Q1 2023 Unaudited Interim Report

Enefit Green

By 2026 we aim to be the largest renewable energy producer in the Baltics and a fast growing one in Poland

Over 20 years renewableenergy experience	Largest wind energy producer in Baltic countries	186 employees in Estonia, Latvia, Lithuaniaand Poland
Production 2022 1.12 TWh (El) 565 GWh (Heat)	2022 operatingrevenue €257.0m EBITDA €154.8m Net profit€110.2m	60 000 ~ investors

2	Enefit Green at a glance
4	Letter from the Chairman of the Management Board
5	Strategy and development portfolio
9	1Q key highlights
10	Operating environment
13	Significant events
14	Financial results of the group
18	Wind energy segment
20	Cogeneration segment
22	Solar energy segment
23	Investments
24	Financing
25	Risk management
26	Condensed consolidated interim financial statements
32	Notes to the condensed consolidated interim financial statements
48	Group structure

Letter from the Chairman of the Management Board

Dear reader

The beginning of 2023 brought relief from exorbitant energy prices. Electricity prices dropped, mainly due to wind conditions that favoured the production of renewable energy but also due to warmer temperatures and higher hydropower output. Other contributing factors were lower natural gas prices and the Olkiluoto-3 nuclear reactor coming online.

It is important to note, however, that a more favourable level of electricity prices does not mean that the energy crisis is over. Electricity prices may again soar to excessive heights during the next winter, because we are still dependent on uncertain and expensive fossil fuel supplies. European countries are investing in renewable energy as a viable long-term solution. Supported by rapidly advancing wind, solar and energy storage technologies, the quantity and relative importance of green energy in the Baltic Sea region will grow significantly by the end of the decade.

The European Union has increased its renewable energy target for 2030 from 32% to 42.5% of the total energy mix. Estonia has set itself an even more ambitious target and is planning to cover its entire annual energy consumption in 2030 with renewable energy. The European Commission has unveiled its proposals for the redesign of the electricity market according to which the regulation is going to support buying electricity under long-term power purchase contracts and permit paying public support only via two-way contracts for difference that have both a price ceiling and floor. The Baltic countries have been taking measures to free the network resource from reservations of connection capacity.

Enefit Green has a clear roadmap for increasing the total capacity of its production assets across its main markets fourfold in the coming years. We invested nearly €92m in Q1 and continued development activities to expand our renewable power production. We are currently building six wind farms in Estonia, Finland and Lithuania (with a total capacity of 549 MW) and four solar farms in Estonia and Poland (with a total capacity of 50 MW).

Excellent cooperation between our team and the teams of our partners has enabled us to remain in the planned timeframe. In the unique Purtse hybrid farm, all five wind generators have been installed and have already started limited-scale electricity production. The work on the solar farm part is on schedule and the Akmene wind farm in Lithuania has also come online and supplied its first electricity.

The development of Estonia's largest wind farm, Sopi-Tootsi, in the northern part of Pärnu county is on track too. We have signed an agreement with the local authority that sees renewable energy as an opportunity to develop local life. Land improvement for the construction of roads and crane operation sites is under way. Pre-construction activities in the area of the Kelme I wind farm in Lithuania have also been successfully launched.

The development of offshore wind energy will play a decisive role in the coming years. The production of offshore wind power is more stable and just 50 offshore wind turbines could generate half of the electricity currently consumed in Estonia. We acquired the Gulf of Riga offshore wind farm development project from Eesti Energia and will continue the development activities with the goal of launching large-scale renewable electricity production before 2030. It is one of the most advanced offshore wind projects in the Baltics that has reached the phase of research required for the environmental impact assessment and preliminary analysis of the technical solution of the wind farm.

Enefit Green produced 406 GWh (+10%) of electricity in Q1. Although the wind conditions in January and February were less favourable than in the same period last year, our three new wind farms in Lithuania and Estonia, which have started partial production, made a considerable contribution to the total output. The availability of our wind farms was also higher than in the comparative period.

The group's Q1 total operating income was approximately €78m (+16%), EBITDA was around €41m (-10%) and net profit was around €31m (-13%). EBITDA and net profit decreased year on year due to lower market prices of electricity and electricity purchase costs incurred to balance the PPA portfolio.

We will continue implementing the growth plans announced a year ago in Q2. Our team is committed to making sure that the projects under construction are on track, all planned investments decisions are made, and our existing production assets produce the maximum amount of energy. Our purpose is to increase the supply of green energy for everyone's benefit.

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

Enefit Green Q1 2023 interim report 5

										Enefit Green Q1 2023 interim report	6
	Projects under construction					546 MW				50 MW
Operating capacity Under construction		75MW	9MW	72MW	21MW	6MW	32MW	3MW	80MW	255MW	1,053MW 596MW
457MW	43MW							715MW			457MW
Operating capacity 1Q 2023	Šilale II	Akmene	Zambrow PV	Tolpanvaara	Purtse	Debnik PV	Purtse PV	Estonia PV	Kelme I	Sopi-Tootsi	Operating capacity + under
Country											construction
Final Investment Decision	2Q 21	3Q 21	3Q 21	4Q 21	1Q 22	1Q 22	2Q 22	4Q 22	4Q 22	4Q 22
First electricity / % in testing phase	92% (11/12)	64% (9/14)	100%	3Q 23	100%	3Q 23	100%	4Q 23	4Q 24	1Q 25
COD * COD – Commercial	3Q 23 Operating Date	2Q 23	3Q 23	1Q 24	2Q 23	4Q 23	4Q 23	1Q 24	1Q 25	2Q 25

** On 2May 2023 there was an incident in Akmene wind farm resulting in a destruction of a wind turbine (see stock exchange announcement). The circumstances and causes of the incident and effect on timing of COD are being investigated.

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 30 April 2023

Complete view of the development portfolio

NB! Development projects are in continuous change.

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

1Q 2023 Key highlights

(up to 1GW capacity)

+38 GWh (electricity production from new wind farms under construction)

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

Operating environment

Key factors influencing the operating environment

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

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

Average electricity price (€/MWh)	1Q 2023	1Q 2022	Change
Estonia	99.4	133.4	(25.5)%
Latvia	100.0	139.7	(28.4)%
Lithuania	101.7	141.4	(28.1)%
Poland	130.9	135.4	(3.3)%
Finland	77.6	91.7	(15.4)%
Norway	79.0	85.9	(8.0)%
Denmark	103.1	152.6	(32.4)%
Sweden	68.0	65.2	4.2%

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 base load electricity price is determined by renewable power that has practically zero variable costs.

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 have decreased in recent months due to a combination of various factors such as lower natural gas prices, warmer and windier weather, higher hydropower production in the neighbouring countries and the coming online of the long-awaited Finnish Olkiluoto-3 nuclear reactor.

During peak hours, the electricity price in the region is typically determined by gas-fired power plants. As gas prices declined, peak hour electricity prices in Q1 2023 were lower than a year earlier. The average daily electricity price in Nord Pool Estonia market area in Q1 was the highest on 23 January, when it was 173.4 €/MWh (-75.4 €/MWh compared with Q1 2022) and the lowest on 15 January, when it was 17.9 €/MWh (a decrease of 6.3 €/MWh compared with Q1 2022). The average price of natural gas on the Dutch gas trading platform TTF was 50.6 €/MWh in Q1 2023 (50.8 €/MWh, 50.1% compared with Q1 2022). The steep fall in the price of natural gas is mainly attributable to relatively warm and windy weather, which reduced natural gas consumption and increased wind power production, as well as the levels of natural gas inventories in Europe, which are significantly higher than in previous years.

The average CO² emission allowance price in Q1 2023 was 89.9 €/t, which is 8% (+6.7 €/t) higher than a year earlier. At the beginning of Q1, the allowance price continued rising due to higher coal power generation. In February 2023, the carbon allowance price broke the 100 €/t level for the first time, primarily because the EU ETS annual cycle ends after Q1. In connection with the decision of the European Parliament's Committee on Industry, Research and Energy to finance the achievement of renewable energy and energy efficiency targets with proceeds from the sale of CO² emission allowances earlier than originally planned, the prices dropped to 92 €/t by the end of Q1.

Interconnectors supply the Baltic countries with Nordic hydropower, which is cheaper than other types of electricity. The average level of the Nordic hydro reservoirs in Q1 2023 was 46.0% of the maximum, which is 3.7 percentage points higher than in Q1 2022.

As the volume of snow and surface water accumulated in the reservoirs this year is 63 TWh higher than a year earlier, hydropower production in 2023 is expected to increase year on year. Higher hydropower production will lower electricity prices in the region because a larger share of the required electricity can be produced by facilities with lower variable costs.

Operating environment

Wind conditions

Due to seasonal factors, wind conditions in Q1 and Q4 are more favourable for wind power production in our region than the rest of the year. The average measured wind speeds in Enefit Green's wind farms in Estonia and Lithuania were somewhat above average in Q1, but lower than in comparative period: 6.9 m/s in Estonia and 7.2 m/s in Lithuania (Q1 2022: 7.0 m/s and 7.5 m/s, respectively). The chart below provides an overview of average quarterly wind speeds in Estonia and Lithuania since the beginning of 2021.

Regulatory environment

On 14 March 2023, the European Commission published its proposals for amending the EU electricity market regulation. The amendments are likely to be adopted by the end of 2023. The proposals are aimed at improving the current regulation, for example by reducing the risks associated with long-term PPAs, increasing possibilities for reducing electricity consumption, and allowing public support to renewable energy producers to be paid only on the basis of CfDs which include both a price cap and a price floor. Network operators will have more options to make anticipatory investments, which should support faster development of electricity production. The proposals do not include plans to extend or make permanent the revenue cap policy which is applies until the end of June 2023.

At the end of March, the Council of the EU and the European Parliament reached a political agreement on amending the Renewable Energy Directive. Among other things, it was decided to raise the share of renewable energy in the EU's overall energy consumption from 32% to 42.5% by 2030.

An amendment to the Electricity Market Act which requires paying a security deposit of €38,000/MVA for connecting to the grid electricity production equipment of over 15 kW entered into force on 17 March. A deadline was set for the commencement of electricity production by new power plants. The security deposit will be refunded if the power plant starts producing electricity during the following minimum period after the completion of the connection point: one year for solar power plants, three years for offshore wind farms, and two years for equipment using other technologies.

The Act lays down an obligation to produce electricity at the maximum capacity specified in the connection contract at least once every two years. For connection capacity that has not been used by the producer for two years, the producer must either pay an underutilisation charge of €38,000/MVA or renounce the right to the connection.

Following these amendments, Estonia has become the country with the most restrictive electricity network connection conditions for electricity producers in Enefit Green's core markets.

Legislative changes facilitating the planning and construction of onshore and offshore wind farms entered into force.

Lithuania established new grid connection principles. There is now a possibility to build hybrid solutions for electricity generation and storage. Principles were also established for limiting electricity production in the event of overproduction, granting preferential treatment to offshore wind farms with a generating capacity of 1,400 MW which have not yet been connected to the network. Producers that connected to the network before the new connection principles were established and new producers whose connection terms and conditions not foresee any production limits will also enjoy special treatment. The remaining new power plants will be the first that will be subject to production limits in the event of overproduction.

As the total capacity of solar power plants connected to the Lithuanian electricity network exceeds 2 GW, the government introduced the possibility to limit the output of new power plants if necessary. Based on an assessment carried out by network operators and taking into account export opportunities, the government also established that 4.4 GW of solar power capacity and 3.6 GW of onshore wind power capacity can be connected to the Lithuanian electricity network until 2030. Once these limits have been reached, both connections to the grid and the output of power plants may be restricted. Out of the 4.4 GW solar power capacity limit, 1.6 GW will be reserved for prosumers that both produce and consume and energy cooperatives.

On 30 March, Lithuania announced an auction to find a developer for an offshore wind farm with a generating capacity of 580–700 MW. Lithuanian authorities estimate that the costs of the offshore wind farm and related connection will amount to €1.8 billion. The developer will not receive any support from the state. The auction will be won by the developer offering the highest development fee to the state. Participants in the auction must register within 60 days.

The ban on planning wind turbines closer to residential buildings than ten times the height of the wind turbine was lifted. The new restriction zone is 700 metres. This will significantly increase the possibilities of building wind turbines in Poland.

Significant events

We acquired the Liivi (Gulf of Riga) offshore wind farm development

Enefit Green acquired from Eesti Energia the Liivi (Gulf of Riga) offshore wind farm development for around €6.2m. It is one for the most advanced offshore wind power projects in the Baltics, which we will continue to develop to launch offshore wind power production already before the end of the current decade.

The planned capacity of the Liivi offshore wind farm is 1 GWh and projected output is approximately 4 TWh per year. The development area is located between the island of Kihnu and the Häädmeeste coastline in southwest Estonia. The research required for the environmental impact assessment and the preliminary analysis of the technical solution of the wind farm are under way.

Significant production contribution from wind farms under construction

Enefit Green is currently building six wind farms and four solar farms. Out of wind farms under construction, Šilale II and Akmene in Lithuania and Purtse in Estonia have partially started production. In Q1 2023 these wind farms produced 38 GWh of electricity thereby contributing the whole year-over-year electricity production growth.

As of today, Purtse solar park also has started to produce electricity.

We are exploring strategic alternatives for biomass assets belonging to the

group

Considering Enefit Green's growing focus on the development of wind and solar energy, the Management Board has decided to explore strategic alternatives regarding the biomass assets owned by the Group. These assets include the Broceni CHP plant, the Broceni pellet plant and the Valka CHP plant in Latvia and the Paide CHP plant in Estonia.

Enefit Green's consolidated operating income for Q1 2023 grew by 16%, but 72% growth in operating expenses lowered EBITDA by 10%. Net profit for Q1 decreased by €4.4m, i.e. 13%, dropping to €30.5m. The key factors which influenced the group's financial performance are described below.

Production and sales volumes

	Unit	Q1 2023	Q1 2022	Change	Change,%
Electricity production	GWh	406	368	38	10%
Incl. new wind farms	GWh	38	0	38	-
Electricity sales*	GWh	495	393	102	26%
Heat energy production	GWh	176	173	3	2%
Pellet production	kt**	39	38	1	2%
Pellet sales	kt	62	55	7	13%

* The difference between sales and production quantities is attributable to forecasted but unrealised production sold under PPAs, which is covered with purchases from Nord Pool and/or the energy imbalance market.

** thousand tonnes

Operating income

The group's electricity production in the first quarter of 2023 was 406 GWh (+10% in the reference period).

Total operating income increased by €10.8m, of which sales revenue contributed €10.6m and renewable energy support and other operating income €0.1m. Of the €10.6m increase in sales revenue, €7.5m derived from the sale of pellets. The average sales price of pellets increased by 69% y-o-y. In the first quarter of 2022, the price was 149.3 €/tonne, in the first quarter of 2023 it was 252.7 €/tonne. In the first quarter, 62k tonnes of pellets were sold (55k tonnes in reference period). First quarter pellet sales were affected by the timing shift from Q4 2022 to 1Q 2023.

From the increase in sales revenue €2.4m was attributable to electricity sales. The growth in electricity sales was most positively influenced by the amount of electricity produced in Lithuania, which increased by 27% y-o-y. In Lithuania, two wind farms under construction, Akmene and Šilale II, started producing electricity in Q1 2023.

Lower market prices for electricity had a negative impact compared to the first quarter of last year. The average electricity price*** on the group's core markets was 100.5 €/MWh in the first quarter (136.4 €/MWh in the reference period). The group's implied captured electricity price**** was 101.4 €/MWh in the reporting period (127.3 €/MWh in the reference period). The implied captured electricity price differs from the average market price in the core markets, as the calculation takes into account long-term electricity sales contracts (PPAs) at a fixed price, renewable energy subsidies and the fact that wind farms do not produce the same amount of electricity every hour.

The average price of electricity sold to the market by the Group was 82.4 €/MWh in the first quarter of 2023, compared to 119.9 €/MWh a year earlier.

In Q1 2023 260 GWh of group's electricity portfolio was covered by PPAs at an average price of 89.8 €/MWh. In the comparative period 129 GWh of electricity was sold via PPA and Feed-in-Tariff (FiT) based revenue model at an average price of 78.8 €/MWh.

Short-term production shortfalls arising from the difference between the realised wind profile and base load PPAs have to be covered with electricity purchases from the day-ahead market. The chart on the next page provides an example of purchases to cover PPA shortfalls during a 24-hour period due to fluctuations in wind power production. The chart also reflects the day-ahead volume forecast and the realised production volumes, which give rise to the so-called open supply transactions (both purchases and sales).

€ million	Q1 2023	Q1 2022	Change	Change, %
TOTAL OPERATING INCOME	77.5	66.7	10.8	16%
Revenue	68.8	58.1	10.6	18%
Renewable energy support and other op. income	8.7	8.6	0.1	2%
TOTAL OPERATING EXPENSES (excl. D&A)	36.4	21.1	15.2	72%
Raw materials, consumables and services used	24.8	14.1	10.7	75%
Payroll expenses	2.5	2.4	0.0	2%
Other operating expenses	4.1	2.5	1.6	62%
Change in inventories	5.1	2.1	3.0	145%
EBITDA	41.1	45.6	(4.5)	(10)%
Depreciation, amortisation and impairment (D&A)	9.8	9.6	0.2	2%
OPERATING PROFIT	31.3	35.9	(4.6)	(13)%
Net finance income (costs)	0.0	(0.2)	0.2	(117)%
Income tax expense	0.8	0.8	0.0	(3)%
NET PROFIT	30.5	34.9	(4.4)	(13)%

TOTAL OPERATING EXPENSES (excl. D&A))	36.4	21.1	15.2	72%
Variable costs (incl. balancing energy purchases)	21.6	11.1	10.5	95%
Fixed costs	9.8	8.0	1.7	22%
Change in inventories	5.1	2.1	3.0	145%

*** Production volume weighted market price

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

The next two charts provide an overview of the quantities of electricity produced, purchased and sold as well as the formation of the realised sales, purchase and market prices and the average implied captured electricity price over the past five quarters.

In Q1 2023, we purchased from the market 92 GWh of electricity at an average price of 116.7 €/MWh. In Q1 2022, we purchased 29 GWh at an average price 128.1 €/MWh (the figures do not include the electricity purchased for pellet production). Electricity purchases from the market in Q1 2022 were significantly smaller because part of the output was covered by a fixed-price FiT support scheme and the volume of PPAs was small. The electricity price in Enefit Green's core markets, presented in the chart, is the average quarterly price in the Baltic and Polish markets, weighted by Enefit Green's production volumes. In Q1 2023, it was 100.5 €/MWh and in Q1 2022 136.4 €/MWh.

Electricity prices €/MWh	1Q 2022	2Q 2022	3Q 2022	4Q 2022	1Q 2023
Price of electricity sold to the market	119.9	127.6	285.2	179.0	82.4
Core markets average*	136.4	151.3	317.7	221.5	100.5
Implied captured price**	127.3	127.0	205.1	163.0	101.4
Realised purchase price	128.1	175.1	337.7	271.1	116.7
PPA (until Q4 22 incl FiT) sale price	78.8	79.1	72.1	126.2	89.8

Heat production remained stable compared with a year earlier but the price of heat sold grew by 38% due to growth in the price of biomass.

Revenue from solar services in Q1 2023 was €0.7m smaller than in Q1 2022 because we exited the provision of turnkey solar solutions in the middle of 2022.

Other operating income

Other operating income for Q1 2023 was affected the most by the change in renewable energy support received by Estonian wind farms, which decreased €1.1m year on year. The eligibility periods of the Tooma I, Vanaküla and Virtsu III wind farms expired in 2022. Other operating income was positively influenced by the decrease in the non-derivative contract liability incurred in 2021 by €0.9m in connection with the partial fulfilment of relevant PPAs. The non-derivative contract liability resulted from previous electricity derivatives (base load swaps) which were converted into fixed-price physical electricity sales contracts (PPAs). The decrease in the non-derivate contract liability does not affect cash flow and monetary settlement of electricity sales takes place on the basis of the PPAs.

* Production weighted average market price on group's core markets

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

Raw materials, consumables and services used

Expenses on raw materials, consumables and services grew by €10.7m, i.e. 75%. The biggest rise was in electricity costs, which grew by €6.8m due to electricity purchased to balance the NP intraday market portfolio and the electricity purchased to balance the PPA portfolio in hours of low wind speed. In Q1 2023, we purchased from the market 92 GWh of electricity at an average price of 116.7 €/MWh. In Q1 2022, we purchased 29 GWh at an average price of 128 €/MWh. Expenses on technological fuel grew by €4.1m due to an increase in the price of biomass. Average biomass expenses in pellet production grew by 108% year on year. The cost of biomass in Q1 2023 was 131.7 €/t compared with 63.4€/t in Q1 2022.

Payroll expenses

The group's payroll expenses grew by 2% compared with the same period last year due to an increase in the number of full-time employees from 169 to 186. New people were mostly hired to the development team to support the group's growth plan in all its markets. The growth resulting from the number of staff was counterbalanced by a decrease in performance-related and other bonuses, which in 2022 included a one-off larger amount of €0.2m.

Group's EBITDA change by drivers, €m

Other operating expenses

Other operating expenses grew by 62%, i.e. €1.6m, driven by higher research and consulting expenses as well as somewhat higher IT and insurance expenses.

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. In Q1 2023, the group produced 39 thousand tonnes (Q1 2022: 38 thousand tonnes) and sold 62 thousand tonnes (Q1 2022: 55 thousand tonnes) of pellets. The change in inventories was €5.1m (Q1 2022: €2.1m). The average sales price of pellets increased by 69% year on year, rising from 149.3 €/t in Q1 2022 to 252.7 €/t in Q1 2022. Sales for Q1 2023 were influenced by the shift of the sales of Q4 2022 to Q1 2023. Due to the increase in the price of pellets, sales of inventories have had a stronger impact because the cost price of pellets has been higher.

Depreciation, amortisation and impairment losses (D&A)

D&A expense remained stable compared with a year earlier. Although the volume of investments made in Q1 2023 was €91.9m, 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.

Fixed costs

Fixed costs comprise costs not directly dependent on the production volume. Fixed costs grew by €1.7m, i.e. 22%, year on year. Most of the growth resulted from an increase in development projects' research and consulting expenses.

Net finance income and costs

Net finance costs decreased by €0.2m year on year. Interest expense on bank loans grew by €1.6m compared with Q1 2022 but most of the interest expense incurred during the construction of wind farms is capitalised. The item of net finance income and costs was positively influenced by the addition of interest income on current accounts and term deposits in Q1 2023.

Income tax

Income tax expense remained at the same level as a year earlier.

Net profit

The group's net profit decreased by €4.4m, amounting to €30.5m for Q1 2023. The decrease is attributable to growth in electricity purchase expenses.

Operating income by segment, €m

Financial results by segments

Based on total operating income and EBITDA, the group's largest segment is Wind energy, which accounted for 58% of operating income and 75% of EBITDA for Q1 2023. The Cogeneration segment contributed 41% to operating income and 31% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 1% the group's operating income.

Among reportable segments, the Cogeneration segment delivered modest EBITDA growth while the EBIDTA of the Wind energy segment decreased the most. A more detailed analysis by segment is presented below.

The EBITDA of the segment Other mainly includes general administrative expenses, which is the largest item for the segment. The segment also includes the network construction services of the Paide CHP facility, the Keila-Joa hydroelectric facility, and the renewable energy solution on the island of Ruhnu. The loss of the segment Other increased by €0.3m.

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 Q1 2023, wind conditions in Estonia and Lithuania were somewhat less favourable for wind power production than a year earlier but the availability of our Estonian and Lithuanian wind farms was higher, being 96.3% and 97.6%, respectively

The electricity production of our wind farms grew by 2% in Estonia and by 27% in Lithuania. Two wind farms nearing completion in Lithuania – Akmene and Šilale II – started generating electricity during the period and at the end of March the Purtse wind farm in Estonia also produced its first electricity. Altogether, wind power production grew by 13% year on year, rising to 351 GWh. Practically all of the growth was attributable to the new wind farms.

Electricity prices

In addition to the market price of electricity, our Estonian wind farms whose eligibility period has not expired receive renewable energy support in the form of Feed-in-Premium (FiP) at the rate of 53.7 €/MWh. Since March 2022, our Estonian wind farms have also 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.

In Q3 2022, we replaced the previous Feed-in-Tariff (FiT) based income model with a model based on PPAs and the market price at all our Lithuanian wind farms. Since the implied captured electricity prices of both our Estonian and Lithuanian wind farms are based on a combination of the market price and PPAs (the share of the Estonian FiP in total operating income is decreasing), we are going to disclose the implied captured electricity price for the Wind energy segment as a whole starting from Q1 2023.

The wind energy segment's implied captured electricity price in Q1 2023 was 99.8 €/MWh (a 19% decline compared with Q1 2022). The implied captured electricity price was affected by lower prices on the Nord Pool market, the addition of long-term PPAs and electricity purchase expenses. Altogether, we sold 260.3 GWh of electricity at an average price of 89.8 €/MWh under PPAs in Q1 2023.

Operating income

The Wind energy segment's operating income, which was positively affected by 13% higher output and negatively affected by lower implied captured electricity prices, grew by 8.2% year on year to €44.8m.

guarantees of origin - day-ahead and intraday purchases on Nord Pool - balancing energy purchases) / production

Wind energy segment

Operating expenses

The operating expenses of the Wind energy segment (excl. D&A) grew by €7.3m year on year, rising to €14.0m. The growth resulted mainly from electricity purchases made to balance the PPA portfolio in hours of low wind speed. Other operating expenses (excl. electricity purchases, expenses on balancing energy and growth in D&A) grew by €0.5m compared with the same period last year.

Operating expenses per MW

In Q1 2023, our wind farm operators' (Enefit Wind OÜ and Enefit Wind UAB) operating expenses (excl. D&A, expenses on balancing energy and electricity purchased to balance the PPA portfolio ) per installed capacity (MW) increased by 7.5% year on year. The cost stability of new maintenance contracts has counterbalanced natural indexation-related growth in maintenance expenses.

The EBITDA of the Wind energy segment was €30.8m compared with €34.7m a year earlier. EBITDA decreased due to the downtrend in the market price of electricity and expenses on electricity purchased to balance the PPA portfolio.

+3.4 (+8.2%) -3.9 (-11.2%) Operating income and EBITDA, €m

+1,0 (+2,7%) Operating expenses per MW for last 4 quarters, €k/MW*

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

Cogeneration segment

31% Share of EBITDA Q1 2023

Enefit Green Q1 2023 interim report 20

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 Q1 2023 was 50.3 GWh, which is at the same level as a year earlier (Q1 2022: 50.2 GW). 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 selling electricity at the prices of the NP Latvia price area since mid-December 2022. Previously, it sold electricity at fixed prices ranging from 79.75 €/MWh to 105.6 €/MWh. 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 April 2023, the court of the second instance ruled in favour of BVKB. The management of SIA Technological Solutions is considering the next steps. 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 Q1 was a high 99.3% (Q1 2022: 99.5%).

The Cogeneration segment's implied captured electricity price decreased by 13% year on year, dropping to 136.2 €/MWh in Q1 2023, due to lower market prices in the NP Estonia and NP Latvia price areas.

Heat energy production and prices

Heat production grew by 1.5% year on year to 176 GWh. The average sales price of heat per MWh increased by 38% year on year, rising to nearly 24 €/MWh in Q1 2023. 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, but the price of heat produced by the Paide and Valka CHPs grew considerably due to an increase in the cost of biomass purchased.

Operating income

The Cogeneration segment's operating income grew by 34% year on year, rising to €32.0m. Pellet sales revenue grew the most (+€7.5m, +92%) due to a higher sales price and a larger sales volume. The average sales price of pellets increased to 252.7 €/t, i.e. by 69%. Pellet sales volume in Q1 2023 was 62 thousand tonnes compared with 55 thousand tonnes in the comparative period. Revenue from gate fees increased due to growth in waste received by €0.3m to €4.6m. Heat sales revenue grew year on year through larger output and a higher sales price by €0.9m to €3.3m. Other operating income grew by €0.1m to €0.7m. Electricity sales revenue decreased by €0.8m to €6.0m due to lower market prices. Electricity production support remained stable compared with a year earlier.

Cogeneration segment

Operating expenses

The change in inventories of finished goods increased expenses for Q1 2023 by €5.1m because pellet sales exceeded pellet production. In Q1 2022, the situation was the same: pellet sales exceeded production and the change in finished goods inventories was €2.1m. Compared with the same period in Q1 2022, the Cogeneration segment's expenses from the change in finished goods inventories grew by €3.0m. The segments' variable costs for Q1 2023 grew by €4.3m due to an increase in the price of biomass. Average biomass expenses in pellet production grew by 108% year on year. The cost of biomass in Q1 2023 was 131.7 €/t compared with 63.4 €/t in Q1 2022. The segment's fixed costs grew by €0.3m to €2.5m. The main source of growth was payroll expenses, which grew by €0.2m year on year.

EBITDA

The Cogeneration segment's EBITDA for Q1 grew by €0.6m year on year, i.e. 5%, , rising to €12.9m. EBITDA growth was supported by higher EBITDA in the pellet business while higher biomass and lower electricity prices had a negative effect.

Solar energy segment

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

Production

The Solar energy segment produced 3.5 GWh of solar power in Q1 2023, 1.9 GWh (35%) less than in Q1 2022 because the weather conditions in Estonia and Poland were less favourable for solar power production. The availability of solar farms remained high, being 99.9% (Q1 2022: 99.8%).

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 Q1 2023 was 492–526 PLN/MWh (104 –112 €/MWh at the three-month average zloty (PLN) exchange rate). From Q1 2023, the solar segment includes the Purtse farm's PPA revenue. Since the farm itself began generating revenue at the end of April, the electricity was sold from the portfolio of other operating assets. The implied captured electricity price in Q1 2023 was supported by sales of guarantees of origin, which were not offered in Q1 2022.

Operating income

The operating income of operating solar farms decreased by €0.8m year on year, mainly due to lower electricity production.

EBITDA

The Solar energy segment's EBITDA for Q1 2023 was negative at €0.4m, which is €0.8m lower than in the same period last year. This was mainly caused by increase in fixed costs related to development activities (including personnel and consultation expenses). To a lesser extent the result was influenced by exit from turnkey solaar solutions business last year.

Availabilities of solar farms (%)

efficient cogeneration support + revenues from sale of guarantees of origin - day-ahead and intraday purchases on Nord Pool - balancing energy purchases) / production

-1%

Share of EBITDA Q1 2023

Enefit Green Q1 2023 interim report 22

Investments

Investments during Q1

The group made capital investments of €91.9m in Q1 2023, which is €78.2m more than in Q1 2022. Growth resulted from development investments, which extended to €91.9m. Of the latter, €59.6m was invested in the development of three wind farms: €32.4m in the Sopi-Tootsi wind farm, €17.2m in the Kelme wind farm, €10.1m in the Purtse wind farm and €6.2m in the acquisition of the Liivi/Gulf of Riga offshore wind farm development from Eesti Energia. The largest investment in solar power development was made in the Purtse solar farm in the amount of €10.9m.

Base investments (expenditure on the maintenance and improvements of existing assets) amounted to €0.1m in Q1 2023, which is €0.3m less than in Q1 2022. Base investments were mainly made in the group's wind farms in Estonia. Base investments in wind farms may differ significantly quarter by quarter because they depend on the wind turbines' repair and maintenance needs in the relevant period.

Investments by segments, €m

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) and the European Bank for Reconstruction and Development (EBRD).

The amortised cost of the group's interest-bearing liabilities at 31 March 2023 was €272.7m (31 December 2022: €279.6m). Loan liabilities to banks accounted for €267.9m of the total, including an outstanding loan balance of €6.7m denominated in Polish zloty.

In Q1 2023, Enefit Green signed a new 12-year loan agreement of €100m with NIB and seven-year loan agreements of €225m with SEB. The loans of €325m in total were fully undrawn at 31 March 2023.

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 31 March 2023).

The interest rate risk of investment loans with the total outstanding balance of €164.0m has been hedged with interest rate swaps, which fix the interest rates of the loans in the range of 1.049% – 1.125% (plus the margin), until the loans mature.

The average interest rate of bank loans drawn down at 31 March 2023 was 2.75% (31 December 2022: 2.60%).

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.

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.

Loans repayment schedule, €m

Liquidity development 2023 Q1, €m

€ million	31 Dec 2022	31 Mar 2023
Interest-bearing liabilities	279.6	272.7
Minus cash and cash equivalents	-131.5	-80.5
Net debt	148.1	192.2
Equity	718.7	748.5
Invested capital	866.8	940.8
EBITDA (LTM)*	154.8	150.4
Operating profit (LTM)	117.1	112.4
Net profit (LTM)	110.2	105.8

Financial leverage (1)	17%	20%
Net debt/LTM EBITDA	0.96	1.28
Return on invested capital (2)	13.5%	12.0%

* 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

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

Price risk of electricity sales

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

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

No new PPAs were signed during Q1 2023.

The total volume of PPAs signed is 10,266 GWh at the average price of 72.0 €/MWh.

Out of electricity produced after 2027, 3,677 GWh is covered with PPAs at an average price of 78.1 €/MWh.

The chart below provides an overview of the next few years' forecasted production volumes and their coverage with risk mitigation measures as at 31 March 2023.

Interest rate risk

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

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

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

	2023	2024	2025	2026	2027	2023-2027 total
Share of production covered by FiT/CfD**	2%	1%	1%	1%	1%	1%
Volume (GWh)	26	28	28	28	28	140
FiT/CfD weighted average price, EUR/MWh	94.1	94.2	96.1	98.1	100.1	96.6

Share of production covered by FiP**	31%	24%	9%	3%	3%	12%
Volume (GWh)	524	502	266	99	79	1 470
Weighted average FiP, EUR/MWh (added to the market price)	50.2	50.2	50.3	53.7	53.7	50.6

Share of production covered by PPAs**	56%	64%	51%	51%	51%	54%
Volume (GWh)	953	1 331	1 516	1 516	1 532	6 848
PPA weighted average price, EUR/MWh	86.9	67.6	64.7	64.7	69.0	69.3

* Price floor – state support in a form of a price floor received from reverse auction at price level of 34.9

€/MWh (maximum 20 €/MWh) with a duration of 12 years

** expected production contains forecasted production volumes of operational and under construction assets

Condensed consolidated interim financial statements Q1 2023

Condensed consolidated interim income statement

€ thousand	Note	Q1 2023	Q1 2022
Revenue	9	68,785	58,141
Renewable energy support and other operating income	10	8,719	8,579
Change in inventories of finished goods and work in progress		(5,060)	(2,067)
Raw materials, consumables and services used	11	(24,792)	(14,134)
Payroll expenses		(2,486)	(2,443)
Depreciation, amortisation and impairment		(9,815)	(9,648)
Other operating expenses		(4,055)	(2,504)
OPERATING PROFIT		31,296	35,924
Finance income		407	170
Finance costs		(380)	(325)
Net finance income (costs)		27	(155)
Profit from associates under the equity method		19	4
PROFIT BEFORE TAX		31,342	35,773
Income tax expense		(820)	(849)
PROFIT FOR THE PERIOD		30,522	34,924

Basic and diluted earnings per share

Weighted average number of shares, thousand	6	264,276	264,276
Basic earnings per share, €	6	0.12	0.13
Diluted earnings per share, €	6	0.12	0.13

Condensed consolidated statement of other comprehensive income

€ thousand	Note	Q1 2023	Q1 2022
PROFIT FOR THE PERIOD		30,522	34,924
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Remeasurement of hedging instruments in cash flow hedges (2023: incl. reclassifications to profit or loss; 2022: no reclassifications to profit or loss)	5, 7	(689)	937
Exchange differences on the translation of foreign operations	7	(35)	(137)
Other comprehensive income (loss) for the period		(724)	800

TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		29,798	35,724

Condensed consolidated interim statement of financial position

€ thousand	Note	31 Mar 2023	31 Dec 2022
ASSETS				EQUITY
Non-current assets
Property, plant and equipment	4	843,998	776,870	parent
Intangible assets		60,342	60,382
Right-of-use assets		4,528	4,239
Prepayments for property, plant and equipment	4	34,538	19,412
Deferred tax assets		1,344	1,321
Investments in associates		524	506
Derivative financial instruments	5, 7	9,206	11,277
Non-current receivables		40	40
Total non-current assets		954,520	874,047	LIABILITIES

Current assets
Inventories		8,628	14,227
Trade and other receivables and prepayments		46,777	41,091
Cash and cash equivalents		80,509	131,456
Derivative financial instruments	5	3,871	3,349
Total current assets		139,785	190,123
Total assets		1,094,305	1,064,170

€ thousand	Note	31 Mar 2023	31 Dec 2022
EQUITY
Equity and reserves attributable to shareholders of the parent
Share capital		264,276	264,276
Share premium	6	60,351	60,351
Statutory capital reserve		3,259	3,259
Other reserves	5, 7	165,730	166,419
Foreign currency translation reserve	7	(797)	(762)
Retained earnings		255,712	225,190
Total equity		748,531	718,733

LIABILITIES
Non-current liabilities
Borrowings	8	252,470	255,755
Government grants		6,991	7,115
Non-derivative contract liability	5, 7	18,086	18,086
Deferred tax liabilities		12,297	12,326
Other non-current liabilities		3,000	3,000
Provisions		9	9
Total non-current liabilities		292,853	296,291
Current liabilities
Borrowings	8	20,266	23,808
Trade and other payables		29,298	20,215
Provisions		2	2
Non-derivative contract liability	5	3,355	5,121
Total current liabilities		52,921	49,146
Total liabilities		345,774	345,437
Total equity and liabilities		1,094,305	1,064,170

Condensed consolidated interim statement of cash flows

€ thousand	Note	Q1 2023	Q1 2022
Cash flows from operating activities
Cash generated from operations	12	44,337	46,035

Interest and loan fees paid		(2,053)	(502)
Interest received		311	2
Income tax paid		(574)	(500)
Net cash generated from operating activities		42,021	45,035

Cash flows from investing activities
Purchase of property, plant and equipment and intangible assets	4	(85,747)	(12,326)
Proceeds from sale of property, plant and equipment		0	3
Net cash used in investing activities		(85,747)	(12,323)

Cash flows from financing activities
Repayments of bank loans	8	(7,137	(4,643)
Repayments of lease principal	8	(84)	(82)
Net cash used in financing activities		(7,221)	(4,725)

Net cash flow		(50,947)	27,987

Cash and cash equivalents at the beginning of the period		131,456	80,454
Cash and cash equivalents at the end of the period		80,509	108,441
Increase in cash and cash equivalents		(50,947)	27,987

Condensed consolidated interim statement of changes in equity

€ thousand	Share capital	Share premium	Statutory capital reserve	Other reserves	Foreign currency translation reserve	Retained earnings	Total equity
Equity as at 31 December 2021	264,276	60,351	479	151,793	(965)	157,673	633,607
Profit for the period	0	0	0	0	0	34,924	34,924
Other comprehensive income for the period	0	0	0	937	(137)	0	800
Total comprehensive income for the period	0	0	0	937	(137)	34,924	35,724
Equity as at 31 March 2022	264,276	60,351	479	152,730	(1,102)	192,597	669,331

Equity as at 31 December 2022	264,276	60,351	3,259	166,419	(762)	225,190	718,733

Profit for the period	0	0	0	0	0	30,522	30,522
Other comprehensive loss for the period	0	0	0	(689)	(35)	0	(724)
Total comprehensive income for the period	0	0	0	(689)	(35)	30,522	29,798
Equity as at 31 March 2023	264,276	60,351	3,259	165,730	(797)	255,712	748,531

Notes to the condensed consolidated interim financial statements

1. Summary of significant accounting policies

These condensed consolidated interim financial statements (interim financial statements) have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting and they do not include all the notes normally included in the annual financial statements. Thus, they should be read in conjunction with the group's annual financial statements as at and for the year ended 31 December 2022, which have been prepared in accordance with IFRS as adopted by the European Union.

These interim financial statements have been prepared using the same accounting policies as those applied in the preparation of the group's annual financial statements as at and for the year ended 31 December 2022.

The preparation of interim financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, and income and expenses. Actual results may differ from those estimates. Significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty were mainly the same as those described in the group's annual financial statements as at and for the year ended 31 December 2022.

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

2. Financial risk management

Through its activities, the group is exposed to various financial risks: market risk (incl. currency risk, fair value and cash flow interest rate risk and price risk), credit risk and liquidity risk. Condensed interim financial statements do not contain all the information about the group's financial risk management which is required to be disclosed in the annual financial statements. Therefore, these interim financial statements should be read in conjunction with group's annual financial statements as at and for the year ended 31 December 2022.

The group uses interest rate swaps for interest rate risk management. Interest rate risk is the risk that the fair value or future cash flows of financial instruments will fluctuate because of changes in market interest rates. Cash flow interest rate risk arises from the group's floating-rate borrowings and is the risk that finance costs will increase when interest rates rise. Interest rate risk is mitigated partly by raising debt at fixed interest rates and partly by hedging: 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 shareholders, issue new shares or sell assets to reduce its financial liabilities, and raise debt capital in the form of loans. On raising loans, management assesses the group's ability to service the principal and interest payments with operating cash flow and, where necessary, starts timely negotiations to refinance existing loans before their maturity. For further information about financing ratios and borrowings, see the Financing chapter in the management report.

3. Segment reporting

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

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

1. Wind energy (comprises all of the group's wind farms);
1. Cogeneration (comprises all of the group's cogeneration facilities and the pellet factory);
1. Solar energy (comprises all of the group's solar farms);
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 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 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	Q1 2023	Q1 2022
REVENUE
Wind energy	37,946	34,617
Cogeneration	30,141	22,118
Solar energy	494	1,279
Total reportable segments	68,581	58,013
Other	205	128
Total	68,785	58,141
RENEWABLE ENERGY SUPPORT AND OTHER INCOME
Wind energy	6,889	6,838
Cogeneration	1,810	1,691
Solar energy	16	32
Total reportable segments	8,714	8,561
Other	5	18
Total	8,719	8,579
EBITDA
Wind energy	30,825	34,720
Cogeneration	12,870	12,286
Solar energy	-435	413
Total reportable segments	43,260	47,419
Other	(2,148)	(1,851)
Total	41,112	45,568
Depreciation, amortisation and impairment losses	9,815	9,648
Net finance costs	0	155
Profit from associates under the equity method	0	(4)
Profit before tax	31,296	35,768
OPERATING PROFIT
Wind energy	23,891	27,908
Cogeneration	10,293	9,708
Solar energy	(661)	185
Total reportable segments	33,523	37,801
Other	(2,227)	(1,877)
Total	31,296	35,924

3. Segment reporting (cont.)

€ thousand	Q1 2023	Q1 2022
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	77,852	11,816
Cogeneration	93	149
Solar energy	12,182	1,161
Total reportable segments	90,127	13,126
Other	1,810	621
Total	91,938	13,746

€ thousand	31 Mar 2023	31 Dec 2022
NON-CURRENT ASSETS
Wind energy	733,564	668,422

Cogeneration 132,026 134,510 Solar energy 73,184 55,035 Total reportable segments 938,775 857,968 Other 15,746 16,079 Total 954,520 874,047

Enefit Green

4. Property, plant and equipment

€ thousand	Land	Buildings	Facilities and structures	Machinery and equipment	Assets under construction	Prepayments	Total
Property, plant and equipment as at 31 December 2022
Cost	63,953	25,573	42,218	751,521	203,637	19,412	1,106,314
Accumulated depreciation	0	(10,385)	(25,014)	(274,615)	(18)	0	(310,032)
Carrying amount	63,953	15,188	17,204	476,906	203,619	19,412	796,282
Total property, plant and equipment as at 31 December 2022	63,953	15,188	17,204	476,906	203,619	19,412	796,282
Movements in the reporting period
Additions	0	0	0	51	76,724	15,162	91,937
Exchange differences	0	0	1	21	1	0	23
Transfers	0	1	2	1,951	(1,918)	(36)	0
Depreciation and impairment	0	(158)	(317)	(9,231)	0	0	(9,706)
Total movements during the period	0	(157)	(314)	(7,208)	74,807	15,126	82,254
Property, plant and equipment as at 31 March 2023
Cost	63,953	25,574	42,221	753,544	278,444	34,538	1,198,274
Accumulated depreciation	0	(10,543)	(25,331)	(283,846)	(18)	0	(319,738)
Carrying amount as at 31 March 2023	63,953	15,031	16,890	469,698	278,426	34,538	878,536

At 31 March 2023, the group had committed to capital expenditures of €440,428k (31 December 2022: €89 623k and 31 March 2022: €212,890k).

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. As at 31 March 2023, the group used cash flow hedging instruments in order to hedge the exposure to interest rate risk resulting from floating-rate borrowings.

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

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

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

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

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

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

• Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;

• Level 2: inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly;

• Level 3: inputs for the asset or liability that are not based on observable market data.

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

Non-derivative contract liability

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

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

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

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

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 31 March 2023 was €(10,781)k.

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

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

The electricity supply period under the EFET agreements began on 1 January 2023. Accordingly, the balance of the liability decreased by €860k in Q1 2023 and was €(11,566)k at 31 March 2023.

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

As at 31 December 2022, the liability of €23,207k was classified into a current portion of €5,121k and a noncurrent portion of €18,086k.

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

€ thousand	Note	Q1 2023	Q2 2023	Q3 2023	Q4 2023	Total
Non-derivative contract liability		(1,766)	(756)	(1,033)	(1,566)	(5,121)
Electricity cash flow hedge reserve	7	860	552	632	754	2,798
Gain on derivative financial instruments	10	905	204	401	813	2,323

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

Interest rate swap transactions

At 31 March 2023, the group had 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 €76,522k whereby the group receives interest at a rate equal to 6 month EURIBOR and pays a fixed rate of interest of 1.1%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan taken out on 30 September 2022.

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

─ An interest rate swap with a notional amount of €37,500k 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 31 March 2023 the main terms of the interest rate swaps matched the terms of the loans (i.e. their notional amounts, currencies, and maturity, payment and other dates). The forward hedges have a hedge ratio of one to one. To test the hedge effectiveness, the group uses the hypothetical derivative method and compares the changes in the fair values of the interest rate swaps against the changes in the fair values of the loan agreements. Hedge ineffectiveness can arise from the following sources:

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

At 31 March 2023, the effect of the hedging instruments on the group's statement of financial position was as follows (€ thousand):

€ 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	168,334	13,077	0	Derivatives	(996)	0	553

* Change compared to 31 December 2022, recognised in other comprehensive income

At 31 March 2023, the effect of the hedged items on the group's statement of financial position was as follows (€ thousand):

€ 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	13,077	13,077	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 and dividends

At 31 March 2023, the number of the registered shares of Enefit Green AS amounted to 264,276,232 (31 December 2022: 264,276,232 shares). The nominal value of a share is €1.

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

Dividends

The group's management board has proposed to the general meeting of the shareholders that the company distribute a dividend of €54,969k for the year ended 31 December 2022 (€0.208 per share). The dividend will be paid out in Q2 2023 after the general meeting has adopted the relevant resolution.

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

	Unit	Q1 2023	Q1 2022
Profit attributable to shareholders of the parent	€ thousand	30,522	34,924

Weighted average number of shares	thousand	264,276	264,276
Basic earnings per share	€	0.12	0.13
Diluted earnings per share	€	0.12	0.13

7. Other reserves

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

Change in fair value of cash flow hedges	860	0
of which electricity cash flow hedge reserve	860	0
Interest rate swap transactions (IRS)	(996)	14,529
Recognised as an increase in interest expense	(553)	97
Exchange differences on the translation of foreign operations	(35)	203

Other reserves at the end of the period	164,933	165,657
of which currency translation reserve	(797)	(762)
of which interest rate swap transactions (IRS)	13,077	14,626
of which electricity cash flow hedge reserve	(11,566)	(12,426)
of which fair value on initial recognition of a derivative financial instrument transaction with the parent	(10,781)	(10,781)
of which other reserves	175,000	175,000

8. Borrowings at amortised cost

	Current borrowings		Non-current borrowings
€ thousand	Bank loans	Lease liabilities	Bank loans	Lease liabilities	Total
Borrowings at amortised cost as at 31 December 2022	23,396	412	251,577	4,178	279,563

Movements in the reporting period
Monetary movements
Borrowings received	0	18	0	358	376
Repayments of borrowings	(7,137)	(84)	0	0	(7,221)
Non-monetary movements
Transfers	3,659	0	(3,659)	0	0
Other movements	2	0	14	2	18
Total movements during the period	(3,476)	(66)	(3,645)	360	(6,827)

Borrowings at amortised cost as at 31 March 2023	19,920	346	247,932	4,538	272,736

Line item ´Transfers´ comprises the change in the current portions of the principal amounts of the loans due to the changes in the repayment schedule.

9. Revenue

€ thousand	Q1 2023	Q1 2022
Revenue by activity
Sale of goods
Pellets	15,676	8,174
Scrap metal	263	291
Other goods	90	45
Total sale of goods	16,029	8,510

Sale of services
Heat	3,276	2,355
Electricity	44,544	42,108
Waste reception and resale	4,593	4,291
Rental and maintenance of assets	248	853
Other services	95	24
Total sale of services	52,756	49,631
Total revenue	68,785	58,141

10. Renewable energy support and other operating income

€ thousand	Q1 2023	Q1 2022
Renewable energy support	7,268	8,282
Government grants	123	135
Gain on derivative financial instruments	906	0
Other income	422	162
Total renewable energy support and other operating income	8,719	8,579

11. Raw materials, consumables and services used

€ thousand	Q1 2023	Q1 2022
Maintenance and repairs	3,102	2,985
Technological fuel	8,359	4,279
Electricity	11,461	4,685
Services related to ash treatment	563	795
Transport services for sale of finished goods	569	461
Materials and spare parts for production	411	698
Transmission services	115	27
Waste handling	80	79
Resource charges for natural resources	1	2
Other raw materials, consumables and services used	50	44
Environmental pollution charges	81	79
Total raw materials, consumables and services used	24,792	14,134

12. Cash generated from operations

€ thousand	Q1 2023	Q1 2022
Profit before tax	31,342	35,773
Adjustments
Depreciation and impairment of property, plant and equipment	9,706	9,620
Amortisation and impairment of intangible assets	109	28
Amortisation of government grants related to assets	(123)	(135)
Interest expense on borrowings	380	319
Profit from associates using the equity method	(19)	(4)
Gain on disposal of property, plant and equipment	0	(2)
Interest and other finance income	(311)	(3)
Foreign exchange (gain) loss loans granted and taken out	15	(91)
Realised gain on derivative financial instruments	(905)	0
Adjusted profit before tax	40,194	45,505
Net change in current assets related to operating activities
Change in receivables related to operating activities	339	79
Change in inventories	5,600	1,740
Net change in other current assets related to operating activities	(5,812)	(2,049)
Total net change in current assets related to operating activities	127	(230)
Net change in liabilities related to operating activities
Change in provisions	0	(1)
Change in trade payables	1,217	1,658
Net change in other current liabilities related to operating activities	2,799	(897)
Total net change in current liabilities related to operating activities	4,016	760
Cash generated from operations	44,337	46,035

13. Transactions and balances with related parties

The parent of Enefit Green AS is Eesti Energia AS. At 31 March 2023, the sole shareholder of Eesti Energia AS was the Republic of Estonia.

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

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

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

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

At 31 March 2023, Enefit Green AS had signed long-term physical electricity sales contracts of 9,111 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 base load energy. The weighted average price of the physical electricity sales contracts signed with the related party is 69.1 €/MWh.

At the beginning of 2021, the group used base load swap derivative contracts in order to hedge the exposure to variability in the price of electricity. The initial fair value of the derivatives designated as hedging instruments of €(10,781)k was recognised directly in equity. The group continued to apply hedge accounting to the open derivatives position until 17 August 2021 when an EFET General Agreement Concerning the Delivery and Acceptance of Electricity (EFET General Agreement) was signed and all open derivative contracts were simultaneously terminated. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k due to the change in the electricity price in the period from the trade date to 17 August 2021. The cumulative change in the fair value of the derivative financial instruments of €(12,426)k was recognised through other comprehensive income and the cash flow hedge reserve in equity (see also note 5). As at 31 March 2023, the balance of the electricity cash flow hedge reserve was €(11,566)k (see also notes 5 and 7).

TRANSACTIONS			BALANCES
PARENT


Sale of services	23,457	2,334	Of which non-derivative
OTHER GROUP COMPANIES


Sale of goods	0	0
Sale of services	420	1,976
OTHER RELATED PARTIES (INCL. ASSOCIATES)


ELERING AS

€ thousand	Q1 2023	Q1 2022
TRANSACTIONS
PARENT
Purchase of services	4,464	2,589
Sale of goods	0	0
Sale of services	23,457	2,334
OTHER GROUP COMPANIES
Purchase of goods	0	6
Purchase of services	857	970
Sale of goods	0	0
Sale of services	420	1,976
OTHER RELATED PARTIES (INCL. ASSOCIATES)
Purchase of services	456	367
Sale of services	0	0
ELERING AS
Purchase of services	1,587	31
Sale of services	7,330	8,368

Group structure

Direct ownership

Indirect ownership

Associates

AI Terminal

Enefit Green

2216_10-q_2023-05-05_066bbf82-6b2c-4523-91fc-7a7874c91f5e.pdf

Enefit Green

Contents

Letter from the Chairman of the Management Board

Dear reader

Target: 4× growth in production capacity

1Q 2023 Key highlights

Operating environment

Key factors influencing the operating environment

Electricity market

Operating environment

Wind conditions

Regulatory environment

Significant events

We acquired the Liivi (Gulf of Riga) offshore wind farm development

Significant production contribution from wind farms under construction

We are exploring strategic alternatives for biomass assets belonging to the

group

Production and sales volumes

Operating income

Other operating income

Raw materials, consumables and services used

Payroll expenses

Group's EBITDA change by drivers, €m

Other operating expenses

Change in inventories

Depreciation, amortisation and impairment losses (D&A)

Fixed costs

Net finance income and costs

Income tax

Net profit

Operating income by segment, €m

Financial results by segments

Group's EBITDA breakdown and change, €m

Wind energy segment

Availability and production

Electricity prices

Operating income

Wind energy segment

Operating expenses

Operating expenses per MW

Cogeneration segment

Electricity production and prices

Heat energy production and prices

Operating income

Cogeneration segment

Operating expenses

EBITDA

Solar energy segment

Production

Electricity prices

Operating income

EBITDA

Investments

Investments during Q1

Investments by segments, €m

Financing

Loan covenants

Financing and return ratios

Loans repayment schedule, €m

Liquidity development 2023 Q1, €m

Price risk of electricity sales

Interest rate risk

Condensed consolidated interim financial statements Q1 2023

Condensed consolidated interim income statement

Basic and diluted earnings per share

Condensed consolidated statement of other comprehensive income

Condensed consolidated interim statement of financial position

Condensed consolidated interim statement of cash flows

Condensed consolidated interim statement of changes in equity

Notes to the condensed consolidated interim financial statements

1. Summary of significant accounting policies

2. Financial risk management

3. Segment reporting

3. Segment reporting (cont.)

3. Segment reporting (cont.)

4. Property, plant and equipment

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