Q3 2024

Unaudited interim report

Letter from the management board	3
Development of generation capacity in 2023–2026	5
Projects under construction	6
Near-term development portfolio	7
Full overview of development portfolio	8
Contribution of new assets* to power generation is increasing	9
Q3 2024 key highlights	10
9 months 2024 key highlights	11
Operating environment	12
Regulatory environment	14
Significant events	15
Financial results	16
Financial results by segments	19
Wind energy	20
Cogeneration	22
Solar energy	24
Investment	25
Financing	26
Risk management	28
Unaudited condensed consolidated interim financial statements Q3 2024	30
Notes to the condensed consolidated interim financial statements	36
Group structure	48

Letter from the management board

Dear reader

The last few months have brought a fresh perspective to the company. Juhan Aguraiuja has joined the team as the new CEO and chairman of the management board, and the selection process for the CFO and member of the management board has also been completed – Argo Rannamets will take up the position on 31 January. Andres Maasing, responsible for development, and Innar Kaasik, responsible for production, continue to serve on the management board. Our team is adapting to internal changes as well as to external developments and will continue to make every effort to provide green energy to our energy-deficient core markets.

Enefit Green is in an active construction phase. We have built new wind and solar farms in Finland, the Baltics and Poland. Many of the projects have been completed, but some are still under construction. Developing, building and commissioning generation capacity takes effort and we have had to overcome a number of challenges.

At the beginning of September, we reached the final stage of installing all 38 wind turbines at the Sopi-Tootsi wind farm, where the first wind turbines were already generating electricity. With the completion of the erection of these turbines, our installed power generation capacity now exceeds 1 GW, which is an important milestone for Enefit Green and our investors. We have signed a new loan agreement with the European Bank for Reconstruction and Development (EBRD), which will ensure the completion of the project and the operation of the wind turbines. The Sopi-Tootsi wind farm will fill a meaningful portion of power deficit in Estonia, while helping to reduce the country's carbon footprint from energy production.

We reached a constructive and fair out-of-court settlement with GE Vernova regarding the Akmenė wind farm incident (collapsed wind turbine). We amended the farm's turbine contract and received compensation of around €8m, half of which was paid in cash and the remainder in a non-cash settlement. The impact of the compensation on our operating income and EBITDA was a significant €5.3m. Negotiations with the insurance company on further claims are ongoing.

We laid the cornerstone for the Kelmė II wind farm in Lithuania, where the construction of the foundations is underway. Installation of the wind turbines is scheduled for Q2 2025. We also inaugurated the Šilalė II wind farm.

During the quarter, we produced 342 GWh of electricity (32% more than in Q3 2023) and 80 GWh of heat (30% less than in Q3 2023). Electricity production was affected by wind conditions and various generation curtailments and downregulations.

Wind energy production is typically low in Q3. While wind speeds were above average in Finland, they were below expectations in Estonia and Lithuania, reducing production by 10 GWh. In addition, production curtailments and downregulations reduced output by 26.4 GWh. Nearly 65% of this was due to negative prices, mostly on the Finnish market. Other reasons were network maintenance and Enefit Green's services to system operators.

We are pleased to report that the availability of our Estonian and Lithuanian wind farms is high. The availability of the Tolpanvaara wind farm also exceeded the target for the second month in a row. Better than expected availability of the operating assets improved the production result for the quarter by 1.6 GWh.

Although electricity production this year is higher than last year, growth is not at the level forecast at the beginning of 2024. The construction of the Sopi-Tootsi wind farm is ahead of schedule, but its production during the start-up phase is below expectations. The start of production at the Kelmė I wind farm and the new solar farms in Latvia has also been delayed.

As a result, we have revised our production forecasts and lowered the forecasts for Q4. The shortfall in production compared to previous expectations increases the likelihood that we will have to purchase more electricity to meet our obligations under previously signed baseload PPAs. Therefore, as in previous quarters, we have entered into power purchase transactions for Q4 to reduce the electricity purchase risks in our portfolio.

The sale of biomass-fired CHP plants and planned and unplanned maintenance outages at the Iru power plant reduced heat production.

Our Q3 operating income was €43.5m (down 2%), EBITDA was €15.7m (down 1%) and net profit was €5.4m (up 8%). The group's financial results were affected by an increase in renewable energy discounts and lower than expected production. However, we are confident that the completion and commissioning of the new farms will help us increase our production volumes in the coming quarters and years and also improve our performance from an investor perspective.

Enefit Green's leadership has been strengthened and we will soon be joined by Argo Rannamets, our new CFO and member of the management board. We will focus on completing the farms under construction and ensuring their profitable and stable operation. At the same time, we will seek new opportunities for sustainable growth in our core markets, where power shortages persist and volatility of power prices is increasing.

Juhan Aguraiuja CEO

Andres Maasing Member of the Board (CDO)

Innar Kaasik Member of the Board (COO)

Development of generation capacity in 2023–2026

Near-term development portfolio* Under construction Operating capacity

* The near-term development portfolio includes projects that are expected to be developed to the final investment decision (FID) stage before the end of 2024. The actual FID timing will depend on PPA demand, the availability of other revenue assurance instruments (government auctions, possible support mechanisms, etc.), generation equipment and construction prices, and financing and funding capacity and conditions.

Projects under construction

* COD – Commercial Operation Date (the date the asset is classified as an operating asset). In Q2 2024, the Tolpanvaara wind farm (72 MW) was classified as an operating asset.

Near-term development portfolio

* The projects are expected to be developed to the FID (final investment decision)/construction readiness stage by the time indicated. The actual FID timing will depend on PPA demand, the availability of other revenue assurance instruments (government auctions, possible support mechanisms, etc.), generation equipment and construction prices, and financing and funding capacity and conditions.

Full overview of development portfolio

* Various onshore wind and solar farm developments that are not expected to reach FID (final investment decision) before 2025. The actual FID timing will depend on PPA demand, the availability of other revenue assurance instruments (government auctions, possible support mechanisms, etc.), generation equipment and construction prices, and financing and funding capacity andconditions.

** Also known as the Hiiumaa offshore wind farm.

**Contribution of new assets* to power generation is increasing**

Enefit Green's aim has been to respond to market signals and regulatory developments in order to supply the market with renewable energy in line with demand.

Our current investment programme for the construction of new generation capacity was launched in 2021, before Enefit Green's shares were publicly listed. It takes time to develop and build new generation capacity: at least one year from the final investment decision to first electricity generation for solar farms and two years for onshore wind farms. This is preceded by a period of pre-development activities and preparation of the investment decision. We have invested nearly €1bn over the past three years, and our new wind and solar farms have been progressively completed and started generating electricity over the past year and a half (since the beginning of 2023). The production of these assets and their increasing contribution to our quarterly electricity generation is shown in the chart on the right. The chart also illustrates the intra-year volatility of our generation profile. As we are mainly a wind energy producer, our production volumes in Q2 and Q3 are significantly lower than in Q1 and Q4.

The table below shows a list of completed and under-construction wind and solar farms and the time when they started generating electricity.

In Q3 2024, the Sopi-Tootsi wind farm, which is still under construction, was added to the list of generating assets. The final 38th wind turbine was installed at Sopi-Tootsi in early September, and in the same month the farm's first commissioned turbines generated their first 12.2 GWh of electricity.

Wind or solar farm	Country	Wind/ solar	Status	Capacity (MW)	Start of generation**
Šilalė II	Lithuania	Wind	Under construction	43	January 2023
Akmenė***	Lithuania	Wind	Under construction	75	March 2023
Purtse	Estonia	Wind	Operating	21	March 2023
Zambrow	Poland	Solar	Operating	9	April 2023
Purtse	Estonia	Solar	Operating	32	May 2023
Estonia	Estonia	Solar	Operating	3	October 2023
Tolpanvaara	Finland	Wind	Operating	72	December 2023
Debnik	Poland	Solar	Operating	6	February 2024
Sopi-Tootsi	Estonia	Wind	Under construction	255	September 2024
			Total	473

Electricity production, GWh

* Assets completed in 2023 or later or still under construction but generating electricity – essentially all assets completed or under construction as part of the investment programme launched in2021.

** The month in which the asset made the first significant contribution to Enefit Green's generation results. *** The Akmenė wind farm was offline for most of the period May–October 2023.

Q3 2024 key highlights

€100m Loan agreement signed with EBRD

€5.3m Impact of the Akmene settlement on Q3 operating income

12 GWh

Electricity generated in September by the first wind turbines commissioned at the Sopi-Tootsi wind farm

* New assets – production assets (wind and solar farms) completed in 2023 or later

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

9 months 2024 key highlights

360 MW Co-development agreement with RES Global Investment for early- stage onshore wind projects

Focus on completing major construction projects

Completing the construction of the Sopi-Tootsi, Kelmė I and Tolpanvaara wind farms and the Sopi solar farm

* Assets completed in 2023 or later

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

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 energy industry regulations and political decisions. Factors affecting our development projects also include market competition, the development and cost of renewable energy technologies, the cost and availability of capital, customers' willingness to enter into long-term green power purchase agreements (PPAs) and renewable energy support schemes.

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

Electricity market

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

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

In Q3, the electricity price in the Baltic markets was higher than in other Nord Pool markets. In Estonia, the average quarterly electricity price rose by 0.9% and, similar to the previous quarter, the price gap with Latvia and Lithuania was close to zero. This was largely due to the long-term outage of the EstLink2 interconnector between Estonia and Finland, which prevented sufficient supplies of cheaper Finnish electricity from reaching the Baltic markets from late January to mid-September. Due to the restart of EstLink2 and higher wind energy production, in September the electricity price in the Baltic markets was slightly lower than in the first months the quarter.

During peak hours, the electricity price in the region is normally determined by gas-fired power plants. In Q3, the price of natural gas remained relatively stable compared to recent years: €35.1/MWh (+€1.3/MWh, +3.9% year on year). European gas storage reached 90% by mid-August, nearly two months ahead of the EU deadline. According to the latest data, the European gas storage facilities were 94% full.

Interconnectors supply the Baltic countries with Nordic hydropower, which is cheaper than other types of electricity. The average level of hydro resources in the Nordic hydropower reservoirs in Q3 2024 was 76.3% of the maximum, which is a marginal 0.6 percentage points higher than in Q3 2023.

The average CO2 emission allowance price in Q3 2024 was €68.5/t, 20.1% (€17.2/t) lower than a year earlier. The emission allowance price also decreased compared to Q2 2024, mainly due to weaker demand and higher renewable energy production. Analysts expect the average CO² emission allowance price to be around €64.0/t in 2024 and €74.0/t in 2025. The price is expected to rise due to regulatory changes in the EU that will reduce the allocation of free allowances in order to curb CO2 emissions and promote renewable energy production.

Average electricity price (€/MWh)	Q3 2024	Q3 2023	Change
Estonia	96.5	95.6	0.9%
Latvia	96.3	101.0	(4.7)%
Lithuania	96.4	101.0	(4.5)%
Poland	101.3	110.7	(8.5)%
Finland	28.1	44.2	(36.3)%
Norway	21.0	23.6	(11.2)%
Denmark	68.7	78.7	(12.6)%
Sweden	17.8	27.3	(34.8)%

Wind conditions

Due to seasonal factors, wind conditions in Q2 and Q3 are less favourable for wind power generation in our region than in the rest of the year. In Q3 2024, there was little wind in our main markets – the average wind speeds in Estonia and Lithuania were 5.4 and 5.6 m/s (-0.3 and -0.1 m/s year on year), respectively. In Finland (Tolpanvaara), wind conditions were quite good – the average wind speed was 6.9 (+0.8) m/s, but as most of our wind power production capacity is located in Estonia and Lithuania, wind conditions had a negative impact on our electricity production in Q3.

Renewable energy discounts

The captured renewable energy price is the average market price, weighted by hourly production. Due to the volatility of renewable energy production, the captured renewable energy price differs from the market price (the arithmetic mean of hourly prices). Market prices tend to be lower during periods of high renewable energy production and higher during periods of low renewable energy production, which is why the captured renewable energy price is usually lower than the market price. The renewable energy discount measures the difference between the captured price and the market price of renewable energy as a percentage.

The charts below show both the wind speed data (wind conditions) and the wind discounts for each market. They reflect the overall market situation and not necessarily the conditions in Enefit Green's production portfolio. Larger wind discounts are caused by hours with negative prices, which producers can counter by actively curtailing their generation assets. In addition, uncorrelated assets can help producers achieve profile discounts below the market average. These factors have helped us at Tolpanvaara wind farm to achieve wind discounts well below the Finnish market average.

Regulatory environment

Estonia

Following consultations with market participants, the original plan to introduce a frequency reserve fee of €5.31/MWh for electricity producers and consumers from February 2025 was rejected. The new plan is to introduce a harmonised fee in partnership with Latvia and Lithuania by 1 January 2026 in order to create a similar operating environment for electricity producers and consumers across the Baltic countries. However, Estonia may introduce a temporary fee for the period 1 July – 31 December 2025. Final decisions will be made in early 2025.

The Estonian parliament has passed an amendment to the Electricity Market Act that will end renewable energy and efficient cogeneration support for the Iru cogeneration plant from 1 January 2025. In Enefit Green's view, the amendment is disproportionate, discriminatory and calls into question whether the state will honour its future 12-year renewable energy development commitments. We have asked the Chancellor of Justice to assess the constitutionality of the amendment and are awaiting a response.

The Ministry of Climate has submitted a number of legislative amendments affecting renewable electricity production, including the following proposals:

Wind farm toleration fees (compensation payments) for the period from the start of production to the receipt of an operating permit will be increased. The current rate is 10% of the minimum fee and the proposed rate is 70% of the minimum fee. Increasing the toleration fee after companies have made investment decisions based on a lower toleration fee sets a dangerous precedent in Estonia.
The rules on electricity storage will change: the storage period will be reduced from one year to one month. Electricity taken from the grid and fed back into the grid during the same storage period will be exempt from network and renewable energy charges. The measurement conditions for electricity storage will be specified. For the purposes of electricity excise duty, it is still planned to treat electricity storage as final consumption of electricity, and excise duty will be payable on stored electricity taken from the grid.
The principles for network service will change: the transmission system operator will be required to make proactive investments in the network and the current cost-based connection fee will be replaced by a significantly higher connection fee of €44,000/MVA, which will reduce the cost of connecting to the transmission network in more remote locations. The maximum length of a direct line that can be built will be increased from 6 to 15 kilometres. Various technical details of the charge for an energy producer's unused grid connection will change.

Discussions on the volumes and principles of future wind energy reverse auctions continued. The legislative changes are expected to be submitted by the end of 2024 and adopted in Q1 2025. The first reverse auctions are expected to be announced in April 2025.

In November, the government decided to offer contracts for the right to build on 85 km2 of state-owned land for 39 years for the development of onshore wind farms with a total capacity of ca 1100 MW.

Latvia

At the end of August, toleration fees (compensation payments) for wind turbines located near residential buildings took effect in Latvia. All new wind turbines with a capacity of over 1 MW will be subject to a toleration fee, regardless of the height of the turbine or whether it is located onshore or offshore. The fee is set at €2,500 per MW of installed capacity per year. The payments are administered by the local authority on whose territory the wind turbines are located. The fee for the previous year of operation is payable by 1 March.

The plan is to review the fee rate every five years using an indexation model yet to be introduced. In exceptional circumstances the rate may be reviewed sooner. Future changes to wind turbine toleration fees represent an additional risk for investors.

Lithuania

The Lithuanian government adopted an updated version of the National Climate and Energy Plan 2021–2030 on 2 October and submitted it to the European Commission. Lithuania's significantly increased target of generating at least 100% of its electricity consumption from renewable sources by 2030 is now firmly in place (in the previous version of the plan, the target was to generate only 45% of Lithuania's electricity consumption from renewable sources by 2030).

On 25 September 2024, the Lithuanian government approved a draft law to increase the cybersecurity safety requirements for power plant control systems and submitted it to the parliament. The control systems of solar and wind farms, as well as electricity storage facilities with a capacity exceeding 100 kW, must ensure that they cannot be accessed or remotely controlled by foreign entities. Existing installations will not have to be decommissioned, but operators will have to take additional security measures when using them. The changes are expected to take effect on 1 May 2025, with the new requirements for existing installations taking effect on 31 May 2026 after a transition period.

Significant events

Loan agreement with EBRD

In August, Enefit Green signed a €100m loan agreement with the European Bank for Reconstruction and Development (EBRD) to complete the construction and to operate the 255 MW Sopi-Tootsi wind farm in Estonia. The Sopi-Tootsi wind farm will cover almost a tenth of Estonia's current annual electricity consumption and prevent the emission of 480,000 tonnes of greenhouse gases per year.

Extension of Innar Kaasik's mandate as a management board member

Enefit Green's supervisory board has extended Innar Kaasik's mandate as a management board member responsible for production for a further three years until 24 September 2027. Innar Kaasik has been a member of Enefit Green's management board since 2017.

Expiry of Veiko Räim's mandate as a management board member

As communicated in the stock exchange announcement of 28 June 2024, Veiko Räim's mandate as Enefit Green's management board member and CFO expired on 24 September 2024.

Settlement of the Akmenė incident with GE Vernova

In September 2024, Enefit Green reached a settlement with GE Vernova regarding an incident during the construction of the Akmenė wind farm, which resulted in the collapse of a wind turbine. As a result of the negotiations, Enefit Green and GE Vernova agreed on an amendment to the Akmenė wind farm turbine supply agreement signed between the parties, including compensation of €8.2m, of which €3.9m was paid by GE Vernova to Enefit Green in cash and the remaining amount was offset against reciprocal receivables and liabilities. Of the €8.2m, €5.3m was recognised as other operating income and €1.6m as a reduction of previously made investments. GE Vernova and Enefit Green also entered into additional agreements totalling €1.3m, which did not affect Enefit Green's financial results.

Total installed production capacity reaches 1,000 MW

At the beginning of September, Enefit Green inaugurated the Šilalė II wind farm (43 MW) and laid the foundation stone for the Kelmė II wind farm (87 MW) in Lithuania. The group also completed the installation of all 38 wind turbines at the Sopi-Tootsi wind farm (255 MW) in Estonia, currently the largest in the Baltic countries. The first Sopi-Tootsi wind turbines started to supply electricity to the grid. Following the installation of all wind turbines at the Sopi-Tootsi wind farm, the total capacity of Enefit Green's installed electricity generation assets exceeds 1,000 MW.

Cooperation agreement with the City of Pärnu and Sunly

Enefit Green, the City of Pärnu and Sunly have signed a cooperation agreement that will enable the Põlendmaa wind farm, when completed, to contribute to the well-being of the local community. In the cooperation agreement, the parties confirm that the Põlendmaa wind farm will be built in close cooperation and with a focus on improving local life and that any issues will be addressed in good faith.

Enefit Green and Sunly have been developing the Põlendmaa wind farm since 2020. In April 2023, the City of Pärnu and the Tori Rural Municipality approved phase I of a designated spatial plan for wind energy development. Phase II of the designated spatial plan, which will specify the detailed solution for the wind farm and the number, height and location of the wind turbines, is underway.

Exploring financing alternatives for further development of Enefit Green

Enefit Green's management board continuously analyses and optimises the group's development and production portfolio in order to increase its value. In this context, we have decided to explore broader strategic options for the execution of our development portfolio and to initiate relevant consultations with third parties.

Financial results

The Enefit Green group's operating income for Q3 2024 decreased by 2% while operating expenses (excl. D&A) decreased by 3% compared to the same period last year. As a result, EBITDA decreased by 1% to €15.7m. Net profit for the period increased by €0.4m to €5.4m. The key factors that influenced the group's financial performance are described below.

The comparison of the group's Q3 performance indicators is strongly affected by the sale of the Brocēni CHP plant and pellet factory, which was completed in Q4 2023, and the sale of the Paide and Valka CHP plants, which was completed in March 2024 ('assets sold'). The results for Q3 2023 include operating income of €5.8m, operating expenses of €6.1m and effects on EBITDA of €0.8m related to the assets, which were sold by the end of Q1 2024.

Production and sales volumes

GWh	Q3 2024	Q3 2023	Change	Change, %
Electricity production (net)	342	259	83	32%
Of which by new wind and solar farms	150	53	97	183%
Of which by assets sold	0	9	(9)	(100)%
Electricity sales*	491	364	127	35%
Heat production	80	115	(34)	(30)%
Of which by assets sold	0	30	(30)	(100)%

The group's Q3 electricity production grew by 83 GWh (32%) to 342 GWh, with the output of new wind and solar farms completed and under construction increasing by 97 GWh. Assets sold had a negative impact, reducing Q3 electricity production by 9 GWh compared to Q3 2023.

Operating income

Total operating income decreased by €1.0m, the figure reflecting a decrease in revenue of €5.8m, an increase in other operating income of €4.8m and no change in the level of renewable energy support. Assets sold, which generated operating income of €5.8m in Q3 2023, did not have any impact on operating income for Q3 2024.

Excluding the impact of assets sold, i.e. operating income from continuing operations was €38.7m for Q3 2023 and €43.5m for Q3 2024 (up €4.8m, the figure reflecting a decrease in revenue of €0.2m and an increase in other operating income of €4.9m).

Of the €0.2m decrease in revenue from continuing operations, €1.4m resulted from electricity sales revenue. In Q3 2024, the average electricity price** in the group's core markets was €87.5/MWh (Q3 2023: €97.8/MWh). The group's average implied captured electricity price*** was €50.3/MWh (Q3 2023: €83.9/MWh).

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

The group's average price of electricity sold to the market was €49.8/MWh in Q3 2024 and €82.2/MWh in Q3 2023. Enefit Green sold 196 GWh of electricity to the market in Q3 2024 compared with 163 GWh in Q3 2023.

€m	Q3 2024	Q3 2023	Change	Change, %
TOTAL OPERATING INCOME	43.5	44.5	(1.0)	(2)%
Revenue	33.8	39.7	(5.8)	(15)%
Renewable energy support and other operating income	9.7	4.8	4.8	100%
TOTAL OPERATING EXPENSES (excl. D&A)	27.8	28.6	(0.8)	(3)%
Raw materials, consumables and services used (excl. electricity)	7.3	12.5	-5.2	(41)%
Electricity purchase costs	15.2	13.5	1.6	12%
Payroll expenses	2.2	2.6	(0.5)	(18)%
Other operating expenses	3.2	3.4	(0.2)	(6)%
Change in inventories	0.0	(3.4)	3.4	(100)%
EBITDA	15.7	15.9	(0.2)	(1)%
Depreciation, amortisation and impairment (D&A)	10.2	10.2	(0.1)	(1)%
OPERATING PROFIT	5.5	5.7	(0.2)	(3)%
Net finance income and costs	(0.1)	(0.4)	0.2	(65)%
Income tax	0.0	0.3	(0.3)	(102)%
NET PROFIT	5.4	5.0	0.4	8%
TOTAL OPERATING EXPENSES (excl. D&A)	27.8	28.6	(0.8)	(3)%
Variable costs (incl. balancing energy purchases)	17.2	20.5	(3.4)	(16)%
Fixed costs	10.7	11.5	(0.8)	(7)%
Change in inventories	0.0	(3.4)	3.4	(100)%

In Q3 2024, 276 GWh of the group's electricity production was covered by PPAs at an average price of €60.7/MWh. In Q3 2023, 202 GWh of electricity was sold under PPAs at an average price of €80.9/MWh. The average price of electricity sold under PPAs has decreased significantly year on year because the settlement periods of PPAs signed in Lithuania and Finland in 2021 at lower prices began in Q1 2024. The share and prices of production covered by PPAs in future periods are disclosed in the Risk management chapter.

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

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

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

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

Average quarterly electricity prices

	Q3 2023	Q4 2023	Q1 2024	Q2 2024	Q3 2024
Price of electricity sold to the market	82.2	64.1	77.6	52.3	49.8
PPA price	80.9	91.2	75.0	68.0	60.7
Realised purchase price	116.5	121.5	106.1	80.4	106.6
Core markets' average electricity price	97.8	93.1	87.0	72.2	87.5
Implied captured electricity price	83.9	80.9	81.4	69.7	50.3

In Q3 2024, we purchased 132 GWh of electricity from the market at an average price of €106.6/MWh, compared with 109 GWh at an average price of €116.5/MWh in Q3 2023 (the prices and volumes exclude the electricity purchased for pellet production in Q3 2023). The volume of electricity purchased increased (+23 GWh) due to higher sales under PPAs. The purchase price decreased compared to Q3 2023 due to lower market prices, but the gap between the purchase price and the sales price widened due to a larger wind discount. Wind discounts deepened significantly year on year. Enefit Green's wind discounts in Estonia and Lithuania were similar to the market level, increasing by 11.6 and 8.1 percentage points in Estonia and Lithuania, respectively. In Finland, however, low correlation of the production with other Finnish wind farms and downregulation of power production during negative prices enabled us to reduce the wind discount more than twofold compared to the market level.

Other operating income (excl. the impact of assets sold) increased by €4.8m, supported by income of €5.3m from the settlement reached with GE Vernova regarding an incident during the construction of the Akmenė wind farm, which resulted in the collapse of a wind turbine. After negotiations concerning the incident, Enefit Green and GE Vernova agreed on an

amendment to the Akmenė wind farm turbine supply agreement signed between the parties, including compensation of €8.2m, of which €3.9m was paid by GE Vernova to Enefit Green in cash and the remaining amount was offset against reciprocal receivables and liabilities. Of the €8.2m, €5.3m was recognised as other operating income and €1.6m as a reduction of previously made investments. GE Vernova and Enefit Green also entered into additional agreements totalling €1.3m, which did not affect Enefit Green's financial results.

Renewable energy support remained stable compared to Q3 2023. The eligibility period of the Purtse wind farm began in Q2 2024, which increased the amount of support received for the period by €0.3m year on year. The output of other wind farms eligible for support in Estonia was lower than in Q3 2023 and, therefore, the amount of support received decreased by €0.5m. The amount of support received in Poland, on the other hand, increased by €0.2m, because the market price of electricity (€103.1/MWh) was below the fixed price of €125–134/MWh and the difference was paid out as support.

Raw materials, consumables and services used

Expenses on raw materials, consumables and services decreased by €5.2m (52%). The largest changes were in technological fuel and pollution charge costs. Technological fuel costs decreased by €5.5m due assets sold and pollution charge costs grew by €0.5m due to an increase in the pollution charge of the Iru cogeneration plant.

Payroll expenses

The group's payroll expenses decreased by 18% year on year. At the reporting date, the group had 131 employees compared with 181 at the end of Q3 2023.

Payroll expenses for Q3 2023 include expenses of €0.6m attributable to assets sold. At the end of Q3 2023, the number of employees attributable to assets sold was 61.

Excluding the impact of assets sold, payroll expenses increased by 6% compared to the same period last year.

New people have mostly been hired to the development team to support projects under construction and development in all markets. At the end of Q3 2024, the development team had 43 employees compared with 36 a year earlier.

Other operating expenses decreased by €0.2m (6%), mainly due to the effect of assets sold on the comparative period.

EBITDA and fixed costs

The factor with the strongest impact on EBITDA development was the decrease in the price of electricity sold (negative impact: €9.0m). Due to PPAs, the quantity of electricity sold grew significantly (positive impact: €7.9m), which also increased the volume of electricity purchased to balance the electricity portfolio (negative impact: €2.9m). The combined effect of the above factors on EBITDA is influenced by the volume and profile of electricity produced during the period. Electricity production grew by 32% year on year.

The total impact of assets sold on EBITDA development was negative at €0.8m.

Excluding the effects of the electricity price and volume, the Iru cogeneration plant had a positive impact on EBITDA. The calculation takes into account the effects of heat, gate fees for waste received and technological fuel. For further information on the results of the Iru cogeneration plant, see the chapter Cogeneration segment.

Further information about income from the settlement of the Akmenė incident is provided in the section on operating income.

Depreciation, amortisation and impairment (D&A)

D&A expense increased by €0.1m (1%). Assets sold lowered D&A expense compared to Q3 2023 by €1.2m. D&A expense excluding the effect of assets sold increased by €1.1m (12%). Noncurrent assets recognised after Q3 2023 include the Zambrow solar farm in Poland (D&A for Q3 2024: €0.1m), the Tolpanvaara wind farm in Finland (D&A for Q3 2024: €0.8m) and the Debnik solar farm in Poland (D&A for September 2024: €11k).

Net finance costs

Net finance costs decreased by €0.2m compared to the same period last year. Interest expense on bank loans increased by €3.7m, but 96% of it was capitalised as the wind and solar farms are still under construction. The change in the exchange rate of the Polish zloty had a positive impact (€0.5m) on net finance costs.

Income tax

Income tax expense decreased by €0.3m compared to Q3 2023.

Other operating expenses

Financial results by segments

Based on operating income and EBITDA, the group's largest segment is Wind energy, which accounted for 73% of operating income and 78% of EBITDA for Q3 2024. The Cogeneration segment contributed 20% to operating income and 31% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 7% the group's operating income and 13% of the group's EBITDA for Q3 2024.

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

The EBITDA of the segment Other mainly includes general administrative expenses, the payroll expenses for employees involved in the Wind energy and the Solar energy segments, and the costs of development projects without an investment decision. The segment also includes the Keila- Joa hydroelectric facility and the renewable energy solution on the island of Ruhnu. The loss of the segment Other increased by €0.1m.

Group's EBITDA breakdown and change, €m

Operating income by segment, €m

Wind energy

The Wind energy segment comprises the group's operating wind farms and wind farm developments with an investment decision. From the Q1 2024 interim report, the expenses for wind energy development teams, wind farm developments without an investment decision and offshore wind developments are included in the segment Other and not in the Wind energy segment.

Availability and production

The group's total wind power production in Q3 2024 was 285.2 GWh, 89.0 GWh higher than in Q3 2023 due to new wind farms coming online. The contribution of new wind farms and wind farms under construction was 130.8 GWh (+92.6 GWh compared to Q3 2023).

Our wind power production in Q3 was negatively affected by wind conditions – average wind speeds in Estonia and Lithuania were lower than expected, reducing the expected production volume by over 20 GWh, but due to better wind conditions in Finland the total impact of wind conditions on the group's wind power production was around -10 GWh. The availability of the group's operating Estonian and Lithuanian wind farms, which was 94.9% and 96.1% respectively, met expectations (Q3 2023: 92.3% and 82.5%, respectively). The availability of the Tolpanvaara wind farm in Finland was 95.7% in Q3. The impact of the availability of operating wind farms on Q3 wind power production was +1.6 GWh.

In Q3 2024, the impact of production curtailments and downregulations was the strongest in recent quarters: -26.4 GWh. Two-thirds of this was due to negative prices and a half of the latter was attributable to the Tolpanvaara wind farm in Finland. Around a quarter of the production reduction was due to network maintenance and constraints, while more than a tenth was due to services provided by Enefit Green to system operators.

At the end of Q3, the first commissioned wind turbines at the Sopi-Tootsi wind farm started producing electricity. While the construction of the farm has progressed faster than expected, its production was 69 GWh lower than expected. The start of production at the Kelmė I wind farm in Lithuania and our new solar farms in Latvia has also been postponed.

Electricity prices

The implied captured electricity price of the Wind energy segment depends on the combination of the market price and PPAs. In Q3 2024, the segment's average implied captured electricity price* including support was €40.0/MWh (45.4% lower than in Q3 2023). The implied captured electricity price was strongly affected by the decrease in the average PPA price due to the start of the supply period in 2024 for the PPAs signed in 2021 at lower prices, which reduced the average implied captured electricity price by €20.9/MWh.

The price of electricity sold to the market also declined compared to the same period last year due to lower prices in the Nord Pool Lithuania price area and the start of production in Finland. The negative impact of lower market prices was partly offset by the lower prices of electricity purchased to balance the PPA portfolio.

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

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

Operating income

The segment's operating income for Q3 2024 increased by €4.5m (16.8%). Operating income was improved by the settlement reached in September with GE Vernova regarding the incident at the Akmenė wind farm. The agreed settlement amount was €8.2m, of which €5.3m was recognised as other operating income and €1.6m as a reduction of investments made. GE Vernova and Enefit Green also entered into additional agreements of €1.3m, which did not affect Enefit Green's financial results (see note 10).

Operating income was also increased by the renewable energy support of €0.3m (Q3 2023: nil) received for the Purtse wind farm that became eligible in Q2 2024. However, the renewable energy support for the other Estonian wind farms decreased by €0.5m (by €0.2m at the Narva wind farm). In the comparative period (Q3 2023) a penalty was charged for the low availability of the Šilutė wind farm, which had increased a comparative period by €0.4m.

Operating expenses

The segment's operating expenses (excl. D&A) grew by €3.0m to €19.2m, mainly due to electricity purchased to balance the PPA portfolio in hours of low wind speed. Electricity purchase costs, including balancing energy purchases and purchases for the PPA portfolio, grew by €2.4m.

Other operating expenses (excl. electricity purchases, expenses on balancing energy and growth in D&A) increased by €0.4m year on year. The largest increase was in wind farm maintenance, repair and land costs (€0.2m). Within maintenance costs, the largest item was the Akmenė wind farm maintenance, which started in August 2024. Additional impact of €0.1m came from electricity network charges for wind farms.

EBITDA

The Wind energy segment's EBITDA for Q3 improved, rising to €12.3m (Q3 2023: €10.9m). The compensation received from GE Vernova increased EBITDA by €5.3. Excluding the settlement, the segment's EBITDA for Q3 2024 would have decreased by €3.9m due to an increase in electricity purchase costs by €2.4m.

Operating expenses per MW

Based on the expenses of the companies holding the group's operating wind farms (Enefit Wind OÜ and Enefit Wind UAB), which are part of the Wind energy segment, wind farm operating expenses (excl. D&A, balancing energy purchases and electricity purchases to service PPAs) per installed capacity (MW) decreased in Q3 2024 by 14.1% year on year. The decline is attributable to the addition of the 72 MW Tolpanvaara wind farm to operating wind farms in Q3 2024. Excluding the impact of the Tolpanvaara wind farm, operating expenses would have increased by €0.2/MW. The period's operating expenses were strongly affected by unplanned repairs at the Šilalė wind farm (€0.1m), which were caused by a lightning strike, and the price indexation of the maintenance contract for the Paldiski II wind farm (€0.1m).

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, starting from Q3 2023 Purtse windfarm and starting from Q3 2024 Tolpanvaara.

Cogeneration

Until the end of 2023, the Cogeneration segment comprised the Iru, Paide, Valka and Brocēni combined heat and power (CHP) plants and a pellet factory. After the sale of the biomass assets in late 2023 and early 2024, the segment comprises the Iru CHP plant that uses mixed municipal waste as fuel.

Electricity production and prices

The Cogeneration segment produced 25.8 GWh of electricity in Q3 2024, 30% less than a year earlier (Q3 2023: 37 GWh). From March 2024, the production figures of the Cogeneration segment consist of the figures of the Iru CHP pant, because the Brocēni CHP plant was sold at the end of December and the sale of the Paide and Valka CHP plants was finalised at the beginning of March.

The electricity production of the Iru CHP plant decreased by 2.6 GWh (9%) year on year due to planned maintenance in July, which was a week longer than planned and 4 days longer than in Q3 2023.

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

* Due to the sale of the other CHP plants, all figures presented are for the Iru CHP plant.

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

The segment's implied captured electricity price increased by 3% year on year to €128/MWh, driven by the market price in the Nord Pool Estonia price area.

Heat production and prices

Heat production decreased by 30% year on year to 80.5 GWh in Q3 2024. The decline attributable to assets sold was 29.6 GWh. The heat output of the Iru CHP plant decreased by 4.7 GWh (6%) year on year to 80.5 GWh (Q3 2023: 85.1 GWh) due to a long maintenance period in July. The average sales price of heat per MWh increased by 63% year on year to €18.3/MWh. In Q3 2023, the price cap for heat produced by the Iru CHP plant was €7.98/MWh. From 1 July 2024, the price cap for heat produced by the Iru CHP plant from mixed municipal waste is €18.29/MWh.

Operating income

The Cogeneration segment's operating income decreased by €5.9m (40%) to €8.7m. Of the decrease, €5.8m was attributable to assets sold.

The Iru CHP plant's electricity sales revenue decreased by €0.7m to €2.8m due to a decline in electricity production and gate fee revenue decreased by €0.5m to €3.1m due to a decrease in waste received, while heat sales revenue increased by €0.8m due to a higher price.

Operating expenses

The Cogeneration segment's operating expenses (excl. D&A) decreased to €5.2m (Q3 2023: €10.7m). In Q3 last year, the fixed and variable costs of assets sold amounted to €6.1m.

The Q3 operating expenses of the Iru CHP plant (excl. D&A) increased by €0.6m (14%) year on year to €5.2m. Variable costs increased by €0.2m, the figure reflecting a decrease in electricity purchase costs of €0.3m (due to a decline in the volume of electricity purchased) and an increase of €0.5m in pollution charges. Fixed costs increased by €0.4m, of which €0.3m resulted from higher maintenance and repair costs.

The segment's EBITDA for Q3 2024 was €4.8m, €1.6m (25%) lower than in the same period last year. One half of the decrease (€0.8m) is attributable to assets sold and the rest is attributable to the Iru CHP plant, whose EBITDA decreased by €0.8m to €4.8m. The decline in the EBITDA of the Iru CHP plant, which was mainly due to lower availability that reduced energy production and higher maintenance and repair costs, was partly offset by an increase in the price cap for heat.

Solar energy

The Solar energy segment comprises operating solar farms, solar farm developments with an investment decision and solar services. From the Q1 2024 interim report, the expenses for the development of solar projects without an

investment decision, management of solar farms and

solar farm development teams are included in the segment Other and not in the Solar energy segment (the figures for the comparative period have been adjusted accordingly).

Electricity production and prices

The Solar energy segment produced 30.9 GWh of solar power in Q3 2024, 4.6 GWh (18%) more than in the same period in 2023 due to the Estonia mine solar farm and the Debnik solar farm coming online. The Estonia solar farm in Estonia supplied its first electricity in Q4 2023 and the Debnik solar farm in Poland in Q1 2024. In Q3 2024, the new assets produced 19.6 MWh of electricity. The availability of solar farms remained high at 99.8% (Q3 2023: 99.7%).

Our solar farms in Estonia are partly exposed to movements in the market price of electricity. The new Estonia solar farm sells electricity at a fixed price of €69/MWh. 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 2024 was €125–134/MWh. The price charged by the new Zambrow solar farm is €63/MWh.

In Q3 2024, the Solar energy segment sold 11.4 GWh of electricity under PPAs at an average price of €79.7/MWh.

The segment's implied captured electricity price was €73.9/MWh, which is 23% lower than in Q3 2023. The implied captured electricity price decreased by 34% in Estonia and by 7% in Poland.

Operating income

The operating income of the Solar energy segment grew by €0.5m. The segment's electricity sales revenue decreased in both Estonia and Poland due to lower prices. However, the support received in Poland increased by €0.2m compared to Q3 2023. As the market price of electricity (€103.1/MWh) was below the fixed price of €125–134/MWh, the difference was paid out as support. Operating income was also increased by one-off income of €0.3m received for the lease agreements of the two small recently completed solar farms.

Operating expenses

The segment's operating expenses (excl. D&A) increased by €0.5m. The recognition of lease agreements for the two smaller newly completed solar farms gave rise not only to income but also to expenses of €0.2m. The rest of the increase resulted from the variable costs of operating solar farms, which grew due to electricity purchased to balance the PPAs of the Purtse solar farm.

EBITDA

The Solar energy segment's EBITDA for Q3 2024 was €2.0m, which is at the same level as in Q3 2023. EBITDA was positively affected by slightly higher production (up 4.6 MWh) and negatively affected by the decline of €22.2/MWh in the implied captured electricity price. In Q3, we recognised lease agreements for two new solar farms, which increased EBITDA by €0.1m.

Investment

The group invested €76.9m in Q3 2024, €10.4m less than in Q3 2023. The decrease resulted from development investments, which amounted to €77.0m. Of this, €55.5m was invested in the construction of three wind farms: €28.9m in the Sopi-Tootsi wind farm and €26.6m in the two Kelmė wind farms (€15.1m in Kelmė I and €11.5m in Kelmė II). The largest development investment in solar energy was made in the Sopi solar project in the amount of €2.4m.

At 30 September 2024, the carrying amounts of the segments' property, plant and equipment and intangible assets were as follows: Wind energy €1,199.7m including goodwill (52% of assets under construction), Cogeneration €91.9m (0% under construction), Solar energy €131.0m (49% under construction) and Other €17.3m (72% under construction).

The estimated cost of completing the assets currently under construction is €180m, most of which is required for the completion of the Kelmė II wind farm.

Update of investment criteria

We have revised our investment policy for new projects. Previously, the policy was that a project's rate of return should be at least the weighted average cost of capital (WACC) plus 2% and that, for revenue security, at least 60% of the project's production for the first five years should be covered by a price risk mitigation instrument (such as a PPA).

The main criterion, i.e. the rate of return, remains the same: WACC + 2%, but we will also consider shorter-term returns, downside scenario analysis and improved value creation for Enefit Green's equity investors.

In terms of revenue security, we will take a more proactive approach to our PPA portfolio, optimising it with power purchases where necessary. We will target a minimum guaranteed level of income that is consistent with the level of our fixed costs and the need to cover them.

We have also created a framework for limited-risk investment in emerging technologies, such as battery storage and hydrogen projects, where conventional investment criteria may not be applicable.

Financing

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

At 30 September 2024, the amortised cost of the group's interest-bearing liabilities was €694.0m (30 June 2024: €629.0m). Loan liabilities to banks accounted for €680.3m of the total, including an outstanding loan balance of €6.0m denominated in Polish zloty.

In Q3, Enefit Green drew down bank loans of €125m. During the quarter, the group signed an investment loan agreement of €100m with EBRD and a new revolving credit facility agreement of €20m with OP Bank to replace a matured revolving credit facility of the same amount provided by SEB, and extended a revolving credit facility agreement of €10m with SEB.

The interest rate risk of investment loans with the total outstanding balance of €144.4m 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 2024 was 4.19% (30 June 2024: 4.23%).

Loans raised but not drawn down at 30 September 2024 totalled €260m, which consisted of investment loans of €210m and revolving credit facilities of €50m.

Bank loan repayment schedule, €m

Loan covenants

The group's loan and credit agreements include covenants that impose certain limits on the group's consolidated financial indicators. At 30 September 2024, the group was in compliance with all loan terms, including covenants.

Financing and return ratios

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

€m	30 September 2024	31 December 2023
Interest-bearing liabilities	694.0	486.4
Less cash and cash equivalents	(31.4)	(65.7)
Net debt	662.7	420.7
Equity	731.9	717.2
Invested capital	1,394.6	1,137.9
EBITDA (last 12 months)	106.6	105.9
Operating profit (last 12 months)	66.4	65.3
Net profit (last 12 months)	61.9	55.8

Financial leverage (1)	48%	37%
Net debt / EBITDA	6.22	3.97
Return on invested capital (2)	4.8%	5.7%
Return on equity (3)	8.5%	7.8%
Interest cover (4)	4.5	7.9

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

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

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

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

Risk management

The group has two main market and financial risks that are actively managed – 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 existing production assets; and
power purchase agreements (PPAs).

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

We have revised our Q4 electricity production forecast from the previous 753 GWh to 645 GWh (+56% compared to Q4 2023). The reason for the downward revision is the slower than expected start of production at the Sopi-Tootsi and the Kelmė I wind farms. Based on the updated Q4 forecast, we expect our assets to generate 1.84 TWh of electricity in 2024, of which 1.35 TWh is expected from operating assets and 0.48 TWh from assets under construction.

1.22 TWh (66.3%) of our expected electricity production in 2024 is covered with PPAs at an average price of €66.5/MWh. In Q3 2024, we continued to actively manage our PPA portfolio for year 2024, taking into account the revised Q4 production forecast, price expectations and other risk factors. As a result, we reduced the Q4 2024 PPA volume in the Baltic price areas by 56.0 GWh using both physical PPAs and financial swap agreements. We intend to continue active management of the PPA portfolio, balancing the mitigation of price risk and management of the risk associated with purchases related to baseload PPAs. The chart shows the expected quarterly development of Enefit Green's electricity portfolio in 2024, with Q1, Q2 and Q3 figures reflecting actual results.

Long-term PPAs

According to previous practice, Enefit Green generally fixed the sales price of electricity for at least 60% of a development project's projected power production for the first five years by the time the final investment decision on the project was made. Enefit Green also used PPAs to hedge the price risk of its operating electricity production portfolio. In Q3, we updated our investment criteria, replacing the above target of a specific proportion of fixed-price production with a target of a minimum level of guaranteed revenue.

We did not sign any new long-term PPAs in Q3 2024. At 30 September 2024, Enefit Green had signed PPAs (incl. financial swaps) for the supply of 8,674 GWh of electricity at an average price of €71.1/MWh over the period of October 2024 – December 2033. The counterparty to most of the PPAs is Eesti Energia AS (7,787 GWh). 49.8% of our expected electricity production in the period 2024–2028 is covered by PPAs at an average price of €68.0/MWh.

	2024	2025	2026	2027	2028	Total 2024–2028
FiT/CfD schemes**	1%	1%	1%	1%	1%	1%
Volume (GWh)	26	26	26	27	27	132
Price***, €/MWh	111.7	114.9	117.2	119.2	121.6	117.0
FiP support**	25%	9%	3%	3%	2%	7%
Volume (GWh)	461	258	91	83	80	974
Price***, €/MWh (added to the market price)	50.2	50.2	53.7	53.7	53.7	51.1
PPAs and financial swaps**	66%	55%	49%	48%	38%	50%
Volume (GWh)	1,221	1,533	1,534	1,549	1,219	7,057
Price***, €/MWh	66.5	64.8	64.8	69.0	76.4	68.0

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

National support measures

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

The share of fixed-price support measures has decreased significantly. Only 1% of Enefit Green's expected electricity production in 2024–2028 is covered by fixed-price support measures (contracts for difference (CfD) schemes in Poland) at an average price of €117.0/MWh.

Forecasted production volumes of production assets (operating,

¹ ³⁵⁴ ¹ ⁴¹¹ ¹ ⁴²⁴ ¹ ⁴⁸⁴ ¹ ⁴⁶⁴ 1 394 ¹ ⁷⁰³ ¹ ⁷⁶⁵ ¹ ⁷⁶⁵ 1 221 1 533 1 534 1 549 1 219 26 26 26 27 27 461 ²⁵⁸ ⁹¹ ⁸³ 80 82 140 140 140 1 839 1 709 2 805 1 899 3 127 1 791 3 249 1 800 3 229 1 466 2024 2025 2026 2027 2028 under construction and planned) and their coverage with PPAs and renewable energy support measures, GWh Operating Under construction PPA FiT/CfD FiP Floor*

Electricity price forecasts for Enefit Green's core markets

In the electricity price forecasts**** published by independent parties, the forecast prices for the Baltic markets have remained at the same level as in our Q2 report, but the forecast prices for Poland and Finland for 2025, 2026 and 2027 have been revised downwards by up to 10%. Long-term electricity price forecasts have remained largely unchanged.

The downward revision of the short-term electricity price forecasts for Poland and Finland is attributed to a decrease in the price of emission allowances and more subdued expectations for electricity consumption growth due to industry challenges and a decrease in expected demand from hydrogen electrolysers.

* 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 forecast production of operating assets and assets under construction

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

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

Enefit Green | Interim report Q3 2024 | 30

Unaudited condensed consolidated interim financial statements Q3 2024

Condensed consolidated interim income statement

€ thousand	Note	Q3 2024	Q3 2023	9M 2024	9M 2023
Revenue	9	33,833	39,660	123,900	146,111
Renewable energy support and other operating income	10	9,656	4,832	26,762	17,051
Change in inventories of finished goods and work in progress		0	3,434	0	3,266
Raw materials, consumables and services used	11	(22,485)	(26,011)	(57,069)	(71,386)
Payroll expenses		(2,159)	(2,634)	(6,747)	(8,025)
Depreciation, amortisation and impairment		(10,157)	(10,218)	(29,328)	(29,740)
Other operating expenses		(3,182)	(3,388)	(9,850)	(10,716)
OPERATING PROFIT		5,506	5,675	47,668	46,561
Finance income		316	747	1,342	2,345
Finance costs		(443)	(1,115)	(1,185)	(1,897)
Net finance income and costs		(127)	(368)	157	448
Profit from associates under the equity method		62	45	13	85
PROFIT BEFORE TAX		5,441	5,352	47,838	47,094
Income tax income (expense)		6	(326)	(5,004)	(10,405)
PROFIT FOR THE PERIOD		5,447	5,026	42,834	36,689

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	0.021	0.019	0.16	0.12
Diluted earnings per share, €	6	0.021	0.019	0.16	0.12

Condensed consolidated statement of comprehensive income

€ thousand	Note	Q3 2024	Q3 2023	9M 2024	9M 2023
PROFIT FOR THE PERIOD		5,447	5,026	42,834	36,689
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	(3,300)	662	(455)	1,202
Exchange differences on the translation of foreign operations	7	66	(349)	125	53
Other comprehensive (loss) income for the period		(3,234)	313	(330)	1,255

TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		2,213	5,339	42,504	37,944

Condensed consolidated interim statement of financial position

€ thousand	Note		30 September 2024 31 December 2023	€ thousand	Note	30 September 2024	31 December 2023
ASSETS				EQUITY
Non-current assets				Equity and reserves attributable to shareholders of the parent
Property, plant and equipment	4	1,322,861	1,027,057	Share capital		264,276	264,276
Intangible assets		59,741	59,891	Share premium	6	60,351	60,351
Right-of-use assets		8,619	9,097	Statutory capital reserve		8,291	5,556
Prepayments for non-current assets	4	41,902	55,148	Other reserves	5, 7	162,996	163,451
Deferred tax assets		1,486	2,013	Foreign currency translation reserve	7	(37)	(162)
Investments in associates		524	548	Retained earnings		236,067	223,718
Derivative financial instruments	5, 7	3,450	5,054	Total equity		731,944	717,190
Non-current receivables		1,353	0	LIABILITIES
Total non-current assets		1,439,935	1,158,808	Non-current liabilities
				Borrowings	8	630,552	454,272
Current assets				Government grants		2,865	3,010
Inventories		5,611	3,180	Non-derivative contract liability	5, 7	12,412	12,412
Trade receivables		6,518	8,618	Deferred tax liabilities		12,416	12,497
Other receivables		8,385	16,380	Other non-current liabilities		5,466	5,331
Prepayments		7,780	30,084	Provisions		7	8
Derivative financial instruments	5	2,480	3,806	Total non-current liabilities		663,717	487,530
Cash and cash equivalents		31,362	65,677	Current liabilities
		62,135	127,745	Borrowings	8	63,494	32,126
Assets classified as held for sale		0	15,370	Trade payables		23,825	29,464
Total current assets		62,135	143,115	Other payables		17,175	24,981
Total assets		1,502,071	1,301,923	Provisions		2	6

Share premium	6	60,351	60,351
Statutory capital reserve		8,291	5,556
Other reserves	5, 7	162,996	163,451
Foreign currency translation reserve	7	(37)	(162)
Retained earnings		236,067	223,718
Total equity		731,944	717,190
LIABILITIES
Non-current liabilities
Borrowings	8	630,552	454,272
Government grants		2,865	3,010
Non-derivative contract liability	5, 7	12,412	12,412
Deferred tax liabilities		12,416	12,497
Other non-current liabilities		5,466	5,331
Provisions		7	8
Total non-current liabilities		663,717	487,530
Current liabilities
Borrowings	8	63,494	32,126
Trade payables		23,825	29,464
Other payables		17,175	24,981
Provisions		2	6
Non-derivative contract liability	5	1,913	5,674
		106,410	92,251
Liabilities directly associated with assets classified as held for sale		0	4,952
Total current liabilities		106,410	97,203
Total liabilities		770,127	584,733
Total equity and liabilities		1,502,071	1,301,923

Condensed consolidated interim statement of cash flows

€ thousand	Note	Q3 2024	Q3 2023	9M 2024	9M 2023
Cash flows from operating activities
Cash generated from operations	12	23,346	18,977	89,511	77,320

Interest and loan fees paid		(9,601)	(2,999)	(22,042)	(7,136)
Interest received		213	127	904	645
Income tax paid		(4,518)	(9,970)	(5,389)	(11,175)
Net cash generated from operating activities		9,440	6,135	63,984	59,654
Cash flows from investing activities
Purchase of property, plant and equipment and		(84,615)	(86,191)	(297,558)	(235,672)
intangible assets
Paid for acquisition of subsidiaries		0	0	0	(6,174)
Proceeds from finance leases		2	1	12	2
Proceeds from sale of property, plant and equipment		27	0	27	0
Dividends received on investments Proceeds from sale of a business (net of cash and cash		0	24	0	24
equivalents transferred)		0	0	16,879	0
Net cash used in investing activities		(84,586)	(86,166)	(280,640)	(241,820)
Cash flows from financing activities
Proceeds from bank loans	8	125,020	70,000	280,020	160,000
Repayments of bank loans	8	(59,219	(17,137)	(72,311	(28,314)
Repayments of lease principal	8	(178)	(97)	(383)	(276)
Proceeds from realisation of interest rate swaps		1,513	0	3,763	0
Dividends paid		0	0	(27,749)	(54,969)
Net cash generated from financing activities		67,137	52,766	183,341	76,441
Net cash flow		(8,010)	(27,265)	(34,315)	(105,725)
Cash and cash equivalents at the beginning of the period		39,372	52,996	65,677	131,456
Cash and cash equivalents at the end of the period		31,362	25,731	31,362	25,731
Change in cash and cash equivalents		(8,010)	(27,265)	(34,315)	(105,725)

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 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
Equity as at 31 December 2023	264,276	60,351	5,556	163,451	(162)	223,718	717,190
Profit for the period	0	0	0	0	0	42,834	42,834
Other comprehensive (loss) income for the period	0	0	0	(455)	125	0	(330)
Total comprehensive income for the period	0	0	0	(455)	125	42,834	42,504
Increase of statutory capital reserve	0	0	2,736	0	0	(2,736)	0
Dividends paid	0	0	0	0	0	(27,749)	(27,749)
Total contributions by and distributions to shareholders of the company, recognised directly in equity	0	0	2,736	0	0	(30,485)	(27,749)
Equity as at 30 September 2024	264,276	60,351	8,291	162,996	(37)	236,067	731,944

Notes to the condensed consolidated interim financial statements

1. Summary of material accounting policies

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

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

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

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

2. Financial risk management

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

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

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

Wind energy. The segment comprises the group's operating wind farms and wind farm developments that have an investment decision. From the interim report for Q1 2024, the costs of wind farm development teams and the development costs of wind energy projects without an investment decision are included in the segment Other and not the Wind energy segment (the figures for the comparative period have been adjusted accordingly).
Cogeneration. Until the end of 2023, the segment comprised the Iru, Paide, Valka and Brocēni cogeneration (CHP) plants and a pellet factory. The sale of the Paide, Valka and Brocēni CHP plants and the pellet factory was announced in Q4 2023. The sale of the Brocēni CHP plant and the pellet factory took place before the end of 2023. The sale of the Paide and Valka CHP plants was completed on 1 March 2024. Since the completion of the sale of the Paide and Valka CHP plants, the Cogeneration segment has consisted of the Iru cogeneration plant.
Solar energy. The segment comprises operating solar farms, solar farm developments and solar services. From the interim report for Q1 2024, the management costs of the development of solar farms and the development costs of solar projects without an investment decision are included in the segment Other and not in the Solar energy segment (the figures for the comparative period have been adjusted accordingly).

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

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

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

Management assesses segment results mainly on the basis of EBITDA, but also monitors operating profit. Finance income and costs, income tax expense and income, and 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. From the interim report for Q1 2024, capitalised interest expenses are allocated to segments (the figures for the comparative period have been adjusted accordingly). Previously, the entire amount was allocated to the segment Other.

Financial results by segments

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023
REVENUE
Wind energy	23,395	23,544	91,740	83,564
Cogeneration	7,652	13,388	25,947	56,289
Solar energy	2,702	2,446	5,906	5,700
Total reportable segments	33,749	39,378	123,593	145,553
Other	83	282	306	557
Total	33,833	39,660	123,899	146,110
RENEWABLE ENERGY SUPPORT AND
OTHER OPERATING INCOME
Wind energy	8,143	3,463	16,892	11,927
Cogeneration	1,007	1,150	8,531	4,382
Solar energy	490	213	1,304	728
Total reportable segments	9,640	4,827	26,727	17,037
Other	16	5	36	15
Total	9,657	4,832	26,762	17,052

EBITDA
Wind energy	12,294	10,887	59,417	54,450
Cogeneration	4,824	6,442	23,655	27,089
Solar energy	2,011	1,952	4,558	4,484
Total reportable segments	19,129	19,281	87,629	86,023
Other	(3,465)	(3,387)	(10,633)	(9,722)
Total	15,664	15,894	76,996	76,301
Depreciation, amortisation and impairment losses	10,157	10,218	29,328	29,740
Net finance income and costs	(127)	(368)	156	448
Profit (loss) from associates under the equity method	25	21	(24)	61
Profit before tax	5,404	5,329	47,801	47,071
OPERATING PROFIT
Wind energy	4,275	3,778	36,560	33,598
Cogeneration	3,420	3,849	19,361	19,338
Solar energy	1,713	1,672	3,686	4,045
Total reportable segments	9,408	9,299	59,606	56,980
Other	(3,902)	(3,624)	(11,938)	(10,420)
Total	5,507	5,676	47,669	46,561

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	72,217	83,567	275,718	214,162
Cogeneration	501	665	863	1,423
Solar energy	3,102	2,815	32,007	34,066
Total reportable segments	75,820	87,048	308,588	249,651
Other	1,032	240	2,879	4,139
Total	76,852	87,287	311,467	253,791

€ thousand	30 September 2024	31 December 2023
NON-CURRENT ASSETS
Wind energy	1,199,732	948,412
Cogeneration	91,894	97,747
Solar energy	131,003	96,484
Total reportable segments	1,422,628	1,142,643
Other	17,308	16,165
Total	1,439,936	1,158,808

4. Property, plant and equipment

€ thousand	Land	Buildings	Facilities and structures	Machinery and equipment	Assets under construction	Pre payments	Total
Property, plant and equipment as at 31 December 2023
Cost	63,982	22,299	44,796	747,900	458,834	55,148	1,392,959
Accumulated depreciation	0	(9,788)	(25,439)	(275,527)	0	0	(310,754)
Total property, plant and equipment as at 31 December 2023	63,982	12,511	19,357	472,373	458,834	55,148	1,082,205
Movements in the reporting period
Additions	419	3,129	13,590	76,016	216,174	2,036	311,364
Sales (at carrying amount)	0	0	0	(130)	0	0	(130)
Exchange differences	0	2	5	155	37	2	201
Transfers	0	0	0	15,295	(11)	(15,284)	0
Depreciation and impairment	0	(403)	(1,151)	(27,324)	0	0	(28,878)
Total movements in the reporting period	419	2,728	12,444	64,012	216,200	(13,246)	282,557
Property, plant and equipment as at 30 September 2024
Cost	64,401	25,430	58,391	839,236	675,034	41,902	1,704,394
Accumulated depreciation	0	(10,191)	(26,590)	(302,851)	0	0	(339,632)
Carrying amount as at 30 September 2024	64,401	15,239	31,801	536,385	675,034	41,902	1,364,762

The group has commitments under construction and development contracts, which have not been recognised as liabilities and are accounted for off the statement of the financial position. At 30 September 2024, commitments under the construction contracts amounted to €151,709k (31 December 2023: €368,953k) and commitments under the development contracts amounted to €85,095k (31 December 2023: €17,400k). The timing and amount of payments under the development projects depend on the achievement of certain contractual development milestones and satisfaction of specific conditions.

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 2024, 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 forecast 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 forecast transaction is ultimately recognised in profit or loss. When a forecast 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 hedged its exposure to electricity price volatility with base load swap derivative contracts. Under the given derivatives, the group was the payer of the floating price and the counterparty was the payer of the fixed price. The group applied hedge accounting to these cash flow hedges.

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

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

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

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

The electricity supply period under the EFET agreements began on 1 January 2023. As a result, the contract liability started to decrease.

In the first three quarters of 2024, the balance of the contract liability decreased by €4,008k and was €(14,078)k at 30 September 2024 (30 September 2023: €(19,652)k). Respective changes were also made to the group's cash flow hedge reserve and income statement. The following changes will be made to the group's reserves and income statement in 2024:

€ thousand	Note	Q1 2024	Q2 2024	Q3 2024	Q4 2024	Total
Non-derivative contract liability		(2,012)	(911)	(1,085)	(1,666)	(5,674)
Electricity cash flow hedge reserve	7	1,086	711	679	827	3,303
Gain on derivative financial instruments	9	926	199	406	840	2,371

Interest rate swap transactions

At 30 September 2024, the group had three interest rate swap agreements to hedge the exposure to the interest rate risk of three loans:

An interest rate swap with a notional amount of €66,087k, 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 €45,833, 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 €32,501, 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 at 30 September 2024 the main terms of the interest rate swaps matched the terms of the loans (i.e. their notional amounts, currencies, and maturity, payment and other dates). The forward hedges have a hedge ratio of one to one. To test the hedge effectiveness, the group uses the hypothetical derivative method and compares the changes in the fair values of the interest rate swaps against the changes in the fair values of the loan agreements.

Hedge ineffectiveness can arise from the following sources:

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

At 30 September 2024, the effect of the hedging instruments on the group's statement of financial position was as follows:

€ thousand	Notional amount	Carrying amount (Asset)	Carrying amount (Liability)	Line item in the statement of financial position	Change in fair value*	Hedge ineffectiveness recognised in profit or loss	Amounts transferred from hedge reserve to profit or loss
Interest rate swaps	144,421	5,927	0	Derivative financial	(3,003)	0	(977)
				instruments

* Change compared to 30 June 2024, recognised in other comprehensive income

At 30 September 2024, the effect of the hedged items on the group's statement of financial position was as follows:

			Amounts recognised in hedge
€ thousand	Change in fair value used to	Amounts recognised in hedge	reserve to which hedge accounting is
	measure ineffectiveness	reserve	no longer applied
Floating rate loans	5,927	5,927	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 2024, Enefit Green AS had 264,276,232 registered shares (30 September 2023: 264,276,232 shares). The nominal value of a share is €1.

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

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

	Unit	Q3 2024	Q3 2023	9M 2024	9M 2023
Profit attributable to shareholders of the parent	€ thousand	5,447	5,026	42,834	36,689
Weighted average number of shares	thousand	264,276	264,276	264,276	264,276
Basic earnings per share	€	0.021	0.019	0.16	0.12
Diluted earnings per share	€	0.021	0.019	0.16	0.12

7. Other reserves

€ thousand	30 September 2024	31 December 2023
Other reserves at the beginning of the period, of which:	163,289	165,657
Foreign currency translation reserve	(162)	(762)
Hedge reserve for cash flow hedges for interest rate risk (interest rate swaps)	8,860	14,626
Hedge reserve for cash flow hedges for electricity price risk	(9,628)	(12,426)
Initial fair value of derivative transactions with the parent	(10,781)	(10,781)
Voluntary financing reserve	175,000	175,000

Change in fair value of cash flow hedges, of which:
Hedge reserve for cash flow hedges for interest rate risk	213	(2,221)
Decrease in hedge reserve for cash flow hedges for electricity price risk	2,474	2,798
Reclassification from other comprehensive income, recognised as a change in interest expense	(3,143)	(3,545)
Exchange differences on the translation of foreign operations	125	600

Other reserves at the end of the period, of which:	162,958	163,289
Foreign currency translation reserve	(37)	(162)
Hedge reserve for cash flow hedges for interest rate risk
(interest rate swaps)	5,930	8,860
Hedge reserve for cash flow hedges for electricity price risk	(7,154)	(9,628)
Initial fair value of derivative transactions with the parent	(10,781)	(10,781)
Voluntary financing reserve	175,000	175,000

8. Borrowings at amortised cost

		Non-current borrowings
€ thousand	Interest	Bank loans	Lease liabilities*	Bank loans	Lease liabilities*
Borrowings at amortised cost as at 31 December 2023	3,967	27,414	745	445,174	9,098	486,398
Movements in the reporting period
Monetary movements
Borrowings received	0	57,500	0	222,520	0	280,020
Repayments of borrowings	(21,751)	(72,311)	(564)	0	0	(94,626)
Non-monetary movements
Addition of borrowings	21,928	0	4	0	27	21,959
Transfers	156	46,406	(19)	(46,562)	19	0
Amortisation of borrowing costs	0	0	0	30	0	30
Effect of movements in foreign exchange rates	2	18	0	74	0	94
Other movements	0	0	0	0	172	172
Total movements in the reporting period	335	31,613	(579)	176,062	218	207,649
Borrowings at amortised cost as at 30 September 2024	4,302	59,027	166	621,236	9,316	694,047

* Repayments of lease liabilities of €564k consist of principal repayments of €383k and interest payments of €181k.

9. Revenue

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023
Revenue by activity
Sale of goods
Pellets	0	4,209	0	22,806
Scrap metal	94	137	324	592
Other goods	12	14	71	40
Total sale of goods	106	4,360	395	23,438

Sale of services
Heat	1,472	1,008	5,030	5,931
Electricity	28,408	30,500	106,679	103,784
Waste reception and resale	3,292	3,596	10,970	12,048
Lease and maintenance of assets	209	77	459	614
Other services	346	119	367	296
Total sale of services	33,727	35,300	123,505	122,673
Total revenue	33,833	39,660	123,900	146,111

Note: From December 2023, the gains arising on electricity derivatives are recognised in the same line item as revenue from the sale of electricity. In connection with this, the amounts for line item 'Electricity' for Q3 2023 and 9M 2023 in the table above have been increased by €401k and €1,511k, respectively.

10. Renewable energy support and other operating income

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023
Renewable energy support	4,271	4,227	15,643	15,850
Government grants	49	135	197	370
Gain on sale of a business	0	0	4,958	0
Other income	5,336	470	5,964	831
Total renewable energy support and other operating income	9,656	4,832	26,762	17,051

Note: From December 2023, the gains arising on electricity derivatives are recognised in the same line item as revenue from the sale of electricity. In connection with this, the line item 'Gain on derivative financial instruments' and related amounts of €906k for Q1 2023, €204k for Q2 2023 and €401k for Q3 2023, i.e. €1,511k for 9M 2023 have been removed from the table above.

The sale of the Paide and Valka CHP plants in March 2024 gave rise to a gain of €4,958k. In the Q1 interim report, the amount was erroneously stated at €5,759k. The overstatement of €801k, which resulted from an intragroup loan receivable not written off at the date of sale, was corrected in the Q2 report by reducing line item 'Gain on sale of a business'. It was a non-cash correction, which did not affect the group's cash flows.

11. Raw materials, consumables and services used

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023
Maintenance and repairs	5,151	5,377	12,089	12,512
Technological fuel	96	5,614	1,438	20,344
Electricity	15,161	13,515	38,855	33,707
Services related to ash treatment	355	411	1,321	1,449
Transport services for sale of goods	0	465	0	1,337
Materials and spare parts for production	433	288	1,010	1,060
Transmission services	415	122	997	344
Waste handling	270	116	467	295
Resource charges for natural resources	1	1	3	4
Other raw materials, consumables and services used	69	40	184	128
Environmental pollution charges	534	62	705	206
Total raw materials, consumables and services used	22,485	26,011	57,069	71,386

12. Cash generated from operations

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023
Profit before tax	5,441	5,352	47,838	47,094
Adjustments
Depreciation and impairment of property, plant and equipment	10,124	10,110	29,228	29,414
Amortisation and impairment of intangible assets	33	108	99	326
Amortisation of government grants related to assets	(49)	(135)	(196)	(370)
Interest expense on borrowings	368	132	783	573
Gain on sale of a business	0	0	(4,958)	0
(Profit) loss from associates under the equity method	(25)	(21)	24	(62)
Loss on sale of non-current assets	104	0	104	0
Interest and other finance income	(213)	(127)	(905)	(645)
Other gains and losses on investments	0	(24)	0	(24)
(Gain) loss on other non-cash transactions	(2)	0	11	0
Foreign exchange loss (gain) on loans granted and taken	42	(270)	92	72
Realised gain on derivative financial instruments	(287)	(401)	(1,288)	(1,510)
Adjusted profit before tax	15,537	14,724	70,833	74,867
Net change in current assets related to operating activities
Change in receivables related to operating activities	(311)	(3,030)	2,050	1,456
Change in inventories	186	(4,912)	(2,105)	(4,950)
Net change in other current assets related to operating activities	3,636	(18,580)	27,253	(18,955)
Total net change in current assets related to operating activities	3,138	(26,522)	27,197	(22,449)
Net change in current liabilities related to operating activities
Change in provisions	0	0	(5)	(1)
Change in trade payables	412	19,111	(7156)	22,446
Net change in other current liabilities related to operating activities	4,260	11,664	(1,358)	2,457
Total net change in current liabilities related to operating activities	4,671	30,775	(8,519)	24,902
Cash generated from operations	23,346	18,977	89,511	77,320

13. Transactions and balances with related parties

The parent of Enefit Green AS is Eesti Energia AS. At 30 September 2024, the sole shareholder of Eesti Energia AS was the Republic of Estonia.

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

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

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

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

At 30 September 2024, Enefit Green AS had signed long-term power purchase agreements (PPAs) for the physical supply of electricity of 7,787 GWh with Eesti Energia AS for the supply of electricity in the Lithuanian, Estonian, Finnish and Polish electricity networks in the period October 2024 – December 2033. The contracts are for the supply of both annual and monthly base load energy. The weighted average price of the PPAs for the physical supply of electricity signed with the related party is €68.5/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 positions until 17 August 2021, when an EFET General Agreement Concerning the Delivery and Acceptance of Electricity (EFET General Agreement) was signed and all open derivative contracts were simultaneously terminated. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k due to the change in the electricity price in the period from the trade date to 17 August 2021. The cumulative change in the fair value of the derivative financial instruments of €(12,426)k was recognised through other comprehensive income and the cash flow hedge reserve in equity (see also note 5). At 30 September 2024, the balance of the electricity cash flow hedge reserve was €(7,154)k (see also notes 5 and 7).

€ thousand	Q3 2024	Q3 2023	9M 2024	9M 2023		30 September 2024	31 December 2023
TRANSACTIONS					BALANCES
PARENT
Purchase of services	4,702	5,057	14,680	12,471	Receivables	7,213	9,497
Sale of goods	0	0	0	0	Payables	15,703	20,281
Sale of services	15,668	15,418	56,419	54,986	Of which non-derivative contract liability	14,156	18,086
OTHER GROUP COMPANIES
Purchase of goods	0	0	0	0	Receivables	579	314
Purchase of services	159	912	446	2,473	Payables	103	62
Sale of goods	0	0	0	0
Sale of services	1,529	2,087	3,272	2,829
OTHER RELATED PARTIES (INCL. ASSOCIATES)
Purchase of services	502	577	1,362	1,461	Receivables	0	22
Sale of services	0	0	0	0	Payables	452	311
ELERING AS
Purchase of services	(1,943)	65	(1,461)	20,124	Receivables	2,630	5,629
Sale of services	4,029	4,261	15,083	16,016	Payables	136	33

AI Terminal

Enefit Green

2216_10-q_2024-10-31_ae126466-d29a-4afe-86a6-8a6f49b1a23d.pdf

Q3 2024

Contents

Letter from the management board

Dear reader

Development of generation capacity in 2023–2026

Projects under construction

Near-term development portfolio

Full overview of development portfolio

Contribution of new assets* to power generation is increasing

Q3 2024 key highlights

12 GWh

9 months 2024 key highlights

360 MW Co-development agreement with RES Global Investment for early- stage onshore wind projects

Focus on completing major construction projects

Operating environment

Key factors influencing the operating environment

Electricity market

Wind conditions

Renewable energy discounts

Regulatory environment

Estonia

Latvia

Lithuania

Significant events

Loan agreement with EBRD

Extension of Innar Kaasik's mandate as a management board member

Expiry of Veiko Räim's mandate as a management board member

Settlement of the Akmenė incident with GE Vernova

Total installed production capacity reaches 1,000 MW

Cooperation agreement with the City of Pärnu and Sunly

Exploring financing alternatives for further development of Enefit Green

Financial results

Production and sales volumes

Operating income

Average quarterly electricity prices

Raw materials, consumables and services used

Payroll expenses

EBITDA and fixed costs

Depreciation, amortisation and impairment (D&A)

Net finance costs

Income tax

Other operating expenses

Financial results by segments

Group's EBITDA breakdown and change, €m

Operating income by segment, €m

Wind energy

Availability and production

Electricity prices

Operating income

Operating expenses

EBITDA

Operating expenses per MW

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

Cogeneration

Electricity production and prices

Heat production and prices

Operating income

Operating expenses

Solar energy

Electricity production and prices

Operating income

Operating expenses

EBITDA

Investment

Update of investment criteria

Financing

Loan covenants

Financing and return ratios

Risk management

Price risk of electricity sales

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

Long-term PPAs

National support measures

Electricity price forecasts for Enefit Green's core markets

Condensed consolidated interim income statement

Condensed consolidated statement of comprehensive income

Condensed consolidated interim statement of financial position

**Contribution of new assets* to power generation is increasing**