Republic of Armenia: Energy Sector Assessment, Strategy and Road Map (Financed by ADB’S Technical Assistance Special Fund)

Technical Assistance Consultant’s Report (Final)

Project Number: 44183 March 2013

Republic of Armenia: Energy Sector Assessment, Strategy and Road Map (Financed by ADB’s Technical Assistance Special Fund)

Prepared by Denzel Hankinson DH Infrastructure, LLC

Massachusetts, USA

For the Government of Armenia

This consultant’s report does not necessarily reflect the views of ADB or the Government concerned, and ADB and the Government cannot be held liable for its contents. (For project preparatory technical assistance: All the views expressed herein may not be incorporated into the proposed project’s design.

CURRENCY EQUIVALENTS (as of 31 March 2013)

Currency Unit – Armenian dram (AMD) AMD1.00 = $0.0023 $1.00 = AMD419.00

ABBREVIATIONS ANPP – Armenia nuclear power plant CCGT – combined cycle gas turbine COBP – country operations business plan CPS – country partnership strategy EBRD – European Bank for Reconstruction and Development EE – energy efficiency ENA – electricity networks of Armenia GEF – global environmental facility GOA – Government of Armenia GPOBA – global partnership for output-based aid GDP – gross domestic product GWh – gigawatt hour HPP – hydro power plant HVEN – high voltage electrical networks IFC – International Finance Corporation JBIC – Japanese Bank for International Cooperation KfW – kreditanstalt Für Wiederaufbau (German Development Bank) KV – kilovolt kwh – kilowatt hour MW – megawatt MENR – ministry of energy and natural resources MTEF – medium-term expenditure framework NPP – nuclear power plant NSS – national security strategy OHL – overhead line O&M – operations and maintenance PFBP – poverty family benefits program PPA – power purchase agreement PSOD – private sector operations department PSRC – public services regulatory commission PV – photovoltaics RE – renewable energy R2E2 – renewable resources and energy efficiency fund SDP – sustainable development program SME – small and medium enterprises SREP – scaling-up renewable energy program in low income countries TPP – thermal power plant

NOTES

(i) The fiscal year (FY) of the Government of Armenia and its agencies ends on 31 December. FY before a calendar year denotes the year in which the fiscal year ends, e.g., FY2012 ends on 31 December 2012.

(ii) In this report, "$" refers to US dollars.

Energy Sector Assessment, Strategy and Road Map: Armenia

Final Report

March 2013

Table of Contents 1 Introduction 7 2 Sector Assessment 7 2.1 Socioeconomic Context 7 2.2 Energy Sector Context 8 2.3 Subsector Assessment 11 2.4 Core Sector Problems 16 3 Sector Strategy and Road Map 29 3.1 Government’s Strategy 30 3.2 Development Partner Support to Energy Sector 32 3.3 ADB Support 35 4 Energy Sector Road Map and Results Framework 41

Tables Table 2.1: Efficiency and Cost of Old and New Gas-Fired TPPs in Armenia 13 Table 3.1: Specific Energy Sector Measures Proposed in GoA Strategies 31 Table 3.2: Ministry of Energy’s Medium-Term Investment Plan, 2013- 2015 32 Table 3.3: Development Partner Activity in the Armenian Energy Sector 34

Figures Figure 2.1: Composition of available capacity and production, 2011 11 Figure 2.2: Net Generation and Consumption, 2006-2011 12 Figure 2.3: Armenia Energy Sector Problem Tree Diagram 18 Figure 2.4: Actual versus Cost-Recovery Residential Tariffs 21 Figure 2.5: Country Comparison of Feed-in Tariffs 29 Figure 3.1: Linking Sector Support Areas with GoA’s and ADB’s Strategy 36

Executive Summary Sector Performance, Problems and Opportunities A. Sector Overview 1. Armenia’s energy sector has seen tremendous change in the two decades since Independence. The sector has gone from a state of near complete collapse in the mid-1990s to one that is largely characterized by affordable, reliable electricity and gas service. The availability of electricity service has increased from just a few hours a day to 24 hours a day, network losses have been reduced from 40 percent to 15 percent, and sector companies have emerged from heavy dependence on state funding to commercial viability. The share of natural gas in the heating fuel mix has increased from 10 percent to more than 70 percent, displacing firewood, electricity and other, dirtier fuels, thanks to the rehabilitation and extension of the gas distribution network. 2. Performance in the energy sector has improved dramatically but a fundamental energy security problem remains: Armenia has no proven oil or natural gas reserves and imports most of its fossil fuel resources from Russia. The energy crisis of the mid-1990s highlighted this vulnerability, when an economic blockade by Turkey and Azerbaijan—imposed after the start of the 1992 Nagorno-Karabakh conflict—cut Armenia off from fuel supplies, and a natural gas pipeline from Georgia suffered repeated acts of sabotage. Armenia now has natural gas supply lines from Iran and Georgia, but now also depends more heavily on natural gas for heating and electricity generation than it did in the 1990s. 3. Because of the lack of domestic resources Armenia is highly dependent on energy imports. Imports account for roughly 60 percent of total primary energy supply and natural gas imports from Russia account for 80 percent of total energy imports.1 Hydropower, and more recently developed wind and biogas generation facilities are Armenia’s only existing domestic energy resources. These domestic resources produce roughly 35 percent of Armenia’s electricity. Natural gas-fired thermal power plants (TPPs) and the Metsamor nuclear power plant (NPP) produce 25 and 40 percent of Armenia’s electricity, respectively.2 4. Reliable and affordable energy supply is critical for economic growth in the post-financial crisis period. The Government has set a target of 5-7 percent GDP growth, which is expected to result in increased demand for energy resources.3 Key areas of economic growth going forward include the industrial, and the commercial and retail services sectors. These sectors accounted for 45 percent of GDP in 2011 and have been the largest contributors to GDP growth in the past two years.4 These

1 Ersado, Lire. “Poverty and Distributional Impact of Gas Price Hike in Armenia.” Policy Research Working Paper 6150. World Bank. July 2012. 2 Uranium for Armenia’s nuclear power plant is also imported, from Russia. 3 Republic of Armenia. “Government Program.” Yerevan, Armenia. June 2012. 4 Ministry of Economy. “Macroeconomic Indicators: January-July 2012.xlsx”

sectors are energy-intensive, accounting for 81 percent of non-residential electricity consumption and 51 percent of total domestic consumption in Armenia in 2011.5 5. The energy sector is also important to supporting the Government’s poverty reduction agenda. Roughly 36 percent of the population was considered poor in 2010 up from 28 percent in 2008. Energy bills constitute a significant component of household expenditure and expected to continue to rise. The import price of natural gas rose 64 percent between 2008 and 2010 leading to higher heating bills for residential customers and higher electricity tariffs.6 The import price for natural gas increased again in 2012 and will reach $320 per thousand cubic meters in 2013. B. Key Sector Problems 6. Energy Security. Armenia’s energy security problem is, to some extent, a function of geography, geopolitics and history, but is also a function of more immediate, and more easily solved financial, technical and regulatory problems. Armenia will face a major supply-demand gap once the Armenian Nuclear Power Plant (ANPP) is retired. The country’s heavy reliance on imported natural gas to generate much of its power makes the sector susceptible to fuel supply interruptions. Inefficient generation, transmission and distribution infrastructure means that the power sector must use more imported fuel to provide the same level of electricity service than it would if this infrastructure were more efficient. Limited regional power trade and under-exploited renewable energy resources mean that Armenia currently has few options for diversifying its energy supply mix away from imported fuels. Armenia needs a strategic plan for replacing ANPP which addresses these energy security concerns and also considers the challenges of financing large generation investments. 7. Inefficient Use of Energy Resources. Old, inefficient electricity generation infrastructure exacerbates Armenia’s energy security problem. Available capacity of domestic hydropower resources is lower than their installed capacities and old thermal power plants make inefficient use of valuable imported fuels. Large hydropower plants (HPPs), in particular, require significant rehabilitation, and as a consequence are operating well below their design capacities. The Argel HPP at Sevan-Hrazdan operates 20 percent below its installed capacity because critical equipment requires rehabilitation, which is expected to cost US$40-60 million. Primary equipment at two of the main gas-fired plants, Hrazdan TPP and Yerevan TPP, has worked beyond the 200,000 work hour design life and does not meet international technical, economic and environmental performance standards.7 The fuel efficiency of Hrazdan TPP is 35 percent compared to 57 percent for a new, efficient TPP. This plant’s low efficiency makes its cost of generation higher than any other plant on the system. The 385 MW ANPP is also beyond its 30 year design life and scheduled for decommissioning in 2021.

5 PSRC data 6 http://www.state.gov/r/pa/ei/bgn/5275.htm 7 Ministry of Energy. Energy Sector Development Strategy in the Context of Economic Development.

8. Old transmission and distribution infrastructure also contributes to energy security problems. Transmission assets are, on average, more than 45 years old and require rehabilitation.8 The state-owned High Voltage Electricity Network (HVEN) has estimated that roughly 33 percent, or 520 km of the 220 kV network are in very poor condition and require urgent rehabilitation at a cost of US$ 80-100 million. Distribution system assets are also in need of rehabilitation. Investments are needed to accommodate load growth, deploy SCADA and electronic meters, and rehabilitate low-voltage equipment. Roughly 75 percent of customers do not have the electronic meters, which are needed to reduce commercial losses and allow ENA to monitor individual end-user demand. Moreover, 30 percent of 6-10 kV equipment and 25 percent of 35 kV substations require rehabilitation. 9. Generation, transmission and distribution infrastructure has deteriorated because of insufficient funding. Government has not rehabilitated any state-owned generation assets in 15 years because it is constrained by concerns about energy affordability and has limited ability to borrow. Private companies in the sector are also struggling to invest as much as needed. End-user tariffs have not changed since 2009, despite increases in the price of gas, and some private companies report that the Public Services Regulatory Commission (PSRC) does not allow recovery of their full investment costs, or does not recognize the full costs of their financing. 10. Under-Exploited Renewable Energy Resources. Armenia diversifies its electricity and fuel supplies by exploiting domestic renewable resources. Significant renewable energy potential exists, but the Government has struggled to attract private investors for non-hydro renewable projects. It is estimated that Armenia has more than 1,000 MW of technically viable capacity from solar photovoltaic (PV), 300- 500 MW from wind, 250-350 MW from unexploited small HPPs and 25 MW from geothermal.9 There is also potential for roughly 100,000 tons per year of biofuel production. Renewable energy is underdeveloped because of a lack of information on the technical, economic and financial viability of specific sites, and because—in the opinions of some in the sector—the feed-in tariffs are too low for wind and small-hydro power plants (HPPs). 11. The development of renewable energy generation and the replacement of the nuclear plant are two key objectives for the Government in its effort to maintain energy security. However, planned renewable energy projects and a new nuclear plant will likely provide more capacity than is needed to serve domestic demand, and building both will adversely impact end-user tariffs. The Government needs to develop a plan for replacing the ANPP that identifies how the Government will finance that plant and export any excess capacity. This will give investors clearer signals on the financial viability of renewable energy projects. 12. Limited regional power trade. There are also unexploited opportunities for Armenia to increase electricity trade with its neighbors. Armenia currently trades electricity with Iran in exchange for natural gas. Trade with Georgia, however, is

8 World Bank. “Charged Decisions: Difficult Choices in Armenia’s Energy Sector.” October 2011. 9 According to Armenia’s Renewable Energy Roadmap developed by the Renewable Energy and Energy Efficiency (R2E2) Fund.

limited because of an asynchronous connection between the two systems. In the short-term, increased trade with Georgia would allow Armenia to export its excess hydropower generation during spring and summer to Turkey via Georgia. In the long- term, if Armenia builds a new nuclear plant, additional transmission capacity will be needed to export electricity from the plant because the planned nuclear plant will be significantly larger than needed for domestic demand. If Armenia does not build a new nuclear plant, additional transmission interconnection capacity could help Armenia meet its supply gap with relatively cheap hydropower imports from Georgia. 13. Armenia’s asynchronous connection with Georgia limits trade between the two countries. Armenia’s system cannot be synchronously connected to both Georgia and Iran because it would compromise grid stability in the IPS/UPS and Iran- Turkmenistan synchronous zones. The Government is negotiating with the Government of Georgia and the Kreditanstalt für Wiederaufbau (KfW) over terms for a new 400 or 500 kV interconnection between the countries. The new line would allow for increased trade between the two countries and increased transit of electricity from Georgia to Iran via Armenia. Government’s Sector Strategy 14. The Government of Armenia’s (GoA) Government Program, adopted in June 2012, identifies the following as priorities in the energy sector: i) increasing the level of energy security, ii) developing renewable energy generation, by increasing the efficiency of existing hydropower plants and developing new sources of renewable energy generation, iii) improving system stability in order to safeguard consumers from voltage fluctuations, iv) developing regional trade by completing 400 kV interconnections with Iran and Georgia, and v) continuing work to build a new nuclear power plant. 15. The GoA plans to fund some investments on its own, or borrow to finance them, but is constrained by a requirement that public debt not rise above 50 percent of GDP. The Ministry of Energy and Natural Resources’ (MENR’s) medium-term investment plan for 2013-2015 highlights four priority investment projects, costing roughly US$94 million over three years, financing for which has already been secured from the state budget or loans from development partners. The projects are: Decontamination and disposal of radioactive waste (state funded); reconstruction of the Gyumri-2 substation (KfW-financed); rehabilitation of the Vorotan hydropower plants (KfW-financed); Rehabilitation of 220 kV overhead lines and the Hrazdan thermal power plant substation (World Bank-financed).10 Public debt currently stands at roughly 43 percent of GDP, meaning GoA will need to carefully prioritize its energy sector investments as the public debt level approaches the debt ceiling. 16. Government has long sought to increase private sector participation as a way of financing additional investment in the sector. The distribution company, Electricity Networks of Armenia (ENA) was privatized in 2002. The feed-in tariff is intended to—and has succeeded—in attracting private investment in renewable

10 A fifth project, included in the plan is focused on investment in energy efficiency in public buildings. This investment will be grant-funded by the World Bank.

energy, small HPPs in particular. The Sevan-Hrazdan Cascade was privatized in 2003, and most recently, in 2012, Armrusgasprom completed construction of the Hrazdan 5 Thermal Power Plant. 17. Some regulatory changes are necessary if Armenia is to continue to attract private investment. The PSRC has not changed end-user tariffs since 2009, but has raised tariffs for gas-fired generators, as gas prices have increased. As a result, the distribution company ENA has expressed concerns that it may not be able to continue to finance investments in rehabilitation of its network. As mentioned above, feed-in tariffs may also be too low. The feed-in tariff for wind has not succeeded in attracting any investment, and there are some signs that the feed-in tariffs for small HPPs are not keeping pace with costs.11 18. There is therefore some complementarity, and some tension between the GoA's energy sector objectives and its higher level strategic objectives of economic growth, poverty reduction and national security.12 Many of the GoA’s sector priorities are complementary to economic growth and poverty reduction: Better electricity system reliability, higher efficiency of generation and transmission infrastructure, and use of cost-effective renewables. However, higher tariffs required to finance new generation investments will put pressure on low-income customers, and—if the increases are substantial—could risk slowing economic growth and dulling export competitiveness. ADB Sector Experience and Assistance Program 19. ADB has partnered with the Government of Armenia since 2005, but has had no active cooperation in the energy sector to date. ADB’s most recent country operational business plan (COBP) for 2012-2013 focuses on urban development, regional cooperation, and private sector development. The energy sector is included as a priority focus area in the upcoming COBP for 2013-2014. The Government has shown continued interest in receiving ADB assistance in the energy sector under these focus areas. This assistance aligns with ADB’s Strategy 2020, which has identified infrastructure development as a core area of future operation in the energy sector, with emphasis on (i) expanding the supply of clean energy; (ii) promoting energy efficiency through supply side and demand side measures; and (iii) removing policy, institutional, and regulatory barriers to efficient energy use. In particular, ADB’s Strategy 2020 states that ADB will support developing member countries to move their economies onto low-carbon growth paths by improving energy efficiency, expanding the use of clean energy sources, and reducing fugitive greenhouse gas emission. ADB’s Energy Policy 2009 prioritized promoting energy efficiency and renewable energy as one of the three pillars of ADB assistance in energy sector. 20. The GoA, in consultation with ADB, has identified the energy sector as a key pillar of ADB’s upcoming Country Partnership Strategy (CPS) for Armenia. ADB

11 Some project developers have tried to cut costs by utilizing cheap, domestically available materials that do not meet design standards. As a result, many of the existing small HPPs have not reached the operational efficiency projected in project design documents and many will likely not reach the expected design life for typical small HPPs without major rehabilitation. 12 As stated in the GoA’s Sustainable Development Program (SDP) and National Security Strategy (NSS).

will support infrastructure projects in Armenia that address critical gaps and constraints in the power system and that rehabilitate and modernize the system. Priority areas for partnership are as follows: (i) rehabilitating aging power transmission infrastructure; (ii) facilitating regional power trade and cooperation; (iii) promoting the development of renewable energy technologies such as hydropower, wind power, geothermal, solar, and others through private sector or public-private partnership structures; (iv) collaborating with other development partners; and (v) supporting policy and institutional reforms and capacity development. Public sector interventions will be closely coordinated with the private sector interventions supported by ADB’s private sector operations department. 21. MENR and HVEN identified several areas for ADB support for public investment to improve the efficiency of transmission infrastructure. Specific investments included: i) partial rehabilitation of 8 substations, ii) rehabilitation of roughly 300 km of 220 kV lines in urgent need of repair, iii) full rehabilitation of substations at Yerevan TPP and the NPP, and iv) expansion of the SCADA system to cover 100 percent of the network. ADB will want to work with MENR and the Ministry of Finance to prioritize these investments given the GoA’s limited ability to borrow for public projects. 22. ADB’s Private Sector Operations Department (PSOD), in cooperation with EBRD, is already considering a loan to the private owner of the Sevan-Hrazdan Cascade for rehabilitation. EBRD has an established presence in the energy sector and is the only development partner to have made a major loan to one of the large private companies in the sector. EBRD is, therefore, a good partner for ADB’s first private sector project in the energy sector. 23. Another area of possible ADB support could include partnering with KfW to provide financing for the new interconnection with Georgia. KfW has approached ADB about providing additional financing if the Government decides to move forward with the project based on the results of the feasibility study. KfW has budgeted roughly €20 million for the project; however, the total cost with the HVDC substation is expected to reach US$ 150-200 million. 24. Finally, ADB could support the development of renewable energy generation. ADB is working closely with the World Bank, IFC, and EBRD to develop an investment plan for renewable energy in Armenia under the Scaling-up Renewable Energy Program in Low Income Countries (SREP). The Investment Plan is expected to be a launching point for further discussion with Government regarding next steps for realizing Armenia’s unexploited renewable energy potential. ADB can use the results of the investment plan to i) identify opportunities for technical assistance to remove some of the barriers to investments in renewables, ii) identify opportunities for finance projects or provide credit support.

1 Introduction 1. The Asian Development Bank (ADB) has provided technical assistance and hired an international consulting firm to develop an Energy Sector Assessment, Strategy and Road Map for Armenia. The objective of this assignment is to prepare an energy sector assessment, strategies, and roadmaps report (ASR), which harmonizes ADB's support program and project planning in Armenia with the Government’s and ADB’s energy strategy. The energy sector ASR will inform project planning and preparation to prioritize investment needs in developing ADB's Country Partnership Strategy (CPS) for Armenia in 2013 – 2017. The Sector Assessment, Strategy and Road Map will: i) present a comprehensive review of sector performance, ii) identify key issues and investment needs facing the energy sector, iii) summarize the Government of Armenia (GoA)’s strategy for the sector, and iv) recommend opportunities for ADB cooperation and support to the sector, in light of donor’s experience. 2. This report presents the Draft Energy Sector Assessment, Strategy and Road Map for Armenia. According to the Terms of Reference (ToR), the Scope of Work for this report includes: (i) analyzing sector performance, problems and opportunities, (ii) analyzing government sector development policy, strategies, and investment plans, (iii) analyzing development partner’s sector experience and assistance programs, and iv) developing a problem tree diagram and a sector results framework. 2 Sector Assessment 3. The energy crisis Armenia went through in the mid-1990s and, more recently, the global financial crisis help to frame the key challenges facing the sector and the strategic role the energy sector has in the Armenian economy. The following subsections provide: i) a description of the socioeconomic context in Armenia and the role the energy sector has in helping the Government of Armenia (GoA) achieve its larger strategic objectives, ii) an overview of the energy sector and the path of reforms that have led to the current sector structure and regulatory framework, iii) an assessment of energy subsectors including electricity generation, transmission, and distribution, energy efficiency, renewable energy, and natural gas, and, iv) an assessment of the core problems facing the sector. 2.1 Socioeconomic Context 4. Armenia experienced strong economic growth over the past decade, but was severely affected by the global financial crisis. Real GDP grew, on average, 12.2 percent from 2002 to 2008, but declined 14.1 percent in 2009. Armenia has experienced moderate growth since 2009 (2.1 percent and 4.6 percent in 2010 and 2011, respectively), but weaker global economic conditions, particularly in the Euro zone, are expected to slow growth in 2012.13 5. The main drivers of economic growth in Armenia include: construction, retail services, mining, manufacturing and agriculture. These sectors were some of

13 World Bank. World Development Indicators.

the hardest hit by the financial crisis, with construction and agriculture remaining depressed in the post-crisis period. Poverty levels also increased as a result of the crisis, with the percentage of the population living below the poverty line increasing from 27.6 percent in 2008 to 35.8 percent in 2010.14 6. The GoA’s primary objectives, especially in the aftermath of the financial crisis, are to support economic growth and poverty reduction, including eliminating extreme poverty.15 The GoA has embarked on a “second generation” of reforms aimed at continuing efforts to liberalize the economy. Additionally, the GoA embarked on an aggressive anti-crisis program aimed at maintaining financial and external stability, curbing inflation, and ensuring social support to protect vulnerable portions of the population from the impact of the crisis.16 7. Reliable energy supply is critical for economic growth in the post-financial crisis period. The GoA has set the ambitious task of achieving 5-7 percent GDP growth, which is expected to result in increased demand for energy resources.17 Key areas of economic growth going forward include industry and commercial and retail services, which accounted for 45 percent of GDP in 2011 and have been the two largest contributors to GDP growth in the past two years.18 These sectors rely heavily on the energy sector, accounting for 81 percent of non-residential electricity consumption and 51 percent of total domestic consumption in Armenia in 2011.19 8. The energy sector is also important to supporting the GoA’s poverty reduction agenda. The import price of natural gas rose 64 percent between 2008 and 2010 leading to higher heating bills for residential customers and higher electricity tariffs. Maintaining affordability of energy prices is a key concern for the GoA as the cost of imported natural gas is expected to increase further. The GoA has placed high priority on increasing use of domestic, renewable resources and improving energy efficiency, particularly of electricity generating facilities, as part of its poverty reduction strategy outlined in the Sustainable Development Program (2008). 2.2 Energy Sector Context 9. Armenia has no proven oil or natural gas reserves and imports most of its fossil fuel resources from Russia. Armenia imports oil from Russia, which is transported across the Black Sea to Georgia and then transported to Armenia via rail car. Armenia imports gas from Russia via a pipeline through Georgia and has begun importing gas from Iran through a new pipeline completed in 2008. Armenia also imports uranium from Russia to fuel the Metsamor nuclear plant. Imports account for roughly 60 percent of total primary energy supply and natural gas imports from Russia account for 80 percent total energy imports.20 This heavy dependence on

14 Social snapshot and Poverty in Armenia, 2010: http://www.armstat.am/file/article/poverty_2011e_2.pdf 15 Sustainable Development Program. 2008. 16 ADB. “Development Effectiveness Brief: Armenia” 17 Republic of Armenia. “Government Program.” Yerevan, Armenia. June 2012. 18 Ministry of Economy. Macroeconomic Indicators. 19 PSRC. Main Characteristics Indicators. 20 Ersado, Lire. “Poverty and Distributional Impact of Gas Price Hike in Armenia.” Policy Research Working Paper 6150. World Bank. July 2012.

imported fuels makes Armenia vulnerable to energy price shocks and supply disruptions. 10. Hydropower and recently developed wind and biogas generation facilities are Armenia’s only existing domestic energy resources. There are six known coal deposits, with estimated coal reserves of 200-250 tons, but no coal production. These domestic resources produce roughly 35 percent of Armenia’s electricity. Natural gas-fired thermal power plants (TPPs) and the Metsamor nuclear power plant (NPP) produce 25 and 40 percent of Armenia’s electricity, respectively. 11. Armenia relies on electricity and gas to meet the majority of its consumption needs. The industrial, residential and transport sectors make up roughly 81 percent of final energy consumption in Armenia.21 Industry relies on a combination of electricity and gas to meet its production needs. Residential households rely on a mix of electricity and gas for heating, cooking and hot water and electricity for lighting and other household appliance. The transport sector relies on oil and gas with 75 percent of the automobile and truck fleet using compressed natural gas (CNG). 12. Armenia’s vulnerability to energy supply disruptions became apparent in the mid-1990s. Between 1992 and 1995, the country experienced a severe energy crisis. An economic blockade by Azerbaijan and Turkey began in 1992 with the start of the Nagorno-Karabakh conflict, which closed off gas imports from Azerbaijan. A new gas pipeline through Georgia, completed in 1993, experienced frequent supply disruptions because of sabotage attacks to the pipeline in Georgia. The nuclear power plant was not available because an earthquake in 1988 forced the plant to shut down. As a result, Armenia was forced to rely almost entirely on its hydropower resources for electricity production. During this period, customers had as little as two hours of electricity supply per day during the winter and system infrastructure suffered from unpredictable outages. 13. The financial sustainability of the sector suffered greatly during the energy crisis. Fiscal and quasi-fiscal subsidies to the sector reached as high as 11 percent of GDP by 1995. Key contributors to the poor financial situation of the sector included: collections as low as 50 percent, commercial losses as high as 25 percent of electricity produced, and below cost-recovery tariffs.22 14. Restart of the second unit of the NPP in 1995 helped bring an end to the energy crisis and restore 24-hour service. Following the end of the crisis, the GoA embarked on a series of electricity sector reforms to improve energy security and financial sustainability in the sector. These reforms have brought the country out of a period of energy crisis in the mid-1990s into a period of relative stability. Key reforms undertaken included: i) unbundling of electricity generation, transmission and distribution, ii) privatization of electricity distribution and some electricity generating plants, iii) establishment of an independent regulator, and iv) meter installation for all end-users with protection against meter tampering. As a result of

21 International Energy Agency. Energy Statistics, 2007 22 Sargsyan, G., A. Balabanyan and D. Hankinson. “From Crisis to Stability in the Armenian Power Sector: Lessons Learned from Armenia’s Energy Reform Experience.” World Bank. Washington, DC. 2006.

these reforms, collections increased to 100 percent, commercial losses have been virtually eliminated, and tariffs have approached cost-recovery levels. 15. The electricity sector consists of nine publicly and privately-owned generation companies, one state-owned transmission company, one privately- owned distribution company, a state-owned system operator and a state-owned settlement center. The gas sector remains vertically integrated. ArmRusGasprom, the gas company jointly owned by the GoA and Russia’s Gasprom, imports gas from Russia and owns and operates the gas distribution network in Armenia. 16. The Ministry of Energy and Natural Resources (MENR), the Ministry of Finance, and the Public Services Regulatory Commission (PSRC) are the key legal, regulatory, policy and investment decision-making entities in energy sector. The MENR is responsible for developing primary legislation and main policy documents guiding energy sector activities, including system planning and investment planning for state-owned entities. The Ministry of Finance approves allocation of financing for public and publicly-guaranteed energy sector investments recommended by the MENR. The PSRC allows for recovery of investment costs through the tariff. Key laws guiding policy in the energy sector include: the Law on Energy passed in 2001 and the Law on Energy Savings and Renewable Energy passed in 2004. 17. Armenia’s market framework is based on the “single buyer model” with regulated tariffs for generation, transmission, and distribution. This framework functions well given the size of the system and small number of market participants. Under this market framework, the Electricity Networks of Armenia (ENA) acts as the single buyer of electricity through contracts with generating companies at prices regulated by the PRSC. The Settlement Center monitors energy flows and ensures timely payment delivery between all sector entities. The System Operator dispatches generators taking into account the economic dispatch order of plants as well as plants’ technical operational constraints. 18. The GoA, with strong support from the donor community, has operated successfully within this policy and regulatory framework to meet sector investment needs. Recent public and private investments in two new gas-fired TPPs has improved the efficiency of thermal generation. A new gas pipeline with Iran increases fuel supply security. Additionally, donors have actively provided direction and support as the GoA has updated its policy over the years to better align with the evolving strategic objectives of both the country and the sector. 19. Despite Armenia’s relative success in achieving sector reform and making needed investments in a timely manner, serious challenges remain which—left unaddressed—could reduce system reliability and threaten energy security. Armenia’s transmission network requires significant rehabilitation to maintain the level of reliability to which customers have grown accustomed. Rehabilitation of both large hydropower plants, which have suffered from years of under- maintenance and lack of investment, is increasingly important to ensure availability of Armenia’s cheapest and most secure energy resources. Maintaining energy security remains an ongoing challenge given Armenia’s limited domestic resources. The remaining subsections provide a subsector assessment and a more in-depth review of core problems facing the energy sector in Armenia.

2.3 Subsector Assessment This subsector assessment focuses on electricity and gas – Armenia’s two main sources of primary energy, with separate assessment of electricity generation, transmission, and distribution. Energy efficiency and renewable energy are also analyzed as separate subsectors because of the importance placed on these subsectors in the Government’s efforts to improve energy security. 2.3.1 Generation 20. Armenia’s electricity system has 3,914 MW of installed capacity, of which only 73 percent or 2,845 MW is currently operational. Electricity is produced by three generation sources: nuclear (34 percent), thermal (32 percent), and hydropower (34 percent). Notably, the share of thermal and hydropower plants in the capacity and production mix has increased in recent years because new plants have been built and Armenia has experienced good hydrological conditions over the past several years. 21. The NPP provides baseload capacity. Other HPPs, including the Vorotan Cascade and several HPPs in the Sevan-Hrazdan Cascade, provide daily load regulation, while TPPs operate to meet winter peak and to serve baseload for several months in autumn when the NPP goes offline for maintenance. Figure 2.1 shows the composition of available capacity and production in 2011. Figure 2.1: Composition of available capacity and production, 2011

22. Demand grew steadily over the past decade, but dropped in 2008 as a result of the global financial crisis. Electricity consumption in Armenia grew 4.5 percent annually from 2004–2008, but consumption fell 7.4 percent in 2009 as a result of the financial crisis. Consumption has since increased, growing 2.9 percent and 8 percent in 2010 and 2011, respectively.23 Peak demand has stayed relatively stable, fluctuating between 1150 MW and 1250 MW since 2003. The increase in consumption over the past decade despite lack of peak demand growth likely results from the fact that summer consumption has increased as a result of increased use of air-conditioning equipment. Figure 2.2 shows Armenia’s electricity balance including

23 PSRC. Main Characteristics Indicators.

net generation, consumption, exports, imports and transmission and distribution losses. Figure 2.2: Net Generation and Consumption, 2006-2011

Source: Public Services Regulatory Commission

23. Electricity demand is expected to grow 1.3 to 3.8 percent annually over the next ten years depending on assumptions about GDP growth. Under these growth assumptions, peak demand will increase by 170 to 543 MW and consumption will increase by 320 to 1681 GWh. Armenia currently has sufficient capacity to meet projected demand growth and maintain a significant reserve margin, but will need new baseload capacity to replace the NPP when it is retired in 2021. 24. The GoA has taken steps to develop new efficient and cost-effective generation. A new 240 MW combined cycle gas turbine (CCGT) at Yerevan TPP, constructed with a US$ 247 million loan from the Japanese Bank for International Cooperation (JBIC), came online in 2010. Additionally, ArmRusGasprom recently completed construction of the 440 MW Hrazdan 5 thermal power plant. The plant has been undergoing testing since late 2011 and is expected to be fully operational in late 2012. These plants will help to reduce system costs going forward by replacing generation from older, inefficient TPPs. As Table 2.1 shows, the generation tariff for the new TPPs is 20 to 35 AMD cheaper than the tariff for the old Hrazdan TPP because of the improved efficiency of the plants.

Table 2.1: Efficiency and Cost of Old and New Gas-Fired TPPs in Armenia

Generation Tariff Heat Rate Thermal Efficiency (AMD/kWh) (Btu/kWh) (%) Hrazdan TPP 41.22 10,384 33% Hrazdan 5 21.65 8,333 41% Yerevan CCGT 5.328 6,390 53%

25. Additionally, the GoA has negotiated electricity trade agreements with Iran and Georgia that exploit Armenia’s competitive advantage and improve energy security and affordability. Armenia negotiated a gas-electricity swap arrangement with Iran under which it exports 3 kWh of electricity in exchange for 1 m3 of gas from Iran. The swap arrangement improves fuel supply security by providing an important second source of gas supply. It also maintains affordability by helping to fully utilize new, efficient gas plants and taking advantage of seasonal differences in demand and availability of hydropower generation between Armenia and Iran.24 Since 2010, Armenia has also imported cheap hydropower from Georgia and traded the power to Iran under the gas-electricity swap. 26. Despite the benefits of the swap arrangement, affordability has been an increasing concern as higher gas prices have pushed up the cost of supply. Additionally, there is some concern that the GoA has kept tariffs below cost-recovery levels for some state-owned companies in order to maintain affordability. Below cost-recovery tariffs have, in turn, led to delay in priority investments at state-owned companies and provided inefficient price signals to end-users. 2.3.2 Transmission 27. Armenia’s transmission network has sufficient capacity to meet domestic demand. The state-owned High Voltage Electricity Network (HVEN) operates the transmission network. In 2011, the transmission network consisted of: 164 km of 330 kV lines and one 330/110 kV substation; 1,527 km of 220 kV lines and 14 substations at 220/110 kV level; and 580 km of 110 kV lines and 18 substations at 110/35 kV level. 28. Armenia has transmission interconnections with all of its neighboring countries, but only the interconnections with Georgia and Iran are operational. Interconnections with Turkey and Azerbaijan have not functioned since 1992 as a result of the Nagorno-Karabakh conflict. The transmission network is synchronously connected to the Iranian grid by two 220 kV interconnections, with a combined

24 The gas-electricity swap helps to maintain affordability in two ways: (i) Since the new state-owned Yerevan CCGT produces 4.5 kWh of electricity per m3 of gas, the excess 1.5 kWh are provided to the Armenian domestic market at no financial cost for fuel and (i) The arrangement is on an energy – not capacity – basis, which allows Armenia to exploits the seasonal differences in demand between the two systems; under this arrangement, Armenia exports power to Iran during summer months when generation from HPPs and demand in Iran are high, allowing Armenia to use some gas imported from Iran to operate TPPs to meet domestic winter peak demand in Armenia.

transmission capacity of 350 MW. Armenia could increase exports to Iran because of significant excess generation capacity, particularly during summer months, but is constrained by the capacity of the transmission lines. The GoA is finalizing financing arrangements with the Iran Export Development Bank for construction of a new, 400 kV interconnection, which would increase Armenia’s export capacity to 1200 MW. Distribution 29. Armenia privatized its distribution network in 2002 merging four state- owned regional distribution companies into one private company. The Electricity Network of Armenia (ENA) is the sole owner and operator of the distribution network, providing electricity service to roughly 935,000 customers. ENA is a subsidiary of RAO UES of Russia. The distribution network includes: 2,675 km of 35 kV lines and 278 35 kV substations; 9,740 km 6(10) kV overhead lines (OHL) and 4,955 km 6(10) kV underground cable lines; and 13,570 km 0.4 kV OHL and 2,160 kV 0.4 kV underground cable lines. ENA provides service to roughly 1,088,000 customers, of which 984,000 are residential households. 30. ENA has invested an average of US$ 30 million annually to rehabilitate the distribution network over the past five years. As a result of these investments, losses fell from 14 percent in 2007 to 10.8 percent in 2011.25 Collections have increased from 88 percent in 1999 to 100 percent in 2010. 2.3.3 Renewable Energy 31. Armenia has a well-developed hydropower sector. The largest HPPs— Sevan-Hrazdan Cascade (556 MW) and Vorotan Cascade (404 MW)—produce roughly 1,700 GWh of electricity annually. There has been an increase, in recent years, in the number of small hydropower plants operating. As of 2011, Armenia had 115 small HPPs with a total capacity of 157 MW and annual generation of 470 GWh, or nearly 10 percent of total consumption in 2011. Roughly 45 percent of this capacity has been added since 2008. Additionally, the PSRC has licensed the construction of 91 new projects, which will potentially add approximately 177 MW of small HPP capacity and 637 GWh average annual generation.26 32. Armenia also generates electricity from two small wind power plants and a biogas power plant. Lori 1 wind farm, which began operating in December 2005, has a capacity of 2.64 MW. The plant was built with a US$ 3.1 million grant from the Government of Iran. Lusakert biogas plant, constructed as a pilot project with bilateral financing from the Danish and Norwegian governments, produces 6 GWh annually using biogas produced using animal waste from the Lusakert poultry processing farm. The two projects are the only non-hydropower renewable energy plants in Armenia. 33. In 2007, the PSRC set renewable energy feed-in tariffs to incentivize private investment in renewable energy. New generating plants receive a 15-year power purchase agreement (PPA) under which ENA is obliged to pay the generator

25 Losses estimated as a percentage of net generation. 26 Tetra Tech ES Inc. 2012. Small Hydro Power (SHPP) Sector Framework, Status, Development Barriers and Future Development: 2012 Update.

for all the power produced. According to the feed-in tariff methodology, the PSRC must adjust feed-in tariffs annually in line with changes in inflation and the USD to AMD exchange rate. Feed-in tariffs for small HPPs range from US$ 0.021 to US$ 0.047 per kWh depending on the water source.27 The feed-in tariffs for wind and biomass generation are US$ 0.083 per kWh and US$ 0.09 per kWh, respectively. 34. The GoA is planning to build several mid-sized HPPs by 2017. The three HPPs include Meghri (140 MW), Loriberd (60 MW) and Shnokh (75 MW). These plants are expected to produce a total of 1300-1400 GWh of electricity annually. The GoA plans to develop Meghri with financing from the Iranian Government and will seek to attract private financing to develop Loriberd and Shnokh. In a recent policy decision, the GoA has suggested that the PSRC not approve a generation tariff of more than US$ 0.065 per kWh for any new HPP larger than 10 MW.28 2.3.4 Energy Efficiency 35. Armenia has significant potential to save energy through energy efficiency (EE) investments. According to the GoA’s Energy Efficiency Action Plan (EEAP) for 2011-2020, investments to improve EE could reduce annual consumption of electricity and natural gas by 1 TWh and 600 million m3, respectively, resulting in savings of 132 billion AMD, or 4.95 percent of GDP.29 The EEAP focuses on improving energy efficiency in public, commercial and residential buildings, industrial production, water supply, and transport. 36. The GoA and international donors are supporting energy efficiency through financing for energy efficiency measures in the energy, industrial, residential, and public sectors. The GoA established the Renewable Resources and Energy Efficiency Fund (R2E2) in 2005 to implement energy efficiency and renewable energy projects in Armenia. With funding from the World Bank and several multi- donor trust funds, such as the Global Environmental Facility (GEF) and the Global Partnership for Output-based Aid (GPOBA), R2E2 has implemented a number of projects, including: rehabilitation of heating systems in schools, providing grants to install individual, efficient heaters in poor households, lending for new renewable energy projects, and identifying opportunities for future RE investment.30 EBRD has also supported energy efficiency measures in the industrial sector and in electricity distribution. 37. However, additional effort is needed to help consumers perceive the benefits of demand-side energy efficiency measures. A World Bank study identified several barriers to EE in Armenia including: inefficient tariff structures, lack of implementation of the legal framework for EE, budgeting and contracting rules in the public sector that discourage EE, and difficulty allocating benefits of EE investment in

27 Water sources for small HPPs include natural streams, irrigation systems, or drinking water sources. 28 Government of Armenia. “Protocol Decision: About the Approval of the Strategic Development Programme in the Area of Hydroenergy of the Republic of Armenia.” 29 Government of Armenia. 2010. RA Government Action Plan for the Implementation of RA Energy Efficiency and Renewable Energy National Program. 30 http://www.r2e2.am/enversion/index.php

common spaces in residential buildings.31 Additionally, a 2010 IFC energy efficiency survey found that managers of small and medium enterprises (SMEs) in Armenia underestimated the company’s potential savings from EE investments by more the 65 percent despite the fact that respondents believed that they were well informed about energy efficiency opportunities.32 Gas and Heating 38. Armenia imports natural gas from Russia and Iran. ArmRusGasprom, owned by Gazprom (80 percent) and the GoA (20 percent), and Yerevan TPP are the only companies licensed to import gas. ArmRusGasprom is the sole distributor of natural gas in Armenia. The company manages 10,483 km of gas pipelines and has approximately 550,000 consumers.33 The residential sector is the largest consumer of natural gas in Armenia, followed by industry, electricity generating plants, and transportation, representing, 32, 29, 19 and 17.5 percent of consumption, respectively.34 39. Yerevan TPP imports gas from Iran via the newly constructed Armenia-Iran gas pipeline. This pipeline, which was completed in 2008, improves Armenia’s natural gas fuel supply security. The pipeline primarily serves to transfer gas to Armenia in exchange for electricity under the gas-electricity swap arrangement. Armenia also has roughly 140 million cubic meters of gas storage capacity at the Abovian underground gas storage facility. 40. Armenian households heat primarily with electricity and natural gas. Armenia’s district heating network, which used to provide heat supply for roughly 55 percent of Armenia households, has fallen into disrepair. Many heat supply companies went bankrupt and closed following the economic and energy blockade that occurred during the early 1990s Nagorno Karabakh conflict. As a result, many households switched to heating with electricity and, more recently, natural gas. The share of natural gas in the heating fuel mix has increased from 10 percent to more than 70 percent, displacing firewood, electricity and other fuels, thanks to a rehabilitation and extension of the gas distribution network. 2.4 Core Sector Problems 41. Energy security is a fundamental, ongoing challenge for the GoA. Energy security means having enough capacity to meet peak demand, and having a system that is able to withstand disturbances and interruptions along the energy supply chain.35 The tenuous level of energy security in Armenia has three effects: i) Heavy reliance on imported fuels, ii) High risk of supply interruptions, and iii) Higher system costs than those of its neighbors. These three effects jeopardize the GoA’s ability to

31 World Bank. “The Other Renewable Resource: The Potential for Improving Energy Efficiency in Armenia.” July 2008. 32 International Finance Corporation (IFC). 2010. Energy Efficiency: A New Resource for Sustainable Growth. 33 PSRC. 2010. The Gas Sector of Armenia. http://www.naruc.org/international/Documents/13 Gas system in Armenia-ENGLISH.pdf. 34 http://www.iea.org/stats/gasdata.asp?COUNTRY_CODE=AM 35 Including, for example, fuel supply disruptions, the failure of a major transmission line, or forced outages of large power plants.

achieve its policy objectives of economic growth and poverty reduction outlined in its Sustainable Development Plan. A heavy reliance on imported fuels costs Armenia dearly in terms of foreign exchange. Supply interruptions have an immediate economic impact on the economy, reducing output and, because of the voltage fluctuations that often come with supply interruption, damaging equipment.36 High system costs, the result of rising gas prices and inefficient equipment, raise the cost of doing business and increases the incidence of energy poverty among residential customers. 42. Three core problems—inefficient infrastructure, limited regional power trade and under-exploited renewable energy resources—contribute to Armenia’s lack of energy security. First, much of Armenia’s generation capacity and transmission infrastructure is old and inefficient. Failing to replace or rehabilitate this infrastructure will lead to higher costs, higher consumption of imported fuels, and higher risk of equipment failure and outages. Second, regional power trade is limited. Regional trade is critical to the sustainability of GoA’s existing strategic plan to maintain energy security in the sector. Third, domestic renewable energy resources are under-utilized making Armenia leaving Armenia vulnerable to price shocks and supply disruptions in fuel imports 43. Figure 2.3 shows a problem tree diagram summarizing the causes of these core problems and how energy security, the core development problem, negatively affects the sector and the country. The following subsections describe the causes of Armenia’s lack of energy security and its three underlying core problems in further detail.

36 The threat of supply interruptions is also a deterrent to potential investors, and may harm the economy over the long-term. It raises the cost of doing business, because of the investment required in stand-by or back-up power supply.

Figure 2.3: Armenia Energy Sector Problem Tree Diagram

2.4.1 Energy Security 44. Armenia faces a major supply-demand gap once the ANPP is retired. At least 800 MW of new capacity will be needed to provide enough capacity to meet peak demand and maintain an adequate reserve margin. The Government is

committed to building a new 1,100 MW nuclear plant to replace the capacity of ANPP. Under the Government’s current plans, a new nuclear plant will be operational by 2021 when the ANPP is expected to be retired. 45. Attracting financing for a new nuclear power plant will be difficult. Given the high capital costs of nuclear projects, the cost of capital strongly affects the economic viability of the project. The cost of capital, in turn, depends on investors’ assessment of the risks involved. Nuclear projects encounter the following challenges, which lead to higher risk and increased difficulty accessing financing compared to other large infrastructure projects. The following discusses these risks in the Armenia context: 46. High capital costs. The cost of constructing a nuclear plant has increased significantly in the past decade. Estimates of the overnight cost of constructing a nuclear power plant in the US ranged from $1,000/kW to $5,000/kW from 2001 to 2005. From 2006 to 2010, estimates ranged from $2,000/kW to $10,000/kW with an average estimate of roughly $5,000/kW by the end of the decade.37 Using these estimates, a new nuclear plant for Armenia would cost US$ 5.5 billion, equal to roughly 55 percent of GDP. 47. Maintaining high capacity factors during operation. Under existing plans, the new plant will have significantly more capacity than is needed to meet domestic demand. The GoA plans to resolve the problem of excess capacity by exporting electricity to Iran and to Turkey via Georgia. The Government can provide a guarantee for domestic off-take; however, the plant may struggle to secure export contracts at a price that would recover its costs. Turkey is expected to experience an energy deficit in the next five years, but exports from Georgia and Azerbaijan, and new hydropower generation in Turkey is likely to be sufficient to meet Turkey’s deficit and is expected to be cheaper than electricity from a new nuclear plant in Armenia. 48. Political and regulatory risk. The often controversial nature of nuclear projects increases political risk for investors. General opposition to a plant may be less prevalent in Armenia given that the nuclear industry is well-established and well- respected. However, the magnitude of tariff hikes that will be necessary to make a new plant financially sustainable will likely make electricity unaffordable for a significant portion of the population and, as a result, lead to public opposition. Even if the Government is able to obtain attractive financing terms for the new plant and find an off-taker for the plant’s excess power, the levelized cost of the new plant (28.5 AMD/kWh) would still be roughly three times higher than the current generation tariff for ANPP (9.7 AMD/kWh).38 49. Financing radioactive waste management and decommissioning. Nuclear projects must have a credible financing scheme in place to fully decommission the plant and dispose of radioactive waste. This is necessary so that investors understand their decommissioning obligations at the start of the project. Often this

37 The Economist. “Bandwagons and busts.” 10 March 2012. 38 The estimate of the levelized cost of a new nuclear plant assumes an 85% capacity utilization factor and 100 percent concessional debt financing at a 3 percent interest rate and 20 year tenor.

scheme involves mandatory annual contributions, treated as an operating expense, into a ring-fenced fund. The decommissioning fund for the ANPP is significantly underfunded and is not expected to come close to covering the costs of decommissioning the old plant. Investors will look at this track record when considering whether to finance a new nuclear power plant. 50. These risks must be addressed if Armenia is to build a new nuclear plant in the next ten years. Armenia might consider other generation options to replace the ANPP given the significant challenges faced by new nuclear plants worldwide faced with rising construction costs and increased safety concerns in the aftermath of the Fukushima disaster. The Government must begin to make decisions about the investment strategy for the energy sector. An updated least-cost generation plan or sector roadmap that comprehensively addresses these serious challenges facing the sector could help the Government weigh the advantages and disadvantages of its investment options. 2.4.2 Old, Inefficient Infrastructure 51. Much of Armenia’s electricity generation and transmission infrastructure is old and inefficient. The condition of assets has deteriorated because of lack of rehabilitation and under-maintenance. Much of the existing generation and transmission infrastructure has reached the end of its useful life and requires major rehabilitation or replacement to continue reliable operation. The poor condition of this infrastructure increases the risk of outages and increases system costs. Thermal plants have higher fuel costs because inefficient equipment reduces the fuel efficiency of the plants. Hydropower plants, which help bring down the average cost of supply, have lower availability because lack of rehabilitation has caused emergency shutdowns and equipment failure. Transmission losses have increased, contributing further to higher costs as end-users have to pay for more power produced that they don’t consume. 52. The sector’s infrastructure has deteriorated because of insufficient funding. Companies lack the funds for new investment because many assets are old and nearly or fully depreciated. As a result, the portion of the tariff covering capital expenditure, which is set based on the value of the asset base, is low for many companies and does not provide sufficient funds for rehabilitation. Public and private investment in new generation has occurred over the past five years, but existing state-owned generating plants have not undergone major rehabilitation in the past 15 years. Private companies have also not invested in rehabilitating generation infrastructure. 53. Tariffs have also not kept pace with rising operating and maintenance costs, fuel costs in particular. As a result, public and private companies have had to delay needed investments in order to cover operating and maintenance expenses. From 2006-2012, the border price for natural gas increased, on average, 17 percent annually. The average inflation rate of this period was 6 percent. During this period, the PSRC only increased end-user tariffs once in 2009 from 25 AMD/kWh to 30 AMD/kWh. Figure 2.4 shows actual residential tariffs versus cost recovery residential tariffs when accounting for fuel price increases and inflation in labor, material costs, and other expenses.

Figure 2.4: Actual versus Cost-Recovery Residential Tariffs

54. The Government has well-established mechanisms for mitigating the social impact of cost increases in basic needs and services. The Poverty Family Benefits Program (PFBP) provides cash transfers paid directly to the households identified through well-targeted means-testing. More recently, the PFBP has begun providing vouchers to compensate poor families for gas bills, which have increased because of gas price increases. The same has not yet happened in the electricity sector. 55. Electricity companies’ financial performance has weakened and companies have struggled to make needed investments because tariffs have not increased since 2009, despite rising costs. In order to neutralize the impact on end-user tariffs, the full cost of investments, including the cost of debt service or a reasonable return on equity, has not been included in the tariff. For public investments, the GoA also waived the part of the tariff which provides a return on assets for state-owned power plants.39 Some private companies report that the PSRC does not allow recovery of their full investment costs, or does not recognize the full costs of their financing. 56. Public and private companies also struggle to access financing for investments. This is partly a result of below cost-recovery tariffs, which signal to lenders that the company could have difficulty servicing debt. The GoA’s concern about debt sustainability also constrains its ability to borrow for public projects. The GoA has set a public debt ceiling of 50 percent of GDP and public debt currently stands at roughly 43 percent of GDP. Private companies have also had difficult accessing external financing. As a result, companies have had to rely on their own

39 Balabanyan, Ani, Edon Vrenezi, Lauren Pierce, and Denzel Hankinson. 2011. Outage: Investment Shortfalls in the Power Sector in Eastern Europe and Central Asia.

funds and available funds from their parent companies to finance small capital expenditure projects. 57. The following subsections discuss the challenges related to inefficient generation and transmission infrastructure in further detail and the consequences that may arise if these challenges are not address. Inefficient Generation 58. Available capacity is low compared to installed capacity because of the age and poor condition of generating plants. The system was designed to serve large industrial demand that has greatly diminished since the collapse of the Soviet Union. Old TPPs now operate under sub-optimal conditions in order to meet Armenia’s current demand for electricity.40 59. Many generating units are old and in poor condition. Roughly 50 percent of available capacity is more than 40 years old.41 Large hydropower plants (HPPs), in particular, require significant rehabilitation. Roughly 54 percent of the equipment installed at the two large HPPs, Vorotan Cascade and Sevan-Hrazdan Cascade, has been in operation for more than 50 years. 60. The rehabilitation planned for the Vorotan and Sevan-Hrazdan Cascades has been delayed because of lack of financing. As a result, equipment has failed and some of the plants in each cascade have undergone emergency shutdown. Several HPPs in both cascades now operate below their design capacities because of the poor condition of the assets.42 For example, the Shamb HPP underwent emergency shutdown in 2008 and was not operational for all of 2010 because of lack of rehabilitation. 61. The GoA is rehabilitating the state-owned Vorotan Cascade with financing from KfW. The Vorotan Cascade is crucial to Armenia’s power system because it provides regulating capacity that allows the system operator to meet daily peaks with low cost supply. The rehabilitation program will replace equipment at the three HPPs in the Cascade leading to restored operation of the Shamb HPP to its design capacity, thereby improving the performance of all HPPs in the Cascade. The rehabilitation, which costs US$ 77 million, is expected to increase annual generation of Vorotan HPP by 15 percent from 1,122 GWh to 1,290 GWh. 62. The Sevan-Hrazdan Cascade, owned by RusHydro, a Russian hydropower company, has not undergone any major investment since the asset was initially privatized in 2002. The HPPs in the Sevan-Hrazdan Cascade are, on average, 60 years old and operate well below their installed capacities. Several of the HPPs operate

40 To address the decline in demand, 810 MW of Hrazdan TPP, designed for baseload generation, were transformed into balancing units and 300 MW of cogeneration units are no longer utilized due to lack of demand for heat. Similarly, the 50 MW of available capacity at Yerevan TPP only produces electricity when heat supply is needed at the nearby Nairi Chemical Plant. The plant’s remaining 500 MW is no longer operational because of obsolete equipment. 41 Estimated based on available capacity of plants greater than 10 MW. 42 HPPs in Armenia also operate below their design capacity because of irrigation and environmental restrictions. For example, the Sevan-Hrazdan Cascade, which operates on the Hrazdan river, uses water from Lake Sevan and tributary rivers. Water releases from Lake Sevan are strictly monitored and release schedules are linked to irrigation needs.

below their design capacity because of inefficient equipment. For example, the Argel HPP at Sevan-Hrazdan operates 20 percent below its installed capacity because critical equipment requires rehabilitation. Investment needs at the Cascade are expected to cost US$ 40-60 million and will include rehabilitating and replacing old equipment and updating water inflow channels in order to reduce water losses and improve generation efficiency. 63. The primary equipment at Hrazdan TPP and Yerevan TPP is beyond its design life and does not meet international technical, economic and environmental performance standards.43 These plants have not undergone necessary capital improvements in recent years and operations and maintenance (O&M) has been consistently under-funded. The plants run on outdated Soviet technology and obtaining spare parts for maintenance is difficult and costly because the equipment is no longer manufactured. Only one of the older generating units at Yerevan TPP remains operational. 64. The inefficiency of the thermal plants leads to higher system costs. The fuel efficiency of Hrazdan TPP is 35 percent compared to 57 percent for a new, efficient TPP. The cost of generation at Hrazdan TPP is more than four times the cost of generation at the nuclear plant—the next most costly plant in the Armenian power system. Heavy reliance on this inefficient plant coupled with gas price increases has led to higher system costs. The PSRC increased end-user tariffs to account for increased gas prices in 2009, which reduced electricity affordability, especially for low-income consumers. However, tariffs have lagged below cost- recovery a level since then, which has harmed the financial sustainability of sector companies. This has created a negative cyclical effect, whereby companies have had to forego needed investments, which would reduce costs by improving efficiency, because tariffs have not kept pace with rising system costs. 65. The nuclear power plant (NPP) is in good condition because of continual efforts to comply with international nuclear safety and operational standards. Nevertheless, Armenia has faced increasing pressure from the European Union to close the NPP for safety reasons.44 The GoA initially planned to shut down ANPP in 2016 and replace it with a new 1,000 or 1,200 MW nuclear plant that would be commissioned in 2017. However, the GoA has now indicated it will extend the life of ANPP until 2021. The MENR is developing a plan that will outline the activities required to extend the operating life of the nuclear plant beyond 2016. The plan must be submitted to the GoA by 5 May 2013 with an estimate of the cost of life extension activities by 1 August 2013.45 66. The NPP and Hrazdan TPP are strategic assets in the Armenian power system and replacing this capacity is a top priority for the GoA. The plants make up 40 percent of the operational capacity of the system. The nuclear power plant provides low-cost baseload capacity. Hrazdan TPP provides capacity to help meet

43 Ministry of Energy. Energy Sector Development Strategy in the Context of Economic Development. 2005. 44 The plant has one of the few remaining reactors built without a primary containment structure and is in an earthquake prone region. 45 http://www.neimagazine.com/story.asp?storyCode=2062249

winter peak and provide for a reserve margin. A 2011 World Bank study found that Armenia will need at least 800 MW of new generation capacity when the existing NPP is decommissioned and old TPPs are retired.46 67. The GoA plans to build a new nuclear power plant to replace the existing plant. However, securing financing for the new plant will be a challenge. Estimates of construction for a new nuclear plant ranged from US$ 5-7 billion in 2010, which is equivalent to roughly 50-70 percent of Armenia’s nominal GDP.47 Most projects have been halted as a result of the Fukishima disaster in Japan, and even before that, many nuclear power projects worldwide faced challenges raising sufficient financing due to cost escalation in recent years. Armenia may be able to source commercial or sovereign lending from Russia; however, it is unclear how the GoA plans to recover the cost of financing as doing so solely through the tariff would make end-user tariffs unaffordable for the majority of the population. Inefficient Transmission 68. The age and poor condition of Armenia’s transmission infrastructure increases losses and jeopardizes supply reliability. Transmission assets are, on average, more than 45 years old.48 HVEN has estimated that roughly 33 percent, or 520 km of the 220 kV network are in very poor condition and require urgent rehabilitation at a cost of US$ 80-100 million. 69. Donors have had a consistent presence in helping rehabilitate the transmission network. In 2012, the World Bank provided a US$39 million loan to repair or replace 45 percent or 230 km of these lines. Additionally, the GoA with support from KfW, the World Bank, and JBIC partially rehabilitated primary equipment in the majority of 220 kV substations over the past several years. 70. Despite ongoing investment in transmission infrastructure, additional investments are needed. In addition to the 220 kV lines currently under rehabilitation, another 290 km require urgent rehabilitation.49 Secondary equipment at more than half of 220 kV substations requires urgent rehabilitation. HVEN estimates replacement or rehabilitation of this equipment will cost roughly US$55 million.50 Additionally, the 220 kV substations at Yerevan TPP and ANPP require full rehabilitation. 71. Failure to rehabilitate substations could lead to widespread outages. Secondary equipment at substations, or protection and control equipment including voltage and current transformers, relays and SCADA equipment, helps maintain the reliability of grid operations. Without this equipment, the system operator cannot quickly react to supply disruptions. As a result, negative impacts from accidents or equipment failure, which could be isolated, instead have widespread consequences.

46 World Bank. “Charged Decisions: Difficult Choices in Armenia’s Energy Sector.” October 2011. 47 Ibid. 48 Ibid. 49 World Bank. Project Appraisal Document: Electricity Supply Reliability Project. 4 May 2011. 50 HVEN estimate.

72. The poor condition of the substations at Yerevan TPP and the nuclear power plant impacts the safety and efficiency of generation. At Yerevan TPP, failure of equipment has forced the new combined cycle gas turbine (CCGT), recently commissioned in 2010, to undergo emergency shutdown four times in past twelve months. At ANPP, poor condition of the substation jeopardizes the safety of nuclear operations. Inefficient Distribution 73. Distribution infrastructure remains inefficient with above normal technical losses despite investments in rehabilitation in recent years. Roughly 30 percent of 6(10) kV equipment requires rehabilitation and equipment in roughly 25 percent of 35 kV substations requires rehabilitation. Common problems in the network include: underutilized and overloaded transformers, rotting poles, moisture in cable lines, cable lines below regulated heights, and difficulty accessing equipment for maintenance personnel. On average, distribution infrastructure is operational, but maintenance is consistently underfunded leading to high operational costs for the company. 74. Operational costs are also high because the ENA lacks the technology to accurately monitor load and network performance. SCADA controls and metering equipment is needed at 84 110 kV substations.51 Roughly 75 percent of customers do not have electronic meters, which are needed to reduce commercial losses and allow ENA to monitor individual end-user demand. Additionally, portions of the distribution grid are overloaded leading to higher losses. The distribution network requires rehabilitation and expansion to meet higher demand in Yerevan and the growing regions of Tzakadsor and Dilijan 75. ENA faces an ongoing challenge to finance new investment. ENA has historically funded new investment through a mix of concessional loans and grants from development partners, commercial loans, and resources from RAO UES. A recent €92 loan from EBRD and Vnesheconombank increased the company’s debt- equity ratio to 3.0 in 2010. Roughly 91 percent of ENA’s debt is denominated in foreign currencies, putting the company at risk for foreign exchange losses related to debt repayment and interest accrual in the event of a sharp depreciation in the Armenian dram. ENA has also expressed difficulty in obtaining PSRC approval to recover the full amount of investments financed by the loans through its tariff. The company may struggle to take on additional debt to finance needed investments and still maintain its financial performance as a result of these factors. 76. Service quality has also decreased in the past year because of underinvestment. The PSRC sets explicit service quality standards, including the number of interruptions per customer, the average duration of interruptions per customer and the average frequency of non-standard customer voltage. ENA is required to pay a fine if it does not comply with these standards. This framework has worked well to incentivize ENA to target investments towards improving service quality. However, there is some concern that the PSRC may have allowed service quality to deteriorate in the interest of maintaining affordability. The frequency and

51 ENA installed SCADA equipment at 17 110 kV substations that were recently replaced with a loan from JBIC.

duration of blackout, which decreased from 2007-2010, increased 14 and 26 percent, respectively, in 2011.52 2.4.3 Regional power trade 77. Armenia lacks sufficient domestic energy resources to meet its energy needs. Limited diversification of energy resources, further contributes to the lack of energy security because it makes Armenia vulnerable to supply disruptions and heavy reliance on imported gas from Russia limits Armenia’s ability to maintain affordability if gas prices increase. 78. Armenia lacks diversification, in part, because it has not fully developed its regional trade opportunities. More regional trade can improve supply diversity and help Armenia maintain affordability by further exploiting the gas-electricity swap by transiting cheap Georgian hydropower. Armenia only trades electricity with two of its neighboring countries—Georgia and Iran. 79. The two largest factors affecting Armenia’s ability to export electricity are the availability of generation and transmission capacity for export and the future cost of generation. Armenia currently has excess hydropower generation during spring and summer that could be exported to Turkey via Georgia, but is constrained by its asynchronous connection. This excess capacity is expected to diminish, however, as domestic demand grows and as trade with Iran increases further. 80. If Armenia builds a new nuclear plant, additional interconnection transmission capacity will be needed to export electricity from the plant. The planned nuclear plant will be significantly larger than needed for the domestic demand. The GoA plans to export excess generation from the plant; however, given the expected availability of cheap excess generation from Georgia and Azerbaijan, it is unlikely that the future export market price will be high enough to cover the full cost of production from the new nuclear plant. Even so, if the GoA finds sufficient financing to build a new 1,000-1,200 MW nuclear plant, the power system must have sufficient load to evacuate the power from the plant.53 In other words, Armenia may be forced to export the power at a financial loss in order to operate the plant to serve domestic demand and maintain system reliability. 81. If Armenia does not build a new nuclear plant, the country may need to import significant volumes of electricity from Georgia in order to meet domestic demand and reduce reliance on imported gas. In this scenario, additional transmission interconnection capacity could help Armenia meet its supply gap with relatively cheap hydropower imports from Georgia. 82. Armenia also lacks the transmission infrastructure to export or import large volumes of electricity with Georgia because of the asynchronous connection between the two countries. Armenia has three transmission interconnections with Georgia: One 220 kV line and two 110 kV lines. However, the asynchronous

52 PSRC. Service Quality Indicators. 2007-2011. 53 Nuclear plants provide baseload power for two reasons: i) nuclear plants have historically provided a guaranteed source of capacity with low operating costs and ii) a nuclear plant’s operating capacity cannot increase or decrease quickly enough to follow changes in demand and shutting down is time-intensive. For example, when the existing NPP in Armenia goes offline, it must stay offline for 3-5 days.

connection limits the quantity and frequency of trade over these lines.54 Armenia cannot be synchronously connected to both Georgia and Iran because it would compromise grid stability in the IPS/UPS and Iran-Turkmenistan synchronous zones. The GoA is negotiating with the Government of Georgia and the German development institution, Kreditanstalt für Wiederaufbau (KfW), over the technical specifications and financing terms for a new 400 or 500 kV interconnection between the countries. However, KfW does not plan to finance a back-to-back HVDC substation which will be needed to export power in large volumes to Georgia and through Georgia to other countries in the region. 83. Even if the physical infrastructure challenges are addressed, the current regulatory environment may limit trade with Georgia. Under existing export-import regulations, import licenses are restricted and the GoA negotiates trade bilaterally with the Government of Georgia. However, in the medium- to long-term as a competitive market for regional trade develops in Georgia, the Government of Georgia may not be willing to negotiate bilateral agreements with Armenia. 2.4.4 Under-exploited renewable energy resources 84. Armenia also lacks diversification because the renewable resources that exist have not been fully exploited. More than half of Armenia’s technically viable renewable resources have not been exploited. According to Armenia’s Renewable Energy Roadmap developed by the Renewable Energy and Energy Efficiency (R2E2) Fund, Armenia has more than 1000 MW of technically viable capacity from solar photovoltaic (PV), 300-500 MW from wind, 250-350 MW from unexploited small HPPs and 25 MW from geothermal. There is also technical potential for roughly 100,000 tons per year of biofuel production. 85. Renewable energy is underdeveloped, in part, because of a lack of information on the technical, economic and financial viability of specific sites. The World Bank is currently assessing the feasibility of several geothermal sites in Armenia, but exploratory drilling is still needed to confirm the potential for geothermal development. Several donors have supported assessments identifying the technical and economic potential for wind energy development, but additional site monitoring and testing is needed over an extended period of time to provide sufficient data. 86. Currently, only small HPPs and roughly 200 MW of wind are considered economically viable. More than 150 MW of small HPPs has been developed, but 150 MW of unexploited, financially viable potential is estimated to remain. The regulatory framework, with its feed-in tariff and guaranteed off-take, helped spur investment in small HPPs. Extensive support from development partners helped develop access to financing for renewable energy projects through domestic commercial banks. Specifically, KfW, EBRD, and the World Bank provided financing, which has been on-lent from the Ministry of Finance to domestic commercial banks, and capacity building, which was used support proper due diligence on potential projects.

54 Georgia and Armenia currently trade electricity in “island mode” across a 220 kV interconnection. However, Georgia will no longer be able to trade large volumes in “island mode” with Armenia once the new 400 kV line between Turkey and Georgia comes online.

87. Investors have expressed concern in the past five years that the feed-in tariff has not kept pace with costs. The development of potential sites is expected to slow because the feed-in tariff is not high enough to cover the costs of more expensive, unexploited project sites. Some project developers have tried to cut costs by utilizing cheap, domestically available materials that do not meet design standards. As a result, many of the existing small HPPs have not reached the operational efficiency projected in project design documents and many will likely not reach the expected design life for typical small HPPs without major rehabilitation.55 88. The level of feed-in tariffs and the length of the off-take period (15 years) have also been a barrier to the development of economically viable wind power in Armenia. Investors have expressed concern that the off-take period is shorter than the average lifetime of a wind project, which is roughly 20 years. Like with small HPPs, the PSRC adjusts feed-in tariffs for wind to account for inflation and foreign exchange rates. However, the feed-in tariff at a given period has always been lower than the break-even tariff identified in feasibility studies. For example, the 19.5 MW wind project at Zod pass required a tariff of €0.1036 per kWh to make the project financially viable, however, the feed-in tariff at the time was only €0.052 per kWh. Similarly, a break-even tariff for the 14.5 MW Semyonovka WPP would equal €0.1224 per kWh, but the feed-in tariff in place at the time of the feasibility study was only €0.077 per kWh. Figure 2.5 shows how feed-in tariffs in Armenia fall below those in other Eastern European countries for on-shore wind, biomass, and hydropower.

55 USAID. “Small Hydro Power (SHPP) Sector Framework, Status, Development Barriers And Future Development.” March 2012.

Figure 2.5: Country Comparison of Feed-in Tariffs

Source: Ukraine: Nechayev, Yuriy. “Ukraine: “Green” (“Feed-In”) Tariff in Ukraine.” Avellum Partners. 16 December 2011. http://www.mondaq.com/x/157224/Oil+Gas+Electricity/Green+FeedIn+Tariff+In+Ukraine Armenia: Public Services Regulatory Commission. All other countries: Europe’s Energy Portal. http://www.energy.eu/

89. Other legal and regulatory barriers also stand in the way of wind power project development. Legal procedures related to land permitting, environmental assessment and permitting, and licensing also need to be streamlined to reduce investor risk of project delays. A heavy tax burden also reduces the financial viability of investment in wind power. Wind projects are subject to significant VAT because most of the equipment is imported and this cost cannot be financed. 90. Long-term sector policy and planning may also prove an obstacle to renewable energy development. The development of domestic, renewable energy and the replacement of the nuclear plant are two key objectives for the GoA in the energy sector. However, a recent World Bank report noted that developing renewable energy resources in addition to a new 1,000 MW nuclear plant would result in higher system costs than if Armenia only developed a new nuclear plant. Planned renewable energy projects and a new nuclear plant provide more capacity than is needed to serve domestic demand and building both will adversely impact end-user tariffs. Once the GoA develops a plan for replacing the ANPP that identifies how the Government will finance that plant and export its excess capacity, the financial viability of renewable energy investments will become clearer. 3 Sector Strategy and Road Map 91. The GoA’s strategy in the energy sector aims to implement solutions to the sector’s core problems. Solutions, which include rehabilitating generation and transmission infrastructure, developing renewable energy, and facilitating regional integration, align well with ADB’s Energy Policy and Strategy 2020 objectives. Opportunities exist for ADB to work with other development partners, who have a

good track record in the sector, to help public and private companies make investments that achieve the GoA’s strategic objectives. This section discusses the Government’s strategy and the activities of other development partners in the sector. It then discusses opportunities for ADB involvement that help the Government achieve its strategic objectives and that fit within ADB’s energy strategy. 3.1 Government’s Strategy 92. The Sustainable Development Program (SDP) and the National Security Strategy (NSS) outline the GoA’s strategic objectives for economic growth, poverty reduction, and national security. Both policies highlight the fundamental importance of the energy sector in achieving these objectives. The most recent Government Program, passed in June 2012, identifies specific targets for achieving the strategic objectives of the SDP and NSS in the 2012-2017 time period. 93. Key priorities of the Government Program include: i) increasing competitiveness as a condition for sustainable economic growth, ii) developing human capital through poverty reduction, access to education, and job development, iii) developing institutional capacity by increasing transparency, accountability and service quality of public institutions. Through implementation of the Government Program, the GoA expects to: i) achieve 5-7 percent GDP growth, ii) ensure faster growth of exports compared to imports, and iii) reduce poverty by 8-10 percentage points. 94. The Government Program identifies investment in infrastructure as a pillar to achieving increased competitiveness. The GoA seeks to increase investments through private sector participation. Key priorities for the energy sector in the 2012- 2017 period include: i) increasing the level of energy security, ii) development of renewable energy, including increased efficiency of existing hydropower potential and creation of alternative energy resources, iii) improving system stability in order to safeguard consumers from voltage fluctuations, iv) development of regional trade by completing 400 kV interconnections with Iran and Georgia, and v) continued work to build a new nuclear power plant. 95. Several energy sector strategic programs identify concrete targets for achieving the GoA’s stated objectives in the sector. These documents include: i) Energy Sector Development Strategies within the Context of the Economic Development in Armenia, approved by the GoA in 2005, ii) the National Program on Energy Saving and Renewable Energy, approved in 2007, and iii) the Action Plan of the MENR of the Republic of Armenia in line with the National Security Strategy, approved in 2007. Table 3.1 shows the policy direction, specific measures and expected outcomes identified in these strategic programs for achieving the GoA’s objectives of maintaining energy security, economic growth, and poverty reduction.

Table 3.1: Specific Energy Sector Measures Proposed in GoA Strategies

Policy Objective Specific Measures Expected Outcomes Cost Achieved to Date (mln. US$) Development of New HPPs at Meghri, Loriberd and Shnokh 275 MW and 1,340 GWh/yr from HPPs 320 None domestic New small HPPs 265 MW by 2025 from small HPPs 320 157 MW and 470 GWh/yr renewable energy 8-10 New WPPs 500 MW from WPPs 500 None Investigate geothermal potential Develop confirmed potential 10 None Increased New CCGTs at Yerevan TPP 416 MW plant saves 265 mln m3 gas/yr 465 240 MW came online in 2010 efficiency of New CCGT at Hrazdan TPP 400 MW plant saves 223 mln m3gas/yr 440 400 MW to come online in 2012 existing resources Modernization of T&D networks Reduce T&D losses by 168 GWh/yr 420 Ongoing T&D rehabilitation Rehabilitate Vorotan Cascade Increase available capacity 77 Rehabilitation currently underway Investments in energy efficiency measures Save up to 1 TWh electricity and 600 Government agency (R2E2)

million m3 natural gas created in 2005 to facilitate EE Safe operation of Complete ANPP safety enhancement and Safe operation of ANPP until plant Life extension plans currently 70 ANPP and maintain safe operations closure under development construction of a ANPP decommissioning plan Begin decommissioning ANPP 46 new NPP Feasibility study, design works and 1,000 MW ANPP unit 1 5,000- commission new ANPP unit 7,000 Diversification of Diversify gas supply Construct Iran-Armenia gas pipeline 120 New gas pipeline in operation energy supply since 2008 Strengthen regional electricity 400 kV line Armenia-Iran 30-40 transmission interconnections 400 kV line Armenia-Georgia 150-200 Modernize and expand gas storage 150 mln m3 of underground gas storage 27

96. The Government Program also emphasizes the importance of balancing debt sustainability against fiscal stimuli aimed to encourage economic growth. The Law on Public Debt sets a public debt ceiling of 50 percent of GDP and borrowing over the past three years to finance an aggressive anti-crisis agenda has brought public debt to within seven percentage points of the limit. 97. The GoA prepares a Medium-term Expenditure Framework (MTEF) every year, which covers the next three years of public spending. The purpose of the MTEF is to help ensure the sustainability of fiscal spending and prioritize public investment to help the GoA meet its strategic objectives. In 2012, the MENR released a medium- term investment plan for 2013-2015. This investment plan, if approved by the Ministry of Finance, will be included in the GoA’s MTEF for 2013-2015. The MENR has already secured financing for these investments from either the state budget or loans from development partners. Investments for the 2013-2015 period target the GoA’s objectives of maintaining safe operations of the NPP and improving efficiency of generation and transmission infrastructure and end-use consumption. Table 3.2 lists the priority investments, the sources of financing secured, and the level of investment planned over the 2013-2015 period. Table 3.2: Ministry of Energy’s Medium-Term Investment Plan, 2013-2015

Investment planned for the 2013-2015 period Confirmed Project (thous. USD) sources of 2013 2014 2015 Total Financing Decontamination and disposal of radioactive 73 75 85 233 State funds waste Reconstruction of 8,036 4,270 --- 12,306 KfW Gyumri-2 substation Rehabilitation of Vorotan 14,374 15,390 14,699 44,464 KfW hydropower plants Rehabilitation of 220 kV World Bank OHLs and Hrazdan TPP 14,547 13,334 8,637 36,518 (IBRD) substation Energy Efficiency in World Bank 744 65 48 858 Public Buildings grant

Source: Ministry of Energy and Natural Resources, “Medium-Term Expenditure Plan for 2013-2015.”

3.2 Development Partner Support to Energy Sector 98. Development partners actively involved in the energy sector include the World Bank, KfW, EBRD, JBIC, and USAID. Areas of focus for donors include: i) promotion of energy efficiency through rehabilitation and upgrade of existing generation, transmission and distribution facilities and promoting demand-side efficiency measures, ii) facilitating private sector investment in renewable energy through credit lines and capacity building at local banks, and iii) supporting regional cooperation through investments in transmission infrastructure and

interconnections. Table 3.3 shows development partner projects that contribute to the GoA’s policy objective and identifies possible implications of those projects for ADB involvement in the sector.

Table 3.3: Development Partner Activity in the Armenian Energy Sector Financing Provided Implications for ADB Policy Area Support Donor Status Loan Grant Support Development of Development of small HPPs EBRD $7 million Ongoing ADB can learn from domestic renewable with credit line through KfW Phase 1: €7.5 million Complete successful energy domestic banks Phase 2: €18 million Ongoing implementation Phase 3: €40 million Prospective arrangement of other World Bank $5 million $3 million Complete donors Regulatory support to promote EBRD Unknown Complete Additional support may renewable energy be needed Increased efficiency of Rehabilitation of Sevan-Hrazdan EBRD $40-60 million Prospective Opportunity for donor existing resource cascade cooperation utilization Rehabilitation of Vorotan KfW €51 million Ongoing None cascade Transmission rehabilitation World Bank $39 million Planned Lessons learned can be KfW €9 million Complete used to support potential ADB projects Energy efficiency improvements EBRD €52 million Ongoing None in distribution network JBIC $39 million Complete None Industrial energy efficiency EBRD $20 million Ongoing None Energy Efficiency in Public World Bank $8.8 million $1.8 Planned None Buildings million Construction of Yerevan CCGT JBIC ¥15,918 million Complete None Maintaining safe Planning support for new USAID $5.9 Ongoing GoA’s nuclear strategy operation of the NPP nuclear plant development million affects all sector and construction of a operations new nuclear plant Diversification of energy Construction of Armenia- KfW €20 million Prospective Opportunity for donor supply through regional Georgia high voltage cooperation integration interconnection

3.3 ADB Support 99. ADB began operations in Armenia in 2005, but has had no active cooperation in the energy sector to date. In its first few years of operation in Armenia, ADB’s strategy focused on: establishing operations which respond to Armenia’s development challenges, selectively determining initial projects that would deliver swift results, and partnering with other development institutions to build upon existing institutional know-how. 100. ADB has developed its Country Operational Business Plan (COBP) in line with the GoA’s strategic objectives and ADB’s development objectives. ADB’s most recent COBP for the 2012-2013 period supports Armenia’s development priorities outlined in the Sustainable Development Program and is consistent with ADB’s focus areas and agenda outlined in ADB’s Strategy 2020. Priority focus areas under the current COBP include: urban development, regional cooperation, and private sector development. The energy sector is included as a priority focus area in the upcoming COBP for 2013-2014. The GoA objectives for the energy sector are also consistent with ADB’s 2009 Energy Policy, which aims to help developing member countries (DMCs) provide reliable, adequate, and affordable energy for inclusive growth in a socially, economically, and environmentally sustainable way. 101. The Government in consultation with ADB has identified the energy sector as a key pillar of ADB’s upcoming Country Partnership Strategy (CPS) for Armenia. ADB will support for Armenia economic infrastructure projects that address critical gaps and constraints in the power system and that rehabilitate and modernize the power infrastructure. Priority areas include: (i) rehabilitation of aging power transmission infrastructures; (ii) facilitating regional power trade and cooperation; and (iii) promotion of renewable energy including hydropower, wind power, geothermal, and solar through private sector or public-private partnership structure. The public sector interventions will be closely coordinated with those supported by ADB’s private sector operations department. ADB may also support sector development by providing knowledge products, innovative financing products, mature project management experience and good practice, institutional training, regulatory development, policy development, and coordination with neighboring countries and development partners. Subject to the Government’s needs and sector diagnosis, ADB’s support may also cover gas, heat supply, energy efficiency improvement, and rural infrastructure development together with other development partners. 102. Expected project outcomes include facilitating cross-border electricity trade, improving efficiency of existing infrastructure, and developing private investment in sustainable energy. These projects fit well within three of the five core areas identified in ADB’s Strategy 2020—infrastructure, environment (including climate change), and regional cooperation and integration. These projects also align well with ADB’s ongoing operations in the country. 103. Figure 3.1 below demonstrates how the priority areas for ADB involvement meets core sector problems and aligns well with the GoA’s and ADB’s strategy for the sector.

Figure 3.1: Linking Sector Support Areas with GoA’s and ADB’s Strategy

104. ADB can support public investments to improve the efficiency of transmission infrastructure and facilitate regional trade. MENR, HVEN and the System Operator have a strong record of working well with development partners to successfully implement projects in the energy sector. MENR, with support from HVEN and the System Operator, has preliminarily identified areas where ADB financing could support priority investment in the sector. ADB will want to work closely with MENR and the Ministry of Finance to identify the size and scope of priority projects, in order to meet the GoA’s dual objectives of achieving energy sector goals and maintaining debt sustainability. 105. ADB’s private sector operations department (PSOD) can provide financing to rehabilitate privately-owned large HPPs and to facilitate private investment in new renewable energy projects. A large portion of the power sector has been privatized and many of these companies have large investments needs with limited access to financing except through loans from their parent companies. Additionally,

PSOD financial support and credit enhancement support for private development of renewable energy projects may be useful if the GoA decides to pursue mid-sized renewable projects under a PPP arrangement. 106. Knowledge products and services in the form of technical assistance may also be needed. ADB can work closely with the GoA and other development partners to identify areas where additional knowledge, information, and capacity building is needed in the sector. Strong coordination with, and support from the GoA in development of these products is needed. Areas for potential support include, but are not limited to: i) project preparatory technical assistance to identify and determine the feasibility of specific investments to improve efficiency in transmission infrastructure, ii) feasibility studies for renewable energy and alternative energy schemes, including wind, biomass, and pumped storage, iii) regulatory support to identify the impact of higher feed-in tariffs for renewables on end-user tariffs, and iv) development of a long-term sector planning and financing strategy. 107. ADB can work closely with other development partners, including KfW, EBRD, the World Bank, and JBIC, to learn from their experience in the sector. ADB is already pursuing development partner coordination in the sector for public and private investment projects as well as technical assistance to develop a renewable energy investment plan for the sector. 108. ADB support coincides with the GoA’s strategy and ADB’s strategy for the energy sector in three key areas: i) improving efficiency of energy infrastructure, ii) regional integration, and iii) development of renewable energy. The following three subsections describe in further detail the rational for ADB support, possible specific investments and technical assistance that might be needed, and expected outcomes and outputs within these three support areas. 3.3.1 Sector Support Area #1: Improved Efficiency of Energy Infrastructure 109. Rationale: Rehabilitation and modernization of existing generation and transmission infrastructure can help improve sector efficiency. Higher efficiency in generation infrastructure contributes to energy security by increasing production from cheap, domestic hydropower resources, which, in turn, reduces utilization of expensive imported fuels. Higher efficiency in transmission infrastructure reduces losses and reduces supply interruptions caused by equipment failure. Specific areas for potential ADB support include rehabilitation and modernization of 220 kV transmission lines and substations, completion of SCADA system installation large HPP rehabilitation, and rehabilitation of large HPPs. 110. Specific Measures: ADB can provide financing to rehabilitate 220 kV lines and substations, which is needed to improve transmission efficiency and system reliability. Specifically, ADB can support: i) rehabilitation of secondary equipment in eight 220 kV substations, which will lead to lower losses and an improvements in supply reliability; ii) reconstruction of substations at Yerevan CCGT and the NPP, which will increase operational safety and reduce outages, and iii) rehabilitation of roughly 55 percent of the 220 kV lines not targeted by the recent World Bank loan, which will further reduce losses in the transmission network. HVEN estimates the total cost of these investments to be US$ 134 million.

111. ADB can also finance extension of the SCADA system, which complements investment in partial rehabilitation of secondary equipment in substations. Currently, the SCADA system only covers 60 percent of the transmission network in Armenia. Expansion of the SCADA system to cover 100 percent of the network will greatly improve system operations and control and optimize power flows. 112. ADB technical assistance could be used to help identify the most urgent investments from HVEN’s list of priority projects and to conduct feasibility studies for a smaller subset of priority projects. For example, little information is available on the actual efficiency gains in terms of a reduction in losses, outages, and frequency of voltage fluctuations that will result from these investments. Technical assistance may also be needed to train staff of HVEN and System Operator on how to use and maintain new equipment. 113. In the private sector, ADB’s Private Sector Operations Department (PSOD) can help rehabilitate the privately-owned Sevan-Hrazdan Cascade and provide concessional financing for distribution rehabilitation and upgrades. The Cascade accounts for 17 percent of Armenia’s operating capacity and accounts for 8-12 percent of gross generation. Rehabilitation of the Cascade would increase annual generation by 20 percent and restore the installed capacity of all HPPs in the cascade. Rehabilitation of the Cascade will also improve the safety of nuclear plant operations. Rehabilitation of the Argel HPP, in particular, will improve reliability because the plant provides direct power supply to meet the emergency back-up power needs of the nuclear plant. Rehabilitation of the distribution network will reduce technical and commercial losses thereby reducing operating costs. 114. ADB, in cooperation with EBRD, is conducting negotiations to provide a loan to the private owner of the Sevan-Hrazdan Cascade through ADB’s PSOD. EBRD has an established presence in the energy sector and is the only development partner to have made a major loan to one of the large private companies in the sector and is, therefore, a good partner for ADB’s first private sector project in the energy sector. The PSRC recently approved the company’s investment plans for the next five years, which should reduce regulatory risk for the project. 115. Outcome: i) Hydropower: 125 GWh annual increase in generation from large hydropower plants ii) Transmission and system operations: Lower losses from rehabilitation and modernization of transmission lines and better reliability, including lower outages and lower frequency of voltage fluctuations, from rehabilitation of secondary equipment in substations and expansion of SCADA system. 116. Output: i) Hydropower: Rehabilitation of Sevan-Hrazdan Cascade ii) Transmission and system operations: Rehabilitation of roughly 300 km of 220 kV lines; Rehabilitation of secondary equipment in 8 substations; Reconstruction of Yerevan TPP substation and NPP substation; Expansion of SCADA system to cover 100% of transmission network; Training for

HVEN and System Operator staff to operate and maintain new equipment. Sector Support Area #2: Regional Integration 117. Rationale: Regional integration can help Armenia diversify its energy supply, which is critical to maintaining energy security given Armenia’s lack of domestic resources. If Armenia builds a new nuclear plant, having sufficient export capacity to evacuate excess power will be critical to: i) maintain the stability and reliability of the power system in Armenia and ii) ensure safe operations of the nuclear plant. In this scenario, regional integration can also help achieve the GoA’s objectives of increasing economic competitiveness through export growth. If Armenia does not build a new nuclear plant, the country will be forced to rely on natural gas for roughly 70 percent of generation. Having sufficient import capacity will ensure that Armenia can import cheap, Georgian hydropower to off-set generation from higher cost gas-fired thermal power plants. Specific Measures: ADB can support the GoA’s plans to increase regional trade with Georgia by financing a back-to-back HVDC substation to Georgia, which is needed to accompany the planned 400 kV interconnection line. Financing for the HVDC substation constitutes a significant portion of the investment costs for the interconnection project and the GoA does not yet have financing for this investment. The new line would increase the capacity for exports between Armenia and Georgia from 100 MW to 350-450 MW. A new back-to-back HVDC substation on the 400 kV line would increase system reliability because it would allow the two countries to trade simultaneously instead of in “island” mode. 118. KfW has actively supported the GoA’s objective of building the 400 kV line by conducting several feasibility studies assessing the need for the line. In August 2012, technical consultants hired by KfW presented the results of the most recent feasibility study for the project assessing the feasibility of the 400 kV line with the HVDC substation. 119. KfW has approached ADB about providing additional financing if the GoA decides to move forward with the project based on the results of the feasibility study. KfW has budgeted roughly €20 million for the project; however, the total cost with the HVDC substation is expected to reach US$ 150-200 million. 120. Outcome: Improved supply diversity through more regional trade with Georgia 121. Output: Construction of new 400 kV interconnection and back-to-back HVDC substation Sector Support Area #3: Development of Renewable Energy 122. Rationale: Renewable energy improves energy security by reducing reliance on imported fuels and improving supply diversity. Low feed-in tariffs pose the largest barrier to realization of the existing economically viable potential. Higher feed-in tariffs could stimulate more private sector development. 123. Armenia can reduce the average cost of supply by the increasing capacity utilization of existing plants and timing new plants to come online as additional capacity is needed. Utilization of excess capacity will be critical to reducing the

average cost of supply if a new nuclear plant comes online. In addition to exporting excess capacity, the GoA has indicated interest in developing pumped storage on some of the existing HPPs to help utilize excess capacity during off-peak hours and provide cheap hydropower during peak hours. 124. Renewable energy, particularly small hydro, biomass, and solar, provides smaller amounts of capacity that will not overburden the system with excess capacity before it is needed. Additionally, if Armenia does not secure financing for a new nuclear plant, developing domestic renewable energy will be a key component of improving Armenia’s energy security and reducing reliance on imported gas. 125. Specific measures: ADB is working closely with the World Bank, IFC, and EBRD to develop an investment plan for renewable energy in Armenia under the Scaling-up Renewable Energy Program in Low Income Countries (SREP). The investment plan will focus on attracting private investment into renewable energy sectors that have yet to be developed in Armenia, including: geothermal, wind, biogas, and solar. 126. The Investment Plan is expected to be a launching point for further discussion with GoA regarding next steps for realizing Armenia’s unexploited renewable energy potential. ADB, in coordination with other development partners, can use the results from the Investment Plan to facilitate discussion on: i) how to implement high priority renewable energy projects that the GoA wishes to pursue and ii) what support, including regulatory, financing, or other, may be needed to overcome barriers to private sector participation in non-hydropower renewable energy. 127. In the short-term, ADB could also consider providing additional financing for private sector development of small HPPs. Significant hydropower potential remains unexploited. Additional financing is needed despite the level of private investment and development partner activity in the sector. ADB might consider implementing a financing arrangement similar to those of other development partners, including KfW and EBRD, which have had success providing financing for small HPP development through credit lines with domestic financial institutions. 128. Outcome: Private sector development of domestic renewable energy resources 129. Output: Financing scheme for small HPPs through domestic financing institutions.

4 Energy Sector Road Map and Results Framework Country Sector Outcomes Country Sector Outputs ADB Sector Inputs Outcomes with ADB Targets with Indicators and Outputs with ADB Indicators with Ongoing and Planned Main Outputs Expected Contribution Baselines Contributions Incremental Targets ADB Operations from ADB Interventions . Capacity of renewable . Increased number of . 317 small HPPs Planned Key Activity . Rehabilitation of energy increased from small HPPs operational by Areas Increased use of secondary equipment 186 MW in 2011 to 948 2020 (2011 domestic renewable . New wind, . Renewable Energy in 8 220 kV substations resources MW in 2025* geothermal and baseline: 115) . Large Hydropower . Rehabilitation of . Generation from new biomass generation . 300-400 MW non- . Electricity substations at Yerevan renewable energy becomes operational hydro renewable Transmission TPP and NPP reaches 2,512 GWh by capacity added . Rehabilitation of 300 2020 (2011 baseline: 2.6 Proposed Loans km of 220 kV lines MW) . Transmission . Extension of SCADA . Generation from Improved efficiency . Efficiency of large Efficiency system for System existing renewable . Generation from of existing HPPs improved Improvement Operator energy increased from existing large HPPs infrastructure . Transmission losses . Renewable Energy . Loans and project 2,074 GWh in 2011 to increased to 2,000 reduced Development preparatory support 2,457 GWh GWh in 2025 (2009 . Large HPP for renewable energy . System losses reduced baseline: 1,640 Improvement (PSOD) projects provided via from 12.7% to 7-8% GWh) local financial . Transmission losses institutions reduced from 1.9% Proposed TA . Rehabilitation of in 2011 to 1.0% . PPTA for Sevan-Hrazdan Increased . Cross-border . Cross-border Transmission . Regional trade with Cascade diversification of capacity with capacity with Efficiency Georgia increased from . Construction of 400 kV energy supply Georgia increased Georgia increased Improvement 117.4 GWh in 2011 to as substation at Hrazdan through regional to 350-450 MW by . TA for RE much as 4,500 GWh in TPP with HVDC integration 2015 (2010 Development 2015 substation baseline: 100 MW) *Excludes large HPPs