given the information available at the moment of drafting the Plan and it corresponds, in terms of the grid's load, to the greatest possible number of possible scenarios. For the basic scenario, the typical consumption levels (WEP, SMP, SNL) were considered for each analyzed timescale: current year + 5 years and current year + 10 years. The summer holiday day low consumption is modeled for the minimum load regime. The extreme low, at Easter, when exceptional measures for operational scheduling are typically taken, is modeled within special studies with a shorter timescale. The alternative scenarios consider different hypotheses compared to the basic scenario, in terms of: - demand increase rate; - electricity exchange with other systems; - installing new generation capacities and decommissioning the existing ones. We take into consideration a reasonable number of alternative scenarios on certain load sections, which complete the conclusions of the analysis carried out for the basic scenario. These scenarios aim to: - evaluate the flexibility of development solutions compared to several possible evolutions; - propose ulterior adjustment criteria for the development plan, depending on system evolutions.

NPS interconnected external power systems System studies are carried out considering that the NPS operates interconnected with other European power systems. Basic scenarios and some alternative scenarios on demand, generation, power exchanges and grid configuration at European level are commonly drafted by grid operators within ENTSO-E. For analysis calculations of the grid load, steady state regime and dynamic regime models of the ENTSO-E synchronously interconnected system are used, of which the NPS is part of. These models are built in cooperation with all European TSOs within regional and European cooperation organizations: ENTSO-E.

106

9.2. Scenarios regarding the evolution of the electricity demand in the NPS The 10-year development plan is based on scenarios for the long and mid-term evolution of the electricity demand, necessary for modelling of the Romanian energy market. In this regard, we analyzed "The preliminary forecast for Autumn 2016" drafted by the National Forecast Commission (CNP) in September 2016 (further revised in January 2017), which estimated a continuous growth of the Gross Domestic Product until 2020, with annual average rates of 4.8% in 2016, 4.3% in 2017, 4.5% in 2018, 4.7% in 2019 and 4.2% in 2020 respectively, compared to the previous year. Table 9.2.1 [%] Annual GDP growth rate 2015 2016 2017 2018 2019 2020 CNP September 2016 3.8 4.8 4.3 4.5 4.7 4.2 CNP January 2017 3.9 4.8 5.2 5.5 5.7 5.7 It is worth mentioning that, after the recovery from the decline caused by the economic crisis and the consolidation of positive evolutions of the Gross Domestic Product, the decoupling of the electricity demand evolution from the economic growth was becoming more and more accentuated. While the GDP registered annual average growth rates between 3% and 4.8% between 2013 and 2016, the increase in electricity demand was less accentuated (ranging between 1.9% and 1.1%), both due to structural adjustments in the national economy, and as a result of the improvement in energy efficiency for end consumers. We notice that the net domestic electricity demand, decoupled from the macroeconomic growth, registered the same value in the first ten months of 2016 as in the same period of 2015. Given extreme meteorological conditions, the last two months of 2016 brought an end to the somewhat constant demand evolution trend, registering significant increases (5.4% in November and 7.8% in December respectively, compared to the same months of 2015), so that we have an overall annual average growth of 1.1%. The electricity demand upward trend continued throughout 2017. Table 9.2.2 and Figure 9.1 show the net domestic consumption evolution scenarios, namely of the balance and net generation of electricity between 2018 and 2027.

TWh 65.0 Scenarii de evolutie a consumului intern net de energie electrica 63.0 in perioada 2013-2027 61.0

59.0

57.0 SCENARIUL DE REFERINTA 55.0 SCENARIUL ALTERNATIV

53.0

51.0

49.0

47.0

45.0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Figure 9.1

107

Table 9.2.2 Energy development scenarios in Romania between 2018 and 2027

2013 2014 2015 2016 2017 * 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 U.M. realizari prognoza

SCENARIUL DE REFERINTA Consum intern net de energie electrica TWh 52.3 53.3 54.8 55.4 56.5 56.6 56.8 57.0 57.5 58.0 58.6 59.3 59.9 60.5 61.1 ritm anual de crestere % -3.9 1.9 2.7 1.1 2.0 0.2 0.4 0.4 0.9 0.9 1.0 1.1 1.1 1.0 0.9 Puterea de varf neta - consum MW 8312 8522 8488 8752 8840 8855 8889 8965 9080 9185 9293 9400 9500 9600 9690 Consum pompe TWh 0.17 0.25 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Sold export-import TWh 2.02 7.13 6.72 5.01 3.00 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 Productie neta de energie electrica TWh 54.5 60.7 61.7 60.6 59.7 60.3 60.5 60.7 61.2 61.7 62.3 62.9 63.6 64.2 64.8

SCENARIUL ALTERNATIV Consum intern net de energie electrica TWh 52.3 53.3 54.8 55.4 57.1 57.7 58.3 58.8 59.4 60.0 60.6 61.2 61.8 62.3 62.8 ritm anual de crestere % -3.9 1.9 2.7 1.1 3.0 1.1 1.0 1.0 1.0 1.0 1.0 1.0 0.9 0.8 0.8 Puterea de varf neta - consum MW 8312 8522 8488 8752 9000 9040 9145 9270 9385 9500 9596 9695 9777 9858 9940 Consum pompe TWh 0.17 0.25 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Sold export-import TWh 2.02 7.13 6.72 5.01 3.20 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 Productie neta de energie electrica TWh 54.5 60.7 61.7 60.6 60.4 61.9 62.4 63.0 63.6 64.2 64.8 65.4 66.0 66.5 67.0 * Data collected until November 2017 show a ca. 2.5% annual average growth rate of the net electricity demand.

108

Comparatie Productie/Consum TWh 70 70

60 60

50 50

40 40

30 30

20 20

10 10

0 0 2018 2022 2027

Nucleara Termo Hidro Biomasa Eolian Solar Consum

Figure 9.2

The reference scenario estimates a moderate increase of the penetration of renewable energy sources and new generation technologies (Figure 9.2). With the commissioning of groups 3 and 4 from Cernavoda, the contribution of the nuclear power plant in the generation mix will double, while the fossil fuel-based generation will continue its descending trend. The hydro generation remains somewhat constant throughout the entire analyzed period.

The analyzed scenarios are coherent with scenarios corresponding to the 2025 and 2030 timescales, analyzed within ENTSO-E for the energy market modelling studies, necessary for drafting the Ten-year network development plan (TYNDP 2018). More precisely, they are based on the same information provided by generators on the evolution of the power plant park. Starting from the aforementioned scenarios, we estimated the demand values on the specific load sections, considered to represent the extreme operational regimes in terms of normal grid circulations. Therefore, we modeled and analyzed in detail the operational regimes for the specific sections presented in Table 9.2.3, corresponding to the reference and alternative scenarios regarding the demand and installed capacity evolution, namely:  the NPS maximum load recorded in the winter evening peak (WEP);  the summer morning peak (SMP) for verifying the supply grid for deficit areas, where the summer demand reaches values close to the winter ones, and the thermal power plants seasonally reduce their power (e.g.: Bucharest);  the summer night low (SNL), for verifying the voltage control means and the power discharge capacity of wind power plants in surplus areas.

109

Table 9.2.3 [MW] 2018 2022 2022 2027 2027 SCENARIUL DE SCENARIUL DE SCENARIUL SCENARIUL DE SCENARIUL REFERINTA REFERINTA FAVORABIL REFERINTA FAVORABIL VSI VDV GNV VSI VDV GNV VSI VDV GNV VSI VDV GNV VSI VDV GNV

Consum intern net de energie electrica 8855 7480 4553 9185 7830 4720 9500 8100 4880 9690 8260 4975 9940 8480 5120

Sold export-import 800 700 550 1000 800 650 1000 800 650 1200 900 750 1200 900 750

Productie neta de energie electrica 9655 8180 5103 10185 8630 5370 10500 8899 5530 10890 9160 5725 11140 9380 5871

When modelling the distribution of the vertical load per counties and individual consumers, we started from the loads measured in every substation, on the specific sections in previous years (Annex B-1) and from the forecast provided by distribution operators (Annex C-1), scaling by percentage in order to obtain the value forecasted for the entire NPS.

9.3. Scenarios regarding the power exchange balance

The volume of power exchanges permanently varies depending on longer- or shorter-term evolutions of the energy market. In the analyzed scenarios, we considered a load peak export which varies between 800 and 1,200 MW in the analyzed timescales, namely a summer peak between 700 and 900 MW and a summer night low between 550 and 750 MW, both for the reference scenario, as well as for the alternative scenario.

9.4. Scenarios regarding the evolution of generation facilities At the request of CNTEE Transelectrica SA, generators provided information – without declaring a firm commitment in this regard – with respect to their intentions to refurbish or discard existing units and to install new groups. It is worth mentioning that 80% of the existing thermal generating units have exceeded their standard lifetime. Until now, the NPS thermal generating units have been refurbished and/or modernized, but very few units are equipped with facilities for reducing emissions which would allow them to comply with the norms set forth by the European Union. In order to comply with EU regulations, the Ministry of Administration and the Interior issued Order no. 859/2005, implementing the "National Program for the reduction of emissions of sulphur dioxide, azote oxide and powders from large burning substations". According to this program, in order to remain operational, all thermal generating units must comply with the environmental requirements set forth. Therefore, for the period 2018-2027, the grid development analysis considered a Reference Scenario for the evolution of generation capacities, which includes a program for the definitive decommissioning of certain thermal generating units once they have reached the end of their lifetime or as a result of non-compliance with the European Union requirements regarding pollution; this analysis returned a total available net capacity of 4,996 MW, out of which 2,714 MW up to and including 2022. In some cases, discarding the units is associated with the intent to replace them with new, better ones; the new capacities must have an increased global efficiency, they must be flexible and they must ensure compliance with the requirements set forth by the grid code and the relevant European regulations.

110

According to this development scenario, the following groups will be recommissioned in the same time period, after rehabilitation: four groups in Turceni, three groups in Rovinari, one group in Craiova and one nuclear group in Cernavoda (shut down for refurbishment, in order to extend lifetime), resulting in a total available net capacity of 2,841 MW. In terms of the intentions to install new groups, as per the information provided by existing generators, these amount to an available net capacity of ca. 2,306 MW, excluding RES based projects. Figure 9.4.1 highlights the projects for rehabilitation and new groups for the period 2018-2022 and 2023-2027 respectively, corresponding to the generation park evolution reference scenario.

Figure 9.4.1 Projects for rehabilitation and new groups

111

Projects for new groups include: - completion of groups 3 and 4 in the Cernavoda NPP, available for the 2027 timescale; - new natural gas groups (gas turbines or combined-cycle, condensation units – Romgaz carries out an investment project in a combined-cycle natural gas power plant in Iernut, with a 400 MW capacity, or cogeneration units – Bucharest); - completion of hydroelectric power plants in various execution stages; - other new intermittent RES groups: wind, solar (photovoltaic); - other new biomass RES groups. Annex C-2 (not published) presents the rehabilitation, conservation and discarding programs, as well as the commissioning of new groups considered in the basic scenario in order to analyze the PTG development needs, their presumed year of occurrence and the presumed available net capacity. In addition to the Reference Scenario for the evolution of capacities, we also analyzed a Favorable ("Green") Scenario, characterized by economic and financial conditions favorable for the implementation of energy policies promoted at EU level (major investments, renewable sources integration, increase of energy efficiency, CO2 emissions reduction, maximum development of Smart Grid type solutions and energy storage capacities), specific to the Favorable Scenario for the evolution of demand.

Figure 9.4.2 Evolution of generation capacities RES development One element specific to the current stage is the high interest in enhancing the renewable energy sources: biomass, hydroelectric power, photovoltaic power and wind power. Law no. 220/2008 has been amended and supplemented by the provisions of GEO no. 57/2013 on the application of the RES promotion scheme and the public electricity grids connection process. This partially postponed the issuing of GCs depending on RES type (after 01.04.2017 for MHPs and PVPPs, and after 01.01.2018 for WPPs respectively), introduced financial securities in the

112 connection process – the amount of which shall be set by ANRE, and limited the RES volume that benefits from the promotion system at the level of the installed capacities established for each year by Government Decision, based on the NREAP reupdated data. After the entry into force of GEO no. 57/2013, the interest of investors was moderate, even decreasing after the entry into force of GD no. 994/2013, which drastically decreased the number of green certificates. In December 2017, the WPP installed capacity amounted to 3,030 MW, mainly concentrated in the Dobrogea and Moldova areas, and the PVPP installed capacity amounted to 1,375 MW.

Figure 9.4.3 Ci evolution in commissioned WPPs

Figure 9.4.4 Ci evolution in commissioned PVPPs We see a fast growth trend in the WPP and PVPP installed capacity in the 2010-2014 period. This shows the increased rate at which these types of power plants were built as a result of incentives granted by the applicable legislation at the time, in particular the promotion system for electricity generated from renewable energy sources set forth by Law no. 220/2008, amended and

113 supplemented by Law no. 139/2010, Emergency Government Ordinance no. 88/2011 and Law no. 134/2012 approving the ordinance. Starting with 2014, the WPP and PVPP construction trend has been moderate, with the interest of investors being moderate, even decreasing after the entry into force of GD no. 994/2013, which drastically decreased the number of green certificates. As of 31.12.2016, the access to the current green certificates-based support scheme has been closed; therefore, new investments in wind, photovoltaic, micro hydro or biomass capacities can be made at a slower pace in the period 2018-2027, in particular the ones that are granted co-funding from European structural funds. The overall increase in RES-based installed capacities between 2018 and 2027 will be smaller compared to the 2010-2017 period. If higher capacities will be installed in wind and photovoltaic power plants, the grid development necessities will also rise – the geographical location of the new power plants will have a decisive influence in this regard. As of drafting the Plan, the uncertainty regarding this evolution was very high.

9.5. NPS generation facilities adequacy analysis in the 2018-2022-2027 period The system adequacy studies the extent to which the NPS generation capacities have the ability to cover the power demand in all steady states in which the system might be. For the perspective evaluation, this capacity was verified for the moment of the year in which the NPS reaches the maximum demand value – namely the winter evening peak, using the methodology applied at European level within ENTSO-E. According to this methodology, it is considered that in order to safely cover the demand, a certain available power ensured by power plants is necessary in the power system, which must be significantly higher than the power consumed at the load peak, as periodical outages occur for repair and maintenance, units are impacted by forced outages or partial, temporary or definitive availability reductions with different causes. An operational reserve must also be permanently available for the TSO. Currently, this is designed for fast balancing during continuous demand variations and during an unexpected triggering of the largest group in the system. Not all units have the ability to provide fast reserves, as the vast majority has a high cold start time and small loading speeds. After the mobilization of the fast reserve, this must be gradually replaced by loading the slow tertiary reserve, so that the units that provide it can be used during the next incident. Once a significant power capacity has been installed in wind power plants – which are characterized by the generation's dependency on wind speed, the fast tertiary reserve must be supplemented in order to compensate the impreciseness of the generation forecast for these power plants. The main factors that will influence the necessary power reserve in the following years are the following: improving the units' reliability indicators, which will decrease the necessary power reserve, and installing wind power plants in the system, which will increase the necessary power reserve.

Table 9.5.1 includes the estimation of the generation system's adequacy for the analyzed timescales (2018-2022-2027) in the Reference Scenario corresponding to the demand variation and the generation capacities respectively:

114

Table 9.5.1 The NPS generation park adequacy – Reference Scenario MW

Putere netă in SEN 2018 2022 2027

1 centrale nucleare 1300 1300 2630 2 centrale termoelectrice conventionale 6559 7148 6529 • pe lignit 2676 3193 2860 • pe huila 428 428 428 • pe gaze naturale / hidrocarburi 3456 3528 3241 3 resurse energetice regenerabile 4500 5100 5500 • eoliene 3000 3400 3600 • fotovoltaice 1350 1500 1600 • biomasa 150 200 300 4 centrale hidroelectrice 6436 6505 6532 • CHEAP 5 Capacitatea netă de producere *5=1+2+3+4+ 18796 20053 21190 6 Putere indisponibilă totala 7946 8628 8924 • Putere indisponibilă (Reduceri temporare+conservari) 4512 4940 5175 • Putere in reparatie planificată 1110 1184 1115 • Putere in reparatie accidentală (după avarie) 1217 1277 1347 • Rezerva de putere pentru servicii de sistem 1107 1227 1287 7 Puterea disponibilă netă asigurată *7=5-6+ 10850 11425 12266 8 Consum intern net la varful de sarcina 8855 9185 9690 9 Capacitate rămasă ( fără considerarea schimburilor cu alte sisteme) *9=7-8+1995 2241 2576 10 Sold Import-Export la varful de sarcina -800 -1000 -1200

115

In this scenario, the surplus available net capacity in the system amounts to ca. 11% of the net generation capacity in 2018, a value which remains somewhat constant even after the commissioning of units 3 and 4 in Cernavoda (12%), due to the gradual reduction of the fossil fuel-based capacity on the one side, and the increase in demand on the other side.

Table 9.5.2 includes the estimation of the generation system's adequacy for the 2018-2022-2027 timescales, in the Alternative Scenario corresponding to the consumption variation and the "Green Scenario" for the evolution of generation capacities.

Table 9.5.2 The NPS generation park adequacy – Consumption Favorable Scenario / "Green" Capacities Scenario

116

Putere netă in SEN 2018 2022 2027

1 centrale nucleare 1300 1300 2630 2 centrale termoelectrice conventionale 6559 7148 6529 • pe lignit 2676 3193 2860 • pe huila 428 428 428 • pe gaze naturale / hidrocarburi 3456 3528 3241 3 resurse energetice regenerabile 4500 5100 6500 • eoliene 3000 3400 4000 • fotovoltaice 1350 1500 2000 • biomasa 150 200 500 4 centrale hidroelectrice 6436 6505 6532 • CHEAP 5 Capacitatea netă de producere *5=1+2+3+4+ 18796 20053 22190 6 Putere indisponibilă totala 7946 8666 9738 • Putere indisponibilă (Reduceri temporare+conservari) 4512 4940 5815 • Putere in reparatie planificată 1110 1179 1135 • Putere in reparatie accidentală (după avarie) 1217 1321 1382 • Rezerva de putere pentru servicii de sistem 1107 1227 1407 7 Puterea disponibilă netă asigurată *7=5-6+ 10850 11387 12452 8 Consum intern net la varful de sarcina 8855 9500 9940 9 Capacitate rămasă ( fără considerarea schimburilor cu alte sisteme) *9=7-8+1995 1886 2512 10 Sold Import-Export la varful de sarcina -800 -1000 -1200

In this scenario, the surplus available net capacity in the system also amounts to ca. 11% of the net generation capacity. The unusable power increase is owed to the unpredictable component associated to increased renewable sources generation, particularly wind and photovoltaic generation. The adequacy forecast considered the fact that installing wind and photovoltaic power plants increases the weight of unavailable capacity, as a consequence of the intermittent operation of these power plants, characterized by a small number of hours of use at maximum capacity. Given that the availability of wind and photovoltaic power plants is limited throughout the year and their production is not controllable compared to classic power plants, in order to ensure adequacy, it is absolutely necessary to have a certain power capacity in classic peak power plants with fast start-up and/or energy storage capacities (e.g. pumped storage hydroelectric power plants, batteries, etc.).

WPP and PVPP integration in the load curve implies that conventional power plants must ensure the frequency control function and compensate the power variation resulted from the variations in wind speed, significantly increasing the frequency of situations in which thermoelectric units must operate with partial load or must be shut down and restarted. Therefore, it is necessary to install peak power plants in the system, as this operation method has negative implications for generation costs and the lifetime of units destined for base operation.

117

9.6. NPS load coverage by generating units – cases analyzed for the verification of the PTG adequacy Given that the transmission grid is unloaded and the differences between the consumption scenarios considered are distributed all throughout the country, it is deemed that these differences do not significantly impact the grid development solutions. Starting from this conclusion, the regime analyses were deepened on the load reference scenario. Due to the large power capacity focused in power plants, changing the hypotheses regarding the installed capacity and the contribution to covering the load might lead to significant changes in the grid operational regime and to different development necessities. Given the high degree of uncertainty regarding the evolution of the generation park, special care was given to drafting a sufficient number of study cases, aiming to adequately reflect the regimes which the grid must face in operational situations which might be deemed normal. The majority of the analyzed cases were based on the reference scenario regarding the evolution of the generation park. The study cases have been built both for the peak, and the off-peak sections, considering certain hypotheses regarding the installed generation capacities and their contribution to covering the load. When developing the fossil fuel price evolution scenario in the analyzed period, different hypotheses and data sources have been considered. Therefore, for the 2018 and 2022 timescales, we extrapolated the data provided by generators and the data available to CNTEE Transelectrica SA from the Powrsym market model runs for 2017, used in the ANRE substantiation of the data from energy contracts on the market. The modelling included a detailed representation of prices in power plants, at group level (considering the average fuel recipe per group and the transportation price), the average values broken down into fuel categories being included in Table 9.6.1. As a result, no change in the merit order of the groups is estimated for 2017-2022. For the market modelling analyses in the 2027 timescale, different scenarios were used for the fuel price evolution (Table 9.6.1), as well as for the CO2 emissions cost (Table 9.6.2), similar to the ones used at ENTSO-E level for TYNDP 2018, taken from the scenarios developed by IEA.

Table 9.6.1 – Fuel price (Euro/Net GJ)

2027

sc. de referinta sc. verde

Lignit 1.10 1.10 Huila 2.45 2.70 Gaze naturale 8.10 8.80

Pacura 16.60 17.90

Table 9.6.2 CO2 emissions cost (Euro/ton)

118

2027

sc. de

referinta sc. verde 40.00 50.00

In the hourly profiling of the power producible in wind and photovoltaic power plants, the Pan- European Climate Database (PECD) was used, available within ENTSO-E for market studies, which includes time series with wind and photovoltaic generation hourly variation indexes for 34 climate years, determined on the grounds of measurements taken between 1982 and 2015 and pertaining to the average wind speed and solar radiation intensity. Hydrologic variability is also one of the climate effects impacting the energy sector. The market analyses modeled the hydrological generation available in different timescales, corresponding to the average year in terms of hydrologic features. Annex C3 (not published) presents the net loads of the NPS power plants for covering the demand (consumption + balance), corresponding to the basic average regime (BAR) in characteristic sections in the reference years. Starting from the case corresponding to the basic average regime, cases were built that lead to the most difficult operational regimes which might occur under normal operational conditions of the NPS and which the grid must face – Reference Design Regimes (RDR – for the methodology please see Annex A). Given the large number of power plant projects based on renewable energy sources for which connection has been requested, the following were studied:  numerous options regarding the location and loading of renewable energy sources-based power plants;  additional scenarios with higher capacities installed in WPP, PVPP and biomass power plants, as per the requests accompanied by contracts/technical connection approvals in different locations. The analyzed scenarios also considered several hypotheses for the location of new thermoelectric units.

119

10. Perspective analysis of PTG operation regimes For an evaluation of the PTG suitability and development needs, the TSO makes sure that system studies are conducted to check the compliance of operation conditions with standardized parameters, by performing steady-state condition [14], static and dynamic stability calculations and a short- circuit current evaluation [5]. The reliability indicators are also computed on the PTG substation busbars [12]. These calculations are carried out for the basic scenario and a reasonable number of alternative scenarios regarding the evolution of demand, the structure of the generation park in various timescales and the power plant loading for balancing the demand and exchange balance with neighboring systems. The grid currently operates at a decreased loading degree (please see Chapter 5.4). In the following years, with the installation of a significant capacity of sources in certain areas of the country and with the intensification of electricity exchanges on the Western and Eastern interconnection lines, the transmission grid will be highly loaded in those areas and will not be able to comply, in the current structure, with the rated technical criteria and the requirements set forth in the Performance standard for the transmission system services. In order to identify the PTG development needs, several studies [5], [8], [12], [13], [14], [19], [20], [22], [24], [26], [29] have been developed for verifying the compliance of the PTG operational regimes with the rated conditions, in the mid (5 years) and long (10-15 years) term. Steady-state regimes, static and transient stability conditions and short-circuit regimes have been analyzed. The conclusions of connection solution studies have also been considered – these studies have been developed at the request of PTG users for the connection of new power plants; projects for increasing the interconnection capacity, developed in cooperation with neighboring grid operators have also been taken into account. The following aspects specific to operational regimes have been analyzed: - the load level of the PTG elements (lines, transformers, autotransformers) in configurations with N and N-1 operational elements; - the voltage levels in the PTG nodes in configurations with N and N-1 operational elements and the reactive power compensation degree; - the level of active power losses in the PTG; - the level of short-circuit powers in PTG nodes; - steady-state and transient stability. The calculations have been carried out based on system models that correspond to the NPS evolution scenarios, considered for the five- and ten-year perspective, for the purposes of verifying the grid adequacy and identifying the need to develop it. In terms of new WPP, PVPP and biomass power plants, given the large number of requests, the power plants modeled as a priority were the ones already commissioned or the ones with a connection agreement concluded; however, additional calculations have been carried out for identifying connection solutions also considering renewable energy sources-based power plants with TCAs. The calculations for verifying the PTG reference design have been carried out for the basic average and reference design regimes according to PE 026/92 (Standard on the principles, criteria

120 and methods for the substantiating the NPS development strategy), considering the operation synchronously interconnected with the system of Continental Europe.

10.1. Analysis of steady-state regimes

In order to carry out system calculations and analyses, calculation models have been developed associated with characteristic cases: - cases deemed as Basic Average Regimes (BAR) for the PTG operation; - cases that lead to the most difficult operational regimes which might occur under normal operational conditions of the NPS and which the grid must face – Reference Design Regimes (RDR). The cases associated with BAR and RDR have been built for the characteristic sections of the load curve: the winter evening peak (WEP), the summer morning peak (SMP) and the summer holiday night low consumption (SNL), for each of the 3 forecast timescales: 2018, 2022 and 2027. When building the Basic Average Regimes (BAR) we considered the implementation of the grid developments planned by CNTEE Transelectrica SA, as well as the grid developments notified by the distribution operators, forecasted to be commissioned in the 2018-2027 period:

2018 stage: CNTEE Transelectrica SA: - Resita-Pancevo (Serbia) 400kV d.c. OHL; SDEE Transilvania Nord SA: - Ruscova 110/20 kV transformer substation connected in input/output system on the Sighet CEIL-Baia Borsa 110 kV, 16MVA OHL; - Tetarom IV 110/20 kV transformer substation connected in input/output system on the Cluj Sud-Poiana 110 kV, 25MVA OHL; E-Distribuție Banat SA: - Continental 110 kV connection substation: o IMT-Continental Al 630mm2 110 kV UPL; o Continental-Padurea Verde Al 630 mm2 110 kV UPL. E-Distribuție Muntenia SA: - Parc Drumul Taberei 110/20 kV, 2x25 MVA substation, connected in input/output system on the Salaj-Drumul Taberei 2 110 kV UPL; - Academia Militara 110/20 kV, 2x25 MVA substation, connected in input/output system on the Panduri-Razoare 110 kV UPL; - Park Lake 110/20 kV, 2x16 MVA substation, connected in input/output system on the Dudesti-Balta Alba 110 kV UPL; o New Dudesti-Park Lake Al 630 mm2 110 kV UPL; o New Balta Alba-Park Lake Al 630 mm2 110 kV UPL; - New Fundeni-Bucuresti Nord Al 1600 mm2 110 kV UPL; - Fundeni-Obor Al 1600 mm2 110 kV UPL, conductor replacement.

121

2022 stage: CNTEE Transelectrica SA: - Portile de Fier-Resita 400 kV OHL (stage I of the 400 kV voltage conversion of the Portile de Fier-Resita-Timisoara-Sacalaz-Arad axis); - Connecting the Stupina-Varna (Bulgaria) 400 kV OHL, input/output in the Medgidia 400 kV substation via a 400 kV d.c. OHL; - Connecting the Rahman-Dobrudja (Bulgaria) 400 kV OHL, input/output in the Medgidia Sud 400 kV substation via a 400 kV d.c. OHL; - Second 250MVA, 400/110 kV TR in the Sibiu Sud substation; - Connecting the Ostrovu Mare 220 kV substation (Portile de Fier II HPP) input/output in a circuit of the Portile de Fier-Cetate 220 kV d.c. OHL; - Second 400MVA, 400/220 kV AT in the Iernut substation; - Second 400MVA, 400/220 kV AT in the Brazi Vest substation; - Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped); - Cernavoda-Gura Ialomitei-Stalpu 400 kV d.c. OHL; - converting the Brazi Vest-Teleajen-Stalpu OHL to the 400 kV voltage; - Medgidia Sud-Constanta Nord 400 kV d.c. OHL (1 circuit equipped); E-Distribuție Banat SA: - Ineu 110/20 kV, 1x25 MVA transformer substation connected in input/output system on the Pancota-Sebis 110 kV OHL: o Pancota-Ineu OlAl 185/32 mm2 110 kV OHL; o Sebis-Ineu OlAl 185/32 mm2 110 kV OHL; - Iulius Mall 110/20 kV transformer substation: o Dumbravita-Iulius Mall Al 630 mm2 110 kV UPL. E-Distribuție Dobrogea SA: - Medgidia Nord-Mircea Voda Nord 110 kV OHL, conductor replacement; - Mircea Voda-Mircea Voda Nord 110 kV OHL, conductor replacement; - Tulcea Vest-Topolog 110 kV OHL, conductor replacement; - Medgidia Nord-Constanta Nord 110 kV OHL, conductor replacement; - Medgidia 1-Nazarcea 110 kV OHL, conductor replacement. E-Distribuție Muntenia SA: - Expozitiei 110/20 kV, 2x25 MVA substation, connected in input/output system on the Pajura- Baneasa 110 kV UPL; - Pantelimon 110/20 kV, 2x25 MVA substation, connected in input/output system on the Titan- Republica-FCME 110 kV UPL; o New Pantelimon-FCME Al 1600 mm2 110 kV UPL; o New Pantelimon-Titan Al 1600 mm2 110 kV UPL; - Giulesti 110/20 kV, 2x25 MVA substation, connected in input/output system on the Cotroceni-Radu Zane 110 kV UPL; - Barbu Vacarescu 110/20 kV, 2x25 MVA substation, connected in input/output system on the Fundeni-Otopeni 110 kV UPL; - Bucuresti Centru-Bucuresti Nord Al 1600 mm2 110 kV UPL, conductor replacement; - Bucuresti Nord-Grozavesti Al 1600 mm2 110 kV UPL, conductor replacement; - Grozavesti-Razoare Al 1600 mm2 110 kV UPL, conductor replacement; - Razoare-Militari Al 1600 mm2 110 kV UPL, conductor replacement; - Grozavesti-Militari Al 1600 mm2 110 kV UPL, conductor replacement.

122

2027 stage: CNTEE Transelectrica SA: - Resita-Timisoara/Sacalaz-Arad 400 kV d.c. OHL (stage II in converting the Portile de Fier- Resita-Timisoara-Sacalaz-Arad axis to the 400 kV voltage); - Gadalin-Suceava 400 kV s.c. OHL; - Suceava-Balti 400 kV s.c. OHL; - Stalpu-Brasov 400 kV d.c. OHL (1 circuit equipped); SDEE Transilvania Nord SA: - Someseni 110/20 kV transformer substation connected in input/output system on the Cluj Sud-Jucu 25MVA 110 kV OHL; - Satu-Mare 6 110/20 kV transformer substation connected in input/output system on the Vetis- Abator 16MVA 110 kV OHL. E-Distribuție Muntenia SA: - Traian 110/20 kV, 2x25 MVA substation, connected in input/output system on the CET Sud- Centru 110 kV UPL; - Bragadiru 110/20 kV, 2x25 MVA substation, connected in input/output system on the Domnesti-Militari 1 110 kV UPL; - Mosilor 110/20 kV, 2x25 MVA substation, connected in input/output system on the Panduri- Centru 110 kV UPL; - Voluntari 110/20 kV, 2x25 MVA substation, connected in input/output system on the Fundeni-Barbu Vacarescu 110 kV UPL.

Distribuție Energie Oltenia SA and Delgaz Grid SA planned no distribution grid developments in the 2018-2022-2027 period. SDEE Transilvania Sud SA and SDEE Muntenia Nord SA have provided no information regarding grid developments for the 2018-2022-2027 period. In the basic average regime (BAR) with N and N-1 operational elements, neither overloads, nor overruns of acceptable limits have been signaled. Checking was performed on the PTG steady-state regime in the reference design regime (RDR) via calculations with N and N-1 operating network elements. For discharging the power from the Cernavoda NPP, the regimes with N-2 operational elements have also been checked. We also checked regimes with simultaneous disconnection of PTG lines that have a double circuit on a length of more than 10 km. Network development should consider solutions that enable eliminating the congestions along the main directions of power flows between generation centers in the eastern part of the country and the western load and storage centers, which correspond to the following transmission corridors: 1. N-S corridor interconnecting Dobrogea and Moldova; 2. E-W corridor interconnecting Dobrogea and Bucharest + limit area; 3. E-W corridor interconnecting Moldova and the NPS to the West. System analyses have established the following lines as technical solutions for consolidating these corridors:

123

- Connecting the Isaccea (Rahmanu)-Dobrudja and Isaccea (Stupina)-Varna 400 kV OHL in the Medgidia 400 kV substation in the input/output scheme in order to secure the N-1 WPPs criterion in the Rahmanu and Stupina 400 kV substations; - Smardan-Gutinas 400 kV d.c. OHL (initially with one circuit equipped); - Cernavoda-Stalpu 400 kV OHL d.c., with one input/output circuit connected in the Gura Ialomitei substation and converting to the 400 kV operational voltage of the Stalpu- Teleajen-Brazi Vest 400 kV OHL, which was built for 400 kV but operates on 220 kV; - Gadalin-Suceava 400 kV OHL s.c.

10.1.1. Analysis of the Dobrogea area The analysis of the Dobrogea area was carried out considering the reference design regime, built starting from BAR, with a WPP and PVPP installed capacity as per the reference scenario with the following changes: WPPs in the Dobrogea area have been loaded up to ca. 70% Ci and 90% Ci respectively. Other hypotheses regarding new generation capacities in the area: - Cernavoda NPP: the two 1,300 MW existing units have been considered as operational in the mid-term, and the commissioning of units 3 and 4 has been considered respectively (from the long-term timescale); - Galati CHPP: a 50 MW unit was considered; - Palas CHPP: a new gas combined-cycle 32 MW unit was considered; - PVPPs in the Dobrogea area have been loaded up to ca. 80% Ci in the SMP section. Mid term In the winter evening peak section – WEP, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the summer morning peak section – SMP, in regimes with N operational elements, the PTG admissible voltage limits are complied with and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. Overloads have been identified on the Stejaru- Gheorghieni 220 kV OHL when disconnecting the Sibiu Sud-Iernut 400 kV OHL. The construction of the Suceava-Gadalin 400 kV s.c. OHL is therefore deemed appropriate. A ca. 100 MW increase in capacity installed in renewable energy sources in the Dobrogea area, considering the WPPs in the area with a 90% loaded Ci, leads to overloads on the Constanta Nord-Tariverde 400 kV OHL and the Constanta Nord-Medgidia Sud 400 kV OHL. It is worth mentioning that currently, there are WPPs with connection contracts in force in the Dobrogea area, amounting to 1,800 MW, out of which the Tulcea-Tariverde area amounts to ca. 843 MW. Therefore, it is appropriate and necessary to replace the existing Isaccea-Tulcea Vest 400 kV s.c. OHL with a new 400 kV double circuit OHL. In the summer night low section – SNL, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the mid-term, a reference design regime was analyzed in the WEP and SMP sections presuming a 600 MW import from the Republic of Moldova towards Bulgaria and Hungary via the Isaccea-Vulcanesti 400 kV OHL, presuming a 90% Ci generation in WPPs from Dobrogea. - In the N operational elements regime there is no overrun of admissible currents or voltage limits and no overloads have been signaled on PDG/PDG elements.

124

- In regimes with verification of the N-1 operational elements criterion during SMP, overloads on the Stejaru-Gheorgheni 220 kV OHL have been identified when disconnecting the following 400 kV lines: Sibiu Sud-Ienut 400 kV OHL, Gutinas- Brasov 400 kV OHL, Brasov-Sibiu Sud 400 kV OHL. The construction of the Suceava- Gadalin 400 kV s.c. OHL is therefore deemed appropriate. Therefore, it is necessary to consolidate the grid transmission capacity for power discharge from surplus areas towards demand and storage centers. Long term In the summer morning peak section – SMP, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the long term, a reference design regime was analyzed in the SMP section presuming a 600 MW import from the Republic of Moldova towards Bulgaria and Hungary via the Isaccea-Vulcanesti 400 kV OHL, presuming a 90% Ci generation in WPPs from Dobrogea: - in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the summer night low section – SNL, in the N operational elements regime, there is no overrun of admissible currents or voltage limits and no overloads have been signaled on PDG/PDG elements. In regimes with N-1 and N-2 operational elements, the mandatory N-1 criterion is not complied with. The overload on the Gura Ialomitei-Cernavoda 400 kV OHL is highlighted; this overload is eliminated when connecting one of the two circuits of the Gura Ialomitei-Cernavoda 400 kV OHL, disconnected in the BAR regime.

10.1.2. Analysis of the Dobrogea and Moldova areas The analysis of the Dobrogea and Moldova areas was carried out considering the reference design regime, based on BAR, with a WPP and PVPP installed capacity as per the reference scenario with the following changes: WPPs in the Dobrogea area have been loaded up to ca. 70% Ci and 90% Ci respectively. Other hypotheses regarding new generation capacities in the area: - Cernavoda NPP: the two 1,300 MW existing units have been considered as operational in the mid-term, and the commissioning of units 3 and 4 has been considered respectively (from the long-term timescale); - Galati CHPP: a 50 MW unit was considered; - Palas CHPP: a new gas combined-cycle 32 MW unit was considered; - Suceava CHPP: two groups were considered, with a total power of 37 MW; - Bacau CHPP: two groups were considered, with a total power of 47 MW; - Iasi CHPP: two groups were considered, with a total power of 80 MW; - PVPPs in the Dobrogea area have been loaded up to ca. 80% Ci in the SMP section. Mid term In the winter evening peak section – WEP, the following regimes were analyzed:

125

– considering the WPP production at 70% and 90% of Ci respectively, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. – considering the WPP production at 0% of Ci, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. – considering a maximum production in Dobrogea (WPP production at 70% of Ci) and a minimum production in Moldova (WPP production at 0% of Ci), in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. – considering a minimum production in Dobrogea (WPP production at 0% of Ci) and a maximum production in Moldova (WPP production at 70% of Ci), in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the summer morning peak section – SMP, the following regimes were analyzed: – considering the WPP production at 70% of Ci and 90% of Ci respectively, and the PVPP production at 80% of Ci, in regimes with N operational elements, no capacity overruns occur on the network elements or admissible voltage limits. In regimes with N-1 and N-2 operational elements, the mandatory N-1 criterion is not complied with. Overloads have been identified on the Stejaru- Gheorghieni 220 kV OHL when disconnecting the Sibiu Sud-Iernut 400 kV OHL and the Brasov- Gutinas 400 kV OHL. The construction of the Suceava-Gadalin 400 kV s.c. OHL or the replacement of conductors in the Stejaru-Gheorgheni 220 kV OHL with a 150%lmax current is therefore deemed appropriate. – considering the WPP and PVPP production at 0% of Ci, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. – considering a maximum production in Dobrogea (WPP production at 70% of Ci and PVPP production at 80% of Ci) and a minimum production in Moldova (WPP and PVPP production at 0% of Ci), in regimes with N operational elements and in regimes with the verification of the N-1 and N- 2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. – considering a minimum production in Dobrogea (WPP and PVPP production at 0% of Ci) and a maximum production in Moldova (WPP production at 70% of Ci and PVPP production at 80% of Ci), in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the summer night low section – SNL, the following regimes were analyzed: – considering the WPP production at 90% of Ci, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the mid-term, a reference design regime was analyzed in the WEP and SMP sections presuming a minimum WPP and PVPP production at 0% of Ci and a 600 MW export in the Republic of Moldova via the Isaccea 400 kV substation, using the Isaccea-Vulcanesti 400 kV OHL:

126

- in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. - The analysis of the surplus area Dobrogea + Moldova shows the necessity to build the Suceava-Gadalin 400 kV OHL. Long term From the analyses of the summer morning peak section – SMP, the results obtained in the mid- term are maintained. – additionally, a reference design regime was carried out presuming no WPP production in the Dobrogea + Moldova area and a 600 MW export in the Republic of Moldova via the Isaccea 400 kV substation, using the Isaccea-Vulcanesti 400 kV OHL: - In the N operational elements regime there is no overrun of admissible currents or voltage limits and no overloads have been signaled on PDG/PDG elements. - In regimes with N-1 and N-2 operational elements, the mandatory N-1 criterion is not complied with. Overloads are highlighted on the Medgidia Sud-Cernavoda 400 kV OHL and the Gura Ialomitei-Lacu Sarat 400 kV OHL. These overloads are intensified with the additional sensitivity considering the WPP production at 0% of Ci and a 1000 MW export in the Republic of Moldova via the Isaccea 400 kV substation and the Suceava 400 kV substation; overloads on these OHLs can be eliminated by replacing the conductors on these lines. – additionally, a reference design regime was carried out presuming maximum production (WPP production at 70% of Ci and PVPP production at 80% of Ci) in the Dobrogea + Moldova area and a 1,000 MW export in the Republic of Moldova via the Isaccea 400 kV and Suceava 400 kV substations: - In the N operational elements regime there is no overrun of admissible currents or voltage limits and no overloads have been signaled on PDG/PDG elements. - In regimes with N-1 and N-2 operational elements, the mandatory N-1 criterion is not complied with. Overloads are highlighted on the Stejaru-Gheorghieni 220 kV OHL when disconnecting the Suceava-Gadalin 400 kV OHL on the Bucuresti Sud-Gura Ialomitei 400 kV OHL and the Cluj Est 400/110 kV TR. In the summer night low section – SNL, the following regimes were analyzed: – considering the WPP production at 70% of Ci, in regimes with N operational elements, no capacity overruns occur on the network elements or admissible voltage limits. In regimes with N-1 and N-2 operational elements, the mandatory N-1 criterion is not complied with. The overload on the Gura Ialomitei-Cernavoda 400 kV OHL is highlighted; this overload is eliminated when connecting one of the two circuits of the Gura Ialomitei-Cernavoda 400 kV OHL, disconnected in the BAR regime. The analysis of the surplus area Dobrogea + Moldova shows the necessity to build the Suceava- Gadalin 400 kV OHL.

127

10.1.3. Analysis of the Moldova area For the reference design regime of the Moldova area – which is considered a deficit area – the following hypotheses regarding the generation capacities in the area have been considered: - Cernavoda NPP: the two 1,300 MW existing units have been considered as operational in the mid-term, and the commissioning of units 3 and 4 has been considered respectively (from the long-term timescale); - Iasi CHPP: one operational group was considered; - Suceava CHPP: two groups were considered, with a total power of 37 MW; - Bacau CHPP: two groups were considered, with a total power of 47 MW; - Iasi CHPP: two groups were considered, with a total power of 80 MW; - WPPs and PVPPs in the Moldova area have been considered loaded up to 0% of Ci. Mid term In the winter evening peak section – WEP and the summer morning peak section – SMP, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. Long term In the winter evening peak section – WEP, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits.

10.1.4. Analysis of the northern Transylvania area For the reference design regime of the northern Transylvania area – which is considered a deficit area – the following hypotheses regarding the generation capacities in the area have been considered: - Iernut CHPP: six 372 MW new gas combined-cycle units were considered; - Oradea CHPP: a 22 MW unit was considered; - WPPs have been considered loaded up to 70% of Ci; - PVPPs have been considered loaded up to 80% of Ci. Mid term In the winter evening peak – WEP – deficit area (WPP production of 0 MW and the Iernut SPP shut down) – in regimes with N operational elements, the PTG admissible voltage limits are observed and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. In scenarios where the Iernut SPP is not operational and a low level of the hydro component is registered, so that the HPPs in northern Transylvania are loaded up to 10% of the available capacity, the capacity of injection transformers from 400 kV to 220 or 110 kV is insufficient. These congestions can be eliminated by installing a new, additional transformer in the Cluj Est 400/110 kV substation. In the winter evening peak section – WEP, with maximum production in the Iernut SPP, WPPs loaded up to 70% of Ci and given a maximum level of the hydro component in the area – in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the summer morning peak section – SMP – deficit area (WPP and PVPP production of 0 MW, Iernut SPP shut down and minimum level of the hydro component), in regimes with N operational

128 elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In the summer morning peak section – SMP, with maximum production in the Iernut SPP and WPPs loaded up to 70% of Ci and given a maximum level of the hydro component in the area – in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. From the analysis of the Ardealul de Nord deficit area, considering the largest thermal power plant in the area (the Iernut SPP) as shut down and the HPPs in the area loaded up to 10% of the available capacity, results the necessity to install the second 400/110 kV TR in the Cluj Est substation. Long term From the analyses of the winter evening peak section – WEP, the results obtained in the mid-term are maintained. Additionally, in the "green" scenario, we carried out a sensitivity analysis which considered commissioning the Tarnita Lapustesti 1,000 MW SPHPP in the long term, set as a generator in the WEP section and as a pump in the SNL section. The "green" scenario is characterized by economic and financial conditions favorable for the implementation of energy policies promoted at EU level (major investments, renewable sources integration, increase of energy efficiency, CO2 emissions reduction, maximum development of Smart Grid type solutions and energy storage capacities). The results of the analysis confirmed that in regimes with N and (N-1) operational elements, the connection of the Tarnita Lapustesti SPHPP via: - the Mintia-Tarnita 400 kV d.c. OHL; - the Gadalin-Tarnita 400 kV d.c. OHL, is appropriate.

10.1.5. Analysis of the South-West area The reference design regime was verified starting from BAR and additionally considering the HPPs in the area at the maximum available capacity, with the Rovinari SPP at the maximum. The PVPPs in the South-West area have been loaded up to ca. 80% Ci in the SMP section. Analyses have been carried out considering the following elements as completed: the new Portile de Fier-Resita 400 kV OHL, the Resita 400/220 kV substation and the Resita-Pancevo 400 kV d.c. OHL, plus the conversion to the 400 kV voltage of the Resita-Timisoara-Arad 220 kV d.c. OHL. Mid term In the winter evening peak – WEP – surplus area with power discharge towards the Bucharest area – in regimes with N operational elements, the PTG admissible voltage limits are complied with and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. Overloads have been identified on the Portile de Fier 400 MVA 400/220 kV AT when disconnecting the Portile de Fier-Resita 220 kV d.c. OHL (c1 and c2). Therefore, its replacement with a 500 MVA 400/220 kV AT in the Portile de Fier substation is deemed necessary.

129

Additionally, for the sensitivity without the Mintia SPP and the Paroseni CHPP, the overload on the Urechesti 400 MVA 400/220 kV AT is highlighted. In the winter evening peak – WEP – surplus area with power discharge towards the Banat area – in regimes with N operational elements, the PTG admissible voltage limits are complied with and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. Overloads have been identified on the Portile de Fier 400 MVA 400/220 kV AT, the Urechesti 400 MVA 400/220 kV AT, the Resita-Timisoara 220 kV d.c. OHL and the Tg. Jiu Nord-Paroseni 220 kV OHL, which are intensified at the additional sensitivity without considering the Mintia SPP and the Paroseni CHPP as operational. Therefore, the replacement of the 400 MVA AT with a 500 MVA 400/220 kV AT in the Portile de Fier substation is deemed necessary, as well as the advancement of the Western axis construction to the long-term stage. Until carrying out these grid consolidations, it is necessary to limit the discharged power from the Portile de Fier 1 HPP or the Rovinari SPP. In the summer morning peak – SMP – surplus area with power discharge towards the Bucharest area – in regimes with N operational elements, the PTG admissible voltage limits are complied with and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. The need to replace the 400 MVA AT with a 500 MVA 400/220 kV AT in Portile de Fier is highlighted; overloads are highlighted on the Portile de Fier-Resita 220 kV d.c. OHL and the Resita- Timisoara 220 kV d.c. OHL respectively, which are intensified at the additional sensitivity without considering the Mintia SPP and the Paroseni CHPP as operational. In the summer morning peak – SMP – surplus area with power discharge towards the Banat area – in regimes with N operational elements, the PTG admissible voltage limits are complied with and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. Higher overloads are highlighted on the Portile de Fier-Resita 220 kV d.c. OHL, the Resita- Timisoara 220 kV d.c. OHL, the Tg. Jiu-Urechesti 220 kV OHL and the Paroseni-Baru Mare-Hajdat 220 kV OHL, which are intensified at the additional sensitivity without considering the Mintia SPP and the Paroseni CHPP as operational. Long term From the analyses of the summer morning peak section – SMP, the results obtained in the mid- term are maintained. The proposal to replace conductors for all the 220 kV OHL line segments of the Urechesti-Tg. Jiu Nord-Paroseni-Baru Mare-Hajdat 220 kV OHL does not solve all overloads which may occur in the PTG; additional output downsizes are necessary for the sources in the South-West area; an analysis of the technical condition of the 220 kV OHL is also needed, pertaining to the possibility to replace conductors correlated with the investment works on the "Banat" 400 kV axis (commissioning term – 2027). A new Urechesti-Mintia 400 kV OHL solves the overloads in the area (on the Urechesti-Tg. Jiu Nord-Paroseni-Baru Mare-Hasdat 220 kV electric highway); however, based on the economic efficiency analysis, this new investment was deemed inefficient. Furthermore, a detailed analysis is necessary on the physical possibilities to build a new 400 kV OHL in the Retezat-Valea Jiului area. In the analyzed stages, the reference design regimes have shown the following: - The necessity to replace the 400 MVA 400/220kV AT with a 500 MVA AT in the Portile de Fier substation; - Converting to the 400 kV voltage of the Resita-Timisoara-Sacalaz-Arad 220 kV OHL.

130

10.1.6. Analysis of the northern Transylvania, Moldova and northern Banat areas, called the North-South section As a result of the territorial distribution of power generated from photovoltaic power plants (PVPPs), a long-term analysis was carried out for the SMP and SNL sections pertaining to a reference design regime for the North-South deficit section. In addition to the provisions regarding the shutdown of the largest source in the area, power plants from the North-South deficit section have also been shut down/reduced: HPP, biomass, WPP and PVPP. A highly severe regime was obtained, which shows that the power from the surplus areas in the southern part of the country (Dobrogea and Oltenia) must be injected in the two deficit areas (S4 and S5). The PVPPs in the North-South section have been loaded up to ca. 80% of Ci in the SMP section. Mid term In the winter evening peak – WEP – deficit area (WPP production of 0 MW and the Iernut SPP shut down) – in regimes with N operational elements, the PTG admissible voltage limits are observed and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. In scenarios where the Iernut SPP is not operational and a low level of the hydro component is registered, so that the HPPs in the area are loaded up to 10% of the available capacity, the capacity of injection transformers from 400 kV to 220 or 110 kV is insufficient. These congestions can be eliminated by installing a new, additional transformer in the Cluj Est 400/110 kV substation. Additionally, the overload on the Urechesti 400/220 kV AT is highlighted, which is eliminated together with the construction of the western axis (Resita-Timisoara-Sacalaz-Arad 400 kV d.c. OHL); a reduced overload is also highlighted on the Tg. Jiu Nord-Paroseni 220 kV OHL. In the winter evening peak – WEP – maximum production in the Iernut SPP, WPPs loaded up to 70% of Ci and maximum level of the hydro component in the area – in regimes with N operational elements, the PTG admissible voltage limits are observed and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. The overload on the 400MVA, 400/220kV AT in the Sibiu Sud substation when disconnecting a circuit of the Lotru-Sibiu Sud 220 kV d.c. OHL or when disconnecting the other 400/220kV AT occurs as a result of the inclusion of the Lotru HPP in the available capacity. These overloads disappear when discharging a power of maximum 375 MW from the Lotru HPP. In the summer morning peak – SMP – deficit area (WPP and PVPP production of 0 MW, Iernut SPP shut down and minimum level of the hydro component) – in regimes with N operational elements, the PTG admissible voltage limits are observed and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. The overload on a circuit of the Timisoara-Resita 220 kV OHL when disconnecting the other circuit is eliminated with the construction of the western axis (Resita-Timisoara-Sacalaz-Arad 400 kV d.c. OHL). If we consider the PVPPs in the area as loaded up to 40% of the available capacity, this loading is reduced to 99.2%. In the summer morning peak – SMP – maximum production in the Iernut SPP, WPPs loaded up to 70% of Ci and maximum level of the hydro component in the area – in regimes with N operational elements, the PTG admissible voltage limits are observed and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. The overload on each 400MVA, 400/220kV AT in the Sibiu Sud substation when disconnecting a circuit of the Lotru-Sibiu Sud 220 kV d.c. OHL or when disconnecting the other 400/220kV AT occurs as a result of the inclusion of the Lotru HPP in the available capacity. These overloads disappear when discharging a power of maximum 265 MW from the Lotru HPP.

131

Long term From the analyses of the winter evening peak section – WEP, the results obtained in the mid-term are maintained. In the summer morning peak – SMP – deficit area (WPP and PVPP production of 0 MW, Iernut SPP shut down and minimum level of the hydro component) – in regimes with N operational elements, the PTG admissible voltage limits are observed and no overruns occur on network elements, however the mandatory N-1 criterion is not complied with. Overloads are highlighted on the Cluj Est 400/110 kV TR, the Urechesti-Tg. Jiu Nord 220 kV OHL and the Tg. Jiu Nord-Paroseni 220 kV OHL. In the summer morning peak – SMP – maximum production in the Iernut SPP, WPPs loaded up to 70% of Ci and maximum level of the hydro component in the area – the results obtained in the mid-term are maintained.

10.1.7. Analysis on the supply of the municipality of Bucharest Currently, as a result of specific economic development conditions in the Bucharest metropolitan area, we see an increase in electricity demand which is higher than the country-wide average. It is forecasted that this trend will continue in the following period. The security of supply to consumers is reduced during the summer, as in summertime total shutdowns are carried out for annual overhauling in thermal plants of the city. This area needs PTG-PDG consolidation/development projects, given other area specific aspects, such as: lack of available land for development works and its extremely high prices, very high concentration of demand, consumers with a high degree of sensitivity to interruptions in supply, large number of cables and issues with the reactive power quantity, dismantling of generating units, developing the production park in Dobrogea – resulting in an increase in power flows that transit substations which supply the Bucharest city. Mid term In the winter evening peak section – WEP and the summer morning peak section – SMP, the following regimes were analyzed: – considering the minimum production in the Bucharest area (the Bucuresti Sud CHPP, the Progresu CHPP and the Grozavesti CHPP shut down, the Bucuresti Vest CHPP operational with 112 MW), supply of consumption from the Dobrogea/Oltenia area, in regimes with N operational elements, the admissible voltage limits are observed and no overruns occur on network elements. In regimes with N-1 operational elements, the mandatory N-1 criterion is not complied with. Overloads have been identified on the Bucuresti Sud 400/220 kV AT3, the Domnesti 400/100 kV T1 and T5 and the Bucuresti Sud 220/110 kV AT1. Therefore, it is appropriate to build a 400/110 kV substation in the central area of the Bucharest municipality (Grozavesti), connected via two 400 kV UPLs to the Domnesti and Bucuresti Sud substations. – considering a maximum production in the Bucharest area and discharging the power towards Dobrogea/Oltenia, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits.

132

The necessity to construct 400 kV injections in the metropolitan Bucharest area is therefore reconfirmed, correlated with the evolution of demand. Long term In the winter evening peak section – WEP, the following regimes were analyzed: – considering the minimum production in the Bucharest area (the Bucuresti Sud CHPP, the Progresu CHPP and the Grozavesti CHPP shut down, the Bucuresti Vest CHPP operational with 122 MW), supply of consumption from the Dobrogea/Oltenia area, in regimes with N operational elements, the admissible voltage limits are complied with and no overruns occur on network elements. In regimes with N-1 operational elements, the mandatory N-1 criterion is not complied with. Overloads have been identified on the Bucuresti Sud 400/220 kV AT, the Domnesti 400/100 kV TR and the Bucuresti Sud 220/110 kV AT. Overloads are eliminated on the limit when considering the solution to consolidate the metropolitan area of Bucharest, namely the construction of the Grozavesti 400/110 kV substation and the Filaret 400/110kV substation. The solution consists of the construction of a 400/110kV substation in Grozavesti, connected via two 400 kV UPLs to the Domnesti and Bucuresti Sud substations and the additional construction of a 400/110kV substation in Filaret, connected for input/output with the cable constructed during the previous stage, from Grozavesti to Bucuresti Sud. – considering a maximum production in the Bucharest area and discharging the power towards Dobrogea/Oltenia, in regimes with N operational elements and in regimes with the verification of the N-1 and N-2 operational elements criterion, no capacity overruns occur on the network elements or admissible voltage limits. In order to identify the concrete measures to consolidate both the PTG and the PDG from the Bucharest municipality area, CNTEE Transelectrica SA authorized in 2015 the following project within TESC: "Study on the development of the supply power grid in the metropolitan area of Bucharest – 10-year perspective" [8]. This study reconfirmed the need to construct two 400/110 kV substations, one in the demand center of the Bucharest municipality (Grozavesti), in the mid-term, and another one in the Filaret area, in the long term. The actions taken by CNTEE Transelectrica SA in order to obtain rights over a land located in Bucharest, Grozavesti area (currently owned by the company ELCEN Bucuresti SA) have not been successful.

10.1.8. Opportunity to replace the active conductor on certain 220 kV OHLs, from a 400 mm2 section to a 450 mm2 section In this regard, the increase in capacity of a 220 kV OHL can consider: - the standardization of the 450 mm2 section of the conductor of a 220 kV OHL, which also contains 400 m2 sections; or - replacing conductors so that the overload on the relevant OHL may be eliminated.

Opportunity to replace the active conductor with a 400 mm2 section with another conductor with a 450 mm2 section on the Alba Iulia-Mintia 220 kV OHL and the Alba Iulia-Cluj Floresti 220 kV OHL Considering that not even in the most unfavorable situations does the loading of these lines exceed 85% of the 400 mm2 capacity, an investment can be brought up only in terms of the reference design regime criteria (standardization of the conductor section).

133

Opportunity to increase the transmission capacity of the Urechesti-Targu Jiu Nord-Paroseni- Baru Mare-Hajdat 220 kV axis (at least by replacing the active conductors with 400 mm2 sections with conductors with 450 mm2 sections) considering the definitive outage of the Mintia SPP and Paroseni CHPP groups The proposal to replace conductors for all the 220 kV OHL line segments of the Urechesti-Tg. Jiu Nord-Paroseni-Baru Mare-Hajdat 220 kV OHL does not solve all overloads which may occur in the PTG; additional output downsizes are necessary for the sources in the South-West area. A new Urechesti-Mintia 400 kV OHL solves the overloads in the area; however, based on the economic efficiency analysis, this new investment was deemed inefficient. Analyses will be continued in order to identify an acceptable solution that leads to an increased safety of supply for significant consumers from the Valea Jiului area, as well as an increased interconnection capacity of the NPS.

Opportunity to increase the transmission capacity of the Lacu Sarat-Filesti-Barbosi-Focsani Vest-Gutinas 220 kV axis (at least by replacing the active conductors with 400 mm2 sections with conductors with 450 mm2 sections) considering the overloads that occur in larger generations in WPPs from section S6 The decision to replace conductors must be taken in correlation with the commissioning of the first circuit of the new Smardan-Gutinas 400 kV d.c. OHL, with the evolution of the Dobrogea WPP installed capacity, but also with the concrete possibilities for replacing conductors, taking into consideration the difficulty to work in city areas, and following an analysis of the OHL technical condition regarding the possibility and ability to replace conductors.

Opportunity to invest in conductor replacement of certain 220 kV OHLs on the Ungheni-Gutinas 220 kV axis, considering the updated evolutions of the NPS connections of renewable sources-based power plants For the Stejaru-Gheorgheni-Fantanele 220 kV OHL section it is deemed appropriate to increase the conductor section by at least 50%, correlated with the construction of the Suceava-Gadalin 400 kV OHL and the evolution of the WPP installed capacity in the S3 section. Replacing conductors in the following elements is not deemed as necessary: Ungheni-Fantanele 220 kV OHL, Stejaru-Dumbrava 220 kV OHL and Dumbrava-Gutinas 220 kV OHL.

10.1.9. Analysis of the impact over the NPS of the delay/postponement of the commissioning deadline of projects set forth in the 2016-2025 PTG development plan and included in the BAR

Impact over the NPS of the delay/postponement of the commissioning deadline of the Portile de Fier-Resita 400 kV OHL Postponing the commissioning deadline of the Portile de Fier-Resita 400 kV OHL leads to increased overloads in the WEP and SMP sections on the Portile de Fier-Resita 220 kV d.c. OHL, thus implying larger power reductions in the Portile de Fier HPP (compared to the scenario with the line in operation) and increased losses from the S1 section, between 6.7 MW and 11.8 MW, depending on the section analyzed. Also, in sensitivity regimes which do not consider the Mintia

134

SPP and the Paroseni CHPP as operational, a power reduction in the Rovinari SPP is also necessary (89 MW in WEP and 109 MW in SMP respectively). In both analyzed sections (WEP and SMP) we see a decreased export in the regime with N operational elements on the Resita-Pancevo d.c. OHL (up to 409 MW in WEP and 353 MW in SMP).

Impact over the NPS of the delay/postponement of the commissioning deadline of the connection of the Stupina-Varna (Bulgaria) 400 kV OHL and the Rahman-Dobrudja (Bulgaria) 400 kV OHL, input/output in the Medgidia Sud 400 kV substation via two 400 kV d.c. OHLs Postponing the commissioning deadline of the connection of the two interconnection lines (with Bulgaria) input/output in the Medgidia Sud 400 kV substation leads to an increase, in all analyzed sections (WEP, SMP and SNL), of the power flow towards the Bucharest area, thus implying power reductions from WPPs in the Medgidia and Constanta areas of ca. 139 MW in WEP, ca. 716 MW in SMP and ca. 202 MW in SNL respectively. Postponing the commissioning deadline of the connection of the two interconnection lines (with Bulgaria) input/output in the Medgidia Sud 400 kV substation also leads to increased losses in the S6 section, between 4.7 MW and 14 MW, depending on the section analyzed. In all analyzed sections (WEP, SMP and SNL) we see a decreased export in the regime with N operational elements on the Stupina-Varna 400 kV OHL and the Rahman-Dobrudja 400 kV OHL (by up to 103 MW in WEP, up to 109 MW in SMP and up to 126 MW in SNL).

Impact over the NPS of the delay/postponement of the commissioning deadline of the Smardan- Gutinas 400 kV d.c. OHL (1 circuit equipped) The postponement of the commissioning deadline of the Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped) leads to the occurrence of an overload on the Filesti-Barbosi 220 kV OHL when disconnecting the existing Smardan-Gutinas 400 kV OHL in the following sections: WEP – considering the WPP production at 90% of Ci and 600 MW transit via Romania from the Republic of Moldova towards Bulgaria/Hungary, SMP – considering the WPP production at 90% of Ci, with and without the 600 MW transit from the Republic of Moldova, SNL – considering the WPP production at 90% of Ci. In order to eliminate the overload, it is necessary to limit the power discharged from WPPs in section S6 and/or to reduce the imported/transited power (where applicable) from the Isaccea 400 kV substation from the Republic of Moldova. In the analyzed sections (WEP, SMP and SNL), in the regime with N operational elements, the postponement of the commissioning deadline of the Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped) leads to a significant increase in power losses in the analyzed area, between 3 MW and 8.7 MW, depending on the section analyzed.

Impact over the NPS of the delay/postponement of the commissioning deadline of the Cernavoda-Gura Ialomitei-Stalpu 400 kV d.c. OHL and the conversion to the 400 kV voltage of the Brazi Vest-Teleajen-Stalpu 220 kV OHL The postponement of the commissioning deadline of the Cernavoda-Gura Ialomitei-Stalpu 400 kV d.c. OHL and the conversion to the 400 kV voltage of the Brazi Vest-Teleajen-Stalpu 220 kV OHL leads to the occurrence of an overload on the Bucuresti Sud-Gura Ialomitei 400 kV OHL and even on the Pelicanu-Cernavoda 400 kV OHL (in the regime with import/transit) in the section

135 where the WPP production is considered at 90% of Ci, with and without the 600 MW import/transit from the Republic of Moldova. In order to eliminate the overload, it is necessary to limit the power discharged from WPPs in section S6 and/or to reduce the imported/transited power (where applicable) from the Isaccea 400 kV substation from the Republic of Moldova. In the analyzed sections (WEP, SMP and SNL), in the regime with N operational elements, the postponement of the commissioning deadline of the Cernavoda-Gura Ialomitei-Stalpu 400 kV d.c. OHL and the conversion to the 400 kV voltage of the Brazi Vest-Teleajen-Stalpu 220 kV OHL leads to a significant increase in power losses in the analyzed area, between 8.6 MW and 24.2 MW, depending on the section analyzed.

Impact over the NPS of the delay/postponement of the commissioning deadline of the Medgidia Sud-Constanta Nord 400 kV d.c. OHL (1 circuit equipped) In the analyzed sections (WEP, SMP and SNL), in the regime with N operational elements, the postponement of the commissioning deadline of the Medgidia Sud-Constanta Nord 400 kV d.c. OHL leads to an increase in power losses in the analyzed area, between 0.6 MW and 3.7 MW, depending on the section analyzed.

Impact over the NPS of the delay/postponement of the commissioning deadline for the conversion to the 400 kV voltage of the West axis – stage 2 – construction of the Resita- Timisoara/Sacalaz-Arad 400 kV d.c. OHL The postponement of the commissioning deadline for the conversion to the 400 kV voltage of the West axis – stage 2 – construction of the Resita-Timisoara/Sacalaz-Arad 400 kV d.c. OHL primarily leads to high overloads on the Resita-Timisoara 220 kV d.c. OHL; these overloads can be eliminated by significant power reductions from the Portile de Fier I HPP (up to under 200 MW) and the Turceni SPP respectively. Increased losses are also highlighted, between 14 MW and 27.4 MW, depending on the regime analyzed.

Impact over the NPS of the delay/postponement of the commissioning deadline of the Gadalin- Suceava 400 kV OHL The postponement of the commissioning deadline of the Gadalin-Suceava 400 kV OHL has an impact over the Ardeal area (section 4), with increased losses between 1.4 MW and 8 MW, depending on the regime analyzed. The postponement of the commissioning deadline of the Gadalin-Suceava 400 kV OHL has an impact over section 3, with a significant increase of overloads on the Stejaru-Gheorgheni 220 kV OHL and the Gheorgheni-Fantanele 220 kV OHL; eliminating these overloads requires a significant reduction of the power discharged from WPPs. Increased losses are also highlighted, between 2.5 MW and 15 MW, depending on the section and the regime analyzed.

Impact over the NPS of the delay/postponement of the commissioning deadline of the Stalpu- Brasov 400 kV d.c. OHL (1 circuit equipped) The postponement of the commissioning deadline of the Stalpu-Brasov 400 kV OHL (1 circuit equipped) leads to increased losses between 0.4 MW and 6 MW, depending on the section and the regime analyzed.

136

The necessity to commission this 400 kV OHL is linked to the increasing surplus in power generated in the S6 section (additional wind power plants and groups 3 and 4 in the Cernavoda NPP respectively).

* In terms of the substations which will be refurbished, it is worth noting the significance of the safety level of functions which these substations fulfill, namely: . reducing operational expenses to a maximum of 1%; . power transit; . connecting and discharging the power of a source; . transformer substation and safety of supply in demand areas.

10.2. Loading degree of PTG elements

In the basic average steady-state conditions, the power flows on the PTG elements are under the thermal thresholds. The PTG usage degree is low in BAR compared to the transmission capacity at the thermal limit of component elements. However, it must be taken into account that during operation, operational regimes might significantly deviate from the BAR as a result of the permanent change in the demand and generation level and structure and due to outages for planned and unexpected repairs. This can lead to very distinct loads on the network elements. A reserve is also mandatory, as the PTG elements must be able to take over the additional load at any time, in the event of triggering an NPS element: line, transformer, group or consumer. Annex G presents the loads on the PTG elements in the basic average regimes in the WEP, SNL and SMP sections, for the mid and long forecast timescales.

10.3. Voltage level, voltage control and reactive power compensation The studies conducted showed that the voltage values at the nodes are within the rated limits as per the PTG Technical Code (included in Table 10.3). Table 10.3 [kV] Rated voltage Rated variation margin 750 735-765 400 380-420 220 198-242

137

Verifications conducted for the regimes with N-1 operating elements in WEP and SNL outlined PTG voltage levels within acceptable limits.

10.4. PTG power losses in sections specific to the load curve

Tables 10.4.1 and 10.4.2 present the values obtained from the active power losses calculations, in basic average regimes with all grid elements in operation, in sections specific to the load curve: Table 10.4.1 – NPS and PTG power losses evolution Palier VSI 2018 VDV 2018 GNV 2018 VSI 2022 VDV 2022 GNV 2022 VSI 2027 VDV 2027 GNV 2027 Total Total Total Total Total Total Total Total Total Total Total Total Total Total Total Total Total Total pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi pierderi SEN RET SEN RET SEN RET SEN RET SEN RET SEN RET SEN RET SEN RET SEN RET [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] [MW] Total 301 184 247 158 168 129 304 194 248 167 168 129 357 224 270 178 191 148

Table 10.4.2 – Share of PTG power losses on grid elements

Palier VSI 2018 VDV 2018 GNV 2018 VSI 2022 VDV 2022 GNV 2022 VSI 2027 VDV 2027 GNV 2027 Element de retea [MW] [%] [MW] [%] [MW] [%] [MW] [%] [MW] [%] [MW] [%] [MW] [%] [MW] [%] [MW] [%] LEA 400 kV 92 50 78 49 75 58 105 54 88 53 75 58 141 63 106 60 104 70 LEA 220 kV 68 37 58 36 34 26 64 33 55 33 34 26 56 25 46 26 23 16 TR 400/110 kV 9 5 8 5 7 5 9 5 8 5 7 6 11 5 10 6 9 6 AT 400/2200 kV 5 3 5 3 5 4 6 3 6 4 5 4 6 3 6 3 5 3 AT 220/110 kV 10 5 10 6 8 6 10 5 10 6 8 6 10 5 10 6 8 5 Total pierderi in RET 184 100 158 100 129 100 194 100 167 100 129 100 224 100 178 100 148 100 [MW] / [%]

Figure 10.4 – Evolution of the share of losses in the net internal electricity demand

Losses in different operational regimes may heavily vary compared to the ones calculated for average regimes, particularly as a result of changes in the loading of power plants. Therefore, in

138 intervals with a high generation in WPPs/PVPPs in Dobrogea and/or Moldova, it is estimated that PTG losses will rise by ca. 20 MW in 2022 and by ca. 16 MW in 2027 respectively, compared to the basic average regime, due to the generation being concentrated far away from the main demand areas.

Energy efficiency within CNTEE Transelectrica S.A is based on the requirements provided by national legislation in conjunction with the applicable European legislation, namely: - Directive (EU) 32/2006; - Directive (EU) 27/2012; - Law no. 121/2014, aimed at enforcing Directive 27/2012 on energy efficiency for end users and energy services; - The National Energy Efficiency Action Plan (NEEAP III 2014-2020); - Law no. 372/2005 on energy performance of buildings;

The energy efficiency approach of CNTEE Transelectrica S.A considers two significant aspects, namely: o Improving the energy efficiency of facilities and equipment in the power transmission grid; o Improving the energy efficiency of buildings from the estate.

Law no. 121/2014 classifies economic operators in different categories in terms of final energy consumption, so that CNTEE Transelectrica S.A falls under the industrial consumer category, with over 1,000 TOE (tons of oil equivalent), this being due largely to the own technological consumption (OTC). Practically, the OTC in the transmission grid is generally given by the load distribution from the NPS and the necessity to operate under normal circumstances whilst assuring continuity of the transmission service and the quality of electricity. CNTEE Transelectrica SA aims to accelerate the modernization and refurbishment program for existing electrical substations by introducing systems for optimizing consumption from internal services in order to increase operational safety, as well as by decreasing electricity consumption in substations:  Endowing Transelectrica substations with photovoltaic panels which can supply part of the energy necessary to support internal services (where possible, regularly after refurbishment);  Optimizing the electricity supply of Transelectrica premises (optimizing thermal power and electricity consumption on Transelectrica premises). Measures for operation: • optimal unlooping of distribution grids; • setting the optimal number of operational and reserve transformation units – whilst complying with safety conditions – aiming to reduce their losses to a minimum; • optimizing the normal scheme for off-peak load regimes (as operational transformation lines and units); • reducing the duration of maintenance and repair works which require powering down the installations; • extending the use of the live works (LW) technology on lines and stations at all voltage levels. In order to reduce PTG losses, the following measures are taken into account:  replacing obsolete bucking coils which have large losses;

139

 replacing old transformation units which have large losses;  using the optimal active conductors’ configuration and section in 400 kV OHLs (e.g.: conversion from 2x450 mm2 to 3x300 mm2 / 3x450 mm2) for reducing Corona and Joule losses respectively;  reducing the grid elements outage duration.

10.5. Short-circuit loads In compliance with PE 026, the levels of short-circuit currents in the 400 kV, 220 kV and 110 kV grids, considered in the reference design of NPS power facilities, are usually the following:  at a 400 kV voltage: 31.5 – 50 kA (20 – 35 GVA);  at a 220 kV voltage: up to 40 kA (15 GVA);  at a 110 kV voltage: up to 40 kA (7.5 GVA).

Mid term

Calculations allowed highlighting the following conclusions:

 The maximum level of the three-phase short-circuit current is recorded in the following substations:  Cernavoda 400 kV, I3 = 22.9 kA;  Portile de Fier 220 kV, I3 = 30.4 kA;  Grozavesti 110 kV, I3 = 46.99 kA.

 The maximum level of the one-phase short-circuit current is recorded in the following substations:  Cernavoda 400 kV, I1 = 27.2 kA;  Portile de Fier 220 kV, I1 = 38.3 kA;  Domnesti 110 kV, I1 = 56 kA.

 The maximum level of the two-phase short-circuit grounded current is recorded in the following substations:  Cernavoda, Constanta Nord, Medgidia Sud 400 kV, I2p = 26 kA;  Portile de Fier 220 kV, I2p = 37 kA;  Domnesti 110 kV, I2p = 53.7 kA.

The computed short-circuit current values have been compared to the breaking current values from the analyzed substation equipment. According to this analysis, in the mid-term, we estimated breaking cap overruns of breakers in 38 110 kV substations in the Bucharest area and in the Medgidia Sud 110 kV substation. These overruns are solved by unlooping the grid and operating under the normal scheme.

Long term

Calculations allowed highlighting the following conclusions:

140

 The maximum level of the three-phase short-circuit current is recorded in the following substations:  Cernavoda 400 kV, I3 = 28.5 kA;  Portile de Fier 220 kV, I3 = 30 kA;  Militari 110 kV, I3 = 42.7 kA.

 The maximum level of the one-phase short-circuit current is recorded in the following substations:  Cernavoda 400 kV, I1 = 37 kA;  Portile de Fier 220 kV, I1 = 40.1 kA;  Domnesti 110 kV, I1 = 51.9 kA.

 The maximum level of the earthed two-phase short-circuit current is recorded in the following substations:  Cernavoda 400 kV, I2p = 36.2 kA;  Portile de Fier 220 kV, I2p = 39.9 kA;  Domnesti 110 kV, I2p = 48.1 kA.

Following the comparison of the short-circuit values resulted from the calculation with the breaking currents of the electric equipment, we established breaking cap overruns of breakers in the following substations:  Medgidia Sud 400kV I1 =32.2 kA, I2p=31.5 kA;  Portile de Fier B 220kV I1 = 40.13 kA, I2p = 40.03 kA;  Medgidia Sud 110kV I1 = 37 kA, I2p = 37.8 kA;  Constanta Nord I1 110 kV substation = 32.18 kA. We also established overruns in 40 110 kV substations in the Bucharest area, which can be solved by unlooping the grid and operating under the normal scheme.

10.6. Inspection of the PTG under steady-state stability conditions 10.6.1. Results of steady-state stability analyses – mid term The PTG inspection under steady-state and transient stability conditions has been carried out via dedicated studies [5]. Table 10.6.1 briefly presents the type of the system areas in every section specific to the NPS, in the mid-term, for the peak basic average regime. Table 10.6.1 – Surplus/deficit in sections specific to the NPS, mid-term [MW] Specific section Type WEP Mid term S1 Surplus 1,963 S2 Deficit 200 S3 Surplus 1,133 S4 Deficit 667

141

S5 Deficit 321 S6 Surplus 1,454 S7 Deficit 1,247

Annex D – Tables 1.1 to 1.7 – presents the admissible limits of power transmitted via sections specific to the NPS.

10.6.2. Results of steady-state stability analyses – long term Table 10.6.2 briefly presents the type of the system areas in every section specific to the NPS, in the long term, for the peak basic average regime:

Table 10.6.2 – Surplus/deficit in sections specific to the NPS, long term [MW] Specific section Type WEP Long term S1 Surplus 1,324 S2 Surplus 943 S3 Surplus 2,460 S4 Deficit 876 S5 Deficit 231 S6 Surplus 2,713 S7 Deficit 1,594

Annex D – Tables 2.1 to 2.7 – presents the admissible limits of power transmitted via sections specific to the NPS. For each of the NPS specific sections we identified the additional steady-state stability reserves (SSR) compared to the maximum admissible powers, in the basic average steady-state regime, in the complete scheme configuration (N) or with one withdrawn element (N-1); this is illustrated in Table 10.6.3: Table 10.6.3 – Additional steady-state stability reserves (SSR) in specific sections Mid term Long term Section SSR [MW] N N-1 N N-1 S1 551 48 1,299 326 S2 2,099 1,666 1,886 784 S3 1,684 1,296 1,590 900 S4 504 0 139 50 S5 380 0 891 676 S6 1,103 927 1,991 1,209 S7 423 17 1,640 1,014 Based on the data presented in Table 10.6.3, the following conclusions can be drawn regarding the basic average steady-state regime: For operation under the long-term N configuration:

142

– In the mid-term, all specific sections (S1 – S7) show sufficient stability reserves in terms of the maximum admissible powers in the section (minimum 380 MW – S5, and maximum 2,099 MW – S2); if power plants from surplus areas (e.g. delimited by S3, S6) will have loads higher than the ones considered in the BAR, the additional reserves are diminished and can even reach negative values, which implies applying congestion management mechanisms. – In the long term, all specific sections (S1 – S7) show sufficient stability reserves in terms of the maximum admissible powers in the section, the lowest being for the S4 section – 139 MW and the highest being for the S6 section – 1,991 MW;

For operation under the long-term N-1 configuration: – In the mid-term, all specific sections (S1 – S7) show stability reserves in terms of the maximum admissible powers in the section, except for the S4 and S5 sections; complying with the operational technical conditions (Padm in the section) implies that in the configuration with N-1 operational elements, the minimum loading of the groups in the section must be at least equal with the one in the S4 and S5 basic average regime, these sections being at the stability limit in this configuration. If power plants from surplus areas (e.g. delimited by S3, S6) will have loads higher than the ones considered in the BAR, the additional reserves are diminished and can even reach negative values, which implies applying congestion management mechanisms.

– – In the long term, all specific sections (S1 – S7) show stability reserves in terms of the maximum admissible powers in the section, the lowest being for the S4 section – 50 MW and the highest being for the S6 section – 1,209 MW. If power plants from surplus areas (e.g. delimited by S1, S6) will have higher loads, the additional reserves are diminished and can even reach negative values, which implies applying congestion management mechanisms.

Table 10.6.4 illustrates the evolution of the steady-state stability limits and the maximum admissible powers in the NPS specific sections for the regime with N operational elements. It can be seen that generally, carrying out PTG development projects leads to the increase of steady-state stability limits or of maximum admissible powers in the specific sections: Table 10.6.4 Features of the Stage Section section 2018 2022 2027 SSL 4,972 5,669 7,784

Pmax adm 3,140 2,514 2,623 - Portile de Fier-Resita 400 New elements in kV OHL S1 Resita- the section/in the - Resita-Pancevo 400 kV d.c. - Timisoara/Sacalaz-Arad corresponding OHL 400 kV d.c. OHL area - Ostrovu Mare 220 kV substation S2 SSL 3,798 4,749 4,437

143

Features of the Stage Section section 2018 2022 2027

Pmax adm 2,819 2,299 2,829 - Connecting the Stupina- Varna (Bulgaria) 400 kV - Gadalin-Suceava 400 OHL, input/output in the kV OHL; Medgidia 400 kV substation via a 400 kV d.c. OHL; - Connecting the Rahman- Dobrudja (Bulgaria) 400 kV - Stalpu-Brasov 400 kV OHL, input/output in the d.c. OHL (1 circuit Medgidia 400 kV substation equipped); via a 400 kV d.c. OHL; - Cernavoda-Gura Ialomitei-Stalpu 400 kV d.c. OHL; - Brazi Vest-Teleajen-Stalpu OHL with 400 kV voltage operation; New elements in - Smardan-Gutinas 400 kV the section/in the d.c. OHL (1 circuit - corresponding equipped); area - Second 400 MVA, 400/220 kV AT in the Brazi Vest substation; - Medgidia Sud-Constanta Nord 400 kV d.c. OHL (1 circuit equipped); - Increasing the transmission capacity of the Stejaru-

Gheorghieni-Fantanele 220 kV OHL; - Increasing the transmission capacity of the Cernavoda- Pelicanu 400 kV OHL; - Increasing the transmission capacity of an 8 km long

segment on the Bucuresti Sud-Pelicanu 400 kV OHL. SSL 3,282 3,280 7,908 P 2,656 2,817 3,360 S3 max adm New elements in - Cernavoda-Gura Ialomitei- - Gadalin-Suceava 400 - the Stalpu 400 kV d.c. OHL; kV OHL;

144

Features of the Stage Section section 2018 2022 2027 section/elements - Connecting the Stupina- that influence the Varna 400 kV OHL and the - Stalpu-Brasov 400 kV corresponding Rahman-Dobrudja 400 kV d.c. OHL (1 circuit area OHL, input/output in the equipped); Medgidia 400 kV substation; - Brazi Vest-Teleajen-Stalpu OHL with 400 kV voltage operation; - Increasing the transmission capacity of the Stejaru-

Gheorghieni-Fantanele 220 kV OHL; - Increasing the transmission capacity of the Cernavoda- Pelicanu 400 kV OHL; - Increasing the transmission capacity of an 8 km long

segment on the Bucuresti Sud-Pelicanu 400 kV OHL; - Smardan-Gutinas 400 kV

d.c. OHL (1 circuit equipped). SSL 1,943 2,255 1,805

Pmax adm 1,171 1,171 1,015 - Second 400 MVA, 400/220 New elements in - Gadalin-Suceava 400 kV AT in the Iernut the kV OHL; S4 substation; section/elements - - Increasing the transmission that influence the capacity of the Stejaru- corresponding Gheorghieni-Fantanele 220 area kV OHL; SSL 1,459 1,799 1,534

Pmax adm 708 701 1,122 - Smardan-Gutinas 400 kV New elements in - Gadalin-Suceava 400 d.c. OHL (1 circuit the kV OHL; S5 equipped); section/elements - - Increasing the transmission that influence the capacity of the Stejaru- corresponding Gheorghieni-Fantanele 220 area kV OHL; SSL 3,305 3,789 6,316 S6 Pmax adm 2,728 2,557 4,704

145

Features of the Stage Section section 2018 2022 2027 - Cernavoda-Gura Ialomitei- Stalpu 400 kV d.c. OHL; - Connecting the Stupina- Varna 400 kV OHL and the Rahman-Dobrudja 400 kV OHL, input/output in the Medgidia 400 kV substation; New elements in - Brazi Vest-Teleajen-Stalpu the OHL with 400 kV voltage - Stalpu-Brasov 400 kV section/elements - operation; d.c. OHL (1 circuit that influence the - Increasing the transmission equipped); corresponding capacity of the Cernavoda- area Pelicanu 400 kV OHL; - Increasing the transmission capacity of an 8 km long segment on the Bucuresti Sud-Pelicanu 400 kV OHL; - Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped). SSL 3,141 3,742 3,996

Pmax adm 1,768 1,670 3,234 - Resita- - Portile de Fier-Resita 400 Timisoara/Sacalaz-Arad kV OHL; 400 kV d.c. OHL; - Resita-Pancevo 400 kV d.c. - Gadalin-Suceava 400 OHL kV OHL; - Stalpu-Brasov 400 kV - Ostrovu Mare 220 kV d.c. OHL (1 circuit substation New elements in equipped); - Second 250 MVA, 400/110 S7 the section/elements kV T in the Sibiu Sud - that influence the substation; corresponding - Second 400 MVA, 400/220 area kV AT in the Iernut substation; - Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped); - Increasing the transmission capacity of the Stejaru-

Gheorghieni-Fantanele 220 kV OHL;

146

Features of the Stage Section section 2018 2022 2027 - Increasing the transmission capacity of the Dumbrava- Stejaru 220 kV OHL.

10.7. Transient stability and protection measures in PTG nodes Considering the major impact of the protection installations' quality on the NPS safety at a relatively lower cost compared to the cost of primary equipment, CNTEE Transelectrica SA adopted a strategy to equip all substations with modern and efficient command, control and protection systems. These systems are introduced both when refurbishing the transmission substations, and by means of a special modernization program enforced in the remaining substations. Remote transmission on PTG lines is also used and while refurbishing the substations we also install modern breakers, with a shorter turn-on duration. These actions lead to improving the NPS transient stability. In order to identify substations which, need measures to ensure the transient stability, as well as to establish protection controls, we carry out dedicated calculations which consider the precise momentary characteristics of primary and secondary equipment from substations, as well as of groups installed in the system. Considering the uncertainties related to the generation park, as well as the sequencing of market changes, the calculations for verifying the transient stability, which identify necessary measures (parameter setting for protections and automations, ensuring remote transmissions, establishing PSS parameter sets in groups), are carried out for each change of situation as well as periodically, at least once per semester. According to Article 132 (a) of the PTG technical code, the transient stability conditions in the PTG are verified for a period of up to five years. For the five- and ten-year period covered by the Development plan, we carried out a set of calculations in order to present an overview of the significant aspects for the safe and stable operation of the NPS and in order to identify potential major problems that can be only solved by preparing precise and detailed analyses ahead of time. In these calculations, in order to check the transient stability in short-circuits on PTG lines, in steady-state regimes characterized by the rated steady-state stability reserve, we used a duration to cover the elimination of defects – working reference – of 200ms (significantly higher than real-time values). For short-circuits on power plant busbars we used a duration of 100ms – working reference – for the elimination of defects, which considers the total time required for all operations associated with a defect on the busbars, correctly eliminated via protections and automations. We also considered that a tripping via DBP in the substation is transmitted as a direct tripping via the remote protection in the ends of the lines adjacent to the busbar with a defect/tripping refusal (t = 100ms).

Transient stability analysis – WEP section – 2018

Discharging the power generated in power plants We analyzed the potentially dangerous situations in terms of transient stability in the vicinity of the following power plants: . Cernavoda NPP, Ci = 2 x 706.5 MW; . Turceni SPP, Ci = 2 x 330 MW;

147

. Rovinari SPP, Ci = 3 x 330 MW; . Iernut SPP, Ci = 2 x 100 MW + 2 x 200 MW; . OMV Brazi CCPP, Ci = 2 x 305 MW + 1 x 315 MW; . Isalnita SPP, Ci = 2 x 315 MW; . Portile de Fier I HPP, Ci = 6 x 194.4 MW.

The analyses carried out did not highlight any potentially dangerous situations. The occurrence of a symmetrical three-phase short-circuit on the electric lines for discharging power from the analyzed power plants, eliminated by tripping the OHL impacted by the defect, with the correct tripping of protections, does not lead to the loss of transient stability. The simulations showed that transient stability is maintained both for the operation in the long-term N configuration, and for the operation in the long-term N-1 configuration. We also carried out calculations to identify the Critical Time for Defect Elimination (CTDE). For each of the analyzed power plants, we simulated a transient metallic three-phase short-circuit on the power plant busbars. Table 10.7.1 presents the calculation results:

Table 10.7.1 – Critical time for defect elimination on the power plant busbars – 2018 CTDE1) DET2) SR3) Restrictive Electric node t t stable unstable machinery [ms] [ms] [%] Cernavoda 400 kV 389 397 100 297 75 G2 Turceni 400 kV 498 506 100 406 80 G4 Urechesti 400 kV 561 569 100 469 82 G4 100 G1, G2, G3, G4, G5, Portile de Fier 400 kV 327 334 234 70 G6 100 G1, G2, G3, G4, G5, Portile de Fier 220 kV A 241 248 148 60 G6 100 G1, G2, G3, G4, G5, Portile de Fier 220 kV B 241 248 148 60 G6 Isalnita 220 kV 209 217 100 117 54 G7 OMV Brazi 400 kV 317 327 100 227 69 G2 OMV Brazi 220 kV 519 530 100 430 91 G3 Iernut 220 kV 233 241 100 141 59 G5, G6 Iernut 400 kV 373 381 100 281 74 G5, G6 1) CTDE – Critical Time for Defect Elimination, 2) DET – Defect Elimination Time, 3) SR – Stability Reserve

The verification of the critical time for defect elimination on the busbars of analyzed power plants highlighted the existence of a stability reserve for the defect isolating time, imposed by the existing protection equipment. The extreme values of the stability reserve are the following:  minimum stability reserve of 54% in the Isalnita SPP, 220 kV section;  maximum stability reserve of 82% in the Rovinari SPP, 400 kV section.

148

Transient stability with limit loading of NPS specific sections In terms of transient stability, we analyzed the dangerous situations which might occur during the operation of the NPS when the specific sections are loaded close to the steady-state stability limits with rated reserve. Taking into account the admissible limits of circulations through sections in terms of steady-state stability, we analyzed the seven NPS specific sections under the following conditions:

. Section S1, surplus, P8 % = 4,384 MW;

. Section S2, deficit, P8 % = 3,328 MW;

. Section S3, surplus, P8 % = 2,791 MW;

. Section S4, deficit, P8 % = 1,493 MW;

. Section S5, deficit, P8 % = 1,201 MW;

. Section S6, surplus, P8 % = 2,833 MW;

. Section S7, surplus, P8 % = 2,616 MW;

The analyses allowed highlighting the following aspects: . For long term steady-state regimes operating in full configuration, we analyzed 524 distinct cases for each NPS specific section. Following the simulations carried out, we can conclude that there is no risk of transient stability loss in the NPS when maintaining a loading level under the steady-state stability limits with rated stability reserve. The calculations consisted of simulating the permanent three-phase short-circuits eliminated by the correct tripping of protections in a 160ms interval (reference defect elimination time). . For long term steady-state regimes operating in incomplete configuration, we analyzed 510 distinct cases for each NPS specific section. Following the simulations carried out, we can conclude that there is no risk of transient stability loss in the NPS in the long-term N-1 configuration when maintaining a loading level under the steady-state stability limits with rated stability reserve. The calculations consisted of simulating the permanent three-phase short-circuits eliminated by the correct tripping of protections in a 160ms interval (reference defect elimination time).

Transient stability analysis – WEP section – 2022

Discharging the power generated in power plants We analyzed the potentially dangerous situations in terms of transient stability identifiable in the vicinity of the following power plants: . Cernavoda NPP, Ci = 2 x 706.5 MW; . Turceni SPP, Ci = 3 x 330 MW; . Rovinari SPP, Ci = 4 x 330 MW; . OMV Brazi CCPP, Ci = 2 x 285 MW + 1 x 315 MW; . Isalnita SPP, Ci = 2 x 315 MW; . Portile de Fier I HPP, Ci = 6 x 194.4 MW.

149

Table 10.7.2 – Critical time for defect elimination on the power plant busbars CTDE1) DET2) SR3) Restrictive Electric node t t stable unstable machinery [ms] [ms] [%]

Cernavoda 400 kV 389 397 100 297 75 G2 Turceni 400 kV 358 366 100 266 73 G7 Urechesti 400 kV 342 350 100 250 71 G3, G4 100 G1, G2, G3, G4, G5, Portile de Fier 400 kV 342 350 250 71 G6 100 G1, G2, G3, G4, G5, Portile de Fier 220 kV A 264 272 172 63 G6 100 G1, G2, G3, G4, G5, Portile de Fier 220 kV B 256 264 164 52 G6 Isalnita 220 kV 225 233 100 133 57 G7 OMV Brazi 400 kV 545 553 100 453 82 G2 OMV Brazi 220 kV 313 322 100 222 68 G3 1) CTDE – Critical Time for Defect Elimination, 2) DET – Defect Elimination Time, 3) SR – Stability Reserve

The verification of the critical time for defect elimination on the busbars of analyzed power plants highlighted the existence of a stability reserve for the defect isolating time, imposed by the existing protection equipment. The extreme values of the stability reserve are the following:  minimum stability reserve of 57% in the Isalnita SPP, 220 kV section;  maximum stability reserve of 82% in the OMV Brazi CCPP, 400 kV section.

. Section S1, surplus, P8 % = 5,189 MW;

150

. Section S2, deficit, P8 % = 3,386 MW;

. Section S3, surplus, P8 % = 2,823 MW;

. Section S4, deficit, P8 % = 1,725 MW;

. Section S5, deficit, P8 % = 1,107 MW;

. Section S6, surplus, P8 % = 3,165 MW;

. Section S7, surplus, P8 % = 2,858 MW;

The analyses allowed highlighting the following aspects: . For long term steady-state regimes operating in full configuration, we analyzed 578 distinct cases for each NPS specific section. Following the simulations carried out, we can conclude that there is no risk of transient stability loss in the NPS when maintaining a loading level under the steady-state stability limits with rated stability reserve. The calculations consisted of simulating the permanent three-phase short-circuits eliminated by the correct tripping of protections in a 200ms interval (reference defect elimination time). . For long term steady-state regimes operating in incomplete configuration, we analyzed 564 distinct cases for each NPS specific section. Following the simulations carried out, we can conclude that there is no risk of transient stability loss in the NPS in the long-term N-1 configuration when maintaining a loading level under the steady-state stability limits with rated stability reserve. The calculations consisted of simulating the permanent three-phase short-circuits eliminated by the correct tripping of protections in a 200ms interval (reference defect elimination time).

The loading of each section to the value of the steady-state stability limiting power with rated stability reserve presents no risk of stability loss in the generating units of the NPS, given PTG symmetrical three-phase short-circuit loadings.

10.8. Conclusions regarding PTG operation regimes in perspective The analysis of the PTG operation regimes identified the need to consolidate the grid, in order to ensure a rated service quality under the forecasted NPS evolution hypotheses.

PTG consolidation needs correlated with the Dobrogea generation park evolution Network development should consider solutions that enable eliminating the congestions along the main directions of power flows between generation centers in the eastern part of the country and the western load and storage centers, which correspond to the following transmission corridors: 1. N-S corridor interconnecting Dobrogea and Moldova; 2. E-W corridor interconnecting Dobrogea and Bucharest + limit area; 3. E-W corridor interconnecting Moldova and the NPS to the West.

151

Several potential projects have been identified, whose adequacy related to the pursued objective has been checked with several system studies in different mid and long term NPS evolution scenarios: - Connecting the Isaccea (Rahmanu)-Dobrudja and Isaccea (Stupina)-Varna 400 kV OHL in the Medgidia 400 kV substation in the input/output scheme in order to secure the N-1 criterion for WPPs connected in the Rahmanu and Stupina 400 kV substations; - Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped); - Cernavoda-Stalpu 400 kV d.c. OHL, with a circuit connected in the Gura Ialomitei substation and conversion to the 400 kV operational voltage of the Stalpu-Teleajen- Brazi Vest OHL operating at 220 kV; - Suceava-Gadalin 400 kV s.c. OHL; - Medgidia Sud-Constanta Nord 400 kV OHL (1 circuit equipped); - Increasing the transmission capacity of the Stejaru-Gheorghieni 220 kV OHL via replacement of conductors; - Converting the Isaccea-Tulcea Vest 400 kV OHL from single to double circuit.

PTG consolidation needs correlated with insufficient generation in deficit areas The steady-state stability analyses show that the S4 (N-V Transylvania) and S5 (Moldova) sections present a high risk of operation close to the maximum admissible power in the section, both in the mid and in the long term, thus proving the need to enhance each one of these sections. To this effect, enhancing the power transmission grid by completing the 400 kV ring between the northeastern and north-western parts of the NPS is beneficial with respect to increasing power reserves of steady-state stability both for sections S4 and S5 and for section S3. Several areas were also identified with local problems in terms of consumption supply safety, where additional injection capacities should be installed from the 400 kV grid towards the lower voltage grid (Iernut, Cluj, Brazi, Sibiu).

PTG consolidation needs for increasing the cross-border exchange capacity on the western border and for the transmission of the generation surplus from the Portile de Fier-Resita area towards the demand centers In order to ensure the increase in the exchange capacity with Serbia and Western Europe, the discharge of power from photovoltaic power plants and the hydroelectric structures in the Portile de Fier-Resita area, it is necessary to consolidate the transmission grid on the western axis (Portile de Fier-Resita-Timisoara-Arad). The following investments have been identified as appropriate solutions for consolidating the transmission grid: - Resita (Romania)-Pancevo (Serbia) 400 kV d.c. OHL; - Portile de Fier-Resita 400 kV d.c. OHL; - Resita 400 kV substation; - increasing the capacity of the Resita-Timisoara-Arad 220 kV d.c. OHL by conversion to the 400 kV voltage, including the construction of the Timisoara and Sacalaz 400 kV substations; - replacing the 400 MVA 400/220kV AT3 with a 500 MVA autotransformer in the Portile de Fier substation.

152

PTG consolidation needs correlated with decreasing generation and increasing consumption in the Bucharest municipality In order to ensure the safety of supply of the Bucharest municipality in the mid and long term, it was deemed appropriate to carry out new power injections from the PTG towards the distribution grid of the city of Bucharest, as well as to consolidate the distribution grid in order to facilitate taking over the demand from one area to another. The following projects were deemed appropriate based on the analyses:  The studies reconfirmed the need to construct two 400/110 kV substations, one in the central area of the Bucharest municipality (Grozavesti), in the mid-term, and another one in the Filaret area, in the long term.

In terms of transient stability, we analyzed dangerous situations which might occur during the operation of the NPS when the specific sections are loaded close to the steady-state stability limits with rated reserve. The transient stability analyses showed no potentially dangerous situations.

The calculation of the safety nodal indicators shows the following: - The refurbishment of substations leads to an improvement in the safety nodal indicators for all substations subject to refurbishment. If the substation subject to refurbishment is a source node for other substations, an improvement in the indicator values for these substations is also noted. - For the double-bar and transfer bar 400 kV and 220 kV substations subject to refurbishment where the transfer bar was disposed of, the improvement is obvious in the number of interruptions and average failure times, the maximum interruption time staying the same, with deviations above or below. - Generally speaking, for substations not subject to refurbishment, a change in the indicators may be noted as a result of the associated change in safety.

153

11. PTG asset maintenance strategy for the following ten years

11.1. PTG facilities' maintenance strategy

11.1.1. General maintenance issues as part of Asset Management

Maintenance is included in CNTEE Transelectrica S.A's asset management concept and is, according to global practice, one of its constituents. In line with ANRE requirements, maintenance is carried out based on the Maintenance Plan (MP) that lays down the planning of the activity and introduces a modern concept of maintenance optimization and implementation. The MP comprises and maintains the entire documentation regarding maintenance activities while providing the framework to elaborate, review and/or update the documents, as the case may be. The MP implementation and the maintenance management are conducted by the CNTEE Transelectrica SA staff based on the operational procedures, prescriptions, technological sheets, internal technical standards and specific work instructions.

Maintenance complies with the requirements of the specific documentation, in particular: - Maintenance management and organization regulation – approved by ANRE Order no. 96/18.10.2017; - Performance standard for the electricity transmission service and system services, approved by ANRE Order no. 12/30.03.2016; - NTE 010/2011/00 – "Regulation on the execution of live works in 110-750 kV overhead power lines"; - Preventive maintenance regulation in PTG facilities and equipment – NTI-TEL-R-001-2007- 04; - PTG Development Plan; - Other specific regulations.

The current technical state of PTG facilities has maintained at a level appropriate for operational safety, as a result of the implementation of a rigorous maintenance program and a sustained investment program (refurbishment/modernization, development) of PTG facilities. Preventive maintenance programs are established in correlation with the investment programs (refurbishment/modernization, development), both at substation level and overhead power line level (OHL), on scientific bases via prioritization criteria leading to decisions on maintenance or investments. Given the current electric power generation and demand within the National Power System (NPS), considering the technologies used or the legislative and property titles aspects, etc., our goal is to promote new PTG maintenance solutions (selecting the type and reference design of OHL conductors, multi-circuit lines for using existing safety corridors, live work techniques (LWT), online treatment of insulation in transformation units for the reduction of outage times and avoidance of costs related to congestions and own technological consumption, multispectral inspection of OHLs, etc.).

Principles and objectives of the maintenance strategy within CNTEE Transelectrica S.A.

154

The maintenance approach required the establishment of principles within a more complex strategy that should lead to fulfilment of strategic maintenance objectives in support of fulfilling the Company's objectives.

Maintenance objectives  General strategic objectives: 1. Providing high availability of PTG assets; 2. Increasing operational flexibility; 3. Cost optimization; 4. Ensuring an appropriate maintenance staff policy;

 The specific strategic objectives for the maintenance activity (derived from the general strategic objectives) are:

1.1. reduction in the number and duration of accidental events, as well as their associated consequences; 1.2. reduction in the number and duration of preventive (planned) maintenance; 1.3. adopting solutions for increasing the flexibility of the program for outages and congestions avoidance; 1.4. increasing the quality of maintenance activities; 1.5. increasing accountability of operational personnel in terms of using active monitoring systems; 1.6. implementing risk management – identifying, analyzing, evaluating and dealing with risks; 1.7. ensuring and maintaining OHL safety corridors; 1.8. defining challenging performance indicators in maintenance and investment agreements (warranty and post warranty) with effect in terms of reducing the fixing periods of non- compliances; 1.9. increasing the response capacity for the occurrence of events with a significant impact on the PTG security and operation, including conducting simulation, training and testing exercises of the Company's capabilities.

2.1. using modern technologies (e.g. LW, multispectral inspections, mobile bays, intervention beams); 2.2. increasing efficiency, scheduling and execution of the outages program; 2.3. adapting maintenance measures to the specifics of new facilities and technologies.

3.1. stocks optimization; 3.2. competitive procurement procedures; 3.3. introducing new technologies; 3.4. increasing maintenance intervals supported by inspection and monitoring activities; 3.5. procuring maintenance services together with the modernization and construction of critical assets (GIS technology facilities, EMS-SCADA process information platforms and metering platforms, etc.); 3.6. digitalization of processes that ensure the implementation of asset management standards; 3.7. enhancing partnerships with works, solutions, products and service providers.

155

4.1. increasing the staff's competencies adapted to the technological progress; 4.2. instructing the staff together with activities of modernization/introduction of new technologies; 4.3. monitoring and evaluating the performances/competencies of personnel.

The specific objectives established by the maintenance strategy are quantified in a set of key performance indicators – KPIs, which may be used to monitor the performances of the maintenance activity. These indicators may also be used for analyzing the components of the activity that require certain improvement measures. The indicators are quantifiable and can cover technical aspects (for instance, regarding consequences of events which might occur during the operation of the PTG or during planned maintenance), as well as economic aspects, as follows:

1. Technical KPIs: – Accidental and planned facilities' unavailability (transformers/autotransformers, OHLs), – Energy nor delivered to consumers (cut off) as a result of accidental PTG events, – Average time of interruption (ATI). 2. Economical KPIs: - Maintenance costs.

The evolution of these indicators highlights the effort undertaken for the achievement of the objectives pursued by the maintenance activity.

The principles of the maintenance strategy applied within CNTEE Transelectrica SA are the following:

o Efficient use of maintenance funds, according to the law; o Correlation of the Maintenance Program with the investment program for all tasks and on each single project level; o Integration in the project implementation of the principles resulted from the integrated quality, environment, security, and occupational health system; o Maintenance stocks management.

The preventive maintenance regulation in PTG facilities and equipment (NTI-TEL-R-001-2007- 04) was developed as a specific internal standard in order to ensure the implementation of the maintenance strategy. As the need for the existence of a single transparent data and information flow has been outlined in terms of the maintenance activity, that should provide all available data and quality control facilities, a specific database of equipment has been created for the management, optimization and coordination of all maintenance actions. The inventories of the functional assemblies (FAs) are drafted in a multilevel manner up to the substation and electric bay level, also using a multilevel encoding manner. The maintenance management system is organized based on these lists and contains the tools necessary for the preparation, launch and implementation of maintenance actions, expense follow-up and back-up equipment management.

156

The functional equipment within the PTG is also associated with information for identification, location, technical and construction features, as well as information on (random and determinist) events required for the creation and maintenance of a unitary technical database, intended for multiple purposes, including within the maintenance activity for selecting, scheduling and implementing works/services.

The following maintenance services/works are carried within CNTEE Transelectrica SA, as the case may be: – corrective maintenance: after detecting the failure, including all actions intended for the re-commissioning of the facility to a state wherein it is able to perform its specific function; – preventive maintenance: prophylactic, for failure prevention and reduction of the failure or degradation probability, aiming at a proper state of balance between these tasks, depending on the influence of different categories of functional assemblies/systems, installations, structures, components (SISC) in terms of the proposed PTG objectives:  operational security;  availability;  efficiency.

Within said programs, the preventive maintenance services/works are classified into levels (level 1  4) which stand for the complexity degree of the work content, the necessary tools/equipment, the necessary contractor/provider skills, etc. Levels 1 and 2 stand for works in the minor maintenance category (generally technical inspections/overhauls and periodical controls). Levels 3 and 4 stand for major maintenance works (generally current and capital repairs). Preventive maintenance is based, as the case may be, on:  time, for minor maintenance, by planning on predefined intervals of time (pursuant to the Preventive maintenance regulation in PTG facilities and equipment) based on their category, voltage and technical features (technology); deadlines may be adjusted based on the relevant condition and, as applicable, on local, specific and significance conditions.  condition, based on the technical state of the equipment/facilities defined by various procedures.

The substantiation of the maintenance program is done in a differentiated manner for each functional assembly, upon compliance with the Reliability Centered Maintenance methodology (RCM) principles, which may also serve for guiding certain proposals on new necessary investments. Within the methodology, the results of the technical condition of the functional assemblies and their significance in terms of the NPS operational security are quantified and conjugated.

For work/services scheduling and planning, given the defined priorities and the qualitative risk analyses conducted, we draft short, mid and long-term development programs intended to not exceed the assigned resources. Planned and incurred costs and volumes are recorded. In order to establish the working technology and to determine the appropriateness of measures using live work (LW), we conduct a comparative analysis of the costs, also considering the components determined by the own technological consumption and by congestions. In compliance with the stated principles and criteria, the implementation of the maintenance strategy and drafting the annual maintenance programs will be conducted via the following steps:

157

 Generating and structuring of the annual maintenance program in compliance with the Company's strategy;  Completing the Annual outage plan (considering the LW technology services/works) correlated with the annual maintenance and investment programs;  Determining the maintenance budget based on the programs drafted;  Procuring and contracting maintenance works/services in compliance with the current legislation and the rigorous selection criteria of CNTEE Transelectrica SA;  Implementing the maintenance program at transmission substations level, methodologically coordinated by the dedicated department within the Company's Executive, with the follow-up of the compliance with the approved budget and using the facilities offered by specialized software packages;  Updating the maintenance program given the permanent correlation with the actual implementation of the investment program and the compliance with the annual outage plan.

The peculiarities of each project correspond to the structure of assets subject to maintenance, but are included in a unitary manner in the maintenance strategy and coordination concept at CNTEE Transelectrica SA level. There are also situations in which we might need to correct, as the case may be, the duration/values of the initially established maintenance program, as a result of conducting corrective maintenance following accidental events caused by various factors, such as: unfavorable weather conditions, stolen components from electrical facilities, physical degradation and outdatedness of equipment as a result of their age. As examples we mention the situations occurred during the implementation of the annual maintenance program that required the need to supplement/reassign initially defined funds, as follows:  technical inspections and overhauls given the increasing rates and unit prices for the equipment in substations not subject to refurbishment/modernization;  emergency interventions for solving accidental situations (replacing elements stolen from OHLs, consolidation of OHL terminal foundations affected by floods, removal of the vegetation for OHL corridor maintenance);  special works as a result of the equipment electric parameter deterioration, particularly in transformation units;  insulation replacement works on certain OHLs under live work regime, for the reduction of outage times of electric facilities and maintaining them under normal operational conditions, as live work rates are higher compared to works conducted on temporarily decommissioned facilities.

Together with the diversification of energy sources in the NPS – the emergence of renewable energy sources, particularly wind sources – a new challenge consisted of identifying alternative maintenance solutions, such as live works (LW) or OHL multispectral aerial inspections.

Prioritization criteria for major maintenance/refurbishment/modernization measures in existing facilities The large number of facilities in need of refurbishment/modernization and major maintenance works, in conjunction with the favorable situation (relatively low loads) forecasted in the PTG for the

158 following years, justifies an increased investment and financial effort in this period, which is also motivated by complying with quality standards provided by existing technical regulations and required for an operation interconnected with the European ENTSO-E system. In order to define the priority order of the refurbishment/modernization and major maintenance actions, an analysis was conducted based on the RCM methodology, considering the following:  the technical condition of the FAs and their components, quantified based on the information on frequency and duration of accidental unavailabilities, the evolution of operational parameters and features, the maintenance history, costs, etc.  the significance of FAs in terms of ensuring safety/stability within the NPS (determined via steady-state regime calculations: currents on the sides, nodes voltage, power not delivered to consumers/blocked in power plants/not transited between system areas, steady-state and transient stability calculations, etc., as well as criteria describing the significance of the facility: voltage level, ensuring system services, supplying significant consumers, discharging power from interconnection power plants, etc.)

Major preventive maintenance activities in functional assemblies and their components are planned depending on the condition and are substantiated by applying the RCM methodology. Major preventive maintenance activities in facility/equipment categories other than functional assemblies (for instance buildings, construction elements, reservoirs, pipelines, fencing, etc.) are planned depending on time and condition and are substantiated based on periodical technical inspections, the technical documentation and operational experience.

Risk management When planning/prioritizing maintenance actions, we consider RM (Risk Management) principles, taking into account related aspects regarding:  the operational behavior established based on the annual recording and processing of statistical data;  the technical condition of FAs and their components;  the significance of FAs and their components within the NPS;  the risk of downtime (probability, impact) of FAs.

FA significance is established/updated by the Operational Unit NPD whenever substantial changes take place in the NPS configuration.

11.1.2. PTG facilities' maintenance schedule (electric substations and lines) The determination of the perspective maintenance program is conducted based on multi-criteria- based analyses, by which major maintenance actions primarily concern the electricity transmission facilities that are responsible for:  the interconnection with the neighboring power systems;  the connections between system areas or important substations;  the discharge of power from large generators;  the supply of significant consumption areas (the increase in the transmission capacity is also considered). The maintenance program for OHLs and substations is developed in a correlated manner and, as shown in the maintenance strategy, in correlation with the investment program (also taking into

159 account, for instance, the execution of special connection works, works for transiting difficult geographic areas, new users' connection to PTG, etc.). Works to avoid emergency situations created by floods, landslides, vandalism etc. are conducted as a priority. Major maintenance The major maintenance work program for the 2018-2027 period considers the priority order of substations depending on the technical condition (age) and significance criteria, but also the geographic location of substations. Scheduling of simultaneous works in substations located in the same geographic area has been avoided (as much as possible). This requirement is the result of the CNTEE Transelectrica S.A's obligation to maintain standard-level safety and continuity of NPS operation throughout the duration of the works in substations and to reduce costs for removing congestions in the grid. Also, planning simultaneous works in the same area of the NPS leads to a need to conduct temporary works (cables, underground crossing towers, etc.) that increase work costs in an unjustifiable manner. Minor maintenance and special works Except major maintenance works in the PTG substations, we also schedule minor (routine) preventive maintenance services/works according to the Regulation regarding preventive maintenance to the PTG installations and equipment (internal technical norm), as well as special services/works with an impact on the operational security and safety of facilities (with special, provisional technologies, etc.) Modern and innovative technical solutions The Company considers developing live work (LW) and fast NPS intervention technologies in order to increase the transmission capacity, reduce maintenance costs and PTG power losses as a result of the reduced periods of time for OHL and substation scheduled outages. Major maintenance projects for substations and overhead power lines for the 2018-2027 period are presented in Tables 11.2 and 11.3 and Annexes E-1 (not published) and E-2 (not published) respectively. Impact over the safety of the NPS in the event of not completing maintenance programs. Measures The operational security of the PTG (NPS) is mainly ensured via minor preventive and corrective maintenance: technical inspections and reviews, periodical controls (CP) and repair works resulted from the minor preventive maintenance activities (RCT). Statistically speaking, these maintenance types register a physical and value-wise completion rate of ca. 90%. Minor preventive maintenance is scheduled on a yearly basis pursuant to the Preventive maintenance regulation – NTI-TEL-R-001, and aims at preventing more complex failures with significant consequences on PTG facilities. If, for system purposes, certain functional assemblies cannot be shut down for preventive maintenance, other assemblies (as far as possible of the same type) are shut down from operation. This type of maintenance directly reduces the need for maintenance activities such as accidental interventions (IA). Maintenance (current and capital repairs) is carried out based on agreements concluded following competitive procurement procedures. This way, given the complexity and duration of necessary activities leading up to the conclusion of such agreements, the differences between the scheduled estimated values and the actual values can be significant.

160

Among the causes which might lead to non-completion of major maintenance programs, we list the following:  values allocated following the competitive procedures are lower than the estimated and scheduled values, or the settled values have been lower than the scheduled ones;  there have been difficulties in granting outages/rescheduling outages of facilities, due to certain situations in the power system which were favorable to the generation from renewable energy sources (wind, photovoltaic);  the occurrence of meteorological conditions unfavorable to the execution of certain works (particularly in OHLs and construction elements in transformation substations);  difficulties in obtaining permits and authorizations from various public entities (city halls, inspectorates, agencies, etc.);  the need to restart the (time-consuming) public procurement proceedings for certain repair agreements as a result of the lack of bidders.

With respect to the impact over the safety of the NPS in the event of not completing maintenance programs, this can be classified as insignificant in the short and mid-term, given that the PTG operational security is mainly based on minor preventive and corrective maintenance measures. On the other hand, not completing maintenance programs may have a significant negative impact in the long term.

In order to increase the degree of completion of major maintenance works, the following measures can be considered, inter alia:  periodical update of maintenance programs, considering the contracted values;  a better correlation of outages for maintenance and investment purposes;  simplifying the process needed to obtain permits and for payment of taxes necessary to commence works;  using simplified procurement procedures.

Table 11.2 Major maintenance program for substations managed by CNTEE Transelectrica SA – 2018-2027 period

Nr. Total TRANSPORT - STATII 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Crt. estimat T1 TOTAL (RK Statii *)

2 Proiecte RC statii

3 Proiecte RK, RC Transformatoare

4 Proiecte RK, RC Cladiri TOTAL Mentenanta majora (RK si RC) T2 Statii, Transformatoare, Cladiri Servicii/lucrari strategice in instalatii 5 Statii, Trafo, Cladiri TOTAL Mentenanta (majora si minora) T3 Statii, Transformatoare, Cladiri

161

Table 11.3 Maintenance program for 110-750 kV OHLs managed by CNTEE Transelectrica SA – 2018-2027 period

Nr. TRANSPORT - LEA Total 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Crt. estimat

1 LEA 220 kV Gutinas - Focsani Vest 2 LEA 400 kV Tantareni - Turceni G1+2 3 LEA 400 kV Tantareni - Turceni G3+4 4 LEA 220 kV Isalnita - Gradiste 5 LEA 220 kV Tihau-Baia Mare 3 6 LEA 400 kV Rosiori-Mukacevo 7 LEA 400 kV Rosiori-Gadalin 8 LEA 220 kV Cluj Floresti-Alba Iulia 9 LEA 400 (220) kV Retezat-Hasdat 10 LEA 220 kV Lacu Sarat - Filesti 11 LEA 400 kV Isaccea - Tulcea Vest 12 LEA 220 kV Aref-Raureni 13 LEA 220 kV Iernut-Ungheni circ. 1 14 LEA 400 kV Bacau Sud - Roman Nord 15 LEA 400 kV Roman Nord - Suceava 16 LEA 400 kV Bucuresti Sud - Pelicanu 17 LEA 400 kV CNE - Pelicanu 18 LEA 400 kV CNE - Gura Ialomitei circ.2 19 LEA 400 kV Urechesti - Domnesti 20 LEA 400 kV Bucuresti Sud - Slatina 21 LEA 400 kV Brazi Vest - Dârste 22 LEA 400 kV Bucuresti Sud - Domnesti 23 LEA 400 kV Rosiori - Vetis 24 LEA 400 kV Lacu Sarat - Smardan 25 LEA 400 kV Isaccea - Smardan circ.1+2 26 LEA 400 kV CNE - Constanta Nord 27 LEA 400 kV Gura Ialomitei-Lacu Sarat 28 LEA 400 kV Porti de Fier - Urechesti 29 LEA 400 kV Porti de Fier - Slatina 30 LEA 220 kV Mintia - Alba Iulia 31 LEA 220 kV Alba Iulia-Sugag 32 LEA 220 kV Alba iulia - Galceag 33 LEA 400 kV Iernut - Sibiu Sud 34 LEA 400 kV Tantareni-Kozlodui circ.1+2 35 LEA 400 kV Tantareni-Bradu 36 LEA 400 kV Tantareni-Urechesti 37 LEA 400 kV CNE - Gura Ialomitei circ.1 38 LEA 220 kV Aref-CHE circ.1+2 39 LEA 220 kV Portile de Fier-Resita 40 LEA 400 kV Mintia-Arad 41 LEA 220 kV Mintia-Timisoara 42 LEA 110 kV Tutora-Ungheni 43 LEA 400 kV Constanta Nord-Tariverde 44 LEA 220 kV Cluj Floresti-Tihau 45 LEA 220 kV Rosiori-Baia Mare3 46 LEA 400 kV Tantareni-Sibiu 47 LEA 220 kV Iernut-Ungheni circ. 2 48 LEA 220 kV Portile de Fier-Turnu Severin 1 49 LEA 220 kV Portile de Fier-Turnu Severin 2 50 Inspectie aeriana multispectrala din elicopter a LEA 110-750 kV 51 Servicii de intretinere a culoarelor de trecere a LEA din zone cu vegetatie arboricola T1 Total Mentenanta majora (RK si RC) LEA 52 Servicii/lucrari strategice in instalatii LEA T2 Total Mentenanta (majora si minora) LEA

162

11.2. Maintenance strategy for electricity quality metering and monitoring systems

The OMEPA metering branch, as administrator of the metering/remote metering systems and the electricity quality monitoring system, is responsible for the maintenance of these systems based on their technical features and using modern methods indicated in technical procedures or prescriptions. Maintenance programs consider the meters, concentrators, modem communication terminals, equipment of the central data management system, portable control kits, meter control table, measuring and standard tools, electricity quality monitorization kits, electricity quality monitoring systems, parameter setting equipment. In line with the "Preventive maintenance regulation in PTG facilities and equipment – NTI-TEL- R-001-2007-004", the OMEPA metering branch annually drafts preventive maintenance programs for the equipment mentioned for each type of functional assembly and subassembly. The periodicity of facilities' checking, as well as the methodological checking complies with the specific applicable legislation. For the equipment and systems that cannot be maintained by the OMEPA metering branch (and that are no longer under warranty), agreements have been concluded with specialized companies for preventive and corrective maintenance services (equipment of the central data management system, standard meters). Mention must be made that, presently, the costs associated with the preventive and corrective maintenance activity are still high due to the multiple local interventions on the technologically outdated equipment (electromechanical meters) and the impossibility to track them remotely. In order to improve their technical performances, CNTEE Transelectrica SA aims to replace this equipment by the end of 2025. Given that, for the wholesale energy market, the equipment used consists of highly reliable electronic devices, the periodicity of their field-based checking has been changed from 6 to 12 months. In the future, the full replacement of unreliable electromechanical meters, which represent approximately 20% of the total number of meters (within the substation refurbishment projects) with static electronic reliable meters will enable the implementation of a unitary strategy for the entire metering equipment park, which will certainly lead to a reduction in operation-related costs.

163

12. Fixed asset development strategy PTG development investments represent the main component of the Fixed asset investment plan of CNTEE Transelectrica SA, ensuring the refurbishment/modernization of equipment from outdated substations and an increased transmission capacity of the grid. Additionally, investments in the PTG associated systems are considered, which will ensure the fulfillment of requirements related to the grid and NPS control and monitoring, the metering of electricity quantities and the protection of critical infrastructure, at the established performance level.

12.1. Evolutions determining the need to develop fixed assets The decisive evolutions that lead to investments for the fixed assets development are:  the degree of wear and tear and obsolescence of the equipment;  change in the level and/or location of electricity demand and generation in the NPS and of cross-border exports/imports/transits;  change in the energy market rules which lead to changes in the demand-generation balancing method, with an influence over the level and volatility of power flows through the grid;  change in the technical features of users' facilities, which requires the adequacy of monitoring and control systems and changing the conditions according to the interface between the users and the PTG.

Degree of wear and tear and obsolescence of the equipment Transmission equipment are associated with a normal operational lifetime (correlated with the depreciation periods related to the straight-line method of depreciation), approved by Government Decision no. 2139/2004, updated, on the classification and normal operational lifetime of fixed assets. The physical wear and tear and obsolescence negatively impacts the maintenance costs, the reliability, the behavior during incidents, the impact over the environment, the accuracy of parameter measurement, etc. The inferior features of the equipment installed in the past do not allow the implementation of remote management in substations. Although over the last years a thorough refurbishment/modernization program was implemented, a majority of the equipment still has a high level of physical and moral wear and tear, having been commissioned before 1990 (over 20 years of age) and being based on outdated technological solutions. Under these circumstances, a large part of the NPS facilities needs to undergo repair works or, where justified, refurbishment/modernization works. For instance, the tables below show the age of breakers and power transformation units, these being the most important primary equipment in PTG substations. We can see that 1/3 of the total number of breakers (31%) and 1/2 of the total number of transformers/autotransformers (50%) have exceeded their normal lifetime periods according to the "Catalogue on the classification and normal operational lifetime of fixed assets owned by CNTEE Transelectrica SA".

164

Table 12.1 Age of breakers Age (years) MV 110 kV 220 kV 400 kV 750 kV Total Age < 18 years 527 588 260 164 1,539 Age ≥ 18 years 183 350 79 82 6 700 Total 710 938 339 246 6 2,239 Table 12.2 Age of transformers and autotransformers

Capacity 10 16 20 25 40 63 100 200 250 400 500 1,250 Total (MVA) Age < 24 years 2 8 7 5 2 39 22 20 2 107 Age ≥ 24 years 6 25 1 18 2 1 43 9 2 1 108 Total 8 33 1 25 7 2 1 82 31 22 2 1 215 The Company considers replacing old equipment with:  increased arc-breaking power and speed switch devices, enabling an increase in speed and selectivity of fault elimination;  quick selective protection systems with flexible and complex logic and remote control;  compact and eco-friendly primary equipment, with a reduced impact over the environment;  transformers with reduced copper and iron losses;  conductors with increased acceptable thermal limit, enabling an increase in the transmission capacity in cases where the construction of additional lines cannot be carried out in due time;  command and control systems, adapted to the increasing number of nodes and the new technical features of the monitored facilities;  efficient metering systems, at the level required by the electricity market operation requirements. Electricity quality monitoring systems will be introduced, first in substations where consumers with potentially disturbing operational particularities are connected to.

Evolutions of the level and/or location of electricity demand and generation in the NPS and of cross-border exports/imports Changing the level and/or location of demand and generation results in the modification of flows on grid elements and may lead to overloads or voltage instability phenomena and non-compliance with the admissible limits in certain areas. The increase in power exchanges between power systems in the region, as a result of the development of the energy market, is another element that leads to grid loading.

Changes in the energy market rules In order to apply the newly introduced market instruments in the energy sector, there is a need to adequately develop the system monitoring and command facilities and the electricity metering systems. This allows for the compliance with the updated transmission system services performance standards and the step-wise implementation of the smart grid concept in the NPS.

165

Changes in the technical features of users' facilities The quickly increasing number of intermittent power plants, especially wind power plants, requires the endowment with new tools to forecast generation from wind power plants within the NPS, in order to integrate this generation in the operative scheduling of power plants' operation and to quickly control generation/demand, when needed. Integrating a significant number of intermittent power plants in the system requires endowing power transmission and distribution grids with specific elements associated to the smart grid concept: efficient telecommunications infrastructure, smart electricity metering systems, smart electric devices and equipment with dedicated information applications allowing the transformation of grids from a passive area of the power system towards active areas capable of identifying changes in significant state parameters and of modifying their own configuration and parameters in order to respond to the new conditions in an optimal manner. CNTEE Transelectrica SA started the process of enhancing the strategy regarding the smart grid concept implementation – CNTEE Transelectrica SA's strategy for research and innovation (2018-2027) [27] and CNTEE Transelectrica SA's Smart Grid policy (2018-2027) [28].

12.2. PTG development strategy 12.2.1. Needs to enhance the PTG determined by the NPS evolution in the 2018-2027 period The PTG development plan has been drafted based on the need to meet the users' requirements under the conditions of maintaining the quality of the transmission system service and the operational safety of the NPS, in compliance with the applicable regulations. The appropriate PTG development is a component of sustainable development, contributing to supporting social welfare by providing the society with an infrastructure favorable to economic development and by decreasing electricity prices as a result of an increasing competitiveness on energy markets. The main evolution directions of the NPS which define the need to enhance the PTG in 2018- 2027 are the following:  The release of new generation capacities, particularly based on renewable sources (wind, photovoltaic, biomass), largely with intermittent operation and priority regime, connected both in the PTG and in the distribution grid;  The development of the energy market at national, regional and European level;  Disappearance or reduction in generation or increase in demand, up to a level which endangers the supply of consumers from certain areas within standardized quality and safety parameters; Chapter 10 presented the results of the regime analyses for the hypotheses considered in the mid (5 years) and long term (10-15 years), as well as the solutions to enhance the PTG which will allow avoiding congestions in the grid. Further on we will present the main areas in which the PTG needs to be developed according to the system and market simulation studies.

The Dobrogea area

166

The generation park in the Dobrogea region has shown an accentuated development. Wind and photovoltaic power plants were and continue being built. The nuclear units 3 and 4 in Cernavoda (2 x 700 MW) are being anticipated as a component of the government's strategy to develop the energy sector. Completing the nuclear units 3 and 4 requires an increase in the power discharge capacity from the Cernavoda substation, in order to comply with the criterion with N-2 operational elements. Even if not all projects will materialize, it is expected that the loading will exceed the admissible limit of specific transmission sections S3 (power discharge from the eastern area of the Dobrogea + Moldova system) and S6 (power discharge from the Dobrogea area). Consequently, there is a need for the consolidation of these sections which provide the transmission of surplus power from the East towards the demand and storage centers located in the West. Given that the grid's loading will increase in the future, it is appropriate to conduct capital repair or refurbishment works primarily in substations that ensure the power discharge and transit from the area towards the rest of the system. The action was started several years ago and must be continued at a sustained pace.

The western area of the NPS The perspective regime analysis shows the need to eliminate congestions expected both on the E-V direction, at the border with Hungary and Serbia, and on the N-S transit direction, by consolidating the Portile de Fier-Resita-Timisoara-Sacalaz-Arad "western axis" (part of the "Romania-Serbia" cluster, also known as the "Mid Continental East Corridor"). Congestions are caused both by the power discharge from photovoltaic power plants expected in the South-West part of the country (Banat) and the existing Portile de Fier hydroelectric structure, and by the increasing power exchange and transit in the area. Interconnection with other systems Both the history of exchanges during previous years, and the market simulations at regional and European level showed that the export trend dominates in the NPS, but there are also cases of import, depending on the energy balance of systems in the region. At the same time, the transmission grid ensures the power transit between Romania's neighboring systems, in particular on the NS direction, according to the rules for synchronously interconnected operation. In order to increase the exchange capacity with other systems, execution agreements/memoranda of understanding have been concluded with partners for the following projects which are in different stages of analysis and promotion:  Increasing the exchange capacity on the Serbian border: execution of the second 400 kV interconnection line with Serbia (Resita-Pancevo 400 kV d.c. OHL) – part of the "Romania- Serbia" cluster, also known as the "Mid Continental East Corridor". In order to build the 400 kV OHL on Romanian territory, CNTEE Transelectrica SA and SC Electromontaj SA Bucharest signed the execution agreement no. C 212/04.06.2014. Due to the significant delay in obtaining the GD for the definitive removal from the forestry of the land plot of 0.2873 ha and the temporary occupation of the land plot of 51.6499 ha, necessary for the execution of this investment objective, the executor cannot begin works in

167

the forested areas and an addendum was concluded to the execution agreement, updating the deadline for completion on 31.03.2018. Currently, the works are in progress. Out of the total number of 206 towers, 203 have been built on the foundation. 206 foundations have been built.

– Increasing the exchange capacity on the Bulgarian border: Several projects for the consolidation of the transmission grid have been planned on Romanian territory: . PCI "Bulgaria–Romania Group, capacity increase", also known as "Black Sea corridor", which includes the following projects of common interest: . Smardan-Gutinas 400 kV d.c. OHL; . Cernavoda-Stalpu 400 kV d.c. OHL, with one input/output circuit in Gura Ialomitei.

– Increasing the electricity exchange capacity with the Republic of Moldova: – Until meeting the conditions to contract a common study analyzing the operational regimes of the power systems of Romania and the Republic of Moldova, based on hypotheses agreed by the parties on the export level and reservation methods in the event of unavailabilities in the grid, CNTEE Transelectrica SA initiated a preliminary study drafted by Tractebel Engineering S.A. The following interconnection projects have been analyzed via back to back substations located on the territory of the Republic of Moldova: Isaccea (RO)- Vulcanesti (RoM) 400 kV OHL; Suceava (RO)-Balti (RoM) 400 kV OHL – for which a memorandum of understanding was signed and preliminary analyses have been conducted; and Iasi (RO)-Ungheni (RoM) 400 kV OHL – for which alternative options exist pertaining to end substations, both in Romania (e.g.: Iasi/Munteni) and in the Republic of Moldova (e.g. Chisinau/Straseni), as well as the consolidation of the internal PTG connecting the line with the existing transmission grid. The study did not account for costs and durations necessary for analyzing the grid consolidations on the territory of the Republic of Moldova. – In 2016, the Ministry of Economy of the Republic of Moldova, via TSO Moldelectrica, launched a feasibility study financed by EBRD ("Moldova and Romania Power Systems Interconnection"). The auction was won by ISPE SA Bucharest. The feasibility study analyzed all three proposed interconnection projects: - Isaccea (RO)-Vulcanesti (RoM)-Chisinau 400 kV OHL single circuit, back to back substation in Vulcanesti, - Suceava (RO)-Balti (RoM) 400 kV OHL single circuit, back to back substation in Balti, - Iasi (RO)-Ungheni-Straseni (RoM) 400 kV OHL single circuit, back to back substation in Straseni. The Vulcanesti back to back substation and Vulcanesti-Chisinau 400 kV OHL interconnection project was recommended as a priority project. The feasibility study for the Vulcanesti back to back substation and Vulcanesti- Chisinau 400 kV OHL has shown that the project is technically and economically feasible. This study was presented in Chisinau in 2016 and 2017. The Moldovan party estimates that the project shall be completed in 2022.

168

Specialists from Transelectrica, Moldelectrica and ISPE cooperated in order to establish the necessary works and equipment on Romanian territory and in order to specify them within the feasibility study. On Romanian territory, the following will be needed: optical fiber installation works on the existing Isaccea (RO)-Vulcanesti (RoM) 400 kV power line up to the border, protections and remote protections installation works in the Isaccea substation, integrating the data acquired from the Isaccea substation for the interconnection line in the load-frequency controller, etc. These works shall be carried out by CNTEE Transelectrica SA and shall be correlated with the Isaccea 400 kV substation refurbishment project. – The Moldovan Ministry of Economy, via the World Bank, also launched a new feasibility study called "Analysis study for interconnecting the Moldovan power system", drafted by EKC Serbia, which analyzed the same three interconnection projects. The study concluded that the best asynchronous interconnection solution is the Isaccea (RO)-Vulcanesti (RoM)-Chisinau 400 kV OHL single circuit, with back to back substation in Vulcanesti. – Suceava (RO)-Balti (RoM) 400 kV OHL – for which a memorandum of understanding was signed and preliminary analyses have been conducted.

Deficit demand areas Development needs were analyzed as determined by: increasing demand in Bucharest by a rate higher than the national average, information and requests received related to the increase in demand of large consumers and new consumers in the Tulcea, Brasov and Constanta area. The increase of the PTG operational security in the Arges-Valcea area was analyzed either by consolidating the area's connection to the PTG and/or via conductor replacement and the local distribution grid reconfiguration measures. Another important element taken into account in the analyses was the notified scrapping of certain groups, which will amplify the deficit of some areas (e.g. Bucharest, Transylvania). Given the estimated demand increase and the intentions of scrapping certain groups, a need was identified to consolidate the transmission capacity and injection capacity towards the distribution grid in certain areas where they have reached or will reach the limit in the following 10 years: – the Bucharest municipality area and the limit area; – the North of Transylvania; – the Sibiu area, for reserving the single injection from the PTG.

12.2.2. Uncertainties concerning the NPS evolution and settlement thereof in the PTG development plan In compliance with the Electricity and Natural Gas Act no. 123/2012, as subsequently amended and supplemented, the PTG development plan must ensure the long-term planning of the necessary investments in transmission capacities in order to cover the system's electricity demand and to ensure deliveries to clients in compliance with the current status and future evolution of electricity demand and sources, including power imports and exports, under the applicable legislation. A high significance lies in the precise knowledge of the quantity and geographical location of the demand, generation and exchanges, in order to accurately design the grid, so that the development

169 resources are allocated where they are needed, on the one hand, and the unjustified consolidation costs are avoided, on the other hand. Hence, the estimations of the average power and the average energy annually consumed and generated in the entire NPS (estimations that are achievable within an acceptable margin of error) have a limited significance for the grid reference design studies. In terms of demand, given its slow evolution pace and the existing capacity of the grid, we can say that the historical data taken from substations, amplified by factors reflecting the forecast of the global evolution of demand in the NPS, leads to estimations containing errors which have no major consequences over the grid development plan. Usually, the investment program can be corrected in due time if a deviation from the forecasted values is noticed, as the time needed to install additional transformers for the injection towards the distribution grid is not very long. The major issue for grid planning in recent years consisted of the uncertainty regarding the evolution of the generation park, given that a large number of new power plants have been announced and the development of the generation park is carried out at decentralized level, as a result of the business plans of investors. There is no body to correlate the evolution of the generation park with the evolution of demand, able to provide the TSO a time development schedule as a basis for planning the grid development. The main information source for the TSO is represented by the notices of intention provided, upon request, by the existing generators, as well as the grid connection requests received from potential users, according to the applicable legislation related to grid access. However, the intent to develop or to reduce the activity of generators are commercially sensible information, and the fulfilment of the actions depends on the success of financing, therefore the credibility of the information received by the TSO is limited. These do not represent the beneficiaries' firm commitment and not complying with their own announced program poses no risk to them. The time required for the construction of new lines can be sensibly higher than the time needed for constructing new generation or demand objectives. This makes it necessary to construct new lines before commencing the user's investment, thus introducing an important risk element for Transelectrica S.A. For an increase in the forecast reliability that the development plan is based on, the TSO supports the implementation of methodologies that should render the PTG users responsible in relation to the TSO. Taking into account the many important above-mentioned uncertainty elements, CNTEE Transelectrica SA considered, when drafting the PTG development program, several demand evolution scenarios and users' projects and related deadlines that could have been deemed as sufficiently reliable. Thus, the following generation capacities development [4] projects with a major impact over the PTG were taken into account:  Commissioning of wind power plants, totalizing an installed capacity of: o 3,400 MW by 2022 and 3,600 MW by 2027, in the reference scenario; o 3,500 MW by 2022 and 4,000 MW by 2027, in the green scenario.  Commissioning of photovoltaic (solar) power plants, totalizing an installed capacity of: o 1,500 MW by 2022 and 1,600 MW by 2027, in the reference scenario; o 1,500 MW by 2022 and 2,000 MW by 2027, in the green scenario.  The commissioning of units 3 and 4 in the Cernavoda NPP, mentioned in the documents regarding the Government's Energy Strategy; the strategy provides the construction of two

170

new reactors, under economic efficiency conditions and while complying with the technical and environmental conditions set at European level. A new difficulty regarding the analysis of the PTG operational regimes that arose in recent years is installing a significant power quantity in wind and photovoltaic power plants, which have a random availability depending on wind speed and solar radiation. In the context presented above, in order to establish the PTG development needs, CNTEE Transelectrica SA analyzed several scenarios regarding the future construction of new power plants, associated with different scenarios regarding the loading of groups for load coverage, with several export scenarios. As all above-mentioned projects lead to an increase in production in the Dobrogea area (by 1,450 MW in 2027 compared to 2018 in the reference scenario, and by 1,520 MW in 2027 compared to 2018 in the "green" scenario), section S6 for discharging the currently existing power, as well as some internal lines in the area, won't be able to face the forecasted power flows (a more detailed analysis is available in Chapter 10). The analyses conducted by Transelectrica S.A. and its consultants (mention must be made of the significant contribution of ISPE S.A. and TRACTEBEL ENGINEERING S.A.) showed the need of significant PTG consolidations in the area, in the absence of which the forecasted newly installed power could not be transmitted towards the demand and storage centers. Projects which were deemed useful in the basic scenario and in several possible alternative scenarios shall be prioritized. Mention must be made that the projects deemed necessary for discharging the power from the Dobrogea area are still applicable if the evolution of the power plant park from the area proves to be different from the analyzed one, namely if groups 3 and 4 in the Cernavoda NPP will no longer be constructed, but the WPP installed capacity will rise considerably over the estimations made at the time of conducting these system studies, on which this development plan was based. In terms of the appropriateness of connecting users to the PTG, the reserves determined for each NPS specific section (Chapter 10.6.2) grant the necessary information for identifying areas where the connection of new consumers or generators poses no specific difficulties.

12.2.3. PTG facilities' development, refurbishment/modernization program Comparative analysis of investment projects included in the 2018 edition of the development plan and in the previous 2016 edition

Since the approval of the previous development plan, the following projects have been completed:  PTG refurbishment/modernization: . Refurbishment of the Campia Turzii 220/110/20 kV substation; . Modernization of the Tihau 220/110 kV substation – primary equipment; . Modernization of the command, control and protection system and the 20 kV substation in the Vetis 220/110/20 kV substation; . Modernization of the SCADA system for the Constanta Nord 400/110 kV substation;

171

. Replacing ATs and Ts in substations – stage 2 – phase 1: o Replacing AT2 – 200 MVA in the Ungheni 220/110/20 kV substation; o Replacing AT2 – 200 MVA in the Raureni 220/110/20 kV substation; o Replacing T2 – 25 MVA in the Gradiste 220/110/20 kV substation; o Replacing T1 – 25 MVA in the Gheorgheni 220/110/20 kV substation; o Replacing AT2 – 200 MVA in the Craiova Nord 220/110 kV substation; o Replacing AT2 – 200 MVA in the Pestis 220/110 kV substation; o Replacing T1 – 16 MVA and T2 – 10 MVA in the Vetis 220/110/20 kV substation.

 Safety of consumption supply: . Replacing the 110/10kV, 25 MVA T3 and T4 with 110/(20)10 kV, 40 MVA transformers in the Fundeni substation.

 Integrating generation from power plants – other areas: . Replacing conductors of the Isalnita-Craiova 220 kV OHL (circuit 1);

In the current edition of the development plan, the following new investment projects have been introduced:  PTG refurbishment/modernization: . Modernization of the Vetis 220/110/20 kV substation – primary equipment The need and appropriateness of investments in the Vetis 220/110/20 kV substation resulted from the fact that the substation can no longer carry out its activities under normal conditions, as the operation and maintenance for the majority of the equipment is difficult, determined by weak performances and poor technical condition at the level of the 1980s. During the operation of the substation, a series of dysfunctionalities occurred which led to high expenditures and poor technical performances. . Modernization of the power supply equipment at the Operational Unit NPD quarters Currently, the existing equipment is deemed physically and morally outdated, with a limited operational safety. Upgrading the power supply equipment at the Operational Unit NPD is important for maintaining the command facilities of the NPS under operational parameters, in order to comply with current operational security requirements of the National Power System, thus resulting in an increased quality of the power transmission service and an increased level of safety in servicing the power transmission grid users. . 110 kV, 220 kV and 400 kV mobile bays A large number of major investment projects are currently undergoing within CNTEE Transelectrica SA, which require using 110 kV, 220 kV and 400 kV mobile bays. These mobile bays are provisionally used throughout the investment works, given the occasional insufficient space conditions for carrying out works under occupational safety conditions, or when the equipment outage conditions do not allow long term outages, therefore ensuring an increased operational security of the NPS. . Installing two modern offset means for reactive power in the 400/220/110/20 kV Sibiu Sud and 400/220/110/20 kV Bradu substations The need for this investment objective resulted from the new challenges that the NPS must face, namely:

172

- The development of demand centers outside generation areas, the NPS consisting of both strong deficit areas, and strong surplus areas in terms of the generation-demand balance. The generation sources in the NPS are also allocated in an unbalanced manner between the northern and the southern halves of the country, with approximately 80% of the power generation being located in the southern part; - The intensification of cross-border exchanges leads to the occurrence of parallel power circulations between the synchronous power systems of the ENTSO-E and fast variations in the import/export balance; - Integrating a very large renewable energy generation (4,535 MW installed capacity in wind, photovoltaic and biomass power plants as of 31.12.2017) and the concentration of wind power plant generation in the south-eastern area of the NPS (approximately 80% of the total 3,030 MW installed capacity in wind power plants as of 31.12.2017), determines changes in power flows in short time intervals. These challenges need a fast voltage level control, adequate to the respective operational regime of the NPS. Introducing modern offset means for reactive power, capable of voltage control in grid nodes, represents a very good method to improve the voltage profile and the voltage stability limit of the system due to the very fast response and fine reactive power control of this equipment, when the system changes its operational state. . Replacing 3 400 kV 100 MAVR BC units in the Arad, Smardan and Bucuresti Sud substations and equipping monitoring facilities on bucking coils and transformation units which are not currently endowed with such facilities

 Safety of consumption supply: . Replacing the ATUS-FS 400/400/160 MVA 400/231/22 kV AT3 in the Portile de Fier 400/220 kV substation Given that the operation of the AT3 autotransformer resulted in a series of dysfunctionalities which led to high corrective maintenance expenditures (RC, IA, LS) and poor technical performances, the replacement measure facilitates the reduction of maintenance costs and ensures monitorization. Given the advanced state of physical and moral wear and tear, the age of 40 years of the main unit and the age of 34 years of the control unit, which substantially surpassed the normal operational lifetime, and given that a repair in a specialized workshop is not justified due to the large number of components that must be replaced, it is deemed necessary to replace the 400/400/160 MVA AT with a 500/500/80 MVA AT which operates under normal conditions. . Increasing the operational security of the Arges-Valcea grid area, constructing the Arefu 400 kV substation and installing the 400 MVA, 400/220 kV AT The need to increase the level of operational security in the Arges-Valcea grid area has been identified by the dedicated study called "Study on increasing the operational security in the Arges-Valcea grid area" [29] and by the analysis report on the incident that took place on 01.06.2016, when an accident occurred in the Bradu 220 kV substation led to a voltage drop in the Stuparei 220/110 kV, Raureni 220/110 kV and Arefu 220/110/20 kV substations, 20 substations belonging to CEZ Distribuție SA, one 220 kV substation and 23 110 kV substations belonging to Hidroelectrica SA, 1 110 kV substation belonging to the Govora CHPP and 3 110 kV consumer substations belonging to Oltchim S.A. – Valcea, CIECH Soda România S.A. – Govora and CIMUS – Campulung (the Valcea county was fully affected and the Arges county was affected in the northern half).

173

 Integrating RES and new power plants generation – Dobrogea and Moldova: . Converting the Isaccea-Tulcea Vest 400 kV OHL from single to double circuit Within the regimes analyzed in the "Study on the PTG development in the mid and long term (2018-2022-2027)" [14], it was deemed appropriate to double the connection between the Isaccea and Tulcea substations, thus eliminating the risk of very high loadings on the existing Isaccea-Tulcea Vest 400 kV OHL and the Constanta Nord-Tariverde 400 kV OHL.

Compared to the approved edition of the plan, in the current edition the following investment projects have been excluded: . Increasing the transmission capacity of the Bucuresti Sud-Fundeni 220 kV d.c. OHL Considering the reduction in the number of users who request connection to the power grid for a new demand and/or generation facility, a large part of the connection requests has not been completed (for instance, the connection of the 120 MW UNIEL CHPP, the 136 MW Platonesti WPP, the 300 MW Giurgeni WPP), or has been conducted at lower capacities. Therefore, there is no justifiable need or appropriateness to conduct the investment objective "Increasing the transmission capacity of the Bucuresti Sud-Fundeni 220 kV d.c. OHL". The cancellation of this objective in the Investment plan of CNTEE Transelectrica SA was approved by Transelectrica's Directorate in Explanatory note no. 40235/30.10.2017. . Increasing the transmission capacity of the Dumbrava-Stejaru 220 kV OHL Within the regimes analyzed by the "Study on the PTG development in the mid and long term (2018-2022-2027)" [14], the conductor replacement in the Stejaru-Dumbrava 220 kV OHL was deemed unnecessary. In regimes with N-1 operational elements, this OHL was loaded up to 72.5% when disconnecting the Sibiu Sud-Iernut 400 kV OHL, in the reference design regime in the 2022 stage for the S3 surplus area, SMP section, considering the S3 section as fully loaded with 90% Ci in wind power plants.

Annex F-3 presents a comparative analysis of the projects in the PTG development plan – 2018 edition, compared to the previous edition of the approved plan, which presents information specific to each project regarding the following aspects: implementation and development stage of each project, reasons for potential delays in commissioning compared to the scheduled period.

Presentation of the PTG development projects included in the PTG development plan for the 2018-2027 timeframe In order to maintain the grid's adequacy so that it is correspondingly designed for the transmission of electricity forecasted to be generated, imported, exported and transited under the conditions of the occurred changes, the ten-year PTG development plan includes two investment categories:  refurbishment of existing substations;

174

 PTG extension by constructing new lines, increasing the transmission capacity of existing lines, extending the existing lines and increasing the transformation capacity in substations.

 Refurbishment and modernization of existing substations The power lines and substations that make up the national transmission system were mostly built in the 1960-1980 period, at that period's technological level. The actual technical condition of facilities remained at a corresponding level so far, both due to the maintenance program conducted, and via a sustained facilities and equipment refurbishment and modernization program. In the following ten years, the ongoing refurbishment projects will be completed and new projects will be started, while complying with the priority order based on the technical condition and significance of substations.

Ongoing refurbishment/modernization projects: . Increasing the security level of facilities in the Bucuresti Sud 400/220/110/10 kV substation replacing the 10 kV equipment; . Refurbishment of the Bradu 400/220/110/20 kV substation; . Refurbishment of the Turnu Severin Est 220/110 kV substation; . Modernization of the Suceava 110 kV and 20 kV substation; . Refurbishment of the Domnesti 400/110/20 kV substation; . Replacing ATs and Ts in substations – stage 2 – phase 2. . Refurbishment of the Ungheni 220/110/20 kV substation; . Modernization of the Arefu 220/110/20 kV substation; . Modernization of the Raureni 220/110 kV substation; . Modernization of the Cluj Est 400/110/10 kV substation; . Modernization of the Dumbrava 220/110 kV substation; . Modernization of the Bacau Sud and Roman Nord 110 kV substations, corresponding to the Moldova 400 kV axis; . Refurbishment of the Isaccea 400 kV substation (stage I) – eliminating several bottlenecks by converting the Isaccea connections' capacities of the Varna and Dobrudja 400 kV OHL to the capacities of the respective lines and replacing reactive coils; . Modernization of the 110 and 400 (220) kV facilities in the Focsani Vest substation; . Modernization of the command, control and protection system of the Sardanesti 220/110/20 kV substation.

Substation refurbishment/modernization projects under the procurement/design procedure: . Refurbishment of the Smardan 400/110 kV/m.t. substation; . Refurbishment of the Otelarie Electrica Hunedoara 220 kV substation; . Refurbishment of the Medgidia Sud 110/20 kV substation; . Refurbishment of the Filesti 220/110 kV substation;

175

. Refurbishment of the Craiova Nord 220/110 kV substation; . Refurbishment of the Baru Mare 220/110 kV/MV substation; . Refurbishment of the Iaz 220/110 kV substation; . Refurbishment of the Hasdat 220/110 kV substation; . Modernization of the Munteni 400 (220)/110/20 kV substation; . Modernization of the 220 kV, 110 kV command, control, protection and metering system in the 220/110/20 kV substation and refurbishment of the medium voltage and DC and AC internal services in the Ghizdaru 220/110/20 kV substation; . Modernization of the CTSI command, control, protection and integration system of the Draganesti Olt substation; . Modernization of the CTSI command, control, protection and integration system of the Gradiste substation; . Modernization of the power supply equipment at the Operational Unit NPD quarters; . 110 kV, 220 kV and 400 kV mobile bays; . Installing two modern offset means for reactive power in the Sibiu Sud 400/220/110/20 kV and Bradu 400/220/110/20 kV substations.

The plan also includes projects for which the procurement/design procedure has not yet been started: . Refurbishment of the Isaccea 400 kV substation (stage II); . Refurbishment of the Pelicanu 400/110 kV substation; . Refurbishment of the Alba Iulia 220/110 kV/MV substation; . Refurbishment of the Darste 400/110 kV substation; . Replacing ATs and Ts in substations – stage 3: • 220/110 kV 200 MVA AT: Tg. Jiu Nord, Sardanesti, Suceava, Dumbrava, Gradiste (AT2); • Tihau 220/110 kV 100 MVA AT; • 110/20 kV 40 MVA Trafo2 in the Tg. Jiu Nord substation and 110/10 kV 40 MVA Trafo2 in the Cluj Est substation; • 110/20 kV 25 MVA Trafo: T1 and T2 in the Cluj Floresti substation, T2 in the Salaj substation, T2 in the Campia Turzii substation, T1 in the Turnu Severin Est substation; • 110/20 kV 20 MVA Trafo in the Turnu Severin Est substation. . Modernization/replacement of the command, control and protection system in the following substations: Calafat 220/110 kV, Fantanele 220/110/20 kV, Cernavoda 400 kV, Fundeni 220/110/10 kV, Paroseni 220/110 kV, Tantareni 400 kV, Salaj 220/110/20 kV, Baia Mare 3 220/110 kV, Cluj Floresti 220/110 kV, Urechesti 400/220/110kV/MT, Nadab 400 kV, Calea Aradului 400 kV, Mintia 400/220/110 kV, Bucuresti Sud 400/220/110 kV, Turnu Magurele 220/110 kV, Gheorgheni 220/110/20 kV, Rosiori 400/220 kV, Targoviste 220/110/20 kV, Oradea Sud 400/110/20 kV, Pestis 220/110 kV.

176

 Increasing the cross-border interconnection capacity

 The following grid developments are planned for increasing the exchange capacity along Romania's western interface: Considering the contribution to the implementation of strategic priorities of the European Union regarding the trans-European power infrastructure, the European Commission introduced the following project group on the third list of Projects of Common Interest (PCI): . PCI "Romania-Serbia Group, between Resita and Pancevo", also known as "Mid Continental East corridor", which includes the following projects of common interest: . Resita (RO)-Pancevo (Serbia) 400 kV d.c. OHL; . Portile de Fier-Resita 400 kV OHL and extending the Resita 220/110 kV substation by building a new 400 kV substation; . Converting the Resita-Timisoara-Sacalaz-Arad 220 kV OHL d.c. to 400 kV, including the construction of the Timisoara and Sacalaz 400 kV substations. These projects will allow eliminating congestions, both on the E-V direction at the Hungarian and Serbian border, and on the N-S direction, by consolidating the Portile de Fier-Resita-Timisoara- Arad corridor. The projects will also allow the integration in the NPS of the generation from photovoltaic power plants expected in the South-West part of the country (Banat) and the existing Portile de Fier hydroelectric structure.

 Oradea Sud-Nadab-Bekescsaba 400 kV s.c. OHL, final stage: line segment between the 1-42 (48) towers of the Oradea Sud-Nadab 400 kV OHL

 The following grid developments are planned for increasing the exchange capacity along Romania's western interface (Bulgarian border) for the transmission of power from intermittent renewable sources installed on the Black Sea coast, towards demand and storage centers: Considering the significant contribution, by increasing the interconnection capacity between Romania and Bulgaria and by strengthening the infrastructure which will support the power flow transmission between the Black Sea coast and the North Sea/Atlantic Ocean coast, the European Commission introduced the following project group on the third list of Projects of Common Interest (PCI):

 PCI "Bulgaria–Romania Group, capacity increase", also known as "Black Sea corridor", which includes the following projects of common interest: . Smardan-Gutinas 400 kV d.c. OHL (1 circuit equipped); . Cernavoda-Stalpu 400 kV d.c. OHL, with one input/output circuit in Gura Ialomitei.

 In order to increase the exchange capacity along the Republic of Moldova interface: The following interconnection projects have been analyzed via back to back substations located on the territory of the Republic of Moldova, without being planned as ulterior developments: . Isaccea (RO)-Vulcanesti (RoM)-Chisinau (RoM) 400 kV OHL;

177

. Suceava (RO)-Balti (RoM) 400 kV OHL; using this project at maximum capacity also depends on the construction of the Suceava-Gadalin 400 kV OHL, included in the plan.

 Increasing the transmission capacity between the eastern region (especially Dobrogea) and the rest of the interconnected power system, and system integration of the power generated from RES and other sources in Dobrogea

In order to consolidate the transmission capacity from Dobrogea towards the rest of the system, several projects for the consolidation of the transmission grid have been planned: . Stupina-Varna 400 kV OHL and Rahman-Dobrudja 400 kV OHL input/output connection in the Medgidia Sud 400 kV substation; . Extending the Medgidia Sud 400/110 kV substation and refurbishing the 110 kV substation in order to increase the breaking power of breakers in correlation with increasing the short- circuit current; . Gadalin-Suceava 400 kV s.c. OHL; . Stalpu-Brasov 400 kV d.c. OHL (1 circuit equipped); . Converting the operational voltage of the Brazi Vest-Teleajen-Stalpu 220 kV OHL to 400 kV (built for 400 kV), including the construction of the Stalpu and Teleajen 400 kV substations; . Medgidia Sud-Constanta Nord 400 kV d.c. OHL (1 circuit equipped); . Suceava-Gadalin 400 kV s.c. OHL; . Replacing conductors of the Stejaru-Gheorghieni-Fantanele 220 kV OHL; . Increasing the transmission capacity of the 8 km long segment with smaller section on the Bucharest Sud-Pelicanu 400 kV OHL; . Increasing the transmission capacity of the 53 km long segment with smaller section on the Cernavoda-Pelicanu 400 kV OHL; . Converting the Isaccea-Tulcea Vest 400 kV OHL from single to double circuit.

 Integrating the power generated from other power plants in the NPS The following works are scheduled: . To provide safe discharge of power from the Portile de Fier II HPP, an agreement was reached with S.C. Hidroelectrica SA pertaining to the 220 kV discharge by building the Ostrovul Mare 220 kV substation and the 220 kV d.c. OHL connecting Ostrovul Mare to the Portile de Fier-Cetate 220 kV OHL.

 Safety of consumption supply in deficit areas . Installing the second 400/110 kV, 250 MVA transformer in the Sibiu Sud 400/220/110/20 kV substation in order to reserve the single injection from the PTG in the Sibiu area; . Installing the second 400/220 kV, 400 MVA AT in the Iernut substation in order to provide consumption supply in the N-V area of the country, in the absence of sufficient installed capacity in power plants from the area; . Replacing the ATUS-FS 400/400/160 MVA 400/231/22 kV AT3 in the Portile de Fier 400/220 kV substation;

178

. Increasing the operational security of the Arges-Valcea grid area by constructing a new Arefu 400 kV substation, with 1 400/220 kV 400 MVA AT and connection in the Tantareni-Sibiu Sud 400 kV OHL via a 400 kV d.c. OHL with a length of approximately 0.05 km.

The supply grid of the Bucharest municipality presents a special situation. The forecasted evolution of the demand leads to the need to construct a 400/110 kV substation in the demand center of the Bucharest municipality, in order to increase the safety of electricity supply. In order to include these projects in the development plan, an agreement must be reached with the distribution operator in the area regarding the distribution substations in which the PTG injections will be made, as well as regarding a common action plan. Until then, the development plan does not include the supply section of the PTG development for the Bucharest municipality.

The PTG development plan does not fully cover the needs, in particular in terms of project completion deadlines, which exceed (sometimes by several years) the timescale in which users announced the completion of new generation capacities. If solutions allowed by the regulation framework will be identified in due time (e.g.: repayable financing provided by the PTG users, connection fee extended for covering the works necessary for the upstream PTG consolidation, other solutions), the advancement of several projects will be attempted. Figure 12 presents the PTG development projects included in the PTG development plan for the 2018-2027 timeframe, while Table 12 presents the staging of these works. Annex F-2 (not published) details the estimated annual staging of expenditures.

179 400 kV OHLs 220 kV OHLs 400 kV OHLs operating at 220 kV

Figure 12 – PTG development needs – 2018-2027 Fossil fuel-based power plants WPP

New lines (> 1000 km) Increasing the line capacity Suceava Increasing the interface capacity Tihau Substations proposed for refurbishment Oradea Refurbished substations Mariselu Iasi Gadalin CCPAS modernization/replacement

Munteni Power flows

High quantity of wind power plants

Mintia Cernavoda NPP Smardan

Retezat 400 kV Inel Isaccea

Stuparei Stupina Rahman

SERBIA Pancevo Tariverde Constanta

Medgidia S

Dobrudja Varna

180

Table 12 – Annual staging of investment works and expenditures – 2018-2027 period SECTIUNEA I - Esalonarea lucrarilor si cheltuielilor de investitii - perioada 2018 - 2027

Nr. Crit. Valoare Total Denumire proiect 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Crt. ANRE estimata 2018-2027

A RETEHNOLOGIZAREA RET EXISTENTE Marirea gradului de siguranță a instalațiilor aferente 1 stației București Sud 400/220/110/10 kV N - Înlocuire echipament 10 kV (Lot I+II) 2 Retehnologizarea staţiei 400 / 220 / 110 / 20 kV Bradu N 3 Retehnologizare staţia 220/110 kV Turnu Severin Est N

4 Modernizare staţia electrică 110 kV şi 20 kV Suceava N

5 Retehnologizarea staţiei 400/110/20 kV Domneşti N Inlocuiri AT şi Trafo în staţii electrice (etapa 2), din care: 6 N faza 1 (6 AT 200 MVA; 5 Trafo 16 si 25 MVA) faza 2 (8 AT 200 MVA; 4 Trafo 16 MVA) Inlocuiri AT şi Trafo în staţii electrice (etapa 3) 7 6 AT & 8 T 8 Retehnologizarea staţiei 220 / 110 / 20 kV Ungheni N 9 Modernizare statia electrica 220/110/20 kV Arefu N 10 Modernizare statia electrica 220/110 kV Raureni N 11 Modernizare statia 400/110 kV Cluj Est N 12 Modernizare statia 220 / 110 kV Dumbrava N

13 Retehnologizare staţia 400 / 110 / 20 kV Smârdan N 14 Retehnologizare stație 220 / 110 kV Craiova Nord N

15 Retehnologizare staţia 220 / 110 / MT kV Baru Mare N 16 Retehnologizare staţia 220 / 110 kV Iaz N 17 Retehnologizare staţia 220 / 110 kV Hăşdat N

18 Retehnologizare staţia 220 kV Oțelarie Hunedoara N

19 Retehnologizare staţia 220 / 110 kV Fileşti N

20 Modernizare statia 400 (220) / 110 / 20 kV Munteni N

21 Retehnologizare staţia Alba Iulia 220 /110 kV/MT N 22 Retehnologizare statia 400/110 kV Darste N 23 Retehnologizare staţia Medgidia Sud 110 kV N Modernizarea statiilor 110 kV Bacau Sud si Roman 24 N Nord aferente axului 400 kV Moldova Retehnologizarea staţiei 400 kV Isaccea (etapa I - 25 N inlocuire 2 BC, celule af. si celula LEA 400 kV Stupina Retehnologizarea staţiei 400 kV Isaccea (etapa II - 26 N retehnologizare statie 400 kV) Retehnologizarea statiei electrice de transformare 27 N 400/110 kV Pelicanu Modernizarea instalațiilor de 110 și 400 (220) kV din 28 N stația Focșani Vest Modernizare sistem de comandă-control-protecţie al 29 N staţiei de 220 / 110 / 20 kV Sărdăneşti Modernizare sistem de comandă-control-protecţie- metering 220 kV, 110 kV în staţia 220/110/20 kV si 30 N retehnologizarea medie tensiune și servicii interne c.c. și c.a. în stația 220/110/20 kV Ghizdaru Modernizare sistem comanda-control-protectie si 31 N integrare in CTSI a statiei Draganesti-Olt Modernizare sistem comanda-control-protectie si 32 N integrare in CTSI a statiei Gradiste Modernizare staţia 220/110/20 kV Vetiş - echipament 33 N primar 34 Modernizare staţia 220/110/20 kV Fântânele N 35 Modernizare statie 220/110 kV Calafat N Modernizare SCADA in statia 400/110/20 kV Oradea 36 N Sud Modernizare sistem de comanda control protectie in 37 N statia 400/220 kV Rosiori Modernizare sistem de comanda control protectie in 38 N statia 220/110/20 kV Salaj Modernizare sistem de comanda control protectie in 39 N statia 220/110 kV Baia Mare 3 Modernizare sistem de comanda control protectie in 40 N statia 220/110 kV Cluj Floresti Modernizare sistem de comanda control protectie in 41 N statia 400 kV Tantareni Modernizare sistem de comanda control protectie in 42 N statia 400/220/110 kV/MT Urechesti Modernizare sistem de comanda control protectie in 43 N statia 220/110 kV Paroseni Modernizare sistem de comanda control protectie in 44 N statia 220/110 kV Pestis

181

Modernizare sistem de comanda control protectie in 45 N statia 400 kV Nadab Modernizare sistem de comanda control protectie in 46 N statia 400 kV Calea Aradului Modernizare sistem de comanda control protectie in 47 N statia 400/220/110 kV Mintia Modernizare sistem de comanda control protectie in 48 N statia 220/110/20kV Targoviste Modernizare sistem de comanda control protectie in 49 N statia 220/110 kV Fundeni Modernizare sistem de comanda control protectie in 50 N statia 400/220/110 kV Bucuresti Sud Modernizare sistem de comanda control protectie in 51 N statia 220/110 kV Turnu Magurele Modernizare sistem de comanda control protectie in 52 N statia 220/110/20 kV Gheorgheni Modernizare sistem de comanda control protectie in 53 N statia 400 kV Cernavoda 54 Modernizare electroalimentare la sediile UNO DEN N Instalarea a două mijloace moderne de compensare 55 a puterii reactive în stațiile 400/220/110/20 kV Sibiu N Sud și 400/220/110/20 kV Bradu 56 Celule mobile de 110 kV, 220 kV si 400 kV N Inlocuire 3 unitati BC 100 MVAR 400 kV in statiile 57 N Arad, Smardan si Bucuresti Sud. Echiparea cu instalații de monitorizare a bobinelor 58 de compensare și a unităților de transformare care N nu sunt dotate în prezent cu astfel de instalații ALTE INVESTIŢII LA NIVEL DE SUCURSALE ŞI B N EXECUTIV (planificate anual)

C SIGURANŢA ALIMENTĂRII CONSUMULUI

Montare trafo T3 - 250 MVA (400 / 110 kV) în staţia 1 E 400/110 kV Sibiu Sud AT2 Iernut - 400 MVA, 400/220 kV Montare AT2 400 MVA, 400/231/22 kV precum şi a celulelor aferente în 2 E staţia Iernut și modernizarea sistemului de comandă control al stației 400/220/110/6 kV Iernut Înlocuire AT3-ATUS-FS 400/400/160 MVA 400/231/22 3 E kV din stația 400/220 kV Porțile de Fier Creșterea siguranței în funcționare a zonei de rețea 4 Argeș-Vâlcea, realizarea statiei 400 kV Arefu si E montarea unui AT 400 MVA, 400/220 kV. INTEGRAREA PRODUCTIEI DIN SRE SI CENTRALE NOI D - DOBROGEA SI MOLDOVA Racordarea LEA 400 kV Isaccea - Varna si LEA 400 kV 1.1 Isaccea - Dobrudja în staţia 400 kV Medgidia Sud. E Etapa I - Extinderea staţiei 400 kV Medgidia Sud Racordarea LEA 400 kV Isaccea-Varna si LEA 400 kV Isaccea - Dobrudja în staţia 400 kV Medgidia Sud. 1.2 E Etapa II - LEA 400 kV d.c. Racorduri la staţia Medgidia Sud Trecere la 400 kV LEA Brazi Vest - Teleajen - Stalpu, inclusiv: Achiziţie AT 400 MVA, 400/220/20 kV şi 2 E lucrări de extindere staţiile 400 kV şi 220 kV aferente, în staţia 400/220/110 kV Brazi Vest 2.1 LEA 400 kV Brazi Vest - Teleajen - Stalpu E

2.2 Extinderea statiei Brazi Vest (inclusiv AT4) E Statia 400 kV Teleajen si retehnologizare statia 2.3 E 110 kV 3 LEA 400 kV d.c. (1c.e) Constanta Nord - Medgidia Sud E Trecerea LEA 400 kV Isaccea - Tulcea Vest de la 4 E simplu circuit la dublu circuit Marirea capacitatii de transport LEA 220 kV Stejaru - 5 N Gheorgheni - Fantanele LEA 400 kV Stalpu - Brasov, inclusiv interconectarea 6 N la SEN (linie nouă) Marirea capacitatii de transport tronson LEA 400 kV 7 N Bucuresti Sud - Pelicanu (8 km) Marirea capacitatii de transport LEA 400 kV 8 N Cernavoda - Pelicanu (53 km) INTEGRAREA PRODUCTIEI DIN CENTRALE - ALTE E ZONE 1 Staţia Ostrovu Mare 220 kV (staţie nouă ) N 2 LEA 220 kV Ostrovu Mare - RET (linie nouă) N

182

F CREŞTEREA CAPACITĂŢII DE INTERCONEXIUNE

Trecerea la tensiunea de 400 kV a axului Portile de Fier - Resita - Timisoara - Sacalaz - Arad. Etapa I: 1 E Extindere statie 400 kV Portile de Fier; LEA 400 kV Portile de Fier - Resita; statia 400 kV Resita 1.1 LEA 400 kV Portile de Fier - Resita E 1.2 Statia 400 kV Resita E 1.3 Extindere statie 400 kV Portile de Fier E Trecerea la tensiunea de 400 kV a axului Portile de Fier - Resita - Timisoara - Sacalaz - Arad. Etapa II : 2 E LEA 400 kV d.c. Resita - Timisoara - Sacalaz + statia 400 kV Timisoara + statia 110 kV Timisoara Retehnologizare staţia 110 kV Timişoara și Trecerea la tensiunea de 400 kV a axului Porțile de Fier - 2.1 E Anina - Reșița - Timișoara - Săcălaz - Arad, etapa II: Stația 400 kV Timișoara 2.2 LEA 400 kV d.c. Resita - Timisoara - Sacalaz E Trecerea la tensiunea de 400 kV a axului Portile de Fier - Resita - Timisoara - Sacalaz - Arad. Etapa III: 3 E LEA 400 kV d.c. Timisoara - Sacalaz - Arad + statia 400/110 kV Sacalaz + extindere stația 400 Arad 3.1 LEA 400 kV d.c. Timisoara - Sacalaz - Arad E Statia 400 kV Sacalaz si retehnologizare statia 3.2 E 110 kV Sacalaz Extindere statie 400 kV Arad si retehnologizare statia 3.3 E de 110 kV Arad LEA 400 kV de interconexiune Reşiţa (România) - 4 E Pancevo (Serbia) (linie nouă) 5 LEA 400 kV d.c. (1c.e) Gutinas - Smardan E Extinderea staţiei 400 kV Cernavodă, et. II: 6 E racordare linii noi LEA 400 kV d.c. Cernavoda - Stalpu si racord in statia 7 E Gura Ialomitei (linie nouă) Extinderea staţiei 400 kV Gura Ialomiţei cu două 8 E celule: LEA 400 kV Cernavodă 3 şi LEA 400 kV Stâlpu Statia 400 kV Stalpu (staţie nouă )+ Modernizare 9 E celule 110 kV si medie tensiune 10 LEA 400 kV s.c. Gădălin - Suceava (LEA nouă) E LEA 400 kV s.c. Suceava - Balti (LEA nouă - pentru 11 E portiunea de pe teritoriul Romaniei)*) LEA 400 kV s.c. Oradea Sud - Nadab - Bekescsaba, 12 etapa finală: tronsonul dintre stâlpii 1-42 (48) ai LEA E 400 kV Oradea Sud - Nădab Platformă integrată de conducere operativă a SEN + Inlocuire componente sistem EMS SCADA AREVA + G N Inlocuire componente suport ale platformei piata de echilibrare Sistem de contorizare și de management al datelor H N de măsurare a energiei electrice pe piața angro MANAGEMENT SISTEME INFORMATICE ŞI J N TELECOMUNICAŢII K INFRASTRUCTURA CRITICA N

L ALTE CHELTUIELI DE INVESTITII TOTAL SECTIUNEA I *) estimarea anuala a lucrarilor si cheltuielilor se va face numai dupa aprobarea oficiala a finantarii de catre Republica Moldova

SECTIUNEA II - Investitii care nu sunt incluse in Plan; se vor include in functie de confirmarea parcurgerii etapelor de decizie necesare la nivelul partilor interesate Nr. Crit. Valoare Total Denumire proiect 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Crt. ANRE estimata 2018-2027 II a TOTAL - Investiţii pt. racordare CHEAP Tarnita 1 LEA 400 kV d.c. Tarnita - Mintia N 2 LEA 400 kV d.c. Tarnita - Gadalin N 3 Statie 400 kV Tarnita N II b TOTAL - Investiţii pt. alimentare Municipiul Bucuresti 1 Statia Grozavesti 400 kV (staţie nouă ) N 2 LEC 400 kV s.c. Domnesti - Grozavesti (linie nouă) N 3 LEC 400 kV s.c. Bucuresti Sud-Grozavesti (linie nouă) N 4 Statia Filaret 400 kV (staţie nouă) N Racord 400 kV d.c. statia Filaret la LEC Grozavesti - 5 N Bucuresti Sud Creșterea capacității de transport a axei 220 kV II c Urechești - Târgu Jiu Nord - Paroșeni - Baru Mare - N Hășdat - Mintia II d Sediu nou CNTEE "Transelectrica" SA N

TOTAL Sectiunea II

TOTAL Sectiunea I + Sectiunea II

183

12.2.4. Estimation of benefit indicators specific to PTG projects In 2017, CNTEE Transelectrica SA contracted the study called "Estimating the benefit indicators for evaluating the impact of PTG development projects" [23] which evaluates the benefits of investment projects from the following categories: "Safe consumption supply", "Integrating the generation from new power plants in Dobrogea and Moldova", "Integrating the generation from power plants – other areas" and "Increasing the interconnection capacity and integrating RES generation". The study is currently in progress. The benefit indicators included in the "ENTSO-E Guideline for Cost Benefit Analysis of Grid Development Projects" [22] methodology are defined as follows: B1. Increased security of supply: security of supply is the ability of a power system to provide an adequate and secure supply of electricity in ordinary conditions, in a specific area. The boundary of the area may consist of a series of grid nodes of a demand subregion/region or a semi-isolated area. The B1 indicator measures the improvement to security of supply (SoS) brought about by the development of the project, compared with the situation in which the project is not implemented. B1 is calculated via the Expected Energy Not Supplied (EENS) or the Loss of Load Expectancy (LOLE) indicators. B1 can be expressed in value terms via the Value of Lost Load (VOLL). B2. Socio-economic welfare: or market integration is characterized by the ability of a power system to reduce congestion and thus provide an adequate grid transfer capability (GTC) so that electricity markets can trade power in an economically efficient manner. Two different approaches can be used for calculating this indicator: the generation cost approach and the total surplus approach. Regardless of the method chosen, B2 is calculated as the difference between the situation in which the project is developed and the situation in which the project is not implemented. B3. Renewable energy sources (RES) integration: support to renewable energy sources (RES) integration is defined as the ability of the power system to allow the connection of new RES plants and unlock existing and future "green" generation. This indicator also considers increasing the transfer capacity of green energy from the analyzed section towards the neighboring sections. B4. Variation in losses (energy efficiency) is the characterization of the evolution of losses in the power system. It is an indicator of energy efficiency and it is correlated with B2. At the same level of generation/demand/transfer between areas, the project development leads to reduced losses. Certain projects can also lead to a more efficient distribution of power circulations which shorten the distance between generation and demand, resulting in reduced losses in the grid. B5. Variation in CO2 emissions is the characterization of the evolution of CO2 emissions in the power system. It is a consequence of renewable energy sources (unlock of generation with lower carbon content) which, given the situation of implementing the project, changes the energy mix by increasing the share of green energy produced/consumed in the entire system. All aforementioned indicators are calculated as the difference between the situation in which the project is developed and the situation in which the project is not implemented. B6. Technical resilience/system safety is the ability of the system to withstand increasingly extreme system conditions. The quantitative estimation of the technical resilience and system safety is performed by scoring a number of key performance indicators (KPIs). Key performance

184 indicators comparatively examine the situations with and without the project in terms of compliance with the stability criteria in case of unavailability of sources/grid elements under maintenance (R1), demand loss (R2) and voltage variation (R3). B7. Flexibility is the ability of the proposed reinforcement to be adequate in different possible future development paths or scenarios, including trade of balancing services. The project impact on society is defined as follows: S.1. The environmental impact characterizes the project impact as assessed through preliminary studies and aims at giving a measure of the environmental sensitivity associated with the project. S.2. The social impact characterizes the project impact on the (local) population that is affected by the project as assessed through preliminary studies, and aims at giving a measure of the social sensitivity associated with the project. GTC. The Grid Transfer Capability (GTC) reflects the ability of the grid to transport electricity across a border or grid section. GTC is calculated with and without the implementation of the analyzed project.

Annex F-4 presents a summary of the values obtained in the first phase of the study, which evaluated PTG development projects during the time stage closest to the commissioning deadline, following the assessment of the 2027 perspective stage projects in the second phase.

12.2.5. Priority technical solutions The following technical solutions will be promoted as a priority: – The new 400 kV lines will be constructed in line with a double circuit solution, with one or two initial circuits, depending on the forecasted loading, thus reducing the long-term impact on the environment; – Substations will be designed with flexible schemes, with double busbar system or 1.5-2 breakers per circuit, depending on the significance and their classification in the system. – Disposal of the transfer bar will be considered in all substations subject to refurbishment/modernization, given the fact that modern and reliable primary equipment will be used, thus reducing the environmental footprint; – Solutions will be adopted for the reduction of grid losses; – Solutions will be adopted to enable supplying CNTEE Transelectrica SA's own substation services from its own grid; – The works are planned taking into account all voltage levels existing in the relevant substation within a unitary project. In all substations where work was planned, we also consider the refurbishment/modernization of the control, protection and automation systems and of the necessary endowments in order to secure remote control. For future strong surplus or deficit expected areas, or for areas which are expected to be subject to large power transits, we consider major maintenance or priority modernization/refurbishment of substations located on the interconnection routes with the rest of the NPS.

185

In order to avoid congestions that occur during certain periods due to the overload on lines, we expect the use of the newest technological solutions, such as replacing existing conductors with increased thermal capacity conductors. The PTG will be further endowed with specific elements associated with the smart grid concept. Out of the different possible solutions for the consolidation of the PTG, the best option is chosen according to the estimations, considering the following:  Expenditures;  Grid losses reduction;  Ability to face system events whose level of gravity exceeds the rated reference design conditions, correlated with the associated consequences;  The appropriateness in relation to the largest possible number of scenarios regarding the potential evolution of the NPS;  Social impact;  Environmental impact;  Acceptability of the project for affected local communities;  Feasibility in terms of obtaining rights over land plots and necessary permits.

12.3. PTG associated systems 12.3.1. Development strategy for the EMS/SCADA-NPD dispatcher management system

The state of the EMS/SCADA-NPD system and of the logistic support elements (telecommunications equipment and network, type and technological level of equipment from transmission substations), as briefly described in subchapter 4.10, requires a program for the replacement and extension of the current system and for the modernization of the support equipment. Considering that the lifecycle of such a process information system is approximately 10-15 years, this program is correlated with the strategic evolutions and existing projects at Company level, at least for the following 15 years.

Correlation with the PTG substation refurbishment program

The program for developing the EMS/SCADA-NPD dispatcher management system is strongly correlated with the program for refurbishing Transelectrica S.A's substations, aiming to reach the objective pertaining to their full remote control and monitorization, both at the level of remote control and supervision centers, and at the level of the operational control centers (dispatchers). Completing the refurbishment works on the substations, and consequently the implementation of the command and control systems in substations (micro-SCADA) will lead to the full integration and functionality of the EMS/SCADA-NPD system. The micro-SCADA systems, introduced in refurbished substations, are implemented in a redundant technology, with optical fiber rings locally built inside substations and the communication lines used by transducers also being redundant and ensuring the direct interface with the EMS/SCADA system, without the need for additional terminal conversion equipment. Therefore, these systems will interact with the EMS/SCADA system on a server level, selectively providing it only the information necessary for the operative management of the National Power System. The data exchange and the full integration in the EMS/SCADA system shall firstly be made based on the obligation to use the IEC 60870-5-101

186 communications protocol "Transmission Protocols – companion standards especially for basic telecontrol tasks", and then by switching over to the IEC 60870-5-104 protocol "Transmission Protocols – Network access for IEC 60870-5-101 using standard transport profiles".

Correlation with the process for integrating generation from renewable sources

The intensive development and integration in the NPS of generation from renewable sources which benefit from the regulated promotion and support system – especially wind and photovoltaic power plants, both in the form of PDG distributed and dispersed generation, and by the construction of very large-scale power plants (hundreds of MW) directly connected to the PTG – leads to the need to take complex measures to integrate these plants in the EMS/SCADA-NPD system, both as distributed dispatchable sources and as large, concentrated sources, which will require an appropriate reference design of hardware equipment in order to ensure the acquisition and processing of a very large data quantity. The specific character of this type of generation, resulted from the high degree of variability and volatility, together with the associated implications on the power reserves at NPS level, and the functioning method on the balancing market, requires the integration of these sources at an appropriate level in the EMS/SCADA system and ensuring the specific energy monitoring and management (via dedicated EMS functions and applications, such as forecast or centralized control). Several integrated communication solutions between the CPD platform and the WPP and PVPP command, control and energy management systems are already adopted.

At the same time, this context represents an additional argument in favor of the need of a much closer functional and information correlation between information applications of the balancing market and the EMS/SCADA applications, in order to ensure the optimal operation, as close as possible to real time operation of the balancing market and system services market, particularly under the assumption of the new intraday energy market launch. Therefore, the need to integrate the two information systems becomes evident, in accordance with the existing worldwide level of software development and high-performance practical solutions provided by process information system developers.

Strategic option regarding the future architecture of EMS/SCADA

Given the aforementioned context, the modernization of the EMS/SCADA-NPD system as a whole (in other words, the NPD, regional sub-systems, CCS in substations, smart grid devices and connecting communications facilities) is a necessity for CNTEE Transelectrica SA in order to take advantage of the current IT and communications technologies and in order to keep up with the current technological level of partners/interconnecting TSOs. Additionally, the Romanian energy market is maturing and extending, needing increasingly complex and integrated functions in order to maintain the system operation. Currently, the new market applications are introduced via adapted procedures or extensions that are weakly integrated in terms of functionality, in the context of existing support facilities.

In terms of strategy, CNTEE Transelectrica SA confirms this evolution and its future vision includes: • developing secure, high-speed and IP-based communication lines, in order to acquire data from substations and equipment in the field. This requires data interfaces (including protocols) that are

187

at the level of RTU devices from substations, which are currently based on serial protocols and must be modernized or endowed with interfacing inverters. Furthermore, the telecommunications equipment used for telemetry will need to be adapted. Policies and techniques will have to be developed in relation to cybersecurity and the provision of associated equipment; • decongesting telecommunications traffic by constructing new concentrating nodes with inter- protocol conversion protocols for transmission on optical fiber data buses, in a flexible manner between points of interest (CPD-TPD-distribution operators-generators); • replacing the EMS/SCADA hierarchy based on files exchange with an integrated and distributed computerization environment, in which the regional system becomes an integral part of a single EMS/SCADA-type system, which may also operate with "virtual" servers; • establishing/adopting a systematic interaction between EMS/SCADA and the automation systems in substations; • facilitating the information exchange with market participants and foreign participants, using secured channels; • switching over to a modern, integrated and unitary system for the operational management of the NPS (EMP – Energy Management Platform), by integrating the EMS/SCADA system with other process information systems or smart equipment for monitoring grids, such as the platform for the balancing market and services auctioning, the synchrophasor measurement system (PMU), etc.; • creating the possibility to integrate or directly interface the metering system with the EMS/SCADA system; • developing applications for labor organization, based on the principle of correlating the maintenance activity with the actual condition of the power grid; • facilitating the coordinated planning of maintenance via efficient scheduling functions of the new EMS/SCADA system; • allowing the economical optimization of generation, transmission and supply of electricity; • creating conditions for the integration of the newest smart devices for monitoring and controlling the grid, as well as the ones from the synchrophasor system (PMU). The reference idea is to implement an integrated dispatcher platform (EMS/SCADA, AGC, balancing market, metering system, ENTSO-E node, PMU system, etc.) with will be implemented over the course of the following 5 to 7 years. This platform is intended to respond to the new necessities imposed by current legislation regarding the dispatcher management of the NPS and operating the balancing markets, capacities allocation and ancillary services. This platform will be designed and built so that it will ensure the highest possible level of redundancy, with functions identical (or improved) to the basic systems, additional functions for emergency situations; additionally, it will have an increased level of reliability and it will be properly protected against cyberattacks. The integration level, functional structure and final architecture of the information platform will be decided upon following an international consultancy project depending on functional requirements expressed at the time of implementing the project – in strong correlation with the evolution of the NPS development and the energy markets at national and European level (market

188 coupling), on the development level of process information systems at international level, on the technological evolution of extended systems for the monitoring of power systems, on the evolution of smart metering systems and the possible launch and implementation of new smart grid-type solutions and applications at NPS level.

Modernizing the data acquisition and exchange method Completing the optical fiber grid on all CNTEE Transelectrica SA lines and switching over the communications infrastructure to new technologies which allow information exchanges at a speed of 100 MB/s or more will bring a significantly increased capacity. This conversion requires however the modernization of the telecommunications equipment, as well as of the data interfaces from the subordinated dispatching centers, RTU terminals and other smart equipment/devices, or even the replacement of equipment with devices capable to operate with new technologies. It is important that the data exchange between the central EMS/SCADA system and the territorial systems to be revised, the hierarchical structure being based on outdated principles, which implies a strongly integrated approach based on modern technologies. At the same time, we will reevaluate communications between control systems of generation companies, market operators and external participants associated with the EMS/SCADA-NPD system in order to identify improvement opportunities of interactive operational processes. In this context, the integration of DMS/SCADA systems of all distribution operators represents a main objective in the mid-term. New solutions will be adopted at Transelectrica level for the modernization and redesign of the communications system with the ENTSO-E interconnection (called "ENTSO-E node"), via modernizations both at information system level and at communications level, in full agreement with ENTSO-E requirements, considering that the ENTSO-E data bus underwent several changes and adaptations over the course of the years, required by the increasing data quantity within inter- TSO exchanges, and considering that the modernization and adaptation process is a dynamic and continuous one.

Security of information systems within EMS/SCADA The energy security strategy adopted by Transelectrica will require adopting the EMS/SCADA system architecture according to the security requirements in the critical infrastructure field (NERC CIP) and the latest security standards specific to EMS/SCADA process systems (IEC 62351, ISO/IEC 27001); in addition, a dedicated organizational structure will have to be created in order to prevent, analyze, identify and react to cybersecurity incidents in information systems within EMS/SCADA and other critical systems within the Company. The new structure will also be responsible with fulfilling the objectives and action lines provided in Decision no. 271/2013 "Romania's cybersecurity strategy and in the National action plan for the implementation of the National cybersecurity system, whilst observing the applicable legal provisions". This strategy requires the existence of specialized, highly trained personnel, both from the IT&C and the energy sector.

12.3.2. Metering system and electricity quality monitoring system development strategy

189

The development of metering systems and electricity quality monitoring systems within CNTEE Transelectrica SA considers the following: – The needs and regulations of the electricity market in Romania and Europe; – CNTEE Transelectrica SA's strategy in terms of metering and electricity quality for the 2011- 2020 period; – Harmonization with European Union and ENTSO-E rules. In this respect, CNTEE Transelectrica SA, via the OMEPA metering branch, a neutral entity towards the energy market participants, ensures the development and operation of remote metering systems, in an impartial, transparent, efficient and reliable manner, in relation to all energy market participants, providing the data necessary for the implementation of the energy market concept in Romania.

Priority objectives for the field's development The field of electricity metering and monitoring is an integral part of the energy sector, which is a dynamic sector, actively supporting the economic development of the country and the reduction of the gaps compared to the European Union. In accordance with the aforementioned goals, the development of this field within CNTEE Transelectrica SA considers the following priority objectives, both in present time, as well as in the mid and long term: 1. ensuring efficient services for electricity metering and electricity quality monitoring; 2. implementing the most modern concepts and technologies for electricity metering and electricity quality monitoring; 3. implementing secure and efficient information systems for the management of metered/aggregated data; 4. developing best practices in the field of human resources management, general management and technical management; 5. developing new services for clients on the energy market (consultancy regarding electricity metering and monitoring systems; ensuring training services for attested metering operators, ensuring on demand services for implementing projects started by economic operators, metrological verification services).

Action lines In order for Transelectrica's strategy (via the OMEPA metering branch) in terms of electricity metering and monitoring to be a successful one, the following actions will be undertaken: 1. Functional policies will be revised, adopted and developed, specific for the following fields:  Remote metering for the wholesale market;  Local metering in Transelectrica substations;  Electricity quality monitoring;  Metrological verification of settlement meters along the PTG border. 2. The OMEPA metering branch will keep its organizational structure as an entity distinct from other operators on the energy market, namely the Balancing Market Operator (BMO), the Commercial Operator (OPCOM), the National Power Dispatcher, etc.

190

3. The strategy and policies specific to the electricity quality metering and monitoring systems will form the basis for drafting Transelectrica requirements for:  Design deadlines for new objectives or objectives subject to maintenance, modernization actions;  The Internal Technical Standards (NTI TEL) specific to systems managed by OMEPA;  TEL operational procedures that ensure the coordinated and structured operation of different organizational entities; 4. Implementing the SMART Metering concept as component part of the SMART Grid concept. 5. The Company will aim to first develop the strategic abilities specific to OMEPA, namely:  Human abilities;  Technical abilities;  Managerial abilities;  Innovation abilities.

Measures for fulfilling priority objectives . General measures The Electricity and Natural Gas Act no. 123/2012, as subsequently amended and supplemented, provides that the TSO (CNTEE Transelectrica SA) has to provide the electricity metering service for PTG users. The Commercial Code of the Wholesale Electricity Market provides that the TSO – MO (OMEPA metering branch) must ensure the unitary aggregation for the entire wholesale electricity market. Aligning the technical performances of equipment for electricity metering and electricity quality parameters monitoring to the rules of the European Union and ENTSO-E is a priority objective of CNTEE Transelectrica SA.

. Measures specific to the fields Implementing the principles of the CNTEE Transelectrica SA strategy in terms of developing the electricity (remote) metering systems and the monitoring systems for quality parameters related to the electricity transited through the PTG, as well as complying with the limits provided in the PTG technical code and other technical regulations to which the Company has acceded, represent priority objectives for the fulfillment of which CNTEE Transelectrica SA – OMEPA metering branch aims to take measures specific to the field of electricity metering and electricity quality parameters monitoring.

- Measures in the field of metering electricity transited on the wholesale market (CNTEE Transelectrica SA's remote metering system for the wholesale market)

 Promoting the new project for the remote metering information platform in the development plan;  Ensuring improved integrated services for clients of the metering platform;  Promoting open technologies and systems that do not limit the dependency to a single supplier or generator (ensuring interoperability) and that promote the requirements of the SMART Metering concept;

191

 The wholesale market remote metering platform solution must allow automatic interfacing with Transelectrica's local metering systems and other systems belonging to different NPS metering operators, in order to ensure redundant measured data for clients on the wholesale electricity market;  OTC management in CNTEE Transelectrica SA facilities requires that the grid elements be metered remotely and, in this respect, all existing or future local metering systems must allow the acquisition of data metered by the metering platform; meters will be installed together with the refurbishment works carried out in substations;  The OMEPA metering branch, via its local services, will conduct preventive maintenance according to the annual maintenance plan at transformation substation level;  Periodical and corrective maintenance for the entire remote metering system will be conducted by third party service providers;  The OMEPA metering branch neutrality in relation to market participants and ANRE acknowledged operators will be ensured by complying with the legal regulations pertaining to OMEPA metering branch's obligations and the energy market participants' rights;  The new remote metering system must ensure the acquisition, processing, displaying and storage of measured data via automated and secure processes that guarantee data accuracy and security;  IT&C solutions must be efficient and must take full advantage of the Company's existing IT&C infrastructure;  Specific equipment used must present technical features that excel in the field of environmental protection, energy efficiency and personnel security;  The spaces where the technical systems are located, well as the spaces where the operational personnel carries out their activities must only host the technical infrastructure destined to the metering platform, and access must only be granted to authorized personnel;  All metering equipment within the remote metering platform will be owned by CNTEE Transelectrica SA and will be managed by the OMEPA metering branch.

- Measures in the field of metering specific to local metering systems

 Implementing local metering systems in order to achieve the objective regarding remote control of transformation substations;  Promoting, within each modernization project or in each new substation, of a local metering system;  Promoting open technologies and systems that do not limit the dependency to a single supplier or generator (ensuring interoperability) and that promote the specific requirements of the SMART Metering concept;  The local metering systems solution must allow interfacing with the metering platform of the wholesale market in order to ensure redundant measured data for clients on the wholesale electricity market, as well as the regulated access to metered data for other clients of CNTEE Transelectrica SA;

192

 All local metering systems will be managed and operated in agreement with standard operational procedures developed by personnel of the OMEPA metering branch;  The new local metering systems must ensure the acquisition, processing, displaying and storage of measured data via automated and secure processes that guarantee data accuracy and security;  IT&C solutions must be efficient and must take full advantage of the Company's existing IT&C infrastructure; these will be installed in racks that are compliant with the required degree of protection;  Specific equipment used must present technical features that excel in the field of environmental protection, energy efficiency and personnel security;  The spaces where the technical systems are located, as well as the spaces where the operational personnel carries out their activities must only host the technical infrastructure destined to the protection and automation systems, and access must only be granted to authorized personnel.

- Measures in the field of metrological verifications In order to verify, with the Company's own resources, the electricity meters subject to the State's mandatory metrological control and owned by CNTEE Transelectrica SA, but also in order to obtain revenues by applying specific tariffs for the provision of metrological services to third parties that own such metering equipment, CNTEE Transelectrica SA aims to adopt the following measures:  Permanently ensuring space and environment conditions as well as facilities and equipment, required for metrological laboratories by the relevant applicable legislation;  Maintaining periodical authorizations issued by the Romanian Office for Legal Metrology (BRML) at time intervals provided by the relevant applicable legislation for CNTEE Transelectrica SA's metrology laboratory which consists of the three metrology laboratories in the Craiova, Sibiu and Timisoara transmission branches, based on the available documentation of the Quality System for carrying out the metrology activity;  Maintaining the periodical authorization of metrologists who carry out their activity within the three metrology laboratories.

- Measures in the field of electricity quality parameters monitoring  Promoting open technologies, products, equipment and systems that do not limit the dependency to a single supplier or generator (ensuring interoperability) and that promote the requirements of the SMART GRID concept;  The integrated electricity quality monitoring system must ensure the acquisition, processing, displaying and storage of measured data via automated and secure processes that guarantee data accuracy and security;  IT&C solutions must be efficient and must take full advantage of the Company's existing IT&C infrastructure, allowing the integration of all quality analyzers compatible with the existing system;  Specific equipment used must present technical features that excel in the field of environmental protection, energy efficiency and personnel security;

193

 The spaces where the technical systems are located, well as the spaces where the operational personnel carries out their activities must only host the technical infrastructure destined to the integrated monitoring system, and access must only be granted to authorized personnel;  All monitoring equipment existing within the system and owned by Transelectrica will be managed by the OMEPA metering branch, including the associated communication equipment and interfaces installed in third party substations and for which Transelectrica is responsible in terms of electricity quality monitoring;  The OMEPA metering branch, via its local services, will conduct preventive maintenance according to the annual maintenance plan at transformation substation level;  Corrective maintenance for the entire technical system will be conducted by third party service providers;  Ensuring the non-discriminatory access of users to the PTG, as per the applicable regulations;  Ensuring the compliance of electricity quality indicators with the limits provided in the PTG technical code and other technical regulations to which the Company acceded;  Ensuring the inclusion in contracts, connection permits and operational agreements of indicators regarding the quality of transmitted electricity, as well as of requirements for preventing the propagation towards the system of disturbances occurred in the user's facilities, which might affect the quality of electricity;  Monitoring electricity quality in the Company's transformation substations, on the PTG/PDG interface, on dispatchable wind/photovoltaic power plants, as well as on PTG connecting disturbance-generating consumers, with class A equipment, in line with the applicable legislation.

12.3.3. Telecommunications system development strategy An important component of CNTEE Transelectrica SA's mission is to ensure the telecommunication services necessary for the operation of the National Power System under maximum security and stability conditions, whilst complying with the approved requirements. In this context, we aim to redefine and reorganize the services provided, which represent a significant support for the Company's activities, by upgrading them to modern technologies, appropriate to the requirements. The communications infrastructure represents a decisive factor in terms of functionality and security of IT applications in the organization. Telecommunications equipment and the associated applications, depending on their specifics and functional destination, are grouped in interconnected platforms. Certain infrastructure components, in particular the ones that use optical fiber as means of transmission, have exceeded their lifecycle, which generates high maintenance costs. This implies that, in addition to the works done for maintaining the current system operational, the equipment that is no longer operationally safe must also be replaced with equipment adapted to new technologies.

194

12.3.4. Critical infrastructure protection development strategy Given the significance of energy security in the context of national security, the security of power facilities is an objective of constant interest for transmission system operators. Evolutions in the last two decades have shown an increasing level of vulnerabilities caused by failures, destruction and/or interruptions in technological infrastructures (transportation, energy, IT, etc.) due to terrorist acts, natural disasters, negligence, accidents, criminal activities. In order to ensure a safe and stable operation of the national power system, CNTEE Transelectrica SA is considering an increase in the protection level of objectives, taking into account both the patrimonial value of assets, and their functional significance. CNTEE Transelectrica SA's strategy on providing an appropriate objective protection level, with minimum costs, includes a set of own tasks conducted at Company level: 1. Assessment of vulnerabilities and risk management: this task identifies critical objectives for carrying out the activities, as well as their vulnerability level. 2. Continuous improvement of the capacity to respond to threats: represents the extent to which staff is prepared to face a most varied range of physical and IT threats. 3. Crisis management: ensures that the system as a whole is ready to respond to physical and IT threats. 4. Drafting process continuity plans: considers aspects related to the reduction in the probability of long-term malfunctions and the increase in the promptitude of recovery of the initial status, via a multicriterial, unitary coordinated prioritization, starting with ensuring functionality of national/European critical infrastructures and continuing with the ones vital for the Company, thus reaching the optimal operational solution under the new conditions. 5. Communication development: provides for coherence of response capacity-related tasks, crisis management and recovery plans. An important aspect is the connections with the authorities. 6. Increase in the physical protection level: pursues a reduction in system inner and outer threats. 7. Information protection: for reducing the probability that critical, classified or non-classified information is available to potential aggressors.

In implementing the aforementioned measures, CNTEE Transelectrica SA aims at setting up and operating a security management framework as an integral part of the Company's management system.

Physical protection program implementation The physical security system that CNTEE Transelectrica SA intends to achieve shall comply with the security principles required to systems of size and complexity similar to those of the Company, i.e.: - possible dispatching of security incidents; - possible definition of increased security areas, depending on the significance of the objective and the various areas on the territory of the objective; - capacity to extend to all Company objectives; - unique identification of access requesting personnel;

195

- authentication of persons approving access requests; - transmission of requests and approvals in a secured, unified and accessible electronic format; - creation of databases to provide for access traceability within strategic objectives related to the critical infrastructure; - possible granting and revocation of operative access.

After the completion in the course of the 2013-2016 timescale of the integrated security systems associated with a total of 13 objectives within the Company, we shall develop a unitary concept for operation and continuous improvement of technical means necessary to ensure the physical security of the Company's objectives. In order to prevent and to manage events that endanger the electricity transmission infrastructure, CNTEE Transelectrica SA also considers the following future projects:  Ensuring continuity of business and recovery after disasters in correlation/interdependency with the Company's security plans associated with the protection of national/European critical infrastructures, operated by CNTEE Transelectrica SA;  Voice-data infrastructure security system and crisis management.

12.3.5. CNTEE Transelectrica SA's strategy in terms of research and innovation 12.3.5.1. Current and future challenges for the transmission system operators (TSOs) Relevant technological trends that will create a new reality in power systems:  Digitalization: this will lead to more numerous, faster and more valuable data, to increased computing power and to a better interconnection of all assets within a power system. This will optimize the design, planning and operation of assets in the field of wind power, solar power, transmission, distribution and usage of electricity in society;  Solar energy: evolutions in photovoltaic generation technologies will reduce costs with solar power by up to 40% over the next ten years and the price of modules will decrease by over 20% for each capacity doubling. Until 2025, photovoltaic technology will be the most inexpensive method to acquire electricity in several regions of the world;  Energy storage;  Bi-directional communications: for a better involvement of end customers in improving the quality of services they benefit from;  Smart Grids: smart grid-type networks will begin to manage themselves and will include features which allow self-configuration in order to manage security, safety and reduction of losses, self-control in order to approach voltage fluctuations and self-optimization in order to mitigate disturbances. New modelling techniques will be developed for the design, testing and verification of power grid management.

Main research and innovation challenges for electricity transmission system operators:  Using data extraction and high-performance computing (HPC) techniques: for a better grid management, closer to its physical limits;  Using new materials and technologies: in order to increase the grid's flexibility;

196

 Developing methodologies and tools in order to operate the grid closer to its physical limits, without endangering its security: TSOs will have to develop decision making expert systems and support instruments in order to anticipate potential emergency situations, to offer a warning to system operators in due time and to suggest possible solutions in real time, along with their probability of success;  Increased use of renewable sources: digitalization of the power system and cybersecurity problems pertaining to these developments and a more active involvement of clients on the energy market are new challenges to which the power system responds through investments in research and innovation activities;  Developments in other sectors: such as energy storage batteries which brought new solutions/challenges in the power system and the need to extend the spectrum of options contributing to system services. Interactions with other electricity conveyors might also become an option in and of itself;  The power system digitalization will ensure: o the development of the information technology sector in the entire society and economy will also influence power systems. The transfer from a "copper-based supply system" to a system that integrates information technology to a higher extent, given that data and data nodes management which supports cybersecurity issues is of great significance. These new developments must be taken into consideration and even completely integrated in the research and innovation activities of grid operators; new complex activities will have to be defined regarding the digitalization of the power system; o structuring and capitalizing on digital data types: . Statistical data – facts such as the annual energy balance of a country; . Structured data – data types or packages extracted from large data groups and used by certain administrators/operators in specific fields (e.g. the data might come from readings of electricity meters); . Big data – large quantities of data collected from various sources (via sensors), most frequently in real time. It represents a large volume of various data, transmitted at high speeds and which must be processed in order to be used for taking decisions and optimizing processes;

 Maintaining the system's security and stability: it is necessary to carry on efforts in using new materials, concepts, standards, instruments and algorithms which will process more and more information in order to approach the power system security and stability issue.

12.3.5.2. Objectives of the research and innovation strategy I. Innovation represents the prerequisite for success in achieving the Company's vision and mission. II. Innovation will be prioritized for the base operations of the Company, creating added value by digitalizing processes, improving services and increasing personnel skills. III. Innovative solutions, technologies, systems and concepts necessary for key activities will be implemented on a generalized scale within the Company, after:  their testing and validation within pilot projects; or  their critical assessment within projects already completed in other organizations.

197

IV. Innovation will be the driver allowing the Company to implement the Learning Organization concepts. V. Innovation and research will support Digitalization as a major objective. VI. Research within the Company will focus on the development of the following pillars:  National and international partnerships in the field of fundamental and technological research (observing basic principles, formulating technology concepts, experimental demonstration of concepts, laboratory validation of technologies);  Partnerships with solutions and equipment suppliers for product/technology demonstrations (technologies validation in relevant and operational environments);  Partnerships within certain competitive procedures (for delivering and commissioning products and solutions). Please see Annex H-1. VII. Participation of personnel to events which have a significant innovation and research component, both in the national and in the international framework (e.g. ENTSO-E, CIGRE, congresses, round tables, symposia etc.), shall also include the process of knowledge sharing and best practices spreading within the Company in an integrated and regulated manner. VIII. Structuring general and specific objectives shall take place considering the methodology promoted within the ENTSO-E strategy for research and innovation. IX. The Company's research and innovation strategy will comply with the centralized organization structure (management committee, strategy manager, processes outline, well defined roles, objective based management). X. Financing research and innovation works will be prioritized both via own sources, as well as external sources, reaching the level of the most consistent group of European grid operators (e.g. non-repayable funding programs, subsidies, grants, partnerships, etc.).

The research and innovation strategy consolidates the Company's vision in terms of the transmission grid modernization, ensuring the necessary support for the implementation of priorities comprised in the Development plan, the Administration plan and the Management plan, and supporting the implementation of the Digital Transformation concept. Objectives associated to key fields of interest for the Company are broken down by activities in Annex H-2. A safe and reliable power system needs an adequate grid infrastructure which must be modernized and maintained based on efficiency criteria. Implementing new smart grid technologies will allow the improvement of this infrastructure's operation. The strategy claims that the development of smart technologies implies a significant effort for the implementation of a larger number of "smart initiatives". These initiatives include:  implementing technologies necessary to monitor and control the grid and its components (asset management based on their condition);  installing sensors and developing the smart infrastructure (e.g. Smart Grid substations) to monitor the technical condition of critical assets;  designing and implementing security solutions to guarantee confidentiality, availability and integrity of information. The digital transformation in the energy industry will bring new challenges for management teams, operational specialists and partners of the Company. The Company will fulfill all

198 requirements for becoming a Learning Organization if it will fully use the potential of new technologies in achieving the digital transformation. As the energy industry evolves, the Company will have to develop the profile of professionals, from technical experts focused on technical excellence, to new professionals who are skilled in the management field, with analytical and innovation abilities. The strategy claims that the grid's digitalization is a clear opportunity for an efficient development and management of the power system, with a proven reliability in terms of improving service quality and lowering operational costs. The research and development strategy ensures the operationalization of all interested parties' vision in terms of implementing a flexible, open and interoperable infrastructure within a digital portfolio ("The Company's digital agenda") in which traditional processes, mainly the manual ones (based on paper and printing) are eliminated or digitalized so that information may be accessible in real time. The objectives included in the "Research and innovation strategy" bring added value in the following fields:  the Company's strategic vision;  asset management;  improving the key performance indicators (KPIs) portfolio;  developing key abilities necessary for the grid operation;  human capital policy;  organizing and operation of the research and innovation activity following the ENTSO-E model (please see Annex H-3);  capitalizing on opportunities for improving the Company's performance;  developing skills for the Company's personnel;  testing and adopting new technologies, standards, solutions, policies, etc.;  Smart Grid policy;  maintenance and operation policy;  developing partnerships with technology and solutions suppliers.

12.3.5.3. Challenges regarding asset management for transmission system operators (TSOs) Both the CNTEE Transelectrica S.A's research and innovation strategy [27] and its Smart Grid policy [28] commit to objectives and targets for the following 10 years and support CNTEE Transelectrica S.A's strategy for asset management.

Smart Grid concepts and standards apply in the European framework in conjunction with the requirements provided by the standards specific to "Asset Management".

ENTSO-E members implemented consistent Smart Grid initiatives:  Smart Grid strategies and policies;  unitary management in terms of organization and implementation of Smart Grid concepts (working groups, clear objectives, roles and tasks delegations, etc.);  infrastructure projects which apply: o the CEN/CENELEC/ETCI/ISO/IEC interoperability standards;

199

o cybersecurity standards and policies;  asset management integrated concepts, supported by Smart Grid concepts: o organization – active health centers; o health index concept; o risk index concept; o concept of monitoring the technical condition of the assets.

The development of practices pertaining to asset management implies knowledge, methodologies and technologies for:  concepts of monitoring the technical condition of assets which are part of electricity transmission grids (primary and secondary equipment) via the massive use of sensors in order to schedule maintenance which maximizes the grid flexibility and reliability;  using technical condition-based maintenance for viewing the optimal use of assets and increasing the grid availability;  optimizing the life cycle costing of facilities/equipment via cost optimization algorithms and sensitivity analyses according to the provisions of IEC 60300-3-3 – "Dependability management: Application guide – Life cycle costing";  developing new maintenance methodologies for new energy technologies (HDVC lines, electronic power inverters, underground cables, etc.);  a better understanding of the way in which the grid works and the conditions affecting the ageing of critical assets.

From the Smart Grid perspective, asset management will allow significant developments in the following fields:  Grid planning (new asset management methods will allow an efficient grid planning by increasing the infrastructure which allows the monitoring of grid assets' status (condition), therefore allowing a more efficient maintenance and development program);  Grid operation (dynamic asset management instruments will further allow proactive measures for improving the grid security and resilience. Monitoring the grid assets' status allows grid operators to use the full asset capacity, thus increasing the grid flexibility and continuity);  Social and economic impact (asset management innovation may improve the grid development by balancing different risk aspects related to system operation and may contribute to reducing system failures).

12.3.5.4. Advantages of applying Smart Grid concepts and standards The advantages of applying Smart Grid concepts and standards for supporting an efficient asset management are:  improving financial performance;  decisions related to investments and asset maintenance are well-founded;  management of risks related to the operation of power systems;  improved services and results;  increased operational efficiency and effectiveness (Operational Excellence);  extending the lifetime of assets.

200

The Smart Grid reference architecture specific to CNTEE Transelectrica SA, together with the associated systems and subsystems, is presented in Annex H-4 and Annex H-5 respectively. Periodical preventive maintenance actions based on the flexibility of grid assets will support strategic and operational decisions in order to improve the general flexibility of power systems and will contribute to a higher level of renewable energy sources integration. In order to improve risk management in transmission grids, we must implement predictive maintenance policies based on more accurate estimations of the lifetime of assets. Real time monitoring of power flows in the grids and of the status (condition) of grid assets may significantly contribute to the decisions related to asset management (e.g. maintenance, modernization, replacement).

201

13. Assessment of investment expenditures for the development of the PTG

Bay cost indicators were evaluated per voltage level and per transformer/autotransformer, for each installed power level, in order to assess the necessary development expenditures volume for the entire PTG in the initial stages of projects. These costs also include the expenses related to constructions, secondary circuits, metering systems and command, control and protection systems.

Unit costs were estimated based on the actual costs of the investment projects conducted after the year of 2005. In cases where the Company lacked its own recent experience, we used information on prices estimated in consultants' studies or obtained in the grid costs estimation process, carried out in order to implement the European loss compensation mechanism between TSOs.

Annex F-1 (not published) presents the specific unit costs related to primary and secondary/ancillary equipment, used for evaluation purposes.

After the implementation of legislation on the renewable energy sources promotion system, CNTEE Transelectrica SA and the distribution operators received a very large number of grid connection requests from this type of power plants (in particular wind power plants), concentrated in a narrow geographical area. Therefore, we had to account for a significant quantity of investments for consolidating the capacity to discharge the generation from these power plants, in addition to the PTG rehabilitation/modernization/development needs in line with previously anticipated historical trends.

The simultaneous launch of high production quantities from renewable energy sources requiring connection to the grid in the following period leads to a need for a grid development effort unprecedented in the last 20 years and results in a substantial increase in expenses as compared to the estimations for the development plans prior to 2008.

CNTEE Transelectrica SA permanently follows the evolution of users' projects and updates its PTG development plan accordingly, also considering its own financial projections. With every update, the Company seeks to establish a sustainable plan, which is balanced both in terms of the possibility to carry out the works, and in terms of CNTEE Transelectrica SA's ability to financially support it.

The progress in terms of constructing new lines is delayed by the very long time period necessary for obtaining permits/authorizations and rights over the necessary land plots (land expropriations, removal from the forestry, removal from agricultural use). Projects for new power lines require obtaining environment permits/agreements, which consist of procedures lasting between 2 and 3 years. In some cases, this led to the resumption of the authorization process for obtaining urban planning certificates, which had an extension timeframe of maximum 1 year, or even to the resumption of the design phase, as other entities/authorities designed/carried out works on the route initially designated to the future power line.

The planning of investment expenditures took these conditions into consideration, so that the expenditures for refurbishing and designing the critical infrastructure dominated in the first half of

202 the interval, while the expenditures associated with the construction of new lines are found predominantly in the second half of the interval.

If the issues associated with obtaining authorizations and land plots for new lines are solved quicker than estimated, investments shall be carried out in the shortest possible timeframe, using potential savings achieved in other prior investments.

Table 12 and Annex F-2 (not published) present the staging of expenditures associated with the direct PTG investment projects proposed in the development plan for the 2018-2027 period.

Figure 13.1 presents a 10-year interval of the investment expenditures for the development of the PTG, estimated in the current plan (2018-2027), in comparison with the last approved edition of the plan (2016-2025).

Figure 13.1

Figure 13.2 presents the structure of the investment expenditures for the development of the PTG, in terms of the pursued objectives.

203

Figure 13.2

204

14. Sources of funding

14.1. CNTEE Transelectrica SA's revenues Regulated tariffs associated to licensed activities (the electricity transmission service, functional system services) represent the main revenue source of CNTEE Transelectrica SA for financing the development of infrastructures operated by the Company. This is complemented by secondary revenue sources, mainly represented by cross-border interconnection grid capacity allocation to energy market participants, but also other services; however, these secondary revenue sources represent a small share in the total revenue of the Company compared to the revenue obtained from the regulated tariffs. Additional revenue sources are the ones from applying the tariff for ancillary services and the ones from managing the balancing market. Both sources mentioned, although significant in size, are not useable for financing the development of the infrastructure operated by CNTEE Transelectrica SA. These revenues do not generate profits, but are designed to be spent in full for financing a specific expenditure category, namely for the procurement of power reserves necessary to ensure the NPS balancing from qualified electricity generators (ancillary services) and for costs related to real time balancing of electricity generation and demand (managing the balancing market).

CNTEE Transelectrica SA's activity is a regulated natural monopoly and, in line with the methodologies set forth by applicable regulations, only the transmission service and functional system service are generating profits.

The methodology for determining tariffs for the electricity transmission service is based on the "revenue cap" principle, according to which the regulated costs are at the center of the tariff setting mechanism. The regulated revenue is calculated based on justified costs, acknowledged by ANRE, while the cost base includes operational and investment costs. Some cost elements from the operational cost base acknowledged in the regulated revenue are capped in order to stimulate the operator to permanently seek solutions in order to increase efficiency. For these cost elements, the tariff setting methodology includes a mechanism to reward operators if they obtain a higher efficiency level compared to the targets set by ANRE; the additional profit thereby obtained is kept in part by the operator (50%), while the remaining 50% goes to the benefit of clients via future tariffs which are lowered accordingly. In terms of investments, the methodology for determining tariffs for the electricity transmission service is made up of two components: (i) recovering the capital invested in transmission assets via the depreciation mechanism; and (ii) the profitability of the asset regulatory base (ARB), calculated as a product of the ARB value (which includes the value of the Company's assets financed from its own funds and loans resulted from efficient investments) and a reasonable level of capital profitability (RRR – regulated rate of return) for covering all funding costs.

14.2. Funding sources for the development of infrastructures operated by the Company

Out of the Company's total revenues, only the ones obtained from the transmission service regulated tariff, the functional system services regulated tariff and the cross-border interconnection

205 capacity allocation are generating sources of funding for investments. Revenues obtained from the ancillary services tariff and revenues obtained from managing the balancing market are limited to the recovery by the Company of the current operational costs necessary to carry out the respective activities, without including a component for investment expenditures (ancillary services are provided with qualified energy capacities owned and operated by energy market participants, therefore it does not require CNTEE Transelectrica SA's own infrastructure), therefore these revenues do not contribute to the funding sources for the Company's investments.

The completion of the PTG development has the following components:

 Transelectrica's own sources (self-funding) . The revenue flow generated by basic operations (mainly via the transmission tariff, complemented by revenues generated by the allocation of transmission capacities on interconnection lines – used in financing PTG investments that lead to an increased interconnection capacity with neighboring systems). . The revenue flow generated by financial investments: collected dividends and interest; the contribution of these amounts is insignificant compared to the cash flow from basic operations.  Transelectrica's external sources (attracted funding): . The banking system – since its establishment (in the year of 2000), CNTEE Transelectrica SA built solid relationships with local banks and international financial institutions (IBRD, EBRD, EIB); an important part of the investment programs implemented by the Company in the last 16 years were financed via loans attracted from the banking system. There is currently a high interest permanently manifested by credit institutions to participate in programs for financing infrastructure investment projects, the energy sector being one of the main areas considered for funding. . Via corporate bond issuances on local or international markets (issuances in the local currency or in euro, as the case may be) which have a determined time period and a fixed financing cost during the entire period. The bond issuance can and does represent a solid alternative to financing the investment program that might compensate a series of shortcomings associated with classic financing methods.

Financing may be attracted both via methods that involve the punctual, ex-ante establishment of individual investment projects with dedicated funding (a model used in the past in relationship with the IBRD, EBRD, EIB), as well as methods that allow using borrowed funds for the general financing needs of investment plans that do not limit the use of funds to a predefined list of projects.

CNTEE Transelectrica SA currently benefits from a substantial indebtedness capacity, plentiful for covering the estimated needed funding for supporting the PTG development plan for 2018- 2027. Given the stable and predictable cash flow, ensured by the regulated tariffs associated with transmission activities and functional system services, the estimated additional debt to be attracted will lead to a level of the debt service that can be comfortably managed by the Company.

206

Within the Large Infrastructure Operational Program, priority axis 8 – "Smart and sustainable transport system for electricity and natural gas", specific objective 8.1 "Increasing the capacity of the National Power System for taking over energy generated from renewable energy sources", CNTEE Transelectrica SA will request financing from European funds for the Gutinas-Smardan 400 kV d.c. OHL (1 circuit equipped) project. The documentation is currently in progress, the final deadline to submit the application is 30.06.2018.

On 09.10.2017, the Company also submitted an application to obtain financial assistance from the EU in the form of a grant, requested in the process of accessing European funds, for conducting and implementing the Project of Common Interest – Cernavoda-Stalpu 400 kV d.c. OHL, via the financial instrument called Connecting Europe Facility (CEF). The list of European funding eligible projects, including the amount of the funds, was published on 24.01.2018. The Cernavoda-Stalpu 400 kV d.c. OHL project received a favorable opinion for financing in the form of a grant, via the financial instrument called Connecting Europe Facility (CEF). According to this financial support mechanism established by EU Regulation no. 1316/2013, the EU financial assistance amounts to maximum 50% of the works' eligible costs.

The indebtedness level is limited by restrictive clauses included in agreements/contractual commitments undertaken by the Company in relation with creditors. The restrictive contractual clauses relate to maintaining the financial risk indicators within pre-set limits. The indicators are regularly calculated, audited and communicated to creditors.

The PTG is the public property of the State, transferred to CNTEE Transelectrica SA under concession in line with the legal provisions; the grantee quality obligates the Company to maintain the transferred assets at least at the technical level at which they were transferred and, as the case may be, at a superior technical level, corresponding to the technological development. As such, the first concern for the tariff financing relates to the modernization and refurbishment works.

As a result of significant changes estimated for the following period in the structure of the generation park, in particular as a result of the development of generation based on renewable energy sources and the construction of two new nuclear units, a major concern is to extend and consolidate the PTG in order to face new power flows that will transit it.

ANRE decides on accepting investments and acknowledging new tariff revenue generating assets in the ARB.

In addition to the funds obtained from the regulated tariff, CNTEE Transelectrica SA will also consider other financing channels which will limit the pressure on the regulated tariff: - Accessing European funds – Large Infrastructure Operational Program; - The financial instrument "Connecting Europe Facility" (CEF) – facilitating financing for projects of common interest (PCIs) if several eligibility criteria are simultaneously fulfilled.

207

Figure 14.2 – Funding sources structure

*) Funding from the regulated tariff for the transmission service/functional system services. The net revenue flow (after covering operational costs) that will be effectively generated by CNTEE Transelectrica SA from the regulated tariff in the timescale of the PTG development plan (10 years) will not cover the entire amount; the regulated tariff will ensure the gradual recovery of invested funds in a timescale longer than the timescale provided for the PTG development plan (the average recovery period for an investment via the tariff is 20 years). In order to account for this temporary deficit not covered by revenues obtained from the tariff during the timescale of the PTG development plan, the plan's necessary funding – namely the part left unaccounted for by non-refundable funding and revenues from cross-border interconnection capacity allocation – will be covered by complementing funds obtained from the regulated tariff with funds attracted from the financial market (examples: bank loans, debt securities issuances). In order to present the PTG development plan funding sources individually, the financing from the regulated tariff includes the funds attracted from the financial market, considering that in a longer timescale, the regulated tariff ensures the full recovery of these funds. A precise determination of the financing amount necessary from the financial market in the timescale provided for the PTG development plan (2018-2027) is not feasible at this moment, considering that the tariff regulation parameters for the following regulation cycles have not been yet established by ANRE.

208

15. Analysis directions for the next stage

Analyses and actions must be conducted on the following aspects for the following stage: - Optimal PTG development, correlated with the NPS evolutions, in order to maintain the NPS operational security; - Establishing a common action plan for developing the transmission and distribution grids in the Bucharest municipality, based on conclusions of studies for identifying the best PTG development solutions in the outskirts and urban area of the Bucharest municipality, drafted by Transelectrica and ENEL Distribuție Muntenia Sud; - Voltage control and reactive power circulation – identifying needs and studying the possibilities to introduce secondary control; - Increasing the interconnection capacity with neighboring systems; - The existence of necessary power reserves and achieving the generation/demand balance by constructing wind power plants and groups 3 and 4 in the Cernavoda NPP, using the statistical analysis of WPP and PVPP operation, correlated with the use of advanced instruments for adequacy evaluation via probabilistic methods which integrate the availability of generation capacities, but also of transmission capacities; - Updating the system analyses necessary to provide for the discharge of the surplus power from the Dobrogea and Moldova areas, considering updating the hypotheses based on the known evolution of projects and newly received requests; - Updating the reliability indicators for PTG nodes; - Preparing the implementation of national and European regulations which impact the TSO's activity, as the regulations enter into force; - Increasing energy efficiency; - Implementing and diversifying LW technologies; - New solutions for implementing the Smart Grid concept in the PTG – Refurbishing the Alba Iulia 220/110kV/MV substation in the Smart Grid concept; - Complementing and adapting the regulatory framework regarding grid access and integrating wind and photovoltaic generation in the NPS.

209

Bibliography

1. PTG Development Plan. 2016-2025 period, Transelectrica S.A., 2016 2. Romania's energy strategy for 2007-2020, approved by Government Decision no. 1069/2007 3. National Renewable Energy Action Plan, 2010 Energy strategy elements for the 2011-2035 period, 2011 4. Romania's energy strategy for 2016-2030, and 2050 as a guide. Preliminary version subject to public consultation, Ministry of Energy, 15 November 2016 5. Analysis of steady-state and transient stability and of short-circuit loads in the PTG, TRACTEBEL Engineering S.A.,2018 6. Operational planning of the NPS operation in the summer of 2017, Transelectrica NPD, 2017 7. Operational planning of the NPS operation in the winter of 2016-2017, Transelectrica NPD, 2017 8. Study on the development of the supply power grid in the metropolitan Bucharest area – 10- year perspective, SC ISPE S.A. & TRACTEBEL Engineering S.A. association, 2015 9. Study on the evaluation of the cost of interruptions in supplying the demand and/or generated power discharge service, ISPE S.A., 2008 10. Study on the factors that influence the OTC in the PTG and methods to reduce it, ISPE S.A., 2010-2011 11. Study regarding the necessary means to control voltage/reactive power in the NPS – 5-year period, ISPE S.A., 2011 12. Study on the update of reliability indicators for PTG nodes, ISPE S.A., 2015 13. Study on the implications regarding connecting wind power plants to the NPS, ISPE S.A., 14. 2008 Study on the PTG development in the mid and long term (2018-2022-2027), SC ISPE S.A., 2018 15. Transelectrica Operational Procedure "Data and technical information exchanges among PTG users and technical operators for safe operation of the NPS", TEL Code – 03.03, ANRE endorsement no. 06/2002 16. Ten-Year Network Development Plan Package 2016, ENTSO-E, 2016 17. System Adequacy Retrospect report for 2016, ENTSO-E, 2016 18. The "UCTE System Adequacy Forecast, 2011-2025" report, ENTSO-E, 2010 19. Assessment of the necessary specific reserves for wind generation in Romania, ISPE S.A., 2009 20. Study regarding the Romanian PTG development directions for the 2011-2035 period – integral part of the national energy strategy, ISPE S.A., 2011 21. Operational Procedure "Establishing the maximum installable capacity in wind power plants in terms of NPS safety", TEL Code – 07.38 22. ENTSO-E methodology "Guideline for Cost Benefit Analysis of Grid Development Projects" approved by the European Commission on 5 February 2015 23. Estimating the benefit indicators for evaluating the impact of PTG development projects, TRACTEBEL Engineering S.A.,2018 24. Analysis of the technical condition of electric equipment and facilities in the PTG, NOVA Industrial, 2018 25. Assessing and monitoring the Romanian distribution grids. PÖYRY MANAGEMENT

210

CONSULTING – Report for the Federation of Associations of Energy Utility Companies (ACUE), June 2017 26. Study for the construction of a new national voltage control system by using the modern power electronics technology, ISPE 2016 27. CNTEE Transelectrica SA's strategy for research and innovation (2018-2027), Transelectrica, 2018 28. CNTEE Transelectrica SA's Smart Grid policy (2018-2027) 29. Study on increasing the operational security in the Arges-Valcea grid area, TRACTEBEL Engineering S.A., 2018 30. Ten-Year Network Development Plan Package 2018, ENTSO-E, 2018

211