Q2 2024

Unaudited interim report

Acting chairman's letter	3
Development of generation capacity in 2023–2026	5
Projects under construction	6
Near-term development portfolio	7
Full overview of development portfolio	8
Q2 2024 key highlights	10
H1 2024 key highlights	11
Operating environment	12
Regulatory environment	14
Significant events	16
Financial results	17
Financial results by segments	20
Wind energy	21
Cogeneration	23
Solar energy	25
Investment	26
Financing	27
Risk management	29
Unaudited condensed consolidated interim financial statements Q2 2024	31
Notes to the condensed consolidated interim financial statements	37
Group structure	48

Acting chairman's letter

Dear reader

During the second quarter, our activities in the energy and financial markets and our project execution have been affected by geopolitical and economic developments in the sector and the wider market. However, our team continues to work relentlessly to provide stability to investors and to achieve our stated goals during these challenging times.

In accordance with the mutual agreement struck between the Supervisory Board the CEO, Aavo Kärmas stepped down from his role as a company's CEO effective from the 1st of July and the supervisory board appointed Juhan Aguraiuja as the new CEO and the chairman of the management board with effect from 14 October and myself as the acting CEO and the Chairman of the Management Board in the interim period. The remaining continuing members of the Management Board are Veiko Räim, our CFO, and Innar Kaasik, who is responsible for production and asset management.

The Management Board's aim is to manage the company with determination and discipline in order to ensure its stable operation, regardless of changes in leadership and the external environment. We will continue to focus on completing the wind and solar farms under construction on time and on budget, while maintaining the high availability of our existing generation assets. We are also working on development and rolling – out of new storage and hydrogen technologies to prepare for a future where the share of conventional generation is in decline and the use of renewables will increase.

In Q2, we produced 358 GWh of electricity (+35% compared to Q2 2023) and 96 GWh of thermal energy (-32%). The significant increase in electricity production for several quarters in a row is due to the generation from wind and solar farms completed since the beginning of 2023 and the commissioning energy from those still under construction. The year-on-year decline in thermal energy production is due to the sale of biomass CHP plants and unplanned outages for repairs at the Iru power plant.

In the last year and a half, eight new renewable energy projects have started generating electricity, of which five have been completed and three are in the final stages of construction. In addition, several renewable energy projects are under construction, including three large wind farms in Estonia and Lithuania with a total capacity of 422 MW.

At the Sopi-Tootsi wind farm, 25 of the 38 wind turbines have been erected since the beginning of Q2 2024 and installation of the remaining turbines is on track. At the adjacent 74 MW solar farm, the construction of the foundation frames is nearing completion and panel installation is underway. In Lithuania, all 14 wind turbines at the Kelmė I wind farm have been erected and the turbine foundations at the Kelmė II wind farm are under construction. The construction of Enefit Green's first solar farms in Latvia is also underway. All of these projects, with the exception of

Kelmė II, are expected to start generating electricity this year. When completed, they will add around 1.4 TWh of competitive renewable energy to the region's electricity supply.

Combining various forms of energy production (i.e. solar and wind) with various forms and duration of storage are essential for the sustainability of the energy system long-term. That is why Enefit Green is actively working on the development of the projects that contain a mix of hybrid generation, battery storage and generation, and hydrogen technologies. The Purtse hybrid wind and solar farm is one such example and is the first of its kind in the Baltics that successfully passed the transmission system operator's grid compliance tests in Q2 and received a corresponding certificate. Work on a battery storage pilot project is already underway at the Purtse hybrid farm. The battery storage system, which is expected to be operational in 2025, will balance wind and solar power generation and make the project more dispatchable.

In addition to battery storage, we are also working on a pilot project for a green hydrogen production. We have teamed up with Alexela and GoBus to produce green hydrogen for the use in public transport and light vehicles around Estonia. The goal is to produce 70-140 tonnes of green hydrogen per year, which should reduce annual greenhouse gas emissions from vehicles by 1,200 tonnes. If all goes according to the plan, the hydrogen production facility will be ready for operation in early 2026. The construction of the innovative project is co-funded by the Estonian Environmental Investment Centre with support from the European Union's NextGenerationEU Recovery and Resilience Facility.

We want to make the investment decisions in the pilot scale battery storage and green hydrogen facilities in the near future to allow for your company to learn more about the use of these technologies and be ready for the deployment of these technologies on a commercial scale. The development of such hydrogen and storage technologies globally continues to facilitate a rapid decline in their price of deployment, expecting to make them commercially viable in a mediumterm.

The completion of new renewable energy capacities will increase the production of green electricity, but it also means that we need to be ready to respond to possible incidents and accidents at such facilities. During the quarter, , we organised an exercise at one of our facilities together with the Estonian Wind Power Association, the Estonian Rescue Board and other interested parties to practise how to respond to an incident in a wind turbine nacelle and how to bring the affected personnel safely to the ground.

One solution to meet growing energy demand and offer energy security of supply is to build an offshore wind farm, which will require significant equity and debt investment over several decades. The Estonian Ministry of Climate is developing a reverse auction plan for offshore wind farms, which is a welcome step and shows that the state of Estonia is serious about the future

energy security of Estonia and the Baltic region overall. Enefit Green is actively participating in the discussions and will continue to work on the predevelopment of the Liivi Bay (Gulf of Riga) offshore wind farm with a view to participating in the upcoming reverse auction.

At the end of June, we amended the €50m loan agreement signed with Swedbank in December 2022. Under the amended terms, the loan amount was increased to €100m and the maturity of the loan was extended to December 2028. We will use the additional loan to invest in wind farms, solar farms and storage solutions.

Although the importance of new assets in our generation portfolio has gradually increased, electricity production in the first half of the year was below target. This is mainly due to lower than expected wind speeds, lower availability of the new generation assets during the commissioning period (particularly at Tolpanvaara) and the return to operation of the replaced turbine at the Akmenė wind farm. As a result, we have revised our power generation forecasts for the year slightly downwards and expect production to be just over 2 TWh.

Enefit Green ended Q2 with operating income of €38.3m (-7%), EBITDA of €18.9m (-2%) and net profit of €3.9m (+246%). Operating income and EBITDA were affected by the lower electricity prices and lower than expected wind speeds. Prices for long-term power purchase agreements (PPAs) were also lower than in a corresponding period last year, due to operational start of the new projects that had a lower underlying PPA rates. Due to the lower than expected power production, we continued to purchase electricity to meet our supply obligations under long-term PPAs.

Your management team will continue to focus on completing construction projects safely, on time and within budget, while ensuring the availability of our operating assets and progressing the current portfolio of development projects. We will also continue to develop storage and hydrogen technologies.

Andres Maasing Acting CEO and Chairman of the Management Board

Development of generation capacity in 2023–2026

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 and conditions.

** Also known as the Hiiumaa offshore wind farm

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

600

The objective of Enefit Green has been to supply renewable energy in a sufficient quantity to meet corresponding demand by responding to market signals and changes in regulation.

Our current investment programme to build new generation capacity was launched in 2021, before the listing of Enefit Green's shares on the stock exchange. It takes time to build new generation capacity: at least one year from taking the final investment decision to the 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 gradually been completed and have started generating electricity over the past year and a half (since the beginning of 2023). The output of these assets and their increasing contribution to our quarterly electricity generation is shown in the chart on the right. This chart also illustrates the intra-annual volatility of our generation profile. As we are wind energy focused producer, our second and third quarter production volumes tend to be quite a bit lower than those in first and fourth quarter.

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

Wind or solar farm	Country	Wind/ solar	Status	Capacity (MW)	Start of generation**
Šilale 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	Under construction	6	February 2024
			Total	218

** 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.

Production volume, older assets Production volume, new assets*

* 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 in 2021.

Q2 2024 key highlights

Focus on completing major construction projects

Strong progress in the construction of the Sopi-Tootsi and Kelmė I wind farms and the Sopi solar farm

€100m

Extension of a loan agreement and increase in the loan amount (previously €50m)

* 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

H1 2024 key highlights

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

Focus on completing major construction projects

Strong progress in the construction of the Sopi-Tootsi, Kelmė I, Tolpanvaara wind farms and the Sopi solar farm

* Assets completed in 2023 or later

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 the group's development projects also include market competition, the development and cost of renewable energy technologies, customers' willingness to enter into long-term green power purchase agreements (PPAs) and renewable energy support schemes.

Most of Enefit Green's 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 the expected electricity generation in the coming years is provided at the end of the management report.

Electricity market

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

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

In Q2, the decline in electricity prices in our largest markets slowed compared to the same period last year. In Estonia, the average quarterly electricity price even rose by 2.1%, and the price gap with Latvia and Lithuania narrowed to zero. This was largely due to the long-term outage of the EstLink2 interconnector between Estonia and Finland, which has prevented sufficient supplies of mostly cheaper Finnish electricity from reaching the Baltic markets since the end of January. Q2 wind conditions in our markets were below the long-term averages, which hampered wind power supply, and several nuclear power plants in the region, including in Finland, have been under maintenance since May, which has also pushed up electricity prices.

During peak hours, the electricity price in the region is typically determined by gas-fired power plants. Although natural gas prices have decreased year on year, electricity prices during peak hours in Q2 2024 were higher than in the same period last year due to weather conditions.

The average price of natural gas on the Dutch gas trading platform TTF was €29.2/MWh in Q2 2024 (€3.7/MWh, 11.3% lower than in Q2 2023). The price has decreased mainly due to the absence of LNG production and supply issues. Lower demand – natural gas demand in the EU has fallen by a fifth compared to 2021 – and higher LNG supply have kept natural gas prices low. European gasstorage was at 80% at the end of Q2 and is expected to reach 89% of the maximum by the end of July.

Interconnectors supply the Baltic countries with Nordic hydropower, which is cheaper than other types of electricity. The average level of hydro resources in the Nordic hydropower reservoirs in Q2 2024 was 43.1% of the maximum, which is 3.3 percentage points higher than in Q2 2023.

As the volume of snow and surface water accumulated in the reservoirs by the end of Q2 was 3.9 TWh higher than a year earlier, hydropower production is expected to increase year on year in the coming quarters, which could lower regional electricity prices.

The average CO² emission allowance price stabilised in Q2 2024, reaching €69.5/t at the end of the quarter, which is 21.5% (€19.0/t) lower than at the same time last year.

Average electricity price (€/MWh)	Q2 2024	Q2 2023	Change
Estonia	76.0	74.4	2.1%
Latvia	75.9	80.8	(6.1)%
Lithuania	75.9	81.3	(6.6)%
Poland	88.6	112.9	(21.5)%
Finland	40.0	43.3	(7.7)%
Norway	36.4	54.9	(33.6)%
Denmark	61.1	83.8	(27.1)%
Sweden	33.7	51.0	(33.9)%

Wind conditions

Due to seasonal factors, wind conditions in Q2 and Q3 are less favourable for wind power production in our region than the rest of the year. In Q2 2024, the average measured wind speeds in Enefit Green's wind farms in Estonia and Lithuania were 5.4 m/s and 5.9 m/s respectively (Q2 2023: 5.2 m/s and 5.4 m/s). While wind speeds were higher than last year, which had a positive impact, they were 0.4 m/s lower than expected in both Estonia and Lithuania. The chart below provides an overview of the average quarterly wind speeds in Estonia and Lithuania since the beginning of 2022.

In connection with the completion of the Tolpanvaara wind farm, Enefit Green's future performance indicators will also be influenced by wind conditions in Finland. In Q2 this year, the average measured wind speed at the Tolpanvaara wind farm was 6.3 m/s (no data for the comparative period), which is 0.5 m/s lower than expected.*

* In the original release of the June and Q2 production data to the stock exchange, the average Q2 wind speed in Finland (Tolpanvaara) was erroneously understated at 5.7 m/s. However, the Q2 production results at Tolpanvaara were affected less by the wind conditions than by warranty improvements (anti-icing systems for wind turbine blades), which will continue until the end of the summer.

Regulatory environment

European Union

Elections for the European Parliament took place in early June. The Greens were the clear losers in the elections, but the current coalition of the big political groups of the European People's Party (EPP), the Socialists and Democrats (S&D) and Renew Europe will probably continue. It is unlikely that the package of green policies adopted during the previous legislature will be reversed, and existing policies on electricity generation and consumption are likely to remain unchanged.

The process of changing the EU's electricity market rules, which took nearly a year and a half, came to an end with the adoption of a Directive (2024/1711) and a Regulation (2024/1747). The changes aim to create a market environment with more stable prices. This is another milestone in the development of the electricity market, but its real impact will become clear in the future: the first part of the Directive is transposed by the member states in January 2025 and a more complex part of the changes (the simultaneous use of multiple electricity consumption contracts and the right to share electricity) in mid-2026. For example, the obligation to use twoway contracts for difference will enter into force in July 2027 for onshore power generation facilities and in July 2029 for offshore wind farms.

In Estonia, Latvia and Lithuania, investments in electricity generation and storage will face greater uncertainty for the next 3 to 8 years. The Regulation gives the transmission system operators (TSOs) in the Baltic countries the right to compete with electricity producers for system services. It also allows the Baltic TSOs to allocate less than 70% of the transnational transmission capacities to the electricity market for up to 8 years after decoupling from the Russian electricity system.

The Directive gives Estonia, Latvia and Lithuania the right to allow their TSOs and their affiliates to own, develop, manage and operate energy storage facilities without an open, transparent and non-discriminatory tendering procedure and to allow such energy storage facilities to buy or sell electricity in the market. This exceptional right can be applied for up to 3 years after separation from the Russian electricity system (and can be extended for a further 5 years).

Estonia

Following the European Parliament elections, the Reform Party started negotiations with the current coalition partners to form a new government. As a result, the publication of the draft Climate Act has been delayed and the updated National Energy and Climate Plan was not submitted to the European Commission by the early July deadline. Legislative proceedings for draft laws have been postponed as it is normal practice to withdraw pending draft laws when there is a change of government.

In Q2, the Accelerated Deployment of Renewable Energy Act was adopted, which introduced a superficies licence for offshore wind farms, thereby changing the rights of persons that had previously developed offshore wind farms. An amendment to the Electricity Market Act was adopted, suspending the payment of renewable electricity and efficient cogeneration support for electricity produced from waste at Enefit Green's Iru power plant in the first half of 2025 (estimated impact on operating income and EBITDA is -€2.8m). If Estonia meets its municipal waste recycling target in 2025, the suspended support will be paid out at the end of 2026. This is the first time in Estonia that the state has not fulfilled its obligation to pay the promised support to a renewable energy producer for a period of 12 years. It reduces the credibility of any future support for renewable energy producers in Estonia by setting a precedent of country risk for all national support schemes that investors either already rely on or may rely on in the future.

Work continued on draft legislation on waste reform, which will affect the production of electricity and heat from waste from 2025. Preparatory work also started on draft laws on reverse auctions for renewable electricity, electricity storage, the introduction of the principle of proactive development of the transmission network and changes to the regulation of district heating, which are expected to enter into force in 2025.

The Baltic TSOs confirmed that the Baltic power systems will leave the Russian synchronous area in February 2025 and join the Continental Europe Synchronous Area. As the Baltic countries will have to maintain their electricity systems within the prescribed parameters from the moment of desynchronisation, this will inevitably entail the hitherto non-existent costs of acquiring frequency reserves. In April, the Competition Authority approved the methodology for allocating the costs of frequency reserves between electricity consumers and producers. In March, the Estonian TSO, Elering AS, estimated the additional cost of frequency reserves for generators to be around €2/MWh, but by June the estimate had risen to €5.31/MWh. Enefit Green considers this additional regulatory cost for electricity producers in Estonia to be too high and believes it would affect negatively the construction of new renewable electricity projects in Estonia.

On 15 July, Elering AS launched a call for tenders for the procurement of 500 MW of electricity generation and storage capacity for frequency control until 203.

On 12 June, the Estonian parliament adopted a decision on supporting the introduction of nuclear energy in Estonia, including preparations for the implementation of nuclear energy in Estonia and the creation of an appropriate legal framework to ensure the security of energy supply during the transition to climate-neutral energy production.

Latvia

A regulation on the compensation (toleration fees) to be paid for the benefit of the communities around wind farms was drafted in cooperation with market participants and local authorities. This is an important development and market participants look forward to its entry into force in the near future.

Preparations continued for the amendment of the Electricity Market Law in the area of network services. New regulatory solutions include the possibility of 'flexible' connection of power plants to the grid, so that the producer does not have a guarantee of continuous supply of electricity to the grid. Existing power plants will be allowed to add a second electricity generation technology. According to plan, until 31 August 2025 it will only be possible to connect to the electricity transmission system using the new 'flexible' grid service and to install a second generation unit using an existing power plant connection.

In order to speed up the use of the right to connect to the grid, it is planned to allow the right to be transferred to another person without losing the deposit paid for the connection.

Lithuania

Amendments to the conditions for connection to the system operator's grid entered into force, clarifying, among other things, the rules for the connection of power plants to be built in several phases and hybrid farms with multiple generation and storage technologies.

The Lithuanian parliament adopted the revised National Energy Independence Strategy, which focuses on the production of electricity from renewable energy sources and the production of hydrogen derivatives, i.e. green synthetic fuels, methanol, ammonia, synthetic methane, etc., from it. The strategy calls for the creation of conditions for competition in the production and storage of renewable electricity and other energy sources in order to maximise their use in Lithuania. The strategy foresees a more than sixfold increase in Lithuania's electricity consumption from 12 TWh today to 74 TWh by 2050.

Poland

Amendments to the regulation on balancing responsibility were adopted and entered into force on 14 June. The reform aims to strengthen market mechanisms so that the pricing of balancing energy would incentivise market participants to adjust production and consumption to market conditions. The balancing responsibility period was also shortened from one hour to fifteen minutes.

Amendments to the Energy Law Act created the Energy Market Information Operator (Operator Informacji Rynku Energii), an institution separate from the TSO, whose task is to collect comprehensive information from the energy market.

Finland

On 12 April, the Finnish Ministry of Economic Affairs and Employment set up a working group to prepare the changes needed for the addition of wind power and industrial electricity consumers. This was done to ensure that a point in the coalition agreement of the current Finnish government, despite its unfortunate wording, is implemented in a sensible manner. It will analyse the relevance of the division of responsibilities between network operators, the adequacy of the development obligation, and the need for regulation on direct power lines.

Significant events

Changes in the management board

In connection with the expiry of the term of office of the chairman of the management board, Aavo Kärmas, on 1 July, the supervisory board of Enefit Green appointed Juhan Aguraiuja as the new chairman of the management board with effect from 14 October.

Until the new chairman of the management board takes office, the supervisory board has appointed Andres Maasing, a member of the management board and head of development, as acting chairman.

Enefit Green has also started the search for a new member of the management board and CFO, as Veiko Räim, who has held this position since 2017, has decided not to apply for an extension of his contract when the current one expires on 24 September 2024.

Enefit Green's management board will have three members on an interim basis. In addition to Andres Maasing and Veiko Räim, the board includes Innar Kaasik, who is responsible for production and asset management.

Purtse hybrid farm passes Elering compliance tests

The first hybrid wind and solar farm in the Baltic countries has successfully passed Elering's (the operator of the Estonian transmission system) grid compliance tests. The certification of Enefit Green's Purtse hybrid farm is significant as it is the first one of its kind to be certified.

Purtse is the first hybrid wind and solar farm in the Baltics where both energy sources use the same connection point. The unique connection solution is important for both cost optimisation and efficient use of grid resources. The hybrid farm uses the same equipment, grid connection and substation to feed electricity into the grid, which makes it both economically and environmentally viable.

Rescue exercise at Paldiski wind farm

Enefit Green, together with the Estonian Wind Power Association, the Estonian Rescue Board and other partners, organised an exercise to practise how to deal with a wind turbine accident. This is the second time that such a large-scale exercise has taken place in Estonia.

Accidents involving wind turbines are rare, but their resolution requires effective preparation and cooperation. The aim of the exercise was to train rescuers to enter a wind turbine, ascend to the gondola at the top of the tower and bring down a disabled technician from a height of 85 metres.

Progress on major wind and solar farms under construction

At the Sopi-Tootsi wind farm, 20 of the 38 wind turbines have been erected and the installation of the remaining turbines is progressing rapidly. At the 74 MW solar farm next to the wind farm, the installation of the foundation frames is in the final stages and panel installation is underway. In Lithuania, all 14 wind turbines at the Kelmė I wind farm have been erected and the foundations for Kelmė II are under construction.

Amendment to loan agreement with Swedbank

At the end of June, Enefit Green signed an amendment to a €50m loan agreement signed with Swedbank in December 2022. Under the amended terms, the loan amount has been increased to €100 million and the maturity has been extended to December 2028. The additional loan amount will mainly be used for the construction of wind and solar farms and storage solutions, as well as for general financing needs.

Financial results

The Enefit Green group's operating income for Q2 2024 decreased by 7% while operating expenses (excl. D&A) decreased by 12% compared to the same period last year. As a result, EBITDA decreased by 2% to €19.3m. Net profit for the quarter increased by €2.8m to €3.9m. The key factors that influenced the group's financial performance are described below.

The comparison of the group's Q2 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 Q2 2023 include operating income of €4.7m, operating expenses of €5.1m and effects on EBITDA of €0.8m related to the above assets, which were sold by the end of Q1 2024. The results for Q2 2024 include a correction of the gain recognised on the sale of the Paide and Valka CHP plants, which reduced the group's EBITDA for Q2 2024 by €0.8m. The sale of the Paide and Valka CHP plants in March 2024 gave rise to a gain of €5.0m. In the Q1 report, the amount was erroneously stated at €5.8m. The overstatement, which resulted from an intragroup receivable not written off at the date of sale, has been corrected in this report by reducing other operating income by €0.8m. It was a non-cash correction, which did not affect the group's cash flows.

Production and sales volumes

GWh	Q2 2024	Q2 2023	Change	Change, %
Electricity production (net)	358	265	93	35%
Of which by new wind and solar farms	141	56	85	152%
Of which by assets sold	-	9	(9)	(100)%
Electricity sales*	460	357	103	29%
Heat production	96	141	(45)	(32)%

The group's Q2 electricity production grew by 93 GWh (35%) to 358 GWh, with the output of new wind and solar farms under construction increasing by 85 GWh. Assets sold had a negative impact, reducing Q2 electricity production by 9 GWh compared to Q2 2023.

Operating income

Total operating income decreased by €2.9m, the figure reflecting a decrease in revenue of €2.9m, an increase in renewable energy support of €0.6m and a decrease in other operating income of €0.8m. The effect of assets sold on operating income was positive at €4.7m in Q2 2023 and negative at €0.8m in Q2 2024.

Excluding the impact of assets sold, i.e. operating income from continuing operations, was €36.5m for Q2 2023 and €39.1m for Q2 2024 (operating income grew by €2.5m, the figure reflecting revenue growth of €1.7m and an increase in other operating income of €0.8m).

Of the €1.7m growth in revenue from continuing operations, €2.1m resulted from electricity sales revenue that was driven by higher production. In Q2 2024, the average electricity price** in the group's core markets was €72.2/MWh (Q2 2023: €78.7/MWh). The group's average implied captured electricity price*** was €69.7/MWh (Q2 2023: €89.3/MWh). The implied captured electricity price differs from the average market price in the group's core markets, because it takes into account long-term fixed-price power purchase agreements (PPAs), renewable energy support, purchases of balancing energy, electricity purchases from the Nord Pool day-ahead and intraday markets and the fact that wind farms do not produce the same amount of electricity every hour.

The group's average price of electricity sold to the market in Q2 2024 was €52.3/MWh (Q2 2023: €63.7/MWh). The group sold 214 GWh of electricity to the market in Q2 2024 compared with 139 GWh a year earlier.

€m	Q2 2024	Q2 2023	Change	Change, %
TOTAL OPERATING INCOME	38.3	41.2	(2.9)	(7)%
Revenue	33.9	36.8	(2.9)	(8)%
Renewable energy support	4.4	4.4	0.0	(1)%
and other operating income
TOTAL OPERATING EXPENSES (excl. D&A)	19.3	21.9	(2.5)	(12)%
Raw materials, consumables and services used (excl. electricity)	5.0	11.9	(6.8)	(57)%
Electricity purchase costs	8.9	8.7	0.1	2%
Payroll expenses	2.4	2.9	(0.5)	(19)%
Other operating expenses	3.1	3.3	(0.2)	(6)%
Change in inventories	0.0	(4.9)	4.9	(100)%
EBITDA	18.9	19.3	(0.4)	(2)%
Depreciation, amortisation and impairment (D&A)	9.8	9.7	0.1	1%
OPERATING PROFIT	9.1	9.6	(0.5)	(5)%
Net finance income and costs	0.0	0.8	(0.8)	(97)%
Income tax	5.1	9.3	(4.1)	(45)%
NET PROFIT	3.9	1.1	2.8	246%
TOTAL OPERATING EXPENSES (excl. D&A)	19.3	21.9	(2.5)	(12)%
Variable costs (incl. balancing energy purchases)	10.4	16.4	(6.1)	(37)%
Fixed costs	9.0	10.3	(1.4)	(13)%
Change in inventories	0.0	(4.9)	4.9	(100)%

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

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

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

In Q2 2024, 246 GWh of the group's electricity production was covered by PPAs at an average price of €68.0/MWh. A year earlier, 218 GWh of electricity was sold under PPAs at an average price of €83.5/MWh. The average price of electricity sold under PPAs has decreased significantly year on year because the settlement periods of PPAs signed in Lithuania and Finland in 2021 at lower prices began in Q1 2024. The share and prices of production covered by PPAs in future periods are disclosed in the risk management chapter.

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

Average quarterly electricity prices

	Q2 2023	Q3 2023	Q4 2023	Q1 2024	Q2 2024
Price of electricity sold to the market	63.7	82.2	64.1	77.6	52.3
PPA price	83.5	80.9	91.2	75.0	68.0
Realised purchase price	83.8	116.5	121.5	106.1	80.4
Core markets' average electricity price	78.7	97.8	93.1	87.0	72.2
Implied captured electricity price	89.3	84.9	80.9	81.4	69.7

In Q2 2024, we purchased 108 GWh of electricity from the market at an average price of €80.4/MWh, compared with 97 GWh at an average price of €83.8/MWh in Q2 2023 (the prices and volumes exclude the electricity purchased for pellet production in Q2 2023). The volume of electricity purchased increased slightly as sales under PPAs have increased, but as the share of production covered by PPAs has decreased, the ratio of electricity purchased to electricity produced decreased year on year. The purchase price decreased compared to Q2 2023, because the market price has declined, but due to a higher wind profile discount the gap between the purchase price and the sales price increased.

Renewable energy support and other operating income (excl. the effect of assets sold) increased by €0.8m compared to the same period last year. Renewable energy support increased by €0.7m. The amount of renewable energy support received is based on the quantity of energy produced by wind farms eligible for support. The eligibility period of the Purtse wind farm began in Q2 2024, which increased the amount of support received by €0.2m. The output of other wind farms eligible for support was 6.4 GWh higher than in Q2 2023.

Raw materials, consumables and services used

Expenses on raw materials, consumables and services decreased by €6.8m (57%). The largest changes were in technological fuel and transmission service costs. Technological fuel costs decreased by €6.2m due assets sold and transmission service costs grew by €0.3m due to an increase in the transmission service costs of the Iru cogeneration plant and the wind farms.

Payroll expenses

The group's payroll expenses decreased by 19% year on year. At the reporting date, the group had 129 employees compared with 202 at the end of Q2 2023.

Payroll expenses for Q2 2023 include expenses of €1.2m attributable to assets sold. At the end of Q2 2023, the number of employees attributable to assets sold was 77.

Excluding the impact of assets sold, payroll expenses increased by 15% compared to the same period last year. We had 129 employees in Q2 2024 and 125 (excl. the employees attributable to assets sold) in Q2 2023. New people have mostly been hired to the development team to support projects under construction and development in all markets. At the end of Q2 2024, the development team had 38 employees compared with 34 a year earlier.

Other operating expenses

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

EBITDA and fixed costs

The factor with the strongest impact on EBITDA development was the price of electricity sold, which decreased compared to Q2 2023 (negative impact: €5.4m). Due to PPAs, the quantity of electricity sold grew significantly (positive impact: €8.2m), which also increased the volume of electricity purchased to balance the electricity portfolio (negative impact: €0.8m).

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 35% year on year.

The total impact of assets sold on EBITDA development was negative at €1.6m. The figure consists of a positive impact on Q2 2023 of €0.8m and a negative impact on Q2 2024 of €0.8m. The latter results from the correction of the gain on the sale of the Paide and Valga CHP plants recognised in April. For further information, see the first section of the financial results chapter.

Excluding the effects of the electricity price and volume, the Iru cogeneration plant had a negative impact on EBITDA. The calculation takes into account the effects of heat, gate fees for waste received and technological fuel. The EBITDA of the Iru cogeneration plant excluding the effects of the electricity price and volume decreased by €0.3m to €4.2m. This was mainly due to lower energy production resulting from lower availability, which was partly offset by a rise in the price cap for heat. See the cogeneration chapter for further details.

Fixed costs are costs that are not directly dependent on the production volume. Fixed costs excluding the fixed costs of assets sold grew by €0.1m.

19.3 (5.6) 18.9 +8.2 (0.8) +0.2 (1.6) (0.3) (0.4) EBITDA 2023 Q2 Sold electricity price impact Sold electricity quantity impact Purchased electricity quantity impact Purchased electricity price impact Sold assets Iru (excl. Fixed costs Volume and price of electricity) Other EBITDA 2024 Q2 EBITDA -0.4 (-2.0%) Impacted by electricity production

Depreciation, amortisation and impairment (D&A)

D&A expense increased by €0.1m (1%). Assets sold lowered D&A expense compared to a year earlier by €1.2m. D&A expense excluding the effect of assets sold increased by €1.3m (15%). Non-current assets recognised after Q2 2023 include the Purtse wind farm (D&A for Q2 2024: €0.2m) and the Purtse solar farm (D&A for Q2 2024: €0.1m) in Estonia, the Zambrow solar farm (D&A for Q2 2024: €0.1m) in Poland and the Tolpanvaara wind farm (D&A for May–June 2024: €0.5m) in Finland.

Net finance income

Net finance income decreased by €0.8m compared to the same period last year. Interest expense on bank loans increased by €3.5m, but 99% 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 negative impact on net finance income (-€0.7m).

Income tax

Income tax expense decreased by €4.1m compared to Q2 2023 due to a lower dividend distribution, which reduced the income tax payable on dividends.

Group's EBITDA change by drivers, €m

Financial results by segments

Based on total operating income and EBITDA, the group's largest segment is Wind energy, which accounted for 70% of operating income and 80% of EBITDA for Q2 2024. The Cogeneration segment contributed 22% to operating income and 28% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 8% the group's operating income and 11% of the group's EBITDA for Q2 2024.

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

The EBITDA of the segment Other mainly includes general administrative expenses, the payroll expenses for employees involved in the Wind energy and Solar energy segments, and the costs of development projects without an investment decision. The segment also includes the Keila-Joa hydroelectric facility and the renewable energy solution on the island of Ruhnu. The loss of the segment Other increased by €0.3m.

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 interim report for Q1 2024, the expenses for the wind energy development teams, wind farm developments without an investment decision and offshore wind farm

developments are included in the segment Other and not in the

Wind energy segment (the figures for the comparative period have been adjusted accordingly).

Availability and production

The group's total wind power production in Q2 2024 was 295.5 GWh, 104.1 GWh higher than in Q2 2023 due to new wind farms coming online. The contribution of new wind farms and wind farms under construction was 120.8 GWh (+80.9 GWh compared to Q2 2023).

Wind power production in Q2 was negatively affected by wind conditions – the average wind speeds in Estonia and Lithuania were lower than expected, which reduced the production volume by over 30 GWh. The availability of the group's operating Estonian and Lithuanian wind farms, which was 96.2% and 95.5%, respectively (Q2 2023: 97.8% and 93.6%, respectively), more or less met expectations. Older wind farms had virtually no availability issues. The availability of new wind farms (farms under construction and completed since 2023) improved significantly in Q2 2024, but was still below target, which reduced output by 7 GWh. The availability issues of the new Lithuanian wind farms have been largely resolved and the farms have shown high availability in recent months. The availability of the Tolpanvaara wind farm in Finland is currently lower than expected as the wind turbine supplier is carrying out warrantyrelated improvements until the end of Q3. Approximately three thirds of the negative impact of the availability of new wind farms on production in Q2 came from the Tolpanvaara wind farm.

Electricity prices

The implied captured electricity price of the Wind energy segment depends on the combination of the market price and PPAs. In Q2 2024, the segment's average implied captured electricity price including support was €64.0/MWh (26% lower than in Q2 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 €12.2/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.

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 Wind energy segment's operating income was positively influenced by higher production due to the addition of new wind farms and the renewable energy support received for the Purtse wind farm from Q2 2024. The combined effect offset the decline in the implied captured electricity price and increased the segment's operating income to €26.8m (12% year on year).

Operating expenses

The Wind energy segment's operating expenses (excl. D&A) increased by €0.4m to €11.6m. This was mainly due to electricity purchases to balance the PPA portfolio in hours of low wind speed. Electricity purchase costs, including balancing energy purchases and purchases to balance the PPA portfolio, grew by €0.8m.

Other operating expenses (excl. electricity purchases, expenses on balancing energy and growth in D&A) decreased by €0.4m year on year. The largest decrease was in the maintenance and repair costs of operating wind farms (€0.4m).

EBITDA

The Wind energy segment's EBITDA for Q2 improved, rising to €15.1m (Q2 2023: €12.7m). EBITDA growth was driven by higher electricity production resulting from the contribution of the Purtse wind farm and wind farms under construction.

+2.9 (+12.0%) +2.3 (+18.1%)

Operating expenses per MW

II kv

I kv

IV kv

III kv

I kv

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 by 12% year on year in Q2 2024. There were some extraordinary costs in Q2 2023. As a result, operating expenses decreased in Q2 2024. Since Q3 2023, operating wind farms have included the Purtse wind farm with an installed capacity of 21 MW.

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

+3.1 (+8.4%)

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

III kv

II kv

I kv

Cogeneration

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

Electricity production and prices

The Cogeneration segment's electricity production in Q1 2024 was 31.0 GWh, 29% lower than a year earlier (Q2 2023: 43.6 GWh). From March 2024, the production figures of the Cogeneration segment consist of the figures of the Iru cogeneration plant because the Brocēni CHP plant was sold at the end of December and the sale of the Paide and Valka CHP plants was finalised at the beginning of March. Electricity production at the Iru cogeneration plant decreased by 3.5 GWh (10%) compared to Q2 2023 due to lower availability, which in Q2 2024 was 87.5%, more than 9 percentage points lower than a year earlier. The main reasons were unplanned outages, including those for the repair of the boiler grate and boiler leaks.

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

The Cogeneration segment's implied captured electricity price increased by 8% year on year to €112.7/MWh in Q2 2024, driven by the increase in the market price in the Nord Pool Estonia price area.

* Due to the sale of the other cogeneration plants, all figures presented are for the Iru power 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

Heat production and prices

Heat production decreased by 32% year on year to 96.3 GWh in Q2 2024. The decline attributable to assets sold was 35.5 GWh. The heat output of the Iru cogeneration plant availability. The average sales price of heat per MWh decreased by 18% year on year to €11.7/MWh. In the comparative period, the price cap for heat produced by the Iru cogeneration plant was €7.98/MWh. From 19 April 2024, the price cap for heat produced by the Iru cogeneration plant from mixed municipal waste is €12.36/MWh instead of the previous €7.98/MWh.

Operating income

The Cogeneration segment's operating income decreased by €5.9m (42%) to €8.3m. Of the decrease, €5.5m was attributable to assets sold.

The Iru cogeneration plant's electricity revenue decreased by €0.1m to €2.9m due to a decline in electricity production, gate fee revenue decreased by €0.2m to €3.6m due to a decrease in

waste received and electricity production support decreased by €0.2m to €1.2m due to lower production, while heat sales revenue increased by €0.3m due to a higher price.

Operating income for Q2 2024 attributable to assets sold includes the negative correction (€0.8) of the gain on the sale of the Paide and Valka CHP plants. The sale of the Paide and Valka CHP plants in March 2024 gave rise to a gain of €5.0m. In the Q1 report, the amount was erroneously stated at €5.8m. The overstatement has been corrected in this report by reducing other operating income by €0.8m.

Operating expenses

The Cogeneration segment's operating expenses (excl. D&A) decreased to €2.9m (Q2 2023: €6.3m). In Q2 last year, the fixed and variable costs of assets sold amounted to €3.9m.

The Q2 operating expenses of the Iru power plant (excl. D&A) increased by €0.5m (19%) year on year to €2.9m. Variable costs increased by €0.2m due to the change in the transmission fee and the addition of the consumption point fee and the capacity fee (€0.1m in total) and growth in other production costs (€0.1m). Fixed costs increased by €0.3m, of which €0.2m resulted from higher maintenance and repair costs incurred in connection with unplanned outages.

EBITDA

The segment's EBITDA for Q2 2024 was €5.4m, €2.4m (31%) lower than in the same period last year.

EBITDA attributable to assets sold decreased by €1.6m. The figure was influenced by the correction of the gain on the sale of the Paide and Valka CHP plants recognised in Q2 0224, which reduced operating income for the period by €0.8m.

The EBITDA of the Iru cogeneration plant decreased by €0.9m to €6.2m. The decline, which was mainly due to lower availability thatreduced energy production and increased 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 interim report for Q1 2024, the expenses for the development of solar projects without an investment decision, the management of solar farms and the costs of 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 31.2 GWh of solar power in Q2 2024, 1.7 GWh (6%) more than in the same period in 2023 due to new solar farms coming online. The Estonia solar farm in Estonia supplied its first electricity in Q4 2023 and the Debnik solar farm in Poland supplied its first electricity in Q1 2024. The availability of solar farms remained high at 99.7% (Q2 2023: 99.8%), but production was affected by cloudier weather in April and generation curtailments – by the network operator in Poland (negative effect on production in Q2: 2.1 GWh) and due to negative prices in Estonia (negative effect: 1.2 GWh).

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 Q2 2024 was €125–134/MWh. The price charged by the new Zambrow solar farm is €63/MWh.

In Q2 2024, the Solar energy segment sold 22.4 GWh of electricity under PPAs at an average price of €74.5/MWh. The segment's implied captured electricity price was €79.8/MWh, which is 6% lower than in Q2 2023. The implied captured electricity price decreased by 23% in Estonia and increased by 19% in Poland. The increase in Poland was due to support received. Without the support, the implied captured electricity price in Poland would also have decreased.

Operating income

The operating income of the Solar energy segment grew by €0.1m. The segment's electricity revenue decreased in both Estonia and Poland due to lower prices. However, due to the support received in Poland, total operating income still increased slightly. The support received in Poland increased by €0.4m compared to Q2 2023. As the market price of electricity was below the fixed price of €125-134/MWh, the lost revenue was paid out as support. Operating income generated in Poland also includes a €0.2m claim for compensation to distribution system operator for curtailment of production.

Operating expenses

The segment's operating expenses (excl. D&A) increased by €0.1m. The increase resulted from the network service charges of the new Zambrow and Purtse solar farms, which were not incurred in the comparative period.

EBITDA

The Solar energy segment's EBITDA for Q2 2024 was €2.2m, which is at the same level as in Q2 2023. EBITDA was supported by slightly higher production and negatively affected by the decline in the implied captured electricity price and the increase in operating expenses (€0.1m).

Investment

Investments in Q2

The group invested €129.8m in Q2 2024, €55.3m more than in Q2 2023. The growth was driven by development investments, which amounted to €129.6m. Of this, €106.9m was invested in the construction of three wind farms: €86.6m in the Sopi-Tootsi wind farm and €20.4m in the Kelmė wind farms (€11.6m in Kelmė I and €8.7m in Kelmė II). The largest development investment in solar energy was made in the Sopi solar project at €7.4m. The segment Other mainly includes development investments in the Liivi offshore wind farm.

Baseline investments (expenditure for the maintenance and improvement of existing assets) in Q2 decreased by €0.3m, mainly due to the CHP plants sold.

The segments had the following amounts of property, plant and equipment and intangible assets at 30 June 2024 (carrying amounts): Wind energy €1,137.6m including goodwill (49% under construction), Cogeneration €92.8m (0% under construction), Solar energy €126.2m (52% under construction) and Other €18.7m (62% under construction).

The estimated cost of completing the assets currently under construction is €250m.

Financing

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

At 30 June 2024, the amortised cost of the group's interest-bearing liabilities was €629.0m (31 March 2024: €503.2m). Loan liabilities to banks accounted for €614.4m of the total, including an outstanding loan balance of €6.4m denominated in Polish zloty.

In Q2, Enefit Green drew down bank loans of €125m and increased a loan taken from Swedbank to €100m.

35.0 39.4 +26.8 (115.7) +93.2 -70,0 -20,0 30,0 80,0 130,0 Cash and cash equivalents 31 Mar 2024 Operating cash flow Investment cash flow Financing cash flow Cash and 30 Jun 2024 Liquidity development 2024 Q2, €m +4.4 (+12.5%)

The interest rate risk of investment loans with the total outstanding balance of €149.8m 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 June 2024 was 4.23% (31 March 2024: 3.79%).

Investment loans raised but not drawn down at 30 June 2024 amounted to €235m.

Loans repayment schedule, €m

Revolving credit facility Long-term payments

Loan covenants

The group's loan and credit agreements include covenants that impose certain limits on the group's consolidated financial indicators. At 30 June 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 June 2024	31 December 2023
Interest-bearing liabilities	629.0	486.4
Less cash and cash equivalents	(39.4)	(65.7)
Net debt	589.6	420.7
Equity	729.7	717.2
Invested capital	1,319.3	1,137.9
EBITDA (last 12 months)	106.8	105.9
Operating profit (last 12 months)	66.6	65.3
Net profit (last 12 months)	61.5	55.8

Financial leverage (1)	45%	37%
Net debt / EBITDA	5.52	3.97
Return on invested capital (2)	5.0%	5.7%
Return on equity (3)	8.4%	7.8%
Interest cover (4)	6.5	7.9

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

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

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

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

Risk management

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

Price risk of electricity sales

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

various kinds of national renewable energy support (FiP, CfD and other schemes) received by the group's existing production assets; and
power purchase agreements (PPAs). The group's general target is to fix the sales price of electricity for at least 60% of a development project's projected output for the first five years by the time a binding investment decision on the project is made.

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

As our actual electricity production in H1 was 156 GWh lower than forecast, we expect our assets to generate 2.06 TWh of electricity in 2024, of which 1.18 TWh is expected from operating assets and 0.88 TWh from newly completed assets and assets under construction. The difference between the forecast and actual production in H1 mainly results from the Wind energy segment. See the segment's financial results chapter for further details.

We have covered 1.29 TWh (62.8%) of our expected electricity production in 2024 with PPAs at an average price of €67.2/MWh. In Q2 2024, we continued to actively manage our PPA portfolio for 2024, taking into account the expected production volumes, price forecasts and other risk factors. As a result, we reduced the PPA volume in the Baltic price areas in Q3 2024 by 23.1 GWh. 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 and Q2 figures reflecting actual results.

Long-term PPAs

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

We did not sign any new long-term PPAs in Q2 2024. At 30 June 2024, Enefit Green had signed PPAs for the supply of 9,005 GWh of electricity at an average price of €70.9/MWh over the period July 2024 – December 2033. The counterparty to most of the PPAs is Eesti Energia AS (8,067 GWh). 47.2% of our expected electricity production in the period 2024–2028 is covered with PPAs at an average price of €68.1/MWh.

	2024	2025	2026	2027	2028	Total 2024– 2028
FiT/CfD schemes**	1%	1%	1%	1%	1%	1%
Volume (GWh)	26	28	28	28	28	139
Price***, €/MWh	112.4	114.5	116.8	119.2	121.6	117.0
FiP support**	23%	8%	3%	2%	2%	7%
Volume (GWh)	469	266	99	79	75	989
Price***, €/MWh (added to the market price)	50.1	50.3	53.7	53.7	53.7	51.1
PPAs**	63%	49%	46%	47%	37%	47%
Volume (GWh)	1,292	1,533	1,534	1,549	1,219	7,127
Price***, €/MWh	67.2	64.8	64.8	69.0	76.4	68.1

National support measures

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

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

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

We have changed the presentation of the chart below to exclude from the forecast production volumes the potential production volumes in the coming years that could be generated by assets for which the investment decision has not yet been made (the so-called near-term development portfolio). This is due to the uncertainties associated with the timing of such investment decisions, which in turn are the result of a number of factors, such as higher interest rates and cost of capital, and lower electricity prices, PPA demand, and short-term electricity demand due to the macroeconomic situation, etc.

Our development activities are currently more focused on completing projects under construction and developing projects under development to construction readiness. The timing of future investment decisions on projects under predevelopment will depend on future changes in the above factors.

Electricity price forecasts for core markets

The price forecasts**** for all core markets for 2025 and 2026 have been revised upwards by around 15% compared to the figures presented in the Q1 interim report. Long-term price forecasts remained largely unchanged.

The higher price forecasts for the next two years are based on the increase in natural gas and emission allowance prices, which will increase the production costs of gas-fired power plants and thus also the electricity price.

* 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 – June 2024, Thema Power Market Outlook – May 2024 (Polish and Finnish prices: May 2023)). The figures presented are nominal prices, which have been estimated assuming a constant 2% rate of inflation.

Enefit Green | Interim report Q2 2024 | 31

Unaudited condensed consolidated interim financial statements Q2 2024

Condensed consolidated interim income statement

€ thousand	Note	Q2 2024	Q2 2023	H1 2024	H1 2023
Revenue	9	33,875	36,760	90,067	106,451
Renewable energy support and other operating income	10	4,377	4,406	17,106	12,219
Change in inventories of finished goods and work in progress		0	4,892	0	(168)
Raw materials, consumables and services used	11	(13,910)	(20,583)	(34,584)	(45,375)
Payroll expenses		(2,363)	(2,905)	(4,588)	(5,391)
Depreciation, amortisation and impairment		(9,829)	(9,707)	(19,171)	(19,522)
Other operating expenses		(3,073)	(3,274)	(6,668)	(7,329)
OPERATING PROFIT		9,077	9,589	42,162	40,885
Finance income		456	1,191	1,026	1,598
Finance costs		(436)	(402)	(742)	(782)
Net finance income and costs		20	789	284	816
Profit (loss) from associates under the equity method		(39)	22	(49)	41
PROFIT BEFORE TAX		9,058	10,400	42,397	41,742
Income tax expense		(5,117)	(9,260)	(5,010)	(10,080)
PROFIT FOR THE PERIOD		3,941	1,140	37,387	31,662

Basic and diluted earnings per share
Weighted average number of shares, thousand	6	264,276	264,276	264,276	264,276
Basic earnings per share, €	6	0.02	0.004	0.14	0.12
Diluted earnings per share, €	6	0.02	0.004	0.14	0.12

Condensed consolidated statement of comprehensive income

€ thousand	Note	Q2 2024	Q2 2023	H1 2024	H1 2023
PROFIT FOR THE PERIOD		3,941	1,140	37,387	31,662
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Remeasurement of hedging instruments in cash flow hedges (incl. reclassifications to profit or loss)	5, 7	1,730	1,228	2,845	540
Exchange differences on the translation of foreign operations	7	5	436		59 401
Other comprehensive income for the period		1,735	1,664	2,904	941

TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		5,676	2,804	40,291	32,603

Liabilities directly associated with assets classified as held for sale 0 4,952 Total current liabilities 154,614 97,203 Total liabilities 720,713 584,733 Total equity and liabilities 1,450,444 1,301,923

Condensed consolidated interim statement of financial position

€ thousand	Note	30 June 2024	31 December 2023	€ thousand	Note	30 June 2024	31 December 2023
ASSETS				EQUITY
Non-current assets				Equity and reserves attributable to shareholders of the parent
Property, plant and equipment	4	1,250,517	1,027,057	Share capital		264,276	264,276
Intangible assets		59,808	59,891	Share premium	6	60,351	60,351
Right-of-use assets		8,651	9,097	Statutory capital reserve		8,291	5,556
Prepayments for non-current assets	4	47,477	55,148	Other reserves	5, 7	166,296	163,451
Deferred tax assets		1,487	2,013	Foreign currency translation reserve	7	(103)	(162)
Investments in associates		499	548	Retained earnings		230,620	223,718
Derivative financial instruments	5, 7	5,772	5,054	Total equity		729,731	717,190
Non-current receivables		1,026	0	LIABILITIES
Total non-current assets		1,375,237	1,158,808	Non-current liabilities
				Borrowings	8	532,860	454,272
Current assets				Government grants		3,139	3,102
Inventories		5,425	3,180	Non-derivative contract liability	5, 7	12,412	12,412
Trade receivables		6,207	8,618	Deferred tax liabilities		12,442	12,497
Other receivables		6,970	16,380	Other non-current liabilities		5,239	5,239
Prepayments		13,098	30,084	Provisions		7	8
Derivative financial instruments	5	4,135	3,806	Total non-current liabilities		566,099	487,530
Cash and cash equivalents		39,372	65,677	Current liabilities
		75,207	127,745	Borrowings	8	96,100	32,126
Assets classified as held for sale		0	15,370	Trade payables		32,720	29,464
Total current assets		75,207	143,115	Other payables		22,916	24,981
Total assets		1,450,444	1,301,923	Provisions		2	6
				Non-derivative contract liability	5	2,876	5,674
						154,614	92,251

Condensed consolidated interim statement of cash flows

€ thousand	Note	Q2 2024	Q2 2023	H1 2024	H1 2023
Cash flows from operating activities
Cash generated from operations	12	31,003	14,006	66,166	58,343

Interest and loan fees paid		(3,944)	(2,084)	(12,441)	(4,137)
Interest received		233	207	691	518
Income tax paid		(871)	(631)	(871)	(1,205)
Net cash generated from operating activities		26,421	11,498	53,545	53,519
Cash flows from investing activities
Purchase of property, plant and equipment and
intangible assets		(115,661)	(69,907)	(212,943)	(149,480)
Paid for acquisition of subsidiaries		0	0	0	(6,174)
Proceeds from sale of a business (net of cash and cash
equivalents transferred)		0	0	16,879	0

Net cash used in investing activities		(115,661)	(69,907)	(196,064)	(155,654)
Cash flows from financing activities
Proceeds from bank loans	8	125,000	90,000	155,000	90,000
Repayments of bank loans	8	(4,080)	(4,040)	(13,092)	(11,177)
Repayments of lease principal	8	(147)	(95)	(205)	(179)
Proceeds from realisation of interest rate swaps		599	0	2,260	0
Dividends paid		(27,749)	(54,969)	(27,749)	(54,969)
Net cash generated from financing activities		93,623	30,896	116,214	23,675

Net cash flow		4,383	(27,513)	(26,305)	(78,460)
Cash and cash equivalents at the beginning of the period		34,989	80,509	65,677	131,456
Cash and cash equivalents at the end of the period		39,372	52,996	39,372	52,996
Change in cash and cash equivalents		4,383	(27,513)	(26,305)	(78,460)

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	31,662	31,662
Other comprehensive income for the period	0	0	0	540	401	0	941
Total comprehensive income for the period	0	0	0	540	401	31,662	32,603
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 June 2023	264,276	60,351	5,555	165,959	(361)	199,586	696,366
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	37,387	37,387
Other comprehensive income for the period	0	0	0	2,845	59	0	2,904
Total comprehensive income for the period	0	0	0	2,845	59	37,387	40,291
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 June 2024	264,276	60,351	8,291	166,296	(103)	230,620	729,731

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 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 costs of solar farm development teams and the development costs of solar projects without an investment decision are included in the segment Other and not 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	Q2 2024	Q2 2023	H1 2024	H1 2023
REVENUE
Wind energy	23,566	21,169	68,345	60,020
Cogeneration	7,851	12,695	18,295	42,900
Solar energy	2,378	2,761	3,206	3,254
Total reportable segments	33,795	36,624	89,846	106,175
Other	80	136	221	276
Total	33,875	36,760	90,066	106,450
RENEWABLE ENERGY SUPPORT AND OTHER OPERATING INCOME
Wind energy	3,218	2,745	8,749	8,464
Cogeneration	406	1,422	7,524	3,232
Solar energy	740	234	814	514
Total reportable segments	4,364	4,401	17,087	12,209
Other	14	5	19	10
Total	4,377	4,406	17,106	12,220

Wind energy 15,053 12,747 47,123 43,563 Cogeneration 5,374 7,794 18,831 20,647 Solar energy 2,169 2,183 2,438 2,464

EBITDA

€ thousand	Q2 2024	Q2 2023	H1 2024	H1 2023
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	118,296	54,498	203,368	127,671
Cogeneration	295	555	360	750
Solar energy	10,067	19,156	29,037	31,511
Total reportable segments	128,658	74,209	232,765	159,932
Other	1,157	348	1,850	6,563
Total	129,815	74,557	234,615	166,495

€ thousand	30 June 2024	31 December 2023
NON-CURRENT ASSETS
Wind energy	1,137,630	948,412
Cogeneration	92,781	97,747
Solar energy	126,171	96,484
Total reportable segments	1,356,583	1,142,643
Other	18,655	16,165
Total	1,375,237	1,158,808

4. Property, plant and equipment

€ thousand	Land	Buildings	Facilities and structures	Machinery and equipment	Assets under construction	Pre payments	Total
Property, plant and equipment as at 31 December 2023
Cost	63,982	22,299	44,796	747,900	458,834	55,148	1,392,959
Accumulated depreciation	0	(9,788)	(25,439)	(275,527)	0	0	(310,754)
Total property, plant and equipment as at 31 December 2023	63,982	12,511	19,357	472,373	458,834	55,148	1,082,205
Movements in the reporting period
Additions	0	0	13,187	74,951	145,087	1,361	234,586
Exchange differences	0	1	7	62	3	1	74
Transfers	0	0	0	12,078	(3,045)	(9,033)	0
Depreciation and impairment	0	(257)	(722)	(17,892)	0	0	(18,871)
Total movements in the reporting period	0	(256)	12,472	69,199	142,045	(7,671)	215,789
Property, plant and equipment as at 30 June 2024
Cost	63,982	22,300	57,990	834,991	600,879	47,477	1,627,619
Accumulated depreciation	0	(10,045)	(26,161)	(293,419)	0	0	(329,625)
Carrying amount as at 30 June 2024	63,982	12,255	31,829	541,572	600,879	47,477	1,297,994

The Group has signed construction and development contracts that are not recognised as a liability in the balance sheet and are accounted for off-balance sheet. As of 30 June 2024, the Group has liabilities arising from construction contracts in the amount of EUR 199,281 thousand (31 December 2023: EUR 368,953 thousand). As of 30 June 2024, the liabilities arising from development contracts are EUR 83,550 thousand (as of 31 December 2023, EUR 17,400 thousand). The timing and amount of payments for development projects depend on the achievement of certain development goals specified in the contract and the fulfilment of relevant requirements.

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 June 2024, the group used cash flow hedging instruments in order to hedge the exposure to interest rate risk resulting from floating-rate borrowings.

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

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

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

Amounts accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects profit or loss (for instance, when the 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 used to hedge its exposure to electricity price volatility with baseload swap derivative contracts. Under the given derivatives, the group was the payer of the floating price and the counterparty was the payer of the fixed price. The group applied hedge accounting to these cash flow hedges.

The group agreed with the counterparty (Eesti Energia AS) to terminate the derivative contracts and replace them with fixed price physical delivery contracts (EFET 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 two quarters of 2024, the balance of the contract liability decreased by €2,923k and was €(15,163)k at 30 June 2024 (30 June 2023: €(20,685)k). Respective changes were also made to the group's cash flow hedge reserve and to the income statement. The following changes will be made to the group's reserves and income statement in 2024:

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

Interest rate swap transactions

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

An interest rate swap with a notional amount of €69,565k, whereby the group receives interest at a rate equal to 6-month EURIBOR and pays a fixed rate of interest of 1.1%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan taken out on 30 September 2022.
An interest rate swap with a notional amount of €46,875, 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 €33,334, 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 June 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 June 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	149,775	9,907	0	Derivative financial	2,085	0	(1,067)
				instruments

* Change compared to 31 March 2024, recognised in other comprehensive income

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

€ thousand	Change in fair value used to measure ineffectiveness	Amounts recognised in hedge reserve	Amounts recognised in hedge reserve to which hedge accounting is no longer applied
Floating rate loans	9,907	9,907	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 June 2024, Enefit Green AS had 264,276,232 registered shares (30 June 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	Q2 2024	Q2 2023	H1 2024	H1 2023
Profit attributable to shareholders of the parent	€ thousand	3,941	1,140	37,387	31,662
Weighted average number of shares	thousand	264,276	264,276	264,276	264,276
Basic earnings per share	€	0.02	0.004	0.14	0.12
Diluted earnings per share	€	0.02	0.004	0.14	0.12

7. Other reserves

€ thousand	30 June 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	3,214	(2,221)
Decrease in hedge reserve for cash flow hedges for electricity price risk	1,797	2,798
Reclassification from other comprehensive income, recognised as a change in interest expense	(2,166)	(3,545)
Exchange differences on the translation of foreign operations	59	600
Other reserves at the end of the period, of which:	166,193	163,289
Foreign currency translation reserve	(103)	(162)
Hedge reserve for cash flow hedges for interest rate risk
(interest rate swaps)	9,907	8,860
Hedge reserve for cash flow hedges for electricity price risk	(7,830)	(9,628)
Initial fair value of derivative transactions with the parent	(10,781)	(10,781)
Voluntary financing reserve	175,000	175,000

8. Borrowings at amortised cost

		Current borrowings		Non-current borrowings		Total
€ 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	13,148	57,500	0	97,500	0	168,832
Repayments of borrowings	(12,335)	(13,092)	(311)	0	0	(25,738)
Non-monetary movements
Addition of borrowings	0	0	2	0	352	354
Transfers	156	18,890	0	(19,046)	0	0
Amortisation of borrowing costs	0	0	0	(3)	0	(3)
Effect of movements in foreign exchange rates	4	12	0	38	8	62
Other movements	0	0	0	0	(262)	(262)
Total movements in the reporting period	973	63,310	(309)	78,489	98	142,561
Borrowings at amortised cost as at 30 June 2024	4,940	90,724	436	523,663	9,196	628,959

* Repayments of lease liabilities of €311k consist of principal repayments of €205k and interest payments of €106k.

9. Revenue

€ thousand	Q2 2024	Q2 2023	H1 2024	H1 2023
Revenue by activity
Sale of goods
Pellets	0	2,921	0	18,597
Scrap metal	111	192	230	455
Other goods	16	17	59	26
Total sale of goods	127	3,130	289	19,078

Sale of services
Heat	1,124	1,647	3,558	4,923
Electricity	28,892	27,753	78,271	73,284
Waste reception and resale	3,710	3,859	7,678	8,452
Rental and maintenance of assets	37	289	250	537
Other services	(15)	82	21	177
Total sale of services	33,748	33,630	89,778	87,373
Total revenue	33,875	36,760	90,067	106,451

Note: From December 2023, the revenue arising from electricity derivatives is recognised in the same line item as revenue from the sale of electricity. In connection with this, the amounts for line item 'Electricity' for Q2 2023 and H1 2023 in the table above have been increased by €204k and €1,110k, respectively.

10. Renewable energy support and other operating income

€ thousand	Q2 2024	Q2 2023	H1 2024	H1 2023
Renewable energy support	4,979	4,355	11,372	11,623
Government grants	49	112	148	235
Gain on sale of a business	(801)	0	4,958	0
Other income	150	(61)	628	361
Total renewable energy support and other operating income	4,377	4,406	17,106	12,219

Note: From December 2023, the revenue gaiarising from electricity derivatives is 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 €204k for Q2 2023 and €1,110k for H1 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, has been corrected in this 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	Q2 2024	Q2 2023	H1 2024	H1 2023
Maintenance and repairs	3,406	4,033	6,938	7,135
Technological fuel	189	6,371	1,342	14,730
Electricity	8,864	8,731	23,694	20,192
Services related to ash treatment	505	475	966	1,038
Transport services for sale of goods	0	303	0	872
Materials and spare parts for production	335	361	577	772
Transmission services	378	107	582	222
Waste handling	103	99	197	179
Resource charges for natural resources	1	2	2	3
Other raw materials, consumables and services used	55	38	115	88
Environmental pollution charges	74	63	171	144
Total raw materials, consumables and services used	13,910	20,583	34,584	45,375

12. Cash generated from operations

€ thousand	Q2 2024	Q2 2023	H1 2024	H1 2023
Profit before tax	9,058	10,400	42,397	41,742
Adjustments
Depreciation and impairment of property, plant and equipment	9,7,96	9,598	19,104	19,304
Amortisation and impairment of intangible assets	33	109	67	218
Amortisation of government grants related to assets	(49)	(112)	(147)	(235)
Interest expense on borrowings	191	61	415	441
Loss (gain) on sale of a business	801	0	(4,958)	0
Loss (profit) from associates under the equity method	39	(22)	49	(41)
Interest and other finance income	(233)	(207)	(692)	(518)
Loss on other non-cash transactions	0	0	13	0
Foreign exchange loss on loans granted and taken	10	326	50	341
Realised gain on derivative financial instruments	(75)	(204)	(1,001)	(1,109)
Adjusted profit before tax	19,571	19,949	55,297	60,143
Net change in current assets related to operating activities
Change in receivables related to operating activities	1,738	5,437	2,361	4,486
Change in inventories	(2,023)	(5,638)	(1,919)	(38)
Net change in other current assets related to operating activities	12,876	4,147	23,617	(375)
Total net change in current assets related to operating activities	12,591	3,946	24,059	4,073
Net change in current liabilities related to operating activities
Change in provision	(5)	(1)	(5)	(1)
Change in trade payables	3,302	2,118	(7,567)	3,335
Net change in other current liabilities related to operating activities	(4,456)	(12,006)	(5,618)	(9,207)
Total net change in current liabilities related to operating activities	(1,159)	(9,889)	(13,190)	(5,873)
Cash generated from operations	31,003	14,006	66,166	58,343

13. Transactions and balances with related parties

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

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

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

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

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

At 30 June 2024, Enefit Green AS had signed long-term power purchase agreements for the physical supply of electricity of 8,067 GWh with Eesti Energia AS for the supply of electricity in the Lithuanian, Estonian, Finnish and Polish electricity networks in the period July 2024 – December 2033. The contracts are for the supply of both annual and monthly baseload energy. The weighted average price of the power purchase agreements for the physical supply of electricity signed with the related party is €68.2/MWh.

At the beginning of 2021, the group used baseload swap derivative contracts in order to hedge the exposure to variability in the price of electricity. The initial fair value of the derivatives designated as hedging instruments of €(10,781)k was recognised directly in equity. The group continued to apply hedge accounting to the open derivatives positions until 17 August 2021, when an EFET General Agreement Concerning the Delivery and Acceptance of Electricity (EFET General Agreement) was signed and all open derivative contracts were simultaneously terminated. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k due to the change in the electricity price in the period from the trade date to 17 August 2021. The cumulative change in the fair value of the derivative financial instruments of €(12,426)k was recognised through other comprehensive income and the cash flow hedge reserve in equity (see also note 5). At 30 June 2024, the balance of the electricity cash flow hedge reserve was €(7,830)k (see also notes 5 and 7).

€ thousand	Q2 2024	Q2 2023	H1 2024	H1 2023		30 June 2024	31 December 2023
TRANSACTIONS					BALANCES
PARENT
Purchase of services	4,402	2,950	9,978	7,414	Receivables	5,368	9,497
Sale of goods	0	0	0	0	Payables	17,397	20,281
Sale of services	14,788	16,111	40,751	39,568	Of which non-derivative contract liability	15,241	18,086
OTHER GROUP COMPANIES
Purchase of goods	0	0	0	0	Receivables	1,168	314
Purchase of services	162	704	287	1,561	Payables	82	62
Sale of goods	0	0	0	0
Sale of services	1,251	322	1,743	742
OTHER RELATED PARTIES (INCL. ASSOCIATES)
Purchase of services	443	428	860	884	Receivables	0	22
Sale of services	0	0	0	0	Payables	370	311
ELERING AS
Purchase of services	230	18,472	482	20,059	Receivables	2,458	5,629
Sale of services	4,646	4,425	11,054	11,755	Payables	105	33

AI Terminal

Enefit Green

2216_ir_2024-08-01_b552efba-7090-45b5-bfd0-49dc615b0d5b.pdf

Q2 2024

Contents

Acting chairman's letter

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

Q2 2024 key highlights

Focus on completing major construction projects

€100m

H1 2024 key highlights

Focus on completing major construction projects

Operating environment

Key factors influencing the operating environment

Electricity market

Wind conditions

Regulatory environment

European Union

Estonia

Latvia

Lithuania

Poland

Finland

Significant events

Changes in the management board

Purtse hybrid farm passes Elering compliance tests

Rescue exercise at Paldiski wind farm

Progress on major wind and solar farms under construction

Amendment to loan agreement with Swedbank

Financial results

Production and sales volumes

Operating income

Average quarterly electricity prices

Raw materials, consumables and services used

Payroll expenses

Other operating expenses

EBITDA and fixed costs

Depreciation, amortisation and impairment (D&A)

Net finance income

Income tax

Group's EBITDA change by drivers, €m

Financial results by segments

Group's EBITDA breakdown and change, €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

EBITDA

Solar energy

Electricity production and prices

Operating income

Operating expenses

EBITDA

Investment

Investments in Q2

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 core markets

Condensed consolidated interim income statement

Condensed consolidated statement of comprehensive income

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