WEO Week: How can social and economic dimensions be core elements of transitions?

Report extract

Market design

National market structure

Ukraine’s electricity sector is comprised of separate generation, wholesale market, transmission system operation, distribution and supply entities.

The wholesale electricity market (WEM), created in 1996, was operated by the state-owned company Energorynok as a sole wholesale trader under a single-buyer model from 2000 to mid-2019; it also acted as a settlement centre for all payments until July 2019. To meet its Association Agreement commitment to implement the EU Third Energy Package, Ukraine successfully switched from single-buyer model to one with a more competitive power market structure consisting of bilateral contracts, day-ahead, intraday, balancing and ancillary services markets in July 2019.

UkrEnergo, Ukraine’s state-owned national electricity company, owns and operates the United Energy System of Ukraine (UES), including transmission networks and interconnections with neighbouring countries. UkrEnergo also provides technical and information support to Energorynok.

The electricity sector has undergone several stages of reform: it was mostly unbundled and partially privatised in the 1990s, while state-owned assets were consolidated in 2004. Most thermal generation plants have been partially or fully privatised, with the private company DTEK controlling the bulk of the market. In 1995, regional distribution and retail companies (oblenergos) were created, one for each administrative region. As a part of electricity market reforms and to ensure retail market competition, Ukraine enforced the unbundling of oblenergos into distribution system operators (DSOs) and electricity supply companies. Since 1995 there have been several rounds of privatisation, so that most DSOs and electricity supply companies are now privately owned by domestic or foreign investors. Ukrenergoatom is the state-owned operator of nuclear power plants.

State-owned NJSC NaftoGaz, subordinated to the cabinet of ministers, is the largest company in Ukraine. Until January 2020 it was a vertically integrated company engaged in the full cycle of gas and oil exploration operations: drilling, development and production; transport, refining and storage; and supplying natural gas and liquefied petroleum gas (LPG) to consumers. However, to meet the requirements of the EU Third Energy Package, Ukraine unbundled Naftogaz by transferring the Gas Transmission System Operator of Ukraine (GTSOU) from NaftoGaz to state-owned Main Gas Pipelines of Ukraine. 

GTSOU operates the gas transmission trunk lines but Naftogaz continues to operate the gas storage facilities since unbundling. Regional gas distribution and supply companies (oblgazes) hold permits from UkrTransGaz to transport gas through main and regional transmission pipelines and are responsible for gas distribution.

State participation in oil and gas exploration and production activities is carried out by NJSC Nadra Ukrayny, which conducts geological surveys, provides resource and economic estimates and enters into joint-venture agreements with private investors. NaftoGaz and its 11 subsidiaries hold the largest share of all oil and natural gas produced in Ukraine. UkrGazVydobyvannya is the company affiliated with NaftoGaz responsible for gas production and LPG/compressed natural gas (CNG) production; it extracts about 15 bcm/y, or 75% of total production. Gas production of the numerous independent oil and gas producers operating in Ukraine has been increasing steadily, to make up 22% of total production in 2017. UkrTransNafta, another subsidiary of NaftoGaz, operates the oil pipeline system. In theory state-owned, but in practice controlled by a private company, UkrNafta is the main oil producer and also produces a small amount of gas. 

Endowed with considerable coal resources, most of Ukraine’s mines are in the Donbass region. Of Ukraine’s approximately 300 mines, many profitable ones have been either privatised or transferred to long-run concessions, predominantly by DTEK. The remaining mines, requiring subsidisation, remain in the ownership of state-controlled companies. Ukraine’s largest mining region in the east has been severely affected by the recent political instability and, furthermore, hundreds of illegal (often smaller) mines are operating in the region.

Nuclear energy was responsible for roughly 54% of Ukraine’s electricity production in 2019. Net nuclear capacity is 13.1 GW (13.8 GW gross capacity) or 28% of Ukraine’s installed electrical capacity, supplied by 15 Soviet-designed VVER reactors in four nuclear power plants: two 440‑MW V-213 models and 13 1 000‑MW units, of which 11 are V-320 models and two are older V-302 and V-338 models. Zaporizhia is Europe’s largest nuclear power plant at a net capacity of 5.7 GW (6 GW gross). All of Ukraine’s operating nuclear plants are owned and operated by Energoatom, which also operates small hydro and pumped-storage power plants used for load-following.

Ukraine’s power system lacks load-balancing capabilities: instead, baseload coal power plants are used for this purpose. Insufficient transmission capacity also limits the output of some nuclear plants. Long-term operation of the existing reactors is a cornerstone of the nuclear energy programme, so it is concerning that most reactors are reaching the end of their original design lifetimes in 2020. Rivne Units 1 and 2 have already received a licence to operate for an additional 20 years with a mandatory safety reassessment after 10.

Large hydro provided about 5% of electricity generation in 2019. The nine large hydropower stations on the Dnieper and Dniester rivers (total installed capacity of 5.9 GW) are all operated by state-owned UkrHydroEnergo. Hydro generation is important for electricity system stability because it provides peak-load supplies, regulates the frequency and capacity of the system, and offers the emergency reserves that outdated fossil-fuelled power plants are unable to guarantee. In 2016, the government approved a programme for hydropower development aimed at increasing installed generation capacity by 3.3 GW and raising hydro’s share in electricity generation to 15.5% by 2026 ( There are currently no plans to privatise UkrHydroEnergo.

Renewable energy accounted for 4.6% of TPES in 2018: 3.4% biofuels and waste, 1% hydro and 0.2% other renewable power. Ukraine experienced a renewable power deployment boom in 2018-19. The share of renewable power in the electricity generation mix increased by 3.6 times – from 1% in 2015 to 3.6% in 2019. According to MEEP projections, the renewables share will increase further to 6.8% or 10 284 gigawatt hours (GWh) in 2020. Despite Ukraine’s low share of renewables in TPES compared with European Union (30% in 2018), it has significant technical potential for further RES development. The economic feasibility of developing this potential, however, depends on factors such as fossil fuel prices, technology availability and public support.

Until recently, other fuels could not compete with highly subsidised natural gas in the residential heating sector. However, the government’s decision in 2016 to completely phase out price subsidies makes heat produced from renewables fully competitive with heat produced from natural gas and provides considerable opportunities for biomass use, especially in the heating sector.

The comprehensive 2011 study “Energy Potential of Biomass in Ukraine” by Lakyda et al. found that the technical potential of forest biomass is 2.1 Mtoe and that of agricultural waste is 12 Mtoe, based on 2008 data. The Biomass Centre estimates that the sizeable agricultural waste generated by Ukraine’s agriculture sector could produce enough biogas to replace 2.6 bcm of natural gas per year, and with agricultural expansion biogas potential could grow to the equivalent of 7.7 bcm of natural gas. It is estimated that organic matter from livestock could support 4 000 biogas installations.

The SAEE under MEEP is responsible for renewables development. 

Ukraine has enormous untapped energy efficiency potential: although end-use data are still limited, current indications are that energy efficiency potential is greatest in industry (34% of the total), the residential sector (33%) and energy transformation at coal-fired power plants (22%). “Energy Efficiency Monitoring for Ukraine” (Dodonov, 2016) claims that by implementing comprehensive and effective policies that reduce sector and industry energy intensity to EU levels, Ukraine could save up to 27.1 Mtoe or 29.9 bcm of natural gas, based on figures for 2014.

MEEP has been the main state authority responsible for efficient energy use, energy savings and renewable energy since 2019, and the SAEE under MEEP is the central governmental body charged with advancing energy efficiency and renewable energy developments, and promoting the deployment of energy-efficient and renewable energy technologies.

Donor support for implementing energy efficiency measures in Ukraine is considerable: numerous international financing institutions (IFIs) such as the World Bank Group, the EBRD, the European Investment Bank (EIB), the KfW, the US Agency for International Development (USAID) and the Global Climate Partnership Fund are active in Ukraine. According to Minregion, several projects of the World Bank (including District Heating Energy Efficiency), the KfW and the EIB in 2016 alone amounted to USD 1.4 billion (

However, successful project implementation requires that Ukraine improve project management. According to former World Bank Country Director in Ukraine Qimiao Fan, the investment portfolio disbursement ratio has declined by three times in recent years to just 10% ( The World Bank estimated the overall risk of implementing its District Heating Energy Efficiency project launched in 2014 as “substantial,” while progress was ranked as “moderately unsatisfactory” in April 2018 ( 

Regulatory framework

State entities dominate oil, gas and electricity provision in Ukraine. The energy market has been designed to maintain state dominance and to subsidise household and public sector energy consumption. The challenge is to design and implement an effective regulatory framework that increases competition, strengthens the efficiency of markets and is attractive to investors. Third-party access, greater market transparency and strong and fair regulatory oversight are key in this regard.

Until July 2019 the electricity market was organised on a single-buyer model. Hydro, nuclear, co‑generation and renewables generators were paid fixed prices set by the National Energy and Utilities Regulation Commission, while thermal plants competed for the remaining demand in an energy-only market. The regulator set a cap for the thermal marginal price and generator bids were above the cap for some hours; the regulator then calculated the weighted average price and added transportation and other costs (including the cross-subsidy) to arrive at a final price paid by non-residential customers. Prices paid to generators could also include an “investment component” for NKREKP-approved investment projects. Generator bids were assessed by the market operator Energorynok for alignment with its estimates of variable costs.

The wholesale price formation mechanism was based on the weighted average price of generation calculated from the competitive marginal price of thermal plants, subsidised prices for households and feed-in tariffs of other technologies.

In April 2017 the parliament adopted the new Electricity Market Law to meet the requirements of the EU Third Energy Package and join ENTSO-E. The law stipulated that the single-buyer model of market operations be replaced by bilateral contracts. Accordingly, the electricity market was divided into a bilateral contracts market, a day-ahead market, an intra-day market, a balancing market and an ancillary services market. The new market model was launched in July 2019, as scheduled under the law. Energorynok was restructured into three companies: a guaranteed buyer (a state-owned trader that buys electricity from producers under feed-in tariffs and sells this electricity on the organised day-ahead and intraday markets), a market operator (responsible for organising trading on the day-ahead and intra-day markets) and Energorynok (responsible for dealing with outstanding debts). The TSO, Ukrenergo, was assigned the roles of commercial metering administrator and settlements administrator.

The wholesale pricing mechanism of the day-ahead market is the marginal price balancing supply and demand; all generators must provide balancing services in volumes of available capacity. The ancillary market is at the developmental stage, and no services have been procured because there are no qualified ancillary service providers registered with the TSO. 

The Law on the Natural Gas Market transposing the Third Energy Package was adopted by the parliament in March 2015. This is a major step in reforming Ukraine’s gas market and NaftoGaz, and in adopting Third Energy Package regulations.

The only gas price Ukrainian legislation regulates is that of gas used as a commodity supplied to households and used by district heating companies to produce heat; all other commercial and public consumers may buy natural gas directly from any trader. The size of the regulated market in terms of natural gas consumed was 53% of consumption in 2017.

The Law on the Natural Gas Market prescribed full gas market liberalisation, including for households, by 1 April 2017, but this milestone was postponed to 1 May 2020. The government raised residential natural gas tariffs by 8.4 times and district heating by 4.6 times between 2014 and May 2016 in nominal terms (in real terms the increases are about half as much). Gas price subsidies for households were also phased out in May 2016 after the government aligned regulated prices with import parity; however, residential gas prices were again substantially below import parity (by about 49%) in July 2018 following gas price increases on the European market and further devaluation of Ukraine’s national currency. In 2019 Ukraine benefited from price drops in the European market and regulated prices had returned to the full costs of supply by mid-2019.

There is no real market for steam coal. One company, DTEK, owns most coal production and coal-fired power plant capacities; most coal is therefore not traded on the market and the price for steam coal is regulated by NKREKP. The coking coal market differs because there is a scarcity of high-quality coking coal in Ukraine, so Ukrainian steel mills must import it and blend it with domestic coking coal. The price is determined by the market rather than being regulated.

Despite the commitment of the parliament and the government in the coalition agreement of November 2014 to phase out all coal subsidies and close ineffective mines, subsidies for producers increased substantially after the NKREKP adopted the new Rotterdam+ price methodology for steam coal in 2016. The price of steam coal for coal-fired power plants was pegged to the API2 coal index in Rotterdam, and then transportation and freight costs from Rotterdam to Ukrainian ports were added on top; this methodology resulted in a substantial rise in the price of Ukrainian coal. As this is the price that would prevail in a free, competitive market, it must be considered equivalent to a subsidy for coal producers ( According to the regulator, the reference price for steam coal in December 2017 was calculated at an average API2 for 12 months (USD 83.08/t) + freight costs (USD 12.21/t) + port transshipment costs (USD 7.02/t) ( Because shipment costs to Black Sea ports and north-western Europe differ by only USD 3-5/t, the transportation cost component of the tariff is the additional rent (about USD 14-16/t) for Ukrainian producers, mostly for the vertically integrated company DTEK that produces most of the steam coal in Ukraine and owns the bulk of coal-fired plants.

In addition, although the NKREKP corrects for the lower calorific value of Ukrainian coal compared with that assumed for API2 index calculations, its very high sulphur (2‑2.5%) and ash content (signs of lower quality that make Ukrainian coal illiquid in the European market) remain unaccounted for in the formula. Applying typical discounts for excess ash and sulphur above the API2 benchmark yields an additional discount of USD 8.5/t on the price of Ukrainian steam coal. Thus, the total producer subsidy per tonne of 6 000 kcal/kg steam coal is estimated at USD 22.5-24.5/t, while the annual rent for coal suppliers is estimated at USD 490-533 million.

As a result of inflated thermal coal prices, the price of electricity supplied by coal-fired plants to the wholesale market increased 62.3%, from UAH 978 per megawatt hour (/MWh) in December 2015 to UAH 1 587/MWh in April 2018 ( However, state-owned mines under the authority of the Ministry of Energy and Coal Industry remain loss-making even at the new prices and still need state budget support.

Application of the Rotterdam+ formula and the consequent wholesale market price hike made it difficult to eliminate the cross-subsidisation of residential consumers by commercial ones. Despite an average 3.5-times tariff increase for households over three years (February 2014 to March 2017), residential subsidies even increased from UAH 38.1 billion in 2014 to UAH 45.3 billion in 2018 by decree of the NKREKP. Application of the Rotterdam+ formula by the regulator ceased entirely only in July 2019 with introduction of the new, more competitive power market structure.

The SAEE is tasked with the dual role of promoting energy efficiency and deploying renewable energy, and responsibility for energy efficiency was moved from the cabinet of ministers to the Ministry of Economy and Trade. Agency subordination was then shifted to Minregion and was re-shifted to the MEEP. MEEP approves draft legislation developed by the SAEE. In 2017 the parliament approved the important legislation developed by the SAEE and Minregion, in particular the Law on Energy Efficiency in Buildings, the Law on Commercial Metering of Utility Services, and the Law on the Energy Efficiency Fund.

The primary barrier to effective policy design, evaluation and implementation is limited and mismatched data on energy use and economic activity in different sectors and subsectors. Accurate and comprehensive data analysis can provide critical information for decision-making, including for future scenarios, baselines and indicators that are necessary for tracking progress and monitoring, evaluating and correcting energy efficiency initiatives.

Ukrainian legislation provides very attractive guaranteed feed-in tariffs, known as green tariffs for electricity produced from RESs. The regulator approves feed-in tariff rates on a case-by-case basis upon completion of a power plant, and approved renewables-based generators are shielded from EUR–UAH exchange rate fluctuations because the fixed-minimum green tariff rates are converted into euros at a fixed exchange rate of 10.86 (based on the 1 January 2009 rate). The regulator can apply the exchange rate effective when the green tariff is established only if it is higher than 10.86. In 2014, it also became permissible for households to sell solar photovoltaic (PV) electricity directly to energy suppliers via feed-in tariffs if their installed capacity is lower than 10 kilowatts (kW) (this threshold has been increased to 30 kW). 

Regional markets and interconnections

Ukraine’s electricity network is fully integrated and interconnected with those of its neighbours in the region. The exception is Burshtyn Island in the western part of the country, which is synchronised with Central European grids and facilitates direct exports to Slovakia, Hungary and Romania. 

Ukraine is an important transit country for Russian gas exports to Europe, for which it gains substantial transit fees, but Russian transit volumes through Ukraine have fallen progressively since the opening of the Blue Stream pipeline to Turkey in 2006, full commissioning of the Nord Stream pipeline (line 1 in 2011 and line 2 in 2012) and TurkStream in 2019. Russian gas transit through Ukraine therefore fell from 137.1 bcm in 2004 to 90 bcm in 2019.

Furthermore, if the proposed Nord Steam II pipeline is built, Russian gas volumes in transit through Ukraine are likely to drop even more or cease entirely. It is critical that modernisation of Ukraine’s pipeline system be tailored to future transit flows and imports to ensure its efficiency.

Ukraine’s oil pipeline system was designed to deliver crude oil supplies from Russia and Kazakhstan to oil refineries in Ukraine, as well as to transit oil to Central and Eastern European countries. The design input capacity is 84 Mt and the output capacity for transit is 36.2 Mt. Russian and Kazakh companies can transit crude oil through Ukraine via three pipelines: the southern branch of the Druzhba pipeline, which enters Ukraine from Belarus (Atyrau-Samara-Unecha-Mozyr-southern Druzhba); the Samara-Lisichansk pipeline; and the Nizhnevartovsk-Lisichansk-Kremenchuk-Odessa pipeline. Volumes of oil in transit through Ukraine have been decreasing steadily in recent years – from 56.4 Mt in 2000 to only 13.3 Mt in 2018 and 13.1 Mt in 2019 – as Russian companies diversify their oil transport routes by building pipelines that bypass Ukraine.