Unaudited interim report

Letter from the CEO	3
Path towards 4X growth	4
Projects under construction	5
Near term development portfolio	6
Complete view of the development portfolio	7
3Q 2023 Key highlights	8
9 months 2023 Key highlights	9
Operating environment	10
Regulatory environment	12
Significant events in Q3	14
Financial results of the group	15
Financial results by segments	19
Wind energy segment	20
Cogeneration segment	22
Solar energy segment	24
Investments	25
Financing	26
Risk management	28
Unaudited condensed consolidated interim financial statements Q3 2023	30
Notes to the condensed consolidated interim financial statements	36
Group structure	47

Letter from the CEO

Dear reader

Electricity prices stabilised somewhat in Q3 this year. Although comparisons with last year's exceptionally high levels reflect a steep fall in prices, the Baltic markets saw a slight increase and other Nord Pool markets saw a slight decrease in electricity prices relative to Q2. The main factors that influence electricity prices are lower natural gas prices, higher wind power production, and strong hydropower production.

Intraday electricity prices on the Nord Pool power exchange have fluctuated widely in recent years and will also remain volatile in the future. The highest average daily electricity price in Q3 was 243.7 €/MWh while the lowest 4.9 €/MWh. Enefit Green's average implied captured electricity price was 84.9 €/MWh, which is 58% lower than a year earlier when it was 205.1 €/MWh.

As in previous periods, our new wind and solar farms, including those still under construction, made a strong 53 GWh contribution to our quarterly electricity production (+38.1 GWh and + 14.9 GWh, respectively). Electricity production in Q3 grew by 37% year on year, rising to 259 GWh. Heat production grew by 37% to 115 GWh.

The Tolpanvaara wind farm (72 MW) in northern Finland, which is still under construction, began producing electricity. After being offline for four months, 11 of the 14 wind turbines in the Akmene wind farm (75 MW) were again brought online. A thorough investigation revealed that the collapse of a turbine in May was caused by a malfunctioning sensor that sent incorrect information to the turbine controller, which led to an excessive load being placed on the tower structure. We are going to continue the construction work so that all 14 wind turbines would be ready for network and other tests as well as power production by the end of November. The Akmene wind farm should be fully complete and operational by the end of Q1 2024.

Enefit Green's Q3 energy production was undermined by availability and reliability issues at our operating wind farms, particularly in Lithuania. Several unplanned production interruptions at the Šilute wind farm, including the repair of the distribution equipment of a substation, had the strongest effect. Although the Šilute wind farm has an operating and maintenance agreement with availability guarantee with General Electric which is effective until 2036, we have decided to commission an independent expert opinion to identify the technical risks associated with the operation of the wind farm as well as relevant risk mitigation activities. At the Mockiai wind farm, the main bearings of a wind turbine had to be replaced. At our Estonian wind farms, planned overhaul of turbine blades was carried out and two gearboxes were replaced.

The factors which affected electricity production and prices, lowered operating income for Q3 by 26% to €44.5m. Although new wind and solar farms contributed strongly, electricity production did not meet the target. Due to the suspension of operations at the Akmene wind farm, the commitments taken under long-term power purchase agreements signed to hedge price risk had to be fulfilled in another way. Electricity purchased at higher prices in order to balance the electricity portfolio lowered EBITDA to €15.9m.

Fixed costs grew by €2.2m, driven by higher operating and development costs. The main cost drivers were maintenance, payroll, research, and consulting expenses, which are essential for the group's growth and long-term operation.

We invested nearly €87m in Q3. The largest amounts were allocated to the construction of the Sopi-Tootsi (255 MW), Kelme I (80 MW) and Tolpanvaara (72 MW) wind farms. We also continued developing our long-term portfolio. Good progress was made with the Risti wind farm project where the Lääne-Nigula local authority approved phase 1 of a special spatial plan.

In order to build the Sopi-Tootsi wind farm, which the largest wind power production facility in the Baltics to date, we entered into a partnership with the European Investment Bank (EIB). The €180m loan agreement signed with EIB not only provides the required funding but also confirms the sustainability of the project and our shared commitment to the achievement of climate goals.

In the current geopolitical and macroeconomic environment, the transition to clean sources of energy requires all stakeholders to make an effort. Surging prices and interest rate spikes also affect the renewable energy sector (through growth in the cost of technologies, construction and capital). However, the decisions made and the steps taken by the European Union reflect unequivocally that our energy system will switch to renewable energy and wind power will grow the most. According to the forecasts of the International Energy Agency, renewable power plants will account for 80% of new electricity production capacities by 2030.

The last quarter of the year, which is about to start, is the most important for us and we are ready for it. Enefit Green is a growth-oriented company with a strong short- and long-term development portfolio with which we will move forward. In the light of developments the operating environment, particularly the uptrend in the cost of capital and wind power investments, we will focus on ensuring the promised return on capital. The risks inherent in the variability of power production and their impact on the results of long-term power purchase agreements will also affect our performance in the future. We monitor price risks in the electricity market with due care and regularly test our portfolio models to make sure that our risk mitigation measures will produce the desired results.

Aavo Kärmas CEO

Enefit Green | Q3 2023 interim report | 4

Path towards 4X growth

Operating Under construction

Projects under construction

* Following projects have been categorized as operating: Purtse WF (21MW), Purtse PV (32MW), Zambrow PV (9MW). Grid tests are being carried out in Purtse. In Zambrow grid tests are completed, waiting for official production permit.

** COD – Commercial Operating Date

Near term development portfolio

NB! Development projects are in continuous change.

The presented information is management team's best assessment of the status of the near-term development portfolio as of 31 October 2023

Complete view of the development portfolio

NB! Development projects are in continuous change.

* Various onshore wind and solar farm developments that are not expected to get final investment decision before 2024.

** Also known as Hiiumaa offshore wind farm

3Q 2023 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

€180m New 12-year loan facility from EIB

+53 GWh Production from new wind and solar farms

9 months 2023 Key highlights

+62 MW New operating capacity Purtse & Zambrow)

+147 GWh Production from new wind and solar farms under construction

€505m New loan agreements (SEB, NIB, EIB)

74MW Sopi solar farm FID

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 fluctuations in the market price of electricity. We mitigate electricity price risk with long-term PPAs. The share of various national renewable energy support schemes in our operating income has decreased significantly compared with previous years. Assets currently eligible to support include mainly production assets in Estonia whose 12-year support period has not yet expired and which therefore receive Feed-in Premium (FiP) in addition to the market price of electricity. The FiP support for the production of approximately 55 GWh and 363 GWh of electricity will expire in 2024 and 2025, respectively. After 2025, the amount of FiP received will be negligible. A more detailed overview of the coverage of the next years' expected electricity output with PPAs and other risk mitigation measures (incl. Contracts for Difference (CfDs) in Poland and the new price floor measure in Estonia) is provided at the end of the management report.

Electricity market

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

Intraday electricity prices on the Nord Pool (NP) power exchange have been highly volatile in recent years. Usually, the peak load electricity price is determined by the more expensive carbon-intensive power and the base load electricity price is determined by renewable power.

Electricity prices in our core markets decreased in Q3 due to lower natural gas prices, growing wind power production, and strong hydropower production in the neighbouring countries.

The International Energy Agency (IEA) expects electricity demand in the European Union (EU) to drop by 3% for the second consecutive year and to hit the past 20 years' lowest level in 2023. The main reason is weaker demand from the industrial sector, which has scaled back production. Electricity demand in the markets where Enefit Green operates has also decreased.

Average electricity price (€/MWh)	Q3 2023	Q3 2022	Change
Estonia	95.6	275.0	(65.2)%
Latvia	101.0	374.8	(73.0)%
Lithuania	101.0	382.1	(73.6)%
Poland	110.7	213.1	(48.0)%
Finland	44.2	220.3	(79.9)%
Norway	23.6	167.6	(85.9)%
Denmark	78.7	347.9	(77.4)%
Sweden	27.3	118.9	(77.0)%

In addition to shrinking demand, Q3 electricity prices on the Nord Pool power exchange were affected by maintenance operations at the region's nuclear power plants. The prices in the NP Estonia price area were influenced the most by the maintenance of the Finnish Olkiluoto 2 nuclear reactor which began in the second half of August. While higher wind power production lowered Baltic electricity prices at the beginning of the quarter, the maintenance of the Finnish nuclear power plant drove up the prices, enabling producers to also generate electricity from natural gas.

In peak hours, the electricity price in the region is typically determined by gas-fired power plants. As natural gas prices have declined significantly, peak hour electricity prices in Q3 2023 were lower than a year earlier. The average daily electricity price in Q3 was the highest on 21 August, when it was 243.7 €/MWh (438.4 €/MWh lower than in Q3 2022) and the lowest on 2 July, when it was 4.9 €/MWh (69.8 €/MWh lower than in Q3 2022).

The average price of natural gas on the Dutch gas trading platform TTF was 33.8 €/MWh in Q3 2023 (173.1 €/MWh, 83.7% lower than in Q3 2022). The price increased slightly compared with Q2 2023, mainly due to factors related to LNG production in Australia which reduced the global LNG supply by 6%. The share of LNG imports to Asia has grown as well, rising from 21% of overall LNG sales in the first half of 2023 to 35% in Q3. While the decrease in LNG supply in Europe is putting upward pressure on the price of natural gas, historically high levels of gas inventories in Europe are keeping the prices of natural gas relatively stable.

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 hydro reservoirs in Q3 2023 was 75.7% of the maximum, which is 4.6 percentage points higher than in Q3 2022.

As the volume of snow and surface water accumulated in the reservoirs this year is 17 TWh higher than a year earlier, hydropower production in 2023 is expected to increase year on year. Higher hydropower production will lower electricity prices in the region because a larger share of the required electricity can be produced by facilities with lower variable costs.

Consistent with the purpose of the EU Emissions Trading System, in recent years the competitiveness of renewable energy in the EU has been supported by the relatively high price of CO² emission allowances. The average CO2 emission allowance price in Q3 2023 was 85.7 €/t, which is 7% (5.6 €/t) higher than in Q3 2022, but 2.9 €/t lower than in Q2 2023. The decline compared with Q2 is attributable to larger quantities of allowances traded, unusually warm weather, and forecasts of growth in renewable energy production.

Wind conditions

Due to seasonal factors, wind conditions in Q2 and Q3 are less favourable for wind power production in our region than the rest of the year. In Q3 2023, the average measured wind speeds in Enefit Green's wind farms in Estonia and Lithuania were at recent years' average level: 5.7 m/s and 5.6 m/s, respectively, but slightly better than in the same period last year (Q3 2022: 5.2 m/s and 5.5 m/s, respectively). The chart below provides an overview of the average quarterly wind speeds in Estonia and Lithuania since the beginning of 2021.

Regulatory environment

European Union

The European Parliament approved amendments to the Renewable Energy Directive, setting a new target of raising the share of renewable energy in the EU's overall energy consumption to at least 42.5%, with the aspiration to reach 45%, by 2030. Permit procedures for renewable energy projects are going to be simplified and the rules for the production of new renewable fuels for the transport sector (incl. hydrogen) were established.

In the coming months, the European Commission will be working on a package of measures designed to support the development of the wind industry by accelerating permitting, improving wind power auction systems, and increasing the availability of skilled labour, access to finance, and supply chain resilience.

In October, the EU energy ministers agreed the general approach to the EU electricity market reform. The deadlock over Contracts for Difference (CfDs) was finally broken and it was agreed that they can be used to support both the construction of new renewable power plants and mitigating the risks of renovating existing nuclear power plants. The decision may affect the renewable energy investment environment in the markets where Enefit Green operates. The wording of the EU electricity market reform is expected to be finalised by the end of 2023.

Estonia

Estonia's new government has launched changes to legislation and published:

amendments to the Environmental Charges Act, which will increase the pollution charges for combined heat and power (CHP) plants;
a package of legislative amendments aimed at accelerating the deployment of renewable energy;
amendments to the composition of data included in the report on the fuel used for electricity production and to the procedure for completing and verifying the report, which will introduce additional requirements for the production of electricity from waste in order to enable the analysis of the composition of the fuel used;
a policy paper outlining its intention to draft a Climate Act.

The Competition Authority conducted a public consultation in connection with the approval of the new network charges of the transmission system operator Elering. According to the changes, power plants will be established monthly network charges based on their contractual capacity and consumption points, and the charges for generating electricity from wind and solar will increase relatively more. Elering's new network charges will take effect from 1 January 2024.

Latvia

Latvia's transmission system operator took an exceptional step and temporarily suspended issuing technical specifications to new electricity producers wishing to connect to the grid in places where the 330 kV grid needs to be reconstructed to ensure successful connection.

The Latvian government supplemented the Cabinet regulation which grants Latvijas Vēja Parki, a joint venture of Latvenergo and Latvia's state forest management company, an exclusive preemptive right to select sites suitable for wind farms before the rights to develop wind farms on state-owned land are auctioned off to other wind farm developers.

Lithuania

The European Commission approved a €193m scheme to support the construction of a 700 MW offshore wind farm in Lithuania's coastal waters. The beneficiary will be selected through a competitive bidding process. The support will be provided through the two-way CfD scheme for a period of 15 years.

The government published a draft Property Tax Act, which setsthe land tax rate for wind power producers at 0.5% until the end of 2031. This would reduce the land tax risk as the current law allows local authorities to set the property tax rate for wind farms at up to 3%.

Since July, producers of electricity from renewable energy sources have also received guarantees of origin for electricity produced and delivered to the grid during the testing period of the power plant. This has made the rules on guarantees of origin fairer for producers.

Poland

Poland's Energy Act was amended to allow additional power production installations to be connected to the grid using the connection point of an existing power production facility: for example, to connect a wind turbine via the connection point of a solar power plant. Allowing hybrid solutions (infrastructure sharing) will reduce the construction costs of new power plants.

Amendments made to the Planning Act prohibit the construction of solar power plants on land plots with class IV soil starting from the beginning of 2025 when fast-track permitting is used. This will reduce the land available for rapid expansion of solar power production and will increase the need to use significantly longer planning proceedings.

Finland

The EU held its first cross-border renewable energy tender in which Finland and Luxembourg participated as the host and the contributing country, respectively. Based on the results, investment support will be awarded for developing in Finland photovoltaic (PV) projects ranging from 5 MW to 100 MW and with a total combined capacity of up to 400 MW.

In September, the Finnish wind discount was 61%, an all-time high. However, the Finnish district heating market regulation, which does not administratively regulate the price of heat, allows efficient use of power to heat. The investment decisions already made on power-to-heat solutions in Finland suggest that in a market regulated in such a manner, wind power producers' minimum sales price will be determined by the price of heat.

Significant events in Q3

Cornerstone laid for the most powerful and modern renewable energy facility in the Baltics

We laid the cornerstone for the Sopi-Tootsi renewable energy production area. We are going to use the abandoned Tootsi peat production field to repurpose the currently low-value land by building a hybrid facility consisting of a wind and a solar farm, which will meet nearly a tenth of Estonia's current electricity consumption.

We are going to install 38 wind turbines with a total capacity of 255 MW and build a solar power plant with around 112,000 bifacial solar panels and a total capacity of 74 MW. The projected combined annual output of the Sopi-Tootsi facility is 750 GWh.

First electricity delivered by the Tolpanvaara wind farm

Our Tolpanvaara wind farm in northern Finland has delivered its first electricity to the grid. All 13 wind turbines have been installed and their testing and commissioning is under way. The Tolpanvaara wind farm should come fully online by the year-end. When completed, it will produce nearly 250 GWh of electricity per year, which is sufficient to meet the annual electricity consumption of nearly 40,000 Finnish households.

Enefit Green's total investment in the wind farm extends to nearly €83m. Most of the expenditure will be covered with long-term PPAs signed with consumers interested in using green energy and fixing their contract terms and conditions.

Loan agreement with European Investment Bank

Enefit Green and the European Investment Bank signed a €180m loan agreement for the construction of the Sopi-Tootsi wind farm. It is the largest single investment in onshore wind power in Estonia to date. The loan term is 12 years.

The new funding accounts for a major share of the financing of our ongoing investment programme. It will also contribute to the implementation of climate measures and social cohesion, the reduction Estonia's CO² emissions, and the achievement of climate neutrality.

Approval of phase 1 of a special spatial plan for wind power development in Lääne-Nigula

The Lääne-Nigula local authority approved phase 1 of a special spatial plan for the development of wind power in Lääne-Nigula municipality. The decision enables Enefit Green to proceed with the development of the Risti wind farm.

We reached agreement with the local authority and community that we will install up to 25 wind turbines with a height of up to 270 metres. A more detailed solution, including the precise locations of the turbines, will be determined in phase 2 of the special spatial plan process.

Incidents of potential misconduct

Enefit Green's internal audit investigations revealed two separate incidents of potential misconduct in Q3. When sufficient evidence had been obtained, the information was handed over to the law enforcement authorities of the countries involved. Both incidents were related to the performance of procurement proceedings. The Estonian law enforcement authorities detained two employees of Enefit Green's Iru power plant and the Lithuanian law enforcement authorities detained an employee of a Polish company that participated in procurement proceedings arranged by Enefit Green.

Enefit Green has zero tolerance for unethical and fraudulent behaviour among employees and business partners.

Enefit Green has issued stock exchange announcements in respect of both incidents but cannot release further information or comments because the investigation is still ongoing.

Situation in the Akmene wind farm

After a through four-month analysis aimed at determining the root cause of the incident which occurred at the Akmene wind farm at the beginning of May, the management board of Enefit Green decided at the beginning of September that wind turbines not affected by the incident would be gradually brought online. By the end of October, 11 of the wind farm's 14 wind turbines were back in operation.

Enefit Green's goal is to complete the construction of the Akmene wind farm by the end of Q1 2024.

Financial results of the group

The Enefit Green group's operating income for Q3 2023 decreased by 26% while operating expenses for the period grew by 4% compared with the same period last year. As a result, EBITDA dropped by 51% to €15.9m. Net profit for the period decreased by €17.9m to €5.0m. The key factors which influenced the group's financial performance are described below.

Production and sales volumes

		Q3 2023	Q3 2022	Change	Change, %
Electricity production (net)	GWh	259	189	70	37%
Of which by new wind and solar farms	GWh	53	-	53	-
Electricity sales*	GWh	364	201	164	82%
Heat production	GWh	115	84	31	37%
Pellet production	kt**	38	39	(1)	(2)%
Pellet sales	kt	17	39	(22)	(56)%

Operating income

Total operating income decreased by €15.8m year on year, the figure comprising a decrease in revenue of €18.0m and an increase in renewable energy support and other operating income of €2.2m. Out of the €18.0m decrease in revenue, €11.0m was attributable to electricity sales which weakened mainly because the market prices of electricity were lower than a year earlier. The average electricity price*** in the group's core markets in Q3 2023 was 97.8 €/MWh (Q3 2022: 317.7 €/MWh). The group's average implied captured electricity price**** for the period was 84.9 €/MWh (Q3 2022: 205.1 €/MWh). The implied captured electricity price differs from the average market price in the core markets, because it is calculated by taking into account long-term fixed-price 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 Q3 2023 was 82.2 €/MWh compared with 285.2 €/MWh a year earlier. The group sold to the market 163 GWh of electricity in Q3 2023 compared with 120 GWh in Q3 2022.

In Q3 2023, 202 GWh of the group's portfolio was covered with PPAs at an average price of 80.9 €/MWh. A year earlier, 81 GWh of electricity was sold under an income model based on PPAs and the Feed-in Tariff (FiT) at an average price of 72.1 €/MWh. The share and prices of production covered with PPAs in future periods are disclosed in the risk management chapter.

	Q3 2023	Q3 2022	Change	Change %
TOTAL OPERATING INCOME	44.5	60.3	(15.8)	(26)%
Revenue	39.3	57.3	(18.0)	(31)%
Renewable energy support
and other operating income	5.2	3.0	2.2	74%
TOTAL OPERATING EXPENSES
(excl. D&A)	28.6	27.5	1.1	4%
Raw materials, consumables
and services used	26.0	25.0	1.0	4%
Payroll expenses	2.6	2.0	0.6	30%
Other operating expenses	3.4	2.6	0.8	32%
Change in inventories	(3.4)	(2.0)	(1.4)	69%
EBITDA	15.9	32.7	(16.8)	(51)%
Depreciation, amortisation
and impairment (D&A)	10.2	9.6	0.6	6%
OPERATING PROFIT	5.7	23.1	(17.4)	(75)%
Net finance income and costs	(0.4)	(0.3)	(0.1)	44%
Profit from associates under
the equity method	0.0	0.1	(0.1)	(63)%
Income tax expense	0.3	0.0	0.3	-
NET PROFIT	5.0	22.9	(17.9)	(78)%

TOTAL OPERATING EXPENSES	28.6	27.5	1.1	4%
(excl. D&A)
Variable costs (incl. balancing	20.5	20.3	0.2	1%
energy purchases)
Fixed costs	11.5	9.3	2.2	24%
Change in inventories	(3.4)	(2.0)	(1.4)	69%

Pellet sales revenue decreased by €3.0m year on year. While the average sales price of pellets increased by 32%, rising from 182.6 €/t in Q3 2022 to 240.6 €/t in Q3 2023, pellet sales volume decreased from 39 thousand tonnes in the comparative period to 17 thousand tonnes in the reporting period.

Heat production grew by 31 GWh to 115 GWh (Q3 2022: 84 GWh) but the price dropped by 14% (1.8 €/MWh). Through the combined effect of higher production and a lower price, heat sales revenue grew by €1.3m.

Revenue for Q3 2022 was also €3.2m higher due the sale of the inventories of the turnkey solar solutions business. We decided to exit the turnkey solar solutions business and sold relevant inventories in the comparative period.

^* The difference between the quantities of electricity sold and produced is attributable to differences between sales under base load PPAs and wind 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. ** k = thousand tonnes

^*** 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) / production

An overview of the quantities of electricity produced, purchased and sold as well as the realised sales, purchase and market prices and the implied captured electricity price for the past five quarters is presented in the charts below.

We purchased from the market 110 GWh of electricity at an average price of 116.5 €/MWh in Q3 2023, compared with 16 GWh at an average price of 337.7 €/MWh in the same period last year (the prices and quantities exclude the electricity purchased for pellet production). In Q3 2022, purchases from the market were substantially smaller because part of the production was covered with the fixed-price FiT support scheme and the volume of PPAs was very small. Electricity purchases were also increased by lower than expected electricity production. The electricity price in Enefit Green's core markets, which is presented in the chart, is the average quarterly price in the Baltic and Polish markets, weighted by Enefit Green's production volumes. The price was 97.8 €/MWh in Q3 2023 and 317.7 €/MWh in Q3 2022.

Average quarterly electricity prices

	Q3 2022	Q4 2022	Q1 2023	Q2 2023	Q3 2023
Price of electricity sold to the market	285.2	179.0	82.4	63.7	82.2
PPA price (incl. FiT until Q4 2022)	72.1	126.2	89.8	83.5	80.9
Realised purchase price	337.7	271.1	116.7	83.8	116.5
Core markets' average electricity price*	317.7	221.5	100.5	78.7	97.8
Implied captured electricity price **	205.1	163.0	101.4	89.9	84.9

* 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) / production

Renewable energy support and other operating income

Renewable energy support and other operating income for Q3 2023 were affected the most by renewable energy support, which grew by €1.4m year on year. The growth in renewable energy support was influenced by the support schemes of our solar farms in Poland: in Q3 2022 we had to repay renewable energy support of €0.7 million under the Polish CfD schemes. Renewable energy support received in Poland in Q3 2023 amounted to €16k. The renewable energy support received by our operating wind farms in Estonia and the Iru power plant grew by €0.3m and €0.4m, respectively. The amount of renewable energy support received is based on the quantity of energy produced. Although the eligibility periods of the Vanaküla and Virtsu III wind farms expired in Q3 2022 (contribution to operating income for the comparative period: €0.2m), the output of wind farms eligible for support in both periods grew by 13.6 GWh year on year (impact on operating income: +€0.5m). The renewable energy output of the Iru power plant grew from 6.2 GWh a year earlier to 10.5 GWh, increasing operating income by €0.4m.

Other operating income was improved by the decrease in the non-derivative contract liability incurred in 2021 by €0.4m in connection with partial fulfilment of relevant PPAs and liquidated damages of €0.4m received for the low availability of the Šilute wind farm. The non-derivative contract liability results from earlier electricity derivatives (base load swaps) which were converted into fixed-price physical electricity sales contracts (PPAs). The decrease in the nonderivative contract liability does not affect cash flow and monetary settlement of electricity sales takes place on the basis of PPAs.

Raw materials, consumables and services used

Expenses on raw materials, consumables and services grew by €1.0m (4%). The biggest rise was in electricity expenses, which grew by €5.6m due to growth in electricity purchased from the Nord Pool intraday market to balance the portfolio and the electricity purchased to balance the PPA portfolio in hours of low wind speed; a contributing factor was lower than expected production volume. The quantities and prices of electricity purchased from the market are disclosed in the operating income chapter. Other direct production costs decreased by €5.4m because in mid-2022 we exited the turnkey solar solutions business.

Payroll expenses

The group's payroll expenses grew by 30% year on year due to an increase in the number of fulltime employees from 172 to 192 and growth in the compensation of existing employees. New people were mostly hired to the development team to support the group's growth plan in all core markets.

Other operating expenses

Other operating expenses grew by €0.8m (32%), driven by growth in the research and consulting expenses of development projects as well as a slight increase in IT and insurance expenses.

Change in inventories

The change in inventories reflects the change in pellet stocks, summarising the quantities of pellets produced and sold in the period under review. In Q3 2023, the group produced 38 thousand tonnes (Q3 2022: 39 thousand tonnes) and sold 17 thousand tonnes (Q3 2022: 39 thousand tonnes) of pellets. The change in inventories was negative at €3.4m (Q3 2022: negative at €2.0m). The average sales price of pellets increased by 32% compared with the same period last year, rising from 182.6 €/t in Q3 2022 to 240.6 €/t in Q3 2023.

EBITDA and fixed costs

The factor with the strongest impact on EBITDA development was the price of electricity sold, which fell steeply compared with Q3 2022 (negative impact: €25.1m). Due to PPAs the quantity of electricity sold grew considerably (positive impact: €15.5m), which also increased the volume of electricity purchased to balance the electricity portfolio (negative impact: €11.2m). The combined effect of the above factors on EBITDA development is influenced by the quantity and profile of electricity produced during the period. Electricity production grew by 37% compared with Q3 2022.

Excluding the effects of the electricity price and quantity, the Cogeneration segment had a positive impact on EBITDA. The calculation takes into account the effects of pellet sales revenue, the change in inventories, technological fuel, and heat sales revenue.

The change in the non-derivative liability increased EBITDA. See the renewable energy support and other operating income chapter for further information.

Fixed costs comprise costs not directly dependent on the production volume. Fixed costs grew by €2.2m (24%) year on year. The increase in fixed costs was attributable to higher maintenance costs, payroll expenses, and research and consulting expenses.

Depreciation, amortisation and impairment (D&A)

D&A expense grew by €0.6m (6%) compared with the same period last year. Major assets recognised during the period included the Purtse wind farm in Estonia and the Zambrow solar farm in Poland: each increased the group's Q3 depreciation expense by €0.3m.

Net finance income and costs

Net finance costs for Q3 2023 grew by €0.1m year on year. Interest expense on bank loans grew by €3.6m but 98% of it was capitalised due to the construction period of the wind farms. Growth in interest income had a positive effect on net finance costs.

Group's EBITDA change by drivers, €m

Income tax

Income tax expense grew by €0.3m compared with the same period last year.

Net profit

The group's net profit decreased by €17.9m year on year to €5.0m. The decline is attributable to lower electricity prices and higher expenses on electricity purchased to balance the electricity portfolio.

Financial results by segments

Based on total operating income and EBITDA, the group's largest segment is Wind energy, which accounted for 61% of operating income and 64% of EBITDA for Q3 2023. The Cogeneration segment contributed 33% to operating income and 41% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 6% the group's operating income and 10% of the group's EBITDA for Q3 2023.

In terms of reportable segments, the EBITDA of the Wind energy segment and the Cogeneration segment decreased the most. A more detailed analysis by segment is presented below.

The EBITDA of the segment Other mainly includes general administrative expenses, which is the largest item for the segment. The segment also includes the network construction services of the Paide CHP facility, the Keila-Joa hydroelectric facility, and the renewable energy solution on the island of Ruhnu. The loss of the segment Other increased by €0.4m.

Group's EBITDA breakdown and change, €m

Operating income by segment, €m

60.3

Wind energy segment

The Wind energy segment comprises operating wind farms, wind farm developments and the management expenses of both wind farm developments and operating wind farms.

Availability and production

In Q3 2023, the average measured wind speed in Estonia and Lithuania was at recent years' average level: 5.7 m/s in Estonia and 5.6 m/s in Lithuania (Q3 2022: 5.2 m/s and 5.5 m/s respectively). Thus, wind conditions were slightly better than in Q3 2022. However, there were some serious issues with the availability of our wind farms, particularly in Lithuania. The factor with the strongest effect on the Q3 availability indicator was the combined effect of several unplanned outages at the Šilute wind farm, which were caused by the failure of the mains cables of the substation that triggered the need to repair the power distribution equipment (lowered availability by 5 percentage points), failures of the wind turbines' central control equipment (lowered availability by 2.4 percentage points), and failures of the blade control systems (lowered availability by 2 percentage points). At the Mockiai wind farm, the main bearings of an Enercon wind turbine had to be replaced (lowered availability by 1 percentage point). The decline in the availability of the Lithuanian wind farms weakened Q3 wind power production by 16.5 GWh and operating income by €1.4m. Major maintenance and repairs of wind turbine blades carried out at several wind farms in Estonia lowered availability by 2 percentage points. The largest effect came from the work done on the blades of our oldest WinWinD wind turbines at Viru-Nigula.

Replacement of the gearboxes of two WinWinD turbines lowered availability by 1 percentage point and unusually long downtime caused by the failure of the automatic blade control systems and subsequent checks at the Paldiski wind farms lowered availability by 0.8 percentage points. The decline in the availability of our Estonian wind farms weakened Q3 wind power production by 5.1 GWh and operating income by €0.4m.

Our wind power production in Q3 2023 was 195.9 GWh, which is 46.7 GWh higher than in Q3 2022 due to new wind farms coming online. The Tolpanvaara wind farm in Finland, which is still under construction, began to produce electricity and the Akmene wind farm in Lithuania, which was temporarily closed after the incident at the beginning of May, was deployed again. New wind farms that are still in the construction phase contributed nearly 38 GWh to the period's wind power production.

Electricity prices

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. In Q3 2022, we replaced the previous Feed-in Tariff (FiT) based income model with an income model based on the combination of long-term fixed-price PPAs and the market price at all our Lithuanian wind farms. The implied captured electricity prices of both our Estonian and Lithuanian wind farms depend on the combination of the market price and PPAs.

The wind energy segment's implied captured electricity price including support in Q3 2023 was 78.1 €/MWh (58% lower than in Q3 2022). The implied captured electricity price was affected by lower prices on the Nord Pool market, the addition of long-term PPAs, and higher electricity purchase expenses. Altogether, the Wind energy segment sold 190.2 GWh of electricity under PPAs in Q3 2023

Operating income

The Wind energy segment's operating income, which was improved by higher electricity production and substantially weakened by a lower implied captured electricity price, dropped by 16% year on year to €27.0m.

Operating expenses

The operating expenses of the Wind energy segment (excl. D&A) grew by €8.2m year on year, rising to €16.9m. This was mainly due to electricity purchases made to balance the PPA portfolio in hours of low wind speed. Other operating expenses (excl. electricity purchases, expenses on balancing energy and growth in D&A) grew by €1.1m compared with the same period last year.

Operating expenses per MW

In Q3 2023, our wind farm operators' (Enefit Wind OÜ and Enefit Wind UAB) operating expenses (excl. D&A, balancing energy purchases and electricity purchased to balance the PPA portfolio) per installed capacity (MW) grew by 8.3% compared with Q3 2022 mainly due to indexation. Since Q3 2023, operated wind farms include the Purtse wind farm with an installed capacity of 21 MW.

EBITDA

The Wind energy segment's EBITDA for Q3 2023 was €10.1m compared with €23.6m a year earlier. The decrease was mainly attributable to the decline in the market price of electricity and higher expenses on electricity purchased to balance the PPA portfolio. Growth in repair and maintenance costs and research and consulting expenses lowered EBITDA by €0.5m and €0.3m, respectively.

Operating expenses per MW for last 4 quarters, €k/MW*

*(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 windpark.

Cogeneration segment

The Cogeneration segment comprises the Iru, Paide, Valka and Broceni CHP facilities and a pellet factory.

Electricity production and prices

The Cogeneration segment's electricity production in Q3 2023 was 37.0 GWh, which is higher than a year earlier (Q3 2022: 28.4 GWh). In addition to the market price of electricity, the Iru and Paide CHP facilities receive 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 Valka CHP has been selling electricity at the prices of the Nord Pool Latvia price area since mid-December 2022. Previously, it sold electricity at fixed prices ranging from 79.75 €/MWh to 105.6 €/MWh. From November 2021 until the final resolution of the legal dispute with the Latvian state construction control bureau BVKB, the Broceni CHP facility will sell electricity at the prices of the Nord Pool Latvia price area.

Our cogeneration facilities' availability in Q3 was 93.3%, which is lower than in the previous quarters but still significantly higher than in Q3 2022 (72.9%), when the indicator was affected by the unplanned maintenance outage of the Iru CHP which lasted for five weeks. Due to lower market prices in the Nord Pool Estonia and Nord Pool Latvia price areas, the Cogeneration

segment's implied captured electricity price in Q3 2023 was 127.5 €/MWh, which is 61% lower than a year earlier.

Heat production and prices

Heat production grew by 37% to 115 GWh. The average sales price of heat per MWh decreased by 14% compared with the same period last year, dropping to around 11 €/MWh in Q3 2023. The price cap for heat produced by the Iru CHP 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 a decline in the price of biomass purchased by the facilities.

Operating income

The Cogeneration segment's operating income decreased by 30% year on year, dropping to €14.5m. Pellet sales revenue decreased by €3.0m (42%) due to unusually warm weather in Europe, which affected Q3 sales volumes. As a result, pellet stocks increased. The average sales price of pellets increased to 240.6 €/t (by 32%). Pellet sales volume in Q3 2023 was 17 thousand tonnes compared with 39 thousand tonnes in Q3 2022. Revenue from gate fees increased by €1.4m to €3.6m due to growth in the quantity of waste received. Heat sales revenue grew by €0.3m to €1.0m, supported by larger production and a higher sales price. Other operating income remained stable at €0.4m. Electricity sales revenue decreased by €5.2m to €4.2m due to lower market prices. Electricity production support grew by €0.4m to €1.1m.

98.8

72.9

95.7

90.9

Operating expenses

The change in finished goods inventories reduced expenses for Q3 2023 by €3.4m because pellet production exceeded pellet sales. In Q3 2022, the situation was the same: pellet production exceeded pellet sales and the change in inventories was €1.9m. Compared with the same period last year, the Cogeneration segment's expenses from the change in inventories decreased by €1.5m. The segments' variable costs decreased by €1.9m year on year, mainly due lower electricity purchase expenses. Average biomass expenses in pellet production grew by 12% compared with Q3 2022. The cost of biomass in Q3 2023 was 133.0€/t compared with 119.1 €/t in Q3 2022. The segment's fixed costs grew by €0.4m to €3.3m.

EBITDA

The Cogeneration segment's EBITDA for Q3 2023 was €6.4m, which is €3.0m (32%) lower than in the same period last year. The main reasons for the decrease were lower electricity prices and a smaller pellet sales volume. Growth in electricity and heat production had a positive impact on EBITDA.

Solar energy segment

The Solar energy segment comprises the group's operating solar farms, solar farm developments and solar services.

Electricity production and prices

The Solar energy segment produced 26.0 GWh of solar power in Q3 2023, 14.6 GWh (128%) more than in the comparative period because two new solar farms came online in Q2: the Purtse solar farm in Estonia and the Zambrow solar farm in Poland. The availability of solar farms remained high at 99.6% (Q3 2022: 99.7%).

Our solar farms in Estonia are partly exposed to movements in the market price of electricity. Most of our solar farms in Poland sell electricity at fixed prices, which are adjusted for inflation on an annual basis – the price for Q3 2023 was 492–526 PLN/MWh (106 –113 €/MWh at the three-month average zloty (PLN) exchange rate). The Solar energy segment sold 11.4 GWh of electricity under PPAs in Q3 2023.

Operating income

The operating income of operating solar farms grew by €1.0m compared with Q3 2022, mainly due to higher electricity production resulting from two new solar farms coming online in Q2 this year.

EBITDA

The Solar energy segment's EBITDA for Q3 2023 was €1.5m, which is at the same level as a year earlier. EBITDA was supported by the output and operating income of two new solar farms but €0.5m (132%) growth in fixed costs had a negative impact (payroll expenses have increased in connection with the implementation of the group's growth plan and land-related costs have increased in connection with new development projects).

Investments

Investments made in Q3

The group invested €87.3m in Q3 2023, which is €7.5m more than in Q3 2022. Growth resulted from development investments, which extended to €85.6m. Of the latter, €79.0m was invested in the construction of three wind farms: €45.4m in the Kelme wind farm, €18.9m in the Sopi-Tootsi wind farm and €14.8m in the Tolpanvaara wind farm. The largest solar energy development investment was made in the Sopi solar project in the amount of €1.9m.

Expenditure on the maintenance and improvement of existing assets increased by €0.8m year on year, rising to €1.7m in Q3 2023. Maintenance expenditure of the period was mainly related to Estonian wind farms. Wind farm maintenance expenditures may fluctuate significantly quarter by quarter as they depend on the wind turbines' repair and maintenance needs. Maintenance expenditures on cogeneration facilities remained stable compared with the same period last year.

Financing

-40,0 -20,0 0,0 20,0 40,0 60,0 80,0 100,0

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).

The amortised cost of the group's interest-bearing liabilities at 30 September 2023 was €411.3m (31 December 2022: €279.6m). Loan liabilities to banks accounted for €407.0m of the total, including an outstanding loan balance of €6.6m denominated in Polish zloty.

In Q3, Enefit Green drew down €60m of an investment loan raised from NIB which matures in 2035 and signed an additional 12-year investment loan agreement of €180m with EIB.

The interest rate risk of investment loans with the total outstanding balance of €158.9m 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 30 September 2023 was 3.80% (31 December 2022: 2.60%).

Investment loans raised but not drawn down at 30 September 2023 amounted to €405m.

Liquidity development Q3 2023, €m

-27.3 (-51.4%)

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 30 September 2023, the group was in compliance with all loan terms and conditions, including the 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.

€ million	31 Dec 2022	30 Sept 2023
Interest-bearing liabilities	279.6	411.3
Less cash and cash equivalents	-131.5	-25.7
Net debt	148.1	385.6
Equity	718.7	701.7
Invested capital	866.8	1,087.3
EBITDA (LTM)*	154.8	122.1
Operating profit (LTM)	117.1	83.5
Net profit (LTM)	110.2	72.1

Financial leverage (1)	17%	35%
Net debt / LTM EBITDA	0.96	3.16
Return on invested capital (2)	13.5%	7.7%
Return on equity (3)	15.3%	10.3%
Interest cover (4)	42.8	12.4

Net debt/EBITDA Financial leverage

* LTM – last twelve months

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

(2) Return on invested capital = LTM operating profit / (net debt + equity)

(3) Return on equity = LTM net profit / equity

(4) Interest cover = LTM EBITDA/ 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), which are being signed in increasing volumes. 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.

As of 30 September 2023, the group had signed PPAs on 9,899 GWh at an average price of 71.5 €/MWh. Outstanding PPA volume in Q4 2023 is 273 GWh with an average price of 91.2 €/MWh.

Out of electricity produced after 2027, 3,677 GWh is covered with PPAs at an average price of 78.1 €/MWh. The chart below provides an overview of the next years' forecasted production volumes and their coverage with risk mitigation measures as at 30 September 2023.

Forecasted production volumes of production assets (operating, under construction and planned) and their coverage with PPAs and renewable

Operating Under construction Investment decision not made PPA FiT/CfD FiP Floor*

Core markets electricity price forecast (consensus)*, €/MWh

* The 2024E – 2033E electricity prices have been estimated by averaging the forecasts of market analysis companies SKM and Volue (SKM Market Predictor Long-Term Power Outlook – August 2023, Volue Long Term Price Forecast – September 2023). The figures presented are nominal prices which have been estimated assuming a constant 2% rate of inflation.

	2023	2024	2025	2026	2027	Total for 2023-2027
FiT/CfD schemes**	2%	1%	1%	1%	1%	1%
Volume (GWh)	27	28	28	28	28	140
Price***, €/MWh	97,6	97,8	99,4	101,4	103,5	100,0
FiP support**	33%	25%	9%	3%	3%	12%
Volume (GWh)	502	502	266	99	79	1 449
Price***, €/MWh (added to the market price)	50,1	50,2	50,3	53,7	53,7	50,6
PPAs**	63%	66%	52%	52%	52%	55%
Volume (GWh)	953	1 331	1 533	1 534	1 550	6 901
Price***, €/MWh	86,9	67,6	64,8	64,8	69,0	69,3

* 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 operational assets and assets under construction.

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

Interest rate risk

The group manages its interest rate risk with interest swap (IRS) agreements.

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 grow when interest rates increase.

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

Enefit Green | Q3 2023 Interim report | 30

Unaudited condensed consolidated interim financial statements Q3 2023

Condensed consolidated interim income statement

€ thousand	Note	Q3 2023	Q3 2022	9M 2023	9M 2022
Revenue	9	39,259	57,254	144,600	156,900
Renewable energy support and other operating income	10	5,233	3,011	18,562	17,363
Change in inventories of finished goods and work in progress		3,434	2,028	3,266	4,607
Raw materials, consumables and services used	11	(26,011)	(24,969)	(71,386)	(55,468)
Payroll expenses		(2,634)	(2,029)	(8,025)	(6,641)
Depreciation, amortisation and impairment		(10,218)	(9,637)	(29,740)	(28,930)
Other operating expenses		(3,388)	(2,574)	(10,716)	(7,721)
OPERATING PROFIT		5,675	23,084	46,561	80,110
Finance income		747	468	2,345	718
Finance costs		(1,115)	(722)	(1,897)	(1,275)
Net finance income and costs		(368)	(255)	448	(558)
Profit from associates under the equity method		45	120	85	687
PROFIT BEFORE TAX		5,352	22,949	47,094	80,239
Income tax expense		(326)	0	(10,405)	(5,441)
PROFIT FOR THE PERIOD		5,026	22,949	36,689	74,798

Basic and diluted earnings per share
Weighted average number of shares, thousand	6	264,276	264,276	264,276	264,276
Basic earnings per share, €	6	0.02	0.09	0.14	0.28
Diluted earnings per share, €	6	0.02	0.09	0.14	0.28

Condensed consolidated interim statement of comprehensive income

€ thousand	Note	Q3 2023	Q3 2022	9M 2023	9M 2022
PROFIT FOR THE PERIOD		5,026	22,949	36,689	74,798
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	662	7,193	1,202	13,717
Exchange differences on the translation of foreign operations	7	(349)	(436)	53	(680)
Other comprehensive income for the period		313	6,757	1,255	13,037

TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		5,339	29,706	37,944	87,835

Condensed consolidated interim statement of financial position

€ thousand	Note	30 September 2023	31 December 2022
ASSETS
Non-current assets
Property, plant and equipment	4	978,497	776,870
Intangible assets		60,275	60,382
Right-of-use assets		4,295	4,239
Prepayments for non-current assets	4	42,522	19,412
Deferred tax assets		1,379	1,321
Investments in associates		568	506
Derivative financial instruments	5, 7	9,310	11,277
Non-current receivables		0	40
Total non-current assets		1,096,846	874,047

Current assets
Inventories		19,177	14,227
Trade and other receivables and prepayments		59,765	41,091
Cash and cash equivalents		25,731	131,456
Derivative financial instruments	5	4,473	3,349
Total current assets		109,146	190,123
Total assets		1,205,992	1,064,170

€ thousand	Note	30 September 2023	31 December 2022
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		5,555	3,259
Other reserves	5, 7	167,621	166,419
Foreign currency translation reserve	7	(709)	(762)
Retained earnings		204,613	225,190
Total equity		701,707	718,733

LIABILITIES
Non-current liabilities
Borrowings	8	334,639	255,755
Government grants		6,745	7,115
Non-derivative contract liability	5, 7	18,086	18,086
Deferred tax liabilities		12,445	12,326
Other non-current liabilities		3,000	3,000
Provisions		8	9
Total non-current liabilities		374,923	296,291
Current liabilities
Borrowings	8	76,686	23,808
Trade and other payables		51,107	20,215
Provisions		2	2
Non-derivative contract liability	5	1,567	5,121
Total current liabilities		129,362	49,146
Total liabilities		504,285	345,437
Total equity and liabilities		1,205,992	1,064,170

Condensed consolidated statement of cash flows

€ thousand	Note	Q3 2023	Q3 2022	9M 2023	9M 2022
Cash flows from operating activities
Cash generated from operations	12	18,977	36,827	77,321	105,742

Interest and loan fees paid		(2,999)	(845)	(7,136)	(1,842)
Interest received		127	6	645	12
Income tax paid		(9,970)	(4,716)	(11,175)	(6,217)
Net cash generated from operating activities		6,135	31,272	59,655	97,695

Cash flows from investing activities
Purchase of property, plant and equipment and intangible assets	4	(86,191)	(82,902)	(235,672)	(129,950)
Paid on acquisition of subsidiaries		0	0	(6,174)	0
Collection of finance lease receivables		1	0	1	0
Proceeds from sale of property, plant and equipment		0	0	0	3
Proceeds from sale of a business		0	5	0	724
Dividends from investments in financial assets		24	62	24	62
Net cash used in investing activities		(86,166)	(82,834)	(241,821)	(129,161)
Cash flows from financing activities
Proceeds from bank loans	8	70,000	130,000	160,000	170,000
Repayments of bank loans	8	(17,137)	(5,476)	(28,314)	(15,146)
Repayments of lease principal	8	(97)	(134)	(276)	(263)
Dividends paid		0	0	(54,969)	(39,906)
Net change in intragroup debt		0	38	0	38
Net cash generated from financing activities		52,766	124,428	76,441	114,723
Net cash flow		(27,265)	72,866	(105,725)	83,257
Cash and cash equivalents at the beginning of the period		52,996	90,845	131,456	80,454
Cash and cash equivalents at the end of the period		25,731	163,711	25,731	163,711
Change in cash and cash equivalents		(27,265)	72,866	(105,725)	83,257

Condensed consolidated interim statement of changes in equity

€ thousand	Share capital	Share premium	Statutory capital reserve	Other reserves	Foreign currency translation reserve	Retained earnings	Total equity
Equity as at 31 December 2021	264,276	60,351	479	151,793	(965)	157,673	633,607
Profit for the period	0	0	0	0	0	74,798	74,798
Other comprehensive income for the period	0	0	0	13,717	(680)	0	13,037
Total comprehensive income for the period	0	0	0	13,717	(680)	74,798	87,835
Increase of statutory capital reserve	0	0	2,780	0	0	(2,780)	0
Dividends paid	0	0	0	0	0	(39,906)	(39,906)
Total contributions by and distributions to shareholders of the company, recognised directly in equity	0	0	2,780	0	0	(42,686)	(39,906)
Equity as at 30 September 2022	264,276	60,351	3,259	165,510	(1,645)	189,785	681,536
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	36,689	36,689
Other comprehensive income for the period	0	0	0	1,202	53	0	1,255
Total comprehensive income for the period	0	0	0	1,202	53	36,689	37,944
Increase of statutory capital reserve	0	0	2,296	0	0	(2,296)	0
Dividends paid	0	0	0	0	0	(54,970)	(54,970)
Total contributions by and distributions to shareholders of the company, recognised directly in equity	0	0	2,296	0	0	(57,266)	(54,970)
Equity as at 30 September 2023	264,276	60,351	5,555	167,621	(709)	204,613	701,707

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 2022, 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 2022.

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 2022.

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 2022.

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, and raise debt capital in the form of loans. On raising loans, management assesses the group's ability to service the principal and interest payments with operating cash flow and, where necessary, starts timely negotiations to refinance existing loans before their maturity. For further information about financing ratios and borrowings, see the Financing chapter in the management report.

3. Segment reporting

Enefit Green's management board assesses the group's financial performance and makes management decisions on the basis of segment reporting where the group's reportable operating segments 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 divided between operating segments based on their core activity.

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:

1. Wind energy (comprises all of the group's wind farms);
1. Cogeneration (comprises all of the group's cogeneration facilities and the pellet factory);
1. Solar energy (comprises all of the group's solar farms);
Other (hydropower, hybrid renewable energy solutions, and central development and management units).

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 profits 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.

Financial results by segments

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022
REVENUE
Wind energy	23,143	29,468	82,054	86,916
Cogeneration	13,345	19,841	56,124	56,722
Solar energy	2,662	7,772	5,929	12,832
Total reportable segments	39,150	57,082	144,107	156,470
Other	109	172	493	430
Total	39,259	57,254	144,600	156,900
RENEWABLE ENERGY SUPPORT AND OTHER OPERATING INCOME
Wind energy	3,864	2,697	13,702	13,815
Cogeneration	1,150	800	4,382	4,020
Solar energy	213	(489)	463	(501)
Total reportable segments	5,228	3,007	18,547	17,334
Other	5	4	15	30
Total	5,233	3,012	18,562	17,363
EBITDA
Wind energy	10,146	23,607	53,242	78,843
Cogeneration	6,446	9,440	27,123	32,334
Solar energy	1,527	1,525	2,753	3,351
Total reportable segments	18,119	34,572	83,118	114,528
Other	(2,225)	(1,851)	(6,817)	(5,488)
Total	15,894	32,721	76,301	109,039
Depreciation, amortisation and impairment
losses	10,218	9,637	29,740	28,930
Net finance income	(368)	(255)	448	(558)
Profit from associates under the equity method	45	120	85	687
Profit before tax	5,353	22,949	47,094	80,239
OPERATING PROFIT
Wind energy	3,033	16,784	32,380	58,367
Cogeneration	3,854	6,909	19,372	24,669
Solar energy	1,095	1,302	1,862	2,672
Total reportable segments	7,982	24,994	53,615	85,709
Other	(2,306)	(1,910)	(7,054)	(5,599)
Total	5,676	23,085	46,561	80,110

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	80,842	67,407	211,327	118,367
Cogeneration	665	322	1,423	935
Solar energy	2,503	11,666	33,383	14,117
Total reportable segments	84,010	79,395	246,133	133,419
Other	3,277	349	7,658	986
Total	87,287	79,744	253,791	134,404

€ thousand	30 September 2023	31 December 2022
NON-CURRENT ASSETS
Wind energy	858,573	668,422
Cogeneration	128,152	134,510
Solar energy	88,576	55,035
Total reportable segments	1,075,300	857,968
Other	21,546	16,079
Total	1,096,846	874,047

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 2022
Cost	63,953	25,573	42,218	751,521	203,637	19,412	1,106,314
Accumulated depreciation	0	(10,385)	(25,014)	(274,615)	(18)	0	(310,032)
Total property, plant and equipment as at 31 December 2022	63,953	15,188	17,204	476,906	203,619	19,412	796,282
Movements in the reporting period
Additions	0	152	497	4,610	226,037	22,475	253,771
Exchange differences	0	2	5	72	299	2	380
Transfers	2	1	3,813	48,188	(52,637)	633	0
Depreciation and impairment	0	(547)	(964)	(27,903)	0	0	(29,414)
Total movements in 9M 2023	2	(392)	3,351	24,967	173,699	23,110	224,737
Property, plant and equipment as at 30 September 2023
Cost	63,955	25,728	46,533	804,391	377,336	42,522	1,360,465
Accumulated depreciation	0	(10,932)	(25,978)	(302,518)	(18)	0	(339,446)
Carrying amount as at 30 September 2023	63,955	14,796	20,555	501,873	377,318	42,522	1,021,019

At 30 September 2023, the group had committed to capital expenditures of €347,139k (31 December 2022: €89,623k and 30 September 2022: €140,594k).

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 30 September 2023, the group used cash flow hedging instruments in order to hedge the exposure to interest rate risk resulting from floatingrate 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 cash flow hedging instruments in order to hedge the exposure to variability in the price of electricity.

A part of the renewable electricity production assets operated by the group which is not subject to a subsidy scheme under a feed-in tariff is exposed to the risk of electricity price fluctuations as the electricity is sold on the Nord Pool power exchange. To hedge the risk of electricity price volatility, the group has used base load swap derivative contracts. Under the given derivatives, the group is the payer of the floating price and the counterparty the payer of the fixed price.

Transactions designed to hedge the risk of variability in electricity prices are designated as hedging instruments in cash flow hedges. The underlying hedged item is the market price risk of highly probable forecasted renewable electricity sales transactions that are exposed to market price fluctuations. The hedge ratio of the hedging relationships is one to one.

The fair values of the level 3 instruments have been estimated using a combination of market prices, mathematical models, and assumptions based on historical and forward-looking market and other relevant data. The most significant input of the fair value of the derivatives is the longterm electricity price. The group determined the underlying price for the calculation of fair value based on the long-term price curve for the Lithuanian and Estonian electricity markets, which was between 34 €/MWh and 59 €/MWh. Derivative financial instruments were remeasured to fair value as at 17 August 2021.

At the trade date the fair value of derivatives designated as hedging instruments was negative at €(10,781)k, which was recognised directly in equity as it reflected a transaction with the parent, Eesti Energia AS. The balance at 30 September 2023 was €(10,781)k.

Enefit Green AS and its parent Eesti Energia AS entered into an EFET General Agreement Concerning the Delivery and Acceptance of Electricity (EFET General Agreement) on 17 August 2021, simultaneously terminating all open derivative contracts existing between them. By signing the agreement, the parties entered into a fixed-price physical electricity sales contract for the period 2023–2027. The contract was entered into for the same quantities of electricity and at the same fixed prices as had been agreed for the originally recognised derivatives.

The group continued to apply hedge accounting to the open derivatives position 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. Since the derivative financial instruments had been measured to fair value by the date of conclusion of the EFET General Agreement, (measurement date 17 August 2021), their value, which has been classified as a liability, will not change before the arrival of the supply period determined in the EFET General Agreement, which is 2023–2027.

The electricity supply period under the EFET agreements began on 1 January 2023. Accordingly, the balance of the liability decreased by €632k in Q3 2023 and was €(10,383)k at 30 September 2023.

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 being recognised at a fixed per-unit value 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 non-derivative contract liability, which will gradually increase recognised revenue until the EFET General Agreement is fulfilled. Such an increase in revenue will be partially offset by the reclassification of the €(12,426)k accumulated in the electricity cash flow hedge reserve to profit or loss due to the discontinuance of hedge accounting. 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 is recognised directly in equity. See note 7 for further information about reserves.

At 31 December 2022, the liability of €23,207k was classified into a current portion of €5,121k and a non-current portion of €18,086k.

In connection with the beginning of the supply period under the EFET agreements, the following changes will be made to the group's reserves and income statement in 2023:

€ thousand	Note	Q1 2023	Q2 2023	Q3 2023	Q4 2023	Total
Non-derivative contract liability		(1,766)	(756)	(1,033)	(1,566)	(5,121)
Electricity cash flow hedge reserve	7	860	552	632	754	2,798
Gain on derivative financial instruments	10	906	204	401	812	2,323

Interest rate swap transactions

At 30 September 2023, 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 €73,043k 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 €50,000k 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 €35,834k 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 30 September 2023 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 30 September 2023, the effect of the hedging instruments on the group's statement of financial position was as follows:

					Hedge
€ thousand		Carrying	Carrying		Change	ineffectiveness	Amounts transferred from
	Notional	amount	amount	Line item in the statement	in fair	recognised in	hedge reserve to profit or
	amount	(Asset)	(Liability)	of financial position	value*	profit or loss	loss
Interest rate swaps	158,877	13,784	0	Derivatives	1,098	0	1,068

* Change compared to 30 June 2023, recognised in other comprehensive income

At 30 September 2023, the effect of the hedged items on the group's statement of financial position was as follows:

	Change in fair value		Amounts recognised in hedge
€ thousand	used to measure	Amounts recognised	reserve to which hedge accounting is
	ineffectiveness	in hedge reserve	no longer applied
Floating rate loans	13,784	13,784	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 30 September 2023, Enefit Green AS had 264,276,232 registered shares (30 September 2022: 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	Q3 2023	Q3 2022	9M 2023	9M 2022
Profit attributable to shareholders of the parent	€ thousand	5,026	22,949	36,689	74,798
Weighted average number of shares	thousand	264,276	264,276	264,276	264,276
Basic earnings per share	€	0.019	0.09	0.14	0.28
Diluted earnings per share	€	0.019	0.09	0.14	0.28

7. Other reserves

€ thousand	30 September 2023	31 December 2022
Other reserves at the beginning of the period	165,657	150,828
of which currency translation reserve	(762)	(965)
of which interest rate swap (IRS) transactions	14,626	0
of which electricity cash flow hedge reserve	(12,426)	(12,426)
of which fair value on initial recognition of a derivative transaction with the parent	(10,781)	(10,781)
of which other reserves	175,000	175,000

Change in fair value of cash flow hedges	2,044	0
of which electricity cash flow hedge reserve	2,044	0
Interest rate swap (IRS) transactions	1,539	14,529
Recognised as an increase in interest expense	(2,381)	97
Exchange differences on the translation of foreign operations	(53)	203
Other reserves at the end of the period	166,912	165,657
of which currency translation reserve	(709)	(762)
of which interest rate swap (IRS) transactions	13,784	14,626
of which electricity cash flow hedge reserve	(10,383)	(12,426)
of which fair value on initial recognition of a derivative transaction with the parent	(10,781)	(10,781)
of which other reserves	175,000	175,000

8. Borrowings at amortised cost

	Current borrowings		Non-current borrowings
€ thousand	Bank loans	Lease liabilities	Bank loans	Lease liabilities	Total
Borrowings at amortised cost as at 31 December 2022	23,396	412	251,577	4,178	279,563
Movements in the reporting period
Monetary movements
Borrowings received	60,000	59	100,000	466	160,525
Repayments of borrowings	(28,314)	(316)	0	0	(28,630)
Non-monetary movements
Transfers	21,448	0	(21,448)	0	0
Amortisation of borrowing costs	0	0	(223)	0	(223)
Other movements	0	1	71	18	90
Total movements in 9M 2023	53,134	(256)	78,400	484	131,762

Borrowings at amortised cost as at 30 September 2023	76,530	156	329,977	4,662	411,325

9. Revenue

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022
Revenue by activity
Sale of goods
Pellets	4,209	7,208	22,806	16,616
Scrap metal	137	116	592	756
Other goods	14	3,259	40	3,357
Total sale of goods	4,360	10,583	23,438	20,729

Sale of services
Heat	1,008	750	5,931	4,672
Electricity	30,099	41,335	102,273	115,205
Waste reception and resale	3,596	2,152	12,048	10,390
Rental and maintenance of assets	77	2,379	614	5,623
Other services	119	55	296	281
Total sale of services	34,899	46,671	121,162	136,171
Total revenue	39,259	57,254	144,600	156,900

10. Renewable energy support and other operating income

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022
Renewable energy support	4,227	2,855	15,850	16,751
Government grants	135	135	370	341
Gain on derivative financial instruments	401	0	1,511	0
Other income	470	21	831	271
Total renewable energy support and other operating income	5,233	3,011	18,562	17,363

11. Raw materials, consumables and services used

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022
Maintenance and repairs	5,377	4,556	12,512	11,357
Technological fuel	5,614	5,822	20,344	14,805
Electricity	13,515	7,928	33,707	16,917
Services related to ash treatment	411	279	1,449	1,635
Transport services for sale of finished goods	465	450	1,337	1,261
Materials and spare parts for production	288	5,682	1,060	8,671
Transmission services	122	85	344	205
Waste handling	116	63	295	247
Resource charges for natural resources	1	2	4	6
Other raw materials, consumables and services used	40	67	128	177
Environmental pollution charges	62	35	206	187
Total raw materials, consumables and services used	26,011	24,969	71,386	55,468

12. Cash generated from operations

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022
Profit before tax	5,352	22,949	47,094	80,239
Adjustments
Depreciation and impairment of property, plant and equipment	10,110	9,580	29,414	28,819
Amortisation and impairment of intangible assets	108	57	326	112
Amortisation of government grants related to assets	(135)	(135)	(370)	(341)
Interest expense on borrowings	132	501	573	1,033
Gain on sale of a business	0	(5)	0	(644)
(Profit) loss from associates using the equity method	(21)	(52)	(62)	20
Gain on disposal of property, plant and equipment	0	0	0	(3
Interest and other finance income	(127)	(6)	(645)	(12)
Other investment (gains) losses	(24)	0	(24)	0
Foreign exchange (gain) loss on loans granted and taken	(270)	(229)	72	(377)
Realised gain on derivative financial instruments	(401)	0	(1,510)	0
Adjusted profit before tax	14,724	32,660	74,868	108,845
Net change in current assets related to operating activities
Change in receivables related to operating activities	(3,030)	4,137	1,456	7,268
Change in inventories	(4,912)	923	(4,950)	(5,815)
Net change in other current assets related to operating activities	(18,580)	(3,097)	(18,955)	(7,194)
Total net change in current assets related to operating activities	(26,522)	1,963	(22,449)	(5,741)
Net change in current liabilities related to operating activities
Change in provisions	0	(30)	(1)	(32)
Change in trade payables	19,111	(428)	22,446	2,179
Net change in other current liabilities related to operating activities	11,664	2,662	2,457	491
Total net change in current liabilities related to operating activities	30,775	2,204	24,902	2,638
Cash generated from operations	18,977	36,827	77,321	105,742

13. Transactions and balances with related parties

The parent of Enefit Green AS is Eesti Energia AS. At 30 September 2023, 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 period 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 30 September 2023, Enefit Green AS had signed long-term physical electricity sales contracts of 8,779 GWh with Eesti Energia AS for the supply of electricity in the Lithuanian, Estonian, Finnish and Polish electricity networks in the period October 2023 – December 2033. The contracts are for the supply of both annual and monthly base load energy. The weighted average price of the physical electricity sales contracts signed with the related party is 68.7 €/MWh.

At the beginning of 2021, the group used base load 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 position 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 30 September 2023, the balance of the electricity cash flow hedge reserve was €(10,383)k (see also notes 5 and 7).

€ thousand	Q3 2023	Q3 2022	9M 2023	9M 2022		30 Sept 2023	31 Dec 2022
	TRANSACTIONS				BALANCES
				PARENT
Purchase of services	5,057	4,211	12,471	9,570	Receivables	7,027	11,968
Sale of goods	0	0	0	0	Payables	21,212	26,412
Sale of services	15,418	6,221	54,986	12,820	Of which non-derivative contract liability	19,652	23,207
				OTHER GROUP COMPANIES
Purchase of goods	0	0	0	8	Receivables	915	31
Purchase of services	912	2,528	2,473	4,544	Payables	354	731
Sale of goods	0	3,205	0	3,205
Sale of services	2,087	3,527	2,829	7,528
OTHER RELATED PARTIES (INCL. ASSOCIATES)
Purchase of services	577	507	1,461	1,249	Receivables	0	21
Sale of services	0	0	0	2	Payables	542	251
ELERING AS
Purchase of services	65	59	20,124	172	Receivables	1,222	2,064
Sale of services	4,261	3,619	16,016	17,947	Payables	23	29

AI Terminal

Enefit Green

2216_ir_2023-11-02_cabba0d3-a2ff-4996-a821-0a2910f2bcf0.pdf

Unaudited interim report

Contents

Letter from the CEO

Dear reader

Path towards 4X growth

Projects under construction

Near term development portfolio

Complete view of the development portfolio

3Q 2023 Key highlights

9 months 2023 Key highlights

Operating environment

Key factors influencing the operating environment

Electricity market

Wind conditions

Regulatory environment

European Union

Estonia

Latvia

Lithuania

Poland

Finland

Significant events in Q3

Cornerstone laid for the most powerful and modern renewable energy facility in the Baltics

First electricity delivered by the Tolpanvaara wind farm

Loan agreement with European Investment Bank

Approval of phase 1 of a special spatial plan for wind power development in Lääne-Nigula

Incidents of potential misconduct

Situation in the Akmene wind farm

Financial results of the group

Production and sales volumes

Operating income

Average quarterly electricity prices

Renewable energy support and other operating income

Raw materials, consumables and services used

Payroll expenses

Other operating expenses

Change in inventories

EBITDA and fixed costs

Depreciation, amortisation and impairment (D&A)

Net finance income and costs

Group's EBITDA change by drivers, €m

Income tax

Net profit

Financial results by segments

Operating income by segment, €m

Wind energy segment

Availability and production

Electricity prices

Operating income

Operating expenses

Operating expenses per MW

EBITDA

Cogeneration segment

Electricity production and prices

Heat production and prices

Operating income

Operating expenses

EBITDA

Solar energy segment

Electricity production and prices

Operating income

EBITDA

Investments

Investments made in Q3

Financing

Loan covenants

Financing and return ratios

Risk management

Price risk of electricity sales

Interest rate risk

Condensed consolidated interim income statement

Condensed consolidated interim statement of comprehensive income

Condensed consolidated interim statement of financial position

Condensed consolidated statement of cash flows

Condensed consolidated interim statement of changes in equity

Notes to the condensed consolidated interim financial statements

1. Summary of significant accounting policies