Armenian_Energy_System_Long-term_Development_Strategy,_(unofficial_translation),__December_2015.pdf

Appendix to Protocol Decision # 54 of the Republic of ARmneia meeting on December 10, 2015

ARMENIAN ENERGY SYSTEM LONG-TERM DEVELOPMENT COURSE (UNTIL YEAR

2036)

1. GOAL

1) The energy development strategic programs developed so far have been designed to ensure the energy security of the Republic of Armenia in line with the provisions of the National Security Strategy of the Republic of Armenia.

The “Energy Security Concept Paper” approved by the President’s Decree # NK-182-N on October 23, 2013 and the “Timeframe program of the activities for 2014-2020 ensuring implementation of the Energy Security Concept Paper provisions” outline affordable, high quality and reliable energy supply for the state’s needs on a daily basis, as well as in emergencies and at war.

The activities mentioned above aim to ensure sustainable development of the energy system based on increasing the energy efficiency of the economy, nuclear energy development and efficient use of renewable resources. According to the timeframe, activities are planned to reduce physical and moral depreciation of the equipment and mechanisms utilized in the energy system, to extend the life of the Armenian NPP’s operational energy unit by 10 years, construct a new 1000 MW energy unit in the Armenian NPP and to construct a second 250- 450 MW combined cycle steam/gas energy unit in the Yerevan TPP. It is also planned to boost the future development of renewable energy ad ensure the regional integration process.

Given the developments in 2013-2014 in the fuel energy market and in the energy system technologies sector, the regional integration deepening and expansion trends, as well as the results of negotiations with the Islamic Republic of Iran, the Russian federation and other countries, a need emerged to plan and merge the programs of strategic importance in the energy sector in the long –term perspective (by 2036), which resulted in development of the “Armenian Energy System Long-term Development Course”.

This document is based on Armenia Least Cost Energy Development Plan, developed with the support of the US Agency for International Development (USAID). The program has been widely discussed in 2014 and 2015 in the Government of Armenia and in the Public Council in coordination with stakeholders and international financial organizations.

At the same time the World Bank, that has been funding energy system infrastructure programs, has initiated an energy system analysis in 2014 and has come up with a number of acceptable recommendations.

The need for developing this document is also justified by the fact that the the new nuclear unit’s commissioning process will last at least 10 years and in order to make a respective decision the Government needs to have a vision of the country’s energy and fuel system long term development and risks.

It is worth mentioning that regardless of any developments , in order to avoid an energy crisis in the future it is absolutely necessary to implement a generation change in generating powers, since as displayed in the table below, the major part of the generation facilities have been in operation for more than 30 years. The transmission and distribution grids were built in 1960-1980 and irrespective of the upgrade activities continuously implemented during the past years, it is still necessary to continue the grid refurbishment.

Name Installed/actual capacity MW

Generation GW/h 2014/maximum

Year of commissioning

Armenian NPP 440/385 2465/2400 1980 1989-1995 stopped

1995 restarted Yerevan CCGT 272/220 1448/1760 2010 Hrazdan TPP units 1-4 3x200/3x185 1x210/1x185

957/5040 1972

Hrazdan-5 480/440 858/3520 1974 Sevan-Hrazdan HPP cascade

559/559 475/500 2011

Vorotan HPP cascade

404/404 833/1200 1936-1962

Small HPPs and wind PPs

222/222 689/689 -

The investment programs in the energy sector are costly, while their funding arrangement time is long-lasting. This is why a need emerges to plan selection of both generation capacities and electricity grid equipment (substations, power lines) through an optimum modelling mechanism, according to technology and timing.

2. Background and General Provisions

1) The Armenia Least Cost Energy Development Plan was developed using the MARKAL- Armenia software with USAID support and funding, with participation of the Scientific Research Institute of Energy. It helps to improve the long-term development of the whole energy system, including all energy resources (oil products, nuclear, hydro, renewable, biomass, etc.), production and transmission infrastructures in all consumption sectors (industry, transport, population, services, agriculture).

The development planning period is 20 years. The international experience has proven that similar developments require a review every 2-3 years in order to consider the current changes.

2) The following baseline provisions were considered during the activity:

a. GDP and Population Annual Growth Rates

Annual Growth 2015 2018 2021 2024 2027 2030 2033 2036 Source

GDP 5.70% 5.70% 5.70% 5.70% 3.00% 3.00% 3.00% 3.00%

World Bank1

Population 0.175% 0.024% 0.024% -0.215% -0.215% -0.215% -0.275% -0.275% GoA

Growth of sector demands Economy Sector Annual growth, % Overall growth, %

Residential 3.0 203

Commercial 2.9 201

Industry 3.8 245

Agriculture 2.3 173

Transport: Passenger 2.0 161

Freight 4.0 254

Growth of sector demands Economy Sector Annual growth, % Overall growth, %

Residential 3.0 203

Commercial 2.9 201

Industry 3.8 245

Agriculture 2.3 173

Transport: Passenger 2.0 161

Freight 4.0 254

b. The table below displays the capacities of gas pipelines of RoA. Picture 1 displays imported natural gas forecasts.

Gas pipeline Daily maximum capacity, million m3 Annual maximum capacity, billion m3 North-South pipeline 1 2 4.38 Iran-Armenia pipeline 8 2.30

Total 20 6.68

1 Data were taken from World Bank study, provided by MENR.

Fig.1

c. RoA Energy balance for 2012 developed by the International Energy Agency (IEA) was used. It is now available at the IEA website.

d. The Armenia Least-Cost Energy Development plan has considered the following technical and economic data of new capacities

Technology Capacity MW Per unit investment, $/KW

Investment, million USD

Efficiency rate Annual production, GWh/year

VVER-1000 1,028 5,230 5,376 0,342 8,105

CANDU-6 670 3,196 2,141 0,342 5,282

ACP-600 610 4,001 2,441 0,342 4,809

SMR (small module reactor)

360 5,988 2,155 0,34 2,838

Existing NPP life extension

385 779 300 0,300 2,777

Meghri HPP 130 0 0 0,88 800 Loriberd HPP 66 2,138 141 0,88 212 Shnogh HPP 70 2,189 168 0,875 270 Small HPPs 148 1,201 (1,501 after year 2021) 177-222 0,9 544

Geothermal 30 3,082 92 194 Solar PV 70 2,689 203 145 Wind 200 2,587 517 527 Combined cycle Gas Turbine Plant

220/400* 1,030 227/412 0,49 1,760/3,200

* projected production is displayed, the forecasted production will be 421 GWh

** final selected capacity of each unit is 234 MW

e. MARKAL software includes more than 1000 consumption technologies for all consumption sectors, as well as expected technologies for years 2015, 2018 and 2021 with respective technical and economic descriptions.

e. According to Article 5 of Vienna Convention on Civil Liability on Nuclear Damage requirements, third party responsibility insurance of at least 5 million USD should be provided for the ANPP energy unit in operation. Armenia will also be required to ratify the 1997 Protocol of Vienna

Convention and/or the Convention on additional compensation for Nuclear Damage, in which case the minimum responsibility amount will be far higher. These additional costs have not been considered in the analysis.

f. The Plan also does not include the costs related to stopping ANPP’s operation. This factor did not have an essential impact on the economic comparison, since the costs will be incurred with each scenario implementation. However, these costs for 2028-2036 activities will make around 35 million USD and should be calculated in the total costs of the system. In order to ensure savings by year 2017 this will cause an additional burden of 0,6 AMD/KWH on ANPP tariffs of 2018-2016.

The 300 million USD funding issue required for next years’ activity has not been solved.

g. The new nuclear unit/units decommission costs have been considered during the analysis and included in the prime cost calculated for nuclear unit/units.

3) The The Armenia Least Cost Energy Development Plan also considers the main factors influencing long term expenditures of the system, energy security levels and own energy resources development. More than one hundred options were considered, which were later summarized in the final reference scenario and a number of alternative scenarios. These are displayed in the below chart (the fundamental provisions of the reference scenario are displayed on blue, while additional provisions on white).

4) This document considers the reference scenario as basic, with the following prerequisites:

a. use of prices on natural gas imported from the Russian Federation, per actual agreement

b. Current nuclear unit life extension until 2027

c. implementation of the Armenia-Iran interstate agreement conditions by 2016. Continue with terms of agreement after 2027, if economically efficient.

d. Commission of the new 1000 MW capacity nuclear unit in 2027.

e. Lack of opportunities to import electricity from the Republic of Georgia to ensure the necessary energy security level.

Gas price

Russian

European

Nuclear

Existing unit life extension

VVER-1000

CANDU 670

ACP 600

SMR

EGE

Exchange per agreement until 2026

Exchange after

Electricity imports from Georgia

No iup to 2000

GWH

No import

AE and RE

AE promotion

RE promotion

Hrazdan 5

Mandated exploitation

Flexible exploitation

F. Utilize economically justified potential of renewable energy (limiting solar PV technologies to 70 MW, wind plants capacity to 200 MW. This causes an expectation that the geothermal potential studies will have positive outcomes and will justify construction of a geothermal plant in the reported period.

g. Energy saving activities

5) The impact of Hrazdan-5 energy unit exploitation agreement provisions on the energy system developments was studied separately, which is also displayed in Figure 2.

The table below displays results of reference scenario capacities inclusion and Power generation forecast:

Power Plant, MW 2012 2015 2018 2021 2024 2027 2030 2033 2036 Hrazdan 5 440 440 440 440 440 440 440 440 440 Hrazdan TPP 1-4 units 370 370 370

New CCGT 220 MW 220 220 220 220 220 220

New CCGT 400 MW 400 400 400 400 400 400 400

Yerevan CC 220 220 220 220 220 220 220 220 220 Loriberd HPP 66 66 66 66 66 66

Meghri HPP 130 130

New Small HPPs 60 120 148 148 148 148 148 148

Sevan-Hrazdan HPP cascade 550 550 550 550 550 550 550 550 550 Shnokh HPP 70 70 70 70 70 70

Small HPPs 221.8 221.8 221.8 221.8 221.8 221.8 221.8 221.8 221.8 Vorotan HPP cascade 400 400 400 400 400 400 400 400 400 Armenian NPP 385 385

Life extension of existing plant 385 385 385

New VVER 1000 AES-92 1028 1028 1028 1028

Geothermal power plant 30 30 30 30 30

Lori Wind Farm 3 3 3 3 3 3 3 3 3 New Wind Farms 50 100 150

Solar PV 20 40 40 40 40 40 40

Total 2589.4 2649.4 3129.4 3163.5 3193.5 3836.5 3886.5 4066.5 4116.5

Energy generation

Power Plant, MW 2012 2015 2018 2021 2024 2027 2030 2033 2036 Hrazdan 5 892 1415 3276 2400 2859 36 14 79

Hrazdan TPP 1-4 units 740 1

New CCGT 220 MW 1754 1754 901 1047 877 1166

New CCGT 400 MW 3189 3189 3189 1799 1829 1508 1506

Yerevan CC 1614 1638 1638 1638 1638 1638 1638 1638 1638 Loriberd HPP 208 208 208 208 208 208

Meghri HPP 797 797

New Small HPPs 220 441 544 544 544 544 544 544

Sevan-Hrazdan HPP cascade 633 472 472 472 472 472 472 472 472 Shnokh HPP 270 270 270 270 270 270

Small HPPs 558 558 558 558 558 558 558 558 558 Vorotan HPP cascade 1119 1119 1119 1119 1119 1119 1119 1119 1119 Armenian NPP 2106 2106

Life extension of existing plant 2106 2106 2106

New VVER 1000 AES-92 7505 7505 7505 7505

Geothermal power plant 194 194 194 194 194

Lori Wind Farm 3 3 3 3 3 3 3 3 3 New Wind Farms 132 264 395

Solar PV 41 83 83 83 83 83 83

Total 7665 7531 12844 14344 14997 15294 15638 16054 16537

In order not to downplay the economic competitiveness of thermal power plants, the studies have not considered the investments required to ensure the Northern gas pipeline capacity and to expand the underground gas reservoir. In the nuclear reference scenario in case a 620 MW thermal power plants are constructed, the volume of gas imported to Armenia through the Northern gas pipeline will not exceed 12 million m3 daily, in which case a new gas pipeline construction will be not be necessary. The mentioned gas volume is preconditioned by the underloaded work of thermal power after 2017, caused by the new nuclear energy unit operations start. However, the technical state of the northern gas pipeline will need improvement. Construction of an additional 100 million m3 underground reservoir (10 million USD) and a 20 MW compression station 950 million USD) will be necessary to ensure 1 month gas supply to consumers and to exercise the contractual liabilities in winter time in case of system failures.

6) the energy system costs in the reference scenario are displayed below:

a. general energy system costs: 44, 555 million USD

b. electricity production costs: 17, 740 million USD

c. average weight share of electricity production: 75.9 $/MWH

7) The reference scenario electricity production cost generation per separate directions is displayed in the table below:

Scenario REF Power plant name Parameter 2012 2015 2018 2021 2024 2027 2030 2033 2036

Armenian NPP

Generation, GWh 2106 2106

Expenditure on Fuel, Million $

25 25 Capacity, MW 385 385 Fixed+operations and maintenance costs, Million $

44 44

Levelized cost, $/MWh 33 33

Geothermal power plant

Annualized Investment Cost, million $ 8 8 8 8 8

Generation, GWh 194 194 194 194 194 Lump sum Investment Cost, MILLION $ 92 Capacity, MW 30 30 30 30 30

Fixed+ operations and maintenance costs, Million $

9 8 8 8 6

Levelized cost, $/MWh 65 63 62 62 56

Hrazdan 5

Generation, GWh 892 1415 3276 2400 2859 36 14 79

MILLION $ 62 88 205 182 239 3 1 8

Capacity, MW 440 440 440 440 440 440 440 440 440 Fixed+ operations and maintenance costs, Million $

6 7 11 9 10 4 4 4 4

Levelized cost, $/MWh 76 67 66 80 87 211 397 157

Hrazdan TPP

Generation, GWh 740 Expenditure on Fuel, MILLION $

Capacity, MW 370 370 370 Fixed+ operations and maintenance costs, Million $

10 10 10

Levelized cost, $/MWh 103 Life extension of existing

Annualized Investment Cost, M$ 47 47 47 plant Generation, GWh 2106 2106 2106

Expenditure on Fuel million $ 25 25 25

Lump sum Investment Cost, MILLION $ 300

Capacity, MW 385 385 385

Fixed+ operations and maintenance costs, Million

43 43 43

Levelized cost, $/MWh 55 55 55

Lori Wind Farm Generation, GWh 3 3 3 3 3 3 3 3 3

Capacity, MW 3 3 3 3 3 3 3 3 3

Fixed+ operations and maintenance costs, Million

0 0 0 0 0 0 0 0 0

Levelized cost, $/MWh 92 92 92 92 92 92 92 92 92

Loriberd HPP

Cost, M$ 12 12 12 12 12 12

Generation, GWh 208 208 208 208 208 208

Cost, MILLION $ 158 Capacity, MW 66 66 66 66 66 66 Fixed+ operations and maintenance costs, Million

0 0 0 0 0 0

Levelized cost, $/MWh 57 57 57 57 57 57

Meghri HPP

Generation, GWh 797 797

Capacity, MW 130 130 maintenance costs, Million

7 7

Levelized cost, $/MWh 9 9

New CCGT 220

Cost, M$ 19 19 19 19 19 19

Generation, GWh 1754 1754 901 1047 877 1166

MILLION $ 122 135 74 90 80 111

Lump sum Investment Cost, MILLION $ 227 Capacity, MW 220 220 220 220 220 220 Fixed+ operations and maintenance costs, Million

21 21 15 16 15 17

Levelized cost, $/MWh 93 100 120 120 130 127

New CCGT 400

Cost, M$ 35 35 35 35 35 35 35

Generation, GWh 3189 3189 3189 1800 1829 1508 1506

MILLION $ 183 223 245 148 158 137 144

Lump sum Investment Cost, MILLION $ 312 Capacity, MW 99 117 135 266 266 266 317 Fixed+ operations and maintenance costs, Million

39 39 39 29 29 27 27

Levelized cost, $/MWh 81 93 100 118 121 132 136

New Small HPPs

Cost, M$ 6 11 15 15 15 15 15 15

Generation, GWh 220 441 544 544 544 544 544 544

Cost, MILLION $ 75 75 44 Capacity, MW 60 120 148 148 148 148 148 148 Fixed+ operations and maintenance costs, Million

2 3 5 5 5 5 5 5

Levelized cost, $/MWh 33 33 36 36 36 36 36 36

New Wind Farms

Annualized Investment Cost, M$ 11 22 33

Generation, GWh 132 264 395 Lump sum Investment 129 129 129

Cost, MILLION $

Capacity, MW 50 100 150 maintenance costs, Million

3 5 8

Levelized cost, $/MWh Annualized Investment Cost, M$

103 103 103

New VVER

493 493 493 493

Generation, GWh 7505 7505 7505 7505

MILLION $ 52 52 52 52

Lump sum Investment Cost, MILLION $ 6491 Capacity, MW 1028 1028 1028 1028 Fixed+ operations and maintenance costs, Million

138 138 138 138

Levelized cost, $/MWh 91 91 91 91

Sevan-Hrazdan HPP cascade

Generation, GWh 633 472 472 472 472 472 472 472 472

Capacity, MW 550 550 550 550 550 550 550 550 550 maintenance costs, Million

11 11 11 11 11 11 11 11 11

Levelized cost, $/MWh 18

24 24 24 24 24 24 24 24

Shnokh HPP

Cost, M$ 14 14 14 14 14 14

Generation, GWh 270 270 270 270 270 270

Cost, MILLION $ 187 Capacity, MW 70 70 70 70 70 70 Fixed+ operations and maintenance costs, Million

0 0 0 0 0 0

Levelized cost, $/MWh 52 52 52 52 52 52 Small HPPs Generation, GWh 558 558 558 558 558 558 558 558 558

Capacity, MW 222 222 222 222 222 222 222 222 222 Scenario REF with Russian gas

Power plant name

Parameter 2012 2015 2018 2021 2024 2027 2030 2033 2036 maintenance costs, Million

29 29 29 29 29 29 29 29 29

Levelized cost, $/MWh 52 52 52 52 52 52 52 52 52

Solar PV

Cost, M$ 5 10 10 10 10 10 10

Generation, GWh 41 83 83 83 83 83 83

Cost, MILLION $ 54 63 Capacity, MW 20 40 40 40 40 40 40 Fixed+O&M costs, MILLION $ 1 2 2 2 2 2 1

Levelized cost, $/MWh 129 138 138 138 138 138 132

Vorotan HPP cascade

Generation, GWh 1119 1119 1119 1119 1119 1119 1119 1119 1119

Capacity, MW 400 400 400 400 400 400 400 400 400 maintenance costs, Million

27 27 27 27 27 27 27 27 27

Levelized cost, $/MWh 24 24 24 24 24 24 24 24 24 Yerevan CC Generation, GWh 1614 1638 1638 1638 1638 1638 1638 1638 1638

Expenditure on Fuel, 97 94 94 114 126 135 141 149 156

MILLION $

Capacity, MW 220 220 220 220 220 220 220 220 220 maintenance costs, Million

12 25 25 25 25 25 25 25 25

Levelized cost, $/MWh 68 72 72 85 92 97 101 106 110 Expenditures on Gen, M$ 391 367 804 1029 1151 1308 1359 1350 1416 9175

Investments, M$ 0 75 840 679 92 6491 129 129 129 8566

Generation, GWh

7665 7532 12845 14344 14998 15296 15639 16055 16539 120912

Electricity Gen cost, $/MWh

51.0 48.8 62.6 71.8 76.7 85.5 86.9 84.1 85.6 75.9

Electricity exports, -1696 -1201 -6004 -6905 -6905 -6905 -6905 -6905 -6905 -50329

Electricity imports 98

Internal consumption 6067 6331 6841 7439 8093 8391 8734 9150 9634

Total System Cost, Million $

44555

8) The results of these studies detailed calculations and their analyses are placed in the Energy Strategy Center (ESC) branch of the Scientific Research Institute of Energy cjsc.

This project was widely discussed in the RoA Government and the Public Council in 2014 and 2015, stakeholders, international financial and non-governmental organizations and was presented to the public through public hearings.

The discussions resulted in a recommendation for the following additional discussions:

a. The energy development scenario only through renewable resources,

b. Given the actual available GDP data for 2015 and 2015 , GDP indicators of the «Armenia

Perspective Development Strategic Plan for 2014-2025» approved by RoA Government decision # 442N of March 27, 2014 and GDP growth forecasts for the years observed, also an additional versions was considered with the data below:

GDP

annual growth

2,5%

4,8%

6,0%

6,5%

6,5%

6,5%

6,5%

6,5%

9) All the scenarios mandate construction of a new nuclear unit but after studying the scenarios the projects recommends the 600 MW nuclear unit instead of 1000 MW as a justified option.

Thus in the Conclusions and Activities table this was considered the key option.

10) as a result of the discussions in the Armenian Government when the construction of a new 234 MW thermal plant with combined gas turbine cycle became realistic, an additional scenario of building a 234 MW CCGT instead of 400 MW (in 2018) and 220 MW (in 2021) CCGT envisaged in the reference scenario, or depending on the scenario, building of similar units was considered.

11) The activities presented in Armenia Energy System Long –Term development (until 2036) document are optionally divided into two periods: mid-term (before 2015) and long term (before 2036) and grouped into three directions: market reforms, infrastructure development and energy generation capacity development.

3. Market Reforms

1. Mid-term activities until 2025

1) Stage by stage liberalization of the Armenian energy market to increase its efficiency and promote investments, in line with Armenia’s EEU accession and EU commitments

2) Introduction of new mechanisms ensuring the regional integration in the energy market: transit, balancing, systems services provision, emergency supply, unforecastable flows management.

3) Energy tariffs setting methods and structure review and introduction of an improved seasonal and hourly structure.

4) Gas tariffs setting methods and structure review and establish new consumer groups and respective tariffs.

2. Long term activities until 2036

1) Extension of Iran Armenia Gas and electricity exchange agreement. Extension of this agreement will improve the sustainable development of the whole energy system, including the economic and technical indicators of the new 1000MW nuclear unit.

2) Ensure economically justified and sustainable development of renewable energy sources.

4. Infrastructures Development

1. Mid-term activities until 2025

1) Upgrade the transmission grid (EDG) substations energy facilities

a. 220 kW Haghtanak, 110 kW Charenstavan -3 and Vanadzor-1 substations reconstruction (2018) is planned with 40 million USD provided by the European Bank of Reconstruction and Development under the Electricity Supply Reliability Project (Additional Financing) In Armenia loan agreement.

b. 220 kW Agarak-2 and Shinuhair substations reconstruction (2019) is planned with around 23,4 million USD provided by the Asian Development Bank under the Electricity transmission grid reconstruction loan agreement.

c. Reconstruction of 220KW Ararat-2 and Yeghegnadzor substations (2019) is also planned under the above project with the support of the European Bank for Reconstruction and Development. The preliminary estimated cost of the project is around 30 million , out of which 20 million USD in a loan, 10 million USD in a grant .

d. The World bank plans to provide the Armenian Government with around 50 million USD loan to reconstruct 220 kW Yerevan TPP and Ashnak substations (201( under the Electricity transmission grid improvement loan project implemented by EBRD.

e. Starting from 2019 the EDG energy facilities upgrade activities he will cause an additional burden on 1 KWH energy tariffs sold to end consumers. The burden will total around 0,8 AMD/KWH in 2025.

2. Transmission grid (DEG cjsc) air transmission lines upgrade activities

a. The 230 km long air transmission lines Noraduz-Lichk- Vayk-Vorotan Hrazdan TPP to Shinuhayr 220 kW substation are reconstructed with 39 million USD provided by the European Bank for Reconstruction and Development under the Electricity Supply Reliability Project. These lines connect two main electricity generating stations of the energy system (Hrazdan TPP and Vorotan cascade). Using the forecasted savings generated from the agreements on reconstructions of the above-mentioned lines also 50 km long Lalvar and Noyemberyan air lines will be reconstructed. Having been in exploitation since 1962 these lines have been experiencing a continuous impact of chemicals emitted to the atmosphere, were corroded and cannot ensure reliable and uninterrupted electricity supply.

b. The transmission grid upgrade activities will generate an additional burden on 1 kWH electricity tariff sold to the end consumers . This burden will total around 0,2 AMD/KWH in 2025.

2) Ensuring regional integration process

a. Iran-Armenia 400 KW double circuit electricity transmission air line and Noravan substation are constructed with 142,4 million AMD with a support from the Export Development Bank of the Islamic Republic of Iran. The construction of the electricity transmission line and the substation will shift the capacity of the electricity exchange between the two countries’ energy systems from 300 MW to 1000-1200 MW. At the same time, this will increase the reliability of the energy systems parallel work and improve the energy security of Armenia.

b. With regard to regional cooperation the Armenia-Georgia 400 kW electricity transmission air line construction is also of importance. The purpose of the project is to merge the Armenian and Georgian energy systems closer to the Georgian border through a 500/400/220 kW high voltage permanent/direct current transformation stations (1050 MW final power ). The connection at the Georgian side will be from Marneuli through 500 kW line. The Armenian side connection will be from Hrazdan via 400 kW line (in the first stage via existing 220 kW Alaverdi line).

The electricity transmission line construction will substantially boost the mutually beneficial regional cooperation development in the region and will create conditions for organizing simultaneous work with the CIS countries energy systems.

The general project implementation was planned in three stages.

The first stage includes the construction of a high voltage direct current 350 MH transformation station and a 500 KW air line from the station to the Georgian border. Upon completion of the first stage, the transmission capacity will be up to 230 MW, depending on the preliminary load amount of the existing Alaverdi-Gardabani 220 kW line.

The second stage includes construction of the direct current converter 350 MW second module and the first chain of Hrazdan-Ayrum 400 kW double circuit air line.

The third stage includes construction of 350 MW third module of direct current converter and the second chain of Hrazdan-Ayrum 400 kW double chain air line, based on the market and regional cooperation demands.

Construction of a 400/220 kW substation is planned in Hrazdan area to connect Armenia- Georgia and Iran-Armenia 400 KW electricity transmission air lines.

The construction of the mentioned substation, of 350 MW third module of direct current converter , as well as of 400 KW double circuit electricity air transmission lines has been discussed with KfW Bank and a preliminary agreement was reached to include this in the first stage of Armenia-Georgia electricity transmission air line project. These volumes are planned to be completed by 2018.

The Bank's experts have estimated the project implementation cost , including the first stage implementation to be around 334 million USD.

On December 2014 the KfW bank, the Ministry of Finance of Armenia and EDG cjsc signed 99 million USD and 13,5 million USD loan and project agreements on «Caucasus Electricity Transmission Network I (Armenia-Georgia Transmission line/substations» project. A grant contribution of up to 13,2 million to the project is also planned under the European Commission's Neighborhood Investment Framework. Other than that, the Borrower and the European Investment Bank have signed a 13,2 million loan agreement.

The Embassy of the Federative Republic of Germany in Armenia released an announcement on December 19, 2014 on the German Government's intention to provide a 132 million USD concessional loan through the KfW Bank for «Caucasus Energy Union II (Armenia- Georgia electricity transmission line, high –voltage power plants) project. The Bank is also willing to fund the remaining amount necessary for the project implementation.

The regional integration process implementation will cause an additional burden on 1 KWH electricity tariff for end consumers starting from 2017. The maximum burden will be around 3,9 AMD/KWH in year 2020. As a result the current capacity of Armenia-Georgia electricity exchange will reach 700 MW from current 200 MW. The capacity of Armenia- Iran electricity exchange will reach 1000-1200 MH from today's 300 MW.

4) SCADA (Supervisory Control And Data Acquisition) Regulation Management Automated System Expansion Expansion of the SCADA Regulation Management Automated System is planned in 2017 with around 13,6 million USD provided by the Asian Development Bank under the Electricity Transmission Grid Reconstruction project.

Expansion of the SCADA system will cause an additional burden 1 KWH energy sale tariff to the end consumer starting from 2019. . The burden will total 0,06 AMD/KWH by 2025.

5) Electricity system management improvement

A reserve regulatory center will be established with 2,5 million USD provided by the European Bank for Reconstruction and Development, which will contribute to the electricity system management improvement. In particular, this is important in a circumstance of a breakdown at the primary dispatch center located in the center of Yerevan because of natural disasters, war or technical causes, and a control and continuous management of the electricity system should be ensured.

The reserve dispatch center will ensure an immediate restoration of control management in case of a such emergency. If the system activities and management are not restored, it can jeopardize the electricity system operations reliability, which can cause electricity supply failures.

6) Distribution center (ENA cjsc) upgrade activities

Per the Scientific research Institute of Energy Experts' opinion, given the depreciation degree of ENA cjsc production and technical resources, reconstruction of about 30% of substations and replacement of main assets ( 5000 capacity transformations with respective measuring and distribution equipment) is required. At least 40% of air and cable wires also need renovation. Old

(induction) meters also subject to replacement. Electricity count and control automated system replacement should be applied to all voltage levels. According to maximum estimates, it will require around 150 billion AMD investment. The mentioned activities will reduce the actual losses by 4% and to bring the technologically inevitable losses to the developed countries level. The distribution grid upgrade activities will cause an additional burden on 1 KW electricity tariff sold to the end consumer staring from 2016. The burden will total at about 2 AMD/KWH is 2025.

Thus, infrastructure development mid-term activity program will cause an additional burden on energy sales tariffs for end consumers starting from 2016. The maximum burden will be 5,5 AMD/KWH in 2020-2021.

2. Long term activities until 2036

1) Ayrum 350 MW direct current converter substation third module construction (in 2027) based on the market and regional cooperation demand. This will help to bring Armenia-Georgia exchange capacity to 1050 MW. Per preliminary estimates, the investment amount will be around 105,6 million USD.

2) construction of a 90 km long 400 KW air line connecting the new NPP 400 KW substation with Hrazdan 400 KW substation in 2027. Per preliminary estimates, the investment amount will be around 39,6 million USD.

3) High voltage energy facilities upgrade activities (reconstruction of 220 KW Marash, Zovuni, Shahumnay-2 and Lichk substations and replacement of AT-1-63000 kWA autotransformer at Alaverdi-2 substation. Per preliminary estimates, the investment amount will be around 40 million

USD.

4) Transmission grid upgrade activities( reconstruction of 220 kW Lori, 110 KW Shahumyan-1,2, Ejmiadzin and Tumanyan 1,2 electricity transmission air lines that are out of resources. Per preliminary estimates, the investment amount will be around 10-12 million USD.

5) Continue the replacement of the depreciated main assets of ENA at its own expenses (3000 capacity transformers with respective counting and distribution equipment and 20% of air and cable lines). Per preliminary estimates, the investment will require around 70 billion AMD and will reduce losses by 1% more. The infrastructure development long term activity program will cause an additional burden on 1 KWH electricity sales tariffs for end consumers starting from 2026. The maximum burden will be 1,4 AMD/KWH in 2035.

5. Electricity generation capacity development

1. The generating capacities construction in the mid-term and long-term include the following:

Hrazdan TPP 1-4 units will stop exploitation after 2019.

The project of 200 MW wind energy power plants construction approved by Clause 8 of the Appendix approved by the RoA government decree # 836-N of July 31, 2014 will probably require a tariff policy to attract private investments.

2. Mid-term activities (until 2025 inclusive)

1) Armenian NPP life extension until 2027 (with the loan (270 million USD) and grant (30 million USD) provided by the Russian Federation. At the same time the safety improvement activities implementation should continue.

2) Total 150 MW small HPPs construction by 2021, considering the specific investment growth and environmental compliance (private investments).

3) Average capacity HPPs (Loriberd 66 MW and Shnogh-70 MH) development and operation in 2021 (private investments), which will increase the annual production by around 500 million KWH.

4) 40 MW total capacity solar PV plants construction by 2021 with the World Bank SREP project funding.

5) New thermal energy facilities construction (400 MW in 2018 and 220 MW in 2021). The need for these capacities is caused by the commitments under Iran-Armenia gas-electricity exchange agreement and by the termination of Hrazdan TPP existing units operations. The needed capacity may be reduced by 400 MW is a stable and reliable competitive electricity imports from Georgia are ensured. This approach is economically more reasonable, since the new 220 an 400 MH CCGT units are underloaded after 2027 (after construction of the new NPP ). Prices on electricity exports from Georgia are displayed in the table below:

Season Import price, $/KWH Winter 0,070 Spring 0,045 Summer 0,059 Autumn 0,073 These prices were provided by the Georgian energy system commercial operator and include transportation costs.

An additional scenario was also discussed when instead of thermal CCGT 400 MW (in 2018 ) and 220 MW (in 2021) capacity energy facilities considered in the reference scenario the 234 MH CCGT construction

The launch is planned for 2018, the exploitation start of the new unit is planned for 2027.

3. New nuclear energy unit construction phases

1) Negotiations on funding with the Russian Federation and other potential investors completed; investors’ conference organized, if necessary;

2) Manager company selected;

3) Technical-economic justification developed;

4) Geology and hydrology surveys of the selected platform completed;

5) Environmental impact assessment completed

6) Public hearings organized,

7) Equipment suppliers tenders prepared and organized.

4. Long term activities (until 2036 inclusive)

1) New nuclear energy exploitation start in 2027. The plant’s testing and setup activities completed, pre-operation testing completed (2026-2027)

2) Armenian NPP operations termination in 2028-2036

3) Armenian-Iranian Meghri HPP construction agreement implemented. The plant is expected to be included in the Armenian energy system by 2023. The installed capacity of the plant will be 130 MW, the annual electricity production will be aroud 800 million KWH. The project review is discussed with the Iranian partners to reduce the capacity by 30 MW.

4) Additional incentive activities implemented for renewable energy development, if necessary.

6. Alternative scenarios discussion

1. Alternative scenarios are based on the following assumptions:

1) It is known that one of the preconditions of Russia’s membership in the International Trade Organization is the energy resources sale with same profitability both at the domestic and any foreign market. In case this requirement is met, the price of gas imported from Russia will follow the European gas prices. Given this circumstance, a number of scenarios were analyzed based taking into consideration the European prices.

2) Nuclear energy development with 670 MW CANDU Canadian reactors

3) Nuclear energy development with 610 MW ACP-600 Chinese reactors

4) Nuclear energy development with 360 MW SMR (small module reactor) reactors.

These reactors are no in the development and/or licensing phase in USA, Russia, Japan, South Korea. Per experts’ estimates, they will be available at the market after 2020.

5) Republic of Armenia fails to construct a new nuclear power plant and there is no nuclear unit after 2027;

6) Iran-Armenia interstate agreements implementation until 2026; agreement termination in 2027

7) Interstate Iran-Armenia agreement terminated in 2027; nuclear energy system developed with CANDU reactors;

8) Interstate Iran-Armenia agreement terminated in 2027; nuclear energy system developed with ACP-600 reactors;

9) Interstate Iran-Armenia agreement terminated in 2027; nuclear energy system developed with only 1000 MW nuclear energy unit;

10) The existing nuclear unit life extension project fails and the ANPP does not work starting from 2017

11) Importing opportunity for up to 2 billion KWH energy from Georgia

2. Different funding conditions for the reference scenario

1) All costs and prices in this document are before VAT. Economic calculations were made using the 2012 exchange rate. Given the international forecast, no growth of nuclear fuel prices was envisaged.

The alternative scenarios were envisaged based on a no state guarantee condition for nuclear and thermal units construction. Two funding options were considered:

a. Total investment amount capital attracted with 7,5%/year interest rate and new nuclear and thermal energy units investments return during the life or the project

(long-term funding : life of thermal units is 30 years, life of nuclear units is 60 years).

b. Total investment amount commercial capital attracted with 10%/year interest rate with a condition of the total amount payback in 15 years for thermal units and 20 years of the nuclear units.

2) The comparative analysis illustrates that the cost of electricity generated in at the 1000 MW capacity nuclear power plant from 91.1 $/KWH (option 1) to 126,7 $/ KWH option 2). The cost of the thermal units production increases from 114.84 $/MW (option 1) to 124,1 $/MWH (option 2) for 220 MW combined cycle steam-gas cycle facility, and from 110,9 $/MWH to 121,4 $/MWH (option 2) for 400 MW CCGT energy facilities. With the second option thermal and nuclear units production volume increases unevenly and they become economically equivalent. At the same time it should be considered that European emission fees may be applied in Armenia in the future (26,4$/T CO2), which will cause thermal plants production additional burden of 10,9$ MWH. Under these conditions the energy units become economically competitive.

3. European gas prices

The prices of gas imported from Russia following European prices scenario model is displayed in the Figure 3.

INSERT CHART- Figure 3. Electricty average wighted cost per investment types

Russian gas- long term funding – the reference scenario with nuclear and thermal plants construction with long term investment funding

European gas – long-term funding- development scenario with natural gas European prices, nuclear and thermal plants construction is funded by long-term investments.

Russian gas, commercial funding – the reference scenario with nuclear and thermal plants construction funding with “commercial «capital (Total investment amount commercial capital attracted with 10%/year interest rate with a condition of the total amount payback in 15 years for thermal units and 20 years of the nuclear units 10%/year interest rate)

European gas, commercial funding – development scenario with European prices (commercial capital attracted for nuclear and thermal plants construction).

The chart presents average weighted costs of electricity production for long-term and short term funding options and in case of Russian and European gas imports prices.

In case of the European prices the electricity cost drastically increases after 2018 and the different makes 26.4 USD/MWH. After the new nuclear unit operation in 2027 this differences decreases up to 7,9-9,2 USD/MWH. The thermal energy units funding option selection does not have an serious impact on the electricity cost before 2026. However, with involvement of commercial capital to fund the new nuclear unit the electricity cost sharply goes up by 19,8 USD/MWH in 2027.

4. Comparative analysis of nuclear and thermal productive capacities development

1) Two nuclear technologies (VVER-1000 and CANDU) and ACP-600 new VVER nuclear technology are available and at the market and can be applied in Armenia. In 2020 the market will offer Small Modular Reactor (SMR) designs. Armenia has an experience in using VVER technologies, but CANDU technology will require additional studies on technologies and equipment transportation.

2) A comparative analysis of the reference scenario and three alternative scenarios has been conducted to evaluate main risks and opportunities of nuclear and thermal capacities development.

The scenarios considered in the comparative analysis are:

a. capacities development with VVER-1000 nuclear unit

b. capacities development with CANDU nuclear unit

c. capacities development with ACP-600 nuclear unit

b. capacities development with thermal units only

3) The perspective development study has also analyzed SMR (Small module reactor) type units use , but in all considered scenarios inclusion of these units in the Armenian energy system has lower economic indicators that the application of other units, hence, its results are not reflected in this document.

4) Inclusion of nuclear units in these scenarios is allowed after 2027. All other renewable and alternative scenarios are included based on the reference scenario assumptions. The nuclear technology type selection is the main factor, so the table below represents the technical economic data of the nuclear units studied:

Indicator VVER-

CANDU 6 ACP-600 SMR

Investment, million $ 5377 2141 2440 2156 Efficiency ratio 0.451 0.438 0.451 0.45 Fixed costs , million $/year

72.20 50.77 42.85 32.78

Fresh fuel cost, $/MWH 6.90 2.92 6.90 7.76 Used fuel cost, $/MWH 1.77 5.35 1.77 1.03 Variable cost $/MWH 0.67 0.73 0.67 0.87 Total variable cost

$/MWH

2.44 6.07 2.44 1.90

Unit capacity, MW 1028 670 610 360 Specific (per unit) investment $/KW

5230 3196 4000.0 5988.42

Specific (per unit) fixed cost $/KW/year

70.24 75.78 70.24 91.04

Maximum annual production GWH/year

8105 5282 4809 2,838

Duration of construction, 6 6 6 4 year Note:

* Due to lack of precise economic indicators for ACP-600 energy unit, all costs of nit have been assessed

**Plant construction one-time cost

*** Operations phase-out costs are included in fixed costs

4) The comparative analysis was conducted exclusively for commercial funding terms and Iran Armenia exchange agreement extension or termination terms.

a. In the reference scenario VVER-1000 nuclear unit is not economically competitive both under conditions Iran- Armenia exchange agreement extension and termination in 2027. In case only this unit is considered , new CCGT units construction becomes economically reasonable. In fact, this scenario becomes a thermal scenario. In case there are no nuclear units and the exchange agreement is terminated, the following thermal capacities will be in effect: 400 MW in 2018 and 220 MW in 2012. In case the agreement is extended in 2027, there is a need to construct a new 220 MW thermal unit in 2027.

With CANDU 670 MW nuclear reactor the nuclear energy development is the economically beneficial way for the country. Moreover, if the exchange agreement is continued after 2027, construction of two nuclear units will be reasonable in 2027 and 2030. Regardless of the agreement extension or termination the new thermal capacities remains the same: 400 MW in 2018 and 220 MW in 2012.

c. the Chinese ACP-600 nuclear energy unit (610 MW) also offers economically reasonable conditions for nuclear development. Regardless of the exchange agreement status after 2027, construction of an ACP-600 energy it is economically justified. In this scenario new thermal capacities construction repeats the previous scenario. Status.

5) Unlike the nuclear scenario, the thermal scenario has a problem with the Northern gas pipeline capacity. Starting from 2027 in winter months the daily volume of the imported gas will exceed the maximum capacity (12 million m3/day) by 3 million m3/day. Given Armenia's energy security and reliable electricity supply requirements, there will be a need to expand the underground gas storages brining the to 400 million m3, which will require around 80 Million USD investment, including the compression plant investments. In this case the country will have at least one month's winter reserves to ensure reliable gas supply.