Kyrgyzstan’s power sector is relatively small with total generating capacity of around 3.9 gigawatts, producing around 15.4 terawatt-hours (TWh) in 2020. Hydroelectric plants dominate the sector, representing 78% of total generating capacity. The remaining generating capacity is largely provided by thermal CHP plants serving the main population centres. The sector’s heavy dependence on hydroelectric plants is reflected in domestic power production levels, with hydropower typically representing around 90% of Kyrgyzstan’s annual power output during normal hydrological periods. The figure below shows current generating capacity and recent trends in power production in Kyrgyzstan.

High dependence on hydropower raises concerns about maintaining the reliability of electricity supply and power system resilience during periods of water shortage. For instance, the power production trends presented in the figure below reflect the impact of water shortages on hydropower production during the last major water scarcity event in 2015 and 2016. During this period, average hydropower production fell to around 11 300 gigawatt-hours (GWh) per year, representing a fall of nearly 1 800 GWh (13.6%) compared with the ten-year average, with most of the production loss experienced during the winter months of 2015 and 2016.1

As a result, Kyrgyzstan experienced significant power shortfalls and rolling blackouts during the winter peak heating seasons in 2015 and 2016. Power shortages also led to substantial increases in relatively expensive power imports and increasing power production from Bishkek’s CHP plant during the winter period for the duration of this event, placing additional financial pressure on an already cash-strapped sector.2

Reliability and resilience risks are magnified by the age and relative fragility of Kyrgyzstan’s electricity infrastructure, as shown in the figure below. The vast majority of the hydroelectric fleet is well over 30 years old, with a weighted average age of over 40 years and nearly 80% of its capital depreciated. Network infrastructure is also relatively old, with over one-third of all transmission lines depreciated and nearly 70% of the substations depreciated. Distribution assets are in similar condition, with depreciation of distribution lines and substations averaging around 60% and 80% respectively.3

High levels of depreciation are typically reflected in higher operating costs, higher rates of unplanned outages and higher network losses. The government reported that over 4 600 supply disruptions were recorded in the distribution system in 2019.4 The World Bank also notes evidence of unplanned infrastructure outages resulting from operating old and under‑maintained assets, which served to exacerbate power system security challenges arising from water shortages experienced during the 2015 and 2016 winter peak seasons.5 And the International Monetary Fund recently observed that old and unreliable power infrastructure had added considerable cost for private-sector power consumers in Kyrgyzstan, with economic losses representing around 4% of annual sales.6

Although the government reports significant reductions in distribution network losses over the last five years, they still remain relatively high by international standards with annual average losses of 12.3% recorded across the four distribution companies in 2019.7 This figure is likely to significantly mask seasonal variability. For instance, on average over 75% of the losses in 2020 were recorded during the winter months,8 with average distribution network losses around 14.4% over this period. Winter network losses across the four distribution businesses ranged from 12.8% to 17.0% in 2020.9 These differences are likely to be largely explained by increasing rates of economic loss associated with the winter peak heating season rather than technical losses. However, this seasonal variability suggests that losses may be more significant from an electricity security perspective during winter periods when they are more likely to coincide with water shortages that jeopardise hydropower production.

The combination of hydro dependence and ageing electricity infrastructure greatly increases Kyrgyzstan’s exposure to potential power supply shortages and power system failures, especially when the power system is under additional stress during periods of water scarcity.

These risks are compounded by rapidly increasing demand for electricity, especially in the residential sector, which is a key driver of growing power demand during the peak winter season. The figure below shows that in 2020, the residential sector dominated power use, accounting for 76% of total final electricity consumption. The industrial sector was the next-largest electricity consumer in 2019, accounting for around 12% of total final electricity consumption. In 2020, around two-thirds of annual electricity consumption occurred during the winter period for all consumer classes except the agricultural sector, reflecting growing use of electricity for space heating, especially among residential consumers.10

Total final consumption of electricity grew by 72% between 2010 and 2020, to around 12 260 GWh. The figure below confirms that rapid growth in residential electricity consumption was the primary contributor to growing power consumption over the period. Residential electricity consumption grew by nearly 170% between 2010 and 2020, to 9 320 GWh. By contrast, trends in electricity demand among the other consuming sectors were variable and subdued, exhibiting little or no growth over the period.

These trends have implications for pursuing power sector reliability and resilience. Residential power consumption is the key driver of growing power demand during the peak winter season, which is also the most likely period for water shortages to jeopardise the reliability of hydropower production. This suggests some potential priorities for power system security policies, in particular, for demand-side management programmes seeking to reduce power use during future power shortages.

Rapid growth in residential consumption has been driven by regulated electricity prices which have been set well below the cost of production. The impact of regulated price movements on consumption can be seen in the figure below, which reflects a significant positive correlation between changes in consumption patterns and changes in regulated tariffs over the period.11 This suggests that Kyrgyz electricity demand is responsive to changes in regulated tariffs. Consumption trends also suggest that the ongoing process of increasing electricity tariffs towards cost-reflective levels would help to moderate the rate of growth in electricity consumption while encouraging greater energy efficiency and ongoing energy savings. This suggests that expediting the tariff reform programme could make a significant positive contribution towards improving power sector reliability and resilience in the present and into the future.

However, electricity prices for the majority of consumption are currently set at levels well below the cost of production, as shown in the figure below. In particular, residential tariffs for the “up to 700 kWh” consumption block have remained unchanged since 2015, despite several policy announcements incorporating tariff increases for this consumption block over recent years.12 The International Monetary Fund has concluded that the current subsidy regime is highly inefficient and poorly targeted, with nearly half of the electricity, district heating and hot water subsidies going to the richest 30% of households, while the bottom 30% receive barely 20% of the subsidies.13

Residential consumption represents approximately 70% of the electricity load, and the majority of that consumption falls within the “up to 700 kWh” pricing block, which is among the most heavily subsided consumption categories.14 Although commercial and industrial consumers and large-volume residential consumers are paying well over a cost-reflective price for their consumption, the total revenue generated through this cross-subsidy is insufficient to offset the total revenue lost through subsidising the “up to 700 kWh” pricing block.15

Accordingly, the power sector is operating in a financially unsustainable manner that is unable to generate sufficient cash flow to fund necessary maintenance and refurbishment, or to finance new investment in a timely and efficient manner. This has been reflected in dangerously low levels of maintenance and investment, and increasing reliance on foreign grants and project funding from international financial institutions to undertake critical refurbishment and sector modernisation over the last two decades. As a result, the nature, scope and pace of electricity sector modernisation have been constrained, further eroding power sector reliability and resilience over time.

Financial unsustainability is also reflected in ballooning sector deficits, as highlighted in the figure below, which shows the results of modelling undertaken by the World Bank.

World Bank analysis indicates that the electricity sector deficit is likely to increase from around KGS 3 billion (Kyrgyzstani soms) in 2020 to more than KGS 12 billion by 2025 (approximately USD 150 million), assuming no change to current tariffs and no new capital expenditure. Given government ownership of the sector and its level of financial distress, it is likely that any additional debt ultimately will be transferred to the budget.

However, public investment in the power sector is already considerable. International Monetary Fund analysis suggests that electricity sector debt had reached almost 20% of GDP and around 32% of overall public debt in 2016. Loan repayments are projected to continue increasing and to exceed 1% of GDP on average between 2019 and 2023.16 Similarly, the latest World Bank analysis suggests that the energy sector’s cumulative debt has reached KGS 103.3 billion, and is likely to remain steady at around 18% of GDP. At the same time, the loan repayment schedule is forecast to quadruple between 2018 and 2025 before plateauing, assuming no additional debt is incurred.17 The government’s potential to further invest in the sector is likely to be limited by financial constraints and competing policy priorities, placing a substantial financial constraint on public funding of power sector debt and modernisation going forward.

Increasing residential tariffs to cost-reflective levels offers the only viable option for permanently addressing the sector’s cash flow crisis. In 2015, electricity consumption represented between 2.3% and 2.6% of total household expenditure, which was one of the lowest levels recorded in the region.18 In principle, this suggests that most residential consumers may have the financial capacity to pay more cost-reflective tariffs, and that the transition towards cost-reflective tariffs could proceed relatively quickly. However, in practice, increasing electricity prices to cost-reflective levels is unlikely to be feasible in the short term, reflecting limited consumer willingness to pay and likely high community resistance.19 Residential tariff reform has become a highly sensitive political issue, which has resulted in slow and limited action over a long period. Government and regulatory reluctance to address this challenge is reflected in the current Medium-Term Tariff Policy, which envisages no change to the residential “up to 700 kWh” pricing block before 2023.20

Increasing power exchanges through the Central Asian Power System (CAPS) offer considerable potential to help alleviate Kyrgyzstan’s growing power system reliability, resilience and imbalance issues in a timely, proven and cost-effective manner. In particular, greater regional integration could expand the reserves available to help improve Kyrgyzstan’s power system reliability and resilience during periods of water shortage, especially those occurring during winter peak periods, while also providing opportunities for regional electricity exchanges to help address its deteriorating supply-demand balance over time. CAPS was originally designed to operate in an integrated manner across the region, with a view to maximising the potential benefits from an economic and electric reliability perspective for all regional participants.21

However, integrated operation of CAPS has greatly decreased since the member jurisdictions gained their independence and began pursuing electricity security objectives based on greater “self-sufficiency” and “self-reliance”, reflecting growing regional uncertainty and mistrust, and a range of disparate policy objectives. This fundamental shift is reflected in changing patterns of electricity trade, as shown in the figure below.

Kyrgyz electricity exports declined substantially over the period, falling from an average of around 25% of total final electricity consumption between 2010 and 2012 to an average of less than 4% of total final electricity consumption between 2014 and 2020. Falling exports over the period have substantially reduced cash flows into the power sector, which has exacerbated the financial instability jeopardising efficient and reliable sector operation and development. At the same time, electricity imports remained low, averaging around 2% of total final electricity consumption over the period. These trends reflect increasing reliance on national operation and management of power systems and electricity supply.

Greater reliance on national operation has exposed inherent weaknesses within the Kyrgyz power system that have the potential to magnify power system security and reliability challenges, especially during periods of water scarcity, while also greatly increasing related management costs. Recent efforts to rebuild regional electricity trade have been led by a number of major infrastructure and technical projects being undertaken with the support of international partners.22 However, various political, economic and infrastructure constraints across the region are likely to limit and slow the realisation of these objectives in practice.

The combination of these factors places Kyrgyzstan’s electricity sector in a precarious position. As a result, Kyrgyzstan’s power services are likely to become less and less reliable and resilient over time, jeopardising power system security. At the same time, if power consumption continues to grow at current rates without corresponding sector investment, it is increasingly likely that the national electricity system will no longer be able to meet demand by the end of the decade at the latest, raising fundamental system adequacy concerns which are likely to worsen considerably over the medium to long term.23