Q3 2022 Unaudited Interim Report

Enefit Greeni III kvartali 2022 vahearuanne

Enefit Green

By 2026 we will be the largest renewable energy producer in the Baltics and a rapidly growing renewable energy company in Poland.

2	Enefit Green at a glance
4	Letter from the Chairman of the Management Board
5	Strategy and development portfolio
9	3Q key highlights
10	Operating environment
12	Significant events
13	Financial results of the group
16	Wind energy segment
18	Cogeneration segment
20	Solar energy segment
21	Investments
22	Financing
23	Risk management
24	Share and shareholders
26	Condensed consolidated interim financial statements
32	Notes to the condensed consolidated interim financial statements
48	Legal structure

Letter from the Chairman of the Management Board

Dear reader

A year of upheaval has reached its last quarter. Winter is coming and Europe is bracing itself for a real-life test of the security of energy supply. In Q3, Enefit Green made preparations for the winter heating period and the high season in wind electricity production. We contribute to energy security by ensuring availability of our existing renewable energy production capacities and by creating new renewable energy production capacities in all our core markets – the Baltic countries, Poland and Finland.

Russia's ruthless aggression against Ukraine is ongoing and the war is affecting numerous sectors, including the energy industry. EU member states that are seeking solutions to the energy crisis have reached agreement on certain mitigation measures. Among other things, it has been decided that regulations will be adopted for the taxation of energy producers and the redistribution of their revenues to the end consumers. However, the search for short-term mitigation of high electricity prices should not inflict long-term damage on the credibility of the market.

The energy crisis is increasing our determination to become independent of uncertain and expensive fossil fuel supplies. For years, it has been said that renewable electricity helps protect nature and the environment. Now it is clear that it also helps ensure our security. Therefore, we should not destroy the investment environment which is essential for the development of renewable energy.

Enefit Green is part of the solution to the energy crisis – we are currently building a total of four new wind farms in Estonia, Lithuania and Finland and three solar farms in Estonia and Poland. In Q3, we laid the cornerstones of all wind farms that have reached the construction phase. We are deeply grateful to all customers whose long-term power purchase agreements – PPAs – help us launch new projects to increase our production capacity. As a token of our appreciation, two turbines at the Akmene wind farm, which is our largest wind power production facility to date, will be named after the customers whose long-term PPAs have been instrumental in kick-starting Enefit Green's growth journey.

Long-term PPAs also play an important role in selling the output of our operational wind farms. In Q3, we exited Lithuania's national feed-in-tariff support scheme and covered a major share of the output of our 60 MW Šilute and 39 MW Ciuteliai wind farms with long-term fixed-price PPAs. The new PPAs ensure the wind farms with cash flow for a considerably longer period and at a higher price than the previous solution.

In 2023, when the projects under construction have been completed, we will add 258 MW of production capacities to the electricity markets of the region where we operate. The capacities will generate over 700 GWh of electricity per year, which should cover the annual electricity consumption of more than 200,000 households.

Our Estonian solar energy developments portfolio grew by 200 MW in Q3. First, we acquired an opportunity to build two large solar farms in Western Estonia. The developments, which are located in Lihula and Pärnu-Jaagupi, have a combined planned capacity of up to 165 MW and a combined projected annual output of up to 169 GWh. We are planning to make the final investment decision on the projects in 2024 and to complete construction within the next two years. In addition, we acquired the 35 MW Seinapalu solar farm development project.

In the next decade, Estonia will become a wind energy country. A larger number of wind power production facilities means that we have to be ready to respond to incidents which may occur during turbine maintenance as well as other emergencies. In Q3, we organised the first rescue exercise in Estonia to practise the rescue of people from a wind turbine in cooperation with the Rescue Board and other partners. Good collaboration with the Rescue Board, the emergency medical services and the police along with preparedness testing gives assurance for the future.

New wind farms can be built quickly only if the planning process is smooth and cooperation with the local communities is good. Accordingly, public discussions and provision of information are among our top priorities. During the planning phase of a new wind farm, people want to know what the turbines will look like and whether they will blend into the landscape. A virtual reality solution implemented by Enefit Green provides people with a 360° experience of the landscape where a wind farm is expected to be built with a realistic visualisation of the planned turbines working at full capacity.

Due to seasonal factors, wind conditions in Q3 are less favourable for wind power production but this year Q3 wind conditions were the past three years' weakest. As a result, we produced only 198 GWh of electricity, 24% less than in the same period last year. We used the period with modest wind conditions to carry out the necessary maintenance and prepare for autumn and winter, which are the high season in wind power production.

One of the steam superheaters of the waste-to-energy unit of the Iru combined heat and power plant malfunctioned in August, which left its mark on the production and availability indicators of the Cogeneration segment. Our heat output for the quarter was 84 GWh, which is 32% smaller than in the same period last year. In view of the upcoming heating period, we decided to replace the damaged parts in full in order to prevent unplanned production interruptions in the winter. Large-scale repair operations were completed on schedule and today the Iru power plant is again operating at full capacity.

The group's financial results were strongly influenced by high electricity prices. Total revenues amounted to €60.3m (a 66% increase year on year), EBITDA was €32.7m (a 28% increase) and net profit was €22.9m (a 50% increase). Our investments in Q3 amounted to nearly €80m, which is €71.6m more than in the same period last year.

Enefit Green intends to sustain rapid growth because the only long-term solution to the energy crisis is the availability of sufficient quantities of renewable energy. Our goal is to increase the production of affordable and environmentally friendly renewable energy in partnership with our 60,000 investors. We are planning to make the final investment decisions on projects of over 300 MW in total before the year-end already. This would more than double the total capacity of projects under construction.

Aavo Kärmas Chairman of the Management Board of Enefit Green

Target: 4× growth in production capacity

Operating capacity Under construction

Targeting renewable capacity growth to ~1900 MW by the end of 2026

Projects under construction

Near term development portfolio

Targeted investment decisions until end of 2023

NB! Development projects are in continuous change.

The presented information is management team's best assessment of the current status of the near term development portfolio as of 31 Oct 2022

Complete view of the development portfolio

NB! Development projects are in continuous change.

* Various onshore wind and solar farm developments that are not expected to get final investment decision before 2024.
** Liivi Offshore wind farm development is owned by Eesti Energia. Eesti Energia is willing to offer Enefit Green a possibility to participate in the project and/or acquire the project based on market terms.

3Q 2022 Key highlights

+74 MW (project acquisition - Tootsi)

+200 MW (project acquisitions)

+3.1 TWh (signed PPAs with up to 10y duration)

Operating environment

Key factors influencing the operating environment

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

Enefit Green's production assets that are exposed to fluctuations in the market price of electricity include the Iru and Paide cogeneration (combined heat and power, CHP) plants, wind farms in Estonia, partly solar farms in Estonia, the Keila-Joa hydroelectric facility, and wind farms in Lithuania. The revenue of our Estonian production assets whose eligibility for support has not expired consists of the market price as well as renewable energy support. The eligibility of the 6.9 MW Virtsu III and the 9 MW Vanaküla wind farm expired in Q3 (in August and September, respectively). The eligibility of the 24 MW Aseriaru wind farm will expire next (in October 2024). In Q3, we replaced the previous feed-in-tariff (FiT) based revenue model for all our Lithuanian wind farms with a revenue model based on a combination of long-term fixed-price PPAs and the market price.

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. The average wind speeds measured in our Estonian and Lithuanian wind farms in Q3 2022 were the recent years' weakest: 5.2 m/s in Estonia and 5.5 m/s in Lithuania (6.0 m/s and 5.6 m/s, respectively, a year earlier), which had a negative effect year on year. The graph below provides an overview of average quarterly wind speeds in Estonia and Lithuania since the beginning of 2020.

Electricity market

Nord Pool's intraday electricity prices have been highly volatile in recent years. Usually, the peak load electricity price is determined by the more expensive carbon-intensive power and the baseload electricity price is determined by renewable power. The electricity markets of the region where Enefit Green operates are well connected by means of interconnectors. Therefore, electricity generation and prices are affected by various factors in both our core markets and beyond.

Average electricity prices in markets relevant to our business continue to be high due to soaring natural gas prices, which inflate the cost prices of gas-fired power plants. The high market price of natural gas (Q3 average: 146.4 €/MWh, +242% year on year) is attributable to the termination of gas supplies from Russia. Surging natural gas prices have created a situation where the cost price of electricity produced by gas-fired power plants is higher than the cost price of electricity produced by oil shale- and coal-fired power plants.

Due to the replacement of natural gas with more carbon intensive energy sources, the price of CO2 emission allowances has been elevated (80.0 €/t, +40%). At the end of Q3, however, it dropped below 70 €/t, mainly because the EU increased the supply of emission allowances in order to support transition to renewable energy.

Water levels in the Nordic hydro reservoirs improved considerably in Q3, reaching 71.1% of the maximum. This is still below the past decades' median but 3.1 percentage points higher than in the same period last year. The improvement in the Nordic hydro balance (compared with previous quarters) should suppress growth in electricity prices.

Estonian weekly average electricity price, €/MWh

Average electricity price (€/MWh)	3Q 2022	3Q 2021	Change
Estonia	275.0	97.5	182.1%
Latvia	374.8	99.5	276.9%
Lithuania	382.1	99.7	283.0%
Poland	213.1	89.0	139.5%
Finland	220.3	78.6	180.1%
Norway	167.6	62.6	167.8%
Denmark	347.9	96.0	262.4%
Sweden	118.9	67.8	75.4%

Regulatory environment

On 30 September, the EU energy ministers agreed to cap the market revenues at 180 €/MWh for inframarginal generators, i.e. electricity producers whose variable costs are low (including producers that generate electricity from wind, solar, waste and biomass). The cap will apply from 1 December 2022 to 30 June 2023. Relevant intervention measures are set out in Council Regulation (EU) 2022/1854 of 6 October 2022. The European Commission is planning to use the funds collected by capping the revenues of electricity producers to enable member states to mitigate the effects of high energy prices on final electricity consumers. The support provided to companies must increase investments in energy efficiency and decarbonisation technologies, including renewables, for example through PPAs or direct investments in renewable energy generation. The specific measures for imposing the revenue cap will have to be established by the member states before the end of this year, which complicates the assessment of the impact of such measures at this stage.

The Estonian parliament set a new national renewable energy production target according to which by 2030 Estonia's annual electricity consumption should be fully covered by renewable electricity produced in Estonia. The previous target was that locally produced renewable electricity should cover at least 40% of annual electricity consumption. To meet the goal, additional renewable electricity reverse auctions of at least 1 TWh will be held in 2024–2025.

Operators of efficient district heating and cooling networks will be exempted from the obligation to use public procurement for the purchase of heat. This will limit the opportunities of our Iru wasteto-energy unit to secure a new agreement for the sale of heat to the Tallinn district heating system after the current one expires in February 2027.

Estonia's transmission system operator Elering published the methodology for preventing the overcompensation of <50 kW solar farms subsidised under the General Block Exemption Regulation that exempts certain businesses and industries from normal state aid rules. The methodology provides a regulatory framework for the termination of renewable electricity production support paid to Enefit Green's Klibuloo solar (PV) farm. There are various options the effect of which depends on the future levels of the market price of electricity and the difference between the average daily electricity price and the price of solar electricity.

In connection with the electricity market reform, household consumers were granted a one-off right to cancel their fixed-term PPAs without paying a contractual penalty. This has set a precedent that lowers the value of PPAs signed with Estonian household consumers because similar intervention in contract terms and conditions may recur.

A draft regulation creating a basis for competing for offshore wind energy projects was submitted to public discussion.

In Latvia, amendments to the regulation governing the qualification requirements for developers of offshore wind farms that apply for the right of superficies in a marine area was submitted to public discussion.

Latvia's state-owned electric utility company Latvenergo and state forest management company LVM announced that they have established a joint venture which is going to build wind farms on state-owned land. There is public discussion of providing all wind power developers with equal access to the construction of wind farms on state-owned land.

Legislation was updated in preparation of a public tender for the development of offshore wind farms in Lithuania.

Laws and regulations governing the development permits, planning, construction and operation of solar farms >100 kW were updated. The purpose is to issue development permits to solar energy developers consistent with the overall 2 GW limit on new solar power generating capacities.

Poland's parliament removed the obligation for electricity producers to sell electricity through the power exchange. The obligation was originally imposed to stabilise and lower electricity prices. Now the opposite procedure was used for the same purpose. Also, stricter penalties were introduced for the use of unlawful practices by energy companies.

Preparations are being made for the adoption of a regulation enabling the construction of direct power lines between electricity producers and consumers.

Significant events

We laid the cornerstones for four wind farms

In Q3, we laid cornerstones for four wind farms that have reached the construction phase: the 72 MW Tolpanvaara wind farm in Finland, the 43 MW Šilale II and the 75 MW Akmene wind farms in Lithuania and the 21 MW Purtse wind farm in Estonia. The Purtse wind farm together with the solar farm that will be built nearby will be Enefit Green's as well as Estonia's first hybrid electricity production facility.

The wind farms will gradually come online and begin supplying green energy starting from the beginning of 2023. Their total annual output exceeds 700 GWh, which should cover the annual electricity consumption of more than 200,000 households.

We acquired solar farm developments with a capacity of up to 200 MW

We acquired Rääbiste Põllud OÜ (new business name: Enefit Green Solar OÜ), a company developing two large solar farms in Western Estonia.

The developments, which are located in Lihula and Pärnu-Jaagupi, have a combined planned capacity of up to 165 MW and a combined projected annual output of up to 169 GWh. The output is sufficient to meet the annual electricity needs of around 50,000 average Estonian households. We are planning to make the final investment decision on the projects in 2024 and to complete construction within the next two years.

In addition, we acquired the 35 MW Seinapalu solar farm development project, which did not involve the acquisition of a legal entity.

We signed new long-term PPAs in Lithuania

We signed long-term fixed-price PPAs for selling the production of the 60 MW Šilute and the 39 MW Ciuteliai wind farms in Lithuania. The average term of the PPAs is nine years. Under the contracts, we sell at least 60% of the two wind farms' projected electricity output at a fixed price that is higher than the previously received national support, which ensures the wind farms' cash flow for a significantly longer period than before. The rest of the output is sold at current market prices on the Nord Pool day-ahead market.

In the Q2 report we announced the transition of our Šilale and Mockiai wind farms to a market-based revenue model and in Q3 we completed our exit from the Lithuanian national FiT support scheme.

Litigation involving the Purtse wind farm development

On 20 September 2022, Viru County Court accepted the case brought by Eesti Ühistuenergia OÜ against Enefit Green AS's subsidiary Enefit Wind Purtse AS. The claimant is seeking that the maximum capacity of turbines at the Purtse wind farm should not exceed 3 MW. Viru County Court has satisfied the claimant's request for an interim protection order.

Enefit Green believes that it has acted lawfully and consistent with the construction permit obtained in all matters related to the construction of the wind farm. We have submitted our position and reasoning to the court.

We conducted a rescue exercise at our Aseriaru wind farm

We practised the resolution of an emergency situation on a turbine together with the Rescue Board and other partners. It was the first training exercise of this kind in Estonia. According to the scenario, the maintenance staff on a turbine of the Aseriaru wind farm in Viru-Nigula required lifesaving assistance.

The exercise enabled us to test the operation of our crisis resolution mechanisms, the provision of comprehensive assistance to the rescue team and the transfer of information during an incident.

We implemented a VR solution in the development of wind farms

During the planning phase of new wind farms people commonly ask what the turbines will look like and how they will fit with the landscape. A virtual reality solution we have implemented enables people to view a future wind farm from different locations and heights.

A VR headset provides the user with a 360° experience of the landscape with a realistic visualisation of the planned turbines working at full capacity.

Outage at the Iru facility

One of the steam superheaters of the waste-to-energy unit of the Iru CHP malfunctioned in August and the elimination of the fault required extraordinary repairs, which lasted for nearly five weeks. This had a significant effect on the Q3 availability as well as electricity and heat production indicators of the Cogeneration segment. The repairs were completed on time and the Iru CHP has been operating at full capacity since 12 October.

Financial results of the group

Enefit Green's consolidated financial results for Q3 2022 improved significantly year on year: total revenues (revenue plus renewable energy support and other income) grew by 66% and EBITDA improved by 28%. Net profit for the period increased by €7.7m, i.e. by 50%, rising to €22.9m. The key factors which influenced the group's financial performance are described below.

Production

	Unit	Q3 2022	Q3 2021	Change	Change,%
Electricity production	GWh	189	250	(61)	(24)%
Heat energy production	GWh	84	123	(39)	(32)%
Pellet production	thousand tonnes	39	37	2	6%

Revenue

The group's electricity production in Q3 2022 was 189 GWh (a 24% decrease compared with 250 GWh in Q3 2021). The group's average implied captured electricity price* including support was 205.1 €/MWh (Q3 2021: 115.8 €/MWh).

The most important revenue driver was growth in electricity prices in the Estonia price area of the Nord Pool (NP) power exchange, which increased the group's revenue by around €14.5m. The average market price in the NP Estonia price area in Q3 2022 was 274.5 €/MWh compared with 97.7 €/MWh in Q3 2021. The implied captured electricity prices of the group's Estonian production entities in the respective periods were 275.1 €/MWh and 133.2 €/MWh. The implied captured electricity price differs from the average NP price because it includes renewable energy support and efficient cogeneration support and wind farms do not produce the same amount of electricity in each hour. The figure also includes the effects of long-term fixed-price PPAs. The share of production covered with PPAs and the prices per year are disclosed in the risk management chapter. The Q3 implied captured electricity prices of the group's Latvian and Lithuanian production entities were 362.1 €/MWh (Q3 2021: 129.7 €/MWh) and 87.6 €/MWh (Q3 2021: 79.2 €/MWh), respectively.

Another factor that strongly affected revenue development was the quantity of electricity produced in Estonia, which decreased year on year due to less favourable wind conditions and a five-week outage at the Iru CHP.

Revenue growth was supported by pellet sales, which grew by €6.7m as sales volume increased from 4k tonnes in Q3 2021 to 39k tonnes in Q3 2022. The sharp rise is attributable to differences in the timing of major pellet supplies during the reporting and the comparative period.

Heat production decreased by 32%, mainly due to an unplanned production interruption at the Iru CHP, while the price of heat sold increased by 23% year on year.

Th rest of revenue growth resulted from the sale of inventories in the Solar energy segment. As we decided to exit the provision of turnkey solar solutions, relevant inventories were sold.

Renewable energy support and other income

Renewable energy support and other income for Q3 2022 were strongly affected by a decrease in the renewable energy support received by the group's Estonian wind farms, which dropped by €2.0m year on year. Renewable energy support is linked to the quantity of energy produced and since quantity decreased, support received also declined. The renewable energy support received by the Iru CHP decreased by €0.5m year on year due to its five-week outage.

Renewable energy support received by the Polish wind farms dropped by €0.9m year on year. Due to high market prices, revenue generated exceeded the guaranteed price and consistent with local laws in such a situation the positive balance has to be repaid to the Polish state.

€ million	Q3 2022	Q3 2021		Change Change, %
TOTAL REVENUES	60.3	36.4	23.9	66%
Revenue	57.3	30.1	27.1	90%
Renewable energy support and other income	3.0	6.3	(3.2)	(52)%
OPERATING EXPENSES (excluding D&A)	27.5	10.9	16.7	153%
Raw materials, consumables and services used	25.0	11.1	13.9	125%
Payroll expenses	2.0	1.6	0.4	25%
Other operating expenses	2.6	1.9	0.7	38%
Change in inventories	(2.0)	(3.7)	1.7	(45)%
EBITDA**	32.7	25.5	7.2	28%
Depreciation, amortisation and impairment (D&A)	9.6	9.5	0.2	2%
OPERATING PROFIT	23.1	16.0	7.0	44%
Net finance costs	(0.3)	(0.5)	0.3	(50)%
Loss from associates underthe equity method	0.1	0.0	0.0	14%
Corporate income tax expense	(0.0)	0.3	(0.3)	(100)%
NET PROFIT	22.9	15.3	7.7	50%

TOTAL OPERATING EXPENSES (excluding D&A)	27.5	10.9	16.7	153%
Variable costs (incl. balancing energy purchases)	20.3	6.5	13.8	213%
Fixed costs	9.3	8.1	1.2	15%
Change in inventories	(2.0)	(3.7)	1.7	(45)%

* Implied captured electricity price = (electricity sales revenue + renewable energy support and efficient cogeneration support – balancing energy purchases) / production

** EBITDA – earnings before net finance costs, profit or loss from equity-accounted investees, taxes, depreciation , amortisation and impairment losses

Financial results of the group

Raw materials, consumables and services used

Expenses on raw materials, consumables and services grew by €13.9m, i.e. 125%. The biggest rise (€5.8m) was in electricity costs, which grew due to a higher electricity price and an accounting policy change according to which the quantities of electricity purchased from the NP intraday market to balance the electricity portfolio are no longer offset against the quantities of electricity sold. There was also an increase in expenses on technological fuel (€3.1m), materials used for production (€1.8m) and inventories sold in the Solar energy segment (€3.2m).

Payroll expenses

The group's payroll expenses grew by €0.4m, i.e. 25% year on year, due to an increase in the average number of full-time employees from 160 to 172 compared with Q3 2021 as well as growth in existing employees' payroll expenses. New people were mostly hired to the development team to support the group's growth plan in all its core markets.

Group's EBITDA development by drivers, €m

Other operating expenses

Other operating expenses grew by €0.7m, i.e. 28%. Several items increased slightly, including research and consulting expenses (mostly in connection with development activities), IT expenses, expenses on equipment and structures, etc.

Change in inventories

Change in inventories reflects the change in pellet stocks, summarising the quantities of pellets produced and sold in the period under review. Pellet production and sales volumes were similar in Q3 2022: output was 39.1k tonnes (Q3 2021: 36.8k tonnes) and sales were 39.5k tonnes (Q3 2021: 3.6k tonnes). The change in inventories was negative at €2.0m (Q3 2021: negative at €3.7m), reflecting that the growth in the value of inventories held was attributable to growth in pellet production costs.

Depreciation, amortisation and impairment losses (D&A)

D&A expense remained stable compared with a year earlier. Although the volume of investments made in Q3 2022 was €79.7m, this did not affect D&A expense because investments were mostly made in wind and solar farm development projects which are still in the construction phase.

Variable costs

Variable costs comprise operating expenses that depend on the production volume, including purchases of balancing energy (in 2022 also expenses on intraday NP transactions made to balance the electricity portfolio, which previously were offset against electricity sales; as the change increased both revenue and expenses by the same amount, it did not affect profit). Variable costs increased in connection with the sale of inventories in the Solar energy segment due to the exit from the provision of turnkey solar solutions and higher expenses on intraday purchases of balancing energy.

Fixed costs

Fixed costs comprise costs not directly dependent on the production volume. Fixed costs grew by €1.2m, i.e. 15% year on year. Both payroll expenses and research and consulting expenses grew to a certain extent.

Financial results of the group

Net finance costs

Net finance costs decreased by €0.3m year on year. Net finance costs were mainly influenced by the capitalisation of borrowing costs and movements in the exchange rate of the Polish zloty (PLN).

Income tax

Income tax expense decreased by €0.3m compared with Q3 2021.

Net profit

The group's Q3 net profit grew by €7.7m year on year, rising to €22.9m. Net profit growth was mainly underpinned by high market prices of electricity.

Financial results by segments

Based on total revenues and EBITDA for Q3 2022, the group's largest segment is Wind energy which accounted for 53% of total revenues and 72% of EBITDA. The Cogeneration segment contributed 34% to total revenues and 29% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 12% of total revenues and 5% of EBITDA.

15 Enefit Green Q3 2022 interim report

Among reportable segments, the strongest EBITDA growth was delivered by Wind energy and Cogeneration as they benefited the most from higher market prices of electricity. A more detailed analysis by segment is presented below.

The EBITDA of the segment Other mainly includes general administrative expenses, which is the largest item for the segment. The segment also includes the network construction services of the Paide CHP facility, the Keila-Joa hydroelectric facility, and the renewable energy solution on the island of Ruhnu. The (EBITDA) loss of the segment Other increased by €0.5m, primarily due to growth in the payroll expenses of the group's central management staff and consulting expenses.

Revenues €60.3m +66% EBITDA €32.7m +28% Net profit €22.9m +50%

Group's EBITDA breakdown and change, €m

Wind energy segment

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

Availability and production

In Q3 2022, wind conditions in Estonia and Lithuania were less favourable for wind power production than in the same period last year. The availability of our Estonian and Lithuanian wind farms was 94.8% and 92.9%, respectively. Since wind conditions were modest, the period was used for maintenance and repairs to ensure operationality and availability in the next quarters that usually have better wind conditions. The lower availability of the Lithuanian wind farms is attributable to larger-scale maintenance and repair operations at the Šilute and Sudenai wind farms.

The electricity production of our Estonian and Lithuanian wind farms dropped by 35% and 12%, respectively. Our total wind energy output was 149 GWh, 26% less than in the same period last year

Electricity prices

In addition to the market price of electricity, our Estonian wind farms whose eligibility period has not expired receive renewable energy support at the rate of 53.7 €/MWh. Since March 2022, our Estonian wind farms have been selling part of their electricity at fixed prices. As a result, their production is not fully exposed to fluctuations in the market price of electricity. The 14 MW Sudenai wind farm in Lithuania has been selling its output on the power exchange, in the NP Lithuania price area, since June 2021.

The Šilale and Mockiai wind farms began to sell their output on the power exchange, in the NP Lithuania price area, from 27 August 2022 and the Šilute and Ciuteliai wind farms from 1 October 2022. Previously, our Lithuanian wind farms operated under the Lithuanian renewable energy support scheme and received a fixed price.

The accounting treatment of intraday NP transactions made to balance the electricity portfolio changed from the beginning of 2022: gross amounts are now reported in revenue and expenses. In earlier periods, electricity purchase expenses and sales revenues from intraday NP transactions were offset. Since the change increased both revenue and expenses by the same amount, it had no effect on profit.

Our Estonian wind farms' Q3 implied captured electricity price including support increased by 103% year on year, rising to 270.7 €/MWh. The figure includes the effect of fixed-price PPAs. The implied captured Q3 electricity price of our Lithuanian wind farms increased by 11%, rising to 87.6 €/MWh.

Total revenues

High market prices of electricity boosted the revenue of the Wind energy segment, increasing it by 35% year on year to €32m.

* (Total electricity revenues - balancing energy purchase + renewable energy support)/production

Wind energy segment

Operating expenses

The operating expenses of the Wind energy segment (excluding D&A) grew by €3.6m to €8.6m. Growth was attributable to expenses on balancing energy purchases, which increased due to a higher electricity price, and the change in the accounting for intraday NP transactions made to balance the electricity portfolio: the effect on growth in operating expenses was €3.2m. Other operating expenses (excluding growth in expenses on balancing energy, the change in the accounting for intraday NP transactions and D&A) grew by €0.4m year on year.

Operating expenses per MW

In Q3 2022, our wind farm operators' (Enefit Wind OÜ and Enefit Wind UAB) operating expenses (excluding D&A and balancing energy purchases) per installed capacity (MW) increased by 1.4% year on year. Cost savings derived from new maintenance contracts counterbalanced natural indexation-related growth in maintenance expenses.

EBITDA

The EBITDA of the Wind energy segment was €23.6m compared with €18.9m a year earlier. Growth was mainly underpinned by high electricity prices.

*(Total operating expenses - balancing energy purchase - D&A) / operating capacity. Only operating wind assets are included: Enefit Wind OÜ and Enefit Wind UAB

Cogeneration segment

29% Share of EBITDA Q3 2022

Enefit Green Q3 2022 interim report 18

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

Electricity production and prices

The Cogeneration segment's electricity production in Q3 2022 was 28.4 GWh, which is 30% lower than a year earlier (Q3 2021: 40.6 GWh). The sharp decline in electricity production resulted from a nearly fiveweek unplanned production interruption and related repairs at the Iru CHP. In addition to the market price of electricity, the Iru and Paide CHP facilities receive renewable energy support of 53.7 €/MWh for electricity produced from renewable sources and efficient cogeneration support of 32 €/MWh for electricity produced from non-renewable sources in efficient cogeneration mode. The Valka CHP has been assigned a fixed electricity price of 79.75 €/MWh as of end of August 2022. The Broceni CHP facility lost its fixed electricity price of 143.6 €/MWh retrospectively from March 2021 due to the decision of the BVKB made in October 2021. Enefit Green's subsidiary SIA Technological Solutions has challenged the BVKB's decision in court. In June the court ruled against SIA Technological Solutions but in July SIA Technological Solutions filed an appeal and the dispute continues. From November 2021 until the final ruling on the matter is made, the Broceni CHP facility will sell electricity at the prices of the NP Latvia price area.

Our cogeneration facilities' availability in Q3 was low (72.9%) and significantly weaker than in Q3 2021 (98.8%). The underlying factor was the unplanned production interruption at the Iru CHP.

Supported by high market prices in the NP Estonia and NP Latvia price area, the segment's Q3 average implied captured electricity price grew by 146% year on year, rising to 327 €/MW.

Heat energy production and prices

Heat production decreased substantially (by 32%) due to the unplanned production interruption at the Iru CHP.

In Q3 2022, the average sales price of heat per MWh increased by 23% year on year, rising to around 13 €/MWh. The price cap for heat produced by the Iru CHP was the same in the reporting and the comparative period, i.e. 7.98 €/MWh, while the price of heat produced by the Paide and Valka CHPs grew considerably due to an increase in the cost of biomass used.

Total revenues

The segment's total revenues grew year on year, rising to €20.6m. Revenue from gate fees decreased due to a decline in waste received by €1.2m to €2.2m, heat sales revenue decreased due to smaller output by €0.3m to €0.7m and other revenue decreased by €0.1m to €0.4m. Electricity sales revenue grew by €5.1m to €9.4m, driven by high market prices and the cessation of the offsetting of intraday NP transactions. Electricity production support decreased by €0.5m year on year, dropping to €0.7m. However, pellet sales revenue for the period grew by €6.7m to €7.2m because pellet sales were 39k tonnes compared with 4k tonnes in the same period last year. The strong increase is attributable to a change in the timing of supplies compared with a year earlier.

* (Total electricity revenues - balancing energy purchase + renewable energy support)/production

Cogeneration segment

Operating expenses

The change in pellet inventories (finished goods) reduced operating expenses for the reporting period by €1.9m. The segment's variable costs grew by €5.5m, rising from €4.6m to €10.2m. Although electricity production decreased, pellet production grew by 6% (from 37k tonnes to 39k tonnes) year on year. Also, the prices of raw materials and supplies as well as electricity purchased increased significantly. Fixed costs remained similar to a year earlier, increasing from €2.8m to €2.9m (+4%).

EBITDA

The segment's Q3 EBITDA grew by 31% year on year, rising by €2.3m to €9.5m. Growth was mainly underpinned by an increase in the EBITDA of the Broceni CHP due to a higher market price of electricity and the EBITDA of pellet production operations. The segment's EBITDA was adversely affected by the unplanned production interruption and related repairs at the Iru CHP, which lasted for nearly five weeks.

Solar energy segment

Electricity production, GWh

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

Production

The Solar energy segment produced 11.4 GWh of solar power in Q3 2022, 2.8 GWh (32%) more than in Q3 2021. Sunny weather increased solar energy production in both Estonia and Poland.

Electricity prices

Our solar farms in Estonia are partly exposed to movements in the market price of electricity. Our solar farms in Poland sell electricity at fixed prices which are adjusted for inflation on an annual basis – the price for Q3 2022 was 430–460 PLN/MWh (92–99 €/MWh at the three-month average zloty (PLN) exchange rate).

Total revenues

The total revenues of operating solar farms grew by €1.0m, supported by a larger sales volume and a higher average sales price. The Q3 revenue from solar services was €5.4m due to inventory sales.

The Solar energy segment's EBITDA for Q3 2022 was €1.5m, €0.8m up on a year earlier. EBITDA grew mainly through growth in the production of solar energy and Enefit Green Q3 2022 interim report 20

Availabilities of solar farms (%)

+61.4 (+56.8%) Implied captured electricity price, €/MWh (1)

* (Total electricity revenues - balancing energy purchase + renewable energy support)/production

+5.8 (+404.4%) Total revenues, €m

7.3

higher electricity prices in Estonia.

EBITDA

0.9

1.4

Investments

Investments during Q3

The group's Q3 capital expenditures grew by €71.6m year on year, rising to €79.7m. Growth resulted from development investments, which extended to €78.9m. Out of the total, €33.5m was invested in the construction of three wind farms: €19.2m in the Šilale 2 wind farm, €8.7m in the Akmene wind farm and €5.6m in the Tolpanvaara wind farm. In addition, Enefit Green acquired the Tootsi wind farm development from Eesti Energia for €26.9m. The largest expenditures on solar power were investments of €2.7m in the execution phase of the Purtse solar farm and €2.9m in the Zambrow solar farm. Additionally, Enefit Green AS acquired Rääbiste Põllud OÜ (which has been renamed Enefit Green Solar OÜ) for €6.6m, which is developing two large solar farms in Western Estonia. Base investments amounted to €0.9m in Q3 2022 compared with €0.2m in the same period last year and were mainly made in the cogeneration plants to ensure their availability during the upcoming heating period. Base investments in wind farms may differ significantly quarter by quarter because they depend on the wind turbines' repair and maintenance needs during the period.

Financing

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

The amortised cost of the group's interest-bearing and debt-like liabilities at 30 September 2022 was €279.4m (31 December 2021: €123.5m). Bank loans accounted for €274.9m of the total, including an outstanding loan balance of €6.8m denominated in Polish zloty.

In Q3 2022, Enefit Green drew down two previously raised investment loans of €130m in total, which mature in September 2026 and January 2034. Enefit Green has signed interest rate swap agreements in respect of investment loans of €170m in total, fixing their interest rates in the range of 1.049% to 1.125% until the underlying loans mature.

Enefit Green has signed three revolving credit facility agreements of €50m in total, which mature in the period 2024–2026 (all credit limits were undrawn at 30 September 2022).

The average interest rate of bank loans drawn down at 30 September 2022 was 1.96% (31 December 2021: 1.17%).

Loan covenants

The group's loan and credit agreements include covenants which set certain limits to the group's consolidated financial indicators. At 30 September 2022, the group was in compliance with all loan terms and conditions, including the covenants.

Liquidity development in Q3 2022, €m

Financing and return ratios

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

€ million	31 Dec 2021	30 Sep 2022
Debt and debt-like items	123.5	279.4
Minus cash and cash equivalents	(80.5)	-163.7
Net debt	43.0	115.7
Equity	633.6	680.5
Invested capital	676.6	796.3
EBITDA (LTM)*	121.5	158.6
Operating profit (LTM)	83.3	120.1
Net profit (LTM)	79.7	114.2

Financial leverage (1)	6%	15%
Net debt/LTM EBITDA	0.35	0.73
Return on invested capital (2)	12.3%	15.1%
Return on equity (3)	12.6%	16.8%
* LTM – last twelve months (1) Financial leverage = net debt / (net debt + equity)

(2) Return on invested capital = LTM operating profit /

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

Net debt/EBITDA Financial leverage

10%

15%

20%

Risk management

The group has identified two main market and financial risks that require active management:

Price risk of electricity sales, which is mitigated by a combination of:

o various kinds of national renewable energy support (FiT, CfD and FIP schemes) received by the group's existing production assets; and
o power purchase agreements (PPAs), which are being signed in increasing volumes. The group has set itself the goal that by the date a final investment decision on a new development project is made the price of electricity sold should be fixed for at least 60% of the project's forecast output for the first five years.
o A more detailed overview of the measures is provided in the group's annual report for 2021. The graph below provides an overview of the next few years' forecast production volumes and their coverage with risk mitigation measures as at 31 October 2022.
o The total volume of PPAs signed is 9,951 GWh at the average price fixed in PPAs is 72.5 €/MWh.
o During the period from July 2022 to October 2022, we signed new PPAs with terms of up to 10 years in the volume of 3,126 GWh at an average price of 124.4 €/MWh.
o Out of electricity produced after 2026, 4,709 GWh is covered with PPAs at an average price of 75.0 €/MWh.

Interest rate risk

o The group's interest rate risk management has changed compared with the previous financial year-end in connection with the conclusion of interest rate swap (IRS) agreements at the end of March and in April 2022.
o Interest rate risk is the risk that the fair value or future cash flows of financial instruments will fluctuate because of changes in market interest rates. Cash flow interest rate risk arises from the group's floating-rate borrowings and is the risk that finance costs will grow when interest rates increase.
o Interest rate risk is mitigated partly by raising debt at fixed interest rates and partly by hedging: fixing the interest expenses of floating-rate borrowings raised with IRS instruments. Information on IRS transactions is disclosed in note 5.

	2022	2023	2024	2025	2026	2022-2026 total
Share of production covered by FiT/CfD		5%	3%	2%	1%	5%
Volume (GWh)		71	71	71	64	600
FiT/CfD weighted average price, EUR/MWh	323 85.4	110.5	110.8	111.5	109.1	97.0

Share of production covered by FiP	42%	31%	22%	8%	2%	14%
Volume (GWh)	497	473	501	268	99	1,837
FiP weighted average price, EUR/MWh (added to the market price)	50.4	50.0	50.2	50.6	53.7	50.5

Share of production covered by PPAs	13%	63%	57%	44%	30%	41%
Volume (GWh)	158	953	1,300	1,415	1,416	5,242
PPA weighted average price, EUR/MWh	112.8	86.9	67.3	63.7	63.7	70.3

Share and shareholders*

At 30 September 2022, the number of the registered shares of Enefit Green AS was 264,276,232 (30 September 2021: 229,793,473 shares). The par value of each share is €1. During the previous year the number of shares has changed due to a bonus issue in August 2021 (225 000 000 shares were issued) and due to the IPO in October 2021 (34,482,527 shares were issued).

Since 21 October 21 2021, Enefit Green's shares are listed on the main list of the Nasdaq Tallinn Stock Exchange (trading symbol: EGR1T, ISIN: EE3100137985).

Since the IPO, the share of retail investors and Baltic pension funds has increased. At 30 September 2022, the number of shareholders exceeded 59,800 (ca. 59,000 at the end of 2021).

Largest shareholders	Ownership %
Eesti Energia AS	77.2%
Swedbank's Baltic pension funds	1.9%
EBRD	1.5%
Government of Norway	0.6%
SEB Baltic pension funds	0.5%
Säästöpankki Korko Plus	0.5%
Other institutional investors	2.7%
Retail investors (over 59 800 accounts)	15.1%
Total	100.0%

* as at 30 September 2022

Shareholders as at 30 Sep 2022

Enefit Green share price*

* Enefit Green share price and total return are shown on dividend adjusted basis. Data since IPO to 30 Sep 2022. Source: Bloomberg

Condensed consolidated interim financial statements Q3 2022

Condensed consolidated interim income statement

€ thousand	Note	Q3 2022	Q3 2021	9M 2022
Revenue	9	57,254	30,133	156,900
Renewable energy support and other income	10	3,011	6,257	17,363
Change in inventories of finished goods and work in progress		2,028	3702	4,607
Raw materials, consumables and services used	11	(24,969)	(11,097)	(55,468)
Payroll expenses		(2,029)	(1,626))	(6,641)
Depreciation, amortisation and impairment		(9,637)	(9,467)	(28,930)
Other operating expenses		(2,574)	(1,867))	(7,721)
OPERATING PROFIT		23,084	16,037	80,110
Finance income		817	1	1,703
Finance costs		(1,072)	(516)	(2,261)
Net finance costs		(255)	(515)	(558)
Profit (loss) from associates under the equity method		120	46	687
PROFIT BEFORE TAX		22,949	15 567	80,239
Corporate income tax expense		-	(308)	(5,441)
PROFIT FOR THE PERIOD		22,949	15,259	74,798
Basic and diluted earnings per share
Weighted average number of shares, thousand	6	264,276	78,163	264,276
Basic earnings per share, €	6	0.09	0.20	0.28
Diluted earnings per share, €	6	0.09	0.20	0.28
Basic earnings per share based on post-IPO number of shares
Post-IPO number of shares, thousand	6	264,276	264,276	264,276
Basic earnings per share, €	6	0.09	0.06	0.28

Condensed consolidated statement of other comprehensive income

€ thousand	Note	Q3 2022	Q3 2021	9M 2022
PROFIT FOR THE PERIOD		22,949	15,259	74,798
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Revaluation of hedging instruments in a cash flow hedge	5, 7	7,193	(9,446)	13,717
Exchange differences on the translation of foreign operations	7	(436)	(280)	(680)
Other comprehensive income (loss) for the period		6,757	(9,726)	13,037

TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		29,706	5,533	87,835

Condensed consolidated interim statement of financial position

€ thousand	Note	30 Sep 2022	31 Dec 2021
ASSETS
Non-current assets
Property, plant and equipment	4	714,715	612,503
Intangible assets		72,550	68,239
Right-of-use assets		4,225	2,750
Prepayments	4	18,798	20,710
Deferred tax assets		734	442
Investments in associates		479	578
Derivative financial instruments	5, 7	11,519	-
Long-term receivables		40	78
Total non-current assets		823,060	705,300

Current assets
Inventories		15,343	9,529
Trade and other receivables and prepayments		22,250	22,373
Cash and cash equivalents		163,711	80,454
Derivative financial instruments	5	2,198	-
Total current assets		203,502	112,356
Total assets		1,026,562	817,656

€ thousand	Note	30 Sep 2022	31 Dec 2021
EQUITY
Equity and reserves attributable to equity holders of the parent
Share capital		264,276	264,276
Share premium	6	60,351	60,351
Statutory capital reserve		3,259	479
Other reserves	5, 7	165,510	151,793
Foreign currency translation reserve	7	(1,645)	(965)
Retained earnings		189,785	157,673
Total equity		681,536	633,607

LIABILITIES
Non-current liabilities
Borrowings	8	249,716	93,884
Government grants		7,209	7,458
Non-derivative contract liability	5, 7	23,207	23,207
Deferred tax liabilities		12,355	12,568
Other non-current liabilities		3,000	3,000
Provisions		11	13
Total non-current liabilities		295,498	140,130
Current liabilities
Borrowings	8	29,733	29,572
Trade and other payables		19,769	14,291
Provisions		26	56
Derivative financial instruments	5	-	-
Total current liabilities		49,528	43,919
Total liabilities		345,026	184,049
Total equity and liabilities		1,026,562	817,656

Condensed consolidated interim statement of cash flows

€ thousand	Note	Q3 2022	Q3 2021	9M 2022
Cash flows from operating activities
Cash generated from operations	12	36,827	25,163	105,742

Interest and loan fees paid		(845)	(783)	(1,842)
Interest received		6	-	12
Corporate income tax paid		(4,716)	(330)	(6,217)
Net cash generated from operating activities		31,272	24,050	97,695

Cash flows from investing activities
Purchase of property, plant and equipment and intangible assets	4	(82,902)	(8,936)	(129,950)
Proceeds from sale of property, plant and equipment		-	-	3
Proceeds from sale of a business		5	-	724
Dividends received on other investments		62	68	62
Net cash used in investing activities		(82,834)	(8,868)	(129,161)

Cash flows from financing activities
Change in overdraft (net)		-	-	-
Bank loans received	8	130,000	-	170,000
Repayments of bank loans	8	(5,476)	(12,143)	(15,146)
Repayments of lease liabilities	8	(134)	(44)	(263)
Dividends paid		-	-	(39,906)
Net change in an intragroup liability		38	-	38
Net cash generated from (used in) financing activities		124,428	(12,187)	114,723

Net cash flow		72,866	2,995	83,257

Cash and cash equivalents at the beginning of the period		90,845	11,140	80,454
Cash and cash equivalents at the end of the period		163,711	14,135	163,711
Increase in cash and cash equivalents		72,866	2,995	83,257

9M 2021	9M 2022

73,252	105,742

(2,361)	(1,842)
24	12
(724)	(6,217)
70,191	97,695

(51,874)	(129,950)
23	3
	724
68	62
(51,784)	(129,161)


33,312
10,000	170,000
(31,105)	(15,146)
(154)	(263)
(27,100)	(39,906)
	38
(15,047)	114,723

3,361	83,257
10,774	80,454
14,135	163,711
3,361	83,257

Condensed consolidated interim statement of changes in equity

€ thousand	Share capital	Share premium	Statutory capital reserve	Other reserves	Foreign currency translation reserve	Retained earnings	Total equity
Equity as at 31 December 2020	4,794	-	479	400,000	(834)	105,111	509,550
Profit for the period	-	-	-	-	-	40,291	40,291
Other comprehensive loss for the period	-	-	-	(12,426)	(188)	-	(12,614)
Total comprehensive income for the period	-	-	-	(12,426)	(188)	40,291	27,677
Increase of share capital	225,000	-	-	(225,000)	-	-	-
Fair value on initial recognition of a derivative financial instruments transaction conducted with the parent	-	-	-	(10,781)	-	-	(10,781)
Dividends paid	-	-	-	-	-	(27,100)	(27,100)
Total contributions by and distributions to owners of the company, recognised directly in equity	225,000	-	-	(235,781)	-	(27,100)	(37,881)
Equity as at 30 September 2021	229,794	-	479	151,793	(1,022)	118,303	499,346

Equity as at 31 December 2021	264,276	60,351	479	151,793	(965)	157,673	633,607

Profit for the period	-	-	-	-	-	74,798	74,798
Other comprehensive income for the period	-	-	-	13,717	(680)	-	13,037
Total comprehensive income for the period	-	-	-	13,717	(680)	74,798	87,835
Increase of statutory capital reserve	-	-	2,780	-	-	(2,780)	-
Dividends paid	-	-	-	-	-	(39,906)	(39,906)
Total contributions by and distributions to owners of the company, recognised directly in equity	-	-	2,780	-	-	(42,686)	(39,906)
Equity as at 30 September 2022	264,276	60,351	3,259	165,510	(1,645)	189,785	681,536

Notes to the condensed consolidated interim financial statements

1. Summary of significant accounting policies

These condensed consolidated interim financial statements (interim financial statements) have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting and as they do not include all the notes of the type normally included in an annual financial report they should be read in conjunction with the group's annual financial statements as at and for the year ended 31 December 2021, which have been prepared in accordance with IFRS as adopted by the European Union.

These interim financial statements have been prepared and presented 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 2021.

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 2021.

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 (including 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 2021.

The group's interest rate risk management has changed compared with the previous financial year-end in connection with the conclusion of interest rate swap (IRS) agreements at the end of March 2022. Interest rate risk is the risk that the fair value or future cash flows of financial instruments will fluctuate because of changes in market interest rates. Cash flow interest rate risk arises from the group's floating-rate borrowings and is the risk that finance costs will grow when interest rates increase. Interest rate risk is mitigated partly by raising debt at fixed interest rates and partly by hedging: fixing the interest expenses of floating-rate borrowings raised 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 owners, 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 in the Financing section on page of the management report.

3. Segment reporting

Enefit Green's management assesses the group's financial performance and makes management decisions on the basis of segment reporting where the group's reportable operating segments have been identified by reference to the main business lines of its business units. All production units operated by the group have been divided into operating segments based on the way they produce energy. Other internal structural units have been divided between operating segments based on their core activity.

The group has identified three main business lines, which are presented as separate reportable segments, and less significant business activities and functions, which are presented within Other:

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

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

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

Management assesses segment results mainly on the basis of EBITDA, but also monitors operating profit. Finance income and costs, income tax expense and profits and losses on investments in equity-accounted investees 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.

3. Segment reporting (cont.)

€ thousand	Q3 2022	Q3 2021	9M 2022	9M 2021
REVENUE
Wind energy	29,468	19,155	86,916	46,990
Cogeneration	19,841	9,626	56,722	43,371
Solar energy	7,772	1,222	12,832	2,722
Total reportable segments	57,082	30,003	156,470	93,084
Other	172	130	430	572
Total	57,254	30,133	156,900	93,655
RENEWABLE ENERGY SUPPORT AND OTHER INCOME
Wind energy	2,697	4,694	13,815	16,281
Cogeneration	800	1,333	4,020	4,187
Solar energy	(489)	222	(501)	502
Total reportable segments	3,007	6,250	17,334	20,970
Other	4	7	30	173
Total	3,012	6,257	17,363	21,143
EBITDA
Wind energy	23,530	18,860	78,767	50,092
Cogeneration	9,517	7,238	32,410	23,869
Solar energy	1,525	729	3,351	1,599
Total reportable segments	34,572	26,827	114,528	75,561
Other	(1,851)	(1,324)	(5,488)	(3,673)
Total	32,721	25,503	109,039	71,888
Depreciation, amortisation and impairment losses	9,637	9,467	28,930	28,592
Net finance costs	(255)	(515)	(558)	(1,946)
Profit (loss) from associates under the equity method	(52)	(46)	687	10
Profit before tax	22,881	15,567	78,865	41,340
OPERATING PROFIT
Wind energy	16,707	12,135	58,291	29,731
Cogeneration	7,022	4,695	24,669	16,256
Solar energy	1,302	556	2,672	1,078
Total reportable segments	25,031	17,386	85,632	47,065
Other	(1,910)	(1,350)	(5,599)	(3,769)
Total	23,121	16,037	80,034	43,296

9M 2022	9M 2021

86,916	46,990
56,722	43,371
12,832	2,722
156,470	93,084
430	572
156,900	93,655

13,815	16,281
4,020	4,187
(501)	502
17,334	20,970
30	173
17,363	21,143

78,767	50,092
32,410	23,869
3,351	1,599
114,528	75,561
(5,488)	(3,673)
109,039	71,888
28,930	28,592
(558)	(1,946)
687	10
78,865	41,340

58,291	29,731
24,669	16,256
2,672	1,078
85,632	47,065
(5,599)	(3,769)
750 08	42 296

3. Segment reporting (cont.)

€ thousand	Q3 2022	Q3 2021	9M 2022
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	67,407	7,973	118,367
Cogeneration	322	(11)	935
Solar energy	11,666	88	14,117
Total reportable segments	79,395	8,049	133,419
Other	349	78	986
Total	79,744	8,127	134,404

9M 2021	9M 2022

49,583	118,367
1,597	935
758	14,117
51,938	133,419
163	986
52,101	134,404

€ thousand	30 Sep 2022	31 Dec 2021
NON-CURRENT ASSETS
Wind energy	611,146	535,000
Cogeneration	134,953	141,286
Solar energy	60,484	25,691
Total reportable segments	806,584	701,977
Other	4,958	3,322
Total	811,541	705,300

4. Property, plant and equipment

€ thousand	Land	Buildings	Facilities and structures	Plant and equipment	Assets under construction	Prepayments	Total
Property, plant and equipment as at 31 December 2021
Cost	39,944	25,415	42,067	744,494	33,883	20,710	906,513
Accumulated depreciation		(9,745)	(23,746)	(239,791)	(18)		(273,300)
Total property, plant and equipment as at 31 December 2021	39,944	15,670	18,321	504,703	33,865	20,710	633,213
Movements in the reporting period
Purchases of property, plant and equipment	20,687	(3)	15	410	110,705	(1,753)	130,061
Exchange differences	-	(7)	(8)	(498)	(8)	(4)	(525)
Transfers	23	125	22	5,258	(5,888)	(155)	(615)
Depreciation charge and write-downs	-	(488)	(927)	(27,206)	-	-	(28,621)
Total movements in 9 months	20,710	(373)	(898)	(22,036)	104,809	(1,912)	100,300
Property, plant and equipment as at 30 September 2022
Cost	60,654	25,547	42,072	746,919	138,674	18,798	1,032,664
Accumulated depreciation	-	(10,250)	(24,649)	(264,252)	-	-	(299,151)
Total property, plant and equipment as at 30 September 2022	60,654	15,297	17,423	482,667	138,674	18,798	733,513

At 30 September 2022, the the group had committed to capital expenditures of €140,594k (31 December 2021: €194,691k).

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

Derivatives are initially recognised at fair value on the date a 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. As at 30 September 2022, the group used cash flow hedging instruments in order to hedge the 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 also 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 are 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 income or other operating expenses. The day one fair value of derivative instruments entered into with the parent company is recognised directly in equity when its economic substance is a distribution to the parent of resources embodying economic benefits.

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

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

During 2021 the group used cash flow hedging instruments in order to hedge the exposure to variability in the price of electricity.

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

Transactions designed to hedge the risk of variability in electricity prices are designated as hedging instruments under cash flow hedges. The underlying hedged item is the market price risk of highly probable forecast renewable electricity sales transactions that are exposed to market price fluctuations. The hedge ratio of the hedging relationships is 1:1.

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

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

At the trade date the fair value of derivatives designated as hedging instruments was negative at €(10,781)k, which was recognised directly in equity as it reflected a transaction with the parent, Eesti Energia AS. The balance at 30 September 2022 was €(10,781)k.

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

The group continued to apply hedge accounting to the open derivatives position until 17 August 2021, recognising changes in the fair value of the derivatives until the date of signature of the EFET General Agreement. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k as 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 trade date and 17 August 2021. Since the derivative financial instruments had been measured to fair value by the date of conclusion of the EFET General Agreement, (measurement date 17 August 2021), their value, which has been classified as a liability, will not change before the arrival of the supply period determined in the EFET General Agreement, which is 2023– 2027. The balance at 30 September 2022 was €(12,426)k.

The EFET General Agreement meets the own use exemption and, therefore, is not considered to be a financial instrument that is required to be measured at fair value under IFRS 9. Rather, it is to be accounted for as an executory contract under IFRS 15 Revenue from Contracts with Customers with the revenue being recognised at a fixed per-unit value only when the delivery of electricity takes place in the years 2023–2027. No gains or losses were recognised at the date the derivative contracts were replaced with the EFET General Agreement. Upon entering into the EFET General Agreement, the carrying amount of the derivatives classified as a liability at that date, which was €(23,207)k, was reclassified as a non-derivative liability, which will gradually increase recognised revenue until the EFET General Agreement is fulfilled. Such an increase in revenue will be partially offset by the reclassification of the €(12,426)k accumulated in the electricity cash flow hedge reserve to profit or loss due to the discontinuance of hedge accounting. The amount is the difference between the fair value of the derivative financial instruments as at 17 August 2021 of €(23,207)k and the trade date fair value of the derivatives of €(10,781)k, which is recognised directly in equity. See note 7 for further information.

Interest rate swap transactions

As at 30 September 2022, the group had entered into three interest rate swap agreements to hedge the exposure to the interest rate risk of three loans (no interest rate swaps in the comparative period):

─ An interest rate swap with a notional amount of €80,000k 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 that was drawn down on 30 September 2022.

─ An interest rate swap with a notional amount of €50,000k whereby the group receives interest at a rate equal to 3 month EURIBOR and pays a fixed rate of interest of 1.049%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan that was drawn down on 24 September 2022.

─ An interest rate swap with a notional amount of €40,000k 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 that was drawn down 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 2022 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 1:1. 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 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 effectiveness.

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

At 30 September 2022, the effect of 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	170 000	13 717	-	Derivatives	7 193	-	-91

* Recognised in other comprehensive income

At 30 September 2022, 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	13,717	13,717	-

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 and dividends

Basic earnings per share (EPS) have been calculated by dividing profit for the period attributable to owners 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.

The company's number of shares changed significantly during the year due to both a bonus issue and the sale of new shares. Therefore, in addition to presenting EPS consistent with IFRS requirements as described above, it may be informative to analyse EPS calculated based on the number of shares outstanding at the end of the reporting period.

The figure is an alternative performance measure (APM), which is not defined in IFRS and may not be comparable with the APMs of other companies. The group believes that APMs provide the readers of the consolidated financial statements with additional useful information about the group's financial performance. The APMs should be viewed as supplemental to, and not as a substitute for, the measures presented in the consolidated financial statements in accordance with IFRS.

Dividends

According to the decision of the group's general meeting of shareholders, dividends of €39,906k (0,151 euros per share) were paid out on 8 June 8 2022.

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

	Unit	Q3 2022	Q3 2021	9M 2022	9M 2021
Profit attributable to owners of the parent	€ thousand	22,949	15,259	74,798	40,291

Weighted average number of shares	thousand	264,276	78,163	264,276	25,519
Basic earnings per share	€	0.09	0.20	0.28	1.36
Diluted earnings per share	€	0.09	0.20	0.28	1.36

9M 2022	9M 2024
74,798	40,291
264,276	25,519
0.28	1.36
0.28	1.36

Basic earnings per share based on post-IPO number of shares

	Unit	Q3 2022	Q3 2021	9M 2022	9M 2021
Post-IPO number of shares	thousand	264,276	264,276	264,276	264,276
Basic earnings per share	€	0.09	0.06	0.28	0.15

7. Other reserves

€ thousand	30 Sep 2022	31 Dec 2021
Other reserves at the beginning of the period	150,828	399,165
of which currency translation reserve	(965)	(835)
of which electricity cash flow hedge reserve	(12,426)	-
of which fair value on initial recognition of a derivative financial instruments transaction conducted with the parent	(10,781)	-
of which other reserves	175,000	400,000
Increase of share capital through a bonus issue	-	(225,000)
Change in fair value of cash flow hedges	-	(12,426)
of which electricity cash flow hedges	-	(12,426)
Fair value on initial recognition of a derivative financial instruments transaction conducted with the parent	-	(10,781)
Interest rate swap transactions	13,717	-
Currency translation differences attributable to foreign subsidiaries	(680)	(130)
Other reserves at the end of the period	163,865	150,828
of which currency translation reserve at the beginning of the period	(1,645)	(965)
of which interest rate swap transactions	13,717	-
of which electricity cash flow hedge reserve	(12,426)	(12,426)
of which fair value on initial recognition of a derivative financial instruments transaction conducted with the parent	(10,781)	(10,781)
of which other reserves	175,000	175,000

8. Borrowings at amortised cost

		Short-term borrowings	Long-term borrowings
€ thousand	Bank loans	Lease liabilities	Bank loans	Lease liabilities	Total
Borrowings at amortised cost as at 31 December 2021	29,348	224	91,049	2,835	123,456

Movements in the reporting period
Monetary movements
Borrowings received	-	-	170,000	-	170,000
Repayments of borrowings	(15,146)	(263)	-	-	(15,409)
Non-monetary movements
Initial recognition of a lease liability	-	86	-	1,694	1,780
Transfers	15,432	87	(15,432)	(87)	-
Other movements	(37)	2	(338)	(5)	(378)
Total movements in 9 months 2022	249	(88)	154,230	1,602	155,993

Borrowings at amortised cost as at 30 September 2022	29,597	136	245,279	4,437	279,449

"Transfers" reflects the change in the short-term portion of loan principal due to a change in the repayment schedule.

9. Revenue

€ thousand	Q3 2022	Q3 2021
Revenue by activity
Sale of goods
Pellets	7,208	493
Scrap metal	116	254
Other goods	3,259	35
Total sale of goods	10,583	781

Sale of services
Heat	750	1,040
Electricity	41,335	24,290
Waste reception and resale	2,152	3,404
Rental and maintenance of assets	2,379	669
Other services	55	(51)
Total sale of services	46,671	29,352
Total revenue	57,254	30,133

9M 2022	9M 2021


16,616	14,990
756	786
3,357	152
20,729	15,927


4,672	5,068
115,205	59,518
10,390	11,459
5,623	1,628
281	55
136,171	77,728
156,900	93,655

10. Renewable energy support and other income

€ thousand	Q3 2022	Q3 2021
Renewable energy support	2,855	6,140
Government grants	135	135
Other income	21	(18)
Total renewable energy support and other income	3,011	6,257

9M 2022	9M 2021
16,751	20,591
341	406
271	146
17,363	21,143

11. Raw materials, consumables and services used

€ thousand	Q3 2022	Q3 2021	9M 2022
Maintenance and repairs	4,556	4,486	11,357
Technological fuel	5,822	2,704	14,805
Electricity	7,928	2,150	16,917
Services related to ash treatment	279	574	1,635
Transport services for sale of finished goods	450	284	1,261
Materials and spare parts for production	5,682	430	8,671
Transmission services	85	269	205
Waste handling	63	101	247
Resource charges for natural resources	2	2	6
Other raw materials, consumables and services used	67	38	177
Environmental pollution charges	35	57	187
Total raw materials, consumables and services used	24,969	11,097	55,468

9M 2022	9M 2021
11,357	11,732
14,805	8,168
16,917	4,708
1,635	1,937
1,261	1,285
8,671	1,287
205	458
247	285
6	5
177	120
187	204
55,468	30,189

12. Cash generated from operations

€ thousand	Q3 2022	Q3 2021
Profit before tax	22,949	15,567
Adjustments
Depreciation and impairment of property, plant and equipment	9,580	9,442
Amortisation and impairment of intangible assets	57	25
Amortisation of government grants received to purchase non current assets	(135)	(135)
Interest expense on borrowings	501	691
Gain on disposal of a business	(5)	-
Profit (loss) from associates under the equity method	(52)	(47)
Gain on disposal of property, plant and equipment	-	-
Interest and other finance income	(6)	-
Foreign exchange gain on loans granted and received	(229)	(174)
Adjusted profit before tax	32,660	25,369
Net change in current assets related to operating activities
Change in receivables related to operating activities	4,137	(2,363)
Change in inventories	923	(4,659)
Net change in other current assets related to operating activities	(3,097)	4,926
Total net change in current assets related to operating activities	1,963	(2,097)
Net change in liabilities related to operating activities
Change in provisions	(30)	7
Change in trade payables	(428)	589
Net change in liabilities related to other operating activities	2,662	1,295
Total net change in liabilities related to operating activities	2,204	1,891
Cash generated from operations	36,827	25,163

13. Transactions and balances with related parties

The parent of Enefit Green AS is Eesti Energia AS. At 30 September 2022, the sole shareholder of Eesti Energia AS was the Republic of Estonia.

For the purposes of the condensed consolidated financial statements of Enefit Green, related parties include the owners, 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.

€ thousand	Q3 2022	Q3 2021	9M 2022	9M 2021	€ thousand	30 Sep 2022
TRANSACTIONS					BALANCES
WITH PARENT
Purchase of services	4,211	2,181	9,570	5,134	Receivables	2,886
Sale of goods				3	Payables	24,215
Sale of services	6,221	1,585	12,820	3,275	Of which non-derivative contract liability	23,207
WITH OTHER GROUP COMPANIES
Purchase of goods	-	3	8	3	Receivables	467
Purchase of services	2,528	635	4,544	1,347	Payables	887
Proceeds from sale of goods	3,205	7	3,205	59
Proceeds from sale of services	3,527	784	7,528	1,753
WITH OTHER RELATED PARTIES (INCLUDING ASSOCIATES)
Purchase of services	507	468	1,249	1,430	Receivables	-
Proceeds from sale of services	-	-	2	-	Payables	461
WITH ELERING AS
Purchase of services	59	62	172	258	Receivables	980
Sale of services	3,619	6,047	17,947	20,742	Payables	25

The original negative fair value of the derivative financial liability of €(10,780.1)k has been recognised directly in equity. The subsequent cumulative negative change in the fair value of the derivative financial liability of €(12,426)k has been recognised in other comprehensive income and the cash flow hedge reserve in equity (see also notes 5 and 7).

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

As at 31 October 2022, Enefit Green AS had signed long-term physical electricity sales contracts of 8,686 GWh with Eesti Energia AS for the supply of electricity in the Lithuanian, Estonian, Finnish and Polish electricity networks in the period 2023–2033. The contracts are for the supply of both annual and monthly baseload energy. The weighted average price of the physical electricity sales contracts signed with the related party is 69.5 €/MWh.

contract liability	23,207	23,207

AI Terminal

Enefit Green

2216_ir_2022-11-03_fba93a26-2add-43f0-8ebc-1c43c0effb51.pdf

Q3 2022 Unaudited Interim Report

Enefit Green

Contents

Letter from the Chairman of the Management Board

Dear reader

Target: 4× growth in production capacity

Projects under construction

Near term development portfolio

Complete view of the development portfolio

3Q 2022 Key highlights

Operating environment

Key factors influencing the operating environment

Wind conditions

Electricity market

Estonian weekly average electricity price, €/MWh

Regulatory environment

Significant events

We laid the cornerstones for four wind farms

We acquired solar farm developments with a capacity of up to 200 MW

We signed new long-term PPAs in Lithuania

Litigation involving the Purtse wind farm development

We conducted a rescue exercise at our Aseriaru wind farm

We implemented a VR solution in the development of wind farms

Outage at the Iru facility

Financial results of the group

Production

Revenue

Renewable energy support and other income

Financial results of the group

Raw materials, consumables and services used

Payroll expenses

Group's EBITDA development by drivers, €m

Other operating expenses

Change in inventories

Depreciation, amortisation and impairment losses (D&A)

Variable costs

Fixed costs

Financial results of the group

Net finance costs

Income tax

Net profit

Financial results by segments

Revenues €60.3m +66% EBITDA €32.7m +28% Net profit €22.9m +50%

Group's EBITDA breakdown and change, €m

Wind energy segment

Availability and production

Electricity prices

Total revenues

Wind energy segment

Operating expenses

Operating expenses per MW

EBITDA

Cogeneration segment

Electricity production and prices

Heat energy production and prices

Total revenues

Cogeneration segment

Operating expenses

EBITDA

Solar energy segment

Production

Electricity prices

Total revenues

Availabilities of solar farms (%)

Investments

Investments during Q3

Financing

Loan covenants

Financing and return ratios

Risk management

Interest rate risk

Share and shareholders*

Shareholders as at 30 Sep 2022

Enefit Green share price*

Condensed consolidated interim financial statements Q3 2022

Condensed consolidated interim income statement

Condensed consolidated statement of other comprehensive income