IEA (2023), Armenia energy profile, IEA, Paris https://www.iea.org/reports/armenia-energy-profile, License: CC BY 4.0
Armenia has no proven reserves of natural gas or oil, and hard coal deposits are a modest 154 Mt, with resources of 163 Mt and further potential of 317 Mt. It has six known coalfields and some shale oil deposits, but the economic viability of mining these deposits has not been determined. There is currently no coal or shale oil production in the country.
Given its more than 400 mostly small, steep mountain rivers of at least 10 km in length, Armenia’s small hydropower potential is significant. Although small hydro has been the focus of considerable development in recent years, the government is also assessing the potential for other forms of renewable energy.
Armenia’s energy security has greatly improved since the gas and power supply crisis in the early to mid-1990s. During the crisis, energy sector management was dysfunctional, losses were extremely high, and the collection rate was below 50%. This resulted in acute supply shortages, with households receiving only a few hours of power per day. Since then, increased natural gas heating, investment in new generation capacity and the network, and improved operational management have restored consistent and uninterrupted supplies of electricity and gas.
Electricity and gas demand are expected to continue growing as living standards rise and poverty is reduced. Significant investment will be needed to meet these rising energy needs, as large portions of the electricity and gas networks date to the Soviet era, and infrastructure modernisation is needed to maintain and improve supply reliability. In its Energy Security Concept, the government estimates approximately 1 000 MW will be retired by 2026, so new investments will be required to satisfy growing demand if the country does not want to become even more reliant on imports. The proposed new 1 000‑MW nuclear plant accounts for planned new capacity, but financing has not been secured.
The sustainability and reduced import dependency offered by renewable energy makes its increased contribution (66% by 2036) a priority, with additional capacities of 191 MW of hydro (small and large), 500 MW of wind and 950 MW of solar PV required to meet this target. According to the government, small hydro capacity was 380 MW in 2020, and 50 MW was planned or under construction.
In electricity, regional integration and supply diversity are advancing, with a 400‑kV double-circuit high-voltage interconnection with Iran under construction as well as a high-voltage interconnection with Georgia with back-to-back high-voltage direct current connection. These interconnections will strengthen regional integration, expand the market and improve supply reliability, and could serve as additional sources of electricity during shortages.
Energy system reliability in Armenia is now considered adequate, as investments in electricity and gas infrastructure, increased residential access to gas and operational improvements since the mid-1990s have led to significant declines in outages and losses.
Network losses in both the gas and electricity sectors are in line with international standards. In the gas sector in 2021, transmission losses were 2.68% and distribution system losses 1.18%; losses are kept relatively low by modern metering devices and a supervisory control and data acquisition system.
Closed joint-stock company (CJSC) Electric Networks of Armenia (ENA) has been installing automated metering and data acquisition systems in the 110/35‑kV portions of the network since 2003 to improve operations and monitoring, and in 2021 electricity transmission losses amounted to 1.43% while distribution losses were 6.03%.
There have also been significant developments in the use of natural gas vehicles (NGVs); in fact, Armenia is one of the leading countries in transport sector natural gas use. The benefits of NGVs are both economic and environmental, owing to their low GHG emissions. At the beginning of 2022, more than 80% of vehicles in Armenia were running on natural gas and the country had 358 gas-charging stations.
As Armenia has switched to mainly natural gas consumption across multiple sectors, potential for further fuel switching is minimal. Residential heating and transport rely heavily on natural gas, as mentioned above. However, the development of renewable energy sources, particularly solar, could allow for switching to renewable electricity in both heating and transport in the future. Solar energy is a cost-effective choice and there is strong potential for future investment, as outlined above.
Emergency response in relation to nuclear power has received increased attention since the Fukushima accident in 2011. Armenia is a party to the Non‑Proliferation Treaty, has an Additional Protocol with the International Atomic Energy Agency (IAEA) and has ratified the Comprehensive Nuclear Test Ban Treaty. In 2011, the IAEA inspected its nuclear power station for operational safety, deeming the plant acceptable.
Armenia also works closely with the United States in managing nuclear safety. In 2013, the US National Nuclear Security Administration (NNSA) conducted two emergency response training sessions in Armenia, with 28 participants from relevant authorities, civil protection agencies and other specialised parties. The NNSA also provides direct emergency management assistance to Armenia and other countries.
Also in 2013, Armenia signed an agreement with Belarus on information exchange and co‑operation in nuclear safety and radiation protection. Belarus commissioned its first nuclear power plant (NPP) in 2021, and a number of activities were carried out within the framework of Armenia’s agreement to assist Belarus.
According to a 2008 Energy Charter report, Armenia’s oil product storage facilities are of adequate capacity, as requirements far exceed annual consumption. Up to 1.2 Mt of light oil products and 0.9 Mt of fuel oil can be stored, but most depots do not comply with modern standards and many need repairs. Meanwhile, upgrades to the Abovyan underground gas storage facility in 2012 doubled its capacity to 135 mcm.
Armenia is not under any international obligation to hold oil stocks. Requirements are legislated by the former Soviet laws, and most of the time stock availability is determined by the country’s financial situation rather than by strict adherence to the legislation.
From 2002 to 2009, Armenia reduced the share of fuelwood- and electricity-based heating in multi‑apartment residential buildings from 90% to 26% and increased gas-based heating from 13% to 71%.
The switch to more efficient and affordable heating was driven by key activities of the government’s Urban Heating Strategy (UHS) and was financed by donor support. In 2001, urban households relied almost entirely on fuelwood and electricity for heating, so in 2002 the government adopted the UHS as a first step towards efficient, clean, safe and affordable heating.
The UHS provided a strategic framework for short-, medium- and long-term development of an affordable and environmentally sustainable urban heating sector. The key factors motivating the rapid switch of urban households to gas-based heating (primarily individual gas boilers) were an improved legal and regulatory framework to support the introduction of gas-based heating; mobilisation of the private sector to provide heat supply equipment and services; financing for consumers to invest in heat supply systems and capital grants for the poor for gas service connection; and rapidly expanding access to gas throughout the country (see Tajikistan’s Winter Energy Crisis, p. 13, Box 2.4, Fuel Switching in Armenia).
Installed generation capacity is 4 147.2 MW, but available capacity is lower (2 878.7 MW) due to the age and condition of plants: approximately 50% of Armenia’s capacity is more than 40 years old. The Yerevan thermal power plant was retired in 2010, and the government plans to retire the oldest units of the Hrazdan plant in 2023. Significant investment will therefore be needed to modernise power system assets over the next 10 to 20 years.
Baseload electricity is produced from the 407‑MW Armenian Nuclear Power Plant (ANPP). The plant was scheduled for retirement by 2016, but its service life has been extended by ten years because of insufficient replacement capacity. Approximately USD 300 million was invested to keep the reactor operating until 2026, and rehabilitation has been completed. Securing financing for the new 1 000‑MW replacement plant remains a challenge, so the government intends to continue operating the existing plant until at least 2036, which will require an additional investment of USD 150 million according to forecasts.
Output from thermal power plants covers demand at peak periods and baseload power generation when the nuclear plant is offline for maintenance. Part of the electricity generated by the Hrazdan‑5 Unit, and all the electricity generated by the Yerevan combined-cycle gas turbine plant, is exported under the gas-for-electricity barter agreement with Iran.
Hydropower (including small hydro) from the Hrazdan and Vorotan rivers and from other dams is a stable component of Armenia’s electricity system and provides daily load regulation with installed capacity of 1 345.6 MW.
Construction of the Megri HPP (110 MW) has been postponed with no exact commissioning date. Contracted and financed by Iran, it will be operated by Iran for 15 years and then ownership will be transferred to Armenia under the build-own-operate-transfer model.
At just 4.23 MW, wind power is a relative newcomer in Armenia’s power supply system.
Government policy to enhance energy security in the power sector is directed towards strengthening regional integration to increase trade flows. For instance, during the spring and summer when hydropower generation is high, Armenia could increase exports of electricity to Georgia, which could subsequently pass it on to the Turkish market because Georgia often has surplus electricity during the summer. Alternatively, Georgia could supply Armenia with low-cost electricity from hydropower when markets are favourable. In addition, when Armenia’s new NPP is operational, it may offer further trade opportunities. More electricity trade would lead to opening of the market and greater competition in the Armenian electricity sector.
Armenia’s electricity network has several cross-border linkages including connections to Georgia and Iran. Electricity trading is currently limited, however, as Georgia and Armenia have asynchronous systems and Armenia’s market is mostly closed. Electricity trade with Iran is based on a barter agreement, whereby much of the gas imported from Iran is used in power generation at the Yerevan power plant, which in turn exports the power to Iran. According to the PSRC, in 2021 Iran bartered around 0.3446 bcm of gas for 1.034 TWh of Armenian electricity. Interconnections with Azerbaijan and Türkiye exist but are not active.
A 65‑km, 220‑kV line and 54.8 km of 110‑kV lines connect Armenia with Georgia. The governments of Armenia and Georgia are co‑operating to build a 400‑kV interconnection: in 2012, the utilities in both countries signed an agreement for parallel operation of their power systems, including the organisation of operational dispatch management and a contract for power supply in emergency situations. The feasibility study was completed in 2013 and construction began in 2017.
Collaboration with Iran on electricity market integration focuses on fully developing the existing interconnection via over 80 km of 220‑kV transmission lines and a new 400‑kV line. With construction beginning in 2017, the interconnection is expected to be operational by 2023. In the long term, Armenia plans to be actively involved in developing a Black Sea power ring and north-south synchronised operation relations (involving Armenia, Georgia, Iran, Russia and other countries). Armenia also has idle connections with Azerbaijan and Türkiye.
Because much of the electricity network is old and inefficient, significant investment in rehabilitation is needed. Grid infrastructure improvements are carried out as part of government-authorised programmes supported by loans from international donors and investment programmes of individual utilities approved by the PSRC. Five substations have been completely reconstructed in recent years with support from the World Bank and Germany’s Kreditanstalt für Wiederaufbau (Credit Institute for Reconstruction, KfW), and five others were under reconstruction in 2021.
Armenia’s electricity market operates under the single-buyer model and includes six large generation companies (private and state-owned), more than 205 small power producers and one transmission system operator (TSO). Generation and transmission operations are unbundled.
There is no competitive wholesale electricity market. The one distribution system operator has the exclusive right to buy electricity from the generators at regulated prices and to sell to final consumers.
The state-owned power system operator is the TSO and is financially and legally unbundled. At the wholesale level, the state-owned CJSC Settlement Centre provides control and metering services and CJSC High-Voltage Electric Networks is the state owner and operator of the transmission network. ENA is the only retailer in the country, and it is owned by the open joint-stock company Inter-RAO UES.
The government amended the Law on Energy in 2017 to encourage greater market liberalisation. Changes will be phased in, and during the transition a hybrid model will continue to prevail. Energy supplies will be guaranteed based on existing power purchase agreements, and generators selling on the market will be obligated to pay electricity networks for distribution only. New amendments to the law also aim to create competition among electricity suppliers, which will reduce ENA’s control over distribution throughout the country.
Changes to this law will also allow consumers to purchase electricity from other suppliers. Large wholesale consumers will be able to enter the market to purchase and consume electricity generated outside Armenia. Mechanisms to implement the amendments went into gradual effect on 1 February 2022, and in the first stage, qualified customers are being given the right to choose their supplier.
The natural gas sector is owned and operated by one vertically integrated operator, Gazprom Armenia (previously ArmRusGazprom). Since January 2014, it has been fully owned by Russia’s Gazprom, which purchased the Armenian government’s remaining 20% share. This deal forgave ArmRusGaz’s debts to Gazprom and reduced the price of gas from USD 270 per 1 000 m3 to USD 150 per 1 000 m3. The current gas price from Russia is USD 165 per 1 000 m3 at the border. No unbundling or opening of the market is envisaged.
The gas transmission network comprises 1 683 km of pipelines, a Soviet-era connection with Russia through Georgia, and a 2.3‑bcm connection with Iran built in 2009 to barter gas imports for electricity. An additional pipeline connection with Azerbaijan exists but is not in operation.
The gas distribution network includes 19 350 km of high-, medium- and low-pressure gas pipelines delivering to about 737 000 customers. Gazprom Armenia has spent approximately USD 900 million since 2007 on large projects to increase consumer access to gas, boosting the connection rate from 20% in 2002 to 96% in 2021. It also rehabilitated the Abovyan underground gas storage facility, almost doubling its capacity to 135 mcm in 2016, and invested USD 215 million in a new gas unit at the Hrazdan‑5 power station, which began operations in March 2013.
Nearly all gas consumed in Armenia is imported from Russia by pipeline through Georgia. Metering of the gas is carried out on Georgian territory, but import controls are done in Armenia. The National Agency of Georgia, responsible for standards, technical regulations and measurements, carries out annual metrological controls and supervises gas metering.
The oil product market is completely privatised, and prices are based on demand and supply.
ANPP is a government-owned company. Commissioned in 1980, its operating capacity is 385 MW (installed capacity is 440 MW); annual generation is approximately 2 400 GWh, covering 37% of domestic supply. The plant’s USD 300‑million rehabilitation in 2017-2018 to extend its service lifetime to 2026 has been fully implemented. The government intends to operate the existing ANPP until at least 2036, requiring an additional USD 150‑million investment according to forecasts.