2022 Management Report and Annual Consolidated Financial Statements

2022 MANAGEMENT REPORT
AND ANNUAL
CONSOLIDATED FINANCIAL
STATEMENTS
CONTENTS
1 ENGIE 2022 RESULTS..............................................................................................................................................7
2 OTHER INCOME STATEMENT ITEMS ............................................................................................................... 21
3 CHANGES IN NET FINANCIAL DEBT ................................................................................................................. 23
4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL POSITION .................................................................. 28
5 PARENT COMPANY FINANCIAL STATEMENTS ............................................................................................. 29
02 CONSOLIDATED FINANCIAL STATEMENTS

INCOME STATEMENT .......................................................................................................................................................... 32
STATEMENT OF COMPREHENSIVE INCOME ............................................................................................................... 33
STATEMENT OF FINANCIAL POSITION........................................................................................................................... 34
STATEMENT OF CHANGES IN EQUITY........................................................................................................................... 36
STATEMENT OF CASH FLOWS ......................................................................................................................................... 38
03 NOTES TO THE CONSOLIDATED FINANCIAL

STATEMENTS
Note 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL
STATEMENTS ........................................................................................................................................................................ 41
Note 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2022................................................................................................ 46
Note 3 INVESTMENTS IN EQUITY METHOD ENTITIES .............................................................................................. 52
Note 4 MAIN CHANGES IN GROUP STRUCTURE ....................................................................................................... 60
Note 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ............................................................ 64
Note 6 SEGMENT INFORMATION.................................................................................................................................... 69
Note 7 REVENUES .............................................................................................................................................................. 74
Note 8 OPERATING EXPENSES ...................................................................................................................................... 79
Note 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES............................................... 81
Note 10 NET FINANCIAL INCOME/(LOSS) ....................................................................................................................... 84
Note 11 INCOME TAX EXPENSE........................................................................................................................................ 85
Note 12 EARNINGS PER SHARE ....................................................................................................................................... 89
Note 13 FIXED ASSETS ........................................................................................................................................................ 90
Note 14 FINANCIAL INSTRUMENTS ................................................................................................................................ 105
Note 15 RISKS ARISING FROM FINANCIAL INSTRUMENTS..................................................................................... 124
Note 16 EQUITY ................................................................................................................................................................... 143
ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

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Note 17 PROVISIONS ......................................................................................................................................................... 147
Note 18 POST-EMPLOYMENT BENEFITS AND OTHER LONG-TERM BENEFITS ............................................... 157
Note 19 SHARE-BASED PAYMENTS............................................................................................................................... 166
Note 20 RELATED PARTY TRANSACTIONS ................................................................................................................. 170
Note 21 EXECUTIVE COMPENSATION .......................................................................................................................... 172
Note 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES, OTHER ASSETS AND OTHER LIABILITIES 173
Note 23 LEGAL AND ANTI-TRUST PROCEEDINGS ..................................................................................................... 175
Note 24 SUBSEQUENT EVENTS ...................................................................................................................................... 182
Note 25 FEES PAID TO THE STATUTORY AUDITORS AND TO MEMBERS OF THEIR NETWORKS .............. 183
Note 26 INFORMATION REGARDING LUXEMBOURG AND DUTCH COMPANIES EXEMPTED FROM THE
REQUIREMENTS TO PUBLISH ANNUAL FINANCIAL STATEMENTS...................................................................... 184

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5
1 ENGIE 2022 RESULTS..............................................................................................................................................7
2 OTHER INCOME STATEMENT ITEMS ............................................................................................................... 21
3 CHANGES IN NET FINANCIAL DEBT ................................................................................................................. 23
4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL POSITION .................................................................. 28
5 PARENT COMPANY FINANCIAL STATEMENTS ............................................................................................. 29

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MANAGEMENT REPORT
1 ENGIE 2022 RESULTS
ENGIE FY 2022 Financial results

Significant progress on execution of strategic plan
Strong financial and operational performance
Proposal to pay a dividend of €1.40 per share for 2022
Business Highlights Financial Performance
• Leading role played by ENGIE to support security • 2022 guidance achieved with continuing NRIgs of
of supply in Europe €5.2 billion
• Continued contribution to public policy measures • EBIT of €9.0 billion, up 43% organically, with growth
through Working Capital support, extraordinary across most activities. Key contribution from GEMS
taxes and dedicated customer actions and Thermal in unprecedented market conditions as
• Major progress on simplification with €11.0 billion well as from new capacity additions for Renewables
disposals signed or closed • Impact of windfall profit taxes of €0.9 billion in 2022,
• €5.5 billion growth Capex, primarily in mainly in Belgium and Italy, in addition to existing
Renewables, Networks and Energy Solutions Government profit sharing mechanisms in Belgium
• Acceleration in Renewables with +3.9 GW of and France (nuclear and hydro) of €1.1 billion
capacity added in 2022, taking total installed • Strong balance sheet and high liquidity with
capacity to c. 38 GW improvement in credit ratios
• Further progress on coal exit, coal represents • Improved Cash Flow From Operations (1), despite
2.6% of centralised generation capacity Working Capital headwinds due to energy prices
• Net financial debt at €24.1 billion, down €1.3 billion.
• 2022 proposed dividend of €1.40 per share
1.1 Key financial figures at December 31, 2022
% change % change
(reported (organic
In billions of euros Dec 31, 2022 Dec 31, 2021 basis) basis) (1)
Revenues 93.9 57.9 +62.2% +60.4%
EBITDA 13.7 10.6 +29.8% +27.0%
EBIT 9.0 6.1 +47.2% +42.7%
Net recurring income of continuing activities, Group share 5.2 2.9 +78.4% +76.2%
Net income, Group share 0.2 3.7 -94.1% ‐
CAPEX (1) 7.9 6.7 +17.4% ‐
Cash Flow From Operations (CFFO) (2) 8.0 6.5 +24.0% ‐
Net financial debt 24.1 -€1,3 billion versus Dec.31, 2021
Economic net debt 38.8 +€0.5 billion versus Dec.31, 2021
Net financial debt 2.8x -0.8X versus Dec.31, 2021
(1) Net of DBSO (Develop, Build, Share & Operate) and tax equity proceeds.
(2) Cash Flow From Operations: Free Cash Flow before maintenance Capex and nuclear phase-out expenses.
(1) Cash Flow From Operations: Free Cash Flow before maintenance Capex and nuclear phase-out expenses.

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MANAGEMENT REPORT
1.2 2023-2025 outlook and guidance
The forecasts set forth below are based on data, assumptions and estimates considered to be reasonable by the Group
at the date of issuance of this document.
These data and assumptions may evolve or be amended due to uncertainties related to the economic, financial,
accounting, competitive, regulatory and tax environment or other factors that the Group may not be aware of at the date
of registration of the management report. In addition, the fulfilment of forecasts requires the success of the Group’s
strategy. The Group therefore makes no commitment or warranty regarding the fulfilment of the forecasts set out in this
section.
The forecasts presented below and the underlying assumptions, also been prepared in accordance with the provisions of
Delegated Regulation (EU) No 2019/980 supplementing Regulation (EU) No 2017/1129 and the ESMA recommendations
on forecasts.
The forecast presented below result from the budget and medium-term plan process as described in Note 14 to the
consolidated financial statements for the year ended December 31, 2021; they have been prepared on a comparable basis
with historical financial information and in accordance with the accounting methods applied to the Group’s consolidated
financial statements.
1.2.1. Assumptions
• Strategy: reinforcing the ENGIE Group’s ambition to be a leader in the energy and climate transition. With its
refocusing and simplification now complete, ENGIE is now embarking on the second stage of its strategic plan and
accelerating its growth in the energy transition. The completion of the divestment plan will allow for a significant
increase in growth investments in renewable energies, both electricity and gas, and decarbonization solutions: €22
to 25 billion over the period 2023-2025, i.e. a 50% increase compared to 2021-2023;
• No change in accounting policies;
• No major regulatory or macro-economic changes;
• Average temperature in France;
• Average hydro, wind ans solar productions;
• Average forex
− €/USD: 1.08 for 2023, 1.09 for 2024 and 1.10 for 2025,
− €/BRL: 5,56 over 2023-25;
• Belgian nuclear availability: c. 90% in 2023, 92% in 2024 and 94% in 2025 – based on availabilities as published
on REMIT as of 01/01/2023;
• Contingencies on Belgian operations of €0.5 billion in 2023, €0.5 billion in 2024 and €0.2 billion in 2025;
• Market commodity prices at December 30, 2022;
• Hedged positions and captured prices at December31, 2022, Belgium and France:
− 100% to 90 €/MWh for 2022,
− 74% to 93 €/MWh for 2023,
− 52% to 120 €/MWh for 2024,
− 15% to 165 €/MWh for 2025,
− Captured prices are shown
o before specific Belgian nuclear and French CNR hydro tax contributions
o before inframarginal rent cap in Belgium and France
o excluding the mark-to-market impact of the proxy hedging used for part of Belgian nuclear volumes
over 2023-2025, which is volatile and historically unwinds to close to zero at delivery,
• Recurring net financial costs of €(2.2)-(2.6) billion per year over 2023-25;
• Recurring effective tax rate: 23-26% over 2023-25;
• Discount rate for post-employment benefit provisions: based on market conditions at December 31, 2022, as
described in Note 18 to the consolidated financial statements;
• Regulatory review on French networks in 2024-25;

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MANAGEMENT REPORT
• Inframarginal rent caps based on current legal texts and additional contingencies;
• Full pass through of supply costs in French BtoC retail tariffs.
The progress on the execution of the strategic plan solidifies the foundation for ENGIE towards delivering long-term growth
while achieving its purpose of carbon neutrality.
The Group anticipates delivering growth in the medium-term primarily fueled by investment in Renewables and improved
results from Energy Solutions, alongside a stable contribution from Networks. GEMS is projected to further enhance the
integrated business model securing energy supply, optimising and managing risks for ENGIE and third parties. Nuclear
contribution, due to the ongoing phase-out capacity plan in Belgium, has been excluded from the EBIT indication.
European commodity price assumption in the guidance for residual merchant exposure: the price assumption used in the
guidance for 2023-2025 provided today is based on the European forward prices as at 31 December 2022.
ENGIE outlook for 2023 to 2025:
In €billion 2023 Results 2024 Results 2025 Results

EBIT excluding
6.6 - 7.6 7.2 - 8.2 7.5 - 8.5
Nuclear
RNRpg guidance 3.4 - 4.0 3.8 - 4.4 4.1 - 4.7
ENGIE remains committed to a “strong investment grade” rating and continues to target a leverage ratio of below or equal
to 4.0x economic net debt to EBITDA.
1.2.2. Overview of key financial targets
The group has set itself the goal of accelerating its growth by focusing on the second stage of its strategic plan:
Accelerating growth in Renewables
Ramp-up in Renewables underpinned by a growing and well-balanced pipeline. The Group commissioned 7 GW of
renewable capacity over the last two years, leading to 38 GW total installed capacity. Despite the supply chain challenges,
ENGIE continues to accelerate its average annual renewable capacity additions to 4 GW until 2025, stepping-up to 6 GW
from 2026 to 2030. This will bring total the installed capacity to 50 GW by 2025 and 80 GW by 2030.
This ambition is fuelled by a growing pipeline of 80 GW at end-2022 (vs. 56 GW at end-2020), which enjoys a good balance
across onshore wind, offshore wind and solar. More than half of this pipeline includes projects already under construction,
secured or at an advanced stage of development.
The geographic priorities remain Europe, North America, and Latin America, with offshore wind across a wider geographic
footprint.
In total, ENGIE will invest between €13 billion and €14 billion over 2023-2025 in Renewables in a balanced portfolio with
limited exposure to merchant risk.
The alliance between the molecule and the electron at the heart of ENGIE model to ensure flexibility and security
of supply
As gas infrastructure owner, operator, and supplier, ENGIE has a critical role to play in Europe. Gas infrastructure
(networks, storage capacities, LNG terminals) played a major role in the energy crisis and will continue to do so in the
energy transition, ensuring security of supply and overall system resilience. Gas networks are also facilitators of the
development of renewable gases and thus contribute to decarbonisation.

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MANAGEMENT REPORT
ENGIE’s gas networks business is largely regulated bringing stability and visibility. ENGIE’s networks have consistently
demonstrated strong operational performance and respect the highest safety standards. They generate strong cash-flow,
enabling the Group to maintain safety and reliability, and finance growth Capex such renewable gases expansion.
Overall our regulated asset base (RAB), in France and international, is expected to reach €39bn in 2025, compared to
€36bn in 2022.
A balanced portfolio is key to ensuring the energy system’s flexibility and efficiency. In a context of strong growth in
Renewables, ENGIE benefits from its large portfolio of flexible generation assets and energy storage, including CCGTs
(51 GW) and pumped storage plants (c. 4 GW), which are absolutely key to absorbing the intermittency associated with
these Renewables.
ENGIE will continue to adapt its fleet to bring more flexibility and optionality to the grid and to its own generation portfolio,
make it leaner, nimbler, more efficient and less CO2 intensive. The business model of CCGTs will increasingly be shifting
to capacity remuneration mechanism and ancillary services.
The Group intends to strongly accelerate in battery storage to complement its gas-fired generation and pumped storage
fleet and has an ambitious target of c.10 GW of battery capacity by 2030, mainly in Europe and the US.
Ramping up in renewable gases
The development of renewable gases will capitalize on existing infrastructure, contributing to security of supply. The Group
will leverage on its existing networks to develop renewable gases and will invest €3.5 billion in decarbonized gases by
2030.
The renewable and low-carbon gas market is set to grow rapidly in the coming decade, driven by the decarbonization
commitments of governments and corporate offtakers.
ENGIE has a target of c.10 TWh of biomethane production per year by 2030.
ENGIE will focus on ramping up in low carbon hydrogen, which is key for hard-to-abate sectors for which electricity is an
unrealistic option for decarbonization.
ENGIE is in a strong position to benefit from the buoyant growth in green hydrogen by leveraging on its world-leading
capabilities in renewable power generation and its expertise in managing complex industrial processes. ENGIE has also
global energy management capabilities to trade hydrogen and e-molecules.
ENGIE has set an ambitious target by 2030 to:

• develop green hydrogen production capacity of 4 GW,
• have 700 km dedicated hydrogen networks and 1 TWh of storage capacity,
• operate more than 100 refuelling stations
Total Capex for hydrogen is earmarked at c.€4 billion over 2023-2030.
Playing a major role in the decarbonization of ENGIE’s customers through distributed infrastructure
Energy Solutions is ideally positioned to capture the growth of the market driven by strong demand from clients for
decarbonized solutions and energy independence as well as increasingly support from public authorities.
Energy Solutions has streamlined its organization through three activities: local energy networks, on-site energy
production, and energy performance services.
In the first two platforms, which benefit from long-term infrastructure-like contracts with stable and recurring revenues as
well as long-term contracted cash flows, ENGIE invests in infrastructure and operates them as part as an asset-based
business model. Capturing the long-term growth opportunities, using greater selectivity in targeting contracts, and with a
more efficient base, EBIT annual growth from distributed energy infrastructure should be high-single digit on average over
2022-2025.

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MANAGEMENT REPORT
In energy management services, the EBIT margin is expected to increase more than 200bps over 2022-2025 to reach 5%.
ENGIE remains committed to adding 8 GW of distributed energy infrastructure by 2025 (vs 2020), translating into around
€3 billion Capex growth over 2023-2025.
Leveraging ENGIE extensive market knowledge through GEMS
GEMS is at the heart of ENGIE’s integrated business model. On the upstream side, GEMS’ mandate is to add value from
technical differences, complementarity, flexibility and optionality within ENGIE’s and partners’ portfolio of assets. On the
downstream side, GEMS provides ENGIE clients with risk management services and tailor-made energy supply contracts.
GEMS EBIT is likely to be lower over 2023-2025 compared to the exceptional level of 2022, but it should remain above
the historical level of 2020-2021 due mainly to commercial growth and continuing challenging energy markets, bringing
optionality and volatility as well as increased customers demand for risk management.
Capital allocation and medium-term financial outlook
ENGIE targets growth Capex of €22-25 billion between 2023 and 25, an increase of 50% versus the previous 2021-23
plan, with 40% being already committed. These will be split 55-65% for Renewables, 10-15% for Networks, and 10-15%
for Energy Solutions. Around 10% will be dedicated to ramping up in renewable gas and batteries. Capital allocation is
based on a strict discipline of financial and ESG-related criteria. The contribution to 2023-25 EBIT of new capacities
commissioned should amount to €1.5bn.
Return On Average Capital Employed excluding nuclear should benefit from this rigorous process to drive value creation:
Group ROACE excluding nuclear is expected to increase to between 7% and 9% in a sustainable way from 6% in 2021.
Maintenance Capex should amount to €7 to 8 billion between 2023 and 2025, of which around 50% in French regulated
infrastructure activities.
Around €9bn will go towards the funding of Belgian nuclear provisions over 2023-2025.
ENGIE will continue to drive efficiency by strong control of general and administrative costs, increasing support functions
efficiency, and turning around underperforming businesses. The Group is aiming for a positive net impact on EBIT of
€0.6 billion in 2023-25.
Main drivers for 2022-2025 EBIT evolution by activity
2022 Activity Expectations for main EBIT evolution drivers vs 2022 2025
Renewables Investments contribution, higher prices ++
Inflation, temperature normalization, investments and portfolio
Networks =-
management, regulatory reviews in France EBIT
Investments contribution, EVBox contribution improvement and excluding
EBIT excluding Energy Solutions =+ Nuclear
continued improvement of performance
Nuclear indication
FLEXGEN (ex Thermal) Dilution, normalization of spreads, higher fleet availability =
€8.0 billion €7.5 billion
Temperature normalization, margin increase, growth in B2C to
Retail ( ex Supply) =+
services and power customer portfolio €8.5 billion
GEMS Decrease of prices and volatility but still high ---
Nuclear Higher prices, lower volumes =+
Convention: each “+” sign amounts to c. €+500m, each “-” sign amounts to c. €-500m, “=+” sign amounts to a variation
between 0 and +250, “=-” sign amounts to a variation between -250 to 0.
1.3 Dividend policy reaffirmed and €1.40 per share proposal for 2022
ENGIE is focused on delivering a progressively growing and sustainable dividend for shareholders.

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MANAGEMENT REPORT
The Board has reaffirmed the Group’s dividend policy with a payout ratio of 65-75% of net recurring income Group share,
and a floor of €0.65 per share for the 2023 to 2025 period.
For 2022, the Board has proposed a payout ratio of 65%. This translates to a dividend of €1.40 per share, which will be
proposed for shareholder approval at the Annual General Meeting on 26 April 2023.
1.4 ENGIE playing a leading role in security of supply and contributing to

support energy affordability
As gas infrastructure owner, operator, and gas supplier, ENGIE has played a crucial role in Europe.
In France, ENGIE’s networks activities have operated at record high utilisation rates, with LNG terminals working at nearly
full capacity, two-fold increase in transit at GRTgaz including reversed flows from France to Germany, and gas storage
levels filled at 82% as at December 31, 2022 compared to c. 53% at December 31, 2021.
ENGIE has contributed €1.1 billion in 2022 to existing Government profit-sharing mechanisms for Belgian Nuclear (specific
tax framework) and French hydro (CNR).
ENGIE has pledged to support its French customers with €90 million in measures for vulnerable customers and a
€60 million fund for industrial/tertiary customers affected by rising energy prices. ENGIE has also launched platforms for
retail and SME customers to monitor and save energy.
ENGIE is contributing to public policy measures to address high energy prices. In France, ENGIE has increased working
capital support for the tariff shield mechanism, now including small and medium-sized enterprises as well as customers
under market prices (by linking their contracts to the regulated tariff). Most of ENGIE’s B2C gas and power contracts in
France benefit from protection against price increases through this tariff shield mechanism or fixed prices over the lifetime
of the contract.
The Group is supporting the implementation of social tariffs in Belgium and a price cap mechanism in Romania and Chile.
In addition, the Group has engaged with various local authorities to provide support through payment facilities. The overall
impact of delayed payment plans worldwide is close to €1.0 billion. The Group is more focused than ever to work
collaboratively with clients on energy efficiency to reduce their energy bill and achieve their decarbonisation goals.
ENGIE has also recognised the engagement of its employees around the world with an exceptional bonus of €1,500
awarded to each employee in an unprecedented energy situation to support in a high inflation environment.
1.5 ENGIE is contributing to public policy measures to address high

energy prices
In France, ENGIE has increased working capital support for the tariff shield mechanism, now including small and medium-
sized enterprises as well as customers under market prices (by linking their contracts to the regulated tariff). Most of
ENGIE’s B2C gas and power contracts in France benefit from protection against price increases through this tariff shield
mechanism or fixed prices over the lifetime of the contract.
The Group is supporting the implementation of social tariffs in Belgium and a price cap mechanism in Romania and Chile.
In addition, the Group has engaged with various local authorities to provide support through payment facilities. The overall
impact of delayed payment plans worldwide is close to €1.0 billion. The Group is more focused than ever to work
collaboratively with clients on energy efficiency to reduce their energy bill and achieve their decarbonisation goals.
ENGIE has also recognised the engagement of its employees around the world with an exceptional bonus of €1,500
awarded to each employee in an unprecedented energy situation to support in a high inflation environment.

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MANAGEMENT REPORT
1.6 Update on European proposals for windfall taxes
In December 2022, the Governments of Belgium and France, ENGIE’s two most significant power generation countries in
the EU, have passed new measures into Law to address inframarginal rent in relation to power prices.
In Belgium, an inframarginal rent cap was implemented retroactively, from 1 August 2022 to 30 June 2023, at a level
depending on the power production’s technology. A possible extension of this period will be evaluated next April. ENGIE’s
nuclear assets, owned and operated via its subsidiary Electrabel, fall into the scope of this measure: normative revenues
exceeding €130/MWh are subject to the new levy but with a mechanism limiting potential double taxation with existing
nuclear taxes.
In France, the Finance Bill for 2023 provides for a rent cap applicable over a period of eighteen months, (from 1 July 2022
until 31 December 2023). The cap ranges from €40/MWh to €175/MWh depending on the power production technology.
The excess revenue is subject to a tax rate of 90%. ENGIE is mainly impacted through its drawing rights on two EDF
nuclear power plants (Chooz B and Tricastin, 1.2 GW, 9 TWh of annual output at an availability rate of 85%) subject to a
€90/MWh cap and its gas power plants (1.4 GW capacity) subject to a €40/MWh cap on the clean spark spread.
In Italy, the Government has already enacted an “extraordinary solidarity contribution” on energy companies calculated on
a variation of VAT-taxable basis between October 2021 and April 2022 versus the same duration a year earlier, at a rate
of 25%. ENGIE has been significantly and adversely impacted due to an ill-designed methodology, not representative of
the excess revenues over the period.
The overall impact of extraordinary taxes in Europe is close to €0.9 billion in 2022, 85% in EBIT and 15% in corporate
income tax.
1.7 Significant progress on the execution of strategic plan
Acceleration in Renewables, infrastructures and renewable gases
ENGIE added 3.9 GW of renewable capacity in 2022, including 1.8 GW of onshore wind, 1.2 GW of solar and
1.0 GW of offshore wind, taking total renewable installed capacity at 100% to c. 38 GW at the end of 2022. Geographically,
the 3.9 GW additions include 2.6 GW in Europe (mainly in UK, Spain and France), 0.8 GW in US and 0.4 GW in Latin
America. The Group is therefore on track with its target to add 4 GW on average per year of renewable capacity until 2025.
This ambition is fuelled by a growing pipeline that totalled 80 GW at end of December 2022, up 14 GW compared to
December 2021.
Ocean Winds, ENGIE’s joint venture with EDPR dedicated to offshore wind continues to grow strongly. In December,
Ocean Winds was awarded a lease area for a floating offshore wind site of 2 GW capacity in California.
In 2022, the Group continued supporting its customers in their decarbonisation efforts by signing a total amount of 2.0 GW
of green Power Purchase Agreements (PPAs).
Energy Solutions has achieved major wins in District Heating and Cooling (DHC) and sustainable mobility in the 2022,
including 12,000 electric vehicle charging points mainly in Belgium and Singapore. In 2022, c. 1 GW net installed capacity
has been added in distributed energy infrastructures.
In Brazil, the internalization of TAG O&M activities has been successfully completed and the two power transmission lines,
Gralha Azul and Novo Estado, are now close to full completion.
ENGIE continues to unlock the potential of renewable gases: 492 biomethane production units, with a yearly production
capacity of up to 8.3 TWh are connected to ENGIE’s networks in France. On hydrogen, the European Commission has
approved up to €5 billion in public support. ENGIE has submitted five projects across Belgium, France, the Netherlands
and Spain, and all of them have been selected.

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MANAGEMENT REPORT
Simplifying and refocusing
The disposal plan financial target of at least €11 billion by the end of 2023 has been achieved with €11.0 billion already
closed or signed, with EQUANS being the main contributor.
On geographic rationalization, the Group will be operating in 31 countries, down from 70 in 2018, once closing of the signed
deals is effective. ENGIE exited seven countries as part of the EQUANS disposal and targets to be in less than 30 countries
by the end of 2023.
Disciplined capital allocation
In 2022, total Capex amounted to €7.9 billion. Growth Capex reached €5.5 billion, of which 58% dedicated to Renewables,
20% to Networks and 13% to Energy Solutions, thus fully aligned with ENGIE’s strategic roadmap.
Performance plan delivering
In a context of rising inflation, ENGIE maintained its momentum on cost efficiency and is on track to achieve its 3-year
target, with a net EBIT contribution in 2022 of €0.4 billion.
1.8 Update on Belgian nuclear assets
In line with the planned nuclear phase-out in Belgium, the Doel 3 reactor was shut down in September 2022 and the
Tihange 2 reactor in February 2023.
In January 2023, ENGIE and the Belgian federal government set a framework for the extension of the nuclear reactors
Doel 4 and Tihange 3, signing the Heads of Terms and Commencement of LTO Studies Agreement which builds on the
Letter of Intent signed on 21 July 2022, with the objective to extend the operational lifetime of both reactors for ten years,
for a total production capacity of 2 GW.
This agreement in principle comprises three conditions, including the establishment of a legal structure dedicated to the
two extended nuclear units equally owned by the Belgian State and ENGIE, the framework for a cap on future nuclear
waste management costs, and a set of guarantees to ensure the proper execution of the nuclear operator’s commitments.
With this agreement, both parties confirm their objective to make reasonable endeavours to restart the Doel 4 and Tihange
3 nuclear units in November 2026.
In December 2022, ENGIE was informed on the new parameters considered by the Commission for Nuclear Provisions
(CPN) for the calculation of the nuclear provision for the dismantling and spent fuel management of Belgian nuclear power
plants following the triennial revision. Based on these parameters, nuclear provisions have increased by €3.3 billion, of
which €2.9 billion borne by Synatom, compared to ENGIE’s initial proposal of an increase of €0.9 billion. ENGIE considers
the increase by €2.9 billion unjustified and has submitted an adapted proposal to the CPN.
1.9 ESG
Key ESG targets
In 2022, greenhouse gas emissions from energy production were reduced to 60 million tons, a decrease of 44% compared
to 2017, and in line with the target of 43 million tons by 2030. 2022 results were positively impacted by the weather and a
lower utilization rate of our CCGTs.
ENGIE increased the share of renewables in its portfolio to 38% at the end of 2022 from 34% at the end of 2021 with the
addition of 3.9 GW of renewables.
ENGIE continues to progress on coal exit with the signing in September of the disposal of Pampa Sul in Brazil and the
closure of Tocopilla in Chile which comprises a total of 0.6 GW installed capacity. ENGIE is committed to exiting all coal
assets in continental Europe by 2025 and globally by 2027, including coal generation for district heating and cooling
networks. At the end of 2022, coal represented 2.6% of ENGIE’s centralized power generation portfolio.

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MANAGEMENT REPORT
On gender diversity, ENGIE had 30% women in management at the end of 2022 and is implementing action plans towards
its ambition of managerial parity of 40% to 60% between men and women.
1.10 Health & Safety
In 2022, ENGIE and its subcontractors experienced severe work-related accidents including 4 fatalities, notably at
construction sites. A major company-wide response and comprehensive action plan are being deployed by the ENGIE
leadership, to re-assess all safety standards and procedures in every activity and geography to ensure the application of
the highest safety standards across the Group and its subcontractors.
1.11 FY 2022 financial review
1.11.3. Revenues
Revenue at €93.9 billion was up 62.2% on a gross basis and 60.4% on an organic basis.
Contributive revenues, after elimination of intercompany transactions
% change % change
(reported (organic
In millions of euros Dec 31, 2022 Dec 31, 2021 basis) basis)
Renewables 6,216 3,653 +70.1% +58.3%
Networks 6,961 6,700 3.9% +2.9%
Energy Solutions 11,552 9,926 16.4% +21.1%
Thermal 7,129 4,089 74.3% +62.6%
Supply 16,810 10,396 61.7% +61.3%
Nuclear 35 56 -37.7% -37.7%
Others 45,163 23,046 96.0% +92.6%
of which GEMS 45,137 22,870 97.4% +92.7%
TOTAL 93,865 57,866 +62.2% +60.4%
Revenue for Renewables amounted to €6,216 million, up 70.1% on a gross basis and up 58.3% organically. The gross
increase was due to favourable foreign exchange effects mainly from the appreciation of the Brazilian real against the
euro. On an organic basis, revenue growth was mainly driven by capacity additions and higher hydro prices in France.
Revenue for Networks amounted to €6,961 million, up 3.9% on a gross basis and up 2.9% organically. The gross increase
was due to favourable foreign exchange effects mainly in Latin America and the scope out effect related to the Turkey and
Argentina disposals. French infrastructures revenue rose driven by significantly higher volumes transported, notably with
exceptional West-East reverse flows, terminals as well as storage activities reflecting own account operations (in the UK)
which offset lower volumes in distribution and expected tariff evolution. Outside France, revenues increased organically
notably in Latin America with higher volumes in distribution. Lower revenues in Brazil reflect the decrease in construction
revenues following progressive commissioning of transmission lines.
Revenue for Energy Solutions amounted to €11,552 million, up 16.4% on a gross basis and 21.1% organically. The gross
increase was driven by favourable foreign exchange effects mainly related to US dollar and scope out effects. Organically,
revenue in France increased significantly on all activities: energy performance management, local energy networks and
on-site energy production. International activities increased significantly driven by commodity prices in all geographies.
Revenue for Thermal amounted to €7,129 million, up 74.3% on a gross basis and up 62.6% organically. The gross increase
benefited from positive foreign exchange effects mainly in Chile, Peru and Pakistan. The organic performance is mainly
driven with exceptional level of spreads and increased ancillaries in Europe. Americas shows a positive growth thanks to
the indexation of PPA contracts in a context of rising commodity prices and inflation.
Revenue for Supply amounted to €16,810 million, up 61.7% on a gross basis and 61.3% organically. The gross variation
was due to favourable foreign exchange effects. Organically, the increase was mainly driven by increasing commodity
prices, offset by negative volume effect mainly due to warmer temperature.

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MANAGEMENT REPORT
Nuclear reported almost no external revenue post-elimination of intercompany operations, as its production was sold
internally to other ENGIE businesses.
Revenue for Others amounted to €45,163 million. The increase compared to last year is mainly driven by GEMS
(€+45,137 million) essentially impacted by increase in commodity prices combined with higher volumes.
1.11.4. EBITDA
EBITDA at €13.7 billion, was up 29.8% on a gross basis and up 27.0% on an organic basis.
Activity/geography matrix
Rest of Latin USA & Middle East, December 31,

In millions of euros France Europe America Canada Asia & Africa Others 2022
Renewables 535 370 1,003 313 17 (35) 2,202
Networks 3,396 96 731 (3) ‐ (8) 4,212
Energy Solutions 605 240 (2) 34 70 (69) 879
Thermal ‐ 1,475 295 47 436 (17) 2,235
Supply (8) 199 6 ‐ 70 (9) 258
Nuclear ‐ 1,510 ‐ ‐ ‐ ‐ 1,510
Others ‐ (16) 1 (1) ‐ 2,433 2,417
Of which GEMS 2,837 2,837
TOTAL EBITDA 4,528 3,875 2,033 390 592 2,295 13,713

Renewables 462 172 1,016 86 12 (47) 1,702
Networks 3,518 121 470 ‐ 18 (7) 4,121
Thermal ‐ 743 424 43 448 (30) 1,628
Supply 356 114 ‐ ‐ 48 (20) 498
Nuclear ‐ 1,403 ‐ ‐ ‐ ‐ 1,403
Others ‐ 2 1 10 ‐ 412 426
Of which GEMS 679 679
TOTAL EBITDA 4,928 2,770 1,908 199 568 190 10,563
1.11.5. EBIT
EBIT at €9.0 billion was up 47.2% on a gross basis and up 42.7% on an organic basis.
• Foreign exchange: a total positive effect of €325 million at EBIT mainly driven by the appreciation of the Brazilian
real and the US dollar.
• Scope: a net negative scope effect of €115 million at EBIT mainly due to 2021 events including partial sale of
GTT’s shares that led to a change in consolidation method, asset sales to achieve the Group’s geographical
refocus and coal exit targets. These effects were only partly offset by the acquisition of Eolia in Spain in May 2022.
• French temperature: compared to average, the temperature effect stood at negative €190 million, generating a
negative year-on-year variation of €308 million compared to 2021 across Networks, Supply and Others in France.
EBIT growth mainly driven by GEMS, Thermal and Renewables.

16
MANAGEMENT REPORT
Activity/geography matrix

Renewables 375 313 796 172 9 (39) 1,627
Networks 1,675 49 658 (3) ‐ (8) 2,371
Thermal ‐ 1,278 51 44 417 (22) 1,768
Supply (164) 115 6 ‐ 49 (13) (7)
Nuclear ‐ 1,026 ‐ ‐ ‐ ‐ 1,026
Others ‐ (16) ‐ (11) ‐ 1,875 1,848
Of which GEMS ‐ ‐ ‐ ‐ ‐ 2,618 2,618
TOTAL EBIT 2,197 2,913 1,506 226 532 1,671 9,045

Renewables 273 117 846 (6) 8 (47) 1,191
Networks 1,823 77 403 ‐ 18 (7) 2,314
Thermal ‐ 564 189 41 421 (32) 1,183
Supply 202 28 ‐ ‐ 25 (23) 232
Nuclear ‐ 959 ‐ ‐ ‐ ‐ 959
Others ‐ 2 ‐ (1) ‐ (86) (85)
Of which GEMS ‐ ‐ ‐ ‐ ‐ 507 507
TOTAL EBIT 2,605 1,880 1,433 82 498 (355) 6,145
EBIT contribution by activity
o/w temp.
% change % change effect
(reported (organic (France)
In millions of euros Dec 31, 2022 Dec 31, 2021 basis) basis) vs. 2021
Renewables 1,627 1,191 +36.6% +19.1% ‐
Networks 2,371 2,314 2.5% +0.5% (197)
Energy Solutions 412 350 17.7% +16.6% ‐
Thermal 1,768 1,183 49.4% 46.6% ‐
Supply (7) 232 (87)
Nuclear 1,026 959 +6.9% +6.9% ‐
Others 1,848 (85) (24)
of which GEMS 2,618 507 (24)
TOTAL 9,045 6,145 +47.2% +42.7% (308)
TOTAL excluding Nuclear 8,019 5,185 +54.7% +49.1% (308)
1.11.5.1. Renewables: contribution of newly commissioned assets and productivity

improvements
% change % change
(reported (organic
EBIT 1,627 1,191 +36.6% +19.1%
Total CAPEX 3,333 1,881 +77.2% ‐
CNR achieved prices (€/MWh) 60 56 +7.0% ‐
DBSO (1) Margins (EBIT level) 102 31 ‐
Operational KPIs
Commissioning (GW at 100%) 3.9 3.0 +30.0% ‐
Hydro volumes France (TWh at 100%) 12.8 15.2 -2.4 ‐
(1) Develop, Build, Share and Operate.

17
MANAGEMENT REPORT
Renewables reported a 19.1% organic EBIT growth, benefiting from the contribution of new capacity across Group’s key
geographies and technologies (+€268 million), performance plan (+€87 million), positive volume effects (+€69 million,
resulting mainly from the reversal of the -€90 million Texas extreme weather event in Q1 2021) and positive price effects
(+€55 million, mainly due to higher prices for French hydro, partly offset by hydro buybacks in France and Portugal in the
context of low hydrology in Europe). Overall growth more than offset the 2021 one-off linked to GFOM ruling effect in Brazil
(-€300 million).
Profit sharing mechanism on CNR hydro production in France has evolved after the adoption in February 2022 of the
“Aménagement du Rhône” law under which the tax rate varies according to captured power prices, varying from 10% for
volumes below €26.5/MWh up to 80% for volumes above €80/MWh. The Group EBIT impact in 2022 amounted to
-€176 million.
1.11.5.2. Networks: strong performance in Latin America, partly offset by warmer temperatures
in Europe
% change % change
(reported (organic
EBITDA 4,212 4,121 +2.2% +1.0%
EBIT 2,371 2,314 +2.5% +0.5%
Total CAPEX 2,321 2,524 -8.0%
Operational KPIs
Temperature effect – France (EBIT in €m) (122) 75.0 (197) ‐
Smart meters (m) 10.9 9.2 1.7 ‐
EBIT amounted to €2,371 million, up 0.5% on an organic basis.
French infrastructures EBIT was down €148 million due to lower distributed volumes following warmer temperatures versus
last year and lower tariffs revenues reflecting regulatory reviews (smoothed out over the 4-year regulatory period). These
effects were partly offset by significant growth in short term revenues in transport, including reversed flows from France to
Germany, as well as in terminals and storage.
The Group performed strongly outside France with EBIT organically up €160 million mainly due to higher contribution from
Latin America, driven by intrinsic growth and inflation indexations.
1.11.5.3. Energy Solutions: higher energy prices and strong commercial performance despite
warmer temperature.
% change % change
(reported (organic
Revenues 11,552 9,926 +16.4% +21.1%
EBIT 412 350 +17.7% +16.6%
Total CAPEX 886 903 -1.8% -
Operational KPIs
Distrib. Infra installed cap. (GW) 24.9 24,1 (1) +3.8% -
EBIT margin (excluding Evbox) 4.6% 5.0% -47 bps -
Backlog - French concessions (bn€) 18.4 16.8 +1.6 -
(1) Restated data to exclude countries ENGIE exited or stopped developments following geographical rationalization presented in May
2021.
EBIT amounted to €412 million, up 16.6% on an organic basis.
Organic growth was driven by the positive impact of energy prices, positive effect of performance plan in energy efficiency
services, commercial market dynamics notably in cogeneration and DHC as well as production ramp up and process
enhancements ongoing on EVBox, despite slowdown of EV market growth pace. These elements were partly offset by
warmer temperature and positive 2021 one-offs on on-site energy production.

18
MANAGEMENT REPORT
1.11.5.4. Thermal: higher spreads and ancillaries captured by flexible assets in Europe.
% change % change
(reported (organic
EBITDA 2,235 1,628 +37.3% +33.7%
EBIT 1,768 1,183 +49.4% +46.6%
Operational KPIs
Average captured CSS Europe (€/MWh) 28.0 19.0 +50%
Installed capacity (GW at 100%) 59.5 59.9 (0.4) ‐
Thermal EBIT amounted to €1,768 million, up 47% on an organic basis.
Organic growth was mainly driven by price effects (+€922 million, mainly from higher spread from European assets partly
offset by negative impact from higher sourcing spot prices in Chile and adverse gas merchant position in Australia) as well
as ancillaries and capacity remuneration mechanisms (+€175 million). These effects were partly offset by lower volumes
(-€440 million) mainly in Europe, due to outages and strikes, and Italy windfall profit tax which ENGIE is contesting.
1.11.5.5. Supply: timing effects, warmer temperatures in Europe, price caps and support
measures.
% change % change
(reported (organic
EBITDA 258 498 -48.2% -47.3%
EBIT (7) 232 ‐ ‐
French temperature effect (EBIT in m€) (53) 34 (87) ‐
EBIT amounted to -€7 million. Organically, the decrease (-€230 million) was driven by lower energy volumes mainly in
France and Belgium, negative price effects in France and support measures to customers, partially offset by improved
performance and higher results in most of the other European countries. EBIT decreased by €626 million over the last
quarter of the year mainly due to expected reversal of timing effects mostly linked to the existing ARENH mechanism as
well as negative climate effects.
1.11.5.6. Nuclear: higher prices triggered higher profit sharing through specific Belgian nuclear
tax and inframarginal rent cap.
% change % change
(reported (organic
En millions d’+euros Dec 31, 2022 Dec 31, 2021 basis) basis)
EBITDA 1,510 1,403 +7.6% +7.6%
EBIT 1,026 959 +6.9% +6.9%
Total Capex 229 201 +14.2%
Operational KPIs
Output (BE + FR, @ share, TWh) 42.1 47.4 -5,4 TWh -
Availability (Belgium at 100%) 83.6% 91.8% - 820 bps -
EBIT for Nuclear amounted to €1,026 million, up 6.9% on organic basis.
Organic increase was driven by higher achieved prices (+€1,694 million, at €97/MWh in 2022 vs €60/MWh in 2021)
resulting in higher nuclear tax contribution on second generation units (-€759 million) and inframarginal rent cap. Also, a
negative volume effect (-€494 million) due to higher outages in Belgium (availability rate at 83.6%, -820 bps vs 2021) and
France.

19
MANAGEMENT REPORT
1.11.5.7. Others: unprecedented contribution from GEMS in a context of extreme market

conditions
GEMS EBIT amounted to €2,618 million, representing an organic increase of €2,087 million compared to 2021.
ENGIE, as an integrated player, operates in the energy markets through GEMS. It sources energy, sells its own production
and hedges upstream and downstream positions to meet customers’ needs for risk management and decarbonisation, as
well as secure supply in Europe. GEMS saw a record level of activity in all activities in an exceptionally volatile price
environment and optimized long-term contracts by leveraging the optionality in ENGIE’s commercial contract-base.
1.11.6. Comparable basis organic growth analysis
% change
(reported/organic
In millions of euros Dec 31, 2022 Dec 31, 2021 basis)
Revenues 93,865 57,866 +62.2%
Scope effect (21) (807) ‐
Exchange rate effect ‐ 1,462 ‐
Comparable data 93,844 58,523 +60.4%
% change
(reported/organic
EBITDA 13,713 10,563 +29.8%
Exchange rate effect ‐ 418 ‐
Comparable data 13,665 10,762 +27.0%
% change
(reported/organic
EBIT 9,045 6,145 +47.2%
Exchange rate effect ‐ 325 ‐
Comparable data 8,998 6,307 +42.7%
The calculation of organic growth aims to present comparable data both in terms of the exchange rates used to convert
the financial statements of foreign companies and in terms of contributing entities (consolidation method and contribution
in terms of comparable number of months). Organic growth in percentage terms represents the ratio between the data for
the current year (N) and the previous year (N-1) restated as follows:
• The N-1 data is corrected by removing the contributions of entities transferred during the N-1 period or prorata
temporis for the number of months after the transfer in N;
• The N-1 data is converted at the exchange rate for the period N;
• The N data is corrected with the N acquisition data or prorata temporis for the number of months prior to the N-1
acquisition.

20
MANAGEMENT REPORT
2 OTHER INCOME STATEMENT ITEMS
The reconciliation between EBIT and Net income/(loss) is presented below:
% change
In millions of euros Dec. 31, 2022 Dec. 31, 2021 (reported basis)
EBIT 9,045 6,145 +47.2%
(+) Mark-to-Market on commodity contracts other than trading instruments (3,661) 721
(+) Non-recurring share in net income of equity method entities (17) 50
Current operating income including operating MtM and share in net income of equity
method entities 5,367 6,916 -22.4%
Impairment losses (2,774) (1,028)
Restructuring costs (230) (204)
Changes in scope of consolidation 91 1,107
Other non-recurring items (1,328) (69)
Income/(loss) from operating activities 1,127 6,722 -83.2%
Net financial income/(loss) (3,003) (1,350)
Income tax benefit/(expense) 83 (1,695)
NET INCOME/(LOSS) 390 3,758 -89.6%
Net recurring income/(loss) relating to continued operations, Group share 5,223 2,927
Net recurring income/(loss) Group share per share 2.24 1.26
Net income/(loss) Group share 216 3,661
Non-controlling interests 173 97
The reconciliation between Net recurring income/(loss) Group share and Net income/(loss) Group share is presented
below:
In millions of euros Dec. 31, 2022 Dec. 31, 2021

Net recurring income/(loss) relating to continued operations, Group share 5,223 2,927
Impairment & Others (1,494) (970)
Changes in scope of consolidation 91 1,107
Mark-to-Market on commodity contracts other than trading instruments (3,661) 721
Net recurring income/(loss) relating to discontinued operations, Group share 287 231
Income from operating activities amounted to €1,127 million, representing a decrease compared with
December 31, 2021, mainly due to unrealized losses on commodity hedges driven by price increases, in particular on
certain economic hedges on gas and electricity not designated as cash flow hedges, higher impairment losses, lower gains
on asset disposals, the recognition of additional costs related to the triennial review of nuclear provisions in Belgium, partly
offset by EBIT growth.
Income from operating activities was affected by:
• net impairment losses of €2,774 million (compared with €1,028 million in 2021) (see Note 9.1);
• restructuring costs of €230 million (compared with €204 million in 2021) (see Note 9.2);
• positive scope effects of €91 million (compared with a positive €1,107 million in 2021). This amount included in
particular the gain on the disposal of the Group’s interest in Gaztransport et Technigaz (GTT) representing
approximately 24.6% of its share capital (a positive €280 million), renewable geothermal assets in Indonesia (a
positive €111 million), Energy Solutions activities in Africa and in France (a negative €127 million), and the
purchase of shares in renewable assets in India with refinancing obligations scheduled for 2023 (a negative €110
million) (see Note 9.3);
• other non-recurring items for a negative €1,328 million (compared with a negative €69 million in 2021), mainly
including the €979 million net expense related to additions to provisions for the back-end of the nuclear fuel cycle
as part of the triennial review of nuclear provisions in Belgium (see Note 9.4).

21
MANAGEMENT REPORT
The net financial loss amounted to €3,003 million in 2022, compared with €1,350 million in 2021 (see Note 10). This
change is mainly due to the impairment loss recognized on the Nord Stream 2 loan (€987 million) and the negative impact
of the changes in the fair value of money market funds held by Synatom (€280 million). Adjusted for non-recurring items,
the financial loss amounted to €1,819 million in 2022, compared with €1,494 million in 2021. This deterioration is due to
the increase in other financial expenses, as well as to the increase in the cost of net debt, in particular due to the increase
in lease liabilities related to the extension of the Compagnie Nationale du Rhône concession. The increase in the average
cost of gross debt, mainly as a result of higher interest rates, was offset by the increase in interest on cash and cash
equivalents and liquid debt instruments.
The income tax for 2022 amounted to a benefit of €83 million (compared with a tax expense of €1,695 million in 2021). It
includes a €1,474 million tax benefit relating to non-recurring taxable items (compared with a tax expense of €552 million
in 2021), mainly MtM losses recognized by ENGIE SA.
Adjusted for these non-recurring items, the recurring effective tax rate was 22.6% at December 31, 2022 compared with
29.3% at December 31, 2021, mainly due to:
• the favorable change in the tax situation in certain countries that only partially recognize their deferred tax assets,
notably in Europe, the United States and Australia - approximately -7.6 points ;
• the effect on deferred tax liabilities of the increase in the future income tax rate voted in the United Kingdom in
2021 - approximately -2.1 points;
• the unfavorable impact of the non-deductibility of the one-off tax contribution voted in 2022 in Italy and recognized
as an operating expense by the Group - approximately +1.2 points;
• the one-off solidarity contribution voted in 2022 in Italy, which increases the income tax charge - by about
+2.1 points.
Net recurring income, Group share relating to continuing operations amounted to €5,223 million compared with
€2,927 million in 2021. This increase was mainly driven by the strong growth in EBIT, the recurring effective tax rate
decrease from 29.3% to 22.6%, partly offset by the increase in the recurring financial expense.
Net income, Group share amounted to €216 million, €3,445 million lower compared with 2021, mainly due to impairment
losses, the recognition of additional costs related to the triennial revision of nuclear provisions in Belgium, the negative
effect of mark-to-market on commodity contracts other than trading instruments, and the recognition of the credit loss on
Nord Stream 2, partially offset by the capital gain realized on the sale of EQUANS.
Net income attributable to non-controlling interests amounted to €173 million, compared with €97 million in 2021, due
to the relatively good performance of companies with minority shareholders, notably in Renewables in the United States
and Networks in France.
Return on Capital Employed (ROCE) improved during 2022 from approximately 9.1% in 2021 to 12.6% in 2022, mainly
due to improved EBIT and a lower effective tax rate.

22
MANAGEMENT REPORT
3 CHANGES IN NET FINANCIAL DEBT
Net financial debt stood at €24.1 billion down by €1.3 billion compared to December 31, 2021. This decrease was mainly
driven by:
• Cash Flow From Operations of €8.0 billion;
• disposals of €9.0 billion, mainly related to the disposal of EQUANS.
These positive elements were partly offset by:
• capital expenditure over the period of €7.9 billion;

• dividends paid to ENGIE SA shareholders and to non-controlling interests of €2.7 billion;
• Belgian nuclear phase-out funding and expenses (1) of €2.0 billion;
• new rights of use of €1.2 billion, mainly following the extension of the CNR hydro concession;
• other elements of €1.9 billion, mainly related to foreign exchange rates.
Changes in net financial debt break down as follows:
In millions of euros
Maintenance CAPEX
Growth CAPEX
(1) Capital expenditure net of DBSO proceeds, and changes in the scope of net financial debt of acquired companies.
(2) Mainly related to the renewal of the CNR concession.
(3) Excluding DBSO proceeds.
(4) Mainly derivatives, and MtM.
(1) Financing flows relating to Synatom were previously recorded in gross Capex and waste management/dismantling expenses in
CFFO.

23
MANAGEMENT REPORT
Economic net debt stood at €38.8 billion, up €0.5 billion compared to December 31, 2021, mainly due to the increase in
asset retirement obligation provisions (€+3.9 billion, mainly including the increase in nuclear provisions of €+3.3 billion
following the triennial review) and other variation (€+1.1 billion, including fair value variation of dedicated assets relating to
nuclear provisions and related derivative financial instruments), partly offset by funding from Synatom and
waste/dismantling expenses (€-2.0 billion), lower financial net debt (€-1.3 billion) and employment benefits provisions (€-
1.2 billion).
Changes in economic net debt break down as follows:
(1) Change in fair value of dedicated assets relating to nuclear provisions and related derivative financial instruments.
The net financial debt to EBITDA ratio stood at 1.7x, down 0.6x compared to December 31,2021. The average cost of
gross debt was 2.73%, up 8 bps compared with December 31, 2021.
In millions of euros Dec 31, 2022 Dec. 31, 2021

Net financial debt 24,054 25,350
EBITDA 13,713 10,563
NET DEBT/EBITDA RATIO 1.75 2.40
The economic net debt to EBITDA ratio stood at 2.8x, down 0.8x compared to December 31, 2021, and in line with the
target ratio of below or equal to 4.0x.
In millions of euros Dec 31, 2022 Dec. 31, 2021

Economic net debt 38,808 38,300
EBITDA 13,713 10,563
ECONOMIC NET DEBT/EBITDA RATIO 2.83 3.63

24
MANAGEMENT REPORT
3.1 Cash flow from operations (CFFO)
Cash Flow From Operations amounted to €8.0 billion, up €1.6 billion compared to 2021. This increase was mainly due
to higher operating cash-flows (+€2.6 billion) driven by higher EBITDA (+€3.1 billion).
Working Capital Requirements were negative €2.4 billion, identical to previous year, with flat variation due to net negative
price effects (-€4.8 billion), mainly due to higher valuation of gas stocks (-€1.8 billion), net receivables (-€2.3 billion) and
unbilled volumes (-€0.5 billion linked to energy in the meter) and European supply tariff shields (-€1.0 billion), due to French
gas and electricity tariff freeze (-€1.7 billion), Romania tariff shield and Belgium social tariff (-€0.6 billion), partly offset by
the French gas tariff freeze monetization (+€1.4 billion). These effects were offset by positive effects of margin calls
(+€4.0 billion) and nuclear activities (+€1.5 billion, mainly G2 tax, inframarginal rent cap and ONDRAF tariff revision).
3.2 Liquidity
Liquidity stood at €20.9 billion, including €15.7 billion of cash (1). The Group maintained a strong level of liquidity, by
implementing dedicated management actions to address pressure on liquidity, mainly caused by unprecedented levels of
commodity prices.
3.3 Net investments
Total Capex amounted to €7.9 billion, including growth CAPEX of €5.5 billion.
Capital expenditure (CAPEX) by activity
(1) Cash and cash equivalents plus liquid debt instruments held for cash investment purposes minus bank overdrafts.

25
MANAGEMENT REPORT
Growth capital expenditure amounted to €5.5 billion, breaking down as follows by activity:
(1) Net of disposals under DBSO operations, excluding Corporate.
The geography/activity matrix for growth capital expenditure is presented below:
Rest of Latin USA & Middle East,

In millions of euros France Europe America Canada Asia & Africa Others Dec. 31, 2022
Renewables 361 1,094 876 648 214 10 3,202
Networks 779 63 245 ‐ ‐ ‐ 1,087
Client Solutions 354 122 19 66 75 80 716
Thermal ‐ 181 9 34 (9) 6 220
Supply 62 42 ‐ ‐ 7 63 174
Nuclear ‐ ‐ ‐ ‐ ‐ ‐ ‐
Others ‐ 4 ‐ ‐ ‐ 80 85
of which GEMS ‐ ‐ ‐ ‐ ‐ 63 63
TOTAL CAPEX 1,556 1,506 1,148 748 287 240 5,485
Rest of Latin USA & Middle East, Dec. 31, 2021

In millions of euros France Europe America Canada Asia & Africa Others (1) (2)
Renewables 244 224 462 767 183 2 1,881

Networks 812 68 440 ‐ ‐ ‐ 1,320
Client Solutions 209 118 15 305 29 40 715
Thermal ‐ 8 26 ‐ (52) 1 (17)
Supply 74 46 ‐ ‐ 11 24 154
Nuclear ‐ ‐ ‐ ‐ ‐ ‐ ‐
Others ‐ 4 ‐ (1) ‐ 218 221
of which GEMS ‐ ‐ ‐ ‐ ‐ (31) (31)
TOTAL CAPEX 1,338 468 942 1,071 171 285 4,275
(1) Growth capital expenditure (CAPEX) now include changes in the scope of net financial debt of acquired companies. Data at
December 31, 2021 have been restated accordingly.
(2) Certain internal reclassifications, which have no impact on the total, have been made between the business lines at
December 31, 2021. The main internal reclassifications concern the transfer of international Energy Supply activities to Others, of
the North American Renewable Energies activities to Energy Solutions, and the reallocation of Corporate costs between business
lines.
Net investments for the period amounted to €0,2 billion and include:
• growth capital expenditure for €5.5 billion (see above);

• gross maintenance capital expenditure amounting to €2.4 billion;

26
MANAGEMENT REPORT
• new right-of-use assets recognized over the period for €1.2 billion;
• the effects of the reduction in net financial debt recognized in accordance with IFRS 5 as Non-current assets held
for sale and discontinued operations for a negative €0.9 billion;
• proceeds from disposals representing an inflow of €-7.9 billion.
3.4 Dividends and movements in treasury stock
Dividends and movements in treasury stock during the period amounted to €3.1 billion and include ENGIE's dividend
payment in May 2022 for the 2021 fiscal year for €2.1 billion, and dividends paid by various subsidiaries to their non-
controlling interests in an amount of €0.5 billion, the hybrid debt repurchase and payment of interest for €0.5 billion, and
capital movements relating to the global employee share ownership plan Link 2022 for €0.1 billion.
3.5 Net financial debt at December 31, 2022
Excluding amortized cost but including the impact of foreign currency derivatives, at December 31, 2022 a total of 83% of
net financial debt was denominated in euros, 11% in US dollars and 10% in Brazilian real.
Including the impact of financial instruments, 90% of net debt is at fixed rates.
The average maturity of the Group's net debt is 12.5 years.
At December 31, 2022, the Group had total undrawn confirmed credit lines of €12.5 billion.
3.6 Rating
On August 17, 2022, S&P reaffirmed its BBB+ long-term issuer rating and short-term issuer rating at A-2, with a stable
outlook.
On September 1, 2022, Moody’s reaffirmed its Baa1/P-2 senior unsecured rating, with a stable outlook.
On October 19, 2022 Fitch confirmed its long-term issuer rating at A-, and its short-term rating at F1, with a stable outlook.

27
MANAGEMENT REPORT
4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL POSITION
4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL

POSITION
In millions of euros Dec. 31, 2022 Dec. 31, 2021 Net change
Non-current assets 131,521 117,418 14,102
Of which goodwill 12,854 12,799 55
Of which property, plant and equipment and intangible assets, net 62,853 57,863 4,990
Of which derivative instruments 33,134 25,616 7,517
Of which investments in equity method entities 9,279 8,498 780
Current assets 103,969 107,915 (3,946)
Of which trade and other payables 31,310 32,556 (1,245)
Of which derivative instruments 15,252 19,373 (4,120)
Of which assets classified as held for sale 428 11,881 (11,452)
Total equity 39,285 41,980 (2,695)
Provisions 27,027 25,459 1,568
Borrowings 40,591 41,048 (457)
Financial instruments derivatives 51,276 46,931 4,346
Other liabilities 77,311 69,916 7,395
Of which liabilities directly associated with assets classified as held for sale 371 7,415 (7,045)
The carrying amount of property, plant and equipment and intangible assets was €62.9 billion, up €5.0 billion compared
with December 31, 2021. This increase was primarily the result of investments carried out over the period (positive
€8.7 billion impact) and translation adjustments (positive €1.0 billion impact, mainly due to the appreciation of the US dollar
and the Brazilian real), partially offset by depreciation and amortization (negative €4.6 billion impact) and impairment losses
(negative €2.3 billion impact).
Goodwill amounted to €12.9 billion, stable compared with December 31, 2021.
Investments in equity method entities increased by €0.8 billion, primarily due to the acquisition of Eolia Renovables
(see Note 4.3).
Total equity amounted to €39.3 billion, a decrease of €2.7 billion compared with December 31, 2021, essentially reflecting
the payment of dividends (negative €2.6 billion impact), operations on deeply-subordinated perpetual notes (negative
€0.5 billion impact), and other comprehensive income (€0.2 billion negative impact, including a negative €4.7 billion of cash
flow hedges on commodities, a positive €2.7 billion of actuarial gains and losses, a positive €0.9 billion of share in equity
method entities, and a positive €0.8 billion of translation adjustments) offset by net income for the period (positive €0.4
billion impact).
Provisions increased by €1.6 billion to €27.0 billion compared with December 31, 2021. This increase stemmed mainly
from the increase in provisions for the decommissioning of nuclear production facilities and for the management of the
back-end of the nuclear fuel cycle by Synatom (see Note 17), partially offset by actuarial gains on provisions for
post-employment benefits and other long-term benefits (which deducted €2.8 billion from the provision amount) owing to
the sharp rise in discount rates over the period (see Note 18).
The increase in derivative instruments is mainly due to the extreme volatility in commodity prices over the year.
“Assets classified as held for sale” and “Liabilities directly associated with assets classified as held for sale”
correspond solely to a thermal power plant in Brazil, following the disposal of EQUANS in October 2022.

28
MANAGEMENT REPORT
5 PARENT COMPANY FINANCIAL STATEMENTS
5 PARENT COMPANY FINANCIAL STATEMENTS
The figures provided below relate to the financial statements of ENGIE SA, prepared in accordance with French GAAP
and applicable regulations.
Revenues for ENGIE SA in 2022 totaled €68,500 million, an increase compared to 2021 (€36,224 million), both on the gas
and electricity markets.
Net operating income amounted to €1,051 million in 2022, an improvement of €1,897 million compared with a loss of
€846 million in 2021. The energy margin deteriorated by €152 million.
Net financial income amounted to €1,786 million, an increase of €1,405 million compared to 2021 due to higher dividends
received.
Non-recurring items represented a loss of €1,461 million, mainly comprising changes in the value of equity interests
(including Electrabel) and capital gains on the disposal of shares (including GazTransport et Technigaz).
The income tax benefit amounted to €321 million, versus an income tax benefit of €474 million in 2021, including a tax
consolidation benefit of €253 million.
Net income for the year came in at €1,697 million.
Shareholders’ equity amounted to €31,117 million at end-2022 compared with €31,211 million at end-2021. The €94 million
decrease was mainly due to the 2022 net income of €1,697 million, and to the 2021 dividend payment for an amount of
€2,093 million.
At December 31, 2022, borrowings and debt stood at €40,885 million, and cash and cash equivalents totaled
€16,809 million (of which €10,105 million relating to subsidiaries’ current accounts).
Information relating to payment terms
Pursuant to Articles L.441-14 and D.441-6 of the French Commercial Code, companies whose annual financial statements
are subject to a statutory audit must publish information regarding supplier and customer payment terms. The purpose is
to demonstrate that there is no significant failure to comply with such terms.
Information relating to supplier and customer payment terms mentioned in Articles L.441-10 to L.441-16 of the
French Commercial Code
Articles L441-10 to L441-16 : Invoices received,

unpaid and overdue at Articles L441-10 to L441-16 : Invoices issued, unpaid
the reporting date and overdue at the reporting date
91 Total 91
1 to 31 to 61 to days (1 day 1 to 31 to 61 to days Total
0 day 30 60 90 or or 0 day 30 60 90 or (1 day or
In millions of euros (indicative) days days days more more) (indicative) days days days more more)
(A) By aging category
Number of invoices ‐ 46,998 ‐ 4,221,959
Aggregate invoice amount (incl. VAT) ‐ 53.7 130.1 8.0 799.8 991.5 ‐ 287.8 147.1 208.3 918.5 1,561.8
Percentage of total amount of ‐ 0.06% 0.16% 0.01% 0.96% 1.19%
purchases (incl.
Percentage VAT)
of total for the period
revenues (incl. ‐ 0.36% 0.18% 0.26% 1.14% 1.93%
VAT) for the period
(B) Invoices excluded from (A) relating to disputed or unrecognized receivables and payables
Number of excluded invoices 540 542
Aggregate amount of excluded (6.9) 0.8
invoices
(C) Standard payment terms used (contractual or legal terms - Article L. 441-6 or Article L. 443-1 of the French Commercial Code)
Payment terms used to calculate late Contractual payment terms: 14 days
payments Legal payment terms: 30 days Legal payment terms: 30 days

29
30
02 CONSOLIDATED
FINANCIAL STATEMENTS
INCOME STATEMENT .......................................................................................................................................................... 32
STATEMENT OF COMPREHENSIVE INCOME ............................................................................................................... 33
STATEMENT OF FINANCIAL POSITION........................................................................................................................... 34
STATEMENT OF CHANGES IN EQUITY........................................................................................................................... 36
STATEMENT OF CASH FLOWS ......................................................................................................................................... 38

31
CONSOLIDATED FINANCIAL STATEMENTS
INCOME STATEMENT
INCOME STATEMENT
In millions of euros Notes Dec. 31, 2022 Dec. 31, 2021

REVENUES 6.2 & 7 93,865 57,866
Purchases and operating derivatives 8.1 (74,535) (38,861)
Personnel costs 8.2 (8,078) (7,692)
Depreciation, amortization and provisions 8.3 (5,187) (4,840)
Taxes 8.4 (3,380) (1,479)
Other operating income 1,624 1,122
Current operating income including operating MtM 4,309 6,116
Share in net income of equity method entities 6.2 1,059 800
Current operating income including operating MtM and share in net income of equity method
entities 0 5,367 6,916
Impairment losses 9.1 (2,774) (1,028)
Restructuring costs 9.2 (230) (204)
Changes in scope of consolidation 9.3 91 1,107
Other non-recurring items 9.4 (1,328) (69)
NET INCOME/(LOSS) FROM OPERATING ACTIVITIES 9 1,127 6,722
Financial expenses (3,700) (2,061)
Financial income 697 711
NET FINANCIAL INCOME/(LOSS) 10 (3,003) (1,350)
Income tax benefit/(expense) 11 83 (1,695)
NET INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS (1,793) 3,678
NET INCOME/(LOSS) RELATING TO DISCONTINUED OPERATIONS 2,183 80
NET INCOME/(LOSS) 390 3,758
Of which Net income/(loss) relating to continuing operations, Group share (1,965) 3,582
Of which Net income/(loss) relating to discontinued operations, Group share 2,182 79
Non-controlling interests 173 97
Of which Non-controlling interests relating to continuing operations 172 96
Of which Non-controlling interests relating to discontinued operations 1 1
BASIC EARNINGS/(LOSS) PER SHARE (EUROS) 12 0.08 1.46
Of which Basic earnings/(loss) relating to continuing operations per share (0.84) 1.43
Of which Basic earnings/(loss) relating to discontinued operations per share 0.93 0.03
DILUTED EARNINGS/(LOSS) PER SHARE (EUROS) 12 0.08 1.46
Of which Diluted earnings/(loss) relating to continuing operations per share (0.84) 1.42
Of which Diluted earnings/(loss) relating to discontinued operations per share 0.93 0.03
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies
in the totals.

32
STATEMENT OF COMPREHENSIVE INCOME
STATEMENT OF COMPREHENSIVE INCOME

Debt instruments 14.1 (378) (21)
Net investment hedges 15 (15) (215)
Cash flow hedges (excl. commodity instruments) 15 938 511
Commodity cash flow hedges 15 (4,719) 3,980
Deferred tax on recyclable or recycled items 951 (1,333)
Share of equity method entities in recyclable items, net of tax 871 270
Translation adjustments 848 909
Recyclable items relating to discontinued operations, net of tax (118) 114
TOTAL RECYCLABLE ITEMS (1,622) 4,215
Equity instruments 14.1 (685) 159
Actuarial gains and losses 2,718 1,742
Deferred tax on non recyclable items (613) (451)
Share of equity method entities in actuarial gains and losses, net of tax 5 ‐
Non-recyclable items relating to discontinued operations, net of tax 48 48
TOTAL NON-RECYCLABLE ITEMS 1,472 1,499
TOTAL RECYCLABLE ITEMS AND NON-RECYCLABLE ITEMS (150) 5,713
TOTAL COMPREHENSIVE INCOME/(LOSS) 240 9,471
Of which owners of the parent (257) 9,415
Of which non-controlling interests 497 56
in the totals.

33
STATEMENT OF FINANCIAL POSITION
STATEMENT OF FINANCIAL POSITION
ASSETS

Non-current assets
Goodwill 13.1 12,854 12,799
Intangible assets, net 13.2 7,364 6,784
Property, plant and equipment, net 13.3 55,488 51,079
Other financial assets 14 10,599 10,949
Derivative instruments 14 33,134 25,616
Assets from contracts with customers 7 9 34
Investments in equity method entities 3 9,279 8,498
Other non-current assets 22 766 478
Deferred tax assets 11 2,029 1,181
TOTAL NON-CURRENT ASSETS 131,521 117,418
Current assets
Other financial assets 14 2,394 2,495
Trade and other receivables, net 7 31,310 32,555
Assets from contracts with customers 7 12,575 8,344
Inventories 22 8,145 6,175
Other current assets 22 18,294 13,202
Cash and cash equivalents 14 15,570 13,890
Assets classified as held for sale 4.2 428 11,881
TOTAL CURRENT ASSETS 103,969 107,915
TOTAL ASSETS 235,490 225,333
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material
discrepancies in the totals.

34
LIABILITIES

Shareholders' equity 34,253 36,994
Non-controlling interests 2 5,032 4,986
TOTAL EQUITY 16 39,285 41,980
Non-current liabilities
Provisions 17 24,663 23,394
Long-term borrowings 14 28,083 30,458
Other financial liabilities 14 90 108
Liabilities from contracts with customers 7 121 68
Other non-current liabilities 22 3,646 2,342
Deferred tax liabilities 11 6,408 7,738
TOTAL NON-CURRENT LIABILITIES 102,427 88,336
Current liabilities
Provisions 17 2,365 2,066
Short-term borrowings 14 12,508 10,590
Trade and other payables 14 39,801 32,822
Liabilities from contracts with customers 7 3,292 2,671
Other current liabilities 22 23,583 16,752
Liabilities directly associated with assets classified as held for sale 4.2 371 7,415
TOTAL CURRENT LIABILITIES 93,778 95,019
TOTAL EQUITY AND LIABILITIES 235,490 225,333

35
STATEMENT OF CHANGES IN EQUITY

Deeply- Changes
Additio- subor- in fair Transla-
nal Consoli- dinated value tion Sharehol- Non-
Share paid-in dated perpetual and adjust- Treasury ders' controlling
In millions of euros capital capital reserves notes other ments stock equity interests Total
EQUITY AT DECEMBER 31, 2020 2,435 31,291 (3,874) 3,913 (1,719) (2,850) (251) 28,945 4,911 33,856
Net income/(loss) 3,661 3,661 97 3,758
Other comprehensive income/(loss) 1,490 3,431 833 5,753 (40) 5,713
TOTAL COMPREHENSIVE
INCOME/(LOSS) 5,151 3,431 833 9,415 56 9,471
Share-based payment ‐ ‐ 48 48 1 49
Dividends paid in cash (1) (1,296) ‐ (1,296) (410) (1,706)
Purchase/disposal of treasury stock (52) 52 ‐ ‐ ‐
Operations on deeply-subordinated
perpetual notes (1) (129) (146) (275) (275)
Transactions between owners (1) (2) 324 324 740 1,064
Transactions with impact on non-
controlling interests (1) (3) ‐ ‐ (312) (312)
Share capital increases and decreases ‐ (1) (1)
Normative changes 43 43 1 44
Other changes (1) (4) (3,937) 3,726 ‐ (211) 1 (209)
EQUITY AT DECEMBER 31, 2021 2,435 26,058 5,238 3,767 1,711 (2,017) (199) 36,994 4,986 41,980
(1) Transactions of the period are listed in Note 19 “Equity” to the consolidated financial statements for the year ended
December 31, 2021.
(2) Mainly relates to the disposal of 11.5% of GRTgaz.
(3) Mainly relates to the partial disposal of Gaztransport & Technigaz SA (GTT).
(4) Mainly concerns the dispute with the French tax authorities on the assignment without recourse of the withholding tax claim made in
2005 by SUEZ. This dispute is presented in Note 26.7.1 “Legal and anti-trust proceedings” in the consolidated financial statements
for the year ended December 31, 2021.
in the totals.

36
Deeply- Changes
Additio- subor- in fair Transla- Non-
nal Consoli- dinated value tion Sharehol- control-
Share paid-in dated perpetual and adjust- Treasury ders' ling
In millions of euros capital capital reserves notes other ments stock equity interests Total
EQUITY AT DECEMBER 31, 2021 2,435 26,058 5,238 3,767 1,711 (2,017) (199) 36,994 4,986 41,980
Net income/(loss) 216 216 173 390
Other comprehensive income/(loss) 1,311 (2,379) 595 (474) 324 (150)
TOTAL COMPREHENSIVE
INCOME/(LOSS) 1,527 ‐ (2,379) 595 ‐ (257) 497 240
Share-based payment ‐ 3 45 48 ‐ 48
Dividends paid in cash (1) (394) (1,689) (2,082) (482) (2,565)
Purchase/disposal of treasury stock (43) 10 (33) ‐ (33)
Operations on deeply-subordinated
perpetual notes (1) (77) (374) (451) ‐ (451)
Transactions between owners (1) (2) 154 154 56 210
Transactions with impact on non-
controlling interests ‐ ‐ (41) (41)
Share capital increases and decreases ‐ 19 19
Normative change (3) (116) (116) (6) (121)
Other changes ‐ (5) ‐ ‐ (5) 3 (1)
EQUITY AT DECEMBER 31, 2022 2,435 25,667 5,036 3,393 (668) (1,422) (189) 34,253 5,032 39,285
(1) Transactions of the period are listed in Note 16 “Equity”.
(2) Mainly relates to the sale of part of the renewable assets portfolio in the United States (see Note 16.2.4 “Other transactions”).
(3) SaaS arrangement (see Note 1.1.2 “Other text”).

37
STATEMENT OF CASH FLOWS
STATEMENT OF CASH FLOWS

Dec. 31, Dec. 31,
In millions of euros Notes 2022 2021
- Net income/(loss) relating to discontinued operations 2,183 80
- Share in net income of equity method entities (1,059) (800)
+ Dividends received from equity method entities 713 662
- Net depreciation, amortization, impairment and provisions 8,057 5,484
- Impact of changes in scope of consolidation and other non-recurring items 74 (1,039)
- Mark-to-market on commodity contracts other than trading instruments 3,661 (721)
- Other items with no cash impact (157) (501)
- Income tax expense 11 (83) 1,695
- Net financial income/(loss) 10 3,003 1,350
Cash generated from operations before income tax and working capital requirements 12,415 9,807
+ Tax paid (1,504) (603)
Change in working capital requirements 22.1 (2,424) (2,377)
CASH FLOW FROM OPERATING ACTIVITIES RELATING TO CONTINUING OPERATIONS 8,488 6,827
CASH FLOW FROM OPERATING ACTIVITIES RELATING TO DISCONTINUED OPERATIONS 98 486
CASH FLOW FROM OPERATING ACTIVITIES 8,586 7,313
Acquisitions of property, plant and equipment and intangible assets 13.2 & 13.3 (6,379) (5,990)
Acquisitions of controlling interests in entities, net of cash and cash equivalents acquired 4 & 14 (289) (392)
Acquisitions of investments in equity method entities and joint operations 4 & 14 (407) (369)
Acquisitions of equity and debt instruments 14 175 (1,548)
Disposals of property, plant and equipment, and intangible assets 13.2 & 13.3 173 88
Loss of controlling interests in entities, net of cash and cash equivalents sold 4 & 14 6,728 (173)
Disposals of investments in equity method entities and joint operations 4 & 14 1,461 62
Disposals of equity and debt instruments 14 268 73
Interest received on financial assets (37) 32
Dividends received on equity instruments 18 57
Change in loans and receivables originated by the Group and other 5.6 (2,877) 121
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES RELATING TO CONTINUING OPERATIONS (1,167) (8,039)
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES RELATING TO DISCONTINUED OPERATIONS (3,123) (3,003)
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES (4,290) (11,042)
Dividends paid (1) (2,665) (1,859)
Repayment of borrowings and debt (10,972) (5,054)
Change in financial assets held for investment and financing purposes 188 464
Interest paid (822) (719)
Interest received on cash and cash equivalents 194 52
Cash flow on derivatives qualifying as net investment hedges and compensation payments on derivatives
and on early buyback of borrowings (216) (219)
Increase in borrowings 8,669 8,353
Increase/decrease in capital (259) 226
Purchase and/or sale of treasury stock (115) ‐
Changes in ownership interests in controlled entities 5.6 ‐ 1,085
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES RELATING TO CONTINUING OPERATIONS (5,997) 2,329
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES RELATING TO DISCONTINUED 3,019 2,519
OPERATIONS
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES (2,979) 4,848
Effects of changes in exchange rates and other relating to continuing operations 356 223
Effects of changes in exchange rates and other relating to discontinued operations 7 10
Effects of changes in exchange rates and other 363 233
TOTAL CASH FLOW FOR THE PERIOD 1,680 1,352
Reclassification of cash and cash equivalents relating to discontinued operations ‐ (440)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 13,890 12,980
CASH AND CASH EQUIVALENTS AT END OF PERIOD 15,570 13,890
(1) The line “Dividends paid” includes the coupons paid to owners of deeply-subordinated perpetual notes (see Note 16 “Equity”).
in the totals.

38
39
03 NOTES TO THE
CONSOLIDATED FINANCIAL
STATEMENTS
Note 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL
STATEMENTS ........................................................................................................................................................................ 41
Note 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2022................................................................................................ 46
Note 3 INVESTMENTS IN EQUITY METHOD ENTITIES .............................................................................................. 52
Note 4 MAIN CHANGES IN GROUP STRUCTURE ....................................................................................................... 60
Note 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ............................................................ 64
Note 6 SEGMENT INFORMATION.................................................................................................................................... 69
Note 7 REVENUES .............................................................................................................................................................. 74
Note 8 OPERATING EXPENSES ...................................................................................................................................... 79
Note 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES............................................... 81
Note 10 NET FINANCIAL INCOME/(LOSS) ....................................................................................................................... 84
Note 11 INCOME TAX EXPENSE........................................................................................................................................ 85
Note 12 EARNINGS PER SHARE ....................................................................................................................................... 89
Note 13 FIXED ASSETS ........................................................................................................................................................ 90
Note 14 FINANCIAL INSTRUMENTS ................................................................................................................................ 105
Note 15 RISKS ARISING FROM FINANCIAL INSTRUMENTS..................................................................................... 124
Note 16 EQUITY ................................................................................................................................................................... 143
Note 17 PROVISIONS ......................................................................................................................................................... 147
Note 18 POST-EMPLOYMENT BENEFITS AND OTHER LONG-TERM BENEFITS ............................................... 157
Note 19 SHARE-BASED PAYMENTS............................................................................................................................... 166
Note 20 RELATED PARTY TRANSACTIONS ................................................................................................................. 170
Note 21 EXECUTIVE COMPENSATION .......................................................................................................................... 172
Note 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES, OTHER ASSETS AND OTHER LIABILITIES 173
Note 23 LEGAL AND ANTI-TRUST PROCEEDINGS ..................................................................................................... 175
Note 24 SUBSEQUENT EVENTS ...................................................................................................................................... 182
Note 25 FEES PAID TO THE STATUTORY AUDITORS AND TO MEMBERS OF THEIR NETWORKS .............. 183
Note 26 INFORMATION REGARDING LUXEMBOURG AND DUTCH COMPANIES EXEMPTED FROM THE
REQUIREMENTS TO PUBLISH ANNUAL FINANCIAL STATEMENTS...................................................................... 184

40
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS
ENGIE SA, the parent company of the Group, is a French société anonyme with a Board of Directors that is subject to the
provisions of Book II of the French Commercial Code (Code du commerce), as well as to all other provisions of French law
applicable to French commercial companies. It was incorporated on November 20, 2004 for a period of 99 years.
It is governed by current and future laws and by regulations applicable to sociétés anonymes and its bylaws.
The Group is headquartered at 1 place Samuel de Champlain, 92400 Courbevoie (France).
ENGIE shares are listed on the Paris, Brussels and Luxembourg stock exchanges.
On February 20, 2023, the Group's Board of Directors approved and authorized for issue the consolidated financial
statements of the Group for the year ended December 31, 2022.
NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR

PREPARING THE CONSOLIDATED FINANCIAL
STATEMENTS
1.1 Accounting standards
Pursuant to European Regulation (EU) 2019/980 dated March 14, 2019, financial information concerning the assets,
liabilities, financial position, and profit and loss of ENGIE has been provided for the last two reporting periods (ended
December 31, 2021 and 2022). This information was prepared in accordance with European Regulation (EC) 1606/2002
“on the application of international accounting standards” dated July 19, 2002. The Group's consolidated financial
statements for the year ended December 31, 2022 have been prepared in accordance with IFRS Standards as published
by the International Accounting Standards Board and endorsed by the European Union (1).
The accounting standards applied in the consolidated financial statements for the year ended December 31, 2022 are
consistent with the policies used to prepare the consolidated financial statements for the year ended December 31, 2021,
except for those described below.
1.1.1 IFRS Standards, amendments or IFRIC Interpretations applicable in 2022
• Amendments to IAS 37 – Provisions, Contingent Liabilities and Contingent Assets: Onerous Contracts - Cost of
Fulfilling a Contract.
• Annual improvements to IFRSs – 2018-2020 cycle.
These amendments and improvements have no material impact on the Group’s consolidated financial statements.
• Amendments to IAS 16 – Property, Plant and Equipment: Proceeds before Intended Use.
The Group elected to early adopt these amendments, as indicated in Note 1.1.3 to the consolidated financial statements
for the year ended December 31, 2021. These amendments have no material impact on the Group's consolidated financial
statements.
(1) Available on the European Commission’s website:

http://eur-lex.europa.eu/legal-content/FR/TXT/?uri=CELEX:02002R1606-20080410

41
1.1.2 Other text
• In its March 2021 agenda decision, the IFRS Interpretations Committee (IFRIC) clarified the accounting treatment
of configuration and customization costs for software in a SaaS (Software as a Service) arrangement. According
to the IFRIC, some of these costs should be recognized as an expense (and not as an intangible asset). This
decision does not have a material impact on the Group’s consolidated financial statements.
1.1.3 IFRS Standards, amendments or IFRIC Interpretations effective as from 2023

and that the Group has elected not to early adopt
• Amendments to IAS 1 - Presentation of Financial Statements: Classification of Liabilities as Current or

Non-Current (1).
• IFRS 17 - Insurance Contracts (including amendments).
• Amendments to IAS 1 – Presentation of Financial Statements and the Materiality Practice Statement: Disclosure
of Accounting Policies.
• Amendments to IAS 8 – Accounting Policies, Changes in Accounting Estimates and Errors: Definition of
Accounting Estimates.
• Amendments to IAS 12 – Income Taxes: Deferred Tax related to Assets and Liabilities arising from a Single
Transaction.
• Amendments to IFRS 16 - Leases: Lease Liability in a Sale and Leaseback (1).
The impact of these standards and amendments is currently being assessed.
1.2 Measurement and presentation basis
1.2.1 Historical cost convention
The Group's consolidated financial statements are presented in euros and have been prepared using the historical cost
convention, except for financial instruments, which are accounted for under the financial instrument categories defined by
IFRS 9.
1.2.2 Chosen options
1.2.2.1 Reminder of IFRS 1 transition options
The Group used some of the options available under IFRS 1 for its transition to IFRS in 2005. The options that continue to
have an impact on the consolidated financial statements are:
• translation adjustments: the Group elected to reclassify cumulative translation adjustments within consolidated
equity at January 1, 2004;
• business combinations: the Group elected not to restate business combinations that took place prior to
January 1, 2004 in accordance with IFRS 3.
1.2.2.2 Business combinations
Business combinations carried out prior to January 1, 2010 were accounted for in accordance with IFRS 3 prior to the
revision. In accordance with IFRS 3 revised, these business combinations have not been restated.
(1) These standards and amendments have not yet been adopted by the European Union.

42
Since January 1, 2010, the Group applies the purchase method as defined in IFRS 3 revised, which consists in recognizing
the identifiable assets acquired and liabilities assumed at their fair values at the acquisition date, as well as any non-
controlling interests in the acquiree. Non-controlling interests are measured either at fair value or at the entity's
proportionate interest in the net identifiable assets of the acquiree. The Group determines on a case-by-case basis which
measurement option to be used to recognize non-controlling interests.
1.2.2.3 Consolidated statement of cash flows
The consolidated statement of cash flows is prepared using the indirect method starting from net income.
“Interest received on non-current financial assets” is classified within investing activities because it represents a return on
investments. “Interest received on cash and cash equivalents” is shown as a component of financing activities because
the interest can be used to reduce borrowing costs. This classification is consistent with the Group's internal organization,
where debt and cash are managed centrally by the Group treasury department.
As impairment losses on current assets are considered to be definitive losses, changes in current assets are presented
net of impairment.
Cash flows relating to the payment of income tax are presented on a separate line.
1.2.3 Foreign currency transactions
1.2.3.1 Translation of foreign currency transactions
Foreign currency transactions are recorded in the functional currency at the exchange rate prevailing on the date of the
transaction.
Functional currency is the currency of the primary economic environment in which an entity operates, which in most cases
corresponds to local currency. However, certain entities may have a functional currency different from the local currency
when that other currency is used for an entity's main transactions and better reflects its economic environment.
At each reporting date:
• monetary assets and liabilities denominated in foreign currencies are translated at year-end exchange rates. The
resulting translation gains and losses are recorded in the consolidated income statement for the year to which they
relate;
• non-monetary assets and liabilities denominated in foreign currencies are recognized at the historical cost
applicable at the date of the transaction.
1.2.3.2 Translation of the financial statements of subsidiaries with a functional currency

other than the euro (the presentation currency)
The statements of financial position of these subsidiaries are translated into euros at the official year-end exchange rates.
Income statement and cash flow statement items are translated using the average exchange rate for the year. Any
differences arising from the translation of the financial statements of these subsidiaries are recorded under “Translation
adjustments” as other comprehensive income.
Goodwill and fair value adjustments arising on the acquisition of foreign entities are classified as assets and liabilities of
those foreign entities and are therefore denominated in the functional currencies of the entities and translated at the year-
end exchange rate.

43
1.3 Use of estimates and judgment
1.3.1 Estimates
The preparation of consolidated financial statements requires the use of estimates and assumptions to determine the value
of assets and liabilities and contingent assets and liabilities at the reporting date, as well as income and expenses reported
during the period.
Developments in the economic and financial environment, particularly relating to highly volatile commodities markets and
the war in Ukraine, have prompted the Group to step up its risk oversight procedures, mainly in measuring financial
instruments, assessing contingencies related to interruptions in the natural gas supply, as well as counterparty and liquidity
risks. The estimates used by the Group, among other things, to test for impairment and to measure provisions, also take
into account this environment and the sharp market volatility.
Accounting estimates are made in a context that remains sensitive to energy market developments, therefore making it
difficult to apprehend medium- and short-term economic prospects. Particular attention has been paid to the consequences
of sharp fluctuations in the price of gas and electricity.
Due to uncertainties inherent in the estimation process, the Group regularly revises its estimates in light of currently
available information. Final outcomes could differ from those estimates.
The key estimates used in preparing the Group's consolidated financial statements relate mainly to:
• measurement of the recoverable amount of goodwill (see Note 13.1), other intangible assets (see Note 13.2) and
property, plant and equipment (see Note 13.3);
• measurement of the fair value of financial assets and liabilities, and, in the current context, factoring in the
uncertainty surrounding the key assumptions used, in particular the contingencies related to interruptions in the
natural gas supply as well as the effects on the minority interest held by the Group in Nord Stream AG and on the
loan related to the financing of the Nord Stream 2 pipeline project (see Note 14). The Group has also updated the
main valuation inputs of its commodity derivatives, in particular the “bid ask” reserve, to reflect the increased
volatility of commodity prices and the reduced liquidity observed in the European gas and electricity markets in the
second half of 2022 (see notes 14 and 15);
• assessment of expected credit losses, particularly in order to update probabilities of default and other inputs, mainly
for calculating the CVA (Credit Valuation Adjustment) in an uncertain context with high market price volatility (see
Note 15);
• measurement of provisions, particularly for the back-end of the nuclear fuel cycle, dismantling obligations, disputes,
and pensions and other employee benefits (see Notes 17 and 18);
• measurement of the fair value of assets acquired and liabilities assumed in a business combination (see Note 4);
• measurement of un-metered revenues (energy in the meter), for which the valuation techniques have been
impacted by changes in certain customers' consumption habits in a context of sharp fluctuations in commodity
prices (see Note 7);
• measurement of recognized tax loss carry-forwards, taking into account, where applicable, taxable income
revisions and projections (see Note 11).
1.3.2 Judgment
As well as relying on estimates, Group management also makes judgments to define the appropriate accounting policies
to apply to certain activities and transactions, particularly when the IFRS Standards and IFRIC Interpretations in force do
not specifically deal with the related accounting issues.
In particular, the Group exercised its judgment in:
• assessing the type of control (see Notes 2 and 3);

• identifying the performance obligations of sales contracts (see Note 7);

44
• determining how revenues are recognized for distribution or transmission services invoiced to customers (see
Note 7);
• recognizing support measures granted by certain governments, particularly in France and Romania (“tariff shield”),
aimed at protecting both consumers and suppliers of gas and electricity against sharp fluctuations in commodity
prices (see Note 7);
• identifying "own use contracts" as defined by IFRS 9 within non-financial purchase and sale contracts (electricity,
gas, etc.) (see Note 14);
• identifying offsetting arrangements that meet the criteria set out in IAS 32 Financial Instruments: Presentation
(see Note 14);
• determining whether arrangements are or contain a lease (see Note 13.3);
• recognizing new contributions in the energy sector in Europe (see Note 8).
Entities for which judgment on the nature of control has been exercised are listed in Note 2 “Main subsidiaries at December
31, 2022” and Note 3 “Investments in equity method entities”.
1.3.3 Consideration of climate issues in the preparation of the Group's financial

statements
In addition to the operational and financial issues and risks taken into account in determining future cash flows, the discount
rate net of inflation and projected growth, the Group has also exercised its judgment to use assumptions reflecting climate
change issues, in order to determine the potential impact on the consolidated financial statements, particularly if there were
indications that non-financial assets might be impaired:
• The commitments made by France, Europe and various countries at international level, in particular with regard to
long-term carbon neutrality, are taken into account (i) in assessing the value of the Group's assets, in particular
through the long-term price scenarios used in impairment tests (see Note 13.4), and (ii) in assessing dismantling
provisions, in particular by assessing the useful life of the gas infrastructures in France based on the expected
change in the energy mix (see Note 17).
• The commitments specifically made by ENGIE are also reflected in the assessment of the value of the Group's
assets (see Note 13.1), in particular (i) the complete withdrawal from coal by 2027, which primarily concerns South
America, depending on each asset's specific prospects (closure, conversion or disposal), and (ii) the gradual
decarbonization of the Group's power generation activities to net zero by 2045 and, more broadly, the Group's
investment strategy in favor of the energy transition by expanding its renewable energy fleet, substituting natural
gas with renewable gas, thereby confirming a mixed gas/electricity scenario in the Group's long-term projections
under the present regulation/remuneration methods for regulated assets (in France in particular), and developing
low-carbon services offerings.
As a reminder, the management of climate and environmental risks and their challenges for the Group are presented in
Chapter 2 “Risk factors” and Chapter 3 “Non-Financial Statement and CSR Information” of the Universal Registration
Document.

45
NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2022
Accounting standards
Controlled entities (subsidiaries) are fully consolidated in accordance with IFRS 10 – Consolidated Financial
Statements. An investor (the Group) controls an entity and therefore must consolidate it if all of the following three
criteria are met:
• it has the ability to direct the relevant activities of the entity;

• it has the rights and is exposed to variable returns from its involvement with the entity;
• it has the ability to use its power over the entity to affect the investor’s return.
2.1 List of main subsidiaries at December 31, 2022
The following lists are made available by the Group to third parties, pursuant to Regulation No. 2016-09 of the French
accounting standards authority (ANC) issued on December 2, 2016:
• list of companies included in consolidation;

• list of companies excluded from consolidation because their individual and cumulative incidence on the Group’s
consolidated financial statements is not material. They correspond to entities deemed not significant as regards
the Group’s main key figures (revenues, total equity, etc) or entities that have ceased all activities and are
undergoing liquidation/closure proceedings;
• list of main non-consolidated interests.
This information is available on the Group’s website (www.engie.com, Investors/Regulated information section).
Non-consolidated companies are classified under non-current financial assets (see Note 14.1.1.1) under “Equity
instruments at fair value”.
The list of the main subsidiaries consolidated under the full consolidation method presented below was determined, as
regards operating entities, based on their contribution to Group revenues, EBITDA, net income and net debt. The main
equity-accounted investments (associates and joint ventures) are presented in Note 3 “Investments in equity method
entities”.
Some entities such as ENGIE SA, ENGIE Énergie Services SA or Electrabel SA comprise both operating activities and
headquarters functions which report to management teams of different reportable segments. In the following tables, these
operating activities and headquarters functions are shown within their respective reportable segments under their initial
company name followed by a (*) sign.

46
Renewables
% interest
Company name Activity Country Dec. 31, 2022 Dec. 31, 2021
Compagnie Nationale du Rhône Electricity distribution and generation France 50.0 50.0
ENGIE Energía Perú * Electricity distribution and generation Peru 61.8 61.8
ENGIE Green Electricity distribution and generation France 100.0 100.0
ENGIE Infinity Renewables Electricity distribution and generation United States 100.0 100.0
ENGIE Resources Inc. Energy sales United States 100.0 100.0
ENGIE Romania * Natural gas distribution, Energy sales Romania 51.0 51.0
ENGIE Solar Solar EPC France 100.0 100.0
ENGIE Brazil Energia Group * Electricity distribution and generation Brazil 68.7 68.7
ENGIE Renewables Electricity distribution and generation France 100.0 100.0
ENGIE Energía Chile Group * Electricity distribution and generation Chile 60.0 60.0
Jupiter Equity Holding LLC Electricity distribution and generation United States 51.0 51.0
Networks
% interest
Elengy Natural gas, LNG France 60.8 60.9
Fosmax LNG Natural gas, LNG France 60.8 60.9
GRDF Natural gas distribution France 100.0 100.0
GRTgaz Group (excluding Elengy) Natural gas transportation France, Germany 60.8 60.9
Storengy Deutschland GmbH Underground natural gas storage Germany 100.0 100.0
Storengy SAS Underground natural gas storage France 100.0 100.0
Energy Solutions
% interest
Cofely Besix Systems, facilities and maintenance UAE 100.0 100.0
CPCU services
Urban heating networks France 66.5 66.5
ENGIE Deutschland GmbH Energy services Germany 100.0 100.0
ENGIE Energie Services SA * Energy services, Networks France 100.0 100.0
ENGIE Servizi S.p.A Energy services Italy 100.0 100.0
Endel Group Systems, facilities and maintenance France ‐ 100.0
Tractebel Engineering services
Engineering Belgium 100.0 100.0
Thermal
% interest
Electrabel SA * Electricity generation, Energy sales Belgium 100.0 100.0
ENGIE Cartagena Electricity generation Spain 100.0 100.0
ENGIE Deutschland AG * Electricity generation Germany 100.0 100.0
ENGIE Energía Perú * Electricity distribution and generation Peru 61.8 61.8
ENGIE Energie Nederland N.V. * Electricity generation, Energy sales Netherlands 100.0 100.0
ENGIE Italia S.p.A * Energy sales Italy 100.0 100.0
ENGIE SA * Energy sales France 100.0 100.0
ENGIE Thermique France Electricity generation France 100.0 100.0
First Hydro Holdings Company Electricity generation United Kingdom 75.0 75.0
Pelican Point Power Limited Electricity generation Australia 72.0 72.0
UCH Power Limited Electricity generation Pakistan 100.0 100.0

47
Supply
% interest
ENGIE Italia S.p.A * Energy sales Italy 100.0 100.0
ENGIE SA * Energy sales France 100.0 100.0
ENGIE Supply Holding UK Limited Energy sales United Kingdom 100.0 100.0
Simply Energy Energy sales Australia 72.0 72.0
Nuclear
% interest
Synatom Managing provisions relating to power Belgium 100.0 100.0
plants and nuclear fuel
Others
% interest
ENGIE CC Financial subsidiaries, Central Belgium 100.0 100.0
ENGIE Deutschland AG * Holding, Energy management functions
trading Germany 100.0 100.0
ENGIE Energie Nederland Holding B.V. * Holding, Energy management trading Netherlands 100.0 100.0
ENGIE Energie Nederland N.V. Electricity generation, Energy sales Netherlands 100.0 100.0
ENGIE Energie Services SA * Energy services, Networks France 100.0 100.0
ENGIE Energy Management * Energy management trading France, Belgium, 100.0 100.0
Italy, United
Kingdom
ENGIE Energy Management Holding Switzerland AG Holding Switzerland 100.0 100.0
ENGIE FINANCE SA Financial subsidiaries France 100.0 100.0
ENGIE Global Markets Energy management trading France, Belgium, 100.0 100.0
ENGIE Holding Inc. Holding - parent company Singapore
United States 100.0 100.0
ENGIE Italia S.p.A * Holding, Energy management trading Italy 100.0 100.0
ENGIE North America Electricity distribution and generation, United States 100.0 100.0
Natural gaz, LNG, Energy services
ENGIE SA * Holding - parent company, Energy France 100.0 100.0
management trading, energy sales
Cogac Holding France 100.0 100.0
GDFI Holding France 100.0 100.0
Engie Energie Services International SA Holding Belgium 100.0 100.0
Genfina Holding Belgium 100.0 100.0
International Power Limited Holding United Kingdom 100.0 100.0

48
EQUANS (1)
% interest
Axima Concept Systems, facilities and maintenance France ‐ 100.0
services
Cofely Fabricom SA Systems, facilities and maintenance Belgium ‐ 100.0
services
Conti Service LLC Energy services United States ‐ 100.0
ENGIE Regeneration Energy services United Kingdom ‐ 100.0
ENGIE Services Nederland N.V. Energy services Netherlands ‐ 100.0
ENGIE Services Holding UK Ltd Energy services United Kingdom ‐ 100.0
ENGIE Services Limited Energy services United Kingdom ‐ 100.0
INEO Group Systems, facilities and maintenance France ‐ 100.0
services
(1) Activities held for sale and classified as “Discontinued operations” at December 31, 2021 (see Note 4 “Main changes in Group structure”).
2.2 Significant judgments exercised when assessing control
The Group primarily considers the following information and criteria when determining whether it has control over an entity:
• governance arrangements: voting rights and whether the Group is represented in the governing bodies, majority
rules and veto rights;
• the nature of substantive or protective rights granted to shareholders, relating to the entity’s relevant activities;
• deadlock resolution mechanisms;
• whether the Group is exposed, or has rights, to variable returns from its involvement with the entity.
The Group exercised its judgment regarding the entities and sub-groups described below.
Entities in which the Group has the majority of the voting rights
GRTgaz (France Infrastructures): 60.8%
The analysis of the shareholders' agreement concluded with Société d'Infrastructures Gazières, a subsidiary of Caisse des
Dépôts et Consignations (CDC), which holds 38.6% of the share capital of GRTgaz, was completed by an assessment of
the rights granted to the French Energy Regulatory Commission (Commission de Régulation de l’Énergie – CRE). As a
regulated activity, GRTgaz has a dominant position on the gas transportation market in France. Accordingly, since the
transposition of the Third European Directive of July 13, 2009 into French law (Code de l’énergie – Energy Code) on
May 9, 2011, GRTgaz has been subject to independence rules as regards its directors and senior management team. The
French Energy Code confers certain powers on the CRE in the context of its duties to control the proper functioning of the
gas markets in France, including verifying the independence of the members of the Board of Directors and senior
management and assessing the choice of investments. The Group considers that it exercises control over GRTgaz and its
subsidiaries (including Elengy) based on the Group’s ability to appoint the majority of the members of the Board of Directors
and take decisions about the relevant activities, especially in terms of the level of investment and planned financing.
Entities in which the Group does not have the majority of the voting rights
In the entities in which the Group does not have the majority of the voting rights, judgment is exercised with regard to the
following items, in order to assess whether there is a situation of de facto control:
• dispersion of the shareholding structure: number of voting rights held by the Group relative to the number of rights
held respectively by the other vote holders and their dispersion;
• voting patterns at shareholders' meetings: the percentages of voting rights exercised by the Group at
shareholders' meetings in recent years;
• governance arrangements: representation in the governing body with strategic and operational decision-making
power over the relevant activities;
• rules for appointing key management personnel;

49
• contractual relationships and material transactions.
The main fully consolidated entity in which the Group does not have the majority of the voting rights at December 31, 2022
is Compagnie Nationale du Rhône (49.98%).
Compagnie Nationale du Rhône (“CNR” – Renewables France): 49.98%
The Group holds 49.98% of the share capital of CNR, with CDC holding 33.2%, and the balance of 16.82% being dispersed
among around 200 local authorities. In view of the current provisions of the French “Murcef” law, under which a majority of
CNR's share capital must remain under public ownership, the Group is unable to hold more than 50% of the share capital.
However, the Group considers that it exercises de facto control as it holds the majority of the voting rights exercised at
shareholders’ meetings due to the widely dispersed shareholding structure and the absence of evidence of the minority
shareholders acting in concert.
2.3 Main subsidiaries with non-controlling interests
The following table shows the subsidiaries with non-controlling interests that are deemed to be material, the respective
contributions to equity and to net income at December 31, 2022 and December 31, 2021, as well as the dividends paid to
non-controlling interests:
Percentage interest Net income/(loss) Equity of Dividends paid to

of non-controlling of non-controlling non-controlling non-controlling
Company name Activity interests interests interests interests
Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31,
In millions of euros 2022 2021 2022 2021 2022 2021 2022 2021
GRTgaz Group (France Regulated gas 39.2 39.1 190 106 1,614 1,554 168 105
Infrastructures, France) transportation activities and
management of LNG
terminals
ENGIE Energía Chile Group Electricity distribution and 40.0 40.0 (158) 17 680 781 ‐ 31
(Latin America, Chile) (1) generation - thermal power
plants
ENGIE Romania Group Distribution of natural gas, 49.0 49.0 31 34 607 592 ‐ 15
(Rest of Europe, Romania) Energy sales
ENGIE Brasil Energia Group Electricity distribution and 31.3 31.3 116 45 296 294 112 38
(Latin America, Brazil) (1) generation
ENGIE Energía Perú (Latin Electricity distribution and 38.2 38.2 21 22 433 393 12 20
America, Peru) (1) generation - thermal and
hydroelectric power plants
Other subsidiaries with non-controlling interests (2) (27) (127) 1,401 1,372 190 201
TOTAL 173 97 5,032 4,986 482 410

(1) ENGIE Energia Chile, ENGIE Brasil Energia and ENGIE Energia Perú are listed in their respective countries.
(2) The net income/(loss) of other non-controlling interests is mainly impacted by the net loss of the operating MtMs for an amount of -
€58 million in 2022 and -€361 million in 2021.

50
2.3.1 Condensed financial information on main subsidiaries with non-controlling

interests
The condensed financial information concerning these subsidiaries presented in the table below is based on a 100%
interest and is shown before intragroup eliminations.
GRTgaz Group ENGIE Energía Chile Group ENGIE Romania Group

In millions of euros Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2021
Income statement
Revenues 2,535 2,209 1,648 1,187 2,819 1,473
Net income/(loss) 485 388 (395) 42 63 69
Net income/(loss) Group share 295 282 (237) 25 32 35
Other comprehensive income/(loss) – Owners of the
parent 54 130 85 107 (15) 9
TOTAL COMPREHENSIVE INCOME/(LOSS) –
OWNERS OF THE PARENT 349 412 (152) 132 17 45
Statement of financial position
Current assets 1,319 1,089 1,108 635 1,091 729
Non-current assets 9,961 10,098 3,210 3,150 975 903
Current liabilities (1,360) (1,272) (540) (345) (753) (357)
Non-current liabilities (5,803) (5,946) (2,091) (1,498) (86) (79)
TOTAL EQUITY 4,116 3,969 1,688 1,941 1,227 1,196
TOTAL NON-CONTROLLING INTERESTS 1,614 1,554 680 781 607 592
Statement of cash flows
Cash flow from operating activities 1,117 1,149 (320) 186 (365) 102
Cash flow from (used in) investing activities (450) (464) (384) (234) (121) (131)
Cash flow from (used in) financing activities (663) (650) 635 29 317 39
TOTAL CASH FLOW FOR THE PERIOD (1) 4 35 (68) (19) (169) 9
(1) Excluding effects of changes in exchange rates and other.
ENGIE Brasil Energia Group ENGIE Energía Perú

In millions of euros Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2021
Income statement
Revenues 2,164 2,118 525 445
Net income/(loss) 370 144 56 57
Net income/(loss) Group share 254 99 34 35
Other comprehensive income/(loss) – Owners of the parent 72 10 51 37
TOTAL COMPREHENSIVE INCOME/(LOSS) – OWNERS OF THE
PARENT 326 109 85 72
Current assets 1,322 1,390 384 360
Non-current assets 4,731 4,236 1,923 1,687
Current liabilities (1,019) (900) (257) (302)
Non-current liabilities (4,213) (3,912) (915) (716)
TOTAL EQUITY 822 813 1,135 1,029
TOTAL NON-CONTROLLING INTERESTS 296 294 433 393
Statement of cash flows
Cash flow from operating activities 1,027 941 62 185
Cash flow from (used in) investing activities (685) (629) (186) (92)
Cash flow from (used in) financing activities (1,010) (126) 17 (14)
TOTAL CASH FLOW FOR THE PERIOD (1) (668) 185 (107) 80
(1) Excluding effects of changes in exchange rates and other.

51
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
The Group accounts for its investments in associates (entities over which the Group has significant influence) and joint
ventures using the equity method. Under IFRS 11 – Joint Arrangements, a joint venture is a joint arrangement whereby
the parties that have joint control of the arrangement have rights to the net assets of the arrangement.
The respective contributions of associates and joint ventures in the statement of financial position, the income statement
and the statement of comprehensive income at December 31, 2022 and December 31, 2021 are as follows:

Investments in associates 4,187 4,007
Investments in joint ventures 5,092 4,492
INVESTMENTS IN EQUITY METHOD ENTITIES 9,279 8,498
Income statement
Share in net income/(loss) of associates 400 306
Share in net income/(loss) of joint ventures 659 495
SHARE IN NET INCOME/(LOSS) OF EQUITY METHOD ENTITIES 1,059 800
Statement of comprehensive income
Share of associates in "Other comprehensive income/(loss)" 510 208
Share of joint ventures in "Other comprehensive income/(loss)" 366 62
SHARE OF EQUITY METHOD ENTITIES IN "OTHER COMPREHENSIVE INCOME/(LOSS)" 876 270
Significant judgments
The Group primarily considers the following information and criteria in determining whether it has joint control or significant
influence over an entity:
• governance arrangements: whether the Group is represented in the governing bodies, majority rules and veto
rights;
• the nature of substantive or protective rights granted to shareholders, relating to the entity’s relevant activities.
This can be difficult to determine in the case of “project management” or “one-asset” entities, as certain decisions
concerning the relevant activities are made upon the creation of the joint arrangement and remain valid throughout
the project. Accordingly, the analysis of rights relates to the relevant residual activities of the entity (those that
significantly affect the variable returns of the entity);
• deadlock resolution mechanisms;
• whether the Group is exposed, or has rights, to variable returns from its involvement with the entity.
This can also involve analyzing the Group’s contractual relations with the entity, in particular the conditions in which
these contracts are entered into, their duration as well as the management of conflicts of interest that may arise
when the entity’s governing body casts votes.

52
The Group exercised its judgment regarding the following entities and sub-groups:
Project management entities in the Middle East and in Africa
The significant judgments made in determining the consolidation method to be applied to these project management
entities related to the risks and rewards relating to contracts between ENGIE and the entity concerned, as well as an
analysis of the residual relevant activities over which the entity retains control after its creation. The Group considers that
it exercises significant influence or joint control over these entities, since the decisions taken throughout the term of the
project about the relevant activities such as refinancing, or the renewal or amendment of significant contracts (sales,
purchases, operating and maintenance services) require, depending on the case, the unanimous consent of two or more
parties sharing control.
Joint ventures in which the Group holds an interest of more than 50%
Tihama (60%)
ENGIE holds a 60% stake in the Tihama cogeneration plant in Saudi Arabia and its partner Saudi Oger holds 40%.
The Group considers that it has joint control over Tihama since the decisions about its relevant activities, including for
example the preparation of the budget and amendments to major contracts, etc., require the unanimous consent of the
parties sharing control.
Transportadora Associada de Gás S.A. (“TAG” - Latin America): 65.0% holding interest (directly and indirectly)
representing a net interest in TAG of 54.8%
The Group exercises joint control over TAG since the decisions about its relevant activities, including, for example, the
preparation of the budget and medium-term plan, investments, operations and maintenance, etc., are taken according to
a majority vote requiring the agreement of ENGIE and Caisse de dépôt et placement du Québec (CDPQ). The Group holds
potential voting rights but they are not yet exercisable. Consequently, this investment is accounted for using the equity
method.
Joint control – difference between joint ventures and joint operations
Classifying a joint arrangement requires the Group to use its judgment to determine whether the entity in question is a joint
venture or a joint operation. IFRS 11 requires an analysis of “other facts and circumstances” when determining the
classification of jointly controlled entities.
The IFRS Interpretations Committee (IFRS IC) (November 2014) decided that for an entity to be classified as a joint
operation, other facts and circumstances must give rise to direct enforceable rights to the assets, and obligations for the
liabilities, of the joint arrangement.
In view of this position and its application to our analyses, the Group has no material joint operations at December 31, 2022.
3.1 Investments in associates
3.1.1 Contribution of material associates and of associates that do not have material
impact on the Group’s financial statements taken individually
The table hereafter shows the contribution of each material associate along with the aggregate contribution of associates
deemed not material taken individually, in the consolidated statement of financial position, income statement, statement of
comprehensive income, and the “Dividends received from equity method entities” line of the statement of cash flows.
The Group used qualitative and quantitative criteria to determine material associates. These criteria include the contribution
to the consolidated line items “Share in net income/(loss) of associates” and “Investments in associates”, the total assets
of associates in Group share, and associates carrying major projects in the study or construction phase for which the
related investment commitments are material.

53
Consolidation Other
percentage of Carrying amount Share in net comprehensive Dividends
investments in of investments in income/(loss) of income/(loss) of received from
Company name Activity Capacity associates associates associates associates associates
Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31,
In millions of euros 2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
Project
management
entities in the
Middle East
(Middle-East,
Asia & Africa,
Saudi Arabia, Gas-fired
Bahrain, Qatar, power plants
United Arab and seawater
Emirates, Oman, desalination
Kuwait) (1) facilities ‐ 1,378 940 181 139 411 102 145 107
Engineering
company in
containment
systems for
shipping and
Gaztransport & storage of
Technigaz (GTT) LNG 5,76 (2) 30.43 139 757 8 1 ‐ ‐ 20 35
Hydro power 1 688
Movhera plant MW 40.00 40.00 521 493 (13) 1 41 (23) ‐ ‐
Energia
Sustentável do Hydro power 3 750
Brasil (Brazil) plant MW 40.00 40.00 567 501 (3) 21 ‐ ‐ ‐ ‐
GASAG Gas and heat
(Germany) networks 31.57 31.57 279 333 26 29 (62) 75 17 11
Wind power
Eolia Renovables plant 40.00 359 33 ‐ 2 ‐ ‐
Other investments in associates that are not
material taken individually 943 982 168 114 118 54 89 81
INVESTMENTS IN ASSOCIATES 4,187 4,007 400 306 510 208 271 234
(1) Investments in associates operating gas-fired power plants and seawater desalination facilities in the Arabian Peninsula have been
grouped together under “Project management entities in the Middle East”. This mainly includes around 40 associates operating
thermal power plants with a total installed capacity of 26,974 MW (at 100%).
These associates have fairly similar business models and joint arrangements: the project management entities selected as a result
of a competitive bidding process develop, build and operate power generation plants and seawater desalination facilities. The entire
output of these facilities is sold to government-owned companies under power and water purchase agreements, over periods
generally spanning 20 to 30 years.
In accordance with their contractual arrangements, the corresponding plants are recognized in accordance with IFRIC 12, IFRS 16
or IAS 16 as property, plant and equipment or as financial receivables. The shareholding structure of these entities systematically
includes a government-owned company based in the same country as the project management entity. The Group’s percentage
interest and percentage voting rights in each of these entities varies between 20% and 50%.
(2) See Note 4.1.4 “Disposal of a portion of ENGIE’s interest in French company Gaztransport & Technigaz SA (“GTT”)”.
The share in net income/(loss) of associates includes a net non-recurring loss of €18 million in 2022 (compared to net non-
recurring income of €6 million in 2021), mainly including changes in the fair value of derivative instruments, impairment
losses and disposal gains and losses, net of tax (see Note 5.3 “Net recurring income Group share (NriGs)”).

54
3.1.2 Financial information regarding material associates
The tables below provide condensed financial information for the Group's main associates. The amounts shown have been
determined in accordance with IFRS, before the elimination of intragroup transactions and after (i) adjustments made in
line with Group accounting policies and (ii) fair value measurements of the assets and liabilities of the associate performed
at the acquisition date at the level of ENGIE, as required by IAS 28. All amounts are presented based on a 100% interest
with the exception of “Total equity attributable to ENGIE”.
Other Total Total

compre- compre- equity
Net hensive hensive Non- Non- attributa-
income/ income/ income/ Current current Current current Total Consolidation ble to
Revenues
In millions of euros (loss) (loss) (loss) assets assets liabilities liabilities equity % of Group ENGIE
AT DECEMBER 31, 2022
Project
management
entities in the
Middle East 5,067 764 1,695 2,459 2,824 19,711 3,343 13,781 5,411 ‐ 1,378
Gaztransport &
Technigaz (GTT) 307 139 2 141 412 2,225 224 2 2,411 5.76 139
Energia
Sustentável do
Brasil 581 (7) ‐ (7) 239 3,275 2,098 ‐ 1,416 40.00 567
Movhera 384 (33) 103 70 147 2,124 699 269 1,303 40.00 521
GASAG 1,606 82 (196) (114) 1,491 2,140 2,462 284 885 31.57 279
Eolia Renovables 216 82 4 86 297 2,097 340 1,155 900 40.00 359
Project
management
entities in the
Middle East 4,442 576 425 1,001 3,067 19,513 4,310 14,693 3,578 ‐ 940
Gaztransport &
Technigaz (GTT) 169 3 ‐ 2 330 2,299 144 (2) 2,488 30.43 757
Energia
Sustentável do
Brasil 496 54 ‐ 54 110 2,941 1,800 (3) 1,253 40.00 501
Movhera 276 2 (58) (57) 198 2,189 226 929 1,232 40.00 493
GASAG 1,368 93 237 331 1,199 2,078 1,927 297 1,054 31.57 333
3.1.3 Transactions between the Group and its associates
The data below set out the impact of transactions with associates on the Group's 2022 consolidated financial statements.
Net Loans and

Purchases financial receivables
of goods Sales of income Trade and at Trade and
and goods and (excluding other amortized other Borrowings
In millions of euros services services dividends) receivables cost payables and debt
Project management entities in the Middle East ‐ 177 16 59 175 ‐ ‐
Contassur (1) ‐ ‐ ‐ 208 2 ‐ ‐
Energia Sustentável do Brasil 136 ‐ ‐ ‐ ‐ 13 ‐
Movhera ‐ 25 6 7 120 5 22
Other 11 34 18 34 218 ‐ 18
AT DECEMBER 31, 2022 146 235 41 307 516 18 40
(1) Contassur is a life insurance company accounted for using the equity method. Contassur offers insurance contracts, chiefly with
pension funds that cover post-employment benefit obligations for Group employees and also employees of other companies mainly
engaged in regulated activities in the electricity and gas sector in Belgium. Insurance contracts entered into by Contassur represent
reimbursement rights recorded within “Other assets” in the statement of financial position. These reimbursement rights totaled
€208 million at December 31, 2022 (€229 million at December 31, 2021).

55
3.2 Investments in joint ventures
3.2.1 Contribution of joint ventures to the Group
The table below shows the contribution of each material joint venture along with the aggregate contribution of joint ventures
deemed not material taken individually to the consolidated statement of financial position, income statement, statement of
comprehensive income, and the “Dividends received from equity method entities” line of the statement of cash flows.
The Group used qualitative and quantitative criteria to determine material joint ventures. These criteria include the
contribution to the line items “Share in net income/(loss) of joint ventures” and “Investments in joint ventures”, the Group’s
share in the total assets of joint ventures, and joint ventures conducting major projects in the study or construction phase
for which the related investment commitments are material.
Consolidation Other
percentage of Carrying amount Share in net comprehensive Dividends
investments in of investments in income/(loss) of income/(loss) of received from
Company name Activity Capacity joint ventures joint ventures joint ventures joint ventures joint ventures
Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31,
In millions of euros 2022 2021 2022 2021 2022 2021 2022 2021 2022 2021
Transportadora
Associada de Gas
Gás S.A. (TAG) transmission
(Brazil) (1) network 65.00 65.00 1,129 792 267 189 153 7 184 222
National Central
Cooling Company
"Tabreed"
(Middle-East, District
Asia & Africa, cooling
Abu Dhabi) networks 40.00 40.00 874 787 53 45 ‐ ‐ 18 14
Combined-
cycle gas-
fired power
plant and
EcoÉlectrica LNG
(Puerto Rico) terminal 534 MW 50.00 50.00 314 310 42 46 ‐ ‐ 60 63
Electricity
Movhera generation 2,392 MW 50.00 50.00 240 253 33 3 15 8 61 35
Electricity
WSW Energie distribution
und Wasser AG and
(Germany) generation 33.10 33.10 249 240 19 41 1 ‐ 11 7
Iowa University
partnership Energy
(United States) services 39.10 39.10 229 208 6 3 2 1 1 2
Electricity
Ocean Winds generation 50.00 50.00 431 169 80 13 124 5 ‐ ‐
Georgetown
University
partnership Energy
(United States) services 50.00 50.00 203 184 6 2 3 ‐ ‐ ‐
Tihama Power
Generation Co Electricity
(Saudi Arabia) generation 1,544 MW 60.00 60.00 94 91 21 13 5 4 29 27
Ohio State
Energy Partners Energy
(United States) services 50.00 50.00 82 78 4 3 8 6 16 9
Gas
Megal GmbH transmission
(Germany) network 49.00 49.00 61 67 2 5 ‐ ‐ 9 9
Transmisora Electricity
Eléctrica del transmission
Norte (Chile) (2) line 50.00 50.00 116 96 5 (1) 19 25 ‐ ‐
Other investments in joint ventures that are
not material taken individually 1,071 1,216 120 132 37 7 53 40
INVESTMENTS IN JOINT VENTURES 5,092 4,492 659 495 366 62 442 428
(1) The Group’s interest in Transportadora Associada de Gás S.A. (TAG) is 54.83%.
(2) The Group’s interest inTransmisora Eléctrica del Norte is 30%.

56
The share in net income/(loss) of joint ventures includes non-recurring gain of €1 million in 2022 (non-recurring gain of
€44 million in 2021), resulting chiefly from changes in the fair value of derivatives, impairment losses and disposal gains
and losses, net of tax (see Note 5.3 “Net recurring income Group share (NriGs)”).
3.2.2 Financial information regarding material joint ventures
The amounts shown have been determined in accordance with IFRS before the elimination of intragroup items and after
(i) adjustments made in line with Group accounting policies and (ii) fair value measurements of the assets and liabilities of
the joint venture performed at the date of acquisition at the level of ENGIE, as required by IAS 28. All amounts are
presented based on a 100% interest with the exception of “Total equity attributable to ENGIE” in the statement of financial
position.
3.2.2.1 Information on the income statement and statement of comprehensive income
Depreciation
and
amortization
of intangible
assets and
property, Other Total
plant and Net financial Income tax Net comprehensive comprehensive
In millions of euros Revenues equipment income/(loss) benefit/(expense) income/(loss) income/(loss) income/(loss)
Transportadora Associada de Gás
S.A. (TAG) 1,549 (292) (386) (215) 411 235 647
National Central Cooling
Company "Tabreed" 167 ‐ (35) ‐ 133 ‐ 133
EcoÉlectrica 166 (32) 1 (4) 85 ‐ 85
Portfolio of power generation
assets in Portugal 512 (50) (14) (27) 74 48 122
WSW Energie und Wasser AG 1,213 (14) ‐ (28) 50 3 53
Iowa University partnership 87 ‐ (21) ‐ 16 6 22
Ocean Winds 40 (9) (23) (1) 160 247 407
Georgetown University
partnership 60 (1) (22) ‐ 12 5 17
Tihama Power Generation Co 119 (6) (9) (6) 35 9 45
Ohio State Energy Partners 180 (1) (65) (2) 7 15 22
Megal GmbH 122 (67) (4) 1 5 ‐ 5
Transmisora Eléctrica del Norte 70 ‐ (27) (7) 13 19 32
Transportadora Associada de Gás
S.A. (TAG) 1,109 (248) (254) (150) 290 11 301
Company "Tabreed" 170 (40) (35) ‐ 113 ‐ 113
EcoÉlectrica 174 (38) ‐ (5) 104 ‐ 104
Portfolio of power generation
assets in Portugal 369 (54) (27) (19) 3 26 29
WSW Energie und Wasser AG 781 (14) (1) (62) 126 ‐ 126
Iowa University partnership 65 ‐ (19) ‐ 9 3 12
Ocean Winds ‐ (12) (13) (1) 25 10 35
partnership 19 ‐ (9) ‐ 5 ‐ 5
Tihama Power Generation Co 107 (5) (11) (6) 22 6 28
Ohio State Energy Partners 193 (1) (48) ‐ 6 12 18
Megal GmbH 122 (64) (3) 1 10 ‐ 10
Transmisora Eléctrica del Norte 41 ‐ (22) ‐ (1) 49 48

57
3.2.2.2 Information on the statement of financial position
Other Total
Cash and Other Non- Other non- equity
cash current current Short-term current Long-term current Total Consolidation attributable
In millions of euros equivalents assets assets borrowings liabilities borrowings liabilities equity % of Group to ENGIE
AT DECEMBER 31,
2022
Transportadora
Associada de Gás
S.A. (TAG)
124 367 6,216 668 71 2,771 1,460 1,737 65.00 1,129
Company "Tabreed" 402 150 2,631 ‐ 194 805 ‐ 2,184 40.00 874
EcoÉlectrica 6 79 580 3 15 ‐ 18 629 50.00 314
Portfolio of power
generation assets in
Portugal 247 514 733 99 278 500 60 557 50.00 240
WSW Energie und
Wasser AG 82 518 950 263 260 147 150 731 33.10 249
Iowa University
partnership 2 17 1,162 7 7 581 ‐ 586 39.10 229
Ocean Winds 337 ‐ 2,425 1,149 189 137 424 863 50.00 431
partnership 5 3 954 ‐ ‐ 555 3 404 50.00 203
Tihama Power
Generation Co 49 145 221 78 51 119 11 156 60.00 94
Ohio State Energy 14 65 1,441 ‐ 10 1,331 17 162 50.00 82
Partners
Megal GmbH 18 14 696 ‐ 44 511 49 125 49.00 61
Transmisora Eléctrica
del Norte 41 34 770 35 3 574 ‐ 233 50.00 116
AT DECEMBER 31,
2021
Transportadora
Associada de Gás S.A.
(TAG)
70 251 5,721 540 75 3,174 1,036 1,218 65.00 792
Company "Tabreed" 294 141 2,469 ‐ 182 755 ‐ 1,967 40.00 787
EcoÉlectrica 14 77 572 3 22 ‐ 18 620 50.00 310
Portfolio of power
generation assets in
Portugal 294 495 793 159 208 558 72 583 50.00 253
WSW Energie und
Wasser AG 17 268 852 156 36 93 142 711 33.10 240
Iowa University
partnership ‐ 7 1,070 9 4 527 3 534 39.10 209
Ocean Winds 79 ‐ 1,079 83 175 362 200 338 50.00 169
partnership 9 ‐ 868 ‐ ‐ 509 1 367 50.00 184
Tihama Power
Generation Co 53 135 286 73 49 191 10 151 60.00 91
Ohio State Energy 31 70 1,274 ‐ 63 1,126 30 156 50.00 78
Partners
Megal GmbH 9 13 729 ‐ 50 511 52 138 49.00 67
Transmisora Eléctrica
del Norte 45 9 730 30 3 559 ‐ 193 50.00 96

58
3.2.3 Transactions between the Group and its joint ventures
The data below set out the impact of transactions with joint ventures on the Group’s 2022 consolidated financial statements.
Net Loans and

Purchases financial receivables
of goods Sales of income Trade and at Trade and
and goods and (excluding other amortized other Borrowings
In millions of euros services services dividends) receivables cost payables and debt
EcoÉlectrica ‐ ‐ ‐ ‐ ‐ ‐ 62
WSW Energie und Wasser AG 2 47 ‐ 6 ‐ 4 ‐
Megal GmbH 65 ‐ ‐ ‐ ‐ 6 ‐
Futures Energies Investissements Holding 14 21 4 8 210 2 ‐
Ocean Winds ‐ ‐ 41 2 569 ‐ ‐
Other 115 123 7 49 164 10 44
AT DECEMBER 31, 2022 196 191 53 64 942 22 105
3.3 Other information on investments accounted for using the equity

method
3.3.1 Unrecognized share of losses of associates and joint ventures
Cumulative unrecognized losses of associates (corresponding to the cumulative amount of losses exceeding the carrying
amount of investments in the associates concerned) including other comprehensive income/(loss), amounted to €6 million
in 2022 (versus €49 million in 2021).
These unrecognized losses correspond to the negative fair value of derivative instruments designated as interest rate and
commodity hedges (“Other comprehensive income/(loss)”) contracted by associates in the Middle-East, Africa and Asia in
connection with the financing of construction projects for power generation plants.
3.3.2 Commitments and guarantees given by the Group in respect of equity method
entities
At December 31, 2022, the main commitments and guarantees given by the Group in respect of equity method entities
concern:
• Energia Sustentável do Brasil (“Jirau”), for an aggregate amount of BRL 4,204 million (€755 million).
At December 31, 2022, the amount of loans granted by Banco Nacional de Desenvolvimento Econômico e Social,
the Brazilian Development Bank, to Energia Sustentável do Brasil amounted to BRL 10,511 million
(€1,889 million). Each partner stands as guarantor for this debt to the extent of its ownership interest in the
consortium;
• TAG for bank guarantees for an amount of €140 million;
• The project management entities in the Middle East and Africa, for an aggregate amount of €694 million.
Commitments and guarantees given by the Group in respect of these project management entities chiefly
correspond to:
− letters of credit to guarantee debt service reserve accounts for an aggregate amount of €179 million.
The project financing set up in certain entities can require those entities to maintain a certain level of cash
within the company (usually enough to service its debt for six months). This is particularly the case when the
financing is without recourse. However, this level of cash may be replaced by letters of credit,
− collateral given to lenders in the form of pledged shares in the project management entities, for an aggregate
amount of €280 million,
− performance bonds and other guarantees for an amount of €235 million.

59
NOTE 4 MAIN CHANGES IN GROUP STRUCTURE
In accordance with IFRS 5 – Non-Current Assets Held for Sale and Discontinued Operations, assets or groups of assets
held for sale are presented separately on the face of the statement of financial position and are measured and accounted
for at the lower of their carrying amount and fair value less costs to sell.
An asset is classified as “held for sale” when its sale is highly probable within twelve months from the date of classification,
when it is available for immediate sale under its present condition and when management is committed to a plan to sell
the asset and an active program to locate a buyer and complete the plan has been initiated. To assess whether a sale is
highly probable, the Group takes into consideration among other things indications of interest and offers received from
potential buyers as well as specific execution risks attached to certain transactions.
If an asset classified as “held for sale” no longer meets the above conditions it will be reclassified in accordance with the
standard.
Furthermore, assets or groups of assets are presented as discontinued operations in the Group’s consolidated financial
statements when they are classified as “held for sale” and represent a separate major line of business under IFRS 5.
4.1 Disposals carried out in 2022
4.1.1 Impact of the main disposals and sale agreements during the period
As part of the presentation of its new strategy, on May 18, 2021, the Group confirmed a significant €11 billion increase in
its asset portfolio rotation program, the majority of which was carried out end of 2022.
The table below shows the impact of the main disposals and sale agreements of 2022 on the Group’s net financial debt,
excluding partial disposals with respect to DBSO (1) activities:
Reduction in net
In millions of euros Disposal price debt
Disposal of EQUANS (1) 6,146 6,975
Earn out related to the disposal of a share of ENGIE's interest in SUEZ - France 347 347
Disposal of ENGIE's residual interest in SUEZ - France 227 227
Disposal of a share of ENGIE's interest in GTT - France 835 835
Disposals of ENGIE's interests in geothermal assets - Indonesia 263 342
Other disposals that are not material taken individually 177 (29)
Effects of classification as "assets held for sale" ‐ 297
TOTAL 7,995 8,994
(1) Does not include the reduction in external net financial debt recognized as held for sale in accordance with IFRS 5 at December 31,
2021.
The €8,994 million reduction in net financial debt at December 31, 2022 is in addition to the €2,025 million decrease
previously recognized at December 31, 2021 as part of the asset disposal program, representing a total of €11,018 million
to date. Disposals in the process of completion at December 31, 2022 are described in Note 4.2 “Assets held for sale”.
4.1.2 Disposal of EQUANS
On October 4, 2022, the Group completed the sale of its interest in EQUANS to Bouygues.
(1) Develop, Build, Share and Operate, a model used in renewable energies based on continuous rotation of capital employed.

60
The combined effects of the transaction and of the cash generated by these activities since January 1, 2022 have reduced
the Group’s net debt by €6,975 million (€7,134 million with the reduction of external net financial debt recognized under
IFRS 5 – Non-current assets held for sale and discontinued operations, as of December 31, 2021).
The disposal gain recognized in “Net income/(loss) relating to discontinued operations” (see Note 4.2.1), amounted to
€2,086 million in 2022.
4.1.3 Earn-out from the disposal of a portion of ENGIE’s interest in French company
SUEZ SA in 2021 and the disposal of its remaining stake in 2022
On October 6, 2020, the Group sold 29.9% of its stake in SUEZ SA to the VEOLIA Group. This sale was subject to an
earn-out mechanism if the VEOLIA Group carried out other capital transactions on SUEZ at a price higher than that of the
29.9% block sold by ENGIE.
In 2021, the VEOLIA Group launched a takeover bid for SUEZ at a price of €20.50 per share (cum dividend) which closed
successfully on January 7, 2022. At the end of 2021, the ENGIE Group considered that all the conditions had been met to
recognize the €347 million in profit or loss related to the earn-out mechanism negotiated with the VEOLIA Group.
ENGIE cashed in this earn-out on January 19, 2022, once the takeover bid had been closed
On January 18, 2022, the Group also contributed its remaining 1.8% stake in SUEZ as part of the public offer initiated by
the VEOLIA Group. This transaction had no impact on the Group’s 2022 results, as the interest was measured at fair value
at December 31, 2021. The effects of the transaction have reduced the Group’s net financial debt by €227 million.
4.1.4 Disposal of a portion of ENGIE’s interest in French company Gaztransport &

Technigaz SA (“GTT”)
On March 24, 2022, ENGIE announced the sale of a stake in GTT representing approximately 9% of the share capital at
a price of €90 per share.
On September 16, 2022, ENGIE sold an additional stake in GTT representing approximately 6% of the share capital at a
price of €115.50 per share.
At December 31, 2022, 96% of the bond redeemable for GTT shares had been converted. The balance was either
converted or redeemed at par in January 2023.
At December 31, 2022, these transactions did not change ENGIE’s representation on GTT’s Board of Directors.
Consequently, following these disposals and conversions, ENGIE has maintained its significant influence and therefore
continues to account for its residual 5.76% interest in GTT using the equity method.
These transactions, which are part of the targeted plan to withdraw from non-strategic businesses and non-controlling
interests, have reduced the Group’s net financial debt by €835 million. The disposal gain before tax, including the effects
of the embedded derivative on the bond redeemable for GTT shares, amounted to €280 million in 2022.
4.1.5 Disposal of ENGIE’s interests in geothermal assets in Indonesia
On September 16, 2022, ENGIE finalized the sale of its entire stake in PT Supreme Energy Muara Laboh to Sumitomo
Corporation and INPEX Geothermal Ltd.
On October 14 and October 24, 2022, ENGIE finalized the sale of its entire stake in PT Supreme Energy Rantau Dedap
to Merit Power Holding bv and INPEX Geothermal Ltd.
These transactions have reduced the Group’s net financial debt by €342 million. The disposal gain before tax amounted
to €111 million in 2022.

61
4.2 Assets held for sale
Total “Assets classified as held for sale” and total “Liabilities directly associated with assets classified as held for sale”
amounted to €428 million and €371 million, respectively, at December 31, 2022.
En millions d’euros 31 déc. 2022 31 déc. 2021

Immobilisations corporelles et incorporelles nettes 336 4,235
Autres actifs 92 7,645
TOTAL ACTIFS CLASSÉS COMME DÉTENUS EN VUE DE LA VENTE 428 11,881
dont Actifs des activités non poursuivies 11,186
Dettes financières 290 368
Autres passifs 80 7,047
TOTAL PASSIFS DIRECTEMENT LIÉS À DES ACTIFS CLASSÉS COMME DÉTENUS EN VUE DE LA
VENTE 371 7,415
dont Passifs directement liés à des actifs des activités non poursuivies 6,952
The assets related to the EQUANS entities, as well as Endel and its main subsidiaries recorded as “Assets held for sale”
at December 31, 2021 were sold in 2022. Due to unfavorable developments in the planned sale of certain renewable
assets in Mexico, they were no longer classified as “Assets held for sale” at December 31, 2022.
At December 31, 2022, “Assets held for sale” relate solely to a thermal power plant in Brazil. Given the expected sale price,
a non-material value adjustment was recognized for the year. This transaction is expected to be completed in first half
2023.
4.2.1 Financial information on discontinued operations
Net income/(loss) from discontinued operations

REVENUES 9,937 12,860
Purchases and operating derivatives (6,164) (7,942)
Personnel costs (3,497) (4,420)
Depreciation, amortization and provisions 38 (239)
Taxes (48) (59)
Other operating income 150 166
Current operating income including operating MtM 416 366
Share in net income of equity method entities 4 ‐
Current operating income including operating MtM and share in net income of equity method entities 420 367
Impairment losses (3) 2
Changes in scope of consolidation 2,030 (53)
Other non-recurring items ‐ (30)
RESULT FROM OPERATING ACTIVITIES 2,420 185
Financial expenses (47) (73)
Financial income 17 24
NET FINANCIAL INCOME/(LOSS) (30) (49)
Income tax benefit/(expense) (206) (55)
NET INCOME/(LOSS) RELATING TO DISCONTINUED OPERATIONS 2,183 80
Of which Net income/(loss) relating to discontinued operations, Group share 2,181 79
Of which Non-controlling interests relating to discontinued operations 1 1
FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION

EBITDA 424 622
EBIT (1) 420 368
Net recurring income/(loss) Group Share (1) 287 231
(1) Includes the impact at December 31, 2022 of no longer depreciating the assets as of their date of classification as “Assets held for
sale”, of a positive €229 million on EBIT (compared with €51 million in 2021) and a positive €170 million on “Recurring net income,
Group share” (compared to €37 million in 2021).

62
Income from discontinued operations relates to ENGIE’s activities relating to the EQUANS entities, including their disposal
gain (see Note 4.1.2).
Cash flows from discontinued operations

NET INCOME/(LOSS) 2,183 80
Cash generated from operations before income tax and working capital requirements 356 462
+ Tax paid (17) (71)
Change in working capital requirements (241) 96
CASH FLOW FROM OPERATING ACTIVITIES 98 486
Acquisitions of property, plant and equipment and intangible assets (135) (208)
Acquisitions of controlling interests in entities, net of cash and cash equivalents acquired (2) (14)
Loss of controlling interests in entities, net of cash and cash equivalents sold 595 ‐
Disposals of property, plant and equipment and intangible assets 3 6
Interest received on financial assets (6) (12)
Change in loans and receivables originated by the Group and other (1) (3,580) (2,782)
Other 1 7
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES (3,123) (3,003)
Repayment of borrowings and debt (124) (155)
Interest received on cash and cash equivalents ‐ (1)
Increase in borrowings 26 8
Others (2) ‐
Cash flow from (used in) financing activities excluding intercompany transactions (120) (181)
Transactions with ENGIE (2) 3,138 2,700
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES 3,018 2,519
Effects of changes in exchange rates and other (3) (422) (1)
TOTAL CASH FLOW FOR THE PERIOD (429) 1
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 429 428
CASH AND CASH EQUIVALENTS AT END OF PERIOD ‐ 429
(1) The line “Change in loans and receivables originated by the Group and other” includes the acquisition by EQUANS of shares in the
“Asset-Light Client Solutions business” held by ENGIE for a negative €3,555 million and disposals, by EQUANS, of shares not
constituting the “Asset-Light Client Solutions business” to ENGIE for a positive €7 million.
(2) The line “Transactions with ENGIE” includes the capital increases of EQUANS, for an amount of €2,774 million subscribed by ENGIE.
(3) The line “Effects of changes in exchange rates and other” corresponds to EQUANS’ cash and cash equivalents at December 31, 2021
for €429 million.
4.3 Acquisitions carried out in 2022
In total, acquisitions carried out in 2022 had an impact of €1,951 million on net financial debt.
On May 4, 2022, ENGIE and Crédit Agricole Assurances completed the acquisition of a 97.33% stake in Eolia Renovables,
a renewable energy producer in Spain, from Canadian institutional investment manager Alberta Investment Management
Corporation. The transaction covers the ownership and operation of 899 MW of operating assets (821 MW of onshore wind
and 78 MW photovoltaic) and a 1.2 GW pipeline of renewable energy projects.
The operating assets are 40% owned by ENGIE and 60% by Crédit Agricole Assurances while ENGIE is developing and
building the pipeline of projects. The Group will provide a complete range of services (O&M, Asset Management, Energy
Management and Development services) for the full asset scope.
The acquired assets benefit from a regulated scheme ensuring predictability of returns for the next ten years. This
transaction has an impact of €0.5 billion on the Group’s net financial debt. The interest in the company holding the operating
assets is accounted for using the equity method. The company responsible for developing and building the pipeline of
projects is fully consolidated by ENGIE. The Group will finalize the purchase price allocation during the first half of 2023.
Other acquisitions during the year relate mainly to the financing of the development of the Group’s offshore wind energy
activities (Ocean Winds joint venture) for €0.4 billion, concession contracts in Brazil for €0.2 billion, the effect of acquiring
a controlling interest in renewable activities in France and India for €0.2 billion each and the acquisition of renewable
energy assets in Chile for €0.1 billion.

63
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL

COMMUNICATION
The purpose of this note is to present the main non-GAAP financial indicators used by the Group as well as their
reconciliation with the indicators of the IFRS consolidated financial statements.
5.1 EBITDA
The reconciliation between EBITDA and current operating income including operating MtM and share in net income of
equity method entities is as follows:

Current operating income including operating MtM and share in net income of equity method entities 5,367 6,916
Mark-to-market on commodity contracts other than trading instruments 3,661 (721)
Net depreciation and amortization/Other 4,576 4,370
Share-based payments (IFRS 2) 92 48
Non-recurring share in net income of equity method entities 17 (50)
EBITDA 13,713 10,563
5.2 EBIT
The reconciliation between EBIT and current operating income including operating MtM and share in net income of equity
method entities is as follows:

Current operating income including operating MtM and share in net income of equity method entities 5,367 6,916
Mark-to-market on commodity contracts other than trading instruments 3,661 (721)
Non-recurring share in net income of equity method entities 17 (50)
EBIT 9,045 6,145

64
5.3 Net recurring income Group share (NriGs)
Net recurring income Group share is a financial indicator used by the Group in its financial reporting to present net income
Group share adjusted for unusual, inhabitual or non-recurring items.
The reconciliation of net income/(loss) with net recurring income Group share is as follows:

NET INCOME/(LOSS) GROUP SHARE 216 3,661
NET INCOME/(LOSS) RELATING TO DISCONTINUED OPERATIONS, GROUP SHARE 2,182 79
NET INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS, GROUP SHARE (1,965) 3,582
Net income attributable to non-controlling interests relating to continuing operations 172 96
Reconciliation items between “Current operating income including operating MtM and
share in net income of equity method entities” and "Net income/(loss) from operating
activities" 4,241 194
Impairment losses 9.1 2,774 1,028
Restructuring costs 9.2 230 204
Changes in scope of consolidation 9.3 (91) (1,107)
Other non-recurring items 1,328 69
Other adjusted items 3,389 (363)
Mark-to-market on commodity contracts other than trading instruments 8 3,661 (721)
Ineffective portion of derivatives qualified as fair value hedges 10 (7) 2
Gains/(losses) on debt restructuring and early unwinding of derivative financial instruments 10 (46) ‐
Change in fair value of derivatives not qualified as hedges and ineffective portion of derivatives
qualified as cash flow hedges 10 (16) 153
Non-recurring income/(loss) from debt instruments and equity instruments 10 1,254 (298)
Other adjusted tax impacts (1,474) 552
Non-recurring income/(loss) included in share in net income of equity method entities 17 (50)
NET RECURRING INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS 5,836 3,509
Net recurring income/(loss) attributable to non-controlling interests 614 581
NET RECURRING INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS, GROUP 5,223 2,927
SHARE
Net recurring income/(loss) relating to discontinued operations, Group share 287 231
NET RECURRING INCOME/(LOSS) GROUP SHARE 5,510 3,158

65
5.4 Industrial capital employed
The reconciliation of industrial capital employed with items in the statement of financial position is as follows:

(+) Property, plant and equipment and intangible assets, net 62,853 57,863
(+) Goodwill 12,854 12,799
(-) Goodwill Gaz de France – SUEZ and International Power (1) (7,241) (7,213)
(+) IFRIC 4, IFRS 16 and IFRIC 12 receivables 2,521 2,456
(+) Investments in equity method entities 9,279 8,498
(-) Goodwill arising on the International Power combination (1) (40) (38)
(+) Trade and other receivables, net 31,310 32,556
(-) Margin calls (1) (2) (5,405) (13,856)
(+) Inventories 8,145 6,175
(+) Assets from contracts with customers 12,584 8,377
(+) Other current and non-current assets 19,060 13,681
(+) Deferred tax (4,379) (6,557)
(+) Cancellation of deferred tax on other recyclable items (1) (2) (14) 841
(-) Provisions (27,027) (25,459)
(+) Actuarial gains and losses in shareholders’ equity (net of deferred tax) (1) 1,058 3,162
(-) Trade and other payables (39,801) (32,822)
(+) Margin calls (1) (2) 6,351 7,835
(-) Liabilities from contracts with customers (3,412) (2,739)
(-) Other current and non-current liabilities (27,279) (19,175)
INDUSTRIAL CAPITAL EMPLOYED 51,416 46,382
(1) For the purpose of calculating industrial capital employed, the amounts recorded in respect of these items have been adjusted from
those appearing in the statement of financial position.
(2) Margin calls included in “Trade and other receivables, net” and “Trade and other payables” correspond to advances received or
paid as part of collateralization agreements set up by the Group to manage counterparty risk on commodity transactions.
From January 1, 2023, the Group will expand its definition of industrial capital employed to include financial assets covering
nuclear provisions, as well as the initial margins required by certain market activities. The following table shows the impact
of these changes on industrial capital employed:

INDUSTRIAL CAPITAL EMPLOYED 51,416 46,382
(+) Financial assets covering nuclear provisions 6,626 5,505
(+) Initials Margins 1,740 4,722
INDUSTRIAL CAPITAL EMPLOYED (new definition for 2023) 59,782 56,609
5.5 Cash flow from operations (CFFO)
The reconciliation of cash flow from operations (CFFO) with items in the statement of cash flows is as follows:
In millions of euros Dec. 31, 2022 Dec. 31, 2021 (1)

Cash generated from operations before income tax and working capital requirements 12,415 9,806
Tax paid (1,504) (603)
Change in working capital requirements (2,424) (2,377)
Interest received on financial assets (37) 32
Dividends received on equity investments 18 57
Interest received on cash and cash equivalents 194 52
Nuclear – expenditure on power plant dismantling and reprocessing, fuel storage 163 202
Change in financial assets held for investment or financing purposes 188 464
(+)Change in financial assets held for investment or financing purposes recorded in the statement of
financial position and other and other (176) (448)
CASH FLOW FROM OPERATIONS (CFFO) 8,016 6,466
(1) In view of the start of work related to the nuclear exit in Belgium, the definition of cash flow from operations (CFFO) has been
adjusted to exclude expenditure on the dismantling of nuclear power plants and the management of radioactive materials and waste.
These expenses are now presented together with investments to cover nuclear provisions, under a dedicated heading. The data at
December 31, 2021 have been restated accordingly.

66
5.6 Capital expenditure (CAPEX) and growth CAPEX
The reconciliation of capital expenditure (CAPEX) with items in the statement of cash flows is as follows:
In millions of euros Dec. 31, 2022 Dec. 31, 2021 (1) (2)
Acquisitions of property, plant and equipment and intangible assets 6,379 5,990
Acquisitions of controlling interests in entities, net of cash and cash equivalents acquired 289 392
(+) Cash and cash equivalents acquired 14 6
Acquisitions of investments in equity method entities and joint operations 407 369
Acquisitions of equity and debt instruments (175) 1,548
Change in loans and receivables originated by the Group and other 2,877 (121)
(+) Other (10) 3
Change in ownership interests in controlled entities ‐ 35
(-) Disposal impacts relating to DBSO (3) activities (472) (270)
(-) Synatom Financial investments / Disposal of Synatom financial assets (1) (1,822) (1,261)
(+) Change in scope - Acquisitions (2) 371 ‐
TOTAL CAPITAL EXPENDITURE (CAPEX) 7,858 6,693
(-) Maintenance CAPEX (2,373) (2,418)
TOTAL GROWTH CAPEX 5,485 4,275
(1) In view of the start of work related to the nuclear exit in Belgium, the definition of capital expenditure (CAPEX) has been adjusted
to exclude hedging of nuclear provisions carried out by Synatom. These expenses are now presented together with investments to
cover expenditure for the dismantling of nuclear power plants and the management of radioactive materials nd waste, under a
dedicated heading. The data at December 31, 2021 have been restated accordingly.
(2) Capital expenditure (CAPEX) now includes changes in the scope of net financial debt of acquired entities. The impact at December
31, 2021 is not material.
(3) Develop, Build, Share & Operate; including Tax equity financing received (See Note 22 “Working capital requirements, inventories,
other assets and other liabilities”).
5.7 Net financial debt
The reconciliation of net financial debt with items in the statement of financial position is as follows:

(+) Long-term borrowings 14.2 & 14.3 28,083 30,458
(+) Short-term borrowings 14.2 & 14.3 12,508 10,590
(+) Financial instruments – carried in liabilities 14.4 51,276 46,931
(-) Derivative instruments hedging commodities and other items (50,542) (46,617)
(-) Other financial assets 14.1 (12,992) (13,444)
(+) Loans and receivables at amortized cost not included in net financial debt 6,720 5,143
(+) Equity instruments at fair value 1,495 2,827
(+) Debt instruments at fair value not included in net financial debt 3,394 3,853
(-) Cash and cash equivalents 14.1 (15,570) (13,890)
(-) Financial instruments – carried in assets 14.4 (48,386) (44,989)
(+) Derivative instruments hedging commodities and other items 48,067 44,489
NET FINANCIAL DEBT 24,054 25,350

67
5.8 Economic net debt
Economic net debt is as follows:

NET FINANCIAL DEBT 14.3 24,054 25,350
Provisions for back-end of the nuclear fuel cycle 17 9,088 8,030
Provisions for dismantling of plant and equipment 17 11,015 8,015
Provisions for site rehabilitation 17 244 246
Post-employment benefits – Pensions 18 452 1,779
(-) Infrastructures regulated companies 272 (16)
Post-employment benefits – Reimbursement rights 18 (208) (228)
Post-employment benefits – Other benefits 18 3,704 5,149
(-) Infrastructures regulated companies (2,392) (3,289)
Deferred tax assets for pensions and related obligations 11 (812) (1,501)
(-) Infrastructures regulated companies 490 780
Plan assets relating to nuclear provisions, inventories of uranium, related derivative financial instruments and
17 & 22
a receivable of Electrabel towards EDF Belgium (7,098) (6,014)
ECONOMIC NET DEBT 38,808 38,300

68
NOTE 6 SEGMENT INFORMATION
6.1 Operating segment and reportable segment
ENGIE is organized around:
• four Global Business Units (GBUs) representing the Group’s four strategic activities: Renewables GBU, Energy
Solutions GBU, Networks GBU and Thermal & Supply GBU;
• two operating entities: Nuclear and Global Energy Management & Sales (“GEMS”);
• an Other group mainly comprising the Corporate functions and certain Holdings.
From 2022 onwards and given the significant volatility of the commodity markets, the Group Executive Committee, which
represents the chief operating decision maker as defined by IFRS 8 – Operating Segments, monitors the activities of
GEMS, which has become an operating segment.
The reportable segments are identical to the operating segments and correspond to the activities underlying the
organization of the GBUs.
• Renewables: comprises all centralized renewable energy generation activities, including financing, construction,
operation and maintenance of renewable energy facilities, using various energy sources such as hydroelectric,
onshore wind, photovoltaic solar, biomass, offshore wind, and geothermal. The energy produced is fed into the
grid and sold either on the open or regulated market or to third parties through electricity sale agreements.
• Networks: comprises the Group’s electricity and gas infrastructure activities and projects. These activities include
the management and development of (i) gas and electricity transportation networks and natural gas distribution
networks in and outside of Europe, (ii) natural gas underground storage in Europe, and (iii) regasification
infrastructure in France and Chile. Apart from the historical infrastructure management activities, its asset portfolio
also contributes to the challenges of energy decarbonization and network greening (gradual integration of green
gas, hydrogen-based projects, etc.).
• Energy Solutions: encompasses the construction and management of decentralized energy networks to produce
low-carbon energy (heating and cooling networks, distributed power generation plants, distributed solar power
parks, low-carbon mobility, low-carbon cities and public lighting, etc.) and related services (energy efficiency,
technical maintenance, sustainable development consulting).
• Thermal: encompasses all the Group’s centralized power generation activities using thermal assets, whether
contracted or not. It includes the operation of power plants fueled mainly by gas or coal, as well as pump-operated
storage plants. The energy produced is fed into the grid and sold either on the open or regulated market or to third
parties through electricity sale agreements. It also includes the financing, construction and operation of
desalination plants, whether or not connected to power plants as well as the development of hydrogen production
capacities.
• Supply: encompasses all the Group’s activities relating to the sale of gas and electricity to end customers, whether
professional or individual. It also includes all the Group’s activities in services for residential clients.
• Nuclear: encompasses all of the Group’s nuclear power generation activities, with seven reactors in Belgium (four
in Doel and three in Tihange) and drawing rights in France.
• Others: encompasses the activities of GEMS and GTT, as well as Corporate and holdings. The GEMS operating
entity is responsible, at the global level, for the supply of energy and the management of risk and optimization of
assets on the markets. It sells energy to companies and offers energy management services and solutions to
support the decarbonization of the Group and its customers.

69
6.2 Key indicators by reportable segment
REVENUES
Dec. 31, 2022 Dec. 31, 2021 (2)

External Intra-Group External Intra-Group
In millions of euros revenues revenues Total revenues revenues Total
Renewables 6,216 136 6,352 3,653 61 3,714
Networks 6,961 961 7,922 6,700 878 7,578
Energy Solutions 11,552 262 11,814 9,926 230 10,155
Thermal 7,129 1,144 8,274 4,089 827 4,916
Supply 16,810 534 17,344 10,396 117 10,513
Nuclear 35 2,653 2,688 56 1,705 1,762
Others 45,163 2,007 47,169 23,046 16,102 39,148
Of which GEMS (1) 45,137 1,979 47,115 22,870 16,077 38,947
Elimination of internal transactions ‐ (7,697) (7,697) ‐ (19,920) (19,920)
TOTAL REVENUES 93,865 ‐ 93,865 57,866 ‐ 57,866
(1) Of which a c. €20 billion price effect compared to 2021.
lines.
EBITDA

Renewables 2,202 1,702
Networks 4,212 4,121
Energy Solutions 879 786
Thermal 2,235 1,628
Supply 258 498
Nuclear 1,510 1,403
Others 2,417 426
Of which GEMS 2,837 679
TOTAL EBITDA 13,713 10,563
lines.
EBIT
In millions of euros Dec. 31, 2022 (1) Dec. 31, 2021 (2)
Thermal 1,768 1,183
Supply (7) 232
Nuclear 1,026 959
Others 1,848 (85)
Of which GEMS 2,618 507
TOTAL EBIT 9,045 6,145
(1) Including €739 million in taxes on “excess profits” and €917 million relating to the tax on nuclear energy production.
lines.

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SHARE IN NET INCOME/(LOSS) OF EQUITY METHOD ENTITIES

Renewables 217 95
Networks 323 233
Thermal 397 301
Supply ‐ ‐
Nuclear ‐ (11)
Others 4 34
Of which GEMS (1) 2
TOTAL SHARE IN NET INCOME/(LOSS) OF EQUITY METHOD ENTITIES 1,059 800
lines.
Associates and joint ventures accounted for €400 million and €659 million respectively of share in net income of equity
method entities at December 31, 2022 (compared to €306 million and €494 million at December 31, 2021).
INDUSTRIAL CAPITAL EMPLOYED

Networks 25,221 24,167
Energy Solutions 7,575 6,687
Thermal 8,091 7,846
Supply 1,023 1,322
Nuclear (2) (16,481) (12,666)
Others 9,399 6,517
Of which GEMS (3) 7,320 2,915
TOTAL INDUSTRIAL CAPITAL EMPLOYED 51,416 46,382
lines.
(2) Including €19,017 million of nuclear provisions at December 31, 2022 (€15,119 million as of December 31, 2021). Capital employed
does not include assets dedicated to covering provisions for €6,626 million as of December 31, 2022 (€5,505 million at
December 31, 2021).
(3) Industrial Capital employed does not include the initial margin required by certain market activities for €1,740 million at December
31, 2022 (€4,722 million at December 31, 2021).
As indicated in Note 5.4, from January 1, 2023, the Group will expand its definition of industrial capital employed to include
financial assets covering nuclear provisions (with an impact on the Nuclear operating segment) as well as the initial margins
required by certain market activities (with an impact on the GEMS operating segment). The following table shows the
impact of these changes to industrial capital employed of the reportable segments:

Networks 25,221 24,167
Energy Solutions 7,575 6,687
Thermal 8,091 7,846
Supply 1,023 1,322
Nuclear (9,855) (7,161)
Others 11,139 11,239
Of which GEMS 9,060 7,637
TOTAL INDUSTRIAL CAPITAL EMPLOYED (new definition for 2023) 59,782 56,609

71
CAPITAL EXPENDITURE
In millions of euros Dec. 31, 2022 (1) Dec. 31, 2021 (1)(2)(3)
Thermal 481 268
Supply 270 300
Nuclear 229 201
Others 338 496
Of which GEMS 149 76
TOTAL CAPITAL EXPENDITURE (CAPEX) 7,858 6,693
(1) Capital expenditure (CAPEX) now include changes in the scope of net financial debt of acquired entities. The impact at
December 31, 2021 is not material.
(2) In the context of the start of work related to the end of life of the nuclear power plant in Belgium, the definition of capital expenditures
(CAPEX) has been modified to exclude investments made by Synatom to cover nuclear provisions. These expenses are now
presented together with investments to cover expenditure for the dismantling of nuclear power plants and the management of
radioactive materials and waste, under a dedicated heading. Data at December 31, 2021 have been restated accordingly.
lines.
GROWTH CAPEX
In millions of euros Dec. 31, 2022 (1) Dec. 31, 2021 (1)(2)
Thermal 220 (17)
Supply 174 154
Nuclear 1 ‐
Others 85 221
Of which GEMS 63 (31)
TOTAL GROWTH CAPEX 5,485 4,275
(1) Growth Capex now includes changes in the scope of net financial debt of acquired companies. The impact at December 31, 2021 is
not material.
lines.
6.3 Key indicators by geographic area
The amounts set out below are analyzed by:
• destination of products and services sold for revenues;

• geographic location of consolidated companies for industrial capital employed.
Revenues Industrial capital employed

In millions of euros Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2021
France 34,248 24,341 32,495 30,241
Belgium 12,705 4,372 (14,201) (10,775)
Other EU countries 22,687 12,501 9,261 6,938
Other European countries 4,202 3,110 1,610 1,447
North America 6,133 4,752 7,101 5,342
Asia, Middle East & Oceania 8,875 4,441 3,507 2,709
South America 4,778 4,053 11,095 9,521
Africa 237 297 548 960
TOTAL 93,865 57,866 51,417 46,382

72
Due to the variety of its businesses and their geographical location, the Group serves a very diverse range of situations
and customer types (industry, local authorities and individual customers). Accordingly, no external customer represents
individually 10% or more of the Group’s consolidated revenues.

73
NOTE 7 REVENUES
NOTE 7 REVENUES
7.1 Revenues
Revenues from contracts with customers concern revenues from contracts that fall within the scope of IFRS 15.
Revenues are recognized when the customer obtains control of goods or services promised in the contract, for the
amount of consideration to which an entity expects to be entitled in exchange for said promised goods or services.
A contractual analysis of the Group’s sale contracts has led to the application of the following revenue recognition
principles:
• Gas, electricity and other energies

Revenues from sales of gas, electricity and other energies are recognized upon delivery of the power to the
retail, business or industrial customer.
Power deliveries are monitored in real time or on a deferred basis for those customers whose energy
consumption is metered during the accounting period, in which case the portion of not yet metered revenues
“in the meter” is estimated on the closing date.
• Gas, electrical and other energy infrastructures

Revenues derived by gas and electricity infrastructure operators upon providing transportation or distribution or
storage capacities, are recognized on a straight-line basis over the contract term.
In the countries where the Group acts as an energy provider (supplier) without being in charge of its distribution
or transportation, mainly in France and Belgium, an analysis of the energy sales contracts and of the related
regulatory framework is carried out to determine whether the distribution or transportation services invoiced to
the customers have to be excluded from the revenues recognized under IFRS 15.
Judgment may be exercised by the Group for this analysis in order to determine whether the energy provider
acts as an agent or a principal for the gas or electricity distribution or transportation services re-invoiced to the
customers. The main criteria used by the Group to exercise its judgment and conclude, in certain countries, that
the energy provider acts as an agent of the infrastructure operator are as follows: who is primarily responsible
for fulfillment of the distribution or transportation services? Does the energy provider have the ability to commit
to capacity reservation contracts towards the infrastructure operator? To what extent does the energy provider
have discretion in establishing the price for the distribution or transportation services?
• Constructions, installations, Operations and Maintenance (O&M)

Construction and installation contracts mainly concern assets built on the premises of customers such as
cogeneration units, heaters or other energy-efficiency assets. The related revenues are usually recognized
according to the percentage of completion on the basis of the costs incurred where the contracts fall within the
scope of IFRS 15.
O&M contracts generally require the Group to perform services ensuring the availability of power generating
facilities. These services are performed over time and the related revenues are recognized according to the
percentage of completion on the basis of the costs incurred.
If it is not possible to conclude from the contractual analysis that the contract falls within the scope of IFRS 15, the
revenues are accounted for as non-IFRS 15 revenues.
Revenues from other contracts, corresponding to revenues from operations that do not fall within the scope of IFRS 15,
presented in the “Others” column include trading, lease and concession income, as well as any financial component of
operating services, and the effects of the tariff shield mechanisms

74
NOTE 7 REVENUES

75
NOTE 7 REVENUES
The table below shows a breakdown of revenues by type:
Sales of Sales of
electricity and services Constructions,
other linked to installations,
In millions of euros Sales of gas energies infrastructures and O&M Others Dec. 31, 2022
Renewables ‐ 5,797 88 242 89 6,216
Networks 232 1 6,021 478 230 6,961
Energy Solutions 246 4,713 96 6,424 73 11,552
Thermal 22 4,522 1,601 396 588 7,129
Supply 7,793 5,372 153 958 2,534 16,810
Nuclear ‐ 5 8 24 (3) 35
Others 21,405 19,595 170 70 3,923 45,163
Of which GEMS 21,405 19,595 170 45 3,923 45,137
TOTAL REVENUES 29,697 40,004 8,135 8,593 7,435 93,865
The significant change in natural gas and electricity prices has led some governments to introduce a “tariff shield” for
natural gas and electricity, particularly in France and Romania.
The measure with the most significant impact on the Group's consolidated financial statements is the one introduced by
the French government for natural gas. Under the Finance Law for 2022 (No. 2021-1900 of December 30, 2021), as
amended by the first Amending Finance Law for 2022 (No. 2022-1157 of August 16, 2022), the regulated natural gas sales
tariffs applied by ENGIE were capped at the level of October 31, 2021, including all taxes, until December 31, 2022. The
loss of revenue borne by ENGIE constitutes an expense attributable to public service obligations and is subject to
guaranteed compensation by the State. The subsidy recognized in 2022 amounts to approximately €1,591 million
(€248 million in 2021) and is recorded under “Supply” business in the “Others” column (“Non-IFRS 15 revenues”). During
2022, the Group signed three non-recourse assignment agreements with Natixis, under the so-called “Dailly” law, in order
to sell part of the receivable relating to the subsidy, amounting to approximately €1,395 million.
Sales of Sales of
electricity services Constructions,
and other linked to installations,
In millions of euros Sales of gas energies infrastructures and O&M Others Dec. 31, 2021 (1)
Renewables ‐ 3,335 85 142 91 3,653
Networks 205 1 5,715 606 173 6,700
Energy Solutions 157 3,368 102 6,247 51 9,926
Thermal 66 3,165 345 451 62 4,089
Supply 5,532 3,539 74 985 265 10,396
Nuclear ‐ 4 11 22 19 56
Others 10,019 11,448 231 353 994 23,046
Of which GEMS 10,019 11,448 231 177 994 22,870
TOTAL REVENUES 15,978 24,861 6,565 8,806 1,656 57,866
lines.

76
NOTE 7 REVENUES
7.2 Trade and other receivables, assets and liabilities from contracts with
customers
On initial recognition, trade and other receivables are recorded at their transaction price as defined in IFRS 15.
A contract asset is an entity’s right to consideration in exchange for goods or services that have been transferred to a
customer but for which payment is not yet due or is contingent on the satisfaction of a specific condition stipulated in
the contract. When an amount becomes due, it is transferred to receivables.
A receivable is recorded when the entity has an unconditional right to consideration. A right to consideration is
unconditional if only the passage of time is required before payment of that consideration.
A contract liability is an entity’s obligation to transfer goods or services to a customer for which the entity has already
received consideration from the customer. The liability is derecognized upon recognition of the corresponding revenue.
Trade and other receivables and assets from contracts with customers are tested for impairment in accordance with the
provisions of IFRS 9 on expected credit losses.
The impairment model for financial assets is based on the expected credit loss model. To calculate expected losses,
the Group uses a matrix approach for trade receivables and assets from contracts with customers, for which the change
in credit risk is monitored on a portfolio basis. An individual approach is used for large customers and other large
counterparties, for which the change in credit risk is monitored on an individual basis.
See Note 15 “Risks arising from financial instruments” for the Group’s assessment of counterparty risk.
7.2.1 Trade and other receivables and assets from contracts with customers

Trade and other receivables, net 31,310 32,555
Of which IFRS 15 7,587 6,453
Of which non-IFRS15 23,723 26,103
Assets from contracts with customers 12,584 8,377
Accrued income and unbilled revenues 9,513 6,817
Energy in the meter (1) 3,071 1,560
(1) Net of advance payments.
In 2022, the most significant assets from contracts mainly concerned GEMS (€5,023 million), Energy Solutions
(€2,758 million) and Supply (€3,097 million).
Dec. 31, 2022 Dec. 31, 2021

Allowances Allowances
and and
expected expected
credit credit
In millions of euros Gross losses Net Gross losses Net
Trade and other receivables, net 33,282 (1,973) 31,310 33,920 (1,365) 32,555
Assets from contracts with customers 12,632 (48) 12,584 8,393 (16) 8,377
TOTAL 45,914 (2,020) 43,894 42,313 (1,381) 40,932

77
NOTE 7 REVENUES
Gas and electricity in the meter
For customers whose energy consumption is metered during the accounting period, the gas supplied but not yet metered
at the reporting date is estimated based on historical data, consumption statistics and estimated selling prices.
For sales on networks used by a large number of grid operators, the Group is allocated a certain volume of energy transiting
through the networks by the grid managers. As the final allocations are sometimes only known several months down the
line, revenue figures cannot be determined with absolute certainty. However, the Group has developed measuring and
modeling tools allowing it to estimate revenues with a reasonable degree of accuracy and subsequently ensure that risks
of error associated with estimating quantities sold and the related revenues can be considered as immaterial.
In France and Belgium, un-metered revenues (“gas in the meter”) are calculated using a direct method taking into account
customers’ estimated consumption based on the last invoice or metering not yet billed. These estimates are in line with
the volume of energy allocated by the grid managers over the same period. The average price is used to measure “gas in
the meter” and takes account of the category of customer and the age of the delivered unbilled “gas in the meter”. The
portion of unbilled revenues at the reporting date varies according to the assumptions about volume and average price.
“Electricity in the meter” is also determined using a direct allocation method similar to that used for gas, but taking into
account specific factors related to electricity consumption. It is also measured on a customer-by-customer basis or by
customer type.
Realized but not yet metered revenues (“un-metered revenues”) mainly related to France and Belgium for an amount of
€5,883 million at December 31, 2022 (€4,638 million at December 31, 2021).
7.2.2 Liabilities from contracts with customers
Dec. 31, 2022 Dec. 31, 2021

In millions of euros Non-current Current Total Non-current Current Total
Liabilities from contracts with customers 121 3,292 3,412 68 2,671 2,739
Advances and downpayments received 53 2,201 2,253 ‐ 1,955 1,955
Deferred revenues 68 1,091 1,159 68 716 784
In 2022, the Global Business Units reporting the greatest amounts of liabilities from contracts with customers were Supply
(€1,717 million) and Energy Solutions (€1,467 million).
7.3 Revenues relating to performance obligations not yet satisfied
Revenues relating to performance obligations only partially satisfied at December 31, 2022 amounted to €1,131 million.
They mainly concern Energy Solutions (€1,013 million) and Renewables (€117 million) which handle a large number of
construction, installation, and maintenance contracts under which revenues are recognized over time.

78
NOTE 8 OPERATING EXPENSES
Operating expenses include:
• purchases and operating derivatives including:

− the purchase of commodities and associated costs (infrastructure, transport, storage, etc.),
− the realized impact, as well as the change in fair value (MtM), of commodity transactions, with or without
physical delivery, that fall within the scope of IFRS 9 – Financial Instruments and that do not qualify as
trading or hedging. These contracts are set up as part of economic hedges of operating transactions in the
energy sector;
• purchases of services and other items such as subcontracting and interim expenses, lease expenses (short-
term lease contracts, leases with a low underlying asset value or leases with variable expenses), concession
expenses, etc.;
• personnel costs;
• depreciation, amortization, and provisions; and
• taxes.
8.1 Purchases and operating derivatives

Purchases and other income and expenses on operating derivatives other than trading (1) (67,676) (32,135)
Service and other purchases (2) (6,860) (6,726)
PURCHASES AND OPERATING DERIVATIVES (74,535) (38,861)
(1) Of which net expense of €3,661 million in 2022 relating to MtM on commodity contracts other than trading (compared to a net
income of €721 million in 2021), notably on certain economic gas and electricity hedging positions not documented as cash flow
hedges.
(2) Of which €56 million in lease expenses not included in the IFRS 16 lease liability (compared to €51 million in lease expenses in
2021).
The increase in purchases and operating derivatives is mainly due to changes in commodity prices over the period.
8.2 Personnel costs

Short-term benefits (7,712) (7,373)
Share-based payments 19 (104) (48)
Costs related to defined benefit plans 18.3.4 (172) (178)
Costs related to defined contribution plans 18.4 (91) (93)
PERSONNEL COSTS (8,078) (7,692)

79
8.3 Depreciation, amortization and provisions

Depreciation and amortization 13.2 & 13.3 (4,576) (4,370)
Net change in write-downs of inventories, trade receivables and other assets (768) (310)
Net change in provisions 17 157 (159)
DEPRECIATION, AMORTIZATION AND PROVISIONS (5,187) (4,840)
At December 31, 2022, depreciation and amortization mainly break down as €1,041 million for intangible assets and
€3,534 million for property, plant and equipment.
8.4 Taxes

TAXES (3,380) (1,479)
Taxes at December 31, 2022 include taxes on "excess profits", mainly the tax on infra-marginal income in Belgium and the
temporary solidarity contribution in Italy, amounting to €739 million, as well as the tax on nuclear power generation for
€917 million. The Italian temporary solidarity contribution of €132 million is recognized in income tax.

80
NOTE 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES
NOTE 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM

OPERATING ACTIVITIES
Other items of Net income/(loss) from operating activities include:
• “Impairment losses”: this line include impairment losses on goodwill, other intangible assets, property, plant and
equipment and investments in entities consolidated using the equity method;
• “Restructuring costs”: this line concern costs corresponding to a restructuring program planned and controlled
by management that materially changes either the scope of a business undertaken by the entity, or the manner
in which that business is conducted, based on the criteria set out in IAS 37;
• “Changes in the scope of consolidation”. This line includes:
− direct costs related to acquisitions of controlling interests,

− in a business combination achieved in stages, remeasurement at fair value at the acquisition date of the
previously held interest,
− subsequent changes in the fair value of contingent consideration,
− gains or losses from disposals of investments which result in a change of consolidation method, as well as
any impact from the remeasurement of retained interests with the exception of gains and losses arising from
transactions realized in the framework of “Develop, Build, Share & Operate” (DBSO) or “Develop, Share,
Build & Operate” (DSBO) business models. These transactions on renewable activities are recognized in
current operating income as they are part of the recurring rotation of the Group’s capital employed;
• “Other non-recurring items”: this line includes other elements of an unusual, abnormal or infrequent nature.
9.1 Impairment losses

Impairment losses:
Goodwill 13.1 ‐ (107)
Property, plant and equipment and other intangible assets 13.2 & 13.3 (2,306) (969)
Investments in equity method entities and related provisions (536) (17)
TOTAL IMPAIRMENT LOSSES (2,841) (1,093)
Reversal of impairment losses:
Property, plant and equipment and other intangible assets 67 64
TOTAL REVERSALS OF IMPAIRMENT LOSSES 67 64
TOTAL (2,774) (1,028)
9.1.1 Impairment losses recognized in 2022
Net impairment losses recognized at December 31, 2022 amounted to €2,774 million. They mainly fall into three categories
(see Note 13.4):
• the effects of the three-yearly revision of nuclear provisions on assets to be recognized against nuclear power
plant dismantling provisions;
• the effects of the ongoing program to exit coal activities;
• the consequences of negotiations initiated or finalized during the year in connection with the renegotiation of PPA
contracts or the disposal of non-strategic assets.

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These impairment losses mainly concern property, plant and equipment and intangible assets. Considering the effects of
deferred taxes and the portion of impairment losses attributable to non-controlling interests, the impact of the impairment
losses on net income Group share amounted to €2,275 million.
With the exception of the induced effects of decisions to dispose of non-strategic assets, no impairment losses were
recognized on non-financial assets as a result of measures to prevent or mitigate climate risks or to achieve the 2045 net
zero-carbon objective.
Impairment tests are carried out in accordance with the procedures described in Note 13.4.
9.1.2 Impairment losses recognized in 2021
Net impairment losses recognized at December 31, 2021 amounted to €1,028 million and related mainly to:
• assets affected by the Group’s announced exit from coal, in 2021, for thermal power generation assets, particularly
in Brazil (€228 million);
• assets affected by the strategic review of Client Solutions, announced by the Group in 2020, in France
(€90 million), Africa (€73 million) and Asia (€33 million);
• assets that have been subject to revisions to their medium- and long-term prospects, or that have encountered
operational difficulties, in particular renewable energy production assets in Latin America (€221 million) and
thermal power generation assets in Asia (€90 million);
• other production or support assets for less significant amounts taken individually.
9.2 Restructuring costs
In 2022, restructuring costs totaled € 230 million (versus €204 million in 2021). Restructuring costs in both years mainly
included costs related to staff reduction plans and measures to adapt to economic situations in 2022 and 2021, as well as
the shutdown or sale of operations, the closure or restructuring of certain facilities as well as other miscellaneous
restructuring costs.
9.3 Changes in scope of consolidation
At December 31, 2022, the impact of changes in the scope of consolidation was a positive €91 million and mainly
comprised:
• a positive impact of €280 million relating to the disposals of shares held in Gaztransport et Technigaz (GTT) for a
total representing approximatively 24.6% of its share capital. This result includes the effects of the almost full
conversion of the exchangeable bond issued by the Group in June 2021;
• a positive impact of €111 million relating to the disposal of geothermal assets in Indonesia;
• a negative impact of €127 million relating to the disposal of the Energy Solutions activities in Africa and France;
• a negative impact of €110 million relating to the purchase of shares in renewable assets in India with refinancing
obligations due in 2023;
• a negative impact of €63 million relating to miscellaneous disposals that are not individually significant.
At December 31, 2021, the impact of changes in the scope of consolidation was a positive €1,107 million and mainly
comprised:
• a positive €628 million impact related to the disposal of 10% of the shares held in GTT for €151 million and the
revaluation of the remaining 30% for €478 million;
• the positive impact of the earn-out to be received on the disposal of the 29.9% stake in SUEZ for €347 million;

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• a positive €113 million change in the fair value of the earn-out from the disposal of LNG activities to TOTAL in
2018;
• a positive €56 million impact relating to various disposals including EPS for €83 million, the Group’s interests in
Georgetown Energy Partners Holding LLC in the United States for €44 million, and in a thermal power generation
asset in Greece for a negative €28 million, and
• a negative €48 million impact related to the change in the fair value of the embedded derivative of the GTT shares
exchangeable bond.
9.4 Other non-recurring items
Other non-recurring items at December 31, 2022 totaled a negative €1,328 million and mainly comprised:
• a negative impact of €979 million related to the three-yearly review of provisions for the management of the back-
end nuclear cycle;
• a negative impact of €205 million related to provisions set up to cover clean-up obligations in France;
• a negative impact of €161 million related to the write-off of intangible assets and property, plant and equipment,
mainly in France.
Other non-recurring items at December 31, 2021 totaled a negative €69 million and comprised asset scrapping, and
disposals of property, plant and equipment.

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NOTE 10 NET FINANCIAL INCOME/(LOSS)
NOTE 10 NET FINANCIAL INCOME/(LOSS)
Dec. 31, Dec. 31,

In millions of euros Expense Income 2022 Expense Income 2021
Interest expense on gross debt and hedges (1,104) - (1,104) (943) - (943)
Cost of lease liabilities (73) ‐ (73) (35) ‐ (35)
Foreign exchange gains/losses on borrowings and hedges (28) ‐ (28) (6) ‐ (6)
Ineffective portion of derivatives qualified as fair value hedges ‐ 7 7 (2) ‐ (2)
Gains and losses on cash and cash equivalents and liquid debt
instruments held for cash investment purposes - 197 197 - 63 63
Capitalized borrowing costs 109 - 109 70 - 70
Cost of net debt (1,097) 205 (893) (916) 63 (852)
Cash payments made on the unwinding of swaps (9) - (9) (73) - (73)
Reversal of the negative fair value of these early unwound derivative
financial instruments ‐ ‐ ‐ ‐ 73 73
Gains/(losses) on debt restructuring transactions ‐ 55 55 ‐ ‐ ‐
Gains/(losses) on debt restructuring and early unwinding of derivative
financial instruments (9) 55 46 (73) 73 ‐
Net interest expense on post-employment benefits and other long-term
benefits (92) ‐ (92) (63) ‐ (63)
Unwinding of discounting adjustments to other long-term provisions (617) ‐ (617) (630) ‐ (630)
Change in fair value of derivatives not qualified as hedges and ineffective
portion of derivatives qualified as cash flow hedges (5) ‐ (5) (152) ‐ (152)
Income/(loss) from debt instruments and equity instruments (1,295) 36 (1,258) (16) 329 313
Interest income on loans and receivables at amortized cost ‐ 69 69 ‐ 125 125
Other (585) 332 (253) (213) 121 (92)
Other financial income and expenses (2,594) 438 (2,156) (1,073) 575 (498)
NET FINANCIAL INCOME/(LOSS) (3,700) 697 (3,003) (2,061) 711 (1,350)
The cost of net debt is higher compared to December 31, 2021 notably due to the increase in lease liabilities relating to
the extension of the Compagnie Nationale du Rhône concession. The higher average cost of gross debt, mainly due to the
rise in interest rates, is partly offset by the increase in interest received on cash and cash equivalents and liquid debt
instruments.
Losses from debt and equity instruments amounted to €1.258 million. This amount mainly includes the impairment of the
loan granted to Nord Stream 2 for €987 million and the negative change in fair value of money market funds held by
Synatom for €280 million (see Note 17.2.4 “Financial assets set aside to cover the future costs of dismantling nuclear
facilities and managing radioactive fissile material”).
At December 31, 2022, the average cost of debt after hedging came out at 2.73% compared with 2.65% at
December 31, 2021.

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NOTE 11 INCOME TAX EXPENSE
The Group calculates taxes in accordance with prevailing tax legislation in the countries where income is taxable.
In accordance with IAS 12, deferred taxes are recognized according to the liability method on temporary differences
between the carrying amounts of assets and liabilities in the consolidated financial statements and their tax bases,
using tax rates that have been enacted or substantively enacted by the reporting date. However, under the provisions
of IAS 12, no deferred tax is recognized for temporary differences arising from goodwill for which impairment losses are
not deductible for tax purposes, or from the initial recognition of an asset or liability in a transaction which (i) is not a
business combination and (ii) at the time of the transaction, affects neither accounting income nor taxable income. In
addition, deferred tax assets are only recognized to the extent that it is probable that taxable income will be available
against which the deductible temporary differences can be utilized.
A deferred tax liability is recognized for all taxable temporary differences associated with investments in subsidiaries,
associates, joint ventures and branches, except if the Group is able to control the timing of the reversal of the temporary
difference and it is probable that the temporary difference will not reverse in the foreseeable future.
Net balances of deferred taxes are calculated based on the tax position of each company or on the total income of
companies included within the relevant consolidated tax group, and are presented in assets or liabilities for their net
amount per tax entity.
Deferred taxes are reviewed at each reporting date to take into account factors including the impact of changes in tax
laws and the prospects of recovering deferred tax assets arising from deductible temporary differences.
Deferred tax assets and liabilities are not discounted.
Tax effects relating to coupon payments on deeply-subordinated perpetual notes are recognized in profit or loss.
11.1 Actual income tax expense recognized in the income statement
11.1.1 Breakdown of actual income tax expense recognized in the income statement
The tax income recognized in the income statement for 2022 amounted to €83 million (€1,695 million income tax expense
in 2021). It breaks down as follows:

Current income taxes (1,762) (740)
Deferred taxes 1,845 (955)
TOTAL INCOME TAX BENEFIT/(EXPENSE) RECOGNIZED IN INCOME 83 (1,695)

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11.1.2 Reconciliation of theoretical income tax expense with actual income tax expense
A reconciliation of theoretical income tax expense with the Group’s actual income tax expense is presented below:

Net income/(loss) 390 3,758
Share in net income of equity method entities 523 784
Net income/(loss) from discontinued operations 2,183 80
Income tax expense 83 (1,695)
Income/(loss) before income tax of consolidated companies (A) (2,400) 4,588
Of which French companies (2,130) 5,604
Of which companies outside France (270) (1,016)
Statutory income tax rate of the parent company (B) 25.8% 28.4%
THEORETICAL INCOME TAX EXPENSE (C) = (A) X (B) 620 (1,303)
Reconciling items between theoretical and actual income tax expense
Difference between statutory tax rate applicable to the parent and statutory tax rate in force in
jurisdictions in France and abroad (8) 38
Permanent differences (1) (313) (30)
Income taxed at a reduced rate or tax-exempt (2) 427 300
Additional tax expense (3) (327) (230)
Effect of unrecognized deferred tax assets on tax loss carry-forwards and other tax-deductible
temporary differences (4) (940) (958)
Recognition or utilization of tax income on previously unrecognized tax loss carry-forwards and other
tax-deductible temporary differences (5) 643 510
Impact of changes in tax rates (6) (37) (17)
Tax credits and other tax reductions (7) 20 185
Other (8) (1) (189)
INCOME TAX BENEFIT/(EXPENSE) RECOGNIZED IN INCOME 83 (1,695)
(1) Mainly includes disallowable impairment losses on goodwill, disallowed operating expenses and the deduction of interest expenses
arising from hybrid debt.
(2) Mainly includes capital gains on disposals of securities exempt from tax or taxed at a reduced rate in some tax jurisdictions,
the impact of the specific tax regimes used by some entities, disallowable impairment losses and capital losses on securities, and
the impact of untaxed income from remeasuring previously-held (or retained) equity interests in connection with acquisitions and
changes in consolidation methods.
(3) Mainly includes tax on dividends resulting from the parent company tax regime, withholding tax on dividends and interest levied in
several tax jurisdictions, allocations to provisions for income tax, and regional and flat-rate corporate taxes. In 2022, this line also
includes the temporary Italian solidarity contribution, which amounts to €132 million.
(4) Includes (i) the cancellation of the net deferred tax asset position for some tax entities in the absence of sufficient profit being
forecast and (ii) the impact of disallowable impairment losses on fixed assets.
(5) Includes the impact of the recognition of net deferred tax asset positions for some tax entities.
(6) Mainly includes the impact of tax rate changes on deferred tax balances in the United Kingdom for 2022 and in the United Kingdom,
France and Argentina for 2021.
(7) Mainly includes reversals of provisions for tax litigation, tax credits in France and other tax reductions.
(8) Mainly includes the correction of previous tax charges.

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11.1.3 Analysis of the deferred tax income/(expense) recognized in the income

statement, by type of temporary difference
Impact in the income statement

Deferred tax assets:
Tax loss carry-forwards and tax credits 1,051 (178)
Pension and related obligations (1) (218)
Non-deductible provisions 55 (56)
Difference between the carrying amount of PP&E and intangible assets and their tax bases 454 174
Measurement of financial instruments at fair value (IAS 32/IFRS 9) (1,260) 6,542
Other (135) 222
TOTAL 164 6,485
Deferred tax liabilities:
Difference between the carrying amount of PP&E and intangible assets and their tax bases (545) (498)
Measurement of assets and liabilities at fair value (IAS 32/IFRS 9) 1,781 (7,148)
Other 398 183
TOTAL 1,634 (7,463)
DEFERRED TAX INCOME/(EXPENSE) 1,798 (977)
Of which continuing activities 1,844 (955)
11.2 Deferred tax income/(expense) recognized in “Other comprehensive

income”
Net deferred tax income/(expense) recognized in “Other comprehensive income” is broken down by component as follows:

Equity and debt instruments 33 (4)
Actuarial gains and losses (646) (447)
Net investment hedges 11 55
Cash flow hedges on other items 943 (1,370)
Cash flow hedges on net debt (3) (19)
TOTAL EXCLUDING SHARE OF EQUITY METHOD ENTITIES & DISCONTINUED OPERATIONS 338 (1,784)
Share of equity method entities (132) (50)
Discontinued operations (21) (13)
TOTAL 185 (1,848)
11.3 Deferred taxes presented in the statement of financial position
11.3.1 Change in deferred taxes
Changes in deferred taxes recognized in the statement of financial position, after netting deferred tax assets and liabilities
by tax entity, break down as follows:
In millions of euros Assets Liabilities Net position

AT DECEMBER 31, 2021 1,181 (7,738) (6,557)
Impact on net income for the year 164 1,635 1,799
Impact on other comprehensive income items (479) 792 313
Impact of changes in scope of consolidation 38 (19) 19
Impact of translation adjustments 101 (146) (45)
Transfers to assets and liabilities classified as held for sale (54) 51 (3)
Other 440 (344) 95
Impact of netting by tax entity 638 (638) ‐
AT DECEMBER 31, 2022 2,029 (6,408) (4,379)

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11.3.2 Analysis of the net deferred tax position recognized in the statement of financial
position (before netting deferred tax assets and liabilities by tax entity), by type of
temporary difference
Measurement of recognized tax loss carry-forwards
Deferred tax assets are recognized on tax loss carry-forwards when it is probable that taxable profit will be available against
which the tax loss carry-forwards can be utilized. The probability that taxable profit will be available against which the
unused tax losses can be utilized, is based on taxable temporary differences relating to the same taxation authority and
the same taxable entity and estimates of future taxable profits. These estimates and utilizations of tax loss carry-forwards
were prepared on the basis of profit and loss forecasts over a six-year tax projection period as included in the
medium-term business plan validated by Management, subject to exceptions justified by a particular context and, if
necessary, on the basis of additional forecasts.
Statement of financial position at

Deferred tax assets:
Tax loss carry-forwards and tax credits 2,202 1,299
Pension obligations 812 1,501
Non-deductible provisions 518 388
Difference between the carrying amount of PP&E and intangible assets and their tax bases 1,830 1,440
Measurement of financial instruments at fair value (IAS 32 / IFRS 9) 8,346 8,968
Other 620 523
TOTAL 14,328 14,119
Deferred tax liabilities:
Difference between the carrying amount of PP&E and intangible assets and their tax bases (9,873) (9,345)
Measurement of financial instruments at fair value (IAS 32 / IFRS 9) (8,141) (10,643)
Other (693) (687)
TOTAL (18,707) (20,675)
NET DEFERRED TAX ASSETS/(LIABILITIES) (4,378) (6,557)
11.4 Unrecognized deferred taxes
At December 31, 2022, the tax effect of tax losses and tax credits eligible for carry-forward but not utilized and not
recognized in the statement of financial position amounted to €4,165 million (€4,642 million at December 31, 2021). Most of
these unrecognized tax losses relate to companies based in countries which allow losses to be carried forward indefinitely
(mainly Belgium, Australia, Luxembourg and the Netherlands). These tax loss carry-forwards did not give rise to the full
or partial recognition of a deferred tax asset due to the absence of sufficient profit forecasts in the medium term.
The tax effect of other tax-deductible temporary differences not recorded in the statement of financial position was
€1,590 million at end-December 2022 versus €1,097 million at end-December 2021.

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NOTE 12 EARNINGS PER SHARE
NOTE 12 EARNINGS PER SHARE
Basic earnings per share is calculated by dividing net income Group share for the year by the weighted average number
of ordinary shares outstanding during the year. The average number of ordinary shares outstanding during the year is
the number of ordinary shares outstanding at the beginning of the year, adjusted by the number of ordinary shares
bought back or issued during the year.
For the diluted earnings per share calculation, the weighted average number of shares and basic earnings per share
are adjusted to take into account the impact of the conversion or exercise of any dilutive potential ordinary shares
(options, warrants and convertible bonds, etc.).
In compliance with IAS 33 – Earnings per Share, earnings per share and diluted earnings per share are based on net
income/(loss) Group share after deduction of payments to bearers of deeply-subordinated perpetual notes (see
Note 16.2.1 “Issuance of deeply-subordinated perpetual notes”).
The Group’s dilutive instruments included in the calculation of diluted earnings per share include bonus shares and
performance shares granted in the form of ENGIE securities.
Dec. 31, 2022 Dec. 31, 2021
Numerator (in millions of euros)

Of which Net income/(loss) relating to continuing operations, Group share (1,965) 3,582
Interest from deeply-subordinated perpetual notes (77) (121)
Net income/(loss)used to calculate earnings per share 140 3,540
Of which Net income/(loss) relating to continuing operations, Group share, used to calculate earnings per
share (2,042) 3,461
Diluted net income/(loss) Group share 140 3,540
Net recurring income/(loss) Group share 5,510 3,158

Of which Net recurring income/(loss) relating to continuing operations, Group share 5,223 2,927
Interest from deeply-subordinated perpetual notes (77) (121)
Net recurring income/(loss)used to calculate earnings per share 5,433 3,037
Of which Net recurring income/(loss) relating to continuing operations, Group share, used to calculate
earnings per share 5,146 2,806
Diluted net recurring income/(loss) Group share 5,433 3,037
Denominator (in millions of shares)

Average number of outstanding shares 2,420 2,419
Impact of dilutive instruments:
Bonus share plans reserved for employees ‐ 12
Diluted average number of outstanding shares 2,420 2,431
Earnings per share (in euros)

Basic earnings/(loss) per share 0.06 1.46
Of which Basic earnings/(loss) Group share relating to continuing operations per share (0.84) 1.43
Diluted earnings/(loss) per share 0.06 1.46
Of which Diluted earnings/(loss) Group share relating to continuing operations per share (0.84) 1.42
Basic recurring earnings/(loss) per share 2.24 1.26

Of which Basic recurring earnings/(loss) Group share relating to continuing operations per share 2.13 1.16
Diluted recurring earnings/(loss) per share (1) 2.23 1.25
Of which Diluted recurring earnings/(loss) Group share relating to continuing operations per share (1) 2.12 1.15
(1) In 2022, the calculation of the denominator includes 12 million potential ENGIE shares which would have a dilutive effect on the
NRIgs and NRIgs relating to continuing operations per share but have not been taken into account in the calculation of the NIgs and
the NIgs relating to continuing operations per share due to the antidilutive effect on the latter.

89
NOTE 13 FIXED ASSETS
13.1 Goodwill
Upon a business combination, goodwill is measured as the difference between:

• on the one hand the sum of:
− the consideration transferred;

− the amount of non-controlling interests in the acquiree, and
− in a business combination achieved in stages, the acquisition-date fair value of the previously held equity
interest in the acquiree;
• on the other hand the net fair value of the identifiable assets acquired and liabilities assumed. The key
assumptions and estimates used to determine the fair value of assets acquired and liabilities assumed include
the market outlook for the measurement of future cash flows as well as applicable discount rates. These
assumptions reflect management’s best estimates at the acquisition date.
The amount of goodwill recognized at the acquisition date cannot be adjusted after the end of the 12-month
measurement period.
Goodwill relating to interests in associates is recorded under “Investments in equity method entities”.
13.1.1 Movements in the carrying amount of goodwill
In millions of euros Net amount

AT DECEMBER 31, 2021 12,799
Changes in scope of consolidation and Other (27)
Translation adjustments 82
AT DECEMBER 31, 2022 12,854
13.1.2 Information on goodwill
For the purposes of impairment testing, goodwill is allocated to operating segments, which represent the lowest level at
which it is monitored for internal management purposes.
The table below shows the amount of goodwill at December 31, 2022:
In millions of euros Dec. 31, 2022

Networks 5,302
Renewables 2,110
Supply 1,830
Energy Solutions 1,316
Thermal 1,152
Nuclear 797
Other 350
TOTAL 12,855

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13.2 Intangible assets
Initial measurement
Intangible assets are carried at cost less any accumulated amortization and any accumulated impairment losses.
Amortization
Intangible assets are amortized on the basis of the expected pattern of consumption of the estimated future economic
benefits embodied in the asset. Amortization is calculated mainly on a straight-line basis over the following useful lives:
Useful life
Main depreciation periods (years) Minimum Maximum
Concession rights 10 30
Customer portfolio 3 20
Other intangible assets 1 50
Intangible assets with an indefinite useful life are not amortized but are tested for impairment annually.
Intangible rights arising on concession contracts
IFRIC 12 – Service Concession Arrangements deals with the treatment to be applied by the concession operator in
respect of certain concession arrangements.
For a concession arrangement to fall within the scope of IFRIC 12, usage of the infrastructure must be controlled by the
concession grantor. This requirement is satisfied when the following two conditions are met:
• the grantor controls or regulates what services the operator must provide with the infrastructure, to whom it must
provide them, and at what price; and
• the grantor controls any residual interest in the infrastructure at the end of the term of the arrangement, for
example it retains the right to take back the infrastructure at the end of the concession.
The intangible asset model according to paragraph 17 of IFRIC 12 applies if the operator receives a right (a license) to
charge the users, or the grantor, depending on the use made of the public service. There is no unconditional right to
receive cash, as the amounts depend on the extent to which the public uses the service.
Concession infrastructures that do not meet the requirements of IFRIC 12 are presented as property, plant and
equipment. This is the case of gas distribution infrastructures in France. The related assets are recognized in
accordance with IAS 16, given that GRDF operates its network under long-term concession arrangements, most of
which are mandatorily renewed upon expiration pursuant to French law No. 46-628 of April 8, 1946.
Research and development costs
Research costs are expensed as incurred.
Development costs are capitalized when the asset recognition criteria set out in IAS 38 are met. Capitalized development
costs are amortized over the useful life of the intangible asset.

91
13.2.1 Movements in intangible assets
Intangible rights
arising on
concession Capacity
In millions of euros contracts entitlements Others Total
GROSS AMOUNT
AT DECEMBER 31, 2021 3,917 2,845 12,936 19,697
Acquisitions 68 ‐ 1,364 1,432
Disposals (485) (15) (622) (1,122)
Translation adjustments 11 ‐ 150 162
Changes in scope of consolidation (37) ‐ 15 (22)
Transfer to "Assets classified as held for sale and discontinued operations" ‐ ‐ 6 6
Other 156 453 (351) 257
AT DECEMBER 31, 2022 3,630 3,282 13,498 20,410
ACCUMULATED AMORTIZATION AND IMPAIRMENT
AT DECEMBER 31, 2021 (1,921) (2,133) (8,860) (12,913)
Amortization (139) (90) (812) (1,041)
Impairment (13) ‐ (41) (54)
Disposals 477 15 519 1,011
Translation adjustments 1 ‐ (45) (44)
Changes in scope of consolidation 9 ‐ 37 46
Other (121) ‐ 71 (50)
AT DECEMBER 31, 2022 (1,706) (2,208) (9,131) (13,046)
CARRYING AMOUNT
AT DECEMBER 31, 2021 1,996 712 4,076 6,784
AT DECEMBER 31, 2022 1,924 1,074 4,366 7,364
In 2022, the net increase in “Intangible assets” was mainly attributable to:
• the investments during the period (positive €1,432 million) relating mainly to information technology projects in
progress (positive €898 million) in the business of Energy Solutions in France, Networks in France and in the
Renewables businesses in Brazil and in the United States;
• a positive foreign exchange impact of €118 million primarily due to the appreciation against the euro of the Brazilian
real (positive €86 million) and of the US dollar (positive €37 million);
• changes in scope of consolidation (positive €24 million) relating mainly to the acquisition of Eolia Renovables in
Spain (positive €22 million) and to the acquisition of Renewables activities in the United States (positive
€14 million);
partially offset by:
• amortizations (negative €1,041 million);

• the impact of the first-time application of the decision of the IFRS IC of March 2021, related to the accounting
treatment of configuration and customization costs for software in a SaaS arrangement (Software as a Service)
for a negative €140 million (Note 1.1 “Accounting standards”);
• impairment losses (negative €54 million).
13.2.2 Capacity entitlements
The Group has acquired capacity entitlements from power stations operated by third parties. These power station capacity
rights were acquired in connection with transactions or within the scope of the Group’s involvement in financing the
construction of certain power stations. In consideration, the Group received the right to purchase a share of the production
over the useful life of the underlying assets. These rights are amortized over the useful life of the underlying assets, not
exceeding 50 years. The Group currently holds entitlements in the Chooz B and Tricastin power plants in France and in
the virtual power plant (VPP) in Italy.

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13.2.3 Other
At December 31, 2022, this caption mainly relates to software and licenses for €1,393 million, as well as intangible assets
in progress €767 million and intangible assets (client portfolio) acquired as a result of business combinations and
capitalized acquisition costs for customer contracts for €1,925 million.
13.2.4 Information regarding research and development costs
Research and development activities primarily relate to various studies regarding technological innovation, improvements
in plant efficiency, safety, environmental protection, service quality, and the use of energy resources. Research and
development priorities are focused on climate change adaptation and mitigation, including renewable energy systems
(solar photovoltaic, onshore and offshore wind), the production and use of green gases (hydrogen, biomethane) or the
development of decentralized energy infrastructure (district heating and cooling, decentralized solar energy, low carbon
cities and mobility.
The capitalized development costs, related to projects in the development phase that meet the criteria for recognition as
an intangible asset as defined in IAS 38, totaled €44 million in 2022 and are mainly related to EV Box (€22 million) which
is active in the Energy Solutions business and to the Renewables businesses of Engie Energia Chile (€20 million).
13.3 Property, plant and equipment
Initial recognition and subsequent measurement
Items of property, plant and equipment are recognized at historical cost less any accumulated depreciation and any
accumulated impairment losses.
The carrying amount of these items is not revalued as the Group has elected not to apply the allowed alternative method,
which consists of regularly revaluing one or more categories of property, plant and equipment.
Investment subsidies are deducted from the gross value of the assets concerned.
In accordance with IAS 16, the initial cost of the item of property, plant and equipment includes an initial estimate of the
costs of dismantling and removing the item and restoring the site on which it is located, when the entity has a present,
legal or constructive obligation to dismantle the item or restore the site. A corresponding provision for this obligation is
recorded for the amount of the asset component.
Borrowing costs that are directly attributable to the construction of the qualifying asset are capitalized as part of the cost
of that asset.
Leases
In accordance with IFRS 16, the Group recognizes a right-of-use asset and a corresponding lease liability with respect
to contracts considered as a lease in which the Group acts as lessee, except for leases with a term of 12 months or less
(“short-term leases”), and leases for which the underlying asset is of a low value (“low-value asset”). Payments
associated with these leases are recognized on a straight-line basis as expenses in profit and loss. The lease contracts
in the Group mainly concern real estate, vehicles and other equipment.
The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for
any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate
of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located,
less any lease incentives received.

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The lease liability is initially measured at the present value of the remaining lease payments, discounted using the
lessee’s incremental borrowing rate. This rate is calculated based on the Group’s incremental borrowing rate adjusted
in accordance with IFRS 16, taking into account (i) the economic environment of the subsidiaries, and in particular their
credit risk, (ii) the currency in which the contract is concluded and (iii) the duration of the contract at inception (or the
remaining duration for contracts existing upon the initial application of IFRS 16). The methodology applied to determine
the incremental borrowing rate reflects the profile of the lease payments (duration method).
The lease term is assessed, including whether a renewal option is reasonably certain to be exercised or a termination
option is reasonably certain not to be exercised, on a case-by-case basis. The lease term is reassessed if a significant
event or a significant change in circumstances that is within the control of the lessee occurs and may affect the
assessment made. In determining the enforceable period of a lease, the Group applies a broad interpretation of the
term penalty and takes into consideration not only contractual penalties arising from termination, but also ancillary costs
that could arise in case of an early termination of the lease.
Cushion gas
“Cushion” gas injected into underground storage facilities is essential for ensuring that reservoirs can be operated
effectively, and is therefore inseparable from these reservoirs. Unlike “working” gas which is included in inventories
(see Note 22.2 “Inventories”), cushion gas is reported in other property, plant and equipment.
Depreciation
In accordance with the components approach, each significant component of an item of property, plant and equipment
with a different useful life from that of the main asset to which it relates is depreciated separately over its own useful life.
Property, plant and equipment is depreciated mainly using the straight-line method over the following useful lives:
Useful life
Main depreciation periods (years) Minimum Maximum
Plant and equipment
⚫ Storage - Production - Transport - Distribution 5 60(*)
⚫ Installation – Maintenance 3 10
⚫ Hydraulic plant and equipment 20 65
Solar and wind farms 25 30
Other property, plant and equipment 2 33
(*) Excluding cushion gas.
The range of useful lives is due to the diversity of the assets in each category. The minimum periods relate to smaller
equipment and furniture, while the maximum periods concern network infrastructures and storage facilities. In
accordance with the law of January 31, 2003 adopted by the Belgian Chamber of Representatives with respect to the
gradual phase-out of nuclear energy for the industrial production of electricity, the useful lives of nuclear power stations
were reviewed and adjusted prospectively to 40 years as from 2003, except for Tihange 1, Doel 1 and Doel 2 for which
the operating lives have been extended by 10 years.
Fixtures and fittings relating to hydro plants operated by the Group are depreciated over the shorter of the contract term
and the useful life of the assets, taking into account the renewal of the concession period if such renewal is considered
to be reasonably certain.
The right-of-use asset related to leases is depreciated using the straight-line method from the commencement date to
the end of the lease term, unless the lease transfers ownership of the underlying asset to the Group by the end of the
lease term. In that case the right-of-use asset is depreciated over the useful life of the underlying asset, which is
determined on the same basis as that used for property, plant and equipment mentioned above.

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13.3.1 Movements in property, plant and equipment
Plant and Dismantling Assets in Right

In millions of euros Land Buildings equipment Vehicles costs progress of use Other Total
GROSS AMOUNT
AT DECEMBER 31, 2021 650 3,312 90,530 304 3,669 4,715 3,867 1,308 108,355
Acquisitions/Increases 4 21 348 33 ‐ 5,473 1,335 69 7,283
Disposals (33) (94) (475) (29) (3) (28) (167) (55) (884)
Translation adjustments 8 15 934 3 13 153 110 23 1,260
Changes in scope of consolidation 5 (2) 178 (12) 22 (75) (88) (22) 6
Transfer to "Assets classified as held for sale
and discontinued operations" ‐ ‐ (372) ‐ ‐ (6) 10 ‐ (369)
Other 16 (491) 4,873 5 2,337 (4,585) 27 (3) 2,179
AT DECEMBER 31, 2022 649 2,762 96,016 304 6,038 5,649 5,094 1,319 117,831
ACCUMULATED DEPRECIATION AND IMPAIRMENT
AT DECEMBER 31, 2021 (146) (1,849) (49,426) (219) (3,115) (387) (1,284) (850) (57,277)
Depreciation (3) (70) (2,797) (29) (102) ‐ (442) (92) (3,534)
Impairment (2) (8) (846) ‐ (911) (472) (19) (2) (2,259)
Disposals 3 78 395 27 1 47 157 49 757
Translation adjustments (1) (8) (331) (2) (4) (12) (24) (8) (390)
Changes in scope of consolidation 1 (8) (78) (3) (25) 97 (76) (4) (97)
Transfer to "Assets classified as held for sale
and discontinued operations" ‐ ‐ 260 ‐ ‐ 3 (1) ‐ 262
Other (4) 93 112 ‐ ‐ 2 (21) 12 193
AT DECEMBER 31, 2022 (153) (1,772) (52,709) (226) (4,155) (724) (1,710) (895) (62,343)
CARRYING AMOUNT
AT DECEMBER 31, 2021 503 1,463 41,105 85 554 4,328 2,583 458 51,079
AT DECEMBER 31, 2022 497 991 43,307 78 1,883 4,925 3,384 424 55,488
In 2022, the net increase in “Property, plant and equipment” essentially takes into account :
• the recognition of decommissioning assets in respect of the revision of decommissioning provisions for which the
main part related to nuclear installations (€2,238 million);
• maintenance and development investments for a total amount of €5,948 million mainly related to the construction
and the development of wind and solar farms primarily in France, the United States and in Latin America
(€2,870 million), as well as to the extension of the transportation and distribution networks in France and Romania
(€1,806 million), to Energy Solutions activities (€461 million) and to Thermal operating segments assets
(€516 million);
• the recognition of the right of use related to the extension of the concession of the Compagnie Nationale du Rhône
(CNR) for a positive €848 million; and
• positive foreign exchange effects of €870 million, mainly resulting from the appreciation against the euro of the
US dollar (positive impact of €601 million) and fluctuations in the Brazilian real (positive impact of €324 million);
largely offset by :
• depreciation for a total amount of €3,534 million;

• the classification under “Assets held for sale” for a negative €107 million, relating mainly to the classification of a
thermal power plant in Brazil (negative €353 million) partially offset by the reversal of the classification as held for
sale of certain renewables assets in Mexico due to the unfavorable evolution of the disposal project (positive
€229 million);
• impairment losses on property, plant and equipment amounting to €2,259 million mainly relating to the nuclear
assets in Belgium (negative €1,219 million).
13.3.2 Pledged and mortgaged assets
Items of property, plant and equipment pledged by the Group to guarantee borrowings and debt amounted to €1,120 million
at December 31, 2022 compared to €1,373 million at December 31, 2021.

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The net decrease mainly relates to the Thermal assets in Brazil for a negative €484 million due to the recognition of a
thermal plant as an asset held for sale.
13.3.3 Contractual commitments to purchase property, plant and equipment
In the ordinary course of their operations, some Group companies have entered into commitments to purchase, and the
related third parties to deliver plant and equipment. These commitments relate mainly to orders for equipment and material
related to the construction of energy production units and to service agreements.
Investment commitments made by the Group to purchase property, plant and equipment totaled €3,548 million at
December 31, 2022 compared to €1,926 million at December 31, 2021 (
1)
.
The net increase primarily relates to the construction of renewable assets in Brazil for €680 million and in the United States
for €392 million and to contractual commitments related to the Zuidwending and JemGum gas storages sites in the
Netherlands for €286 million.
13.3.4 Other information
Borrowing costs for 2021 included in the cost of property, plant and equipment amounted to €109 million at
December 31, 2022 compared to €70 million at December 31, 2021.
13.4 Impairment testing of goodwill, intangible assets and property, plant

and equipment
Risk of impairment
Goodwill
Goodwill is not amortized but is tested for impairment each year in accordance with IAS 36, or more frequently where
an indication of impairment is identified. All goodwill are tested for impairment based on data at the end of June,
supplemented by a review of events in the second half.
Impairment tests are carried out at the level of cash-generating units (CGUs) or groups of CGUs, which constitute groups
of assets which generate cash flows that are largely independent from cash flows generated by other CGUs.
Goodwill is impaired if the net carrying amount of the CGU (or group of CGUs) to which the goodwill is allocated is
greater than the recoverable amount of that CGU.
Impairment losses in relation to goodwill cannot be reversed and are shown as “Impairment losses” in the income
statement.
Intangible assets and property, plant and equipment
In accordance with IAS 36, impairment tests are carried out on items of property, plant and equipment and intangible
assets where there is an indication that the assets may be impaired. Such indications may be based on events or
(1) Investment commitments made by the Group to purchase property, plant and equipment as of December 31, 2021, have been adjusted
for double counting.

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changes in the market environment, or on internal sources of information. Intangible assets that are not amortized are
tested for impairment annually.
Property, plant and equipment and intangible assets with finite useful lives are only tested for impairment when there is
an indication that they may be impaired. This is generally the result of significant changes in the environment in which
the assets are operated or when economic performance is lower than expected.
Items of property, plant and equipment and intangible assets are tested for impairment at the level of the cash-generating
unit (CGU), as appropriate and determined in accordance with IAS 36. If the recoverable amount of an asset is lower
than its carrying amount, the carrying amount is written down to the recoverable amount by recording an impairment
loss. Upon recognition of an impairment loss, the depreciable amount and possibly the useful life of the asset concerned
is revised.
Impairment losses recorded in relation to property, plant and equipment or intangible assets may be subsequently
reversed if the recoverable amount of the asset increases to exceed the carrying amount. The increased carrying
amount of an item of property, plant or equipment following the reversal of an impairment loss may not exceed the
carrying amount that would have been determined (net of depreciation/amortization) had no impairment loss been
recognized in prior periods.
Indicators of impairment
The main indicators of impairment used by the Group are:
• using external sources of information
− a decline in an asset’s value over the period that is significantly more than would be expected from the
passage of time or normal use;
− significant adverse changes that have taken place over the period, or will take place in the near future, in
the technological market, economic or legal environment in which the entity operates or in the market to
which an asset is dedicated;
− an increase over the period in market interest rates or other market rates of return on investments if such
increase is likely to affect the discount rate used in calculating an asset’s value in use and decrease its
recoverable amount materially;
− the carrying amount of the net assets of the entity exceeds its market capitalization;
• using internal sources of information
− evidence of obsolescence or physical damage to an asset;

− significant changes in the extent to which, or manner in which, an asset is used or is expected to be used,
that have taken place in the period or soon thereafter and that will adversely affect it. These changes include
the asset becoming idle, plans to dispose of an asset sooner than expected, reassessing its useful life as
finite rather than indefinite or plans to restructure the operations to which the asset belongs;
− internal reports that indicate that the economic performance of an asset is, or will be, worse than expected.
Measurement of recoverable amount
For operating entities which the Group intends to hold on a long-term and going concern basis, the recoverable amount
of a CGU corresponds to the higher of its fair value less costs to sell and its value in use. Value in use is primarily
determined based on the present value of future operating cash flows including a terminal value. Standard valuation
techniques are used based on the following main economic assumptions:
• market perspectives and developments in the regulatory framework;

• discount rates based on the specific characteristics of the operating entities concerned;
• terminal values in line with available market data specific to the operating segments concerned and growth rates
associated with these terminal values, not exceeding the inflation rate.

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Discount rates are determined on a post-tax basis and applied to post-tax cash flows. The recoverable amounts
calculated on the basis of these discount rates are the same as the amounts obtained by applying the pre-tax discount
rates to cash flows estimated on a pre-tax basis, as required by IAS 36.
For operating entities which the Group has decided to sell, the related recoverable amount of the assets concerned is
based on market value less disposal costs. Where negotiations are ongoing, this value is determined based on the best
estimate of their outcome as of the reporting date.
13.4.1 General assumptions
The impairment tests were performed in the context of a highly volatile economic environment, as described in
Note 1.3 “Use of estimates and judgments”.
In most cases, the recoverable amounts are determined by reference to a value in use that is calculated using cash flow
projections drawn up on the basis of the 2023 budget and the 2024-2025 medium term business plan, as approved by the
Executive Committee and the Board of Directors, and on the basis of extrapolated cash flows beyond that time frame.
Cash flow projections are determined on the basis of macroeconomic assumptions (inflation, exchange rates and growth
rates), and price forecasts resulting from the Group’s reference scenario for 2026-2050 as revised and validated by the
Executive Committee in October 2022. The forecasts and projections included in the reference scenario were determined
on the basis of the following inputs:
• forward market prices over the liquidity period for fuel (coal, oil and gas), CO 2 and electricity on each market
against a backdrop of highly volatile energy prices;
• beyond this period, medium- and long-term energy prices were determined by the Group based on macroeconomic
assumptions and fundamental supply and demand equilibrium models, the results of which are regularly compared
against forecasts prepared by external energy sector specialists. Long-term projections for CO2 prices are in line
with the 2030 emissions reduction target of 55% and the 2050 climate neutrality objectives set by the European
Commission as part of the "European Green Deal" presented in December 2019 and July 2021. Among the
external scenarios, the Group's scenario is similar to that of the International Energy Agency, with its APS
(Announced Pledges Scenario) model, and that of ADEME ("green technology");
• more specifically, medium- and long-term electricity prices were determined by the Group using electricity demand
forecasting models, medium- and long-term forecasts of fuel and CO2 prices, and expected trends in installed
capacity and in the technology mix of the production assets within each power generation system. ENGIE has
opted for a balanced mix, integrating renewable gas and carbon dioxide capture and storage in order to guarantee
an energy system with the best levels of efficiency and resilience. This trajectory has been included in the Group’s
report as part of the "Task Force on Climate Related Financial Disclosures" (TCFD) initiative. The risk factors
arising from climate and environmental issues are also detailed in the Group's Universal Registration Document.
13.4.2 Renewables
At December 31, 2022, goodwill amounted to €2,110 million, intangible assets to €1,305 million and property, plant and
equipment to €14,679 million. Renewables comprises all centralized renewable energy generation activities, including
financing, construction, operation and maintenance of renewable energy facilities, using various energy sources such as
hydroelectric, onshore wind, photovoltaic solar, biomass, offshore wind, and geothermal. The energy produced is fed into
the grid and sold either on the open or regulated market or to third parties through electricity sale agreements.
The main assumptions and key estimates relate primarily to discount rates, assumptions as to the renewal of the
hydropower concession agreements and changes in electricity prices beyond the liquidity period.
Value in use of the Compagnie Nationale du Rhône and SHEM was calculated based on assumptions including the
extension or renewal of a tender process for the concession agreements, as well as on the conditions of a potential
extension.

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The cash flows for the periods covered by the renewal of the concession agreements are based on a number of
assumptions relating to the economic and regulatory conditions for operating these assets (royalty rates, required level of
investment, etc.) during this period.
In 2022, the discount rates applied to these activities ranged between 4.5% and 10.2%. In 2021, these rates ranged
between 4.5% and 10%.
Results of the impairment tests
At December 31, 2022, no impairment losses were recognized on goodwill in consideration of the recoverable amount of
the cash generating unit to which it belongs.
However, impairment losses totaling €232 million were recognized during the year on property, plant and equipment,
notably in Latin America for €135 million and in North America for €82 million.
Sensitivity analyses
A decrease of €10/MWh in electricity prices for hydropower generation would have a negative €0.4 billion impact on the
recoverable amount. However, the recoverable amount of goodwill would remain above the carrying amount. Conversely,
an increase of €10/MWh in electricity prices would have a positive €0.3 billion impact on the recoverable amount.
An increase of 50 basis points in the discount rates used for hydropower generation activities in France would have a
negative €0.3 billion impact on the recoverable amount. However, the recoverable amount of goodwill would remain above
the carrying amount. A reduction of 50 basis points in the discount rates used would have a positive €0.3 billion impact on
the recoverable amount.
13.4.3 Networks
Networks comprises the Group’s electricity and gas infrastructure activities and projects. These activities include the
management and development of (i) gas and electricity transportation networks and natural gas distribution networks in
and outside of Europe, (ii) underground natural gas storage in Europe, and (iii) regasification infrastructure in France and
Chile.
Apart from the historical infrastructure management activities, its asset portfolio also contributes to the challenges of the
energy transition and network greening (biomethane, hydrogen, etc.).
equipment to €29,942 million. Regulated infrastructure assets in France amounted to €940 million for intangible assets
and €26,369 million for property, plant and equipment.
The valuation of activities in France is mainly based on cash flow projections determined on the basis of tariffs negotiated
with the French energy regulator (CRE) and terminal values corresponding to the expected value of the Regulated Asset
Base (RAB). The RAB is the value assigned by the CRE to the assets operated by distributors. It is the sum of the future
pre-tax cash flows, discounted at the pre-tax rate of return guaranteed by the regulator.
In respect of the valuation of activities in France, the energy mix scenario for 2050, adopted by the Group and detailed in
Note 17.3.1 “Dismantling obligations arising on non-nuclear plant and equipment”, will not lead to any significant change
in RAB. Given the vital role of gas, a reliable energy source able to supplement renewable energy sources that are
intermittent by nature, non-controllable and difficult to store, the Group is planning to maintain or convert its gas network
infrastructures to allow for the transport of green gases (biomethane, hydrogen, etc.), wich will progressively replace natural
gas.
To achieve this, the Group plans to maintain its current level of investment. This approach is largely supported by a rapidly
developing legal framework supporting the rise in the use of hydrogen (and to a certain extent, biomethane) in the European
Union, which will result in concrete European targets, for hydrogen at least. This legal framework should be in place within
the next two years.

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France's political and social strategy concerning the energy transition aims to achieve carbon neutrality by 2050. The
priorities of the French climate and energy policy are being updated with France's future roadmap Stratégie Française sur
l’Énergie et le Climat (SFEC) (see Note 17.3.1 “Dismantling obligations arising on non-nuclear plant and equipment”). This
future policy could have an impact on the role and scope of gas infrastructures in France.
In 2022, the discount rates applied to all these activities ranged between 4.7% and 8.5%. In 2021, they ranged between
4.5% and 8.5%.
However, impairment losses totaling €65 million were recognized during the year on property, plant and equipment, notably
in Germany.
Sensitivity analysis
Given the regulated nature of the Networks business in France, as well as the progressive transition from natural gas to
green gas, a reasonable change in any of the valuation inputs (discount rate, inflation rate and rate of return on assets)
would not result in any impairment losses. A very substantial change in the regulatory framework could have a significant
impact on the valuation of gas infrastructure assets in France. In this respect, the 2022 RAB of Networks assets in France,
as well as the related depreciation and amortization charges, are as follows:
Depreciation
and
In millions of euros 2022 RAB amortization
GRDF 16,137 (990)
GRTgaz 9,047 (540)
Storengy 3,958 (147)
Elengy 900 (56)
13.4.4 Energy Solutions
equipment to €2,496 million.
Energy Solutions encompasses the construction and management of decentralized energy networks to produce low-
carbon energy (heating and cooling networks, distributed power generation plants, distributed solar power parks, low-
carbon mobility, low-carbon cities and public lighting, etc.) and related services (energy efficiency, technical maintenance,
sustainable development consulting).
The terminal value used to calculate the value in use of the services and energy sales businesses in France was
determined by extrapolating the cash flows beyond the medium-term business plan period using a long-term growth rate
of 2% per year.
The main assumptions and key estimates relate primarily to discount rates and changes in price beyond the liquidity period.
In 2022, the discount rates applied to these activities ranged between 4.9% and 8.9%. In 2021, they ranged between 4.5%
and 8.6%

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mainly in connection with renegotiations of contracts due to expire shortly in France.
Given the essentially contractual nature of Energy Solutions activities, a reasonable change in any of the valuation inputs
would not result in impairment losses on goodwill.
13.4.5 Thermal
At December 31, 2022, goodwill amounted to €1,152 million, intangible assets to €237 million and property, plant and
Thermal encompasses all the Group’s centralized power generation activities using thermal assets, whether contracted or
not. It includes the operation of power plants fueled mainly by gas or coal, as well as pump-operated storage plants. The
energy produced is fed into the grid and sold either on the open or regulated market or to third parties through electricity
sale agreements. It also includes the financing, construction and operation of desalination plants, whether or not connected
to power plants.
The value in use of these activities was calculated using the cash flow projections drawn up on the basis of the 2023
budget and the 2024-2025 medium-term business plan. Beyond this three-year period, cash flows were projected over the
useful lives of the assets based on the reference scenario adopted by the Group.
The main assumptions and key estimates relate primarily to discount rates, estimated demand for electricity and changes
in the price of CO2, fuel and electricity beyond the liquidity period. These assumptions also concern the duration of tax
measures involving inframarginal rent caps in France and Italy.
In 2022, the discount rates applied to these activities ranged between 6% and 10.3%. In 2021, they ranged between 6%
and 10%.
mainly in connection with the ongoing coal exit program which is scheduled to be completed by 2027 at the latest.
An increase of 50 basis points in the discount rates used would have a negative 1% impact on the excess of the recoverable
amount of thermal power plants in France, Belgium, the Netherlands and Spain over their carrying amount. However, the
recoverable amount of goodwill would remain above the carrying amount. A reduction of 50 basis points in the discount
rates used would have a positive 1% impact on the calculation.
A 10% decrease in the margin captured by thermal power plants in France, Belgium, the Netherlands and Spain would
have a negative impact of 5% on the excess of the recoverable amount of goodwill over the carrying amount. An increase
of 10% in the margin captured would have a positive 5% impact on this calculation.
13.4.6 Supply
At December 31, 2022, goodwill amounted to €1,830 million, intangible assets to €682 million and property, plant and
equipment to €119 million.
Supply encompasses all the Group's activities relating to the sale of gas and electricity to end customers. It also includes
all the Group’s activities in services for residential clients.

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The terminal value used to calculate the value in use of the main services and energy sales businesses in Europe was
determined by extrapolating cash flows beyond the medium-term business plan period using a long-term growth rate of
approximately 2% per year.
In 2022, the discount rates applied to these activities ranged between 7.8% and 10%. In 2021, they ranged between 7%
and 9%
However, impairment losses totaling €53 million were recognized during the year on property, plant and equipment in
connection with the geographic refocusing decided by the Group.
Given the capital-light nature of Supply activities, a reasonable change in any of the valuation inputs would not result in
impairment losses on goodwill.
13.4.7 Nuclear
At December 31, 2022, goodwill amounted to €797 million, intangible assets to €1,075 million and property, plant and
Nuclear encompasses the power generation activities from the Group's nuclear power plants in Belgium and drawing rights
on the Chooz B and Tricastin power plants in France.
Key assumptions used for the impairment test
The cash flow projections for these activities are based on a large number of key assumptions, such as prices of fuel and
CO2, expected trends in electricity demand and prices, availability of power plants, the market outlook, and changes in the
regulatory environment (especially concerning nuclear capacities in Belgium, the extension of drawing rights agreements
for French nuclear plants and the tax measures involving inframarginal rent caps). Lastly, the key assumptions also include
the discount rate used to calculate the value in use of these activities, which amounted to 7% for 2022, unchanged from
2021.
Cash flow projections for the period beyond the medium-term business plan were determined as described below:
Activities Assumptions applied beyond the term of the business plan

Drawing rights on Chooz B and Cash flow projection over the remaining term of existing contract plus the assumption that drawing rights will be
Tricastin power plants extended for a further 10 years.
As regards second-generation reactors, the principle of a gradual phase-out of nuclear power and the schedule for this
phase-out, with the shutdown of Doel 3 in 2022, Tihange 2 in 2023 and Tihange 3 and Doel 4 in 2025, after 40 years of
operation, were first set out in the law of January 31, 2003 on the gradual phase-out of nuclear power for industrial electrical
generation, and were reaffirmed in the Belgian government's general policy memorandum of November 4, 2020. However,
this principle remained subject to analysis mechanisms enabling this decision to be reassessed based on its impacts on
the security of supply, the climate, energy prices and the security of power plants subject to a monitoring process.
In March 2022, the Belgian government announced that it was considering extending the operation of certain nuclear plants
beyond 2025. On July 21, 2022, the Group signed a non-binding letter of intent to assess the feasibility and conditions
regarding an extension of the operating lives of the Doel 4 and Tihange 3 reactors.

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Under the terms of the non-binding agreement signed on January 9, 2023, the Belgian government and ENGIE have
committed to making best efforts to extend the operating life of the second-generation nuclear reactors Doel 4 and
Tihange 3, and to restart these units in November 2026 with a total production capacity of 2 GW.
Given the stage of negotiations and the lack of precise information on the economic conditions of this extension to date,
the period of extension beyond 2025 was not considered in the impairment tests performed at December 31, 2022.
In France, the Nuclear Safety Authority authorized the start-up of Tricastin 1 on December 20, 2019 after its shutdown for
its fourth 10-yearly inspection and, on December 3, 2020, published a draft decision setting out the conditions for the
900 MW reactors to continue operating beyond 40 years. Confirmation of a 10-year extension of the operating life of the
900 MW series reactors is therefore expected to be formalized in the next few years, once the conditions for continued
operation have been determined by the Nuclear Safety Authority and a public inquiry has been held. The Group has
therefore considered the 10-year extension of the nuclear units, and the corresponding drawing rights, beyond their fourth
10-yearly outage. The last ten-yearly outage at Tricastin (VD4) has taken place in 2021, and in 2019 for Chooz B (VD3).
The assumption of an extension was already considered in previous years.
Results of the impairment test
Taking into account the effects of the triennial review of nuclear provisions on assets to be recognized against
decommissioning provisions of nuclear power plants, the Group recognized an impairment loss of €1,219 million relating
to decommissioning assets for the year.
The recoverable amount of the Nuclear assets remains above the value of goodwill, particularly due to the excess value
attached to the plants in France.
A decrease of €10/MWh in electricity prices for nuclear power generation beyond the forward period would lead to a
decrease of €0.4 billion in the recoverable amount, but without any impairment of goodwill.
An increase of 50 basis points in the discount rates would lead to a decrease of €0.1 billion in the recoverable amount with
non-material impairment losses on the Belgian plants.
A 5% decrease in availability of all Belgian nuclear power plants would lead to an impairment loss of around €0.3 billion
on the Belgian plants. A similar decrease for the French plants would lead to a decrease of €0.2 billion in the recoverable
amount, but without any impairment.
13.4.8 Other
The goodwill allocated to the Other segment amounted to €350 million at December 31, 2022. The Other segment
encompasses energy management and optimization activities, the BtoB supply activities in France of Entreprises &
Collectivités (E&C), and the Corporate and holding activities.
For the Other segment, a significant headroom exists between the recoverable amount and the carrying amount for
operating activities to which goodwill is allocated at December 31, 2022.

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104
NOTE 14 FINANCIAL INSTRUMENTS
14.1 Financial assets
In accordance with the principles of IFRS 9 – Financial Instruments, financial assets are recognized and measured
either at amortized cost, at fair value through equity or at fair value through profit or loss based on the following two
criteria:
• a first criterion relating to the contractual cash flow characteristics of the financial asset. The analysis of
contractual cash flow characteristics makes it possible to determine whether these cash flows are “only
payments of principal and interest on the outstanding amounts” (known as the “SPPI” test or Solely Payments
of Principal and Interest);
• a second criterion relating to the business model used by the Group to manage its financial assets. IFRS 9
defines three different business models: a first business model whose objective is to hold assets in order to
collect contractual cash flows (hold to collect), a second model whose objective is achieved by both collecting
contractual cash flows and selling financial assets (hold to collect and sell), and other business models.
The identification of the business model and the analysis of the contractual cash flow characteristics require judgment
to ensure that the financial assets are classified in the appropriate category.
Where the financial asset is an investment in an equity instrument and is not held for trading, the Group may irrevocably
elect to present the gains and losses on that investment in other comprehensive income.
Except for trade receivables, which are measured at their transaction price in accordance with IFRS 15, financial assets
are measured, on initial recognition, at fair value plus, in the case of a financial asset not at fair value through profit or
loss, transaction costs that are directly attributable to their acquisition.
At the end of each reporting period, financial assets measured using the amortized cost method or at fair value through
other comprehensive income (with a recycling mechanism) are subject to an impairment test based on the expected
credit losses method.
Financial assets also include derivatives that are measured at fair value in accordance with IFRS 9.
In accordance with IAS 1, the Group presents current and non-current assets and current and non-current liabilities
separately in the statement of financial position. In view of the majority of the Group's activities, it was considered that
the criterion to be used to classify assets is the expected time to realize the asset or settle the liability: the asset is
classified as current if this period is less than 12 months and as non-current if it is more than 12 months after the
reporting period.

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The following table presents the Group’s different categories of financial assets, broken down into current and non-current
items:
Dec. 31, 2022 Dec. 31, 2021

Non- Non-
In millions of euros Notes current Current Total current Current Total
Other financial assets 14.1 10,599 2,394 12,992 10,949 2,495 13,444
Equity instruments at fair value through other comprehensive
income 1,217 ‐ 1,217 2,344 ‐ 2,344
Equity instruments at fair value through income 278 ‐ 278 483 ‐ 483
Debt instruments at fair value through other comprehensive
income 2,128 290 2,418 2,157 104 2,261
Debt instruments at fair value through income 1,178 568 1,745 1,794 395 2,189
Loans and receivables at amortized cost 5,798 1,537 7,334 4,171 1,996 6,167
Trade and other receivables 7.2 ‐ 31,310 31,310 ‐ 32,555 32,555
Assets from contracts with customers 7.2 9 12,575 12,584 34 8,344 8,377
Cash and cash equivalents ‐ 15,570 15,570 ‐ 13,890 13,890
Derivative instruments 14.4 33,134 15,252 48,386 25,616 19,373 44,989
TOTAL 43,741 77,102 120,843 36,599 76,657 113,256
14.1.1 Other financial assets
14.1.1.1 Equity instruments at fair value
Equity instruments at fair value through other comprehensive income (OCI)
Under IFRS 9 an irrevocable election can be made to present subsequent changes in the fair value of an investment in
an equity instrument that is not held for trading in other comprehensive income. This choice is made on an instrument
by instrument basis. Amounts presented in other comprehensive income should not be transferred to profit or loss
including proceeds of disposals. However, IFRS 9 authorizes the transfer of the accumulated profits and losses to
another component of equity. Dividends from such investments are recognized in profit or loss unless the dividend
clearly represents the recovery of a portion of the cost of the investment.
The equity instruments recognized under this line item mainly concern investments in companies that are not controlled
by the Group and for which OCI measurement has been selected given their strategic and long-term nature.
Upon initial recognition, these equity instruments are recognized at fair value, which is generally their acquisition cost,
plus transaction costs.
At each reporting date, for listed securities, fair value is determined based on the quoted market price at the reporting
date. For unlisted securities, fair value is measured using valuation models based primarily on the latest market
transactions, the discounting of dividends or cash flows and the net asset value.
Equity instruments at fair value through profit or loss
Equity instruments that are held for trading or for which the Group has not elected for measurement at fair value through
other comprehensive income are measured at fair value through profit or loss.
This category mainly includes investments in companies not controlled by the Group.
Upon initial recognition, these equity instruments are recognized at fair value, which is generally their acquisition cost.
At each reporting date, for listed and unlisted securities, the same measurement method as described above should be
applied.

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Equity instruments
at fair value
through other Equity instruments
comprehensive at fair value
In millions of euros income through income Total
AT DECEMBER 31, 2021 2,344 483 2,827
Increase 213 93 306
Decrease (647) (263) (910)
Changes in fair value (686) (15) (701)
Changes in scope of consolidation, translation adjustments and other (7) (20) (27)
AT DECEMBER 31, 2022 1,217 278 1,495
Dividends 12 3 15
Equity instruments break down as €875 million of listed equity instruments (€1,750 million at December 31, 2021) and
€620 million of unlisted equity instruments (€1,077 million at December 31, 2021). This amount includes in particular the
minority interest held by the Group in Nord Stream AG, now valued at €90 million, down €474 million compared to
December 31, 2021. This decrease is a result of damage to the pipeline and due to the heightened risk profile of
Nord Stream’s single customer, Gazprom. This change in fair value does not affect the income statement, as it is recorded
as a reduction in other items of the statement of comprehensive income. The decrease notably includes the disposal of
the remaining 1.8% interest in SUEZ for a negative €227 million.
14.1.1.2 Debt instruments at fair value
Debt instruments at fair value through other comprehensive income
Financial assets that are held within a business model whose objective is achieved by both collecting contractual cash
flows and selling financial assets and for which the contractual terms give rise on specified dates to cash flows that are
solely payments of principal and interest on the outstanding amount (SPPI), are measured at fair value through OCI
(with a recycling mechanism). This involves a measurement through profit or loss for interest (at amortized cost using
the effective interest method), impairment and foreign exchange gains and losses, and through OCI (with a recycling
mechanism) for other gains or losses.
This category mainly includes bonds.
Fair value gains and losses on these instruments are recognized in other comprehensive income, except for the
following items which are recognized in profit or loss:
• expected credit losses and reversals;

• foreign exchange gains and losses.
When the financial asset is derecognized, the cumulative gain or loss that was previously recognized in other
comprehensive income is reclassified from equity to profit or loss.
Debt instruments at fair value through profit or loss
Financial assets whose contractual cash flows do not consist solely of payments of principal and interest on the amount
outstanding (SPPI) or that are held in view of an “other” business model are measured at fair value through profit or
loss.
The Group's investments in UCITS are accounted for in this caption. They are considered as debt instruments, according
to IAS 32 – Financial Instruments: Presentation, given the existence of an obligation for the issuer to redeem units, at
the request of the holder. They are measured at fair value through profit or loss because the contractual cash flow
characteristics do not meet the SPPI test.

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Liquid debt
instruments Liquid debt
held for cash instruments
Debt investment held for cash
instruments at purposes at Debt investment
fair value fair value instruments purposes at
through other through other at fair value fair value
comprehensive comprehensive through through
In millions of euros income income income income Total
AT DECEMBER 31, 2021 2,260 1 1,593 595 4,449
Increase 1,751 22 1,704 200 3,677
Decrease (1,207) (1) (2,040) (20) (3,269)
Changes in fair value (386) ‐ (280) (7) (673)
Changes in scope of consolidation, translation adjustments and
other ‐ (22) ‐ ‐ (22)
AT DECEMBER 31, 2022 2,418 ‐ 977 769 4,163
Debt instruments at fair value at December 31, 2022 primarily included bonds and money market funds held by Synatom
for €3,350 million (see Note 17.2.4 “Financial assets set aside to cover the future costs of dismantling nuclear facilities and
managing radioactive fissile material”) and liquid instruments deducted from net financial debt for €769 million (respectively
€3,806 million and €596 million at December 31, 2021).
14.1.1.3 Loans and receivables at amortized cost
Loans and receivables held by the Group under a business model consisting in holding the instrument in order to collect
the contractual cash flows, and whose contractual cash flows consist solely of payments of principal and interest on the
principal amount outstanding (SPPI test) are measured at amortized cost. Interest is calculated using the effective
interest method.
The following items are recognized in profit or loss:
• interest income using the effective interest method;

• expected credit losses and reversals;
• foreign exchange gains and losses.
The Group has entered into concession agreements with certain public authorities under which the construction,
extension or improvement of infrastructure is carried out in return for an unconditional right to receive payment from the
concession holder in cash or other financial assets. In this case, the Group recognizes a financial receivable from the
concession holders.
The Group has entered into services or take-or-pay contracts that are, or contain, a lease and under which the Group
acts as lessor and its customers as lessees. Leases are analyzed in accordance with IFRS 16 in order to determine
whether they constitute an operating lease or a finance lease. Whenever the terms of the lease transfer substantially all
the risk and rewards of ownership of the related asset, the contract is classified as a finance lease and a finance
receivable is recognized to reflect the financing deemed to be granted by the Group to the customer.
Leasing security deposits are presented in this caption and recognized at their nominal value.
Please refer to Note 15 “Risks arising from financial instruments” regarding the assessment of counterparty risk.

108
Dec. 31, 2022 Dec. 31, 2021

In millions of euros Non-current Current Total Non-current Current Total
Loans granted to affiliated companies and other debt
instruments at amortized cost 3,583 427 4,010 2,267 195 2,462
Other receivables at amortized cost 261 734 995 240 1,537 1,777
Amounts receivable under concession contracts 1,564 187 1,751 1,200 123 1,324
Amounts receivable under finance leases 390 189 579 463 141 604
TOTAL 5,798 1,537 7,334 4,171 1,996 6,167
Loans granted to affiliated companies and other debt instruments at amortized cost include the cash of the debt instruments
held by Synatom to be invested for €2,270 million (€167 million at December 31, 2021) (see Note 17.2.4. “Financial assets
set aside to cover the future costs of dismantling nuclear facilities and managing radioactive fissile material”).
Amounts receivable under concession contracts amounted to €1,751 million at December 31, 2022. They are related to
the Novo Estado and Gralha Azul electric power transmission networks in Brazil.
Impairment and expected credit losses against loans and receivables at amortized cost stood at €1,294 million at
December 31, 2022 (versus €228 million at December 31, 2021), and include the impairment of the loan relating to the
financing of the Nord Stream 2 pipeline project for €987 million (see Note 15.2.2.1 “Loans and receivables at amortized
cost” and Note 10 “Net financial incole/(loss)”)
Other net gains and losses recognized in the income statement relating to loans and receivables at amortized cost break
down as follows:
Post-acquisition measurement
Foreign currency Expected credit
In millions of euros Interest income translation loss
At December 31, 2022 211 (64) (6)
At December 31, 2021 223 (15) (7)
Amounts receivable under finance leases
These contracts refer to lease contracts in which ENGIE acts as lessor, classified as finance leases in accordance with
IFRS 16. They relate to energy purchase and sale contracts where the contract conveys an exclusive right to use a
production asset, and certain contracts with industrial customers relating to assets held by the Group.
The Group has recognized finance lease receivables, notably for cogeneration plants for Wapda and NTDC
(Uch - Pakistan).

Undiscounted future minimum lease payments 758 713
Unguaranteed residual value accruing to the lessor 12 11
TOTAL GROSS INVESTMENT IN THE LEASE 770 724
Unearned financial income 47 56
NET INVESTMENT IN THE LEASE (STATEMENT OF FINANCIAL POSITION) 723 668
Of which present value of future minimum lease payments 718 660
Of which present value of unguaranteed residual value 5 9
Undiscounted minimum lease payments receivable under finance leases can be analyzed as follows:

Year 1 137 122
Years 2 to 5 inclusive 376 351
Beyond year 5 245 240
TOTAL 758 713

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14.1.2 Trade and other receivables, assets from contracts with customers
Information on trade and other receivables and assets from contracts with customers are provided in Note 7.2.”Trade and
other receivables, assets and liabilities from contracts with customers”.
14.1.3 Cash and cash equivalents
This item includes cash equivalents as well as short-term investments that are considered to be readily convertible into
a known amount of cash and where the risk of a change in their value is deemed to be negligible based on the criteria
set out in IAS 7.
Bank overdrafts are not included in the calculation of cash and cash equivalents and are recorded under “Short-term
borrowings”.
Cash and cash equivalent items are subject to impairment tests in accordance with the expected credit losses model of
IFRS 9.
“Cash and cash equivalents” totaled €15,570 million at December 31, 2022 (€13,890 million at December 31, 2021). This
item comprises standard money market funds with daily liquidity (50%), term deposits with a maturity of less than one
month (36%), and deposits with a maturity of less than three months and other products (14%).
This amount included funds related to the green bond issues, which remain unallocated to the funding of eligible projects
(see section 5 of the Universal Registration Document).
At December 31, 2022, this amount also included €12 million in cash and cash equivalents subject to restrictions
(€172 million at December 31, 2021).
Gains recognized in respect of “Cash and cash equivalents” amounted to €196 million in 2022 compared to €54 million
in 2021.
14.1.4 Transfer of financial assets
The Group carried out disposals without recourse to financial assets as part of transactions leading to full derecognition,
for an outstanding amount of €3,733 million at December 31, 2022.
14.1.5 Financial assets and equity instruments pledged as collateral for borrowings and
debt

Financial assets and equity instruments pledged as collateral 3,532 3,915
This item mainly includes the carrying amount of equity instruments pledged as collateral for borrowings and debt.

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14.2 Financial liabilities
Borrowings and other financial liabilities are measured at amortized cost using the effective interest rate method.
On initial recognition, any issue or redemption premiums and discounts and issuing costs are added to/deducted from
the nominal value of the borrowings concerned. These items are taken into account when calculating the effective
interest rate and are therefore recorded in the consolidated income statement over the life of the borrowings using the
amortized cost method.
As regards structured debt instruments that do not have an equity component, the Group may be required to separate
an “embedded” derivative instrument from its host contract. When an embedded derivative is separated from its host
contract, the initial carrying amount of the structured instrument is broken down into an embedded derivative component,
corresponding to the fair value of the embedded derivative, and a financial liability component, corresponding to the
difference between the amount of the issue and the fair value of the embedded derivative. The separation of components
upon initial recognition does not give rise to any gains or losses.
The debt is subsequently recorded at amortized cost using the effective interest method while the derivative is measured
at fair value, with changes in fair value recognized in profit or loss.
Financial liabilities are recognized either:
• as “Amortized cost liabilities” for borrowings, trade payables and other creditors, and other financial liabilities;
• as “Liabilities measured at fair value through profit or loss” for derivative financial instruments and for financial
liabilities designated as such.
The following table presents the Group’s different financial liabilities at December 31, 2022, broken down into current and
non-current items:
Dec. 31, 2022 Dec. 31, 2021

In millions of euros Notes Non-current Current Total Non-current Current Total
Borrowings and debt 14.3 28,083 12,508 40,591 30,458 10,590 41,048
Trade and other payables 14.2 ‐ 39,801 39,801 ‐ 32,822 32,822
Liabilities from contracts with 7.2 121 3,292 3,412 68 2,671 2,739
customers
Derivative instruments 14.4 39,417 11,859 51,276 24,228 22,702 46,931
Other financial liabilities 90 ‐ 90 108 ‐ 108
TOTAL 67,711 67,460 135,171 54,863 68,785 123,648
14.2.1 Trade and other payables

Trade payables 39,165 32,197
Payable on fixed assets 636 625
TOTAL 39,801 32,822
The carrying amount of these financial liabilities represents a reasonable estimate of their fair value.
The increase in trade payables is mainly due to the rise in commodity prices.

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14.2.2 Liabilities from contracts with customers
Information on liabilities from contracts with customers are provided in Note 7.2. “Trade and other receivables, assets and
liabilities from contracts with customers”.

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14.3 Net financial debt
14.3.1 Net financial debt by type
Dec. 31, 2022 Dec. 31, 2021

Non- Non-
In millions of euros current Current Total current Current Total
Borrowings and debt Bond issues 21,007 2,550 23,557 24,035 2,205 26,240
Bank borrowings 4,679 797 5,476 3,829 1,977 5,806
Negotiable commercial paper ‐ 7,386 7,386 ‐ 4,962 4,962
Lease liabilities 2,482 393 2,875 1,709 334 2,043
Other borrowings (1) (85) 768 682 885 613 1,498
Bank overdrafts and current account ‐ 615 615 ‐ 499 499
BORROWINGS AND DEBT 28,083 12,508 40,591 30,458 10,590 41,048
Other financial assets deducted from net financial
Other financial assets debt (2) (249) (1,133) (1,383) (251) (1,369) (1,621)
Cash and cash equivalents Cash and cash equivalents ‐ (15,570) (15,570) ‐ (13,890) (13,890)
Derivative instruments Derivatives hedging borrowings (3) 394 22 416 (147) (41) (187)
NET FINANCIAL DEBT 28,228 (4,174) 24,054 30,060 (4,710) 25,350
(1) This item corresponds to the revaluation of the interest rate component of debt in a qualified fair value hedging relationship for
a negative €200 million, margin calls on debt hedging derivatives carried in liabilities for €364 million and the impact of amortized
cost for €144 million (compared to, respectively, €227 million, €269 million and €99 million at December 31, 2021).
(2) This item notably corresponds to assets related to financing for €67 million, liquid debt instruments held for cash investment
purposes for €769 million and margin calls on derivatives hedging borrowings carried in assets for €547 million (compared to,
respectively, €47 million, €596 million and €977 million at December 31, 2021).
(3) This item represents the interest rate component of the fair value of derivatives hedging borrowings in a designated fair value
hedging relationship. It also represents the exchange rate and outstanding accrued interest rate components of the fair value of all
debt-related derivatives irrespective of whether or not they qualify as hedges.
The fair value of gross borrowings and debt (excluding lease liabilities) amounted to €35,179 million at December 31, 2022,
compared with a carrying amount of €37,690 million.
Financial income and expenses related to borrowings and debt are presented in Note 10 “Net financial income/(loss)”.

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14.3.2 Reconciliation between net financial debt and cash flow from (used in) financing
activities
Cash flow
from
operating
and
investing
activities
Cash and
flow change in Change in
from cash and Change scope of
Dec. 31, financing cash in fair Translation consolidation Dec. 31,
In millions of euros 2021 activities equivalents value adjustments and others 2022
Borrowings and debt Bond issues 26,240 (2,805) ‐ ‐ 218 (96) 23,557
Bank borrowings 5,806 (639) ‐ ‐ 277 32 5,476
Negotiable commercial paper 4,962 2,352 ‐ ‐ 71 ‐ 7,386
Lease liabilities(1) 2,043 (501) ‐ ‐ 38 1,295 2,875
Other borrowings 1,498 (359) ‐ (105) 30 (381) 682
Bank overdrafts and current account 499 3 ‐ ‐ 115 (3) 615

BORROWINGS AND DEBT 41,048 (1,949) ‐ (105) 749 848 40,591
Other financial Other financial assets deducted from (1,621) 187 ‐ 29 (1) 22 (1,383)
assetsand cash
Cash net financial
Cash debt
and cash equivalents (13,890) ‐ (945) ‐ (363) (371) (15,570)
equivalents
Derivative Derivatives hedging borrowings (187) (97) ‐ 525 170 5 416
instruments
NET FINANCIAL 25,350 (1,859) (945) 449 556 503 24,054
DEBTLease liabilities: the negative amount of a negative €501 million included in the “Cash flow from financing activities” column
(1)
corresponds to lease payments, excluding interest (total cash outflow for leases amounted to €552 million, of which €51 million
relating to interest).
14.3.3 Main events of the period
14.3.3.1 Impact of changes in the scope of consolidation and in exchange rates on net
financial debt
In 2022, changes in exchange rates resulted in a €556 million increase in net financial debt, including a €271 million
increase in relation to the US dollar and a €307 million increase in relation to the Brazilian real.
The extension of the Compagnie Nationale du Rhône’s concession until 2041 resulted in an increase in lease liabilities of
€850 million at December 31, 2022.
Changes in the scope of consolidation (including the cash impact of acquisitions and disposals) led to a €7,043 million
decrease in net financial debt. This change mainly reflects:
• asset disposals during the period, resulting in a €8,697 million decrease in net financial debt (see
Note 4.1 “Disposals carried out in 2022”). They mainly include:
− the disposal to Bouygues of the Group’s interest in EQUANS;

− the additional price related to the sale of part of the stake in SUEZ and the disposal of the 1.8% remaining
interest in SUEZ to VEOLIA;
− the two successive disposals of nearly 9% and then 6% of the Group’s interest in Gaztransport & Technigaz SA
(GTT) and the conversion of 96% of the bond redeemable for GTT shares (representing nearly 10% of the
company's capital);
− the disposal of the Group’s interest in geothermic assets PT SUPREME ENERGY MUARA LABOH and
RANTAU DEDAP in Indonesia;
• the change in the classification of entities under “Assets held for sale”, resulting in a €297 million decrease in net
financial debt. They include the ongoing disposal of a thermal power plant in Brazil and the unfavorable evolution
of the planned disposal of some renewable assets in Mexico (see Note 4.2 “Assets held for sale”);

114
• acquisitions carried out in 2022 which increased net financial debt by €1,951 million (see Note 4.3 “Acquisitions
carried out in 2022”).
14.3.3.2 Financing and refinancing transactions
The Group carried out the following main transactions in 2022:
ENGIE SA
• on March 9, 10 and 11, 2022 ENGIE SA drew on bilateral lines for a total amount of €1,485 million, for a one month
period. The redemption took place on April 11, 2022;
• on July 6, 2022 ENGIE SA redeemed at maturity JPY 10 billion (€71 million) worth of bonds (private placement)
with a 1.26% coupon;
• on July 20, 2022 ENGIE SA redeemed at maturity €410 million worth of bonds, with a 2.625% coupon;
• on September 27, 2022 ENGIE SA issued €650 million worth of green bonds, maturing in September, 2029,
bearing a 3.5% coupon;
• on October 10, 2022 ENGIE SA redeemed at maturity USD 750 million (€773 million) worth of bonds, with a
2.875% coupon;
• on October 18, 2022 ENGIE SA redeemed at maturity €693 million worth of bonds, with a 3.5% coupon;
• on October 24, 2022 ENGIE SA redeemed partially in advance several bonds for an aggregate nominal amount
of €1,125 million, including:
− a €220 million tranche of green bonds, maturing in March 2024, with a 0.875% coupon,
− a €396 million tranche, maturing in March 2025, with a 1.375% coupon,
− a €157 million tranche, maturing in September 2025, with a 0.875% coupon,
− a €54 million tranche, maturing in May 2026, with a 2.375% coupon,
− a €123 million tranche, maturing in March 2027, with a 0% coupon,
− a €175 million tranche, maturing in June 2027, with a 0.375% coupon;
• in November and December 2022, 96% of the bond redeemable for GTT shares was converted for €278 million.
Other Group entities
• in June 2022, Compagnie Nationale du Rhône redeemed at maturity a bank loan of €300 million, with a 0.55%
coupon;
• in May 2022, ENGIE Brasil Energia redeemed at maturity three bank loans for a total amount of €238 million;
• throughout 2022, ENGIE Energia Chile took out several bank loans for a total amount of USD 797 millions
(€748 million);
• in July 2022, ENGIE Energia Perù SA redeemed at maturity two bank loans for a total amount of €142 million, with
1.01% and 1.06% coupons;
• in August 2022, ENGIE Energia Perù SA took out a USD 264 million (€251 million) bank loan, maturing in
August 2033;

115
• in October 2022, Compagnie Nationale du Rhône redeemed at maturity a bank loan of €300 million, with an
EURIBOR 6 months plus a 0.9% spread coupon;
• throughout 2022, Compagnie Nationale du Rhône redeemed several bilateral lines for a total amount of
€525 million;
in November 2022, ENGIE Brasil Energia redeemed at maturity a bank loan of USD 200 million (€205 million),
with a 3.37% coupon.

116
14.4 Derivative instruments
Derivative financial instruments are measured at fair value. This fair value is determined on the basis of market data,
available from external contributors. In the absence of an external benchmark, a valuation based on internal models
recognized by market participants and favoring data directly derived from observable data such as OTC quotations is
used.
The change in fair value of derivative financial instruments is recorded in the income statement except when they are
designated as hedging instruments in a cash flow hedge or net investment hedge. In this case, changes in the value of
the hedging instruments are recognized directly in equity, excluding the ineffective portion of the hedges.
The Group uses derivative financial instruments to manage and reduce its exposure to market risks arising from
fluctuations in interest rates, foreign currency exchange rates and commodity prices, mainly for gas and electricity. The
use of derivative instruments is governed by a Group policy for managing interest rate, currency and commodity risks
(see Note 15 – Risks arising from financial instruments).
Derivative financial instruments are contracts (i) whose value changes in response to the change in one or more
observable variables, (ii) that do not require any material initial net investment, and (iii) that are settled at a future date.
Derivative instruments include swaps, options, futures and swaptions, as well as forward commitments to purchase or
sell listed and unlisted securities, and firm commitments or options to purchase or sell non-financial assets that involve
physical delivery of the underlying.
For purchases and sales of electricity and natural gas, the Group systematically analyzes whether the contract was
entered into in the “normal” course of operations and therefore falls outside the scope of IFRS 9. This analysis consists
firstly in demonstrating that the contract is entered into and continues to be held for the purpose of physical delivery or
receipt of the commodity in accordance with the Group’s expected purchase, sale or usage requirements for volumes
intended to be used or sold by the Group within a reasonable time frame, as part of its operations.
The second step is to demonstrate that the Group has no practice of settling similar contracts on a net basis and that
these contracts are not equivalent to written options. In particular, in the case of electricity and gas sales allowing the
buyer a certain degree of flexibility concerning the volumes delivered, the Group distinguishes between contracts that
are equivalent to capacity sales considered as transactions falling within the scope of ordinary operations and those
that are equivalent to written financial options, which are accounted for as derivative financial instruments.
Only contracts that meet all of the above conditions are considered as falling outside the scope of IFRS 9. Adequate
specific documentation is compiled to support this analysis.
Embedded derivatives
The main Group contracts that may contain embedded derivatives are contracts with clauses or options potentially
affecting the contract price, volume or maturity. This is the case primarily with contracts for the purchase or sale of
non-financial assets, whose price is revised based on an index, the exchange rate of a foreign currency or the price of
an asset other than the contract’s underlying.
An embedded derivative is a component of a hybrid (combined) instrument that also includes a non-derivative host
contract – with the effect that some of the cash flows of the combined instrument vary in a way similar to a stand-alone
derivative.
If a hybrid contract contains a host that is an asset within the scope of IFRS 9, the Group applies the presentation and
measurements requirements described in Note 18.1 to the entire hybrid contract.

117
Conversely, when a hybrid contract contains a host that is not an asset within the scope of IFRS 9, an embedded
derivative shall be separated from the host and accounted for as a derivative if, and only if:
• the economic characteristics and risks of the embedded derivative are not closely related to the economic
characteristics and risks of the host;
• a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative;
and
• the hybrid contract is not measured at fair value with changes in fair value recognized in profit or loss (i.e., a
derivative that is embedded in a financial liability at fair value through profit or loss is not separated).
Where an embedded derivative is separate from the host contract, it is measured at fair value and fair value changes
are recognized in profit or loss (except if the embedded derivative is documented in a hedge relationship).
Hedging instruments: recognition and presentation
Derivative instruments qualifying as hedging instruments are recognized in the consolidated statement of financial
position and measured at fair value. However, their accounting treatment varies according to whether they are classified
as (i) a fair value hedge of an asset or liability; (ii) a cash flow hedge, or (iii) a hedge of a net investment in a foreign
operation.
Fair value hedges
A fair value hedge is defined as a hedge of the exposure to changes in fair value of a recognized asset or liability such
as a fixed-rate loan or borrowing, or of assets, liabilities or an unrecognized firm commitment denominated in a foreign
currency.
The gain or loss from remeasuring the hedging instrument at fair value is recognized in profit or loss. The gain or loss
on the hedged item attributable to the hedged risk adjusts the carrying amount of the hedged item and is also recognized
in profit or loss even if the hedged item is in a category in respect of which changes in fair value are recognized through
other comprehensive income. These two adjustments are presented net in the consolidated income statement, with the
net effect corresponding to the ineffective portion of the hedge.
Cash flow hedges
A cash flow hedge is a hedge of the exposure to variability in cash flows that could affect the Group’s income. The
hedged cash flows may be attributable to a particular risk associated with a recognized financial or non-financial asset
or a highly probable forecast transaction.
The portion of the gain or loss on the hedging instrument that is determined to be an effective hedge is recognized
directly in other comprehensive income, net of tax, while the ineffective portion is recognized in profit or loss. The gains
or losses accumulated in equity are reclassified to the consolidated income statement under the same caption as the
loss or gain on the hedged item – i.e., current operating income for operating cash flows and financial income or
expenses for other cash flows – in the same periods in which the hedged cash flows affect income.
If the hedging relationship is discontinued, in particular because the hedge is no longer considered effective, the
cumulative gain or loss on the hedging instrument remains recognized in equity until the forecast transaction occurs.
However, if a forecast transaction is no longer expected to occur, the cumulative gain or loss on the hedging instrument
is immediately recognized in profit or loss.
Hedge of a net investment in a foreign operation
In the same way as for a cash flow hedge, the portion of the gain or loss on the hedging instrument that is determined
to be an effective hedge of the currency risk is recognized directly in other comprehensive income, net of tax, while the

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ineffective portion is recognized in profit or loss. The gains or losses accumulated in other comprehensive income are
transferred to the consolidated income statement when the investment is liquidated or sold.
Hedging instruments: identification and documentation of hedging relationships
The hedging instruments and hedged items are designated at the inception of the hedging relationship. The hedging
relationship is formally documented in each case, specifying the hedging strategy, the hedged risk and the method used
to assess hedge effectiveness. Only derivative contracts entered into with external counterparties are considered as
being eligible for hedge accounting
Hedge effectiveness is assessed and documented at the inception of the hedging relationship and on an ongoing basis
throughout the periods for which the hedge was designated.
Hedge effectiveness is demonstrated both prospectively and retrospectively using various methods, based mainly on a
comparison between changes in fair value or cash flows between the hedging instrument and the hedged item. Methods
based on an analysis of statistical correlations between historical price data are also used.
Derivative instruments not qualifying for hedge accounting: recognition and presentation
These items mainly concern derivative financial instruments used in economic hedges that have not been – or are no
longer – documented as hedging relationships for accounting purposes.
When a derivative financial instrument does not qualify or no longer qualifies for hedge accounting, changes in fair value
are recognized directly in profit or loss under (i) current operating income for derivative instruments with non-financial
assets as the underlying, and (ii) financial income or expenses for currency, interest rate and equity derivatives.
Derivative instruments not qualifying for hedge accounting used by the Group in connection with proprietary commodity
trading activities and other derivatives expiring in less than 12 months are recognized in the consolidated statement of
financial position in current assets and liabilities, while derivatives expiring after this period are classified as non-current
items.
Fair value measurement
The fair value of instruments listed on an active market is determined by reference to the market price. In this case,
these instruments are presented in level 1 of the fair value hierarchy.
The fair value of unlisted financial instruments for which there is no active market and for which observable market data
exist is determined based on valuation techniques such as option pricing models or the discounted cash flow method.
The models used to evaluate these instruments take into account assumptions based on market inputs:
• the fair value of interest rate swaps is calculated based on the present value of future cash flows;
• the fair value of forward foreign exchange contracts and currency swaps is calculated by reference to current
prices for contracts with similar maturities by discounting the future cash flow spread (difference between the
forward exchange rate under the contract and the forward exchange rate recalculated in line with the new market
conditions applicable to the nominal amount);
• the fair value of currency and interest rate options is calculated using option pricing models;
• commodity derivatives are valued by reference to listed market prices based on the present value of future cash
flows (commodity swaps or commodity forwards) and option pricing models (options), for which market price
volatility may be a factor. Contracts with maturities exceeding the depth of transactions for which prices are
observable, or which are particularly complex, may be valued based on internal assumptions;
• exceptionally, for complex contracts negotiated with independent financial institutions, the Group uses the
values established by its counterparties.
These instruments are presented in level 2 of the fair value hierarchy except when the evaluation is based mainly on
data that are not observable, in which case they are presented in level 3 of the fair value hierarchy. Most often, this is

119
the case for derivatives with a maturity that falls outside the observability period for market data relating to the underlying
or when certain inputs such as the volatility of the underlying are not observable.
Except in case of enforceable master netting arrangements or similar agreements, counterparty risk is included in the
fair value of financial derivative instrument assets and liabilities. It is calculated according to the “expected loss” method
and takes into account the exposure at default, the probability of default and the loss given default. The probability of
default is determined on the basis of credit ratings assigned to each counterparty (“historical probability of default”
approach).
Offsetting of financial assets and liabilities in the statement of financial position
Financial assets and liabilities are presented net in the statement of financial position when the offsetting criteria of
IAS 32 are met. Offsetting relates to instruments entered into with counterparties for which the contractual terms provide
for a net settlement of transactions and a collateralization agreement (margin calls). In particular, commodity derivative
assets and liabilities are offset for transactions with the same counterparty, in the same currency, by type of commodity
and delivery point and with identical maturities.
Derivative instruments recognized in assets and liabilities are measured at fair value and broken down as follows:
Dec. 31, 2022 Dec. 31, 2021

Assets Liabilities Assets Liabilities
Non- Non- Non- Non-
In millions of euros current Current Total current Current Total current Current Total current Current Total
Derivatives hedging
borrowings 226 92 319 620 114 735 370 130 501 224 89 313
Derivatives hedging
commodities 30,932 15,076 46,008 37,210 11,698 48,907 24,474 19,190 43,664 22,335 22,507 44,842
Derivatives hedging other
items (1) 1,975 84 2,059 1,587 47 1,634 772 52 824 1,670 106 1,775
TOTAL 33,134 15,252 48,386 39,417 11,859 51,276 25,616 19,373 44,989 24,228 22,702 46,931
(1) Derivatives hedging other items mainly include the interest rate component of interest rate derivatives (not qualifying as hedges or
qualifying as cash flow hedges) that are excluded from net financial debt, as well as net investment hedge derivatives.
The increase in the balance of derivatives hedging commodities is due to the extreme volatility of commodity prices in
2022. Most of these derivatives mature in 2023 and 2024. This fair value also incorporates market parameters at
December 31,2022, in particular the “bid ask” reserve, which have been updated to reflect the higher volatility of commodity
prices and the reduced liquidity in the European natural gas and electricity markets in the second half of 2022. In the main
markets where the Group operates (Europe, United States, Singapore) a 10% increase or decrease in these market
parameters (including the “bid ask” spread) would impact the fair value of the derivates concerned by a negative €143
million (increase) and a positive €143 million (decrease).

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14.4.1 Offsetting of derivative instrument assets and liabilities
The net amount of derivative instruments after taking into account enforceable master netting arrangements or similar
agreements, whether or not they are offset in accordance with paragraph 42 of IAS 32, are presented in the table below:
Dec. 31, 2022 Dec. 31, 2021
Net amount Net amount

recognized in the recognized in the
statement of Other statement of Other
Gross financial offsetting Total net Gross financial offsetting Total net
In millions of euros amount position (1) agreements (2) amount amount position (1) agreements (2) amount
Derivatives
hedging
Assets commodities 72,322 46,008 (8,866) 37,142 75,043 43,664 (9,281) 34,383
Derivatives
hedging
borrowings and
other items 2,378 2,378 (364) 2,014 1,325 1,325 (269) 1,056
Derivatives
hedging
Liabilities commodities (75,221) (48,907) 5,094 (43,813) (76,220) (44,842) 4,987 (39,855)
Derivatives
hedging
borrowings and
other items (2,369) (2,369) 547 (1,822) (2,089) (2,089) 977 (1,111)
(1) Net amount recognized in the statement of financial position after taking into account offsetting agreements that meet the criteria
set out in paragraph 42 of IAS 32. Due to the extreme volatility of commodity prices, this offsetting had a significant impact on the
statement of financial position at December 31, 2022 and mainly concerns OTC derivatives concluded with counterparties for which
the contractual terms provide for a net settlement of the transactions as well as a collateralization agreement (margin calls).
(2) Other offsetting agreements include collateral and other guarantee instruments, as well as offsetting agreements that do not meet
the criteria set out in paragraph 42 of IAS 32.

121
14.5 Fair value of financial instruments by level in the fair value hierarchy
14.5.1 Financial assets
The table below shows the allocation of financial instruments carried in assets to the different levels in the fair value
hierarchy:
Dec. 31, 2022 Dec. 31, 2021

In millions of euros Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
Other financial assets (excluding loans and receivables at 5,658 4,225 ‐ 1,433 7,276 5,556 ‐ 1,720
amortized cost)
Equity instruments at fair value through other comprehensive 1,217 875 ‐ 342 2,344 1,524 ‐ 820
income
Equity instruments at fair value through income 278 ‐ ‐ 278 483 227 ‐ 256
Debt instruments at fair value through other comprehensive 2,418 2,418 ‐ ‐ 2,261 2,254 ‐ 7
income
Debt instruments at fair value through income 1,745 933 ‐ 813 2,189 1,552 ‐ 637
Derivative instruments 48,386 138 44,730 3,518 44,989 177 41,606 3,206
Derivatives hedging borrowings 319 ‐ 319 ‐ 501 ‐ 501 ‐
Derivatives hedging commodities - relating to portfolio
management activities (1) 40,992 ‐ 40,825 168 35,381 ‐ 35,306 75
Derivatives hedging commodities - relating to trading 5,016 138 1,528 3,350 8,284 177 4,975 3,131
(1)
activities
Derivatives hedging other items 2,059 ‐ 2,059 ‐ 824 ‐ 824 ‐
TOTAL 54,044 4,363 44,730 4,951 52,266 5,734 41,606 4,926
(1) Derivative financial instruments relating to commodities classified in level 3 mainly include long-term gas supply contracts and
electricity contracts measured at fair value through profit or loss. Due to geopolitical uncertainties, the fair value of contracts with
Russian suppliers takes into account contingencies related to natural gas supply cuts.
A definition of these three levels is presented in Note 14.4 “Derivative instruments”.
Other financial assets (excluding loans and receivables at amortized cost)
Changes in level 3 equity and debt instruments at fair value can be analyzed as follows:
Equity Debt Other

instruments at instruments at Equity Debt financial
fair value fair value instruments at instruments assets
through other through other fair value at fair value (excluding
comprehensive comprehensive through through loans and
In millions of euros income income income income receivables
AT DECEMBER 31, 2021 821 7 256 637 at amortized
1,721
cost)
Acquisitions 30 16 93 205 344
Disposals (2) (1) (36) (21) (60)
Changes in fair value (1) (499) ‐ (15) (8) (521)
Changes in scope of consolidation, foreign currency translation (8) (23) (20) ‐ (51)
and other changes
AT DECEMBER 31, 2022 342 ‐ 278 813 1,433
Gains/(losses) recorded in income relating to instruments held at
the end of the period (4)
(1) Changes in fair value comprises the €474 million decrease in the value of the Group's minority interest in Nord Stream AG (see note
14.1.1.1 "Equity instruments at fair value").
Derivative instruments
Changes in level 3 commodity derivatives can be analyzed as follows:
In millions of euros Net Asset/(Liability)

AT DECEMBER 31, 2021 (210)
Changes in fair value recorded in income 3,271
Settlements (1,336)
Transfer from level 3 to levels 1 and 2 34
Net fair value recorded in income 1,759
Deferred Day-One gains/(losses) 78
AT DECEMBER 31, 2022 1,837

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14.5.2 Financial liabilities
The table below shows the allocation of financial instruments carried in liabilities to the different levels in the fair value
hierarchy:
Dec. 31, 2022 Dec. 31, 2021

In millions of euros Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
Borrowings used in designated fair value hedges 3,679 ‐ 3,679 ‐ 4,255 ‐ 4,255 ‐
Borrowings not used in designated fair value hedges 31,500 17,093 14,407 ‐ 36,875 24,262 12,613 ‐
Derivative instruments 51,276 ‐ 49,595 1,681 46,931 ‐ 43,515 3,415
Derivatives hedging borrowings 735 ‐ 735 ‐ 313 ‐ 313 ‐
Derivatives hedging commodities - relating to portfolio management
activities(1) 48,907 ‐ 47,227 1,681 35,458 ‐ 34,374 1,084
Derivatives hedging commodities - relating to trading activities(1) ‐ ‐ ‐ ‐ 9,384 ‐ 7,053 2,331

Derivatives hedging other items 1,634 ‐ 1,634 ‐ 1,775 ‐ 1,775 ‐
TOTAL 86,455 17,093 67,682 1,681 88,061 24,262 60,383 3,415
(1) Derivative financial instruments relating to commodities classified in level 3 mainly include long-term gas supply contracts and
electricity contracts measured at fair value through profit and loss. Due to geopolitical uncertainties, the fair value of contracts with
Russian suppliers takes into account a risk of supply cuts.
A definition of these three levels is presented in Note 14.4 “Derivative instruments”.
Borrowings used in designated fair value hedges
This caption includes bonds in a designated fair value hedging relationship, which are presented in level 2 in the above
table. Only the interest rate component of the bonds is remeasured, with fair value determined by reference to observable
inputs.
Borrowings not used in designated fair value hedges
Listed bond issues are included in level 1.
Other borrowings not used in a designated hedging relationship, are presented in level 2 in the above table. The fair value
of these borrowings is determined on the basis of future discounted cash flows and relies on directly or indirectly observable
data.

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NOTE 15 RISKS ARISING FROM FINANCIAL INSTRUMENTS
The Group mainly uses derivative instruments to manage its exposure to market risks. Financial risk management
procedures are set out in Chapter 2 “Risk factors” of the Universal Registration Document.
15.1 Market risks
15.1.1 Commodity risk
Commodity risk arises primarily from the following activities:
• portfolio management; and

• trading.
The Group has primarily identified two types of commodity risks: price risk resulting from fluctuations in market prices, and
volume risk inherent to the business.
In the ordinary course of its operations, the Group is exposed to commodity risks on natural gas, electricity, coal, oil and
oil products, other fuels, CO2 and other “green” products. The Group is active on these energy markets either for supply
purposes, or to optimize and secure its energy production chain and its energy sales. The Group also uses derivatives to
offer hedging instruments to its clients and to hedge its own positions.
15.1.1.1 Portfolio management activities
Portfolio management seeks to optimize the market value of assets (power plants, gas and coal supply contracts, energy
sales and gas storage and transportation) over various timeframes (short-, medium- and long-term). Market value is
optimized by:
• guaranteeing supply and ensuring the balance between physical needs and resources;
• managing market risks (price, volume) to unlock optimum value from portfolios within a specific risk framework.
The risk framework aims to safeguard the Group’s financial resources over the budget period and smooth out
medium-term earnings (over three or five years, depending on the maturity of each market). It encourages portfolio
managers to take out economic hedges on their portfolio.
Sensitivities of the commodity-related derivatives portfolio used as part of the portfolio management activities at
December 31, 2022 are detailed in the table below. Due to the significant increase and volatility of commodity prices on
the markets, particularly over the past several months in the European zone, the price assumptions for natural gas and
electricity in Europe have been revised upwards for 2022. These sensitivities have been established in the current
uncertain context.
These new assumptions do not constitute an estimate of future market prices and are not representative of future changes
in consolidated earnings and equity, insofar as they do not include the sensitivities relating to the purchase and sale
contracts for the underlying commodities, which are not recognized at fair value.

124
Sensitivity analysis (1)
Dec. 31, 2022 Dec. 31, 2021

Pre-tax impact on Pre-tax impact on Pre-tax impact on Pre-tax impact on
In millions of euros Changes in price income equity income equity
Oil-based products +USD 10/bbl ‐ 81 19 159
Natural gas - Europe (2) -€10/MWh (700) (1,237) N/A N/A
Natural gas - Europe (2) +€10/MWh 700 1,237 246 588
Natural gas - Rest of the world (2) +€3/MWh 29 206 52 35
Electricity - Europe (2) -€20/MWh (51) 245 N/A N/A
Electricity - Europe (2) +€20/MWh 51 (245) (73) (49)
Electricity - Rest of the world (2) +€5/MWh (122) ‐ (37) ‐
Greenhouse gas emission rights +€2/ton 24 1 (134) ‐
EUR/USD +10% 36 (186) 16 83
EUR/GBP +10% (17) (34) (49) (6)
(1) The sensitivities shown above apply solely to financial commodity derivatives used for hedging purposes as part of the portfolio
management activities.
(2) In 2021, the impact corresponded to a sensitivity of +€3/MWh for gas and +€5/MWh for electricity. For December 2022 and in
relation to the sensitivities shown, more drastic upward and downward price changes, although difficult to quantify, could occur
depending how the economic or political situation evolves. For example, an increase (decrease) of €50/MWh for natural gas and
€100/MWh for electricity would impact sensitivities by a positive €9.7 billion (a negative €9.7 billion) and a negative €1 billion (a
positive €0.9 billion), respectively for natural gas and electricity.
The significant increase in commodity prices in 2022 contributed to substantial changes in the fair value of financial
instruments, impacting the income statement (see Note 8 “Operating expenses”) as well as the other comprehensive
income for the Group (see “Statement of comprehensive income”).
15.1.1.2 Trading activities
Revenues from trading activities totaled €4,499 million in 2022 (€1,011 million in 2021).
The Group’s trading activities are primarily conducted within:
• ENGIE Global Markets and ENGIE Energy Management. The purpose of these wholly-owned companies is to
(i) assist Group entities in optimizing their asset portfolios; and (ii) create and implement energy price risk
management solutions for internal and external customers;
• ENGIE SA for the optimization of part of its long-term gas supply contracts, of a power exchange contract and of
part of its gas sales contracts with retail entities in France and Benelux and with power generation facilities in
France and Belgium.
These entities operate on organized or OTC markets in derivative instruments such as futures, forwards, swaps, or options.
Exposure to trading activities is strictly controlled by daily monitoring of compliance with Value at Risk (VaR) limits.
The use of VaR to quantify market risk arising from trading activities provides a transversal measure of risk, taking all
markets and products into account. VaR represents the maximum potential loss on a portfolio over a specified holding
period based on a given confidence interval. It is not an indication of expected results but is back-tested on a regular basis.
The Group uses a one-day holding period and a 99% confidence interval to calculate VaR, as well as stress tests,
in accordance with banking regulatory requirements.
The VaR shown below corresponds to the global VaR of the Group’s entities with trading activities. The increase in VaR
reflects the exceptional increase and significant volatility in commodity market prices in 2022.
Value at Risk
In millions of euros Dec. 31, 2022 2022 average(1) 2022 maximum(2) 2022 minimum(2) 2021 average(1)
Trading activities 28 33 143 6 10
(1) Average daily VaR.
(2) Maximum and minimum daily VaR observed in 2022.

125
VaR limits are set within the framework of Group governance, which was strengthened during the year to take account of
the extremely volatile market environment. These limits have been revised upwards and any excesses have been reported
in accordance with the market risk control process, which may have led to the closure or reduction of certain positions, the
limitation of new positions or the revision of the portfolio allocation.
The continuous monitoring of market risks and the strict application of these measures have enabled the Group to perform
its trading activities in a supervised environment during the year. At December 31, 2022, VaR had fallen below its limit.
The increasing average VaR in 2022 reflects extreme market conditions applied to lower positions than in 2021.
15.1.2 Hedges of commodity risks
Hedging instruments and sources of hedge ineffectiveness
The Group enters into cash flow hedges, using derivative instruments (firm or option contracts) contracted over the counter
or on organized markets, to reduce its commodity risks, which relate mainly to future cash flows from contracted or
expected sales and purchases of commodities. These instruments may be settled net or involve physical delivery of the
underlying.
Sources of hedge ineffectiveness are mainly related to uncertainty regarding the timing and potential mismatches in
settlement dates, in a context of highly volatile commodity market prices; and indices between the derivative instruments
and the associated underlying exposures.
The fair values of commodity derivatives are indicated in the table below:
Dec. 31, 2022 Dec. 31, 2021

Non- Non- Non- Non-
In millions of euros current Current current Current current Current current Current
Derivative instruments relating to portfolio
management activities 30,932 10,060 (37,210) (11,698) 24,474 10,906 (22,335) (13,123)
Cash flow hedges 3,538 4,400 (2,483) (4,140) 2,643 5,141 (1,533) (3,796)
Other derivative instruments 27,394 5,660 (34,726) (7,558) 21,831 5,765 (20,802) (9,327)
Derivative instruments relating to trading
activities ‐ 5,016 ‐ ‐ ‐ 8,284 ‐ (9,384)
TOTAL 30,932 15,076 (37,210) (11,698) 24,474 19,190 (22,335) (22,507)
The fair values shown in the table above reflect the amounts for which assets could be exchanged, or liabilities settled, at
the end of the reporting period. They are not representative of expected future cash flows insofar as positions
(i) are sensitive to changes in prices; (ii) can be modified by subsequent transactions; and (iii) can be offset by future cash
flows arising on the underlying transactions.
15.1.2.1 Cash flow hedges
The fair values of cash flow hedges by type of commodity are as follows:
Dec. 31, 2022 Dec. 31, 2021

Non- Non- Non- Non-
Natural gas 3,204 3,825 (1,825) (3,149) 2,194 4,792 (1,044) (2,971)
Electricity 114 324 (208) (521) 195 171 (215) (439)
Oil 219 248 (449) (470) 246 176 (274) (386)
Other (1) 1 3 (1) 1 9 2 ‐ ‐
TOTAL 3,538 4,400 (2,483) (4,140) 2,643 5,141 (1,533) (3,796)
(1) Mainly includes foreign currency hedges on commodities.

126
Notional amounts (net) (1)
Notional amounts and maturities of cash flow hedges are as follows:
Total at
Beyond 5 Dec. 31,
Unit 2023 2024 2025 2026 2027 years 2022
Natural gas GWh 158,983 68,913 19,053 (412) 6,002 ‐ 252,539
Electricity GWh (7,447) (3,226) (835) (465) (457) (649) (13,079)
Oil-based products Thousands of barrels (11,913) (11,768) ‐ ‐ ‐ ‐ (23,681)
Forex Millions of euros 2 ‐ ‐ ‐ ‐ ‐ 2
Greenhouse gas emission rights Thousands of tons 105 80 86 20 ‐ ‐ 291
(1) Long/(short) position.
Effects of hedge accounting on the Group’s financial position and performance
Dec. 31, 2022 Dec. 31, 2021

Fair Value Nominal Fair value Nominal
In millions of euros Assets Liabilities Total Total Total Total
Cash flow hedges 7,939 (6,623) 1,315 39,983 2,455 15,590
TOTAL 7,939 (6,623) 1,315 39,983 2,455 15,590
The fair values represented above are positive for assets and negative for liabilities.
Change in the
value of the Ineffective Amount
Change in fair value hedging instrument portion reclassified from
In millions Nominal Fair used for calculating recognized in recognized in the hedge reserve Line item of
of euros amount Value hedge effectiveness equity (1) profit or loss (1) to profit or loss (1) profit or loss
Cash Current
flow Hedging operating
hedges instruments 39,983 1,315 (1,747) 189 (3,003) income
Hedged
items (4,067)
(1) Gains/(losses).
Hedge inefficiency, the amount of wich in 2022 is affected by the extreme volatility of commodity prices during the year
and the partial decorrelation of the various markets particularly in Europe, is calculated based on the change in the fair
value of the hedging instrument compared to the change in the fair value of the hedged items since inception of the hedge.
The fair value of the hedging instruments at December 31, 2022 reflects the cumulative change in the fair value of the
hedging instruments since inception of the hedges.
Maturity of commodity derivatives designated as cash flow hedges
In millions of euros 2023 2024 2025 2026 2027 Beyond 5 years Dec. 31, 2022 Dec. 31, 2021
Fair Value of derivatives by maturity 503 645 224 (37) (11) (9) 1,315 2,455
Amounts presented in the statement of changes in equity and the statement of comprehensive income
The following table provides a reconciliation of each component of equity and an analysis of other comprehensive income:
Cash flow hedge
In millions of euros Derivatives hedging commodities
AT DECEMBER 31, 2021 4,094
Effective portion recognized in equity (1,770)
Amount reclassified from hedge reserve to profit or loss (3,023)
Translation differences ‐
Changes in scope of consolidation and other ‐
AT DECEMBER 31, 2022 (699)

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15.1.2.2 Other commodity derivatives
Other commodity derivatives include:
• commodity purchase and sale contracts that were not entered into or are no longer held for the purpose of the
receipt or delivery of commodities in accordance with the Group’s expected purchase, sale or usage requirements;
• embedded derivatives; and
• derivative financial instruments that are not eligible for hedge accounting in accordance with IFRS 9 or for which
the Group has elected not to apply hedge accounting.
15.1.3 Currency risk
The Group is exposed to currency risk, defined as the impact on its statement of financial position and income statement
of fluctuations in exchange rates affecting its operating and financing activities. Currency risk comprises (i) transaction risk
arising in the ordinary course of business, (ii) specific transaction risk related to investments, mergers and acquisitions or
disposal projects, and (iii) translation risk arising from the conversion into euros of income statement and statement of
financial position items from subsidiaries with a functional currency other than the euro. The main translation risk exposures
correspond, to assets in US dollars, Brazilian real and pounds sterling.
15.1.3.1 Financial instruments by currency
The following tables present a breakdown by currency of outstanding borrowings and debt and net financial debt, before
and after hedging:
15.1.3.2 Currency risk sensitivity analysis
A sensitivity analysis to currency risk on financial income/(loss) – excluding the income statement translation impact of
foreign subsidiaries – was performed based on all financial instruments managed by the treasury department and
representing a currency risk (including derivative financial instruments).
A sensitivity analysis to currency risk on equity was performed based on all financial instruments qualified as net investment
hedges at the reporting date.
For currency risk, sensitivity corresponds to a 10% rise or fall in exchange rates of foreign currencies against the euro
compared to closing rates.

128
Dec. 31, 2022

Impact on income Impact on equity
In millions of euros +10%(1) -10%(1) +10%(1) -10%(1)

Exposures denominated in a currency other than the functional currency of companies carrying the
liabilities on their statements of financial position(2) (19) 19 NA NA
Financial instruments (debt and derivatives) qualified as net investment hedges(3) NA NA 426 (426)
(1) +(-)10%: depreciation (appreciation) of 10% of all foreign currencies against the euro.
(2) Excluding derivatives qualified as net investment hedges.
(3) This impact is countered by the offsetting change in the net investment hedged.
15.1.4 Interest rate risk
The Group seeks to manage its borrowing costs by limiting the impact of interest rate fluctuations on its income statement.
The Group’s policy is therefore to arbitrate between fixed rates, floating rates and capped floating rates for its net debt.
The interest rate mix may shift within a range defined by Group Management in line with market trends.
In order to manage the interest rate structure for its net debt, the Group uses hedging instruments, particularly interest rate
swaps and options.
The Group has a forward interest rate pre-hedges portfolio on 2027 and 2028, with a 20-year maturity on each of the
volumes initiated, to protect the refinancing interest rate on a portion of its debt.
15.1.4.1 Analysis of financial instruments by type of interest rate
The following tables present a breakdown by type of interest rate of outstanding borrowings and debt and net financial
debt before and after hedging:
15.1.4.2 Interest rate risk sensitivity analysis
Sensitivity was analyzed based on the Group’s net debt position (including the impact of interest rate and foreign currency
derivatives relating to net debt) at the reporting date.
For interest rate risk, sensitivity corresponds to a 100-basis-point rise or fall in the yield curve compared to year-end interest
rates.
Dec. 31, 2022
Impact on income Impact on equity
In millions of euros +100 basis points -100 basis points +100 basis points -100 basis points
Net interest expense on floating-rate net debt (nominal
amount) and on floating-rate leg of derivatives (16) 16 NA NA
Change in fair value of derivatives not qualifying as (123) 135 NA NA
hedges
Change in fair value of derivatives qualifying as cash
flow hedges NA NA 198 (323)

129
15.1.5 Currency and interest rate hedges
15.1.5.1 Currency risk management
Foreign currency exchange risk (or “FX” risk) is reported and managed based on a Group-wide approach, reflected in a
policy approved by Group Management. The policy distinguishes between the three following main sources of currency
risk:
• Regular transaction risk
Regular transaction risk corresponds to the potential negative financial impact of currency fluctuations on business
and financial operations denominated in a currency other than the functional currency.
The management of regular transaction risk is fully delegated to the subsidiaries for their scope of activities, while
the risks related to central activities are managed at corporate level.
FX risks related to operational activities are systematically hedged when the related cash flows are certain, with a
hedging horizon that corresponds at least to the medium-term plan horizon. For cash flows that are not certain, in
their entirety, the hedge is initially based on a “no regret” volume. Exposures are monitored and managed based
on the sum of nominal cash flows in FX, including highly probable amounts and related hedges.
For FX risks related to financial activities, all significant exposures related to cash, financial debt, etc. are
systematically hedged. Exposures are monitored based on the net sum of balance sheet items in FX.
• Project transaction risk
Specific project transaction risk corresponds to the potential negative financial impact of FX fluctuations on specific
major operations such as investment projects, acquisitions, disposals and restructuring projects, involving multiple
currencies.
The management of these FX risks includes the definition and implementation of hedging transactions, taking into
account the likelihood of the risk (including probability of project completion) and its evolution, the availability of
hedging instruments and their associated cost. Management’s aim is to ensure the viability and the profitability of
the transactions.
• Translation risk
Translation risk corresponds to the potential negative financial impact of FX fluctuations concerning consolidated
entities with a functional currency other than the euro. It relates to the translation of their income and expenses
and their net assets.
Translation risk is managed centrally, with a focus on securing the net asset value.
The pertinence of hedging this translation risk is assessed regularly for each currency (as a minimum) or set of
assets in the same currency, taking into account notably the value of the assets and the hedging costs.
The Group principally uses the following risk management levers for mitigating currency risk:
• derivative instruments: these mostly correspond to over-the-counter contracts and include FX forward transactions,
FX swaps, currency swaps, cross currency swaps, plain vanilla FX options or combinations (calls, puts or collars);
• monetary items such as debt, cash and loans.

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Sources of hedge ineffectiveness are mainly related to uncertainty regarding the timing and in some cases the amount of
the future cash flows in foreign currency that are being hedged.
15.1.5.2 Interest rate risk management
The Group is exposed to interest rate risk through its financing and investing activities. Interest rate risk is defined as a
financial risk resulting from fluctuations in base interest rates that may increase the cost of debt and affect the viability of
investments. Base interest rates are market interest rates, such as EURIBOR, US LIBOR, etc., that do not include the
borrower’s credit spread.
Reform of interbank benchmark rates
As part of the interest rate benchmark reform, the Group benchmarked all USD denominated new financing contracts to
the SOFR index. ENGIE also plans to align its derivative contracts with the same index. However, the transition of existing
financing and derivative contracts indexed on US Libor towards SOFR will be completed by June 2023, when the
publication of US Libor is expected to end.
The Group does not expect the transition to have any impact.
The two main sources of interest rate risk are as follows:
• Interest rate risk relating to Group net debt
Interest rate risk relating to Group net debt designates the financial impact of base rate movements on the debt
and cash portfolio from recurring financing activities. This risk is mainly managed centrally.
Risk management objectives are, by order of importance:
− to protect the long-term viability of assets;

− to optimize financing costs and ensure competitiveness; and
− to minimize uncertainty on the cost of debt.
Interest rate risk is actively managed by monitoring changes in market rates and their impact on the Group’s gross
and net debt.
• Project interest rate risk
Specific project interest rate risk corresponds to the potential negative financial impact of base rate movements on
specific major operations such as investment projects, acquisitions, disposals and restructuring projects. Interest
rate risk after the closing of an operation is considered as regular (see “Interest rate risk” above).
Interest rate risk is managed for specific project transactions in order to protect the economic viability of projects,
acquisitions, disposals and restructuring initiatives against adverse changes in interest rates. It may include the
implementation of hedging transactions, depending on a number of factors including the likelihood of completion,
the availability of hedging instruments and their associated cost.
The Group principally uses the following risk management levers for mitigating interest rate risk:
• derivative instruments: these mostly correspond to over-the-counter contracts that are used to manage base
interest rates. Such instruments include:
− swaps, to change the nature of interest payments on debts, typically from fixed to floating rates or vice versa,
− plain vanilla interest rate options;

131
• caps, floors and collars that allow the impact of interest rate fluctuations to be limited by setting minimum and/or
maximum limits on floating interest rates.
Sources of hedge ineffectiveness are mainly related to changes in the credit quality of the counterparties and related
charges, as well as potential gaps in settlement dates and in indices between the derivative instruments and the related
underlying exposures.
15.1.5.3 Currency and interest rate hedges
The Group has elected to apply hedge accounting whenever possible and suitable for currency risk and interest rate risk
management purposes and also manages a portfolio of undesignated derivative instruments, corresponding to economic
hedges relating to net debt and foreign currency exposures.
The Group uses the three hedge accounting methods: cash flow hedging, fair value hedging and net investment hedging.
In general, the Group does not frequently reset hedging relationships, designate specific risk components as a hedged
item or designate credit exposures as measured at fair value through income.
The Group qualifies interest rate or cross currency swaps transforming fixed-rate debt into floating-rate debt as fair value
hedges.
Cash flow hedges are mainly used to hedge future cash flows in foreign currency, floating-rate debt as well as future
refinancing requirements.
Net investment hedging instruments are mainly FX swaps and forwards.
The fair values of derivatives (excluding commodity instruments) are indicated in the table below:
Dec. 31, 2022 Dec. 31, 2021

Non- Non- Non- Non-
Derivatives hedging borrowings 226 92 (620) (114) 370 130 (224) (89)
Fair value hedges 167 4 (394) (38) 261 97 (24) (35)
Cash flow hedges 30 5 (195) (11) 36 1 (121) (4)
Derivative instruments not qualifying for hedge
accounting 30 84 (32) (65) 73 33 (79) (51)
Derivatives hedging other items 1,975 84 (1,587) (47) 772 52 (1,670) (50)
Cash flow hedges 509 41 (222) (7) 110 9 (264) ‐
Net investment hedges 156 ‐ (1) ‐ 6 ‐ (20) ‐
Derivative instruments not qualifying for hedge
accounting 1,310 43 (1,364) (40) 656 44 (1,385) (51)
TOTAL 2,201 176 (2,208) (161) 1,142 183 (1,894) (140)
The fair values shown in the table above reflect the amounts relating to the price that would be received for the sale of an
asset or paid for the transfer of a liability between market participants in the normal course of business. They are not
representative of expected future cash flows insofar as the positions (i) are sensitive to changes in prices or to changes in
credit ratings, (ii) can be modified by subsequent transactions, and (iii) can be offset by future cash flows arising on the
underlying transactions.

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Amount, timing and uncertainty of future cash flows
The following tables provide a profile of the timing at December 31, 2022 of the nominal amount of hedging instruments:
In millions
of euros
Interest Derivative instrument Beyond 5
Buy/Sell rate type type Currency Total 2023 2024 2025 2026 2027 years
Buy Fixed CCS USD (443) (94) (117) (89) (96) ‐ (47)
GBP (1,804) ‐ ‐ ‐ ‐ ‐ (1,804)
HKD (277) ‐ ‐ ‐ ‐ (108) (168)
PEN (239) (40) (19) ‐ (61) (62) (57)
Other (602) (107) (367) (73) ‐ ‐ (54)
Sell Fixed CCS currencie
EUR 2,568 ‐ 216 75 ‐ 98 2,179
s
USD 279 47 23 ‐ 72 72 66
Floating CCS EUR 273 129 144 ‐ ‐ ‐ ‐
CCS BRL 392 93 114 90 95 ‐ ‐
In millions
of euros
Interest Derivative instrument Beyond 5
Buy/Sell rate type type Currency Total 2023 2024 2025 2026 2027 years
Sell Fixed CAP EUR 10 6 5 ‐ ‐ ‐ ‐
IRS EUR 8,089 (1,205) (480) 249 1,253 389 7,883
USD 1,963 725 12 12 725 283 205
Other 72 3 3 3 4 4 54
Floating SWAPTION currencies
EUR 1,000 ‐ ‐ ‐ ‐ ‐ 1,000
Floating IRS EUR 15,376 1,398 2,000 1,415 1,950 800 7,813
BRL 141 141 ‐ ‐ ‐ ‐ ‐
The tables presented above exclude currency derivatives (except for cross currency swaps - CCS). Their maturity dates
are aligned with those of the hedged items.
Pursuant to the FX and interest rate risk management policy, FX sensitivity is presented in Note 15.1.3.2 “Currency risk
sensitivity analysis” and the average cost of debt is 2.73% as presented in Note 10 “Net financial income/(loss)”.
Effects of hedge accounting on the Group’s financial position and performance
Currency derivatives
Dec. 31, 2022 Dec. 31, 2021

Nominal Nominal
Fair value amount Fair value amount
Cash flow hedges 28 (366) (338) 3,139 (253) 3,201
Net investment hedges 156 (1) 155 5,939 (14) 2,794
Derivative instruments not qualifying for
hedge accounting 217 (94) 123 12,007 (39) 10,166
TOTAL 401 (461) (60) 21,085 (306) 16,161
Interest rate derivatives
Dec. 31, 2022 Dec. 31, 2021

Nominal Nominal
Fair value amount Fair value amount
Fair value hedges 171 (432) (261) 5,148 299 4,203
Cash flow hedges 552 (67) 485 5,260 17 2,110
Derivative instruments not qualifying for
hedge accounting 1,247 (1,433) (186) 25,885 (710) 18,933
TOTAL 1,970 (1,932) 38 36,293 (394) 25,246

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The fair values presented in the above table are positive for an assets and negative for a liabilities.
Amount
Change in reclassified
Change in fair the value of Ineffective from the
value used for the hedging portion hedge
Nominal and calculating instrument recognized reserve to Line item of
outstanding hedge recognized in profit or profit or loss the income
In millions of euros amount Fair value (1) ineffectiveness in equity (2) loss (2) (2) statement
Hedging
Fair value instruments 5,148 (261) (261) (21) 7 NA Cost of net debt
hedges
Hedged items (3) (4) 3,821 (200) (576) NA NA
Other financial
income and
expenses /
Current
Cash flow operating
hedges income
Hedging including
instruments 8,399 147 259 (446) 9 (507) operating MtM
Hedged items (253)
Other financial
income and
expenses /
Current
Net investment operating
hedges income
Hedging including
instruments 5,939 155 194 82 NA (25) operating MtM
Hedged items (194)
(1) The adjustment of the fair value of hedged items is presented as long term and short-term borrowings and debt for a negative
amount of €200 million.
(2) Gains/(losses).
(3) The difference between the fair value used to determine the ineffective portion relating to hedging instruments and that relating to
the hedged items corresponds to the amortized cost of borrowings and debt that are part of a fair value hedge relationship.
(4) Of which €57 million relating to hedging items that are no longer adjusted as a result of disqualification as a fair value hedge.
Hedge inefficiency is calculated based on the change in the fair value of the hedging instrument compared to the change
in the fair value of the hedged items since inception of the hedge. The fair value of the hedging instruments at
December 31, 2022 reflects the cumulative change in the fair value of the hedging instruments since inception of the
hedges. For fair value hedges, the same principle applies to the hedged items.
No significant impact in terms of ineffectiveness or disqualification of certain hedges was recognized at December 31,2022.
Foreign currency and interest rate derivatives designated as cash flow hedges can be analyzed as follows by maturity
Total at Total at
Beyond 5 Dec. 31, Dec. 31,
In millions of euros 2023 2024 2025 2026 2027 years 2022 2021
Fair value of derivatives by maturity 43 13 18 12 42 19 147 (235)
date

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Amounts presented in the statement of changes in equity and the statement of comprehensive income
The following table provides a reconciliation of each component of equity and an analysis of other comprehensive income:
Cash flow hedge Net investment hedge

Derivatives hedging Derivatives hedging Derivatives hedging Derivatives hedging
borrowings - currency other items - interest other items - currency other items - currency
In millions of euros risk hedging (1) (3) rate risk hedging (1) (3) risk hedging (2) (3) risk hedging (2) (4)
AT DECEMBER 31, 2021 45 (751) 27 (371)
Effective portion recognized in equity 424 23 (82)
Amount reclassified from the hedge reserve to
profit or loss 507 ‐ 25
Translation differences ‐ ‐ ‐ ‐
Changes in scope of consolidation and other ‐ 2 (15) 42
AT DECEMBER 31, 2022 46 181 35 (386)
(1) Cash flow hedges for given periods.
(2) Cash flow hedges for given transactions.
(3) Of which a negative €86 million of cash flow hedge reserves for which hedge accounting is no longer applied.
(4) All of the reserves relate to continuing hedging relationships.
15.2 Counterparty risk
Due to its financial and operational activities, the Group is exposed to the risk of default of its counterparties (customers,
suppliers, EPC contractors, partners, intermediaries, and banks). Default could affect payments, delivery of goods and/or
asset performance.
The principles of counterparty risk management are set out in the Group counterparty risk policy, which:
• assigns roles and responsibilities for managing and controlling counterparty risk at different levels (Corporate, BU
or entity), and ensures operational procedures are in place and consistent across the Group;
• characterizes counterparty risk and the mechanisms by which it impacts the economic performance and financial
statements of the Group;
• defines indicators, reporting and control mechanisms to ensure visibility and to provide tools for financial
performance management; and
• provides guidelines on the use of mitigating mechanisms such as collateral and guarantees, which are widely used
by some businesses.
Depending on the nature of the business, the Group is exposed to different types of counterparty risk. As a result some
businesses use collateral instruments – particularly the Energy Management business, where the use of margin calls and
other types of financial collateral (standardized legal framework) is a market standard. In addition, other businesses may
request guarantees from their counterparties in certain cases (parent company guarantees, bank guarantees, etc.).
Under the new IFRS 9 standard, the Group has defined and applied a Group-wide methodology, which includes two
different approaches:
• a portfolio approach, whereby the Group determines that:

− coherent customer portfolios and sub-portfolios have to be considered (i.e., portfolios that have comparable
credit risk and/or comparable payment behavior), taking into account the following aspects:
▪ public or private counterparties,
▪ residential or BtoB counterparties,
▪ geography,
▪ type of activity,
▪ size of the counterparty, and
▪ any other aspects the Group may consider relevant,
− impairment rates must be determined based on historical aging balances and, when correlation is proven and
documentation possible, historical data must be adjusted by forward-looking elements; and

135
• an individualized approach for significant counterparties, for which the Group has set rules for defining the stage
of the concerned asset for Expected Credit Loss (ECL) calculations:
− stage 1 covers financial assets that have not deteriorated significantly since initial recognition. The ECL for
stage 1 is calculated on a 12-month basis,
− stage 2 covers financial assets for which the credit risk has significantly increased. The ECL for stage 2 is
calculated on a lifetime basis. The decision to move an asset from stage 1 to stage 2 is based on certain criteria
such as:
▪ a significant downgrade in the creditworthiness of a counterparty and/or its parent company and/or
its guarantor (if any),
▪ significant adverse change in the regulatory environment,
▪ changes in political or country-related risk, and
▪ any other aspect the Group may consider relevant.
Regarding financial assets that are more than 30 days past due, the move to stage 2 is not systematically applied
as long as the Group has reasonable and verifiable information that demonstrates that, even if payments become
more than 30 days past due, this does not represent a significant increase in the credit risk since initial recognition.
− stage 3 covers assets for which default has already been observed, such as:
▪ when there is evidence of significant and ongoing financial difficulty of the counterparty,
▪ when there is evidence of failure in credit support from a parent company to its subsidiary (in this
case the subsidiary is the Group’s at risk counterparty),
▪ when a Group entity has initiated legal proceedings against the counterparty for non-payment.
Regarding financial assets that are more than 90 days past due, the presumption can be rebutted if the Group has
reasonable and supportable information that demonstrates that even if payments become more than 90 days past
due, this does not indicate counterparty default.
The ECL formula applicable in stages 1 and 2 is ECL = EAD x PD x LGD, where:
• for 12-month ECL, Exposure At Default (EAD) equals the carrying amount of the financial asset, to which the
relevant Probability of Default (PD) and the Loss Given Default (LGD) are applied;
• for lifetime ECL, the calculation method consists in identifying changes in exposure for each year, especially the
expected timing and amount of the contractual repayments, and then applying to each repayment the relevant PD
and the LGD, and discounting the figures obtained. ECL is then the sum of the discounted figures; and
• probability of default is the likelihood of default over a particular time horizon (in stage 1, this time horizon is
12 months after the reporting period; in stage 2 this time horizon is the entire lifetime of the financial asset). This
information is based on external data from a well-known rating agency. The PD depends on the time horizon and
of the rating of the counterparty. The Group uses external ratings if they are available; ENGIE’s credit risk experts
determine an internal rating for major counterparties with no external rating.
LGD levels are notably based on Basel standards:
• 75% for subordinated assets; and

• 45% for standard assets.
For assets considered to be of strategic importance for the counterparty, such as essential public services or goods, LGD
is set at 30%.
The Group has decided that write-offs apply in the following situations:
• assets for which a legal recovery procedure is pending: these should not be written off as long as the procedure
is ongoing; and

136
• assets for which no legal recovery procedure is pending: should be written off once the trade receivable is 3 years
overdue (5 years overdue for public counterparties).
Against the backdrop of a deteriorating global economic environment, historically high energy prices and the ongoing war
in Ukraine, the Group continued to monitor cash receipts throughout the year and strengthened its monitoring of default
risk in its BtoB, BtoC and Energy Management activities.
In the context of its market activities (mainly on BtoB clients), the Group has taken into account, in the assessment of its
expected credit losses, prospective information that best reflects the situation of a series of economic sectors considered
to be the most critical. In particular, a specific adjustment of the provisioning rate for expected credit losses was made as
at December 31, 2022 on certain customers in business sectors with high energy consumption, and therefore particularly
exposed to a significant increase in commodity prices.
In addition, the risk of default on the Group's BtoC energy supply activities has so far been relatively limited, given the
introduction of government measures in some countries to limit price increases (tariff shields, energy vouchers, payment
deferral plans, etc.), as well as the existence in the Group's portfolio of customers who still have a contract with a fixed
price that was signed before the crisis.
15.2.1 Counterparty risk arising on operating activities
Counterparty risk arising on operating activities is managed via standard mechanisms such as third-party guarantees,
netting agreements and margin calls, using dedicated hedging instruments or special prepayment and debt recovery
procedures, particularly for retail customers.
Under the Group’s policy, each global business unit is responsible for managing counterparty risk, although the Group
continues to manage the biggest counterparty exposures centrally.
The credit rating of large- and mid-sized counterparties with which the Group has exposures above a certain threshold is
measured based on a specific rating process, while a simplified credit scoring process is used for commercial customers
with which the Group has fairly low exposures. These processes are based on formally documented, consistent methods
across the Group. Consolidated exposures are monitored by counterparty and by segment (credit rating, sector, etc.) using
standard indicators (payment risk, mark-to-market exposure).
GEMS' large exposures to trading counterparties and large commercial clients are regularly monitored by the Group's
governance committees.
15.2.1.1 Trade and other receivables, assets from contracts with customers
Total outstanding exposures presented in the tables below do not include impacts relating to VAT or to any other item not
subject to credit risk, which amounted to €6,084 million at December 31, 2022 (compared to €14,438 million at
December 31, 2021).
Individual approach
Dec. 31, 2022

Level 1: Level 2: Level 3: Total by
Individual low credit increased impaired Total by Investment counterparty
In millions of euros approach risk credit risk assets risk level Grade (1) Other type
Trade and other Gross 22,754 21,321 1,316 118 22,754 20,668 2,086 22,754
receivables, net Expected
credit losses (737) (533) (75) (129) (737) (452) (285) (737)
TOTAL 22,017 20,787 1,241 (11) 22,017 20,216 1,801 22,017
Assets from Gross 5,277 5,245 29 3 5,277 4,100 1,177 5,277
contracts with Expected
customers credit losses (20) (16) ‐ (4) (20) (13) (7) (20)
TOTAL 5,256 5,229 29 (1) 5,256 4,087 1,169 5,256

137
Dec. 31, 2021

Level 1: Level 2: Level 3: Total by
Individual low credit increased impaired Total by Investment counterparty
In millions of euros approach risk credit risk assets risk level Grade (1) Other type
Trade and other Gross 15,997 15,023 830 144 15,997 14,063 1,933 15,997
receivables, net Expected
credit losses (377) (237) (23) (116) (377) (174) (203) (377)
TOTAL 15,620 14,786 806 28 15,620 13,890 1,730 15,620
Assets from Gross 3,366 3,327 37 3 3,366 2,434 933 3,366
contracts with Expected
customers credit losses (12) (10) ‐ (2) (12) (8) (4) (12)
TOTAL 3,354 3,316 37 1 3,354 2,425 929 3,354
(1) Investment Grade corresponds to counterparties that are rated at least BBB- by Standard & Poor’s.
Collective approach
Dec. 31, 2022

Total past due
Collective assets at Dec.
In millions of euros approach 0 to 6 months 6 to 12 months beyond 31, 2022
Trade and other receivables, Gross 4,459 300 101 272 673
net Expected credit
losses (1,151) (19) (47) (172) (238)
TOTAL 3,308 281 54 100 435
Assets from contracts with Gross 7,370 8 ‐ 1 10
customers Expected credit
losses (27) ‐ (8) ‐ (8)
TOTAL 7,343 8 (8) 1 2
Dec. 31, 2021

Total past due
Collective assets at Dec.
In millions of euros approach 0 to 6 months 6 to 12 months beyond 31, 2021
Trade and other receivables, Gross 3,529 544 152 267 964
net Expected credit
losses (971) (21) (21) (221) (263)
TOTAL 2,558 523 132 46 701
Assets from contracts with Gross 5,042 584 5 16 604
customers Expected credit
losses (4) ‐ ‐ (1) (1)
TOTAL 5,038 584 5 15 603
15.2.1.2 Commodity derivatives
In the case of commodity derivatives, counterparty risk arises from positive fair value. Counterparty risk (CVA), which is
taken into account when calculating the fair value of these derivative instruments, is based on default probabilities whose
parameters have been updated, in a context of uncertainty, to take account of an increased risk of default.
The extreme volatility of commodity prices has not significantly changed the Group's exposure thanks to the credit quality
of its counterparties.
Dec. 31, 2022 Dec. 31, 2021

Investment Investment
In millions of euros Grade(1) Total Grade(1) Total
Gross exposure (2) 36,371 46,012 35,386 43,660
Net exposure (3) 12,434 16,124 15,796 19,089
% of credit exposure to "Investment Grade" counterparties 77.1% 82.7%
(1) Investment Grade corresponds to transactions with counterparties that are rated at least BBB- by Standard & Poor’s, Baa3 by
Moody’s, or equivalent by Dun & Bradstreet. “Investment Grade” is also determined based on an internal rating tool that has been
rolled out within the Group, and covers its main counterparties.
(2) Corresponds to the maximum exposure, i.e., the value of the derivatives shown under assets (positive fair value).
(3) After taking into account the liability positions with the same counterparties (negative fair value), collateral, netting agreements and
other credit enhancement techniques.

138
15.2.2 Counterparty risk arising on financing activities
For its financing activities, the Group has put in place procedures for managing and monitoring risk based on
(i) the accreditation of counterparties according to external credit ratings, objective market data (credit default swaps,
market capitalization) and financial structure, and (ii) counterparty risk exposure limits.
To reduce its counterparty risk exposure, the Group has drawn increasingly on a structured legal framework based on
master agreements (including netting clauses) and collateralization contracts (margin calls).
The oversight procedure for managing counterparty risk arising from financing activities is managed by a Middle Office
that operates independently of the Group’s Treasury department and reports to the Finance division.
15.2.2.1 Loans and receivables at amortized cost
The total outstanding exposures presented in the tables below do not include impacts relating to VAT or to any other item
not subject to credit risk, which amounted to €547 million at December 31, 2022 (compared to €977 million at
December 31, 2021).
Dec. 31, 2022

Level 2: Level 3: Total by
Level 1: low increased impaired Total by risk Investment counterparty
In millions of euros credit risk credit risk assets level Grade (1) Other type
Gross 6,596 274 720 7,591 3,490 4,101 7,591
Expected credit losses (99) (38) (1,154) (1,291) (158) (1,133) (1,291)
TOTAL 6,497 236 (434) 6,300 3,332 2,967 6,300
Dec. 31, 2021

Level 2: Level 3: Total by
Level 1: low increased impaired Total by risk Investment counterparty
In millions of euros credit risk credit risk assets level Grade (1) Other type
Gross 4,643 302 26 4,971 1,906 3,065 4,971
Expected credit losses (76) (36) (113) (226) (147) (79) (226)
TOTAL 4,567 265 (87) 4,745 1,759 2,986 4,745
(1) Investment Grade corresponds to counterparties that are rated at least BBB- by Standard & Poor’s.
In 2022, the Group impaired the loan related to the financing of the Nord Stream 2 pipeline project for a total amount of
€987 million (including capitalized interest).
15.2.2.2 Counterparty risk arising on investing activities and the use of derivative financial
instruments
The Group is exposed to counterparty risk arising on investments of surplus cash and from the use of derivative financial
instruments. In the case of financial instruments at fair value through income, counterparty risk arises on instruments with
a positive fair value. Counterparty risk is taken into account when calculating the fair value of these derivative instruments.
Dec. 31, 2022 Dec. 31, 2021

Non Non-
In millions of Investment Investment- Investment Investment
euros Total Grade (1) Unrated (2) Grade (2) Total Grade (1) Unrated (2) Grade (2)
Exposure 15,738 92.3% 4.5% 3.2% 14,194 85.9% 8.2% 5.9%
(1) Investment Grade corresponds to counterparties that are rated at least BBB- by Standard & Poor’s or Baa3 by Moody’s.
(2) Most of these two exposures is carried by consolidated companies that include non-controlling interests, or by Group companies
that operate in emerging countries, where cash cannot be pooled and is therefore invested locally.
Furthermore, at December 31, 2022, Crédit Agricole Corporate and Investment Bank (CACIB) is the main Group
counterparty and represents 30% of cash surpluses. This relates mainly to a depositary risk.

139
15.3 Liquidity risk
In the context of its operating activities, the Group is exposed to a risk of having insufficient liquidity to meet its contractual
obligations. As well as the risks inherent in managing working capital requirements (WCR), margin calls are required in
certain market activities, which are a way of mitigating counterparty risk on hedging instruments through the use of
collateral.
The Group has set up a committee that meets weekly and is tasked with managing and monitoring liquidity risk throughout
the Group, by maintaining a broad range of investments and sources of financing, preparing forecasts of cash investments
and divestments. ENGIE has set up a comprehensive framework to monitor and streamline cash movements related to
OTC margin calls and margin calls via clearing houses, based on the use of liquidity swaps with its key counterparties, as
well as the issuing of letters of credit. Given the current high volatility of the markets, these margin calls may have a
significant timing impact on the Group’s cash position, and the use of the two abovementionned levers has therefore been
reinforced in order to monitor the impact on its cash position. Quartely stress-tests are also performed on the margin calls
put in place when commodity, interest rate and currency derivatives are negotiated to assess the Group’s resilience in
terms of liquidity.
The Group centralizes virtually all the financing needs and cash flow surpluses of the companies it controls, as well as
most of their medium- and long-term external financing requirements. Centralization is provided by financing vehicles
(long-term and short-term) and by dedicated Group cash pooling vehicles based in France, Belgium and Luxembourg.
Surpluses held by these structures are managed in accordance with a uniform policy. In accordance with this policy,
unpooled cash surpluses are invested in instruments selected on a case-by-case basis in light of local financial market
imperatives and the financial strength of the counterparties concerned.
The succession of financial crises since 2008 and the ensuing rise in counterparty risk prompted the Group to tighten its
investment policy with the aim of keeping an extremely high level of liquidity and protecting invested capital and a daily
monitoring of performance and counterparty, allowing the Group to take immediate action where required in response to
market developments. Consequently, 81% of the cash pooled at December 31, 2022 was invested in overnight bank
deposits and standard money market funds with daily liquidity.
The Group’s financing policy is based on:
• centralizing external financing;

• diversifying sources of financing between credit institutions and capital markets;
• achieving a balanced debt repayment profile.
The Group seeks to diversify its sources of financing by carrying out public or private bond issues within the scope of its
Euro Medium Term Notes program. It also issues negotiable commercial paper in France (Negotiable European
Commercial Paper) and in the United States (U.S. Commercial Paper) as well as the issuance of deeply-subordinated
perpetual notes. As negotiable commercial paper is relatively inexpensive and highly liquid, it is used by the Group in a
cyclical or structural manner to finance its short-term cash requirements. However, the refinancing of all outstanding
negotiable commercial paper remains secured by confirmed bank lines of credit – mainly centralized – allowing the Group
to continue to finance its activities if access to this financing source were to dry up. These facilities are appropriate for the
scale of its operations and for the timing of contractual debt repayments.
The various actions carried out by the Group ensure a high and reinforced level of liquidity.

140
Diversifying sources of financing and liquidity (1)

(1) These sources of financing and liquidity do not include the deeply-subordinated perpetual notes recognized in equity (see
Note 16.2.1 “Issuance of deeply-subordinated perpetual notes”).
(2) Net amount of negotiable commercial paper.
(3) Cash corresponds to cash and cash equivalents for €15,570 million, other financial assets deducted from net financial debt for
€769 million, net of bank overdrafts and current accounts for €615 million, of which 78% was invested in the Eurozone.
At December 31, 2022, all Group entities whose debt is consolidated complied with the covenants and declarations
included in their financial documentation, except for some non-significant entities for which compliance actions are being
implemented. None of the available centralized credit lines contain a default clause linked to financial ratios or rating level.
15.3.1 Undiscounted contractual payments relating to financial activities
Undiscounted contractual payments on outstanding borrowings and debt by maturity
Beyond 5 Total at Dec. Total at Dec.

In millions of euros 2023 2024 2025 2026 2027 years 31, 2022 31, 2021
Bond issues 2,550 930 1,518 2,316 2,493 13,751 23,557 26,240
Bank borrowings 797 381 447 247 464 3,141 5,476 5,806
Negotiable commercial paper 7,386 ‐ ‐ ‐ ‐ ‐ 7,386 4,962
Lease liabilities 403 398 304 275 251 1,624 2,875 2,043
Other borrowings 140 4 2 1 2 225 374 903
Bank overdrafts and current accounts 615 ‐ ‐ ‐ ‐ ‐ 615 499
Other financial assets and cash and cash equivalents deducted from net financial debt have a liquidity of less than one
year.
Undiscounted contractual interest payments on outstanding borrowings and debt by maturity

Undiscounted contractual interest flows on
outstanding borrowings and debt 916 796 757 701 602 7,358 11,131 10,676
Undiscounted contractual payments on outstanding derivatives (excluding commodity instruments) by maturity

Derivatives (excluding commodity instruments) (15) (127) (20) (12) (10) 423 239 126

141
To better reflect the economic substance of these transactions, the cash flows linked to the derivatives recognized in assets
and liabilities shown in the table above relate to net positions.
Undiscounted contractual payments related to leases
At December 31, 2022, the Group, as lessee, was potentially exposed to future cash outflows not reflected in the
measurement of lease liabilities for €1,407 million (of which approximately 72% relate to potential cash outflows
beyond 2027). Those potential future cash outflows relate to leases not yet commenced to which the Group is committed
(real estate and LNG vessels).
In addition, the Group is also exposed to future cash outflows in the form of variable lease payments in connection with
the extension of the Rhone concession. These variable lease payments are dependent on revenue from electricity sales.
Undrawn credit facility programs

Confirmed undrawn credit facility programs 1,339 854 5,670 ‐ 4,004 644 12,511 11,961
Of these undrawn programs, an amount of €7,386 million is allocated to covering commercial paper issues.
At December 31, 2022, no single counterparty represented more than 10% of the Group’s confirmed undrawn credit lines.
15.3.2 Undiscounted contractual payments relating to operating activities
The table below provides an analysis of undiscounted fair values due and receivable in respect of commodity derivatives
recorded in assets and liabilities at the reporting date.
The Group provides an analysis of residual contractual maturities for commodity derivative instruments included in its
portfolio management activities. Derivative instruments relating to trading activities are considered to be liquid in less than
one year, and are presented under current items in the statement of financial position.
Beyond 5 Total at Dec. 31, Total at Dec. 31,

In millions of euros 2023 2024 2025 2026 2027 years 2022 2021
Derivative instruments carried in
liabilities
relating to portfolio management (11,693) (24,661) (7,271) (2,458) (1,075) (2,102) (49,260) (35,541)
activities
relating to trading activities ‐ ‐ ‐ ‐ ‐ ‐ ‐ (9,365)
Derivative instruments carried in assets
relating to portfolio management 10,035 18,122 7,860 4,323 432 202 40,975 35,368
activities
relating to trading activities 5,098 ‐ ‐ ‐ ‐ ‐ 5,098 8,304
TOTAL 3,441 (6,538) 589 1,866 (644) (1,900) (3,187) (1,234)
15.3.3 Commitments relating to commodity purchase and sale contracts entered into in
the ordinary course of business
Some Group operating companies have entered into long-term contracts, some of which include “take-or-pay” clauses.
These consist of firm commitments to purchase or sell specified quantities of gas, electricity or steam as well as related
services, in exchange for a firm commitment from the other party to deliver or purchase said quantities and services. These
contracts were documented as falling outside the scope of IFRS 9. The table below shows the main future commitments
arising from contracts entered into by GBU Renewables and GEMS (expressed in TWh).
Total at Dec. 31, Total at Dec. 31,

In TWh 2023 2024-2027 Beyond 5 years 2022 2021
Firm purchases (423) (762) (700) (1,884) (1,922)
Firm sales 435 552 256 1,243 1,421

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NOTE 16 EQUITY
NOTE 16 EQUITY
16.1 Share capital
Number of shares Value

(in millions of euros)
Additional paid-in
Total Treasury stock Outstanding Share capital capital Treasury stock
AT DECEMBER 31, 2021 2,435,285,011 (15,083,149) 2,420,201,862 2,435 26,058 (199)
Dividend paid in cash ‐ ‐ ‐ ‐ (394) ‐
Link 2022 worldwide employee ‐ 13,079,518 13,079,518 ‐ ‐ 171
share
Capital increase Link 3,081,774 ‐ 3,081,774 3 29 ‐
Capital decrease Link (3,081,774) 3,081,774 ‐ (3) (27) 40
Purchase/disposal of treasury stock ‐ (19,054,771) (19,054,771) ‐ ‐ (245)
Delivery of treasury stock (bonus) ‐ 3,446,201 3,446,201 ‐ ‐ 43
Revaluation ‐ ‐ ‐ ‐ ‐ ‐
AT DECEMBER 31, 2022 2,435,285,011 (14,530,427) 2,420,754,584 2,435 25,667 (189)
Changes in the number of shares during 2022 resulted from:
• employee share issues as part of the “Link 2022” worldwide employee share plan. All in all, 16.2 million shares
were subscribed. At December 22, 2022 the transaction resulted in the sale to employees of 13.1 million shares
purchased on the market in the fourth quarter of 2022 for €171 million and a capital increase of €32.4 million. The
latter amount is divided into a capital increase of €3.1 million and additional paid-in capital of €29.3 million;
• a capital decrease of €40.4 million by the cancellation of 3.1 million shares in the form of a capital decrease,
€10.7 million charged to consolidated reserves and €26.6 million charged to additional paid-in capital;
• the delivery of 3.4 million treasury shares as part of bonus share plans; and
• the purchase of 2.9 million of treasury shares on the market.
16.1.1 Potential share capital and instruments providing a right to subscribe for new
ENGIE SA shares
Since 2017, the Group no longer has any stock purchase or subscription option plans.
Shares to be allocated under the performance share award plans described in Note 19 “Share-based payments” are
covered by existing ENGIE SA shares.
16.1.2 Treasury stock
Treasury shares are recognized at acquisition cost and deducted from equity. Gains and losses on disposals of
treasury shares are recorded directly in equity and do not, therefore, impact income for the period.
The Group has a stock repurchase program as a result of the authorization granted to the Board of Directors by the
Ordinary and Extraordinary Shareholders’ Meeting of April 21, 2022. This program provides for the repurchase of up to
10% of the shares comprising the share capital of ENGIE SA at the date of the said Shareholders’ Meeting. The aggregate
amount of acquisitions net of expenses under the program may not exceed €7.3 billion, and the purchase price must be
less than €30 per share excluding acquisition costs.

143
NOTE 16 EQUITY
At December 31, 2022, the Group held 14.5 million treasury shares. To date, all the shares have been allocated to cover
the Group's share commitments to employees and corporate officers.
The liquidity agreement signed with an investment service provider assigns to the latter the role of operating on the market
on a daily basis, to buy or sell ENGIE SA shares, in order to ensure liquidity and an active market for the shares on the
Paris and Brussels stock exchanges. To date, the resources allocated to the implementation of this agreement amount to
€50 million.
16.2 Other disclosures concerning additional paid-in capital, consolidated

reserves and issuance of deeply-subordinated perpetual notes
(Group share)
Total additional paid-in capital, consolidated reserves and issuance of deeply subordinated perpetual notes (including net
income for the year), amounted to €34,097 million at December 31, 2022, including €25,667 million in additional
paid-in capital. Additional paid-in capital includes a portion of the cash dividend payment for 2021 in an amount of
€394 million.
Consolidated reserves include the cumulative income of the Group, the legal and statutory reserves of ENGIE SA,
cumulative actuarial gains and losses, net of tax and the change in fair value of equity instruments at fair value through
OCI.
Under French law, 5% of the net income of French companies must be allocated to the legal reserve until the latter reaches
10% of share capital. This reserve can only be distributed to shareholders in the event of liquidation. The ENGIE SA legal
reserve amounts to €244 million.
16.2.1 Issuance of deeply-subordinated perpetual notes
In October 2022, ENGIE SA carried out an early redemption of deeply subordinated perpetual notes for a total amount of
€374 million, resulting in:
• A €244 million early redemption of green deeply subordinated perpetual notes (PERP NC 04/2023, a 1.375%
coupon, ISIN code: FR0013310505), out of a residual nominal amount of €274 million. Following the redemption,
the Group, having redeemed more than 80% of this deeply subordinated perpetual debt, carried out a squeeze-
out for the remaining €30 million, paid on December 5, 2022;
• The partial early redemption of two other tranches of deeply-subordinated perpetual notes for a total amount of
€100 million, i.e. :
− €55 million (PERP NC 06/2024, a 3.875% coupon, ISIN code: FR0011942283), out of a residual nominal
amount of green deeply subordinated perpetual notes of €393 million;
− €45 million (PERP NC 07/2031, a 1.875% coupon, ISIN code: FR00140046Y4), out of a nominal amount of
€750 million.
In accordance with IAS 32 - Financial Instruments - Presentation, and given their characteristics, these instruments are
recognized in equity in the Group's consolidated financial statements.
At December 31, 2022, the outstanding nominal value of deeply subordinated perpetual notes amounted to €3,393 million
(against €3,767 million at December 31, 2021).
In 2022, the Group paid €77 million to the holders of these notes, i.e., €90 million coupons, net of €13 million early
redemption allowances received. This amount is accounted for as a deduction from equity in the Group's consolidated
financial statements; the related tax saving is accounted for in the income statement.

144
NOTE 16 EQUITY
16.2.2 Distributable capacity of ENGIE SA
ENGIE SA's distributable capacity totaled €27,365 million at December 31, 2022 (compared with €27,758 million at
December 31, 2021), including €25,667 million of additional paid-in capital.
16.2.3 Dividends
It was proposed, at the Shareholders’ Meeting convened to approve the ENGIE Group financial statements for the year
ended December 31, 2021, to pay a dividend of €0.85 per share, representing a total payout of €2,060 million based on
the number of shares outstanding at December 31, 2021. It was increased by 10% for all shares held for at least two years
on December 31, 2021 and up to the 2021 dividend payment date. Based on the number of outstanding shares on
December 31, 2021, this increase is valued at €22 million.
Proposed dividend in respect of 2022
At the Shareholders’ Meeting convened to approve the ENGIE Group financial statements for the year ended
December 31, 2022, the shareholders will be asked to approve a dividend of €1.40 per share, representing a total payout
of €3 389 million based on the number of shares outstanding at December 31, 2022. It will be increased by 10% for all
shares held for at least two years at December 31, 2022 and up to the 2022 dividend payment date. Based on the number
of outstanding shares at December 31, 2022, this increase is valued at €40 million.
Subject to approval by the Shareholders’ Meeting of Wednesday April 26, 2023, this dividend will be detached on Friday
28 April, 2023 and paid on Wednesday May 3, 2023. It is not recognized as a liability in the financial statements at
December 31, 2022, since the financial statements at the end of 2022 were presented before the appropriation of earnings.
16.2.4 Other transactions
On March 31, 2022, the Group signed an agreement to sell a 49% interest, without loss of control, in a portfolio of two wind
and one solar projects for 665 MW of renewable energy in the United States to the American group InfraRed Capital
Partners. ENGIE continues to fully consolidate these assets and to operate and maintain them. This transaction resulted
in an inflow of €224 million and a similar increase in equity.
16.3 Recyclable gains and losses recognized in equity (Group share)
All items shown in the table below correspond to cumulative gains and losses (Group share) at December 31, 2022 and
December 31, 2021, which are recyclable to income in subsequent periods.

Debt instruments (369) 9
Net investment hedges (1) (386) (371)
Cash flow hedges (excl. commodity instruments) (1) 218 (699)
Commodity cash flow hedges (1) (318) 4,383
Deferred taxes on the items above (112) (1,064)
Share of equity method entities accounted in recyclable items, net of tax (2) 300 (546)
Recyclable items relating to discontinued operations, net of tax ‐ 118
TOTAL RECYCLABLE ITEMS BEFORE TRANSLATION ADJUSTMENTS (668) 1,831
Translation adjustments (1,422) (2,136)
TOTAL RECYCLABLE ITEMS (2,090) (306)
(1) See Note 15 “Risks arising from financial instruments”.
(2) See Note 3 “Investments in equity method entities”.
16.4 Capital management
ENGIE SA seeks to optimize its financial structure at all times by pursuing an optimal balance between its economic net
debt and its EBITDA. The Group's key objective in managing its financial structure is to maximize value for shareholders

145
NOTE 16 EQUITY
and reduce the cost of capital, while ensuring that the Group has the financial flexibility required to continue its expansion.
The Group manages its financial structure and makes any necessary adjustments in light of prevailing economic
conditions. In this context, it may choose to adjust the amount of dividends paid to shareholders, reimburse a portion of
capital, carry out share buybacks (see Note 16.1.2 “Treasury stock”), issue new shares, launch share-based payment
plans, recalibrate its investment budget, or sell assets in order to scale back its net debt.
The Group's policy is to maintain an “strong investment grade” rating from the rating agencies. To achieve this, it manages
its financial structure in line with the indicators usually monitored by these agencies, namely the Group's operating profile,
financial policy and a series of financial ratios. One of the most commonly used ratios is the ratio where the numerator
includes operating cash flows less cost of debt and taxes paid, and the denominator includes adjusted net financial debt.
Net financial debt is mainly adjusted for nuclear provisions and provisions for pensions, as well as for 50% of hybrid debt
(deeply-subordinated notes). In addition, the Group has issued a guidance targeting an “economic net debt to EBITDA”
ratio less than or equal 4x.
The Group’s objectives and processes for managing capital have remained unchanged over the past few years.
ENGIE SA is not obliged to comply with any external minimum capital requirements except those provided for by law.

146
NOTE 17 PROVISIONS
NOTE 17 PROVISIONS
General principles related to the recognition of a provision
The Group recognizes a provision where it has a present obligation (legal or constructive) towards a third party arising
from past events and where it is probable that an outflow of resources will be necessary to settle the obligation with no
expected consideration in return.
A provision for restructuring costs is recognized when the general criteria for setting up a provision are met, i.e., when
the Group has a detailed formal plan relating to the restructuring and has raised a valid expectation in those affected
that it will carry out the restructuring by starting to implement that plan or announcing its main features to those affected
by it.
Provisions with a maturity of over 12 months are discounted when the effect of discounting is material. The Group’s
main long-term provisions are provisions for the back-end of the nuclear fuel cycle, provisions for dismantling facilities,
provisions for site restoration costs, and provisions for post-employment and other long-term benefits. The discount
rates used reflect current market assessments of the time value of money and the risks specific to the liability concerned.
Expenses with respect to unwinding the discount on the provision are recognized as other financial income and
expenses.
Estimates of provisions
Factors having a significant influence on the amount of provisions, and particularly, but not solely, those relating to the
back-end of the nuclear fuel cycle, to the dismantling of nuclear facilities and of gas infrastructures in France, include:
• cost estimates (notably the retained scenario for managing radioactive nuclear fuel consumed) (see Note 17.2);
• the timing of expenditure (notably, for nuclear power generation activities, the timetable for reprocessing
radioactive nuclear fuel consumed and for dismantling facilities as well as the timetable for the end of gas
operations regarding the main gas infrastructure businesses in France) (see Notes 17.2 and 17.3); and
• the discount rate applied to cash flows.
These factors are based on information and estimates deemed by the Group to be the most appropriate as of today.
Modifications to certain factors could lead to a significant adjustment in these provisions.

147
NOTE 17 PROVISIONS
Back-end of the
Post- nuclear fuel
employment and cycle and Dismantling of
other long-term dismantling of non-nuclear Other
In millions of euros benefits nuclear facilities facilities contingencies Total
AT DECEMBER 31, 2021 7,000 15,119 1,172 2,169 25,459
Additions 279 1,028 6 669 1,981
Utilizations (379) (163) (62) (630) (1,235)
Reversals (1) ‐ ‐ (41) (42)
Changes in scope of consolidation 29 ‐ (3) 46 72
Impact of unwinding discount adjustments 89 454 28 5 576
Translation adjustments 13 ‐ 14 4 32
Other (2,558) 2,579 175 (13) 184
AT DECEMBER 31, 2022 4,471 19,017 1,330 2,209 27,027
Non-current 4,393 18,594 1,329 346 24,663
Current 78 423 1 1,863 2,365
The impact of unwinding discount adjustments in respect of post-employment and other long-term benefits relates to the
interest expense on the benefit obligation, net of interest income on plan assets.
The “Other” line mainly comprises actuarial gains and losses arising on post-employment benefit obligations in 2022, which
are recorded in “Other comprehensive income” as well as provisions recorded against a dismantling or site rehabilitation
asset.
Additions, utilizations, reversals and the impact of unwinding discount adjustments are presented as follows in the
consolidated income statement:
In millions of euros Dec. 31, 2022

Income/(loss) from operating activities (738)
Other financial income and expenses (577)
TOTAL (1,315)
The different types of provisions and the calculation principles applied are described below.
17.1 Post-employment benefits and other long-term benefits
See Note 18 “Post-employment benefits and other long-term benefits”.
17.2 Obligations relating to nuclear power generation activities
In the context of its nuclear power generation activities, the Group assumes obligations related to the management of the
back-end of the nuclear fuel cycle and the dismantling of nuclear facilities.
17.2.1 Legal framework
The Belgian law of April 11, 2003, partially repealed and amended by the law of July 12, 2022, granted Group subsidiary
Synatom responsibility for managing provisions set aside to cover the costs of dismantling nuclear power plants and
managing spent fuel. The tasks of the Commission for Nuclear Provisions (CNP) set up pursuant to the above-mentioned
law is to oversee the process of computing and managing these provisions.
In accordance with the law, every three years the CNP conducts an audit of the application and adequacy of the calculation
methods used to compute nuclear provisions.
To this end, Synatom submitted its triennial report on the revaluation of nuclear provisions to the CNP on
September 2, 2022, which issued a set of remarks on December 16, 2022, confirming the reference scenarios, adding
additional costs and adjusting the discount rates. The provisions recorded as of December 31, 2022 take full account of
the comments and assumptions made by the CNP.

148
NOTE 17 PROVISIONS
However, contesting some of the CNP’s remarks as being overly conservative or technically unsuitable, the Group
submitted a new adapted proposal on February 14, 2023, in accordance with the law, explaining the reasons why it
considered that these remarks could not be implemented. The CNP will then give its final opinion, if necessary, under the
jurisdiction of the Belgian Market Court in Brussels.
In addition, with a view to a possible extension of the Doel 4 and Tihange 3 nuclear reactors, the ENGIE Group has entered
into discussions with the Belgian government on the capping of nuclear waste processing costs for ENGIE, which represent
approximately 58% of the total provisions recorded at December 31, 2022. A letter of intent between the parties was signed
on July 22, 2022, then reiterated and supplemented by a non-binding agreement in principle dated January 9, 2023. These
documents provide for broad agreements in principle by March 15 and a binding agreement by June 2023. Assuming that
the parties reach an agreement, the difference between the amount of the cap and the amount of the provisions recognized
at December 31, 2022 would constitute a liability to be recognized.
In the absence of an overarching agreement to date, the provisions recognized at December 31, 2022 do not take into
account any additional commitments or adjustments to the Group’s liabilities that may result from these discussions and
remain based on the current contractual and legal framework, which sets the operating life of the nuclear units at 50 years
for Tihange 1 and Doel 1 and 2, and at 40 years for the other units.
The provisions include in their assumptions all existing or planned environmental regulatory requirements on a European,
national and regional level. If new legislation were to be introduced in the future, the cost estimates used as a basis for the
calculations could vary.
The estimated provision amounts include margins for contingencies and other risks that may arise in connection with
dismantling and radioactive spent fuel management procedures. Contingency margins relating to the disposal of waste are
determined by the Belgian Agency for Radioactive Waste and Enriched Fissile Material (ONDRAF) and built into its fees.
The Group also estimates appropriate margins for each cost category.
The CNP’s remarks and the obligations related to projects to dispose of nuclear waste have resulted in a €3.3 billion
increase in the ENGIE Group’s nuclear liabilities, in addition to the net recurring annual expense for the year due mainly
to a decrease in the discount rate used for the provision for managing spent fuel and an increase in certain costs used to
estimate the provision for dismantling nuclear power plants.
Lastly, the amount recorded for these provisions may also be revised in the event of an agreement yet to be signed with
the Belgian government.
The breakdown of dismantling provisions between Synatom and Electrabel is shown below:
In millions of euros Current Non-current Dec. 31, 2022

Provisions for dismantling nuclear facilities – Synatom 305 8,464 8,769
Provisions for the back-end of the nuclear fuel cycle – Synatom 118 8,970 9,088
Provisions for dismantling nuclear facilities – Electrabel ‐ 1,160 1,160
TOTAL 423 18,594 19,017
17.2.2 Provisions for the back-end of the nuclear fuel cycle
Allocations to provisions for the management of spent fuel are computed based on the average unit cost of the quantities
expected to be used up to the end of the operating life of the plants, applied to quantities used at the closing date. An
annual allocation is also recognized with respect to unwinding the discount on the provisions.
When spent fuel is removed from a reactor and temporarily stored on-site, it requires conditioning, before being consigned
to long-term storage.

149
NOTE 17 PROVISIONS
The long-term disposal assumption in the scenario adopted by the CNP is based on the assumption that the waste will be
buried in a deep geological repository at a site yet to be identified and classified in Belgium. This scenario has not yet been
confirmed, as Belgium has not yet adopted a national program that complies with Article 12 of
Directive 2011/70/EURATOM. On November 27, 2019, the European Commission sent a reasoned opinion to Belgium
under the breach procedure provided for in Article 258 of the Treaty on the Functioning of the European Union. A Royal
Decree issued on October 28, 2022 has since introduced "the first part of the National Policy for the Long-Term
Management of High-Level and/or Long-Lived Radioactive Waste and specifying the process for the introduction in phases
of the other parts of this National Policy". This Royal Decree confirms that "the disposal deep underground of this waste
on Belgian territory on one or more sites" is "the preliminary draft concept for the long-term management of the radioactive
waste referred to in Article 3, pending the outcome of the decision-making process (...)". It also sets out "the reversibility
of the National Policy, which implies that, following reconsideration, one or more parts of this Policy may be reversed". It
is therefore not possible to guarantee that Belgium will retain the disposal deep underground of category B waste –
i.e., low- or medium-activity long-lived waste from dismantling - and category C waste – i.e., high-activity and/or long-lived
waste – as its technical solution of choice.
If this assumption were to be challenged, the costs of downstream management may need to be adjusted. The ENGIE
Group has also sent a formal notice to the Belgian State requesting that it put an end to the uncertainty created by this
state of affairs and to the damage caused by having postponed the various projects necessary for the management of
nuclear waste in Belgium, and reserves its right to seek compensation if necessary.
In view of a series of developments in the nuclear fuel market, Synatom has proposed, and the CNP has confirmed, that
the scenario of reprocessing a portion of fuel in order to allow for the processing of MOX fuel historically used in Belgian
power plants, in particular, could no longer be the reference scenario. Contrary to previous assessments, the reference
scenario no longer includes the cost of a reprocessing contract or the associated margins for contingencies, but includes
an assumption that MOX will be directly disposed of deep underground. Should circumstances change, the costing may
be revised.
The provisions booked by the Group for managing spent fuel cover all of the costs linked to this scenario, including on-site
storage, transportation, conditioning, storage and geological disposal. They are calculated based on the following principles
and inputs:
• storage costs primarily comprise the costs of building and operating additional dry storage facilities and operating
existing facilities, along with the costs of purchasing containers;
• radioactive spent fuel that has not been reprocessed is to be conditioned, which requires conditioning facilities to
be built according to ONDRAF’s approved criteria. ONDRAF’s recommendations as regards the cost of these
facilities have been fully taken into account;
• the cost of burying fuel in deep geological repositories is estimated using the fee rate established by ONDRAF
based on a total disposal facility cost of €12 billion;
• the long-term obligation is calculated using estimated internal costs and external costs assessed based on offers
received from third parties;
• the baseline scenario includes ONDRAF’s latest scenario, with geological storage starting in around 2070 and
ending in around 2135;
• the discount rate used by the CNP is 3.0% (including inflation of 2.0%).
The costs effectively incurred in the future may differ from the estimates in terms of their nature and timing of payment.
Certain ONDRAF recommendations that have not yet been quantified will be discussed by the CNP, which will issue an
additional opinion in 2023 if necessary.
Sensitivity
Provisions for the back-end of the nuclear fuel cycle remain sensitive to assumptions regarding costs, the timing of
operations and expenditure, as well as to discount rates:
• on the basis of an analysis carried out by ENGIE Group experts, certain remarks made by the CNP as part of the
triennial review procedure described above are considered as unjustified and have been the subject of a reasoned

150
NOTE 17 PROVISIONS
opinion sent to the CNP. The impact of taking this opinion into account (at a discount rate of 3.0% as recommended
by the CNP) would represent a decrease in provisions of €0.5 billion.
• ENGIE is also contesting the 25 basis points reduction from the previous rate and the 50 basis points reduction
from Synatom’s initial proposal. Maintaining the 3.25% rate used since 2019 would represent a decrease in
provisions of €0.7 billion.
• These various elements were the subject of a reasoned opinion sent by the ENGIE Group to the CNP on February
14, 2023, as provided for by the law of July 12, 2022.
• A 10% increase in ONDRAF’s fees above the fee for the removal of category C waste would lead to an increase
in provisions of approximately €0.3 billion based on unchanged contingency margins
17.2.3 Provisions for dismantling nuclear facilities
A provision is recognized when the Group has a present legal or constructive obligation to dismantle facilities or to
restore a site. The present value of the obligation at the time of commissioning represents the initial amount of the
provision for dismantling with, as the counterpart, an asset for the same amount, which is included in the carrying
amount of the facilities concerned. This asset is depreciated over the operating life of the facilities and is included in the
scope of assets subject to impairment tests. Adjustments to the provision due to subsequent changes in (i) the expected
outflow of resources, (ii) the timing of dismantling expenses or (iii) the discount rate, are deducted from or subject to
specific conditions, added to the cost of the corresponding asset. The impacts of unwinding the discount are recognized
in expenses for the period.
A provision is also recorded for nuclear units for which the Group holds a capacity right up to its share of the expected
dismantling costs to be borne by the Group.
Nuclear power plants have to be dismantled at the end of their operating life. Provisions are set aside in the Group’s
financial statements to cover all costs relating to (i) the shutdown phase, which involves removing radioactive spent fuel
from the site and (ii) the dismantling phase, which consists of decommissioning and cleaning up the site.
The dismantling strategy is based on the facilities being dismantled (i) immediately after the reactor is shut down, (ii) on a
mass basis rather than on a site-by-site basis, and (iii) completely, the land being subsequently returned to greenfield
status.
Provisions for dismantling nuclear facilities are calculated based on the following principles and inputs:
• the start of the technical shutdown procedures depends on the facility concerned and on the timing of operations
for the nuclear reactor as a whole. The shutdown procedures are immediately followed by dismantling operations;
• the scenario adopted is based on a dismantling program and on timetables that have to be approved by the nuclear
safety authorities. A dialogue on the safety conditions for the shutdown and dismantling phases of the power plants
has been initiated with the Belgian Federal Agency for Nuclear Control (AFCN). The costs may change depending
on the outcome of these discussions and the detailed schedule for the implementation of these phases which is
currently being defined;
• costs payable over the long term are calculated by reference to the estimated costs for each nuclear facility, based
on a study conducted by independent experts under the assumption that the facilities will be dismantled on a mass
basis. The costs effectively incurred in the future may differ from the estimates in terms of their nature and timing
of payment.
• fees for handling Class A - low or medium activity and short-lived - and B - low or medium activity and long-lived
dismantling waste are determined using the fee rate established by ONDRAF and include the margins
recommended by ONDRAF for waste reclassification risk given the uncertainty over the definition of the criteria for
classification in those classes; the difficulty in obtaining operating permits for class A waste storage led ONDRAF
to redefine a technical solution for storage and set a new assessment in 2022;

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NOTE 17 PROVISIONS
• for the various phases, margins for contingencies, reviewed by ONDRAF and the Commission for Nuclear
Provisions, are included;
• an inflation rate of 2.0% is applied until the dismantling obligations expire in order to determine the value of the
future obligation;
• the discount rate used by the CNP is 2.5% (including inflation of 2.0%).
In addition, the liabilities for the disposal of operational waste at Electrabel include the tariff update approved by the Board
of Directors of ONDRAF in May 2022.
Lastly, the Group has also set aside provisions, based on provisions for the Belgian assets most closely related to these
plants, to cover the costs relating to the final shutdown phase of its drawing rights in Tricastin and Chooz B, as well as for
the dismantling period leading to the decommissioning and clean-up of the Chooz B site, in accordance with the respective
agreements with EDF.
Sensitivity
• On the basis of an analysis carried out by ENGIE Group experts, certain remarks made by the CNP as part of the
triennial review procedure described above are considered as unjustified and have been the subject of a reasoned
opinion sent to the CNP. The impact of taking this opinion into account (at a discount rate of 2.50% as
recommended by the CNP) would represent a decrease in provisions of €0.6 billion.
• Based on currently applied inputs for estimating costs and the timing of payments, a change of 10 basis points in
the discount rate used could lead to an adjustment of approximately €85 million in dismantling provisions. A fall in
discount rates would lead to an increase in outstanding provisions, while a rise in discount rates would reduce the
provision amount.
17.2.4 Financial assets set aside to cover the future costs of dismantling nuclear facilities
and managing radioactive fissile material
17.2.4.1 Principles, objectives and governance
As indicated above, the Belgian law of July 12, 2022, partially repealing and amending the law of April 11, 2003, granted
the Group’s wholly-owned subsidiary Synatom responsibility for managing and investing funds received from operators of
nuclear power plants in Belgium and intended to cover the costs of dismantling nuclear power plants and managing spent
fuel. Pursuant to the law of April 11, 2003, Synatom could lend up to 75% of these funds to nuclear power plant operators
provided that certain credit quality criteria are met.
In accordance with the law of July 12, 2022, the amount of the outstanding loans between Synatom and the nuclear
operators representing the countervalue of the provisions for managing spent fuel will be repaid by December 31, 2025 to
Synatom according to a schedule provided for in the law. The amount of the outstanding loans between Synatom and
Electrabel representing the countervalue of the dismantling provisions will be repaid to Synatom by December 31, 2030
according to a schedule provided for in the law.
The percentage of the provisions not subject to loans to nuclear operators is invested by Synatom either in external financial
assets or in loans to legal entities meeting the "credit quality" criteria imposed by law.
Accordingly, in 2022, Synatom invested nearly €1.9 billion in such assets.
Synatom’s objective in terms of investment in these assets is to offer, in the long term and for an acceptable level of risk,
a sufficient return, in order to cover dismantling costs and the management of radioactive fissile material, under the
constraints of diversification, risk minimization and availability as defined by the law of July 12, 2022.
The Synatom Board of Directors and its Investment Committee are responsible for defining Synatom’s investment policy
after consultation with the CNP, in accordance with the law of July 12, 2022. Based on a rigorous risk control policy, the
Investment Committee oversees investment decisions, which are managed by a team headed by an investment director.

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NOTE 17 PROVISIONS
17.2.4.2 Strategic allocation and composition of financial assets
The strategic allocation of financial assets is determined on the basis of a periodic asset-liability analysis, which consists
of determining the asset categories and their respective weighting in order to meet the return objective while respecting
the risk framework identified for each type of liability.
This allocation varies according to the type of liability and the different investment horizons and discount rates. Separate
risk profiles are considered for:
• assets in relation to provisions for dismantling nuclear power plants,

• assets in relation to provisions for managing spent fuel.
The target allocation of plan assets based on the two aforementioned risk profiles is as follows:
Management of
radioactive fissile
In % material Dismantling
Shares 40% 35%
Bonds 40% 55%
Unlisted assets 20% 10%
TOTAL 100% 100%
Listed equities consist of international securities. Listed bonds consist of international sovereign bonds and international
corporate bonds. Unlisted assets consist of securities representing funds or real estate, private equity, infrastructure or
private debt investment vehicles. Investments are managed by specialized asset management companies.
Synatom believes that the inclusion of Environmental, Social and Governance (ESG) principles in investment decisions
allows for better management of non-financial risks in order to generate long-term sustainable returns. The integration of
ESG principles implies a broader consideration of the risks and opportunities that can influence financial performance. The
selection process for external managers also incorporates ESG principles.
To implement this investment policy, Synatom has an investment company with variable share capital (SICAV) under
Luxembourg law, the Nuclear Investment Fund (“NIF”), and an investment company with variable share capital under
Belgian law, the Belgian Nuclear Liabilities Fund ("BNLF").
17.2.4.3 Changes in financial assets in 2022
The value of financial assets dedicated to covering nuclear provisions amounted to €6,626 million at December 31, 2022,
and their return was -13.56% for the year. 2022 was marked by unprecedented events that greatly increased the volatility
of global equity and bond markets. The inflationary pressures that followed the Covid crisis prompted the various central
banks to carry out a series of interest rate hikes. Mixed published macroeconomic data and the war in Ukraine have
particularly impacted the equity markets, especially in Europe. All asset classes, except monetary assets, had negative
returns in 2022.

153
NOTE 17 PROVISIONS
17.2.4.4 Valuation of financial assets in 2022
Loans to entities outside the Group and other cash investments are shown in the table below:

Loans to third parties 5 8
Loan to Sibelga 5 8
Other loans and receivables at amortized cost 2,270 167
Debt instruments - restricted cash UCITS 2,270 167
Total loans and receivables at amortized cost 2,276 175
Equity and debt instruments at fair value 863 1,509
Equity instruments at fair value through other comprehensive income 24 11
Equity instruments at fair value through income 887 1,520
Debt instruments at fair value through other comprehensive income 2,418 2,254
Debt instruments at fair value through income 933 1,552
Debt instruments at fair value 3,350 3,806
Total equity and debt instruments at fair value 4,237 5,326
Derivative instruments 113 4
TOTAL (1) 6,626 5,505
(1) Not including €308 million in uranium inventories at December 31,2022 (€414 million at December 31, 2021).
Loans to legal entities outside the Group and the cash held by the Undertaking for Collective Investment in Transferable Securities
(UCITS) are presented in the statement of financial position under “Loans and receivables at amortized cost”. Bonds and associated
hedging instruments held by Synatom through the UCITS are presented under equity or debt instruments (see Note 14.1 “Financial
assets”).
The breakdown in the change in the cumulative fair value of Synatom's assets is presented as follows:
Cumulative change in the fair value of

dedicated financial assets
Equity instruments at fair value through other comprehensive income (157) 116
Debt instruments at fair value through other comprehensive income (282) 51
Debt instruments at fair value through income (52) 154
TOTAL (491) 321
Net loss for the period generated by these assets amounted to €210 million in 2022 (gain of €228 million in 2021).
Effects on the result of the return on

dedicated financial assets
Disposal proceeds 14 50
Dividends received 66 45
Interest received 7 7
Change in fair value of derivatives not designated as hedges (15) (115)
Change in fair value of dedicated assets through income (282) 241
TOTAL (210) 228
17.3 Dismantling of non-nuclear plant and equipment and site

rehabilitation
17.3.1 Dismantling obligations arising on non-nuclear plant and equipment
Certain items of plant and equipment, including conventional power stations, transmission and distribution pipelines,
storage facilities and LNG terminals, have to be dismantled at the end of their operational lives or at least safely shut down.
These obligations are the result of prevailing environmental regulations in the countries concerned, contractual

154
NOTE 17 PROVISIONS
agreements, or an implicit Group commitment. The most important issue for the Group concerns gas infrastructures in
France.
France’s political and societal guidelines for the energy transition aim to achieve carbon neutrality by 2050, by reducing
greenhouse gas emissions and promoting renewable or so-called "green" energies, particularly biomethane and hydrogen.
The various scenarios that make it possible to achieve carbon neutrality, in particular the National Low Carbon Strategy in
France, the French Environment and Energy Management Agency (ADEME) scenarios, and the "Energy Futures" study
by the electricity transmission system operator, RTE, all lead to a significant decrease in the quantities of gas consumed,
while maintaining a high number of gas connection points to manage peak electricity demand. The Group is closely
analyzing this prospect, particularly for the purpose of defining its strategy and assessing the useful life of assets and
evaluating provisions for their possible dismantling.
The future French Strategy for Energy and Climate (SFEC) will set out France’s updated roadmap to achieve carbon
neutrality by 2050 and ensure that France can adapt to the impacts of climate change. It will encompass the first five-year
programming law on energy and the climate (LPEC), which must be adopted before the end of first-half 2023 and set out
in the National Low-Carbon Strategy (SNBC, 3rd issue), the National Climate Change and Adaptation Plan (PNACC,
3rd issue) and the Long Term Energy Schedule (PPE 2024-2033), which must be adopted in the first half of 2024.
Consequently, the next five-year review of the PPE and the SNBC will be preceded for the first time by the adoption of a
programming law on energy and the climate, which will set the French policy for energy and climate’s priorities for action.
In line with the objective of carbon neutrality by 2050, the long-term scenario adopted by the Group, which governs the
implementation of its strategy, is one that combines reasonable electrification, i.e. just under 50% of final demand in 2050,
with the development of a diversified range of green gases (biomethane, synthesized e-CH4, natural gas with the
Carbon-Capture and Storage process, pure hydrogen). The scenario used by the Group is close to the ADEME’s
S3 scenario.
Due to the importance of green gases in the French energy mix scheduled for 2050 and beyond, gas infrastructures will
remain largely necessary and will be essential to provide flexibility to the energy system. The adaptation and conversion
of these infrastructures to green gas mean that they can be used in the very distant future, which means that the present
value of provisions for their dismantling is almost zero, except in the specific cases of LNG terminals and reduced operation
and non-regulated storage sites, for which provisions for dismantling amounted to €382 million at December 31, 2022 and
€402 million at December 31, 2021.
Given its time horizon and the many underlying inputs (in particular, better knowledge of the compatibility of gas
infrastructures with hydrogen, and changes in French and European public policies), the Group will continue to assess the
long-term scenario that will enable it to achieve carbon neutrality by 2050 on a regular basis. These assessments will be
accompanied by a review of the valuation of dismantling provisions.
17.3.2 Hazelwood Power Station & Mine (Australia)
The Group and its partner Mitsui announced in November 2016 their decision to close the coal-fired Hazelwood Power
Station, and cease coal extraction operations from the adjoining mine from late March 2017. The Group holds a 72%
interest in the former 1,600 MW power station and adjoining coal mine, which has been consolidated as a joint operation.
At December 31, 2022, the Group’s share (72%) of the provision covering the obligation to dismantle and rehabilitate the
mine amounted to €220 million, versus €251 million at December 31, 2021.
Dismantling and site rehabilitation work commenced in 2017 and focused on: managing site contamination; planning site
wide environmental clean-up; the demolition and dismantling of all of the site’s industrial facilities, including the former
power station; and ongoing aquifer pumping and designated earthworks within the mine to ensure mine floor and batter
stability with a view to long-term rehabilitation into a pit lake.
Several policies and laws that have a direct or indirect impact on mine rehabilitation and on the agencies that administer
them have recently been reformed. Consequently, the ultimate regulatory obligations are likely to be revised during the life
of the project and could therefore have an impact on provisions.

155
NOTE 17 PROVISIONS
The average discount rate used to determine the amount of the provisions is 4%.
The amount of the provision recognized is based on the Group’s best current estimate of the demolition and rehabilitation
costs that Hazelwood is expected to incur. However, the amount of this provision may be adjusted in the future to take into
account any changes in the key inputs.
17.4 Other contingencies
This caption essentially includes provisions for commercial litigation, tax claims and disputes (except income tax, pursuant
to IFRIC 23) as well as provisions for onerous contracts relating to storage and transport capacity reservation contracts.

156
NOTE 18 POST-EMPLOYMENT BENEFITS AND OTHER
LONG-TERM BENEFITS

LONG-TERM BENEFITS
Depending on the laws and practices in force in the countries where the Group operates, Group companies have
obligations in terms of pensions, early retirement payments, retirement bonuses and other benefit plans. Such
obligations generally apply to all employees within the companies concerned.
The Group’s obligations in relation to pensions and other employee benefits are recognized and measured in compliance
with IAS 19. Accordingly:
• the cost of defined contribution plans is expensed based on the amount of contributions payable in the period;
• the Group’s obligations concerning pensions and other employee benefits payable under defined benefit plans
are assessed on an actuarial basis using the projected unit credit method. These calculations are based on
assumptions relating to mortality, staff turnover and estimated future salary increases, as well as the economic
conditions specific to each country or entity of the Group. Discount rates are determined by reference to the
yield, at the measurement date, on investment grade corporate bonds in the related geographical area (or on
government bonds in countries where no representative market for such corporate bonds exists).
Pension commitments are measured on the basis of actuarial assumptions. The Group considers that the assumptions
used to measure its obligations are relevant and documented. However, any change in these assumptions could have
a significant impact on the resulting calculations.
Provisions are recorded when commitments under these plans exceed the fair value of plan assets. Where the value of
plan assets (capped where appropriate) is greater than the related commitments, the surplus is recorded as an asset
under “Other assets” (current or non-current).
As regards post-employment benefit obligations, actuarial gains and losses are recognized in other comprehensive
income. Where appropriate, adjustments resulting from applying the asset ceiling to net assets relating to overfunded
plans are treated in a similar way. However, actuarial gains and losses on other long-term benefits such as long-service
awards, are recognized immediately in profit or loss.
Net interest on the net defined benefit liability (asset) is presented in net financial income/(loss).
18.1 Description of the main pension plans
18.1.1 Companies belonging to the Electricity and Gas Industries sector in France
Since January 1, 2005, the CNIEG (Caisse Nationale des Industries Électriques et Gazières) has operated the pension,
disability, death, occupational accident and occupational illness benefit plans for electricity and gas industry (hereinafter
“EGI”) companies in France. The CNIEG is a social security legal entity under private law placed under the joint
responsibility of the ministries in charge of social security and the budget.
Employees and retirees of EGI sector companies have been fully affiliated to the CNIEG since January 1, 2005. The main
affiliated Group entities are ENGIE SA, GRDF, GRTgaz, Elengy, Storengy, ENGIE Thermique France, CPCU, CNR and
SHEM.
Following the funding reform of the special EGI pension plan introduced by Law No. 2004-803 of August 9, 2004 and its
implementing decrees, specific benefits (pension benefits on top of the standard benefits payable under ordinary law)
already vested at December 31, 2004 (“past specific benefits”) were allocated between the various EGI entities. Past

157
LONG-TERM BENEFITS
specific benefits (benefits vested at December 31, 2004) relating to regulated transmission and distribution businesses
(“regulated past specific benefits”) are funded by the levy on gas and electricity transmission and distribution services
(Contribution Tarifaire d’Acheminement) and therefore no longer represent an obligation for the ENGIE Group. Unregulated
past specific benefits (benefits vested at December 31, 2004) are funded by EGI sector companies to the extent defined
by Decree No. 2005-322 of April 5, 2005.
The special EGI pension plan is a legal pension plan available to new entrants.
The specific benefits vested under the plan since January 1, 2005 are wholly financed by EGI sector companies in
proportion to their respective weight in terms of payroll costs within the EGI sector.
As this plan is a defined benefit plan, the Group has set aside a pension provision in respect of specific benefits payable
to employees of unregulated activities and specific benefits vested by employees of regulated activities since
January 1, 2005. This provision also covers the Group’s early retirement obligations. The provision amount may be subject
to fluctuations based on the weight of the Group’s companies within the EGI sector.
Pension benefit obligations and other “mutualized” obligations are assessed by the CNIEG.
At December 31, 2022, the projected benefit obligation in respect of the special pension plan for EGI sector companies
amounted to €2.6 billion.
The duration of the pension benefit obligation of the EGI pension plan is 20 years.
18.1.2 Companies belonging to the electricity and gas sector in Belgium
In Belgium, the rights of employees in electricity and gas sector companies, principally Electrabel, Laborelec and some
ENGIE Energy Management Trading and ENGIE CC employee categories, are governed by collective bargaining
agreements.
These agreements, applicable to “wage-rated” employees recruited prior to June 1, 2002 and managerial staff recruited
prior to May 1, 1999, specify the benefits entitling employees to a supplementary pension equivalent to 75% of their most
recent annual income, for a full career and in addition to the statutory pension. These top-up pension payments provided
under defined benefit plans are partly reversionary. In practice, the benefits are paid in the form of a lump sum for the
majority of plan participants. Most of the obligations resulting from these pension plans are financed through pension funds
set up for the electricity and gas sector and by certain insurance companies. Pre-funded pension plans are financed by
employer and employee contributions. Employer contributions are calculated annually based on actuarial assessments.
The projected benefit obligation relating to these plans represented around 23% of total pension obligations and related
liabilities at December 31, 2022. The average duration is nine years.
"Wage-rated" employees recruited after June 1, 2002 and managerial staff (i) recruited after May 1, 1999 or (ii) having
opted for the transfer through defined contribution plans, are covered under defined contribution plans. Prior to
January 1, 2017, the law specified a minimum average annual return (3.75% on wage contributions and 3.25% on
employer contributions) when savings are liquidated.
The law on supplementary pensions, approved on December 18, 2016 and enforced on January 1, 2017 henceforth
specifies a minimum rate of return, depending on the actual rate of return of Belgian government bonds, within a range of
1.75%-3.25% (the rates are now identical for employee and employer contributions). In 2022, the minimum rate of return
stood at 1.75%.
An expense of €38 million was recognized in 2021 and 2022 in respect of these defined contribution plans.
18.1.3 Other pension plans
Most other Group companies also grant their employees retirement benefits. In terms of financing, pension plans within
the Group are almost equally split between defined benefit and defined contribution plans.

158
LONG-TERM BENEFITS
The Group’s main pension plans outside France, Belgium and the Netherlands concern:
• the United Kingdom: the large majority of defined benefit pension plans is now closed to new entrants and future
benefits no longer vest under these plans. All entities run a defined contribution scheme. The pension obligations
of International Power’s subsidiaries in the United Kingdom are covered by the special Electricity Supply Pension
Scheme (ESPS). The assets of this defined benefit scheme are invested in separate funds. Since June 1, 2008,
the scheme has been closed and a defined contribution plan has been set up for new entrants;
• Germany: the Group’s German subsidiaries have closed their defined benefit plans to new entrants and now offer
defined contribution plans;
• Brazil: ENGIE Brasil Energia operates its own pension scheme. This scheme has been split into two parts, one for
the (closed) defined benefit plan, and the other for the defined contribution plan that has been available to new
entrants since the beginning of 2005.
18.2 Description of other post-employment benefit obligations and other

long-term benefits
18.2.1 Other benefits granted to current and former EGI sector employees
Other benefits granted to EGI sector employees are:
• Post-employment benefits:
− reduced energy prices;

− end-of-career indemnities;
− bonus leave;
− death capital benefits.
• Long-term benefits:
− allowances for occupational accidents and illnesses;

− temporary and permanent disability allowances;
− long-service awards.
The Group’s main obligations are described below.
18.2.1.1 Reduced energy prices
Under Article 28 of the national statute for electricity and gas industry personnel, all employees (current and former
employees, provided they meet certain length-of-service conditions) are entitled to benefits in kind, which take the form of
reduced energy prices known as “employee rates”.
This benefit entitles employees to electricity and gas supplies at a reduced price. For retired employees, this provision
represents a post-employment defined benefit. Retired employees are only entitled to the reduced rate if they have
completed at least 15 years’ service within EGI sector companies.
In accordance with the agreements signed with EDF in 1951, ENGIE provides gas to all current and former employees of
ENGIE and EDF, while EDF supplies electricity to these same beneficiaries. ENGIE pays (or benefits from) the balancing
contribution payable in respect of its employees as a result of energy exchanges between the two utilities.
The obligation to provide energy at a reduced price to current and former employees during their retirement is measured
as the difference between the energy sale price and the preferential rate granted (including, in 2022, the impacts of the
tariff shield for electricity) and the preferential rate granted.

159
LONG-TERM BENEFITS
The provision set aside in respect of reduced energy prices stood at €2.8 billion at December 31, 2022. The duration of
the obligation is 20 years.
18.2.1.2 End-of-career indemnities
Retiring employees (or their dependents in the event of death during active service) are entitled to end-of-career
indemnities, which increase in line with the length of service within the EGI sector.
18.2.1.3 Compensation for occupational accidents and illnesses
EGI sector employees are entitled to compensation for accidents at work and occupational illnesses. These benefits cover
all employees or the dependents of employees who die as a result of occupational accidents or illnesses, or injuries
undergone on the way to work.
The amount of the obligation corresponds to the likely present value of the benefits to be paid to current beneficiaries,
taking into account any reversionary annuities.
18.2.2 Other benefits granted to employees of the gas and electricity sector in Belgium
Electricity and gas sector companies also grant other post-employee benefits such as the reimbursement of medical
expenses, electricity and gas price reductions, as well as length-of-service awards and early retirement schemes. These
benefits are not prefunded, with the exception of the special “allocation transitoire” termination indemnity, considered as
an
end-of-career indemnity.
18.2.3 Other collective agreements
Most other Group companies also grant their staff post-employment benefits (early retirement plans, medical coverage,
benefits in kind, etc.) and other long-term benefits such as jubilee and length-of-service awards.
18.3 Defined benefit plans
18.3.1 Amounts presented in the statement of financial position and statement of

comprehensive income
In accordance with IAS 19, the information presented in the statement of financial position relating to post-employment
benefit obligations and other long-term benefits results from the difference between the gross projected benefit obligation
and the fair value of plan assets. A provision is recognized if this difference is positive (net obligation), while a prepaid
benefit cost is recorded in the statement of financial position when the difference is negative, provided that the conditions
for recognizing the prepaid benefit cost are met.

160
LONG-TERM BENEFITS
Changes in provisions for pension plans, post-employment benefits and other long-term benefits, plan assets and
reimbursement rights recognized in the statement of financial position are as follows:
In millions of euros Provisions Plan assets Reimbursement rights

AT DECEMBER 31, 2021 (6,999) 72 229
Exchange rate differences (22) (2) ‐
Changes in scope of consolidation and other 109 (94) (29)
Actuarial gains and losses 2,466 308 ‐
Periodic pension cost (331) (23) 2
Contributions/benefits paid 306 55 6
AT DECEMBER 31, 2022 (4,471) 316 208
Plan assets and reimbursement rights are presented in the statement of financial position under “Other non-current assets”
or “Other current assets”.
The cost recognized for the period amounted to €354 million in 2022 (€547 million in 2021). The components of this defined
benefit cost in the period are set out in Note 18.3.3 “Components of the net periodic pension cost”.
The Eurozone represented 98% of the Group’s net obligation at December 31, 2022, (98% at December 31, 2021).
Cumulative actuarial gains and losses recognized in equity amounted to €1,400 million at December 31, 2022, compared
to €4,232 million at December 31, 2021.
Net actuarial differences arising in the period and presented on a separate line in the statement of comprehensive income
represented a net actuarial gain of €2,774 million in 2022 and a gain of €1,803 million in 2021.

161
LONG-TERM BENEFITS
18.3.2 Change in benefit obligations and plan assets
The table below shows the amount of the Group’s projected benefit obligations and plan assets, changes in these items
during the periods presented, and their reconciliation with the amounts reported in the statement of financial position:
Dec. 31, 2022 Dec. 31, 2021

Other post- Other post-
Pension employment Long-term Pension employment Long-term
benefit benefit benefit benefit benefit benefit
obligations obligations obligations obligations obligations obligations
(1) (3) Total (1) (3) Total
In millions of euros (2) (2)
A - CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit
obligation at January 1 (7,566) (4,649) (499) (12,715) (9,186) (5,167) (565) (14,919)
Service cost (229) (97) (45) (372) (353) (88) (80) (521)
Interest expense (124) (60) (6) (190) (85) (39) (3) (126)
Contributions paid (8) ‐ ‐ (8) (13) ‐ ‐ (13)
Amendments ‐ ‐ ‐ ‐ (2) ‐ ‐ (2)
Changes in scope of
consolidation 10 2 ‐ 12 1,108 4 58 1,170
Curtailments/settlements (87) ‐ ‐ (87) 13 1 ‐ 13
Financial actuarial gains
and losses 2,118 1,390 81 3,590 869 533 32 1,434
Demographic actuarial
gains and losses 8 (4) 34 39 (230) 2 11 (217)
Benefits paid 346 110 39 495 389 107 47 543
Other (of which
translation adjustments) (33) ‐ (1) (34) (78) ‐ (1) (78)
Projected benefit
obligation at December A (5,565) (3,308) (395) (9,268) (7,566) (4,649) (499) (12,715)
31
B - CHANGE IN FAIR VALUE OF PLAN ASSETS
Fair value of plan
assets at January 1 5,843 ‐ - 5,843 6,034 ‐ ‐ 6,034
Interest income on plan
assets 97 ‐ ‐ 97 58 ‐ ‐ 58
Financial actuarial gains
and losses (739) ‐ ‐ (739) 629 ‐ ‐ 629
Contributions received 133 ‐ ‐ 133 198 ‐ ‐ 198
Changes in scope of
consolidation 3 ‐ ‐ 3 (862) ‐ ‐ (862)
Settlements 81 ‐ ‐ 81 (11) ‐ ‐ (11)
Benefits paid (260) ‐ ‐ (260) (283) ‐ ‐ (283)
Other (of which
translation adjustments) 22 ‐ ‐ 22 81 ‐ ‐ 81
Fair value of plan
assets at December 31 B 5,181 ‐ - 5,181 5,843 ‐ - 5,843
C - FUNDED STATUS A+B (384) (3,308) (395) (4,087) (1,723) (4,649) (499) (6,872)
Asset ceiling (68) ‐ ‐ (68) (55) ‐ ‐ (55)
NET BENEFIT OBLIGATION (452) (3,308) (395) (4,155) (1,779) (4,649) (499) (6,927)
ACCRUED BENEFIT
LIABILITY (768) (3,308) (395) (4,471) (1,850) (4,649) (499) (6,999)
PREPAID BENEFIT 316 ‐ ‐ 316 72 ‐ ‐ 72
COSTPensions and retirement bonuses.
(1)
(2) Reduced energy prices, healthcare, gratuities and other post-employment benefits.
(3) Length-of-service awards and other long-term benefits.

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LONG-TERM BENEFITS
18.3.3 Components of the net periodic pension cost
The net periodic cost recognized in respect of defined benefit obligations for the years ended December 31, 2022 and
2021 breaks down as follows:

Current service cost 372 521
Actuarial gains and losses (1) (116) (43)
Gains or losses on pension plan curtailments, terminations and settlements 6 ‐
Total accounted for under current operating income including operating MtM and share in net
income of equity method entities 261 479
Net interest expense 93 68
Total accounted for under net financial income/(loss) 93 68
TOTAL 354 547
(1) On the long-term benefit obligation.
18.3.4 Funding policy and strategy
When defined benefit plans are funded, the related plan assets are invested in pension funds and/or with insurance
companies, depending on the investment practices specific to the country concerned. The investment strategies underlying
these defined benefit plans are aimed at striking the right balance between return on investment and acceptable levels of
risk.
The objectives of these strategies can be summarized as follows: to maintain sufficient liquidity to cover pension and other
benefit payments; and as part of risk management, to achieve a long-term rate of return higher than the discount rate or,
where appropriate, at least equal to future required returns.
When plan assets are invested in pension funds, investment decisions are the responsibility of the fund management
concerned. For French companies, where plan assets are invested with an insurance company, the latter manages the
investment portfolio for unit-linked policies or euro-denominated policies, in a manner adapted to the risk and long-term
profile of the liabilities.
The funding of these obligations for each of the periods presented can be analyzed as follows:
Projected
benefit Fair value of Total net
In millions of euros obligation plan assets Asset ceiling obligation
Underfunded plans (3,886) 3,391 (63) (558)
Overfunded plans (1,360) 1,788 (4) 424
Unfunded plans (4,021) ‐ ‐ (4,021)
AT DECEMBER 31, 2022 (9,267) 5,180 (68) (4,156)
Underfunded plans (5,891) 4,671 (50) (1,271)
Overfunded plans (1,116) 1,172 (5) 51
Unfunded plans (5,708) ‐ ‐ (5,708)
AT DECEMBER 31, 2021 (12,715) 5,843 (55) (6,927)

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LONG-TERM BENEFITS
The allocation of plan assets by principal asset category can be analyzed as follows:
In % Dec. 31, 2022 Dec. 31, 2021

Equity investments 27 29
Sovereign bond investments 25 21
Corporate bond investments 35 27
Money market securities 4 3
Real estate 2 2
Other assets 8 18
TOTAL 100 100
All plan assets were quoted on an active market at December 31, 2022.
The actual return on assets of EGI sector companies stood at a negative 12.2% in 2022.
In 2022, the actual return on plan assets of Belgian entities amounted to approximately 2.6% in Group insurance and a
negative 14.2% in pension funds.
The allocation of plan asset categories by geographic area of investment can be analyzed as follows:
In % Europe North America Latin America Asia - Oceania Rest of the World Total
Equity investments 53 33 ‐ 12 2 100
Sovereign bond investments 76 1 19 ‐ 3 100
Corporate bond investments 61 29 1 6 3 100
Money market securities 85 4 3 1 7 100
Real estate 92 2 6 ‐ 1 100
Other assets 13 ‐ ‐ ‐ 87 100
18.3.5 Actuarial assumptions
Actuarial assumptions are determined individually by country and company in conjunction with independent actuaries.
Weighted discount rates for the main actuarial assumptions are presented below:
Pension benefit Other post-employment Long-term benefit

obligations benefit obligations obligations Total benefit obligations
2022 2021 2022 2021 2022 2021 2022 2021
Eurozone 3.8% 1.2% 3.8% 1.2% 3.8% 1.2% 3.8% 1.2%
Discount rate
UK Zone 2.1% 1.6% - - - - - -
Eurozone 4.2% 1.8% 4.2% 1.8% 4.2% 1.8% 4.2% 1.8%
Inflation rate
UK Zone 3.9% 3.6% - - - - - -
18.3.5.1 Discount and inflation rates
The discount rate applied is determined based on the yield, at the date of the calculation, of investment grade corporate
bonds with maturities mirroring the term of the plan.
The rates were determined for each monetary area based on data for AA corporate bond yields. For the Eurozone, data
(from Bloomberg) are extrapolated on the basis of government bond yields for long maturities.
According to the Group’s estimates, a 100-basis-point increase (decrease) in the discount rate would result in a decrease
(increase) of approximately 13% in the projected benefit obligation.
The inflation rates were determined for each monetary area. A 100-basis-point increase (decrease) in the inflation rate
(with an unchanged discount rate) would result in an increase (decrease) of approximately 12% in the projected benefit
obligation.

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LONG-TERM BENEFITS
18.3.6 Estimated employer contributions payable in 2023 under defined benefit plans
The Group expects to pay around €172 million in contributions into its defined benefit plans in 2023, including €122 million
for EGI sector companies. Annual contributions in respect of EGI sector companies will be made by reference to rights
vested during the year, taking into account the funding level for each entity in order to even out contributions over the
medium term.
18.4 Defined contribution plans
In 2022, the Group recorded a €91 million expense in respect of amounts paid into Group defined contribution plans of
which €9 million concerning multi-employers plans in Netherlands (€196 million in 2021, of which €74 million concerning
multi-employers in Netherlands). These contributions are recorded under “Personnel costs” in the consolidated income
statement.

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NOTE 19 SHARE-BASED PAYMENTS
Under IFRS 2, share-based payments made in consideration for services provided are recognized as personnel costs.
These services are measured at the fair value of the instruments awarded.
The fair value of bonus share plans is estimated by reference to the share price at the grant date, taking into account
the fact that no dividend is payable over the vesting period, and based on the estimated turnover rate for the employees
concerned and the probability that the Group will meet its performance targets. The fair value measurement also takes
into account the non-transferability period associated with these instruments. The cost of shares granted to employees
is expensed over the vesting period of the rights and offset against equity.
A Monte Carlo pricing model is used for performance shares granted on a discretionary basis and subject to external
performance criteria.
Expenses recognized in respect of share-based payments break down as follows:
Expense for the year

Employee share issues (1) (49) (1)
Bonus/performance share plans (2) (3) (40) (47)
Other Group companies' plans (3) ‐
TOTAL (92) (48)
(1) Including Share Appreciation Rights set up within the scope of employee share issues in certain countries.
(2) Of which an additional expense of €4.2 million in 2022 following the review of the performance conditions (a reversal of €0.3 million
in 2021).
(3) Of which a reversal of €9.8 million in 2022 for failure to meet the condition of continuing employment within the Group (€4 million in
2021).
19.1 Link 2022
19.1.1 Description of available ENGIE share plans
In 2022, Group employees and former Group employees were entitled to purchase ENGIE shares as part of the “Link 2022”
worldwide employee share ownership plan. The offering mainly involved the sale of treasury shares. Employees could
subscribe to either:
• the Link Classique Plan: this plan allows employees to subscribe to shares at a discount, either directly or via an
employee mutual fund and with an employer top-up contribution;
• the Link Multiple Plan: under this plan, employees may subscribe to shares at a discount, either directly or via an
employee mutual fund, and also benefit from any increase in the share price (leverage effect) in addition to the
amounts invested. Through a Swap Agreement with the bank that structures the Plan, employees are guaranteed
to recover 100% of the invested amount as well as a minimum capitalized return;
• Share Appreciation Rights (SARs): this leveraged plan entitles beneficiaries who purchase shares to receive a
cash bonus equal to the increase in the share price after a period of five years. The resulting employee liability is
covered by warrants.
The Link Classique Plan featured an employer contribution under the terms and conditions described below:
• participating French employees were entitled to bonus ENGIE shares depending on the amount of their own
contribution to the plan:

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− for an employee contribution of €200, the employer contribution corresponded to 200% of this amount; for an
additional employee contribution of €100, the employer contribution represented 50% of the amount. The
employer contribution was capped at €450.
• for employees in other countries, ENGIE shares were granted through a bonus share award plan, subject to the
still being employed with the Group and depending on their own contribution to the plan:
− for an employee contribution of €200, the employer contribution corresponded to 200% of this amount; for an
additional employee contribution of €100, the employer contribution represented 50% of the amount. The
employer contribution was capped at €450;
− the bonus shares will be awarded to employees on December 22, 2027, provided that they are still employed
by the ENGIE Group.
19.1.2 Accounting impacts
The subscription price for the 2022 plan represents the average closing price of the ENGIE share on the Euronext Paris
over the 20 trading days between October 18, 2022 and November 14, 2022 inclusive. The reference price is set at €13.14
less 20% for the Link Classique and the Link Multiple plans, i.e. €10.51.
The expense recognized in the consolidated financial statements in respect of the Link Classique, and Link Multiple plans
corresponds to the difference between the fair value of the shares subscribed and the subscription price. The fair value
takes into account the lock-up period of five years, as provided for by French legislation.
The following assumptions were applied:
5 years
Risk-free interest rate 2.70%
Spread applicable to the retail banking network 1.00%
Employee financing cost 3.70%
Share lending cost 1.00%
Share price at grant date 14.38
The accounting impacts break down as follows:
Link Classique
France - additional
employer's
Link Classique Link Multiple contribution Total
Amount subscribed (in millions of euros) 27 135 ‐ 162
Number of shares subscribed (in millions of shares) 2.6 12.8 0.8 16.2
Discount (€/share) 3.9 3.9 14.4 ‐
Non-transferability restriction (€/share) (1.4) (1.4) (1.4) ‐
Cost for the Group (in millions of euros) 6 32 10 48
Subscriptions to the Link 2022 worldwide employee share ownership plan totaled €162 million and break down as follows:
• the sale of treasury shares to employees amounted to €130 million;

• a capital increase and additional paid-in capital of €32 million (excluding issuance costs). This amount is broken
down into €8 million for Link Classique and €24 million for Link Multiple.
The Group recognized a total expense of €48 million for 2022 in respect of the 15.4 million shares subscribed and the
0.8 million bonus shares awarded under employer contributions.

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The accounting impact of cash-settled Share Appreciation Rights consists in recognizing a payable to the employee over
the vesting period, with a corresponding adjustment recorded in profit or loss. At December 31, 2022, the fair value of the
liability relating to the 2018 and 2022 awards amounted to €0.2 million.
19.2 Performance shares
19.2.1 New awards in 2022
ENGIE Performance Share plan of December 8, 2022
On December 8, 2022, the Board of Directors approved the award of 4.7 million performance shares to members of the
Group's executive and senior management, breaking down into three tranches:
• performance shares vesting on March 14, 2026, subject to a one-year lock-up period;
• performance shares vesting on March 14, 2026, without a lock-up period; and
• performance shares vesting on March 14, 2027, without a lock-up period.
In addition to a condition requiring employees to be employed with the Group at the vesting date, each tranche is made up
of instruments subject to four different conditions, excluding the first 500 performance shares granted to beneficiaries
(excluding top management), which are exempt from performance conditions. The performance conditions are as follows:
• a market performance condition relating to ENGIE’s Total Shareholder Return compared to that of a reference
panel of six companies, as assessed between December 2022 and February 2026, which accounts for 25% of the
total award;
• an internal performance condition relating to net recurring income Group share compared to that of a reference
panel of six companies, as assessed between the second half of 2022 and the first half of 2025, which accounts
for 25% of the total award;
• an internal performance condition relating to Return On Capital Employed (ROCE) in 2025 which accounts for 30%
of the total award;
• an internal performance condition relating to non-financial criteria in terms of targets for greenhouse gas emissions
from energy productions, increasing the share of renewable capacities and increasing the percentage of women
in management, as assessed between December 2022 and December 2025, which accounts for 20% of the total
award.
Under this plan, performance shares without conditions were also awarded to the winners of the Innovation and Incubation
programs (6,450 shares awarded).
ENGIE Bonus Share plan of November 18, 2022
As part of the Link 2022 employee share plan, bonus shares were awarded to subscribers of the Link Classique plan
(outside France). A total of 247,163 bonus shares were awarded under this plan (see Note 19.1.1 Description of available
ENGIE share plans).

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19.2.2 Fair value of bonus share plans with or without performance conditions
The following assumptions were used to calculate the unitary fair value of the new plans awarded by ENGIE in 2022:
Market-
related
End of the lock-up Price at the Expected performance
Award date Vesting date period award date dividend condition Unitary fair value
November 18, 2022 December 22, 2027 December 22, 2027 14.4 1,15 no 9.20
Weighted average fair value of the December 22, 2022 plan 9.20
December 8, 2022 March 14, 2026 March 14, 2027 14.3 1,15 yes 9.91
December 8, 2022 March 14, 2026 March 14, 2026 14.3 1,15 no 11.05
Weighted average fair value of the December 8, 2022 plan 10.24
19.2.3 Review of internal performance conditions applicable to the plans
In addition to the condition of continuing employment within the Group, eligibility for certain bonus share and performance
share plans is subject to an internal performance condition. When this condition is not fully met, the number of bonus
shares granted to employees is reduced in accordance with the plans’ regulations, leading to a decrease in the total
expense recognized in relation to the plans in accordance with IFRS 2. Performance conditions are reviewed at each
reporting date.

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NOTE 20 RELATED PARTY TRANSACTIONS
This note describes material transactions between the Group and its related parties.
Compensation payable to key management personnel is disclosed in Note 21 “Executive compensation”.
Transactions with joint ventures and associates are described in Note 3 “Investments in equity method entities”.
Only material transactions are described below.
20.1 Relations with the French State and with entities owned or partly
owned by the French State
20.1.1 Relations with the French State
The French State’s interest in the Group at December 31, 2022 remained unchanged at 23.64% compared with the
previous year. This entitles it to three of the 15 seats on the Board of Directors (one director representing the State
appointed by decree, and two directors appointed by the Shareholders’ Meeting at the proposal of the State).
The French State holds 33.56% of the theoretical voting rights (33.71% of exercisable voting rights) compared with 33.20%
at end-2021.
On May 22, 2019, the PACTE Law (“Action plan for business growth and transformation”) was enacted, enabling the
French State to dispose of its ENGIE shares without restriction.
In addition, the French State holds a golden share aimed at protecting France’s critical interests and ensuring the continuity
and safeguarding of supplies in the energy sector. The golden share is granted to the French State indefinitely and entitles
it to veto decisions taken by ENGIE if it considers they could harm France’s interests.
Public service engagements in the energy sector are defined by the law of January 3, 2003.
Transmission rates on the GRTgaz transportation network and the gas distribution network in France, as well as rates for
accessing the French LNG terminals and revenues from storage capacities, are all regulated.
The Law on Energy and Climate enacted on November 8, 2019 will put an end to regulated gas tariffs and will restrict
regulated electricity tariffs for consumers and small businesses. The final date for the discontinuation of regulated gas
tariffs is July 1, 2023.
20.1.2 Relations with EDF
Following the creation on July 1, 2004 of the French gas and electricity distribution network operator (EDF Gaz de France
Distribution), Gaz de France SA and EDF entered into an agreement on April 18, 2005 setting out their relationship as
regards the distribution business. The December 7, 2006 law on the energy sector reorganized the natural gas and
electricity distribution networks. Enedis SA, a subsidiary of EDF SA, and GRDF SA, a subsidiary of ENGIE SA, were
created on January 1, 2007 and December 31, 2007, respectively, and act in accordance with the agreement previously
signed by the two incumbent operators. With the deployment of smart meters for both electricity and gas, the "common"
activities operated by the two distributors evolved significantly. The remaining mixed activities are mainly in the areas of
inventory management, human resources, medical field, local IT and accountancy. This scope will be further reduced in
2023 to be limited to areas relating to medical field and social activities.

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20.2 Relations with the CNIEG (Caisse Nationale des Industries

Électriques et Gazières)
The Group’s relations with the CNIEG, which manages all old-age, death and disability benefits for active and retired
employees of the Group who belong to the special EGI pension plan, employees of EDF and Non-Nationalized Companies
(Entreprises Non Nationalisées – ENN), are described in Note 18 “Post-employment benefits and other long-term benefits”.

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NOTE 21 EXECUTIVE COMPENSATION
NOTE 21 EXECUTIVE COMPENSATION
The executive compensation presented below includes the compensation of the members of the Group's Executive
Committee and Board of Directors.
The Executive Committee had 10 members at December 31, 2022 (compared to 11 members at December 31, 2021).
Their compensation breaks down as follows:

Short-term benefits 34 22
Post-employment benefits ‐ 1
Share-based payments 4 3
Termination benefits ‐ 7
TOTAL 37 33

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NOTE 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES, OTHER ASSETS AND OTHER LIABILITIES
NOTE 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES,

OTHER ASSETS AND OTHER LIABILITIES
In accordance with IAS 1, the Group’s current and non-current assets and liabilities are shown separately in the
consolidated statement of financial position. For most of the Group’s activities, the breakdown into current and non
current items is based on when assets are expected to be realized, or liabilities extinguished. Assets expected to be
realized or liabilities extinguished within 12 months of the reporting date are classified as current, while all other items
are classified as non-current.
Inventories
Inventories are measured at the lower of cost and net realizable value. Net realizable value corresponds to the estimated
selling price in the ordinary course of business, less the estimated costs of completion and the estimated costs
necessary to make the sale.
The cost of inventories is determined based on the first-in, first-out method or the weighted average cost formula.
Nuclear fuel purchased is consumed in the process of producing electricity over a number of years. The consumption
of this nuclear fuel inventory is recorded based on estimates of the quantity of electricity produced per unit of fuel.
Gas inventories
Gas injected into underground storage facilities includes working gas, which can be extracted without adversely affecting
the subsequent operation of the reservoirs, and cushion gas, which is inseparable from the reservoirs and essential for
their operation (see Note 13.3 “Property, plant and equipment”).
Working gas is classified in inventories and measured at weighted average purchase cost upon entering the
transportation network regardless of its source, including any regasification costs.
Group inventory outflows are valued using the weighted average unit cost method.
Certain inventories are used for trading purposes and are recognized at fair value less selling costs, in accordance with
IAS 2. Any changes in said fair value are recognized in the consolidated income statement for the year in which they
occur.
Greenhouse gas emission rights, energy saving certificates and green certificates
In the absence of specific IFRS standards or IFRIC interpretations on accounting for greenhouse gas emission
allowances, energy saving certificates and green certificates, the Group has decided to recognize certificates in
inventories at their acquisition or production cost. At the reporting date, a liability is recognized if the certificates held by
the Group are insufficient to meet the obligation to return certificates to the French government. When not covered by
the certificates held in inventories, the liability is measured at the market value or based on the price of any future
contracts that have been entered into, when applicable.
Tax equity
The ENGIE Group finances its renewables projects in the United States through tax equity structures, in which part of
the necessary funds is provided by a tax partner. The tax partner obtains, up to a pre-determined level, a preferential
right essentially to the project’s tax credits, which it can deduct from its own tax base.

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NOTE 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES, OTHER ASSETS AND OTHER LIABILITIES
The tax partner’s investments meet the definition of a liability under IFRS. Since the tax equity liability corresponding to
these tax benefits does not give rise to any cash outflow for the project entity, it does not represent a financial debt and
is accounted for in “Other liabilities”.
Besides the unwinding effect, the liability changes mainly in line with the tax credits allocated to the tax partner and
recognized in profit or loss.
22.1 Composition of change in working capital requirements
Change in working Change in working

capital capital
requirements at requirements at
Inventories (2,115) (2,349)
Trade and other receivables, net (11,614) (11,043)
Trade and other payables, net 8,521 10,676
Tax and employee-related receivables/payables 1,545 364
Margin calls and derivative instruments hedging commodities relating to trading activities 199 (706)
Other 1,040 680
TOTAL (2,424) (2,377)
22.2 Inventories

Inventories of natural gas, net 4,628 3,079
Inventories of uranium (1) 308 408
CO2 emissions allowances, green certificates and energy saving certificates, net 1,788 1,526
Inventories of commodities other than gas and other inventories, net 1,420 1,161
TOTAL 8,145 6,175
(1) Financial hedging instruments are backed by these uranium inventories and represented a negative amount of €229 million at
December 31, 2022.
22.3 Other assets and other liabilities
Dec. 31, 2022 Dec. 31, 2021

Non- Non- Non- Non-
Other assets and liabilities 766 18,294 (3,646) (23,583) 478 13,202 (2,341) (16,752)
Tax receivables/payables ‐ 14,647 ‐ (16,863) ‐ 10,628 ‐ (11,316)
Employee receivables/payables 523 22 (2) (2,479) 300 18 (2) (2,033)
Dividend receivables/payables ‐ 12 ‐ (23) ‐ 15 ‐ (9)
Other 243 3,614 (3,644) (4,218) 178 2,541 (2,339) (3,395)
At December 31, 2022, other non-current assets included a receivable towards EDF Belgium in respect of nuclear
provisions amounting to €162 million (€96 million at December 31, 2021).
Other liabilities include €1,981 million in investments made by tax partners as part of the financing of renewable projects
in the United States by tax equity (€1,229 million at December 31, 2021).

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NOTE 23 LEGAL AND ANTI-TRUST PROCEEDINGS
The Group is party to a number of legal and anti-trust proceedings with third parties or with legal and/or administrative
authorities (including tax authorities) in the normal course of its business.
The main disputes and investigations presented hereafter are recognized as liabilities or give rise to contingent assets or
liabilities.
In the normal course of its business, the Group is involved in a number of disputes and investigations before state courts,
arbitral tribunals or regulatory authorities. The disputes and investigations that could have a material impact on the Group
are presented below.
23.1 Renewables
23.1.1 Mexico – Renewable energy
In 2021, the Mexican government and public authorities took positions and legislative and regulatory measures that directly
affect private players in the energy sector (in particular renewable energy producers) and go against the letter and spirit of
the latest energy sector reforms introduced in 2013 and 2014. The constitutionality and legality of some of these measures
have been contested in legal proceedings launched by non-government bodies and private investors, in particular by
ENGIE subsidiaries that develop or implement renewable energy projects in the country. These proceedings are currently
ongoing. The Mexican President has also submitted a draft revision of the Constitution that would substantially change the
regulatory framework applicable to the electricity sector. The case was put on hold in the first half of 2022.
23.2 Networks
23.2.1 Investigation into the regulatory framework for natural gas storage in France
On February 29, 2020, the European Commission announced that it had launched an in-depth investigation into the
regulatory framework for natural gas storage introduced on January 1, 2018 to secure France’s natural gas supply.
Storengy and Géométhane provided the Commission with all the necessary information to substantiate their analyses. The
European Commission closed its investigation and published a press release on June 28, 2021 announcing that it had
concluded that the regulatory framework for natural gas storage complies with EU rules on State aid. Nevertheless, the
Commission considered that the scheme constituted illegal State aid for the period during which it was implemented without
having been approved in advance. This decision was published in the Official Journal on March 18, 2022, marking the start
of the two-month period for filing an appeal. To our knowledge, no appeal has been filed.
23.3 Energy Solutions
23.3.1 Spain - Púnica
In the Púnica case (procedure concerning the awarding of contracts), 15 Cofely España employees, as well as the
company itself, were placed under investigation by the examining judge in charge of the case. The criminal investigation
was closed on July 19, 2021 with the referral of Cofely España and eight (former) employees before the criminal court.
Cofely España lodged an appeal against this decision on September 30, 2021. On March 9, 2022, the appeal was
dismissed and the referral decision upheld. The hearings are expected to begin in 2023.

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23.3.2 Italy - Competition procedure
On May 9, 2019, a fine of €38 million was jointly and severally imposed on ENGIE Servizi SpA and ENGIE Energy Services
International S.A. (“ENGIE ESI”) by the Italian Competition Authority (the “Authority”) for certain alleged anti-competitive
practices relating to the award of the Consip FM4 2014 contract. An appeal was lodged with the Lazio Regional
Administrative Court (Lazio RAC). On July 18, 2019, the Lazio RAC suspended the payment of the fine, and on
July 27, 2020, it overturned the Authority’s decision as regards both ENGIE Servizi SpA and ENGIE ESI. On
November 17, 2020, the Authority appealed the Lazio RAC’s decision before Italy’s highest administrative court. On
May 9, 2022, the Italian administrative court rejected the Authority’s appeal and upheld the Lazio RAC’s reversal of the
Authority’s decision. Two companies filed a special appeal against the administrative court’s decision before the
administrative court itself on June 13, 2022, and an appeal challenging the administrative court’s rejection of the appeal
before the Supreme Court on July 11, 2022. These appeals do not have a suspensive effect. Both proceedings are still
pending.
23.3.3 Italy – Manitalidea
In 2012, ENGIE Servizi formed a temporary association (“associazione temporanea di imprese” or “ATI) with Manitalidea
with the aim of submitting a bid for a public contract launched by CONSIP. ENGIE Servizi had an 85% stake in the ATI,
with Manitalidea holding the remaining 15%. The purpose of the contract was to provide energy and maintenance services
to hospitals.
In September 2012, three lots of the contract were awarded to the ATI.
On March 11, 2022, Manitalidea filed for damages against ENGIE Servizi with the Rome Civil Court, claiming that (i) ENGIE
Servizi had not complied with the provisions of the temporary association agreement relating to the distribution of contracts
between the partners, and (ii) as a result, Manitalidea had missed an opportunity to increase its revenue. After Manitalidea
filed for bankruptcy, the claim was extended to include the alleged responsibility of ENGIE Servizi for Manitalidea’s financial
difficulties and bankruptcy.
A hearing is scheduled for the first half of 2023.
23.4 Supply
23.4.1 Canvassing
EDF brought an action against ENGIE before the Nanterre Commercial Court on July 20, 2017, seeking €13.5 million in
damages for alleged losses due to unfair competitive practices pursued by ENGIE mainly in its door-to-door canvassing
campaigns. In its judgment of December 14, 2017, the court ordered ENGIE to pay EDF the sum of €150,000, concluding
that ENGIE was guilty of unfair competition but acknowledging that there had been no disparagement of EDF and that
ENGIE had set up training and control arrangements for its partners.
ENGIE appealed the judgment and EDF brought a cross-appeal seeking €94.7 million in damages for its alleged loss. The
Versailles Court of Appeal delivered its judgment on March 12, 2019, ordering ENGIE to pay EDF €1 million. It also ordered
ENGIE to cease and desist from all parasitic business practices and disparagement to the detriment of EDF, subject to a
penalty of €10,000 per infringement for a period of one year.
On July 6, 2020, EDF asked the enforcement judge at the Nanterre Court to assess the penalty ordered by the Versailles
Court of Appeal, seeking payment from ENGIE of the sum of €106.89 million and a final penalty of €50,000 per infringement
for a period of one year. On December 11, 2020, the enforcement judge ordered ENGIE to pay EDF the sum of €230,000
and ordered a new provisional penalty of €15,000 per new infringement reported by EDF for a period of one year as of
notification of the judgment.
On December 22, 2020, EDF appealed the enforcement judge’s decision before the Versailles Court of Appeal. The
Versailles Court of Appeal handed down its decision on July 1, 2021. It reduced ENGIE’s fine to €190,000 and, considering

176
that ENGIE had demonstrably implemented measures that were likely to be efficient and that the difficulties encountered
stemmed for the most part from the behavior of service providers/partners and door-to-door salespeople, annulled the new
provisional penalty and rejected EDF’s request to impose a definitive penalty. EDF appealed this decision before the
French Court of Cassation on July 29, 2021. The Court of Cassation rejected EDF’s appeal in its ruling of October 6, 2022.
The case is therefore closed.
23.4.2 Peru – Antamina
In 2012, following a tender for the annual purchase of 170 MW until 2032, ENGIE Energía Perú S.A. entered into a long-
term gas purchase agreement with the Peruvian mining company Antamina (the “Agreement”).
In 2021, however, Antamina launched another tender for the same annual volume and entered into three purchase
agreements with three new suppliers for a six-month period renewable twice. This called into question the exclusivity and
“take or pay” clause that ENGIE Energía Perú S.A. believed it had been granted until 2032 under the Agreement. Following
the signing of these new agreements, Antamina refused, as of January 2022, to accept delivery of the agreed upon quantity
of gas under the Agreement and, consequently, to pay the corresponding penalty.
On April 26, 2022, ENGIE Energía Perú S.A. filed an arbitration procedure against Antamina, seeking recognition of the
exclusive nature of the Agreement and Antamina’s obligation to only procure gas supplies from ENGIE. The suit also seeks
the payment of invoices that have been outstanding since January 2022. The arbitration procedure is governed by the
rules of the Arbitration Center of the Lima Chamber of Commerce. On January 4, 2023, ENGIE Energía Perú S.A. filed its
pleading. Antamina will have to file its pleading by the end of March at the latest.
23.4.3 GEM – GPE
At the beginning of the fourth quarter of 2022, ENGIE initiated an arbitration procedure against Gazprom Export LLC
seeking, in particular to obtain (i) recognition of Gazprom Export LLC’s non-performance of its gas delivery obligations
towards ENGIE under long-term gas delivery agreements and (ii) payment of contractual penalties as well as compensation
for damages resulting from this non-performance from Gazprom Export LLC.
This arbitration procedure is due to the significant delivery shortages by Gazprom Export LLC to ENGIE as of mid-June
2022, followed by Gazprom Export LLC’s unilateral decision at the end of summer 2022 to reduce its deliveries to ENGIE
due to a disagreement between the parties on the application of the agreements.
23.4.4 Commissioning
Regarding the customer management services carried out on behalf of the grid manager in the electricity sector (in this
case ERDF, now ENEDIS), following proceedings brought by ENGIE, in a decision of July 13, 2016, the Conseil d’État
ruled that the principle whereby the grid manager pays compensation to the supplier should apply. In the same decision,
the Conseil d’État denied the CRE the right to set a customer threshold beyond which the compensation would not be
payable, which hitherto prevented ENGIE from receiving any compensation. In light of this decision, ENGIE brought an
action against ENEDIS seeking payment for these customer management services. The legislature has adopted a decision
that retroactively validates the agreements entered into with ENEDIS and precludes any request for compensation for
unpaid customer management services. In a decision handed down on April 19, 2019, the Constitutional Court ruled that
this provision was constitutional. On April 11, 2022, the Paris Commercial Court recorded the termination of the
proceedings. The case against ENEDIS is therefore closed.
23.4.5 Chile – TOTAL
On January 3, 2023, ENGIE Energía Chile S.A. initiated international arbitration proceedings against TotalEnergies Gas
& Power Limited for breaching its contractual obligations under an LNG supply contract entered into in August 2011.

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23.5 Thermal
23.5.1 Italy - Vado Ligure
On March 11, 2014, the Court of Savona seized and closed down the VL3 and VL4 coal-fired production units at the Vado
Ligure thermal power plant belonging to Tirreno Power S.p.A. (TP), a company which is 50%-owned by the ENGIE Group.
This decision was taken as part of a criminal investigation against the present and former executive managers of TP into
environmental infringements and public health risks. The investigation was closed on July 20, 2016. The case was referred
to the Savone Court to be tried on the merits. The proceedings before the Court of First Instance began on
December 11, 2018 and will continue through 2022 and 2023.
23.5.2 Brazil – Claim against sales tax adjustments
On December 14, 2018, the Brazilian tax authorities sent ENGIE Brasil Energia S.A. tax deficiency notices for the 2014,
2015 and 2016 fiscal years considering that the company was liable for the PIS and COFINS taxes (federal value added
taxes) on the reimbursement of certain fuels used in the production of energy by thermoelectric plants. The adjustments
amounted to a total of 581 million Brazilian real, including 229 million Brazilian real in taxes plus fines and interest.
ENGIE Brasil Energia disputes these tax deficiency notices and introduced tax claims in 2019, which the tax authorities
have rejected, however.
On November 22, 2022, ENGIE Brasil Energia filed a special administrative appeal, which was not recognized by the
Administrative Court. On January 9, 2023, the company filed another administrative appeal seeking recognition of the
special administrative appeal and an analysis of the merits of the case. If these proceedings are unsuccessful, the case
will have to be brought before the ordinary courts and tribunals.
23.5.3 Italy – Tax on excess profits
In December 2022, ENGIE filed an action to obtain the reimbursement of the tax it paid in July and November 2022 for a
total amount of more than €308 million, pursuant to two legislative decrees (no. 21 and 50/2022) that introduced an
exceptional solidarity contribution to be paid by operators in the energy sector. ENGIE contests the validity of the basis of
the tax in relation to the decree’s objective, its compatibility with the Italian Constitution as well as its compatibility with
Italy’s European commitments (European law).
23.5.4 Flémalle – EPC
In November 2021, Electrabel SA entered into an EPC (Engineering, Procurement, Construction) agreement with SEPCO
III for the construction of a gas-fired power plant in Flémalle (Belgium), in the context of the CRM (Capacity Remuneration
Mechanism).
In August 2022, Electrabel SA terminated the EPC agreement with SEPCO III for non-performance of its contractual
obligations and initiated arbitration proceedings in November 2022, to obtain compensation for its damages.
23.6 Nuclear
23.6.1 Extension of operations at the nuclear power plants 2015-2025
Various associations have brought actions before the Constitutional Court, the Conseil d’État and the ordinary courts
against the laws and administrative decisions authorizing the extension of operations at the Doel 1 and 2 reactors. On
June 22, 2017 the Constitutional Court referred the case to the Court of Justice of the European Union (CJEU) for a
preliminary ruling. In its judgment of July 29, 2019, the CJEU ruled that the Belgian law extending the operating lives of
the Doel 1 and Doel 2 reactors (law extending Doel 1 and Doel 2) was adopted without the required environmental

178
assessments being carried out first, but that the effects of the law on extension may provisionally be maintained where
there is a genuine and serious threat of an interruption to electricity supply, and then only for the length of time that is
strictly necessary to eliminate this threat. In its decision of March 5, 2020, the Constitutional Court overturned the law
extending Doel 1 and Doel 2, while maintaining its effects until the legislator adopts a new law after having carried out the
required environmental assessment, including a cross-border public consultation process, by December 31, 2022 at the
latest.
The environmental assessment and the cross-border public consultation were carried out by the Belgian State in 2021.
The draft law incorporating the conclusion of the assessment and the consultation was passed by the Belgian Federal
Parliament on October 11, 2022 and published on November 3, 2022.
The appeal before the Conseil d’État against the administrative decisions that allowed the extension of operations at the
Doel 1 and Doel 2 plants is still pending.
23.6.2 Shutdown of the Doel 3 and Tihange 2 power plants
Various associations have lodged appeals before the Brussels Court of First Instance against Electrabel, the Belgian State,
the Nuclear Safety Authority and/or the Elia electricity transmission network to contest the decisions and actions to shut
down the Doel 3 (on September 23, 2022) and/or Tihange 2 (on January 31, 2023) power plants. In a first judgment dated
November 16, 2022, the Brussels Court of First Instance, ruling in summary proceedings in one of the cases, confirmed
the decisions and actions taken in relation to the shutdown. The cases are ongoing with a timetable extending into 2023.
23.7 Other
23.7.1 Withholding tax
In their tax deficiency notice dated December 22, 2008, the French tax authorities questioned the tax treatment of the non
recourse sale by SUEZ (now ENGIE) of a withholding tax (précompte) receivable in 2005 for an amount of €995 million
(receivable relating to the précompte paid in respect of the 1999-2003 fiscal years). The Montreuil Administrative Court
handed down a judgment in ENGIE’s favor in April 2019, which led the French tax authorities to appeal the decision before
the Versailles Court of Appeal, which overturned the prior Court’s decision on December 22, 2021. While recognizing the
fiscal nature of the receivable sold, the Court did not validate the exemption of the sale price because there was no text or
principle to that effect, and because the sale was not authorized by the State.
Regarding the dispute over the précompte itself, on February 1, 2016, the Conseil d’État dismissed the appeal before the
Court of Cassation seeking the repayment of the précompte in respect of the 1999, 2000 and 2001 fiscal years. On June
23, 2020, the Versailles Administrative Court of Appeal found in favor of ENGIE as regards the cases seeking repayment
of the précompte in respect of the 2002 and 2003 fiscal years but rejected the case in respect of the 2004 fiscal year. As
the précompte receivables for 2002/2003 have been assigned, the relevant amounts have been repaid to the assignee
banks. The case has been referred to the Conseil d’État by the two parties. In parallel, following the decision of the Court
of Justice of the European Union of May 12, 2022, interpreting the deduction of the précompte on the redistribution by a
parent company of dividends received from subsidiaries established in the European Union as incompatible with Directive
90/435/EC of 1990, in June 2022, several groups, including ENGIE, invited the Conseil d’État to submit a request for a
priority ruling on an issue of constitutionality to the Constitutional Court to rule on the unconstitutionality of the précompte
legislation. The Conseil d’État granted this request. In October 2022, the Constitutional Court rejected the request of ENGIE
and the other groups. This decision will have no impact on ENGIE’s financial statements and little impact on the other
ongoing proceedings.
Furthermore, after ENGIE and several French groups lodged a complaint, on April 28, 2016, the European Commission
issued a reasoned opinion to the French State as part of infringement proceedings, setting out its view that the Conseil
d’État did not comply with European Union law when handing down decisions in disputes regarding the précompte, such
as those involving ENGIE. On July 10, 2017, the European Commission referred the matter to the Court of Justice of the
European Union on the grounds of France’s failure to comply. On October 4, 2018, the Court of Justice of the European
Union ruled partially in favor of the European Commission. Following this decision, France must revisit its methodology in

179
order to determine the précompte repayment amounts in closed and pending court cases. No action has been initiated to
date due to parallel litigation proceedings on the basis of Directive 90/435/EC.
23.7.2 Luxembourg – State aid investigation
On September 19, 2016, the European Commission announced its decision to open an investigation into whether or not
two private rulings granted by the Luxembourg State in 2008 and 2010 covering two similar transactions between several
of the Group’s Luxembourg subsidiaries constituted State aid. On June 20, 2018, the European Commission adopted a
final, unfavorable decision deeming that Luxembourg had provided ENGIE with State aid. On September 4, 2018, ENGIE
requested the annulment of the decision before the European Courts, thereby challenging the existence of a selective
advantage. As these proceedings did not have a suspensive effect, ENGIE paid a sum of €123 million into an escrow
account on October 22, 2018 in respect of one of the two transactions in question, since no aid was actually received for
the other. Following the proceedings before the European Courts, this sum will be returned to ENGIE or paid to the
Luxembourg State depending on whether or not the Commission’s decision is annulled. On May 12, 2021, the Court
rejected the appeals of the Luxembourg State and of ENGIE, thereby confirming the European Commission’s position on
the existence of State aid granted to the Group’s Luxembourg subsidiaries. On July 22, 2021, ENGIE referred the matter
to the Court of Justice of the European Union seeking the annulment of the Court’s decision. The proceedings are currently
ongoing. After the parties exchanged their pleadings with the Commission, ENGIE filed an application for a hearing and
joinder of appeals on March 21, 2022. The hearing was held in late January 2023
23.7.3 Poland – Competition procedure
On November 7, 2019, a fine of 172 million Polish zloty (€40 million) was imposed on ENGIE Energy Management Holding
Switzerland AG (EEMHS) for failing to respond to a request for disclosure of documents from the Polish Competition
Authority (UOKiK) in proceedings initiated by the UOKiK which suspected a potential failure to notify by EEMHS and other
financial investors involved in the financing of the Nord Stream 2 pipeline (main proceeding). EEMHS filed an appeal with
the Competition Protection Court. The appeal proceedings are pending.
In the context of the main proceedings, on October 6, 2020, the UOKiK ordered EEMHS to pay a fine of 55.5 million Polish
zlotys (approximately €12.3 million). The UOKiK also ordered the termination of the financing agreements for the Nord
Stream 2 project. On November 5, 2020, EEMHS appealed this decision with the Competition Protection Court (the
“Court”). The appeal automatically suspends the execution of all of the penalties ordered by the UOKiK. On
November 21, 2022, the Court overturned the UOKiK’s decision in its entirety. The UOKiK has appealed this decision.
23.7.4 Claim by the Dutch tax authorities related to interest deductibility
Based on a disputable interpretation of a statutory modification that came into force in 2007, the Dutch tax authorities
refused the deductibility of a portion (€1.1 billion) of the interest paid on financing contracted for the acquisition of
investments made in the Netherlands since 2000. Following the Dutch tax authorities’ rejection of the administrative claim
against the 2007 tax assessment, action was brought before the Arnhem Court of First Instance in June 2016. On
October 4, 2018, the court ruled in favor of the tax authorities. On October 26, 2020, the ruling was confirmed by the
Arnhem Court of Appeal. ENGIE Energie Nederland Holding BV considers that the Court committed errors in law and that
its decision was not well-founded, either under Dutch or European law. It has therefore appealed the decision before the
Court of Cassation. In July 2022, the Court of Cassation decided to refer questions on the compatibility of the Dutch
legislation on interest with three of the European fundamental freedoms to the Court of Justice of the European Union for
a preliminary ruling.
23.7.5 Transfer price of gas
The Belgian tax authorities’ Special Tax Inspectorate has issued two tax deficiency notices in respect of taxable income
for fiscal years 2012 and 2013 for an aggregate amount of €706 million, considering that the price applied for the supply
of gas by ENGIE (then GDF SUEZ) to Electrabel S.A. was excessive. ENGIE and Electrabel S.A. are challenging this
adjustment and have submitted a request for conciliation proceedings, which was accepted by France and Belgium in

180
May 2018. The proceedings are ongoing between the two States, who have rediscussed their respective positions, with
no major progress having made in 2022. No major problems were identified.

181
NOTE 24 SUBSEQUENT EVENTS
NOTE 24 SUBSEQUENT EVENTS
No significant subsequent events have occurred since the closing of the accounts at December 31, 2022.

182
NOTE 25 FEES PAID TO THE STATUTORY AUDITORS AND TO MEMBERS OF THEIR NETWORKS
NOTE 25 FEES PAID TO THE STATUTORY AUDITORS AND TO

MEMBERS OF THEIR NETWORKS
Pursuant to Article 222-8 of the General Regulations of the French Financial Markets Authority (AMF), the following table
presents information on the fees paid by ENGIE SA, its fully consolidated subsidiaries and joint operations to each of the
auditors in charge of auditing the annual and consolidated financial statements of the ENGIE Group.
The Shareholders’ Meeting of ENGIE SA of May 14, 2020 decided to renew the terms of office of Deloitte and EY as
Statutory Auditors for a six-year period from 2020 to 2025.
Deloitte EY
Deloitte &
In millions of euros Associés Network Total EY & others Network Total Total
Statutory audit and review of
consolidated and parent
company financial
statements 4.5 5.7 10.2 5.2 10.5 15.7 25.9
ENGIE SA 2.4 - 2.4 2.8 - 2.8 5.1
Controlled entities 2.1 5.7 7.8 2.4 10.5 12.9 20.7
Non-audit services 0.6 1.1 1.7 0.9 1.0 1.8 3.5
ENGIE SA 0.5 0.5 1.0 0.7 - 0.7 1.8
Of which services related to
legal and regulatory
requirements 0.4 - 0.4 0.4 - 0.4 0.7
Of which other audit
services 0.1 - 0.1 0.3 - 0.3 0.5
Of which reviews of internal
control - - - 0.0 - 0.0 0.0
Of which due diligence - 0.5 0.5 - - - 0.5
services
Of which tax services 0.0 - 0.0 - - - 0.0
Controlled entities 0.1 0.5 0.7 0.1 1.0 1.1 1.7
Of which services related to
legal and regulatory
requirements 0.0 0.3 0.3 0.1 0.2 0.3 0.6
Of which other audit
services 0.1 0.0 0.1 0.0 0.2 0.2 0.3
Of which reviews of internal
control - - - - - - -
Of which due diligence 0.0 - 0.0 - - - 0.0
services
Of which tax services - 0.2 0.2 ‐ 0.5 0.5 0.8
Total 5.1 6.8 11.9 6.1 11.4 17.5 29.4

183
NOTE 26 INFORMATION REGARDING LUXEMBOURG AND DUTCH COMPANIES EXEMPTED FROM THE REQUIREMENTS TO PUBLISH ANNUAL FINANCIAL
STATEMENTS
NOTE 26 INFORMATION REGARDING LUXEMBOURG AND

DUTCH COMPANIES EXEMPTED FROM THE
REQUIREMENTS TO PUBLISH ANNUAL FINANCIAL
STATEMENTS
Some companies do not publish annual financial statements pursuant to domestic provisions under Luxembourg law
(Article 70 of the Law of December 19, 2002) and Dutch law (Article 403 of the Civil Code) relating to the exemption from
the requirement to publish audited annual financial statements.
The companies exempted are notably: ENGIE Energie Nederland NV, ENGIE Energie Nederland Holding BV, ENGIE
Nederland Retail BV, ENGIE United Consumers Energie BV, Electrabel Invest Luxembourg, ENGIE Treasury Management
SARL and ENGIE Invest International SA.

184
A public limited company with a share capital of 2,435,285,011 euros
Corporate headquarters: 1, place Samuel de Champlain
92400 Courbevoie - France
Tel: +33 (1) 44 22 00 00
Register of commerce: 542 107 651 RCS PARIS
VAT FR 13 542 107 651
engie.com

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2022 MANAGEMENT REPORT

02 CONSOLIDATED FINANCIAL STATEMENTS

03 NOTES TO THE CONSOLIDATED FINANCIAL

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

1 ENGIE 2022 RESULTS

ENGIE FY 2022 Financial results

Business Highlights Financial Performance

1.1 Key financial figures at December 31, 2022

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

1.2 2023-2025 outlook and guidance

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

ENGIE outlook for 2023 to 2025:

In €billion 2023 Results 2024 Results 2025 Results

1.2.2. Overview of key financial targets

Accelerating growth in Renewables

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

Ramping up in renewable gases

ENGIE has set an ambitious target by 2030 to:

Total Capex for hydrogen is earmarked at c.€4 billion over 2023-2030.

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

Leveraging ENGIE extensive market knowledge through GEMS

Capital allocation and medium-term financial outlook

Main drivers for 2022-2025 EBIT evolution by activity

GEMS Decrease of prices and volatility but still high ---

Nuclear Higher prices, lower volumes =+

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

1.4 ENGIE playing a leading role in security of supply and contributing to

1.5 ENGIE is contributing to public policy measures to address high

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

1.6 Update on European proposals for windfall taxes

1.7 Significant progress on the execution of strategic plan

Acceleration in Renewables, infrastructures and renewable gases

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

Simplifying and refocusing

Disciplined capital allocation

Performance plan delivering

1.8 Update on Belgian nuclear assets

Key ESG targets

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

1.10 Health & Safety

1.11 FY 2022 financial review

Contributive revenues, after elimination of intercompany transactions

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

Rest of Latin USA & Middle East, December 31,

Rest of Latin USA & Middle East, December 31,

EBIT growth mainly driven by GEMS, Thermal and Renewables.

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

Rest of Latin USA & Middle East, December 31,

Rest of Latin USA & Middle East, December 31,

EBIT contribution by activity

1.11.5.1. Renewables: contribution of newly commissioned assets and productivity

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

EBIT amounted to €2,371 million, up 0.5% on an organic basis.

EBIT amounted to €412 million, up 16.6% on an organic basis.

ENGIE - 2022 CONSOLIDATED FINANCIAL STATEMENTS

Thermal EBIT amounted to €1,768 million, up 47% on an organic basis.