Enefit Greeni III kvartali 2022 vahearuanne

3	Letter from the Chairman of the Management Board
4	Strategy and development portfolio
8	2Q key highlights
9	Operating environment
12	Significant events
13	Financial results of the group
17	Wind energy segment
19	Cogeneration segment
21	Solar energy segment
22	Investments
23	Financing
24	Risk management
25	Condensed consolidated interim financial statements
31	Notes to the condensed consolidated interim financial statements
47	Group structure

Letter from the Chairman of the Management Board

Dear reader

Last year's rally in energy commodity prices has reversed with prices normalising, average electricity prices in our core markets declined by almost two times. Enefit Green's implied captured electricity price in the second quarter was €90/MWh (-29%).

This was mainly due to lower natural gas prices, warmer than normal weather, the start of the regular production at the Olkiluoto-3 nuclear reactor and strong hydropower supply in the region.

Considering factors driving power generation and prices, Enefit Green's Q2 financial results were lower than expected. Mainly the decline in implied captured electricity price, but also lower production volumes influenced by weak wind conditions and higher fixed costs all left their marks on the results. Although there was a 56GWh contribution from new wind and solar farms under construction, our Q2 electricity production still decreased by 2% compared to last year. The increase in fixed costs was driven by development activities and related overheads and management expenses, including personnel and research and consulting expenses. The planned increase in fixed costs is intended to support the implementation of our long-term growth plan. Higher income tax expense related to the dividend payout put an additional dent on the Q2 bottom line.

The electricity price outlook for autumn and winter will depend to a large extent on how Europe manages its natural gas inventory and on the carbon price. There is still a shortage of renewable power plants at the system level and the Baltic region is heavily dependent on imported electricity. Largest growth opportunities are continuously seen in wind and solar power. There just aren't enough renewable power plants to cover power demand without gas, oil shale or European coal plants. Forecasts indicate that average electricity prices should remain higher in the second half of the year than in the second quarter.

In early May, an unfortunate incident occurred – a wind turbine under construction collapsed at the Akmene wind farm. At the time of the accident, there was no-one inside or near the wind turbine and no-one was injured. Safety is one of Enefit Green's core values and creating and maintaining a safe working environment is our number one priority. Following the incident, we immediately suspended construction work and launched a thorough investigation with the assistance of the best experts to identify all possible risks and hazards that need to be taken into account in order to avoid similar accidents in the future.

As new renewable power plants come online the volatility of electricity prices will increase, which will create opportunities for consumption management and different storage solutions. We have started preparations for a pilot project to add a battery storage to Purtse hybrid park. Current plan foresees a 4MW/8MWh battery solution which is partially financed by the Centre of Environmental Investments.

In the Purtse Hybrid Park, which was opened on International Wind Day, a wind farm with five wind turbines and a solar farm with nearly 49 000 panels produce renewable electricity in parallel, which together provides electricity for nearly 25 000 Estonian households per year. The unique hybrid solution yields constructionrelated cost savings along with a smarter use of the grid connection capacity.

At the beginning of August, we are going to lay the cornerstone for the largest renewable energy zone in both Estonia and the Baltics. The construction of the Sopi-Tootsi wind farm has been going on since the beginning of the year. In May, we made an investment decision to erect a 74 MW solar farm near the wind farm and the first activities for its construction are also under way.

During the quarter, we made strong progress with projects which are in the planning phase. We increased the capacity of the planned wind and solar farms in our development portfolio by 400 MW. We also finalised the environmental impact assessment report for the North-West Estonia (Loode-Eesti) offshore wind farm, which was submitted for approval by the Ministry of Climate in mid-July. To boost and ensure sustainability of our development capabilities we recruited new employees in our core markets.

Enefit Green has a very clear growth plan up to 2026. In the first half of this year, we invested nearly €166m in increasing our production capacity. This is almost three times more than in the same period last year. When making new investment decisions, we are guided by the market situation and the investment criteria we have set to ensure the sufficient return on capital. In the second half of the year, it is crucial to ensure high availability of our operating assets in order to reach the production targets in key fall and winter months ahead.

Aavo Kärmas Chairman of the Management Board of Enefit Green

Enefit Green Q2 2023 interim report 4

Path towards 4X growth: 62MW added to operating portfolio during Q2

Operating Under construction

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

** COD – Commercial Operating Date

*** On 2May 2023 there was an incident in Akmene wind farm resulting in a destruction of a wind turbine under construction. See page 12 for update on situation in Akmene.

	Near term development portfolio		Targeted investment decisions until the end of 2024			300	MW			364	MW	Enefit Green Q2 2023 interim report
operating under construction 1,127 MW	near term dev portfolio up to ~90MW	up to ~150MW	up to ~6MW	up to ~11MW	up to ~9MW	up to ~21MW	up to ~45MW	up to ~92MW	up to ~45MW	up to ~60MW	up to ~35MW	up to ~100MW	up to ~1,791 MW 664
608 519 Operating + under	Kelme II	Kelme III	Carnikava Austrumi PV	Carnikava Dzerves PV	Mockiai PV	Šilale PV	Seinapalu PV	Vändra PV	Strzalkowo PV	Vändra	Pakri PV	Lihula PV	608 519 Operating + under constr. +
construction capacity (31 July 2023) Country													NT dev port capacity (31 July 2023)
Final investment decision COD	2H 2023 2025	2H 2023 2025	2H 2023 2024	2H 2023 2024	2H 2023 2024	2H 2023 2024	2H 2023 2025	2H 2023 2026	1H 2024 2025	2H 2024 2026	2H 2024 2026	2H 2024 2026

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 July 2023

NB! Development projects are in continuous change.

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

2Q 2023 Key highlights

* (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 in 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 coverage of the next years' expected electricity output with PPAs and other risk mitigation measures (incl. Contracts for Difference (CfDs) in Poland and the new price floor measure in Estonia) is provided at the end of the management report.

Electricity market

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

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

Electricity prices in our core markets decreased in Q2 due to lower natural gas prices, the Finnish Olkiluoto 3 nuclear reactor starting regular production, and strong hydropower production in the region. In addition, unusually warm weather weakened electricity demand.

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 Q2 2023 were lower than a year earlier. The Q2 average daily electricity price was the highest on 15 June, when it was 130.7 €/MWh (133.3 €/MWh lower than in Q2 2022) and the lowest on 13 April, when it was 22.7 €/MWh (2.1 €/MWh higher than in Q2 2022).

The average price of natural gas on the Dutch gas trading platform TTF was 32.9 €/MWh in Q2 2023 (-80.9 €/MWh, -71.1% compared with Q2 2022). The steep fall in the price of natural gas is mainly attributable to the facts that due to a warmer winter natural gas inventories in Europe are significantly higher than in previous years and LNG imports have grown to replace previous imports of Russian pipeline gas.

The Finnish nuclear power plants had the strongest impact on electricity prices in May, when the Finnish electricity prices were negative on some days. In June, electricity prices in the Baltic markets were affected by the maintenance of the region's power plants and weather conditions which lowered wind power production.

The Baltic electricity price is also affected by the production of Nordic hydropower, which is supplied through interconnectors. The average level of the Nordic hydro reservoirs in Q2 2023 was 39.7% of the maximum, which is 2.4 percentage points higher than in Q2 2022. As the volume of snow and surface water accumulated in the reservoirs this year is 39 TWh higher than last year, the availability of favourably priced hydropower is expected to increase year on year.

The average CO² emission allowance price in Q2 2023 was 88.6 €/t, which is 6% higher than a year earlier. In April, the European Council decided to change the emission allowance policy and to set a more ambitions emissions reduction target along with an additional reduction of the quantity of available emission allowances.

Quarterly average electricity prices on Enefit Green core markets and in Nordic countries

Average electricity price (€/MWh)	Q2 2023	Q2 2022	Change
Estonia	74.4	142.1	(47.6)%
Latvia	80.8	164.0	(50.7)%
Lithuania	81.3	168.1	(51.6)%
Poland	112.9	150.9	(25.2)%
Finland	43.3	117.5	(63.1)%
Norway	54.9	93.9	(41.5)%
Denmark	83.8	179.6	(53.3)%
Sweden	51.0	85.6	(40.4)%

Operating environment

Wind conditions

Due to seasonal factors, wind conditions in Q2 and Q3 are less favourable for wind power production in our region than the rest of the year. In Q2 2023, the average measured wind speeds in Enefit Green's wind farms in both Estonia and Lithuania were the recent years' weakest - 5.2 m/s (Q2 2022: 5.9 m/s and 5.8 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

The European Council continued the debate on electricity market reform. The reform will have a significant impact on the business environment for investing in electricity generation in the EU.

In April, the European Council decided to change the policy on CO² emission allowances and to set a new EU-wide emissions reduction target. Consistent with the decision, free allocation of emission allowances to production installations will be phased out by 2034, and by 2030 the emissions of sectors covered by the EU Emissions Trading System will have to decrease by 62% compared to the 2005 levels, which is 19 percentage points more ambitious than the previous target. The decision will make the output of fossil fuel power plants even more expensive and encourage investment in new renewable power plants. While the previous regulation reduced the number of CO² allowances in circulation by 2.2% per year, the new regulation raises the annual reduction rate to 4.3% in the period 2024–2027 and 4.4% in the period 2028–2030.

Parliamentary elections in Estonia were held in March 2023. The new government's Action Programme 2023–2027 includes a number of targets that will affect the business environment for renewable electricity generation.

The government's goal is to make Estonia a country that exports electricity.
To meet the target of 100% renewable electricity and to speed up the construction of offshore wind farms, reverse auctions with price ceilings and floors will be organised. Relevant regulatory amendments have to be prepared by April 2024.
The state-owned real estate company Riigi Kinnisvara AS will have to purchase renewable electricity for the buildings under its management starting from April 2024.
Households and apartment associations producing up to 30 kW of electricity will be offered an opportunity to connect to the grid at a fixed price. The measure may increase electricity overproduction during summer days and lower the market price of electricity.

The new government's EU policy priorities until 2025 include the following objectives:

Creating a single price area in the Baltic electricity market in order to increase the market for renewable electricity. This will reduce the price risk for renewable electricity producers and facilitate risk mitigation before new investments are made.
Building the third electricity transmission cable, Estlink 3, between Estonia and Finland by the early 2030s.

In June, the government established a procedure for granting permits for the construction of wind farms on state and municipally-owned land. The prepared framework gives Latvijas vēja parki, a subsidiary of the state-owned companies Latvenergo and Latvijas valsts meži, a one-off right to submit a reasoned construction permit application for up to 10% of the total area the state forest management company Latvijas valsts meži is offering for the construction of wind farms. This gives an advantage to the state-owned company and discriminates against other market players interested in developing wind farms on state and municipally-owned land in Latvia.

In June, the electricity market regulator VERT changed the principles of the price ceiling for electricity producers and extended the price ceiling retroactively from 1 December 2022 to the production of power plants under construction. The change does not have a major financial impact, but increases the risks of investing in electricity generation in Lithuania.

The rule according to which the minimum distance between a wind turbine and a residential building must be at least ten times the height of the wind turbine was lifted. The new restriction zone for new wind turbines is 700 metres from a residential building. The amendment opens up opportunities for the development of new onshore wind projects in Poland.

The Polish government decided to maintain the temporary price cap imposed by the EU on renewable electricity producers until the end of the year.

Significant events

We began building the 74 MW Sopi solar farm

We made the investment decision and started building Enefit Green's largest solar farm to date in the Sopi-Tootsi renewable energy zone. The 74 MW Sopi solar farm, which is scheduled to come online in early 2025, will produce around 75 GWh of electricity per year, which should cover the annual electricity consumption of approximately 22,500 average Estonian households. We will invest around €44m in the construction of the solar farm.

The solar farm along with the wind farm that will be built nearby will give the depleted Tootsi peat extraction site a new purpose and take Estonia closer to meeting its renewable energy targets.

We opened Estonia's first wind-solar hybrid farm

On the Global Wind Day, we opened the Purtse wind-solar hybrid farm. It is a unique renewable power plant, which comprises a 21 MW wind farm with five wind turbines and a 32 MW solar farm with nearly 49,000 solar panels. The output of the hybrid facility covers the annual electricity consumption of around 25,000 average Estonian households.

The Purtse farm features the first new, state-of-the-art wind turbines to be erected in Estonia in years. The unique hybrid solution enables us to use the same connection point to connect to the network various production capacities and, in the future, a storage facility.

EIA report for the North-West Estonia offshore wind farm

In mid-July, Enefit Green submitted the environmental impact assessment (EIA) report for the North-West Estonia offshore wind farm (also known as the Hiiumaa offshore wind farm) for approval by the Ministry of Climate, which has 30 days to make a decision. It is the most comprehensive report on the state of the North-West Estonian marine area, compiled over a period of 10 years. The EIA concludes that it is possible to build a wind farm in the area, giving preference to the alternative with a higher capacity but fewer wind turbines.

The approval of the EIA report is the first major step in the North-West Estonia offshore wind farm project. The next steps in the development process are the technical design for the superficies licence proceedings and marine spatial planning. During design, the construction technology will be determined and further studies will be carried out. The superficies licence proceedings will be followed by the construction permit proceedings.

Incident at the Akmene wind farm under construction in Lithuania

On 2 May 2023, a wind tower (together with a General Electric GE 158-5.X turbine) collapsed at the Akmene wind farm in Lithuania. No people were injured. The operation of all wind turbines at the Akmene wind farm has been suspended until the root causes of the incident are determined.

Current situation at the Akmene wind farm

At the date of release of this report, the investigation led by the wind turbine manufacturer General Electric involving, Enefit Green; Akmene wind farm construction company, Merko Statyba; an independent technical consultant to Enefit Green, DNV Services UK Limited (DNV); and the Akmene project insurer together with its independent technical experts at the Akmene wind farm is still ongoing. Enefit Green has been fully cooperating with all the levels of the Lithuanian Government and will continue to do so for the term of the investigation.

Since the incident, a series of activities have been undertaken to identify the root cause of the collapse, including turbine data analysis; site inspections; operational data review; operational safety assessments; tower strength assessments; turbine visual inspections; and so on. Enefit Green holds safety as its highest priority and activities on the site will be restarted once the cause of the collapse has been substantiated, and all parties involved in the investigation have the confidence that all necessary remediation measures have been implemented to avoid any recurrence of this specific or similar incident in the future.

No entry' safety perimeter has been established around the collapsed turbine to avoid any access to the site, other than supervised access for specific investigative purposes. The collapsed turbine dismantling, and removal methodology is under preparation by General Electric and BDT (JSC ''Vilniaus Betono Demontavimo Technika"). Before the turbine dismantling and removal process can commence, it will have to be assessed, verified and approved by all parties involved in the investigation.

Enefit Green is not in a position to make any further comments in respect of the financial impact of this incident at the Akmene wind farm.

Enefit Green's objective is to complete the commissioning of the entire wind farm (incl. the replacement of the wind turbine that was destroyed in the incident) in Q1 2024.

The Enefit Green group's operating income for Q2 2023 decreased by 13% while operating expenses for the period grew by 32% compared with Q2 2022. As a result, EBITDA decreased by 37% to €19.3m. Net profit for the period fell by €15.8m to €1.1m. The key factors which influenced the group's financial performance are described below.

Production and sales volumes

	Unit	Q2 2023	Q2 2022	Change	Change,%
Electricity production	GWh	265	270	(6)	(2)%
Incl. new wind and solar farms	GWh	56	-	56	-
Electricity sales*	GWh	357	284	73	26%
Heat energy production	GWh	141	152	(11)	(7)%
Pellet production	kt**	37	36	2	5%
Pellet sales	kt	12	7	4	54%

* 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

Total operating income decreased by €6.1m year on year, the figure comprising a decrease in revenue of €4.9m and a decrease in renewable energy support and other operating income of €1.2m. Out of the €4.9m decrease in revenue, €4.4m was attributable to electricity sales. Results weakened because the market prices of electricity were lower than a year earlier. The average electricity price*** in the group's core markets in Q2 2023 was 78.7 €/MWh (Q2 2022: 151.3 €/MWh). The group's average implied captured electricity price**** for the period was 89.9 €/MWh (Q2 2022: 126.8 €/MWh). The implied captured electricity price differs from the average market price in the core markets, because its calculation takes into account long-term fixed-price power purchase agreements (PPAs), renewable energy support, purchases of balancing energy, electricity purchases from the Nord Pool day-ahead and intraday markets, and the fact that wind farms do not produce the same amount of electricity every hour.

The group's average price of electricity sold to the market in Q2 2023 was 63.7 €/MWh compared with 127.6 €/MWh a year earlier. In Q2 2023, the group sold to the market 139 GWh of electricity compared with 182 GWh in Q2 2022.

In Q2 2023, 218 GWh of the group's portfolio was covered with PPAs at an average price of 83.5 €/MWh. A year earlier, 102 GWh of electricity was sold under an income model based on PPAs and the Feed-in Tariff (FiT) at an average price of 79.1 €/MWh. The share and prices of production covered with PPAs in future periods are disclosed in the risk management chapter.

Another factor which affected revenue was lower electricity production. In Q2 2023, the group produced 265 GWh of electricity, which is 2% less than in Q2 2022 (270 GWh). The decline was due to weaker wind conditions.

€ million	Q2 2023	Q2 2022	Change	Change, %
TOTAL OPERATING INCOME	41.2	47.3	(6.1)	(13)%
Revenue	36.6	41.5	(4.9)	(12)%
Renewable energy support and other op. income	4.6	5.8	(1.2)	(20)%
TOTAL OPERATING EXPENSES (excl. D&A)	21.9	16.5	5.3	32%
Raw materials, consumables and services used	20.6	16.4	4.2	26%
Payroll expenses	2.9	2.2	0.7	34%
Other operating expenses	3.3	2.6	0.6	24%
Change in inventories	(4.9)	(4.6)	(0.2)	5%
EBITDA	19.3	30.7	(11.5)	(37)%
Depreciation, amortisation and impairment (D&A)	9.7	9.6	0.1	1%
OPERATING PROFIT	9.6	21.1	(11.5)	(54)%
Net finance income	0.8	0.5	0.3	61%
Profit from associates under the equity method	0.0	(0.1)	0.1	(129)%
Income tax expense	9.3	4.6	4.7	102%
NET PROFIT	1.1	16.9	(15.8)	(93)%

TOTAL OPERATING EXPENSES (excl. D&A))	21.9	16.5	5.3	32%
Variable costs (incl. balancing energy purchases)	16.4	12.4	4.0	32%
Fixed costs	10.3	8.8	1.6	18%
Change in inventories	(4.9)	(4.6)	(0.2)	5%

Revenue from solar services in Q2 2023 was €2.2m smaller than in Q2 2022 because we exited the turnkey solar solutions business in mid-2022.

Pellet sales revenue grew by €1.7m compared with a year earlier. The average sales price of pellets increased by 53%, rising from 165.8 €/t in Q2 2022 to 253.6 €/t in Q2 2023. Pellet sales volume increased from 7 thousand tonnes in Q2 2022 to 12 thousand tonnes in Q2 2023.

The price of heat grew by 16% due to an increase in the price of biomass, but heat production decreased by 7%. Heat sales revenue remained at a level similar to Q2 2022.

*** 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

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

In Q2 2023, we purchased from the market 97 GWh of electricity at an average price of 83.8 €/MWh compared with 18 GWh at an average price of 175.1 €/MWh in the same period last year (the prices and quantities exclude the electricity purchased for pellet production). In Q2 2022, purchases from the market were smaller because part of the production was covered with the fixed-price FiT support scheme and the volume of PPAs was very small. Electricity purchases were also increased by lower than expected electricity production. The electricity price in Enefit Green's core markets, which is presented in the chart, is the average quarterly price in the Baltic and Polish markets, weighted by Enefit Green's production volumes. The price was 78.7 €/MWh in Q2 2023 and 151.3 €/MWh in Q2 2022.

Electricity produced, purchased and sold (GWh)

Electricity prices €/MWh	Q2 2022	Q3 2022	Q4 2022	Q1 2023	Q2 2023
Price of electricity sold to the market	127.6	285.2	179.0	82.4	63.7
PPA (until Q4 22 incl FiT) sale price	79.1	72.1	126.2	89.8	83.5
Realised purchase price	175.1	337.7	271.1	116.7	83.8
Core markets average*	151.3	317.7	221.5	100.5	78.7
Implied captured price**	126.8	205.1	163.0	101.4	89.9

Average quarterly electricity prices (€/MWh)

Other operating income

Other operating income for Q2 2023 was affected the most by the change in renewable energy support received by Estonian wind farms, which decreased by €1.5m compared with a year earlier. Renewable energy support is related to the quantity of electricity produced and as output decreased, the amount of renewable energy support received decreased as well. The eligibility periods of the Vanaküla and Virtsu III wind farms expired in Q3 2022. Other operating income was improved by the decrease in the non-derivative contract liability incurred in 2021 by €0.2m in connection with the partial fulfilment of relevant PPAs. The non-derivative contract liability results from earlier electricity derivatives (base load swaps) which were converted into fixed-price physical electricity sales contracts (PPAs). The decrease in the non-derivative contract liability does not affect cash flow and monetary settlement of electricity sales takes place on the basis of 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

Group's EBITDA change by drivers, €m

Expenses on raw materials, consumables and services grew by €4.2m (26%). The biggest rise was in electricity expenses, which grew by €4.4m due to growth in electricity purchased to balance the Nord Pool intraday market portfolio and the electricity purchased to balance the PPA portfolio in hours of low wind speed; a contributing factor was lower than expected production volume. The quantities and prices of electricity purchased from the market are disclosed in the operating income chapter. Expenses on technological fuel grew by €1.6m due to an increase in the price of biomass. Average biomass expenses in the pellet production business grew by 59%: biomass expenses in Q2 2023 were 148.8 €/t compared with 98.1 €/t in Q2 2022. Other direct production costs decreased by €2.0m because in mid-2022 we exited the turnkey solar solutions business.

Payroll expenses

The group's payroll expenses grew by 34% year on year due to an increase in the number of full-time employees from 177 to 197 and due to increased compensation of existing employees. New people were mostly hired to the development team to support the group's growth plan in all its markets.

30.7 19.3 (12.1) +6.5 (6.8) +1.9 +0.6 +0.2 (1.6) (0.2) EBITDA Q2 2022 Sold electricity price impact Sold electricity quantity impact Purchased electricity quantity impact Purchased electricity price impact Cogeneration (excl. Volume and price of electricity) Decrease in nonderivative contract liability Fixed cost Other EBITDA Q2 2023 EBITDA -11.5 (-37.2%) Impacted by electricity production

Other operating expenses

Other operating expenses grew by €0.6m (22%), driven by growth in the research and consulting expenses of development projects as well as a slight increase in IT and communication expenses.

Change in inventories

The change in inventories reflects the change in pellet stocks, summarising the quantities of pellets produced and sold in the period under review. In Q2 2023, the group produced 37 thousand tonnes (Q2 2022: 36 thousand tonnes) and sold 12 thousand tonnes (Q2 2022: 7 thousand tonnes) of pellets. The change in inventories was negative at €4.9m (Q2 2022: negative at €4.6m). The average sales price of pellets increased by 53% compared with a year earlier, rising from 165.8 €/t in Q2 2022 to 253.6 €/t in Q2 2023.

EBITDA and fixed costs

The factor with the strongest impact on EBITDA development was the price of electricity sold, which fell steeply compared with Q2 2022 (negative impact €12.1m). Due to PPAs the quantity of electricity sold grew considerably (positive impact €6.5m), which increased the volume of electricity purchased to balance the electricity portfolio (negative impact €6.8m). The combined effect of the above factors on EBITDA is influenced by the quantity and profile of electricity produced during the period. Electricity production decreased by 2% compared with Q2 2022.

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

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

Fixed costs comprise costs not directly dependent on the production volume. Fixed costs grew by €1.6m (18%) year on year. The increase in fixed costs was driven by development activities and related overheads and management expenses, including personnel and research and consulting expenses.

Depreciation, amortisation and impairment losses (D&A)

D&A expense remained stable compared with the same period last year. Although the group made capital investments of €74.6m in Q2 2023, this did not affect D&A because investments were mostly made in wind and solar farm development projects which are still in the construction phase.

Net finance income

Net finance income grew by €0.3m compared with Q2 2022. Interest expense on bank loans grew by €1.8m but it was fully capitalised due to the construction period of the wind farms. Net finance income was supported by growth in interest income.

Income tax

Income tax expense grew by €4.7m due to the payment of dividends. Under the Estonian income tax regulation, resident companies pay income tax when profit is distributed in the form of dividends or other profit distributions. Consistent with the resolution adopted by the shareholders' general meeting in May, dividends for 2022 were paid out in June 2023.

Net profit

The group's net profit for Q2 decreased by €15.8m to €1.1m. The decrease is attributable to lower electricity prices, higher expenses on electricity purchased to balance the electricity portfolio, and higher income tax expense.

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 61% of EBITDA for Q2 2023. The Cogeneration segment contributed 34% to operating income and 40% to EBITDA. The smallest reportable segment is Solar energy, which accounted for 7% the group's operating income for Q2 2023.

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

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

Group's EBITDA breakdown and change, €m

Wind energy segment

Enefit Green Q2 2023 interim report 17

96.3

94.9

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 Q2 2023, wind conditions in Estonia and Lithuania were the recent years' weakest: the average measured wind speed in our wind farms was 5.2 m/s both in Estonia and Lithuania (Q2 2022: 5.9 m/s and 5.8 m/s, respectively). There were also some issues with the availability of the Lithuanian wind farms, which dropped in Q2. A major factor was the replacement of some main components at the Šilute wind farm.

Compared with the same period last year, our wind power production was 24% lower in Estonia and 13% higher in Lithuania. In Lithuania, the Šilale wind farm, which is still under construction, started generating electricity and the Akmene wind farm, which is also under construction, also supplied electricity until the incident in May. Altogether, we produced 191 GWh of wind power, which is 9% less than a year earlier. Wind farms still in the construction phase contributed nearly 40 GWh.

Electricity prices

In addition to the market price of electricity, our Estonian wind farms whose eligibility period has not expired receive renewable energy support in the form of Feed-in Premium (FiP) at the rate of 53.7 €/MWh. In Q3 2022, we replaced the previous Feed-in Tariff (FiT) based income model with a model based on PPAs and the market price at

all our Lithuanian wind farms. The implied captured electricity prices of both our Estonian and Lithuanian wind farms depend on the combination of the market price and PPAs.

The wind energy segment's implied captured electricity price in Q2 2023 was 86.9 €/MWh (a 26% decline compared with Q2 2022). The implied captured electricity price was affected by lower prices on the Nord Pool market, the addition of long-term PPAs, and lower than expected production which increased electricity purchase expenses. Altogether, the Wind energy segment sold 203.9 GWh of electricity under PPAs in Q2 2023.

Operating income

The Wind energy segment's operating income, which was affected by lower electricity production and a lower implied captured electricity price, dropped by 11.8% year on year to €23.9m.

Wind energy segment

Operating expenses

The operating expenses of the Wind energy segment (excl. D&A) grew by €5.5m year on year, rising to €12.1m. This was mainly due to electricity purchases made to balance the PPA portfolio in hours of low wind speed. Other operating expenses (excl. electricity purchases, expenses on balancing energy and growth in D&A) grew by €0.5m compared with the same period last year.

Operating expenses per MW

In Q2 2023, our wind farm operators' (Enefit Wind OÜ and Enefit Wind UAB) operating expenses (excl. D&A, balancing energy purchases and electricity purchased to balance the PPA portfolio) per installed capacity (MW) increased by 11.2% compared with Q2 2022 mainly due to indexation.

EBITDA

The Wind energy segment's EBITDA for Q2 2023 was €11.8m compared with €20.5m a year earlier. The decrease resulted from a decline in the market prices of electricity, lower electricity production and higher expenses on electricity purchased to balance the PPA portfolio.

Q2 Q1 Q4 Q2 Q1 Q4 Q3 Q3 Q2 Q2 Q1 Q1 8,9 9,3 8,0 8,6 9,0 10,0 +2,1 (+6,1%) Q2 Q1 Q4 Q2 Q1 Q4 34.8 36.9

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

Q3 Q3 Q4 Q4 8,9 9,0 2022/2021 2023/2022 Q3 Q3

*(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

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

Electricity production and prices

Production, GWh

The Cogeneration segment's electricity production in Q2 2023 was 43.6 GWh, which is less than a year earlier (Q2 2022: 46.7 GWh). The decline is attributable to planned maintenance at Iru and optimization of the production process at Valka power station under conditions of high fuel prices. In addition to the market price of electricity, the Iru and Paide CHP facilities receive renewable energy support of 53.7 €/MWh for electricity produced from renewable sources and efficient cogeneration support of 32 €/MWh for electricity produced from non-renewable sources in an efficient cogeneration mode. The Valka CHP has been selling electricity at the prices of the Nord Pool Latvia price area since mid-December 2022. Previously, it sold electricity at fixed prices ranging from 79.75 €/MWh to 105.6 €/MWh. The Broceni CHP facility lost its fixed electricity price of 143.6 €/MWh retrospectively from March 2021 due to the decision of the Latvian state construction control bureau 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. In May, the management of SIA Technological Solutions filed an appeal against the ruling. From November 2021 until the final resolution of the matter, the Broceni CHP facility will sell electricity at the prices of the Nord Pool Latvia price area.

Our cogeneration facilities' availability in Q2 was a high 97.7% (Q2 2022: 97.4%).

Due to lower market prices in the Nord Pool Estonia and Nord Pool Latvia price areas, the Cogeneration segment's implied captured electricity price in Q2 2023 was 104.6 €/MWh (40% lower than a year earlier).

Implied captured electricity price, €/MWh*

Heat energy production and prices

Heat production decreased by 7% to 141 GWh. The average sales price of heat per MWh increased by 16% compared with the same period last year, rising to nearly 14 €/MWh in Q2 2023. The price cap for heat produced by the Iru CHP was 7.98 €/MWh in both the reporting and the comparative period, but the price of heat produced by the Paide and Valka CHPs grew due to an increase in the price of biomass purchased by the facilities.

Operating income

The Cogeneration segment's operating income was €14.1m, 14% lower than in Q2 2022. Pellet sales revenue grew by €1.7m (136%) due to a higher sales price and a larger sales volume. The average sales price of pellets increased to 253.6 €/t (by 53%). Pellet sales volume in Q2 2023 was 12 thousand tonnes compared with 7 thousand tonnes in the same period last year. Revenue from gate fees decreased due to a decline in waste received by €0.1m to €3.9m. Heat sales revenue remained stable and other operating income decreased by €0.2m to €0.5m. Electricity sales revenue decreased by €3.7m to €3.7m due to a lower market price and a decline in production. Electricity production support remained stable compared with a year earlier.

Cogeneration segment

Operating expenses

The change in inventories reduced expenses for Q2 2023 by €4.9m because pellet production exceeded pellet sales. In Q2 2022, the situation was the same: pellet production exceeded pellet sales and the change in inventories was €4.6m. Compared with the same period in Q2 2022, the Cogeneration segment's expenses from the change in inventories decreased by €0.2m. The segments' variable costs for Q2 2023 grew by €0.9m, mainly due to an increase in the price of biomass, while electricity purchase expenses decreased. Average biomass expenses in pellet production grew by 59% compared with Q2 2022. The cost of biomass in Q2 2023 was 148.8€/t compared with 98.1 €/t in Q2 2022. The segment's fixed costs grew by €0.1m to €2.4m.

EBITDA

The Cogeneration segment's EBITDA for Q2 2023 was €7.8m, which is €3.0m (27%) lower than in the same period last year. The main reasons for the decline were higher biomass and lower electricity prices as well as a decrease in electricity production. The pellet sales price and volume had a positive impact on EBITDA.

EBITDA, €m -3.0 (-27.8%)

Solar energy segment

10%

Share of EBITDA Q2 2023

Enefit Green Q2 2023 interim report 21

Availabilities of solar farms (%)

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

Production

The Solar energy segment produced 29.5 GWh of solar power in Q2 2023, 16.5 GWh (126%) more than in the comparative period because two new solar farms came online in Q2: the Purtse solar farm in Estonia and the Zambrow solar farm in Poland. The availability of solar farms remained high at 99.9% (Q2 2022: 99.9%).

Electricity prices

Our solar farms in Estonia are partly exposed to movements in the market price of electricity. Most of our solar farms in Poland sell electricity at fixed prices which are adjusted for inflation on an annual basis – the price for Q2 2023 was 492–526 PLN/MWh (110 –118 €/MWh at the three-month average zloty (PLN) exchange rate). The Solar energy segment sold 14.2 GWh under PPAs in Q2 2023.

Operating income

The operating income of operating solar farms grew by €1.5m compared with Q2 2022, mainly due to higher electricity production resulting from two new solar farms coming online in Q2 this year.

EBITDA

The Solar energy segment's EBITDA for Q2 2023 was €1.9m, which is €0.7m higher than in the same period last year. The improvement was mainly driven by increased production and revenue from two new solar farms. EBITDA has also been influenced by growing fixed costs of development activities (including personnel and consultation expenses).

*(Electricity sales revenue + renewable energy support and efficient cogeneration support – electricity purchases on the Nord Pool day-ahead and intraday market – balancing energy purchases) / production

Investments

Investments during Q2

The group invested €74.6m in Q2 2023, which is €33.6m more than in Q2 2022. Growth resulted from development investments, which extended to €74.0m. Of the latter, €48.0m was invested in the construction of three wind farms: €31.7m in the Tolpanvaara wind farm, €13.9m in the Sopi-Tootsi wind farm and €2.4m in the Akmene wind farm. The largest solar farm development investment was made in the Vändra solar project in the amount of €9.4m.

Expenditure on the maintenance and improvement of existing assets amounted to €0.5m in Q2 2023, which is €0.5m less than in Q2 2022. Maintenance expenditure in Q2 2023 was mainly related to the Iru CHP whereas in the comparative period it was mostly related to the Estonian wind farms. Maintenance expenditure on wind farms may fluctuate significantly quarter by quarter as it depends on the wind turbines' repair and maintenance needs.

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 30 June 2023 was €358.9m (31 December 2022: €279.6m). Loan liabilities to banks accounted for €353.9m of the total, including an outstanding loan balance of €6.4m denominated in Polish zloty.

In Q2, Enefit Green drew down the €50m raised under three previously signed revolving credit facility agreements which mature in the period 2024–2026 and €40m of an investment loan raised from NIB which matures in 2034.

The interest rate risk of investment loans with the total outstanding balance of €163.2m has been hedged with interest rate swaps, which fix the interest rates of the loans in the range of 1.049% – 1.125% (plus the margin), until the loans mature.

The average interest rate of bank loans drawn down at 30 June 2023 was 3.44% (31 December 2022: 2.60%). Investment loans raised but not drawn down at 30 June amounted to €285m.

Loan covenants

The group's loan and credit agreements include covenants which set certain limits to the group's consolidated financial indicators. At 30 June 2023, the group was in compliance with all loan terms and conditions, including the covenants.

Financing and return ratios

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

Loan repayment schedule, €m

Net debt/EBITDA Financial leverage

€ million	31 Dec 2022	30 June 2023
Interest-bearing liabilities	279.6	358.8
Less cash and cash equivalents	(131.5)	(53.0)
Net debt	148.1	305.9
Equity	718.7	696.4
Invested capital	866.8	1,002.2
EBITDA (LTM)*	154.8	138.9
Operating profit (LTM)	117.1	100.9
Net profit (LTM)	110.2	90.0

Financial leverage (1)	17%	31%
Net debt/LTM EBITDA	0.96	2.20
Return on invested capital (2)	13.5%	10.1%
Return on equity (3)	15.3%	12.9%
Interest cover (4)	42.8	19.7

* LTM – last twelve months

(net debt + equity)

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

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

(3) Return on equity = LTM net profit / equity (4) Interest cover= LTM EBITDA/ interest expense

4 217

Risk management

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 a goal that generally, 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.

At 30 June 2023, the group had signed PPAs on 10,100 GWh at an average price of 71.7 €/MWh.

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

The chart below provides an overview of the next years' forecasted production volumes and their coverage with risk mitigation measures as at 30 June 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.

Forecasted production volumes of production assets (operating, under construction and planned) and their coverage with PPAs and renewable support measures, GWh 332 3 311

4 052

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

	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	97.3	96.5	98.5	100.5	102.6	99.1

Share of production covered by FiP**	32%	24%	9%	3%	3%	12%
Volume (GWh)	509	503	274	99	79	1,466
Weighted average FiP, EUR/MWh (added to the market price)	50.1	50.2	50.4	53.7	53.7	50.6

Share of production covered by PPAs**	60%	64%	51%	52%	52%	55%
Volume (GWh)	953	1,331	1,533	1,534	1,550	6,901
PPA weighted average price, EUR/MWh	86.9	67.6	64.8	64.8	69.0	69.4

* 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 Q2 2023

Condensed consolidated interim income statement

€ thousand	Note	Q2 2023	Q2 2022	H1 2023	H1 2022
Revenue	9	36,556	41,505	105,341	99,646
Renewable energy support and other operating income	10	4,610	5,773	13,329	14,352
Change in inventories of finished goods and work in progress		4,892	4,646	(168)	2,579
Raw materials, consumables and services used	11	(20,583)	(16,365)	(45,375)	(30,499)
Payroll expenses		(2,905)	(2,169)	(5,391)	(4,612)
Depreciation, amortisation and impairment		(9,707)	(9,644)	(19,522)	(19,292)
Other operating expenses		(3,274)	(2,645)	(7,329)	(5,150)
OPERATING PROFIT		9,589	21,101	40,885	57,025
Finance income		1,191	1,117	1,598	1,525
Finance costs		(402)	(626)	(782)	(1,188)
Net finance income		789	491	816	337
Profit (loss) from associates under the equity method		22	(76)	41	(72)
PROFIT BEFORE TAX		10,400	21,516	41,742	57,290
Income tax expense		(9,260)	(4,592)	(10,080)	(5,441)
PROFIT FOR THE PERIOD		1,140	16,924	31,662	51,849
Basic and diluted earnings per share
Weighted average number of shares, thousand	6	264,276	264,276	264,276	264,276
Basic earnings per share, €	6	0.004	0.06	0.12	0.20
Diluted earnings per share, €	6	0.004	0.06	0.12	0.20

Condensed consolidated statement of other comprehensive income

€ thousand	Note	Q2 2023	Q2 2022
PROFIT FOR THE PERIOD		1,140	16,924
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Remeasurement of hedging instruments in cash flow hedges (incl. reclassifications to profit or loss)	5, 7	1,228	5,586
Exchange differences on the translation of foreign operations	7	436	(106)
Other comprehensive income for the period		1,664	5,480

TOTAL COMPREHENSIVE INCOME FOR THE PERIOD		2,804	22,404

Condensed consolidated interim statement of financial position

€ thousand	Note	30 Jun 2023	31 Dec 2022
ASSETS				EQUITY
Non-current assets
Property, plant and equipment	4	899,039	776,870	parent
Intangible assets		60,304	60,382
Right-of-use assets		4,510	4,239
Prepayments for non-current assets	4	45,462	19,412
Deferred tax assets		1,751	1,321
Investments in associates		547	506
Derivative financial instruments	5, 7	8,866	11,277
Non-current receivables		40	40
Total non-current assets		1,020,519	874,047

Current assets
Inventories		14,265	14,227
Trade and other receivables and prepayments		37,304	41,091
Cash and cash equivalents		52,996	131,456
Derivative financial instruments	5	4,887	3,349
Total current assets		109,452	190,123
Total assets		1,129,971	1,064,170

€ thousand	Note	30 Jun 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		5,555	3,259
Other reserves	5, 7	166,959	166,419
Foreign currency translation reserve	7	(361)	(762)
Retained earnings		199,586	225,190
Total equity		696,366	718,733

LIABILITIES
Non-current liabilities
Borrowings	8	283,032	255,755
Government grants		6,879	7,115
Non-derivative contract liability	5, 7	18,086	18,086
Deferred tax liabilities		12,482	12,326
Other non-current liabilities		3,000	3,000
Provisions		9	9
Total non-current liabilities		323,488	296,291
Current liabilities
Borrowings	8	75,818	23,808
Trade and other payables		31,698	20,215
Provisions		2	2
Non-derivative contract liability	5	2,599	5,121
Total current liabilities		110,117	49,146
Total liabilities		433,605	345,437
Total equity and liabilities		1,129,971	1,064,170

Condensed consolidated interim statement of cash flows

€ thousand	Note	Q2 2023	Q2 2022
Cash flows from operating activities
Cash generated from operations	12	14,006	22,898

Interest and loan fees paid		(2,084)	(495)
Interest received		207	3
Income tax paid		(631)	(1,001)
Net cash generated from operating activities		11,498	21,405

Cash flows from investing activities Purchase of property, plant and equipment and intangible assets	4	(69,907)	(34,739)
Acquisition of a subsidiary*		0	0
Proceeds from sale of property, plant and equipment		0	0
Proceeds from sale of a business		0	718
Net cash used in investing activities		(69,907)	(34,021)

Cash flows from financing activities
Proceeds from bank loans	8	90,000	40,000
Repayments of bank loans	8	(4,040)	(5,027)
Repayments of lease principal	8	(95)	(47)
Dividends paid		(54,969)	(39,906)
Net cash generated from (used in) financing activities		30,896	(4,980)

Net cash flow		(27,513)	(17,596)
Cash and cash equivalents at the beginning of the period		80,509	108,441
Cash and cash equivalents at the end of the period		52,996	90,845
Change in cash and cash equivalents		(27,513)	(17,596)

* In the statement of cash flows for Q1, acquisition of a subsidiary of €6,174k was reported in 'Purchase of property, plant and equipment and intangible assets'.

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	51,849	51,849
Other comprehensive income for the period	0	0	0	6,524	(244)	0	6,280
Total comprehensive income for the period	0	0	0	6,524	(244)	51,849	58,129
Increase of statutory capital reserve	0	0	2,780	0	0	(2,780)	0
Dividends paid	0	0	0	0	0	(39,906)	(39,906)
Total contributions by and distributions to shareholders of the company, recognised directly in equity	0	0	2,780	0	0	(42,686)	(39,906)
Equity as at 30 June 2022	264,276	60,351	3,259	158,317	(1,209)	166,836	651,830

Equity as at 31 December 2022	264,276	60,351	3,259	166,419	(762)	225,190	718,733
Profit for the period	0	0	0	0	0	31,662	31,662
Other comprehensive income for the period	0	0	0	540	401	0	941
Total comprehensive income for the period	0	0	0	540	401	31,662	32,603
Increase of statutory capital reserve	0	0	2,296	0	0	(2,296)	0
Dividends paid	0	0	0	0	0	(54,970)	(54,970)
Total contributions by and distributions to shareholders of the company, recognised directly in equity	0	0	2,296	0	0	(57,266)	(54,970)
Equity as at 30 June 2023	264,276	60,351	5,555	166,959	(361)	199,586	696,366

Notes to the condensed consolidated interim financial statements

1. Summary of significant accounting policies

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

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

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

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

2. Financial risk management

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

The group uses interest rate swaps (IRS) for interest rate risk management. Interest rate risk is the risk that the fair value or future cash flows of financial instruments will fluctuate because of changes in market interest rates. Cash flow interest rate risk arises from the group's 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: raising floating-rate borrowings and fixing their interest expenses with IRS instruments. Information on IRS transactions is disclosed in note 5.

The group regards equity and borrowings (debt) as capital. In order to maintain or change its capital structure, the group may change the dividend distribution rate, repay capital contributions to shareholders, issue new shares or sell assets to reduce its financial liabilities, and raise debt capital in the form of loans. On raising loans, management assesses the group's ability to service the principal and interest payments with operating cash flow and, where necessary, starts timely negotiations to refinance existing loans before their maturity. For further information about financing ratios and borrowings, see the Financing chapter in the management report.

3. Segment reporting

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

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

1. Wind energy (comprises all of the group's wind farms);
1. Cogeneration (comprises all of the group's cogeneration facilities and the pellet factory);
1. Solar energy (comprises all of the group's solar farms);
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 sold products and services, there are no intragroup transactions between segments to be eliminated.

Management assesses segment results mainly on the basis of EBITDA, but also monitors operating profit. Finance income and costs, income tax expense and profits and losses on investments in equity-accounted investees (associates) are not allocated to operating segments.

The group's non-current assets are allocated to segments based on their purpose of use. Liabilities and current assets are not allocated to segments.

3. Segment reporting (cont.)

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
REVENUE
Wind energy	20,965	22,832	58,911	57,448
Cogeneration	12,638	14,762	42,779	36,879
Solar energy	2,773	3,782	3,267	5,060
Total reportable segments	36,376	41,375	104,957	99,388
Other	179	130	384	258
Total	36,556	41,505	105,341	99,646
RENEWABLE ENERGY SUPPORT AND OTHER INCOME
Wind energy	2,952	4,280	9,841	11,118
Cogeneration	1,422	1,530	3,232	3,221
Solar energy	231	(45)	247	(13)
Total reportable segments	4,605	5,765	13,319	14,326
Other	5	8	10	26
Total	4,610	5,773	13,329	14,352
EBITDA
Wind energy	11,826	20,517	42,651	55,237
Cogeneration	7,806	10,809	20,677	22,892
Solar energy	1,865	1,206	1,430	1,826
Total reportable segments	21,498	32,532	64,758	79,955
Other	(2,202)	(1,786)	(4,351)	(3,637)
Total	19,296	30,746	60,408	76,318
Depreciation, amortisation and impairment losses	9,707	9,644	19,522	19,293
Net finance income	789	491	816	337
Profit (loss) from associates under the equity method	22	(76)	41	(72)
Profit before tax	10,400	21,517	41,660	57,434
OPERATING PROFIT
Wind energy	5,010	13,676	28,902	41,584
Cogeneration	5,225	8,259	15,518	17,760
Solar energy	1,633	978	973	1,371
Total reportable segments	11,869	22,914	45,392	60,715
Other	(2,280)	(1,812)	(4,507)	(3,689)
Total	9,589	21,102	40,885	57,025

3. Segment reporting (cont.)

€ thousand	Q2 2023	Q2 2022	2023	H1 2022
INVESTMENTS IN NON-CURRENT ASSETS
Wind energy	53,068	38,761	130,702	50,961
Cogeneration	555	464	750	613
Solar energy	18,799	1,290	30,879	2,451
Total reportable segments	72,422	40,514	162,332	54,024
Other	2,136	399	4,164	636
Total	74,557	40,914	166,495	54,660

€ thousand	30 Jun 2023	31 Dec 2022
NON-CURRENT ASSETS
Wind energy	779,282	668,422
Cogeneration	130,039	134,510
Solar energy	93,516	55,035
Total reportable segments	1,002,838	857,968
Other	17,681	16,079
Total	1,020,519	874,047

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)
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	201	140,886	25,408	166,495
Exchange differences	0	8	23	490	498	9	1,028
Transfers	2	1	2	3,050	(3,688)	633	0
Depreciation and impairment	0	(352)	(635)	(18,317)	0	0	(19,304)
Total movements in H1 2023	2	(343)	(610)	(14,576)	137,696	26,050	148,219
Property, plant and equipment as at 30 June 2023
Cost	63,955	25,582	42,243	755,262	341,333	45,462	1,273,837
Accumulated depreciation	0	(10,737)	(25,649)	(292,932)	(18)	0	(329,336)
Total property, plant and equipment as at 30 June 2023	63,955	14,845	16,594	462,330	341,315	45,462	944,501

At 30 June 2023, the group had committed to capital expenditures of €428,936k (31 December 2022: €89,623k and 30 June 2022: €182,701k).

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

Derivatives are initially recognised at fair value on the date the derivative contract is entered into and are subsequently measured at their fair value. The method for recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if it is, the nature of the item being hedged. At 30 June 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 30 June 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 €552k in Q2 2023 and was €(11,014)k at 30 June 2023.

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

At 31 December 2022, the liability of €23,207k was classified into a current portion of €5,121k and a 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 30 June 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 €36,667k whereby the group receives interest at a rate equal to 6 month EURIBOR and pays a fixed rate of interest of 1.125%. The swap is designed to hedge the exposure to the interest rate risk of a floating-rate loan taken out on 30 June 2022.

The interest rate swaps have been designated as hedging instruments in cash flow hedges. There is an economic relationship between the hedging instruments (interest rate swaps) and the hedged items (the loan agreements) because as at 30 June 2023 the main terms of the interest rate swaps matched the terms of the loans (i.e. their notional amounts, currencies, and maturity, payment and other dates). The forward hedges have a hedge ratio of one to one. To test the hedge effectiveness, the group uses the hypothetical derivative method and compares the changes in the fair values of the interest rate swaps against the changes in the fair values of the loan agreements. Hedge ineffectiveness can arise from the following sources:

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

At 30 June 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	163,189	13,753	0	Derivatives	1,437	0	761

* Change compared to 31 March 2023, recognised in other comprehensive income

At 30 June 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	13,753	13,753	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 30 June 2023, the number of the registered shares of Enefit Green AS amounted to 264,276,232 (30 June 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 general meeting of the company's shareholders, which took place in May, approved the proposal of the management board to pay dividends of €54,969k (€0.208 per share) for the financial year ended 31 December 2022. The list of shareholders entitled to the dividend was determined in accordance with the resolution of the general meeting on 8 June 2023 and the dividends were paid out on 15 June 2023.

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

	Unit	Q2 2023	Q2 2022	H1 2023	H1 2022
Profit attributable to shareholders of the parent	€ thousand	1,140	16,924	31,662	51,849

Weighted average number of shares	thousand	264,276	264,276	264,276	264,276
Basic earnings per share	€	0.004	0.06	0.12	0.20
Diluted earnings per share	€	0.004	0.06	0.12	0.20

H1 2022	H1 2023
51,849	31,662

264,276	264,276
0.20	0.12
0.20	0.12

7. Other reserves

€ thousand	30 June 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 (IRS) transactions	14,626	0
of which electricity cash flow hedge reserve	(12,426)	(12,426)
of which fair value on initial recognition of a derivative transaction with the parent	(10,781)	(10,781)
of which other reserves	175,000	175,000

Change in fair value of cash flow hedges	1,412	0
of which electricity cash flow hedge reserve	1,412	0
Interest rate swap (IRS) transactions	441	14,529
Recognised as an increase in interest expense	(1,313)	97
Exchange differences on the translation of foreign operations	401	203

Other reserves at the end of the period	166,598	165,657
of which currency translation reserve	(361)	(762)
of which interest rate swap (IRS) transactions	13,754	14,626
of which electricity cash flow hedge reserve	(11,014)	(12,426)
of which fair value on initial recognition of a derivative transaction with the parent	(10,781)	(10,781)
of which other reserves	175,000	175,000

8. Borrowings at amortised cost

€ thousand	Current borrowings		Non-current borrowings
	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	50,000	59	40,000	418	90,477
Repayments of borrowings	(11,177)	(179)	0	0	(11,356)
Non-monetary movements
Transfers	13,269	0	(13,269)	0	0
Amortisation of borrowings costs	0	0	(235)	0	(235)
Other movements	33	5	308	55	401
Total movements in H1 2023	52,125	(115)	26,804	473	79,287

Borrowings at amortised cost as at 30 June 2023	75,521	297	278,381	4,651	358,850

9. Revenue

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
Revenue by activity
Sale of goods
Pellets	2,921	1,234	18,597	9,408
Scrap metal	192	349	455	640
Other goods	17	53	26	98
Total sale of goods	3,130	1,636	19,078	10,146

Sale of services
Heat	1,647	1,567	4,923	3,922
Electricity	27,549	31,762	72,174	73,870
Waste reception and resale	3,859	3,947	8,452	8,238
Rental and maintenance of assets	289	2,391	537	3,244
Other services	82	202	177	226
Total sale of services	33,426	39,869	86,263	89,500
Total revenue	36,556	41,505	105,341	99,646

External sales of guarantees of origin of €81k in Q1 and €173k in Q2 were reclassified from sales of other goods to sales of electricity.

10. Renewable energy support and other operating income

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
Renewable energy support	4,355	5,614	11,623	13,896
Government grants	112	71	235	206
Gain on derivative financial instruments	204	0	1,110	0
Other income	(61)	88	361	250
Total renewable energy support and other operating income	4,610	5,773	13,329	14,352

H1 2023	H1 2022
11,623	13,896
235	206
1,110	0
361	250
13,329	14,352

11. Raw materials, consumables and services used

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
Maintenance and repairs	4,033	3,816	7,135	6,801
Technological fuel	6,371	4,704	14,730	8,983
Electricity	8,731	4,304	20,192	8,989
Services related to ash treatment	475	561	1,038	1,356
Transport services for sale of finished goods	303	350	872	811
Materials and spare parts for production	361	2,291	772	2,989
Transmission services	107	93	222	120
Waste handling	99	105	179	184
Resource charges for natural resources	2	2	3	4
Other raw materials, consumables and services used	38	66	88	110
Environmental pollution charges	63	73	144	152
Total raw materials, consumables and services used	20,583	16,365	45,375	30,499

12. Cash generated from operations

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
Profit before tax	10,400	21,516	41,742	57,290
Adjustments
Depreciation and impairment of property, plant and equipment	9,598	9,618	19,304	19,238
Amortisation and impairment of intangible assets	109	26	218	55
Amortisation of government grants related to assets	(112)	(71)	(235)	(206)
Interest expense on borrowings	61	214	441	532
Gain on sale of a business	0	(639)	0	(639)
(Profit) loss from associates using the equity method	(22)	76	(41)	72
Gain on disposal of property, plant and equipment	0	0	0	(3)
Interest and other finance income	(207)	(3)	(518)	(6)
Foreign exchange (gain) loss on loans granted and taken	326	(56)	341	(148)
Realised gain on derivative financial instruments	(204)	0	(1,109)
Adjusted profit before tax	19,949	30,681	60,143	76,185
Net change in current assets related to operating activities
Change in receivables related to operating activities	4,147	3,052	4,486	3,131
Change in inventories	(5,638)	(8,478)	(38)	(6,738)
Net change in other current assets related to operating activities	5,437	(2,252)	(375)	(4,097)
Total net change in current assets related to operating activities	3,946	(7,678)	4,073	(7,704)
Net change in current liabilities related to operating activities
Change in provisions	(1)	(1)	(1)	(2)
Change in trade payables	2,118	956	3,335	2,607
Net change in other current liabilities related to operating activities	(12,006)	(1,060)	(9,207)	(2,171)
Total net change in current liabilities related to operating activities	(9,889)	(105)	(5,873)	434
Cash generated from operations	14,006	22,898	58,343	68,915

13. Transactions and balances with related parties

The parent of Enefit Green AS is Eesti Energia AS. At 30 June 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 30 June 2023, Enefit Green AS had signed long-term physical electricity sales contracts of 8,940 GWh with Eesti Energia AS for the supply of electricity in the Lithuanian, Estonian, Finnish and Polish electricity networks in the period July 2023 – December 2033. The contracts are for the supply of both annual and monthly base load energy. The weighted average price of the physical electricity sales contracts signed with the related party is 68.9 €/MWh. The increased share of PPAs in total sales of electricity has resulted in increased sale of services to the parent.

At the beginning of 2021, the group used base load swap derivative contracts in order to hedge the exposure to variability in the price of electricity. The initial fair value of the derivatives designated as hedging instruments of €(10,781)k was recognised directly in equity.

The group continued to apply hedge accounting to the open derivatives position until 17 August 2021 when an EFET General Agreement Concerning the Delivery and Acceptance of Electricity (EFET General Agreement) was signed and all open derivative contracts were simultaneously terminated. The negative value of the derivative financial instruments classified as liabilities increased from €(10,781)k at the trade date to €(23,207)k due to the change in the electricity price in the period from the trade date to 17 August 2021. The cumulative change in the fair value of the derivative financial instruments of €(12,426)k was recognised through other comprehensive income and the cash flow hedge reserve in equity (see also note 5). At 30 June 2023, the balance of the electricity cash flow hedge reserve was €(11,014)k (see also notes 5 and 7).

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
TRANSACTIONS
PARENT
Purchase of services	2,950	2,770	7,414	5,359
Sale of goods	0	0	0	0
Sale of services	16,111	4,265	39,568	6,599
OTHER GROUP COMPANIES
Purchase of goods	0	2	0	8
Purchase of services	704	1,046	1,561	2,016
Sale of goods	0	0	0	0
Sale of services	322	2,025	742	4,001
OTHER RELATED PARTIES (INCL.	ASSOCIATES)
Purchase of services	428	375	884	742
Sale of services	0	2	0	2
ELERING AS
Purchase of services	18,472	82	20,059	113

€ thousand	Q2 2023	Q2 2022	H1 2023	H1 2022
TRANSACTIONS
PARENT
Purchase of services	2,950	2,770	7,414	5,359
Sale of goods	0	0	0	0
Sale of services	16,111	4,265	39,568	6,599
OTHER GROUP COMPANIES
Purchase of goods	0	2	0	8
Purchase of services	704	1,046	1,561	2,016
Sale of goods	0	0	0	0
Sale of services	322	2,025	742	4,001
OTHER RELATED PARTIES (INCL.	ASSOCIATES)
Purchase of services	428	375	884	742
Sale of services	0	2	0	2
ELERING AS
Purchase of services	18,472	82	20,059	113
Sale of services	4,425	5,960	11,755	14,328

Group structure

Indirect ownership

Associates

AI Terminal

Enefit Green

2216_ir_2023-08-03_53ab602e-b833-46b4-b758-780a42578d64.pdf

Contents

Letter from the Chairman of the Management Board

Dear reader

Path towards 4X growth: 62MW added to operating portfolio during Q2

2Q 2023 Key highlights

Operating environment

Key factors influencing the operating environment

Electricity market

Quarterly average electricity prices on Enefit Green core markets and in Nordic countries

Operating environment

Wind conditions

Regulatory environment

Significant events

We began building the 74 MW Sopi solar farm

We opened Estonia's first wind-solar hybrid farm

EIA report for the North-West Estonia offshore wind farm

Incident at the Akmene wind farm under construction in Lithuania

Current situation at the Akmene wind farm

Production and sales volumes

Operating income

Average quarterly electricity prices (€/MWh)

Other operating income

Raw materials, consumables and services used

Payroll expenses

Other operating expenses

Change in inventories

EBITDA and fixed costs

Depreciation, amortisation and impairment losses (D&A)

Net finance income

Income tax

Net profit

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

EBITDA

Cogeneration segment

Electricity production and prices

Our cogeneration facilities' availability in Q2 was a high 97.7% (Q2 2022: 97.4%).

Heat energy production and prices

Operating income

Cogeneration segment

Operating expenses

EBITDA

Solar energy segment

Production

Electricity prices

Operating income

EBITDA

Investments

Investments during Q2

Financing

Loan covenants

Financing and return ratios

Loan repayment schedule, €m

Risk management

Price risk of electricity sales

Interest rate risk

Condensed consolidated interim financial statements Q2 2023

Condensed consolidated interim income statement

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