Enefit Green

Quarterly Report • May 2, 2024

Q1 2024 Unaudited interim report

Contents

Chairman's address	3
Development of the generation capacity 2023 – 2026	4
Projects under construction	5
Near term development portfolio	6
Complete view of the development portfolio	7
Q1 2024 key highlights	8
Operating environment	9
Regulatory environment	11
Significant events	12
Financial results	13
Financial results by segments	16
Wind energy	16
Cogeneration	19
Solar energy	21
Investment	22
Financing	23
Risk management	25
Unaudited condensed consolidated interim financial statements Q1 2024	28
Notes to the condensed consolidated interim financial statements	34
Group structure	45

Chairman's address

Dear reader

Compared to last year, Enefit Green's results for Q1 2024 were strongly influenced by a warmer winter, lower electricity prices and weaker wind conditions, particularly in February and March.

We produced 494 GWh of electricity (+22%) and 129 GWh of heat (-27%) in Q1. Higher electricity production was driven by newly completed wind and solar farms and wind and solar farms under construction (+131 GWh). The production remained 95 GWh lower than expected. This was mainly due to lower-than-expected production from wind farms under construction (-47 GWh) and weaker than average wind conditions (-42 GWh).

The availability of our operating wind farms was close to the expected level. We have significantly improved the availability of the Šilutė wind farm in Lithuania after the faults which occurred in the second half of last year and we have maintained high availability of the WinWind turbines in Estonia.

In April at the Tolpanvaara wind farm we have taken over the wind turbines from the supplier and the full-service contract with availability guarantee signed with Nordex entered into force. All 13 turbines generate electricity and only the grid tests remain to be passed.

At the Akmenė wind farm in Lithuania, the wind turbine that collapsed last May has been replaced and the wind farm is expected to be completed in coming summer after the necessary adjustment works. Negotiations are ongoing with both the insurance company and the wind turbine manufacturer, General Electric, for settlement of contractual and other claims related to last year's incident.

The decrease in heat production compared to the previous year is mainly due to the sale of our biomass cogeneration plants. In March, after obtaining the necessary approvals, we completed the sale of the Paide and Valka CHP plants to Utilitas. This marks our exit from the biomass cogeneration business and allows us to focus on the development of wind and solar power in the Baltic countries and Poland and the efficient management of the Iru power plant.

At Sopi-Tootsi, the largest renewable energy site in the Baltics, construction has reached the phase of installation of wind turbines and solar panels. At the Kelme I wind farm in Lithuania, the first 230-metre Nordex wind turbines have been erected. When completed, these wind farms are expected to supply the region's electricity market with more than 1 TWh of renewable energy. We have started the construction of the Kelme II wind farm in Lithuania and our first solar farms in Latvia.

The quarter also saw the conclusion of two important cooperation agreements signed in early April. The start of a collaboration with the Polish developer RES Global Investment will allow us to expand our wind energy portfolio. The acquisition of development rights to eight early-stage onshore wind projects with a total capacity of up to 360 MW strengthens our development portfolio and provides opportunities for sustainable future growth.

We signed a direct power line agreement with hydrogen technology company Elcogen under which the Iru power plant will supply energy to Elcogen's new fuel cell plant for a period of ten years. The direct power line will be beneficial to Elcogen from both energy price and availability angles compared to ordinary grid connection.

We ended Q1 with operating income of €68.9m (-11%), EBITDA of €42.4m (+3%) and net profit of €33.4m (+10%). Operating income and EBITDA were influenced by a combination of several factors. Our electricity production was higher by a fifth, but electricity prices on our core markets were lower (-13% on average). Also, the PPA prices were lower than last year and lower than projected production meant led to continuing electricity purchases to fulfil the delivery obligations under PPAs.

Our focus this year will be on completing projects under construction on schedule and maintaining the high availability of our operating assets. We will also continue to work with our development portfolio to increase the value of the business in the longer term.

Aavo Kärmas CEO, Enefit Green

Development of the generation capacity 2023 – 2026

* Near-term development portfolio includes projects, which are developed to the state of final investment decision (FID) readiness before the end of 2024. The actual timing of FID depends of PPA demand, availability of other instruments for revenue security (state auctions, possible support mechanisms etc), pricing of equipment for electricity production, construction prices and financing

Projects under construction

* Replacement of the turbine that collapsed in Akmene in May 2023 was carried out in March 2024

** COD – Commercial Operation Date (a date when the asset will be categorised as operating asset).

Near term development portfolio

* Projects are being developed to the state of final investment decision (FID) readiness by the indicated time. The actual timing of FID depends of PPA demand, availability of other instruments for revenue security (state auctions, possible support mechanisms etc), pricing of equipment for electricity production, construction prices and financing

Complete view of the development portfolio

* Various onshore wind and solar farm developments that are not expected to get final investment decision before 2025. The actual timing of FID depends on PPA demand, availability of other instruments for revenue security (state auctions, possible support mechanisms etc), pricing of equipment for electricity production, construction prices and financing.

** Also known as Hiiumaa Offshore Wind Farm

Q1 2024 key highlights

* (Electricity sales revenue + renewable energy support and efficient cogeneration support – electricity purchases on the Nord Pool day-ahead and intraday market – balancing energy purchases) / production

360 MW Agreement with RES Global Investment to co-develop onshore wind farms

0

25

50

75

100

+131 GWh Production growth from completed and under construction wind and solar farms

Operating environment

Key factors influencing the operating environment

Enefit Green's operations are strongly influenced by seasonality, weather conditions and electricity prices as well as regulations governing the energy industry and political decisions. Factors which affect the group's development projects also include market competition, the development and cost of renewable energy technologies, customers' willingness to enter into long-term green power purchase agreements (PPAs) and renewable energy support schemes.

Most of Enefit Green's production assets are either partly or fully exposed to market risk resulting from fluctuations in the market price of electricity. We mitigate electricity price risk mainly through long-term PPAs. The share of various national renewable energy support schemes in our operating income has decreased significantly compared with previous years. A more detailed overview of the PPAs and other risk mitigation measures covering the expected electricity production in the coming years is provided at the end of the managementreport.

Electricity market

The electricity markets in the region where Enefit Green operates are well interconnected. Therefore, electricity generation and prices are affected by various factors both in our core markets and beyond.

Intraday electricity prices on the Nord Pool (NP) power exchange have been highly volatile in recent years. During peak hours, the electricity price is usually determined by the more expensive carbon-intensive power, while during off-peak hours it is determined by renewable power.

Electricity prices in our core markets continued to decrease in Q1 due to increasing wind power generation and strong hydropower production in neighbouring countries.

During peak hours, the electricity price in the region is typically determined by gas-fired power plants. Although natural gas prices have decreased year on year, electricity prices during peak hours in Q1 2024 were higher than in the same period last year due to weather conditions. The average daily electricity price in Q1 was the highest on 5 January, when it was €890.5/MWh (+€717.1/MWh compared to Q1 2023) and the lowest on 29 March, when it was €24.8/MWh (+€6.9/MWh compared to Q1 2023).

The average price of natural gas on the Dutch gas trading platform TTF was €30.5/MWh in Q1 2024 (€20.1/MWh, 39.7% lower than in Q1 2023). The price of natural gas decreased compared to Q1 2023, mainly due to high LNG production and lack of supply issues. Demand was also affected by the fact that the period from December 2023 to February 2024 was the third warmest on record, meaning that heating demand was significantly lower than usual.

As a result of warmer temperatures during the heating season, the levels of natural gas inventories in Europe are significantly higher and according to forecasts there should be no problems with the availability of natural gas this year. At the end of Q1, gas storage facilities in Europe were at 60% (55% a year earlier) and are expected to reach 89% of the maximum by the end of July.

Interconnectors supply the Baltic countries with Nordic hydropower, which is cheaper than other types of electricity. The average level of hydro resources in the Nordic hydropower reservoirs in Q1 2024 was 41.4% of the maximum, which is 4.6 percentage points lower than in Q1 2023.

As the volume of snow and surface water accumulated in the reservoirs by the end of Q1 was 5.7 TWh lower than a year earlier, hydropower production in the following quarters may decrease year on year. Lower hydropower production may influence electricity prices in the region because a larger share of the required electricity has to be produced by facilities with higher variable costs.

The average CO2 emission allowance price in Q1 2024 was €61.7/t, which is 31.4% (-€28.2/t) lower than a year earlier. In March, the price dropped to the lowest level in two years. The main reasons for the price decrease were a weaker macroeconomic situation in the EU and the release of additional allowances by the European Commission in Q1

Average electricity price (€/MWh)	Q1 2024	Q1 2023	Change
Estonia	90.4	99.4	(9.1)%
Latvia	87.0	100.0	(13.0)%
Lithuania	87.1	101.7	(14.4)%
Poland	81.7	130.9	(37.6)%
Finland	72.8	77.6	(6.1)%
Norway	58.1	79.0	(26.5)%
Denmark	64.9	103.1	(37.0)%
Sweden	53.3	68.0	(21.6)%

Wind conditions

Due to seasonal factors, wind conditions in Q1 and Q4 are more favourable for wind power production in our region than the rest of the year. In Q1 2024, the average measured wind speeds in Enefit Green's wind farms in Estonia and Lithuania were 6.5 and 7.2 m/s respectively (Q1 2023: 6.9 m/s and 7.1 m/s). As a result, the impact of wind conditions also differed by region. The chart below provides an overview of the average quarterly wind speeds in Estonia and Lithuania since the beginning of 2022.

In connection with the completion of the Tolpanvaara wind farm, Enefit Green's future performance indicators will also be influenced by wind conditions in Finland. In Q1 this year, the average measured wind speed at the Tolpanvaara wind farm was 7.4 m/s.

Regulatory environment

European Union

The process of changing the EU electricity market regulation was not completed in Q1 2024. Repeated postponement of the adoption a market model makes meeting the 2030 targets more difficult. In addition to the electricity market design reform, the hydrogen and decarbonised gas market package will be adopted.

On 6 February, the European Commission issued a recommendation for a new EU climate target: a 90% net greenhouse gas (GHG) emissions reduction by 2040 compared to 1990 levels. An important shift in emphasis in the GHG policy was also formulated – in addition to the current increase of energy efficiency and renewable energy production, a greater role is seen for industrial and natural removal of CO² emissions. Together with the communication on the 2040 climate target, the European Commission issued a separate communication on industrial carbon management. Carbon capture is seen as necessary in the production of electricity from biomass and low-carbon hydrogen, in the refining sector, waste incineration and in heat production. The intention is to introduce a regulation to incentivise carbon sequestration.

Estonia

Discussions on the drafting of a Climate Act continued and a call for ideas on necessary changes to sectoral legislation was launched.

The Ministry of Climate published a proposal for waste reform. One of the objectives is to reduce the use of unsorted municipal waste for energy production. The reform will encourage Enefit Green to increase the use of sorting residues (secondary waste). The reform may make the production of heat and electricity from waste more expensive than at present. The necessary legislative changes will be adopted at the end of 2024.

The Estonian parliament is in the process of transposing the Renewable Energy Directive, which requires Estonia to introduce measures to reduce the use of wood for energy production.

The Estonian parliament is also in the process of amending the Building Code to speed up the deployment of renewable energy. There is a risk that, despite 18 years of development of the North-West Estonia offshore wind farm, Enefit Green will be deprived of its legitimate expectation that the superficies licence procedure will be initiated on the basis of the application submitted by Enefit Green.

Latvia

A new version of Latvia's climate and energy plan has come under heavy criticism from the private sector because the national targets in the document submitted to the European Commission only include the project volumes of state-owned companies. The plan is presented in a way that appears to make private investment in renewable energy generation unnecessary.

Latvia published a draft law on the construction of the fourth Estonian-Latvian electricity interconnector (ELWIND) and an associated offshore wind farm, which outlines the legislative changes needed to facilitate the development of the wind farm (e.g. the state will ensure the grid connection and grant the right to use the marine area for 70 years instead of 30 years).

Latvia launched a public consultation on a report on nuclear energy options. Nuclear power is seen as a potential carbon-neutral alternative to electricity generation from renewables or hydrogen. The vision is for a Latvian state-owned company to participate in a nuclear power plant to be built in Estonia or to build its own nuclear power plant in Latvia. Cooperation with Estonia is considered important so that nuclear waste could be stored in Ida-Viru county in Estonia. A plan for the use of nuclear energy will be prepared in cooperation with Estonia and published at the end of August 2024.

In February, the Latvian government announced plans to partially privatise several important state-owned energy companies via the stock exchange, including SIA Latvijas vēja parki, a joint venture of Latvenergo and Latvijas valsts meži.

Lithuania

Rules for monitoring birds and bats at wind farms came into force.

Poland

The new government has started drafting regulatory changes.

Poland submitted an updated climate and energy plan to the European Commission. The projection for renewable electricity generation in 2030 has been significantly increased. Instead of the 32% projected in 2019, Poland now expects to cover 50.1% of its energy consumption with electricity from renewable sources.

Finland

In Finland, an environmental impact assessment (EIA) programme for extending the service life and uprating the thermal power of units 1 and 2 of the Olkiluoto nuclear power plant has been submitted for consultation. Under the current permit, both units are due to close in 2038, but an extension to 2048 or 2058 is now being sought. Plans also include increasing the units' thermal power from 2,500 MW to 2,750 MW. The operating licences of Olkiluoto 1 and 2 have already been extended once.

Significant events

Construction of the Sopi-Tootsi wind farm reaches wind turbine installation stage

At Sopi-Tootsi, the most powerful renewable energy site in the Baltics, the wind farm's drainage systems, roads, crane platforms and foundations for almost all the wind turbines are complete and the delivery of wind turbine components has started. The installation of solar panels in the solar farm area has also begun.

The largest wind and solar farm in the Baltic countries, built by Enefit Green in the northern part of Pärnu county, will produce more than 770 GWh of renewable electricity per year. According to current plans, the wind farm will be completed in early 2025 and the solar farm in late 2025.

Wind turbine installation begins at Kelme I wind farm

We began installing the first 230-metre high wind turbines at the Kelme I wind farm (80 MW) in western Lithuania. We will install a total of 14 wind turbines, which will produce around 270 GWh of renewable energy per year.

Electricity production at the wind farm is expected to start at the end of this year and the wind farm is scheduled to be completed in Q3 2025.

Sale of Paide and Valka CHP plants finalised

On 29 November 2023, Enefit Green signed a contract for the sale of the Paide and Valka CHP plants to Utilitas, the largest district heating company in Estonia. The transaction was finalised on 1 March following approval by the Estonian and Latvian competition authorities.

Enefit Green sold its biomass CHP business to sharpen the focus on its strategic business of developing wind and solar power in the Baltic countries and Poland.

Situation at Akmenė wind farm

The wind turbine that collapsed in the Akmenė wind farm in May 2023 was replaced in March and the new one is being tested and adjusted. The entire wind farm with its 14 wind turbines is expected to be operational and complete by the end of Q2.

Enefit Green has entered into negotiations with the insurer of the Akmenė project (Compensa) and the wind turbine supplier (General Electric) regarding the losses caused by the incident in 2023. The parties have not yet reached agreement on the settlement of contractual and other claims.

Events after the reporting period

Agreement signed to acquire early stage onshore wind projects in Poland

Enefit Green and Polish developer RES Global Investment have signed an agreement under which Enefit Green will acquire 100% of the development rights to eight separate early stage onshore wind projects with a total planned installed capacity of up to 360 MW. The transaction strengthens Enefit Green's wind development portfolio and creates opportunities for sustainable future growth.

The construction of the wind farms is not expected to start before 2028. It is currently expected that the wind farms will operate either under merchant market conditions or under power purchase agreements to be signed at the time of the final investment decision. The total investment is estimated to be around €80m.

Direct line power purchase agreement signed with Elcogen

Under the terms of the agreement signed with Elcogen, a direct power line will be built from the Iru power plant to Elcogen's new fuel cell manufacturing facility. For Elcogen, the direct power line will provide electricity at a lower cost than a standard grid connection, while the proximity to a large power generation unit will also ensure security of supply. For Enefit Green, the agreement with a large long-term consumer will allow more effective management of its energy production flows.

The capacity of the direct power line will be 10 megavolt amperes (MVA), which is comparable to the consumption capacity of an average settlement in Estonia. The construction of the power line will start soon and is expected to be completed in January 2025. The direct power purchase agreement has been signed for ten years.

Change of chairman of management board

Aavo Kärmas, who has been the chairman of the management board of Enefit Green since 2017, will step down effective from 1 July 2024. The supervisory board has accepted his resignation and has started the process of recruiting a new chairman of the management board.

Financial results

The Enefit Green group's operating income for Q1 2024 decreased by 11% while operating expenses for the period decreased by 22% compared to the same period last year. As a result, EBITDA increased by 3% to €42.4m and net profit for the quarter increased by 10% to €33.4m. The key factors which influenced the group's financial performance are described below.

The comparison of the group's performance indicators for Q1 2024 is strongly affected by the sale of the Brocēni CHP plant and pellet factory, which was completed in Q4 2023, and the sale of the Paide and Valka CHP plants, which was completed in March 2024. The results for Q1 2023 include operating income of €20.0m, operating expenses of €17.6m and effects on EBITDA of €3.6m, which are related to assets sold by the end of Q1 2024. The results for Q1 2024 include operating income of €8.0m (incl. sales gain of €5.5m recognised in March) and operating expenses of €1.3m with a total effect on EBITDA of €6.7m that are related to the Paide and Valka CHP plants.

Production and sales volumes

GWh	Q1 2024	Q1 2023	Change	Change, %
Electricity production (net)	494	406	89	22%
Of which by new wind and solar farms	169	38	131	343%
Electricity sales*	627	495	133	27%
Heat production	129	176	(47)	(27)%

The group's total electricity production grew by 89 GWh (+22%) to 494 GWh in Q1, with electricity production at new wind farms and wind farms under construction increasing by 131 GWh. Nevertheless, electricity production was around 95 GWh lower than forecasted. This was due to weather conditions (mainly lower than expected wind speeds) and low availability of wind farms under construction. For further details, see the chapter on the results of the Wind energy segment.

Operating income

Total operating income decreased by €8.6m, the figure reflecting a decrease in revenue of €13.5m and an increase in renewable energy support and other operating income of €4.9m. Operating income for Q1 2023 includes €20.0m generated by assets sold in Q4 2023 and Q1 2024 €8.0m ('assets sold'). Excluding the impact of assets sold, the group's operating income was €57.5m for Q1 2023 and €60.9m for Q1 2024 and operating income grew by €3.4m, the figure reflecting revenue growth of €4.1m and a decrease in other operating income of €0.7m.

Of the €4.1m revenue growth, €4.9m resulted from electricity sales revenue that was driven by higher production.

In Q1 2024, the average electricity price** in the group's core markets was €87.0 €/MWh (Q1 2023: €100.5/MWh). The group's average implied captured electricity price*** was €81.4/MWh (Q1 2023: €101.2/MWh). The implied captured electricity price differs from the average market price in the group's core markets, because it takes into account long-term fixed-price power purchase agreements (PPAs), renewable energy support, purchases of balancing energy, electricity purchases from the Nord Pool day-ahead and intraday markets and the fact that wind farms do not produce the same amount of electricity every hour.

The group's average price of electricity sold to the market in Q1 2024 was €77.6/MWh compared with €82.4/MWh a year earlier. The group sold 292 GWh of electricity to the market in Q1 2024 compared with 234 GWh a year earlier.

	Q1 2024	Q1 2023	Change	Change, %
TOTAL OPERATING INCOME	68.9	77.5	(8.6)	(11)%
Revenue	56.2	69.7	(13.5)	(19)%
Renewable energy support and other operating income	12.7	7.8	4.9	63%
TOTAL OPERATING EXPENSES (excl. D&A)	26.5	36.4	(9.9)	(27)%
Raw materials, consumables and services used (excl. electricity)	5.8	13.3	(7.5)	(56)%
Electricity purchase costs	14.8	11.5	3.4	29%
Payroll expenses	2.2	2.5	(0.3)	(10)%
Other operating expenses	3.6	4.1	(0.5)	(11)%
Change in inventories	0.0	5.1	(5.1)	(100)%
EBITDA	42.4	41.1	1.3	3%
Depreciation, amortisation and impairment (D&A)	9.3	9.8	(0.5)	(5)%
OPERATING PROFIT	33.1	31.3	1.8	6%
Net finance income	0.3	0.0	0.2	878%
Income tax	(0.1)	0.8	(0.9)	(113)%
NET PROFIT	33.4	30.5	2.9	10%
TOTAL OPERATING EXPENSES (excl. D&A)	26.5	36.4	(9.9)	(27)%
Variable costs (incl. balancing energy purchases)	17.0	21.6	(4.5)	(21)%
Fixed costs	9.5	9.8	(0.3)	(3)%
Change in inventories	0.0	5.1	(5.1)	(100)%

* The difference between the quantities of electricity sold and produced is attributable to differences between sales under baseload PPAs and wind energy production profiles as well as day-ahead forecasts and unrealised production, which is covered with purchases from Nord Pool and/or the energy imbalance market.

** Production-weighted average market price in the group's core markets

*** Implied captured electricity price = (electricity sales revenue + renewable energy support and efficient cogeneration support + revenue from sale of guarantees of origin – day-ahead and intraday purchases on Nord Pool – balancing energy purchases – purchases of fixed supply) / production

In Q1 2024, 335 GWh of the group's electricity production was covered by PPAs signed at an average price of €75.0/MWh. A year earlier, 260 GWh of electricity was sold under PPAs at an average price of €89.8/MWh. The average price of electricity sold under PPAs has decreased significantly year on year because the settlement periods of PPAs signed in Lithuania and Finland in 2021 at lower prices began in Q1 2024. The share and prices of production covered by PPAs in future periods are disclosed in the risk management chapter.

An overview of the quantities of electricity produced, purchased and sold, the realised prices and the resulting implied captured electricity price for the past five quarters is presented in the chart and table below.

Average quarterly electricity prices

	Q1 2023	Q2 2023	Q3 2023	Q4 2023	Q1 2024
Price of electricity sold to the market	82.4	63.7	82.2	64.1	77.6
PPA price	89.8	83.5	80.9	91.2	75.0
Realised purchase price	116.7	83.8	116.5	121.5	106.1
Core markets' average electricity price	100.5	78.8	97.8	93.1	87.0
Implied captured electricity price	101.2	88.9	84.9	80.9	81.4

In Q1 2024, we purchased 138 GWh of electricity from the market at an average price of €106.1/MWh, compared with 92 GWh at an average price of €116.7/MWh in Q1 2023 (the prices and volumes exclude the electricity purchased for pellet production in Q1 2023). The volume of electricity purchased increased because sales under PPAs and the share of production covered by PPAs have increased and therefore the purchases needed to balance the baseload PPA portfolio have also increased. The purchase price decreased compared to Q1 2023 because the market price has declined, but due to a higher wind profile discount the difference between

the purchase price and the market price increased. In Lithuania, the Q1 wind profile discount increased by 3.3 percentage points year on year, rising to 15%. In Estonia, the wind profile discount rose by 0.4 percentage points to 13.5%. In 2024, we started to supply electricity under a PPA in Finland, which is why we also started to purchase electricity in Finland. In Finland, the wind profile discount in Q1 2024 was 28.1%.

Renewable energy support and other operating income increased by €4.9m. The figure reflects the gain on the sale of the Paide and Valka CHP plants of €5.4m and a decrease in renewable energy support of €0.8m. The amount of renewable energy support received is based on the quantity of energy produced by wind farms eligible forsupport, which in Q1 2024 was 12.0 GWh lower than a year earlier.

Raw materials, consumables and services used

Expenses on raw materials, consumables and services decreased by €7.5m (-56%). The largest change was in technological fuel costs: technological fuel costs related to assets sold amounted to €8.3m in Q1 2023 and €0.9m in Q1 2024.

Electricity purchase costs

Electricity purchase costs grew by €3.4m compared to Q1 2023. The main contributors were expenses on electricity purchased from Nord Pool to service PPAs (€2.4m up on Q1 2023) and expenses on balancing energy (€1.4m up on Q1 2023). The costs result from electricity purchased from the Nord Pool intraday market to balance the portfolio and electricity purchased to balance the PPA portfolio in hours of low wind speed; a contributing factor during the period was lower than expected production volume. The volumes and prices of electricity purchased from the market are disclosed in the operating income chapter.

Payroll expenses

The group's payroll expenses decreased by 10% year on year. Payroll expenses related to assets sold amounted to €0.8m in Q1 2023 and to €0.2 in Q1 2024. Excluding the impact of assets sold, the group's payroll expenses increased by 21% compared to the same period last year. New people have mostly been hired to the development team to support the group's growth plan in all core markets. By the end of Q1 2024, the development team has increased to 39 employees compared with 33 a year earlier.

Other operating expenses

Other operating expenses decreased by €0.5m (-11%), mainly due to assets sold.

EBITDA and fixed costs

The factor with the strongest impact on EBITDA development was the price of electricity sold, which decreased compared to Q1 2023 (impact: -€8.3m). Due to PPAs, the quantity of electricity sold grew considerably (impact: +€12.3m), which also increased the volume of electricity purchased to balance the electricity portfolio (impact: -€4.7m). The combined effect of the above factors on EBITDA development is influenced by the volume and profile of electricity produced during the period. Electricity production grew by 22% year on year.

The total impact of assets sold on EBITDA development was +€3.1m. The largest item was gain on the sale of the Paide and Valka CHP plants of €5.5m.

Excluding the effects of the electricity price and volume, the Iru cogeneration plant had a negative impact on EBITDA. The calculation takes into account the effects of heat energy, gate fees for waste received and technological fuel. The EBITDA of the Iru cogeneration plant decreased because gate fees decreased by €0.7m due to a decline in the volume of waste received and expenses on natural gas increased by €0.3m due an unplanned production interruption in February during which replacement heat was produced from natural gas.

Fixed costs are costs that are not directly dependent on the production volume. Fixed costs excluding the fixed costs of assets sold grew by €1.0m. The increase was attributable to higher maintenance costs and IT expenses.

Depreciation, amortisation and impairment (D&A)

D&A expense decreased by €0.5m (-5%). Assets sold lowered D&A expense compared to a year earlier by €1.1m. Non-current assets recognised after Q1 2023 include the Purtse wind farm (D&A for Q1 2024: €0.2m) and the Purtse solar farm (D&A for Q1 2024: €0.1m) in Estonia and the Zambrow solar farm (D&A for Q1 2024: €0.1m) in Poland.

Net finance income

Net finance income grew by €0.2m compared to the same period last year. Interest expense on bank loans increased by €3.0m but 99% of it was capitalised due to the wind farms still being under construction. Growth in interest income had a positive effect on net finance income.

Income tax

The change in income tax was -€0.9m compared to Q1 2023.

Group's EBITDA change by drivers, €m

Financial results by segments

Based on total operating income and EBITDA, the group's largest segment is Wind energy, which accounted for 73% of operating income and 76% of EBITDA for Q1 2024. The Cogeneration segment contributed 25% to operating income and 32% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 1% the group's operating income and 1% of the group's EBITDA for Q1 2024.

In segment terms, Wind energy delivered the strongest EBITDA growth. A more detailed analysis by segment is presented below. In Q1 2024, the group adjusted the allocation of income and expenses to segments (the figures for the comparative period have been adjusted accordingly). Until Q1 2024, the Wind energy and Solar energy segments included their respective payroll expenses and predevelopment costs of development projects without an investment decision. The Wind energy segment also included the costs of offshore wind developments. From Q1 2024, the Wind energy and Solar energy segments include the financial impacts of operating assets and development projects with an investment decision.

The EBITDA of the segment Other mainly includes general administrative expenses, the payroll expenses for employees involved in the Wind energy and Solar energy segments, and the costs of development projects without an investment decision. The segment also includes the Keila-Joa hydroelectric facility, and the renewable energy solution on the island of Ruhnu. The loss of the segment Other increased by €0.6m.

Operating income by segment, €m

100

Group's EBITDA breakdown and change, €m

Wind energy

The Wind energy segment comprises the group's operating wind farms and wind farm developments with an investment decision. From the interim report for Q1 2024, the Wind energy development teams related expenses (including payroll), wind farm developments that do not have an investment decision and offshore wind

farm developments are included in the segment Other, not the Wind energy segment (the figures for the comparative period have been adjusted accordingly).

Availability and production

The group's wind power production in Q1 2024 was 451.4 GWh, which is 100.1 GWh higher than in Q1 2023 due to new wind farms coming online. New wind farms and wind farms still under construction contributed 163.3 GWh to total wind power production (+124.9 GWh compared to Q1 2023).

The availability of the group's operating Estonian and Lithuanian wind farms, which was 95.1% and 96.0% respectively, was slightly lower than a year earlier (Q1 2023: 96.2% and 97.6%, respectively), but in line with expectations. After the problems in the second half of 2023, the availability of operating Lithuanian wind farms has been restored to the targeted high levels. This has been possible due to focused cooperation with General Electric in making various improvements to the Šilute wind farm and the replacement of the main bearings of a wind turbine at the Mockiai wind farm.

Although the availability of the wind farms under construction in Lithuania and Finland – Akmenė, Šilale II and Tolpanvaara – has improved from month to month, it was still significantly lower than expected in Q1. As a result, electricity production was more than 47 GWh lower than it would have been had availability been as expected.

In April, however, the availability of the Tolpanvaara wind farm was high enough for Nordex's full-service contract with 95% availability warranty to take effect.

Weaker than expected wind conditions lowered expected production by around 42 GWh (of which around ¾ at operating wind farms and ¼ at wind farms under construction).

Electricity prices

The implied captured electricity price of the Wind energy segment depends on the combination of the market price and PPAs. In Q1 2024, the Wind energy segment's average implied captured electricity price including support was €77.9/MWh (-19% compared to Q1 2023).

In addition to the market price of electricity, our Estonian wind farms whose eligibility period has not expired receive renewable energy support in the form of feed-in premium (FiP) at the rate of €53.7/MWh. While the eligibility period of the Aseriaru wind farm (24 MW) expires in Q4 2024, the eligibility period of the Purtse wind farm (21 MW) begins in Q2 2024.

* (electricity sales revenue + renewable energy support and efficient cogeneration support + revenue from sale of guarantees of origin – day-ahead and intraday purchases on Nord Pool – balancing energy purchases – purchases of fixed supply) / production

Operating income

The Wind energy segment's operating income was positively influenced by higher production due to the addition of new wind farms, which increased operating income by 13% to €50.3m.

Operating expenses

The operating expenses of the Wind energy segment (excl. D&A) increased by €4.5m to €18.2m. This was mainly due to electricity purchases made to balance the PPA portfolio in hours of low wind speed. Electricity purchase expenses including balancing energy purchases and purchases to balance the PPA portfolio grew by €4.1m. Other operating expenses (excl. electricity purchases, expenses on balancing energy and growth in D&A) grew by €0.4m year on year.

Operating expenses per MW

According to the expenses of entities holding the group's operating wind farms (Enefit Wind OÜ and Enefit Wind UAB) that belong to the Wind energy segment, wind farm operating expenses (excl. D&A, balancing energy purchases and electricity purchases to service PPAs) per installed capacity (MW) increased by 15% year on year due to indexation. Since Q3 2023, operating wind farms have included the Purtse wind farm with an installed capacity of 21 MW.

EBITDA

The Wind energy segment's EBITDA for Q1 amounted to €32.1m (Q1 2023: €30.8m). EBITDA growth was driven by higher electricity production resulting from new wind farms and wind farms under construction.

Operating expenses per MW for last 4

*(Total operating expenses - balancing energy purchase - D&A) / operating capacity. Only operating wind assets are included: Enefit Wind OÜ, Enefit Wind UAB and starting from Q3 2023 Purtse windfarm.

Cogeneration

Until the end of 2023, the Cogeneration segment comprised the Iru, Paide, Valka and Brocēni CHP plants and a pellet factory. The sale of the Paide, Valka and Brocēni CHP plants and the pellet factory was announced in Q4 2023. The sale of the Brocēni CHP plant and the pellet factory took place before the end of 2023 and the sale of the Paide and Valka CHP plants was completed on 1 March 2024.

Electricity production and prices

The Cogeneration segment's electricity production in Q1 2024 was 34.0 GWh, which is 32% lower than a year earlier (Q1 2023: 50.3 GWh). The decrease is mainly attributable to assets sold. From March, the production figures of the Cogeneration segment consist of the figures of the Iru cogeneration plant because the Brocēni CHP plant was sold at the end of December and the sale of the Paide and Valka CHP plants was finalised at the beginning of March. The volume of electricity produced by the Iru cogeneration plant decreased by 6.4 GWh (-18%) compared to Q1 2023. The main reasons were cold weather at the beginning of the year, which forced the group to focus on supplying heat to the city of Tallinn, reducing the amount of steam generated for electricity production, and an unscheduled outage.

In addition to the market price of electricity, the Iru cogeneration plant receives renewable energy support of €53.7/MWh for electricity produced from renewable sources and efficient cogeneration support of €32/MWh for electricity produced from non-renewable sources in an efficient cogeneration mode.

The cogeneration facilities' availability in Q1 was 96.3%, 3 percentage points lower than in the same period last year. Due to lower than expected availability, electricity production was 1.7 GWh lower than expected.

As a result of lower market prices in the Nord Pool Estonia and Nord Pool Latvia price areas, the Cogeneration segment's implied captured electricity price in Q1 2024 was €125.9/MWh, which is 7% lower than a year earlier.

Heat production and prices

Heat production decreased by 27% to 129 GWh in Q1 2024. The decrease was related to assets sold. The volume of heat produced by the Iru cogeneration plant reduced 3.8 GWh (-3%) compared to the same period last year (112 GWh) reaching 108 GWh. The average sales price of heat per MWh decreased by 20% to around €19/MWh compared to the same period last year. The price cap for heat produced by the Iru cogeneration plant was €7.98/MWh in both the reporting and the comparative period, but the price of heat produced by the Paide and Valka CHPs decreased due to the decline in the price of biomass purchased by the facilities. From 19 April 2024, the price cap for heat produced by the Iru cogeneration plant from mixed municipal waste is €12.36/MWh.

Operating income

The Cogeneration segment's operating income decreased by 45% to €17.6m. Assets sold accounted for €12m of the decrease. The Iru cogeneration plant's electricity revenue decreased by €1.4m to €3.2m due to a decline in electricity production and a lower market price of electricity, gate fee revenue decreased by €0.7m to €3.9m due to a decrease in waste received and electricity production support decreased by €0.3m to €1.2m due to a decrease in

* (electricity sales revenue + renewable energy support and efficient cogeneration support + revenue from sale of guarantees of origin – day-ahead and intraday purchases on Nord Pool – balancing energy purchases – purchases of fixed supply) / production

production volume. Iru cogeneration plant's heat sales revenue and other operating income remained at the same level as a year earlier. Operating income generated by assets sold of €8.0m includes the gain on the sale of the Paide and Valka CHP plants of €5.5m.

Operating expenses

The segment's operating expenses decreased to €4.1m (Q1 2023: €19.2m). The decrease resulted from assets sold. The fixed and variable costs of the Iru cogeneration plant remained at the same level as in Q1 2023.

EBITDA

The Cogeneration segment's EBITDA for Q1 2024 was €13.5m, €0.6m (+5%) higher than in the same period last year. The EBITDA of the Iru cogeneration plant decreased by €2.5m to €6.7m due lower electricity production and market prices. The EBITDA of assets sold increased by €3.1m compared to Q1 2023 through the gain on the sale of the Paide and Valka CHP plants.

EBITDA, €m +0.6 (+4.7%)

Solar energy

The Solar energy segment comprises operating solar farms, solar farm developments with an investment decision and solar services. From the interim report for Q1 2024, the development costs of solar projects without an investment decision, the costs of solar farm development teams (including payroll) are included in the segment Other, not the Solar energy segment (the figures for the comparative period have been adjusted accordingly).

The Solar energy segment produced 8.5 GWh of solar power in Q1 2024, 5.0 GWh (+143%) more than in the same period in 2023 due to new solar farms coming online. The Purtse solar farm in Estonia and the Zambrow solar farm in Poland started production in Q2 2023 and the Estonia solar farm in Estonia in Q4 2023. The availability of solar farms remained high at 99.8% (Q1 2023: 99.9%).

The group's solar farms in Estonia are partly exposed to movements in the market price of electricity. Most of the group's solar farms in Poland sell electricity at fixed prices, which are

adjusted for inflation on an annual basis – the price for Q1 2024 was PLN 539–576/MWh (€124 –133/MWh at the three-month average zloty (PLN) exchange rate).

The Solar energy segment sold 4.8 GWh of electricity under PPAs in Q1 2024. The segment's implied captured electricity price was €78/MWh, which is 25% lower than in Q1 2023. The price decrease was due to lower market prices and the addition of PPAs at an average price of €81.4/MWh.

Operating income

The operating income of operating solar farms grew by €0.1m. The segment's electricity production increased, supported by the addition of new solar farms, but operating income increased only slightly due to a lower implied captured electricity price.

EBITDA

1%

Share of EBITDA Q1 2024

The Solar energy segment's EBITDA for Q1 2024 was €0.3m, 22% higher than a year earlier. EBITDA was supported by the production and operating income of three new solar farms, but the lower implied captured electricity price and slightly higher variable costs of the operating solar farms had a negative impact. The increase in variable costs is mainly due to electricity purchased to service the PPA of the Purtse solar farm.

Investment

Investments in Q1

The group invested €104.8m in Q1 2024, which is €12.9m more than in Q1 2023. Growth resulted from development investments, which extended to €104.7m. Of this, €77.6m was invested in the construction of three wind farms: €64.8m in the Sopi-Tootsi wind farm and €12.9m in the Kelme wind farms – €10.4m in Kelme I and €2.5 in Kelme II. The largest solar energy development investment was made in the Sopi solar project in the amount of €17.6m.

Baseline investments (expenditure for the maintenance and improvement of existing assets) remained at the same level as in the comparative period, amounting to €0.1m.

The segments had the following amounts of property, plant and equipment at 31 March 2024 (carrying amounts): Wind energy €1,029.2m including goodwill (52% under construction), Cogeneration €93.9m (0% under construction), Solar energy €116.1m (48% under construction) and Other €16.9m (62% under construction).

Financing

The group's main sources of debt capital are investment loans and credit facilities raised from regional commercial banks, the Nordic Investment Bank (NIB), the European Investment Bank (EIB) and the European Bank for Reconstruction and Development (EBRD).

At 31 March 2024, the amortised cost of the group's interest-bearing liabilities was €503.2m (31 December 2023: €482.4m). Loan liabilities to banks accounted for €493.6m of the total, including an outstanding loan balance of €6.4m denominated in Polish zloty.

In Q1, the group drew down bank loans of €30m.

65.7 35.0 +27.1 (80.4) +22.6 0,0 20,0 40,0 60,0 80,0 100,0 120,0 140,0 Cash and cash equivalents 31 Dec 2023 Operating cash flow Investment cash flow Financing cash flow Cash and 31 Mar 2024 Liquidity development 2024 Q1, €m -30.7 (-46.7%)

The interest rate risk of investment loans with the total outstanding balance of €151.7m has been hedged with interest rate swaps, which fix the interest rates of the loans in the range of 1.049–1.125% (plus the margin) until the loans mature. The average interest rate of bank loans drawn down at 31 March 2024 was 3.79% (31 December 2023: 3.75%).

Investment loans raised but not drawn down at 31 March 2024 amounted to €285m.

Loan repayment schedule, €m

Loan covenants

The group's loan and credit agreements include covenants which set certain limits to the group's consolidated financial indicators. At 31 March 2024, the group was in compliance with all loan terms, conditions and covenants.

Financing and return ratios

The group's management determines the maximum level of debt by reference to financial leverage and the net debt to EBITDA ratio.

€m	31 March 2024	31 December 2023
Interest-bearing liabilities	505.6	486.4
Less cash and cash equivalents	(35.0)	(65.7)
Net debt	470.6	420.7
Equity	752.3	717.2
Invested capital	1,222.9	1,137.9
EBITDA (last 12 months)	107.2	105.9
Operating profit (last 12 months)	67.1	65.3
Net profit (last 12 months)	58.7	55.8
Financial leverage (1)	38%	37%
Net debt / EBITDA	4.39	3.97
Return on invested capital (2)	5.5%	5.7%
Return on equity (3)	7.8%	7.8%
Interest cover (4)	6.5	7.9

(1) Financial leverage = net debt / (net debt + equity)

(2) Return on invested capital = operating profit for the last 12 months / (net debt + equity)

(3) Return on equity = net profit for the last 12 months / equity

(4) Interest cover = EBITDA for the last 12 months / interest expense

Risk management

The group has identified two main market and financial risks that require active management – the price risk of electricity sales and interest rate risk.

Price risk of electricity sales

The price risk of electricity sales is mitigated by a combination of:

• various kinds of national renewable energy support (FiP, CfD and other schemes) received by the group's various existing production assets; and
• power purchase agreements (PPAs). The group has set itself the goal that by the date a final investment decision on a new development project is made the price of electricity sold should generally be fixed for at least 60% of the project's forecasted output for the first five years.

Short-term outlook: management of electricity price risk in 2024

Taking into account the actual production volume for Q1 (95 GWh less than projected), we expect our production assets to generate 2.12 TWh of electricity in 2024, of which 1.21 TWh is expected from operating assets and 0.91 TWh from newly completed assets and assets under construction. The shortfall in production was driven primarily by wind energy segment. See the chapter on wind segment results for further details.

We have covered 1.31 TWh, i.e. 62%, of the expected electricity production in 2024 with PPAs at an average price of €67.7/MWh. In Q1 2024, Enefit Green reviewed its PPA portfolio for 2024 to manage the risk associated with electricity purchases needed to balance the PPA portfolio. As a result, Enefit Green signed a PPA to purchase 16.5 GWh of Finnish electricity during the period March – July 2024 and is considering purchasing an additional 19.6 GWh for the period August – December 2024. In addition, the group changed the supply area for 112.4 GWh of electricity to be supplied under PPAs from Lithuania to Estonia. The group will continue proactive management of the PPA portfolio, balancing the mitigation of price risk and the management of the risk associated with purchases related to baseload PPAs. The following chart shows the expected quarterly development of Enefit Green's electricity portfolio in 2024 with the figures for Q1 reflecting the actual results.

Long-term PPAs

According to current practice, Enefit Green generally fixes the sales price of electricity for 60% of a development project's projected output for the first five years by the time the final investment decision on the project is made. Enefit Green has also used PPAs to hedge the price risk of its operating electricity production portfolio.

Enefit Green did not sign new long-term PPAs in Q1 2024. As of 31 March 2024, Enefit Green had signed PPAs for the supply of 9,274 GWh of electricity at an average price of €70.8/MWh in the period April 2024 – December 2033. The counterparty to most of the PPAs is Eesti Energia AS (8,266 GWh). 47.1% of Enefit Green's expected electricity production in the period 2024–2028 is covered with PPAs at an average price of €68.2/MWh.

National support measures

Part of Enefit Green's electricity production in Estonia continues to receive renewable energy support, which is paid in addition to the sales price of electricity (feed-in-premium, FiP). 7% of Enefit Green's expected electricity production in the period 2024–2028 is covered with FiP support measures at an average FiP rate of €51.1/MWh.

The share of fixed-price support measures has decreased significantly. Only 1% of Enefit Green's expected electricity production in 2024–2028 is covered with fixed-price support measures (contracts for difference (CfD) schemes in Poland) at an average price of €116.3/MWh.

Enefit Green has signed PPAs for the supply of 2,458 GWh of electricity at an average price of €79/MWh in 2029–2033.

* Price floor – state support (capped at €20/MWh) in the form of a price floor determined in a reverse auction at the level of €34.9/MWh for a period of 12 years

** Estimated share of production covered by the measure. Estimated production comprises the forecasted production of operating assets and assets under construction.

*** Weighted average sales price or support of production covered by the measure.

**** 2025E – 2034E electricity prices have been estimated by averaging the forecasts of market analysis companies SKM, Volue and Thema (SKM Market Predictor Long-Term Power Outlook – February 2024, Volue Long Term Price Forecast – March 2024, Thema Power Market Outlook – February 2024 (Polish and Finnish prices: May 2023)). The figures presented are nominal prices, which have been estimated assuming a constant 2% rate of inflation.

						Total
	2024	2025	2026	2027	2028	2024–
						2028
FiT/CfD schemes**	1%	1%	1%	1%	1%	1%
Volume (GWh)	27	28	28	28	28	141
Price***, €/MWh	112.1	113.9	116.2	118.5	120.9	116.3
FiP support**	23%	9%	3%	2%	2%	7%
Volume (GWh)	484	266	99	79	75	1,004
Price***, €/MWh
(added to the market price)	50.1	50.3	53.7	53.7	53.7	51.1
PPAs**	62%	49%	46%	47%	37%	47.1%
Volume (GWh)	1,315	1,533	1,534	1,549	1,219	7,150
Price***, €/MWh	67.7	64.8	64.8	69.0	76.4	68.2

Forecasts of core markets electricity prices

The price forecasts for all our core markets**** have been revised downward compared to the figures presented in the annual report for 2023, with pronounced changes in the forecasts for years 2025 and 2026. The prices expected for the Baltics have been lowered on average by €22/MWh for 2025 and by €13/MWh for 2026. The prices expected for Finland and Poland have been lowered by €13/MWh and €17/MWh, respectively, for 2025 and by €9/MWh for both for 2026.

Reduction of forecasted prices is explained by lower natural gas and CO² prices, lower than expected consumption and growing renewable energy supply.

Interest rate risk

The group uses interest swap (IRS) agreements for interest rate risk management.

Interest rate risk is the risk that the fair value or future cash flows of financial instruments will fluctuate because of changes in market interest rates. Cash flow interest rate risk arises from the group's floating-rate borrowings and is the risk that finance costs will increase when interest rates rise.

Interest rate risk is mitigated partly by raising debt at fixed interest rates and partly by hedging: borrowing at a floating-rate and fixing the interest rate with IRS instruments. Information on IRS transactions is disclosed in note 5 to the financial statements.

Enefit Green | Interim report Q1 2024 | 28

Unaudited condensed consolidated interim financial statements Q1 2024

Condensed consolidated interim income statement

€ thousand	Note	Q1 2024	Q1 2023
Revenue	9	56,192	69,691
Renewable energy support and other operating income	10	12,729	7,813
Change in inventories of finished goods and work in progress		0	(5,060)
Raw materials, consumables and services used	11	(20,674)	(24,792)
Payroll expenses		(2,225)	(2,486)
Depreciation, amortisation and impairment		(9,342)	(9,815)
Other operating expenses		(3,595)	(4,055)
OPERATING PROFIT		33,085	31,296
Finance income		570	407
Finance costs		(306)	(380)
Net finance income and costs		264	27
Profit (loss) from associates under the equity method		(10)	19
PROFIT BEFORE TAX		33,339	31,342
Income tax income (expense)		107	(820)
PROFIT FOR THE PERIOD		33,446	30,522
Basic and diluted earnings per share
Weighted average number of shares, thousand	6	264,276	264,276
Basic earnings per share, €	6	0.13	0.12
Diluted earnings per share, €	6	0.13	0.12

Condensed consolidated interim statement of comprehensive income

€ thousand	Note	Q1 2024	Q1 2023
PROFIT FOR THE PERIOD		33,446	30,522
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Remeasurement of hedging instruments in cash flow hedges (incl. reclassifications to profit or loss)	5, 7	1,115	(689)
Exchange differences on the translation of foreign operations	7	54	(35)
Other comprehensive income (loss) for the period		1,169	(724)
TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		34,615	29,798

Condensed consolidated interim statement of financial position

€ thousand	Note	31 March 2024	31 December 2023
ASSETS
Non-current assets
Property, plant and equipment	4	1,123,597	1,027,057
Intangible assets		59,857	59,891
Right-of-use assets		8,764	9,097
Prepayments for non-current assets	4	54,240	55,148
Deferred tax assets		2,095	2,013
Investments in associates		538	548
Derivative financial instruments	5, 7	5,169	5,054
Non-current receivables		1,826	0
Total non-current assets		1,256,086	1,158,808
Current assets
Inventories		3,402	3,180
Trade and other receivables and prepayments		40,930	55,082
Derivative financial instruments		3,720	3,806
Cash and cash equivalents	5	34,989	65,677
		83,041	127,745
Assets classified as held for sale		0	15,370
Total current assets		83,041	143,115
Total assets		1,339,127	1,301,923

€ thousand	Note	31 March 2024	31 December 2023
EQUITY
Equity and reserves attributable to shareholders of the parent
Share capital		264,276	264,276
Share premium	6	60,351	60,351
Statutory capital reserve		5,556	5,556
Other reserves	5, 7	164,566	163,451
Foreign currency translation reserve	7	(108)	(162)
Retained earnings		257,163	223,718
Total equity		751,804	717,190
LIABILITIES
Non-current liabilities
Borrowings	8	437,916	454,272
Government grants		3,054	3,102
Non-derivative contract liability	5, 7	12,471	12,497
Deferred tax liabilities		12,412	12,412
Other non-current liabilities		5,239	5,239
Provisions		8	8
Total non-current liabilities		471,100	487,530
Current liabilities
Borrowings	8	67,685	32,126
Trade and other payables		44,870	54,445
Provisions		6	6
Non-derivative contract liability	5	3,662	5,674
		116,223	92,251
Liabilities directly associated with assets classified as held for sale		0	4,952
Total current liabilities		116,223	97,203
Total liabilities		587,323	584,733
Total equity and liabilities		1,339,127	1,301,923

Condensed consolidated interim statement of cash flows

€ thousand	Note	Q1 2024	Q1 2023
Cash flows from operating activities
Cash generated from operations	12	35,163	44,337
Interest and loan fees paid		(8,497)	(2,053)
Interest received		458	311
Income tax paid		0	(574)
Net cash generated from operating activities		27,124	42,021
Cash flows from investing activities
Purchase of property, plant and equipment and intangible assets	4	(97,282)	(85,747)
Proceeds from disposal of subsidiaries (net of cash and cash		16,879	0
equivalents transferred)
Net cash used in investing activities		(80,403)	(85,747)
Cash flows from financing activities
Proceeds from bank loans	8	30,000	0
Repayments of bank loans	8	(9,012)	(7,137)
Repayments of lease principal	8	(58)	(84)
Proceeds from realisation of interest rate swaps		1,661	0
Net cash generated from (used in) financing activities		22,591	(7,221)
Net cash flow		(30,688)	(50,947)
Cash and cash equivalents at the beginning of the period		65,677	131,456
Cash and cash equivalents at the end of the period		34,989	80,509
Change in cash and cash equivalents		(30,688)	(50,947)

Condensed consolidated interim statement of changes in equity

€ thousand	Share capital	Share premium	Statutory capital reserve	Other reserves	Foreign currency translation reserve		Total equity
Equity as at 31 December 2022	264,276	60,351	3,259	166,419	(762)	225,190	718,733
Profit for the period	0	0	0	0	0	30,522	30,522
Other comprehensive loss for the period	0	0	0	(689)	(35)	0	(724)
Total comprehensive income for the period	0	0	0	(689)	(35)	30,522	29,798
Equity as at 31 March 2023	264,276	60,351	3,259	165,730	(797)	255,712	748,531
Equity as at 31 December 2023	264,276	60,351	5,556	163,451	(162)	223,718	717,190
Profit for the period	0	0	0	0	0	33,446	33,446
Other comprehensive income for the period	0	0	0	1,115	54	0	1,169
Total comprehensive income for the period	0	0	0	1,115	54	33,446	34,615
Equity as at 31 March 2024	264,276	60,351	5,556	164,566	(108)	257,163	751,804

Notes to the condensed consolidated interim financial statements

1. Summary of significant accounting policies

These condensed consolidated interim financial statements (interim financial statements) have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting and they do not include all the notes normally included in the annual financial statements. Thus, they should be read in conjunction with the group's annual financial statements as at and for the year ended 31 December 2023, which have been prepared in accordance with IFRS as adopted by the European Union.

These interim financial statements have been prepared using the same accounting policies as those applied in the preparation of the group's annual financial statements as at and for the year ended 31 December 2023.

The preparation of interim financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, and income and expenses. Actual results may differ from those estimates. Significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty were mainly the same as those described in the group's annual financial statements as at and for the year ended 31 December 2023.

These interim financial statements have not been audited or otherwise checked by auditors.

2. Financial risk management

Through its activities, the group is exposed to various financial risks: market risk (incl. currency risk, fair value and cash flow interest rate risk, and price risk), credit risk, and liquidity risk. Condensed interim financial statements do not contain all the information about the group's financial risk management which is required to be disclosed in the annual financial statements. Therefore, these interim financial statements should be read in conjunction with group's annual financial statements as at and for the year ended 31 December 2023.

The group uses interest rate swaps (IRS) for interest rate risk management. Interest rate risk is the risk that the fair value or future cash flows of financial instruments will fluctuate because of changes in market interest rates. Cash flow interest rate risk arises from the group's floatingrate borrowings and is the risk that finance costs will increase when interest rates rise. Interest rate risk is mitigated partly by raising debt at fixed interest rates and partly by hedging: raising floating-rate borrowings and fixing their interest expenses with IRS instruments. Information on IRS transactions is disclosed in note 5.

The group regards equity and borrowings (debt) as capital. In order to maintain or change its capital structure, the group may change the dividend distribution rate, repay capital contributions to shareholders, issue new shares or sell assets to reduce its financial liabilities,

3. Segment reporting

The group has identified three main business lines, which are presented as separate reportable segments, and less significant business activities and functions, which are presented within Other. The management board assesses the group's financial performance and makes management decisions on the basis of segment reporting where the reportable operating segments of Enefit Green AS have been identified by reference to the main business lines of its business units. All production units operated by the group have been divided into operating segments based on the way they produce energy. Other internal structural units have been included in the segment Other.

1. Wind energy. The segment comprises the group's operating wind farms and wind farm developments that have an investment decision. From the interim report for Q1 2024, the costs of wind farm development teams and the development costs of wind energy projects without an investment decision are included in the segment Other, not the Wind energy segment (the figures for the comparative period have been adjusted accordingly).

2. Cogeneration. Until the end of 2023 the segment comprised the Iru, Paide, Valka and Brocēni cogeneration plants and a pellet factory. The sale of the Paide, Valka and Brocēni CHP plants and the pellet factory was announced in Q4 2023. The sale of the Brocēni CHP plant and the pellet factory took place before the end of 2023. The sale of the Paide and Valka CHP plants was completed on 1 March 2024. Since completion of the sale of the Paide and Valka CHP plants, the Cogeneration segment has consisted of the Iru cogeneration plant.

3. Solar energy. The segment comprises operating solar farms, solar farm developments and solar services. From the interim report for Q1 2024, the costs of solar farm development teams and the development costs of solar projects without an investment decision are included in the segment Other, not the Solar energy segment (the figures for the comparative period have been adjusted accordingly).

4. Other. The segment comprises hydropower, hybrid renewable energy solutions, and central development and management units. From the interim report for Q1 2024, the segment also includes the costs of the teams involved in the development of wind and solar farms as well as offshore wind farm developments and wind and solar farm development projects without an investment decision (the figures for the comparative period have been adjusted accordingly).

The segment Other comprises activities whose individual contribution to the group's revenue and EBITDA is insignificant. None of those activities exceeds the quantitative thresholds for separate disclosure.

Segment revenues and other operating income include revenues and other operating income from external customers only, generated by the sale of respective products or services. As the segments are based on externally sold products and services, there are no intragroup transactions between segments to be eliminated.

Management assesses segment results mainly on the basis of EBITDA, but also monitors operating profit. Finance income and costs, income tax expense and income and losses on investments in equity-accounted investees (associates) are not allocated to operating segments.

The group's non-current assets are allocated to segments based on their purpose of use. Liabilities and current assets are not allocated to segments. From the interim report for Q1 2024, capitalised interest expenses are allocated to segments (the figures for the comparative period have been adjusted accordingly). Previously, the entire amount was allocated to the segment Other.

Financial results by segments

€ thousand	Q1 2024	Q1 2023
REVENUE
Wind energy	44,769	38,852
Cogeneration	10,444	30,206
Solar energy	829	494
Total reportable segments	56,041	69,551
Other	141	140
Total	56,182	69,691
RENEWABLE ENERGY SUPPORT AND OTHER
OPERATING INCOME
Wind energy	5,531	5,719
Cogeneration	7,118	1,810
Solar energy	73	280
Total reportable segments	12,723	7,809
Other	6	5
Total	12,728	7,814
EBITDA
Wind energy	32,063	30,816
Cogeneration	13,457	12,853
Solar energy	346	283
Total reportable segments	45,866	43,952
Other	(3,446)	(2,840)
Total	42,420	41,112

Depreciation, amortisation and impairment losses	9,342	9,815
Net finance income	264	27
Profit (loss) from associates under the equity method	(10)	19
Profit before tax	33,332	31,343
OPERATING PROFIT
Wind energy	24,886	23,886
Cogeneration	12,011	10,275
Solar energy	59	203
Total reportable segments	36,956	34,364
Other	(3,878)	(3,067)
Total	33,078	31,297

€ thousand	Q1 2024	Q1 2023
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	85,127	75,868
Cogeneration	79	93
Solar energy	18,919	12,412
Total reportable segments	104,124	88,373
Other	689	3,565
Total	104,813	91,938

€ thousand	31 Mar 2024	31 Dec 2023
NON-CURRENT ASSETS
Wind energy	1,029,173	948,412
Cogeneration	93,931	97,747
Solar energy	116,060	96,484
Total reportable segments	1,239,165	1,142,643
Other	16,921	16,165
Total	1,256,086	1,158,808

4. Property, plant and equipment

€ thousand	Land	Buildings	Facilities and structures	Machinery and equipment	Assets under construction	Pre payments	Total
Property, plant and equipment as at 31 December 2023
Cost	63,982	22,299	44,796	747,900	458,834	55,148	1,392,959
Accumulated depreciation	0	(9,788)	(25,439)	(275,527)	0	0	(310,754)
Total property, plant and equipment as at 31 December 2023	63,982	12,511	19,357	472,373	458,834	55,148	1,082,205
Movements in the reporting period
Additions	0	0	4	5	104,407	342	104,758
Exchange differences	0	1	7	54	3	1	66
Transfers	0	0	0	12,078	(10,827)	(1,251)	0
Depreciation and impairment	0	(128)	(327)	(8,737)	0	0	(9,192)
Total movements in the reporting period	0	(127)	(316)	3,400	93,583	(908)	95,632
Property, plant and equipment as at 31 March 2024
Cost	63,982	22,300	44,807	760,037	552,417	54,240	1,497,783
Accumulated depreciation	0	(9,916)	(25,766)	(284,264)	0	0	(319,946)
Carrying amount as at 31 March 2024	63,982	12,384	19,041	475,773	552,417	54,240	1,177,837

At 31 March 2024, the group had committed to capital expenditures of €305,051k (31 December 2023: €368,953k and 31 March 2023: €440,428k).

5. Non-derivative contract liability, derivative financial instruments and hedge accounting

Derivatives are initially recognised at fair value on the date the derivative contract is entered into and are subsequently measured at their fair value. The method for recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if it is, the nature of the item being hedged. At 31 March 2024, the group used cash flow hedging instruments in order to hedge the exposure to interest rate risk resulting from floating-rate borrowings.

The group documents at the inception of the transaction the relationship between the hedging instruments and the hedged items, and its risk management objectives and strategy for undertaking various hedge transactions. The group also documents whether there is an economic relationship between the derivatives that are used in hedging transactions and the changes in the cash flows of the hedged items. At inception of the hedge, the group documents the sources of hedge ineffectiveness. Hedge ineffectiveness is quantified in each reporting period and recognised in profit or loss.

The full fair value of hedging derivatives is classified as a non-current asset or liability when the remaining maturity of the hedging instrument is more than 12 months and as a current asset or liability when the remaining maturity of the hedging instrument is less than 12 months.

The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognised in other comprehensive income. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss as a net amount within other operating income or other operating expenses. The day one fair value of derivative instruments entered into with the parent is recognised directly in equity when its economic substance is a distribution to the parent of resources embodying economic benefits.

Amounts accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects profit or loss (for instance, when the forecasted sale that is hedged takes place).

When a hedging instrument expires or is sold, or when a hedge no longer meets the criteria for hedge accounting, any cumulative gain or loss existing in equity at that time remains in equity and is recognised when the forecasted transaction is ultimately recognised in profit or loss. When a forecasted transaction is no longer expected to occur, the cumulative gain or loss that was reported in equity is immediately recognised in other operating income or other operating expenses in profit or loss.

The different levels for the determination of the fair value of financial instruments have been defined as follows:

• Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;
• Level 2: inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly;
• Level 3: inputs for the asset or liability that are not based on observable market data.

The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The valuation techniques maximise the use of observable market data where it is available and rely as little as possible on the group's own estimates. An instrument is included in Level 3 if one or more significant inputs are not based on observable market data.

Non-derivative contract liability

In 2021, the group used to hedge its exposure to electricity price volatility with baseload swap derivative contracts. Under the given derivatives, the group was the payer of the floating price and the counterparty was the payer of the fixed price. The group applied hedge accounting to these cash flow hedges.

The group agreed with the counterparty (Eesti Energia AS) to terminate the derivative contracts and replace them with fixed price physical delivery contracts (EFET - European Federation of Energy Traders) with the same volumes, prices and periods.

The group continued to apply hedge accounting to the open derivatives positions until 17 August 2021, recognising changes in the fair value of the derivatives until the date of signature of the EFET General Agreement. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k at 31 December 2021 due to the change in the electricity price in the period from the trade date to 17 August 2021. The negative fair value change of €(12,426)k has been recognised in other comprehensive income as no material sources of hedge ineffectiveness were identified in the hedging relationships in the period between the trade date and 17 August 2021. The derivative financial instruments were measured at fair value until the date of conclusion of the EFET General Agreement (measurement date 17 August 2021). Their carrying amount, classified as a contract liability, did not change until the arrival of the supply period determined in the EFET General Agreement, which is 2023–2027.

The EFET General Agreement meets the own use exemption and, therefore, is not considered to be a financial instrument that is required to be measured at fair value under IFRS 9. Rather, it is to be accounted for as an executory contract under IFRS 15 Revenue from Contracts with Customers with the revenue recognised at a fixed per-unit price only when the delivery of electricity takes place in the years 2023–2027. No gains or losses were recognised at the date the derivative contracts were replaced with the EFET General Agreement. Upon entering into the EFET General Agreement, the carrying amount of the derivatives classified as a liability at that date, which was €(23,207)k, was reclassified as a contract liability, which will gradually increase recognised revenue until the EFET General Agreement is fulfilled. The increase in revenue will be partially offset by the reclassification of the €(12,426)k accumulated based on discontinued hedge accounting in the electricity cash flow hedge reserve to profit or loss. The amount is the difference between the fair value of the derivative financial instruments at 17 August 2021 of €(23,207)k and the trade date fair value of the derivatives of €(10,781)k, which was recognised directly in equity.

See note 7 for further information about reserves. At 31 December 2023, the remaining balance of the liability of €18,086k was classified into current and non-current portions of €5,674k and €12,412k, respectively.

The electricity supply period under the EFET agreements began on 1 January 2023. As a result, the contract liability started to decrease. In Q1 2024, the balance of the contract liability decreased by €2,012k and was €(16,074)k at 31 March 2024 (31 March 2023: €(21,441)k). Respective changes were also made to the group's cash flow hedge reserve and to the income statement. The following changes will be made to the group's reserves and income statement in 2024:

€ thousand	Note	Q1 2024	Q2 2024	Q3 2024	Q4 2024	Total
Non-derivative contract liability		(2,012)	(911)	(1,085)	(1,666)	(5,674)
Electricity cash flow hedge reserve	7	1,086	711	679	827	3,303
Gain on derivative financial instruments	10	926	199	406	840	2,371

Interest rate swap transactions

At 31 March 2024, the group had three interest rate swap agreements to hedge the exposure to the interest rate risk of three loans:

• An interest rate swap with a notional amount of €69,565k, whereby the group receives interest at a rate equal to 6-month EURIBOR and pays a fixed rate of interest of 1.1%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan taken out on 30 September 2022.
• An interest rate swap with a notional amount of €47,917k, whereby the group receives interest at a rate equal to 3-month EURIBOR and pays a fixed rate of interest of 1.049%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan taken out on 24 September 2022.
• An interest rate swap with a notional amount of €34,168k, whereby the group receives interest at a rate equal to 6-month EURIBOR and pays a fixed rate of interest of 1.125%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan taken out on 30 June 2022.

The interest rate swaps have been designated as hedging instruments in cash flow hedges. There is an economic relationship between the hedging instruments (interest rate swaps) and the hedged items (the loan agreements) because as at 31 March 2024 the main terms of the interest rate swaps matched the terms of the loans (i.e. their notional amounts, currencies, and maturity, payment and other dates). The forward hedges have a hedge ratio of one to one. To test the hedge effectiveness, the group uses the hypothetical derivative method and compares the changes in the fair values of the interest rate swaps against the changes in the fair values of the loan agreements.

Hedge ineffectiveness can arise from the following sources:

A change in the credit risk of the group or the counterparty of the interest rate swap. The effect of credit risk may cause an imbalance in the economic relationship between the hedging instrument and the hedged item so that the values of the hedging instrument and the hedged item no longer move in opposite directions. According to the assessment of the group's management, it is highly unlikely that credit risk will cause significant hedge ineffectiveness.

At 31 March 2024, the effect of the hedging instruments on the group's statement of financial position was as follows:

€ thousand	Notional amount	Carrying amount (Asset)	Carrying amount (Liability)	Line item in the statement of financial position	Change in fair value*	Hedge ineffectiveness recognised in profit or loss	Amounts transferred from hedge reserve to profit or loss
Interest rate swaps	151,649	8,888	0	Derivatives	1,129	0	1,100

* Change compared to 31 December 2023, recognised in other comprehensive income

At 31 March 2024, the effect of the hedged items on the group's statement of financial position was as follows:

			Amounts recognised in hedge
€ thousand	Change in fair value used to	Amounts recognised in hedge	reserve to which hedge accounting is
	measure ineffectiveness	reserve	no longer applied
Floating rate loans	8,888	8,888	0

Fair value has been measured based on a model from a third party, which was supported by the confirmation of the counterparty to the trade.

In its internal calculations, the group determines the fair value of interest rate swaps by estimating the present value of the expected future cash flows based on the interest rate curves of EURIBOR observable in the market. The fair value measurement takes into account the credit risk of the group and the counterparty, which is calculated based on current credit spreads derived from credit default swaps or bond prices. The fair value of interest rate swaps qualifies as a Level 2 measurement.

6. Share capital

At 31 March 2024, Enefit Green AS had 264,276,232 registered shares (31 March 2023: 264,276,232 shares). The nominal value of a share is €1.

Basic earnings per share (EPS) have been calculated by dividing profit for the period attributable to shareholders of the parent by the weighted average number of ordinary shares outstanding during the period. Since the group has no potential ordinary shares, diluted earnings per share for all periods presented equal basic earnings per share.

Basic and diluted earnings per share based on the weighted average number of shares

	Unit	Q1 2024	Q1 2023
Profit attributable to shareholders of the parent	€ thousand	33,446	30,522
Weighted average number of shares	thousand	264,276	264,276
Basic earnings per share	€	0.13	0.12
Diluted earnings per share	€	0.13	0.12

7. Other reserves

€ thousand	31 March 2024	31 December 2023
Other reserves at the beginning of the period, of which:	165,657	165,657
Foreign currency translation reserve	(162)	(762)
Hedge reserve for cash flow hedges for interest rate risk (interest rate swaps)	8,860	14,626
Hedge reserve for cash flow hedges for electricity price risk	(9,628)	(12,426)
Initial fair value of derivative transactions with the parent	(10,781)	(10,781)
Voluntary financing reserve	175,000	175,000
Change in fair value of cash flow hedges, of which:
Hedge reserve for cash flow hedges for interest rate risk	1,129	(2,221)
Recognised as a decrease of a contract liability	1,086	2,798
Reclassified from other comprehensive income, recognised as a change in interest expense	(1,100)	(3,545)
Exchange differences on the translation of foreign operations	54	600
Other reserves at the end of the period, of which:	164,458	163,289
Foreign currency translation reserve	(108)	(162)
Hedge reserve for cash flow hedges for interest rate risk (interest rate swaps)	8,888	8,860
Hedge reserve for cash flow hedges for electricity price risk	(8,541)	(9,628)
Initial fair value of derivative transactions with the parent	(10,781)	(10,781)
Voluntary financing reserve	175,000	175,000

8. Borrowings at amortised cost

	Current borrowings				Non-current borrowings
€ thousand	Interest	Bank loans	Lease liabilities	Bank loans	Lease liabilities	Total
Borrowings at amortised cost as at 31 December 2023	3,967	27,414	745	445,174	9,098	486,398
Movements in the reporting period
Monetary movements
Borrowings received	6,179	30,000	10	0	35	36,224
Repayments of borrowings	(7,739)	(9,012)	(58)	0	0	(16,809)
Non-monetary movements
Transfers	0	16,378	(206)	(16,378)	206	0
Amortisation of borrowing costs	0	0	0	12	0	12
Effect of movements in foreign exchange rates	1	0	0	0	(266)	(265)
Other movements	0	6	0	35	0	41
Total movements in the reporting period	(1,559)	37,372	(254)	(16,331)	(25)	19,203
Borrowings at amortised cost as at 31 March 2024	2,408	64,786	491	428,843	9,073	505,601

9. Revenue

€ thousand	Q1 2024	Q1 2023
Revenue by activity
Sale of goods
Pellets	0	15,676
Scrap metal	119	263
Other goods	43	9
Total sale of goods	162	15,948
Sale of services
Heat	2,434	3,276
Electricity	49,379	45,531
Waste reception and resale	3,968	4,593
Rental and maintenance of assets	213	248
Other services	36	95
Total sale of services	56,030	53,743
Total revenue	56,192	69,691

Note: From December 2023, income from power derivatives will be recognized under "electricity sales". Due to this, the line "electricity sales" in Q1 2023 has been corrected by +€906k.

10. Renewable energy support and other operating income

€ thousand	Q1 2024	Q1 2023
Renewable energy support	6,393	7,268
Government grants	99	123
Gain on sale of a business	5,759	0
Other income	478	422
Total renewable energy support and other operating income	12,729	7,813

Note: From December 2023, income from power derivatives will be recognized under "electricity sales". Due to this, the line "gain on derivatives" in the amount €906k has been removed from the table in Q1 2023.

11. Raw materials, consumables and services used

€ thousand	Q1 2024	Q1 2023
Maintenance and repairs	3,532	3,102
Technological fuel	1,153	8,359
Electricity	14,830	11,461
Services related to ash treatment	461	563
Transport services for sale of finished goods	0	569
Materials and spare parts for production	242	411
Transmission services	204	115
Waste handling	94	80
Resource charges for natural resources	1	1
Other raw materials, consumables and services used	60	50
Environmental pollution charges	97	81
Total raw materials, consumables and services used	20,674	24,792

12. Cash generated from operations

€ thousand	Q1 2024	Q1 2023
Profit before tax	33,339	31,342
Adjustments
Depreciation and impairment of property, plant and equipment	9,286	9,706
Amortisation and impairment of intangible assets	56	109
Amortisation of government grants related to assets	(98)	(123)
Interest expense on borrowings	224	380
Gain on disposal of an investment in a subsidiary	(5,759)	0
Loss (profit) from associates under the equity method	10	(19)
Interest and other finance income	(459)	(311)
Other investment (gains) losses	13	0
Foreign exchange (gain) loss on loans granted and taken	40	15
Realised gain on derivative financial instruments	(926)	(905)
Adjusted profit before tax	35,726	40,194
Net change in current assets related to operating activities
Change in receivables related to operating activities	623	339
Change in inventories	104	5,600
Net change in other current assets related to operating activities	10,741	(5,812)
Total net change in current assets related to operating activities	11,468	127
Net change in current liabilities related to operating activities
Change in trade payables	(10,869)	1,217
Net change in other current liabilities related to operating activities	(1,162)	2,799
Total net change in current liabilities related to operating activities	(12,031)	4,016
Cash generated from operations	35,163	44,337

13. Transactions and balances with related parties

The parent of Enefit Green AS is Eesti Energia AS. At 31 March 2024, the sole shareholder of Eesti Energia AS was the Republic of Estonia.

For the purposes of the condensed consolidated interim financial statements of Enefit Green, related parties include the shareholders, other companies belonging to the same group (group companies), members of the executive and higher management, and close family members of the above persons and companies under their control or significant influence. Related parties also include entities under the control or significant influence of the state.

The Group has applied the exemption from disclosure of individually insignificant transactions and balances with the government and other related parties where the state has control or joint control of, or significant influence over, such parties.

Enefit Green AS and its subsidiaries produce renewable energy that is sold directly to third parties (incl. to the Nord Pool power exchange). The parent, Eesti Energia AS, provides Enefit Green AS with back-office services to assist in those sales procedures. The costs related to the services are presented in the table within purchases of services.

The group also discloses transactions with companies under the control or significant influence of the state. In the reporting and the comparative period, the group conducted ordinary purchase and sales transactions with the Estonian transmission system operator Elering AS, which is wholly owned by the state.

At 31 March 2024, Enefit Green AS had signed long-term power purchase agreements for the physical supply of electricity of 8,266 GWh with Eesti Energia AS in the Lithuanian, Estonian, Finnish and Polish electricity networks in the period April 2023 – December 2033. The contracts are for the supply of both annual and monthly baseload energy. The weighted average price of the power purchase agreements for the physical supply of electricity signed with the related party is €68.0/MWh.

At the beginning of 2021, the group used baseload swap derivative contracts in order to hedge the exposure to variability in the price of electricity. The initial fair value of the derivatives designated as hedging instruments of €(10,781)k was recognised directly in equity. The group continued to apply hedge accounting to the open derivatives positions until 17 August 2021, when an EFET General Agreement Concerning the Delivery and Acceptance of Electricity (EFET General Agreement) was signed and all open derivative contracts were simultaneously terminated. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k due to the change in the electricity price in the period from the trade date to 17 August 2021. The cumulative change in the fair value of the derivative financial instruments of €(12,426)k was recognised through other comprehensive income and the cash flow hedge reserve in equity (see also note 5). At 31 March 2024, the balance of the electricity cash flow hedge reserve was €(8,541)k (see also notes 5 and 7).

€ thousand	Q1 2024	Q1 2023		31 March 2024	31 Dec 2023
TRANSACTIONS		BALANCES
PARENT
Purchase of services	5,595	4,464	Receivables	8,765	9,497
Sale of goods	0	0	Payables	17,166	20,281
Sale of services	26,001	23,457	Of which non-derivative contract liability	16,074	18,086
OTHER GROUP COMPANIES
Purchase of goods	0	0	Receivables	556	314
Purchase of services	352	857	Payables	62	62
Sale of goods	0	0
Sale of services	1,592	420
OTHER RELATED PARTIES (INCL. ASSOCIATES)
Purchase of services	417	456	Receivables	0	22
Sale of services	0	0	Payables	334	311
ELERING AS
Purchase of services	252	1,587	Receivables	2,748	5,629
Sale of services	6,408	7,330	Payables	95	33

Group structure