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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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Form
(Mark One)
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REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
OR
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SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Date of event requiring this shell company report
Commission file number:
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(Exact name of Registrant as specified in its charter)
Republic of
(Jurisdiction of incorporation or organization)
(Address of principal executive offices)
Tel +
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
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Securities registered or to be registered pursuant to Section 12(b) of the Act.
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Title of each class |
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Trading Symbol(s) |
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Name of each exchange on which registered |
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(Which represent the right to receive two Shares) |
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* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission. |
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
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Ordinary shares |
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes
Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has fi led a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP
☐
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ☐ Item 18 ☐
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
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T ABLE OF CONTENTS |
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Page |
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iii |
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iv |
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ix |
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P A R T I |
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Item 1. |
1 |
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Item 2. |
1 |
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Item 3. |
1 |
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1 |
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Item 4. |
23 |
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23 |
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36 |
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36 |
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Global Gas & LNG Portfolio and Power |
58 |
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62 |
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67 |
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72 |
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73 |
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75 |
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75 |
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85 |
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96 |
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96 |
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Item 4A. |
97 |
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Item 5. |
97 |
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98 |
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113 |
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118 |
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119 |
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Item 6. |
128 |
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128 |
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137 |
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138 |
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154 |
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155 |
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Item 7. |
156 |
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156 |
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156 |
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Item 8. |
157 |
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157 |
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157 |
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Item 9. |
158 |
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158 |
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159 |
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Item 10. |
160 |
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160 |
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167 |
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167 |
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167 |
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172 |
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Item 11. |
173 |
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Item 12. |
175 |
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Item 12A. |
175 |
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Item 12B. |
175 |
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Item 12C. |
175 |
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Item 12D. |
175 |
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PART II |
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Item 13. |
177 |
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Item 14. |
MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS |
177 |
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Item 15. |
177 |
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Item 16. |
178 |
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Item 16A. |
178 |
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Item 16B. |
178 |
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Item 16C. |
178 |
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Item 16D. |
179 |
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Item 16E. |
Purchases of equity securities by the issuer and affiliated purchasers |
179 |
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Item 16F. |
179 |
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Item 16G. |
179 |
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Item 16H. |
182 |
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Item 16I. |
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
182 |
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Item 16J. |
182 |
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Item 16K. |
182 |
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PART III |
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Item 17. |
186 |
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Item 18. |
186 |
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Item 19. |
187 |
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ii
Ce r tain dis c losu r es contained he r ein in c ludin g , without limitation, ce r tain in f ormation appearing in “Item 4 – In f ormation on the Compa n y”, and in pa r ticular “Item 4 – Explo r ation & P r oductio n ”, “Item 5 – Ope r ating and Financial R e view and P r ospects” and “Item 11 – Quantitat i v e and Qualitat i v e Dis c losu r es about Ma rk et Risk” contain f or w a r d-looking statements r e g a r ding futu r e e v ents and the futu r e r esults of Eni that a r e based on cur r ent e xpectation s , estimate s , f o r ecast s , and p r ojections about the industries in w hi c h Eni ope r ates and the beliefs and assumptions of the mana g ement of Eni. Eni may also ma k e f or w a r d-looking statements in other written material s , in c luding other documents f iled with or furnished to the U . S . Securities and E x c han g e Commission (the “SEC”). In addition, Eni ’ s senior mana g ement may ma k e f or w a r d-looking statements o r al l y to ana l yst s , i n v esto r s , r ep r esentat i v es of the media and othe rs . In pa r ticula r , among other statement s , ce r tain statements with r e g a r d to mana g ement object i v e s , t r ends in r esults of ope r ation s , ma r gin s , cost s , r eturn on capital, risk mana g ement and competition a r e f or w a r d looking in natu r e . W o r ds su c h as ‘ e xpects’, ‘anticipates’, ‘ta rg ets’, ‘ g oals’, ‘p r ojects’, ‘intends’, ‘plans’, ‘beli e v es’, ‘seeks’,‘estimates’, v ariations of su c h w o r d s , and similar e xp r essions a r e intended to identify su c h f or w a r d-looking statement s . These f or w a r d-looking statements a r e on l y p r edictions and a r e subject to risk s , unce r taintie s , and assumptions that a r e dif f icult to p r edict because th e y r elate to e v ents and depend on ci r cumstances that will occur in the futu r e . The r e f o r e , Eni ’ s actual r esults may dif f er material l y and ad v e r se l y f r om those e xp r essed or implied in a n y f or w a r d-looking statement s . F acto r s that mi g ht cause or contribute to su c h dif f e r ences in c lud e , but a r e not limited t o , those discussed in this Annual R epo r t on F orm 20-F under the section entitled “Risk f acto r s” and else w he r e . A n y f or w a r d-looking statements made b y or on behalf of Eni speak on l y as of the date th e y a r e mad e . Eni does not unde r ta k e to update f or w a r d-looking statements to r eflect a n y c han g es in Eni ’ s e xpectations with r e g a r d the r eto or a n y c han g es in e v ent s , conditions or ci r cumstances on w hi c h a n y su c h statement is based. The r eader should, h ow e v e r , consult a n y fu r ther dis c losu r es Eni may ma k e in documents it f iles with the SE C .
CE R T AIN DEFINED TERMS
In this F o r m 20- F , the te r ms “Eni”, the “G r oup”, or the “Compa n y” r efer to the pa r ent compa n y Eni SpA and its consolid a ted subsidiaries and, unless the cont e xt otherwise r equi r e s , their r espect iv e p r edecessor companie s . All r efe r ences to “It a l y” or the “St a te” a r e r efe r ences to the R epu b lic of It a l y , a ll r efe r ences to the “G o v ernment” a r e r efe r ences to the g o v ernment of the R epu b lic of It a l y . F or de f initions of certain oil and gas te r ms used he r ein and certain co n v ersion s , see “Glossary” and “Co n v ersion T a b le”.
PRESENTATION OF FINANCIAL AND OTHER INFORMATION
The Consolid a ted Financi a l St a tements of Eni, included in this An n u a l R eport, h a v e been p r epa r ed in acco r dance with Intern a tion a l Financi a l Standa r ds (IFRS) as issued b y the Intern a tion a l Accounting Standa r ds Boa r d (IASB).
Unless otherwise indic a ted, a n y r efe r ence he r ein to “Consolid a ted Financi a l St a tements” is to the Consolid a ted Financi a l St a tements of Eni (including the Notes the r eto) included he r ein.
Unless otherwise speci f ied or the cont e xt otherwise r equi r e s , r efe r ences he r ein to “dollars”, “$”, “ U . S . dollars”, “US$” and “USD” a r e to the cur r ency of the United St a te s , and r efe r ences to “eu r o”, “EUR” and “€” a r e to the cur r ency of the Eu r opean Monetary Union.
Unless otherwise specified or the context otherwise requires, references herein to “Division” and “segment” are to any of the following Eni’s business activities: “Exploration & Production” (or “E&P”), “Global Gas & LNG Portfolio and Power”, “Enilive and Plenitude”, “Refining and Chemicals” and “Corporate and Other activities”.
References to Enilive are to Eni’s biofeedstock supply, storage, production, distribution and marketing of biofuels, oil products, biomethane, smart mobility solutions and mobility services, all managed through its fully-owned subsidiary Enilive and its controlled entities. References to Plenitude are to Eni’s retail gas and power activities and services, renewables and e-mobility businesses which are managed through its fully-owned subsidiary Eni Plenitude SpA Società Benefit and Plenitude’s controlled entities. The results of the operations of Enilive and Plenitude are included in the segment information “Enilive and Plenitude” for financial reporting purposes.
R efe r ences to V ers a lis or Chemic a l a r e to Eni ’ s chemic a l act i vities w hich a r e man a ged th r ough its ful l y- o wned subsidiary V ers a lis and V ers a lis’ cont r olled entitie s . The results of operations of the Chemical business are included in the segment information “Refining and Chemicals” for financial reporting purposes.
For further details on Eni’s business structure and financial reporting segments refer to “Item 4 – Information on the Company”.
Exhibit 99 which contains Eni’s disclosure pursuant to the EU Taxonomy regulation does not form part of this Form 20-F and is not incorporated herein.
S TA TEMENTS REGARDING COMPETITIVE POSITION
St a tements made in “Item 4 – In f o r m a tion on the Compa n y” r eferring to Eni ’ s competit iv e position a r e based on the Compa n y ’ s b e lie f , and in some cases re l y on a r ange of sou r ce s , including i n v estment an a l ysts’ r eport s , independent ma r k et studies and Eni ’ s intern a l assessment of ma r k et sha r e based on pu b lic l y a v ail a b le in f o r m a tion a bout the f inanci a l r esults and per f o r mance of ma r k et participant s . Ma r k et sha r e estim a tes contained in this document a r e based on man a gement estim a tes unless otherwise indic a ted.
iii
G L OSSA R Y
B e l o w is a s e lection of the most f r equent l y used te r ms th r oughout this An n u a l R eport on F o r m 20- F . A n y r efe r ence he r ein to a non-GAAP measu r e and to its most di r ect l y compa r a b le GAAP measu r e sh a ll be intended as a r efe r ence to a non-IFRS measu r e and the compa r a b le IFRS measu r e .
Financial terms
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Identified net gains (losses) |
Identified net gains (losses) include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. Exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the derivative market. Finally, special items include the accounting effects of fair-valued commodity derivatives relating to commercial exposures: in addition to those which lack the criteria to be designed as hedges, also those which are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well as the accounting effects of settled commodity and exchange rates derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods. Correspondently, special charges/gains also include the evaluation effects relating to assets/liabilities utilized in a natural hedge relation to offset a market risk, as in the case of accrued currency differences at finance debt denominated in a currency other than the reporting currency, where the cash outflows for the reimbursement are matched by highly probable cash inflows in the same currency. The deferral of both the unrealized portion of fair-valued commodity and other derivatives and evaluation effects are reversed to future reporting periods when the underlying transaction occurs. |
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L e v e r a g e |
A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Ratio of total debt to total shareholders equity (including non-controlling interest)” see “Item 5 – Financial Condition”. |
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Net bor ro wings |
Eni evaluates its financial condition by reference to “net borrowings”, which is a non-GAAP measure. Eni calculates net borrowings as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. From 2024, it includes certain long-term financing receivables due to the Company by affiliates, based on the Company’s sole exposure to counterparty credit risk and as a reimbursement plan has been scheduled. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Total debt” see “Item 5 – Financial condition”. |
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TSR ( T otal Sha r eholder R eturn) |
Management uses this measure to assess the total return on Eni’s shares. It is calculated on a yearly basis, keeping account of the change in market price of Eni’s shares (at the beginning and at end of year) and dividends distributed and reinvested at the ex-dividend date. |
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Business terms
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ARERA (Italian Regulatory Authority for Energy, Networks and Environment) formerly AEEGSI (Authority for Electricity Gas and Water) |
The Italian Regulatory Authority for Energy, Networks and Environment is the Italian independent body which regulates, controls and monitors the electricity, gas and water sectors and markets in Italy. The Authority’s role and purpose is to protect the interests of users and consumers, promote competition and ensure efficient, cost-effective and profitable nationwide services with satisfactory quality levels. Furthermore, since December 2017 the Authority also has regulatory and control functions over the waste cycle, including sorted, urban and related waste. |
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Associated gas |
Associated gas is a natural gas found in contact with or dissolved in crude oil in the reservoir. It can be further categorized as Gas-Cap Gas or Solution Gas. |
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Average reserve life index |
Ratio between the amount of reserves at the end of the year and total production for the year. |
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Barrel/BBL |
Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons. |
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BOE |
Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a certain coefficient (see “Conversion Table” on page ix). |
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Compounding |
Activity specialized in production of semifinished products in granular form, resulting from the combination of two or more chemical products. |
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Concession contracts |
Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive right on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state. |
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Condensates |
Condensates are a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. |
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Consob |
The Italian National Commission for listed companies and the stock exchange (Commissione Nazionale per le Società e la Borsa). |
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Contingent resources |
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. |
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Conversion capacity |
Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units. |
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Conversion index |
Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation. |
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Deep waters |
Waters deeper than 200 meters. |
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Development |
Drilling and other post-exploration activities aimed at the production of oil and gas. |
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Enhanced recovery |
Techniques used to increase or stretch over time the production of wells. |
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Eni carbon efficiency index |
Ratio between GHG emissions (Scope 1 and Scope 2 in tonnes CO 2 eq.) of the main industrial activities operated by Eni divided by the productions (converted by homogeneity into barrels of oil equivalent using Eni’s average conversion factors) of the single businesses of reference. |
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EPC |
Engineering, Procurement and Construction. |
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EPCI |
Engineering, Procurement, Construction and Installation. |
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Exploration |
Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling. |
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FPSO |
Floating Production Storage and Offloading System. |
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FSO |
Floating Storage and Offloading System. |
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Greenhouse Gases (GHG) |
Gases in the atmosphere, transparent to solar radiation, that trap infrared radiation emitted by the earth’s surface. The greenhouse gases relevant within Eni’s activities are carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). GHG emissions are commonly reported in CO2 equivalent (CO2eq) according to Global Warming Potential values in line with IPCC AR4, 4th Assessment Report. |
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Infilling wells |
Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels. |
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LNG |
Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas. |
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LPG |
Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression. |
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Margin |
The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability. |
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Mineral Potential |
(Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage. |
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Natural gas liquids (NGL) |
Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids. |
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Net GHG Lifecycle Emissions |
GHG Scope 1+2+3 emissions associated with the value chain of the energy products sold by Eni, including both those deriving from own productions and those purchased from third parties, accounted on equity basis, net of offset, mainly from Natural Climate Solutions. |
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Net Carbon Footprint |
Overall Scope 1 and Scope 2 GHG emissions associated with Eni’s operations, accounted for on an equity basis, net of carbon sinks mainly from Natural Climate Solutions. |
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Net Carbon Intensity |
Ratio between the Net GHG lifecycle emissions and the energy content of products sold accounted for on an equity basis. |
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Network Code |
A code containing norms and regulations for access to, management and operation of natural gas pipelines. |
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Oilfield chemicals |
Innovative solutions for supply of chemicals and related ancillary services for Oil & Gas business. |
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Over/Under lifting |
Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations. |
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Plasmix |
Plasmix is the collective name for the different plastics that currently have no use in the market of recycling and can be used as a feedstock in the new circular economy businesses of Eni. |
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Possible reserves |
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. |
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Probable reserves |
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. |
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Primary balanced refining capacity |
Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d. |
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Production Sharing Agreement (PSA) |
Contract regulates relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. |
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Proved reserves |
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. |
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REDD+ |
The REDD+ (Reducing Emissions from Deforestation and Forest Degradation) scheme was designed by the United Nations (United Nations Framework Convention on Climate Change - UNFCC). It involves conserving forests to reduce emissions and improve the natural storage capacity of CO2, as well as helping local communities develop through socio-economic projects in line with principles on sustainable management, forest protection and nature conservation. |
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Renewable Installed Capacity |
Renewable Installed Capacity is measured as the maximun generating capacity of Eni’s share of power plants that use renewable energy sources (wind, solar and wave, and any other non-fossil fuel source of generation deriving from natural resources, excluding, from the avoidance of doubt, nuclear energy) to produce electricity. The capacity is considered “installed” once the power plants are in operation or the mechanical completion phase has been reached. The mechanical completion represents the final construction stage excluding the grid connection. |
|
Reserves |
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. |
vii
|
Reserve life index |
Ratio between the amount of proved reserves at the end of the year and total production for the year. |
|
Reserve replacement ratio |
Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices. |
|
Scope 1 GHG Emissions |
Direct greenhouse gas emissions from company’s operations, produced from sources that are owned or controlled by the company. |
|
Scope 2 GHG Emissions |
Indirect greenhouse gas emissions resulting from the generation of electricity, steam and heat purchased from third parties. |
|
Scope 3 GHG Emissions |
Indirect GHG emissions associated with the value chain of Eni’s products. |
|
SERM (Standard Eni Refining Margin) |
It approximates the margin of Eni's refining system in consideration of the refinery |
|
Ship-or-pay |
Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported. |
|
Take-or-pay |
Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years. |
|
Title Transfer Facility |
The Title Transfer Facility, more commonly known as TTF, is a virtual trading point for natural gas in the Netherlands. TTF Price is quoted in euro per megawatt hour and, for business day, is quoted day-ahead, i.e. delivered next working day after assessment. |
|
UN SDGs |
The Sustainable Development Goals (SDGs) are the blueprint to achieve a better and more sustainable future for all by 2030. Adopted by all United Nations Member States in 2015, they address the global challenges the world is facing, including those related to poverty, inequality, climate change, environmental degradation, peace and justice. For further detail see the website https://unsdg.un.org |
|
Upstream/Downstream |
The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities. |
|
Upstream GHG Emission intensity |
Ratio between 100% Scope 1 GHG emissions from Upstream operated assets and 100% gross operated production (expressed in barrel of oil equivalent). |
viii
|
mmCF |
= million cubic feet |
mmtonnes |
= million tonnes |
|
BCF |
= billion cubic feet |
MW |
= megawatt |
|
mmCM |
= million cubic meters |
GWh |
= gigawatthour |
|
BCM |
= billion cubic meters |
TWh |
= terawatthour |
|
BOE |
= barrel of oil equivalent |
/d |
= per day |
|
|
|
/y |
= per year |
|
KBOE |
= thousand barrel of oil equivalent |
|
|
|
mmBOE |
= million barrel of oil equivalent |
|
|
|
BBOE |
= billion barrel of oil equivalent |
|
|
|
BBL |
= barrels |
|
|
|
KBBL |
= thousand barrels |
|
|
|
mmBBL |
= million barrels |
|
|
|
BBBL |
= billion barrels |
|
|
|
mmBTU |
= million British thermal unit |
|
|
|
ktonnes |
= thousand tonnes |
|
|
|
KW |
= kilowatt |
|
|
|
GW |
= gigawatt |
|
|
|
Gcal |
= giga calorie |
|
|
CONVERSION T ABLE
|
1 acre |
= 0.405 hectares |
|
|
1 barrel |
= 42 U.S. gallons |
|
|
1 BOE |
= 1 barrel of crude oil |
= 5,232 cubic feet of n a tu r a l gas |
|
1 barrel of crude oil per day |
= approximately 50 tonnes of crude oil per year |
|
|
1 cubic meter of natural gas |
= 35.3147 cubic feet of natural gas |
|
|
1 cubic meter of natural gas |
= approximately 0.00675 barrels of oil equivalent |
|
|
1 kilometer |
= approximately 0.62 miles |
|
|
1 short ton |
= 0.907 tonnes |
= 2,000 pounds |
|
1 long ton |
= 1.016 tonnes |
= 2,240 pounds |
|
1 tonne |
= 1 metric ton |
= 1,000 kilograms |
|
|
|
= approximately 2,205 pounds |
|
1 tonne of crude oil |
= 1 metric ton of crude oil |
= approximately 7.3 barrels of crude oil
|
ix
Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
NOT APPLICABLE
Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE
Item 3. KEY INFORM A TION
Eni is exposed to the effects of changing commodity prices and margins
Eni is primarily in a commodities business that by nature is exposed to the price volatility of the relevant commodities. The most significant factor that affects the Company’s results of operations is the price of crude oil, which can be influenced by general economic conditions and level of economic growth, including low or negative growth; industry production and inventory levels; technology advancements, including those in pursuit of a lower carbon economy; greenhouse gas emissions and climate change; production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries (“OPEC”) or other producers; weather-related damage and disruptions due to other natural or human causes beyond Eni’s control; competing fuel prices; geopolitical risks; the pace of energy transition; customer and consumer preferences and the use of substitutes; and governmental regulations, policies and other actions regarding the development of oil and gas reserves. Eni evaluates the risk of changing commodity prices as a core part of its business planning process and resource allocation. An investment in the Company carries significant exposure to fluctuations in global crude oil prices.
In the short term, crude oil prices are mainly determined by the balance between global oil supply and demand, the global levels of commercial inventories and producing countries’ spare capacity, as well as by expectations of financial operators who trade crude oil derivatives contracts (futures and options) influencing short-term price movements via their positioning. A downturn in economic activity normally triggers lower global demand for crude oil and possibly oversupplies and inventories build-up, because in the short-term producers are unable to quickly adapt to swings in demand. Whenever global supplies of crude oil exceeds demand, crude oil prices decrease. In the short term, global demand for crude oil is influenced by macroeconomic trends in large consuming countries (such as China, India and the United States) as well as any financial crisis, inflation and interest rates, geo-political crisis, local conflicts, wars, strikes, attacks, sabotages (particularly in the crude oil-rich area of Middle East), social and political instability, pandemic diseases, the flows of international commerce, trade disputes and governments’ fiscal policies, extreme weather events and natural disruptions, among others.
In the long term, demand for crude oil may be negatively affected by development of alternative energy sources (e.g., nuclear and renewables), technological breakthroughs, shifts in consumer preferences, and measures and other initiatives adopted by governments to tackle climate change and to curb carbon-dioxide emissions (CO 2 emissions), including stricter regulations and control on production and consumption of crude oil. Eni’s management believes the push to reduce worldwide greenhouse gas emissions and the ongoing energy transition towards a low carbon economy could materially affect the worldwide energy mix and may lead to structural lower crude oil demands and prices. See the risk factor titled “Rising concerns about climate change and the effects of the energy transition could lead to a decline in demand for hydrocarbons and potentially lower prices. Climate change could also have a physical impact on our assets and supply chains. This risk may also lead to additional legal and/or regulatory measures, resulting in project delays or cancellations, potential additional litigation, operational restrictions, and additional compliance obligations and expenses” below.
Notwithstanding the United States is the first oil producer in the world since the shale oil revolution of 2011, in the short term the global balance between oil supply and demand is controlled to a large degree by the OPEC and its allied countries, among them Russia and Kazakhstan, known as the OPEC+ alliance, which have signed a declaration of cooperation (“DoC”) few years ago, designed to manage production through quotas and voluntary production cuts to help stabilize crude oil prices. Countries adhering to the DoC are currently estimated to hold a spare capacity of 5-6 million bbl/day, as per market sources, representing about 5-6% of the world crude oil and natural gas liquids supply. This poses a material risk to the outlook of crude oil prices because there is no guarantee that the cooperation among OPEC+ producers will continue in the future. In case the DoC countries decide to end the agreement in place and to produce based on each respective available capacity, given the demand outlook, crude oil prices are likely to weaken materially.
1
The drivers of prices and demand for natural gas are similar to those of crude oil. The development of massive liquefaction capacity that has occurred in recent years in countries like the United States, Qatar and Australia has helped to develop a global liquid market of natural gas, with traders being able to redirect LNG volumes from one geography to another based on price arbitrages. Differently from crude oil, the absolute levels of natural gas prices change from region to region due to specific supply dynamics (e.g. in 2024 the price of natural gas in the United States was one fifth that of Europe, because Europe is a net importer, whilst the United States is currently an oversupplied market due to growing domestic production), while consumption of natural gas is significantly exposed to seasonal patterns and competition from renewables. All those trends may result in a higher degree of volatility in natural gas prices compared to crude oil. In 2024, natural gas prices in Europe fell by a significant amount due to continuing production growth in the United States, weak industrial demand in Europe and China and high levels on inventories to meet the expected seasonal winter demand peak in the Northern hemisphere. The outlook for natural gas prices in the short to medium term is compounded by expectations of material additions of LNG production capacity in the United States and Qatar and rising competition from renewables. In the long-term, demand for natural gas is exposed to the risks of the transition to a low-carbon economy.
The volatility of hydrocarbon prices significantly affects the Group’s financial performance. Lower hydrocarbon prices negatively affect the Group’s consolidated results of operations and cash flow; while the opposite effect is caused by a rise in prices. This is because lower prices translate into lower revenues recognized in the Company’s Exploration & Production segment at the time of the price change, whereas expenses in this segment are either fixed or less sensitive to changes in crude oil prices than revenues. However, the same relative change in the crude oil price yields a considerably larger impact at the Group’s results of operations and cash flow than the natural gas price. This is because a significant portion of natural gas production volumes are marketed at fixed prices or are indexed to the price of crude oil.
In 2024, hydrocarbons prices declined by 2.2 % and 14% respectively for the Brent crude oil and the European spot price of natural gas, reduced Exploration & Production operating profit by an estimated amount of €0.7 billion.
Finally, movements in hydrocarbon prices significantly affect the reportable amount of production and proved reserves under our production sharing agreements (“PSAs”), which represented 57% of our proved reserves as of end of 2024. The entitlement mechanism of PSAs foresees the Company is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditure, and vice versa. In 2024 our reported production and reserves were increased by an estimated amount of respectively 2 KBOE/d and by 30 mmBOE due to a decreased Brent reference price. Considering the current portfolio of oil&gas assets, the Company estimates its production to vary by up to 1 KBOE/d for each one-dollar change in the price of the Brent crude oil.
Eni’s Refining and Chemical businesses are in cyclical economic sectors. Their results are impacted by trends in the supply and demand of oil products and commodity plastics, which are influenced by macro-economic variables and by competitive dynamics which ultimately determine the level of products prices. Margins for refined and chemical products depend upon the speed at which products’ prices adjust to reflect movements in oil prices.
All these risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholders returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.
2
There are growing systemic risks to the macroeconomic outlook in connection with the persistence of Russia’s military invasion of Ukraine, peril of escalation in the tense situation in the Middle East and the deteriorating commercial relationships between the United States and China. Those risks could derail the macroeconomic recovery, and this could negatively affect demand for hydrocarbon.
The conflict between Russia and Ukraine has been ongoing since February 2022, when Russian military forces invaded Ukraine. This conflict has negatively impacted the global economy and triggered an energy crisis in Europe as well as a downturn in industrial activity, given the disruption in the political relationships between Western Countries and Russia, in the supply chains as well as an increase in cybersecurity threats. In response to Russia’s aggression, the EU nations, the UK, and the United States have adopted severe economic and financial sanctions to curb Russia’s ability to fund the war, which are negatively affecting the overall economic activity.
The conflict in the Gaza strip and in Lebanon involving the Israelis forces and Iran-backed Hamas and Hezbollah armed militias is often on the verge of a possible escalation and further enlargement of the conflict. This situation in the Middle East is a further negative factor on the macroeconomic scenario.
A prolonged armed conflict in those two areas, a possible escalation of the military action, and deterioration of US-China commercial relationships pose risks to the macroeconomic recovery because they can eventually undermine consumers’ confidence and deter investment decisions, thus increasing the risks of a worldwide slowdown or, under a worst-case scenario, a global recession. Such developments could negatively and significantly affect hydrocarbons demands, leading to lower commodity prices and adversely impacting our results of operations and cash flow, as well as business prospects, with a possible lower remuneration of our shareholders.
Risks in connection with our presence in Russia and our commercial relationships with Russia’s State-owned companies
The most important exposure of Eni to Russia is relating to the purchase of natural gas from Russian state-owned company Gazprom and its affiliates, based on long-term supply contracts with take-or-pay clauses. In the past, the volumes supplied from Russia have represented a material amount of our global portfolio of natural gas supplies (see table “Natural gas supply” in Item 4 – Global Gas & LNG Portfolio, providing information about the last three-year period). In 2024, natural gas supplies from Russia were marginal, representing 12% of our total purchases of natural gas (same as in 2023) as we made no liftings at our contracts with Gazprom to serve our customers in European markets or our trading activities at European hubs. This situation was due to the unilateral decision from our Russian supplier to suspend deliveries to Eni in 2023, against the backdrop of a commercial dispute between the two parties. We intend to continue replacing Russian-origin natural gas in our portfolio with gas volumes coming from other suppliers and geographies, aiming at terminating the current supply contracts with our Russian counterparties in the shortest possible timeframe.
The Group's business plans have accounted for the assumption of zeroing the supplies from Russia, and sales plans have been adapted accordingly by limiting sales commitments. To cope with the expected reduced availability of Russian natural gas, the Group has increased purchases from other geographies through various commercial initiatives, such as using contractual flexibilities to increase withdrawals from existing long-term contracts or by developing integrated upstream-midstream projects leveraging equity natural gas reserves and new liquefactions capacity. The process of replacing Russian-origin natural gas, including terminating existing contracts, may entail operational and financial risks which may be significant.
Other Eni’s assets in Russia are immaterial to the Group results of operations (see Item 4).
3
There is strong competition worldwide, both within the oil industry and with other industries, to supply energy and petroleum products to the industrial, commercial, and residential energy markets
The current competitive environment in which Eni operates is characterized by volatile prices and margins of energy commodities, limited product differentiation and complex relationships with state-owned companies and national agencies of the countries where hydrocarbons reserves are located to obtain mineral rights. On the other hand, the Company’s downstream businesses (particularly the refining of crude oil to produce fuels and the production of petrochemicals) is characterized by lack of technological entry barriers, global overcapacity and competition from larger players, who can leverage economies of scale due to plants optimal size, access to cheap raw materials and lower energy and logistic expenses. Furthermore, competition within commodity industries is considerably influenced by the economic cycle. Normally an economic downturn negatively affects demands for commodities leading to a more intense price competition. As commodity prices are not within the Eni’s control, Eni’s ability to remain competitive and profitable in this environment requires continuous focus on technological innovation, efficiencies in operating costs, effective management of capital resources and the supply of valuable services to energy buyers. It also depends on Eni’s ability to gain access to new investment opportunities. Competitive trends represent a risk to the profitability of all Eni’s business segment:
• E&P may be negatively affected by its relatively smaller scale compared to other players in the industry;
• The business of marketing natural gas in the European wholesale market managed by the GGP segment is exposed to pricing competition and competition from renewables considering anticipated weak demand trends in Europe;
• The businesses of oil refining and production of basic chemical products located mainly in Europe are exposed to ongoing weak demand trends, overcapacity, competition from players with wider scale and cost advantages which are operating in geographies characterized by lower energy expenses and environmental liabilities compared to Europe, and finally growing market penetration by more sustainable products. In 2024, Eni’s refining business incurred a loss of €674 million driven by reduced crack spreads of refined products due to an oversupplied market, a subdued US driving season and weak manufacturing, construction, and trucking activity, as well as the penetration of LNG-fueled trucks negatively affected demands for gasoil and fuel oil, particularly in China. Eni’s Chemical business incurred an operating loss for the third consecutive year (€1,007 million in 2024) due to the above-mentioned weak business’s fundamentals which have been exacerbated by the comparatively higher energy inputs of manufacturing activities in Europe with respect to other geographies following the European energy crisis of 2022, which has further reduced the competitiveness of the Eni’s chemicals activity against the backdrop of macroeconomic headwinds.
• The business of marketing natural gas and electricity to the retail market managed by our subsidiary Plenitude, is exposed to the competitive trends of the retail market, which is characterized by an almost complete deregulation, a high number of suppliers, low entry barriers, and customers’ ability to switch readily from one supplier to another. The same applies to retail marketing of fuels which is managed by our subsidiary Enilive, operating in a market characterized by intense price competition and low brand loyalty. Enilive also engages in the manufacturing of biofuels and returns of this activity are exposed to the competition risks in connection with oversupplies and dumping by unregulated operators and an uncertain regulatory framework. In 2024, the margins on the sale of biofuels were negatively and significantly affected by those trends.
More information about Eni’s segments competitive trends is disclosed in Item 4.
4
Rising concerns about climate change and the effects of the energy transition could lead to a decline in demand for hydrocarbons and potentially lower prices. Climate change could also have a physical impact on our assets and supply chains. This risk may also lead to additional legal and/or regulatory measures, resulting in project delays or cancellations, potential additional litigation, operational restrictions, and additional compliance obligations and expenses.
Societal demand for urgent action on climate change has increased, especially since the Intergovernmental Panel on Climate Change (IPCC) Special Report of 2018 on 1.5°C effectively made the more ambitious goal of the Paris Agreement to limit the rise in global average temperature this century to 1.5 degrees Celsius the default target. This increasing focus on climate change and drive for an energy transition have created a risk environment that is changing rapidly, resulting in a wide range of governmental actions at global, local and company levels, increasing pressure from civil society and the investing and lending community to speed up our decarbonization plans.
The energy transition, as well as increasingly stricter regulations in the field of CO 2 emission, could entail risks to the Group’s financial performance and business prospects, because the Company still relies substantially on the legacy business of Exploration & Production.
Firstly, international initiatives and national, regional, and state legislation and regulations targeting GHG emissions are in various stages of design, adoption, and implementation. These policies and initiatives - some of which support the global net zero emissions ambitions of the Paris Agreement - can change the amount of energy consumed, the rate of energy-demand growth, the energy mix, and the relative economics of one fuel versus another. Laws and regulations whether already in force or under consideration are seeking to limit greenhouse gas (GHG) emissions by taxing them or by imposing operational restrictions and other compliance costs on oil&gas companies. Regulators may seek to limit certain oil and gas projects or make it more difficult to obtain required permits. Additionally, climate activists are challenging the grant of new and existing regulatory permits. We expect that these challenges and protests are likely to continue and could delay or prohibit operations in certain cases. We also expect that actions by customers to reduce their emissions will continue to lower demand and potentially affect prices for fossil fuels, as will tax incentives in support of electric vehicles and renewables and other low-carbon solutions.
The pace and extent of the energy transition could pose a risk to Eni if we decarbonize our operations and the energy we sell at a different speed relative to society. If we are slower than society, customers may prefer a different supplier, which would reduce demand for our products and adversely affect our reputation besides materially affecting our earnings and financial results. If we move much faster than society, we risk investing in technologies, markets or low-carbon products that are unsuccessful because there is limited demand for them.
The physical effects of climate change such as, but not limited to, increases in temperature and sea levels and fluctuations in water levels could also adversely affect our operations and supply chains.
Certain investors have decided to divest from fossil fuel companies, which could undergo growing scrutiny from financial markets participants to obtain funds and borrowings facilities. If this were to continue, it could have a material adverse effect on the price of our securities and our ability to access capital markets. Stakeholder groups are also putting pressure on commercial and investment banks to stop financing fossil fuel companies. Some financial institutions have started to limit or cease altogether their exposure to fossil fuel projects. Accordingly, our ability to use financing for these types of future projects may be adversely affected.
In some countries, governments, regulators, organizations, and individuals have filed lawsuits seeking to hold oil companies liable for costs associated with climate change or seeking to have oil companies condemned to speed up decarbonization plans based on alleged crimes against the environment or human rights violations. While we believe these lawsuits to be without merit, losing could have a material adverse effect on our business.
5
In summary, rising climate change concerns, the pace at which we decarbonize our operations relative to society and effects of the energy transition have led and could lead to a decrease in demand and potentially affect prices for fossil fuels. If we are unable to find economically viable, publicly acceptable solutions that reduce our GHG emissions and/or GHG intensity for new and existing projects and for the products we sell, we could experience financial penalties or extra costs, delayed or cancelled projects, potential impairments of our assets, additional provisions and/or reduced production and product sales, negatively affecting future results of operations, cash flow, liquidity, business prospects, financial condition, shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares may be adversely and significantly affected.
The Company will continue to develop oil and gas resources to meet customers’ and consumers’ demand for energy, targeting to increase the proportion of natural gas in the production mix. At the same time, Eni has been implementing a strategy designed to gradually reduce the weight of hydrocarbons in the Company’s portfolio by growing the businesses of renewable energy, manufacturing of biofuels and lower carbon gases, as well as developing new technologies in the fields of nuclear energy, plastic recycling, and other energy vectors and solutions, like the geological permanent sequestration of CO 2 , to decarbonize hard-to-abate products or process with the long-term goal of achieving net zero emissions of CO 2 at the whole of its products and processes by 2050. Eni integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews, and risk management tools and processes, where it believes they are applicable. They are also factored into the Company’s long-range supply, demand, and energy price forecasts. These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as electric vehicle and renewable fuel penetration, energy efficiency standards, and demand response to oil and natural gas prices. In case demand for hydrocarbons declines more rapidly than management’s planning assumptions and capital programs, our results of operations and business prospects may be significantly and negatively affected.
The above mentioned risks may emerge in the short, medium and long term.
a) Regulatory risk: increasing worldwide efforts to tackle climate change may lead to the adoption of stricter regulations to curb carbon emissions and this could lead to increasing expenditures in the short term and may end up suppressing demands for our products in medium-to-long term.
It is possible that a growing share of our GHG emissions may be subject to regulation going forward, resulting in increased compliance costs and operational constraints. Regulatory actions intended to reduce greenhouse gas emissions include adoption of cap and trade regimes, carbon taxes, carbon-based import duties or other trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support transitioning to lower-emission energy sources. Depending on how policies and regulations are formulated and applied, such policies and regulations could negatively affect our investment returns, make our hydrocarbon-based products more expensive or less competitive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon alternatives. Current and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring, tracking or sequestering emissions.
Some governments have already introduced carbon pricing schemes. Eni’s operating and compliance expenses could increase in the short-to-medium term in case of widespread adoption of carbon tax mechanisms. Currently, about half of the direct GHG emissions coming from Eni’s operated assets are included in national or supranational Carbon Pricing Mechanisms, such as the European Emission Trading Scheme (ETS), which provides an obligation to purchase, on the open market, emission allowances in case GHG emissions exceed a pre-set amount of emission allowances allotted for free. In 2024 to comply with this carbon emissions scheme, Eni accrued an expense of €850 million for allowances corresponding to 11.7 million tons of CO 2 emissions (11.5 million tons in 2023 for a total expense of €950 million). Due to the likelihood of new regulations in this area and expectations of a reduction in free allowances under the European ETS and the likely adoption of similar schemes in other jurisdictions, Eni could incur increased investments and significantly higher operating expenses in case the Company is unable to reduce the carbon footprint of its operations.
It is also possible that new restrictions on oil&gas activities may be introduced in response to the climate emergency. Governments in jurisdictions where we operate may deny permissions to start new oil and gas projects or may impose restrictions on drilling and other field activities. These possible developments could significantly and negatively affect our business’s prospects and results of operations.
6
b) Market/Technological risk: in the long-term demands for hydrocarbons may be materially reduced by the projected mass adoption of electric vehicles, the development of green hydrogen, the deployment of massive investments to grow renewable energies also supported by governments fiscal policies and the development of other technologies to produce clean feedstock, fuels, and energy.
In the long term, the weight of hydrocarbons in the global energy mix may decline due to an expected increase in the amount of energy generated by renewable sources, the possible emergence of new products and technologies, as well as changing consumers’ preferences. The automotive industry is investing material amounts of resources to ramp up the production of electric vehicles (EVs), whose sales according to certain outlooks are expected to surpass internal-combustion-engine sales by 2030 also helped by state tax-incentives and governmental targets on the production of EVs and restrictions or ban on sales of internal-combustion-engine cars. In the long term this trend could disrupt the consumption of gasoline which is one of the main drivers of global crude oil demand. Other potentially disruptive technologies designated to produce clean energy and fuels are emerging, driven by the development of hydrogen-based solutions as an energy vector or the utilization of renewables feedstock to manufacture fuels and other goods replacing oil-based products. Electricity generation from wind power or solar technologies is projected to grow massively in line with the stated targets by several governments and institutions like the EU, the United States, and the UK to decarbonize the electricity sector, and this could reduce demand for gas-fired electricity generation. Finally, some market forecasters are projecting a resurgence of investments in nuclear capacity due to a changing perception from public opinions and institutions about the role of this form of energy in the global mix and its being carbon neutral. As matter of fact, the EU has recently upgraded nuclear energy as a net zero emission technology.
These trends could reduce demand for hydrocarbons in the long-term.
A large portion of Eni’s business depends on the global demand for oil and natural gas. If existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including state incentives to conserve energy or use alternative energy sources, technological breakthroughs in the field of renewable energies, hydrogen, production of nuclear energy or mass adoption of electric vehicles trigger a structural decline in worldwide demand for oil and natural gas, Eni’s results of operations and business prospects may be materially and adversely affected in case the Company fails to adapt its business model at the same pace of the energy transition as the economy.
c) Legal risk: several lawsuits are pending in various jurisdictions against oil&gas companies based on alleged violations of human rights, damage to environment and other claims and such legal actions may be brought against us.
In recent years, there has been a marked increase in climate-based litigation. Courts could be more likely to hold companies who have allegedly made the most significant contributions to climate change to account. Cases brought to courts against oil&gas companies in several jurisdictions indicate that there are risks that oil and gas companies may have an individual legal responsibility to reduce emissions to address climate change based on an alleged relationship between climate change and human rights violations. Courts may condemn oil and gas companies to compensate individuals, communities, and states for the economic losses due to global warming because of their alleged responsibility in supporting hydrocarbons and their alleged awareness of knowingly hurting the environment. In some cases, companies’ boards have been summoned for having allegedly failed to take effective actions to contrast climate change.
Private individuals, associations and NGOs may also bring legal actions against states or companies to get them condemned to adopt stricter targets of reducing GHG emissions and that could entail more restrictive measures on businesses. For example, in 2023, certain NGOs and several private citizens filed a complaint before an Italian court alleging that Eni is liable for climate change. The plaintiffs claimed economic losses and other damages and requested that Eni revises its decarbonization strategy and immediately stops any harmful conducts, alleging several environmental crimes and violations of human rights.
As such, climate litigation represents a significant risk. In case the Company is condemned to reduce its GHG emissions at a much faster rate than planned by management or to compensate for damage related to climate change due to ongoing or potential lawsuits, we could incur a material adverse effect on our results of operations and business’s prospects.
7
d) Reputational risk: the consideration of oil&gas companies as poorly performing investments from an environmental standpoint by financial market participants, could reduce the attractiveness of their securities or limit their ability to access the capital markets. Activist investors have been seeking to interfere in companies’ plans and strategies through matter of shareholders’ resolutions and other means.
The reputational risk of oil&gas companies owes to the growing perception by certain governments, financial institutions, and the society that those companies may be allegedly liable for global warming due to GHG emissions across the hydrocarbon value chain, particularly related to the use of energy products, and may be poorly performing players in the ESG dimensions. This could possibly impair their reputation and make their securities and debt instruments less attractive than other industrial sectors to investors and lenders.
Asset managers, mutual funds, global allocation funds, generalist investors and pensions funds have been reducing their exposure to the fossil fuel industry due to the adoption of stricter ESG criteria in selecting investing opportunities. In some cases, those investors have adopted climate change targets in determining their policies of asset allocations. Many of them have announced plans to completely divest from the fossil fuel industry. This trend could reduce the market for our share and negatively affect shareholders’ returns. Likewise, banks, financing institutions, lenders and insurance companies are cutting exposure to the fossil fuel industry due to the need to comply with ESG mandate or to reach emission reduction targets in their portfolios and this could limit our ability to access new financing, could drive a rise in borrowing costs to us or increase the costs of insuring our assets. Several large, well established financing institutions have announced their intention to stop financing directly the development new oil and gas fields, a move that could herald an emerging trend among banks and lenders towards a phase-out of financing the hydrocarbons sector.
As a result of those developments, we could expect the cost of capital to the Company to rise in the future and reduced ability on part of Eni to obtain financing for future projects in the oil&gas business or to obtain it at competitive rates, which may curb our investment opportunities or drive an increase in financing expenses, negatively affecting our results of operations, returns on investments and business prospects.
Shareholders and activist funds may have resolutions passed at annual general meetings of listed oil&gas companies, which could interfere with management’s long-term goals, strategies and capital allocation processes leading to unplanned cost increases and sub-optimal investment decisions. Activist investors may also bring lawsuit against oil&gas companies and their boards, claiming their responsibilities for not implementing adequate strategies to manage the transition risk; and we believe that such kind of claims can be brought against us.
e) Climate change adaptation: extreme weather phenomena, which are allegedly caused by climate change, may disrupt our operations
The scientific community has concluded that increasing global average temperature produces significant physical effects, such as the increased frequency and severity of hurricanes, storms, droughts, floods, or other extreme climatic events that could interfere with Eni’s operations and damage Eni’s facilities. Extreme and unpredictable weather phenomena can result in material disruption to Eni’s operations, and consequent loss of or damage to properties and facilities, as well as a loss of output, loss of revenues, increasing maintenance and repair expenses and cash flow shortfall.
As a result of these trends, climate-related risks could have a material and adverse effect on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends and the price of Eni’s shares.
Investments in our lower carbon products and services may not achieve expected returns
We are building our portfolio of lower carbon products and services such as electricity generated from solar and wind power, biofuels, projects for permanent geological sequestration of CO 2 , and charging for electric vehicles through organic and inorganic growth.
In expanding our offerings of these lower carbon products and services, we expect to undertake acquisitions and form partnerships. The success of these transactions will depend on our ability to realize the synergies from combining our respective resources and capabilities, including the development of new processes, systems and distribution channels. For example, it may take time to develop these areas through retraining our workforce and recruitment for the necessary new skills. It may take longer to realize the expected returns from these transactions.
The operating margins for our lower carbon products and services may not be as high as the margins we have experienced historically in our oil and gas operations. Furthermore, lower carbon products are experiencing increasing competition risks. In 2024, our biofuels margins were negatively affected by an oversupply of products coming from China, which found an outlet in the European market, as well as by an uncertain regulatory environment. Renewable electricity sold at spot markets is exposed to risks of uneconomic pricing due to objective limits of current transmission networks to handle peak production volumes which are a feature of the renewable sector.
Therefore, developing our lower carbon products and services is subject to challenges which could have a material adverse effect on future results of operations, cash flow, liquidity, business prospects, financial condition, shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares may be adversely and significantly affected.
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Risks deriving from Eni’s exposure to weather conditions
Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of Eni’s businesses engaged in the marketing of natural gas and, to a lesser extent, the Refining & Marketing business, as well as the comparability of results over different periods may be affected by such changes in weather conditions. Over recent years, this pattern could have been possibly affected by the rising frequency of weather trends like milder winter or extreme weather events like heatwaves or unusually cold snaps.
The Group is exposed to significant operational and economic risks associated with the exploration and production of crude oil and natural gas
The exploration and production of oil and natural gas require high levels of capital expenditures and are subject to specific operational and economic risks as well as to natural hazards and other uncertainties. The natural hazards and the economic risks described below could have an adverse and significant impact on Eni’s future growth prospects, results of operations, cash flows, liquidity, and shareholders’ returns.
a) Operational risks in connection to drilling and extraction operations
The physical and geological characteristics of oil and gas fields entail natural hazards and other operational risks including risks of eruptions of hydrocarbons, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, oil spills, gas leaks, risks of blowout, fire or explosion and risks of earthquake in connection with drilling and extraction activities. Eni has material offshore operations which are inherently riskier than onshore activities. In 2024, approximately 70 % of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Norway, Libya, Indonesia, Angola, Kazakhstan, the United Arab Emirates, Venezuela, the United Kingdom and Congo. Offshore accidents and oil spills could cause damage of catastrophic proportions to the ecosystem and to communities’ health and security due to the apparent difficulties in handling hydrocarbons containment in the sea, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Furthermore, offshore operations are subject to marine risks, including storms and other adverse weather conditions and perils of vessel collisions, which may cause material adverse effects on the Group’s operations and the ecosystem.
b) Exploratory drilling efforts may be unsuccessful
Exploration activities are mainly subject to the mining risk, i.e. the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling and completing wells have margins of uncertainty, and drilling operations may be unsuccessful because of a large variety of factors, including geological failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents. A large part of the Company’s exploratory drilling operations is located offshore, including in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea, the Gulf of Mexico, deep water leases off West Africa, Indonesia, the Mediterranean Sea and the Caspian Sea). In these locations, the Company generally experiences higher operational risks and more challenging conditions and incurs higher exploration costs than onshore. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the operational and the financial risks associated with these activities.
Because Eni plans to make significant investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas, which is highly dependent on the rate of success of exploration projects and could have an adverse impact on Eni’s future performance, growth prospects and returns. In 2024, we incurred €555 million of charges related to the write-offs of capitalized exploration expenditures and unproved properties due to the discovery of uneconomic quantities of reserves and other reasons.
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c) Development projects bear significant operational risks which may adversely affect actual returns
Projects to develop and market reserves of crude oil and natural gas normally entail long lead times because of the complexity of the activities required to achieve the production start-up, which comprise:
• appraising a discovery to evaluate the economic and operating viability of a development project;
• finalizing negotiations with joint venture partners, governments and state-owned companies, suppliers and potential customers to define project terms and conditions, including, for example, the fiscal take, the production sharing terms with the first party, or negotiating favorable long-term contracts to market gas reserves;
• obtaining timely issuance of permits and licenses by government agencies, including obtaining all necessary administrative authorizations to drill locations, install producing infrastructures, build pipelines and related equipment to transport and market hydrocarbons;
• effectively carrying out the front-end engineering design in order to prevent the occurrence of technical inconvenience during the execution phase;
• timely manufacturing and delivery of critical plants and equipment by contractors, like platforms and floating production storage and offloading (FPSO) vessels, or market availability for renting such kind of vessels, as well as building transport infrastructures to export production to final markets. For example, in case of a shortage of FPSOs to rent, we may have no other option than to build the facility thus incurring upfront the whole costs of the investment, which could negatively affect a project’s returns;
• preventing risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
• carefully planning the commissioning and hook-up phase where mismanagement might lead to delays to achieve first oil;
• changes in operating conditions and cost overruns. Notwithstanding inflationary pressures have eased in 2024, we expect the costs of renting rigs and other drilling vessels and facilities to remain elevated as oil companies competes for a stable amount of supply of this kind of equipment considering the restructuring the oilfield service sector has undergone due to reduced capital spending by their clients; and
• operating risks, including third-party claims, environmentalists protests, changes to the work scope requested by governmental authorities, contractors’ underperformance.
Moreover, projects executed with partners and joint venture partners limit the ability of the Company to manage risks and costs, and Eni may have limited influence over and control of the operations and performance of its partners.
The occurrence of any of such risks may negatively affect the time-to-market of the reserves and may cause cost overruns and start-up delays, lengthening the project pay-back period. Those risks would adversely affect the economic returns of Eni’s development projects and the achievement of production growth targets, also considering that those projects are exposed to the volatility of oil and gas prices which may be substantially different from those estimated when the investment decision was made, thereby leading to lower return rates.
Finally, if the Company is unable to develop and operate major projects as planned, or in case actual reservoir performance and natural field decline do not meet management’s expectations, it could incur significant impairment losses of capitalized costs associated with reduced future cash flows of those projects.
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d) Inability to replace produced oil and natural gas reserves could adversely impact results of operations and financial condition, including cash flows
Future oil and gas production is a function of the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiations with national oil companies and other owners of known reserves and acquisitions.
An inability to replace produced reserves by discovering, acquiring, and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of reserve replacement, Eni’s future total proved reserves and production will decline.
e) Uncertainties in estimates of oil and natural gas reserves
The accuracy of proved reserve estimates and of projections of future rates of production and timing of development costs depends on several factors, assumptions and variables, including:
● the quality of available geological, technical and economic data and their interpretation and judgment;
● management’s assumptions regarding future rates of production and costs and timing of operating and development costs. The projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions;
● changes in the prevailing tax rules, other government regulations and contractual terms and conditions;
● results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and
● changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.
Many of the factors, assumptions and variables underlying the estimation of proved reserves involve management’s judgement or are outside management’s control (prices, governmental regulations) and may change over time, therefore affecting the estimates of oil and natural gas reserves from year-to-year.
The prices used in calculating Eni’s estimated proved reserves are, in accordance with the U.S. Securities and Exchange Commission (the “U.S. SEC”) requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ending at December 31, 2024, average prices were based on 81 $/barrel for the Brent crude oil, 2 $/barrel lower than the 2023 reference price 83 $/barrel, resulting in us having to remove 22 million BOE of reserves that have become uneconomical at a lower price.
Accordingly, the estimated reserves reported as of the end of 2024 could be significantly different from the quantities of oil and natural gas that will be ultimately recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s business prospects, results of operations, cash flows and liquidity.
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f) The development of the Group’s proved undeveloped reserves “PUD” may take longer and may require higher levels of capital expenditures than it currently anticipates, or the Group’s proved undeveloped reserves may not ultimately be developed or produced
As of December 31, 2024, approximately 43% of the Group’s total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of PUD requires significant capital expenditures and successful drilling operations. The Group’s reserve estimates assume the Group can and will make these expenditures and conduct these operations successfully. These assumptions may prove to be inaccurate and are subject to the risk of a structural decline in the prices of hydrocarbons, which could reduce available funds to develop PUD. The Group’s reserve report as of December 31, 2024, includes estimates of total future development and decommissioning costs associated with the Group’s proved total reserves of approximately €41.7 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities; €42.6 billion in 2023). It’s uncertain that estimated costs of the development of these reserves will prove correct, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company’s plans to develop those reserves, or if it is not otherwise able to successfully develop these reserves as a result of the Group’s inability to fund necessary capital expenditures due to a prolonged decline in the price of hydrocarbons or otherwise, it will be required to remove the associated volumes from the Group’s reported proved reserves.
g) The oil&gas industry is a capital-intensive business and needs large amount of funds to find and develop reserves. In case the Group does not have access to sufficient funds its oil&gas business may decline
The oil and gas industry is a capital intensive business. Eni makes and expects to continue making substantial capital expenditures in its business for the exploration, development and production of oil and natural gas reserves. Historically, Eni’s capital expenditures have been financed with cash generated from operations, proceeds from asset disposals, borrowings under its credit facilities and proceeds from the issuance of debt and bonds. The actual amount and timing of future capital expenditures may differ materially from Eni’s estimates because of, among other things, changes in commodity prices, changes in cost of oil services, available cash flows, lack of access to capital, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments. Eni’s cash flows from operations and access to capital markets are subject to several variables, including but not limited to:
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the amount of Eni’s proved reserves; |
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the volume of crude oil and natural gas Eni is able to produce and sell from existing wells; |
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the prices at which crude oil and natural gas are marketed; |
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Eni’s ability to acquire, find and produce new reserves; and |
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the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds considering that adoption of ESG targets by lenders may restrict our access to third-party financing. |
If cash generated by operations, cash from asset disposals, or cash available under Eni’s liquidity reserves or its credit facilities or issuance of new bonds is not sufficient to meet capital requirements, due to among other things a decline in oil and gas prices or more stringent ESG criteria adopted by banks and other lenders, reduce cash flows or failure to obtain additional financing could result in a curtailment of operations relating to the development of Eni’s reserves, which in turn could adversely affect its results of operations and cash flows and its ability to achieve its growth plans. In the next four-year plan we are forecasting significant capital expenditures of more than €5 billion on average per year to fund new development projects and production ramp ups and considering expected continuation of inflationary trends in upstream costs. In case of a cash flow shortfall, we may be forced to take on new finance debt from banks and financing institutions to pursue our development plans and that could increase our financial risk profile. Finally, funding Eni’s capital expenditures with additional debt will increase its leverage and the issuance of additional debt will require a portion of Eni’s cash flows from operations to be used for the payment of interest.
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h ) Oil and gas activity may be subject to increasingly high levels of income taxes and royalties
Oil and gas operations are subject to the payment of royalties and income taxes, which tend to be higher than those payable in other commercial activities. Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices, which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices. Adverse changes in the tax rate applicable to the Group’s profit before income taxes in its oil and gas operations would have a negative impact on Eni’s future results of operations and cash flows.
In 2022, in response to a surge in hydrocarbons and electricity prices due to the perceived risks of disruption in connection with the Russian military aggression of Ukraine, governments of the EU member states and of the UK have enacted solidaristic contributions in the form of one-off or temporary windfall levies to increase the fiscal take on the profits of energy companies relating to the portion of those profits deemed to exceed historical averages, to collect funds to alleviate the financial burden on households and businesses due to rising costs of fuels and energy. In 2024, we disbursed about €0.45 billion to settle an Italian windfall tax levied in 2023 on profits of energy companies. Notwithstanding hydrocarbons and electricity prices have been on a downward trend since 2023, they are still perceived to remain at elevated levels compared to historic averages by governments, businesses, and consumers in the Eurozone so to hamper competitiveness of the manufacturing sector and to reduce the purchase power of households. Given rising pressures on public finances due to an ongoing economic slowdown in the EU and the general consideration that the oil&gas companies may continue benefiting from the ongoing geopolitical tensions in Ukraine and the Middle East, management cannot rule out the possibility of the introduction of new windfall taxes and other extraordinary levies targeting the hydrocarbons sector, which could negatively affect the Group’s results of operations and cash flows.
i) The present value of future net revenues from Eni’s proved reserves will not necessarily be the same as the current market value of Eni’s estimated crude oil and natural gas reserves
The present value of future net revenues from Eni’s proved reserves may differ from the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with the SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first day of the month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the SEC pricing method in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
● the actual prices Eni receives for sales of crude oil and natural gas;
● the actual cost and timing of development and production expenditures;
● the timing and amount of actual production; and
● changes in governmental regulations or taxation.
The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. Additionally, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni’s reserves or the crude oil and natural gas industry in general.
At December 31, 2024, the net present value of Eni’s proved reserves totaled approximately €55.6 billion. The average prices used to estimate Eni’s proved reserves and the net present value at December 31, 2024, as calculated in accordance with the SEC rules, were at around 80 $/barrel for the Brent crude oil. Actual future prices may materially differ from those used in our year-end estimates. Commodity prices have decreased significantly in the first quarter of 2025 compared to the price used in the reserve calculations at 2024 year-end. Holding all other factors constant, if commodity prices used in Eni’s year-end reserve estimates at end of 2025 were in line with the pricing environment existing at the end of the first quarter of 2025, Eni’s PV-10 at December 31, 2025 would decrease.
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Risks related to political considerations
As at December 31, 2024, about 83% of Eni’s proved hydrocarbon reserves were located in non-OECD (Organisation for Economic Co-operation and Development) countries, mainly in Africa, Central Asia and Middle East where the socio-political framework, the financial system and the macroeconomic outlook are less stable than in the OECD countries. In those non-OECD countries, Eni is exposed to a wide range of political risks and uncertainties, which may impair Eni’s ability to continue operating economically on a temporary or permanent basis, and Eni’s ability to access oil and gas reserves. Particularly, Eni faces risks in connection with the following potential issues and risks:
● socio-political instability leading to internal conflicts, revolutions, establishment of non-democratic regimes, protests, attacks, and other forms of civil disorder and unrest, such as strikes, riots, sabotage, blockades, vandalism, and theft of crude oil at pipelines, acts of violence and similar events. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, loss of assets and threats to the security of personnel. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographical areas in which Eni operates. Additionally, any possible reprisals because of military or other action, such as acts of terrorism in Europe, the USA or elsewhere, could have a material adverse effect on the world economy and hence on the global demand for hydrocarbons;
● lack of well-established and reliable legal systems and uncertainties surrounding the enforcement of contractual rights;
● unfavorable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalization or forced divestiture of assets and unilateral cancellation or modification of contractual terms, tax or royalty increases (including retroactive claims) and restrictions on exploration, production, imports and exports;
● sovereign default or financial instability since those countries rely heavily on petroleum revenues to sustain public finance. Financial difficulties at country level often translate into failure by state-owned companies and agencies to fulfil their financial obligations towards Eni relating to funding capital commitments in projects operated by Eni or to timely paying for supplies of equity oil and gas volumes;
● difficulties in finding qualified international or local suppliers in critical operating environments;
● risks of U.S. sanctions which could impair our ability to conduct profitable operations or to recover our investments like for example in Venezuela or other commercial restrictions imposed by U.S. to certain economic sectors and activities involving Chinese suppliers which could led to projects delays and cost overruns; and
● complex processes of granting authorizations or licenses affecting time-to-market of certain development projects.
Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to Libya, Venezuela, Nigeria, and Egypt.
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Eni’s operations in Libya are exposed to geopolitical risks. The social and political instability of the country dates to the revolution of 2011 that brought a change of regime and a civil war with a material impact on our operations in that year. A divided political landscape emerged from those events, which caused a prolonged period of internal instability which has triggered several acts of internal conflict, clashes, civil turmoil, and unrest involving the opposing factions amidst failed attempts to hold general elections and appoint a national government, resulting in several disruptions to Eni’s activities in the country up and until 2023 when a relative stability was achieved. In 2024, a rift between the Government of National Unity installed in Tripoli and recognized by the UN and the self-appointed National Stability Government installed in the east of the country regarding the appointment of the chief of Libya’s national bank has resulted in a blockade of oil export terminals in the Eastern part of the country and in declaration of force majeure at several oilfields in the Southern zone which have only marginally impacted our operations which are mainly focused on gas asset. In 2024, Eni production in Libya was 169 kboe/d, equal to about 10% of the Group’s total production and was in line with management’s plans. Management continues to monitor Libya’s geopolitical situation which is recognized as a source of risk and uncertainty to Eni’s operations in the country and related Group’s financial results.
The financial difficulties of Venezuela due to the US sanction regime have impaired our ability to conduct profitable operations in the country. Currently, after having completely impaired other projects in past reporting periods, the Company retains just one asset in Venezuela: the 50%-participated Cardón IV joint venture, which is operating an offshore natural gas field and is supplying its production to the national oil company, Petroleos de Venezuela SA (“PDVSA”), under a long-term supply agreement. PDVSA has failed to regularly pay the receivables for the gas volumes supplied by Cardón IV venture and consequently a significant amount of overdue trading receivables has accumulated over the years and a credit loss provision has been booked to reflect the counterparty risk. In 2024, thanks to a temporary suspension of sanctions granted by the U.S and an additional waiver obtained by the US Department of State, it was possible to offset part of the long-standing overdue receivables accrued with PDVSA-owned crude oil cargoes. As of 31 December 2024, Eni's credit exposure to PDVSA amounted to approximately €2.1 billion (€0.8 billion net of the impairment provision). There is a great deal of uncertainty about the evolution of the US sanctions against Venezuela and our ability to recover our outstanding receivables.
The Group has significant credit exposure towards state-owned and privately-held local companies in Nigeria following the divestment of its onshore operations in the country to a local company. Considering the historic underperformance of our counterparts in reimbursing amounts owed to us considering a deteriorated financial framework of the country, we believe that we are exposed to a credit risk going forward.
Egypt has been experiencing financial restraints due to an economic slowdown and a contraction in reserves of foreign currencies. Eni is currently supplying its equity share of natural gas production to local state-owned oil companies that in the past have failed to pay receivables owed to us in a timely manner; in 2024 the situation has improved, and no incremental overdue amounts have been noted. Due to this, a loss provision in the balance sheet has been defined accordingly, reflecting the time value of an agreed repayment plan.
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Sanction targets
The most relevant sanction programs for Eni are those issued by the European Union and the United States and, as of today, the restrictive measures adopted by such authorities in respect of Russia.
As consequence of Russia’s military aggression of Ukraine, the European Union, the United Kingdom, the United States and the G-7 countries adopted a comprehensive system of sanctions against Russia to weaken its economy and its ability to finance the war. The sanction system is constantly evolving.
The main targets of the sanctions are the Russian Central Bank and the major financial institutions of the country, as well as Russia’s exports of crude oil and refined products to international markets. Considering the complexity of the sanctions and the existing Eni’s contracts for natural gas supplies from Russia and the need to make payments to Russian counterparties, the Company is exposed to the risk of possible violations of the sanction’s regime.
Eni adopted the necessary measures to ensure that its activities are carried out in accordance with the applicable rules, ensuring continuous monitoring of the evolution in the sanction framework, to adapt on an ongoing basis its activities to the applicable restrictions.
Furthermore, an escalation of the international crisis, resulting in a tightening of sanctions, could entail a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group’s business, financial conditions, results of operations and prospects.
From 2017, the United States have enacted a regime of economic and financial sanctions against Venezuela, which have been expanded to encompass the country’s oil&gas sector where Eni is currently operating. The U.S. sanction regime is also restricting any Venezuelan oil exports, including swap schemes utilized by foreign entities to recover trade and financing receivables from PDVSA and other Venezuelan counterparties. The U.S. sanction regime has reduced the Group’s ability to collect the trade receivable owed to Eni for its activity in the country, except for limited waivers which have been agreed with U.S. relevant authorities from time to time allowing the Company to lift some PDVSA’s entitlements of crude oil as an in-kind reimbursement of overdue amounts owed to us in connection with our supplies of equity natural gas to PDVSA. Recoverability of trade receivables owed to us by PDVSA is uncertain and there is no assurance that we will able to recover the full amount of credits outstanding as of end of 2024 (gross amount of about €2.1 billion). See notes to the Consolidated Financial Statements.
Eni carefully evaluates on a case-by-case basis the adoption of adequate measures to minimize its exposure to any sanctions risk which may affect its business operation. In any case, the U.S. sanctions add stress to the already complex financial, political, and operating outlook of the country, which could further limit the ability of Eni to recover its investments in Venezuela.
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Specific risks of the Company’s gas business in Italy
a) Currently, negative trends in the competitive environment of the European natural gas sector may impair the Company’s ability to fulfil its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts
Eni is currently party to a few long-term gas supply contracts with state-owned companies of key producing countries, from where most of the gas supplies directed to Europe are sourced via pipeline (Russia, Algeria and Norway). These contracts which were intended to support Eni’s sales plan in Italy and in other European markets, provide take-or-pay clauses whereby the Company has an obligation to lift minimum, preset volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to a minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations which arise from contracts with transmission system operators or pipeline owners, which the Company has entered into to secure long-term transport capacity. Long-term gas supply contracts with take-or pay clauses expose the Company to a volume risk, as the Company is obligated to purchase an annual minimum volume of gas, or in case of failure, to pay the underlying price. The structure of the Company’s portfolio of gas supply contracts is a risk to the profitability outlook of Eni’s wholesale gas business due to the current competitive dynamics in the European gas markets. In past downturns of the gas sector, the Company incurred significant cash outflows in response to its take-or-pay obligations. Furthermore, the Company’s wholesale business is exposed to volatile spreads between the procurement costs of gas, which are linked to spot prices at European hubs or to the price of crude oil, and the selling prices of gas which are mainly indexed to spot prices at the Italian hub. In case the Company fails to meet its sales targets due to competition in the European gas market, it could incur the take-or-pay clause at its long-term supply contracts which could negatively affect its financial performance.
Eni’s management is planning to continue its strategy of renegotiating the Company’s long-term gas supply contracts in order to constantly align pricing terms to current market conditions as they evolve and to obtain greater operational flexibility to better manage the take-or-pay obligations (volumes and delivery points among others), considering the risk factors described above. The revision clauses included in these contracts state the right of each counterparty to renegotiate the economic terms and other contractual conditions periodically, in relation to ongoing changes in the gas scenario. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately obtained and the timing of recognition of profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, both parties can start an arbitration procedure to obtain revised contractual conditions. All these possible developments within the renegotiation process could increase the level of risks and uncertainties relating the outcome of those renegotiations.
b) Risks associated with the regulatory powers entrusted to the Italian Regulatory Authority for Energy, Networks and Environment in the matter of pricing to residential customers
Eni’s wholesale gas and retail gas and power businesses are subject to regulatory risks mainly in Italy’s domestic market. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas and power pricing. Specifically, the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users who are opting for adhering to regulated tariffs until the market is fully opened. Developments in the regulatory framework aimed at increasing the level of market liquidity, promoting deregulation or limiting operators’ ability to pass cost increases in raw materials onto customers may negatively affect future sales margins of gas and electricity, operating results, and cash flow. In the current environment characterized by rising energy costs, it is possible that the Authority may enact measures intended to limit revenues of inframarginal power generation and to reduce the indexation of the cost of the raw materials in pricing formulae applied by retail companies that market natural gas and electricity to residential customers and that development could negatively affect our results of operations and cash flow in the domestic retail business of natural gas and power. In the current energy crisis context, many regulatory interventions at both the EU and national level aim to ensure security of supply and curb consumptions and energy prices for final customers. Our GGP business that engages in the wholesale marketing of natural gas and the power generation business that sell produced electricity on the spot market could be exposed to a regulatory risk, although on a smaller scale than the retail business due to well-established and liquid spot markets for natural gas and electricity.
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ENVIRONMENTAL, HEALTH AND SAFETY RISKS.
a) The Group is exposed to material HSE risks due to the nature of its operations
The Group engages in the exploration and production of crude oil and natural gas, processing, transportation and refining of crude oil, transport of natural gas by pipeline, transport of LNG by carriers, storage and distribution of petroleum products and the production of base chemicals, plastics, and elastomers. The Group’s operations expose Eni to a wide range of significant health, safety, security, and environmental risks. Flammability and toxicity of hydrocarbons, technical faults, malfunctioning of plants, equipment and facilities, control systems failure, human errors, acts of sabotage, attacks, loss of containment and climate-related hazards can trigger adverse consequences such as explosions, blow-outs, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants and pollutants in the air, ground and water, toxic emissions, and other negative events. The magnitude of these risks is influenced by the geographic range, operational diversity, and technical complexity of Eni’s activities. Eni’s future results of operations, cash flow and liquidity depend on its ability to identify and address the risks and hazards inherent to operating in those industries.
b) Eni expects to incur material operating expenses and expenditures in future years in relation to compliance with applicable environmental, health and safety regulations, including compliance with any national or international regulation on greenhouse gas (GHG) emissions, as well as to retain high standards of reliability in its industrial operations
Eni’s activities are highly regulated. Laws and regulations intended to preserve the environment and to safeguard health and safety of workers and communities impose several obligations, requirements, and prohibitions to the Company’s businesses due to their inherent risky nature because of flammability, dangerousness, and toxicity of hydrocarbons and of objective complexities of industrial processes to explore, develop, extract, refine, handle and transport oil, natural gas, liquified natural gas and products. These laws and regulations require acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, including refinery and petrochemical plant operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace, the health of employees, contractors and other Company collaborators and of communities involved by the Company’s activities, and impose criminal and civil liabilities for polluting the environment or harming employees’ or communities’ health and safety as result from the Group’s operations. These laws and regulations control the emission of scrap substances and pollutants, discipline the handling of hazardous materials and waste and set limits to or prohibit the discharge of soil, water or groundwater contaminants, emissions of toxic gases and other air pollutants or can impose taxes on carbon dioxide emissions, as in the case of the European Trading Scheme that requires the purchase of an emission allowance for each tons of carbon dioxide emitted in the environment above a pre-set threshold, resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned or operated by Eni.
Breaches of environmental, health and safety laws and regulations as in the case of negligent or willful release of pollutants and contaminants into the atmosphere, the soil, water or groundwater or exceeding the concentration thresholds of contaminants set by the law expose the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage and expenses for environmental remediation and clean-up, as well as damage to reputation. Furthermore, in the case of violation of certain rules regarding the safeguard of the environment and the health and safety of employees, contractors, and other collaborators of the Company, and of communities, the Company may incur liabilities in connection with the negligent or willful violations of laws by its employees as per Italian Law Decree No. 231/2001.
Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations, to upgrade plants and equipment to improve security standards and to safeguard the environment and the health and safety of employees, contractors and communities involved by the Company activities by retaining reliable industrial operations and by adhering to industry best practices, including:
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costs to prevent, control, eliminate or reduce release of pollutants and other hazardous materials in the soil, groundwater and the marine environment, and of GHG and other toxic gases in the atmosphere, as well as to maintain high standards of efficiency and reliability at its plants and equipment, including offshore platforms, FPSO vessels, oil&gas treatment plants, refineries, petrochemicals complexes and pipelines; |
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remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties, as well as decommissioning costs of productive infrastructures and well plugging of industrial hubs and oil and gas fields once production and manufacturing activities are discontinued; and |
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damage compensation claimed by individuals and entities, including local, regional, or state administrations in case Eni is found liable of a HSE incident, contamination, pollution of marine or water resources, soil or the atmosphere, or violations of HSE laws. |
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As a further consequence of any new laws and regulations or other factors, like the actual or alleged occurrence of environmental damage at Eni’s plants and facilities, the Company may be forced to curtail, modify, or cease certain operations or implement temporary shutdowns of facilities. Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.
c) The Group is exposed to operational risks in connection with the transportation of hydrocarbons
All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend on several factors and variables, including the hazardous nature of the products transported due to their flammability and toxicity, the transportation methods utilized (pipelines, shipping, river freight, rail, road and gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly exposed to risks of blowout, fire, release of toxic agents in the atmosphere, spillover of oil and other pollutants and loss of containment and, given that normally high volumes are involved, could present significant risks to people, the environment and the property.
d) The Group is not insured against all potential HSE risks
Eni retains worldwide third-party liability insurance coverage, which is designed to hedge part of the liabilities associated with possible incidents occurring at the Group plants and installations resulting in damage to third parties, loss of value to the Group’s assets related to adverse events and in connection with environmental clean-up and remediation. Management believes that its insurance coverage is in line with industry practice and is enough to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster, such as the incident which occurred at the Macondo well in the Gulf of Mexico several years ago, Eni’s third-party liability insurance would not provide any material coverage and thus the Company’s liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in case of a disaster of material proportions would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such a loss would not have a material adverse effect on the Company.
The Company has invested and will continue to invest significant financial resources to continuously upgrade the methods and systems for safeguarding the reliability of its plants, production facilities, well execution, vessels, transport and storage infrastructures, the safety and the health of its employees, contractors, local communities, and the environment, to prevent risks, to comply with applicable laws and policies and to respond to and learn from unforeseen incidents. However, these measures may ultimately not be completely successful in preventing and/or altogether eliminating risks of adverse events. Failure to properly manage these risks as well as accidental events like human errors, unexpected system failure, sabotages, cyberattacks or other unexpected factors could cause incidents of any kind of impact and magnitude which could trigger in a worst case scenario serious consequences, including loss of life, damage to properties, environmental pollution, legal liabilities and/or damage claims and consequently a disruption in operations and potential economic losses that could have a material and adverse effect on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares. For example, in December 2024, a fire occurred at a fuel storage site operated by Eni, which caused the death of five people while working at site operations, several wounded and damage to property. The Group made a loss provision to account for all damage to people and property because insurance coverage was not enough.
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LEGAL, IT AND FINANCIAL RISKS
a) Eni is exposed to the risk of material environmental liabilities in connection with pending litigation
Eni has incurred in the past and may incur in the future material environmental liabilities in connection with the alleged breach of environmental laws claimed by administrative bodies and third parties at industrial hubs where the Group is currently performing its activities or where the Group has ceased to operate and is performing decommissioning and remediation activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against the Company. Furthermore, environmental regulations in Italy and elsewhere typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, environmental damage, and other damages because of Eni’s conduct of operations that was lawful at the time it occurred or of the management of industrial hubs by prior operators or other third parties, who were subsequently taken over by Eni. In addition, plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found liable for violations of any environmental laws or regulations. Due to the history and development of the Group, Eni is particularly exposed to this kind of risk in Italy. The Group is performing remediation and cleaning-up activities at several Italian industrial hub where the Group’s products were produced, processed, stored, distributed, or sold, such as chemical plants, mineral-metallurgic plants, refineries, and other facilities, which were subsequently disposed of, liquidated, closed, or shut down. Eni has been alleged to be liable for having polluted and contaminated proprietary or concession areas where those dismissed industrial hubs were located. State or local public administrations have sued Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company, or which the Company has committed to performing, including allegations of violations of criminal laws (for example for alleged environmental crimes such as failure to perform soil or groundwater reclamation, environmental disaster and contamination, illegal discharge of toxic materials, amongst others). Although Eni believes that it may not be held liable for having exceeded in the past pollution thresholds that are unlawful according to current regulations, but were allowed by laws then effective, or because the Group took over operations from third parties, it cannot be excluded that Eni could potentially incur such environmental liabilities. Eni’s financial statements account for provisions relating to the expected costs to clean up and remediate contaminated areas and groundwater at Eni’s shut-down or operational Italian hubs, where legal or constructive obligations exist and the associated costs can be reasonably estimated in a reliable manner, representing management’s best estimates of the Company’s existing environmental liabilities.
Although the Company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the Company will continue to incur additional liabilities in the future. The additional costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the remediation actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the Company does not expect these costs will have a material effect on its consolidated financial position or liquidity.
b) Risks related to legal proceedings and compliance with anti-corruption legislation
Eni is the defendant in several civil and criminal actions and administrative proceedings. In future years Eni may incur significant losses due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements or to judge a negative outcome only as possible or to conclude that a contingency loss could not be estimated reliably; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to circumstances that are often inherently difficult to estimate. Certain legal proceedings and investigations in which Eni or its subsidiaries or its officers and employees are defendants might involve allegations of breaching anti-bribery and anti-corruption laws and regulations and other ethical misconduct. Such proceedings are described in the Notes to the Consolidated Financial Statements (note no.28). Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and anti-corruption laws, by Eni, its officers and employees, its partners, agents or others acting on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation, business prospects and results of operations.
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c) Risks from acquisitions
Eni is constantly monitoring the market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case of a prolonged decline in the market prices of commodities. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks related to acquisitions materialize, expected synergies from acquisition may fall short of management’s targets and Eni’s financial performance and shareholders’ returns may be adversely affected. In 2024, Eni has closed the acquisition of the group Neptune Energy with a transaction value of €2.4 billion, which represents the largest acquisition made by Eni in recent years and this deal could entail integration risks.
d) Eni’s crisis management systems may be ineffective
Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed period could prolong the impact of any disruption and could severely affect business, operations and financial results. Eni has crisis management plans and the capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, this could adversely impact the Group’s reputation, its business prospects and results of operations.
e ) Cyberattacks, disruption to or breaches of Eni’s critical IT services or digital infrastructure and security systems could adversely affect the Group’s business, increase costs and damage Eni’s reputation
The Group’s activities depend heavily on the reliability and security of its information technology (IT) systems and digital security. The Group’s IT systems, some of which are managed by third parties, are susceptible to being compromised, damaged, disrupted or shutdown due to failures during the process of upgrading or replacing software, databases or components, power or network outages, hardware failures, cyberattacks (viruses, computer intrusions), user errors or natural disasters. The cyber threat is constantly evolving. The oil and gas industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. Attacks are becoming more sophisticated with regularly renewed techniques while the digital transformation amplifies exposure to these cyber threats. The adoption of new technologies, such as the Internet of Things (IoT) or the migration to the cloud, as well as the evolution of architectures for increasingly interconnected systems, are all areas where cyber security is a very important issue. The Group and its service providers may not be able to prevent third parties from breaking into the Group’s IT systems, disrupting business operations or communications infrastructure through denial of service, attacks, or gaining access to confidential or sensitive information held in the system. The Group, like many companies, has been and expects to continue to be the target of attempted cybersecurity attacks. While the Group has not experienced any such attack that has had a material impact on its business and results of operations, the Group cannot guarantee that its security measures will be sufficient to prevent a material disruption, breach, or compromise in the future which could negatively and significantly affect the Company, its reputation and results of operations. As a result, the Group’s activities and assets could sustain serious damage, services to clients could be interrupted, material intellectual property could be divulged and, in some cases, personal injury, property damage, environmental harm and regulatory violations could occur.
f) Violations of data protection laws carry fines and expose the Company and/or its employees to criminal sanctions and civil suits
Data protection laws and regulations apply to Eni and its joint ventures and associates in most countries in which they do business. The General Data Protection Regulation (EU) 2016/679 (GDPR) came into effect in May 2018 and increased penalties up to a maximum of 4% of global annual turnover for breach of the regulation. The GDPR requires mandatory breach notification, a standard also followed outside of the EU (particularly in Asia). Non-compliance with data protection laws could expose Eni to regulatory investigations, which could result in fines and penalties as well as harm the Company’s reputation. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. The Company could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offence in some countries, and individuals can be imprisoned or fined.
If any of the risks set out above materialize, they could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
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g) Eni is exposed to treasury and trading risks, including liquidity risk, interest rate risk, foreign exchange risk, commodity price risk and credit risk and may incur substantial losses in connection with those risks
Eni’s business is exposed to the risk that changes in interest rates, foreign exchange rates or the prices of energy commodities will adversely affect the value of assets, liabilities or expected future cash flows. The Group does not hedge its exposure to volatile hydrocarbons prices in its business of developing and extracting hydrocarbons reserves and other types of commodity exposures (e.g. exposure to the volatility of refining margins and of certain portions of the gas long-term supply portfolio) except for specific markets or business conditions. The Group has established risk management procedures and enters financial derivatives contracts to hedge its exposures to different commodity indexations and to currency and interest rates risks. However, hedging may not function as expected. In addition, Eni undertakes commodity derivatives contracts to optimize commercial margins or with a view of profiting from expected movements in market prices. Those derivatives may or may not be risk-reducing. Although Eni believes it has established sound risk management procedures to monitor and control commodity trading, this activity involves elements of forecasting and Eni is exposed to the risk of incurring significant losses if prices develop contrary to management expectations and to the risk of default of counterparties.
Eni is exposed to the risks of unfavorable movements in exchange rates primarily because Eni’s consolidated financial statements are prepared in Euros, whereas Eni’s main subsidiaries in the Exploration & Production sector are utilizing the U.S. dollar as their functional currency. This translation risk is unhedged. As a rule of thumb, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity.
Eni’s credit ratings are potentially exposed to risk from possible reductions of the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the debt instruments issued by the Company could be downgraded.
Eni is exposed to credit risk. Eni’s counterparties could default, could be unable to pay the amounts owed to it in a timely manner or meet their performance obligations under contractual arrangements. These events could cause the Company to recognize loss provisions with respect to amounts owed to it by debtors of the Company and cashflow shortfall. For example, in 2024 we continued incurring credit losses in connection with our supplies of equity gas the national oil company of Venezuela “PDVSA” due to the financial difficulties of our counterpart and the effect of US sanctions. The exposure towards PDVSA has reached about €2.1 billion. More information on this issue are reported in the notes to the Consolidated Financial Statements.
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or that the Group is unable to sell its assets on the marketplace to meet short-term financial requirements and to settle obligations. Such a situation would negatively affect the Group’s results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern.
If any of the risks set out above materializes, this could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholders returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.
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Item 4. INFORMATION ON THE COMPANY
History and development of the Company
Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders. The Company shares are listed at the main Italian stock exchange, which the primary trading market for the Company, and at the New York stock exchange where the Company’s ADRs are traded under the ticker symbol “E”.
The SEC maintains an Internet site that contains reports, proxy and information statements of the Company, and other information regarding Eni that we file electronically with the SEC at http:// www.sec.gov, searching for: ENI SPA (E, EIPAF) (CIK 0001002242). The same reports and information are available at the Company’s website: www.eni.com .
Eni’s r egister ed head of fice is located at Piazza le Enrico Mattei 1, R ome , Ita ly (telephone number : +39-0659821).
Eni branches ar e located in:
San Donato Milanese (Milan), Vi a Emilia, 1; and
San Donato Milanese (Milan), Piazza Ezio V anoni, 1. Internet addr ess: eni.com
The name of the agent of Eni in the United States is Marco Margheri, Washington DC – USA 601, 13th street, NW 20005.
Eni Spa is the parent company of Eni’s group companies. Eni Spa together with its subsidiaries and through several participated entities engages in producing and selling energy products and services to worldwide markets, with operations in the traditional businesses of exploring for, developing, extracting, and marketing crude oil and natural gas, manufacturing and marketing oil-based fuels and chemicals products and gas-fired power as well as energy products from renewable sources. The Company is implementing a strategy designed to improve profitability and shareholders’ returns leveraging on maximizing the value of its assets’ portfolio, through organic exploration, fast reserve development, production growth and by applying the satellite model to unlock asset value, while restructuring and revamping the businesses operating in challenged sectors. This strategy aims to gradually reduce the Company’s carbon footprint, with the goal of reaching carbon neutrality by mid-century.
Effective October 1st, 2024, the Company reorganized its business activities into three business groups to increase the effectiveness of the strategy execution:
the “Chief Transition & Financial Officer” business group, responsible for increasing the value of the two Eni’s subsidiaries, Plenitude and Enilive, which are engaged in growing the businesses related to the energy transition, mainly production of electricity from renewable sources, e-mobility and manufacturing of biofuels in synergy with the traditional activities of retail marketing of gas, power and fuels. The goal of increasing the value of those two subsidiaries will be pursued also by means of third-party investments in the share capital of these entities and possibly by market offerings of shares and listing;
the “Global Natural Resources” business group, responsible for increasing the value of the oil&gas exploration and development activities and of wholesale gas, LNG and power activities by leveraging organic growth and with the support of trading activities, vertical integration and operational excellence. It is also in charge of developing the new CCS and agri-hub businesses;
the “Industrial Transformation” business group, responsible for implementing the restructuring and upgrading of the Chemical business, managed by the subsidiary Versalis, and of the oil-based refining business leveraging on proprietary technologies, product specialization and the criteria of the circular economy and by reducing the weight of business lines with challenged fundamentals (commodity chemicals and low-scale refineries). It is also in charge of managing environmental remediation activities conducted by the subsidiary Eni Rewind.
Description of business activities and operating data as disclosed in Item 4 and financial data requested by accounting standards for segmental reporting as disclosed in Item 5 are presented based on the operating segments tracked by the chief operating decision maker to evaluate profit centers financial performance and resources allocation, as follows:
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Exploration & Production: engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 35 countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Qatar, Côte d'Ivoire and the United Arab Emirates. In certain geographies, mainly Angola, Norway and the UK, the business activities are conducted through equity-accounted entities. The business also engages in oil and products trading activities, designed to perform supply balancing transactions in the market with a view of ensuring the requested slate of crudes to the refining business and to stabilize or hedge commercial margins. |
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Global Gas & LNG Portfolio and Power: engages in the wholesale activity of supplying and marketing gas via pipeline and LNG, maximizing supply of equity gas/LNG, wholesale marketing of electricity and international transport activity. It also comprises gas, LNG, and power trading activities targeting both hedging and stabilizing the Group’s commercial margins and optimizing the gas asset portfolio. This operating segment also includes the results of operations of the Power business, engaged in the production of power produced by a fleet of thermoelectric plants located in Italy and in providing back-up capacity to the Italian grid.
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Enilive engages in the manufacturing of biofuels at the Italian plants of Venice and Gela and through the Chalmette JV in the USA, whilst advancing expansion plans in Italy and South-East Asia. It manages a network of about 5.2 thousand refueling service stations in Italy and selected European markets, also providing services and non-fuel products to drivers. |
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Plenitude engages in the activities of retail marketing of gas, power and related services, As of December 31, 2024, Eni’s customer base was over 10 million retail points of delivery (gas and electricity) in Europe (of which 8 million were in Italy). It engages in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore), which comprises building, commissioning, and managing renewable energy producing installations and wholesale marketing of electricity and managing and expanding a network of charging stations for electric vehicles distributed throughout the European territory, in particular in Italy. |
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Refining and Chemicals: the Refining business engages in refining crude oil to manufacture fuels and in wholesale marketing activities, which mainly consist of the inter-company supply of refined products to the Group subsidiary Enilive and in sales to large accounts. In the Chemical business Eni, through its wholly-owned subsidiary Versalis, engages in the production and marketing of basic chemical products, plastics and elastomers. Versalis is developing the business of manufacturing chemical products from renewable raw materials, bioplastics and bio-based products through the recently acquired subsidiary Novamont. Activities are concentrated in Italy and in Europe. The results of operations of the Refining business and the Chemical business have been combined in a single reporting segment because the businesses exhibit similar economic characteristics. |
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Corporate and Other activities: include the costs of the main business support functions, as well as, the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind and of the businesses engaged in developing the projects for CO 2 capture and storage and/or utilization and agricultural hubs to ensure supply of bio-feedstock to the Group’s biorefineries. |
A list of Eni’s subsidiaries is provided in “Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements”.
Str ate gy
The Company is executing a strategy designed to grow the business and maximize value creation. We are leveraging organic opportunities within our asset portfolio and the satellite model to improve results, while retaining financial discipline and seeking to deliver competitive shareholders’ returns. This strategy aims to address the current challenges in the global energy markets, focusing on ensuring stable, affordable, and increasingly decarbonized energy supplies to customers worldwide. We intend to advance the Company’s transformation to remain competitive in a low-carbon economy, progressing towards Eni’s long-term goal of achieving net zero emissions at our industrial processes and products by 2050, addressing GHG emissions across scopes 1, 2, and 3. We plan to monetize the value of our oil&gas businesses and to speed up the growth plans of the new activities related to the energy transition, where we expect higher growth rates than traditional activities. The strategic guidelines that are driving our plans are:
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To actively contribute to the achievement of the 17 UN SDGs, which are reflected in Eni’s mission, particularly the goals of tackling climate change and securing universal access to reliable, affordable, and clean energy.
To grow the oil&gas business mainly by increasing the weight of gas in our portfolio by upgrading gas reserves and production. The profitability of the gas value chain is expected to improve by means of strengthening integration between the upstream and midstream activities, by reaping synergies across the gas-LNG marketing activities, and finally by optimizing margins through oil&gas commodity trading.
To accelerate the development of our new businesses related to the energy transition, managed by our subsidiaries, Enilive and Plenitude, leveraging our distinctive satellite model designated to attract aligned capital to make, enabling these entities to become increasingly financially independent and capable of pursuing their own growth plans. As part of this strategy, in 2024, we signed landmark agreements with private equity funds that are finalizing investments in the share capital of both Enilive and Plenitude by acquiring non-controlling stakes. These investments will contribute about €3.7 billion of fresh funds to support their independent growth while unlocking value for the parent company. These funds will also help develop the manufacturing capacity of biofuels at Enilive and the renewable capacity at Plenitude.
To upgrade our oil&gas portfolio by creating geographically focused entities through joint ventures with local partners, which are able to grow independently and benefit shareholders, as well as by divesting non-strategic properties. In 2024, replicating the previous successes of Azule Energy in Angola and Var Energi in Norway, we combined our UK oil&gas assets with independent operator Ithaca Energy, creating a new, equity-accounted entity focused on pursuing growth opportunities and generating returns for shareholders. Also, we made progress in divesting long-lived assets that require significant capex and no longer align with our financial framework.
To execute an industrial plan to restructure and transform our loss-making downstream oil refining and petrochemicals production businesses, leveraging our proprietary technologies and selected capex to upgrade existing plants into biorefineries or activities linked to the energy transition and circular economy, including the development of chemicals from bio-feedstock and specialty products.
To establish a new transition-related satellite in the activity of carbon capture and storage, where we have made substantial progress in starting two large hubs for CO 2 capture and storage: one at the Hynet project in the UK and another at depleted gas fields off the Ravenna coast in Italy.
To maximize the benefits of integrating our portfolio along the entire energy value chain.
To retain financial discipline by selecting investment opportunities that fit our strict return criteria and executing a divestment plan to balance growth expenditures and maintain solid financial metrics.
To ensure competitive and progressive returns to shareholders by gradually increasing dividends and employing share repurchases as a flexible tool to distribute growing amounts of cash in scenario upsides.
To leverage our proprietary technologies to underpin the development of new businesses or the restructuring of businesses still tied to the oil cycle.
To further alliances and collaboration with a wide range of stakeholders by developing mutually beneficial solutions and synergies. As part of this guideline, we have successfully expanded our vertically integrated agricultural business in several African countries to produce a renewable feedstock for manufacturing biofuels with a lower carbon footprint at our biorefineries in Italy. This project applies the advanced sustainability and circular economy standards by repurposing abandoned land and favorably contributing to local job creation and development without competing with the food chain.
Our distinctive satellite business model is intended to optimize and valorize our asset portfolio in two ways.
First, we have established controlled entities focused on specific, high-growth market segments related to the energy transition. This approach can attract aligned third-party capital, thus enabling Eni to unlock the value of these businesses. In March 2024, we finalized an agreement with an institutional investor who subscribed to a dedicated share capital increase of our Plenitude subsidiary, engaged in renewables, energy retail, and EV charging. This investor acquired a 7.6% minority interest, resulting in about €0.6 billion in cash proceeds credited to Eni. Subsequently, this investor increased its stake in Plenitude to 10% by acquiring an additional 2.4% interest, a transaction was finalized at the end of March 2025. Additionally, in October 2024, private fund KKR agreed to make a nearly €3 billion investment in our other transition-related satellite, Enilive, engaged in biofuels manufacturing and mobility retail activities. KKR acquired a non-controlling 25% stake in the entity’s share capital, and in February 2025, the fund agreed to increase its stake to 30% under the same terms and conditions as the first transaction. The transaction agreed in October 2024 closed at the beginning of March 2025.
Secondly, we have created financially independent, jointly controlled entities or associates to our legacy businesses by contributing our assets to newly established ventures with other operators in specific geographies. This approach aims to maximize operational and financial synergies, enhance growth opportunities, and harvest dividends. Recently, we have established financially independent, equity-accounted entities by combining our oil&gas assets with those of selected partners. Notably, we created the Var Energy associate in Norway and the Azule Energy JV in Angola. In October 2024, we closed the combination of our North Sea oil&gas assets with Ithaca Energy, receiving in exchange a 37% interest in the newly formed entity. This combination brings together two highly complementary portfolios and will be able to maximize growth and returns by exploiting synergies. These E&P satellites have already been delivering significant dividends to Eni.
25
Our financial plans for the next four-year period from 2025 to 2028 assume a Brent crude oil price starting at 75 $/bbl in 2025 and gradually rising to our long-term case of 80$. Based on this assumption, we anticipate a gross capital expenditures program of around €33 billion (or about €27 billion net of portfolio transactions). Our future performance will be driven by: profitable production growth in E&P, continued margin optimizations in our GGP business (by leveraging integration with upstream equity projects), steady and growing results in our businesses focused on transitioning to more sustainable energy sources (particularly through the expansion of biofuels manufacturing and renewable generation capacities), enhanced marketing performance, cross-selling opportunities in the retail markets for gas, power, and fuels, and finally, a gradual recovery of profitability within our oil downstream businesses (see Item 5 in the looking forward section). We plan to remain financially disciplined and retain a solid balance sheet, with our leverage ratio projected to stay in a 0.1-0.2 range over the next four years plan (see Item 5 in the looking forward section).
Climate change-related risk management
Societal demand for urgent action on climate change has increased, especially since the Intergovernmental Panel on Climate Change (IPCC) Special Report of 2018 on 1.5°C effectively made the more ambitious goal of the Paris Agreement to limit the rise in global average temperature this century to 1.5 degrees Celsius the default target. This increasing focus on climate change and drive for an energy transition have created a risk environment that is changing rapidly, resulting in a wide range of governmental actions at global, local and company levels, increasing pressure from civil society and the investing and lending community to speed up our decarbonization plans.
The energy transition, as well as increasingly stricter regulations in the field of CO 2 emission, could represent significant risks to the Group’s financial performance and business prospects, because the Company still relies in a substantial way on the legacy business of Exploration & Production. The potential impact and likelihood of the associated exposure for Eni could vary across different time horizons, depending on the specific components of the risk.
The process of identifying and assessing climate-related risks is part of the Eni Integrated Risk Management Model, developed to ensure that decisions consider risks from an integrated, comprehensive, and forward-looking perspective. The process guarantees the detection, consolidation, and analysis of Eni risks and supports the BoD in verifying the compatibility of the risk profile with the strategic objectives over a medium to long-term perspective by monitoring the evolution of the key risks and identifying de-risking actions. Risks, including climate change, are assessed considering both the probability of occurrence and the quantitative and qualitative impacts on Eni's objectives, which are determined within a defined time horizon if the risk were to occur. These risks are also represented on matrices, enabling comparison and classification by relevance.
Risks related to climate change are analyzed, assessed, and managed considering both risks associated with the energy transition (regulatory, legal, market scenario, technological evolution, and reputational aspects) and physical risk (acute and chronic). This analysis follows an integrated and transversal approach involving the relevant functions as well as the business lines. Furthermore, risks related to executing planned strategic actions to mitigate climate change are also considered.
The energy transition policies implemented by the governments of numerous states significantly influence Eni’s operating context. These policies define the course of action to realize the commitments made by countries under the Paris Agreement, particularly with the agreement reached at COP28 on Global Stocktake, which makes explicit reference for the first time to the need to "transition away from fossil fuels." Commitments to achieving carbon neutrality and the possible change of consumer preferences could lead to a structural decrease in demand for hydrocarbon in the medium to long term and an increase in the operating costs of the oil & gas sector.
Uncertainties surrounding demand trends and the economic feasibility of decarbonization technologies make long-term investment decisions increasingly risky. In addition, the increasing polarization of the public debate on climate change and the rigorous scrutiny by various stakeholders could lead to difficulties in accessing capital and challenge the "license to operate" of the companies. In response to these emerging trends, Eni is committed to the execution of a portfolio repositioning strategy based on gradually reducing the weight of hydrocarbons to benefit the growth of renewable energy, biofuels, sustainable and environmentally friendly chemicals, as well as the development of emission capture/abatement technologies and lower carbon energy carriers. A description of the main climate-related risks is presented below .
a) Regulatory risk: increasing worldwide efforts to tackle climate change may lead to adopting stricter regulations to curb carbon emissions, which could increase expenditures in the short term and may end up suppressing demand for our products in the medium to long term.
At the global level, given countries' commitment to decarbonization, it is conceivable that regulatory developments will lead to the diffusion of new carbon pricing mechanisms and obligations to introduce minimum market shares of renewable or lower carbon fuels in the medium to long term. In the European context, Eni is subject to the European Emission Trading Scheme (EU ETS) and the UK Emission Trading Scheme (UK ETS) for about half of its direct GHG emissions. Under these mechanisms, the company must purchase emission allowances to cover any excess over its free allocations. In the non-EU area, several developing economies have announced the implementation of carbon pricing mechanisms. However, these CO 2 prices are expected, at least at an initial stage, to be low and have an insignificant impact on Eni's activities. In addition, the possible adoption of measures aimed at decreasing hydrocarbon consumption or introducing mining restrictions could reduce the growth prospects of the traditional business, resulting in the need to accelerate portfolio diversification.
26
b) Market/Technological risk: in the long term, the deployment of massive investments in renewable energies, supported by government fiscal policies, alongside the projected rise of electric vehicles and the development of green hydrogen and other technologies for producing lower-carbon fuel and energy, may materially reduce hydrocarbons demand.
Currently, the market is characterized by high uncertainty due to the simultaneous action of several variables: geopolitical tensions, unevenly applied decarbonization policies (geographically), and fluctuating supply and demand trends. This scenario accentuates the complexity of investment decisions and decreases the predictability of the timing and nature of the energy transition. Additionally, technological innovation plays a crucial role in the transition plans of Oil & Gas companies. In the medium to long term, several technologies aimed at building a low-carbon energy consumption model could reach the commercial stage, including advancements in electric mobility, energy storage from renewable sources, and the development of new energy carriers. Eni is developing new technologies and energy carriers to transform its portfolio, such as emission capture and storage, hydrogen production/transport, and magnetic confinement fusion. Failure to anticipate shifts in the supply/demand trends and fundamental technologies in the energy transition could significantly affect growth prospects, operating results, cash flow, and shareholder returns.
c) Legal risk: several lawsuits are pending in various jurisdictions against Oil & Gas companies based on alleged violations of human rights, damage to the environment, and other claims; such legal actions may be filed against us.
Several public and private entities have initiated legal proceedings against major Oil & Gas companies, claiming their liability for climate change-related damages, alleged human rights violations, and other unlawful practices. Some institutional investors or members of civil society have obtained judgments condemning oil companies for failing to adopt faster decarbonization plans (although various levels of appeal are still pending.). In other cases, they have demanded that the Board be held accountable for managing climate strategy or have promoted shareholder resolutions that interfere with corporate plans. These events demonstrate how some institutions and stakeholders are challenging the license to operate of western oil companies, which are perceived as slow or reluctant to adapt their business model and capital allocation processes to the decarbonization scenario. This landscape increases the risk of new litigation.
d) Reputational risk: the perception of Oil & Gas companies as poorly performing investments from an environmental standpoint by financial market participants could reduce the attractiveness of their securities or limit their ability to access the capital markets. Activist investors have been seeking to interfere in companies’ plans and strategies through shareholders’ resolutions.
In the context of increasing polarization surrounding climate change, various segments of civil society (environmental movements, NGOs, younger generations), governmental institutions, and other stakeholders often hold Oil & Gas companies as primarily responsible. This debate increases pressure on the boards of oil companies to accelerate transition strategies and plans and on the financial sector (asset managers, banks, and insurance companies) to align their portfolios with "Net Zero" targets. Recently, some large banks and financial institutions, especially in Europe, have announced to stop direct financing of new Oil & Gas projects. The financial world's disengagement from hydrocarbons could lead to difficulties accessing the capital market, resulting in increased pressure on Oil & Gas companies' stock prices, higher financing costs, and greater equity risk.
e) Physical risk: extreme weather events, attributed to climate change, may disrupt our operations.
Based on studies within the scientific community, the increased frequency of acute and chronic weather and climate phenomena with high impact on the economy and lives of communities, such as, but not limited to, hurricanes, floods, droughts, desertification, rising ocean levels, melting of perennial glaciers, is related to climate change. These extreme weather events could cause prolonged disruptions in industrial operations and damage to facilities and infrastructure, leading to losses in productivity and cash flow, as well as increased repair and maintenance costs, including effects on the supply chain.
Eni has adopted a structured risk management process for identifying and analyzing assets exposed to potential changes in natural events (acute and chronic) over the medium to long term, which may impact the operability and safety conditions of the assets. This process ensures that we consider different climate scenarios, consistent with varying emission scenarios and time horizons of short (5/10 years), medium (10/20 years), and long-term (20/30 years). We assess the inherent risk of the assets, defined as their exposure to specific natural events based solely on location and climate evolution, and the residual risk, which is the exposure assessed after considering existing or planned mitigation measures). After mitigation actions, assets still at risk are analyzed in more detail as part of the Asset Integrity process.
27
Governance of climate related risk
Role of the BoD. Eni's decarbonization strategy is a key component of its overall business strategy, implemented through a structured Corporate Governance system, where the BoD and the CEO play a central role in addressing key climate change issues. Specifically, the BoD reviews and approves the Strategic Plan proposed by the CEO, which sets out strategies and targets, including those related to climate change and energy transition. Since 2019, the BoD has also reviewed and approved Eni’s medium/long-term plan, which aims to outline and monitor the progress of the decarbonization targets and their economic and business sustainability through to 2050.
Moreover, the BoD assesses Eni's economic and financial exposure to carbon pricing risk during the preliminary phase before approving individual investments and monitors the project portfolio every six months thereafter. Annually, the BoD is informed of the impairment test result performed on the main Cash Generating Units, which considers the International Energy Agency (IEA) Net Zero Emissions (NZE) scenario. Finally, the Board is notified quarterly about the outcomes of Eni's risk assessment and top risks monitoring, including climate change risk.
Since 2014, the Eni BoD has been supported in performing its duties by the Sustainability and Scenarios Committee (SSC), established on a voluntary basis, which, among other tasks, periodically examines the integration between strategy, development scenarios and the medium/ long-term sustainability of the business with a view to energy transition and climate change.
Concerning the Board composition, based on the self-assessment, about 90% of the Board Members expressed their positive opinion on the professionalism within the Board – in terms of knowledge, experience, and skills (with particular reference to advisory, training and publication activities in the energy and environmental field, participation in governmental and non-governmental, national and international bodies that deal with these issues) – and on the personal contribution that the individual Board Members make to the Board of Directors in matters of sustainability, ESG and energy transition. These topics have characterized the work of the new Board since the start of its mandate, including through targeted training initiatives.
Role of management. In 2024, the Company reorganized its business activities into three structures to maximize operational effectiveness and accelerate the implementation of the carbon neutrality strategy: (i) “Chief Transition & Financial Officer” aimed at maximizing the value of transition-related businesses; (ii) “Global Natural Resources”, tasked with optimizing margins across the entire oil & gas value chain, including power and trading. (iii) Industrial Transformation, focused on accelerating the conversion of downstream oil and the restructuring of the chemicals sector.
Since 2019, issues related to climate strategy and long-term planning have been managed by the CFO area through dedicated structures overseeing the process of defining Eni’s decarbonization strategy and the related portfolio of initiatives. The strategic commitment to reducing carbon footprint is reflected in the Variable Incentive Plans for the CEO, General Managers, Managers with strategic responsibilities, and other Executive Managers. In particular, the Long-Term Stock-based Incentive Plan includes environmental sustainability and energy transition targets, accounting for a total weight of 35%, related to “Net GHG emissions upstream (scope 1 and 2) equity” (20%) and Biojet fuel production capacity (15%). The Short-Term Incentive Plan is also aligned with Eni's strategic transformation objectives, including an environmental sustainability target focused on “Net GHG emissions upstream (scope 1 and 2) equity” consistent with the Long-Term Incentive Plan. For the CEO, this objective carries an overall weight of 20%, while for the Company management, the weight is allocated based on the assigned responsibilities.
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Decarbonization strategy
In response to the identified risks emerging on connection with the energy transition, the Company has designed an action plan and a climate strategy to remain competitive and profitable in a low-carbon economy. The Company’s medium- and long-term strategy and action plans are expected to drive a gradual, albeit significant, reduction in our emissions of greenhouse gases (GHG) emissions, in line with Eni’s stated objective of net zero by 2050 across all our industrial activities and products sold to customers both in terms of absolute and intensity. Our objective consists of intermediate targets and a set of planned actions leading to the following milestones:
Net zero emissions for Upstream industrial processes (Scope 1+2) by 2030, with intermediate targets of -50% by 2024 (which has been reached, and -65% by 2025 vs. the 2018 baseline; and Net zero emissions by 2035 for all other Eni Group’s industrial processes;
-35% of Net GHG Lifecycle Emissions (Scope 1+2+3) by 2030 vs. the 2018 baseline, -55% by 2035 and -80% by 2040;
-15% of Net Carbon Intensity of energy products sold by 2030 vs. 2018 and -50% by 2040.
We plan to utilize nature-based solutions to offset hard-to-abate emissions from our industrial processes, mainly related to projects of forest conservation and rehabilitation, contributing about 5% of the total supply chain emissions reduction by 2050 or about 20-25 million tons of CO 2 offset per year in the long-term.
Our action plans to reach the goal of net zero emissions by 2050 will include several industrial and technological levers and will be pursued in accordance with evolving market trends and societal demands for energy, with a view to continuing to supply secure and affordable energy to our customers.
Significant effort has been made in recent years to upgrade our business portfolio and to align it with our long-term goals, including:
Rebalancing our upstream portfolio towards the gas component, thanks partly to recent business combinations (e.g., Neptune Energy), asset divestments (Alaska, Nigeria, and Congo), capital projects (e.g., the FLNG project in Congo, the planned development of gas reserves in Indonesia, Cyprus, Mozambique, and Libya). These transactions reflect a commitment to target a 60% gas production level (including condensates) by 2030 and above 90% after 2040. This development, together with other efficiency actions like the start of projects already designed to have net zero scopes 1&2 emissions from the beginning (like the Argo-Cassiopea project in Italy and the Baleine oil project offshore Cote d’Ivoire), will contribute to reaching our E&P goal by 2030;
Developing the manufacturing capacity of biofuels, which will be driven by upgrading and reconverting the Livorno refinery and boosting the Venice refinery in Italy, as well as by building two biorefineries in East Asia through joint ventures with local operators in South Korea and Malaysia. Our goal is to reach an organic refining capacity of more than 5 million tons by 2030, with an intermediate target of more than 3 million tons by 2028;
Increasing Plenitude’s installed renewable capacity, with the goal of installing more than 15 GW by 2030. Our intermediate targets are to install more than 5.5 GW by 2025 and 10 GW by 2028, eventually rising to 60 GW by 2050. This growth is part of our plan to expand the customer base to around 20 million by 2050;
Establishing Plenitude as one of the most significant players in the electric vehicle charging service in Italy and Europe through Be Charge, with a goal of installing 40k electric vehicle charging points by 2030, rising to about 160,000 by 2050;
Increasing produced volumes of electricity through new energy carriers (e.g., power with CCS) and nuclear fusion. The Company is collaborating with partners to develop magnetic fusion technology, with the first operational plant expected by the early 2030s;
Acquiring leadership positions in the UK, Italy, and other geographies to develop CO 2 storage hubs for hard-to-abate emissions.
A gradual growth in the share of investments dedicated to new energy products and services will support the evolution toward a decarbonized product portfolio. The share of spending allocated to Oil & Gas activities is expected to be gradually reduced. Major investment projects will be evaluated in line with emission reduction targets and the commitment to phase out investments in highly emissive “unabated” activities or products, which is a necessary condition to achieve carbon neutrality by the mid-century. Expenditure earmarked for lower carbon activities will represent around 30% of the total amounts planned in the Group’s financial projections for the 2025-2028 four-year period.
Sensitivity of Oil & Gas asset book values to stress-test scenarios
Our portfolio of oil and gas properties features a large weight of natural gas, the least GHG-emitting fossil energy source. As of December 31, 2024, natural gas proved reserves represented approximately 52% of Eni’s total proved reserves of its subsidiary undertakings and joint ventures. The other constituencies of our portfolio of oil&gas properties which are mitigating the risk of stranded assets are the large weight of conventional projects, featuring low CO 2 intensity, and a low Brent price of breakeven.
29
The low breakeven price of our reserves has been driven by our exploration and development model that features: i) organic reserve replacement by means of effective exploration, which has been focused on near-field and proven/mature plays to leverage on existing infrastructures to readily put new reserves into production by this way reducing development expenses and time-to-market; ii) a focus on low-complexity developments; and iii) a phased approach to putting reserves into production featuring early production start-up and subsequent ramp up to reduce the financial exposure of development projects and accelerate the time-to-market and the pay-back period. Based on those drivers, we have gradually reduced the breakeven price of our reserves and improved the resilience to low-carbon scenarios, which also considering the emissive profiles of our assets are expected to mitigate the risk of stranded reserves going forward. The risk of stranded assets might emerge in case of a structural decline in hydrocarbons demands because of the transition risks described in previous paragraphs.
Eni’s portfolio exposure to those risks is reviewed annually against changing GHG regulatory regimes, evolving consumers’ preferences, technological developments, and physical conditions to identify emerging risks.
As part of such review, the management stress-tested the recoverability of the book values of the Company’s oil & gas assets of the 2024 financial statements by applying the assumptions set forth in the IEA Net Zero “NZE 2050” scenario and other lowered price assumptions, without assuming any management’s actions on capex rescheduling, reduction or curtailments, cost revisions or other possible measures to adapt the business to a changed trading environment. Since the IEA NZE scenario does not provide short-term pricing assumptions, we have utilized the crude oil pricing and other assumptions from our industrial plan for the years 2025-2028 and then we have made a linear interpolation up to 2030, which is the first available year of IEA pricing projections.
The purpose of those stress tests is to evaluate the reasonableness of the outcome of the impairment review of those assets that is regularly performed by the management utilizing its own oil pricing, costs and other assumptions and considering proved reserves and certain amounts of unproved reserves, “the base case”, as well as possible risks of stranded assets that could emerge within transition pathways that are faster than those forecast by the managements. Those stress tests covered the whole of the oil & gas cash generating units (CGUs) that are regularly tested for impairment in accordance with IAS 36. The stress test performed by Eni’s management of the values-in-use of Eni’s oil&gas assets under the pricing and cost assumptions of the IEA NZE scenario highlighted a loss of value and potential asset write-downs, all of which were not material based on management’s judgement. Overall, the stress test confirmed the overall resilience of Eni’s assets. Those stress tests have been performed by just updating pricing and CO 2 cost assumptions in management’s cash flow projections and do not assume any change to all other factors in the models used, such as cost levels, volumes, and the discount rate, to calculate recoverability of carrying amounts. Sensitivity testing has been performed by applying the alternative commodity price scenarios to cash flows for the whole period until the end of life of the assets tested.
The results of those stress-tests are disclosed in “Item 18 - Note No.15 to the Consolidated Financial Statements”.
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Key performance indicators
Climate
|
|
|
2024 |
2023 |
|
|
|
Total |
Total |
|
GHG EMISSIONS |
|
|
|
|
Direct GHG emissions (Scope 1) |
(million tonnes CO 2 eq) |
31.1 |
32.3 |
|
Direct GHG emissions (Scope 1) by type of source |
|
|
|
|
of which: CO 2 equivalent from combustion and process |
|
25.3 |
26.5 |
|
of which: CO 2 equivalent from flaring |
|
3.6 |
3.9 |
|
of which: CO 2 equivalent from venting |
|
2.0 |
1.7 |
|
of which: CO 2 equivalent from methane fugitive emissions |
|
0.2 |
0.2 |
|
Direct methane emissions (Scope 1) |
(ktonnes CH 4 ) |
16.0 |
16.6 |
|
of which: fugitive upstream |
|
1.7 |
2.0 |
|
Upstream methane emission intensity |
(%) |
0.09 |
0.10 |
|
Volumes of hydrocarbon sent to flaring |
(billion Sm 3 ) |
0.84 |
0.89 |
|
of which: Upstream routine |
|
0.12 |
0.24 |
|
Indirect GHG emissions (Scope 2) location-based |
(million tonnes CO 2 eq) |
0.6 |
0.6 |
|
Net GHG lifecycle Emissions (Scope 1+2+3) |
|
395 |
398 |
Key target indicators 1
|
|
|
2024 |
2023 |
target |
|
Net Carbon Footprint upstream (Scope 1+2) |
(million tonnes CO 2 eq) |
6.8 |
9.0 |
UPS Net zero @2030 |
|
Net Carbon Footprint Eni (Scope 1+2) |
|
23.6 |
26.2 |
Eni Net zero @2035 |
|
Net GHG Lifecycle Emissions (Scope 1+2+3) |
|
395 |
398 |
Net zero @2050 |
|
Net Carbon Intensity (Scope 1+2+3) |
(gCO 2 eq./MJ) |
65.2 |
65.6 |
Net zero @2050 |
|
|
|
|
1 Indicators accounted for on an equity basis. |
|
Other environmental and social KPI
|
|
|
2024 |
2023 |
|
|
|
operated |
operated |
|
POLLUTION |
|
|
|
|
Operational oil spills volumes (>1 barrel) |
(barrels) |
675 |
7,625 |
|
volumes of oil spills due to sabotages (including thefts) (>1 barrel) |
|
2,140 |
5,094 |
|
WATER AND MARINE RESOURCES |
|
|
|
|
reused and recycled fresh water |
(million cubic meters) |
1,133 |
1,066 |
|
water withdrawls |
|
1,162 |
1,150 |
|
of which: sea water |
|
1,032 |
1,038 |
|
RESOURCES AND CIRCULAR ECONOMY |
|
|
|
|
total waste generated |
(million tonnes) |
4.4 |
4.5 |
|
total hazardous waste |
|
0.6 |
0.3 |
|
COMMUNITIES INVOLVED |
|
|
|
|
local development investments |
(€ million) |
88.8 |
95.0 |
|
|
|
2024 |
2023 |
|
OWN WORKFORCE |
|
|
|
|
TRIR (total recordable injury rate) |
(total recordable injuries/worked hours) x 1,000.000 |
0.67 |
0.57 |
|
new hires with permanent contract |
(number) |
2,616 |
1,949 |
|
training hours |
(hours) |
1,027,822 |
1,154,495 |
|
gender pay gap |
(%) |
6.8 |
3.4 |
31
Significant business and portfolio developments
|
|
● |
March 2025 – Completed the EIP’s transaction to increase its stake in Plenitude’s share capital, reaching a 10% stake in the aggregate. The increase of EIP's stake is based on a capital increase of about €209 million, which, including €588 million paid in March 2024, brings the total investment to about €800 million. |
|
|
● |
March 2025 - Versalis started operations at a new plant in Porto Marghera dedicated to production of plastics made wholly or partially from mechanically recycled raw materials. The materials produced at the new plant are part of the Versalis Revive® range and contain between 35% and 100% post-consumer recycled plastics. |
|
|
● |
March 2025 - Plenitude has started the construction of a new 90 MW solar plant in the municipality of Fortuna, in Spain. |
|
|
●
|
March 2025 - Plenitude, through the joint venture Hergo Renewables, has completed the construction of a new 37 MW agri-voltaic plant (24 MW Eni share) in the municipality of Montalto di Castro (Viterbo), Lazio. |
|
|
●
|
March 2025 - Eni and Vitol agreed on the economic terms and conditions of the farm-out to Vitol of a 25% working interest (w.i.) in the Eni-operated Congo FLNG project (with Eni retaining a post-closing 40% w.i.) and of a 30% w.i. in the Eni-operated Baleine oil project offshore Cote d’Ivoire (with Eni retaining a post-closing 47.25% w.i.) for a cash consideration of $1.65 billion and economic date January 1, 2024. Closing is subject to customary regulatory approval and other conditions. |
|
|
●
|
March 2025 - Eni signed a collaboration agreement with the United Kingdom Atomic Energy Authority (UKAEA) to jointly conduct research and development activities in the field of fusion energy. The collaboration primary will start with the construction of the UKAEA-Eni H3AT, the world’s largest and most advanced tritium fuel cycle facility, a vital fuel for future fusion power stations. |
|
|
● |
March 2025 - Eni and KKR finalized the transaction agreed in October 2024 providing an investment of 25% by KKR in Enilive with cash proceeds to Eni of about €2.94 billion. |
|
|
● |
February 2025 - Eni announced a proposed combination of its oil&gas assets in Indonesia with part of the asset portfolio of Petronas in the region including certain Petronas assets in Malaysia. The combined entity will target a production plateau of 500 Kboe/d, which is expected to be sustained over a long period due to the mineral potential of the interested acreage. |
|
|
● |
February 2025 - Signed collaboration agreements with UAE-based companies for developing data centers in Italia, which will be powered by Eni with gas-fired electricity with associated capturing and storing of CO 2 emissions. The agreements also cover renewable energy transmission through cross border interconnection between Albania and Italy, and critical minerals, allowing Eni to expand collaboration with the UAE. |
|
|
● |
February 2025 - Eni signed an agreement with the KKR fund to increase the fund’s interest in Enilive by a further 5% to reach 30% on the same terms and conditions as the transaction signed in October 2024. |
|
|
● |
February 2025 - Eni signed an agreement with Cyprus and Egypt to develop gas reserves of Eni’s Block 6 offshore Cyprus, to be exported to Europe through Eni’s existing treatment and liquefaction facilities located in Egypt. |
|
|
● |
January 2025 - Eni successfully issued a hybrid bond to refinance a similar instrument approaching the reset date. This voluntary offer, aimed at repurchasing in cash, and subsequently canceling, all or part of an outstanding perpetual hybrid bond worth €1.5 billion, resulted in an amount accepted by Eni for about €1.2 billion, equivalent to approximately 83% of the outstanding amount to be refinanced. |
|
|
● |
January 2025 - Enilive started operations at the first dedicated plant to the production of Sustainable Aviation Fuel (SAF) at the Gela biorefinery. The plant has a capacity of 400 ktons/y. |
|
|
● |
January 2025 - Versalis signed a partnership with Lummus Technology, a global provider of process technologies, which will serve as the exclusive licensor for phenolics value chain. |
|
|
● |
January 2025 - Plenitude, through its US subsidiary Eni New Energy US Inc. has completed the construction of the Guajillo plant in Texas with a capacity of 200 MW, equipped with lithium-ion LFP batteries (lithium iron phosphate). |
|
|
● |
January 2025 - Plenitude, through its US subsidiary Eni New Energy US Inc. signed an agreement with EDP Renewables North America LLC to purchase a 49% equity stake in a portfolio of 2 operational photovoltaic plants and an electricity storage facility in construction located in the state of California. |
|
|
|
|
32
|
|
● |
January 2025 - Plenitude completed the installation of a 150 MW renewable facility at Caparacena in Granada, consisting of three photovoltaic plants nearly 50 MW capacity each. Moreover, Plenitude also completed the construction of other plants totalling nearly 250 MW in the solar parks of Renopool, in Extremadura, and Guillena, in Andalusia. Thanks to these projects, Plenitude, in Spain, has reached nearly 950 MW of photovoltaic and wind power capacity. |
|
|
● |
December 2024 - Eni started production of Phase 2 at the large Baleine oilfield offshore of the Côte d'Ivoire’s. Phase 2 includes the use of the Floating Production, Storage and Offloading Unit (FPSO) Petrojarl Kong, alongside the Floating Storage and Offloading Unit (FSO) Yamoussoukro, aimed at the export of oil. In addition, all the processed gas is intended to supply the local energy demand through the connection with the national grid built during the project’s Phase 1. |
|
|
● |
December 2024 - Enilive signed with EasyJet an agreement for supply of Sustainable Aviation Fuel (SAF) a number of flights from Milan Malpensa Airport. In addition, the Company signed a Letter of Intent to purchase about 30,000 tons of SAF to be used in EasyJet's operations in Italy, between 2025 and 2030. |
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● |
November 2024 - closed the sale to Hilcorp of 100% of the Nikaitchuq and Oooguruk oil assets owned in Alaska for a value of $1 bln. The transaction received the approval of all relevant authorities. |
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November 2024 - Eni signed with the Ministry of Mines, Petroleum and Energy of the Côte d'Ivoire contracts finalized to acquire four new offshore exploration blocks. The agreement includes Blocks CI-504, CI-526, CI-706 and CI-708, covering a total area of about 5,720 km2. |
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November 2024 – As part of the large Congo FLNG project to valorize the gas reserves of operated block Marine XII, Eni launched the Nguya Floating Liquefied Natural Gas (FLNG) facility. The FLNG will have a liquefaction capacity of 2.4 mln tons/y and will complement the existing Tango FLNG, which is in operation since December 2023 with a capacity of 0.6 mln tons/y, bringing the total liquefaction capacity of Congo LNG project to 3 mln tons/y, by the end of 2025. |
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November 2024 - Plenitude started operations in a new photovoltaic plant in the municipality of Bouillac, in France with an installed capacity of 5 MW. The plant will produce 6,700 MWh/y of electricity and will be connected to the local distribution network via a 1.7 km underground medium voltage line. |
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November 2024 - Eni has been awarded “Gold Standard reporting” of the Oil and Gas Methane Partnership 2.0 (OGMP 2.0) for its commitment to reporting emissions at the highest data quality levels. |
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November 2024 - Eni, Plenitude and Energy Infrastructure Partners (EIP) signed the agreement to further increase EIP’s share in Plenitude through a capital increase of approximately €209 mln. The stake of EIP, post-transaction, would be 10% of Plenitude’s share capital, for a total investment of around €800 mln, including the €588 mln paid in March 2024. |
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November 2024 - Enilive signed a Memorandum of Understanding with MSC (Mediterranean Shipping Company) aimed at developing joint initiatives in the field of sustainability and energy transition. |
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November 2024 - Eni completed and launched a new supercomputing system (High Performance Computing - HPC) HPC6. HPC6 provides a significant increase in computational power to a peak of 606 PFlop/s, or over 600 quadrillion mathematical operations per second. |
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November 2024 – Eni signed an agreement with the Ministry of Water and Forests of Côte d'Ivoire to launch a project to preserve and restore forest areas in the country. The initiative will cover 14 forests over an area of 155,000 hectares located in the South and South-East of the Country. |
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October 2024 - The UK Government granted public funds in relation to the Liverpool Bay CO 2 transport and storage (T&S) project. The funding includes investment for Track 1 industrial emitters and is a key milestone towards the execution phase of Eni-operated HyNet project to capture and store CO 2 at Eni’s depleted fields in the Liverpool Bay. |
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October 2024 - Eni and KKR signed an agreement under which KKR will take a 25% stake in Enilive’s share capital, for a total agreed consideration of €2.94 billion. |
33
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October 2024 – Plenitude launched On the Road, the new identity of its e-mobility solutions, consolidating the Be Charge integration process within the company. |
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October 2024 – Eni and SERI Industrial, a company operating in the energy storage sector, have set out an agreement for the potential development of the industrial chain for lithium-iron-phosphate electrochemical batteries for storage applications (ESS) and industrial and commercial electric mobility. |
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October 2024 - Eni announced its transformation, decarbonization and relaunch plan for its chemicals business first depicted in March 2024. The plan will involve about €2 bln of investment to upgrade chemical plants. |
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October 2024 - Eni signed a charter agreement for the LNG bunker vessel Avenir Aspiration with Avenir LNG Limited with a view of expanding Eni’s activities in the small-scale LNG bunkering market in the Mediterranean Sea. |
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October 2024 - Eni signed a Memorandum of Cooperation with Japan Organization for Metals and Energy Security with the aim of promoting the role of gas and LNG in the energy transition pathway, including LNG supply opportunities by Eni to Japan and the support of Japanese financial institutions to the Coral North project in Mozambique. |
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October 2024 - in Spain, Plenitude started operations of the wind farms of Numancia in the area of Almarza (Soria) with installed capacity of about 13 MW able to generate 31 GWh/y and the construction works of a solar plant in Villarino de los Aires (Salamanca), with installed capacity of 220 MW. |
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October 2024 - Versalis, in collaboration with Vesta, launched the new brand “ReUp” in the home décor and interior design sector with the aim to produce and sale plastic solutions obtained in whole or in part from renewable or recycled sources. |
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October 2024 - completed the combination of the upstream assets in the UK, excluding East Irish Sea assets and CCUS activities, with Ithaca Energy plc. The combination is funded through the issue to Eni UK of such number of new ordinary shares that represents approximately 37% of the share capital of Ithaca post transaction. |
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September 2024 - Versalis signed an agreement with Bridgestone and Gruppo BB&G aimed at establishing a closed-loop ecosystem to transform end-of-life tyres into new tyres. The partnership will develop a model for the creation of a scalable and increasingly sustainable supply chain. |
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September 2024 - Eni and Snam started CO 2 injection in a depleted reservoir as part of the Ravenna CCS Phase 1 project in the Adriatic Sea. Ravenna CCS is the first project on the capture, transport and permanent storage of CO₂ in Italy. |
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September 2024 - Enilive signed a Letter of Intent with Volotea operating in 15 Italian airports, for a long-term supply contract of SAF in the 2025-2030 period. |
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September 2024 - On the occasion of the IEA-COP29 high-level event on Turning Methane Pledges Into Action, Eni has published its first dedicated “Methane Report 2024”, a milestone that underscores the company’s commitment to transparency and reducing global methane emissions, while reaffirming the goal of near zero methane emissions by 2030. |
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September 2024 - Obtained the environmental authorization, necessary for the granting of the final permit from relevant Italian bodies to start construction works to build a new biorefinery at the Livorno hub. |
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September 2024 - Green Volt project participated by Plenitude through the joint venture Vårgrønn was selected as the only floating offshore wind to secure a contract in the UK's latest renewables allocation round (“AR6”). |
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September 2024 - Eni and SOCAR signed agreements in the energy security, reduction of greenhouse gas emissions and in the biofuel production chain sectors. |
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August 2024 - Enilive and LG Chem reached the final investment decision (FID) to develop a biorefinery in South Korea with processing capacity of 400 ktons/y of feedstocks, leveraging on Eni's Ecofining™ technology. |
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August 2024 - on the occasion of the yearly update (in August 2024) Moody’s ESG Solutions further improved Eni’s score and confirmed Eni positioning in the Advanced band, the highest one of the methodology, due to the capabilities in managing ESG risks. |
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August 2024 - Plenitude signed a 10-year Power Purchase Agreement (PPA) with Ferriera Valsabbia, an Italian steel company, for the supply of energy produced 100% from renewable sources. The agreement covers the entire output of a 15 MW wind facility in the portfolio of Plenitude. |
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August 2024 - the Indonesian authorities approved the Plan of Development (PoD) of the Geng North (North Ganal PSC) and Gehem (Rapak PSC) fields. The integrated development of the two fields will create a new production hub, called Northern Hub, in the Kutei Basin. The Indonesian authorities have also approved the PoD for Gendalo & Gandang fields (Ganal PSC). Additionally, Eni has been awarded by the Indonesian authorities a 20-year extension of the IDD licences named Ganal and Rapak. |
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August 2024 - finalized the sale of wholly-owned subsidiary Nigerian Agip Oil Company (NAOC) engaged in onshore oil&gas exploration and production in Nigeria to the local company Oando. The transaction is in line with Eni’s strategy of upgrading and rationalizing the upstream portfolio. The 5% participating interest in SPDC (Shell Production Development Company Joint Venture) is not included in the transaction, as it will be retained in Eni’s portfolio. Eni will continue to be present in the Country through investment in deepwater projects and Nigeria LNG, while also exploring new opportunities related to agri-feedstock sector. |
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August 2024 - started gas production at the Argo Cassiopea field, the most important gas development project in Italy. The gas is being transported through a 60 km subsea pipeline to the Gela processing plant, linked to the national grid. |
34
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August 2024 - Enilive signed with Poste Italiane an important collaboration agreement for the supply of biofuels for ground vehicles and aircraft aimed at accelerating the path towards energy transition and carbon neutrality goals. |
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July 2024 - Plenitude completed the construction of a new onshore wind facility with a capacity of around 39 MW in Southern Italy. The plant is able to generate 84 GWh/y of electricity at capacity. |
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July 2024 - Enilive, Petronas and Euglena reached a final investment decision (FID) to build a biorefinery located in Malaysia. The construction of the biorefinery will have the capacity to process about 650 ktonnes/y of raw materials to produce SAF, HVO, and bio-naphtha. |
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In July 2024 - Enilive signed agreements in Italy with Itabus to supply HVO diesel to a fleet of 100 buses for civilian transport. |
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July 2024 - Versalis and Forever Plast launched REFENCE™, a portfolio of innovative recycled polymers for food contact packaging. |
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July 2024 - announced a new discovery with the Yopaat-1 EXP exploration well in Block 9, in the mid-deep water of the Cuenca Salina in the Sureste Basin, offshore Mexico. |
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July 2024 - Eni and ITQuanta formed a joint venture, Eniquantic, with the aim of developing an integrated hardware and software quantum machine capable of solving complex problems and initiating specific and significant quantum computing applications to support the energy transition. |
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July 2024 - Eni and the National Company KazMunayGas (KMG) announced the commencement of construction for their joint 250 MW Hybrid Renewables-Gas Power Plant Project in Zhanaozen, Mangystau Region, Kazakhstan. |
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July 2024 - Eni received formal consent from the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) for the sale of NAOC Ltd to Oando Plc. |
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June 2024 - Eni completed the sale of 10% of the share capital of Saipem S.p.A. |
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June 2024 - Eni and FS Italiane Group have signed a Letter of Intent with the objective of developing joint initiatives aimed at accelerating the energy transition towards new energy sources. |
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June 2024 - Eni, in partnership with Biocarbon Partners (BCP), launched the Great Limpopo project, the largest initiative ever developed in Mozambique to protect forests and counteract deforestation causes in line with the REDD+ framework, defined and promoted by the United Nations. |
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June 2024 - Versalis and Crocco (SpA SB), a pioneering flexible packaging company, launched a collaboration to produce food packaging film made from raw materials partly derived from the recycling of post-consumer plastics, targeting mass production for the large-scale retail market. |
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June 2024 - Plenitude inaugurated in Cuenca (Spain), the Villanueva II solar plant with an installed capacity of 50 MW, connected to the national transmission grid. The facility counts more than 76,000 photovoltaic modules and produces 100 GWh/year of electricity, equivalent to the energy needs of more than 30,000 households. |
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June 2024 - Plenitude signed a strategic partnership with MERKUR for the installation, construction and management of innovative electric vehicle charging stations, including 62 technologically advanced fast and ultra-fast charging points, at MERKUR shopping centres across Slovenia. |
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June 2024 - Enilive Iberia finalized the acquisition of 100% shares of Atenoil, a company operating in the service station sector. The transaction, which has been approved by the relevant authorities, comprises 21 service stations in the regions of Madrid, Andalusia and Castilla-La Mancha. |
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May 2024 - Eni has been named the upstream industry’s most valuable explorer in Wood Mackenzie’s industry-leading annual Exploration Survey. |
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May 2024 - IFC (International Finance Corporation) and the Italian Climate Fund announced a $210 million investment in Eni S.p.A.’s Kenya subsidiary to expand the production and processing of advanced biofuels, supporting the decarbonization of the global transport industry and the livelihoods of up to 200,000 small-scale Kenyan oilseed farmers. |
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April 2024 - Eni reached an agreement on the combination of its upstream assets in the UK, excluding East Irish Sea assets and CCUS activities with Ithaca Energy, marking a strategic move to significantly strengthen its presence on the UK Continental Shelf. |
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April 2024 - Versalis finalized the acquisition of 100% of Tecnofilm SpA, a specialist company operating in the compounding sector. |
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April 2024 - Plenitude started construction works at the 330 MWp Renopool photovoltaic solar installation, in Spain. |
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March 2024 - Eni signed an agreement with Fincantieri and RINA to evaluate initiatives in the energy transition, targeting the decarbonization of the maritime sector. |
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March 2024 - Eni renewed its membership participation in the MIT Energy Initiative (MITEI) as a Founding Member until the end of 2027, furthering its commitment to the field of low-carbon energy research. |
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For significant business and portfolio developments occurred from January 2024 to the beginning of March 2024 see also the Annual Report on Form 20-F 2023 filed to SEC on April 5, 2024. |
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35
Competitive trends in the industries where the Company operates
In the Exploration & Production segment, Eni is facing competition from both international and state-owned oil companies for obtaining exploration and development rights and developing and applying new technologies to maximize hydrocarbon recovery. Because of the larger size of some other international oil companies, Eni may face a competitive disadvantage when bidding for large scale or capital intensive projects and it may be exposed to the risk of obtaining lower cost savings in a deflationary environment compared to its larger competitors given its potentially smaller market power with respect to suppliers, whereas in case of rising input costs due to a shortage of materials, labor and other productive factors Eni may experience higher pressure from its suppliers to raise the price of goods and services to the Company compared to Eni’s larger competitors. Due to those competitive pressures, Eni may fail to obtain new exploration and development acreage, to apply and develop new technologies and to control costs.
Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 35 countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Qatar, Côte d'Ivoire and the United Arab Emirates. In 2024, Eni average daily production amounted to 1,572 KBOE/d on an available-for-sale basis. Profit per barrel of oil equivalent was 3.69 $/bbl 2 (compared to 8.58 $/bbl in 2023 and 21.07 $/bbl in 2022); the decline of this indicator in 2024 compared to 2023 was driven by lower prices, the effects of divestment and higher impairment of assets.
As of December 31, 2024, Eni’s total proved reserves amounted to 6,497 mmBOE; proved reserves of subsidiaries totaled 4,433 mmBOE; Eni’s share of reserves of equity-accounted entities was 2,064 mmBOE.
“Eni’s strategy and short-to-medium term targets in its Exploration & Production segment are disclosed in Item 5 – Business trends and Management’s expectations of operations.”
Disclosure of reserves
Overview
The Company has adopted comprehensive classification criteria for the estimates of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of- the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.
Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil&gas reserves can be designated as “proved”, the accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information.
Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s equity interest to total proved reserves of the contractual area, until expiration of the relevant mineral right. Eni’s proved reserves entitlements at PSAs are calculated so that the sale of production entitlements cover expenses incurred by the Group for field development (Cost Oil) and recognize a share of profit set contractually (Profit Oil). A similar scheme applies to service contracts.
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2 Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements” for a calculation of results of operations from oil and gas producing activities.
36
Reserves governance
Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is in charge of: (i) ensuring the periodic certification process of proved reserves; (ii) updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.
Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which stated that those guidelines comply with the SEC rules 3 . D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines, while for certain joint ventures and associates Eni relies on the annual certification of independent petroleum engineering companies.
The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department and the operations unit at the head office verify the production profiles of such properties where significant changes have occurred and operating expenses, respectively; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above-mentioned units and aggregates worldwide reserves data.
Eni’s Head of Reserves holds a Master's degree in Petroleum Engineering from the Polytechnic of Turin and 5-years Degree in Civil Hydraulic Engineering from the Alma Mater Studiorum - University of Bologna. He has 20 years of experience in the upstream industry and in reserves evaluation.
Staff involved in the reserves evaluation process fulfils the professional qualifications requested by the role and complies with the required level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.
Reserves independent evaluation
Eni has its proved reserves audited on a rotational basis by independent oil engineering companies.
The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators.
These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.
In order to calculate the net present value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third-party evaluators.
The volumes and monetary values of the reserves of certain joint venture and affiliated companies are certified on their behalf in a similar manner by independent petroleum engineering companies and provided to Eni 4 .
In 2024 5 , Ryder Scott Company and Sproule, for consolidated subsidiaries, and DeGolyer and MacNaughton, for equity accounted entities, provided an independent evaluation of approximately 40% 6 of Eni’s total proved reserves at December 31, 2024, confirming, as in previous years, the reasonableness of Eni internal evaluation. In the 2022-2024 three-year period, 85% of Eni total proved reserves were subject to an independent evaluation.
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3 See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009.
4 In 2024 Azule Energy and Vår Energi.
5 See "Item 19 - Exhibits".
6 Includes Azule Energy and Vår Energi for which Eni received a Third Party Letter.
37
Summary of proved oil and gas reserves
The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2024, 2023 and 2022. The break-down of proved reserves by geographic area complies with disclosure criteria as regulated by U.S. Securities and Exchange Commission (SEC) Regulation S-K, Item 1202.
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HYDROCARBONS (mmBOE) |
Italy |
Rest of Europe |
North Africa |
Sub-Saharan Africa |
Kazakhstan |
Rest of Asia |
Americas |
Australia and Oceania |
Total reserves |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 |
368 |
10 |
1,479 |
638 |
876 |
881 |
145 |
36 |
4,433 |
|
developed |
262 |
10 |
805 |
418 |
823 |
385 |
92 |
5 |
2,800 |
|
undeveloped |
106 |
|
674 |
220 |
53 |
496 |
53 |
31 |
1,633 |
|
Dec. 31, 2023 (a) |
374 |
60 |
1,658 |
809 |
933 |
733 |
238 |
37 |
4,842 |
|
developed |
261 |
56 |
935 |
482 |
872 |
379 |
184 |
11 |
3,180 |
|
undeveloped |
113 |
4 |
723 |
327 |
61 |
354 |
54 |
26 |
1,662 |
|
Dec. 31, 2022 (b) |
352 |
78 |
1,710 |
813 |
941 |
675 |
285 |
79 |
4,933 |
|
developed |
271 |
73 |
984 |
460 |
881 |
383 |
207 |
43 |
3,302 |
|
undeveloped |
81 |
5 |
726 |
353 |
60 |
292 |
78 |
36 |
1,631 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 (c) |
|
572 |
50 |
819 |
|
379 |
244 |
|
2,064 |
|
developed |
|
311 |
50 |
305 |
|
|
244 |
|
910 |
|
undeveloped |
|
261 |
|
514 |
|
379 |
|
|
1,154 |
|
Dec. 31, 2023 (a) |
|
425 |
8 |
494 |
|
378 |
267 |
|
1,572 |
|
developed |
|
235 |
8 |
305 |
|
|
267 |
|
815 |
|
undeveloped |
|
190 |
|
189 |
|
378 |
|
|
757 |
|
Dec. 31, 2022 (b) |
|
473 |
9 |
531 |
|
383 |
285 |
|
1,681 |
|
developed |
|
257 |
9 |
338 |
|
|
285 |
|
889 |
|
undeveloped |
|
216 |
|
193 |
|
383 |
|
|
792 |
|
Consolidated subsidiaries and equity accounted entities |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 |
368 |
582 |
1,529 |
1,457 |
876 |
1,260 |
389 |
36 |
6,497 |
|
developed |
262 |
321 |
855 |
723 |
823 |
385 |
336 |
5 |
3,710 |
|
undeveloped |
106 |
261 |
674 |
734 |
53 |
875 |
53 |
31 |
2,787 |
|
Dec. 31, 2023 (a) |
374 |
485 |
1,666 |
1,303 |
933 |
1,111 |
505 |
37 |
6,414 |
|
developed |
261 |
291 |
943 |
787 |
872 |
379 |
451 |
11 |
3,995 |
|
undeveloped |
113 |
194 |
723 |
516 |
61 |
732 |
54 |
26 |
2,419 |
|
Dec. 31, 2022 (b) |
352 |
551 |
1,719 |
1,344 |
941 |
1,058 |
570 |
79 |
6,614 |
|
developed |
271 |
330 |
993 |
798 |
881 |
383 |
492 |
43 |
4,191 |
|
undeveloped |
81 |
221 |
726 |
546 |
60 |
675 |
78 |
36 |
2,423 |
|
(a) Effective January 1, 2023, Eni has updated the conversion rate of gas produced to 5,232 cubic feet of gas equals to 1 barrel of oil (it was 5,263 cubic feet of gas per barrel in previous reporting period). The effect of this update on the change in the initial reserves balance as of January 1, 2023 amounted to 21 mmBOE. Prior-year converted amounts were left unchanged. |
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(b) Effective January 1, 2022, Eni has updated the conversion rate of gas produced to 5,263 cubic feet of gas equals 1 barrel of oil (it was 5,310 cubic feet of gas per barrel in previous reporting periods). The effect of this update on the change in the initial reserves balance as of January 1, 2022 amounted to 30 mmBOE. Prior-year converted amounts were left unchanged. |
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(c) Reserves volumes of the Rest of Europe area for 2024 were affected by the business combination with Ithaca Energy where the reserves divested in the consolidated subsidiary Eni UK were offset by the acquisition of an interest in the reserves of the equity-accounted entity resulting from the combination, participated by Eni with a 37.17% interest. |
38
|
LIQUIDS (mmBBL) |
Italy |
Rest of Europe |
North Africa |
Sub-Saharan Africa |
Kazakhstan |
Rest of Asia |
Americas |
Australia and Oceania |
Total reserves |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 |
213 |
|
458 |
268 |
591 |
578 |
127 |
|
2,235 |
|
developed |
129 |
|
291 |
187 |
539 |
233 |
81 |
|
1,460 |
|
undeveloped |
84 |
|
167 |
81 |
52 |
345 |
46 |
|
775 |
|
Dec. 31, 2023 |
211 |
27 |
523 |
334 |
637 |
485 |
213 |
|
2,430 |
|
developed |
136 |
24 |
326 |
225 |
576 |
240 |
163 |
|
1,690 |
|
undeveloped |
75 |
3 |
197 |
109 |
61 |
245 |
50 |
|
740 |
|
Dec. 31, 2022 |
188 |
36 |
531 |
367 |
644 |
433 |
234 |
1 |
2,434 |
|
developed |
139 |
32 |
336 |
212 |
585 |
231 |
171 |
1 |
1,707 |
|
undeveloped |
49 |
4 |
195 |
155 |
59 |
202 |
63 |
|
727 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 (a) |
|
391 |
8 |
226 |
|
110 |
23 |
|
758 |
|
developed |
|
207 |
8 |
103 |
|
|
23 |
|
341 |
|
undeveloped |
|
184 |
|
123 |
|
110 |
|
|
417 |
|
Dec. 31, 2023 |
|
326 |
6 |
207 |
|
110 |
26 |
|
675 |
|
developed |
|
167 |
6 |
107 |
|
|
26 |
|
306 |
|
undeveloped |
|
159 |
|
100 |
|
110 |
|
|
369 |
|
Dec. 31, 2022 |
|
350 |
8 |
235 |
|
100 |
27 |
|
720 |
|
developed |
|
173 |
8 |
135 |
|
|
27 |
|
343 |
|
undeveloped |
|
177 |
|
100 |
|
100 |
|
|
377 |
|
Consolidated subsidiaries and equity accounted entities |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 (a) |
213 |
391 |
466 |
494 |
591 |
688 |
150 |
|
2,993 |
|
developed |
129 |
207 |
299 |
290 |
539 |
233 |
104 |
|
1,801 |
|
undeveloped |
84 |
184 |
167 |
204 |
52 |
455 |
46 |
|
1,192 |
|
Dec. 31, 2023 |
211 |
353 |
529 |
541 |
637 |
595 |
239 |
|
3,105 |
|
developed |
136 |
191 |
332 |
332 |
576 |
240 |
189 |
|
1,996 |
|
undeveloped |
75 |
162 |
197 |
209 |
61 |
355 |
50 |
|
1,109 |
|
Dec. 31, 2022 |
188 |
386 |
539 |
602 |
644 |
533 |
261 |
1 |
3,154 |
|
developed |
139 |
205 |
344 |
347 |
585 |
231 |
198 |
1 |
2,050 |
|
undeveloped |
49 |
181 |
195 |
255 |
59 |
302 |
63 |
|
1,104 |
|
( a) Reserves volumes of the Rest of Europe area for 2024 were affected by the business combination with Ithaca Energy where the reserves divested in the consolidated subsidiary Eni UK were offset by the acquisition of an interest in the reserves of the equity-accounted entity resulting from the combination, participated by Eni with a 37.17% interest. |
|||||||||
39
|
NATURAL GAS (BCF) |
Italy |
Rest of Europe |
North Africa |
Sub-Saharan Africa |
Kazakhstan |
Rest of Asia |
Americas |
Australia and Oceania |
Total reserves |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 |
817 |
54 |
5,338 |
1,931 |
1,489 |
1,583 |
94 |
190 |
11,496 |
|
developed |
693 |
52 |
2,692 |
1,206 |
1,486 |
799 |
56 |
23 |
7,007 |
|
undeveloped |
124 |
2 |
2,646 |
725 |
3 |
784 |
38 |
167 |
4,489 |
|
Dec. 31, 2023 |
859 |
174 |
5,935 |
2,479 |
1,546 |
1,303 |
131 |
192 |
12,619 |
|
developed |
653 |
167 |
3,181 |
1,350 |
1,546 |
725 |
107 |
58 |
7,787 |
|
undeveloped |
206 |
7 |
2,754 |
1,129 |
|
578 |
24 |
134 |
4,832 |
|
Dec. 31, 2022 |
869 |
223 |
6,204 |
2,341 |
1,560 |
1,281 |
264 |
408 |
13,150 |
|
developed |
695 |
214 |
3,402 |
1,306 |
1,560 |
796 |
195 |
223 |
8,391 |
|
undeveloped |
174 |
9 |
2,802 |
1,035 |
|
485 |
69 |
185 |
4,759 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 (a) |
|
939 |
222 |
3,103 |
|
1,411 |
1,159 |
|
6,834 |
|
developed |
|
545 |
222 |
1,054 |
|
|
1,159 |
|
2,980 |
|
undeveloped |
|
394 |
|
2,049 |
|
1,411 |
|
|
3,854 |
|
Dec. 31, 2023 |
|
515 |
14 |
1,501 |
|
1,406 |
1,260 |
|
4,696 |
|
developed |
|
359 |
14 |
1,036 |
|
|
1,260 |
|
2,669 |
|
undeveloped |
|
156 |
|
465 |
|
1,406 |
|
|
2,027 |
|
Dec. 31, 2022 |
|
646 |
9 |
1,562 |
|
1,490 |
1,355 |
|
5,062 |
|
developed |
|
444 |
9 |
1,070 |
|
|
1,355 |
|
2,878 |
|
undeveloped |
|
202 |
|
492 |
|
1,490 |
|
|
2,184 |
|
Consolidated subsidiaries and equity accounted entities |
|
|
|
|
|
|
|
|
|
|
Dec. 31, 2024 (a) |
817 |
993 |
5,560 |
5,034 |
1,489 |
2,994 |
1,253 |
190 |
18,330 |
|
developed |
693 |
597 |
2,914 |
2,260 |
1,486 |
799 |
1,215 |
23 |
9,987 |
|
undeveloped |
124 |
396 |
2,646 |
2,774 |
3 |
2,195 |
38 |
167 |
8,343 |
|
Dec. 31, 2023 |
859 |
689 |
5,949 |
3,980 |
1,546 |
2,709 |
1,391 |
192 |
17,315 |
|
developed |
653 |
526 |
3,195 |
2,386 |
1,546 |
725 |
1,367 |
58 |
10,456 |
|
undeveloped |
206 |
163 |
2,754 |
1,594 |
|
1,984 |
24 |
134 |
6,859 |
|
Dec. 31, 2022 |
869 |
869 |
6,213 |
3,903 |
1,560 |
2,771 |
1,619 |
408 |
18,212 |
|
developed |
695 |
658 |
3,411 |
2,376 |
1,560 |
796 |
1,550 |
223 |
11,269 |
|
undeveloped |
174 |
211 |
2,802 |
1,527 |
|
1,975 |
69 |
185 |
6,943 |
|
(a) Reserves volumes of the Rest of Europe area for 2024 were affected by the business combination with Ithaca Energy where the reserves divested in the consolidated subsidiary Eni UK were offset by the acquisition of an interest in the reserves of the equity-accounted entity resulting from the combination, participated by Eni with a 37.17% interest. |
|||||||||
Proved reserves of natural gas liquids are immaterial to the Group operations.
Volumes of oil and natural gas applicable to long- term supply agreements with foreign governments in mineral assets where Eni is operator were marginal as of December 31, 2024 (2 and 5 mmBOE as of December 31, 2023 and 2022, respectively). Said volumes are not included in reserves volumes shown in the table herein.
|
|
Subsidiaries |
|
Equity-accounted entities |
||||
|
(mmBOE) |
2024 |
2023 |
2022 |
|
2024 |
2023 |
2022 |
|
Revisions of previous estimates |
323 |
303 |
(64) |
|
83 |
9 |
152 |
|
Improved recovery |
1 |
|
7 |
|
|
|
4 |
|
Extensions and discoveries |
38 |
105 |
118 |
|
329 |
|
61 |
|
Purchases of minerals-in-place |
89 |
44 |
22 |
|
230 |
2 |
551 |
|
Sales of minerals-in-place |
(381) |
(58) |
(228) |
|
(4) |
(1) |
(49) |
|
|
|
|
|
|
|
|
|
|
Total additions to proved reserves |
70 |
394 |
(145) |
|
638 |
10 |
719 |
|
Production for the year (a) |
(479) |
(485) |
(493) |
|
(146) |
(119) |
(95) |
(a) The difference compared to production sold of 565.0 mmBOE (532.0 mmboe in 2022 and 545.9 mmboe in 2023) reflected hydrocarbons volumes of 60.0 mmBOE consumed in operations, changes in inventories and other factors (55.8 mmBOE in 2022 and 58.2 mmBOE in 2023).
40
|
|
Subsidiaries and equity-accounted entities |
||
|
(%) |
2024 |
2023 |
2022 |
|
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources |
113 |
67 |
98 |
|
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic |
124 |
69 |
47 |
Eni’s proved reserves as of December 31, 2024 totaled 6,497 mmBOE (liquids 2,993 mmBBL; natural gas 18,330 BCF). Eni’s proved reserves reported an increase from December 31, 2023 (up by 83 mmBOE, or 1% from 2023) due to progress made in the year in exploring and developing new reserves and property acquisitions net of property sales.
Portfolio activities provided net negative additions of 66 mmBOE and comprised: (i) the Neptune Energy acquisition, jointly with Eni’s associate Vår Energi, with acquired assets in Norway, Algeria, Indonesia, the Netherlands and the United Kingdom; (ii) the business combination with Ithaca Energy, where the reserves divested from the consolidated subsidiary Eni UK were offset by Eni’s share of reserves in the equity-accounted entity resulting from the business combination (Eni’s interest 37.17%); (iii) the disposal of Nigerian onshore petroleum assets, the Nikaitchuq and Oooguruk petroleum assets in Alaska and certain minor oilfields in Congo.
All sources additions to proved reserves booked in 2024 were 708 mmBOE; of which 70 mmBOE came from Eni’s subsidiaries, while 638 mmBOE from Eni’s equity-accounted entities.
The net effect of price changes was a negative 22 mmBOE in 2024 (of which a net negative revision of 20 mmBOE recorded at Eni’s subsidiaries and a net negative revision of 2 mmBOE recorded at Eni’s equity-accounted entities) due to a lower Brent crude oil reference price used in the reserve estimation process of 81 $/barrel in 2024, compared to 83 $/barrel used in 2023. This price change led to the removal of reserves which have become uneconomical in the 2024 scenario (negative revision of 12 mmBOE recorded mainly at Eni’s subsidiaries) and net lower reserves entitlements under PSA contracts (negative revision of 8 mmBOE mainly recorded at Eni’s subsidiaries).
The methods (or technologies) used in Eni’s proved reserves assessment in 2024 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However, for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates.
The all sources reserves replacement ratio reported by Eni’s subsidiaries and equity-accounted entities was 113% in 2024 (67% in 2023 and 98% in 2022). The organic reserves replacement ratio was 124% in 2024 (69% in 2023 and 47% in 2022) which excluded sales and purchases of minerals-in-place.
The all sources reserve replacement ratio during the three-year period ended December 31, 2024, which included a net increase of 217 mmBOE related to sales and purchases, was 93%.
The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities – Oil & Gas (Topic 932) (see the supplemental oil and gas information in “Item 18 – Consolidated Financial Statements”). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserve replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects.
However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, reservoir performance, application of new technologies to improve the recovery factor as well as changes in oil&gas prices, political risks and geological and environmental risks. See “Item 3 – The Group is exposed to significant operational and economic risks associated with the exploration and production of crude oil and natural gas – Uncertainties in estimates of oil and natural gas reserves”.
The average reserves life index of Eni’s proved reserves was 10.4 years as of December 31, 2024, which included reserves of both subsidiaries and equity-accounted entities.
41
Eni’s subsidiaries
Eni’s subsidiaries added 70 mmBOE of proved oil and gas reserves in 2024. Additions comprised an increase of 13 mmBBL of liquids and of 292 BCF of natural gas. The breakdown of total additions to proved reserves was the following:
(i) revisions of previous estimates were positive for 323 mmBOE. The main positive revisions were obtained at the Ghasha, Lower Zakum and Hail fields in the United Arab Emirates, Berkine North, In Amenas, In Salah, HBNS and Brn Silurian fields in Algeria, Baleine field in Côte d'Ivoire and in the United States. The main negative changes were reported in Belayim and Meleiha fields in Egypt. Revisions also included net negative price effects of 20 mmBOE;
(ii) new discoveries and extensions of 38 mmBOE mainly as a result of the final investment decision at the Umm Shaif field in the United Arab Emirates and at the Bonga North field in Nigeria;
(iii) purchase of minerals-in-place of 89 mmBOE and mainly related to the acquisition of Neptune assets in Indonesia, the Netherlands and the United Kingdom; and
(iv) sales of minerals-in-place of 381 mmBOE mainly due to the sale of Alaska assets in the United States, Nigerian onshore assets and certain fields in Congo. In addition, sales of minerals-in-place included the offsetting effects of the business combination with Ithaca Energy, resulting in lower reserves at subsidiaries and increased reserves at equity-accounted entities.
Further information and explanations of significant changes with respect to each line item of the movements in net proved reserves are provided in “Item 18 – Notes to the Consolidated Financial Statement - Supplemental oil and gas information”.
Eni’s share of equity-accounted entities
Eni’s share of equity-accounted entities added 638 mmBOE of proved oil and gas reserves in 2024. Additions comprised an increase of 163 mmBBL of liquids and of 2,490 BCF of natural gas. The breakdown of total additions to proved reserves is the following: (i) new discoveries and extensions of 329 mmBOE related to booking of reserves at the Coral North project offshore Mozambique (329 mmBOE), based on the Company final investment decision, status of project maturity and commitment within the JV as well as the management’s reasonable expectation that remaining formal government approvals will be received shortly. The development of Coral North Project is governed under the terms and conditions of the Area 4 PSC assigned to the JV in 2006; (ii) purchase of minerals-in-place of 230 mmBOE related to the Vår Energi purchase of Neptune assets in Norway as well as the business combination with Ithaca Energy in UK; (iii) revisions of previous estimates were positive for 83 mmBOE and mainly related to the Coral South project in Mozambique, the Touat field in Algeria as well Azule Energy in Angola and Vår Energi. Revisions also included net negative price effects of 2 mmBOE; and (iv) sales of minerals-in-place of 4 mmBOE due to the divestment of certain fields of Vår Energi in Norway and Azule Energy in Angola.
Further information and explanations of significant changes with respect to each line item of the movements in net proved reserves are provided in “Item 18 – Notes to the Consolidated Financial Statement - Supplemental oil and gas information”.
Proved undeveloped reserves
Proved undeveloped reserves as of December 31, 2024 totaled 2,787 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,192 mmBBL and of natural gas amounted to 8,343 BCF, mainly concentrated in Africa and Asia. Proved undeveloped reserves of consolidated subsidiaries amounted to 775 mmBBL of liquids and 4,489 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2024.
|
Subsidiaries and equity-accounted entities |
|
|
(mmBOE) |
2024 |
|
Proved undeveloped reserves as of December 31, 2023 |
2,419 |
|
Transfers to proved developed reserves |
(128) |
|
Extensions and discoveries |
367 |
|
Revisions of previous estimates |
107 |
|
Improved recovery |
0 |
|
Portfolio |
22 |
|
Proved undeveloped reserves as of December 31, 2024 |
2,787 |
|
|
|
During 2024, Eni matured 128 mmBOE of proved undeveloped reserves to proved developed reserves due to progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the fields/projects in the following countries: Côte d'Ivoire, Angola, Kazakhstan and Italy.
For further information, please see the additional information on Oil & Gas producing activities required by the SEC in the “Item 18 - Notes to the consolidated financial statements”.
In 2024, capital expenditure amounted to approximately €10.3 billion to progress the development of PUDs.
Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complexity of development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The proved undeveloped reserves that have remained undeveloped for five years or more at the balance sheet date amounted to 0.85 BBOE, increasing from 2023, and are mainly related to the following projects where developments activities are in progress: (i) certain Libyan gas fields (0.45 BBOE) where production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force; (ii) certain fields in the United Arab Emirates (0.2 BBOE); (iii) the Johan Castberg project of Vår Energi (0.1 BBOE) due to project complexity; and (iii) Val d’Agri field in Italy (0.1 BBOE). (See also our discussion under the “Risk factors” section about risks associated with oil and gas development projects).
42
Eni remains strongly committed to put these projects into production in the coming years. The length of the development period depends on a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project.
Delivery commitments
Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities.
Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 611 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Ghana, Indonesia, Kazakhstan, Libya, Mozambique, Norway and Venezuela.
The sales contracts contain a mix of fixed and variable pricing formulas that are generally indexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available mainly from production of the Company's proved developed reserves. Production is expected to fully account of delivery commitments.
Eni has met all contractual delivery commitments as of December 31, 2024.
Oil and gas p r oduction, p r oduction prices and p r oduction costs
The matte r s r e g a r ding futu r e p r oduction, additions to r ese r v es and r elated p r oduction costs and estimated r ese r v es discussed bel o w and else w he r e he r ein a r e f or w a r d-looking statements that i n v ol v e risks and unce r tainties that could cause the actual r esults to dif f er material l y f r om those in su c h f or w a r d-looking statement s . Su c h risks and unce r tainties r elating to futu r e p r oduction and additions to r ese r v es in c lude political d e v elopments af f ecting the a w a r d of e xplo r ation or p r oduction inte r ests or w o r ld supp l y and prices f or oil and natu r al g a s , or c han g es in the unde r l ying economics of ce r tain of Eni ’ s impo r tant h y d r oca r bons p r oject s . Su c h risks and unce r tainties r elating to futu r e p r oduction costs in c lude delays or un e xpected costs incur r ed in Eni ’ s p r oduction ope r ation s .
In 2024, oil and n a tu r a l gas p r oduction a v ail a b le f or s a le a v e r a ged 1,572 KBOE/d (1,529 KBOE/d in 2023). Production increased by 3% compared to 2023 and was driven by organic growth and the full integration of Neptune, partly offset by the divestment of oil properties in Nigeria, Alaska and Congo, as part of a plan to high-grade the portfolio. The organic growth was due to continuing production ramp-ups at the Baleine project in Côte d'Ivoire, Congo and Mozambique, the start-up of a gas project in Italy as well as higher activity in Mexico and Libya.
Liquids production (783 KBBL/d) increased by 15 KBBL/d, or approximately 2% from the full year of 2023, mainly due to the Neptune acquisition and growth in Côte d'Ivoire, Mexico and Libya. These increases were partly offset by lower contribution in Egypt and Kazakhstan as well as mature fields decline and divestments.
Natural gas production (4,132 mmCF/d) increased by 152 mmCF/d, or approximately 4% compared to the full year of 2023, mainly due to the Neptune acquisition, growth in Congo, Mozambique and Libya, and the start of a gas project offshore Sicily (Italy). These increases were offset by mature fields decline and a slowdown of activities in Egypt due to issues on part of state-owned companies to fund their share of expenditures.
S a les v olumes of oil and gas p r oduction w e r e 565 mmBOE. The 11 mmBOE di f fe r ence o v er p r oduction on a v ail a b le- f o r -s a le basis (576 mmBOE in 2024) r e f lected main l y changes in i n v entory and other factor s . Approximately 3% of liquids production sold (287 mmBBL) was destined to Eni’s Refining business. About 13% of natural gas production sold (1,451 BCF) was destined to Eni’s Global Gas & LNG Portfolio business.
43
The t a b les b e l o w p ro vide Eni subsidiaries and its equity-accounted entities’ p r oduction (an n u a l v olumes and dai l y a v e r a ges), b y f in a l p r oduct ma r k eted of liquids and n a tu r a l gas b y country and ge o g r a phic a l a r ea of each of the last th r ee f isc a l y ear s .
Average daily production available for sale (a)
|
|
2024 |
|
2023 (b) |
|
2022 (c) |
||||||||||||
|
|
Liquids |
|
Natural gas |
|
Hydrocarbons |
|
Liquids |
|
Natural gas |
|
Hydrocarbons |
|
Liquids |
|
Natural gas |
|
Hydrocarbons |
|
|
(KBBL/d) |
|
(mmCF/d) |
|
(KBOE/d) |
|
(KBBL/d) |
|
(mmCF/d) |
|
(KBOE/d) |
|
(KBBL/d) |
|
(mmCF/d) |
|
(KBOE/d) |
|
Eni consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Italy |
27 |
|
166 |
|
59 |
|
29 |
|
178 |
|
63 |
|
36 |
|
208 |
|
76 |
|
Rest of Europe |
16 |
|
181 |
|
50 |
|
18 |
|
98 |
|
37 |
|
20 |
|
113 |
|
42 |
|
Netherlands |
1 |
|
61 |
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
15 |
|
120 |
|
38 |
|
18 |
|
98 |
|
37 |
|
20 |
|
113 |
|
42 |
|
North Africa |
177 |
|
1,900 |
|
540 |
|
190 |
|
2,039 |
|
581 |
|
199 |
|
1,978 |
|
575 |
|
Algeria |
56 |
|
253 |
|
104 |
|
62 |
|
249 |
|
110 |
|
62 |
|
96 |
|
81 |
|
Egypt |
59 |
|
1,071 |
|
264 |
|
67 |
|
1,242 |
|
305 |
|
77 |
|
1,337 |
|
331 |
|
Libya |
60 |
|
568 |
|
169 |
|
59 |
|
540 |
|
162 |
|
58 |
|
536 |
|
159 |
|
Tunisia |
2 |
|
8 |
|
3 |
|
2 |
|
8 |
|
4 |
|
2 |
|
9 |
|
4 |
|
Sub-Saharan Africa |
86 |
|
342 |
|
152 |
|
84 |
|
329 |
|
147 |
|
139 |
|
361 |
|
207 |
|
Angola |
|
|
|
|
|
|
|
|
|
|
|
|
52 |
|
|
|
52 |
|
Congo |
26 |
|
149 |
|
55 |
|
36 |
|
106 |
|
56 |
|
40 |
|
145 |
|
68 |
|
Côte d'Ivoire |
17 |
|
12 |
|
20 |
|
4 |
|
1 |
|
4 |
|
|
|
|
|
|
|
Ghana |
12 |
|
77 |
|
26 |
|
14 |
|
76 |
|
29 |
|
16 |
|
76 |
|
30 |
|
Nigeria |
31 |
|
104 |
|
51 |
|
30 |
|
146 |
|
58 |
|
31 |
|
140 |
|
57 |
|
Kazakhstan |
109 |
|
210 |
|
149 |
|
114 |
|
216 |
|
154 |
|
87 |
|
168 |
|
119 |
|
Rest of Asia |
93 |
|
415 |
|
173 |
|
85 |
|
354 |
|
153 |
|
78 |
|
345 |
|
143 |
|
China |
|
|
|
|
|
|
1 |
|
|
|
1 |
|
1 |
|
|
|
1 |
|
Indonesia |
1 |
|
411 |
|
80 |
|
1 |
|
343 |
|
66 |
|
1 |
|
271 |
|
52 |
|
Iraq |
28 |
|
|
|
28 |
|
23 |
|
|
|
23 |
|
15 |
|
|
|
15 |
|
Pakistan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50 |
|
10 |
|
Timor Leste |
|
|
2 |
|
1 |
|
|
|
7 |
|
2 |
|
1 |
|
17 |
|
4 |
|
Turkmenistan |
6 |
|
|
|
6 |
|
6 |
|
|
|
6 |
|
4 |
|
|
|
4 |
|
United Arab Emirates |
58 |
|
2 |
|
58 |
|
54 |
|
4 |
|
55 |
|
56 |
|
7 |
|
57 |
|
Americas |
59 |
|
30 |
|
64 |
|
68 |
|
45 |
|
76 |
|
59 |
|
54 |
|
69 |
|
Mexico |
25 |
|
12 |
|
27 |
|
22 |
|
13 |
|
24 |
|
14 |
|
9 |
|
15 |
|
United States |
34 |
|
18 |
|
37 |
|
46 |
|
32 |
|
52 |
|
45 |
|
45 |
|
54 |
|
Australia and Oceania |
|
|
13 |
|
2 |
|
|
|
36 |
|
7 |
|
|
|
50 |
|
10 |
|
Australia |
|
|
13 |
|
2 |
|
|
|
36 |
|
7 |
|
|
|
50 |
|
10 |
|
|
567 |
|
3,257 |
|
1,189 |
|
588 |
|
3,295 |
|
1,218 |
|
618 |
|
3,277 |
|
1,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eni share of equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Algeria |
|
|
55 |
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Angola |
86 |
|
76 |
|
101 |
|
85 |
|
74 |
|
100 |
|
36 |
|
63 |
|
49 |
|
Mozambique |
1 |
|
107 |
|
21 |
|
1 |
|
88 |
|
18 |
|
|
|
6 |
|
1 |
|
Norway |
114 |
|
329 |
|
176 |
|
87 |
|
244 |
|
133 |
|
89 |
|
274 |
|
141 |
|
Tunisia |
2 |
|
|
|
2 |
|
2 |
|
|
|
2 |
|
3 |
|
|
|
2 |
|
United Kingdom |
6 |
|
24 |
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela |
7 |
|
284 |
|
61 |
|
5 |
|
279 |
|
58 |
|
4 |
|
258 |
|
53 |
|
|
216 |
|
875 |
|
383 |
|
180 |
|
685 |
|
311 |
|
132 |
|
601 |
|
246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
783 |
|
4,132 |
|
1,572 |
|
768 |
|
3,980 |
|
1,529 |
|
750 |
|
3,878 |
|
1,487 |
|
(a) It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 135, 127 and 124 KBOE/d in 2024, 2023 and 2022, respectively. |
|
(b) Effective January 1, 2023, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil equivalent = 5,232 cubic feet of gas (it was 1 barrel of oil 5,263 cubic feet of gas). The effect of this update on production was 5 KBOE/d in the full year 2023. Prior-year converted amounts were left unchanged. |
|
(c) Effective January 1, 2022, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,263 cubic feet of gas (it was 1 barrel of oil = 5,310 cubic feet of gas). The effect of this update on production was 8 KBOE/d in the full year 2022. Prior-year converted amounts were left unchanged. |
44
Annual production available for sale (a)
|
|
2024 |
|
2023 (b) |
|
2022 (c) |
||||||||||||
|
|
Liquids |
|
Natural gas |
|
Hydrocarbons |
|
Liquids |
|
Natural gas |
|
Hydrocarbons |
|
Liquids |
|
Natural gas |
|
Hydrocarbons |
|
|
(mmBBL) |
|
(BCF) |
|
(mmBOE) |
|
(mmBBL) |
|
(BCF) |
|
(mmBOE) |
|
(mmBBL) |
|
(BCF) |
|
(mmBOE) |
|
Eni consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Italy |
10 |
|
61 |
|
21 |
|
10 |
|
65 |
|
23 |
|
13 |
|
76 |
|
28 |
|
Rest of Europe |
6 |
|
66 |
|
19 |
|
7 |
|
36 |
|
13 |
|
7 |
|
41 |
|
15 |
|
Netherlands |
|
|
22 |
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
6 |
|
44 |
|
14 |
|
7 |
|
36 |
|
13 |
|
7 |
|
41 |
|
15 |
|
North Africa |
65 |
|
695 |
|
198 |
|
69 |
|
744 |
|
211 |
|
73 |
|
722 |
|
210 |
|
Algeria |
20 |
|
92 |
|
38 |
|
23 |
|
91 |
|
40 |
|
23 |
|
35 |
|
30 |
|
Egypt |
22 |
|
392 |
|
97 |
|
24 |
|
453 |
|
111 |
|
28 |
|
488 |
|
121 |
|
Libya |
22 |
|
208 |
|
62 |
|
21 |
|
197 |
|
59 |
|
21 |
|
196 |
|
58 |
|
Tunisia |
1 |
|
3 |
|
1 |
|
1 |
|
3 |
|
1 |
|
1 |
|
3 |
|
1 |
|
Sub-Saharan Africa |
32 |
|
125 |
|
56 |
|
31 |
|
120 |
|
54 |
|
51 |
|
132 |
|
76 |
|
Angola |
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
19 |
|
Congo |
10 |
|
54 |
|
20 |
|
13 |
|
39 |
|
20 |
|
15 |
|
53 |
|
25 |
|
Côte d'Ivoire |
6 |
|
5 |
|
7 |
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
Ghana |
4 |
|
28 |
|
10 |
|
5 |
|
28 |
|
11 |
|
6 |
|
28 |
|
11 |
|
Nigeria |
12 |
|
38 |
|
19 |
|
11 |
|
53 |
|
21 |
|
11 |
|
51 |
|
21 |
|
Kazakhstan |
39 |
|
77 |
|
54 |
|
41 |
|
79 |
|
56 |
|
32 |
|
61 |
|
43 |
|
Rest of Asia |
34 |
|
152 |
|
63 |
|
31 |
|
129 |
|
56 |
|
28 |
|
126 |
|
52 |
|
China |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Indonesia |
1 |
|
150 |
|
29 |
|
|
|
125 |
|
24 |
|
|
|
99 |
|
19 |
|
Iraq |
10 |
|
|
|
10 |
|
9 |
|
|
|
9 |
|
6 |
|
|
|
6 |
|
Pakistan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18 |
|
3 |
|
Timor Leste |
|
|
1 |
|
1 |
|
|
|
3 |
|
1 |
|
|
|
7 |
|
1 |
|
Turkmenistan |
2 |
|
|
|
2 |
|
2 |
|
|
|
2 |
|
2 |
|
|
|
2 |
|
United Arab Emirates |
21 |
|
1 |
|
21 |
|
20 |
|
1 |
|
20 |
|
20 |
|
2 |
|
21 |
|
Americas |
21 |
|
11 |
|
24 |
|
25 |
|
17 |
|
28 |
|
22 |
|
20 |
|
25 |
|
Mexico |
9 |
|
4 |
|
10 |
|
8 |
|
5 |
|
9 |
|
5 |
|
3 |
|
5 |
|
United States |
12 |
|
7 |
|
14 |
|
17 |
|
12 |
|
19 |
|
17 |
|
17 |
|
20 |
|
Australia and Oceania |
|
|
5 |
|
1 |
|
|
|
13 |
|
3 |
|
|
|
18 |
|
4 |
|
Australia |
|
|
5 |
|
1 |
|
|
|
13 |
|
3 |
|
|
|
18 |
|
4 |
|
|
207 |
|
1,192 |
|
436 |
|
214 |
|
1,203 |
|
444 |
|
226 |
|
1,196 |
|
453 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eni share of equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Algeria |
|
|
20 |
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Angola |
31 |
|
28 |
|
37 |
|
31 |
|
27 |
|
36 |
|
13 |
|
23 |
|
18 |
|
Mozambique |
|
|
39 |
|
8 |
|
|
|
32 |
|
7 |
|
|
|
2 |
|
1 |
|
Norway |
42 |
|
120 |
|
64 |
|
32 |
|
89 |
|
49 |
|
33 |
|
100 |
|
51 |
|
Tunisia |
1 |
|
|
|
1 |
|
1 |
|
|
|
1 |
|
1 |
|
|
|
1 |
|
United Kingdom |
2 |
|
9 |
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Venezuela |
3 |
|
104 |
|
22 |
|
2 |
|
102 |
|
21 |
|
1 |
|
95 |
|
19 |
|
|
79 |
|
320 |
|
140 |
|
66 |
|
250 |
|
114 |
|
48 |
|
220 |
|
90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
286 |
|
1,512 |
|
576 |
|
280 |
|
1,453 |
|
558 |
|
274 |
|
1,416 |
|
543 |
|
(a) It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 49.3, 46.2 and 45.1 mmBOE in 2024, 2023 and 2022, respectively. |
|
(b) Effective January 1, 2023, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,232 cubic feet of gas (it was 1 barrel of oil = 5,263 cubic feet of gas). The effect of this update on production expressed in boe was approximately 2 mmboe for the full year of 2023. Prior-year converted amounts were left unchanged. |
|
(c) Effective January 1, 2022, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,263 cubic feet of gas (it was 1 barrel of oil = 5,310 cubic feet of gas). The effect of this update on production expressed in boe was approximately 3 mmBOE for the full year of 2022. Prior-year converted amounts were left unchanged. |
45
Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 17 KBOE/d, 33 KBOE/d and 35 KBOE/d in 2024, 2023 and 2022, respectively.
The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. In addition, Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided.
|
($) |
|
|
|
|
|
|
|
|
|
|
2022 |
|
|
|
|
|
|
|
|
|
|
Consolidated subsidiaries |
Italy |
Rest of Europe |
North Africa |
Sub-Saharan Africa |
Kazakhstan |
Rest of Asia |
Americas |
Australia and Oceania |
Total |
|
Oil and condensates, per BBL |
67.07 |
93.94 |
90.32 |
103.96 |
86.94 |
94.13 |
92.03 |
60.89 |
92.41 |
|
Natural gas, per KCF |
20.32 |
30.22 |
7.12 |
4.99 |
0.69 |
10.57 |
6.48 |
4.10 |
8.61 |
|
Total hydrocarbons, per BOE |
87.98 |
128.03 |
55.43 |
83.12 |
64.59 |
76.85 |
83.45 |
22.25 |
69.07 |
|
Average production cost, per BOE |
14.77 |
13.15 |
4.87 |
12.12 |
5.85 |
6.56 |
17.05 |
6.15 |
7.94 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Oil and condensates, per BBL |
|
97.51 |
17.82 |
85.71 |
|
|
88.39 |
|
92.97 |
|
Natural gas, per KCF |
|
31.02 |
9.67 |
33.79 |
|
|
4.76 |
|
19.87 |
|
Total hydrocarbons, per BOE |
|
121.12 |
19.31 |
108.43 |
|
|
29.27 |
|
98.29 |
|
Average production cost, per BOE |
|
11.58 |
7.57 |
14.15 |
|
|
1.32 |
|
9.86 |
|
2023 |
|
|
|
|
|
|
|
|
|
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Oil and condensates, per BBL |
67.76 |
72.77 |
72.10 |
81.79 |
72.71 |
80.19 |
75.30 |
54.02 |
74.87 |
|
Natural gas, per KCF |
13.67 |
14.44 |
6.93 |
5.36 |
0.74 |
10.38 |
3.22 |
4.16 |
7.28 |
|
Total hydrocarbons, per BOE |
69.80 |
74.31 |
48.60 |
60.51 |
54.01 |
69.03 |
68.89 |
22.11 |
56.23 |
|
Average production cost, per BOE |
16.36 |
16.21 |
4.86 |
13.21 |
5.12 |
5.90 |
18.22 |
10.68 |
7.84 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Oil and condensates, per BBL |
|
79.33 |
18.00 |
75.26 |
|
|
67.62 |
|
76.60 |
|
Natural gas, per KCF |
|
20.53 |
9.69 |
11.94 |
|
|
5.22 |
|
12.18 |
|
Total hydrocarbons, per BOE |
|
88.95 |
19.31 |
72.12 |
|
|
30.76 |
|
71.32 |
|
Average production cost, per BOE |
|
12.46 |
10.09 |
13.48 |
|
|
1.00 |
|
10.70 |
|
2024 |
|
|
|
|
|
|
|
|
|
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Oil and condensates, per BBL |
67.40 |
75.00 |
71.00 |
78.66 |
72.71 |
76.97 |
73.73 |
|
73.61 |
|
Natural gas, per KCF |
11.73 |
10.20 |
6.78 |
5.75 |
0.89 |
11.09 |
3.20 |
4.38 |
7.24 |
|
Total hydrocarbons, per BOE |
64.18 |
59.88 |
47.98 |
59.22 |
54.17 |
68.33 |
68.71 |
22.95 |
55.42 |
|
Average production cost, per BOE |
17.67 |
19.22 |
5.31 |
12.02 |
5.58 |
6.73 |
18.49 |
29.33 |
8.37 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Oil and condensates, per BBL |
|
76.72 |
20.98 |
74.77 |
|
|
68.12 |
|
75.30 |
|
Natural gas, per KCF |
|
12.99 |
7.45 |
9.95 |
|
|
5.3 |
|
9.48 |
|
Total hydrocarbons, per BOE |
|
73.54 |
37.09 |
68.67 |
|
|
32.3 |
|
64.15 |
|
Average production cost, per BOE |
|
11.23 |
7.81 |
15.03 |
|
|
1.10 |
|
10.71 |
Development well activity
In 2024, a total of 217 development wells were drilled (57.3 of which represented Eni’s share) as compared to 165 development wells drilled in 2023 (83.6 of which represented Eni’s share) and 187 development wells drilled in 2022 (71.1 of which represented Eni’s share).
The drilling of 105 development wells (35.8 of which represented Eni’s share) is currently underway.
46
The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2024. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
|
|
Net wells completed |
|
Wells in progress at 31 Dec. |
||||||
|
(units) |
2024 |
2023 |
2022 |
|
2024 |
||||
|
|
Productive |
Dry |
Productive |
Dry |
Productive |
Dry |
|
Gross |
Net |
|
Italy |
1.2 |
|
1.0 |
|
1.0 |
|
|
|
|
|
Rest of Europe |
3.8 |
|
4.8 |
|
4.6 |
|
|
12.0 |
1.4 |
|
North Africa |
21.3 |
0.5 |
39.4 |
|
25.6 |
0.5 |
|
8.0 |
6.5 |
|
Sub-Saharan Africa |
9.2 |
0.5 |
5.6 |
|
8.5 |
|
|
43.0 |
13.1 |
|
Kazakhstan |
1.2 |
|
2.0 |
|
0.6 |
|
|
2.0 |
0.6 |
|
Rest of Asia |
13.4 |
|
22.9 |
|
22.1 |
|
|
37.0 |
11.2 |
|
Americas |
6.2 |
|
6.9 |
|
8.2 |
|
|
2.0 |
2.0 |
|
Australia and Oceania |
|
|
1.0 |
|
|
|
|
1.0 |
1.0 |
|
Total including equity-accounted entities |
56.3 |
1.0 |
83.6 |
|
70.6 |
0.5 |
|
105.0 |
35.8 |
Exploration well activity
In 2024, a total of 37 new exploratory wells were drilled (15.0 of which represented Eni’s share), as compared to 39 exploratory wells drilled in 2023 (21.6 of which represented Eni’s share) and 40 exploratory wells drilled in 2022 (18.9 of which represented Eni’s share).
The overall commercial success rate was 12.5% (12.8% net to Eni) as compared to 34.5% (38% net to Eni) and 45% (44% net to Eni) in 2023 and 2022, respectively.
The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2024. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. For further information on the ageing of suspended wells see “Item 18 - Note 12 to the Consolidated Financial Statements.”
|
|
Net wells completed |
|
Wells in progress at Dec. 31 |
||||||
|
(units) |
2024 |
2023 |
2022 |
|
2024 |
||||
|
|
Productive |
Dry |
Productive |
Dry |
Productive |
Dry |
|
Gross |
Net |
|
Italy |
|
|
|
|
|
|
|
1.0 |
0.6 |
|
Rest of Europe |
|
1.9 |
0.1 |
0.4 |
0.4 |
1.2 |
|
66.0 |
16.9 |
|
North Africa |
1.5 |
4.6 |
5.0 |
6.2 |
5.4 |
8.3 |
|
15.0 |
10.4 |
|
Sub-Saharan Africa |
0.1 |
|
0.3 |
0.9 |
3.7 |
2.4 |
|
37.0 |
18.3 |
|
Kazakhstan |
|
1.0 |
|
|
|
|
|
|
|
|
Rest of Asia |
|
3.5 |
0.9 |
1.3 |
0.7 |
1.0 |
|
14.0 |
6.3 |
|
Americas |
|
|
|
1.4 |
|
|
|
6.0 |
3.6 |
|
Australia and Oceania |
|
|
|
|
|
|
|
1.0 |
0.3 |
|
Total including equity-accounted entities |
1.6 |
11.0 |
6.3 |
10.2 |
10.2 |
12.9 |
|
140.0 |
56.4 |
Oil and gas properties, operations and ac r eage
In 2024, Eni performed its operations in thirty-five countries located in five continents. As of December 31, 2024, Eni’s mineral right portfolio consisted of 874 exclusive or shared rights of exploration and development oil and gas activities. Total acreage amounts to 211,347 square kilometers net to Eni (total acreage was 301,308 square kilometers net to Eni as of December 31, 2023). Developed acreage was 26,384 square kilometers and undeveloped acreage was 184,963 square kilometers net to Eni.
In 2024 new leases were purchased or awarded in Netherlands, Namibia, Australia, Angola, Côte d'Ivoire, Norway, and the United Kingdom for a total increase in acreage of approximately 24,600 square kilometers. Relinquishment for the year related mainly to Morocco, Kenya, Angola, Argentina, Indonesia, Italy, Nigeria, Oman, Timor Leste and Vietnam covering an acreage of approximately 113,030 square kilometers. Interest increases were reported mainly in Indonesia and Mexico for a total acreage of approximately 2,270 square kilometers. Partial relinquishment was reported mainly in Egypt, Ghana, Italy, Mexico, the United Kingdom, and the United Arab Emirates for approximately 3,800 square kilometers.
47
Eni’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions under which the Company maintains exploration and/or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Eni may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, Eni has generally been successful in obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Company.
The gross undeveloped acreages that will expire in the next three years are related to exploration leases, blocks, concessions in: (i) Rest of Europe, in particular in Cyprus, Albania, Netherlands, Norway and the United Kingdom; (ii) Rest of Asia, in particular in Kazakhstan, Timor Leste, Vietnam, Lebanon, Oman and the United Arab Emirates; (iii) North Africa, in particular in Algeria, Libya and Egypt; (iv) Sub-Saharan Africa, in particular in Angola, Namibia, Ghana and Côte d'Ivoire; (v) Americas, in particular in Mexico; and (vi) Australia and Oceania, in particular in Australia. In most cases extension or renewal options are contractually defined and may or may not be exercised depending on the results of the studies and the planned activities. Management believes that a significant amount of acreage will be maintained following extension or renewal.
The t a b le b e l o w p ro vides certain in f o r m a tion a bout the Compa n y ’ s oil&gas p r opertie s . It p ro vides the tot a l g r oss and net d eve loped and und eve loped oil and n a tu r a l gas ac r e a ge in w hich the G r oup and its equity-accounted entities had inte r est as of December 31, 2024. A g r oss ac r e a ge is one in w hich Eni o wns a w o r king inte r est.
48
|
|
December 31, 2023 |
|
December 31, 2024 |
||||||
|
|
Total |
|
Number of |
Gross developed |
Gross undeveloped |
Total gross |
Net developed |
Net undeveloped |
Total net |
|
|
net acreage (a) |
|
interests |
acreage (a) (b) |
acreage (a) |
acreage (a) |
acreage (a) (b) |
acreage (a) |
acreage (a) |
|
EUROPE |
35,246 |
|
474 |
18,486 |
72,104 |
90,590 |
8,966 |
29,785 |
38,752 |
|
Italy |
10,430 |
|
102 |
7,523 |
1,913 |
9,436 |
6,286 |
1,511 |
7,797 |
|
Rest of Europe |
24,816 |
|
372 |
10,963 |
70,191 |
81,154 |
2,680 |
28,274 |
30,955 |
|
Albania |
587 |
|
1 |
|
587 |
587 |
|
587 |
587 |
|
Cyprus |
13,988 |
|
7 |
|
25,474 |
25,474 |
|
13,988 |
13,988 |
|
Netherlands |
|
|
35 |
2,003 |
2,539 |
4,542 |
855 |
744 |
1,599 |
|
Norway |
8,161 |
|
181 |
5,820 |
34,436 |
40,256 |
926 |
9,247 |
10,174 |
|
United Kingdom |
2,080 |
|
148 |
3,140 |
7,155 |
10,295 |
899 |
3,708 |
4,607 |
|
AFRICA |
113,242 |
|
286 |
45,710 |
185,879 |
231,589 |
12,755 |
61,171 |
73,926 |
|
North Africa |
54,659 |
|
154 |
20,796 |
114,038 |
134,834 |
8,298 |
36,833 |
45,131 |
|
Algeria |
7,872 |
|
75 |
10,626 |
8,067 |
18,693 |
4,143 |
3,952 |
8,095 |
|
Egypt |
12,427 |
|
53 |
4,911 |
25,070 |
29,981 |
1,714 |
8,491 |
10,205 |
|
Libya |
24,644 |
|
14 |
1,963 |
78,085 |
80,048 |
958 |
23,686 |
24,644 |
|
Morocco |
7,529 |
|
|
|
|
|
|
|
|
|
Tunisia |
2,187 |
|
12 |
3,296 |
2,816 |
6,112 |
1,483 |
704 |
2,187 |
|
Sub-Saharan Africa |
58,583 |
|
132 |
24,914 |
71,841 |
96,755 |
4,457 |
24,338 |
28,795 |
|
Angola |
7,633 |
|
73 |
10,790 |
40,335 |
51,125 |
914 |
8,542 |
9,456 |
|
Congo |
1,299 |
|
12 |
666 |
1,320 |
1,986 |
386 |
713 |
1,099 |
|
Côte d'Ivoire |
3,960 |
|
11 |
1,310 |
8,948 |
10,258 |
1,068 |
7,939 |
9,007 |
|
Ghana |
495 |
|
4 |
226 |
946 |
1,172 |
100 |
402 |
502 |
|
Kenya |
35,724 |
|
|
|
|
|
|
|
|
|
Mozambique |
3,260 |
|
7 |
719 |
7,803 |
8,522 |
180 |
3,080 |
3,260 |
|
Namibia |
|
|
1 |
|
5,386 |
5,386 |
|
1,144 |
1,144 |
|
Nigeria |
6,212 |
|
24 |
11,203 |
7,103 |
18,306 |
1,809 |
2,518 |
4,327 |
|
ASIA |
140,571 |
|
44 |
9,515 |
150,500 |
160,015 |
3,440 |
77,464 |
80,904 |
|
Kazakhstan |
1,947 |
|
6 |
2,391 |
2,505 |
4,896 |
442 |
831 |
1,273 |
|
Rest of Asia |
138,624 |
|
38 |
7,124 |
147,995 |
155,119 |
2,998 |
76,633 |
79,631 |
|
China |
7 |
|
2 |
43 |
|
43 |
7 |
|
7 |
|
Indonesia |
12,128 |
|
10 |
2,379 |
15,076 |
17,455 |
2,006 |
10,045 |
12,051 |
|
Iraq |
446 |
|
1 |
1,074 |
|
1,074 |
446 |
|
446 |
|
Lebanon |
610 |
|
1 |
|
1,742 |
1,742 |
|
610 |
610 |
|
Oman |
58,955 |
|
2 |
|
11,256 |
11,256 |
|
9,037 |
9,037 |
|
Qatar |
38 |
|
1 |
|
1,206 |
1,206 |
|
38 |
38 |
|
Timor Leste |
5,960 |
|
3 |
412 |
4,032 |
4,444 |
108 |
4,032 |
4,140 |
|
Turkmenistan |
180 |
|
1 |
200 |
|
200 |
180 |
|
180 |
|
United Arab Emirates |
17,830 |
|
11 |
3,016 |
28,251 |
31,267 |
251 |
16,407 |
16,658 |
|
Vietnam |
21,251 |
|
3 |
|
17,902 |
17,902 |
|
15,245 |
15,245 |
|
Other Countries (c) |
21,219 |
|
3 |
|
68,530 |
68,530 |
|
21,219 |
21,219 |
|
AMERICAS |
9,498 |
|
62 |
1,943 |
11,566 |
13,509 |
895 |
7,441 |
8,336 |
|
Mexico |
3,442 |
|
10 |
67 |
5,165 |
5,232 |
67 |
3,269 |
3,336 |
|
United States |
631 |
|
41 |
615 |
172 |
787 |
331 |
31 |
362 |
|
Venezuela |
1,066 |
|
6 |
1,261 |
1,543 |
2,804 |
497 |
569 |
1,066 |
|
Other Countries |
4,359 |
|
5 |
|
4,686 |
4,686 |
|
3,572 |
3,572 |
|
AUSTRALIA AND OCEANIA |
2,751 |
|
8 |
328 |
15,394 |
15,722 |
328 |
9,101 |
9,429 |
|
Australia |
2,751 |
|
8 |
328 |
15,394 |
15,722 |
328 |
9,101 |
9,429 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
301,308 |
|
874 |
75,982 |
435,443 |
511,425 |
26,384 |
184,962 |
211,347 |
|
(a) Square kilometers. |
|||||||||
|
(b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves. |
|||||||||
|
(c) Includes exploration acreage in Russia that are expected to be relinquished. |
|||||||||
The table below sets forth, as of December 31, 2024 and by main producing countries in each geographic area, Eni’s producing assets, the year in which Eni’s activities started and the Eni’s participating interest in each asset. The table does not include the assets held by the joint ventures and associates. In particular: (i) in Angola, the Azule Energy joint venture (Eni's interest 50%) holds interests in 17 blocks (of which 9 exploration blocks) and also in the Angola LNG JV; (ii) in the United Kingdom, the Ithaca Energy joint venture (Eni’s interest 37.17%) holds interests in 37 fields, of which 10 operated and production fields, located in the North Sea; (iii) in Norway, the Vår Energi associate (Eni's interest 63.1%) holds interests in 142 licences (of which 83 development licenses and 59 exploration licences); (iv) in Mozambique, the Mozambique Rovuma Venture SpA joint venture (Eni's interest 35.71%) is the operator of the Area 4 production licence; (v) in Venezuela, where the Cardon IV (Eni's interest 50%), PetroSucre (Eni’s interest 26%) and PetroJunin (Eni’s interest 40%) joint ventures holds interests in the Perla, Corocoro and Junin 5 production fields, respectively; (vi) in Tunisia, where operate the Société Italo Tunisienne d’Exploitation Pétrolière (Eni’s interest 50%) joint venture; and (vii) in Algeria, where operate the E&E Touat BV joint venture (Eni’s interest 54%).
49
|
ITALY |
Adriatic and Ionian Sea: Barbara (100%), Annamaria (100%), Clara NW (51%), Hera Lacinia (100%) and Cervia-Arianna (100%) |
|
(1926) |
Basilicata Region: Val d'Agri (61%) |
|
|
Sicily: Gela (100%), Argo-Cassiopea (60%), Giaurone (100%) and Bronte (100%) |
|
|
|
|
REST OF EUROPE |
|
|
Netherlands |
E17a-A (37.15%), F3 (58.96%), G-blocks (from 32,85% to 60%), K2b-A (56.62%), K9ab-B (from 31.06% to 35.43%), L12-L15 (from 30% to 60.23%), L10/K12 (from 30.39% to 49.29%), L5 hub (from 59.50% to 60%), Q13a-A (50%) and K6-D (27.47%) |
|
(2024) |
|
|
|
|
|
NORTH AFRICA |
|
|
Algeria (a) |
Sif Fatima II (49%), Zemlet El Arbi (49%), Ourhoud II (49%), Blocks 403a/d (100%), Block ROM North (35%), Blocks 401a/402a (100%), Block 403 (50%), Block 405b (75%), Berkine South (75%), In Amenas (45.89%), In Salah (33.15%) and Block 404-208 (17.5%) |
|
(1981) |
|
|
Egypt (a)(b) |
Shorouk (Zohr - 50%), Nile Delta (Abu Madi West/Nidoco - 75%), Sinai (Belayim Land, Belayim Marine, Abu Rudeis and Sinai Ras Gharra - 100%), Meleiha (76%), North Port Said (Port Fouad - 100%), Temsah (Tuna, Temsah and Denise - 50%), Southwest Meleiha (75%), Baltim (50%), North El Hammad Offshore (Bashrush - 37.5%), East Obayed (Faramid - 75%), Ras el Barr (Ha'py and Seth - 50%), South Ghara (25%) and Alam El Shawish (25%) |
|
(1954) |
|
|
Libya (a) |
Onshore contract areas: Area A (former concession 82 - 50%), Area B (former concession 100/ Bu-Attifel and Block NC 125 - 50%), Area E (El-Feel - 33.3%) and Area D (Block NC 169 - 50%) |
|
(1959) |
Offshore contract areas: Area C (Bouri - 50%) and Area D (Block NC 41 - 50%) |
|
Tunisia |
Maamoura (49%), Baraka (49%), Adam (25%), Oued Zar (50%) and Djebel Grouz (50%) |
|
(1961) |
|
|
|
|
|
SUB-SAHARAN AFRICA |
|
|
Congo |
Néné-Banga Marine and Litchendjili (Block Marine XII, 65%), Kitina (52%), M’Boundi (83%) and Yanga Sendji (29.75%) |
|
(1968) |
|
|
Côte d'Ivoire |
Baleine (77.25%) |
|
(2015) |
|
|
Ghana |
Offshore Cape Three Points (44.44%) |
|
(2009) |
|
|
Nigeria (c) |
OML 125 (100%) and OML 118 (12.5%) |
|
(1962) |
|
|
|
|
|
KAZAKHSTAN (a) |
Karachaganak (29.25%) and Kashagan (16.81%) |
|
(1992) |
|
|
|
|
|
REST OF ASIA |
|
|
Indonesia |
Jangkrik (55%) and Merakes (65%) |
|
(2001) |
|
|
Iraq |
Zubair (41.56%) (d) |
|
(2009) |
|
|
United Arab Emirates |
Lower Zakum (5%), Umm Shaif and Nasr (10%) and Area B - Sharjah (50%) |
|
(2018) |
|
|
|
|
|
AMERICAS |
|
|
Mexico |
Area 1 (100%) |
|
(2019) |
|
|
United States |
Allegheny (100%), Appaloosa (100%), Pegasus (100%), Longhorn (75%), Devils Towers (100%), Triton (100%), Europa (32%), Medusa (25%), Lucius (14.45%), Frontrunner (37.5%) and Heidelberg (12.5%) |
|
(1968) |
|
|
|
50
|
(a) In certain extractive initiatives, Eni and the host Country agree to assign the operatorship of a given initiative to an incorporated joint venture, a so‐called operating company. The operating company in its capacity as the operator is responsible of managing extractive operations. Those operating companies are not controlled by Eni. |
|
(b) Eni’s working interests (and not participating interests) are reported. This includes Eni’s share of costs incurred on behalf of the first party accordingly to the terms of PSAs inforce in the Country. |
|
(c) As partners of SPDC JV, Eni holds a 5% interest in 15 onshore blocks and in 1 conventional offshore block. |
|
(d) Eni is leading a consortium of partners including Kogas and the national oil companies Missan Oil and Basra Oil within a Technical Service Contract as contractor. |
The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2024. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same borehole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 6,808 (2,147.9 of which represent Eni’s share).
|
Productive oil and gas wells at Dec. 31, 2024 (a) |
|||||
|
(units) |
Oil Wells |
|
Natural gas Wells |
||
|
|
Gross |
Net |
|
Gross |
Net |
|
Italy |
120.0 |
108.5 |
|
230.0 |
200.1 |
|
Rest of Europe |
694.0 |
68.1 |
|
297.0 |
64.3 |
|
North Africa |
1,827.0 |
788.0 |
|
452.0 |
183.2 |
|
Sub-Saharan Africa |
1,608.0 |
238.8 |
|
124.0 |
14.8 |
|
Kazakhstan |
212.0 |
58.0 |
|
2.0 |
0.6 |
|
Rest of Asia |
960.0 |
299.0 |
|
80.0 |
29.9 |
|
Americas |
190.0 |
86.3 |
|
9.0 |
5.3 |
|
Australia and Oceania |
|
|
|
3.0 |
3.0 |
|
|
|
|
|
|
|
|
Total including equity-accounted entities |
5,611.0 |
1,646.7 |
|
1,197.0 |
501.2 |
(a) Multiple completion wells included above: approximately 894 (235.2 net to Eni).
Eni’s exploration and production activities are subject to a broad range of laws and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and condition of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These contractual arrangements usually take the form of concession agreements or production sharing agreements:
- Concession contracts are currently applied mainly in OECD countries and regulate relationships between States and oil companies with regards to hydrocarbon exploration and production activity. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions obtained. As compensation for mineral concessions, it pays royalties on production (which may be in cash or in-kind) and taxes on profits from the exploitation of oil and gas concessions to each state in accordance with local tax legislation. Both exploration and production licenses are granted generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases): the term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right.
In Particular, Eni’s exploration and production activities are regulated by concession contracts or a similar scheme mainly in Italy, Ghana, Tunisia, the United Arab Emirates, the United Kingdom, the United States, certain assets in Nigeria, Angola and Australia. In Norway, Eni’s activities are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.
- Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in countries in Africa, Middle East and Far East. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil).
51
A similar scheme applies to some Service contracts.
Eni’s exploration and production activities are regulated by PSA or scheme similar in Algeria, Angola, China, Congo, Egypt, Indonesia, Libya, Mexico, Mozambique, Timor Leste in the JPDA area, Turkmenistan, certain assets in Nigeria, and Kazakhstan.
Development and production activities in Iraq are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to PSA.
Eni’s principal oil and gas properties are described below. For further information on main activities of the year see also “Significant business portfolio”. In the discussion that follows, references to hydrocarbon production are intended to represent hydrocarbon production available for sale.
Italy
Eni’s activities in Italy are mainly deployed in the Adriatic and Ionian Seas, the Central Southern Apennines and mainland and offshore Sicily. Eni operates 23 onshore and 46 offshore productive concessions. In 2024, Italy accounted for approximately 4% of Eni’s total worldwide production of oil and natural gas.
In 2024, 30% of Eni’s domestic production came from fields in the Adriatic and Ionian Seas, 49% from the Central Southern Apennines and approximately 15% from Sicily.
In the gas assets of the Adriatic and Ionian Seas, activities concerned: (i) production start-up of the Donata 4 well through existing facilities; (ii) maintenance and production optimization intervention mainly at the Cervia field; (iii) asset rationalization program; and (iv) an upgrading compression facilities project at Casalborsetti and Falconara treatment facilities in order to increase efficiency and reduce CO 2 emissions. The project completion is expected in 2025.
The decommissioning program has been continued during 2024, according to the Italian Ministerial Decree 15 February 2019 “Linee guida nazionali per la dismissione mineraria delle piattaforme per la coltivazione in mare e delle infrastrutture connesse”, by means of awarding a contract for the removal of 10 platforms. Activities start-up is expected in 2025. A plug-and-abandon campaign of non-productive onshore and offshore wells is ongoing.
In the Val d’Agri concession, activities carried out during the year concerned: (i) sidetrack of existing two wells, in line with approved “Work Program”. Production start-up was achieved in 2025; and (ii) production optimization activities to mitigate field decline.
In August 2024 the production of the Argo Cassiopea gas field has started. Natural gas production is delivered via a sealine to the Gela treatment facilities and then to the national grid.
During 2024, the cancellation of the -PiTESAI- has brought the legislative mining right (Titoli minerari) back to the original text, thus reopening to the possibility of activities in previously non-suitable areas. In addition, the Decree 153/2024 (D.L. Ambiente) has introduced some important changes to the mining regulations, in particular reducing the limit for offshore upstream activities from 12 to 9 miles from coast.
Exploration activities yielded positive results with the GEMINI 1 exploration well drilled at the end of 2024 in the Sicily offshore, nearby Cassiopea field. Production start-up, with all required authorization, will leverage on the synergies with the Argo Cassiopea production and treatment facilities.
Rest of Europe
Eni’s operations in the Rest of Europe are mainly conducted in the United Kingdom through Ithaca Energy, Norway through Vår Energi and Netherlands as a result of the Neptune acquisition. In 2024, the Rest of Europe accounted for 15% of Eni’s total worldwide production of oil and natural gas.
Netherlands . Main development activities concerned: (i) production optimization programs in the K12-G and K2b-A6 licenses; and (ii) concept definition activities of the L7F field development project, with a final investment decision expected in 2025.
Norway . Main development activities concerned the Johan Castberg and Balder X sanctioned project in the PL 001 licence in the North Sea as well as the Halten East sanctioned project. Development activities are ongoing and production start-up of three projects is expected in 2025. In addition, during 2024, the Balder Phase V development project was sanctioned.
On March 31, 2025, the Johan Castberg oil field in the Barents Sea came on stream. The Johan Castberg field consists of the Skrugard, Havis and Drivis discoveries, which were made between 2011 and 2014. The field will be producing for 30 years and can produce 220 KBBL/d at peak. Eni’s associate Vår Energi ASA has a 30% working interest in the asset.
Exploration activities yielded positive results with 13 wells drilled in the Ringhorne North, Cerisa, and Countach operated hubs, near the existing production infrastructures of Balder, Gjoa, and Goliat fields, respectively.
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United Kingdom . In October 2024, Eni finalized the combination of the upstream assets in the UK, excluding East Irish Sea assets and CCUS activities, with Ithaca Energy plc. The combination provided the contribution of Eni’s assets to Ithaca Energy in exchange for a participating interest of 37.17% in the entity post transaction. The transaction closed at the beginning of October 2024, having been approved by the competent authorities and the relevant antitrust regulators.
Development activities concerned: (i) production start-up of the Talbot project; and (ii) the completion of drilling activities and production start-up of three development wells in the Seagull field. During the year, one additional development well was completed and start-up is expected in 2025.
The PL2638, P2664, and P2668 exploration licenses were awarded in 2024, located in the North Sea.
North Africa
Eni’s operations in North Africa are mainly conducted in Algeria, Egypt, Libya and Tunisia. In 2024, North Africa accounted for 35% of Eni’s total worldwide production of oil and natural gas.
Algeria . In 2024, the acquisition of the Neptune assets in Western Sahara in the Touat concession (Eni’s interest 35.1%) was completed.
In July 2024, Eni signed a Memorandum of Understanding with Sonatrach and Sonelgaz to conduct feasibility studies for a joint project aimed to producing electricity from renewable sources in Algeria, to be exported to and marketed in Europe through a submarine sealine between Algeria and Italy.
Development activities concerned: (i) production optimization programs by means of the drilling of seven wells in the Berkine North concession and one well in the Berkine South concession; (ii) completion of the ROD Debottlenecking project with an increase in the gas treatment capacity of the existing plant; and (iii) the construction of a 10 MW photovoltaic plant in the BRN field in the block 403, doubling the existing plant capacity. Programs are under evaluation for the construction of a 12 MW photovoltaic plant in the MLE field in the block 405b.
Egypt . During the year production optimization program in the Sinai, Western Desert and Mediterranean Sea concessions progressed at a good pace. In particular, Zohr production was aligned with expectation sustained also by two development projects: (i) a compression project through operational synergy with the nearby El Gamil plant; and (ii) a project to increase onshore water treatment plant.
As of December 31, 2024, Eni’s proved reserves booked at the Zohr field amounted to 429 mmBOE.
The rights of Eni to produce at the Zohr Development Lease will expire in 2037.
In addition, in the Western Desert concession, development activities included: (i) the Meleiha Phase 2 project ongoing with the completion of transport facility to increase the existing gas operational flexibility; and (ii) the completion of the flaring down program at the Meleiha oil treatment plant allowing to achieve zero routing flaring.
Eni holds interest in the Damietta liquefaction plant with a capacity of 5.2 mmtonnes/y of LNG associated to approximately 283 BCF/y of feed gas.
Libya . In 2024, Libya represented approximately 11% of the Group’s total production. In 2024, a relatively stabler sociopolitical environment than in previous years, allowed continuity to production operations and to develop projects sanctioned in 2023. Despite those developments, going forward, management continues to monitor Libya's geopolitical situation which is recognized as a source of risk and uncertainty to Eni's operations in the Country and related Group’s financial results. For further information on this matter, see “Item 3 – Risk factors – Political considerations”.
The rights of Eni to produce at its assets in Libya will expire in 2038 for Contract Areas C, in 2042 for Contract Area E, in 2043 for Contract Areas A, B and D-producing fields, in 2059 for Area D-new developments (A&E Structures).
Development activities progressed in all ongoing projects in the Country. In particular: (i) in the A&E Structure project located in Area D off the Libyan coast, development activities progressed aiming at gas production start-up. Progress for the year included the award of main contracts for the development of the A structure; (ii) in the BGUP project to reduce CO 2 emissions and to valorize associated gas of the Bouri field, the construction activities are ongoing and submarine surveys were finalized; (iii) in the Sabratha Compression project to support current production of the Bahr Essalam field, construction activities of unit compression and the preparatory activities for the installation phase progressed.
Tunisia . Main Development activities concerned: (i) a production optimization program; and (ii) the completion activities of some wells with production start-up at Maamoura concession and at the Iklil field in the Adam concession.
Sub-Saharan Africa
Eni’s operations in Sub-Saharan Africa are conducted mainly in Congo, Côte d'Ivoire, Ghana, Mozambique and through Azule Energy in Angola. In 2024, Sub-Saharan Africa accounted for 17% of Eni’s total worldwide production of oil and natural gas.
Angola . In 2024, Azule finalized: (i) the farm-in agreement with Rhino Resources to purchase a 42.5% interest of the offshore Block 2914A in Namibia. The agreement included the option for the operatorship of the block; and (ii) the disposal of a12% stake in the Block 3/05 and a 16% stake in the Block 3/05A, located in the Lower Congo Basin.
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The development activities are focused on: (i) the development project of the Quiluma and Maboqueiro fields within the New Gas Consortium. The project is the first non-associated gas development in the country and consists of the installation of two offshore production platforms, an onshore treatment plant, and the connection facilities to A-LNG liquefaction plant. The start-up is expected at the end of 2025, with an estimated production plateau of approximately 330 mmCF/d; (ii) the Agogo Integrated West Hub project in the western area of the Block 15/06. The main contracts are under execution, and the production startup is expected in 2025 with an estimated production peak of 170 KBOE/d; (iii) the progress of the development optimization studies of PAJ project in the Block 31; (iv) the start-up of infilling activities in the Block 18.
The exploration activities brought positive results with the Likembe 1X oil well in the Block 15, the Dalia-6 oil well in the Block 17 and the PKBB oil well in the Block 14 which is already in production.
Congo . In 2024, Eni finalized with Perenco the divestment of its participating interest in several production licenses in the country.
In February 2024, the Congo FLNG project commenced its deliveries of LNG to international markets, ensuring the Republic of Congo the status of exporter in the global landscape of this fuel. The gas volumes of the Marine XII Block are monetized both for the country’s energy needs and, the surplus gas quota, for LNG production through Congo FLNG Project. The production start-up was achieved through a modular and phased development approach, also leveraging on the existing assets. The liquefaction gas capacity is planned to achieve approximately a 160 BCF/y plateau. According to the agreements recently signed, all LNG production will be marketed by Eni.
The development activities are focused on: (i) the completion activities of the Nguya FLNG, which will complement the current FLNG Tango of the Congo FLNG project. The new FLNG unit will significantly increase the project’s liquefaction capacity from the current 0.6 MTPA to 3 MTPA once commissioned by the end of 2025; and (ii) programs of sidetracks of existing wells and drilling of new infilling wells in order to maximize Nènè field oil production.
The exploration activities have also positive results in the Marine VI Bis block (Eni’s interest 65%) with the Poalvou Marine 2 gas and condensate and the Mbenga Marine 1 oil and gas discoveries wells.
Côte d'Ivoire. In 2024, Eni was awarded the CI-504, CI-526, CI-706, and CI-708 offshore exploration blocks with an 88% interest, near the Block CI-205 where the Calao discovery is located.
In December 2024, Eni completed the Phase 2 of the Baleine field development program with the addition of two FPSO-FSO units, and the relevant subsea wells with the interconnecting facilities. The Baleine fields is located in the operated offshore CI-101 (Eni’s interest 83%) and CI-802 (Eni’s interest 76.9%) blocks. The Phase 2 development program will increase the block production plateau up to 60 KBBL/d and approximately 70 mmCF/d of associated gas.
The Baleine full field project also includes a Phase 3 development that is aimed to achieve a production capacity equal to 150 KBBL/d and approximately 210 mmCF/d of associated gas.
In 2024, the exploration activities resulted in the Calao discovery in the Block CI-205 (Eni’s interest 90%).
Mozambique . Eni has been present in Mozambique since 2006, following the award of the exploration license of the offshore Area 4 Block.
In 2011 Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by TotalEnergies. In 2012 Eni made another large gas discovery in the Coral prospect, which is entirely in Area 4. During the exploration period, which expired in 2015, six Discovery Areas (DA) were identified. Mozambique Decree Law 02/2014 reports that individual plans of development can be submitted on each DA.
Under the Area 4 EPCC (Exploration and Production Concession Contract), each Plan of Development once approved by the Government of Mozambique entitles the Concessionaires to develop and to produce for a period of 30 years, with an extension option pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law. Following two separate transactions occurred respectively in 2013 and in 2017, Eni divested to CNPC and ExxonMobil indirect interests of 20% and 25% respectively in the discoveries of Area 4, by diluting its participating interest in Mozambique Rovuma Venture SpA, the operator of Area 4. Post transactions, Eni retains a 25% indirect interest in the Area 4 concession.
The other concessionaires of Area 4 are the state-owned oil company ENH, Galp and Kogas, each with a 10% working interest.
In 2017, the concessionaries of Area 4 achieved the Final Investment Decision (FID) to develop the reserves of the Coral discovery, sanctioning the Coral South project.
The Coral South project is currently in production. The Coral Sul Floating Liquefied Natural Gas (FLNG) vessel is the design to treat, liquefy the gas and to store and export the LNG, with a capacity of approximately 3.4 mmtonnes/y of LNG, produced through six subsea wells.
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In 2024, the Company took the final investment decision to develop the Coral North project. The Coral North development plan was submitted for approval to the Country’s government. The Coral North project is part of the development program to bring in production the Area 4 reserves by the delegated operators (Eni and ExxonMobil). This program relies on both offshore development scenarios in analogy with Coral South FLNG project, and onshore options also through synergies with Area 1.
Nigeria. In August 2024, Eni finalized the sale of wholly-owned subsidiary Nigerian Agip Oil Company (NAOC Ltd) to the local company OANDO PLC. NAOC was in charge of the onshore oil&gas exploration and production activities. The transaction is in line with Eni’s strategy of upgrading and rationalizing the upstream portfolio. The 5% participating interest in the SPDC JV (Shell Production Development Company Joint Venture) is not included in the transaction, as it will be retained in Eni’s portfolio. Eni will continue to be present in the Country through investment in deepwater projects and Nigeria LNG.
The main development activity is the Bonga North project in OML 118 where the Final Investment Decision (FID) was sanctioned in 2024. The project will connect of new subsea wells to the existing FPSO of Bonga.
Eni holds also a 10.4% interest in the Nigeria LNG Ltd joint venture, which owns and runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant has a production capacity of 22 mmtonnes/y of LNG associated with approximately 1,270 BCF/y of feed gas. The natural gas supplies to the plant are currently provided under a gas supply agreement from the SPDC JV, TEPNG JV and Oando Energy Resources Nigeria Limited JV (former NAOC JV). In 2024, the Bonny liquefaction plant processed approximately 810 BCF. LNG production is sold under long-term contracts and exported mainly to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG, as well as is sold FOB by means of the fleet owned by third parties.
Kazakhstan
Eni’s operations in Kazakhstan are performed at the Kashagan and the Karachaganak oilfields. In 2024, Kazakhstan accounted for 10% of Eni’s total worldwide production of oil and natural gas.
Kashagan . Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field, that was discovered in the Northern section of the contractual area in the year 2000 in an area extending for 4,600 square kilometers. Management believes this field to contain a large amount of hydrocarbon resources, which are expected to be developed in phases. The NCSPSA expires in 2041.
In addition to Eni, the partners of the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies TotalEnergies, Shell and ExxonMobil, each with a participating interest of 16.81%, CNPC with 8.33%, and Inpex with 7.56%.
In 2024, production at the Kashagan field averaged 65 KBBL/d of liquids and 57 mmCF/d of natural gas net to Eni. The liquid production is stabilized at the Bolashak plant and then marketed. Gas production is partly processed and sold to the national oil company, while the raw gas volumes (approximately 50%) is re-injected in the reservoir.
Development plans of the Kashagan field envisage a phased increase in the production capacity. The first development phase provides for a progressive increase up to 450 KBBL/d. The activities, sanctioned in 2020, include the upgrading of management capacity of associated gas by means of: (i) increasing gas reinjection capacity by adding new equipment, which was completed in 2022; and (ii) installation of a new onshore treatment unit operated by a third party, currently under construction, for the remaining part of associated gas volumes.
Management believes that significant capital expenditure will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long-time horizon, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures.
As of December 31, 2024, Eni’s proved reserves booked for the Kashagan field amounted to 558 mmBOE.
Karachaganak . Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA that expires in 2037. Eni and Shell are cooperators of the venture. Eni’s interest in the Karachaganak project is 29.25%.
In 2024, production of the Karachaganak field averaged 44 KBBL/d of liquids and 153 mmCF/d of natural gas net to Eni. This field is producing liquids from the deeper layers of the reservoir. The gas is delivered (about 45%) to the Russian gas plant of Orenburg; management believes this transaction does not violate the current sanction regime imposed to Russia following the military invasion of Ukraine. The remaining gas volumes are utilized for re-injection in the higher layers of the reservoir and as fuel gas. Almost the entire liquid production is stabilized at the Karachaganak Processing Complex (KPC) and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline, this latter also a new route opened in 2023 leading to Germany.
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In 2024 the additional development phase, sanctioned in 2020, of the Karachaganak field progressed and included: (i) the drilling of three new injection wells and the construction of a new sixth injection line. Activities were completed in 2023; (ii) the installation of a fifth compression gas unit, started up in 2024; and (iii) the installation of a sixth compression unit, last development phase, sanctioned in 2022. Start-up is expected in 2026.
Rest of Asia
Eni’s operations in the Rest of Asia are mainly conducted in Indonesia, Iraq, Turkmenistan and the United Arab Emirates. In 2024, Eni’s operations in the Rest of Asia accounted for approximately 11% of its total worldwide production of oil and natural gas.
Indonesia . During the year, Eni has been awarded by the country’s authorities a twenty-year extension of the Ganal (Eni’s interest 82%) and Rapak (Eni’s interest 82%) development blocks, as well as of the Muara Bakau development and production license.
In August 2024, the Indonesian authorities approved: (i) the Plan of Development (PoD) of the Geng North and Gehem fields. The integrated development of the two fields will create a new production hub, called Northern Hub, in the Kutei Basin. These fields will be put into production by means of subsea wells, flowlines and by building and installing a new FPSO with a treatment capacity of approximately 1 BCF/d gas, approximately 80 KBBL/d of condensates and a storage capacity of 1 mmBBL. Natural gas will be treated by the FPSO and will be carried to onshore facilities linked to the East Kalimantan pipeline network. The production will be delivered to the Bontang LNG plant and exported; a part of gas production will be destined to fulfil domestic needs. The condensates production will be stabilized and stored by the FPSO and then marketed; (ii) the PoD of the Gendalo & Gandang fields. Production start-up will be achieved by means of the linkage to existing facilities of the Jangkrik production field, thus extending the useful life of the vessel.
Other development activities mainly concerned: (i) execution phase of the Merakes East project in the East Sepinggan operated block, in the deepwater of the Eastern Kalimantan. Start-up is expected in 2025; (ii) the Maha project in the West Ganal operated offshore block (Eni’s interest 70%) with start-up expected in 2026.
Iraq . Activities comprised the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field. Main facilities have already been installed. Ongoing development activities include programs to expand water availability to maintain adequate reservoir pressurization in the long term and to increase water treatment and re-injection capacity.
In 2024, a specific project was defined to achieve zero technical flaring by 2027.
The field reserves will be progressively put into production by drilling additional productive wells over the next few years and by means of the collection facilities expansion and the completion of the water reinjection wells.
Turkmenistan . Development activities mainly concerned: (i) drilling of infilling wells; and (ii) the water injection expansion system project to increase hydrocarbons recovery of the Burun field.
United Arab Emirates . Development activities of the year concerned: (i) the development plan of the Waset field was sanctioned. The field is located in the exploration Block 2 (Eni operator with a 70% interest), in the Abu Dhabi offshore; (ii) three development projects were sanctioned in the Lower Zakum and Umm Shaif/Nasr concessions to support the target of production increase; and (iii) execution phase of the Hail & Ghasha development project, sanctioned in 2023, in the Ghasha concession.
Americas . Eni’s operations in Americas are conducted mainly in Mexico, United States and Venezuela. In 2024, Eni’s operations in the Americas area accounted for approximately 8% of its total worldwide production of oil and natural gas.
Mexico . In 2024, production start-up was achieved at the Tecoalli and Amoca WHP2 platforms with the completion of the development and installation activities, concluding the development program of the Area 1 operated license. Ongoing drilling activities of new production wells will be completed in 2025.
Exploration activities yielded positive results with the Saasil-1 and Yopaat-1 discoveries in the Area 10 (Eni’s interest 76%) and Area 9 (Eni’s interest 50%) operated licences, respectively.
United States . In 2024, Eni closed the divestment of: (i) 100% of the Nikaitchuq and Oooguruk assets in Alaska to Hilcorp; and (ii) some offshore assets in the Gulf of Mexico.
Development activities concerned (i) the completion of second development phase at the non-operated Lucius - Hadrian North project (Eni’s interest 14.45%), with production start-up; (ii) the completion of the fourth development phase at the non-operated St. Malo license (Eni’s interest 1.3%), achieving production start-up. In addition, started development activities of water injection project and subsea multiphase pumping system; and (iii) the drilling of an additional production well in the non-operated Europa field, with production start-up in early 2025.
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Venezuela . In 2024, Eni’s production of oil and natural gas averaged 61 KBOE/d and accounted for approximately 4% of Eni’s total production. Eni’s production comes mainly from the Perla gas field. Other petroleum interests held by Eni in the Country comprise the Corocoro field in the Gulf de Paria and the Junín 5 oil field in the Orinoco Oil Belt. These latter interests are immaterial to the Company. The operations in the Country have been negatively affected by a difficult operational environment mainly due to the deteriorated economic and financial outlook of the Country that has been made worse by the U.S. sanctions regime, thus limiting the ability of the Company to collect the revenues from the sale of its equity production at the Perla field. In 2024, thanks to a temporary suspension of sanctions granted by the U.S and an additional waiver obtained by the US Department of State, it was possible to offset part of the long-standing receivables accrued with PDVSA-owned crude oil cargoes. However, there is a great deal of uncertainty about the evolution of the US sanctions against Venezuela and Eni’s ability to recover its outstanding receivables.
For further information on this matter, see “Item 3 — Risk factors – Political considerations”.
Capital expenditures
See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”.
Disclosure pursuant to Section 13(r) of the Exchange Act
The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. In 2017, Eni recovered certain overdue trade receivables owed by Iranian state-owned companies relating to the cost recovery of past projects in accordance with agreements signed in 2016, while the amounts of cost recovery not covered by such agreements were written down in Eni accounts in the following years. Eni is seeking to recover approximately $30 million of such remaining receivables in compliance with the applicable regulation and once certain administrative compliance procedures in the country are completed, subsequently allowing the de-registration of the local branch.
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Global Gas & LNG Portfolio and Power
Competitive trends in the industries where the Company operates
In the Global Gas & LNG Portfolio business, Eni is facing strong competition in the European wholesale markets to sell gas to industrial customers, the thermoelectric sector and retail companies from other gas wholesalers, upstream companies, traders and other players. The results of Eni’s wholesale gas business are affected by global and regional dynamics of gas demand and supplies, as well as by the constraints of its portfolio of long-term, take-or-pay supply, whereby the Company is obligated to offtake minimum annual volumes of gas or in case of failure to pay the corresponding purchase price (see below). Due to the competitive nature of the business, sales margins tend to be small. We believe wholesale margins of gas will be negatively affected by competitive pressures in connection with an oversupplied global natural gas market and rising LNG flows, a structural decline in European consumption due to plant closures or relocations, energy saving measures introduced by the EU during the gas crisis of 2022 and by the expected growth of renewable sources of energy that will replace natural gas in supplying electricity to European markets in the medium term.
The results of the LNG business are mainly influenced by the global balance between demand and supplies, considering the higher level of flexibility of LNG with respect to gas delivered via pipeline.
Eni also engages in the business of producing gas-fired electricity that is largely sold in the wholesale market and in providing the service of peak-load capacity to the Italian grid. The business is exposed to competition from large players and other electricity producers, like renewables.
Global Gas & LNG Portfolio engages in the wholesale activity of supplying and selling natural gas via pipeline and LNG, and the international transport activity. It also comprises gas trading activities targeting to both hedge and stabilize the Group commercial margins and optimize the gas asset portfolio. In 2024, Eni ’ s w o r l d wide s a les of n a tu r a l gas amounted to 50.88 BCM. S a les in It a l y amounted to 24.40 BCM, w hile s a les in Eu r opean ma r k ets w e r e 23.40 BCM th a t included 1.26 BCM of gas sold to certain importers to It a l y .
The b usiness r esults of ope r a tions in 2024 and its st r a tegy a r e described in “Item 5 – G r oup r esults of ope r a tions” and “Item 5 – Man a gement ’ s e xpect a tions of ope r a tion s .”
Supply of natu r al g as
The supply contracts which were intended to support Eni’s sales plan in Italy and in other European markets, provide take-or-pay clauses whereby the Company has an obligation to lift minimum, preset volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to a minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations which arise from contracts with transmission system operators or pipeline owners, which the Company has entered into to secure long-term transport capacity.
In 2024, Eni subsidiaries’ total supply of natural gas was 51.05 BCM, increased by 1.00 BCM, or 2% from 2023. Gas volumes supplied outside Italy (43.39 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 85% of total supplies, decreased by 0.95 BCM, or 2.1% compared to the previous year, due to lower volumes purchased in Algeria (down by 1.36 BCM), in Libya (down by 1.11 BCM) and in the UK (down by 0.19 BCM), partially offset by higher purchases in Norway (up by 0.39 BCM), in Indonesia (up by 0.30 BCM) and in the Netherlands (up by 0.24 BCM). Supplies in Italy (7.66 BCM) reported an increase of 34.2% from the full year 2023.
In 2024, main gas volumes from equity production derived from: (i) certain Eni fields located in the British and Norwegian sections of the North Sea (1.7 BCM); (ii) Italian gas fields (1.7 BCM); (iii) Indonesia (1.4 BCM); (iv) Libyan fields (0.4 BCM); (v) fields located in Congo (0.3 BCM). Supplied gas volumes from equity production were about 5.5 BCM representing around 11% of total volumes available for sale.
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The t a b le b e l o w sets f orth Eni ’ s pu r chases of n a tu r a l gas b y sou r ce f or the periods indic a ted.
|
Natural gas supply |
2024 |
|
2023 |
|
2022 |
|
|
(BCM) |
||||
|
Italy |
7.66 |
|
5.71 |
|
3.40 |
|
Outside Italy |
43.39 |
|
44.34 |
|
57.19 |
|
Algeria (including LNG) |
10.70 |
|
12.06 |
|
11.86 |
|
Norway |
6.88 |
|
6.49 |
|
6.75 |
|
Russia |
6.19 |
|
6.16 |
|
17.20 |
|
Qatar (LNG) |
2.91 |
|
2.91 |
|
2.56 |
|
Indonesia (LNG) |
1.86 |
|
1.56 |
|
1.36 |
|
the Netherlands |
1.86 |
|
1.62 |
|
1.39 |
|
Libya |
1.41 |
|
2.52 |
|
2.62 |
|
the United Kingdom |
1.23 |
|
1.42 |
|
1.91 |
|
Congo (LNG) |
0.45 |
|
|
|
|
|
Other supplies of natural gas |
6.80 |
|
5.89 |
|
8.11 |
|
Other supplies of LNG |
3.10 |
|
3.71 |
|
3.43 |
|
Total supplies of subsidiaries |
51.05 |
|
50.05 |
|
60.59 |
|
Withdrawals from (input to) storage |
(0.09) |
|
0.54 |
|
0.00 |
|
Network losses, measurement differences and other changes |
(0.08) |
|
(0.08) |
|
(0.07) |
|
Volumes available for sale of Eni’s subsidiaries |
50.88 |
|
50.51 |
|
60.52 |
|
Total volumes available for sale |
50.88 |
|
50.51 |
|
60.52 |
Sales of natural g as
Eni is s e lling gas to w holes a le ma r k ets in It a l y and in a n umber of Eu r opean countrie s . The w holes a le ma r k et includes s a les to la r ge accounts (industri a ls and the r mo e lectric utilities) and on Eu r opean spot ma r k et s .
In 2024, natural gas sales amounted to 50.88 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities), representing an increase of 0.37 BCM, or 0.7% from the previous year, mainly due to higher sales outside Europe. Sales in Italy (24.40 BCM) were in line compared to 2023, mainly due to higher volumes marketed in the wholesale and industrial sectors offset by lower sales to hub. Sales in the European markets amounted to 22.14 BCM, increased by 2.7% or 0.59 BCM from 2023.
S a les to long-te r m b u y ers w e r e 1.26 BCM, down by 45.0 % BCM compa r ed to the p re vious y ear due to the lower a v ail a bility of Li by an output.
Sales in the Extra European markets (3.08 BCM) increased by 0.81 BCM or 35.7% due to higher LNG volumes sold in the Asian markets.
The tables below set forth Eni’s sales of natural gas by principal market for the periods indicated.
|
Natural gas sales by geographical area |
|
2024 |
|
2023 |
|
2022 |
|
|
|
(BCM) |
||||
|
Worldwide gas sales |
|
50.88 |
|
50.51 |
|
60.52 |
|
Italy (including own consumption) |
|
24.40 |
|
24.40 |
|
30.67 |
|
Rest of Europe |
|
23.40 |
|
23.84 |
|
27.41 |
|
Outside Europe |
|
3.08 |
|
2.27 |
|
2.44 |
|
|
|
|
|
|
|
|
|
Natural gas sales by market |
|
2024 |
|
2023 |
|
2022 |
|
|
|
|
|
(BCM) |
|
|
|
ITALY |
|
24.40 |
|
24.40 |
|
30.67 |
|
Wholesalers |
|
11.01 |
|
10.71 |
|
12.22 |
|
Italian gas exchange and spot markets |
|
5.94 |
|
6.28 |
|
9.31 |
|
Industries |
|
1.56 |
|
1.50 |
|
2.89 |
|
Power generation |
|
0.51 |
|
0.52 |
|
0.83 |
|
Own consumption |
|
5.38 |
|
5.39 |
|
5.42 |
|
INTERNATIONAL SALES |
|
26.48 |
|
26.11 |
|
29.85 |
|
Rest of Europe |
|
23.40 |
|
23.84 |
|
27.41 |
|
Importers in Italy |
|
1.26 |
|
2.29 |
|
2.43 |
|
European markets |
|
22.14 |
|
21.55 |
|
24.98 |
|
Iberian Peninsula |
|
3.18 |
|
2.75 |
|
3.93 |
|
Germany/Austria |
|
4.35 |
|
3.35 |
|
3.58 |
|
Benelux |
|
3.63 |
|
3.75 |
|
4.24 |
|
United Kingdom/Northern Europe |
|
1.23 |
|
1.42 |
|
1.92 |
|
Turkey |
|
6.10 |
|
6.90 |
|
7.62 |
|
France |
|
3.58 |
|
3.31 |
|
3.62 |
|
Other |
|
0.07 |
|
0.07 |
|
0.07 |
|
Extra European markets |
|
3.08 |
|
2.27 |
|
2.44 |
|
WORLDWIDE GAS SALES |
|
50.88 |
|
50.51 |
|
60.52 |
59
The LNG b usiness
Eni LNG b usiness can count cur r ent l y on a port f olio of cont r acted long-te r m supplies main l y f r om: Q a ta r , Nigeria and Indonesia. In the plan period, Eni intends to d eve lop its LNG b usiness l ev e r a ging on the integ r a tion with the E&P segment and the v a loriz a tion of the equity ga s . Fin a l ma r k ets of th a t gas include Eu r op e and Asia. The b usiness ’ s p r o f it a bility will be a lso dr iv en b y enhancing the comme r ci a l p r esence in p r emium ma r k ets and conti n uing integ r a tion with t r ading act i vitie s .
|
LNG sales |
|
2024 |
|
2023 |
|
2022 |
|
|
|
(BCM) |
||||
|
Europe |
|
6.7 |
|
7.3 |
|
7.0 |
|
Extra European markets |
|
3.1 |
|
2.3 |
|
2.4 |
|
|
|
9.8 |
|
9.6 |
|
9.4 |
Inte r national t r ansport
Eni has t r ansport rights on a la r ge Eu r opean net w o r k of integ r a ted inf r astructu r es f or t r ansporting n a tu r a l ga s , w hich links k ey consumption ma r k ets with the main p r oducing a r eas (Russia, Algeria, the North Sea, including the Netherlands and Norway, and Li by a). Eni has cont r acted the t r ansport c a pacity under ship-o r -p a y cont r act s , w hich a r e similar to t a k e-o r -p a y cont r act s .
The main assets of Eni ’ s t r ansport act i vities a r e p ro vided in the t a b le b e l o w .
|
International Transport infrastructure Route |
|
|
|
|
|
|
|
|
|
|
|
Lines |
|
Total length |
|
Diameter |
|
Transport capacity |
|
Compression stations |
|
|
(units) |
|
(km) |
|
(inch) |
|
(BCM/y) |
|
(No.) |
|
TTPC (Oued Saf Saf-Cap Bon) |
2 lines of km 370 |
|
740 |
|
48 |
|
34.3 |
|
5 |
|
TMPC (Cap Bon-Mazara del Vallo) |
5 lines of 155 |
|
775 |
|
20/26 |
|
33.5 |
|
|
|
GreenStream (Mellitah-Gela) |
1 line of km 516 |
|
516 |
|
32 |
|
11.5 |
|
1 |
|
Blue Stream (Beregovaya-Samsun) |
2 lines of km 387 |
|
774 |
|
24 |
|
16.0 |
|
1 |
International t r ansport activities
The TTPC pip e lin e , 740-kilometer long, is made up of t w o lines th a t a r e each 370-kilometers long with a t r ansport c a pacity of 34.3 BCM/y and f iv e comp r ession st a tion s . This pip e line t r ansports n a tu r a l gas f r om Algeria ac r oss T unisia f r om Oued Saf Saf a t the Algerian bo r der to C a p Bon on the Mediter r anean coast w he r e it links with the TMPC pip e lin e .
The TMPC pip e line f or the import of Algerian gas is 775-kilometer long and consists of f iv e lines th a t a r e each 155-kilometers long with a t r ansport c a pacity of 33.5 BCM/ y . It c r osses the Sici l y Chann e l f r om C a p Bon to Maza r a d e l V a llo in Sici l y , the point of entry into the It a lian n a tu r a l gas t r ansport system.
The G r eenSt r eam pip e lin e , joint l y- o wned with the Li by an N a tion a l Oil C orporation , started ope r a tions in October 2004 f or the import of Li by an gas p r oduced a t the Eni ope r a ted f i e lds of B a hr Ess a lam and W afa. It is 516-kilometers long with a t r ansport c a pacity of 11.5 BCM/y c r ossing the Mediter r anean Sea f r om M e llit a h on the Li by an coast to G e la in Sici l y , the point of entry into the It a lian n a tu r a l gas t r ansport system.
The Blue St r eam under w a ter pip e line ( w a ter depth g r e a ter than 2,150 meters) links the R ussian coast to the T u r kish coast of the Black Sea. This pip e line is 774-kilometer long on t w o lines and has t r ansport c a pacity of 16 BCM/ y . It is part of a joint v entu r e to s e ll gas p r oduced in R ussia on the T u r kish ma r k et.
See "Risks in connection with Russia’s military aggression of Ukraine and the Middle East conflict in the Gaza strip" in the Risk factors section for further information.
60
Power
As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market.
Power sales in the open market
In 2024, power sales in the open market were 26.55 TWh, representing a decrease of 2.7% compared to 2023 due to lower volumes marketed to the free market, partly offset by higher volumes marketed to power exchange and to the third parties (up by 1 TWh).
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(TWh) |
||||
|
Power generation sold |
|
20.16 |
|
20.66 |
|
21.37 |
|
Trading of electricity (a) |
|
6.39 |
|
6.64 |
|
9.49 |
|
Power availability |
|
26.55 |
|
27.30 |
|
30.86 |
|
|
|
|
|
|
|
|
|
Power sales in the open market (b) |
|
26.55 |
|
27.30 |
|
30.86 |
|
of which: sales to third parties |
|
18.86 |
|
17.89 |
|
20.37 |
(a) Include positive and negative imbalances (differences between power introduced in the grid and the one planned).
|
(b) Data include intercompany sales. |
Power generation
Enipower’s power generation sites are located in Brindisi, Ferrera Erbognone, Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2024, installed operational capacity of Enipower’s power plants was approximately 5 GW. In 2024, thermoelectric power generation was 20.16 TWh, down by 0.50 TWh compared to 2023. Electricity trading (6.39 TWh) reported a decrease of 0.25 TWh from 2023.
|
Site |
Total installed capacity in 2024 (a) |
|
Technology |
|
Fuel |
|
|
(MW) |
|
|
|
|
|
Brindisi |
1,268 |
|
CCGT |
|
gas |
|
Ferrera Erbognone |
1,052 |
|
CCGT |
|
gas/syngas |
|
Mantova |
851 |
|
CCGT |
|
gas |
|
Ravenna |
907 |
|
CCGT/Peaker |
|
gas |
|
Ferrara |
785 |
|
CCGT |
|
gas |
|
Bolgiano |
64 |
|
Power station |
|
gas |
|
Photovoltaic plants (b) |
0.2 |
|
Photovoltaic |
|
Photovoltaic |
|
|
4,926 |
|
|
|
|
|
(a) Data refer to 100% of the installed capacity. |
|
|
|
|
|
|
(b) Managed by EniPower Mantova |
|
|
|
|
|
|
Power generation |
|
|
2024 |
|
2023 |
|
2022 |
|
Purchases |
|
|
|
|
|
|
|
|
Natural gas |
(mmCM) |
|
4,078 |
|
4,144 |
|
4,218 |
|
Other fuels |
(ktoe) |
|
139 |
|
156 |
|
175 |
|
- of which steam cracking |
|
|
71 |
|
85 |
|
86 |
|
Production |
|
|
|
|
|
|
|
|
Electricity |
(TWh) |
|
20.16 |
|
20.66 |
|
21.37 |
|
Steam |
(ktonnes) |
|
6,761 |
|
6,981 |
|
6,900 |
|
Installed generation capacity (*) |
(GW) |
|
4.9 |
|
4.9 |
|
4.9 |
|
|
|
|
|
|
|
|
|
|
(*) Data refer to 100% of the installed capacity. |
|
|
|
|
|
|
|
Capital e xpenditu r es
See “Item 5 – Liquidity and c a pit a l r esou r ces – C a pit a l e xpenditu r es b y segment”.
61
Competitive trends in the industries where the Company operates
Enilive is facing strong competition in the marketing of fuels to retail customers due to low product differentiation and customers’ sensitivity to prices at pump. We are making investments to upgrade our service stations and to expand our offer to include biofuels and other energy vectors. Those investments are intended to retain our customers and to improve profitability by leveraging on cross-selling opportunities and the growing customers’ needs of having more products and services bundled with the refuelling.
However, customers’ preferences may change very rapidly, and we are exposed to risks of losing customers and sales volumes in case our competitors adopt more aggressive pricing policies or more effective marketing strategies.
Plenitude engages in the supply of gas and electricity to customers in the retail markets mainly in Italy, France, Spain, and other countries in Europe. Those markets have been almost fully liberalized. Customers include households, large residential accounts (hospitals, schools, public administration buildings, offices) and small and medium-sized businesses. The retail market is characterized by strong competition among selling companies which mainly compete in terms of pricing and the ability to bundle valuable services with the supply of the energy commodity. Due to the commoditized nature of the business, the ability of residential customers to switch smoothly from one supplier to another and a low level of customer loyalty, management expects competition to significantly affect the business going forward.
Enilive
Enilive is dedicated to the supply of biofeedstock, processing and production of biofuels in Italy (Venice and Gela biorefineries) and in the United States, with a 50% interest in the Chalmette biorefinery and biomethane. In addition, Enilive is engaged in the offer of smart mobility solutions, including Enjoy car sharing, and the marketing and distribution of a wide range of products, including biogenic fuels such as HVO (Hydrotreated Vegetable Oil), bio-LPG and biomethane, hydrogen and electricity, as well as other oil products such as fuels, bitumen, and lubricants. The business also deals with wholesale operators, consisting mainly of resellers, industrial companies, service companies, public bodies and municipal companies, condominiums, operators in the agricultural and fishing sectors.
The b usiness r esults of ope r a tions in 2024 and its st r a tegy a r e described in “Item 5 – G r oup r esults of ope r a tions” and “Item 5 – Man a gement ’ s e xpect a tions of ope r a tions”.
|
|
Ownership share |
|
Capacity (2024) |
|
Throughput (2024) |
|
|
(%) |
|
(mmtonnes/y) |
|
(mmtonnes/y) |
|
Wholly-owned biorefineries |
|
|
|
|
|
|
Venice |
100 |
|
0.4 |
|
0.2 |
|
Gela |
100 |
|
0.7 |
|
0.5 |
|
|
|
|
|
|
|
|
Partially owned biorefineries |
|
|
|
|
|
|
Chalmette |
50 |
|
0.55 |
|
0.5 |
|
Total biorefineries |
|
|
1.65 |
|
1.1 |
Enilive fully owns two biorefineries in Italy, specifically in Venice and Gela.
In Venice biorefinery biofuels production started in June 2014 from the conversion of the existing oil-based refinery. The biorefinery has a processing capacity of 0.4 mmtonnes/y, leveraging the Ecofining™ proprietary technology to transform biofeedstock (both vegetable oil and waste and residues) in hydrotreated bio-fuels. Capacity is expected to be increased to 0.6 million tonnes/year with biojet production (SAF) started in 2025 .
Since 2020 Gela biorefinery has been using the Ecofining TM conversion technology, developed by Eni, capable of converting vegetable oils and feedstock consisting of waste and residues, such as used cooking oils and animal fats, into HVO. The specifics of the plant, with a capacity of 0.7 million tons/year, together with a strong supply strategy, allow HVO to be produced in compliance with recent regulatory constraints in terms of reducing GHG emissions throughout the product life cycle. In March 2021, the Biomass Treatment Unit (BTU) was launched to expand the range of raw materials to be treated by the plant, allowing the processing of waste and residues such as animal fats and used cooking oil, replacing palm oil, which has not been used since the end of 2022. In January 2025, the biorefinery started the production of Sustainable Aviation Fuel (SAF) with a capacity of 400,000 tonnes/year.
In June 2023, Enilive and PBF Energy Inc. (PBF) finalized the 50% interest joint venture in St. Bernard Renewables LLC (SBR), an operational biorefinery co-located with PBF's Chalmette Refinery in Louisiana (USA). The biorefinery started with a processing capacity of approximately 1.1 million tonnes/year of feedstock (waste and residues and vegetable oils) with full pre-treatment capabilities. It mainly produces HVO Diesel using the Ecofining™ process developed by Eni in collaboration with Honeywell UOP.
In December 2024, Enilive in partnership with Petronas and Euglena, established the company “Pengerang Biorefinery Sdn. Bhd”, following the FID for the construction of a biorefinery in Malaysia and the clearance from the relevant antitrust authorities. The contracts for the biorefinery construction have been awarded. In addition, Enilive, together with LG Chem, established the company “LG-Eni BioRefining Co. Ltd.”., after the FID for the construction of a biorefinery in South Korea and the clearance from the relevant antitrust authorities, The contract for the biorefinery construction has been awarded.
In 2024, biorefinery throughputs has been 1.12 mmtonnes, an increase of 0.25 mmtonnes compared to 2023 (up by 29%), thanks to the contribution of volumes processed by Chalmette bio refinery; these improvements more than offset lower Venice and Gela biorefineries throughput.
Biorefineries
|
|
|
2024 |
|
2023 |
|
2022 |
|
Bio throughputs |
(ktonnes) |
1,115 |
|
866 |
|
543 |
|
Sold production of biofuels |
|
982 |
|
635 |
|
428 |
|
Average biorefineries utilization rate |
(%) |
74 |
|
72 |
|
58 |
62
Ma r k eting
Enilive markets a wide range of refined petroleum products, primarily in Italy, through a widespread operated network of service stations, franchises, and other distribution systems.
The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.
|
Oil products sales in Italy and outside Italy |
2024 |
|
2023 |
|
2022 |
|
|
(mmtonnes) |
||||
|
Italy |
|
|
|
|
|
|
Retail |
5.40 |
|
5.32 |
|
5.38 |
|
Wholesale |
9.53 |
|
9.39 |
|
7.85 |
|
Petrochemicals |
0.37 |
|
0.44 |
|
0.39 |
|
Other sales |
2.27 |
|
2.71 |
|
2.53 |
|
Total sales in Italy |
17.57 |
|
18.01 |
|
17.83 |
|
Outside Italy |
|
|
|
|
|
|
Retail |
2.30 |
|
2.20 |
|
2.12 |
|
Wholesale |
2.86 |
|
2.73 |
|
3.11 |
|
Total sales outside Italy |
5.16 |
|
4.93 |
|
5.23 |
|
|
|
|
|
|
|
|
TOTAL SALES |
22.73 |
|
22.94 |
|
23.06 |
In 2024, sales of refined products (22.73 mmtonnes) were substantially unchanged from 2023 as result of lower volumes marketed in Italy partly balanced by higher sales abroad.
R etail sales in Italy
In 2024, retail sales in Italy were 5.40 mmtonnes, up by 0.08 mmtonnes or 1.5% vs. 2023 .
Average gasoline and gasoil throughputs (1,457 kliters) were down by 22 kliters vs. 2023 (1,479 kliters). Eni’s 2024 retail market share was 21.2%, lower than 2023 (21.4%).
As of December 31, 2024, Eni’s retail network in Italy consisted of 3,925 service stations, lower by 51 units from December 31, 2023 (3,976 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (-56 units) partly offset by the positive balance of the Company-owned stations (+5 units).
63
R etail sales in the R est of Eu r ope
Retail sales in the Rest of Europe were 2.30 mmtonnes, an increase of 4.5% from 2023 as a result of higher volumes sold mainly in Spain, following the Atenoil acquisition (21 petrol stations), in Germany and France, which offset the decrease in Austria and Switzerland.
At December 31, 2024, Eni’s retail network in the Rest of Europe consisted of 1,329 units, increasing by 38 unit from December 31, 2023, mainly thanks to the openings in Spain, Germany and France balanced by the reductions in Austria and Switzerland. Average throughput (2,179 kliters) increased by 14 kliters compared to 2023 (2,166 kliters).
Other businesses
Wholesale and other sales
Enilive is st r ong l y p r esent in the w holes a le ma r k et in It a l y , including s a les of dies e l fu e l f or automot iv e use and f or he a ting purpose s , f or a gricultu r a l ve hicles and f or v ess e ls as well as s a les of fu e l oil. Major customers a r e other oil companies, r es e ller s , a gricultu r a l user s , ma n ufacturing industrie s , pu b lic utilities and t r ansport s , as we ll as f in a l users (t r ansporter s , condominium s , fa r mer s , f isher s , etc.). Enilive p ro vides its customers with its e xpertise in the a r ea of fu e ls with a wide r ange of p r oducts th a t c o v er a ll ma r k et r equi r ement s . Customer ca r e and p r oduct distri b ution a r e supported b y a widesp r ead comme r ci a l and l o gistic a l o r ganiz a tion p r esence th r oughout It a l y and is articul a ted in loc a l ma r k eting o f f ices and a net w o r k of a gents and concessionai r e s .
In 2024 , s a les v olumes on w holes a le ma r k ets in It a l y (9.53 mmtonnes) increased b y 1.5 % f r om 2023, mainly due to higher sales of jet fuel which offset the reduction registered in the other segments.
W holes a le s a les outside Italy w e r e 2.86 mmtonne s , up by 4.8 % f r om 2023 mainly in Germany and Spain, balanced by the reduction reported in Austria, Switzerland and France.
Supplies of feedstock to the petrochemical industry (0.37 mmtonnes) increased by 15.9%. Other sales in Italy and outside Italy (2.27 mmtonnes) decreased by 0.44 mmtonnes or down by 16.2%, mainly due to lower volumes sold to other oil companies.
LPG
The marketing of LPG in Italy is supported by the refining production and a logistic network made up of two bottling plants, one owned storage site and coastal storage sites located in Livorno, Naples and Ravenna.
LPG is used as heating and automotive fuel.
Lubricants
Enilive operates two owned blending and filling plants, in Spain, Germany and a co-owned one in the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of the art know how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, grease, industrial machinery and metal processing). In Italy, Enilive is leader in the sale of lubricant bases and additives, manufactured respectively at Eni’s refinery in Livorno and in Robassomero facility.
Enilive distributes its products in more than 80 countries through subsidiaries, licensing agreements and distributors.
64
Plenitude
Overall Eni, through Plenitude, supplies over 10 million retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 8 million.
Gas demand
Eni operates in a liberalized market where energy customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and offers.
Gas and power sales to retail and business customers
|
Gas sales by market |
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
|
(bcm) |
||||
|
ITALY |
|
|
3.83 |
|
4.11 |
|
4.65 |
|
Retail |
|
|
2.71 |
|
2.91 |
|
3.34 |
|
Business |
|
|
1.12 |
|
1.20 |
|
1.31 |
|
INTERNATIONAL SALES |
|
|
1.68 |
|
1.95 |
|
2.19 |
|
European markets: |
|
|
|
|
|
|
|
|
France |
|
|
1.29 |
|
1.54 |
|
1.69 |
|
Greece |
|
|
0.26 |
|
0.26 |
|
0.33 |
|
Other |
|
|
0.13 |
|
0.15 |
|
0.17 |
|
RETAIL AND BUSINESS GAS SALES |
|
|
5.51 |
|
6.06 |
|
6.84 |
In 2024, retail and business gas sales, in Italy and in European markets, amounted to 5.51 BCM, down by 0.55 BCM or 9.1% from 2023. Sales in Italy amounted to 3.83 BCM, a decrease of 6.8% (down by 0.28 BCM) compared to 2023, as a result of lower sales to the residential segment.
Sales in the European market were 1.68 BCM, decreasing by 13.8% (down by 0.27 BCM) compared to 2023. Lower volumes were marketed mainly in France.
In Europe, Plenitude operates through the subsidiaries Eni Gas&Power France SA (99.999% Plenitude interest) in France, Gas Supply Company of Thessaloniki (100% Plenitude interest) in Greece, Adriaplin doo (51% Plenitude interest) in Slovenia and Eni Plenitude Iberia SLU (100% Plenitude interest) in Spain and Portugal.
In 2024, retail and business power sales to end customers, managed by Plenitude and its subsidiaries companies in France, Greece and Iberian Peninsula, amounted to 18.28 TWh, an increase of 1.7% from the full year 2023, thanks to the increase in the power customers portfolio in Italy and abroad.
65
Renewables
Eni is engaged in the renewable energy business (solar and wind) aiming at developing, constructing and managing renewable energy producing plants.
Eni’s targets in this business will be reached by leveraging on an organic development of a diversified and balanced portfolio of assets, integrated with selective asset acquisitions, as well as projects and national and international strategic partnership.
|
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
|
(TWh) |
||||
|
Energy production sold from renewable sources |
|
|
4.67 |
|
3.98 |
|
2.55 |
|
of which: photovoltaic |
|
|
2.55 |
|
1.74 |
|
1.13 |
|
wind |
|
|
2.12 |
|
2.24 |
|
1.42 |
|
of which: Italy |
|
|
1.45 |
|
1.53 |
|
0.82 |
|
outside Italy |
|
|
3.22 |
|
2.45 |
|
1.73 |
Energy production from renewable sources amounted to 4.67 TWh in 2024 (of which 2.55 TWh photovoltaic and 2.12 TWh wind) up by 0.69 TWh, or 17.3% compared to 2023.
The increase in production compared to the previous year benefitted from the entry in exercise of new capacity, mainly for the contribution of acquisition of assets in operation as well as for the organic projects start-ups.
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(gigawatt) |
||||
|
Total installed capacity from renewables at period end |
|
4.1 |
|
3.0 |
|
2.2 |
|
of which: - photovoltaic (including installed storage capacity) |
|
71% |
|
64% |
|
54% |
|
- wind |
|
29% |
|
36% |
|
46% |
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(gigawatt) |
||||
|
Italy |
|
1.0 |
|
1.0 |
|
0.8 |
|
Outside Italy |
|
3.1 |
|
2.0 |
|
1.4 |
|
United States |
|
1.7 |
|
1.3 |
|
0.8 |
|
Spain |
|
0.8 |
|
0.4 |
|
0.3 |
|
Other (Australia, France, Germany, Kazakhstan, UK) |
|
0.6 |
|
0.3 |
|
0.3 |
|
TOTAL INSTALLED CAPACITY (INCLUDING INSTALLED STORAGE CAPACITY) * |
|
4.1 |
|
3.0 |
|
2.2 |
* Installed storage capacity amounted to 221 MW, 21 MW and 7 MW in the 2024, 2023 and 2022, respectively.
At the end of 2024, the total installed capacity for the generation of energy from renewable sources amounted to 4.1 GW (100% Plenitude and including the storage power), up by 1.1 GW vs 2023 mainly due to the organic development of projects mainly in the United States, Spain, in the UK and Italy and the acquisitions in Spain and Germany, as well as the acquisition of 2 photovoltaic plants in the United States with a total capacity of 0.2 GW, signed at the end of 2024.
E-mobility
On the back of a mobility market experiencing a constant increase in the number of electric vehicles in circulation in Italy and in Europe, Plenitude, disposes one of the largest and most widespread networks of public charging infrastructure for electric vehicles.
As of December 31, 2024, there are 21,274 charging points distributed throughout Europe, in particular in Italy.
66
Refining and Chemicals
Competitive trends in the industries where the Company operates
Eni’s oil refining business is exposed to structural headwinds of the industry due to muted trends in the European demand for fossil fuels, with expectations of long-term decline due to market penetration of electric vehicles and growing supplies of biofuels, refining overcapacity with new additions expected to come online in the next years or to become operational shortly and continued competitive pressure from players in the Middle East, the United States and Far East Asia. Those competitors can leverage on larger plant scale and cost economies, availability of cheaper feedstock and lower energy expenses. Eni’s refining business is incurring expenses for the purchase of allowances in connection with the emission of CO 2 in its operations to comply with the requirements of the European ETS, which reduce the competitiveness of Eni’s fuels with respect to other jurisdictions that do not yet impose those charges to refiners.
The refining business is engaged in the processing of crude oil, production, storage and handling of petroleum products in Italy, Germany and the Middle East (through a 20% interest in ADNOC Refining).
The b usiness r esults depend he a vi l y on t r ends in r e f ining ma r gin s , i. e . the sp r ead bet w een the cost of the oil feedstock and the price of the r e f ined p r oducts obtained f r om the crude p r ocessing.
Eni’s chemical business is exposed to strong competition from well-established international players and state-owned petrochemical companies, considering the commoditized nature of most of the market segments where Eni’s chemicals business operates (such as the production of basic petrochemical products), which demand is a function of macroeconomic growth. Many of these competitors based in the Far East and the Middle East have been able to benefit from cost economies due to larger plant scale, wide geographic moat, availability of cheap feedstock, lower energy prices and proximity to end markets. Petrochemical producers based in the United States have regained market share, as their cost structure has become competitive due to the availability of cheap feedstock deriving from the production of domestic shale gas from which ethane is derived, which is a cheaper raw material to produce ethylene than the oil-based feedstock utilized by Eni’s petrochemical subsidiaries. Finally, the running of petrochemicals operations in Europe is less competitive than other geographies due to relatively higher energy costs and environmental liabilities, as well as a growing consumers’ preference towards replacing single-use plastics with more sustainable packaging. The weak fundamentals of Eni’s mostly commoditized segments make them more sensitive to the cyclical nature of the industry and overcapacity.
In order to reduce Versalis’ exposure to basic chemicals, in October 2024, Eni announced a transformation and relaunch plan. This should make Versalis’ operations profitable again, through the transformation, the decarbonization and the revamping of the chemical business. A new investment plan will be executed to develop new chemical platforms in high value downstream activities such as renewables, circular and specialized products while restructuring efforts will address exposure to basic chemicals, with an overall net positive impact on employment.
Refining
In 2024, the Standard Eni Refining Margin reported an average of 5.1 $/barrel vs. 8.1 $/barrel reported in the comparative period. Refining margins decreased driven mainly by less favourable products crack spreads, pressured by weak demand, overcapacity and competitive pressures from other geographies.
Supply
In 2024, a total of 16.22 mmtonnes of crude were purchased for the directly supplied refineries by Eni (compared with 19.08 mmtonnes in 2023), of which 5.06 mmtonnes by equity crude oil. The breakdown by geographic area was the following: 31% of purchased crude came from Central Asia, 21% from North Africa, 9% from the Middle East, 9% from Italy, 6% from the North Sea, 5% from West Africa and 19% from other areas.
67
R efining
In 2024, Eni refinery capacity (balanced with conversion capacity), excluding Adnoc equity-accounted refinery, was approximately 22.9 mmtonnes (equal to 458 KBBL/d), with a conversion index of 52%. Conversion index is a measure of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 14.9 mmtonnes (equal to 298 KBBL/d), with a 53% conversion index. In 2024, Eni’s refineries throughputs in Europe were 16.28 mmtonnes. The average refinery utilization rate, ratio between throughputs and refinery capacity, is 78%.
|
Refining system in 2024 |
|
|
|
|
|
|
Ownership share |
Capacity (2024) |
|
|
|
(%) |
(KBBL/d) |
|
Italy |
|
|
|
|
Sannazzaro |
subsidiary |
100 |
180 |
|
Taranto |
subsidiary |
100 |
104 |
|
Livorno |
subsidiary |
100 |
14 |
|
Milazzo |
joint-operation |
50 |
100 |
|
Outside Italy |
|
|
|
|
Germany* |
|
|
|
|
Vohburg/Neustadt (Bayernoil) |
joint-operation |
20 |
41 |
|
Schwedt |
equity-accounted |
8.33 |
19 |
|
United Arab Emirates |
|
|
|
|
Adnoc Refinery |
equity-accounted |
20 |
163 |
|
Total |
|
|
621 |
|
*Results of the refining activities in Germany are reported within Enilive business. |
|||
Ita l y
Eni ’ s r e f ining system in It a l y is composed of the w hol l y- o wned r e f ineries of Sannazza ro , L i v orno and T a r ant o , as we ll as its 50% st a k e in the Milazzo r e f inery in Sici l y . Eni ’ s r e f ineries ope r a te to maximi z e asset v a lue acco r ding to ma r k et conditions and the integ r a tion with ma r k eting act i vitie s .
The Sannazza r o r e f inery has a b a lanced c a pacity of 180 KBBL/d and a co n v ersion ind e x of 54%. Loc a ted in the P o V a lle y , in the center of the Northern It a l y , Sannazza r o is one of the most e f f icient r e f ineries in Eu r op e . The high f l e xibility and co n v ersion c a pacity of this r e f inery a ll o ws it to p r ocess a wide r ange of feedstock. The main equipment in the r e f inery is: t w o primary distill a tion columns and t w o associ a ted v acuum unit s , th r ee desulphuriz a tion unit s , a f luid c a t a l ytic c r ac k er (FCC), t w o h y d r oc r ac k ers (HdC), t w o r e f o r ming unit s , a gasi f ic a tion p r oducing a syngas used in a combined c y cle p o w er gene r a tion.
The T a r anto r e f inery has a b a lanced c a pacity of 104 KBBL/d and a co n v ersion ind e x of 56%. T a r anto has a st r ong ma r k et position due to the fact th a t is the on l y r e f inery in Southern Continent a l It a l y and is upst r eam integ r a ted with the V a l d’Agri (Eni 61%) and Tempa Rossa f i e lds in Basilic a ta th r ough a pip e lin e . The main equipment is a topping- v acuum unit, a residue hydrocracking and a gasoil hydrocracking unit, a pl a t f o r ming unit and t w o desulphuriz a tion unit s .
The Livorno refinery, with a balanced refining capacity of 14 KBBL/d and a conversion index of 12%, until February 2024 is dedicated to the production of lubricants and specialties. From the second quarter of 2024 the refinery has only the gasoline line running with a platforming and isomerization unit and a desulphurization unit for the production of fuels processing Virgin Nafta. In 2024, Eni progressed the decarbonisation process, obtaining the final investment decision to convert the traditional Livorno refinery into a biorefinery, following the same successful model adopted in Gela and Venice. The project foresees the construction of a biogenic feedstock pre-treatment unit, an Ecofining™ plant and a facility for the production of hydrogen from natural gas.
The Milazzo refinery (Eni 50%) has a balanced capacity of 100 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipment in the refinery is: two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracker (HdC), one reforming unit and one LC fining (ebullated bed residue conversion).
68
Rest of Europe
In Germany, Eni owns an interest of 8.33% stake in the Schwedt refinery (PCK) and an interest of 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni’s refining capacity in Germany is 60 KBBL/d to supply Eni’s distribution network in the country.
The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated.
|
Availability of refined products |
|
2024 |
|
2023 |
|
2022 |
|
|
|
(mmtonnes) |
||||
|
Italy |
|
13.76 |
|
16.88 |
|
16.12 |
|
of which: At wholly-owned refineries |
|
10.58 |
|
13.31 |
|
13.25 |
|
At account of third parties |
|
(1.50) |
|
(1.32) |
|
(1.70) |
|
At affiliated refineries |
|
4.68 |
|
4.89 |
|
4.57 |
|
Outside Italy* |
|
10.45 |
|
10.51 |
|
11.00 |
|
TOTAL THROUGHPUTS ON OWN ACCOUNT |
|
24.21 |
|
27.39 |
|
27.12 |
|
*Results of the refining activities in Germany are reported within Enilive business. |
|
|
|
|
|
|
In 2024, Eni ’ s r e f ining th r oughputs on o wn account w e r e 24.21 mmtonne s , increasing by 11.6% from 2023 following the lower processing, in particular at the Livorno refineries due to a new production set-up and at Sannazzaro refinery impacted by higher plant shutdowns compared to the comparison period. The r e f inery utiliz a tion r a t e , r a tio bet w een th r oughputs and r e f inery c a pacit y , is 78%.
Approximately 31% of processed crude was supplied by Eni’s Exploration & Production segment, representing an increase from 2023 (24.4%).
Other businesses
Logistics
Eni is a leading ope r a tor in the It a lian oil and r e f ined p r oducts sto r a ge and t r ansport a tion b usines s .
Oil and r e f ined p r oducts a r e t r ansported: (i) b y sea th r ough spot and long-te r m cont r acts of tan k er ships; and (ii) inland th r ough a p r oprietary pip e line and depots net w o r k di r ect l y ope r a ted.
In particula r , Eni o wns and ope r a tes an integ r a ted inf r astructu r e consisting of 15 di r ect l y man a ged depots and one managed through the subsidiary Petroven, 100% owned since December 2019 .
Eni also owns a network of oil and refined products pipelines extending approximately 1,200 kilometers operating. Eni l o gistic mod e l is o r gani z ed in f our operative management (Northern depot s , Cent r a l depot s , Southern depots and LPG and Pip e line) operating in handling and storage of the p r oduct f l o ws in o r der to gua r antee high safet y , asset integrity and technic a l standards (HSE e asset integrity), as we ll as cost optimization and constant p r oducts a v ail a bility a long the countr y . Eni is a lso part of 7 di f fe r ent l o gistic joint ventures (Sigemi, Seram, Disma, Seapad, Toscopetrol, Porto Petroli Genova and Costiero Gas Livorno), together with other Italian operators, that operate other localized depots and pipelines.
Secondary distribution is outsourced to independent trucks, selected as market leaders.
Ox y g enates
Eni ’ s , th r ough its subsidiary Ecofu e l (100% Eni ’ s sha r e), s e lls a pp r o xim a t e l y 0.9 mmtonnes/y of o x y gen a te s , main l y ethers ( a pp r o xim a t e l y 1.5% of w o r ld demand, used as a gasoline octane booster) and methanol (main l y f or pet r ochemic a l use). About 76% of o x y gen a tes a r e p r oduced in Eni ’ s plants in It a l y ( R a v enna), Saudi A r a bia (in joint v entu r e with S a bic) and V enezu e la (in joint v entu r e with P equ iv en) and the r emaining 24 % is pu r chased.
69
Chemicals
In 2024, sales of chemical products amounted to 3,169 ktonnes and slightly increased from 2023 (up by 52 ktonne s , or 1.7 %). In particular, the main increases were recorded in the intermediates (olefines, aromatics and fenol derivatives), up by 4.2%, and in polymers (polyethylene, styrenics and elastomers), down by 7%. In the compounding business, sales amounted to 64 ktonnes, down by 4.5% from the comparative period. Reductions were reported also in the oilfield business, down by 14 ktonnes or down by 33.3%. Additional volumes derive from Novamont Group’s entities and Matrica and amounted to 88 ktonnes (both companies were consolidated starting from October).
Average sale prices of the intermediates business decreased by 1.9% from 2023, with olefins down by 3% and derivatives down by 0.7 %. The polymers reported a decrease of 1.1% from 2023 .
Chemical production amounted to 5,685 ktonnes (up by 22 ktonnes vs. 2023). Lower production was reported in the intermediates business (down by 26 ktonnes), in particular aromatics and derivatives. The main reductions were reported at Priolo plant (down by 195 ktonnes) and Mantua site (down by 85 ktonnes). Those reductions were offset by increased volumes at Dunkerque plant (up by 285 ktonnes).
The a v e r a ge plant utiliz a tion r a t e, c a lcul a ted on nomin a l c a pacity, w as 50.4 % representing a decrease from the comparative period (51.4% in 2023).
The t a b le b e l o w sets f orth Eni ’ s main chemic a l p r oducts a v ail a bility f or the periods indic a ted.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(ktonnes) |
||||
|
Intermediates |
3,851 |
|
3,877 |
|
4,897 |
|
Polymers |
1,559 |
|
1,658 |
|
1,873 |
|
Biochem |
206 |
|
57 |
|
5 |
|
Moulding & Compounding |
69 |
|
71 |
|
81 |
|
Total production |
5,685 |
|
5,663 |
|
6,856 |
|
Consumption losses |
(3,106) |
|
(3,247) |
|
(3,923) |
|
Purchases and change in inventories |
590 |
|
701 |
|
819 |
|
Chemical products availability |
3,169 |
|
3,117 |
|
3,752 |
The t a b le b e l o w sets f orth Eni ’ s main chemic a l p r oducts sale s f or the periods indic a ted.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(ktonnes) |
||||
|
Intermediates |
1,720 |
|
1,651 |
|
2,158 |
|
Polymers |
1,255 |
|
1,350 |
|
1,494 |
|
Oilfield chemicals |
14 |
|
21 |
|
21 |
|
Biochem |
116 |
|
28 |
|
3 |
|
Moulding & compounding |
64 |
|
67 |
|
76 |
|
|
|
|
|
|
|
|
Total sales |
3,169 |
|
3,117 |
|
3,752 |
70
Intermediates
Intermediates revenues (€1,530 million) increased by €33 million from 2023 (up by 2.2%). Sales volumes increased by 69 ktonnes, or 4.2% vs. 2023. In particular, reported positive performance in olefines (up by 14.6%), offset by lower sales of aromatics (down by 17.2%) and derivatives (down by 5.6%). Average prices decreased by 1.9%, in particular olefins (down by 3%) and derivatives (down by 0.7%).
Intermediates production (3,851 ktonnes) registered a decrease of 0.7% from 2023. Decreases were also registered in aromatics (down by 17.8%) and in derivatives (down by 9.4%).
P o l yme r s
Revenues in the polymers segment (€1,979 million) decreased by €176 million or 8.2% from 2023 due to lower sales volumes (-95 ktons) and in the average sales prices (down by 1.1%).
Sold volumes reported a decrease (down by 3.5%) due to lower sales of LLDPE (down by 13.4%) and HDPE (down by 17.4%). These negatives were partially balanced by the increase in volumes of EVA (up by 23.4%).
As for elastomers, decreases were reported in sales of latex (down by 24.7%), EPR/EPDM (down by 11.4%) and BR (down by 1.9%), while sales of NBR and SBR increased by 2.6% and 10.1%, respectively. Average sales prices increased by 1.3%.
The decrease in sales volumes of styrenics, due to the reduction of demand, particularly affected GPPS (down by 5.1%) and HIPS (down by 23.5%).
Polymers production (1,559 ktonnes) decreased by 6.0% from the 2023 due to the lower production of styrenics (down by 10.3%), elastomers (down by 9.2%) and polyethylene (down by 0.8%).
Oilfield chemicals, Biochem e Moulding & Compounding
Oilfield chemicals revenues decreased by 19.2% (down by €19 million compared to 2023) as a result of decreasing sales volumes (down by 33.3%).
Biochem business revenues (€316 million) significantly increased by €233 million from 2023, mainly thanks to the inclusion of Novamont Group in the consolidation area starting from October 1, 2023 .
Moulding & Compounding business revenues decreased by €22 million from 2023 (down by 8%) due to lower sales volumes (down by 4.5%).
Capital e xpenditu r es
See “Item 5 – Liquidity and c a pit a l r esou r ces – C a pit a l e xpenditu r es b y segment”.
71
Corpor ate and Other activities
These acti vities include the f ollo wing b usinesses:
|
|
● |
the “Other activities” segment comprises results of operations of Eni’s subsidiary Eni Rewind (former Syndial SpA) which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and |
|
|
● |
the “Corporate and financial companies” segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. It also includes the results of the CO 2 Capture, Storage and Utilisation and Agri-business, which is under development.
Through Eni’s subsidiaries Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance DAC, Eni carries out cash management activities, administrative services to its foreign subsidiaries, lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an intercompany basis. Eni Servizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations. |
Seasonality
Eni’s results of operations r eflect the seasona lity in demand f or natura l gas and certain refined products used in residentia l space heating, the demand f or w hich is typica lly highest in the first quarter of the y ear, w hich includes the coldest months and lo west in the third quarter, w hich includes the w armest months. Mor eove r, y ear - to-year comparability of results of operations is affected b y we ather conditions af fecting demand f or gas and other refined products in residentia l space heating. In colder y ears, w hich ar e characterized b y lo we r temperatur es than historica l a ve ra ge temperatur es , demand f or gas and products is typica lly higher than norma l consumption patterns, and vice v ersa.
72
Eni’s Research and Technological Innovation is a key element to make effective and efficient access to new energy resources, improve the use of existing ones and at the same time reduce the impact on the environment. The objectives are, therefore, declined on the following strategic directives:
|
|
● |
process decarbonization: with the aim of reducing, capturing, transforming or storing CO 2 , increasing energy efficiency, reducing emissions and promoting energy vectors with a low carbon footprint; |
|
|
● |
circular and bio-products: with the aim of reducing, recycling and reusing products and by-products, transforming waste into value-added products for biorefinery, sustainable mobility and biochemicals; |
|
|
● |
renewables and new energies: with the aim of supporting the development of renewable energies and energy storage solutions, and to develop breakthrough energy technologies such as magnetic confinement fusion; |
|
|
● |
operational excellence: with the aim of developing technologies that ensure the highest level of efficiency and safety, the lowest environmental impact, while reducing costs and time to market of our activities. |
A key point of Eni’s research and innovation is the integrated and transversal approach being a lever to create value, with the aim of minimizing the time to market that from research leads to the development of technologies and their implementation on an industrial scale.
In 2024, Eni filed 39 patent applications (28 in 2023).
In 2024, Eni’s overall expenditure in R&D amounted to €178 million which were almost entirely expensed as incurred (€166 million in 2023). In 2024, about 80% of total R&D expenditures were dedicated to the decarbonization, renewable energies and circular economy.
73
Research and Development in Eni is characterized by three main factors: in-house expertise, Open Innovation model and development of the entire technology chain. About 1,000 researchers are engaged in research activities, with expertise ranging from upstream to downstream, from renewables to the environment. This knowledge base is complemented by a network of 70 national and international universities and research centers and becomes even more effective with an opening to the market and to startups, both in Italy and abroad, through Joule (startup accelerator) and Eni Next (Corporate Venture Capital).
Eni’s approach in research and development is aimed at enhancing the entire technology value chain: thorough identification of a portfolio of technology solutions to be provided to the business, to meet the challenges of an evolving world with important decarbonization goals, and the definition of an approach to accelerating the industrial deployment of technologies, also through financial instruments or specific vehicles, such as the setup of Eniverse, Eni corporate venture building company.
In this way, Eni Innovation follows all stages of the process: while we develop proprietary technologies already applicable to our businesses to increase efficiency, we continue to support the search for innovative solutions for business of tomorrow and to make access to energy resources more efficient and sustainable, contributing to the reduction of the carbon footprint. The company adopts a synergistic approach, involving all its expertise to address the challenges of an energy sector in constant evolution.
One of the key areas of interest is CCUS (Carbon Capture, Utilization, and Storage), with the goal of covering the entire carbon chain: from capture to transport, storage, and utilization. In particular, the focus is on the capture phase, where we are evaluating different technological solutions to increase process efficiency.
Another key aspect is the development of bio-based and low-carbon products. The goal is to replace, or at least integrate, fossil raw materials with renewable or biologically sourced resources, in order to produce fuels and other materials with lower emissions.
At the same time, the company is committed to improving renewable energies and storage systems. Research focuses on optimizing solar and wind energy technologies, also evaluating new renewable sources and developing advanced systems to ensure stable and continuous supply. Regarding storage, studies aim to enhance the performance of batteries and thermal storage systems, to better integrate them into existing grids.
Eni's innovation also extends to bio-based, circular, compounding, and polymer materials, with a significant commitment to creating more sustainable materials for sectors such as packaging, automotive, and construction. Finally, the focus is also on the research of advanced polymers, designed to address the challenges of electric mobility, renewable energy, and lightweight materials for innovative structures.
Another pillar of the strategy is environmental and water resource management, as we invest in innovative solutions for soil remediation and the sustainable management of water, a key element of the energy transition. One of the main objectives is the reuse of wastewater, thus contributing to the circular management of water resources.
In the field of fusion, research focuses on the development of innovative materials capable of withstanding extreme conditions and optimizing the systems necessary for the efficient and safe operation of future reactors. The goal is to improve the performance and reliability of these technologies, contributing to the progress of a possible sustainable energy source for the future.
Finally, we work towards operational excellence, developing solutions to improve safety, reliability, and sustainability of industrial activities. The strategy includes the adoption of advanced technologies for plant monitoring, predictive maintenance, and energy consumption optimization. Furthermore, decarbonization is at the heart of corporate initiatives, with the integration of carbon capture and storage solutions and the increasing use of renewable sources throughout the entire energy value chain.
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In order to control the insurance costs incurred by each of Eni’s business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance DAC, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group’s results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market. Eni enters into insurance arrangements through its shareholding in the Everen Ltd (a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the Everen Lt d. In addition, Eni uses reputable, high quality insurance companies which are well established in the market. Insured liabilities vary depending on the nature and type of circumstances; however, underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.1 billion for offshore events and $1.3 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1.3 million for tankers and charters and up to $1 billion for FPSOs used by the Exploration & Production segment for developing offshore fields.
Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one that occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See “Item 3 — Risk factors — Risk associated with the exploration and production of oil and natural gas”.
Environmental regulation
Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in certain protected areas or provide special measures to be adopted to protect health and safety at workplace and health of communities that could have been affected by the Company’s activities. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. See “Item 3 – Risk factors”.
We believe that the Company will continue to incur significant amounts of expenses to comply with pending environmental, health and safety protection and safeguard regulations; particularly in order to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere and cope with climate change and water quality of discharges, as well as availability.
The Group balance sheet has accrued the expenses for environmental liabilities in place at the closing date, which will likely require a disbursement on part of the Company in future reporting periods and for which a reliable estimate can be made.
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Management believes that it is possible that in the future Eni may incur significant or material environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavourable developments in ongoing litigation on the environmental status of certain of the Company’s sites where a number of public administrations, the Italian Ministry of the Environment or third parties are claiming compensation for environmental or other damages such as damages to people’s health and loss of property value; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites.
International and European Union Environmental Laws Framework
At global level, the most important policy framework to strengthen the global response to the threat of climate change is the Paris Agreement, an international treaty, entered into force on November 4, 2016. Although the Paris Agreement does not apply directly to Eni, it includes commitments from all countries to reduce their emissions and work together to adapt to the impacts of climate change, and calls on countries to strengthen their commitments over time.
In this context, during the UN Climate Change Conference of Parties (COP 28), taken place in Dubai in 2023, the Parties agreed to “transitioning away from fossil fuels in energy systems, in a just, orderly and equitable manner, accelerating action in this critical decade, so as to achieve net zero by 2050 in keeping with the science”. In case this goal is effectively pursued by the Parties through policies and regulations, than hydrocarbons demand could decrease in the medium to long term, coupled with a potential increase of operational expenses for the O&G sector. On the other side, the final decision of COP28 highlights also some important levers for the decarbonization of the energy system that could represent business opportunities for Eni, such as renewables, Carbon Capture and Storage, low carbon hydrogen, transitional fuels, nuclear energy.
Alongside the COP28, several initiatives have been launched or strengthened. Among them, Eni supported (i) the Global Flaring and Methane Reduction (GFMR) Partnership, a new multi-donor trust fund focused on helping developing countries cut carbon dioxide and methane emissions generated by the oil and gas industry and (ii) the Oil and Gas Decarbonization Charter (OGDC), where Signatories have committed to net-zero operations by 2050 at the latest, and ending routine flaring by 2030, and near-zero upstream methane emissions.
Regarding the European Union (EU), during 2023, almost all new or emended directives and regulations, proposed in the "Fit for 55" package (July 2021) entered into force, among which the most impactful are: (i) 42.5% renewable share in the overall energy consumption by 2030; (ii) 40% GHG reduction for non-ETS sectors by 2030 vs 2005 and 62% GHG reduction for ETS sectors by 2030 vs 2005; (iii) 11.7% reduction in energy consumption by 2030, compared to the 2020 reference scenario at EU level.
Within the revised Renewable Energy Directive (RED III), the EU institutions established also a new binding and challenge target for transport sector set at 29% renewable share in the final energy consumption of the transport sector by 2030 or alternatively a 14,5% reduction in GHG intensity compared to a fossil fuel baseline. The new Directive also requires Member States to increase the consumption of advanced biofuels and of Renewable Fuels of Non-Biological Origin (RFNBO) to 5.5% in 2030, of which at least 1% from RFNBO. In a separate regulation, the EU regulator also introduced a minimum blending mandate for Sustainable Aviation Fuels and a limit to the carbon intensity of the energy used on board ships, to support the uptake of sustainable maritime fuels. These mandates coupled with adequate incentives could increase the demand of sustainable biofuels that Eni is already committed to supply to the market.
Regarding the ETS directive, main changes that, if implemented, could impact Eni are the (i) scope extension to the building, road transport and shipping sectors, (ii) downward revision of the cap (iii) potentially fewer free allowances allocation due to a revision of the emissions benchmark. EU also adopted the new Carbon Border Adjustment Measure (CBAM) aimed at ensuring a level playing field between EU and non-EU installations, thus securing the EU industrial competitiveness, in the following sectors cement, electricity, fertilisers, iron and steel, aluminum and hydrogen. However, for the time being, Eni operations are only marginally covered by the CBAM.
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In the energy efficiency field, the directive of September 2023 introduces a series of measures and embraces the “energy efficiency first” principle. The main features and changes from the previous directive includes:
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increasing annual energy savings from 0.8% (at 2023) to 1.3% (2024-2025), then 1.5% (2026-2027) and 1.9% from 2028; |
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introducing an annual energy consumption reduction target of 1.9% for the public sector; |
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extending the annual 3% buildings renovation obligation to all the levels of public administration; |
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introducing a different approach, based on energy consumption, for business to have an energy management system or to carry out an energy audits; |
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bringing in a new obligation to monitor the energy performance of data centres, with an EU-level database collecting and publishing data. |
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promoting local heating & cooling plans in larger municipalities. Progressively increasing the efficient energy consumption in heat or cold supply, also in district heating. |
From 2022, the efforts of the European Commission legislators focused on several proposals to support enhanced non-financial disclosure obligations for financial market participants, financial advisors and large corporations.
On 23 February 2022, the European Commission published its proposal for a Directive on Corporate Sustainability Due Diligence that on 25 July 2024 came into force (Directive No. 2024/1760). The new rules apply to large EU companies (>1,000 employees and >450 million euros in net turnover worldwide) and large non-EU companies (>450 million euros in net turnover within the EU). The directive aims to promote sustainable and responsible business conduct in companies' operations and throughout their value chains. Companies must ensure the identification and assessing of actual or potential adverse impacts and, where necessary, prioritising actual and potential adverse impacts; preventing and mitigating potential adverse impacts, and bringing actual adverse impacts to an end and minimising their extent; providing remediation for actual adverse impacts. . The core elements of this duty are identifying and addressing potential and actual adverse human rights and environmental impacts in the company’s own operations, their subsidiaries and, where related to their value chain(s), those of their business partners.
Furthermore, the directive establishes the obligation to adopt and implement a transition plan for climate change mitigation, in line with the Paris Agreement’s goal of climate neutrality by 2050, as well as the intermediate targets set by EU climate legislation.
The Corporate Sustainability Reporting Directive (CSRD) is another key initiative of the Green Deal for Europe and is part of a broader regulatory framework concerning non-financial disclosure requirements. On 5 January 2023, Directive 2022/2464/EU came into force, updating the EU rules on corporate sustainability disclosures by broadening the scope and introducing detailed reporting requirements, also with a view to combating greenwashing. Companies subject to the CSRD will have to report according to European Sustainability Reporting Standards (ESRS). The standards were published in the Official Journal on 22 December 2023 under the form of a delegated regulation. The CSRD amends Directive 2013/34/EU on non-financial business information by introducing ad hoc provisions on corporate sustainability reporting. In Italy, the CSRD was transposed on September 6, 2024, via Legislative Decree No. 125. Eni, among the first companies affected, will publish the "Sustainability Report" in line with ESRS from 2025 (for the 2024 reporting year), replacing its Non-Financial Disclosure (DNF), with the relevant data disclosed within the Management Report (Eni’s Consolidated Financial Statements).
Air quality remains at the center of the European environmental policies and strategies. In 2019 the European Commission has completed a fitness check of the two EU Ambient Air Quality (AAQ) Directives (Directives 2008/50/EC and 2004/107/EC). In October 2022, the Commission proposed stronger rules on ambient air quality, setting interim 2030 EU air quality standards more closely aligned with the 2021 World Health Organization guidelines, aiming for zero air pollution by 2050 in synergy with climate-neutrality efforts. A key change was the tightening of the annual limit value for fine particulate matter (PM2.5) to 10 µg/m³ by 2030, down from the previous 25 µg/m³ limit.
In 2024, the EU legislature introduced further measures to progressively improve air quality to levels no longer harmful to human health, natural ecosystems, and biodiversity, while enhancing public access to information and strenghthening the assessment of air quality by a representative high-quality monitoring network. On October 23, 2024, Directive 2024/2881 on ambient air quality was published, reinforcing implementation and tightening permissible pollutant levels to align more closely with WHO recommendations by 2030.
Additionally, Regulation 2024/1244, in force since May 22, 2024, replaces Regulation (EC) No. 166/2006 and will apply from January 1, 2028. It establishes a European emissions portal to enhance industrial facility environmental data reporting.
Lastly, Directive 2024/1785, effective August 4, 2024, amends Directive 2010/75/EU on industrial emissions (integrated pollution prevention and reduction). Member States must transpose it into national law by July 1, 2026. The main areas of improvement include:
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• Innovation and transformation through the most effective viable emissions reduction techniques.
• Tightened rules on reducing emissions with stricter emissions limit values and more stringent conditions on granting derogations.
• Access to environmental data (new Industrial Emissions Portal Regulation).
• Address Circular economy and resource efficiency, as well as reducing the use of hazardous chemicals.
• Coverage of activities to reduce unregulated emissions.
• Rights of the public by strengthening and broadening public information, participation and access to justice.
The Industrial Emission Directive (IED) 2010/75/EU is fundamental for European industries, it provides the framework for granting permits for about 40000 of industrial installations across the EU. It lays down rules on the integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are defined by the sector specific and cross sector Best Available Technology (BAT) Conclusions.
On May 12, 2021, the European Commission adopted the EU Action Plan: "Towards a Zero Pollution for Air, Water and Soil" (and annexes) - a key deliverable of the European Green Deal whose objectives are “The zero pollution vision for 2050 is for air, water and soil pollution to be reduced to levels no longer considered harmful to health and natural ecosystems, that respect the boundaries with which our planet can cope, thereby creating a toxic-free environment”. In July 2021 the conclusion of the EU consultation on the revision of the Wastewater Directive was published. The 25th October 2022, the European Commission published the proposal for the new Urban Wastewater Treatment Directive (UWWTD). The revised Urban Wastewater Treatment Directive, which entered into force on 1 January 2025, protects human health and the environment from the effects of untreated urban wastewater. It requires EU countries to ensure that towns and cities properly collect and treat wastewater cost-effectively. It aims to:
• Improve water quality through stricter water treatment and the inclusion of new pollutants;
• Strengthen the EU’s polluter-pays principle by ensuring that those responsible for pollution bear the costs of remediating it;
• Advance circularity through water reuse and the recovery of valuable resources from wastewater;
• Address climate change through GHG emission reduction of treatment plants and urban adaptation to heavy rainfall;
• Ensure access to sanitation for all, particularly the most vulnerable and marginalised.
The European Commission decided to revise the Waste Framework Directive, in order to reduce waste generation, improve waste collection and optimize recycling, increase the collected amount of waste oil and ensure its treatment according to the EU waste hierarchy; a legislative proposal was presented on 5th July 2023, including measures aimed to tackle food and textile waste and a provisional agreement was reached on 18 February 2025 between the European Parliament and the Council.
On April 11, 2024, the European Parliament and of the Council approved the Regulation (EU) 2024/1157 on shipments of waste, which entered into force on 20 May 2024; most provisions will apply from 21 May 2026 and most export rules will apply from 21 May 2027; until then, the provisions of Waste Shipment Regulation 1013/2006 continue to apply. The new Regulation sets stricter rules on waste export, also requiring independent audits in the facilities outside the EU, to strengthen the contrast to illegal shipments and to facilitate the waste shipments in the internal market of EU, also through the digitalization of procedures. Shipments of plastic waste are subject to a specific regime. Other waste suitable for recycling will be exported from the EU to non-OECD countries only when they ensure that they can deal with it in a sustainable manner, by the mean of independent audits.
On February 11, 2025, the Packaging and Packaging Waste Regulation 2025/40 (PPWR) entered into force; its general date of application is 18 months after that. It regulates what kind of packaging can be placed on the EU market, as well as packaging waste management and prevention measures, aiming to minimize the quantities of packaging and waste generated while lowering the use of primary raw materials and fostering the transition to a circular, sustainable and competitive economy. The PPWR replaces the Packaging and Packaging Waste Directive 94/62/EC (PPWD) and harmonises national measures further - strengthening the internal market - notably for secondary raw materials, manufacturing, recycling and reuse.
Those measures could lead to increased operating expenses for Eni, but they are not expected to have a significant impact on the Group’s results.
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European Union Health and Safety Laws Framework
Legislative Decree No. 81/2008 concerned the protection of health and safety in the workplace and was designed to regulate the work environments, equipment and individual protection devices, physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals.
With Law 215 of 17 December 2021, important innovations were introduced into Legislative Decree 81/08. These changes bring a much-needed initial novelty and update to a number of prevention and control issues in the workplace, such as:
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Regional coordination committees; |
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Joint organisms; |
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Role of the “Preposto”; |
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National prevention information system; |
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Vigilance; |
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Suspension of activities; |
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Training. |
Additional modifications were introduced by Law 20 May 2022, n. 51, Law 3 July 2023, n. 85, Law 27 November 2023, n. 170, Law 15 December 2023, n. 191, Law 30 December 2023, n. 214, Law 29 April 2024, n. 56, Law 13 December 2024, n. 203.
On June 1, 2007, the REACH Regulation of the European Union came into force (Regulation (EC) No. 1907/2006 concerning the Registration, Evaluation, Authorization and Restriction of Chemicals).
The Commission is currently reviewing the REACH Regulation, through a public consultation aimed at SMEs, citizens and stakeholders with the aim of obtaining opinions on the expected impacts of the envisaged changes.
The overall objective of this revision is to ensure that the provisions of the REACH Regulation reflect the Commission's innovation ambitions for safe and sustainable chemicals and a high level of health and environmental protection, while preserving the internal market, as foreseen in the Chemical Strategy for Sustainability adopted on October 14, 2020.
This strategy is part of the EU's zero pollution ambition, a key commitment of the European Green Deal, and aims to better protect citizens and the environment from harmful chemicals as well as stimulate innovation by promoting the use of safer and more sustainable chemicals.
The European Chemicals Agency (ECHA) contributes to the implementation of the strategy with its scientific and regulatory expertise, databases, digital tools and networks, and practical experience in chemicals regulation, where necessary.
The European Regulations are constantly evolving which materialize with the publication of adjustments and delegated regulations on specific topics with large impact on Eni and the companies that produce and market products, such as:
- Regulation (EU) 2020/878 published on 26 June 2020, amending Annex II of REACH relating to the "Requirements for completing safety data sheets (SDS)" for substances and mixtures, in force since 16 July 2020, applicable from 1 January 2021, that represents a challenging moment for the company that manages a large number of SDSs, as starting from 1 January 2023 all SDSs will necessarily have to be drawn up in accordance with this Regulation.
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- Regulation (EU) 2017/542 of 22 March 2017 which amends Regulation (EC) no. 1272/2008 (CLP) of the European Parliament and of the Council on classification, labeling and packaging of substances and mixtures of the European Parliament and of the Council on classification, labeling and packaging of substances and mixtures through the addition of an annex on harmonized information on emergency health response and its subsequent amendments. In fact, starting from January 2021, in Italy, new dangerous preparations for consumer and professional use must be notified on the ECHA portal through the PCN (Poison Centers Notification). While previously, information on the dangerous mixture had to be sent to the ISS by 30 days from the date of placing on the market, now the submission of information has to be done to ECHA before the mixture is placed on the market.
- Delegated Regulation 2023/707 amending CLP Regulation, in force from 20 April 2023, which sets out new hazard classes and criteria for the classification, labelling and packaging of substances and mixtures.
- Regulation (EU) 2024/2865, adopted on October 23, 2024, amends the CLP Regulation (EC) No 1272/2008. This amendment introduces significant changes, including new instructions for classifying complex substances - referred to as 'substances containing more than one constituent' (MOCS) - and updates to labelling formats by adding Chapter 3 to Title III of the CLP Regulation. The regulation entered into force on December 10, 2024, and will be implemented in phases, with the first provisions applying from July 1, 2026. The remaining requirements will come into full effect on January 1, 2027.
- Update of Annex VII of REACH Regulation (5 update in 2023)
- Evolution on PFAS (Per- and polyfluoroalkyl substances) regulation and restrictions that involved about 10000 substances. ECHA’s scientific committees will now start evaluating the proposal in terms of the risks to people and the environment, and the impacts on society.
It applies to all chemical substances and mixtures placed on the EU market under REACH. It also applies to active substances in biocidal products and plant protection products, which are normally prioritised for harmonised classification in the EU.
Compliance with REACH requirements and the involvement of all stakeholders in the Company are coordinated and supervised by the HSEQ/Product Safety function.
European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction.
On June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The Directive, also named Offshore Directive, was transposed into Italian law by means of Legislative Decree 145 of August 18, 2015.
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The main elements of the EU Directive are the following:
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The Directive introduces licensing rules for the effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil&gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas. |
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Independent national competent authorities, responsible for the safety of installations, are in charge of verifying the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards. |
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Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities. |
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Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation. |
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Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents. |
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Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities. |
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Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore). |
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Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations. |
We believe that Eni operations are currently in compliance with all those regulations in each European country where they have been enacted.
The Company has been adopting for year standard practices and operating procedures to reduce risks of incidents and adverse events in its oil&gas operations, particularly offshore, which we believe to be adequate to scale, reach, geographical location and complexity of our operations.
Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Moreover, in order to achieve the highest safety standards of our operations in the Gulf of Mexico, Eni ent ered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Well Containment Group (HWCG) perfo rms certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.
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Worldwide Eni approach was to join international consortiums for main equipment and to develop in-house technologies to improve the intervention capability. Eni Emergency Response Kit consists of:
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Outsourced equipment contracted by Eni Head Quarter; |
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Access Agreement to Subsea Capping Equipment consortium; |
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Access Agreement to Global Dispersant Stockpile consortium; |
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Eni Head Quarter proprietary equipment; |
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Rapid Cube; |
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Killing System relating to drilling operations. |
In addition to the above, Eni is a participant member of Oil Spill Response Limited, the largest international industry-funded cooperative which exists to respond to oil spills wherever in the world they may occur, by providing preparedness, response and intervention services.
As regards major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015).
The main changes in comparison to the previous Seveso Directive are:
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technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures; |
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expanded public information about risks resulting from Company activities; |
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modified rules in participation by the public in land-use planning projects related to Seveso plants; and |
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stricter standards for inspections of Seveso establishments. |
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Eni has carried out specific activities aimed at guaranteeing the compliance of its own industrial site. |
HSE activity for the year 2024
Eni is committed to continuously improving its model for managing health, safety and environment issues across all its businesses in order to minimize risks associated with its own industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations.
In 2024, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 320, of which:
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92 certifications according to the ISO 14001 standard; |
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10 registrations according to the EMAS regulation; |
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32 certifications according to the ISO 50001 standard (certification for an energy management system); |
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101 according to the new ISO 45001 standard; |
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41 according to the ISO 9001 standard (certification of the quality management system). |
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In 2024 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 86% for the ISO 45001 standard and 84% for the ISO 14001 standard.
In 2024, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,569 million (up by 12% vs 2023).
Environment .
In 2024, Eni incurred total expenditures of €1,150 million for the protection of the environment (with an increase of 9% with respect to 2023). Environmental expenditures are mainly related to remediation and reclamation activities (€581 million), waste management (€247 million), water management (€178 million), air protection (€46 million) and spill prevention (€42 million).
Safety .
Eni is constantly engaged in the research and development of all the actions necessary to guarantee safety in the workplace, in particular in the development of models and tools of risks assessment and management and in the promotion of a safety culture, in order to pursue its commitment to zero accidents.
In 2024, the new legislation did not have a significant impact on the procedures already in place for occupational and process safety. In 2024, the commitment to reduce accidents continues at Eni, through the:
- application of the THEME methodology on analysing worker behaviour and human reliability in order to identify action strategies to strengthen human barriers and safe behaviour;
- deployment of training course dedicated to: Operational Safety Management with the aim of familiarising with the basic principles and minimum safety requirements to be applied in risky activities; Process Safety Management, in order to provide basic information on Process Safety Management System; RC Eni investigation methodology, which enables the identification of root causes and effective action to prevent the recurrence of accidents; Industrial Hygiene Management with the aim of increase and share knowledge, principles and requirements to be applied in sampling and monitoring of risk agents.
- extension to all operational sites of the digital Safety Presense tool, which, with the help of artificial intelligence and machine learning, enables predictive analysis by exploiting the data available in the safety reporting, sending the site an alert when it detects a high frequency of recurring hazardous situations that retrace a past accident;'
- diffusion of the Campaign on Process Safety Fundamentals. Process Safety Fundamentals are key operating principles that, if respected, may contribute to the reduction of approximately one third of Company Process Safety Events.
In terms of industrial hygiene, great attention was paid to the identification and management of personal protective equipment (PPE). In 2024 continues at Eni the extension to all operational sites of the Integrated System Personal Protective Equipment web system aimed at the digital management of Personal Protective Equipment (PPE) and the promotion of specific training initiatives to raise awareness of the importance of correct identification and use of them.
Eni has developed a radiation protection system capable of managing the risk deriving from the use of artificial radioactive sources (for example in systems for monitoring fluid levels and density) and from the presence of natural radioactive sources (Radon and TENORM).
In particular, has validated a methodology for the mapping of TENORM matrices in Eni sites all over the word and has implemented management systems for monitoring the disposal of matrices contaminated by natural radionuclides.
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In 2024 the total recordable injury rate (TRIR) of the workforce increased compared to 2023 (0.67 vs 0.57 in 2023), due to a higher number of injuries (106 vs 93). Five fatalities occurred in Italy among contractors following an explosion in the Calenzano oil hub (Florence): at the time of writing this document, Investigations on dynamics and the causes of the event (occurred in December) are still ongoing.
In the area of emergencies, particular attention was paid to the prevention and management of emergencies induced by natural risks and in November 2021 a Memorandum of Understanding was signed between Eni and the Department of Civil Protection, to further strengthen cooperation and define emergency plans specific for each type of risk with an impact on the continuity of energy supply on the national territory.
Emergency preparedness is regularly tested during exercises where the response capacity is tested in line with dedicated plans, including the timely alerting of the chain of command and of the resources necessary to face the event. The operational sites maintained a high level of preparedness for emergencies by carrying out over 4,590 exercises.
In addition, in 2024 Eni has also focused on the development and provision of a new training course dedicated to preparedness and response, reserved for HSEQ operational staff in Italy, with the aim of increasing and sharing knowledge, international approaches and tools for more efficient emergency management.
Costs incurred in 2024 to support the safety levels of operations and to comply with applicable rules and regulations were €344 million.
Health activity for 2024
Eni protects and promotes the health, considering its physical, mental and social dimensions, of its people, workers, families and communities, through a management system based on the principles of precaution, prevention and promotion.
The total amount spent in 2024 was €47.9 million divided into: occupational health and industrial hygiene activities, medical assistance and health emergencies, health promotion, Global Health activities in favor of communities.
The correct management of health-related risks is guaranteed with the constant updating of the health profile assessments of the countries of presence, which take into account the expectations of stakeholders and the potential impacts on health deriving from company’s activities, with continuous monitoring of any presence of epidemic and pandemic outbreaks. In order to guarantee people's health at every stage of the business cycle, a dedicated management system is active in all operational areas, in collaboration with qualified healthcare providers and national and international university and government institutions and research centres. Eni acts following local regulations and highest international standards and guarantees continuous updating of staff training and skills. Health at the center of the company's strategy and operating models contributes to achieving a "just" energy transition for people in the geographical areas in which the company operates.
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Main 2024 initiatives:
- Occupational health and industrial hygiene:
• Medical and occupational hygiene activities aimed at the evaluation, identification and control of risk factors that may have an impact on the well-being of workers.
• Scientific research activities in relation to the energy transition, focusing in biorefineries, biogas production and agribusiness processes.
• Testing of new Internet of Things technologies: 99 sensors were tested at on-shore operating sites in Italy for monitoring the healthiness of indoor working environments to protect the health of workers.
- Medical assistance and health emergency:
• Services for the prevention, diagnosis, treatment and management of acute and chronic pathologies, for workers and, where applicable, family members.
• Continuous updating of epidemic and pandemic response plans.
• Online psychological support service available for employees in Italy and abroad, covering 74% of employees, expected to extend to 85% by 2028.
• Psychological First Aid Service (PFA) available to all employees in Italy and abroad in cases of catastrophic and unexpected events.
• Specific services regarding gender health and assistance have been activated, such as in Italy a helpline dedicated to victims of gender harassment and violence.
• "Più Salute" has been extended throughout Italy, a package of free health care services for Eni people and their families which provides extended care 24 hours a day, to respond to needs, from telemedicine to home medical services, from booking at health facilities to the anamnestic interview.
- Health promotion:
• Raising awareness in relation to endemic diseases, such as tuberculosis and malaria, sexually transmitted diseases, non-communicable diseases, such as diabetes and hypertension.
• Extension of the “Previeni con Eni” service to new Italian regions, a free biennial checkup for cancer and cardiovascular prevention.
• Provision of the influenza vaccination campaign in Italy.
- Global health:
• 11 Health Impact Assessment (HIA) studies completed, of which 5 integrated ESHIA studies to evaluate the potential impacts of industrial projects on the health of the communities involved.
• 33 health development initiatives have been implemented in 13 countries, reaching over 820,000 beneficiaries
• Collaboration with health institutions, organizations and scientific/medical partners in the countries of presence was strengthened by signing of 4 new agreements besides of the 26 already active.
In 2024 Eni, within the public-private partnership with the ILO aimed at improving safety and health at work and access to social health protection measures, have conducted a new assessment in the Ivory Cost and continuous interactions with local authorities, aggregators and local farmers has been carried on in Kenya where Eni is developing projects for the production of vegetable oil, not in competition with the food chain, to supply biorefineries.
Regulation of Eni’ s businesses
The Group engages in the exploration and production of oil and natural gas, processing, transportation and refining of crude oil, transport of natural gas, storage and distribution of petroleum products and the production of base chemicals, plastics, and elastomers. By their nature, the Group’s operations expose Eni to a wide range of significant health, safety, security, and environmental risks. Technical faults, malfunctioning of plants, equipment and facilities, control systems failure, human errors, acts of sabotage, attacks, loss of containment and climate-related hazards can trigger adverse consequences such as explosions, blow-outs, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants and pollutants in the air, ground and water, toxic emissions, and other negative events. The magnitude of these risks is influenced by the geographic range, operational diversity, and technical complexity of Eni’s activities. Eni’s future results of operations, cash flow and liquidity depend on its ability to identify and address the risks and hazards inherent to operating in those industries.
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The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, higher-than-average rates of income taxes, additional royalties and taxes on production, environmental protection measures, control over the development and decommissioning of fields and installations, and restrictions on production. A description of the main regulations which impose restrictions and liabilities to the Company’s businesses is provided below.
Overview
The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments.
R egulation of e xplor ation and pr oduction activities
Eni’s e xploration and production acti vities ar e conducted in man y countries and ar e ther ef or e subject to a broad range of legisla tion and r egula tions. These co ve r virtua lly a ll aspects of e xploration and production acti vities , including matters such as license acquisition, production ra tes , ro y a lties , pricing, en vir onmenta l protection, e xport, tax es and f or eign ex change. The terms and conditions of the leases , licenses and contracts under w hich these oil&gas inter ests ar e h el d v ary from country to countr y . These leases , licenses and contracts ar e gener a lly granted b y or entered into with a g o v ernment entity or state compan y and ar e sometimes entered into with pri v ate property o wners . These arrangements usua lly tak e the f orm of licenses or production sharing a g r eements .
Licenses (or concessions) give the holder the right to e xplor e f or and e xploit a commer cial discov er y . Under a license , the holder bears the risk of e xploration, de ve lopment and production acti vities and pro vides the financing f or these operations. In principle, the license holder is entitled to a ll production minus an y production tax es or ro y a lties , w hich ma y be in cash or in-kind. Concession contracts currentl y applied mainl y in Western countries regulating r e lationships betw een States and oil companies with regards to h y drocarbon e xploration and production activit y . Both e xploration and production licenses ar e gener a lly f or a specified period of time (ex cept f or production licenses in the United States w hich remain in effect until production ceases). The term of Eni’s licenses and the e xtent to w hich these licenses ma y be r enewe d v ary b y area. Contractua l clauses go v erning minera l concessions, licenses and e xploration permits r egula te the access of Eni to h y drocarbon r eserves . The compan y holding the mining concession has an exclusive right on e xploration, de ve lopment and production acti vities , sustaining a ll the operationa l risks and costs r e lated to the e xploration and de ve lopment acti vities , and it is entitled to the productions r e a liz ed. As a compensation f or minera l concessions, pa ys ro y a lties on production (w hich ma y be in cash or in-kind) and tax es on oil r eve n ues to the state in accordance with loca l tax legisla tion.
Pro v ed r eserves to w hich Eni is entitled ar e determined b y appl ying Eni’s shar e of production to tota l pro v ed r eserves of the contractua l area, in r espect of the duration of the r elev ant minera l right.
Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in African, Middle Eastern and Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.
Pursuant to these contracts, Eni is entitled to a portion of a field’s r eserves , the sa le of w hich is intended to co ve r e xpenditur es incurred b y the Compan y to d eve lop and operat e the field. The Compan y’s shar e of production v olumes and r eserves representing the Profit Oil includes the shar e of h y drocarbons w hich corresponds to the tax es to be paid, according to the contractua l agreement, b y the nationa l go v ernment on beha lf of the Compan y . Ther ef or e , the Compan y r ecognizes at the same time an incr ease in the taxab le pro f it, through the incr ease in r eve n ues , and a tax expense . Pro ve d r eserves to w hich Eni is entitled under PSAs ar e c alculated so that the sa le of production entitlements should co ve r expenses incurred b y the Group to de ve lop a field (Cost Oil) and r ecognize the Profit Oil set contractua lly (Profit Oil). A similar scheme to PSA a pplies to Service contracts.
In gener a l , Eni is required to pa y income tax on income generated from production acti vities (w hether under a license or PSA). The tax es imposed upon oil&gas production profits and acti vities ma y be substantia lly higher than those imposed on other b usinesses .
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R egulation of the Italian h y drocarbons industry
The matters regarding the effects of recent or proposed c hang es in Italian legislation and regulations or EU dir ecti ves discussed belo w and elsewhere herein are forw ar d-looking statements and involve risks and uncertainties that could cause the actual results to diff er materially f r om those in such forw ar d-looking statements. Such risks and uncertainties include the pr ecise manner of the interpretation or implementation of such legal and regulatory c hang es or proposals , w hic h may be affected b y political and other dev elopments.
Exploration & Production
The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”).
Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession granted by the Ministero dell’Ambiente e della Sicurezza Energetica - MASE or, in some specific cases (e.g. special-status region) by the Region.
The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State (only for initial acreages larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the end of the field economic life.
These provisions are to be coordinated with a new law effective as of February 12th, 2019 (Law 12/2019 — ex “D.L. Semplificazioni”) and further amendments, which requires certain Italian administrative bodies to define and adopt within end September 2021 a plan (PiTESAI) aiming to identify areas suitable for exploration, development, and production of hydrocarbons in the national territory, including the territorial seawaters. The plan has been adopted on December 28th, 2021.
However, PiTESAI has been considered too restrictive by industry operators (including Eni) which lodged an appeal before Lazio Regional Administrative Court – Rome (TAR Lazio). On February 13th, 2024, TAR Lazio ruling declared PiTESAI void.
On October 18th, 2024, a new law was issued (D.L. 153/2024 “Ambiente”) containing some provisions affecting the current hydrocarbon industry regulation. In particular:
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a) |
all the provisions related to PiTESAI are cancelled; |
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new exploration and production onshore-offshore licenses - oil targeted – can no longer be granted. Only the existing licenses can continue/complete their authorized activities; |
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the restriction on upstream activities related to the distance from shoreline or protected marine areas is reduced from 12 to 9 nautical miles; |
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new opportunities to boost gas production are slightly redefined. |
Starting from June 1st, 2019, the above-mentioned law increases 25 times the current annual fee for all licensees (exploration permits and production concessions).
Moreover, the Fiscal decree no. 124/2019, converted into Law 157/2019 established (art. 38) the property tax on marine structures (IMPI) starting from year 2020.
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On March 1st, 2022, the Italian government issued a first Decree (D.L. Energia) aimed at boosting the gas national production by mitigating the effects of PiTESAI. This was converted into law on April 27th, 2022.
A second decree, with the same objectives was issued on December 9th, 2023, providing the ground for new upstream development opportunities converted into law on 2nd February 2024.
As mentioned above (point d), D.L. n.153/2024 “Ambiente” slightly redefines the new opportunities to boost national gas production and removes all the PiTESAI restriction. However, discussions are ongoing between the Ministry and O&G Companies on possible amendments to be introduced.
Royalties . The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 – Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with exemptions only for on shore gas concessions with production lower than 10 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20.06%, with no exemptions).
Gas & P ower
Eni’s wholesale gas and retail gas and power businesses are subject to regulatory risks mainly in Italy’s domestic market. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas and power pricing. Specifically, the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users who are opting for adhering to regulated tariffs until the market is fully opened. Developments in the regulatory framework intended to increase the level of market liquidity or of deregulation or intended to reduce operators’ ability to transfer to customers cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results, and cash flow.
Wholesale gas market in Italy
In the last decade, and even more in the last years, a number of new rules have been introduced in order to improve liquidity and efficient functioning of the Italian wholesale gas market, fostering competition and at the same time improving the system security of supply. Among such new rules, it could be worth mentioning:
– Market based mechanisms for the allocation of storage capacities and of regasification capacities: moving away from the past allocation criteria based on tariffs, new auction mechanisms were implemented that enabled market players to express the market-value of storage and of regasification capacities, while at the same time ensuring the allowed revenues of regulated storage operators and regulated LNG terminal operators by means of specific parallel measures. Thanks to these reforms, higher levels of capacity bookings have become possible for both types of infrastructures, and more LNG deliveries have been attracted in recent years to the country.
– An organized market platform (MGAS) for gas trading and gas balancing market, managed by the independent operator Gestore dei Mercati Energetici (GME) which also acts as a central counterparty, where different market participants (including TSO) can carry out spot and forward transactions at the “Punto di Scambio Virtuale” (PSV – Virtual Trading Point). In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS: such activity is based on the service provided by some liquidity providers, in order to boost liquidity and trading activity on the same exchange, initially for the day-ahead market but with possible future extension to the within-day section and to the forward section of the MGAS.
– A gas balancing regime, entered into force since October 2016 as an evolution of the one already in place and in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by the TSO about the daily gas consumption. The new gas balancing regime provides the incentive for shippers to balance their position via penalizing imbalance prices and at the same time it provides the possibility for shippers to modify intra-day their gas flow nominations and to trade on the market with other shippers and/or with the TSO itself (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities).
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In the context of the energy crisis following the Russian-Ukrainian war, and in the framework of the emergency and transitional regulations at EU level, the Italian competent authorities introduced in 2022 a number of new regulatory measures aimed at ensuring the system security of supply in the short-term and improving it in the longer term, such as specific market based solutions in order to: i) incentivize storage booking and filling and ensure the compliance with the new filling targets set by the European regulation; ii) further facilitate market access to existing regasification capacities; iii) quickly develop new regasification capacities and making them accessible to the market. Such new measures may represent risk factors as well as business opportunities.
Natural gas and electricity prices in the retail sector in Italy - Risks associated with the regulatory powers entrusted to the Italian Regulatory Authority for Energy, Networks and Environment in the matter of pricing to residential customers
Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the ARERA retains a power of surveillance on this matter as per Law No. 481/1995 (establishing the ARERA) and Legislative Decree No. 164/2000. Furthermore, the ARERA is still entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by ARERA beside their own price proposals.
In 2013, a new tariff regime was fully enacted by ARERA targeting Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the ARERA are residential clients. With Resolution No. 196 effective from October 1, 2013, the ARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices at the TTF (Title Transfer Facility) hub in Northern Europe, replacing the then current regime that provided a mix between an oil-based indexation and spot prices.
This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed.
This new gas tariff indexation aiming at safeguarding the households was initially intended to remain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year (as per Law Decree 91/2018), and finally has been prorogated to January 2024. From that point onwards, in Italy households other than vulnerable customers no longer have access to regulated tariffs for gas supplies. Consumers have to choose among the different pricing proposals made by gas selling companies, while only vulnerable customers are entitled to the regulated tariff after January 2024. The ARERA has established that gas selling companies comply with certain requirements about the offerings to customers which include at least two pricing indexations (fixed and variable), both complemented with contractual conditions regulated by the ARERA. Management believes that this development will increase competition in the Italian retail market for selling gas.
Given the context of rising prices that occurred between 2021 and 2022 in gas market, ARERA carried out a series of investigations to evaluate interventions on commodity prices and then decided to switch the gas raw material reference from TTF to PSV, with monthly update of the component covering wholesale natural gas supply costs for regulated customers.
In the electricity market the regulated prices phase out has been effective from July 1, 2021, for small enterprises (enterprise which employs fewer than 50 persons and whose annual turnover and/or annual balance sheet total does not exceed €10 million). For microenterprises (enterprise which employs fewer than 10 persons and whose annual turnover and/or annual balance sheet total does not exceed €2 million) the regulated prices phase out became effective from April 2023, while for non-vulnerable households the deadline was furtherly prorogated to July 2024. The publication of the results of the bidding process took place on February 6, 2024. It will be critical that the manner in which the winners handle clients be properly monitored to avoid unfair practices. The Annual Law for the Market and Competition 2023 provided that vulnerable domestic customers have the right to request, by June 30, 2025, access to the tiered protection service, provided by the awarded operator of the area in which the relevant delivery point is located. On January 22, 2025, ARERA published Resolution 10/2025/R/eel, setting out the implementation procedures, including those concerning the certification of the fulfillment of the vulnerability requirements, as evidenced on its official website. This provision applies to all customers meeting the vulnerability criteria, even if they are served in the liberalized market.
Other regulatory developments in the gas and electric sector in Italy and Europe
Within the scope of the costs and criteria for accessing the main logistic infrastructures of the gas system, the main risk factors for the business are linked to the processes for defining the economic conditions and the rules for accessing transportation, LNG regasification and storage services, which periodically involve all the European countries in which Eni operates. The regulation criteria for gas transportation tariffs have been redefined for the four-year period 2024-2027 in countries such as Italy, France and Belgium, but the re-definition of transportation tariffs criteria at pre-established multi-yearly deadlines, as well as the timely definition on an annual basis of the specific applicable tariff values, is an element that all European countries have in common and which also in the future could have an impact on logistic costs. Changes in rules and tariff levels may also affect the regasification and storage sector representing risk factors as well as business opportunities, also in consideration of the market context following the energy crisis in 2022-2023 and of the need to pursue new solutions to ensure European security and diversification of supplies.
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Moreover, the energy crisis scenario that materialized in 2022 has directed legislators, at European level and in individual countries, towards evolutions - albeit temporary in some cases - of the legislation and of the consequent regulations that can affect the market dynamics, with the aim of containing prices for end customers and improving the security of supplies (e.g. obligations on storage filling trajectories, possible obligations to reduce final consumption).
From a retail perspective, there were a number of various measures adopted at national level. For example, in 2021, the Spanish government in a measure to protect final consumers with low voltage supplies (>10kW power), reduced VAT from 21% to 10% and in 2022 proceeded to lower it further, to 5%. However, while retailers invoice final costumers 5% VAT, distribution companies continue to invoice retailers at the normal 21% rate. The value-added tax rate for energy bills gradually returned to 21% in 2024.
In France, during 2022, electricity and gas regulated tariffs were maintained below cost with a compensation distributed to all suppliers. For 2023, the government increased the frozen regulated electricity and gas tariffs by 15%. Although suppliers will continue to be compensated for 2023, this freeze will continue to have a negative impact on the competitiveness of alternative suppliers. Moreover, the amount of compensation is based on sales prices, which are set by the government below the suppliers' real costs. The ad hoc compensation mechanism introduced in 2022 for apartment blocks has also been extended until the end of 2023 and now covers both electricity and gas consumption. The government has also introduced a new support mechanism for SME electricity consumption throughout 2023. The compensation that suppliers gave to their customers (both condominiums and SMEs) was financed by the government. Therefore, their financial and commercial impact is limited. As far as gas is concerned, regulated tariffs were phased out in 2023. As far as electricity is concerned, in November 2024, the French Regulator (CRE) published an assessment supporting the reasons for the permanence and extension for a further 5 years (until 2030) of the electricity regulated tariff. Shortly after, the French Competition Authority has published an opinion strongly criticizing such decision and denouncing the non-transitory nature of the regulated tariff as well as its negative impact on the competitiveness of the energy market, thus suggesting its timely repeal. The Government has validated the decision for the extension of the regulated tariffs on electricity until 2030 and notified its decision to the European Commission.
In Italy there have been some government interventions to contain retail prices such as:
- cancellation of general system charges in the electricity sector, which in the gas sector even assume negative value;
- strengthening of social bonuses in both sectors;
- decrease of VAT in the gas sector (until December 31, 2023).
Once the energy crisis has been overcome, in the medium term we could expect that gas demand at European level can still be supported by policies aimed at phasing out coal in power generation, in view of the decarbonisation targets. On the other side, with the progressive implementation of the EU Green Deal and of the related ambitious regulatory interventions aimed at decarbonisation, in the coming years the regulation of the gas sector will be affected by potentially significant changes, as a consequence of adjustments in the market design and/or new obligations or constraints on operators in the sector which will accompany the evolution of European regulations, in the context of energy transition and consistently with the decarbonisation objectives of the energy sector (including the related objectives for the development of renewable or decarbonised gases, for the promotion of technologies enabling greater integration between the electricity and gas sectors, for the reduction of methane emissions). These changes will put pressure on the natural gas sector, but on the other side they will likely open up and support new business opportunities in the renewable and decarbonized gases sectors that Eni is ready to pursue.
With regard to power sector, Italian Capacity Market auctions, taken place in November 2019 and in February 2022, allocated capacity with delivery in 2022, 2023 and 2024 to the power producers. During the delivery period the operators selected by the auctions will receive a fixed premium and, in return for this payment, they must i) offer power capacity on energy markets (day- ahead Market and intraday Market) and/or on the dispatching services market; ii) pay the difference between a market reference price and a pre-determined strike price whenever the reference price exceeds the strike price. Eni has been awarded all the capacity offered in the tenders so it will receive a net benefit for its existing Eni group’s power plants during the delivery period (2022, 2023 and 2024) and for a new power plant, that will be built in Ravenna, for a period of fifteen years (starting in 2023).
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At the end of 2023, with a consultation concerning some changes in the Italian Capacity Market Guidelines, Terna (the Italian TSO) started the process towards the Capacity Market’s auctions with delivery 2025, 2026, 2027 and 2028 which it has been completed by Terna with the publication of the final release of the Capacity Market Guidelines and by ARERA with the publication of the auction reserve price and of the other economic variables. The auctions for the delivery years 2025, 2026 and 2027 have been held in November 2024, December 2024 and February 2025, respectively and Eni was awarded a premium for existing capacity of 45.000, 46.000 and 47.000 €/MW/y respectively. There is a risk that the tenders could be canceled due to the administrative appeal filed by a power producer against the tender procedure for the delivery years 2025, 2026 and 2027.
The auction for the allocation capacity with delivery 2028, which will likely take place at the last quarter of 2025, will be affected by increasing competition as a consequence of lower adequacy demand due to the new energy storage capacity, which Terna has procured by the centralized auction system, the so called “MACSE” (MACSE’s auction with delivery 2028 will take place in September 2025, before Capacity Market’s auction with delivery 2028). After 2028, Capacity Market Guidelines shall be completely rebuilt because the current mechanism has been approved by European Commission till December 31, 2028.
Besides, in the next years Italian power market design could significantly be affected by the implementation of European market model. The main innovations concern the introduction of negative prices and the launch of new Intraday Market based on continuous trading and gate-closure close to delivery period (h -1 gate closure), both adopted in the second half of 2021, fostering the cross-border integration of European energy and balancing market (coupling of intraday market, coupling of balancing reserves markets) the implementation of new regulatory provisions concerning the rules which govern the Italian balancing market (the so called “Nuovo Testo Integrato del Dispacciamento” or “Nuovo TIDE”), that has partially entered into force since January 1, 2025 and will be fully implemented from 1.2.2026. Management believes that all these issues will increase competition, in particular in the Italian balancing market which will be also affected by the incentive granted to Terna in order to minimize the balancing market cost (the new scheme for the period 2025-2027 has entered into force since 1.1.2025) and by the entrance of new storage capacity due to the starting of MACSE.
The revision of the European electricity market design carried by the Commission, amended four pieces of legislation throughout Regulation (EU) 2024/1747 and Directive (EU) 2024/1711: the Electricity Directive 2019/944 and Regulation 2019/943, RED II (2018/2001, regarding support schemes for renewables) and Regulation 2019/942 establishing ACER. The revision is more targeted and limited in the changes that were initially anticipated, most notably it conserves the merit-order pricing system, while reinforcing the role of long-term contracts for renewable energy sources, namely two ways CfDs and PPAs. With respect to Capacity Remuneration Mechanisms, the reform recognizes such mechanisms as structural elements of electricity markets, removing the reference to the temporary requirement. It maintains the validity of the Commission approval according to the State Aid Guidelines for ten years, but it charges the Commission with the proposal of a new simplified approval process for new CRMs. Such a process is currently undergoing within the discussion of Clean Industrial State Aid Framework, which is expected to be concluded in the second quarter 2025. Furthermore, the reform introduced several obligations on suppliers. First, an obligation to offer fixed-price, fixed-term contracts, without first guaranteeing the possibility of charging termination fees. Second, it opens the possibility for Member States to require suppliers to cover part of their risk exposure using PPAs. Finally, it establishes the framework for declaring future price crisis, in which case Member States may impose below cost regulated prices, however, conditions are set whereby suppliers must be compensated for selling energy below cost, that there should be no discrimination between suppliers and that all suppliers are eligible to provide below cost offers on the same basis.
At present, the emergency interventions adopted by the government to compensate for the phenomenon of high energy prices are finished. In fact, in addition to the suspension of tax credits for companies (starting from IIIQ2023) and the reinstatement of system charges for the electricity sector (starting from IIQ23), the 5% VAT reduction for gas, which was still in place until IVQ2023, is also terminated. Currently, only a few measures are provided for the most vulnerable households (for example the extraordinary contribution for electricity bonus holders confirmed for IQ24).
Regarding the development of power generation from renewable sources, there are many issues under discussion that could represent risk factors for the sector. Noting the critical issues related to the complexity of the authorization processes, Law No. 201 of Nov. 28, 2023 (Art. 3) extended from 16 to 24 months the provisions of Art. 26 of the Competition Law 2021 (118/2022) on the adoption of one or more legislative decrees on simplification, thus moving the deadline for the exercise of the delegation to August 25, 2024.
In addition, the pending Decree on Eligible Areas and Regional Burden Sharing, the approval of which is desirable in a timely manner to ensure investment in the sector, and the Decree on Incentivizing Renewable Energy Plants Close to Competitiveness (FERX), which confirms the introduction of inflation adjustment mechanisms for tariffs, represents an element of uncertainty for the achievement of the expected energy transition goals.
With regard to the development of offshore power generation, particularly with floating technology, a certain framework of rules is strongly expected with reference to the finalization of maritime spatial planning tools and the publication (by the Ministry of Environment and Energy Security) of the guidelines/vademecum related to the necessary fulfillments for the purpose of initiating the single procedure for the authorization of such plants, as per the provisions of Legislative Decree No. 199 of November 8, 2021 (Art. 23). In addition, a strong impact for pipeline projects will be the definition of the Decree on incentives aimed at innovative plants or those still far from market competitiveness (RES2) and an adjustment of the regulatory framework related to port areas: a first positive step in this direction is represented by the provisions of DL 181/2023, which started the process for the identification of two port areas in the South of Italy for the development of investments of the shipbuilding sector for the production, assembly and launching of floating platforms and related electrical infrastructure.
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Refining and marketing of petr oleum products
Refining . The current regulations on refining activity in Italy provides that Italian administrative bodies authorize plans filed by refining operators intended to set up new processing and storage plants and to upgrade capacity, while all other changes that do not affect capacity can be freely implemented. This regime was streamlined by Law Decree No. 5/2012 (as converted in Law 35/2012) that defined mineral oil processing and storage plants as “strategic installations” that need authorization from the State, in agreement with the local administrations. The Decree introduced a unitized process of authorization that must be finalized within 180 days, subject to compliance with applicable environmental regulations.
Marketing. Following the enactment of the Law Decree No. 1/2012, an increase level of competition in the retail marketing of fuels have been introduced. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012, principals have been allowed to freely supply up to 50% of their requirements. In such case, the distributing companies have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Furthermore, the Budget Law 2018 (Law 205/2017) provides some measures for preventing of tax evasion in the sale of oil products that in the past produced anticompetitive effects on the sector. The law requires the advance payment of Value Added Tax (VAT) on oil products before the extraction from deposits or the sale to consumer.
In 2019, the Law no 157/2019 introduced a set of measures to prevent illegal conduct/practices linked to fiscal fraud for the exchange of products in the retail fuel market. These regulatory initiatives will also address for more competition and efficiency of the sector. In 2020, the Budget Law 2021 (Law 178/2020) extends some measures to prevent fiscal frauds and introduces electronic communication for some information.
Service stations . Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third -party access to unused storage capacity for petroleum products. Subsequently, various regulations have been enacted in Italy with the aim of improving network efficiency, modernizing service stations and opening up the market. Currently, all service stations are provided with self-service equipment and the sale of non-oil products has been broadly introduced by local administrative bodies.
Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside urban areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations, which might limit the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours.
In 2023, the Law Decree 5/2023 provided measures for the transparency and control of the prices of the road transport sector fuels. Ministry of Industry and Made in Italy calculates and publishes on its website: (i) the arithmetic average, on a regional basis, of the prices communicated by fuel sellers operating on the service stations located off highway and (ii) the arithmetic average, on a national basis, of fuel prices communicated by operators located in highway. Subsequently, pursuant to the abovementioned Law Decree 5/2023, the Ministerial Decree of March 31, 2023 provided the rules for the exposition of the relevant average reference prices for the fuel sellers. With ruling n. 1806 dated 23 February 2024, the Consiglio di Stato declared the illegitimacy of the provision contained in art. 7 of the Ministerial Decree of March 31, 2023, which established the obligation for fuel distributors to display on a daily basis the average price.
Law no. 124/2017 aims to promote the structural reorganization of the fuel distribution network also in order to increase competition and efficiency. The law requires the closure of fuel stations that are incompatible with road safety regulations and environmental streamlining procedures for the decommissioning. The Law Decree 76/2020 extended the simplified procedures for the fuel station decommissioning by 2023.
The regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/UE (AFID) on alternative fuel infrastructures – has introduced minimum requirements for the construction of infrastructure for the development of alternative fuels to mitigate the environmental impacts of the transport sector.
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Regulation (EU) 2023/1804 (AFIR) on the deployment of alternative fuels infrastructure repeals Directive 2014/94/EU and establishes, inter alia, mandatory national targets leading to the deployment of sufficient alternative fuels infrastructure in the Union for road vehicles, trains, vessels and stationary aircraft. It also lays down common technical specifications and requirements on user information, data provision and payment requirements for alternative fuels infrastructure. It applies from April 2024.
The 2021 Budget law (Law 178/2020) introduced the obligations for concessionaires’ highway stations to provide electric charging points (up to 50 kW) within their own area of competence. Finally, the Law Decree 76/2020 introduced simplified procedures for the installation of electric charging points and stations and incentives to be recognized by local authorities (i.e. tax reduction or exemption for public land use). With the provisions of the Law Decree 77/2021 the installation of public access electric vehicle charging infrastructure is not subject to the issuance of a building permit and is considered free construction activity.
Moreover, the annual Competition Law for 2022 (legislative decree No 118/2022) provides for competitive, transparent and non-discriminatory procedures for the selection of the operators responsible for the installation of electric recharging points on the highways network (fast and ultra-fast).
Among the measures introduced to spread sustainable mobility in Italy, starting from the 2019 Budget law the so-called ecobonus contributions are in place for the purchase of low-emission vehicles. The DPCM of 20 May 2024 remodulates the resources allocated to incentives, their subdivision by vehicle category and their amount.
Also the Law Decree No 17/2022 provided a new incentive framework (from 2022 to 2030) for, inter alia, purchasing low-emission vehicles.
With other several Acts (Law Decree 34/2020,104/2020, Legislative Decree 187/2021), new measures and extension of existing provisions for sustainable mobility have been adopted in order to decarbonize the transport sector, through incentive mechanisms for low emission vehicles.
Renewables uptake in the transport sector. In order to support the achievement of the renewables target in the transport sector established by the EU and national laws, the Ministerial Decree of March 2, 2018, provides the legislative framework to incentivize the production of both biomethane and other advanced biofuels to be used in the transport sector.
The Decree provides incentives for plants starting operations between 2018 and 2022 and for plants that are converted to biomethane production.
The incentive consists in an allocation of a Certificate (CIC) for every 10 Gcal of biomethane produced. The certificate has a market value since fossil fuel marketers have to sell a minimum percentage of biofuels annually, for which they receive the same Certificates.
In order to access to incentives, producers must comply with legal and technical regulations governing the quality and certification of the produced biomethane, verified by the competent Authority (Gestore dei Servizi Energetici, GSE).
These measures aim to favor advanced biofuels production through the valorization of waste, notably of agricultural and farm/zootechnical waste.
Regarding biomethane, the incentive scheme has been replaced, following approval by the European Commission, by the Ministerial Decree of September 15, 2022. The mechanism consists of an operating aid – in the form of a CfD linked to the market value of natural gas and of the biomethane Guarantee of Origin, auctioned through a competitive procedure – and an investment aid – covering up to 40% of the eligible investment costs and funded by the NRRP. The mechanism differentiates between new plants and refurbishments and between agro or waste-based plants. Law 136/2023 introduced an inflation-linked indexation for the base tariffs set by MD September 15, 2022. In every auction, tariffs will be updated following the total inflation accrued between November 2021 and the auction’s opening month.
At the end of 2020, the Ministerial Decree of October 2014 on conditions, criteria and implementation of biofuels (conventional and advanced) obligations for suppliers was modified. Among the novelties, were introduced the increase of the overall 2021 target from 9% to 10% and a new additional target of 0,5% of advanced liquid biofuels to be mandatory blended by each supplier (outside the incentive scheme provided by DM 2018).
Law 238/2021 (European Law 2019-2020) confirmed the GHG saving requirement (6%) previously set for the year 2020 only and revised the calculation methodology for the current 7% maximum threshold for food-and-crop derived biofuels.
The Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources has been transposed with the Legislative Decree No 199/2021. The Decree set targets for RES penetration in the transport sector (16%) and introduced some innovations in the transport sector’s regulatory framework: i) palm-oil, PFAD and EFB based fuels cannot contribute to RES targets in the transport sector. However, they can be taken into account if certified as low-ILUC risk. The contribution of PFAD and EFB can be counted to 1° January 2026, as set by the Law Decree 202/2024. ii) biomethane support schemes – as defined by the Ministerial Decree of March 2, 2018 – have been updated iii) Recycled Carbon Fuels count as renewable towards the general target, on the basis of the EU delegated acts (Delegated Regulation 2023/1185) and iv) confirms the use of some wastes as feedstock for the production of biofuels.
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Law Decree No 17/2022 (converted into Law No 34/2022) further developed the regime set in Legislative Decree No 199/2021 (transposing Directive (EU) 2018/2001 - REDII), introducing an obligation for the fuels suppliers to supply pure bioliquids to be used in the transport sector (additional to the existing obligation on biofuels). The measure requires a mandatory cumulative share of at least 300 ktonnes released in 2023, with volumes increasing by 100 ktonnes per year and reaching 1 million tonnes per year from 2030 onwards.
The measure also incentivizes, by means of investment aid, existing refineries conversions aimed at producing the above- mentioned pure biofuels. The incentive is financed by the Fund for the decarbonisation and green conversion of existing refineries, established under the Ministry of environment and energy security with an overall budget of € 260 million for the three- year period 2022-24. The Ministerial Decree of June 17, 2024 sets the criteria and conditions for assigning the resources, with the following directorial decree n. 86 of December 17, 2024 providing the operative rules.
Provisions regarding both supply obligation and reconversion funding have been implemented by Decree No 107/2023 and No 343/2023 of the Minister of the Environment and Energy Security.
In particular, the methods and criteria for implementing supply obligations for the period 2023-2030 were regulated by Ministerial Decree No 107/2023 which also defines the trajectories for achieving all biofuels targets (traditional, advanced, pure biofuel and including the specific biomethane subtargets). The Decree No 107/2023 was then integrated by the Ministerial Decree No 343/2023. To comply with the national supply obligations, biofuels blended, with a minimum rate of 20%, are assimilated to the pure form only for a transitional period 2023-2024.
As for feedstock, with Ministerial Decree of August 8, 2024 new categories of feedstock to produce double counting biofuels have been introduced in Annex VIII of Decree 199/2021, transposing the reviewed Annex IX of the REDIII. In particular, intermediate crops and crops grown on severely degraded lands are included in Part A (advanced) when used for SAF production or in Part B for the other cases. Moreover, with the Ministerial Decree of August 7, 2024, the National Certification System for the Sustainability of Biofuels has been established. This system also includes the certification of renewable fuels of non-biological origin and recycled carbon fuels. The decree establishes criteria and procedures for the certification of biofuels and other included fuels aims and ensure the sustainability of biofuels used in Italy.
Law Decree 63/2024 (DL Agricoltura) expanded the self-consumption regime for biomethane consumers. Self-consumption – subject to operating rules still to be drafted by the GSE after a public consultation - is no more strictly limited to on-site consumption of self-produced biomethane but it can also include on-site consumption of biomethane produced on the same site by a third subject or produced in a different site by a third subject, under a specific contractual agreement covering the biomethane and – with an average price equal to 0 - the corresponding Guarantees of Origin.
In June 2024 Italy submitted its final updated NECP, a strategic plan where EU member States deliver on their commitments and reach the 2030 targets as set by the EU Fit for 55% legislation and REPowerEU and in particular the provisions of Directive 2413/2023 (REDIII), currently under the process of national transposition.
Recent EU legislation promotes alternative fuels specifically in aviation and maritime transports. The ReFuelEU Aviation regulation (2405/2023) provides EU-wide blending targets for sustainable aviation fuel (SAF) (), from 2025 to 2050. The Regulation’s provisions apply from 1 January 2024, with the exception of the main obligations that start from 1 January 2025. The FuelEU Maritime regulation (1805/2023) introduces progressive GHG intensity reduction requirements for the energy used on board by ships from 2025 to 2050. The Regulation’s provisions apply from 31 August 2024 for the monitoring provisions and from 1 January 2025 for all others measures.
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At the EU level, Regulation (EU) 2023/1115 on Deforestation (EUDR) came into force on June 29, 2023. This regulation imposes strict supply chain due diligence (DD) and reporting obligations on specific commodities and products, such as palm oil and its derivatives, imported into and exported out of the EU. Following the adoption of Regulation (EU) 2024/3234, the application date of the EUDR has been postponed by 12 months (December 30, 2025, for medium and large companies, and June 30, 2026, for micro and small enterprises).
On October 15, 2024, Legislative Decree 147/2024 came into force, amending Legislative Decree 47/2020 by updating the national regulations on greenhouse gas emission allowance trading to incorporate Directive (EU) 2023/959 revising the ETS Directive and Directive (EU) 2023/958 on the ETS system for aviation. Specifically, the introduced changes concern the gradual elimination of free allowances for the aviation sector, the inclusion of the maritime sector in the ETS mechanism, and the establishment of a new parallel ETS system (ETS II) involving commercial buildings, road transport, and small industries. Consequently, under the ETS II, from January 1, 2025, the companies that place into market the fuels used in road transport must have an authorization to emit GHG.
National Recovery and Resilience Plan (NRRP – Piano Nazionale Ripresa e Resilienza). The NRRP, as approved by the Italian Parliament in April 2021, includes relevant proposal for the R&M business area. It allocates €230 million to develop at least 40 recharging stations based on hydrogen for light and heavy vehicles by 2026. It also assigns €741 million for the installation of charging infrastructures for electric vehicles, envisaging the entry in operation, by 2025, of a minimum of 7.500 rapid recharging stations along freeways (at least 175 kW) as well as 13.000 rapid recharging stations in urban areas (at least 90 kW).
Petroleum product prices. Petroleum products’ prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Economic Development; such recommendations are considered by service station operators in establishing retail prices for petroleum products.
Compulsory stocks. As a member of the European Union and the International Energy Agency (IEA), Italy has the obligation to maintain oil product stocks to ensure supplies in case of a national or international crisis, in accordance with Directive UE 2009/119/CE. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC. Legislative Decree no. 249 dated 31 December 2012 introduced the new procedures to maintain and manage the petroleum emergency stocks and provided for the creation of the Organismo Centrale di Stoccaggio Italiano (OCSIT), under the surveillance of the Ministry of Environment and Energy Security.
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Italy’s compulsory stocks level must be at least 90 days of net import, including a 10% deduction for minimum operational requirements. Compulsory stocks are determined each year by a decree of the Minister of Environment and Energy Security defining also the compulsory stocks to be held by each economic operator according to previous year domestic consumption data.
As of December 31, 2024, Eni owned 4.3 mmtonnes of oil products inventories, of which 2.9 mmtonnes as “compulsory stocks”, 1.3 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.1 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (30%), light and medium distillates (39%), refinery feedstock (21%), fuel oil (8%), and other products (2%) were located throughout the Italian territory both in refineries (85%) and in storage sites (15%).
Competition
Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts do not infringe the Treaty. In addition, the burden of pro ving an infringement of Article 101(1) or of Article 102 of the Treaty sha ll rest on the party or the authority a lleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:
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requiring that an infringement be brought to an end; |
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ordering interim measur es; |
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accepting commitments; and |
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imposing fines, periodic penalty payments or any other penalty provided for in their national law. |
National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the “EEA Agreement”), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers.
Pr opert y, plant and equipment
Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. The Company enters into operating lease contracts with third parties to hire plant and equipment such as floating production and storage offloading vessels (FPSO), drilling rigs, time charter, service stations and other equipment. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’ worldwide proved oil&gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas.
Eni SpA is the parent company of the Eni Group. As of December 31, 2024, there were 479 subsidiaries and 153 associates, joint ventures and joint operations that were accounted for under the equity or cost method or in accordance to Eni’s share of revenues, costs and assets of the joint operations calculated based on Eni’s working interest. Information on Eni’s investments as of December 31, 2024 is provided in the “Item 18 - Notes to the Consolidated Financial Statements”.
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Item 4A. UNRESOLVED STAFF COMMENTS
None.
Item 5. OPER A TING AND FINANCIAL REVIEW AND PROSPECTS
This section is the Compa n y ’ s ana l ysis of its financial per f ormance and of significant t r ends that may affect its futu r e per f ormance. It should be r ead in conjunction with the Consolidated Financial Statements and r elated Notes the r eto in c luded in Item 18 . The Consolidated Financial Statements a r e p r epa r ed in accordance with International Financial R epo r ting Standards as issued by the IAS B .
This section contains f or w ard-looking statement s , w hi c h a r e subject to risks and unce r taintie s . For a list of impo r tant f acto r s that could cause actual r esults to differ material l y f r om those e xp r essed in the f or w ard-looking statement s , see the cautiona r y statement concerning f or w ard-looking statements on pa g e ii.
Basis of preparation
Effective October 1st, 2024, the management has established a new organizational set-up of the Company articulated on three business groups:
i) “Chief Transition & Financial Officer” focused on maximizing the value of the businesses relating to new energies, renewables and biofuels. Eni’s subsidiaries Enilive and Plenitude report to the manager in charge of this businesses group; therefore results of the two subsidiaries have been aggregated in this item;
ii) “Global Natural Resources” designated to maximize the value of the Company’s assets in the oil & gas value chain;
iii) “Industrial Transformation” designated to accomplish the restructuring of the chemicals and the oil downstream businesses.
Based on changes in the attribution of profit responsibilities, Eni’s reportable segments have been redefined as follows:
- Exploration & Production, which is now integrating results of the E&P operating segment with those of activities of marketing, shipping and trading of oil&products to enhance synergies and to fully capture margins across the value chain;
- Global Gas & LNG Portfolio and Power, which is now integrating results of the operating segment Global gas, power and LNG portfolio with those of the activities of managing and upgrading the fleet of gas-fired power plants which are ancillary to gas and power supply and trading activities;
- Enilive: this operating segment engages in the manufacturing of biofuels at the operated Italian plants of Venice and Gela and through the Chalmette JV in the USA, whilst advancing expansion plans in EU, South-East Asia and US. It manages a network of refueling service stations in Italy and selected European markets, also providing services and non-fuel products to drivers. It also markets fuels through other channels (resellers, ports, airports, etcetera);
- Plenitude engages in the activities of retail marketing of gas, power and related services, As of December 31, 2024, Eni’s customer base was over 10 million retail points of delivery (gas and electricity) in Europe (of which 8 million were in Italy). It engages in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore), which comprises building, commissioning, and managing renewable energy producing installations and wholesale marketing of electricity and managing and expanding a network of charging stations for electric vehicles distributed throughout the European territory, in particular in Italy;
- Refining and Chemicals: this reportable segment aggregates the results of the refining business and those of the chemicals business managed by Eni’s subsidiary Versalis. The Refining business engages in refining crude oil to manufacture fuels and in wholesale marketing activities, which mainly consist of the inter-company supply of refined products to the Group subsidiary Enilive and in sales to large accounts. The Chemical business engages in the production and marketing of basic petrochemical products, plastics and elastomers. Versalis is developing the business of manufacturing chemical products from renewable raw materials, bioplastics and bio-based products through the recently acquired subsidiary Novamont. Activities are concentrated in Italy and in Europe. The results of operations of the Refining business and the Chemical business have been combined in a single reporting segment because the businesses exhibit similar economic characteristics;
- Corporate and Other activities: include the costs of the main business support functions, as well as, the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind and of the businesses engaged in developing the projects for CO 2 capture and storage and/or utilization and agricultural hubs to ensure supply of bio-feedstock to the Group’s biorefineries.
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The re-segmentations of the operating profit for the 2023-2022 years published in the Annual Report on Form 20-F 2023 are disclosed below:
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2022 |
2023 |
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(€ million) |
As published |
As restated |
As published |
As restated |
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Operating profit (loss) |
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17,510 |
17,510 |
8,257 |
8,257 |
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of which: |
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E&P |
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15,963 |
16,158 |
8,549 |
8,693 |
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GGP |
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3,730 |
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2,431 |
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Enilive, Refining and Chemicals |
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460 |
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(1,397) |
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- Enilive |
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416 |
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665 |
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- Refining |
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930 |
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(657) |
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- Chemicals |
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(886) |
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(1,405) |
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Plenitude & Power |
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(825) |
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(464) |
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- Plenitude |
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(1,326) |
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(659) |
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- Power |
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501 |
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195 |
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GGP & Power |
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4,231 |
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2,626 |
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- GGP |
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3,730 |
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2,431 |
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- Power |
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501 |
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195 |
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Enilive and Plenitude |
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(450) |
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(74) |
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- Enilive |
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876 |
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585 |
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- Plenitude |
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(1,326) |
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(659) |
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Refining and Chemicals |
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(606) |
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(2,121) |
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- Refining |
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280 |
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(716) |
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- Chemicals |
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(886) |
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(1,405) |
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Corporate and other activities |
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(1,956) |
(1,961) |
(943) |
(948) |
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Impact of unrealized intragroup profit elimination |
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138 |
138 |
81 |
81 |
2024 trading environment
The 2024 trading environment was mixed. The price of the Brent benchmark crude oil, the main driver of the Group’s results of operations, was 80.76 $/bbl on average in the year and was fractionally lower compared to 2023, down by 2%. After favorable market trends in the first half 2024 with Brent averaging almost 85 $/bbl, crude oil prices have gradually weakened throughout the second half as uncertainties prevailed among financial operators –about a possible supply build-up. Chinese demand failed to match expectations of a more robust recovery, dragged down by a downturn in the construction sector and muted private sector consumption, while industrial activity continued to contract in Europe. At the same time, production grew noticeably in USA and Canada. The perceived deterioration of market fundamentals and uncertainties about the tapering of the voluntary production cuts made by countries of the OPEC+ alliance triggered a price correction driven by a sell-off of future contracts by financial operators. The Brent price bottomed in the month of September at around 70 $/bbl and then regained part of the losses due to little evidence of a build-up in global commercial inventories of oil and products and continuing commitment to support prices on the part of countries in the OPEC+ alliance by extending their voluntary production cut and by maintaining compliance with the agreed production ceilings.
98
The outlook for 2025 remains uncertain due to projections of weak economic growth in China and Europe, the strength of the USD, which reduces the purchasing power of non-USD importing countries, forecast of continued production growth in the USA and Canada and the underlying risk of non-compliance with production quotas by OPEC+ countries. Also, the recently enacted US administration import tariffs on multiple commercial partners are expected to add uncertainty to the outlook for oil prices, because tariffs on imports of goods can interfere with international trade flows thus negatively affecting global macroeconomic growth and demand for crude oil. Factoring in the described trends, the management has downgraded its crude oil forecast to 75 $/bbl for the year 2025. As discussed in Item 3-Risk factors, the Group results of operations are exposed to the variability of crude oil prices and the other scenario variables described herein.
In 2024, natural gas prices at the main European hubs declined by 14% compared to 2023 due to an oversupplied market reflecting continuing production gains in USA and a ramp-up in liquefaction capacity to export LNG overseas, weak economic growth in the Eurozone and China and rising competition from renewables. Reduced LNG consumption in China have had Chinese buyers reroute LNG cargoes to Europe, further depressing spot prices. However, prices have staged a recovery in the closing part of 2024 and in the initial part of 2025 due to a stronger start of the heating season reflecting more rigid whether conditions in the Northern Hemisphere than in the recent past, and the significant underperformance of renewables installations in Europe, leading to a fast depletion of inventories.
Crack spreads of refined products, mainly gasoil, and margins of petrochemicals products have been negatively and significantly affected by the European economic downturn and low growth of the Chinese economy, as well as the disadvantages of the European manufacturing sector due to comparatively higher expenses for feedstock and energy inputs, and environmental charges than in competing geographies and lack of scale.
|
|
2024 |
|
2023 |
|
2022 |
|
Average price of Brent dated crude oil in U.S. dollars (1) |
80.76 |
|
82.62 |
|
101.19 |
|
Average price of Brent dated crude oil in euro (2) |
74.64 |
|
76.43 |
|
96.09 |
|
Average EUR/USD exchange rate (3) |
1.082 |
|
1.081 |
|
1.053 |
|
PSV (4) |
36 |
|
42 |
|
122 |
|
Standard Eni Refining Margin (SERM) (5) |
5.1 |
|
8.1 |
|
8.1 |
|
Euribor - three month euro rate % (3) |
3.57 |
|
3.43 |
|
0.35 |
|
(1) |
Price per barrel. Source: Platt’s Oilgram. |
|
(2) |
Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB). |
|
(3) |
Source: ECB. |
|
(4) |
In €/MWh natural gas prices at the main European hubs. Source: ICIS European Spot Gas Markets |
|
(5) |
In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. From January 1, 2024, the benchmark refining margin has been calculated based on a new methodology which considers a revised industrial set-up in connection with the planned restructuring of the Livorno plant and implemented optimizations of utilities consumption, as well as current trends in crude supplies building in a slate of both high-sulfur and low-sulfur crudes. |
99
K e y consolidated financial data
|
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
|
(€ million) |
||||
|
Sales from operations |
|
|
88,797 |
|
93,717 |
|
132,512 |
|
Operating profit (loss) |
|
|
5,238 |
|
8,257 |
|
17,510 |
|
Adjusted operating profit (Non-GAAP measure) (1) |
|
|
10,348 |
|
13,805 |
|
20,386 |
|
Net profit (loss) attributable to Eni |
|
|
2,624 |
|
4,771 |
|
13,887 |
|
Adjusted net profit (Non-GAAP measure) (1) |
|
|
5,257 |
|
8,322 |
|
13,301 |
|
Net cash provided by operating activities |
|
|
13,092 |
|
15,119 |
|
17,460 |
|
Capital expenditures |
|
|
8,485 |
|
9,215 |
|
8,056 |
|
Acquisitions |
|
|
2,593 |
|
2,592 |
|
3,311 |
|
Disposal of assets, consolidated subsidiaries and businesses |
|
|
2,788 |
|
596 |
|
1,202 |
|
Shareholders’ equity including non-controlling interest |
|
|
55,648 |
|
53,644 |
|
55,230 |
|
Finance debt (including lease liabilities) |
|
|
36,801 |
|
34,065 |
|
31,868 |
|
Net borrowings excluding lease liabilities (1) |
|
|
12,175 |
|
10,899 |
|
7,026 |
|
Net profit (loss) attributable to Eni fully diluted |
(€ per share) |
|
0.78 |
|
1.40 |
|
3.95 |
|
Dividend per share |
(€ per share) |
|
1.00 |
|
0.94 |
|
0.88 |
|
Ratio of finance debt (including lease liabilities) to total shareholders’ equity |
|
|
0.66 |
|
0.63 |
|
0.58 |
|
Ratio of net borrowings excluding lease liabilities to total shareholders’ equity (leverage) (1) |
|
|
0.22 |
|
0.20 |
|
0.13 |
|
|
|
|
(1) |
For a discussion of the usefulness and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see – "Non-GAAP measures of performance" and "Liquidity and capital resources – Financial Conditions" below. |
Executive summary
Against the trading environment described above, the Group’s 2024 performance was solid, albeit lower than in 2023, thanks to the consistent execution of our strategy of growing the business and unlocking the intrinsic value of our activities related to the transition, while we have been speeding up the restructuring and transformation of our loss-making chemicals segment and of the oil refining business affected by global overcapacity and competitive pressures.
The Group’s 2024 results of operations were mainly driven by the E&P operating segment, which in a 80-dollar environment for the Brent benchmark crude oil has been capable of delivering significant profitability and cash flow, also boosted in 2024 by a 3% production increase to 1,572 million boe/d.
The wholesale activity of marketing gas, LNG and power, managed by the GGP operating segment, has proven the resiliency of its business model based on the continued optimization of the asset portfolio (supply contracts, access to transport and storage infrastructures, trading operations, integration with the E&P to market equity LNG), which was able to deliver positive results also in a trading environment of weak natural gas prices and reduced volatility.
Eni’s businesses related the energy transition are managed by Plenitude, engaged in the production of electricity from renewable sources and the marketing of gas and electricity to residential customers and the development of a network of recharges for electric vehicles “EV”, and by Enilive, engaged in the manufacturing of biofuels complying with EU regulations for green Taxonomy and the managing of a network of service stations to markets fuels and services for road transport. Both businesses reported steady results notwithstanding an adverse trading environment. One of the main strategic developments in 2024 was the finalization of investments by private equity funds in both abovementioned Eni’s subsidiaries, as part of our satellite model designated to attract pools of aligned capital to boost the independent growth and financial autonomy of several of our businesses, at the same time unlocking intrinsic value to the parent company.
A first transaction was carried out with Energy Infrastructure Partners “EIP”, a private equity fund, who subscribed two separate tranches of new shares issued by Plenitude respectively in March and November 2024, acquiring a combined noncontrolling interest of about 10% post-closing for cash proceeds of about €0.8 billion to Eni, which retained control of the subsidiary. The first transaction for €0.6 billion was finalized in 2024; the second one for about €0.2 billion was finalized at the end of March 2025.
Another important development of the year was an investment of about €2.97 billion made in October 2024 by private equity fund Kohlberg Kravis Roberts & Co. Partners LLP (“KKR”) into Enilive through subscription of newly issued shares of Enilive and the purchase of an interest from Eni resulting in KKR acquiring a 25% noncontrolling interest in Enilive post transaction, with the Eni retaining control of the subsidiary. The deal was completed in March 2025.
In February 2025, KKR agreed to purchase a further 5% interest in Enilive bringing its total ownership interest to 30% on the same terms and conditions as the transaction agreed in October 2024. The transaction is expected to close shortly.
The deals of Enilive and Plenitude were based on an implied cumulative enterprise value of about €21 billion for both the Eni’s subsidiaries.
100
Neither transaction has any effect through profit and loss because there is no change of control of the interested subsidiaries. Any differences between the book value of the shareholding recognized to the investors and the cash collected by Eni are recognized through retained earnings. In 2024, the Group financial position benefitted of only the cash-in from the first tranche of the EIP/Plenitude transaction for €0.6 billion.
R epo r ted earnings
In 2024, the Group earned €5.24 billion of reported operating profit, translating to net profit pertaining to Eni of €2.62 billion after interest expense, income from investments and taxes. Both results were lower compared to 2023 due mainly to reduced operating results down by approximately €3 billion due to the E&P operating segment mainly on the back of lower gas prices, and the GGP segment reflecting an outsized performance in 2023 helped by the favorable effects of one-off items due to contract renegotiations and a positive outcome of an arbitration procedure with a customer. Lower income taxes, but higher interest expense and reduced results at equity accounted entities translated into an overall improvement of about €0.9 billion, thus bringing the year-on-year change in net profit attributable to Eni’s shareholders to down €2.1 billion.
NON-GAAP measures of performance: adjusted operating profit and adjusted net profit
Adjusted operating profit (loss) and adjusted net profit (loss) are calculated by excluding from the reported results inventory holding gains or losses and identified gains and losses or extraordinary items (pre and post-tax, respectively) that in our view do not reflect business base performance.
Extraordinary items recognized in 2024 mainly comprised asset impairments at the E&P operating segment (around €2.2 billion pre-tax), losses at fair-valued derivatives (€1.1 billion), environmental provisions (€0.9 billion), impairment losses at other businesses (€0.7 billion) , a gain on a favorable transaction with another Italian operator for sharing environmental cleanup and remediation expenses at a number of Italian dismissed industrial sites jointly managed in the past (€0.87 billion), gains on disposal of assets and investments (€0.72 billion) and a revaluation of previously devaluated deferred tax assets at Italian subsidiaries (€1.1 billion) for an overall net positive adjustment of €2.63 billion. Those same items categories amounted to a net loss of €3.55 billion in 2023.
Management is excluding the above mentioned identified items from reported results when evaluating the Group and each operating segment’s underlying performance. By doing so, the management is determining and utilizing non-GAAP measures of financial performance, defined as “adjusted operating profit” and “adjusted net profit”. Management believes that those non-GAAP measures of financial performance furnish valuable information to investors and users of financial reports because the identified items excluded from the GAAP measures to determine the adjusted results are intrinsically difficult to forecast and are influenced by several factors like possible permitted accounting choices, the modalities whereby assets are increased by organic development vs acquisitions, evolution in the operating environment influencing the timing of recognition of expenses and provisions, and managerial decisions and judgement. Furthermore, we understand that those non-GAAP measures are utilized by other oil&gas companies, which are removing the same items as the ones identified by our Company from reported results, and this facilitate comparison of performances across the industry. Finally, we note that we have consistently applied those adjustments to our results for several reporting years, by this way preserving comparability of our performance as measured in terms of adjusted results over time.
A brief reconciliation of Group’s reported results vs adjusted results for the three-year period 2022-2024 is provided below:
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(€ million) |
||||
|
GAAP operating profit (loss) |
|
5,238 |
|
8,257 |
|
17,510 |
|
Inventory holding (gains) and losses |
|
434 |
|
562 |
|
(564) |
|
Identified net (gains) losses |
|
4,676 |
|
4,986 |
|
3,440 |
|
Total net items in operating profit |
|
5,110 |
|
5,548 |
|
2,876 |
|
Non-GAAP operating profit (loss) |
|
10,348 |
|
13,805 |
|
20,386 |
|
GAAP net profit (loss) |
|
2,624 |
|
4,771 |
|
13,887 |
|
Inventory holding (gains) and losses, post tax |
|
308 |
|
402 |
|
(401) |
|
Identified net (gains) losses, post tax |
|
2,325 |
|
3,149 |
|
(185) |
|
Total net items in net profit |
|
2,633 |
|
3,551 |
|
(586) |
|
Non-GAAP net profit (loss) |
|
5,257 |
|
8,322 |
|
13,301 |
101
The Group underlying performance – i.e. excluding the identified gains and losses as well as the inventory holding profit – was an adjusted operating profit of €10,348 million compared to €13,805 million in 2023, down by approximately 25% or €3.5 billion.
This performance reflected the lower contribution by (i) the E&P segment (down by €0.9 billion) due to a reduction in natural gas prices in all the geographies, thus impacting realizations on equity production; ( ii) the GGP and Power segment (down by €2.2 billion) which in 2023 had benefitted from significant gains on contractual one-offs and a favorable arbitration outcome and; (iii) the underperformance of the Chemical business (with a loss of €0.8 billion, €0.2 billion worse than in 2023) due to a slowdown in demand and cost disadvantages, and finally a significantly deteriorated refining scenario leading to lower adjusted operating profit at the Refining business (down by €0.33 billion). These negative trends were offset by a positive performance at Enilive and Plenitude.
Excluding identified items and the inventory evaluation profit, adjusted net profit for 2024 was €5,257 million, a €3,065 million decrease compared to €8,322 million reported in 2023. The result was driven by a lower operating performance, partly offset by higher contribution from equity accounted entities. The Group tax rate, excluding identified items (see paragraph “Taxes” of this item), was 52% and was higher than in 2023 (44% in 2023) because of the prevailing effect of the Upstream high taxation in foreign jurisdictions and a reduced pre-tax contribution of other sectors generally operating in OECD jurisdiction with lower tax rates than E&P.
Breakdown of identified items
In 2024, identified items amounted to a total positive adjustment of €5,110 million in operating profit and of €2,633 million in net profit, including an inventory pre-tax loss of €434 million (€308 million post-tax) relating to oil and refined products. Those items mainly comprised:
(i) impairment losses of €2.2 billion in the Exploration & Production segment mainly driven by the alignment of disposal groups to their fair values and downward reserves revisions at other oil&gas assets;
(ii) the mark-to-market of commodity derivatives lacking the formal criteria to be classified as hedges under applicable accounting standards (net loss of €1.1 billion);
(iii) the write-down of capital expenditures made for compliance and stay-in-business at certain CGUs with expected negative cash flows in the Refining business (€0.3 billion) and in the chemicals business (€0.2 billion), as well as an impairment charge of a liquefaction plant in the GGP segment to reflect assumptions of lower utilization rates in the medium term (€0.2 billion);
(iv) a gain on a favorable transaction with an Italian operator for the sharing of environmental remediation expenses at several decommissioned Italian industrial sites jointly managed in the past (€0.87 billion),
(v) environmental and remediation provision of €0.9 billion which were recorded for about €0.4 billion by our subsidiary managing environmental remediation activities at dismissed Italian plants, €0.25 billion by the refining business and €0.2 billion by the chemicals business in connection with the recognition of environmental obligations as a result of past activities, soil and groundwater characterization and plant restructuring and because expected future expenses could be reliably estimated;
(vi) write-off of an exploration project due to geopolitical constraints of €0.14 billion.
These items were partly offset by gains in relation to the divestment of upstream assets (€0.4 billion), to the business combination with Ithaca Energy (€0.1 billion) and the sale of a 10% stake in Eni’s Saipem joint venture (€0.2 billion). Furthermore, tax item included about €1.1 billion of write-up of deferred tax assets due to improved profitability prospects of Italian subsidiaries, mainly Plenitude and Enilive.
102
For a breakdown of identified gains and losses by business segments, refer to the reconciliation of the Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS, in the Operating profit (loss) by segment section.
The table below sets forth details of the identified gains and losses included in the net results during the period presented.
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(€ million) |
||||
|
Identified gains and losses of operating profit (loss) |
|
4,676 |
|
4,986 |
|
3,440 |
|
- environmental charges |
|
900 |
|
648 |
|
2,056 |
|
- gains on an environmental agreement with an Italian operator |
|
(869) |
|
|
|
|
|
- impairment losses, net |
|
2,900 |
|
1,802 |
|
1,140 |
|
- impairment of exploration projects |
|
140 |
|
|
|
2 |
|
- net gains on disposal of assets |
|
(38) |
|
(11) |
|
(41) |
|
- risk provisions |
|
44 |
|
39 |
|
87 |
|
- provision for redundancy incentives |
|
73 |
|
158 |
|
202 |
|
- effects of fair-valued commodity derivatives |
|
1,056 |
|
1,255 |
|
(389) |
|
- exchange rate differences and derivatives |
|
258 |
|
(16) |
|
149 |
|
- other |
|
212 |
|
1,111 |
|
234 |
|
Net finance (income) expense |
|
(155) |
|
30 |
|
(127) |
|
of which: |
|
|
|
|
|
|
|
- exchange rate differences and derivatives reclassified to operating profit (loss) |
|
(258) |
|
16 |
|
(149) |
|
Net (income) expense from investments |
|
(319) |
|
(698) |
|
(2,834) |
|
of which: |
|
|
|
|
|
|
|
- gain on the SeaCorridor deal |
|
|
|
(834) |
|
|
|
- gain on the divestment of a 10% stake in Saipem |
|
(166) |
|
|
|
|
|
- net gain on the divestment of upstream assets |
|
(373) |
|
|
|
|
|
- gain on the divestment interest in Var Energi |
|
|
|
|
|
(448) |
|
- net gains on the divestment of Angolan assets |
|
|
|
|
|
(2,542) |
|
Income taxes |
|
(1,941) |
|
(1,180) |
|
(683) |
|
Total non core gains and losses of net profit (loss) |
|
2,261 |
|
3,138 |
|
(204) |
|
Attributable to: |
|
|
|
|
|
|
|
- non-controlling interest |
|
(64) |
|
(11) |
|
(19) |
|
- Eni's shareholders |
|
2,325 |
|
3,149 |
|
(185) |
Cash flow and net borrowings
Group’s results of operations in 2024 drove a cash flow provided by operating activities “CFFO” of €13.1 billion, €2 billion lower than in 2023 due to reduced Group’s profitability. The CFFO included €1.95 billion of dividends paid by equity-accounted and other non-controlled entities.
Cash inflows of the year funded capital expenditures of €8.5 billion to pursue Group’s development projects and to sustain oil&gas production, leaving a surplus of about €4.6 billion that was utilized to fund part of cash returns to Eni’s shareholders of €5.1 billion, consisting of €3.1 billion of dividends and stock repurchases of €2 billion. The stock repurchases comprised completion of the 2023 buy-back program and 80% of the 2024 buy-back program of €2 billion. This latter was completed in February 2025.
Cash flow from divesting activities broadly matched funds deployed for acquisitions, leaving a small surplus of around €0.2 billion. The main 2024 dispositions included oil properties in Alaska (€1 billion), the acquisition by the EIP fund of a non-controlling interest in Plenitude for €0.6 billion and the divestment of one-third of Eni shareholding in the Saipem JV, or 10% of the venture’s share capital, for about €0.4 billion, as well as other non-strategic assets in the E&P segment for €0.6 billion, including mineral properties in Congo and onshore assets in Nigeria. Those inflows were almost completely absorbed by the funds to acquire 100% of the share capital of the UK independent oil&gas operator Neptune for €2.4 billion, including Neptune’s net borrowings which have been consolidated in the Group accounts.
As a result of those cash movements and including the repayment of lease liabilities and the incurrence of finance debt in connection with supplier finance agreements, GAAP finance debt including lease liabilities reached €36.8 billion at December 31, 2024, about €2.7 billion higher than at the end of 2023. The GAAP measure of indebtedness which compare gross debt to total equity was around 0.66.
Our net borrowing (Non-GAAP measure – see Glossary) increased by €1.28 billion to €12 billion. Despite that increase, the management’s tracked measure of financial structure – leverage (ratio of net borrowings to total equity – see glossary) came in at 0.22, very close to the management’s stated range of 0.1-0.2 expected in the next four-year plan. When considering the benefits of the divestment transactions defined in 2024, particularly the €2.97 billion relating to the investment of the KKR fund in Enilive cashed-in in March 2025, the leverage would have been lower than 0.22.
103
G r oup profit and loss
The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS. For the disclosure on 2023 Group results compared to 2022 see the Annual Report on Form 20-F 2023, filed to the SEC on April 5, 2024.
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(€ million) |
||||
|
Sales from operations |
|
88,797 |
|
93,717 |
|
132,512 |
|
Other income and revenues (1) |
|
2,417 |
|
1,099 |
|
1,175 |
|
Total revenues |
|
91,214 |
|
94,816 |
|
133,687 |
|
Operating expenses |
|
(74,544) |
|
(77,221) |
|
(105,497) |
|
Other operating (expense) income |
|
(352) |
|
478 |
|
(1,736) |
|
Depreciation, depletion and amortization |
|
(7,600) |
|
(7,479) |
|
(7,205) |
|
Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net |
|
(2,900) |
|
(1,802) |
|
(1,140) |
|
Write-off of tangible and intangible and right of use assets |
|
(580) |
|
(535) |
|
(599) |
|
OPERATING PROFIT (LOSS) |
|
5,238 |
|
8,257 |
|
17,510 |
|
Finance income (expense) |
|
(599) |
|
(473) |
|
(925) |
|
Income (expense) from investments |
|
1,850 |
|
2,444 |
|
5,464 |
|
PROFIT (LOSS) BEFORE INCOME TAXES |
|
6,489 |
|
10,228 |
|
22,049 |
|
Income taxes |
|
(3,725) |
|
(5,368) |
|
(8,088) |
|
Net profit (loss) |
|
2,764 |
|
4,860 |
|
13,961 |
|
Attributable to: |
|
|
|
|
|
|
|
- Eni's shareholders |
|
2,624 |
|
4,771 |
|
13,887 |
|
- Non-controlling interest |
|
140 |
|
89 |
|
74 |
|
|
|
|
|
|
|
(1) |
Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income. |
104
Analysis of the line items of the p r of it and loss account
a) Sales from operations
The table below sets forth, for the periods indicated, sales from operations generated by each of Eni’s business segments including intragroup sales, together with consolidated sales from operations.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(€ million) |
||||
|
Exploration & Production |
54,440 |
|
55,773 |
|
61,834 |
|
Global Gas & LNG Portfolio and Power |
18,876 |
|
24,168 |
|
58,119 |
|
Enilive and Plenitude |
31,301 |
|
32,877 |
|
39,942 |
|
Refining and Chemicals |
21,210 |
|
23,061 |
|
26,633 |
|
Corporate and other activities |
1,905 |
|
1,830 |
|
1,785 |
|
Consolidation adjustments |
(38,935) |
|
(43,992) |
|
(55,801) |
|
SALES FROM OPERATIONS |
88,797 |
|
93,717 |
|
132,512 |
2024 compared to 2023. Sales from operations (revenues) for 2024 (€88,797 million) decreased by €4,920 million from 2023 (or down by 5.2%) reflecting a downturn in the commodity environment, which negatively affected all business segments.
The drivers of the changes in revenues year-on-year are detailed in the following table:
|
Sales from operations: change 2024 vs 2023 |
change |
of which: |
|
price effects |
|
volume/mix effects |
|
|
(€ billion) |
|||||
|
E&P |
(1.3) |
|
|
(0.7) |
|
(0.7) |
|
|
|
|
|
|
|
|
|
GGP and Power |
(5.3) |
|
|
(4.9) |
|
(0.4) |
|
|
|
|
|
|
|
|
|
Enilive and Plenitude |
(1.6) |
|
|
(1.1) |
|
(0.5) |
|
|
|
|
|
|
|
|
|
Refining and Chemicals |
(1.8) |
|
|
(1.7) |
|
(0.1) |
Other income and r e v enues
2024 compared to 2023. Eni’s other income and revenues amounted to €2,417 million and mainly included a €1,048 million gain relating to the agreement with an Italian operator on a 50-50 sharing of environmental costs related to certain decommissioned Italian sites jointly managed several years ago, which expenses had previously been incurred or provisioned by Eni at 100%. This line item also included the share of lease repayments debited to joint operators in Eni-led upstream projects (€194 million).
b) Ope r ating e xpenses
The ta b le b e l o w sets f orth the components of Eni ’ s ope r a ting e xpenses f or the periods indic a ted.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(€ million) |
||||
|
Purchases, services and other |
71,114 |
|
73,836 |
|
102,529 |
|
Impairment losses (impairment reversals) of trade and other receivables, net |
168 |
|
249 |
|
(47) |
|
Payroll and related costs |
3,262 |
|
3,136 |
|
3,015 |
|
Operating expenses |
74,544 |
|
77,221 |
|
105,497 |
105
2024 compared to 2023. Operating expenses for 2024 (€74,544 million) decreased by €2,677 million compared to 2023, down by 3.5%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstocks).
Payroll and related costs (€3,262 million) increased by €126 million from 2023 (up by 4.0%) mainly due to the higher average number of employees, also following the business acquisition of the year.
c) Dep r eciation, depletion, amortization, impairment losses (impairment r e v e r sals) net and write-off
The ta b le b e l o w sets f orth a b r eakd o wn of dep r eci a tion, depletion, amortiz a tion, impai r ment losses (impai r ment rev ersals) net and write-o f f f or the periods indic a ted.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(€ million) |
||||
|
Exploration & Production |
6,353 |
|
6,271 |
|
6,130 |
|
Global Gas & LNG Portfolio and Power |
267 |
|
295 |
|
268 |
|
Enilive and Plenitude |
708 |
|
665 |
|
552 |
|
Refining and Chemicals |
161 |
|
142 |
|
150 |
|
Corporate and other activities and impact of unrealized intragroup profit elimination |
111 |
|
106 |
|
105 |
|
Total depreciation, depletion and amortization |
7,600 |
|
7,479 |
|
7,205 |
|
Impairment losses (impairment reversals) of tangible and intangible assets, goodwill and right of use assets, net |
2,900 |
|
1,802 |
|
1,140 |
|
Write-off of tangible and intangible and right of use assets |
580 |
|
535 |
|
599 |
|
Total depreciation, depletion, amortization, impairment losses (impairment reversals) of tangible and intangible and right of use assets, net and write off of tangible and intangible and right of use assets |
11,080 |
|
9,816 |
|
8,944 |
2024 compa r ed to 2023. In 2024, depreciation, depletion and amortization charges (€7,600 million) increased by €121 million from 2023, mainly in the Exploration & Production segment following start-ups and ramp-ups of new projects and changes in the consolidation scope with the acquisition of the Neptune Energy Group at the beginning of the year, partly offset by the effect of disposals, particularly the contribution of UK oil&gas assets to Ithaca Energy Plc in exchange of a 37% noncontrolling interest in the entity. Also, charges increased in the Enilive and Plenitude segment due to start-ups of new renewable energy installations.
In 2024, the Group recorded impairment losses at property, plant and equipment for a total amount of €2,900 million, out of which €2,203 million recorded at the Exploration & Production segment, mainly at certain assets in Alaska and Congo due to the alignment to the fair value of divestments as part of a portfolio review resulting in a reprioritization of capital allocation away from the development of future phases of marginal properties and in a greater focus on core projects consistent with our financial framework. Also, impairment charges were driven by minor downward reserves revisions at oil&gas assets in Italy and Turkmenistan. The Refining and Chemicals segment incurred €455 million of impairment losses driven by the write-off of expenditures incurred in the year for compliance and stay-in-business at certain Cash Generating Units with expected negative cash flows in the Refining business (€292 million) and in the Chemicals business (€163 million, including a small write-off of an uneconomical plant).
Write-off of tangible and intangible and right of use assets amounted to €580 million and mainly related to the E&P segment as capitalized costs of suspended exploratory wells were expensed through profit due to the negative assessment of recoverable reserves or economic feasibility of exploration projects in the United Arab Emirates, Egypt, Kazakhstan, Vietnam, Cyprus and Oman as well as exploration mineral rights because the Company decided to stop pursuing the underlying initiatives due to geopolitical issues.
106
d) Ope r ating p r ofit (loss) b y s e gment
The ta b le b e l o w sets f orth Eni ’ s ope r a ting p r o f it b y b usiness segment f or the periods indic a ted.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
( € million) |
||||
|
Exploration & Production |
6,715 |
|
8,693 |
|
16,158 |
|
Global Gas & LNG Portfolio and Power |
(909) |
|
2,626 |
|
4,231 |
|
Enilive and Plenitude |
1,589 |
|
(74) |
|
(450) |
|
Refining and Chemicals |
(1,681) |
|
(2,121) |
|
(606) |
|
Corporate and other activities |
(371) |
|
(948) |
|
(1,961) |
|
Impact of unrealized intragroup profit elimination |
(105) |
|
81 |
|
138 |
|
Operating profit (loss) |
5,238 |
|
8,257 |
|
17,510 |
Exploration & Production. In 2024, the Exploration & Production segment reported an operating profit of €6,715 million, with a decreased of €1,978 million compared to the operating profit of €8,693 million reported in 2023. The decrease was driven by lower gas prices reflecting an unfavorable commodity environment due to a global oversupply and an economic slowdown, while international oil price for the Brent benchmark crude oil declined by a smaller 2%. In 2024, Eni’s average prices for crude oil and natural gas liquids decreased on average by 3% with Eni’s average natural gas prices decreasing by 5%, reflecting the price exposure of the production portfolio, where about 32% of volumes are indexed to the price of crude oil, higher than the share of production linked to European hub pricing (18%). The remainder of E&P produced gas volumes is sold at fixed prices.
In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in segment performance, management generally excludes the identified gains and losses presented below to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. In 2024, identified gains and losses included impairment losses of €2,203 million, write-off of an exploration project due to geopolitical constraints (€140 million).
Excluding those items, the E&P segment reported a Non-GAAP operating profit of €9,220 million, with a decrease of €904 million from 2023, down by 8.9%, driven by lower realizations in US dollars at equity production partly offset by higher production sold as well as by cost efficiencies.
|
|
change |
of which: |
|
price effects |
|
volume/mix effects |
|
cost effects |
|
|
(€ million) |
|
|
|||||
|
Change in E&P Non-GAAP operating profit (loss) 2024 vs. 2023 |
(904) |
|
|
(679) |
|
(344) |
|
119 |
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
Exploration & Production |
|
(€ million) |
||||
|
GAAP operating profit (loss) |
|
6,715 |
|
8,693 |
|
16,158 |
|
Impairment losses (impairment reversals), net |
|
2,203 |
|
1,043 |
|
432 |
|
Net gains on disposal of assets |
|
(25) |
|
2 |
|
(27) |
|
Environmental provisions |
|
9 |
|
81 |
|
30 |
|
Risk provisions |
|
9 |
|
7 |
|
34 |
|
Reclassification of currency derivatives and translation effects to management measure of business performance |
|
22 |
|
73 |
|
(104) |
|
Write off of exploration projects |
|
140 |
|
0 |
|
2 |
|
Other |
|
147 |
|
225 |
|
106 |
|
Total identified gains and charges |
|
2,505 |
|
1,431 |
|
473 |
|
Non-GAAP operating profit (loss) |
|
9,220 |
|
10,124 |
|
16,631 |
107
Global Gas & LNG Portfolio (GGP) and Power
This reportable segment aggregates the results of the GGP business engaged in the purchase and marketing of gas, LNG and electricity and in trading activities, with those of the power business engaged in the production of electricity from cogeneration plants feed with gas and in providing backup capacity to the Italian grid because this business is ancillary to GGP.
In 2024, the GGP and Power segment reported an operating loss of €909 million compared to a profit of €2,626 million in 2023. The decrease was negatively affected by movements in fair-valued commodity derivatives entered into (from a loss of around €100 million in 2023 to a loss of €1,740 million in 2024), a large part of which was lacking correlation with the underlying performance due to the accounting under IFRS, as well as lower sales volumes, reduced gas prices and volatility which negatively affected optimization and trading opportunities. Furthermore, the 2023 result of GGP benefitted from certain big one-off gains recognized on contract renegotiations and the settlement of an arbitration.
In reviewing the performance of the Company’s GGP and Power segment and with a view to better explaining year-on-year changes in the segment performance, management generally excludes certain fair-valued commodity derivatives with gains and losses recognized through to profit to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods.
We enter into commodity and currency derivatives to reduce our exposure to: (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas or to lock in a commercial margin once a sale contract has been signed or is highly probable; and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge the Group net exposure to commodities and exchange rates but do not meet the requirements for being accounted for as hedges in accordance with IFRS. as part of our ordinary activities, we also entered into forward gas sale contracts which are intended to be settled with the delivery of the commodity and which are accounted at fair value because they were not eligible for the own use exemption at their inceptions, whereas the purchase costs of gas were accounted on an accrual basis.
In explaining year-on-year changes and in evaluating the business performance, management believes that is appropriate to exclude the fair value of commodity derivatives which lacked the formal criteria to be accounted for as hedges or were not eligible for the own use exemption, including the ineffective portion of cash flow hedges. We also excluded from our measure of underlying performance the effects of the settlement of certain commodity derivatives of which the underlying physical transaction had yet to be finalized with the delivery of the commodity. Furthermore, although the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivables and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and currency differences at our dollar-denominated trade payables and receivables as part of the underlying business performance.
In 2024, those fair value effects on commodity derivatives amounted to a loss of €1,740 million.
In 2024, identified items also excluded a €159 million gain determined as a timing difference between the value of gas inventories accounted for under the weighted-average cost method provided by IFRS as measured at the balance sheet date and the management’s own measure of performance, which considers the storage injection season and the withdrawal season and defer the margins captured by leveraging the seasonal “summer vs. winter” spreads in gas prices net of the effects of the associated commodity derivatives to when those volumes held in storage are actually sold, normally during the next withdrawal winter season.
Excluding the below-listed gains and charges, the GGP business reported a Non-GAAP operating profit of €1,099 million, with a decrease of €2,148 million from 2023 mainly driven by the aforementioned trends in the gas market and the one-off effects recorded in 2023.
The Power business reported an adjusted operating profit of €136 million (down by €30 million from 2023).
|
|
change |
of which: |
|
price effects |
|
contract renegotiations and risk provisions |
|
cost effects |
|
|
(€ million) |
|
|
|||||
|
Change in GGP and Power Non-GAAP operating profit (loss) 2024 vs. 2023 |
(2,178) |
|
|
(1,288) |
|
(890) |
|
|
108
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
Global Gas & LNG Portfolio and Power |
|
(€ million) |
||||
|
GAAP operating profit (loss) |
|
(909) |
|
2,626 |
|
4,231 |
|
Impairment losses (impairment reversals), net |
|
101 |
|
(38) |
|
(66) |
|
Provision for redundancy incentives |
|
1 |
|
6 |
|
6 |
|
Fair value gains/losses on commodity derivatives |
|
1,740 |
|
99 |
|
(1,981) |
|
Reclassification of currency derivatives and translation effects to management measure of business performance |
|
228 |
|
(105) |
|
239 |
|
Other |
|
74 |
|
825 |
|
(96) |
|
Total identified gains and charges |
|
2,144 |
|
787 |
|
(1,898) |
|
Non-GAAP operating profit (loss) |
|
1,235 |
|
3,413 |
|
2,333 |
|
- Global Gas & LNG Portfolio |
|
1,099 |
|
3,247 |
|
2,063 |
|
- Power |
|
136 |
|
166 |
|
270 |
Enilive and Plenitude . In 2024, the Enilive and Plenitude segment reported an operating profit of €1,589 million, compared to an operating loss of €74 million in 2023, an increase of €1,663 million. Enilive reported an operating profit of €282 million (€585 million in 2023) while Plenitude reported an operating profit of €1,307 million, compared to an operating loss of €659 million in 2023.
The main item excluded from GAAP operating profit in determining the Non-GAAP profitability measure of Enilive is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies.
The main item excluded from GAAP operating profit in determining the Non-GAAP profitability measure of Plenitude were the effects related to fair value changes of commodity derivatives lacking the formal criteria to be accounted as hedges under IFRS.
In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the inventory holding gain (or loss) and the other identified gains and losses described above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods.
Excluding those items, the Enilive business reported a Non-GAAP operating profit of €571 million (an operating profit of €742 million in 2023), negatively affected by deteriorated margins, impacted by oversupplies pressuring spot HVO prices in the EU and lower RIN in North America. These negatives were partly offset by a positive performance of Marketing activities at Eni advanced network of service stations.
The Plenitude business reported a Non-GAAP operating profit of €616 million (an operating profit of €515 million in 2023) driven by higher margins at the retail business in Italy and in the European markets (mainly in France), also leveraging cross-selling opportunities of the integrated value chain, and increased sales volumes of renewables electricity thanks to the ramp-up in renewable installed capacity and the contribution of acquired assets.
|
|
change |
of which: |
|
price effects |
|
volume/mix effects |
|
cost effects |
|
|
(€ million) |
|
|
|||||
|
Change in Enilive Non-GAAP operating profit (loss) 2024 vs. 2023 |
(171) |
|
|
(382) |
|
287 |
|
(76) |
|
Change in Plenitude Non-GAAP operating profit (loss) 2024 vs. 2023 |
101 |
|
|
40 |
|
95 |
|
(34) |
109
The items excluded from GAAP operating loss in determining the Non-GAAP measure of profitability mainly include effects associated with commodity fair-valued derivatives, lacking the formal criteria to be classified as hedges under IFRS which amounted to a profit of €682 million.
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
Enilive and Plenitude |
|
(€ million) |
||||
|
GAAP operating profit (loss) |
|
1,589 |
|
(74) |
|
(450) |
|
(Profit) loss on inventory |
|
112 |
|
47 |
|
(196) |
|
Risk provisions |
|
2 |
|
8 |
|
0 |
|
Impairment losses (impairment reversals), net |
|
113 |
|
45 |
|
60 |
|
Environmental provisions |
|
38 |
|
36 |
|
385 |
|
Provision for redundancy incentives |
|
(2) |
|
22 |
|
80 |
|
Fair value gains/losses on commodity derivatives |
|
(682) |
|
1,142 |
|
1,588 |
|
Reclassification of currency derivatives and translation effects to management measure of business performance |
|
(1) |
|
2 |
|
(1) |
|
Other |
|
18 |
|
29 |
|
7 |
|
Total identified gains and charges |
|
(402) |
|
1,331 |
|
1,923 |
|
Non-GAAP operating profit (loss) |
|
1,187 |
|
1,257 |
|
1,473 |
|
of which: |
|
|
|
|
|
|
|
- Enilive |
|
571 |
|
742 |
|
1,128 |
|
-Plenitude |
|
616 |
|
515 |
|
345 |
Refining and Chemicals
In 2024, this segment reported an operating loss of €1,681 million compared to the loss of €2,121 million in the previous year, driven by lower impairment and other charges and a lower loss on the book value of oil and products inventories stated at the weighted-average cost of supplies of the last quarter of the year due to a recovery of products prices.
In 2024, Eni’s refining business with a Non-GAAP operating loss of €76 million was negatively affected by weaker refining margins due to a downturn in gasoil demand and rising competitive pressures as new capacity entered the market, as well as lower throughputs.
In addition to the inventory holding profit (or loss), the identified items of this business for the year 2024 comprised environmental provisions of €254 million, the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows (€292 million).
The Chemical business reported a non-GAAP operating loss of €814 million in 2024, compared to a non-GAAP operating loss of €614 million in 2023 due to lower demand across all business segments driven by a slowdown in the macro environment and comparatively higher production costs in Europe for energy inputs and other expenses, which reduced the competitiveness of Versalis production with respect to US and Asian players, against the backdrop of global overcapacity. In addition to the inventory holding profit (or loss), the identified items of this business for the year 2024 comprised the write-down of capital expenditures made for compliance and stay-in-business (€163 million) at certain CGU with expected negative cash flows and environmental provisions of around €200 million, offset by Versalis’ share of the gain on an environmental agreement.
|
|
change |
of which: |
|
price effects |
|
volume/mix effects |
|
cost effects |
|
|
(€ million) |
|
|
|||||
|
Change in Refining Non-GAAP operating profit (loss) 2024 vs. 2023 |
(328) |
|
|
(346) |
|
18 |
|
|
|
Change in Chemicals' Non-GAAP operating profit (loss) 2024 vs. 2023 |
(200) |
|
|
(301) |
|
121 |
|
(20) |
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
Refining and Chemicals |
|
(€ million) |
||||
|
GAAP operating profit (loss) |
|
(1,681) |
|
(2,121) |
|
(606) |
|
(Profit) loss on inventory |
|
95 |
|
557 |
|
(220) |
|
Environmental provisions and other costs net of a gain of an environmental agreement |
|
177 |
|
337 |
|
577 |
|
Impairment losses (impairment reversals), net |
|
455 |
|
726 |
|
674 |
|
Net gains on disposal of assets |
|
(2) |
|
(9) |
|
(7) |
|
Risk provisions |
|
33 |
|
11 |
|
52 |
|
Provision for redundancy incentives |
|
19 |
|
31 |
|
28 |
|
Fair value gains/losses on commodity derivatives |
|
(1) |
|
(1) |
|
(11) |
|
Reclassification of currency derivatives and translation effects to management measure of business performance |
|
6 |
|
11 |
|
18 |
|
Other |
|
9 |
|
96 |
|
140 |
|
Total identified gains and charges |
|
791 |
|
1,759 |
|
1,251 |
|
Non-GAAP operating profit (loss) |
|
(890) |
|
(362) |
|
645 |
|
- Refining |
|
(76) |
|
252 |
|
899 |
|
- Chemicals |
|
(814) |
|
(614) |
|
(254) |
110
Corpo r ate and Other act i vities . These activities are mainly cost centers comprising holdings, financing and treasury activities in support of operating subsidiaries, central functions like legal counselling, human resources, captive insurance activities, general and administrative support, as well as research and development, new technologies, business digitalization and the environmental activity developed by the subsidiary Eni Rewind. Furthermore, the results of CCUS and Agribusiness of Eni have been included in the “Corporate and other activities” reporting segment. More information on the Company's segment reporting is disclosed in note n.35 to the Consolidated Financial Statements.
The aggregate Corporate and Other activities reported an operating loss of €371 million compared with a loss of €948 million in 2023. The reduced loss reflected environmental gains mainly relating to the signing of a comprehensive agreement with an Italian operator on a 50-50 sharing of environmental costs related to several Italian sites, which were previously incurred or provisioned by Eni at 100%.
e) Net finance e xpenses
The ta b le b e l o w sets f orth a b r eakd o wn of Eni ’ s net f inancial e xpenses f or the periods indic a ted:
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(€ million) |
||||
|
Income (expense) on derivative financial instruments |
|
278 |
|
(61) |
|
13 |
|
of which - Derivatives on exchange rate |
|
310 |
|
(63) |
|
(70) |
|
- Derivatives on interest rate |
|
(32) |
|
2 |
|
81 |
|
- Options |
|
|
|
|
|
2 |
|
Exchange differences, net |
|
(38) |
|
255 |
|
238 |
|
Finance expense from banks on short and long-term debt |
|
(1,185) |
|
(874) |
|
(635) |
|
Interest expense for lease liabilities |
|
(314) |
|
(267) |
|
(315) |
|
Interest income due to banks |
|
294 |
|
356 |
|
57 |
|
Net income from financial assets measured at fair value through profit or loss |
|
388 |
|
284 |
|
(55) |
|
Finance expense due to the passage of time (accretion discount) |
|
(261) |
|
(341) |
|
(199) |
|
Other finance income and expense, net |
|
17 |
|
81 |
|
(67) |
|
|
|
(821) |
|
(567) |
|
(963) |
|
Finance expense capitalized |
|
222 |
|
94 |
|
38 |
|
NET FINANCE EXPENSES |
|
(599) |
|
(473) |
|
(925) |
In 2024, net finance expenses were €599 million (€473 million in 2023). The increase in net financial expenses in 2024 compared to 2023 was due to the Company having increased finance debt during the year as well as to the impact of higher rates loans, whereas interest income from cash deposits was affected by a declining yield environment, whereas fair-valued financial assets held for trading recorded gains.
f) Net income f r om i n v estments
The ta b le b e l o w sets f orth a b r eakd o wn of Eni ’ s net income from investments f or the periods indic a ted:
|
|
|
Year ended December 31, |
||||
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
(€ million) |
||||
|
Share of gains (losses) from equity-accounted investments |
|
866 |
|
1,336 |
|
1,841 |
|
Dividends |
|
227 |
|
255 |
|
351 |
|
Net gains (losses) on disposals |
|
562 |
|
430 |
|
483 |
|
Other income (expense), net |
|
195 |
|
423 |
|
2,789 |
|
|
|
1,850 |
|
2,444 |
|
5,464 |
111
In 2024, the Group reported a net profit from investments of €1,850 million, down by about €594 million from 2023 due to the lower Eni’s share of profits generated by equity-accounted investments (down by €470 million) and was mainly driven by lower profits in the Refining and Chemical segment (down by €308 million) and in the Exploration & Production segment (down by €108 million). “Other income, net” reduced by €228 million due to gains recorded in 2023, partly offset by a gain of around €100 million recognized on the contribution of Eni’s oil&gas assets in the UK to Ithaca Energy in exchange of a participating interest of 37.17% in the entity.
A break-down of profits earned for the main investments is provided below:
|
|
|
(i) |
in E&P, we recognized a profit of €904 million, a decrease of €108 million. It included Eni’s share in the joint venture Vår Energi (€259 million), the Azule Energy Holdings joint venture result of €602 million, as well as Eni’s share in Ithaca Energy (€7 million); |
|
|
|
(ii) |
The GGP SeaCorridor associate for €44 million; |
|
|
|
(iii) |
The Refining ADNOC Refining&Trading associate, where we recognized a profit of €80 million, down from the previous year due to lower refining margins; |
|
|
|
(iv) |
the joint venture Saipem, where we recognized a profit of €75 million. |
Dividends of €227 million were paid by minority investments in certain entities which were designated at fair value through other comprehensive income under IFRS 9, except for dividends which were recorded through profit. These entities mainly comprised Nigeria LNG Ltd (€166 million), and Saudi European Petrochemical Co (€22 million).
Net gains on the disposal of assets amounted to €562 million, increasing by €132 million and related to the gains on the divestment of certain assets in the Exploration & Production segment for €370 million, as well as €184 million recorded in the Corporate and Other activities segment and mainly referred to the sale of a 10% stake in the equity interests of Saipem (€166 million).
g) T a x es
In 2024, income taxes decreased by €1,643 million to €3,725 million and compared to the pre-tax profit of €6,489 million resulted in a tax rate of 57.4% (compared to 52.5% in 2023), and included about €1.1 billion of write-up of deferred tax assets due to improved profitability prospects of Italian subsidiaries, mainly Plenitude and Enilive. The increase in the reported tax rate was due to a higher share of taxable profit earned by subsidiaries in the E&P sector, which were subject to a higher rate of taxes than other Group’s activities as well as a decline in taxable profits reported by Italian subsidiaries which are taxed at a lower-than-Group average tax rate.
The adjusted tax rate, which exclude the impact of identified gains and losses including the write-up of deferred tax assets, is the measure of tax rate tracked by management, and increased by approximately 8 percentage points in 2024 compared to 2023, to 52% due to the prevailing effect of the high taxation in foreign jurisdictions operating in the E&P segment and a reduced pre-tax contribution of other sectors generally operating in OECD jurisdiction with lower tax rates than E&P.
112
Liquidity and capital r esou r ces
Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and share repurchases have been financed in the last three years primarily by a combination of funds generated from operations, issues of equity investments (hybrid bonds), divestments of property, plant and equipment and shareholdings in equity accounted entities, or the reimbursement of operating financing receivables owed to Eni by unconsolidated entities, and in 2024 also by taking on new finance debt. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and balanced financing structure.
The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated.
This cash flow statement is a GAAP measure of cash flow and is presented herein to help readers understand the change in the year of the Group net borrowings which is a NON-GAAP measure as explained further on.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(€ million) |
||||
|
Net profit (loss) |
2,764 |
|
4,860 |
|
13,961 |
|
Adjustments to reconcile net profit to net cash provided by operating activities: |
|
|
|
|
|
|
- amortization and depreciation charges, impairment losses, write-off and other non monetary items |
9,951 |
|
7,781 |
|
4,369 |
|
- net gains on disposal of assets |
(601) |
|
(441) |
|
(524) |
|
- dividends, interest, taxes and other changes |
4,246 |
|
5,596 |
|
8,611 |
|
Changes in working capital related to operations |
1,286 |
|
1,811 |
|
(1,279) |
|
Dividends received by equity investments |
1,946 |
|
2,255 |
|
1,545 |
|
Taxes paid |
(5,826) |
|
(6,283) |
|
(8,488) |
|
Interests (paid) received |
(674) |
|
(460) |
|
(735) |
|
Net cash provided by operating activities |
13,092 |
|
15,119 |
|
17,460 |
|
Capital expenditures |
(8,485) |
|
(9,215) |
|
(8,056) |
|
Acquisition of investments and businesses |
(2,593) |
|
(2,592) |
|
(3,311) |
|
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments |
2,788 |
|
596 |
|
1,202 |
|
Other cash flow related to investing activities |
(996) |
|
(348) |
|
2,361 |
|
Net cash inflow (outflow) related to financial activities |
(531) |
|
2,194 |
|
786 |
|
Changes in short and long-term finance debt |
(1,293) |
|
315 |
|
(2,569) |
|
Repayment of lease liabilities |
(1,205) |
|
(963) |
|
(994) |
|
Dividends paid and changes in non-controlling interests and reserves |
(4,522) |
|
(4,882) |
|
(4,841) |
|
Net issue (repayment) of perpetual hybrid bond |
1,640 |
|
(138) |
|
(138) |
|
Effect of changes in consolidation and exchange differences of cash and cash equivalent |
83 |
|
(62) |
|
16 |
|
Net increase (decrease) in cash and cash equivalent |
(2,022) |
|
24 |
|
1,916 |
|
Cash and cash equivalent at the beginning of the year |
10,205 |
|
10,181 |
|
8,265 |
|
Cash and cash equivalent at year end |
8,183 |
|
10,205 |
|
10,181 |
113
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(€ million) |
||||
|
Net cash provided by operating activities |
13,092 |
|
15,119 |
|
17,460 |
|
Capital expenditures |
(8,485) |
|
(9,215) |
|
(8,056) |
|
Acquisitions of investments and businesses |
(2,593) |
|
(2,592) |
|
(3,311) |
|
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments |
2,788 |
|
596 |
|
1,202 |
|
Other cash flow related to capital expenditures, investments and divestments |
(996) |
|
(348) |
|
2,361 |
|
Repayment of lease liabilities |
(1,205) |
|
(963) |
|
(994) |
|
Net borrowings (1) of acquired companies |
(631) |
|
(234) |
|
(512) |
|
Net borrowings (1) of divested companies |
|
|
(155) |
|
142 |
|
Exchange differences on net borrowings and other changes |
(364) |
|
(1,061) |
|
(1,352) |
|
Dividends paid, share repurchases and changes in minority interest and reserves |
(4,522) |
|
(4,882) |
|
(4,841) |
|
Net issue (repayment) of perpetual hybrid bond |
1,640 |
|
(138) |
|
(138) |
|
Change in net borrowings (1) before IFRS 16 effects |
(1,276) |
|
(3,873) |
|
1,961 |
|
Repayment of lease liabilities |
1,205 |
|
963 |
|
994 |
|
Inception of new leases and other changes |
(2,322) |
|
(1,348) |
|
(608) |
|
Change in net borrowings after IFRS 16 effects (1) |
(2,393) |
|
(4,258) |
|
2,347 |
|
Net borrowings (1) at the beginning of the year |
16,235 |
|
11,977 |
|
14,324 |
|
Net borrowings (1) at year end |
18,628 |
|
16,235 |
|
11,977 |
(1) Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below.
In 2024, adjustments to reconcile the net profit reported in the year to net cash provided by operating activities mainly related to depreciation, depletion, amortization, impairment charges and results of equity-accounted entities for €9,951 million. Adjustments to net profit also included accrued income taxes (€3,725 million) and net interest expense (€748 million), more than offset by amounts actually paid (€5,826 million and €674 million, respectively).
The dividends received by equity-accounted investments of €1,946 million mainly related to Azule Energy Holdings, Vår Energi and Adnoc R&T, while other dividends recorded through profit of €166 million mainly related to Nigeria LNG.
114
a) Chan g es in w o r king capital r e lated to ope r ations
In 2024, working capital generated an inflow of €1,286 million driven by several initiatives to optimize working capital needs including non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk, partly offset by the cash-outs relating to utilizations of provisions in connection with advancement of Group’s decommissioning activities at oil&gas assets and environmental remediation programs.
|
|
Year ended December 31, |
||||
|
|
2024 |
|
2023 |
|
2022 |
|
|
(€ million) |
||||
|
Exploration & Production |
6,055 |
|
7,135 |
|
6,252 |
|
Global Gas & LNG Portfolio and Power |
110 |
|
119 |
|
173 |
|
Enilive and Plenitude |
1,303 |
|
1,064 |
|
754 |
|
Refining and Chemicals |
632 |
|
556 |
|
605 |
|
Corporate and other activities |
408 |
|
360 |
|
276 |
|
Impact of unrealized intragroup profit elimination |
(23) |
|
(19) |
|
(4) |
|
Capital expenditures |
8,485 |
|
9,215 |
|
8,056 |
|
Acquisitions of investments and businesses |
2,593 |
|
2,592 |
|
3,311 |
|
|
11,078 |
|
11,807 |
|
11,367 |
|
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments |
(2,788) |
|
(596) |
|
(1,202) |
Capital expenditures totaled €8,485 million and €9,215 million, respectively in 2024 and in 2023.
For a discussion of capital expenditures by business segment and a description of year-on-year changes see “Capital expenditures by segment”.
Cash outflows for acquisitions of €2,593 million mainly related to the acquisition of the upstream operator Neptune Energy (€2.4 billion including acquired net debt), expansion of renewable generation capacity at Plenitude, and a service stations network in Spain. These outflows were offset by divestment of E&P Nigerian and Alaskan onshore assets (€1.7 billion), the sale of 10% of the share capital of Saipem (€0.4 billion), production licenses in Congo (€0.2 billion), as well as the Plenitude capital contribution of about €0.6 billion following the finalization of the agreement with the EIP fund who acquired a minority interest (7.6%).
b) Dividends paid, sha r e r epu r chases and chan g es in non-cont r olling inte r ests and r eser v es
In 2024, dividends paid and changes in non-controlling interests and reserves (€4,522 million) related to the dividends paid to Eni shareholders (€3,068 million which comprised two quarterly installments of the 2023 dividend for about €1.5 million and the first and the second quarterly installment of the 2024 dividend of €0.25 per share each, amounting to €1.6 billion). In addition, to complete the 2023 buy-back program (€0.4 billion) and as a part of the 2024 new buy-back program (€1.6 billion), the company purchased own shares for an amount of €2,012 million.
As of February 20, 2025, the 2024 buy-back program was completed with an overall amount of 144 million shares purchased for a cash outlay of €2,000 million.
Financial condition
Management assesses the Group’s capital structure and capital condition by tracking net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt, including finance leases as per IFRS 16) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, a liquidity reserve made of held-for-trading securities and finally other liquid assets not related to operations. In 2024, the Group included in its financial assets subtracted from gross finance debt certain long-term financing receivables owed to us by non-consolidated entities to reflect the increasing financial autonomy of such entities as provided by our satellite strategy, the planned reimbursement of several instalments of those financing receivables in the 2025-2028 four-year plan and the fact that the Group is currently exposed only to the credit risk with respect to those entities. The amount of those long-term financing receivables reclassified among financial assets was €1.34 billion at the opening balance 2024.
115
Financial assets measured at fair value through profit or loss constituting part of the Group’s liquidity reserves amounted to €6.8 billion as of end of 2024 and were accounted as mark-to-market financial instruments. Of this amount, fixed income securities issued by industrial companies and financial institutions were €5.5 billion. Although the fair value of these investments is netted from financial debt in our calculation of net borrowings, there is no certainty that these investments could be readily monetizable at their carrying value, particularly in the event of market stress. For further information, see “Item 18 – Note 7 – Financial assets at fair value through profit and loss – of the Notes to the Consolidated Financial Statements”. Non-operating financing receivables comprised long-term financing receivables owed by equity-accounted entities, as well as deposits with banks and other financing institutions and deposits in escrow (mainly cash deposits established as a collateral of derivative transactions).
Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced compared to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to other companies.
The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure.
|
|
(€ million) |
Dec 31 2024 |
Dec 31 2023 |
|
Total finance debt including lease liabilities |
|
36,801 |
34,065 |
|
less: |
|
|
|
|
Cash and cash equivalents |
|
(8,183) |
(10,193) |
|
Financial assets measured at fair value through profit or loss |
|
(6,797) |
(6,782) |
|
Financing receivables held for non-operating purposes (a) |
|
(3,193) |
(855) |
|
Lease liabilities |
|
(6,453) |
(5,336) |
|
Net borrowings excluding lease liabilities |
|
12,175 |
10,899 |
|
Shareholders' equity including non-controlling interest |
|
55,648 |
53,644 |
|
Leverage before lease liability ex IFRS 16 |
|
0.22 |
0.20 |
|
|
|
|
|
|
(a)From January 1, 2024, considering Eni’s strategy based on the satellite model which envisages an increasing autonomy of non-consolidated entities, loans granted to certain JVs, previously classified as invested capital, have been reclassified as long-term financing receivables because it has been recognized that Eni is exposed to a credit risk as a repayment plan is scheduled. Therefore, such financing receivables have been netted against gross finance debt to determine Eni’s net borrowings and to calculate the Group leverage. See also Item 18 - Note 20 on Consolidated Financial Statements. |
|||
|
|
|
As of December 31, |
||
|
|
|
2024 |
|
2023 |
|
|
|
(€ million) |
||
|
Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS |
|
55,648 |
|
53,644 |
|
Ratio of finance debt including lease liabilities to total equity |
|
0.66 |
|
0.63 |
|
Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total equity |
|
(0.33) |
|
(0.33) |
|
Ratio of net borrowing to total equity |
|
0.33 |
|
0.30 |
|
Ratio of net borrowing excluding lease liabilities to total equity |
|
0.22 |
|
0.20 |
116
At December 31, 2024, total finance debt of €36,801 million including lease liabilities consisted of €8,820 million of short-term debt (including the portion of long-term debt due within twelve months equal to €4,582 million) and €21,528 million of long-term debt. At the same date, lease liabilities were €6,453 million (short-term portion €1,279 million).
Total finance debt included unsecured bonds for €18,507 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €4,350 million (including accrued interest and discount).
During 2024, new bonds in euro were issued by Eni SpA for a nominal value of €3,164 million.
Eni has established with financing institutions a sustainability-linked framework, on which basis the Group may issue securities and obtain financing which costs are indexed to the achievement of the following sustainability targets: (i) net carbon footprint upstream (GHG emission Scope 1 and 2) equal to or less than 5.2 million tons of CO 2 equivalent by December 31, 2025; (ii) renewable energy installed capacity of at least or more than 5 GW December 31, 2025. In case the Company misses those targets, a step-up mechanism will be applied, increasing the interest cost.
As of December 31, 2024, Eni SpA, within the Euro Medium Term Notes program, had in place sustainability-linked bonds for a total nominal value of €3,750 million.
As of December 31, 2024, Eni SpA had in place a sustainability-linked senior unsecured convertible bond with an aggregate nominal amount of €1,000 million.
In 2024, net borrowings including lease liabilities amounted to €18,628 million, representing a €2,393 million increase from 2023 driven by a reduction in net cash provided by operating activities and increased finance debt in connection with supplier financing agreements and the hiring of new plants and equipment recognized as finance leases.
IFRS 16 lease liabilities amounted to €6,453 million in 2024 (€5,336 million in 2023) and mainly related to the leased FPSO vessels relating to the offshore project OCPT in Ghana and in Area 1 off Mexico, E&P equipment in support of major offshore projects, as well as several minor assets like motorway concessions, land leases, service station leased for petroleum products marketing activities, as well as leases of vessels for shipping activities, leased buildings and the car fleet dedicated to the business of car sharing. The IFRS 16 lease liabilities included €616 million pertaining to joint operators in Eni-led upstream unincorporated joint ventures, which are expected to be recovered through a partner-billing process.
Net borrowings excluding the lease liabilities, which is the Non-GAAP measure of financial condition mostly tracked by management would amount to €12,175 million, up by €1.3 billion compared to December 31, 2023, which benefitted from the reclassification at the opening balance 2024 of €1.34 billion of long-term financing receivables as liquid assets deducted from finance debt to calculate net borrowings.
The ratio of finance debt to total equity was 0.66 at 2024 year-end, including the IFRS 16 lease liability (0.63 at 2023 year-end). Total equity of €55,648 million decreased by €2,004 million from December 31, 2023. This was due to the net profit for the period (€2,764 million), the positive foreign currency translation differences (€3,066 million) reflecting the appreciation of the US dollar vs. the euro as of December 31, 2024 vs. December 31, 2023, and issuance of a hybrid bond from a Group subsidiary for €1,800 million to finance a capital project, which was recognized as equity because the Group retain an unconditional right to avoid transfer cash or other financial assets to bondholders, classified as part of non-controlling interests. Those increases were partly offset by the negative change in the cash flow hedge reserve of €912 million reflecting trends in gas prices, the payment of dividends to Eni shareholders (two tranches of the 2023 dividend for €1.5 billion and the first and the second quarterly instalment of the 2024 dividend for €1.6 billion) as well as the buy-back of Eni shares (€2 billion).
The Group Non-GAAP measure of its financial condition mostly tracked by management was leverage calculated as ratio of net borrowings excluding finance liabilities of IFRS 16 to total equity and was 0.22 at year end (0.20 at the end of 2023). Considering that in 2024 the noncontrolling interest increased significantly, leverage calculated as ratio of net borrowings to equity attributable to Eni’s shareholders (€52.78 billion) would be 0.23.
Capital e xpenditu r es by segment
Exploration & Production . In 2024, capital expenditures of the Exploration & Production segment amounted to € 6,055 million and mainly related to the development of hydrocarbon fields (€5,564 million). Significant expenditures were directed mainly in in Côte d'Ivoire, Congo, Italy, Egypt, Iraq, Libya, Indonesia, Algeria, Kazakhstan and the United Arab Emirates.
117
Global Gas & LNG Portfolio and Power.
In 2024, capital expenditure in the Global Gas & LNG portfolio and Power totaled €110 million.
Enilive and Plenitude In 2024, capital expenditures in the Enilive and Plenitude segment amounted to €1,303 million. Plenitude’s capital expenditure was €887 million and mainly related to development activities in the renewable business, acquisition of new customers, as well as development of electric vehicles network infrastructure, Enilive’s capital expenditure was €416 million and regarded mainly: (i) marketing activity in the retail network for the development of food and non-oil programs; (ii) regulation compliance and stay-in-business initiatives in the retail network in Italy and in the rest of Europe; (iii) the development of bio refining and biomethane activities as well as HSE initiatives.
Refining and Chemicals
In 2024, capital expenditures in the Refining and Chemicals segment amounted to €632 million and mainly related to: (i) traditional refining in Italy (€422 million) relating to the new Livorno biorefinery, maintenance and stay-in-business; and (ii) circular economy and asset integrity in the chemical business (€210 million).
Recent d e v elopments and significant transactions
The ta b le b e l o w sets f orth certain indic a tors of the t r ading e n vi r onment f or the periods indic a ted (rounded for the first quarter 2025):
|
|
|
Three months ended March 31, |
|
Three months ended March 31, |
|
|
|
2024 |
|
2025 |
|
Average price of Brent dated crude oil in U.S. dollars (1) |
|
83.0 |
|
75.7 |
|
Average EUR/USD exchange rate (2) |
|
1.090 |
|
1.052 |
|
Standard Eni Refining Margin (SERM) (3) |
|
8.7 |
|
3.8 |
|
Gas at the TTF in $/mmBTU |
|
8.7 |
|
14.4 |
|
(1) |
Price per barrel. Source: Platt’s Oilgram. |
|
(2) |
Source: ECB. |
|
(3) |
In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. From January 1, 2024, the benchmark refining margin has been calculated based on a new methodology which considers a revised industrial set-up in connection with the planned restructuring of the Livorno plant and implemented optimizations of utilities consumption, as well as current trends in crude supplies building in a slate of both high-sulfur and low-sulfur crudes. |
See “management expectations of operations” below for a discussion on how key market indicators are performing against management’s expectations.
The main business transactions that occurred in the first quarter 2025 are reported in Item 4. See also section “Subsequent events” in the Notes to the Consolidated Financial Statements.
118
Management’s expectations of operations
Business trends
Exploration & Production
In the next four-year plan 2025-2028, management intends to increase the financial returns of the E&P segment leveraging on profitable production growth, capital and cost discipline, and fast time-to-market of projects. At the same time, we are planning to reduce CO 2 direct emissions at our E&P operations. Our plans are assuming a Brent crude oil price scenario of 75 $/BBL in 2025, increasing to our long-term case of 80 $ in real terms 2028 (i.e. taking into account management’s assumption relating to the average inflationary rate during the plan period, i.e. 2% per annum). In money of the day, we see Brent crude oil prices at 69 $/bbl till 2033, then declining to 49 $ in 2050 to take into account our expectation of the energy transition impact and a possible significant decline in demands for crude oil.
Against those pricing assumptions, we plan to grow production at a compounded average growth rate “CAGR” of about 2-3% through 2030. This growth rate is discounting the planned divestment of part of our working interests at certain assets; before divestments the expected CAGR would be in the range of 3-4%. The main drivers of this expected growth are the development of our recent discoveries, such as the offshore of Cyprus and Indonesia, Coral North in Mozambique and Baleine phase three in Cote d’Ivoire, as well as new fields start-ups and ramp-ups in Congo, Libya, Qatar, Angola, and Norway. Our production plans contemplate a gradual increase of the proportion of natural gas in the production mix till achieving a share higher than 60% by 2030 (including natural gas liquids).
Due to market risks and uncertainties, management intends to retain a strong focus on capital and cost discipline, on shortening the projects cycle and on reducing the time-to-market of our reserves as levers to maintain our development projects profitable also at lower crude oil prices than our planning assumptions.
We plan to invest more than €5 billion per year on average in the next four-year plan 2025-2028 to explore for and develop hydrocarbons reserves. Those expenditure do not include expected expenditures that will be incurred by our participated joint ventures and associates, like the expenditures that will be incurred by Var Energi, by Azule Energy and by Ithaca Energy. Those equity-accounted entities are expected to self-finance their respective capital expenditures needs, without recurring to shareholders’ s funds. Our capex plan includes the assumptions of continuing inflationary pressures throughout the E&P supply chain and the depreciation of the EUR vs the USD.
Our strategy is designed to retain profitable and cash-generative E&P operations, by leveraging accretive exploration and effective development and field operation activities to accelerate the time-to-market of reserves thus reducing projects’ pay-back period, to minimize financial exposure and to reduce the full cycle cost of the barrel and hence the Brent breakeven price. The execution of an asset disposition plan will help accelerate the cash conversion cycle of reserves, i.e. in a stage earlier than development and production. Asset dispositions will target high-potential discoveries, where we retain large working interests and we can dilute our stakes maintaining the operatorship in line with our dual exploration model, as well as mature producing fields. The cash proceeds from asset disposals will reduce the cash requirements to fund the organic growth plans.
We believe that this strategy based on capital discipline and acceleration of the cash conversion cycle of reserves will reduce the segment’s financial exposure and the Brent price of breakeven given current uncertainties in the short- and medium-term outlook due to a possible macroeconomic slowdown and risks of oversupplies, as well as the risks posed by the energy transition in a longer term.
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We plan to carefully select our development projects against our pricing assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure and the execution risk leveraging on a phased approach in developing our projects. Although we plan to deliver our planned projects on time and on budget, several of our projects are complex due to scale and reach of operations, environmentally sensitive locations, external conditions, including offshore operations, industry potential bottlenecks like in the case of shipyards and rigs and other industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. In addition, costs of industrial inputs (labor, materials, field services) are expected to rise driven by inflation, albeit at a smaller pace than in recent years. Sticky inflationary pressures in the oil supply chain have been driven by the process of rightsizing, restructuring and investment reduction executed by suppliers of specialized oilfield services, rigs, and other equipment in response to the prolonged downturn in the oil sector from 2015 throughout the COVID pandemic, resulting in constraints on the supply of vessels, rigs and skilled labor. Our capital plans included our best assumptions of expected cost increases due to inflation. To deliver on our expected rate of returns at our projects we are planning to:
performing project activities in accordance with a so-called parallel approach as opposed to a sequential approach, for example the discovery appraisal and pre-fid activities, by upgrading existing plants and vessels and by deploying a phased project approach to achieve early start-up and then ramping up production, thus reducing the time-to-market and financial exposure; examples of this approach are the Baleine project in Côte d’Ivoire where we have refurbished and upgraded an existing vessel thus reducing the timing of first oil and the Congo LNG project, which has stated operations in just twelve months following the investment decision thanks to utilization of existing facilities and technologies. While already producing positive cash flows in the early production phase, both projects have entered the ramp-up phase. The Baleine projects has already achieved the first oil of the second phase at the end of 2024 with the commissioning of a second FPSO vessel; while the Congo FLNG project is due to achieve the start of phase two by end of 2025 with the expected installation and commissioning of a vessel for the floating production of LNG;
signing master agreement with our main supplies to maximize cost savings and by designing facilities using a modular approach that enables us to extend the useful lives of plants and vessels;
reducing the time to complete tender processes to sign up contracts with EPC contractors and other key suppliers reducing the risk of future price revisions;
leveraging on near-field or infrastructure-led exploration that has proven to be effective at increasing the reserves at already producing fields thus enabling to exploit synergies from existing facilities so to reduce the time to market; for example the important natural gas discoveries off Indonesia are planned to be developed through two main production hubs, the Northern Hub and the Southern Hub, and will leverage the production facilities existing in the area, including the spare capacity available at the Bontang liquefaction plant and the operated Jangkrik FSU vessel. Those development strategies will help reduce the time-to-market of reserves and obtain savings in development activities;
continuing in-sourcing critical engineering and project management phases, for example by exercising tight control over construction, hook-up and commissioning, which based on our experience could significantly improve the ability of the Company to carry out projects on time and on budget;
applying our design-to-cost method whereby the Company has redirected its exploration efforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies, for example the Congo LNG project and the discoveries in Indonesia. We expect that cost control and profitable operations will be supported by a continued progress in our technologies designed to improve drilling performance and the recovery factor and digital investment to improve workplace safety and asset integrity thus reducing asset downtime.
According to our plans, exploration will continue ensuring cost-effective replacement of produced reserves, supporting cash generation and evolving our reserve portfolio towards the planned mix of resources featuring a bigger weight of natural gas. Our exploration initiatives will comprise two clusters:
Exploration projects in prospects near-field and in proven/mature areas and in other infrastructure-lead basins i.e. in permits close to producing fields, where we can leverage existing infrastructures to readily develop the discovered resources, attaining fast contribution to cash flows and production levels with minimum impact on expenditures;
Selected initiatives in high-risk/high-rewards plays, where we retain a high working interest and the operatorship, which will enable us to apply our dual exploration model in case of material discoveries with a view of accelerating the conversion of resources into cash.
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In the four-year plan 2025-2028, we will invest significant amount in exploration activities.
Our production plans include assumptions relating to production levels in certain countries that are particularly exposed to risks of disruptions and political instability. To factor in possible risks of unfavorable geopolitical developments in those countries, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, social unrest, clashes, and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. This contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. Furthermore, in recent years we have pursued a strategy intended to diversify the geographic reach of our operations aiming at reducing the geopolitical risk in our portfolio.
Global Gas & LNG Portfolio
The European natural gas market has found a better balance from the start of the 2024-2025 winter season in the Northern Hemisphere due to colder temperatures than prevailing seasonal trends of recent years, renewables underperformance, fast depletion of inventories and as Russian gas flows to Europe have almost dried up, leaving Europe more dependent on imports of overseas LNG loadings in competition with Asian buyers. In February 2025, natural gas prices have reached their highest level in over two years. However, we expect natural gas prices to weaken in the medium-to-long term due to a possible structural decline in EU consumption driven by growing penetration of renewables and massive investment to grow production of natural gas and to build new liquefaction plants in the USA and Qatar, with other options like Canada entering the LNG arena to monetize its huge amount of reserves. Against this backdrop, our GGP business has established a business model designated to achieve steady profitability and cash generation independently from trends in natural gas prices and in market volatility. This business model is leveraging the continuing optimization of the segment’s asset portfolio (long-term contracts with contractual flexibilities, physical flows, access to transport capacity, availability of storage capacity, trading activities) and integration with E&P by trading growing amount of equity LNG to capture the full margin of commercial opportunities, as well as contractual renegotiations.
Our planning assumptions are discounting the zeroing of natural gas purchases from Russia, although our long-term supply contracts with Russia’s state-owned company Gazprom are still valid. Our sales commitments relating to supplies to our retail subsidiary Plenitude, the supply of natural gas to our natural gas-fired power plants owned by the subsidiary EniPower and other ongoing selling obligations will be covered by purchases under our outstanding long-term contracts with suppliers other than Russian counterparts and by increasing off-takes of equity gas, maximizing the integration between the E&P and the GGP segments.
Against this scenario, the Company’s priority in its GGP business is to retain stable profitability and cash generation based on the following drivers:
(i) To continuously renegotiate our long-term gas supply and sale contracts to align pricing terms and delivery quantities to current market conditions and dynamics as they evolve;
(ii) To effectively manage our portfolio of assets (supply and sales contracts, their flexibilities and optionality and logistics availability) in order to extract value from portfolio flexibilities through continuing optimizations;
(iii) To grow the LNG marketing business leveraging on the integration with the E&P segment with the aim of maximizing the profitability of equity natural gas along the entire value-chain. We plan to increase contracted supplies of LNG through new equity supplies like from Algeria, Congo, Qatar, Mozambique, and Cyprus leveraging the expected ramp-up of equity production of LNG to achieve a robust portfolio of reselling opportunities, targeting a volume of contracted LNG of about 20 MTPA by 2030;
We make use of commodity and financial derivatives to hedge against the risks of different indexation formulas in our gas procurement costs vs. selling prices in relation to contracted sales or highly probable sales. A number of these derivatives may not be accounted as hedges in accordance with IFRS and consequently are recorded through profit and loss and may add a component of volatility to our results of operations. We believe those derivatives are normally risk-reducing, although there is also a degree of uncertainty about results. Furthermore, we are also making use of derivatives to improve margins by leveraging on market volatility and availability of assets like the flexibilities associated with our take-or-pay gas contracts, LNG contracts, transport rights to capture arbitrage opportunities (for example the winter vs summer spread, the spot vs. the Brent indexation spread) and time lags in contracts indexation formulae. Those derivatives are of speculative nature with gains and losses recognized through profit. Although asset availability tends to limit the possible downside risks associated with those derivatives, still the Company is exposed to price volatility and to the incurrence of losses also of significant amount.
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Refining
The downstream oil refining business is exposed to the structural headwinds of the European industry due to lack of scale, global overcapacity, higher energy costs and environmental expenses than in other geographies and tough competition from player in Middle East, Far East and Africa which can count on advantages due to economies of scale, lower expenses and proximity to expanding markets. The profitability of our refining business will be affected by weak growth in Europe and a structural reduction in consumption of fossil fuels in our key European markets due to the expected penetration of EVs and mandated measures by EU governments to reduce CO 2 emissions. Based on those assumptions, we plan to retain a strong focus on plant efficiency and reliability, cost discipline, measures to optimize natural gas consumption in the operations to maximize our realized refining margins. Considering the structural weaknesses of the refining sector in Europe, we plan to continue evaluating viable solutions to restructure and downsize our oil-based, operated refineries in Italy. Currently, works have started to transform the Livorno hub into a biorefinery, based on the same reconfiguration process that we deployed in the past to upgrade the Gela and the Venice refineries. The Livorno biorefinery is expected to start operations at the end of 2026, and by that time it is planned to be contributed to Enilive. Other refinery transformations are being evaluated by the management.
Enilive (biofuels & marketing)
Enilive, operational from January 1, 2023, has been established through the spin-out of Eni’s activities in the field of biofuels manufacturing and in the retail marketing of fuels and non-fuels products. It also engages in selling fuels to wholesale markets and the cargo market. Enilive is designated to market increasing volumes of decarbonized fuels to people on the move, leveraging integration with its biorefineries as well as to grow the share of revenues from non-fuel product and service leverage emerging trends in mobility and marketing innovations. In 2024, Eni and private equity fund KKR agreed the terms and conditions for an investment of €2.97 billion of KKR by acquiring a noncontrolling interest of 25% in the share capital of Enilive. This deal was finalized in March 2025. In February 2025, KKR agreed to purchase a further 5% interest in Enilive bringing its total ownership interest to 30% on the same terms and conditions as the transaction agreed in October 2024. This transaction is expected to close shortly. Those transactions highlight the value of the Enilive business model which integrates manufacturing operations in the biofuels segment with a significant retail market presence based on a network of modern and advanced service stations. Once the transaction closes, Eni will continue fully consolidating Enilive results because the proposed transaction does not entail change of control.
The Group plans to significantly grow the manufacturing capacity of biofuels with the goal of reaching more than 3 million tons of installed capacity in 2028 through the upgrading of existing plants, the planned entry into operations of other biorefineries in Italy and international expansion as we plan to start operations at two new plants in South Korea in partnership with LG Chem and in Malaysia in partnership with Petronas and Euglena. International expansion will leverage our co-developed “Ecofining” technology to produce hydrogenated vegetable oils “HVO”. The management is engaged in building a reliable and sustainable supply chain of bio-feedstock to be processed at the Company’s manufacturing units. As part of that plan, we are developing a vertically integrated business model, which contemplates establishing a network of agricultural hubs in many of the countries of E&P operations, in Africa, in Italy and in other geographies. This activity is intended to not compete with the food chain and to produce a vegetable oil at Eni’s dedicated mills by treating supplies of raw vegetables grown by local farmers, supplied to Eni’s biorefineries under long-term agreements. The agricultural business will be scaled up in the planning period to reach a level of supplies of more than 1 mln tonnes by 2030. This feedstock availability will strengthen Enilive’s access to supplies and boost margins on the production of biofuels, insulating our company from the volatility of raw materials costs. We are also planning to develop the offer of sustainable aviation fuels to diversify the product mix.
In Marketing activities, where we expect a very competitive environment, we are seeking to retain steady and robust profitability mainly by focusing on innovation of products and services anticipating customer needs, strengthening our line of premium products, as well as efficiency. We plan to enhance the network by upgrading several service stations to transform them from traditional outlets into mobility hubs to capitalize on the growing demand for a wider mobility experience and by expanding the number of service stations where we will market our innovative HVO-based biofuels and other alternative energy carriers (for example the service of recharging electric vehicles and biomethane). Profitability will be also supported by increasing sales of non-fuel products and services leveraging on new formats and partnerships with established operators in various fields and cross-selling opportunities with customers of Plenitude. Based on those drivers, the management expects that Enilive will significantly improve its profitability going forward.
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Plenitude
Plenitude, Eni’s subsidiary managing the Group legacy retail marketing of natural gas business and related services, the renewable electricity business and the network of charging points for EV will leverage the synergies among those businesses to improve its profitability going forward. Plenitude has the mission to supply its customers with increasingly decarbonized energy commodities going forward. In 2024, Eni and private equity fund EIP agreed the terms and conditions for an investment of almost €0.8 billion of EIP by acquiring a noncontrolling interest of 10% in the share capital of Plenitude, through two distinctive but paired transactions: the first one relating to the purchase of 7.6% of the share capital of Plenitude closed in March 2024; a second transaction relating to a 2.4% stake was finalized at the end of March 2025.
We plan to accelerate the development of the installed capacity to produce renewable power to reach about 10 GW of installed capacity by the end of the plan. Our network of charging points for electric vehicles will be expanded with the objective of building 33 thousand rechargers by 2028. We plan to selectively grow our customer base, with the target to reach over 11 million customers by 2028 and to boost profitability by extracting more value from the customer portfolio, by supplying an increasing volumes of equity renewable energy, as well as by expanding the offer of new products and services other than the commodity and by continuing innovation in marketing processes including the deployment of digitalization in the acquisition of new customers, a reduction in the cost to serve and effective management of working capital. Customer retention and expansion will also leverage cross selling opportunities and joint marketing initiatives with Enilive. Based on those drivers, the management expects that Plenitude will significantly improve its profitability going forward.
Chemicals business
In 2024, the Eni’s chemicals sector managed by the subsidiary Versalis reported another year of losses due to the structural weaknesses of the business, because of global overcapacity and rising competition from producers in USA, Middle and East Asia, which are advantaged by economies of scale and lower operating expenses, against the backdrop of sluggish economic growth in Europe and a slowdown in demand for plastics, which exacerbated the price competition. Furthermore, the Eni’s business was negatively affected by comparatively higher costs of plant utilities indexed to natural gas (for example the cost of natural gas in Europe is four, five times that of USA) and environmental obligations than in other geographies, which made overseas products more competitive than ours, and those trends negatively affected products margins and sales volumes. Those negative trends are likely to continue affecting the business performance in the future. The Company has begun a plan of restructuring and transformation of Versalis, which will leverage Eni’ technologies to establish new product platforms in the segments of transition and circular economy, as well as upgrading chemicals from bio-feedstock and specialties, seeking to reduce exposure to the most commoditized market segments and to achieve a structurally more sustainable and competitive products mix. The main levers of the industrial plan comprise: (i) to restructure and to shut down permanently loss-making cracking units and to build installations related to the transition or the circular economy in their place; (ii) to develop the segment of bioplastics and biochemicals leveraging the integration of the recently-acquired Novamont; (ii) to increase the weight of differentiated products called “specialties” which, based on our experience, are more profitable than commodity plastics, also leveraging on growing our market share in the compounding and specialized formulations through Finproject that we acquired in 2021, (iv) to develop the business of the circular economy by increasing production of polymers made from the mechanical recycling of waste plastics or through the expected launch at industrial scale of a technology for producing polymers via the chemical recycling of used plastics, currently in a pilot phase. Based on those actions, the management expects Versalis to recover profitability by the end of the plan period.
Expected Group financial performance
For 2025, we expect net cash provided by operating activities (“operating cash flow”) and cash from divesting activities to be the primary sources of cash to fund our capital plans, returns to shareholders and other commitments. Our operating cash flow is mainly driven by our E&P business due to its relative larger size and higher profitability compared to our other businesses. Therefore, our operating cash flow is exposed to the volatility of hydrocarbons prices, which are highly correlated to the macroeconomic cycle, the global balance between demands and supplies and the worldwide levels of inventories, among other things. Based on our experience, those backdrop conditions can vary very rapidly and accordingly hydrocarbons prices corrections can be sudden and severe. Due to those considerations, our operating cash flow features high variability and little predictability.
The 2025 outlook is compounded by many risks and uncertainties in connection with the uneven pace of recovery in the global economy, considering an ongoing slow pace in the recovery of the Chinese economy and other imbalances in what is the second largest consumer of crude oil in the world, stagnant activity in the Eurozone, and the impacts of the recently enacted tariffs by the new US administration on goods imported from key commercial partners (China, Canada, Mexico and the Eu among others). On the supply side, factors that are expected to affect crude oil prices include the willingness of the OPEC+ cartel to stick with its current plans of gradually tapering the production cuts, the level of compliance of cartel members with quotas and the retention of capital discipline by major oil companies. Finally, other factors will be the monetary policy of the US Federal Reserve which will greatly influence movements in currency markets and the economic performance of developing countries, and the evolution of the conflict between Russia and Ukraine and other geopolitical risk factors as the situation in the Middle East. Any negative development in the macroeconomic context could negatively affect the price of crude oil.
From an industrial standpoint the greatest uncertainties will involve the ability of US shale producers to continue growing production despite financial discipline and reports from market sources that shale growth may have plateaued. Another factor will be any possible development in the political relationships involving USA, Iran, and Venezuela which could lead to the reimposition of sanctions on exports of crude oil. Considering those risks and uncertainties, we are assuming a Brent crude oil price of 75 $/bbl for 2025, a lower level than in 2024. As disclosed in Item 3, our results of operations and cash flow are subject to trends in crude oil prices and, to a lesser extent, prices of natural gas and products. We estimate that each one-dollar change in the price of the Brent crude oil from our planning assumption impacts our cash flow from operation by around €140 million. We are assuming spot prices of natural gas at European hubs to be around 14 $/mmBTU, higher than in 2024, and the Company’s gouge of the refining trading environment, SERM at 4.7 $/bbl; the average EUR vs USD exchange rate is assumed at 1EUR=1.05 USD. We are estimating our cash flow operations to vary by about €100 million for each one-dollar change in the spot prices of natural gas in Europe, while we are estimating our cash flow operations to vary by about €130 million for each one-dollar change in the SERM.
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As opposed to the volatility of our operating cash flows, our funding requirements to develop hydrocarbons reserves are characterized by a low degree of flexibility. The E&P segment is a capital-intensive business and needs large amounts of financial resources to support production volumes and to develop new oil&gas reservoirs. Hydrocarbons development projects are long lead-times projects due to the complexity of activities to be carried out before production is achieved, hence the payback of capital projects usually begins in a very distant future, leaving the Company exposed both financially and to price volatility during the execution phase. Once a final investment decision has been made to develop a new hydrocarbon field and contracts have been signed to build production facilities, platforms, vessels, FPSO units and other equipment, management may face difficulties at postponing or stopping cash outlays in response to a sudden contraction in operating cash flows. Management can reduce incremental investments at producing fields, like workover or infilling operations, when economic and operating conditions allow for that. The Company is executing an important growth plan and in case the scenario for crude oil and natural gas prices evolves adversely, the Company may experience a cash flow shortfall leading to inability to fund its minimum capital requirements and the dividend by internally generated funds. In such a situation, the Company could be forced to take on new debt or to draw its liquidity reserves and that could negatively affect the Company’s results of operations, returns, and put at risk its targets of leverage. We plan to make an amount of capital expenditures lower than €9 billion in 2025, driven by new project start-ups and ramp-ups in E&P, cost inflation, by development of the renewable generation capacity of our subsidiary Plenitude, the manufacturing capacity of biofuels, and the restructuring of the chemicals business and refineries. The businesses linked to the energy transition are currently absorbing cash because they are in a ramp-up phase.
Furthermore, we expect to fund a significant portion of the planned cash requirements in 2025 through the execution of an asset disposal plan which will encompass a possible dilution of our working interest in E&P assets (for example large discovery areas or fields currently in production phase). Those proceeds are included in our 2025 financial plan. However, the execution of our disposal plan is exposed to risks in connection with an uncertain macro-outlook and the announcement of asset disposal plans by several companies competing with Eni, which could reduce transaction values. On March 19, 2025, Eni and Vitol agreed on the economic terms and conditions of the farm-out to Vitol of a 25% working interest in the Eni-operated Congo FLNG project (with Eni retaining a post-closing 40% w.i.) and of a 30% working interest in the Eni-operated Baleine oil project offshore Cote d’Ivoire (with Eni retaining a post-closing 47.25% w.i.) for a cash consideration of USD1.65 billion and economic date January 1, 2024. Closing is subject to customary regulatory approval and other conditions. Those transactions will significantly derisk the Eni disposal plan for 2025.
The management is retaining a prudent financial framework, based on capital and cost discipline, selective investment criteria, pre-set cash allocation priorities and adoption of a ceiling to the maximum amount of debt – that the Company may incur . New capital projects are approved when they fit strict economic criteria, including being profitable in a low-price environment and having short pay-back periods and reduced time-to-market to limit financial exposure. By applying those criteria, we aim to increase projects’ resilience to possible risks relating to price volatility and, in the long-term, to the energy transition.
One on the pillars of our financial discipline is our internal requirement of self-financing the planned committed capital expenditures through operating cash flows, also leaving a safety margin. For 2025 under our pricing, exchange rate and inflation assumptions, we expect to generate enough cash flow from operations to fund planned capital expenditures of about €9 billion, leaving a surplus to cover other cash requirements. That surplus and the expected proceeds from our disposal plan will be deployed to fund other Company’s cash commitments, which will mainly comprise cash return to shareholders, disbursements in connection with already closed acquisitions and the repayment of lease liabilities and other commitments, without the need of taking on new finance debt. Our expected net borrowings level will reflect the planned execution of reverse factoring transactions whereby the payables recognized in connection with the purchase of capital goods are classified as finance debt at inception due to the deferral of the payment terms accepted by the suppliers. For 2025, management expects oil and gas production to be in line with 2024.
Those plans are exposed to the volatility of hydrocarbons prices and refining margins. Brent prices have been trending in with our expectations so far in 2025, averaging about 76 $/bbl in the period January 1 – March 31, 2025, albeit on a declining trend. Currently, we are estimating our operating cash flow to vary by approximately €140 million for each one-dollar change in the Brent crude oil price with respect to our base case assumption of 75 $/bbl for 2025. Also, natural gas prices have been trending in line with Company’s expectation, with the average spot price in the same period at around 14 $/mmBTU; we are estimating our cash flow operations to vary by about €100 million for each one-dollar change in the sport prices of natural gas in Europe. The Company’s refining margins have been performing slightly lower than expected, with an average of around 4 $/bbl in this first part of 2025. Currently, we are estimating our cash flow operations to vary by about €130 million for each one-dollar change in the SERM.
For planning purposes, management is assuming a flat USD/EUR exchange rate 1.05 U.S. dollars per euro in the 2025-2028 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty. In the first quarter of 2025 the USD/EUR exchange rate was better than expected with the USD strengthening further against the EUR. Currently, we are estimating our cash flow from operating activities to vary by about €530 million for a 5 USD/cent movement in the USD/EUR cross rate.
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For further information see Item 3 – Risk factors and notes to the consolidated financial statements.
This financial framework is complemented by the retention of a liquidity reserve consisting of cash on hand, marketable securities and committed credit lines, which have been sized to help the Company withstand a sudden contraction in operating cash flows, a spike in the volatility of commodity prices leading to increased margining obligations in connection with our derivatives transactions, or short-term difficulties in accessing capital markets. At the end of 2024 this liquidity reserve amounted to €16 billion of cash on hand and held-for-trading securities and other financing receivables and €9 billion of committed borrowings facilities.
The actions planned in the next four-year period featuring profitable hydrocarbons production growth, an increasing contribution of our transition businesses managed by Plenitude and Enilive due to a planned expansion of renewable capacity, biofuels manufacturing capacity additions and synergies from cross selling opportunities in the retail space to customer of energy products and fuels, continuing portfolio optimizations in GGP, and expected progress in the restructuring of downstream oil businesses coupled with capital and cost discipline will underpin a solid cash generation. On those bases, and considering the proceeds expected from the execution of our disposal plan, we expect to be in the position to ensure competitive shareholders returns and to retain a robust balance sheet with our core ratio of net borrowings to total equity – leverage – before the effects of IFRS 16 expected to remain within the planned range of 0.1-0.2 across the plan period, lower than our previous financial plans, and expected to average around 0.16 in the four-year plan.
In the next four-year plan 2025-2028, we expect to incur about €33 billion of capital expenditures with the following break-down for the main businesses:
More than €20 billion to explore for and develop new oil&gas projects, mainly natural gas and LNG initiatives, to maintain the production plateau at existing fields, and to explore for new hydrocarbons reserves, both in new, high-risk prospects and in near-field acreage and mature areas;
around €1.2 billion per year to develop the renewable generation capacity, the network of EV charging points, consolidate and growing retail and business customer base, as well as other initiatives of Plenitude;
around €0.5 billion per year invested in increasing biorefining capacity in Italy and abroad and improving performance of Enilive service station network. It is worth mentioning that the expansion plans of Enilive in overseas markets will be executed through non-consolidated ventures therefore, Eni cash flows from investing activities will not reflect those significant amounts of capex;
around €2 billion for the five-year plan to restructure the Chemical activity and to develop new products platform in the biochemistry and in the circular economy;
around €0.5 billion to develop the ongoing initiatives in the businesses under development of upgrading depleted natural gas fields into hubs to permanently store CO 2 and related facilities; those amounts will include development of agricultural hubs to produce feedstock for Eni’s biorefineries.
We expect to fund part of the cash requirements of our capital expenditure programs through the net proceeds of a disposal plan (i.e. in excess of the cash-outs related to the closing of ongoing acquisitions and possibly other minor tuck-in acquisitions). By this way, we see our net cash used in investing activities to average less than €7 billion per year in the plan period.
To support the Group cash generation, we are planning to execute a cost saving program of about €1.8 billion in the 2024-2027 period.
Due to cash flow unpredictability as a function of the scenario volatility, management is always allocating a portion of funds to uncommitted projects, which can be more comfortably cancelled or postponed in case of a downturn in the oil prices. In the four-year plan 2025-2028 out of the planned capital budget of €33 billion, the portion allocated to uncommitted projects represents 15% in 2025, and an average of more than 40% in the four-year financial projections.
Our financial projections and capital investment decisions are based on management’s evaluation of the cost of capital to the Group at about 6%. This rate is one percentage point lower than in 2023 due to a perceived reduction in the market risk premium and lower risk-free yields. When making final investment decisions, the thresholds against which specific investment internal rate of returns are benchmarked, are defined by adding to the above-mentioned cost of capital, a risk premium associated with the country where the investment will be executed and an additional business risk premium to cover high-risk investments (like exploration projects).
This financial outlook is subject to the volatility of crude oil prices and to the other risk factors described in Item 3.
Remuneration policy
The management is committed to delivering on a progressive and competitive shareholder remuneration policy, which is reflective of the expected growth in underlying earnings and cash flows at a constant scenario basis and of the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders’ remuneration, management is also considering its assumptions about future trends in the crude oil prices and in other market variables.
As part of that framework, the management is planning to return shareholders an amount of cash representing a proportion in a range from 35 to 40% of the expected cash flow from operations before working capital requirements, an improvement compared to our latest announcements on shareholders’ remuneration policy (previously it was 30-35% of the expected cash flow from operations before working capital requirements).
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Distributions will include a combination of dividends and share repurchases. We expect to gradually increase the dividend in future years in line with the expected improvement in the Group underlying financial performance, and to enhance the dividend resilience to the scenario. Share repurchases will complement the dividend and are intended as a flexible tool to distribute raising amount of cash generated by the business in case of upside in the scenario variables or other factors. According to our financial framework, in case the Group performs better than management’s plans due to a better pricing environment than management expectations, or to an improved underlying performance of the business, management intends to distribute up to 60% of the incremental cash flows through share repurchase (in line with the past). Furthermore, if our disposal plan delivers more cash proceeds than planned, the Company may decide to further increase the percentage of cash flow distribution, like it was accomplished in 2024 when the cash returns to shareholders exceeded the planned upper limit of the percentage range of cash flow distribution (i.e. more than 35%).
In case the scenario evolves contrary to management’s expectations, the Company intends to preserve shareholders’ returns leveraging on the Company’s financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio.
For 2025, having assessed the progress of the Company in executing its strategy, basing on a sound financial position and management’s scenario assumptions, management is planning to increase the annual total dividend to €1.05 per share, up 5% from 2024. This dividend is expected to be paid in four quarterly instalments in September 2025, November 2025, March 2026, and May 2026. Therefore, the expected cash out for dividend payments in 2025 will include two instalments of the 2024 dividend of €0.25 per share each, and two instalments of the planned 2025 dividend of approximately the same amount.
Furthermore, consistently with its remuneration policy and as the current authorized buy-back program has been completed by February 2025, Eni plans to execute a new share buyback program of at least €1.5 billion for 2025, following due shareholders’ approval at the Annual General Meeting scheduled in May 2025.
Off-balance sheet arrangements
Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in “Item 18 – Note 28 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments undertake-or-pay or ship-or-pay contracts in the gas business, are described under “Contractual obligations” below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses.
Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources.
Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. These arrangements are described in “Item 18 – Note 28 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”.
Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term financing requirements and to settle obligations. Such a situation would negatively impact the Group results and cash flow as it would result in the Company incurring higher borrowing expenses to meet its obligations, divesting assets at discount to their fair values or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities as we retain cash reserves and cash on hand to meet currently foreseeable funding requirements. The Group cash reserve consists of cash on hand and very liquid financial assets (short-term deposits and held-for-trading securities) of €16 billion and committed borrowing facilities of €9 billion for a total liquidity reserve of about €25 billion. This liquidity reserve according to our financial framework can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity up to a 48-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – Note 28 to the Consolidated Financial Statements”. Due to the continued volatility in commodity markets, we might incur increased liquidity risks due to the need to deposit larger amounts of cash collateral at financial institutions and commodity-based exchanges to guarantee the settlement of derivatives contracts (margin calls). The Group is adopting measures to strengthen its financial headroom to cope with possible market turbulence. To withstand uncertain financial markets and macroeconomic conditions, the Group has retained a level of financial flexibility in planning future capital requirements to grow the business, as a portion of the capital expenditure plan of €33 billion of the four-year period 2025-2028 is allocated to uncommitted projects (15% in the first year, more than 40% on average in the plan).
W o r king capital
Management believes that, considering unutilized credit facilities, the Company’s liquidity reserves, our credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements.
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C r edit risk
The credit risk is the risk that our commercial or financial partners fail to pay amounts due to us in connection with the provision of goods and services or financing. In recent years, the Group has experienced a significant level of counterparty default due to Europe and Italy’s weak economic growth and financial difficulties affecting national oil state-owned entities and local companies, which are joint operators in Eni-lead projects. It is possible that the ability of our debtors to pay amounts due to us will deteriorate in the next future, in case of a deepening of the current economic slowdown, leading us to recognize significant amounts of expected credit losses in future reporting periods.
For a description of how the Company manages the credit risk see “Item 18 – Note 28 to the Consolidated Financial Statements”. For more information about the allowance for doubtful accounts calculated in accordance with the expected credit loss model see “Item 18 – Note 8 to the Consolidated Financial Statements”.
Volatility of the macro environment
Global financial markets are volatile due to several macroeconomic risk factors and unpredictable developments. In case of unpredictable developments in the Russia military aggression against Ukraine or in the Middle-East tensions, intensification of trade disputes following recent US administration measures to introduce tariffs on several imported goods targeting several trading partners, spreading of a new pandemic disease or a financial crisis lead to a downturn in economic activity and energy demand, in the event of a credit cruch, or if Eni is unable to access the financial markets (including cases where this is due to Eni’s financial position or market sentiment as to Eni’s prospects) at a time when cash flows from Eni’s business operations may be under pressure, the Company may incur significantly higher borrowing costs than in the past or difficulties obtaining the necessary financial resources to fund Eni’s development plans, therefore jeopardizing Eni’s ability to maintain long-term investment programs. A reduction in the investments needed to develop Eni’s reserves and to grow the business may significantly and negatively affect Eni’s business prospects, results of operations and cash flows, and may impact shareholder returns, including dividends and the share price appreciation.
Ma r k et risk
The fair values of Eni’s financial assets and liabilities as well as expected cash flow from highly probable transactions are exposed to movements in commodity prices, currency fluctuations and changes in interest rates. Unfavorable movements in prices and rates could significantly and negatively affect Eni’s results of operations and cash flow.
The Group does not hedge its strategic exposure to volatile hydrocarbons prices in the activity of producing its oil&gas reserves, except for specific transactions or particular market circumstances. Other strategic, unhedged exposures include long-term gas supply contracts for the portion not balanced by sales contracts (already stipulated or expected), the margin deriving from the chemical transformation process, the refining margin and long-term storage functional to the logistic-industrial activities. The Group enters into commodity derivatives to manage exposure to price volatility in commercial activities involving the reselling of commodities in view of optimizing margins. Frequently, exposures to price volatility or to different indexation between the cost of supplies and the reselling prices are not hedged on a transaction-by-transaction basis; instead, exposures are pooled at Group level and derivatives are activated to hedge net exposures, with gain and losses recognized through profit.
Eni’s euro-denominated subsidiaries incur revenues and expenses in currencies other than the euro or are otherwise exposed to currency fluctuations because prices of oil, natural gas and refined products generally are denominated in, or linked to, the U.S. dollar, while a significant portion of Eni’s expenses are incurred in euros and because movements in exchange rates may negatively affect the fair value of assets and liabilities denominated in currencies other than the euro. Therefore, movements in the U.S. dollar (or other foreign currencies) exchange rate versus the euro affect results of operations and cash flows and year-on-year comparability of the performance. These exposures are normally pooled at Group level and net exposures to exchange rate volatility are netted on the marketplace using derivative transactions. However, the effectiveness of such hedging activity is uncertain, and the Company may incur losses also of significant amounts.
Eni is exposed to fluctuations in interest rates that may affect the fair value of Eni’s financial assets and liabilities as well as the amount of finance expense recorded through profit. Eni enters into derivative transactions with the purpose of minimizing its exposure to the interest rate risk.
For a description of how the Company manages the Market risk see “Item 18 – Note 28 of the Notes on Consolidated Financial Statements”.
R esea r ch and de ve lopment
For a description of Eni’s research and development operations in 2024, see “Item 4 – Research and development”.
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Item 6. DIREC T OR S , SENIOR MA N A GEMENT AND EMP L O YEES
Di r ectors and Senior Management
The following table lists the Company’s Board of Directors as at December 31, 2024:
|
Name |
|
Position |
|
Year elected or appointed |
|
Age |
|
Giuseppe Zafarana |
|
Chairman |
|
2023 |
|
61 |
|
Claudio Descalzi |
|
CEO |
|
2014 |
|
69 |
|
Elisa Baroncini |
|
Director |
|
2023 |
|
58 |
|
Massimo Belcredi |
|
Director |
|
2023 |
|
63 |
|
Roberto Ciciani |
|
Director |
|
2023 |
|
52 |
|
Carolyn Adele Dittmeier |
|
Director |
|
2023 |
|
68 |
|
Federica Seganti |
|
Director |
|
2023 |
|
58 |
|
Cristina Sgubin |
|
Director |
|
2023 |
|
44 |
|
Raphael Louis L. Vermeir |
|
Director |
|
2020 |
|
69 |
In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members.
The current Board of Directors was appointed by the ordinary Shareholders’ Meeting held on May 10, 2023 which also established the number of Directors at nine for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2025.
The Board of Directors is appointed by means of a slate voting system: slates may be presented by the shareholders representing at least 0.5% of the Company’s share capital. According to the Eni By-laws, three out of nine Directors are appointed from among the candidates of the non-controlling shareholders.
Giuseppe Zafarana, Claudio Descalzi, Elisa Baroncini, Roberto Ciciani, Federica Seganti, and Cristina Sgubin were the candidates of the Ministry of the Economy and Finance. Massimo Belcredi, Carolyn Adele Dittmeier and Raphael Louis L. Vermeir were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Giuseppe Zafarana as the Chairman of the Board of Directors and, on May 11, 2023, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.
Four Directors out of nine were drawn from the less represented gender, reaching the ratio of at least two-fifths of the Directors as provided by Italian law and Eni’s By-laws.
The following provides details on the personal and professional profiles of the Directors.
Giuseppe Zafarana was born in Piacenza in 1963 and has been Chairman of the Board of Directors of Eni since May 2023. He is a member of the Italian Corporate Governance Committee. Furthermore, he is Chairman of the Board of Directors of Fondazione Eni Enrico Mattei (FEEM) since June 28, 2023 and, since 13 June 2024, Chairman of the Board of Directors of Finint Investments, an asset management company belonging to the Banca Finint Group.
He graduated in Law, Political Sciences and Economic and Financial Security Sciences and obtained a II level Master's Degree in Corporate Tax Law from the Luigi Bocconi University in Milan.
Experience
His military career began in 1981, when he attended the 81st "Osum II" course at the Corps Academy. He went into service in 1985 and held several operational assignments in Lombardy, Veneto, Lazio, Calabria and Sicily, commanding various divisions, taking on assignments in the leading investigative departments of the Corps and carrying out relevant Military staff functions. From 1995 to 1997, he attended the biennial Advanced Tax Police Course and a highly qualified stage in the United States of America, on the subject of contrasting organised crime. He was Provincial Commander of Rome (from 2003 to 2008) and Regional Commander of Lombardy (from 2015 to 2016).
Moreover, he performed several assignments in the training sector, in particular as commander of the Academy of the Guardia di Finanza, and later served as Chief of Staff of the General Command of the Guardia di Finanza (from 2016 to 2018), and interregional commander for Central Italy (from 2018 to 2019). From May 2019 to May 2023 he held the office of Commander General of the Guardia di Finanza. He taught at the Academy of the Guardia di Finanza, the School of the Tributary Police of the Guardia di Finanza, and the School of the economic-financial Police of the Guardia di Finanza. He has been awarded various decorations and honours, including the Knight Grand Cross of the Order of Merit of the Italian Republic.
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Claudio Descalzi was born in Milan and has been Eni’s CEO since May 2014. He is a member of the General Council and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala.
He is a member of the National Petroleum Council. He is one of the founding CEOs of the Oil and Gas Climate Initiative, and was awarded the Atlantic Council’s Distinguished Business Leadership Award in 2022.
Experience
He joined Eni in 1981 as Oil & Gas field petroleum engineer and then became project manager for the development of North Sea, Libya, Nigeria and Congo. In 1990 he was appointed Head of Reservoir and operating activities for Italy. In 1994, he was appointed Managing Director of Eni’s subsidiary in Congo and in 1998 he became Vice President & Managing Director of Naoc, a subsidiary of Eni in Nigeria. From 2000 to 2001 he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005 he was Executive Vice President for Italy, Africa, Middle East, covering also the role of member of the board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of the Exploration & Production Division in Eni. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer in the Exploration & Production Division of Eni. From 2010 to 2014 he held the position of Chairman of Eni UK.
In 2012, Claudio Descalzi was the first European in the field of Oil&Gas to receive the prestigious “Charles F. Rand Memorial Gold Medal 2012” award from the Society of Petroleum Engineers and the American Institute of Mining Engineers. He is a Visiting Fellow at The University of Oxford. In 2014 he founded the Oil and Gas Climate Initiative together with other CEOs of major Oil & Gas companies to lead the industry’s response to climate change. In December 2015 he was made a member of the “Global Board of Advisors of the Council on Foreign Relations”. In December 2016 he was awarded an Honorary Degree in Environmental and Territorial Engineering by the Faculty of Engineering of the University of Rome, Tor Vergata. In May 2022 he was awarded by the Atlantic Council with the Distinguished Business Leadership Award for the extraordinary role he has played in the energy sector at an international level, for the technological transformation of the company aimed at complete decarbonisation by 2050 and for his contribution to the new challenge of Italian and European energy security. He graduated in physics in 1979 from the University of Milan.
Elisa Baroncini was born in Castel San Pietro Terme (Bologna) in 1966 and has been Eni Director since May 2023. She is Professor of International Law at the Alma Mater Studiorum – University of Bologna, where she teaches International Trade and Investment Law, International Law on Sustainable Development, International Energy Law and she is a member of the teaching board of the PhD program in Juridical Sciences. Founder and Coordinator of DIEcon, the interest group on International Economic Law of the Italian Society of International Law (SIDI), she co-chaired the interest group on International Economic Law of the European Society of International Law (ESIL) in 2013-2022 and since December 2023 she was appointed as a Member of the Executive Council of Society of International Economic Law (SIEL). She is a member of the Journal of World Investment and Trade and of the review Diritto del commercio internazionale – Bologna Editorial Board.
In December 2024 she was renewed as a member of the Scientific Council of the Alma Mater Institute for Advanced Studies for the period 2025-2028 and was appointed "TSD Expert" (international arbitrator) by the European Commission for dispute resolution mechanisms of the European Union new generation free trade agreements. She is also a member of the "Interuniversity Centre on the Law of International Economic Organisations" (CIDOIE), and a member of the University of the “Associazione delle docenti universitarie dell’Università di Bologna” (AdDU) Steering Committee. She participates in various associations and organisations active in the fields of governance and international and European law (Leuven Centre for Global Governance Studies, Society of International Economic Law, Società italiana di diritto internazionale, International Law Association (ILA) – Branch of Italy, Associazione italiana studiosi di diritto dell’Unione europea).
Experience
She is the author of several publications among Italian and foreign publishers and magazines, particularly in the field of international economic law and the external relations and trade policy of the European Union. She has been a Visiting Professor at various foreign universities and Visiting Researcher at the European University Institute (EUI), and member and manager of national and international research projects. After being appointed as Coordinator of the Re-Globe Jean Monnet Module (2022-2025), of the Seed Funding Una Europa WHC@50 project and of the Seed Funding Una Europa ImprovEUorGlobe project, she is currently Scientific Director of the project "The World Trade Organization as a protagonist of sustainable development in the relaunch of the multilateral system", funded by the Ministry of Foreign Affairs and International Cooperation. Additionally, Elisa Baroncini holds the Jean Monnet Chair with the SustainEUorPlanet project and is a member of the Scientific Committee of the Advanced Training Course on Energy Law at the University of Bologna. Elisa Baroncini's fields of research include: the crisis of the WTO appellate body and the multilateral system reform process; the relationship between trade liberalisation and non-trade values; the new generation of free trade agreements of the European Union; transparency in international economic law; the role of the European Parliament and Commission in finalizing international agreements; UNESCO and international economic law; exceptions related to national security in international economic law; EU trade policy and Sustainable Development Goals (SDGs) of the UN Agenda 2030; Energy Trilemma and International Energy Law.
She graduated with honour in law, with the “Baldisseri” award as best dissertation of the year in European Community Law, from the University of Bologna, where she also obtained a PhD in European Community Law.
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Massimo Belcredi was born in Brindisi in 1962 and has been Eni Director since May 2023. He is currently Full Professor of Corporate Finance at the Faculty of Economics of the Università Cattolica del Sacro Cuore in Milan; and Founder and Director of FIN-GOV (Centre for financial research on corporate governance of the Catholic University).
He is a member of the Steering Committee of Cor-Gov (Master II level in Corporate Governance) and of the committee of the Department of Economics and Business Management. He is a member of the Italian Academy of Business Economics (AIDEA) and the Association of Professors of Economics of Financial Market Intermediaries (ADEIMF). He is also a member of the Rivista Bancaria (Minerva Bancaria) Scientific Committee. Since 2021 he has been Director of Armònia SGR and a member of the Nedcommunity Scientific Committee. He provides technical consultancy and advice on the subjects of corporate finance and corporate governance, support for the board evaluation, remuneration policies, and related-parties transactions.
Experience
He has been a member of the Board of Directors, European Financial Management Association and of the Editorial Board, Journal of Management Governance. He is author of several national and international publications, primarily in the field of corporate governance, directors' remuneration, economic analysis of listed companies law, business crises, and has worked as a consultant for Assonime on corporate governance, company law and crisis and regulation of financial markets matters, also participating in the working group for the development of the Italian Corporate Governance Code.
Since 2003, he was Director in unlisted and listed companies, as well as companies under the supervision of Public Authorities (Arca SGR, Banca Italease, BPER Banca, Erg, Gedi and Pirelli Tyre), being also appointed as a member or chairman of internal committees (Nomination, Remuneration, Control and Risk, Related Parties). He was a member of the Advisory Board for the transformation and privatisation of municipal companies in the Municipality of Rome, and a member of the competition commissions for Consob and the Energy and Gas Authority (AEEG). In 2014 he received the "Ambrogio Lorenzetti" award for corporate governance, category ‘Board of Director’s’. He was Professor at the University of Svizzera Italiana and the University of Bologna. He graduated in Business and Economics from the Università Cattolica del Sacro Cuore in Milan, where he also held the role of researcher and associate professor of Corporate Finance.
Roberto Ciciani was born in Rome in 1972 and has been Eni Director since May 2023. He is a lawyer, currently General Manager and Director of Directorate I of the Economy Department at the Ministry of Economy and Finance.
He is a Director and member of the Remuneration Committee of TELT – Lyon-Turin Euroalpine Tunnel.
Experience
He began his career at Studio Legale Compagno. He then took part to the final stage of the 2nd management training course-competition and took on the role of lawyer at the Tiber River Basin Authority, a public body responsible for landscape protection (from 2001 to 2002). Since 2002 he has held managerial positions in several Directorates of the Treasury and Economy Department - Ministry of Economy and Finance. He was a member of the Higher Council of the Sicily Foundation (from 2016 to 2019), a Director of Poste Tutela SpA, a company owned by Poste Italiane Group (from 2013 to 2016), and MEFOP SpA, a majority state-owned company for the development of pension funds (from 2013 to 2019).
He has extensive, meaningful experience in the economic-financial sector, both at international and european level, in administrative, accounting and management procedures; he has considerable knowledge of risk monitoring and management, and has developed skills in the analysis of problems relating to international and domestic law and economics, banking, finance, business, the prevention of tax and financial crimes and market abuse, primarily gained through pre-legislative work at national, European and international level (definition of standards and international recommendations). He was Professor at the Sapienza, Tor Vergata and LUISS Guido Carli universities in Rome. He graduated in law from the Sapienza University of Rome, where he also held a PhD in Administrative Law.
Carolyn Adele Dittmeier was born in Salem (USA) in 1956 and has been Eni Director since May 2023. She is currently Independent Director and member of the Audit and Risk Committees of HSBC Uk Bank Plc.
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She is also independent director and Chairman of the Control and Risk Committee of Illycaffé S.p.A. and a member of the Board of Statutory Auditors of Moncler SpA and of the Bologna University Business School Foundation. She has taken part to the European Growth Audit Network (coordinated by Tapestry), which organizes benchmark meetings between the Audit Committee Chairs of major European companies, with a focus on “high growth” companies. She is a certified internal auditor and certified risk management assurance professional. She has been a promoter of the working group dedicated to risk and control matters within the Nedcommunity.
Experience
She began her career at KPMG in 1978, as an auditor at Philadelphia, Pennsylvania, USA, later launching a corporate governance services practice in Italy. She held the position of Financial Manager and, subsequently, Internal Audit Manager for the Montedison/Compart Group. From 2002 to 2014 she served as Internal Audit Manager of the Poste Italiane Group, and of the Supervisory Body, as sole auditor. From 2017 until September 2024, she served as an Independent Director, as well as the President of the Audit Committee and a member of the Corporate Governance, Sustainability, and Nomination Committee of Alpha Services & Holdings SA and its subsidiary Alpha Bank SA, where she also held the position of Lead Director on ESG issues.
From 2012 to 2015 she was a member of the Audit Committee of the FAO (United Nations Food and Agriculture Organisation), where she became President in 2014. She was also an independent director and chairman of the Control and Risk Committee at Autogrill SpA and Italmobiliare SpA. From 2014 to April 2023, she was Chairman of the Board of Statutory Auditors of Assicurazioni Generali SpA. From 2016 to the end of 2023, she was senior advisor of Ferrero International SA as a member of Audit Committee.
From 2004 to 2014, she held various positions at the Institute of Internal Auditors (IIA), including those of president of ECIIA and AIIA. She is author of publications on risk governance and Internal Auditing and, in 2014 and 2017 respectively, she received the Ambrogio Lorenzetti Award, Board Members category, and the Minerva (Federmanager) Women of Excellence award. She has been teaching at the LUISS Guido Carli University, with teaching assignments in the fields of corporate governance, risk management, internal control and internal auditing. She graduated in Economics from the Wharton School, University of Pennsylvania, USA.
Federica Seganti was born in Trieste in 1966 and has been Eni Director since May 2023. She is currently Chairman and Chief Executive Officer of the Friuli Venezia Giulia regional finance company Friulia SpA and Chairman of BTX Italian Retail and Brands Srl, as well as Director of Finest SpA and BancoPosta Fondi SpA SGR (where she is Chairman of the Remuneration Committee and member of the Risk Committee).
She is Professor of Finance, Core Faculty at the MIB Trieste School of Management, and of Insurance Operations Technique at the Department of Economics and Statistics at the University of Udine. She is Director of the Master’s course in Insurance & Risk Management and the Corporate Master’s course in Risk Management and Finance at the MIB Trieste School of Management.
Experience
From 1994 to 2022 she was Director in several listed and unlisted companies (Fincantieri SpA, Eurizon Capital SGR, Autostrada Pedemontana Lombarda SpA, InRete SpA, Autovie Servizi SpA, Autovie Venete SpA), while also being appointed as a member or Chairman of advisory committees (Nomination, Remuneration, Control and Risks). From 2003 to 2008 she was Commissioner at Covip - Supervisory Commission on Pension Funds, from 2010 to 2016 a Member of the Occupational Pensions Stakeholder Group of EIOPA - European Insurance and Occupational Pensions Authority, and from 2017 to 2019 of the Strategy Advisory Board of EY Financial Services. From 2017 to April 2023, she was an independent Director of Hera SpA, where she was also Chairman of the Ethics and Sustainability Committee.
She was a contract professor of Transport Economics at the University of Trieste. She is the author of many publications and has been awarded three prizes. She has a degree in Political Science from the University of Trieste, and a PhD in Finance from the School of Finance (University of Trieste, Udine, Florence and Bocconi Milan), as well as an MBA in International Business from the MIB Trieste School of Management.
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Cristina Sgubin was born in Frosinone in 1980 and has been Eni Director since May 2023. Lawyer, expert in corporate law, corporate governance and regulation. She is currently Director of SACE, ISPRA (Higher Institute for Environmental Protection and Research), Vianini SpA and Biesse SpA
She is also Secretary General of Telespazio SpA, a leading international company operating in the satellite sector. She lectures on both degree and master's courses in Public Economic Law and Administrative Law.
Experience
She gained extensive experience as a lawyer for leading national and international law firms, then she pursued the in-house managerial career. As a lawyer, she has served the IPI (Institute of Industrial Promotion), in-house company of the Ministry of the Economic Development (“MISE”, now Ministry of Enterprises and Made in Italy) for Promuovitalia S.p.A. and for the Ministry itself. She was General Counsel of Italo-Nuovo Trasporto Viaggiatori SpA. While working at Leonardo she subsequently became Head of Regulatory Affairs, and then Chief of Staff to the Chief Executive Officer. Since 2021 she has been Secretary General of Telespazio, responsible for legal and corporate affairs, compliance, security and anti-corruption.
She is author of monographs, particularly on complex industrial crises, collective works and scientific articles. She had a law degree from the University of Rome Tor Vergata and a level II University Master's degree in "Law and management of public services" from the LUMSA University in Rome.
Raphael Louis L. Vermeir was born in Merchtem (Belgium) in 1955 and has been Eni Director since May 2020. Since April 2021 he has been Lead Independent Director, appointment confirmed in May 2023. He is currently an independent advisor for the mining and oil industry.
He serves as Trustee of the Classical Opera Company in London, as well as Chairman of Malteser International and board member of Sedibelo Resources Limited. He is Fellow of the Energy Institute and the Royal Institute of Naval Architects.
Experience
He joined ConocoPhillips in 1979, initially working in marine transportation and production engineering services in Houston, Texas. He then handled upstream acquisitions in Europe and Africa and managed Conoco's exploration activities in continental Europe from the Paris headquarters. In 1991 Vermeir moved to London to lead the business development activities for refining and marketing in Europe. In 1996 he became managing director of Turcas in Istanbul (Turkey). He returned to London in 1999 to lead strategic initiatives in Russia and to complete major acquisition deals in the North Sea. He also headed an integration team during the Conoco-Phillips merger. In 2007 he became head of external affairs Europe and in 2011 was appointed as president of operations in Nigeria. Subsequently and until 2015, Vermeir was Vice President of Government Affairs International for ConocoPhillips.
Raphael Vermeir was a member of the Board of Directors of Oil Spill Response Ltd and until 2011 was Chairman of the International Association of Oil and Gas Producers for four years in a row. Since 2016 and until April 2021 was Senior Advisor for Energy Intelligence and Strategia Worldwide. From 2016 and until 2021 he was Chairman of IP week. Since 2016 until 2022 he was Senior Advisor for AngloAmerican. From April 2021 Raphael Vermeir has been appointed as Lead Independent Director of Eni. He served as Trustee of St Andrews Prize for the Environment. A Belgian national, he graduated in Electrical and Mechanical Engineering from the Ecole Polytechnique in Brussels. He holds a Masters of Science degrees in engineering and management from the Massachusetts Institute of Technology.
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Senior Mana g ement
The table below sets forth the composition of Eni’s Senior Management as at December 31, 2024. It includes the CEO, as General Manager of Eni SpA, as well as the Chief Operating Officers and the executives who report directly to the CEO and to the Board, and on its behalf, to the Chairman.
|
Name |
|
Management position |
|
Year first appointed to current position |
|
Total number of years of service at Eni |
|
Age |
|
|
|
|
|
|
|
|
|
|
|
Claudio Descalzi |
|
Chief Executive Officer of Eni |
|
2014 |
|
43 |
|
69 |
|
Guido Brusco |
|
Global Natural Resources Chief Operating Officer and General Manager |
|
2022 |
|
27 |
|
54 |
|
Francesco Gattei |
|
Chief Transition & Financial Officer, Chief Operating Officer and General Manager |
|
2020 |
|
29 |
|
55 |
|
Giuseppe Ricci |
|
Industrial Transformation Chief Operating Officer |
|
2021 |
|
39 |
|
66 |
|
Gianfranco Cariola |
|
Internal Audit Director |
|
2021 |
|
13 |
|
56 |
|
Grazia Fimiani |
|
Integrated Risk Management Director |
|
2021 |
|
28 |
|
54 |
|
Luca Franceschini |
|
Integrated Compliance Director and Board Secretary and Board Counsel |
|
2016 |
|
33 |
|
58 |
|
Claudio Granata |
|
Director Stakeholder Relations & Services |
|
2020 |
|
41 |
|
64 |
|
Erika Mandraffino |
|
External Communication Director |
|
2020 |
|
18 |
|
52 |
|
Lapo Pistelli |
|
Public Affairs Director |
|
2020 |
|
9 |
|
60 |
|
Stefano Speroni |
|
Legal Affairs & Commercial Negotiation Director |
|
2020 |
|
6 |
|
62 |
|
Roberto Ulissi |
|
Corporate Affairs and Governance Director |
|
2006 |
|
18 |
|
62 |
|
Lorenzo Fiorillo |
|
Technology, R&D & Digital Director |
|
2024 |
|
25 |
|
50 |
The Global Natural Resources Chief Operating Officer and General Manager, the Chief Transition & Financial Officer, Chief Operating Officer and General Manager, Industrial Transformation Chief Operating Officer, the Director Legal Affairs and Commercial Negotiations, the Director Corporate Affairs and Governance, the Director Integrated Compliance, the Director External Communication, the Director Stakeholder Relations & Services, the Director Internal Audit, the Director Public Affairs, the Director Integrated Risk Management, the Director Technology, R&D & Digital, the Director CCUS, Forestry & Agro-Feedstock, the Director Development, Operations & Energy Efficiency, the Director Exploration, the Director Global Gas & LNG Portfolio, the Director Power Generation & Marketing, the Director Refining Evolution and Transformation, the Director Upstream, the Head Accounting and Financial Statements, the Head Planning, Control and Insurance are members of the Management Committee 9 , which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of the Committee Secretary are performed by the Director Corporate Affairs and Governance.
As of August 1, 2020, the Head of the Accounting and Financial Statements has been appointed by the Board of Directors as the Officer in charge of preparing Company’s financial reports pursuant to Italian law, replacing the CFO, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors.
The Internal Audit Director is appointed by the Board of Directors as Director in charge of the internal control and risk management system, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer.
The Board of Directors decides with the support of the Control and Risks Committee and the Nomination Committee, after having heard the Board of Statutory Auditors. The Board Secretary and Board Counsel is appointed by the Board of Directors upon a proposal of the Chairman.
Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause.
|
|
|
9 The committee includes also the Chairman of the Board and CEO's of certain Eni's subsidiaries.
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Senior Mana g e r s
Guido Brusco was Born in Maratea in April 1970, he graduated with Honors in Mechanical Engineering at “La Sapienza” University of Rome. He holds the position of Eni’s Chief Operating Officer Global Natural Resources and General Manager since October 1, 2024. He joined Eni in 1997, starting his career in the technical areas of the Exploration & Production business holding positions of increasing complexity and seniority across different countries, up to the role of Managing Director in Kazakhstan in 2013 and subsequently in Angola in 2015. He held the positions of Executive Vice President for the Sub-Saharan Africa Region and then Director of Eni’s Upstream business. He took over as Chief Operating Officer Natural Resources in February 2022. Since October 2024, he has been appointed Chief Operating Officer Global Natural Resources as well as General Manager1, overseeing exploration activities, engineering, development and production of oil&gas, LNG and Power, Trading and Portfolio management, sustainable development, Carbon Capture and Storage, forestry and agro-feedstock and, lastly, to the realization of asset development projects. He has been appointed Chairman of Confindustria Energia, Italy's Federation of energy sector associations, in July 2023. He has been a Board Director of Vår Energi (since December 2021), of Azule Energy (since August 2020) and of Ithaca Energy (since October 2024).
Francesco Gattei was born in Bologna in February 1969, he graduated in Economy and Commerce with a thesis in the oil market. He holds the position of Chief Transition & Financial Officer, Chief Operating Officer and General Manager since October 1, 2024. He joined Agip S.p.A. in 1995 and participated in major negotiation processes in Central Asia and Russia, firstly as Business Analyst and subsequently as Negotiator. From 2001 to 2005 he was Head of Negotiations & Commercial Planning in Libya activities during the start-up and then the construction phases of the Western Libyan Gas Project. From 2006 to 2008, he returned to Eni’s headquarters to become Head of Business Planning and Development activities for Africa, Europe, Asia and America during a period of major business growth, supporting the E&P Division’s Deputy General Director. In 2009, he was appointed Head of Upstream M&A, contributing to the rationalization of the portfolio, particularly in the UK and United States. In 2011, he became Senior Vice President of Market Scenarios and Strategic Options in Eni SpA, where he was also appointed Secretary of the Scenario and Sustainability Committee, a post he held until 2019. In 2014, he was appointed Head of Investor Relations and also acted as Secretary to Eni's Advisory Board from 2016 to 2019. In 2019, he moved to Houston to become Upstream Director of the Americas, managing the E&P business in the USA, Mexico, Venezuela and Argentina. He was a member of the Board of Directors of Saipem from 2014 to 2015. Since 2020, he is Board Member of Vår Energi, a company listed on the Oslo Stock Exchange. He was appointed Eni Chief Financial Officer on August 1st, 2020. On October 1st, 2024, he has been appointed Chief Transition & Financial Officer as well as Chief Operating Officer and General Manager, overseeing the process and the implementation of Eni economic and financial strategy, as well as the management and evolution of the sustainable mobility, retail gas & power and renewables businesses. Since October 2024, he’s Board Member of Ithaca Energy.
Giuseppe Ricci was born in Casale Monferrato in 1958. He was appointed Chief Operating Officer of Energy Evolution on January 1, 2021. He joined Eni in 1985 initially working in the study and development of new refining processes at the Sannazzaro refinery, before becoming involved in the creation and consolidation of the joint venture with Kuwait Petroleum at the Milazzo refinery. In 2000 he returned to head office where he was responsible for Refining Processes Development and oversaw the performance optimization at the refining facilities of Agip Petroli. He left central technologies to take over, in 2004, as director of the Gela Refinery, a particularly challenging assignment both from a managerial perspective and in terms of the refining cycle and the complexity of the plant; in 2006 he was appointed managing director of the refinery. In June 2010 he was appointed as Senior Vice President of the Industrial Sector for Refining & Marketing, with responsibility for the refineries, storage deposits, oil pipelines and plant and facilities in Italy, as well as the management of subsidiary and associated companies in Italy and abroad. As Industrial Director he also held a series of additional responsibilities, such as the chairmanship of Gela and Milazzo. In 2012 he took on the delicate role of Eni’s Executive Vice President Health, Safety Environment and Quality with responsibility for providing the guidelines, coordination and control of safety, industrial health, product safety, the environment and quality. On September 12th, 2016, he was appointed as Chief Refining & Marketing Officer. On July 2020 as Eni’s Deputy Chief Operating Officer of Energy Evolution and Director Green/Traditional Refinery and Marketing. Since July 2017 up to June 2023 he was appointed President of Confindustria Energia and since 2018 President of AIDIC (Italian Association of chemical Engineering). He took over as Chief Operating Officer Energy Evolution from January 1st, 2021. Since October 1, 2024, he has been appointed Chief Operating Officer Industrial Transformation, overseeing the industrial transformation activities of traditional refining and chemical, as well as the business development activities and environmental remediation.
Gianfranco Cariola was born in Cosenza in 1968, he was appointed as Director Internal Audit at Eni on April 1, 2021. Between 1993 and 1999, he served as Officer at Guardia di Finanza (Italian Tax Police) General Command. Afterwards, he joined KPMG- KLegal, where he took on the role of Ordinary Member working for a number of major multinational groups in the field of risk management, compliance programs and internal control systems. In 2001 he was seconded to KPMG LLP in Washington DC where he specializes in the structuring of compliance programs and anti-corruption models. In 2003, he moved to the Internal Audit Department of Eni spa where he initially worked on Eni’s Group compliance 231 models; then, he was appointed as Senior Audit Vice President and Head of Planning, Methodologies and Eni’s Internal Control System. From 2013 to 2016, he was the Group Chief Audit Executive and Head of Anti-Corruption and Transparency at RAI spa. Between 2016 and November 2019, he joined Ferrovie dello Stato Italiane spa (FS spa) as Group Chief Audit Executive. On December 2019 he was appointed as Chief Audit Executive at TIM spa. He graduated in Economics, qualified as Italian Certified Public Accountant, in 2008, he completed an Executive MBA in General Management at the SDA Bocconi School of Management and the Polytechnic University of Milan. In 2017 he obtained a second degree, in Economic and Financial Security Sciences.
134
Grazia Fimiani was born in Salerno in 1970. She was appointed Director of Integrated Risk Management at Eni on January 1, 2021. Having graduated with honors in Economics and Commerce from Sapienza University in Rome, she joined Eni in 1996, following a brief experience in the financial sector. At Eni, she began her professional career in the Human Resources department, by gaining transversal experience on the processes of Organizational Management, HR Planning and Development. She then went on to management roles in International Business, in particular in the Gas & Power sector, acquiring increasing responsibilities until she took on the role of HR Business Partner in the Gas & Power division. During this period, she coordinated and managed aspects of Human Resources related to business development projects, with particular reference to the integration of entities/companies subject to acquisition at European level and to the re-engineering of business processes, required by the growing exposure of the sector to the dynamics of market. In 2014 she was appointed Head of Human Resources and Organization of Eni reporting to the Chief Services & Stakeholder Relations Officer and, from July 2020, as the Human Capital & Procurement Coordination Director. In this role she coordinated central functions of the Organization Management, HR Development, Industrial Relations and all the activities related to HR Business Partner in several Eni Business areas (Natural Resources, Energy Evolution, Support Functions), as well as the Excellence Centers focused on Recruitment and Training (Eni International Resources and Eni Corporate University). From 2016 to June 2021 she was a standing member, representing Eni in the Executive Committee of Valore D. She participated in sessions of ‘In The Boardroom 4.0 – Eighth Class’ executive training program for Board members. In October 2022, as Eni representative, she was appointed Council Member of World Business Council for Sustainable Development. She is currently member of Boards of Directors of Versalis and Eni Trading & Biofuels, as well as of Eni Foundation .
Luca Franceschini was born in Milan in 1966, from July 1, 2020 he is Head of Integrated Compliance and, from January 1, 2021, also Secretary of the Board of Directors. He is lawyer registered with the Italian Bar Association in Rome. After graduating in Law from the University of Milan, he first joined Eni in 1991 in the legal department of the then Agip S.p.A., providing legal assistance, initially, in commercial litigation and procurement area, and, subsequently, in a wide range of national and international projects in the Exploration & Production sector. In 2000, during the process for the liberalization of the natural gas sector, he was involved in the spin-off of the gas storage business and in the establishment and operational start of Stogit SpA, for which he became head of Legal and Corporate Affairs. He made his return to Eni Spa in 2005 as head of Italian Legal Assistance in the Gas & Power division. Following the concentration of all legal functions in Eni’s central Legal Department, he takes on positions of increasing responsibility, becoming, in 2009, head of legal assistance for Italian Business and Antitrust and in 2015, head of Legal and Regulatory Compliance. After the separation of the compliance function from the Legal Affairs department, in 2016 he became head of the new Integrated Compliance department. In 2017 he was awarded “Compliance Officer of the Year” by the Top Legal Corporate Counsel Awards and the Inhouse Community Awards. He is a member of the Scientific Committee of the Advanced Training Course for Corporate Counsel of the Luiss Business School. He was also member of the boards of directors of Italgas and Stogit.
Claudio Granata was born in Rome in 1960. He holds the position of Director Stakeholder Relations & Services since October 1, 2024 and he has been appointed Chairman of the board of Eni Corporate University since November 2014. He started working in Eni in 1983 and from 1983 to 1994 worked as a labour market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999 he continued his experience with Eni Corporate as an expert in industrial relations. In 2000 he was made responsible for Staff and Organisation within Eni Servizi Amministrativi, a company that was set up to centralise Eni’s administrative activities. In 2001, he took over the management of Eni’s territorial divisions, restructuring the management of staff by geographical area and in 2003 he took on the role of Business HR for Eni Corporate, ensuring support for departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), which was characterised by the mergers of Snam and AgipPetroli and the restructuring of staff organisation. In the same year he was also appointed head of Human Resources and Organisation of SOFID (Eni’s financial services company). In 2006 he was appointed Human Resources Director of the E&P Division, where he oversaw the planning, management, development and compensation processes for human resources and organisation activities. He also collaborated with the top management in the reorganisation of macro processes for the division and promoted change management initiatives. He became a board member of Eni International Resources Ltd in 2006 and was Chairman of the board of Eni International Resources Ltd from 2012 to 2013. From 2012 to March 2015, he was a board member of Eni UK ltd. In 2013 he was appointed Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, responsible for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in "time to market" and efficiency. He was appointed Chief Services & Stakeholder Relations Officer in Eni since July 1, 2014. Until May 2016, he was a member of the Board of Directors of the Eni Foundation. He was appointed Director Human Capital & Procurement since July 1, 2020.
135
Erika Mandraffino was born in Syracuse in 1972, mother of two. She was appointed Director External Communication of Eni on November 1, 2020. After graduating in European Business Administration in London, where she lived almost uninterruptedly from 1991 to 2005, she began her career as a corporate and financial communications consultant at Ludgate Communications where she worked from 1996 to 1999. Before joining Eni in 2006 as head of the financial and international press office, to then become head of Eni Group media relations in 2011, she worked as Director at the Brunswick Group in London, managing the international communication of European corporates (in Italy, Spain, Holland, Portugal) during crisis situations, mergers, acquisitions and IPOs. From 2000 to 2001 she worked as a communication consultant at Barabino & Partners in Rome. From October 2013 to February 2015 she was Saipem’s Senior Vice President of Institutional Relations and Communication, where she built the external relations department reporting directly to the CEO and managed the company’s communication in a period of crisis. In 2015 she was called back to Eni as Senior Vice President Media Relations and Corporate Publishing, a position held until April 2016 when she took on the role of Senior Vice President Media Relations and Social Networks. In 2018 she became Senior Vice President Global Media Relations and Crisis Communications. From July 1, 2020 she was Eni’s Director Media Relation reporting directly to the CEO until she assumed the current role. She has also been Chairman of Versalis S.p.A from May 2018 until January 2021.
Lapo Pistelli was born in Florence in 1964. He was appointed Director Public Affairs of Eni on July 1, 2020. Graduated with honors in 1988 in International Law at the Political Science faculty “Cesare Alfieri” at the University of Florence, he started working at a research center, while serving for two mandates in the local administration of Florence. He was member of the Italian Parliament from 1996 to 2015 (1996/2004 and 2008/2015), and also member of the European Parliament (2004/2008). He served as Deputy Minister of Foreign Affairs and International Cooperation of Italy from 2013 to 2015. He resigned from all his institutional and political roles in July 2015, when he entered Eni. He taught and lectured at the University of Florence, the Overseas Studies Program of Stanford University and many others international academic institutions. He regularly contributed to many European and American think tanks and research centers specialized in international relations. He is member of the board of the European Council on Foreign Relations (ECFR) and of the Istituto Affari Internazionali (IAI), and member of the WE – World of Energy editorial committee. He also collaborates with Limes and Aspenia magazines. He’s Chairman of OME (Observatoire Mediterranéen de l’Energie et du Climat).
Stefano Speroni was born in Milano in 1962. He was appointed Director Legal Affairs and Commercial Negotiations of Eni on July 1, 2020. He has accumulated vast experience in over 30 years of professional activity in the field of corporate affairs, mergers and acquisitions, private equity operations and capital markets. He has given professional support to Italian and International listed companies (in a wide range of sectors including aerospace and defence, oil & gas, telecommunications, transport and infrastructure) in strategic corporate affairs, in share trading, joint ventures and commercial agreements. From January 2016 to December 2018, he was a Managing Partner for Corporate M&A in Dentons’ Italian practice. He joined Eni in January 2019 and he was appointed Senior Executive Vice President of Legal Affairs. In 2012, he was one of the founders of the Grimaldi Legal Studio, after having previously been managing partner of Dewey Ballantine’s Rome practice which involved managing its Italian activities for around 10 years. He was also a partner in Studio Gianni, Origoni, Grippo Capelli & Partners (2001 – 2003), in the Simmons and Simmons Italian practice (1991 – 2001), and manager of the European Corporate Department and member of the World-wide Remuneration Committee. He is a member of the scientific committee and contributor to SDA Bocconi’s Private Equity Laboratory and was awarded “Best Lawyer of the Year” 2018 by the Best Lawyers international directory. He graduated in Law at Università degli Studi in Milan and is a registered member of the Italian Bar Association in Milan.
Roberto Ulissi was born in Rome in 1962. Since 2006, he has been Head (now called Director) of Corporate Affairs and Governance, reporting directly to the Chief Executive Officer. He is a Board member and Vice Chairman of Banor SIM. He is a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance head of the Banking and Financial System and Legal Affairs Department. He was a Board member of Telecom Italia (and Chairman of the Audit Committee), Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He was also a member of numerous Italian and European committees representing the Ministry of the Economy including, at a national level, the Commission for the Reform of Corporate Law (“Vietti” Commission) and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of Banking Law at the University of Cassino. He is “Grande Ufficiale della Repubblica Italiana”. Until December 2020, he was Eni’s Company Secretary (Board Secretary and Corporate Governance Counsel) and was a Board Member of Eni International BV. From 2018 to 2021 he was the Coordinator of the Corporate Governance Forum of Company Secretaries..
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Fiorillo Lorenzo was born in Vibo Valentia in 1974. He is appointed as Director Technology, R&D & Digital of Eni since May 2024. After graduating in Chemical Engineering in Pisa in 1998, in January 1999 he joined Eni as a Production Optimization Technician at San Donato Milanese headquarters. Later on an initial experience in the field on reservoir studies and in the Italian operating districts, in 2004 he held the role of Technical Manager at Enimed company in Gela, subsequently increasing his responsibilities, both in Sicily and in Tunisia, until being appointed in January 2010 as President and CEO of Enimed. Between 2012 and 2018 he was in Congo holding the role of Directeur General of the Eni Congo company with the responsibility of managing Eni's business in the country, working on the development of long-term activities, in particular through the strategy of valorising gas reserves. Following his experience in Congo, he held a similar role in Nigeria in the Nigerian Agip Oil Company until July 2020, also assuming the Presidency of the OPTS (Oil Producers Trade Section). He subsequently held the position of Head of the Upstream West Africa Region and in April 2021 he took the responsibility for the entire Sub-Saharan Africa Region. Starting from June 2022 he is appointed Operations & Energy Efficiency Manager in the Natural Resources General Department, with responsibility for production, maintenance, drilling, logistics and decommissioning activities. Since 2023 he has been a member of the Confindustria Technical Group.
The information concerning compensation is provided in the Remuneration Report prepared in accordance to Italian listing standards, which is incorporated herein by reference. See the Exhibit 15. a (i).
As of December 31, 2024, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer, Chief Operating Officers, and other Managers with strategic responsibilities (with reference to the employed ones in service, who, during the course of the 2024 period, filled said roles, even if only for a fraction of the year), was €1,214 thousand.
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Name |
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(€ thousand) |
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Descalzi Claudio |
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CEO and General Manager of Eni |
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436 |
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Brusco Guido |
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Chief Operating Officer Global Natural Resources |
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6 |
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|
Ricci Giuseppe |
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Chief Operating Officer Chief Transition & Financial Officer |
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34 |
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|
Senior managers (a) |
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|
|
738 |
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|
|
|
|
|
1,214 |
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(a) No. 24 managers.
137
Corporate G o vernance
The Corporate Governance structure of Eni follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. On December 23, 2020 Eni adopted the Corporate Governance Code approved by the Italian Corporate Governance Committee on January 2020 (hereinafter “Code”), effective from January 1, 2021.
The names of Eni’s Directors, their positions, the year in which each of them was initially appointed as a Director and their ages are reported in the relevant table above.
Boa r d of Directors’ duties and responsibilities
The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated May 11, 2023, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board.
In the same resolution, the Board of Directors resolved to confer to the Chairman a major role in internal controls and non- operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code in force at that time, the Head of the Internal Audit Department reports to the Board, and on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system. The Chairman is also involved in the appointment of the primary Eni officers in charge of internal controls and risk management, as well as in approving internal rules governing the Internal Audit process. In addition, the Chairman carries out his statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer.
On the same date (May 11, 2023), the Board of Directors appointed the Secretary of the Board of Directors and Board Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He provides assistance and independent (from the management) legal advice to the Board and the Directors.
With resolution dated May 11, 2023 the Board of Directors updated the specific responsibilities reserved to itself, which are fully reported below. Accordingly, the Board, in addition to powers that may not be delegated by law and by By-laws, has the following exclusive powers:
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10 The information contained in this chapter is updated to December 31, 2024 and for specific aspects, expressly indicated, up to the date of approval of this Report. |
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138
the Board:
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defines the system and rules of corporate governance for the Company, evaluating and promoting, where necessary, the appropriate amendments, submitting the same, when appropriate, to the Shareholders' meeting. Defines the structure of the Group it leads. Approves the Report on corporate governance and ownership, with the support of the Control and Risk Committee with regard to the internal control and risk management system. Approves, having received the opinion of the Control and Risk Committee, the guidelines for the internal regulatory system and the policies on Ethics, Compliance & Governance. Having received the favourable opinion of the Control and Risk Committee, adopts rules ensuring the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or a Statutory Auditor holds a personal interest or an interest on behalf of third parties, assessing on an annual basis whether any revision is needed. Upon proposal of the Chairman, in consultation with the CEO, it also adopts a procedure for the internal handling and the disclosure of Company documents and information, with particular reference to inside information.
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Defines its operational rules and procedures, including the procedures for providing information to directors. Establishes the Board’s internal Committees, with preliminary, propositional and consultative functions, defines their composition appointing and revoking their members and Chairmen, favouring the competence and experience of their members and avoiding an excessive concentration of offices. Determines their duties, and also upon proposal of the Remuneration Committee and following consultation with the Board of Statutory Auditors, the compensation of the relevant members; acting upon proposal of the same committees, approves their rules of procedures and annual budgets. Moreover, establishes in the rules of procedure of the committees the terms and conditions on which committees can use external consultants.
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Upon their appointment and on annual basis, as well as at the occurrence of relevant circumstances, based on the information provided by the interested party or available to the Company and following the preliminary investigation of the Nomination Committee, assesses the independence and integrity of its members, as well as the non-existence of reasons for ineligibility and incompatibility. Defines ex ante the quantitative and qualitative criteria for assessing the significance of commercial, financial or professional relations, as well as of any remuneration other than the fixed remuneration that may compromise or appear to compromise independence. Carries out the assessments vested in it by law in relation to the requirements applicable to Statutory Auditors. Acting upon a proposal of the Nomination Committee, it expresses its policy on the maximum number of director or statutory auditor positions that can be held by its members in any other listed company, whether Italian or foreign, or in financial, banking or insurance companies or in companies of significant size that are compatible with the effective performance of their role as director, taking into account the time commitment required by the role, and periodically verifies their compliance, at least on an annual basis. Every year carries out an assessment on the specific functioning of the Board itself and of its committees, as well as on their size and composition, using an external independent consultant, appointed upon proposal of the Nomination Committee, also considering the role it has played in defining strategies and monitoring management and the adequacy of the internal control and risk management system. The Chairman ensures, with the help of the Board Secretary, the adequacy and transparency of the self-assessment process of the administrative body, with the support of the Nomination Committee. The Nomination Committee upon request of the Board, provides assistance in the self- assessment activities of the Board and its Committees. Taking into account the outcomes of such assessment, with the support of the Nomination Committee, the Board defines the optimal composition of the Board itself and of its committees, issuing its advice for shareholders on the size and composition of the new Board before its appointment. With the assistance of the Nomination Committee, identifies candidates for the office of Director in case of co-optation and, where possible and appropriate, prepares and submits its own slate for the renewal of the body. Requires to whoever submits a slate with a number of candidates that is higher than half the number of members to be elected to provide adequate information, in the documentation presented for filing the slate, on the compliance of the slate with the advice expressed by the Board, and also with reference to diversity criteria envisaged by the law and by the Corporate Governance Code, and to indicate the candidate for the office of Chairman of the Board.
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Where applicable, appoints and revokes an independent director as “lead independent director”
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Delegates and revokes powers to/from the Chief Executive Officer and the Chairman, establishing the limits and methods for exercising these powers and, after examining the proposals of the Remuneration Committee and following consultation with the Board of Statutory Auditors, determining the remuneration connected with these duties. The Board may impart directives to the delegated bodies and itself undertake any operations falling within the delegated powers. Prepares, updates and implements, with the support of the Nomination Committee, a succession plan for the Chief Executive Officer identifying at least the procedures to be followed in the event of early termination of office. It also ascertains the existence of adequate procedures for the succession of top management. |
139
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Taking into account the obligations established by current legislation on the matter: (i) establishes the basic guidelines for the organizational, administrative and accounting structure, including the internal control and risk management system, of the Company, of subsidiaries with strategic importance and of the Group; (ii) it evaluates the adequacy of the organizational, administrative and accounting structure of the Company, of the subsidiaries with strategic importance and of the Group, with particular reference to the internal control and risk management system, put in place by the Chief Executive Officer.
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With the support of the Control and Risk Committee and following consultation with the Chairman in regard of the internal audit activities, establishes the general guidelines for the internal control and risk management system, in line with the Company's strategies. With reference to the four-year Plan, defines the nature and level of risk compatible with the strategic objectives of the company, on the basis of an estimate of the probability and impact of the risks issued (and, if necessary, updated during the year) by the Integrated Risk Management function, including in its assessments all the risks that may be relevant in terms of sustainable success of the Company. Upon proposal of the Chief Executive Officer and with the support of the Control and Risk Committee, it annually defines, within the framework of the four-year Plan, the specific guidelines for the internal control and risk management system, in line with the Company's strategies, and evaluates their implementation annually, based on a report from the Chief Executive Officer, without prejudice to the general guidelines on the subject contained in internal regulations. Upon proposal of the Chief Executive Officer and in agreement with the Control and Risk Committee and the Board of Statutory, defines the principles concerning the coordination and information flows between the various subjects involved in the internal control and risk management system. Approves the guidelines on the internal audit activity, upon proposal of the Chairman, in agreement with the Chief Executive Officer and having consulted the Control and Risk Committee. Defines the guidelines for the management and control of financial risks, after having heard the opinion of the Control and Risk Committee, and defines the financial risk limits for the Company and its subsidiaries. With the support of the Control and Risk Committee (i) examines the main Company risks, identified by the Chief Executive Officer, taking into account the nature of the business of the Company and of its subsidiaries, as reported by the Chief Executive Officer to the Board at least once every three months and (ii) every six months, based on the reports prepared by the Officer in charge of preparing financial reports of Eni SpA, as well as the reports by the Control and Risk Committee, the Risk Report and, annually, also on the basis of the Report on compliance with financial risk limits and the Integrated Compliance Report, evaluates the adequacy of the internal control and risk management system with regard to the nature of the business and its risk profile, as well as its effectiveness. It also evaluates the adequacy of powers and means given to the Officer in charge of preparing financial reports, and the actual compliance with the administrative and accounting procedures prepared by said Officer; (iii) assesses on an annual basis the adequacy of the organizational structure of the internal control and risk management system with respect to the characteristics of the company and its risk profile as well as its effectiveness, except for amendments that could make a six-monthly revision necessary, taking this into account also for the purposes of the evaluation on the adequacy of the internal controls and risk management system under point ii). Approves the Management, Supervision and Control Model of the risks on Health, Safety and Environment, Security and Public Safety of the Company, and its substantial amendments. |
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At least annually, approves the Audit Plan prepared by the Head of the Internal Audit Department, with the support of the Control and Risk Committee and following consultation with the Chairman, the Chief Executive Officer and the Board of Statutory Auditors. Evaluates, with the support of the Control and Risk Committee and following consultation with the Board of Statutory Auditors, the findings contained in the recommendation letter, if any, of the audit firm and in its additional report, together with any comments of the Board of Statutory Auditors, informing the Board of Directors on the results of the auditing.
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Defines, upon proposal of the Chief Executive Officer, the strategic guidelines and objectives of the Company and of the Group, pursuing its sustainable success and monitoring its implementation. Examines and approves the four- year Plan and the medium-long term plans of the Company and of the Group and related budgets, also on the basis of the analysis of the issues relevant to the generation of long-term value, periodically monitoring their implementation. Examines and approves the plan for the Company’s non-profit activities, after the assessment of the Sustainability and Scenarios Committee; it also approves operations not included in the non-profit plan whose cost exceeds € 1 million, provided that reports on operations not included in the plan and not subject to Board approval are periodically submitted to the Board, in accordance with paragraph below. |
140
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• |
Examines and approves, with the support of the Board Committees to the extent applicable, the Annual Financial Report, which includes the draft of Eni Financial Statements, the Consolidated Financial Statements and the consolidated non- financial statement, the consolidated annual Sustainability Report not already contained within the non-financial statement and the half-year financial report. It also examines and approves any semi-annual and quarterly financial reports and preliminary reports, the annual Report on Payments to Governments and any additional periodic statements or reports in accordance with applicable regulations.
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Receives from Directors with delegated powers at the Board meetings, on at least a bi- monthly basis, reports on actions taken in exercising their delegated powers, as well as on Group activities and on atypical or unusual transactions that have not been submitted to the Board for examination and approval, as well as on the execution of transactions with related parties and those in which the Directors and Statutory Auditors hold an interest in accordance with the relevant internal procedures. It also receives prior information: (i) on the closure of significant industrial sites in the refining and chemical sector, when the closure does not follow the liquidation of a company and (ii) on exiting countries where the Company operates, when entry was authorized by the Board.
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Receives periodic reports from the Chairman, on the implementation of Board resolutions. At each Board meeting, receives information from the Board’s internal Committees on the most relevant issues examined during their meetings and, at least on a semi-annual basis, a report on their activities.
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Assesses general trends in the operations of the Company and of the group on the basis of information received from Directors with delegated powers, paying particular attention to conflicts of interest and comparing, normally on a quarterly basis, results – as reported in the annual financial statements and interim financial reports – with budget forecasts.
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Examines and approves, with the support of the competent board committees, transactions by the Company and by its subsidiaries with related parties as provided for in the relative procedure approved by the Board, as well as transactions in which the Chief Executive Officer holds an interest pursuant to art. 2391, first paragraph, of the Italian Civil Code, that fall under the responsibility of the Chief Executive Officer.
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Evaluates and approves any transaction executed by the Company and by its subsidiaries (excluding the joint- control companies), that has a significant impact on the Company's strategy, performance or financial position. |
The Board ensures compliance with the principles of good corporate governance and management of the subsidiaries, protecting their operational autonomy with specific regard to listed companies and companies for which law or regulations require it. It also ensures the confidentiality of transactions between said subsidiaries and Eni or third parties for the protection of the subsidiaries' interests. Without prejudice to any of the provisions mentioned below, transactions with a significant impact include the following:
a) acquisitions and disposals of equity investments, companies or business units, property rights, leases active and passive of companies or business units, transfers of assets (with the exception, for all of these, of transactions with and between subsidiaries), mergers, demergers and liquidations of companies exceeding €200 million in the upstream oil&gas sector and €150 million in other business sectors, without prejudice to art. 23.2 of the By-laws;
b) acquisitions and disposals (also as part of “unification” agreements) of exploration mining rights exceeding €150 million and productive mining rights exceeding €200 million;
c) capital increases (i) of subsidiaries: for amounts exceeding €1 billion, (ii) of associate companies: for amounts exceeding €500 million, if proportionate to the interest held, and of any amount, if not proportional to the interest held;
d) investments in fixed assets exceeding €500 million in the upstream oil&gas sector, and €300 million in other sectors;
e) transactions that imply: (i) entry into new countries, with a significant operational presence or with initiatives that present a particular risk and/or (ii) significant entry into new business sectors;
f) real estate leases, purchase and sale of goods and contracts for the provision of work or services (other than those intended for investment and gas supplies), with the exclusion of contracts with and between subsidiaries, at a total price exceeding €1 billion or, if the total price exceeds €500 million, with a duration of more than 20 years;
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g) gas and LNG purchase and supply contracts, of at least 3 billion cubic meters per year and ten-year duration or changes to gas purchase and supply contracts involving increases in commitments of at least 3 billion cubic meters per year and increases in duration, inclusive of the residual duration of the contract, exceeding 10 years, with the exception of modifications made in execution of contractual clauses already included in the original agreement;
h) loans to subjects other than subsidiaries: (i) if in favour of associate companies: for an amount exceeding €300 million, if in proportion to interest held; and for an amount exceeding €10 million if not proportional to interest held; (ii) if in favour of non- associate companies: of any amount; (iii) changes in the loans referred to in points (i) and (ii), which determine a worsening in the approved contractual terms.
The following transactions do not require the approval of the Board:
a. financial commitments assumed in a non-proportional amount to interest held (so-called "carry agreement") within contracts relating to the exploration and development phase of hydrocarbons, provided that the following conditions are jointly warranted: (i) the obligations are assumed in favour of the host state or an oil company directly or indirectly wholly-owned by the host state; (ii) the obligations are distributed in proportion to the interest held in the reference asset by subjects other than the State or the State oil company (referred to in point i) at the time the financial commitment is made; (iii) with relation only to carry agreements for the development phase, the risk of repayment of the loan is guaranteed by any future financial or production flows of the underlying mining investment. The carry agreements, or amendments thereof, stipulated after the conclusion of the above contracts, are subject to the approval of the Board if they determine a non-proportional increase in the exposure and for amounts exceeding €200 million;
b. the signing and application of default clauses contained in the contracts regulating the mining activity between partners of a joint venture;
i) issuing of unsecured and secured guarantees to entities other than subsidiaries: (i) for amounts exceeding €500 million, if in the interest of the Company or of Eni subsidiaries; (ii) for amounts exceeding €300 million, if in the interest of non-controlled associated companies; (iii) in any case, for amounts exceeding €10 million if the guarantee is not proportionate to the interest held in the obligations underlying the guarantee (with the exception of the case in which the non-proportionality is due to the presence of a carry agreement within the limits indicated in letter h) above); (iv) if in the interest of entities belonging to "Temporary Business Groupings" for participation in tenders for which Eni or its subsidiaries act as agents, for an amount exceeding €50 million, or for any amount if there is no provision for the issue of a counter-guarantee by the entities participating in the "Temporary Business Grouping"; (v) for any amount, if in the interest of third parties; (vi) for an indeterminate amount, in the interest of any person; (vii) changes to the guarantees referred to in the previous points, which determine a worsening in guarantees already issued;
j) waiver of rights with a value equal to the thresholds set out in the preceding letters for the acquisition or transfer of the same rights;
k) Eni S.p.A. intermediation agreements, understood as contracts in which the Company, in relation to a specific business initiative, appoints an entity for the exclusive purpose of putting the Company in contact with third parties, promoting the interests of the Company with the aforementioned subjects and facilitating the stipulation/execution of contracts with them.
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Appoints and revokes – acting upon proposal of the Chief Executive Officer in agreement with the Chairman and following consultation with the Nomination Committee – the Chief Operating Officers, defining the content and limits of their powers as well as the provisions for exercising them. In the case of appointment of the Chief Executive Officer as General Manager, the proposal is made by the Chairman. At the time of the appointment and periodically, the Board assesses compliance with the integrity requirements provided for by current legislation for General managers.
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Upon proposal of the Chairman, appoints and revokes the Board Secretary and Board Counsel, which reports hierarchically and operationally to the Board and by means of it to the Chairman, and determines the remuneration, the charter and the annual budget.
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After assessing his compliance with professional and integrity requirements, appoints and removes the Officer in charge of preparing financial reports – acting upon a proposal of the Chief Executive Officer and in agreement with the Chairman, following consultation with the Nomination Committee, and having received the favourable opinion of the Board of Statutory Auditors; also, following the opinion of the Control and Risk Committee, ensures that he has adequate powers and means to carry out his statutory duties and monitors compliance with the administrative and accounting procedures established by the abovementioned officer. The Board periodically assesses the possession of the integrity requirements provided for by current legislation for the Officer in charge of preparing financial reports.
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Acting upon proposal of the Chairman, in agreement with the Chief Executive Officer, with the support of the Control and Risk Committee, and following consultation with the Board of Statutory Auditors, it (i) appoints and removes the Head of Internal Audit Department, with the support of the Nomination Committee (ii) it approves the Internal Audit budget, ensuring that the Head of Internal Audit Department has adequate resources to carry out his duties: (iii) establishes his remuneration structure in accordance with the Company’s remuneration policies. The Head of Internal Audit Department reports hierarchically to the Board and, on its behalf, to the Chairman, without prejudice to its operational dependence on the Control and Risk Committee and on the Chief Executive Officer.
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With the support of the Control and Risk Committee, determines the attribution of supervisory functions and the composition criteria of the supervisory body pursuant to Legislative Decree 231/2001 and, on the proposal of the Chief Executive Officer, in agreement with the Chairman: (i) having heard the Nomination Committee and, for external members, also the opinion of the Board of Statutory Auditors, it appoints and removes the members of the Supervisory Body referred to in Legislative Decree no. 231 of 2001, determining its composition and (ii) establishing the remuneration of its members. Upon proposal of the Supervisory Body, approves the related annual "budget".
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Evaluates, with the support of the Control and Risk Committee, the adoption of measures to guarantee the effectiveness and impartiality of judgment of the Integrated Risk Management and Integrated Compliance functions and of any other functions involved in controls, verifying that they are equipped with adequate skills and resources.
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Promotes, in the most appropriate way, dialogue with shareholders and other relevant stakeholders for the company. Upon the proposal of the Chairman, in agreement with the Chief Executive Officer, adopts and describes, in the corporate governance report, a policy for managing dialogue with the generality of shareholders. The Chairman ensures, within the terms established by said policy, that the Board receives, by the first useful meeting and in any case within the terms established by the policy, information on the development and significant contents of the dialogue taking place with all the shareholders. |
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Defines, with the assistance of the Remuneration Committee, the policy for the remuneration of directors, managers with strategic responsibilities and, without prejudice to the provisions of art. 2402 of the Italian civil code, of members of the control body; it approves, on the proposal of the same Committee, the Report on the remuneration policy and compensation paid to be presented to the Shareholders' Meeting called to approve the financial statements. Furthermore, in implementing the Remuneration Policy, approved in the Shareholders' Meeting, following a proposal from the Remuneration Committee: (i) defines, having heard the opinion of the Board of Statutory Auditors, the remuneration of Directors with delegated powers and those with particular offices; (ii) establishes the objectives, and verifies their final achievement, connected to the variable remuneration of Directors with delegated powers and the incentive plans; (iii) implements the remuneration plans based on shares or financial instruments approved by the Shareholders' Meeting; (iv) ensures that the remuneration paid and accrued is consistent with the principles and criteria defined in the policy, in light of the results achieved and other relevant circumstances for its implementation. Upon termination of office and/or of the relationship with the Chief Executive Officer or a Chief Operating Officer, based on the outcome of the internal processes leading to the attribution or recognition of any indemnity and/or other benefits, approves the press release to be disseminated to the market with the information required by the Corporate Governance Code and/or by any applicable regulations. |
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Decides – acting upon a proposal of the Chief Executive Officer – on the exercise of voting rights and, in consultation with the Nomination Committee, on the appointment of members of corporate bodies of the subsidiaries with strategic importance and Saipem S.p.A. In the case of listed companies, the Board must guarantee compliance with the provisions of the Corporate Governance Code that fall under the competence of the Shareholders' Meeting. |
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Formulates proposals to submit to the Shareholders' Meeting and, through the Chairman and the Chief Executive Officer, reports to the Shareholders' Meeting on the activities carried out and planned, working to ensure that shareholders receive adequate information about the elements they need to take the decisions pertaining to them, with knowledge of the facts. |
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Examines and decides on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity. |
In accordance with art. 23.2 of the By-laws, the Board also decides upon: mergers and proportional spin-offs of companies in which the Company’s shareholding is at least 90%; the establishment and closing of secondary offices; and the amendment of the By-laws to comply with regulatory provisions. For the purposes of the above-mentioned resolution and the Corporate Governance Code, to which Eni S.p.A. adheres, "subsidiaries with strategic importance" means the following companies: Eni International BV, Eni Plenitude S.p.A. Società Benefit and Versalis S.p.A
According to this resolution, the Chief Executive Officer is also in charge of establishing and maintaining the internal control and risk management system. The Board authorizes the Chief Executive Officer to modify investment transactions previously approved by the Board, in ways that do not involve a substantial reconfiguration of the underlying industrial project. The Board receives annual information on these modifications in the event of: (i) an increase in the whole life cost of more than 30% compared to the authorized amount and/or (ii) a reduction in profitability below the hurdle rate or of the adjusted WACC, for projects authorized on the basis of these parameters.
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Directors’ independence
On the basis of statements made by the Directors and other information available to the Company, the Board of Directors after its appointment, in its meeting of May 11, 2023:
- first, defined the criteria for assessing independence, pursuant to the Code, confirming the criteria already identified by the former Board of Directors, relating to the identification of additional remuneration and significance of relationships that could compromise independence;
- and then assessed that the Chairman and Directors Baroncini, Belcredi, Dittmeier, Seganti, Sgubin and Vermeir meet the independence requirements provided for by law and by the Code. At the assessments carried out in February 2024 and February 2025, the Board of Directors, after preliminary assessment by the Nomination Committee, confirmed the previous assessment of independence pursuant to law and to the Code of the Chairman of the Board of Directors Zafarana and Directors Baroncini, Belcredi, Dittmeier, Seganti, Sgubin and Vermeir.
The outcome of the assessments of independence of directors is disclosed to the market immediately after the appointment through a specific press release and, later, in the annual Corporate Governance Report, available on Eni website.
The relationships were evaluated on the basis of statements made by the Directors and other information available to the Company.
The Board of Statutory Auditors verified the proper application of criteria and procedures adopted by the Board of Directors in assessing the independence of its members.
Such independence criteria may be not equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company.
On May 11, 2023, the Board of Directors of Eni confirmed Raphael Louis L. Vermeir Lead Independent Director. Pursuant to Italian Corporate Governance Code, the Lead Independent Director collects and coordinates the requests and contributions of non-executive directors and, in particular, of independent ones and coordinates the meetings of the independent directors.
Boa r d Committees
The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the Remuneration Committee; (c) the Nomination Committee; and (d) the Sustainability and Scenarios Committee. Committees under letters (a), (b) and (c) are recommended by the Code. The composition, duties and operational procedures of these committees are governed by their own rules, which are approved by the Board, in compliance with the criteria outlined in the Code.
The Committees recommended by the Code are composed of no fewer than three members and, in any case, less than a majority of members of the Board. The composition is described in the following sections pertaining each Committee.
All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. In addition, the Chairmen of the Committees report to the Board at each meeting of the Board on the key issues examined by the Committees in their previous meetings.
In the exercise of their functions, the Committees have the right to access any information and Company functions necessary to perform their duties. They are also provided with adequate financial resources, in accordance with the terms established by the Board of Directors and can avail themselves of external advisers.
The Chairman of the Board of Statutory Auditors or a Statutory Auditor designated by her, participates in Control and Risk Committee. Members of the Board of Statutory Auditors may also attend other Committee’s meetings. Upon invitation of the Chairman of the Committee, the Chairman of the Board of Directors and/or the Chief Executive Officer may attend specific meetings 11 as well as other Directors, after having heard the Chairman of the Board. Moreover, upon invitation of the Chairman of the Committee, and having informed the Chief Executive Officer, other members of the Company structure, for their own competence, may be invited to participate in the meeting on specific items of the agenda.
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11 Except for meetings of the Remuneration Committee examining proposals regarding their remuneration. Rules of the Remuneration Committee establish that “no Director and, in particular, no Director with delegated powers may take part in meetings of the Committee during which Board proposals regarding his or her remuneration are being discussed, unless such proposals regard all the members of the Committees established within the Board of Directors.” |
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The Board Secretary and Board Counsel coordinates the secretaries of the Board Committees, receiving for this purpose information on the calendar of the meetings and the items in the Committees’ agendas, the notices of the meetings, as well as their signed minutes.
Minutes of all Committee meetings are usually drafted by their respective secretaries. The current members of the Control and Risk Committee, Remuneration Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on May 11, 2023.
Remuneration Committee
Members: Massimo Belcredi (Chairman), Cristina Sgubin, Raphael Louis L. Vermeir.
The Remuneration Committee is made up of three non-executive Directors, all of whom independent.
The members of the Committee shall have expertise that is consistent with the duties they are required to perform, to be evaluated by the Board of Directors at the time of the appointment.
In particular, at their appointment, the Directors Belcredi and Vermeir have been identified by the Board as members "with adequate knowledge and experience in financial matters or remuneration policies", as recommended by the Corporate Governance Code.
In accordance with the By-laws and the Corporate Governance Code, the Committee assists the Board of Directors with preparatory, consultative and advisory functions on remuneration issues. More specifically, the Committee:
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submits to the Board of Directors for its approval the “Report on remuneration policy and remuneration paid” and, in particular, the remuneration policy for members of corporate bodies, General Managers and managers with strategic responsibilities, without prejudice to provisions of Art. 2402 of Italian Civil Code, to be presented to the Shareholders’ Meeting called to approve the financial statements, as provided for by the applicable law; |
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presents proposals and expresses opinions for the remuneration of the Chairman of the Board of Directors and the Chief Executive Officer, covering the various forms of compensation and benefits awarded; |
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presents proposals and expresses opinions for the remuneration of the members of the Board’s internal committees; |
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examines the CEO’s indications and presents proposals for: |
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general criteria for the remuneration of managers with strategic responsibilities; |
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annual and long-term incentive plans, including equity-based plans; |
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establishing performance targets and assessing results for performance plans in connection with the determination of the variable portion of the remuneration for Directors with delegated powers and with the implementation of incentive plans; |
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periodically evaluates the adequacy, overall consistency and actual implementation of the adopted policy, as described in letter a) above and assesses, in particular, the actual achievement of the performance objectives, formulating proposals on the matter to the Board; |
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performs the tasks required under the Company’s procedures for handling related party transactions; |
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examines and monitors the results of engagement activities carried out in support of the Eni Remuneration Policy, within the terms set forth in the engagement policy approved by the Board. |
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reports to the Board, at least once every six months and no later than the deadline for the approval of the annual and semi- annual financial report, on its activities at the Board meeting indicated by the Chairman of the Board of Directors . |
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Control and Risk Committee
Members: Raphael Louis L. Vermeir (Chairman), Carolyn Adele Dittmeier, Federica Seganti and Cristina Sgubin.
The Control and Risk Committee supports the Board of Directors’ assessments and decisions relating to the Internal Control and Risk Management System (ICRMS) and the approval of periodical financial and non-financial reports. The Committee supports the Board with preparatory work, following which it formulates assessments and/or opinions to the Board.
The Control and Risk Committee comprises four non-executive independent directors. 12
In particular, the Directors Vermeir, Dittmeier and Seganti have been identified by the Board as members "with adequate knowledge and experience in accounting, finance or risk management", required by the Code of Corporate Governance (Recommendation 35) 13 . The Chairman of the Committee was elected from the minority list presented by Italian and foreign institutional investors.
The Committee supports the Board of Directors with preparatory work, following which it formulates assessments and/or opinions, in particular with regard to:
a) the guidelines for the internal control and risk management system (ICRMS) consistently with the Company’s strategies, so that the main risks that affect the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored, expressing in this regard the opinion required by internal regulations on the matter; it also supports the Board of Directors in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives and preliminary examining the main company risks, taking into account the characteristics of the activities carried out by the company or its subsidiaries. In the course of 2024, the Committee contributed to the design of the Eni Risk and Internal Control Holistic Framework Policy (Enrich), which integrates established practices to effectively identify, measure, manage and monitor key risks, driving the development of adaptive control systems for the specific contexts in which we operate with a view of better adapting to the Company’s ongoing transformation and supporting achievement of Company’s goals and strategy execution;
b) the definition, within the Strategic Plan, of the annual guidelines of the internal control and risk management system ("Annual plan for the integrated management of strategic risks"), proposed by the Chief Executive Officer, in line with the strategies of the company, as well as the annual assessment of the implementation of these guidelines, based on the Report prepared for this purpose by the Chief Executive Officer;
c) the evaluation performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the ICRMS;
d) the fundamental guidelines of the Regulatory System, the regulatory instruments to be approved by the Board of Directors, their amendment or update, and, upon request by the CEO, on specific aspects in relation to the instruments implementing the fundamental guidelines, expressing in this regard the opinion required by internal regulations on the matter;
e) the guidelines for the management and control of financial risks, expressing in this regard the opinion required by internal regulations on the matter;
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12 In accordance with the rules of the Control and Risk Committee, the Committee is made up of three to four non-executive Directors, all of whom are independent. Alternatively, the Committee may be made up of non-executive Directors, the majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. In any case, the number of members shall be fewer than the number representing a majority on the Board. |
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13 The Governance system put in place by Eni establishes that the Committee as a whole possesses adequate expertise in the sector of activity in which the Company operates, as necessary to assess the related risks, and must in any case have adequate skills in relation to the tasks it is called upon to perform, as assessed by the Board of Directors upon the appointment; two members of the Committee if there are such members on the Board, or in any case at least one member of the Committee or in any case at least one member of the Committee must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment. |
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f) the proposals concerning the appointment, the removal and, consistent with the Company’s policies, the structure of the fixed and variable compensation of the Internal Audit Director, as well as on the adequacy of the resources provided to the latter to perform his duties, expressing the opinion required by internal regulations on the matter;
g) at least once a year, the Audit Plan prepared by the Internal Audit Director, expressing the opinion required by internal regulations on the subject (guidelines on Internal Audit activity - Internal Audit Charter);
h) the assessment of opportunities to adopt measures to ensure the effectiveness and impartiality of judgment of the Integrated Risk Management and Integrated Compliance units and of any other functions involved in the controls identified by the Board of Directors, as well as the annual verification that they are equipped with adequate professionalism and resources;
i) the choice relating to the attribution of supervisory functions pursuant to Legislative Decree no. 231/2001 and the composition criteria of the Watch structure pursuant to Legislative Decree no. 231/2001 which is reported in the Corporate Governance Report;
j) the exam of reports on the ICRMS, also following periodic meetings with the relevant structures of the Company;
k) investigations and examinations carried out by third parties regarding the internal control and risk management system; findings reported by the Audit Firm in any management letter it may issue and in the latter’s additional report which includes any opinions of the Board of Statutory Auditors. The additional report includes any opinions of the Board of Statutory Auditors;
l) the illustration, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, and how the different subjects involved therein are coordinated, providing an indication of benchmark models as well as national and international best practices, and an evaluation of the overall adequacy of the system itself;
m) the adoption and amendment of the rules for the transparency and substantial and procedural correctness of transactions with related parties and those in which a Director or Statutory Auditor holds an interest, on his own or on behalf of third parties, expressing the opinion required by regulations, including internal ones, on the subject and carrying out the additional tasks assigned to it by the Board of Directors, also with reference to the examination and issue of an opinion on certain types of transactions, except for those relating to remuneration;
n) the proposal of the Chief Executive Officer for the definition of the principles concerning the coordination and information flows between the various parties involved in the ICRMS.
In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the Officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the consolidated financial statements, issuing an opinion prior to their approval by the Board of Directors; b) examines and evaluates Reports prepared by the Officer in charge of preparing financial reports through which it shall give its opinion to the Board of Directors on the appropriateness of the powers and resources assigned to the Officer himself and on the proper application of accounting and administrative procedures, enabling the Board to exercise its tasks of supervision required by law; c) assesses whether the periodic non-financial information is suitable to correctly represent the Company’s business model, its strategies, the impact of its business and the performance achieved, expressing an opinion to the Board in coordination with the Sustainability and Scenarios Committee; d) examines the content of the periodic non-financial information relevant to the ICRMS; e) expresses opinions to the Board of Directors on specific aspects relating to the identification of the main corporate risks; f) on request of the Board, it supports, with adequate preliminary activities, the Board of Directors’ assessments and resolutions on the management of risks arising from detrimental facts which the Board may have become aware of and g) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and oversees its activities with respect to the duties of the Board of Directors and the Chairman of the Board on its behalf, in this area, ensuring that they are performed with the necessary independence and required level of objectivity, competence and professional diligence, in accordance with the Code of Ethics of Eni SpA and international standards, as well as with the terms provided by the guidelines on Internal Audit activities (Internal Audit Charter).
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In particular, the Committee also: a) examines and evaluates, on the occasion of his/her appointment, whether the Internal Audit Director meets the integrity, professionalism, competence and experience requirements and, on an annual basis, assesses their fulfilment; b) examines the results of the audit activities performed by the Internal Audit Department and the periodic reports prepared by it containing adequate information on the activities carried out, on the manner in which risk management is conducted and on compliance with risk containment plans, as well as assessment of the appropriateness of the ICRMS . It also examines the reports promptly prepared by the Internal Audit Department on events of particular importance; c) examines the information received from the Internal Audit Department and promptly reports its assessment to the Board of Directors in the case of: (i) significant deficiencies in the system for preventing irregularities and fraudulent acts, and irregularities or fraudulent acts committed by management personnel or by employees who perform important roles in the design or operation of the ICRMS; and (ii) circumstances which may affect the maintenance of the independence of the Internal Audit Department and of auditing activities and d) may ask the Internal Audit Department to perform audits of specific operational areas, providing simultaneous notice to the Chairman of the Board of Directors, the CEO and the Chairman of the Board of Statutory Auditors, unless there are conflicts of interest.
The Committee also examines and assesses: a) communications and information received from the Board of Statutory Auditors and its members regarding the ICRMS, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports and b) half yearly reports issued by Eni’s Watch Structure, as well as the timely updates provided by the Structure, after the updates have been given to the Chairman of the Board and to the CEO, about any particular materiality or significant situation detected in the execution of its duty.
Furthermore, in case of judicial inquiries and proceedings, carried out in Italy and/or abroad, involving the CEO and/or the Chairman of Eni SpA and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, in relation to crimes against the Public Administration and/or corporate crimes and/ or environmental crimes, related to their duties and their scope of responsibility, in which the Board of Directors determines that the CEO may have an interest, pursuant to Article 2391 of the Civil Code, in order to ensure the independence of judgment of the Legal Department of the Company, in the interest of the same, the Board provides the Legal Department with the necessary information on its activities, with the support of the Committee. In particular, the Board avails itself of the Committee in order to ascertain the legal classification of the facts under investigation and proceedings, to acquire all necessary information on said investigations and proceedings from the legal department, to verify their completeness and accuracy, to be informed of the performance of such investigations and proceedings and to receive guidance to be provided to the legal department.
Nomination Committee
Members: Carolyn Adele Dittmeier (Chairman), Elisa Baroncini and Massimo Belcredi.
The Nomination Committee is made up of three non-executive Directors, all of whom independent.
In accordance with the By-laws and the Corporate Governance Code, the Committee assists the Board of Directors with preparatory, consultative and advisory functions on appointment and succession plans issues. More specifically, the Committee:
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a) assists the Board of Directors in formulating any criteria for the appointment of persons indicated in letter b) below, and of the members of the other boards and bodies of Eni’s associated companies;
b) provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment falls under the Board’s responsibilities and oversees the associated succession plans. It supports the Board in the elaboration, update and implementation of the Chief Executive succession plan, by identifying, at least, the procedures to be followed in the event of an early termination of office;
c) upon a proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession planning for the Company’s managers with strategic responsibilities;
d) assists the Board in the identification of candidates to serve as Directors in the event one or more positions need to be filled during the course of the year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements regarding the minimum number of independent Directors and the percentage reserved for the less represented gender, as well the representation of non-controlling interests;
e) proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, in the absence of proposals submitted by the shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders;
f) with reference to the annual evaluation program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, it assists the Chairman of the Board of Directors in the activity attributed to it, of ensuring the adequacy and transparency of the self-assessment process of the Board; assists the Board in the preparatory work for the appointment of an external consultant and in the evaluation of the outcomes of the process. On the basis of the results of the self-assessment, the Committee supports the Board of Directors regarding the size and composition of the Board or its Committees, as well as, the skills and managerial and professional qualifications it feels should be represented within the same Board and Committees also in light of the industrial characteristics of the Company, taking into account the diversity criteria and the Board of Directors guidelines on the maximum number of positions a Director can hold in other companies, so that the Board itself can issue its guidelines to the shareholders prior to the appointment of the new Board;
g) assists the outgoing Board in the proposition of the slate of candidates for the position of Director to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3 (1) of the By-laws, ensuring the transparency of the process leading to the slate’s structure and proposition;
h) in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of positions of Director or Statutory Auditor that a Company Director may hold and performs the preliminary activity for the associated periodic checks and evaluations for submission to the Board;
i) periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible, at least on an annual basis and upon the occurrence of circumstances relevant to independence;
j) provides its opinion to the Board of Directors on any activities carried out by the Directors, which are in competition with the Company;
k) reports to the Board of Directors, at least once every six months and no later than the deadline for the approval of the annual and semi-annual financial report, on the activity carried out, at the Board meeting indicated by the Chairman of the Board of Directors.
The preliminary examination of corporate affairs or governance issues is carried out jointly with the Director Corporate Affairs and Governance, who, in this case, participates in the Committee meetings.
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Sustainability and Scenarios Committee
Members: Federica Seganti (Chairman), Elisa Baroncini and Roberto Ciciani.
The Sustainability and Scenarios Committee is made up of three non-executive Directors, a majority of whom are independent.
The Committee assists the Board of Directors with preparatory, consultative and advisory functions on scenarios and sustainability issues, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: climate transition and technological innovation; access to energy, energy sustainability; environment and energy efficiency; local development, particularly economic diversification, health, well- being and safety of people and communities; respect and protection of rights, particularly of the human rights; integrity and transparency; diversity and inclusion.
More specifically, in its preparatory, consultative and advisory function towards the Board of Directors, the Committee:
a. examines scenarios for the preparation of the Strategic Plan, giving its opinion to the Board of Directors;
b. examines and evaluates climate transition issues, i.e. decarbonisation at both operational and product portfolio level, technological innovation, green chemistry and circular economy, aimed at ensuring the creation of value over time for shareholders and all other stakeholders;
c. examines and evaluates other aspects of the sustainability policy, in accordance with the principles of sustainable development, as well as sustainability strategies and objectives;
d. monitors the Company’s position in terms of sustainability with regard to financial markets, particularly with regard to annual reporting on new sustainable finance tools, as well as the Company’s inclusion in the leading sustainability indexes;
e. examines and evaluates the sustainability report submitted annually to the Board of Directors;
f. monitors international sustainability projects as part of global governance processes and the Company’s participation in such projects, designed to strengthen the Company’s international leadership;
g. examines and assesses local sustainability initiatives, including in relation to individual projects, provided for in agreements with producer countries, submitted by the CEO for presentation to the Board;
h. examines how the local sustainability policy is implemented in business initiatives, on the basis of indications provided by the Board of Directors;
i. examines the Company’s non-profit strategy and its implementation, including in relation to individual projects, through the non-profit plan submitted each year to the Board, as well as non-profit initiatives submitted to the Board;
j. at the request of the Board, gives its opinion on other sustainability issues;
k. in agreement with the Chief Executive Officer, evaluates the opportunity of organizing open Committee meetings, possibly including other directors, with institutional stakeholders, to listen to their point of view with reference to the issues falling within the competence of the Committee;
l. at least once every six months, reports to the Board of Directors on its activities, by the date of the approval of the annual and semi-annual financial reports, during the meeting of the Board of Directors indicated by the Chairman of the Board of Directors;
m. coordinates with the Control and Risk Committee in assessing the suitability of periodic non-financial information, to correctly represent the business model, the strategies of the company, the impact of its activity and the performance achieved.
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Boa r d of Statutory Auditors
|
Name |
|
Position |
|
Year first appointed to Board of Statutory Auditors |
|
Rosalba Casiraghi |
|
Chairman |
|
2017 |
|
Enrico Maria Bignami |
|
Auditor |
|
2017 |
|
Marcella Caradonna |
|
Auditor |
|
2021 |
|
Giulio Palazzo |
|
Auditor |
|
2023 |
|
Andrea Parolini (1) |
|
Auditor |
|
2023 |
|
Giulia De Martino |
|
Alternate |
|
2023 |
|
Giovanna Villa |
|
Alternate |
|
2023 |
|
|
|
(1) Andrea Parolini was also Standing Auditor of Eni SpA from April 13, 2017 to May 13, 2020.
The current Eni’s Board of Statutory Auditors, composed of five standing members and two substitute members, was appointed by the shareholders on May 10, 2023 for three years, until the date of the Ordinary Shareholders’ Meeting convened for approval of financial statements for the year ending December 31, 2025. The Standing Statutory Auditors Marcella Caradonna, Giulio Palazzo, Andrea Parolini and the Alternate Auditor, Giulia De Martino were elected from the slate submitted by the Ministry of Economy and Finance (the “majority slate”); Rosalba Casiraghi, appointed Chairman of the Board of Statutory Auditors, the Standing Statutory Auditor, Enrico Maria Bignami and the Alternate Auditor, Giovanna Villa were elected from the slate presented by non-controlling shareholders (the “minority slate”).
The Auditors are appointed by means of a slate voting system: the lists are presented by shareholders representing at least 0.5% of the share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders.
In accordance with the provisions designed to ensure gender balance, two Statutory Auditors were drawn from the less represented gender.
The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of Financial Statements and internal control processes. The Board of Statutory Auditors, acting as the Internal Control and Financial Auditing Committee pursuant to Legislative Decree no. 39/2010 (Consolidate Law on Statutory Audits of annual accounts and consolidated accounts), must satisfy the requirement imposed by Art. 19 of that law, providing that “the members of the internal control and financial auditing committee, as a body, are competent in the sector in which the company being audited operates”. In addition, the Corporate Governance Code 2020 which Eni adopted from December 23, 2020, applicable from January 1, 2021, also recommends that all members of the Board of Statutory Auditor possess the independence requirements envisaged for Directors. Compliance with those criteria is verified by the Board of Statutory Auditors itself.
Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters within the scope of the Board’s Authority, the adequacy of the internal control system and the administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.
152
In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, in its role as the “internal control and financial auditing committee” the Board of Statutory Auditors: a) informs the Board of Directors of the conclusion of the statutory audit and the outcome of the sustainability reporting certification activity and transmits to the Board the “additional report” of the audit firm adding proper evaluation if deemed necessary; b) oversees the financial reporting process and the corporate sustainability reporting as well as presents recommendations to ensure its integrity; c) controls the effectiveness of internal quality control system and Risk Management, the effectiveness of internal audit, with reference to the financial reporting process and to the corporate sustainability reporting, without violating its independence; d) oversees the statutory audit of annual accounts and consolidated accounts and the sustainability reporting certification activity, also considering results of quality control of the audit activity performed by the public authority responsible for regulating the Italian financial markets; e) verifies and monitors the independence of the audit Firm and of the Firm that carries out the certification activity of sustainability reporting with particular reference to non-audit services; f) is responsible of the procedure to select the audit Firm, making a recommendation to the Shareholders’ Meeting for the appointment of the audit Firm.
The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee”, with reference to the statutory auditing, are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “Sarbanes-Oxley Act” (discussed in greater detail below).In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements.
On March 22, 2005, the Board of Directors, electing the exemption granted by the SEC applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and SEC rules. On June 15, 2005, the Board of Statutory Auditors approved the internal rules, later updated, concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by the SEC include:
|
● |
evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor; |
|
● |
overseeing the work of the external Auditor engaged to audit the accounts or perform other audit, review or certification services; |
|
● |
examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management; |
|
● |
making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting. |
In addition the Board of statutory auditor:
|
● |
approves the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters; |
|
● |
examines reports from the CEO and the Head of Eni’s Accounting and Financial Statements department concerning: i) any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and ii) any fraud that involves management or other employees who have a significant role in the Company’s internal controls. |
153
The Board of Statutory Auditors, in the performance of its duties, is supported by the Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department.
231 Supervisory Body and Model 231
In accordance with the Italian regulations concerning the “administrative liability of legal entities deriving from criminal offences”, contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, “Legislative Decree No. 231/2001”), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the 231 Supervisory Body. Moreover, as a result of changes in the Italian legislation governing the matter and in the Company’s organizational structure, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of November 18, 2021 approved the updating of Model 231.
Italian Legislative decree no. 231/2001 has established companies’ liability for crimes committed by their managers and employees in performing their job tasks, because allegedly committed on behalf of a company. Companies are not liable in case they prove that they have adopted effective internal control systems designed to prevent wrongdoing by their managers and employees. The rule covers several types of offences, including offences against the public administration, corruption, environmental crimes, human rights violations, money laundering, data privacy violation and cybersecurity crimes, misleading financial statements, organized crimes, and crimes related to terrorism and insurgency.
Furthermore, the Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics; the new Code sets out the fundamental principles of Eni’s Model 231 which is one of the pillars of Eni “regulatory system” and inspires it.
At present, the 231 Supervisory Body is composed of three external members, one of which with the role of Chairman as well as by the Chairman of the Board of Statutory Auditors and the Director of Internal Audit, as internal members. External members are independent professionals, experts in law and/or economic matters.
Audit Firm
The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit Firm appointed by the Shareholders’ Meeting on the basis of a reasoned recommendation of the Board of Statutory Auditors.
In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm issues a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit Firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting. The financial statements of Eni’s subsidiaries generally are subject to auditing by Eni’s Audit Firm. Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of May 10, 2018 approved the engagement of PricewaterhouseCoopers SpA to perform the external statutory audit of the accounts of the Company and the audit of the internal control system over financial reporting, pursuant to U.S. law, for the period 2019 – 2027.
Court of Auditors (Corte dei Conti)
The financial management of Eni is subject to the control of the Italian Court of Auditors in order to preserve the integrity of the public finances. This task has been carried out by the Magistrate of the Court of Auditors, Giovanni Coppola, on the basis of the resolution approved in November 7-8, 2023 , by the Presidential Council of the Court of Auditors.
The Magistrate of the Court of Auditors attends the meetings of the Board of Directors and of the Board of Statutory Auditors.
As of December 31, 2024, Eni had a total of 32,492 empl o yee s , with a decrease of 650 empl o yee s ( 2.0% compared to December 31, 2023), which mainly re f lects a decrease of 1,001 employes working abroad and an increase of 351 empl o yees w orking in Italy.
|
|
|
|
|
|
154
This decrease mainly reflected the extraordinary M&A operations such as the sale of Nigerian upstream assets, of the Ecuadorian refining companies partly offset by the acquisition of the Neptune Group in the upstream business and of the Aten Oil company in the Enilive business to expand the service station in Spain.
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
|
(number) |
|
|
|
Exploration & Production |
9,188 |
|
9,840 |
|
9,733 |
|
Global Gas & LNG Portfolio and Power |
1,151 |
|
1,130 |
|
1,317 |
|
Enilive and Plenitude |
5,899 |
|
5,759 |
|
5,303 |
|
Refining and Chemicals |
10,060 |
|
10,449 |
|
9,770 |
|
Corporate and Other activities |
6,194 |
|
5,964 |
|
6,065 |
|
|
32,492 |
|
33,142 |
|
32,188 |
The table below sets forth Eni’s employees as of December 31, 2022, 2023 and 2024 in Italy and outside Italy:
|
|
|
2024 |
|
2023 |
|
2022 |
|
|
|
|
|
(number) |
|
|
|
Exploration & Production |
Italy |
4,017 |
|
3,913 |
|
3,902 |
|
|
Outside Italy |
5,171 |
|
5,927 |
|
5,831 |
|
|
|
9,188 |
|
9,840 |
|
9,733 |
|
Global Gas & LNG Portfolio and Power |
Italy |
765 |
|
740 |
|
729 |
|
|
Outside Italy |
386 |
|
390 |
|
588 |
|
|
|
1,151 |
|
1,130 |
|
1,317 |
|
Enilive and Plenitude |
Italy |
3,827 |
|
3,656 |
|
3,342 |
|
|
Outside Italy |
2,072 |
|
2,103 |
|
1,961 |
|
|
|
5,899 |
|
5,759 |
|
5,303 |
|
Refining and Chemicals |
Italy |
7,559 |
|
7,702 |
|
7,077 |
|
|
Outside Italy |
2,501 |
|
2,747 |
|
2,693 |
|
|
|
10,060 |
|
10,449 |
|
9,770 |
|
Corporate and other activities |
Italy |
5,932 |
|
5,738 |
|
5,828 |
|
|
Outside Italy |
262 |
|
226 |
|
237 |
|
|
|
6,194 |
|
5,964 |
|
6,065 |
|
Total |
Italy |
22,100 |
|
21,749 |
|
20,878 |
|
|
Outside Italy |
10,392 |
|
11,393 |
|
11,310 |
|
|
|
32,492 |
|
33,142 |
|
32,188 |
|
of which senior managers |
|
945 |
|
960 |
|
966 |
We seek to maintain constructive relationship with labor unions.
As of February 26, 2025, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 1,472,015 less than 0.1% of Eni’s share capital outstanding as of the same date. Eni issues only ordinary shares, each bearing the right to one-vote; therefore shares held by those persons have no different voting rights. The breakdown of share ownership for each of those persons is provided below.
|
Name |
Position |
Number of shares owned |
|
|
Board of Directors |
|
|
|
|
Claudio Descalzi |
CEO |
552,237 |
|
|
Senior Managers (a) |
|
919,778 |
(1) |
|
(a) Members of the Management Committee at December 31, 2024. |
|
(1) No. 13,637 shares owned by spouses not legally separated and by underage children. |
Employees’ involvement in the capital of the Company In 2024, based on a Shareholders’ resolution of May 15, 2024, Eni has adopted an Employee Stock Ownership Plan 2024-2026, which has been initially implemented for employees in Italy and is expected to be gradually extended to foreign subsidiaries, with the aim of strengthening employees’ retention to the Company and their participation in the growth of corporate value, in line with the interests of the shareholders.
The Plan grants two annual award (in 2024 and 2025) of free for no consideration with an annual individual monetary value of €2,000, with a three-year lock-up period. In 2026, a co-investment model will be implemented whereby, upon the employee's purchase of shares, free shares will be granted equal to 50% of the shares purchased, up to a maximum value of €1,000.
At the grant date (November 27, 2024), a total of 3,102,700 shares were issued.
155
Item 7. MAJOR SHAREHOLDERS AND RELATED P A R TY TRANSACTIONS
Major Shareholders
The Ministry of Economy and Finance controls Eni as a result of the shares directly owned and those indirectly owned through Cassa Depositi e Prestiti SpA (CDP), in which the Ministry of Economy and Finance holds a 82.77% stake.
As of March 13, 2025, the total amount of Eni’s voting securities owned, either directly or indirectly, by persons that have notified that their holding exceeds the threshold of 3% 15 pursuant to Article 120 of the Legislative Decree No. 58/1998 and to the Consob Regulation No. 11971/1999 and, in any case, by controlling shareholders, was:
|
Title of class |
|
Number of shares owned |
|
Percent of class |
|
Ministry of Economy and Finance |
|
65,586,402 |
|
2.08 |
|
Cassa Depositi e Prestiti SpA |
|
936,179,478 |
|
29.75 |
As of March 13, 2025, the percentage of Eni’s treasury shares was equal to 2.91% of the share capital 16 .
In relation to the Italian legislation g o verning the special powers of the Italian State see “Item 10 – A d dition a l information – Limitations on changes in cont r ol of the Company (Special Powers of the Italian State)”.
As of March 13, 2025, there were 20,497,491 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 1.30% of Eni’s share capital. See “Item 9 – The offer and the listing”.
Related parties transactions
In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with associates, joint ventures, joint operations or other affiliates, as well as other companies owned or controlled by the Italian Government. All such transactions are conducted in the interest of Eni Group companies 17 .
Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in “Item 18 – Note 36 to the Consolidated Financial Statements”.
|
|
|
|
15 Major holdings pursuant to Article 120 of the Legislative Decree No. 58/1998 are updated also on the basis of communication made by intermediaries pursuant to Article 83-novies of the Legislative Decree No. 58/1998 in order to exercise the corporate rights. |
|
|
16 Eni's Board of Directors approved the start of the buy-back program for 2024 in execution of the authorization granted by the Shareholders Meeting held on May 15, 2024. Purchases started on May 27, 2024 and terminated on February 20, 2025. Following the purchases made until the termination of the buy-back programme for the year 2024, considering the treasury shares already held and the free of charge shares granted to Eni’s employees (as provided by the “Long-Term Incentive Plan 2020-2022” approved by Shareholders’ Meeting of May 13, 2020, and by the “Employee Stock Ownership Plan” approved by Eni’s Shareholders’ Meeting of 15 May 2024), Eni held n. 229,335,738 shares equal to 6.98% of the share capital. Following the cancellation of no. 137,725,411 treasury shares made on the basis of the authorization granted by the Shareholders’ Meeting held on May 15, 2024 and executed on March 13, 2025, Eni holds no. 91,610,327 treasury shares. |
|
|
17 For more details on internal rules on related parties transactions, please refer to Item 10, paragraph “Interests in Company’s transactions”. |
|
156
Consolidated Statements and other financial information
See “Item 18 – Financial Statements”.
Legal proceedings
Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account existing risk provisions and that in some instances it is not possible to make a reliable estimate of any contingency losses, Eni believes that these legal proceedings will likely not have a material adverse effect on the Group Consolidated Financial Statements.
A description of the most significant proceedings currently pending is provided in “Item 18 – Note 28 to the Consolidated Financial Statements”. Generally, and unless otherwise indicated, these legal proceedings have not been provisioned because Eni believes that an unfavorable outcome is unlikely or because the amount of the provision cannot be estimated reliably.
Dividends and remuneration policy
Management is committed to delivering on a progressive and competitive shareholder remuneration policy, that is reflective of the expected growth in underlying earnings and cash flows at a constant scenario basis and the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders’ remuneration, management also consider trends in crude oil prices and in other market variables.
As part of that framework and to reflect improved financial metrics of the Company, management is planning to enhance shareholders’ remuneration by pegging expected distributions to a percentage ranging from 35 to 40% of the expected cash flow from operations before working capital, up from the previous stated range of 30 to 35%. Distributions will contemplate a combination of dividends and share repurchases. We expect to grow the dividend in future years in line with the expected growth in the Group underlying financial performance, and to improve the dividend resilience to the scenario.
The management intend to distribute up to 60% of the incremental cash flow from operations due to better-than-expected Group financial results through incremental stock repurchases. In case the scenario evolves contrary to management’s expectations, the Company intends to preserve shareholders’ returns leveraging on the Company’s financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio.
For 2025, having assessed the progress of the Company in executing its strategy, basing on a sound financial position and at the management’s crude oil prices outlook of 75 $/bbl, the Company is planning to increase the annual total dividend to €1.05 per share, up 5% from €1 per share relating to fiscal year 2024. This dividend is expected to be paid in four quarterly instalments in September 2025, November 2025, March 2026 and May 2026.
As part of the stated remuneration policy and as the current authorized buy-back program has been completed in February 2025, Eni plans to commence a new share buyback program of at least €1.5 billion, following expected shareholders’ approval at the Annual General Meeting scheduled in May 2025, which could rise to €3.5 billion in case of better-than-expected results.
See “Item 5 – Recent developments and Management’s expectations of operations” for a discussion of significant subsequent business developments and transactions occurred after the closing date up to the latest practicable d a te.
157
Item 9. THE OFFER AND THE LISTING
The principal trading market for the ordinary shares of the Company (the “Shares”) is the Euronext Milan (“EXM”). EXM, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (“Borsa Italiana”).
Eni’s American Depositary Receipts (“ADRs, and each an “ADR”), each representing two Shares, are listed on the New York Stock Exchange. Since June 27, 2017, Citibank N.A. (the “Depositary”) acts as the company’s depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) entered into among Eni, the Depositary, some beneficial owners (the “Beneficial Owners”) and registered holders from time to time of the ADRs issued hereunder.
As of March 13, 2025, there were 20,497,491 ADRs outstanding, representing 40,994,982 ordinary shares or approximately 1.30% of all Eni’s share capital, held by 105 holders of record (including the Depository Trust Company) in the United States, all of which are U.S. residents. Since a number of ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere.
In Italy, the Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian Stock Exchange. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on EXM and the Euronext MIV Milan (“MIV”) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The FTSE MIB is market cap-weighted after adjusting constituents for free float.
A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana.
Borsa Italiana reports daily market data and news for each listed security, including volume traded and high and low prices. For the purposes of the automatic control of the regularity of trading, the regulations of Borsa Italiana defines certain price variation limits (established in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana and available on its website). Where the price of a contract that is being concluded exceeds one of those limits, trading in that security will be automatically suspended and a reservation phase begun.
158
Consob is the public authority responsible for regulating and supervising the Italian financial markets to, inter alia , ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of Euronext, following the acquisition effective April 29, 2021, is a joint stock company authorized by Consob to operate, among the others, regulated markets in Italy. It is responsible for the organization and management of the Italian Stock Exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of the supervisory tasks (to be performed by Consob and the Bank of Italy) from the tasks relating to market management (to be performed by Borsa Italiana). The main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading as well as the surveillance of the markets.
According to Consob regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for. Such regulated markets are, by way of example, EXM (shares, convertible bonds, pre-emptive rights, warrants), ETFplus (Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes, Structured ETFs and Actively managed ETFs), IDEM (futures and options contracts whose underlying assets are financial instruments, interest rates, foreign currencies, goods or related indexes), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets.
According to the regulatory framework introduced by: (i) Markets in Financial Instruments Directive No. 2014/65/EU as amended from time to time (“ MiFID II ”) and as implemented in Italy, (ii) Regulation (EU) No. 600/2014 (“ MiFIR ”), applicable from January 3, 2018 as amended from time to time, as well as (iii) Consob regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (MTFs) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments — in the system and in accordance with non-discretionary rules — in a way that results in a contract. A Systematic Internaliser is an investment firm which, on an organized, frequent, systematic and substantial basis, deals on own account when executing client orders outside a Regulated Market, an MTF or an Organized Trading Facility (“ OTF ”) without operating a multilateral system. Following the transposition in Italy of MiFID II and the application of MiFIR, OTFs are now included among the “trading venues” that are subject to regulation.
An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract.
According to Italian Legislative Decree No. 58 of February 24, 1998, as amended from time to time (“ Decree No. 58”, the Consolidated Law on Financial Intermediation), the provision of investment services and activities to the public on a professional basis is, inter alia , reserved to investment firms, EU investment companies, Italian banks, EU banks and companies of non-EU countries authorized to operate in Italy (“ Authorized Persons ”). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct. Besides, for the purposes of the application of certain provisions of MiFIR, the Bank of Italy and Consob are the Italian competent authorities. In particular, Consob, as far as the protection of the investors is concerned, is competent for the orderly functioning and soundness of the financial markets or of the commodity markets whereas the Bank of Italy is competent for the stability of the whole (or part of) the financial system.
The Bank of Italy and Consob also regulate the functioning of the clearing and settlement service for transactions involving financial instruments as well as the performance of central securities depository services, in line with the European framework — in particular, Regulation (EU) No. 648/2012 as amended by Regulation EU n. 2019/834, as amended from time to time, (“ EMIR REFIT ”) and the Regulation (EU) No. 909/2014, as amended from time to time, (“ Central Securities Depositories Regulation ”). The regulations and measures of general application adopted by Consob and the Bank of Italy are respectively available on the website of Consob or Bank of Italy.
The regulations adopted by Borsa Italiana are available on its website.
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Item 10. ADDITIONAL INFORMATION
Memorandum and Articles of Association
Company register
“Eni SpA” is the company resulting from the privatization of Ente Nazionale Idrocarburi, a public agency, established by Law No. 136 of February 10, 1953, and it is registered in the Rome Companies Register, with identification number (and tax number) 00484960588, and VAT number 00905811006. The Company’s registered office is in Rome, Italy, and the Company has two offices in San Donato Milanese (Milan).
The full text of Eni’s By-laws is attached as an exhibit to this Annual Report (“Exhibit 1”).
Company objects and purpose
In accordance with Article 4 of Eni’s By-laws, the Company’s purpose includes the direct and/or indirect exercise, through equity holdings in companies or other entities of: activities in the field of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law; activities in the field of chemicals, nuclear fuels, geothermal energy, renewable energy sources and energy in general, including the sale of electricity, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and in the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.
Directors’ issues
Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting. If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members.
The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions. According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance.
The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time.
The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors.
In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote.
For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see “Item 6 — Board of Directors’ duties and responsibilities”.
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Interests in Company’s transactions
As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob (“Commissione Nazionale per le Società e la Borsa” is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the “Consob Regulation”), the Board of Directors — on November 18, 2010 — unanimously approved the internal rules on “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, which has been in effect from January 1, 2011 18 to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. These rules, lastly approved by the Board of Directors on November 16, 2023 19 - mainly in order to adapt them to the principles of the new Eni Regulatory System (assuming the format of a Policy) and to take into account the application experience and from a risk-based perspective - received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The Policy sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required.
Moreover, to ensure compliance with the procedures envisaged by the above mentioned Policy, Directors and Statutory Auditors issue a periodically declaration, upon their appointment and every six months (normally in January and in July provided that at least 3 months have passed since the appointment) and/or when there is any change, in which they state their potential interests related to Eni and its subsidiaries. In any case the Directors and the Statutory Auditors report in good time the single transactions that Eni intends to carry out in which they have an interest. Directors report the interest to the Chief Executive officer (or the Chairman, in the case of interests of the Chief Executive Officer), who will in turn notify the other Directors and the Board of Statutory Auditors. Statutory Auditors report the interest to the other Statutory Auditors and the Chairman of the Eni SpA Board of Directors.
Compensation
Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors with delegated powers in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the Remuneration Committee, after examining the opinion of the Board of Statutory Auditors (for more details about the compensation policy in 2024, see the Remuneration Report 2023 incorporated herein by reference).
Borrowing powers
The power to borrow is included in the Company purpose. Moreover, in accordance with Article 11 of the By-laws, the Company may issue bonds, including convertibles bonds and warrants, in compliance with the law.
Retirement and shareholdings
There are no provisions in the By-laws relating to either retirement based on age-limit requirements and the number of shares required for a Director to qualify.
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18 These internal rules replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The provisions regarding information to be provided to the public, under both the Consob Regulation and the internal rules, have been applied since December 1, 2010. |
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19 The rules have been updated, with reference to the implementation procedures, on March 2025. |
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Company’s shares
In accordance with Article 5 of the By-laws, the Company’s share capital amounts to €4,005,358,876.00, fully paid, and is represented by 3,146,765,114 19 ordinary registered shares without indication of par value as of March 13, 2025. As required by the Italian law on the dematerialization of financial instruments, Eni’s shares (the “Shares”) must be held with “Monte Titoli SpA” (the Italian Central Securities Depository) and their beneficial owners may exercise their rights through special deposit accounts opened with intermediaries, such as banks, brokers and securities dealers. Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the Meeting, by electronic means. Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.
In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors. Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE.
Dividend rights
Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations. Specifically, the ordinary Shareholders’ Meeting called to approve the annual Financial Statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.
Voting rights
The general provisions on share “voting rights” are described at the paragraph “Shareholders’ Meeting” below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see “Item 6”), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 28, 2025, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization), or by the Board of Directors. Each shareholder may, severally or jointly, submit and vote for a single slate only. There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.
Liquidation rights
In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors.
Change in shareholders’ rights
A shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision making quorum established by law for extraordinary meetings.
Shareholders’ Meeting
The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in “ordinary” or “extraordinary” form. The ordinary and the extraordinary Shareholders’ Meetings are normally held after a single call, with the majorities required by law in this case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after more than one call; their resolutions at first, second or third call must be passed with the majorities required by law in each case. Shareholders’ Meetings shall normally be held at the Company’s registered office, unless otherwise decided by the Board of Directors, provided however they are held in Italy.
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19 The Shareholders’ Meeting, held on May 15, 2024, has approved to authorise the Board of Directors with the option of delegation to the Chief Executive Officer and sub-delegation by the same, to cancel up to a maximum of 321,600,000 treasury shares, purchased on the basis of the authorisation of the Shareholders' Meeting, held on the same day, without any impact on the Company’s share capital. The cancellation of 137,725,411 treasury shares made on the basis of the above mentioned authorisation was executed on March 13, 2025. |
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The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by mail (the information is also available on the Company’s website) and, if envisaged, it may include instructions for participating in the Shareholders’ Meeting by means of telecommunication systems, as well as exercising the right to vote by electronic means. The Board of Directors shall make a report on each of the items on the agenda available to the public at the Company’s registered office, on the Company’s website and by other means envisaged by Consob regulations by the same date of the publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements.
The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit and debit records entered on the authorized intermediaries’ accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement, issued by the authorized intermediary, must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the Meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the Meeting; otherwise, the date of each call is deemed the reference date.
Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the Meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collection of proxies shall be made available in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.
The right to vote may also be exercised by mail in accordance with the applicable laws and regulations. If provided for in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules.
The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by applicable laws and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.
The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.
The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his or her opinion on the items on the agenda. The Shareholders' Meetings held on May 11, 2022 has approved an update of such Rules.
During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information.
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In accordance with Article 11 of Law No. 21 of 5 March 2024 , which extended the effectiveness of the measures contained in the Article 106, paragraph 4, second sentence, of Decree Law no. 18 of March 17, 2020, ratified with amendments by Law No. 27 of April 24, 2020 also to the Shareholders’ Meeting to be held by December 31, 2024, the participation in the Shareholders’ Meeting of May 15, 2024 was permitted solely through the Shareholders’ representative designated by the Company pursuant to Article 135-undecies of Consolidated Law on Financial Intermediation. Decree Law No. 202 of December 27, 2024, ratified with amendments by Law No. 15 of February 21, 2025 extended the effectiveness of the above-mentioned measures also to the Shareholders’ Meeting to be held by December 31, 2025.
Stock ownership limitation and voting rights restrictions
Without prejudice to any specific regulations regarding international sanctions, there are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to both residents and non-residents of Italy). In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 3 20 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.
Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban. Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.
Limitation on changes in control of the Company (Special Powers of the Italian State)
Decree Law No. 21 of March 15, 2012 (so called “Golden Power Decree”), ratified with amendments by Law No. 56 of May 11, 2012 (Law No. 56/2012), modified Italian legislation governing the special powers of the Italian State to comply with European rules.
The special powers apply to company assets in the following sectors: defense and national security; broadband electronic telecommunication networks based on 5G technology, cloud-based and other assets relevant to cybersecurity; energy, transport and communications, as defined by the regulations which implement the relevant law.
With reference to the energy sector, the special powers include: a) veto power (or the power of imposing conditions or requirements) over certain transactions or resolutions involving strategic assets (identified by Decrees of the President of the Council of Ministers no. 179 and 180 of 2020) or companies that hold such assets and which give rise to an extra-ordinary situation, not regulated by national and European sector regulations, of a threat of a serious prejudice to public interests relating to the safety and operation of networks and facilities and the continuity of supplies and b) power of attaching conditions or opposing the acquisition by an entity of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets and the acquisition, by an entity outside of the EU, of shareholdings in such company equal to at least 10% and the total value of the investment exceeds one million euros, or the acquisitions result in the 15%, 20%, 25%, 50% thresholds being exceeded, if the purchase entails a threat of a serious prejudice to the essential interests of the State or a danger to security or public order.
Companies that hold strategic assets or carry out activities of strategic importance, or entities that intend to acquire certain shareholdings in such companies, are required to notify the Prime Minister’s Office with a full disclosure of the resolution, act or transaction, or of the acquisition of the shareholdings. The notification obligation extends also to the incorporation of companies that carry out activities of strategic importance or hold strategic assets if one or more shareholders, external to the EU, hold a share of voting rights or capital equal to at least 10%.
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20 This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below. |
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With particular reference to the power referred to in letter b), until the notification and thereafter, up to the expiration of the term for the possible exercise of such power, the voting rights and any other non-financial right related to the significant shareholding may not be exercised.
In the case of non-fulfillment of imposed conditions, throughout the relevant period, the voting rights and any other non- financial right related to the significant shareholding may not be exercised. The resolutions adopted with the decisive vote of such shareholding, or otherwise the resolutions or acts adopted in breach or default of the imposed conditions are void. In addition, unless the fact constitutes a crime, failure to comply with imposed conditions entails for the purchaser a fine.
In case of opposition, the buyer may not exercise the voting rights and any other non-financial right related to the significant shareholding, which must be sold within a year. In case of non-compliance, at the request of the Government, the Court will order the sale of the significant shareholding. Shareholders’ Meeting resolutions adopted with the decisive vote of such participation shall be void.
The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of the EU of stock in a company that holds strategic assets will be allowed on condition of reciprocity, in compliance with international agreements signed by Italy or the EU.
These powers are exercised exclusively on the basis of objective and non-discriminatory criteria.
Finally, Decree-Law No. 104/2023, converted into Law No. 136/2023, amended the Golden Power Decree by providing that the special powers can also be exercised on transactions, resolutions or deeds within a corporate group involving assets covered by intellectual property rights relating to artificial intelligence, machinery for the production of semiconductors, cybersecurity, aerospace, energy storage, quantum and nuclear technologies, food production technologies and concern one or more non-EU parties (subject to verification of the conditions for the exercise of the special powers).
Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.
In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any such provisions.
Shareholder ownership thresholds
There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Financial Intermediation 21 and the Consob Regulation 22 , any direct or indirect holding in the voting shares of an Italian listed company in excess of 3% 23 , 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6% and 90% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds.
Such disclosures shall be made — using the forms contained in Annex 4A to the above Regulation — without delay and, in any case, within four trading days of the transaction, starting from the day on which the subject gains knowledge of the transaction that can lead to the obligation, regardless of the date of execution, or from the date on which the subject obliged to make the disclosure gains knowledge of the event that leads to changes in the share capital as contemplated in the Consob Regulation.
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21 Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122. |
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22 Article 117 of Consob Decision No. 11971/1999 and subsequent amendments. |
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23 If the company is not a SME (small or medium enterprise). Moreover, Consob may, by means of measures justified by the need to protect investors, as well as corporate control market and capital market efficiency and transparency, envisage — for a limited period of time — lower thresholds by its decree for companies with particularly extensive shareholding structure. |
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For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria 24 . The obligation to notify also applies to any direct or indirect holding owned through ADRs.
Specific disclosure requirements (with partially different thresholds) are connected to investments in financial instruments and for aggregate investments 25 .
Under the above mentioned Consolidated Law on Financial Intermediation, as amended by Decree Law No. 148/2017, in the case of the purchase of a stake in listed issuers equal or above the thresholds of 10%, 20% and 25% of the relevant share capital in listed companies, the investor shall state the objectives it intends to pursue in the following six months 26 . The declaration shall state under the responsibility of the declarant: a) the means of financing the acquisition; b) whether acting alone or in concert; c) whether it intends to stop or continue its purchases, and whether it intends to acquire control of the issuer or anyway have an influence on the management of the company and, in such cases, the strategy it intends to adopt and the transactions to be carried out; d) its intentions as to any agreements and shareholders’ agreements to which it is party; e) whether it intends to propose the integration or revocation of the issuer’s administrative or control bodies. Consob can identify, with its own regulation, the cases where the aforementioned declaration is not due, taking into account the characteristics of the entity making the declaration or of the company whose shares have been purchased.
The declaration shall be transmitted to the company whose shares have been purchased and to Consob and shall be subject to public disclosure in accordance with the terms and conditions established by Consob Regulation.
Voting rights attached to listed shares which have not been notified pursuant to the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in court, under the Italian Civil Code.
According to the Italian Civil Code (Article 2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed one-fifth of the capital of the parent company — if the latter is a listed company — taking into account for this purpose the shares held by the same parent company or its subsidiaries.
The Consolidated Law on Financial Intermediation provides rules governing cross-holdings. In particular, except for the cases contemplated by the above mentioned Article 2359-bis of the Italian Civil Code, in case of a reciprocal participation exceeding the limit of 3% of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.
The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-quater.1 of the Consolidated Law on Financial Intermediation) if the threshold is exceeded by both companies subsequent to an agreement authorized in advance by the ordinary shareholders’ meetings of the companies concerned.
If a person holds an interest exceeding the aforementioned threshold of a listed company, such listed company or any person controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended. Where it is not possible to ascertain which of the two persons was the last to exceed the limit, the suspension shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.
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24 Article 118 of Consob Decision No. 11971/1999 and subsequent amendments. |
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25 Article 119 of Consob Decision No. 11971/1999 and subsequent amendments. |
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26 Consob may, with a provision reasoned by investor protection needs as well as efficiency and transparency of the corporate control market and of the capital market, introduce, for a limited period of time, in addition to the thresholds above indicated, a threshold of 5 percent for companies with a particularly widespread shareholder base. |
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The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company.
Under the Consolidated Law on Financial Intermediation, any agreement, in any form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed with the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights attached to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares may be challenged under the Italian Civil Code.
The same provisions also apply to agreements, in any form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe them; (c) provide for the purchase of the shares or of the above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis) which aim to encourage or frustrate a takeover bid or an exchange tender offer, including commitments relating to non-participation in a takeover bid.
Finally, pursuant to Law No. 287 of October 10, 1990, any merger or acquisition of (legal or factual) sole or joint control over a company or any change of control over a company is subject to the prior authorization by the Italian Antitrust Authority 27 if the companies involved exceed given turnover thresholds. If the said merger, acquisition or change of control were to significantly affect competition, in particular because they create or strengthen a dominant position, the Italian Antitrust Authority can either prohibit the transaction or make it subject to remedies preventing a restriction of competition. Moreover, if the transaction or the companies involved exceed other quantitative or qualitative thresholds set by European or other jurisdictions’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value, market shares of the parties or the potential competitiveness of the target), the transaction can also be subject to the prior authorization by competition authorities of such other jurisdictions. Finally, pursuant to new rules enacted in 2022, in some circumstances both the Italian Antitrust Authority and the European Commission might require that specific mergers, acquisitions or changes of control be made subject to their approval, even if they are below said thresholds.
Changes in share capital
Eni’s By-laws do not provide for more stringent conditions than those required by law. Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.
None.
Under current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by an Italian resident to a non-resident.
The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.
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27 Autorità garante della concorrenza e del mercato (AGCM). |
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Italian taxation
The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.
Income tax
Dividends regarding income of financial years 2023 onwards, received by Italian resident individuals holding the shares or ADRs otherwise than in connection with entrepreneurial activity, are subject to a substitute tax of 26% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return.
Subject to certain limitations and requirements (including a minimum holding period), dividends received by Italian resident individuals holding the shares not in connection with an entrepreneurial activity or social security entities pursuant to Legislative Decree No. 509 of June 30, 1994 and Legislative Decree No. 103 of February 10, 1996 may be exempt from taxation if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.
Dividends received by Italian investment funds and società di investimento a capitale variabile (“SICAV”) are not subject to substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares.
Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units.
Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute tax. Subject to certain limitations and requirements (including a minimum holding period), shares received by Italian resident pension funds may be excluded from the taxable base of the substitute tax, if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.
Dividends paid to non-Italian residents are subject to substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment.
The above-mentioned 26% substitute tax will not be applied in the event of dividends distributed in favor of foreign undertakings for collective investment which comply with European Directive 2009/65/EC of the European Parliament and of the Council of July 13, 2009 (UCITS Directive), and to undertakings for collective investment which do not comply with the aforesaid Directive 2009/65/EC, whose manager is subject to regulatory supervision in the foreign country in which it is established in accordance with European Directive 2011/61/EU of the European Parliament and of the Council of June 8, 2011 (AIFM Directive), established in an EU Member States or a European Economic Area (“EEA”) State included in the list of States and territories allowing an adequate exchange of information with the Italian tax authorities according to the Ministerial Decree of September 4, 1996 (“White List”).
Dividends are subject to a 1.20% substitute tax introduced by the Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to non-Italian companies and entities that are (i) resident in an EU Member State or EEA State included in the White List, and (ii) subject to a corporate income tax in their country of residence.
The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income Tax Treaties with approximately 100 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.
In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes.
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Under the Tax Treaty between the United States and Italy (the “Italy U.S. Tax Treaty”), dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s voting stock are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed base in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the “IRS”) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.
Where the Beneficial Owner has not provided the above-mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.
As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (“ADSs”), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary.
The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith.
Capital gains tax
This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy. Profits gained by Italian resident individuals, not in connection with entrepreneurial activity, in financial year 2025, are subject to substitute tax for 26%. Two different systems may be applied at the option of the shareholder as an alternative to the so-called “tax return regime” (regime della dichiarazione – it is the default regime for taxation of capital gains, according to which capital gains are reported in the taxpayer's tax return and paid within the deadline for the payment of the balance income taxes due on the basis of the relevant tax return):
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the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and |
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the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 26% substitute tax to be applied by the portfolio.
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Subject to certain limitations and requirements (including a minimum holding period), gains realized upon sale, transfer or redemption by Italian resident individuals holding the shares not in connection with an entrepreneurial activity or social security entities pursuant to Legislative Decree No. 509 of June 30, 1994 and Legislative Decree No. 103 of February 10, 1996 may be exempt from taxation, if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.
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Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax. On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to tax on capital gains.
Any gains realized by a holder of the shares who is an Italian pension fund (subject to the regime provided for by article 17 of the Italian Legislative Decree No. 252) will be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a to a 20% annual substitute tax. Subject to certain limitations and requirements (including a minimum holding period), capital gains realized by Italian pension funds may be excluded from the taxable base of the substitute tax, if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.
Gains realized by undertakings for collective investment which comply with European Directive 2009/65/EC of the European Parliament and of the Council of July, 13, 2009 (UCITS Directive), and by undertakings for collective investment, established in an EU Member States or a EEA State included in the White List, which do not comply with the aforesaid Directive 2009/65/EC, whose manager is subject to regulatory supervision in the foreign country in which it is established in accordance with European Directive 2011/61/EU of the European Parliament and of the Council of June 8, 2011 (AIFM Directive), will not be applied.
However, double taxation treaties may eliminate the capital gains tax. Under the Italy U.S. Tax Treaty, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned-conditions of non taxability pursuant to the Italy U.S. Tax Treaty have been satisfied.
Financial Transactions Tax
Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable is 0.10% for ADR negotiated in regulated markets (like the NYSE).
Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law.
Inheritance and gift tax
Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:
(a) 4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary);
(b) 6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding €100,000 (per beneficiary);
(c) 6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity, as well as to persons related by collateral affinity up to the third degree; and
(d) 8 per cent: in all other cases.
If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.
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United States taxation
The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not discuss all material tax consequences of the ownership of Shares or ADSs, including tax consequences arising under the Medicare contribution tax on net investment income or the alternative minimum tax. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to- market, certain insurance companies, broker-dealers, investors that actually or constructively own 10% or more of the combined voting power of Eni SpA’s voting stock or of the total value of Eni SpA’s stock, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar.
This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof and the Italy U.S. Tax Treaty. These authorities are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.
If an entity or arrangement that is treated as a partnership for U.S. federal income tax purposes holds Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs.
As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is:
(i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.
The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the Italy U.S. Tax Treaty with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax.
Distributions
Subject to the passive foreign investment company (“PFIC”) rules discussed below, distributions paid on the Shares or ADSs will generally be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends- received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities.
For non-corporate U.S. Holders, dividends that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by Eni SpA that are received with respect to the ADSs will generally be qualified dividend income if the ADSs are readily tradable on an established securities market in the United States. Eni SpA’s ADSs are listed on the New York Stock Exchange and Eni SpA therefore expects that dividends with respect to the ADSs will be qualified dividend income. Dividends paid by Eni SpA with respect to the Shares will generally be qualified dividend income provided that, in the year that you receive the dividend, Eni SpA is eligible for the benefits of the Italy U.S. Tax Treaty. Eni SpA believes that it is currently eligible for the benefits of the Italy U.S. Tax Treaty and Eni SpA therefore expects that dividends on the Shares will also be qualified dividend income, but there can be no assurance that Eni SpA will continue to be eligible for the benefits of the Italy U.S. Tax Treaty.
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The amount of the dividend distribution that must be included in the income of a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot EUR/USD rate on the date the dividend is distributed, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend is distributed to the date the U.S. Holder converts the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.
Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a reduction or refund of the tax withheld is available to a U.S. Holder under Italian law or under the Italy U.S. Tax Treaty, the amount of tax withheld that could have been reduced or that is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See “Italian taxation — Income tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the Shares or ADSs will generally be income from sources outside the United States and will, generally be “passive” income for purposes of computing the foreign tax credit allowable to you. However, if (a) Eni SpA is 50% or more owned, by vote or value, by United States persons and (b) at least 10% of Eni SpA’s earnings and profits are attributable to sources within the United States, then for foreign tax credit purposes, a portion of Eni SpA’s dividends would be treated as derived from sources within the United States. With respect to any dividend paid for any taxable year, the United States source ratio of Eni SpA’s dividends for foreign tax credit purposes would be equal to the portion of Eni SpA’s earnings and profits from sources within the United States for such taxable year, divided by the total amount of our earnings and profits for such taxable year. Eni SpA does not expect to be 50% or more owned, by vote or value, by United States persons, and therefore does not expect that any portion of Eni SpA’s dividends will be treated as derived from sources within the United States.
Sale or exchange of Shares
Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency, its U.S. dollar equivalent). The amount realized will generally be reduced by any Italian Financial Transaction Tax paid in respect of such transfer, and a U.S. Holder will not be entitled to claim a foreign tax credit in respect of the payment of the Italian Financial Transaction Tax. Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non-corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.
PFIC rules
Eni SpA believes that Shares and ADSs should not currently be treated as stock of a PFIC for U.S. federal income tax purposes and Eni SpA does not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, the U.S. Holder would be treated as having realized such gains and certain “excess distributions” ratably over the holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, a U.S. Holder’s Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during the period the Shares or ADSs were held. Dividends received from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to the U.S. Holders either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.
Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company’s website. The Company is subject to the information requirements of the Security Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Eni files its Annual Report on Form 20-F and other related documents with the U.S. SEC. It’s possible to read and copy documents that have been filed with the U.S. via commercial document retrieval services, and from the SEC website ( www.sec.gov ).
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Item 11. Q U ANTI TA TIVE AND Q U ALI TA TIVE DISC L OSURES ABOUT MARKET RISK
Market risk is the possibility that the exposure to fluctuations in commodity prices, currency exchange rates, interest rates or other market benchmarks will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.
The impact of changes in crude oil prices on the Company’s refining and marketing and petrochemical businesses depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.
As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives or in case of extraordinary market conditions.
The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and its subsidiarie Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trade & Biofuels SpA and Eni Global Energy Markets (from January 1, 2021, together formerly Eni Trading & Shipping) that are in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA manage the Group subsidiaries’ financing requirements covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies are managed by the parent company. With respect to the commodity risk, Eni Trade & Biofuels and Eni Global Energy Markets centralize the negotiation of financial instruments on the markets.
In 2021, the above mentioned centralized model for the execution of financial instruments has been updated in light of the relevant changes in the main financial regulations (Mifid II/EMIR/Dodd Frank act). Eni’s activities comply with the regulatory requirements for the execution of financial instruments on European and non-European Regulated Markets, on Multilateral Trading Facilities, on Organized Trading Facilities or bilaterally with OTC counterparties.
In addition to the reinforcement of the centralized execution model, as required by the financial regulation, all derivative transactions are classified and segregated in accordance with the EMIR requirements of “risk reducing” and “non-risk reducing” derivative contracts. The Company’s activities in financial instruments were thus classified in order to clearly: a) segregate ex ante non-risk reducing activities; b) define before inception the types of derivative contracts included in the hedging portfolios and the eligibility criteria, and stating that the derivative transactions included in the hedging portfolios are limited to covering risks directly related to commercial or treasury financing activities; and c) provide for a sufficiently disaggregated view of the hedging portfolios in terms of for example asset classes, products and time horizons, in order to establish the direct link between the portfolio of hedging transactions and the risks that this portfolio seeks to hedge. A financial instrument can be qualified as risk reducing when, by itself or in combination with other derivative contracts (so-called macro or portfolio hedging) it:
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directly or through closely correlated instruments (so-called proxy hedging) covers the risks arising from potential changes in the value of different assets under Eni control or that Eni will have under its control in the normal course of business driven by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk; or |
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qualifies as a hedge pursuant to IFRS. |
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Use of financial instruments (in euro or currencies different from euro) is allowed with the following risk reducing purposes:
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Back-to-back : includes market risk-free instruments that are negotiated in accordance with an execution criteria and normally settled with an intermediation fee. They normally comply with hedge accounting requirements or own use exemption. These are transaction-based activities characterized by a substantial absence of market risk. A hedging instrument can be considered back to back when the financial derivative is structured as to match as much as possible asset class, size and maturity of the hedged position. As a result, the combination of the hedged item, normally a single asset/contract, and the hedging instrument, i.e. the financial derivative, is substantially market risk free or is exposed only to a basic risk related to the ineffective portion of the hedging item. In addition, the hedging item may entail counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes. |
|
• |
Flow hedging : flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, according to a portfolio basis. A central department processes a continuous flow of orders from the Group’s various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity on the received orders, which are normally related to assets managed by the business units. The central broker entity can normally rely on a continuous flow of hedging orders that can be predictable to a large extent, on the basis of the regular hedging programs made by the Group’s business units. The central entity is therefore in the position to net opposite orders, by retaining the level of risk necessary to cover timing, volume and asset class mismatch among orders. The benefits are the maximization of integration across the whole of the Group assets portfolio and the related netting potential, avoiding unnecessary derivatives, thus reducing costs and aggregated notional amounts of hedging programs. Flow hedging is managed on a portfolio basis and is dynamic by nature, since resulting net position is normally adjusted in order to take into account new orders received and maximum allowed exposure, related to timing, volume and asset classes mismatch. Those derivatives are recorded in profit and loss as the hedging of net exposures does not qualify as hedges under IFRS. |
|
• |
Asset-backed hedging : is a portfolio-based activity performed to enhance assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated with assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible the asset, the higher its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. To enhance the value of asset flexibility, a business unit may transfer to a central entity part or the whole of an asset flexibility or a portfolio of flexibilities and the central entity will hedge such flexibility on financial markets so to lock its value by monetizing it via derivatives. Hedging strategies adopted for asset-backed hedging are normally portfolio based, very dynamic and entail large use of proxies. Depending on the optimization model such strategies are continuously adjusting relevant hedging ratios buying and selling the same financial products several times, since the underlying asset flexibility to be hedged is changing depending on price level, price volatility, time to delivery, etc. These derivatives may lead to gains as well as losses which in each case may be significant and are accounted through profit and loss as they lack the hedge requirements provided by IFRS. However, we believe that the risks associated with those derivatives are mitigated by the natural hedge granted by the asset availability. |
|
• |
Portfolio management : is a portfolio based activity performed on a combination of underlying positions, such as physical assets (production plants, transmission infrastructures, storages, etc.), commercial assets (spot and forward short/medium/long term supply and sale contracts with physical delivery) and related financial derivatives. Normally, the target of a portfolio management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, price scenarios and logistic flexibility/constraints, determine the optimal configuration in terms of volume, price and flexibility for physical and commercial assets in the portfolio. Financial derivatives are then used in the portfolio management activity in order to manage the overall risk level associated with such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the portfolio in line with the Company’s targets. Market risk associated with portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence, financial derivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several times in a given time frame. These derivatives may lead to gains, as well as losses which in each case may be significant and are accounted through profit as they lack the hedge requirements provided by IFRS. |
Pursuant to internal policy, all derivatives transactions concerning interest rates and foreign currencies are executed for risk reducing purposes, as described above. Only commodity derivatives can also be executed in the context of non-risk reducing operations and be consequently classified as Proprietary Trading, which is an ancillary activity not related to industrial assets that makes use of financial derivatives which are entered into with the objective to obtain an uncertain profit, if favorable market expectations occur.
174
Eni monitors on a daily basis that every activity involving derivatives is correctly classified according to the risk reducing taxonomy (i.e. back to back, flow hedging, asset-backed hedging or portfolio management), is directly or indirectly related to the hedged industrial assets and effectively optimizes the risk profile to which Eni is, or could be, exposed. When some derivatives fail to prove their risk reducing purpose, they are reclassified as Proprietary Trading. Provided that Proprietary Trading is segregated ex ante from other activities, its resulting market risk exposure is subject to specific limits expressed in terms of Stop Loss, VaR and notional amounts. The aggregated notional amounts of non-risk reducing derivatives at Group/Entity level are constantly benchmarked with the thresholds required by relevant international financial regulations.
Please refer to “Item 18 — Note 28 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks.
Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Not a pplica b le.
Not a pplica b le.
Not a pplica b le.
Item 12D. American Depositary Shares
In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary share s.
Pursuant to the Deposit Agreement dated June 27, 2017 (the “Deposit Agreement”) between Eni, Citibank N.A. and the holders and beneficial owners ADSs, Citibank N.A. serves as the Depositary for Eni’s ADR Program, and Citibank N.A. Milan Branch serves as Custodian.
Computershare is the transfer agent for the Eni’s ADR Program.
Fees and charges payable by ADR holders
Pursuant to the Deposit Agreement, ADR holders may be required to pay various fees to the Depositary, and the Depositary may refuse to provide any service for which a fee is assessed until the applicable fee has been paid.
175
The f ollo wing ADS fees ar e pa y ab le under the terms of the Deposit Agreement:
|
|
Service |
|
Rate |
|
By Whom Paid |
|
(1) |
Issuance of ADSs (e.g., an issuance upon a deposit of Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason), excluding issuances as a result of distributions described in paragraph (4) below. |
|
Up to U.S. $5.00 per 100 ADSs (or fraction thereof) issued. |
|
Person receiving ADSs. |
|
(2) |
Cancellation of ADSs (e.g., a cancellation of ADSs for delivery of deposited Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason). |
|
Up to U.S. $5.00 per 100 ADSs (or fraction thereof) cancelled. |
|
Person whose ADSs are being cancelled. |
|
(3) |
Distribution of cash dividends or other cash distributions (e.g., upon a sale of rights and other entitlements). |
|
Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. |
|
Person to whom the distribution is made. |
|
(4) |
Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) an exercise of rights to purchase additional ADSs. |
|
Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. |
|
Person to whom the distribution is made. |
|
(5) |
Distribution of securities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares). |
|
Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. |
|
Person to whom the distribution is made. |
|
(6) |
ADS Services. |
|
Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary. |
|
Person holding ADSs on the applicable record date(s) established by the Depositary. |
Direct and indirect payments b y the Depositary
The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the Program and the listing of Eni’s ADSs on the NYSE. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.
For the year 2024, the Depositary reimbursed to Eni $ 2,925,270.08 in connection with the above mentioned expenditures.
The Depositary has a lso a g r eed to w a ive certain standard fees associated with the administration of the ADR Pro g ram.
176
P ART II
Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
None.
Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
None.
Item 15. CONTROLS AND PROCEDURES
Dis c losu r e cont r ols and p r ocedu r es
In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), the Company’s management, including the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department in his capacity as Officer in Charge of the Preparation of Corporate Accounts (“Dirigente Preposto alla redazione dei documenti contabili societari” pursuant to the Italian Consolidated Financial Law — Legislative Decree No. 58 of February 24, 1998), recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.
It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries.
The Company’s management, with the participation of the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department, has evaluated the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Rule 13a-14(c) under the Exchange Act as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department have concluded that these disclosure controls and procedures are effective.
Mana g ement ’ s Annual R epo r t on Internal Cont r ol o v er Financial R epo r ting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.
Management has excluded 53 entities from its assessment of internal control over financial reporting as of December 31, 2024 because they were acquired by the Company in several purchase business combinations during 2024. These entities, which are wholly-owned, comprised, in the aggregate, total assets and total revenues excluded from management's assessment of internal control over financial reporting of approximately 2% of consolidated total assets and less than 1% of consolidated total revenues as of and for the year ended December 31, 2024.
The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition, this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system.
The Company’s management, including the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (CoSO) in 2013. Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2024.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2024, has been audited by PricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on page F-1 of this Annual Report on Form 20-F.
177
Chan g es in Internal Cont r ol o v er Financial R epo r ting
There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 16A. Boa r d of Statutory A uditors f inancial e xpert
Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: Rosalba Casiraghi, who is the Chairman of the Board, Enrico Maria Bignami, Marcella Caradonna, Giulio Palazzo and Andrea Parolini. All members are independent.
Eni adopted a Code of Ethics that applies to all Eni’s employees, including Executive Officers, principal Financial and Accounting Officers, Directors and Statutory Auditors. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F. Information on our website is not incorporated by reference into this report.
Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model.
Item 16 C . Principal accountant fees and services
PricewaterhouseCoopers SpA (PwC SpA) served as Eni’s principal independent registered public accounting firm for fiscal year 2024, for which audited Consolidated Financial Statements have been included in this Annual Report on Form 20-F. PwC SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements.
The following table reports total fees for services rendered to Eni by PwC SpA and member firms of its network for the years ended December 31, 2024 and 2023.
|
|
Year ended December 31, |
|
|||
|
|
2024 |
|
|
2023 |
|
|
|
(€ thousand) |
|
|||
|
Audit fees |
30,098 |
|
|
26,562 |
|
|
Audit-related fees (a) |
1,739 |
|
|
3,000 |
|
|
Tax fees |
- |
|
|
- |
|
|
All other fees |
- |
|
|
- |
|
|
Total |
31,837 |
|
|
29,562 |
|
|
(a) |
Audit related services provided by PwC SpA mainly relate to services for the issue of comfort letters, services related to the report prepared by Eni SpA on payments to governments and checks on cost recharges/rates, agreed verification procedures, and tariff certifications. |
Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting.
Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include, merger and acquisition due diligence, audit, certification services not required for by law and regulations and consultations concerning financial accounting and reporting standards.
Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning.
178
All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.
P r e-app r o v al policies and p r ocedu r es of the Internal Cont r ol Committee
The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities controlled (directly or indirectly) by Eni SpA as well as to jointly controlled entities that are material to the Eni Group. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors.
During 2023, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (C) of Rule 2-01 of Regulation S-X.
Item 16 D . E x emptions f r om the Listing Standa r ds f or A udit Committees
Making use of the exemption provided by Rule 10A-3(c)(3) for foreign private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, performs the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act to be carried out by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 — Board of Statutory Auditors” above).
Item 16E. Pu r chases of equity securities by the issuer and af f iliated pu r chasers
Eni’s Board of Directors, in execution of the authorization granted by the Eni Shareholders’ Meeting of May 15, 2024 directed the management to carry out a share buy-back program of the Eni's common shares of up to €3.5 billion, repurchasing no more than 328 million of shares. As a part of the Board mandate, the management resolved to repurchase €2 billion worth of Eni’s shares. The purchases started on May 27, 2024 and ended on February 20, 2025 for a total amount of €2 billion.
#
|
Period |
|
Total number of shares purchased |
|
Average weighted price paid per share |
|
Total number of shares purchased as part of publicly announced plans or programs |
|
Total purchase cost |
|
Approximate € value of Shares that may yet be purchased under the plans or programs |
|
|
|
|
|
€ per share |
|
|
|
(€ million) |
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
|
|
|
2024 |
|
|
|
|
|
|
|
|
|
|
|
1 January - 31 January…........................................................ |
|
14,686,415 |
|
15.06 |
|
14,686,415 |
|
221 |
|
142 |
|
1 February - 29 February….................................................... |
|
8,739,490 |
|
14.39 |
|
8,739,490 |
|
126 |
|
16 |
|
1 March - 5 March…............................................................. |
|
1,127,199 |
|
14.35 |
|
1,127,199 |
|
16 |
|
0 |
|
Total as of March 5, 2024 (a) …........................................... |
|
24,553,104 |
|
14.60 |
|
24,553,104 |
|
363 |
|
|
|
Start of the program May 27 - May 31,2024 ….................... |
|
3,442,000 |
|
14.48 |
|
3,442,000 |
|
50 |
|
1,950 |
|
1 June - 28 June…………...................................................... |
|
9,521,500 |
|
14.06 |
|
9,521,500 |
|
134 |
|
1,816 |
|
1 July - 31 July…................................................................... |
|
13,057,219 |
|
14.35 |
|
13,057,219 |
|
187 |
|
1,629 |
|
1 August - 30 August….......................................................... |
|
16,721,060 |
|
14.44 |
|
16,721,060 |
|
242 |
|
1,387 |
|
2 September - 30 September………........................................ |
|
10,018,423 |
|
14.08 |
|
10,018,423 |
|
141 |
|
1,246 |
|
1 October - 31 October…....................................................... |
|
17,496,817 |
|
14.19 |
|
17,496,817 |
|
248 |
|
998 |
|
1 November - 29 November…................................................ |
|
14,463,765 |
|
13.83 |
|
14,463,765 |
|
200 |
|
798 |
|
2 December - 30 December….................................................. |
|
33,206,856 |
|
13.17 |
|
33,206,856 |
|
437 |
|
361 |
|
2025 |
|
|
|
|
|
|
|
|
|
|
|
2 January - 31 January…........................................................ |
|
16,089,680 |
|
13.67 |
|
16,089,680 |
|
220 |
|
141 |
|
3 February - 20 February….................................................... |
|
10,108,091 |
|
13.91 |
|
10,108,091 |
|
141 |
|
0 |
|
Total as of February 20, 2025 …............................................... |
|
144,125,411 |
|
13.88 |
|
144,125,411 |
|
2,000 |
|
|
|
(a) This share buy-back program was authorized by Eni's Shareholders’ Meeting of May 10, 2023 for up to €3.5 billion. As a part of this €2.2 billion worth of shares were purchased starting on May 12, 2023 and ended on March 5, 2024. |
The management will request the Annual Shareholders' Meeting convened in May 2025 to grant authorization to execute a new buy-back program.
Item 16 F . Change in R egist r ant ’ s Certifying Accountant
Not Applicable
Corporate Governance . Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities. The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code approved by the Italian Corporate Governance Committee in January 2020 effective from January 1, 2021, which Eni has adopted on December 23, 2020 (the “Code”).
179
Independent Directors
NYSE standards . In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a Director’s independence.
Eni standards . In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of judgment.
Eni’s By-laws require that at least one Director — if the Board has no more than five members — or at least three Directors — if the Board is composed of more than five members — must satisfy the independence requirements. The Corporate Governance Code provides for additional independence requirements, recommending that a significant number of non-executive directors is independent. In particular, in large companies other than those with concentrated ownership, like Eni, independent directors should account for at least half of the board. Independence is defined as not having currently or recently entered into, nor recently had, even indirectly, relations with the company or with subjects related to the latter, such as to condition their current autonomy of judgment. The Corporate Governance Code identifies the circumstances that jeopardise, or appear to jeopardise, the independence of a director. Immediately after the appointment of a Director who qualifies as independent and subsequently, upon the occurrence of circumstances that concern the independence and in any case at least once a year, the Board of Directors assesses the independence of the Director. The Board of Statutory Auditors verifies the correct application of the criteria and procedures adopted by the Board of Directors to evaluate the independence of its members. The Board of Directors shall disclose to the market the outcome of its assessment, immediately after the appointment, through a specific press release and, later, in the Annual Corporate Governance Report. In accordance with Eni’s By-laws, if a Director, who qualifies as independent, does not or no longer satisfies the independence requirements established by law, the Board declares the Director disqualified and provides for their substitution. Directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise.
Meetings of non- ex ecut i v e Di r ectors
NYSE standards . Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors. In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year.
Eni standards . Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year in the absence of the other Directors.
On May 11, 2023, the Board of Directors of Eni confirmed Raphael Louis L. Vermeir Lead Independent Director. Pursuant to Italian Corporate Governance Code, the Lead Independent Director collects and coordinates the requests and contributions of non-executive directors and, in particular, of independent ones and coordinates the meetings of the independent directors.
During 2024, the independent Directors, coordinated by the Lead Independent Director, met on November 13 and, taking into account the frequency of board meetings, had further informal meeting opportunities on these occasions to exchange views, pursuant to the Corporate Governance Code recommendations.
A udit Committee
N Y SE standa r ds . Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.
180
Eni standa r ds . At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of SEC applicable to foreign issuers listed on regulated U.S. markets, assigned to the Board of Statutory Auditors, effective from June 1, 2005 and within the limits set by Italian law, the functions specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the SEC rules (see “Item 6 — Board of Statutory Auditors” earlier). Under Section 303A.07 of the NYSE Listed Company Manual, audit committees of U.S. companies have additional functions and duties which are not mandatory for non-U.S. private issuers and which are therefore not included in the list of functions reported in “Item 6 — Board of Statutory Auditors”.
Nominating/Corpo r ate G o v e r nance Committee
NYSE standards . U.S. listed companies must have a Nominating/Corporate Governance Committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers.
Eni standards . Pursuant to the Code, the Board of Directors shall establish among its members a nomination committee the majority of whose members shall be independent Directors. The Nomination Committee of Eni is made up of three to four Directors, a majority of whom shall be independent in accordance with the recommendations of the Code. On May 11, 2023, the Board of Directors of Eni established the Nomination Committee, chaired by Carolyn Adele Dittmeier (independent Director) and composed of Elisa Baroncini (independent Director) and Massimo Belcredi (independent Director).
Further details on this Committee are reported in the Item 6.
R emune r ation Committee
NYSE standards . U.S. listed companies must have a Remuneration Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The Remuneration Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The Remuneration Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers.
Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a Remuneration Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have an adequate knowledge and experience in financial matters or remuneration policies. First established by the Board of Directors in 1996, the Remuneration Committee is currently chaired by Director Massimo Belcredi (independent Director). The other members include Directors Cristina Sgubin, and Raphael Louis L. Vermeir, both independent Directors. Two out of three directors possess knowledge and experience in financial matters or remuneration policies. The composition and functions of the Remuneration Committee are outlined in the committee charter (“Rules”) available on the Company’s website.
Further details on this Committee are reported in the Item 6.
Code of Business Conduct and Ethics
NYSE standards . The NYSE listing standards require each U.S. listed company to adopt a Code of Business Conduct and Ethics for its Directors, Officers and employees, and to promptly disclose any waivers of the code for Directors or Executive Officers.
Eni standards . The Board of Directors of Eni, at its meetings of December 15, 2003 and January 28, 2004, approved an organizational, management and control model pursuant to Italian Legislative Decree No.231 of 2001 (hereinafter “Model 231”) and established the associated 231 Supervisory Body of Eni SpA, with the role of supervising the effectiveness of Model 231 and of assessing its suitability to prevent crimes provided in the Italian Legislative Decree No. 231 of 2001.
The Model 231 was most recently updated by resolution of the Board of Directors, in the meeting of November 18, 2021, taking into account the experience gained, amendments to Legislative Decree no. 231/2001, and the corporate organizational changes of Eni SpA.
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The autonomy and independence of the 231 Supervisory Body are guaranteed by the position recognized to it within the organizational structure of the Company, and by the requisites of independence, good standing and professionalism of its members.
Furthermore, the Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics, that has been updated to become a modern and effective Charter of Values, designed to inspire and guide the conduct of all members of the administrative and control bodies and employees of Eni and its stakeholders.
Eni’s Code of Ethics sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All Eni personnel, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties.
Item 16H. Mine safety disclosu r e
Not applicable since Eni does not engage in mining operations.
Item 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
Item 16J. Insider trading policies
Eni has adopted insider trading policies and procedures, governing the purchase, sale, and other dispositions of the Company’s securities by directors, senior management and employees, that are reasonably designed to promote compliance with applicable insider trading laws, rules and regulations, and any listing standards applicable to the Company.
The Management System Guideline “Market Information Abuse (Issuers)”, together with Annex C “Managers’ transactions and Blocking Periods” are filed as exhibit.
The Company is aware that the oil&gas sector is particularly vulnerable to cybersecurity risks because of the geographical reach of operations, the complexity of integrating IT infrastructures with industrial control systems, and exposure to geopolitical risks.
In this context, Eni’s has adopted a set of processes and systems for assessing, identifying and managing the significant risks related to cybersecurity threats with the goal of minimizing the impacts of any potential cybersecurity incidents and avoid as far as possible any disruptions to the Company’s information systems, information resources, data infrastructures and ultimately to its business operations given that information systems are core to our industrial activities, financial transactions and correct and complete record, storage and use of data regarding acquisition and disposition of Company’s assets, and customers and other third parties data.
Eni’s cybersecurity program includes multi-layered technological capabilities designed to prevent and detect cybersecurity disruptions and is based on industry standard frameworks. The cybersecurity program incorporates an incident response plan to engage cross-functionally across the Corporation and report cybersecurity incidents to appropriate levels of management, including senior management, and the Audit Committee or the Board of Directors, based on potential impact. The Group conducts annual cybersecurity awareness training and routinely tests cybersecurity awareness and business preparedness for response and recovery, which are developed based on real-world threats.
In recent years the business environment has been characterized by a significant rise in the cybersecurity risks, both in terms of frequency of incidents and their relevance, driven by increased operation complexity and geopolitical factors. Eni has established and is maintaining a risk-assessment program specifically designated to identify and to manage cybersecurity risks and based on the outcome of this review has adopted a suite of mitigation measures and protocols. We believe that thanks to those remedies our overall exposure to the cybersecurity risks has remained stable as the Company has been able to counteract an increased number of attacks against the Company’s information systems, which have arisen in connection with the adoption of the hybrid working environment (for example remote working) and a changed environment for cyber threats in connection with a deteriorated geopolitical landscape.
The internal control system has been designed taking into consideration primarily the characteristics of the Eni business, the Company’s long-term strategy, its countries of operations, the specific risks the oil&gas sector is exposed to (see Item 3 - Risk Factors for more information), among which the cybersecurity risk ranks highly.
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Looking forward the Company believes that cybersecurity threats in the following areas may materially affect the Company’s business strategy, reputation, results of operations and financial conditions:
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Disruptions to industrial processes which may lead to loss of revenues and unplanned and restoring expenses; |
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Interruption in the IT systems used by the businesses and corporate and finance departments which may lead to a temporarily inability to record physical data and dispositions of Company’s products, to send invoices, to collect receipts which may results in disruptions, loss of revenues and cash collections and higher finance expenses impacting the profit&loss and the financial condition; |
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Breaches, violations, and subtraction of retail customer data which may negatively affect the Company’s reputation and may lead to violations of laws on data protection and claims against us. |
Considering the possible risks of cybersecurity incidents, the Group has adopted several mitigation measures of the cybersecurity risks, which include the continuous upgrading of the IT infrastructure, availability of services to protect the Company against cybersecurity threats, extension of those measures to the cloud, also integrating technologies based on AI, strengthening procedures and resources of technological security and governance at the headquarter, foreign subsidiaries and industrial hubs by means of deploying tailored programs of technological enforcement.
Centralized information systems have been upgraded to improve monitoring and specific controls and procedures have been adopted intended to identify, mitigate, and supervise cyber risks that could be brought in by third parties performing activities on behalf of Eni, including supplier of cloud services. The Group takes a risk-based approach with respect to its third-party service providers, tailoring processes according to the nature and sensitivity of the data or systems accessed by such third-party service providers and performing additional risk screenings and procedures, as appropriate.
To ensure continuity in the functioning of the Company’s information systems, management has deployed several measures (contingency plans) intended to ensure the uninterrupted performance of information systems in case of cybersecurity threats and other malfunctioning of IT systems with possible fallouts on business operations, as well as in case of massive cyber threats having low probability of occurrence but that could cause relevant system disruptions. Those measures include adoption of a continuity management plan of the information system infrastructures, which drives simultaneously technologies, processes and procedures with the goal of ensuring resiliency and recovery of information systems in accordance with minimum services levels dictated by the business lines.
In addition, the set of countermeasures to mitigate cyber risk has been updated, consistent with recent industry-specific, legal obligations also by disseminating throughout the organization a cybersecurity culture aimed at making managers and employees more conscious about ongoing cyber threats and at how to deal with cyber risks. Those also include the management of fault scenarios, the preparation of contingency plans and the execution of stress tests and test simulations.
The Company owns a proprietary green data center where most of the Company’s applications and systems run, and massive amounts of the Company’s data are stored. Considering that this is a core asset, several measures and procedures have been adopted which are designated to ensure continuity in the performance of the Company’s information systems even in case of an outage of the whole data center, particularly by equipping a backup site to ensure a disaster recovery of most critical information systems and data warehouse, and by preserving continuity at the core business. The green data center has undergone an upgrading plan which comprised:
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advances in technological solutions to prevent and manage through automated procedures partial or component faults; |
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availability of spare capacity to elaborate and manage data and/or availability of off-line backup data at other sites; |
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reinforcement of the geographic enterprise redundant connectivity to consume services from GDC and Cloud suppliers. |
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The Company’s internal control system is designed by the Company’s management under the direct supervision of the Board of Directors and the ultimate supervision of the Board of Statutory Auditors. The Board of Directors sets the guidelines of the internal control system, sets the tone of an effective organizational environment that drives management to continuously monitor and treat Company risks, and finally determines the maximum level of tolerable exposure to the Company’s main risks in view of achieving the Company’s profitability and industrial targets and executing against its stated strategic vision, both on the short and the medium-long term.
The CEO of Eni is responsible for establishing and maintaining an effective internal control system and for executing the guidelines defined by the Board. In performing this ample task, the CEO coordinates other management representatives and reports to the Board and the Committee on a quarterly basis about how the Company is responding and reacting to the main risks in the business environment and in the Company’s industrial operations and support processes.
Middle management is responsible for identifying and assessing risks across the whole of Eni’s industrial and business- support processes, which could jeopardize the achievement of the Company’s targets. This activity is performed at various organizational levels: subsidiary, business process, profit center, cost center, department, and business-supporting functions, among others, and is structured in various steps.
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First, risk identification and assessment enable each manager to gain a comprehensive picture of possible adverse events which could negatively affect the effectiveness and efficiency of Company’s processes and operations. |
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Second, potential adverse impacts associated with each risk event are estimated both in quantitative (i.e., impacts on financial results and business continuity) and qualitative (i.e., impacts on Company reputation) terms, also weighting impacts by probability of occurrence. |
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Third, mitigating actions and plans are implemented or those in place are revised to reduce any possible risks to a tolerable level. |
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Finally, controls have been designed to test the effective functioning of mitigating actions.
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Top management is responsible for verifying and monitoring whether all risk-reducing actions and plans are compatible with the ongoing evolution of the Company’s business model, the Company’s strategic guidelines and targets, including financial targets (operating profits and cash flow from operations), operating targets (production volumes, installed capacity, development of new product lines), business security and continuity targets (HSE incidents, cybersecurity threats, security of personnel and assets in high-risk areas, climate-adaptation of Company’s plants and equipment) and preservation of Company’s reputation. Those activities enable management to gain full comprehension of the effectiveness of the internal control system and risk treatment considering current/expected trends in the business environment (market trends, consumer behavior, evolution of technologies and of the competitive landscape) and in the Company’s structure (entrance in new markets, significant asset acquisitions/dispositions, restructuring and reorganizations).
Top management, including the CEO, reports to the Board and the Committee on a regular basis about the effectiveness of the Company’s internal control system, its evolution in connection with emerging risks or significant modifications of the Company’s risk profile and possible improvements, covening all aspects of the business, including the cybersecurity risk.
The manager in charge of running the Company’s IT infrastructures and information systems identifies on a regular basis the main cybersecurity threat, to which the Company is exposed, assesses the level of vulnerability and adopts all IT solutions and security protocols to reduce those risks to an acceptable level.
We believe that this manager has the academic background and the experience in IT systems required to perform its tasks effectively.
IT management provides regular reports to the Company’s senior management throughout the year, and to the Audit Committee or the Board of Directors, as appropriate, on a regular schedule. Such reports typically address, among other things, the Company’s cybersecurity strategy, initiatives, key security metrics, penetration testing and benchmarking learnings, and business response plans as well as the evolving cybersecurity threat landscape.
The cybersecurity risk is regularly monitored to assess the effectiveness of the Company’s risk-reducing activities, proper functioning of controls and to identify emerging risks that may warrant improvements/upgrading of the Company’s cybersecurity infrastructures and protocols. Those activities are reported regularly to the Board of Directors and the Internal Control Committee, as part of the general process of reporting the whole of the internal control system for risk management, so directors can appreciate the robustness of the whole of the process for identifying, assessing, and mitigating cybersecurity threats.
As of the date of this report, we have not identified any risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected, or are reasonably likely to materially affect the Company, including our business strategy, results of operations, or financial condition.
While Eni believes its cybersecurity program to be appropriate for managing constantly evolving cybersecurity risks, no program can fully protect against all possible adverse events. In 2024, no material cybersecurity incidents were reported. For additional information on these risks and potential consequences if the measures we are taking prove to be insufficient or if our proprietary data is otherwise not protected, see “Item 3 - Risk Factors” in this report.
185
P ART III
Item 17. FINANCIAL STATEMENTS
NOT APPLICABLE
Item 18. FINANCIAL STATEMENTS
Inde x to Financia l Statements:
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Description of securities registered under Section 12 of the Exchange Act |
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List of subsidiaries (see Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements) |
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11.
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11.2 |
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Certifications: |
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Certifications pursuant to Rule 13a-14(a) of the Securities Exchange Act |
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12.2. |
Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act |
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13.1. |
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13.2. |
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15.a(i) |
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15.a(ii) |
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15.a(iii) |
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15.a(iv) |
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15.a(v) |
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97 |
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99 |
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101.INS |
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
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101.SCH |
Inline XBRL Taxonomy Extension Schema |
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101.CAL |
Inline XBRL Taxonomy Extension Schema Calculation Linkbase |
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101.DEF |
Inline XBRL Taxonomy Extension Schema Definition Linkbase |
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101.LAB |
Inline XBRL Taxonomy Extension Schema Label Linkbase |
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101.PRE |
Inline XBRL Taxonomy Extension Schema Presentation Linkbase |
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104. |
Cover Page Interactive Date File (formatted as Inline XBRL and contained in Exhibit 101) |
187
SIGNATURES
The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: April 4, 2025
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Eni SpA |
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/s/ FRANCESCO ESPOSITO |
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Francesco Esposito |
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Title: Head of Accounting and |
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Financial Statements |
188
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Eni SpA
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Eni SpA and its subsidiaries (the “Company”) as of December 31, 2024 and 2023, and the related consolidated profit and loss account and consolidated statements of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2024, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under Item 15. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Annual Report on Internal Control over Financial Reporting, management has excluded 53 entities from its assessment of internal control over financial reporting as of December 31, 2024 because they were acquired by the Company in several purchase business combinations during 2024. We have also excluded these 53 entities from our audit of internal control over financial reporting. These entities, each of which is wholly-owned, comprised, in the aggregate, total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting of approximately 2% and 1% of consolidated total assets and consolidated total revenues, respectively, as of and for the year ended December 31, 2024.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-1
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Estimated Proved Oil and Natural Gas Reserves on E&P Property, Plant and Equipment, Net
As described in Notes 1 and 12 to the consolidated financial statements, the Company’s consolidated net property, plant and equipment (PP&E) was €59.9 billion as of December 31, 2024, of which €51.3 billion relates to the Exploration and Production (E&P) segment. The Company’s depreciation, depletion and amortization (DD&A) expense for E&P wells, plant and machinery was €5.7 billion for the year ended December 31, 2024. Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting. Under this method, proved oil and gas assets are depreciated generally on a unit of production basis. Proved exploration rights and acquired proved mineral interests are amortised over proved reserves; proved exploration and appraisal costs and development costs are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves. The estimate of the reserves depends on a number of factors, assumptions and variables, including: (i) the quality of available geological and technical engineering data; (ii) projections regarding future rates of production and operating costs and development costs; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of the Company’s reservoirs; and (v) changes in oil and natural gas commodity prices. As disclosed by management, staff involved in the reserves evaluation process have qualifications that comply with international standards and proved reserves are evaluated on a rotational basis by independent oil engineering companies (collectively “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the impact of estimated proved oil and natural gas reserves on E&P PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and management’s specialists in developing the estimates of proved oil and natural gas reserves; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved oil and natural gas reserves. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the data, methods and assumptions used by management and management’s specialists; (ii) testing the completeness and accuracy of the underlying data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the process related to the reserve estimates including certain data, methods and assumptions used by management’s specialists and (ii) the relevance and reliability of geological and technical engineering data used by management’s specialists to develop the reserve estimates.
Recoverability Assessment of Certain E&P Property, Plant and Equipment, Net
As described in Notes 1 and 12 to the consolidated financial statements, the Company’s consolidated net PP&E was €59.9 billion as of December 31, 2024, of which €51.3 billion relates to the E&P segment. The Company incurred impairment losses, net of recognized impairment reversals, before taxes associated with the E&P segment of €2.2 billion for the year ended December 31, 2024. The recoverability assessment is performed for each cash-generating unit (CGU) represented by the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or group of assets. The assessment of the recoverability of non-financial assets depends on management estimates on highly uncertain and complex matters such as future commodity prices, future discount rates, future development costs and production costs, and the effects of inflation. For the determination of value in use, the estimated future cash flows are discounted using a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the estimated future cash flows. For oil and natural gas properties, the expected future cash flows are estimated based on proved and probable reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future rates of production is based on assumptions related to future commodity prices, operating costs, lifting and development costs, field decline rates and other factors. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognised in the profit and loss account. The impairment reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years.
F-2
The principal considerations for our determination that performing procedures relating to the recoverability assessment of certain E&P PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the value in use of oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to the discount rates, future rates of production, future commodity prices including the effects of inflation, and future development costs and production costs, as applicable to the CGU; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s E&P PP&E, net recoverability assessment. These procedures also included, among others, (i) testing management’s process for assessing the recoverability of carrying amounts of E&P PP&E, net; (ii) evaluating the appropriateness of the value in use models used by management; (iii) testing the completeness and accuracy of underlying data used in the value in use models; and (iv) evaluating the reasonableness of significant assumptions used by management related to future rates of production, future commodity prices, and future development costs and production costs. Evaluating management’s assumptions related to future commodity prices involved comparing the assumptions to observable market data. Evaluating management’s assumptions related to future development costs and production costs involved comparing the assumption to the past performance of the Company. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved and probable oil and natural gas reserves and the reasonableness of the future production volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the data, methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the underlying data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the process related to the reserve estimates including certain data, methods and assumptions used by management’s specialists; (ii) the relevance and reliability of geological and technical engineering data used by the specialists to develop the reserve estimates; (iii) the appropriateness of the value in use models; (iv) the reasonableness of the future commodity prices including the effects of inflation assumption; and (v) the reasonableness of the discount rates assumption.
/s/
April 4, 2025
We have served as the Company’s auditor since 2019.
F-3
CONSOLIDATED BALANCE SHEET
(€ million)
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December 31, 2024 |
December 31, 2023 |
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Total amount |
of which with related parties |
Total amount |
of which with related parties |
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ASSETS |
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Current assets |
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Cash and cash equivalents |
(6) |
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Financial assets at fair value through profit or loss |
(7) |
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Other current financial assets |
(17) |
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Trade and other receivables |
(8) |
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Inventories |
(9) |
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Income tax receivables |
(10) |
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Other current assets |
(11) (24) |
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Non-current assets |
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Property, plant and equipment |
(12) |
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Right-of-use assets |
(13) |
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Intangible assets |
(14) |
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Inventory - Compulsory stock |
(9) |
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Equity-accounted investments |
(16) (37) |
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Other investments |
(16) |
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Other non-current financial assets |
(17) |
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Deferred tax assets |
(23) |
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Income tax receivables |
(10) |
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Other non-current assets |
(11) (24) |
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Assets held for sale |
(25) |
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TOTAL ASSETS |
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LIABILITIES AND EQUITY |
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Current liabilities |
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Short-term debt |
(19) |
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Current portion of long-term debt |
(19) |
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Current portion of long-term lease liabilities |
(13) |
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Trade and other payables |
(18) |
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Income tax payables |
(10) |
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Other current liabilities |
(11) (24) |
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|
|
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
|
Long-term debt |
(19) |
|
|
|
|
|
Long-term lease liabilities |
(13) |
|
|
|
|
|
Provisions |
(21) |
|
|
|
|
|
Provisions for employee benefits |
(22) |
|
|
|
|
|
Deferred tax liabilities |
(23) |
|
|
|
|
|
Income tax payables |
(10) |
|
|
|
|
|
Other non-current liabilities |
(11) (24) |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities directly associated with assets held for sale |
(25) |
|
|
|
|
|
TOTAL LIABILITIES |
|
|
|
|
|
|
Share capital |
|
|
|
|
|
|
Retained earnings |
|
|
|
|
|
|
Cumulative currency translation differences |
|
|
|
|
|
|
Other reserves and equity instruments |
|
|
|
|
|
|
Treasury shares |
|
(
|
|
(
|
|
|
Profit |
|
|
|
|
|
|
Equity attributable to equity holders of Eni |
|
|
|
|
|
|
Non-controlling interest |
|
|
|
|
|
|
TOTAL EQUITY |
(26) |
|
|
|
|
|
TOTAL LIABILITIES AND EQUITY |
|
|
|
|
|
See the accompanying notes.
Information about the definitive purchase price allocation of business combinations made in 2023 is provided in note 27 ‐ Other Information.
F-4
CONSOLIDATED PROFIT AND LOSS ACCOUNT
(€ million except as otherwise stated)
|
|
|
2024 |
2023 |
2022 |
|||
|
|
Note |
Total amount |
of which with related parties |
Total amount |
of which with related parties |
Total amount |
of which with related parties |
|
Sales from operations |
|
|
|
|
|
|
|
|
Other income and revenues |
|
|
|
|
|
|
|
|
REVENUES AND OTHER INCOME |
(29) |
|
|
|
|
|
|
|
Purchases, services and other |
(30) |
(
|
(
|
(
|
(
|
(
|
(
|
|
Net (impairments) reversals of trade and other receivables |
(8) |
(
|
(
|
(
|
|
|
(
|
|
Payroll and related costs |
(30) |
(
|
|
(
|
(
|
(
|
(
|
|
Other operating income (expense) |
(24) |
(
|
|
|
|
(
|
|
|
Depreciation and amortization |
(12) (13) (14) |
(
|
|
(
|
|
(
|
|
|
Net (impairments) reversals of tangible, intangible and right-of-use assets |
(15) |
(
|
|
(
|
|
(
|
|
|
Write-off of tangible and intangible assets and right-of-use assets |
(12) (13) (14) |
(
|
|
(
|
|
(
|
|
|
OPERATING PROFIT |
|
|
|
|
|
|
|
|
Finance income |
(31) |
|
|
|
|
|
|
|
Finance expense |
(31) |
(
|
(
|
(
|
(
|
(
|
(
|
|
Net finance income (expense) from financial assets at fair value through profit or loss |
(31) |
|
|
|
|
(
|
|
|
Derivative financial instruments |
(24) (31) |
|
|
(
|
|
|
|
|
FINANCE INCOME (EXPENSE) |
|
(
|
|
(
|
|
(
|
|
|
Share of profit (loss) from equity-accounted investments |
|
|
|
|
|
|
|
|
Other gain (loss) from investments |
|
|
(
|
|
|
|
|
|
INCOME (EXPENSE) FROM INVESTMENTS |
(16) (32) |
|
|
|
|
|
|
|
PROFIT BEFORE INCOME TAXES |
|
|
|
|
|
|
|
|
Income taxes |
(33) |
(
|
|
(
|
|
(
|
|
|
PROFIT |
|
|
|
|
|
|
|
|
Attributable to Eni |
|
|
|
|
|
|
|
|
Attributable to non-controlling interest |
(26) |
|
|
|
|
|
|
|
Earnings per share (€ per share) |
(34) |
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
|
|
|
Diluted |
|
|
|
|
|
|
|
See the accompanying notes .
F-5
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(€ million)
|
|
Note |
2024 |
2023 |
2022 |
|
Profit |
|
|
|
|
|
Other items of comprehensive income (loss) |
|
|
|
|
|
Items that are not reclassified to profit or loss in later periods |
|
|
|
|
|
Remeasurements of defined benefit plans |
(26) |
|
(
|
|
|
Share of other comprehensive income (loss) on equity-accounted investments |
(26) |
|
(
|
|
|
Change of minor investments measured at fair value with effects to OCI |
(26) |
|
|
|
|
Tax effect |
(26) |
(
|
|
(
|
|
|
|
|
|
|
|
Items that may be reclassified to profit or loss in later periods |
|
|
|
|
|
Currency translation differences |
(26) |
|
(
|
|
|
Change in the fair value of cash flow hedging derivatives |
(26) |
(
|
|
|
|
Share of other comprehensive income (loss) on equity-accounted investments |
(26) |
(
|
|
(
|
|
Tax effect |
(26) |
|
(
|
(
|
|
|
|
|
(
|
|
|
Total other items of comprehensive income (loss) |
|
|
(
|
|
|
Total comprehensive income |
|
|
|
|
|
Attributable to Eni |
|
|
|
|
|
Attributable to non-controlling interest |
|
|
|
|
See the accompanying notes.
F-6
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(€ million)
|
|
|
Equity attributable to equity holders of Eni |
|
|
||||||
|
|
Note |
Share capital |
Retained earnings |
Cumulative currency translation differences |
Other reserves and equity instruments |
Treasury shares |
Profit for the year |
Total |
Non-controlling interest |
Total equity |
|
Balance at December 31, 2023 |
(26) |
|
|
|
|
(
|
|
|
|
|
|
Profit for the year |
|
|
|
|
|
|
|
|
|
|
|
Other items of comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
Remeasurements of defined benefit plans net of tax effect |
(26) |
|
|
|
|
|
|
|
|
|
|
Share of “Other comprehensive income” on equity-accounted investments |
(26) |
|
|
|
|
|
|
|
|
|
|
Change of minor investments measured at fair value with effects to OCI |
(26) |
|
|
|
|
|
|
|
|
|
|
Items that are not reclassified to profit or loss in later periods |
|
|
|
|
|
|
|
|
|
|
|
Currency translation differences |
(26) |
|
|
|
(
|
|
|
|
|
|
|
Change in the fair value of cash flow hedge derivatives net of tax effect |
(26) |
|
|
|
(
|
|
|
(
|
(
|
(
|
|
Share of “Other comprehensive income (loss)” on equity-accounted investments |
(26) |
|
|
|
(
|
|
|
(
|
|
(
|
|
Items that may be reclassified to profit or loss in later periods |
|
|
|
|
(
|
|
|
|
|
|
|
Total comprehensive income (loss) of the year |
|
|
|
|
(
|
|
|
|
|
|
|
Dividend distribution of Eni SpA |
(26) |
|
(
|
|
|
|
|
(
|
|
(
|
|
Dividend distribution of other companies |
|
|
|
|
|
|
|
|
(
|
(
|
|
Allocation of 2023 profit |
|
|
|
|
|
|
(
|
|
|
|
|
Capital contribution by non-controlling interests |
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury shares |
(26) |
|
(
|
|
|
(
|
|
(
|
|
(
|
|
Cancellation of treasury shares |
(26) |
|
|
|
(
|
|
|
|
|
|
|
Long-term share-based incentive plan and employee stock ownership plan |
(26) (30) |
|
|
|
(
|
|
|
|
|
|
|
Issuance of perpetual subordinated bonds |
(26) |
|
|
|
|
|
|
|
|
|
|
Coupon payment on perpetual subordinated bonds |
(26) |
|
(
|
|
|
|
|
(
|
|
(
|
|
Change in non‐controlling interest |
(26) |
|
|
|
|
|
|
|
|
|
|
Transactions with holders of equity instruments |
|
|
(
|
|
|
(
|
(
|
(
|
|
(
|
|
Other changes |
|
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
|
Other changes in equity |
|
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
|
Balance at December 31, 2024 |
(26) |
|
|
|
|
(
|
|
|
|
|
See the accompanying notes.
F-7
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
continued
(€ million)
|
|
|
Equity attributable to equity holders of Eni |
|
|
||||||
|
|
Note |
Share capital |
Retained earnings |
Cumulative currency translation differences |
Other reserves and equity instruments |
Treasury shares |
Profit for the year |
Total |
Non-controlling interest |
Total equity |
|
Balance at December 31, 2022 |
|
|
|
|
|
(
|
|
|
|
|
|
Profit for the year |
|
|
|
|
|
|
|
|
|
|
|
Other items of comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
Remeasurements of defined benefit plans net of tax effect |
(26) |
|
|
|
(
|
|
|
(
|
|
(
|
|
Share of “Other comprehensive income” on equity-accounted investments |
(26) |
|
|
|
(
|
|
|
(
|
|
(
|
|
Change of minor investments measured at fair value with effects to OCI |
(26) |
|
|
|
|
|
|
|
|
|
|
Items that are not reclassified to profit or loss in later periods |
|
|
|
|
|
|
|
|
|
|
|
Currency translation differences |
(26) |
|
|
(
|
(
|
|
|
(
|
|
(
|
|
Change in the fair value of cash flow hedge derivatives net of tax effect |
(26) |
|
|
|
|
|
|
|
|
|
|
Share of “Other comprehensive income (loss)” on equity-accounted investments |
(26) |
|
|
|
|
|
|
|
|
|
|
Items that may be reclassified to profit or loss in later periods |
|
|
|
(
|
|
|
|
(
|
|
(
|
|
Total comprehensive income (loss) of the year |
|
|
|
(
|
|
|
|
|
|
|
|
Dividend distribution of Eni SpA |
(26) |
|
(
|
|
|
|
|
(
|
|
(
|
|
Dividend distribution of other companies |
|
|
|
|
|
|
|
|
(
|
(
|
|
Allocation of 2022 profit |
|
|
|
|
|
|
(
|
|
|
|
|
Reimbursement to non-controlling interests |
|
|
|
|
|
|
|
|
(
|
(
|
|
Purchase of treasury shares |
(26) |
|
(
|
|
|
(
|
|
(
|
|
(
|
|
Cancellation of treasury shares |
(26) |
|
|
|
(
|
|
|
|
|
|
|
Long-term share-based incentive plan |
(26) (30) |
|
|
|
(
|
|
|
|
|
|
|
Coupon payment on perpetual subordinated bonds |
(26) |
|
(
|
|
|
|
|
(
|
|
(
|
|
Change in non‐controlling interest |
(26) |
|
|
|
|
|
|
|
(
|
|
|
Transactions with holders of equity instruments |
|
|
|
|
(
|
|
(
|
(
|
(
|
(
|
|
Issuing effect of convertible bonds |
(26) |
|
|
|
|
|
|
|
|
|
|
Other changes |
|
|
|
(
|
(
|
|
|
|
(
|
|
|
Other changes in equity |
|
|
|
(
|
(
|
|
|
|
(
|
|
|
Balance at December 31, 2023 |
(26) |
|
|
|
|
(
|
|
|
|
|
See the accompanying notes.
F-8
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
continued
(€ million)
|
|
|
Equity attributable to equity holders of Eni |
|
|
||||||
|
|
Note |
Share capital |
Retained earnings |
Cumulative currency translation differences |
Other reserves and equity instruments |
Treasury shares |
Profit for the year |
Total |
Non-controlling interest |
Total equity |
|
Balance at December 31, 2021 |
|
|
|
|
|
(
|
|
|
|
|
|
Profit for the year |
|
|
|
|
|
|
|
|
|
|
|
Other items of comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
Remeasurements of defined benefit plans net of tax effect |
|
|
|
|
|
|
|
|
|
|
|
Share of “Other comprehensive income” on equity-accounted investments |
|
|
|
|
|
|
|
|
|
|
|
Change of minor investments measured at fair value with effects to OCI |
|
|
|
|
|
|
|
|
|
|
|
Items that are not reclassified to profit or loss in later periods |
|
|
|
|
|
|
|
|
|
|
|
Currency translation differences |
|
|
|
|
|
|
|
|
|
|
|
Change in the fair value of cash flow hedge derivatives net of tax effect |
|
|
|
|
|
|
|
|
|
|
|
Share of “Other comprehensive income (loss)” on equity-accounted investments |
|
|
|
|
(
|
|
|
(
|
|
(
|
|
Items that may be reclassified to profit or loss in later periods |
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) of the year |
|
|
|
|
|
|
|
|
|
|
|
Dividend distribution of Eni SpA |
|
|
|
|
|
|
(
|
(
|
|
(
|
|
Interim dividend distribution of Eni SpA |
|
|
(
|
|
|
|
|
(
|
|
(
|
|
Dividend distribution of other companies |
|
|
|
|
|
|
|
|
(
|
(
|
|
Allocation of 2021 profit |
|
|
|
|
|
|
(
|
|
|
|
|
Capital contribution by non-controlling interests |
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury shares |
|
|
(
|
|
|
(
|
|
(
|
|
(
|
|
Cancellation of treasury shares |
|
|
|
|
(
|
|
|
|
|
|
|
Long-term share-based incentive plan |
|
|
|
|
(
|
|
|
|
|
|
|
Coupon payment on perpetual subordinated bonds |
|
|
(
|
|
|
|
|
(
|
|
(
|
|
Change in non‐controlling interest |
|
|
|
|
|
|
|
|
|
|
|
Transactions with holders of equity instruments |
|
|
|
|
|
(
|
(
|
(
|
|
(
|
|
Other changes |
|
|
|
(
|
(
|
|
|
|
|
|
|
Other changes in equity |
|
|
|
(
|
(
|
|
|
|
|
|
|
Balance at December 31, 2022 |
|
|
|
|
|
(
|
|
|
|
|
See the accompanying notes.
F-9
CONSOLIDATED STATEMENT OF CASH FLOWS
(€ million)
|
|
Note |
2024 |
2023 |
2022 |
|
Profit |
|
|
|
|
|
Adjustments to reconcile profit to net cash provided by operating activities |
|
|
|
|
|
Depreciation and amortization |
(12) (13) (14) |
|
|
|
|
Net impairments (reversals) of tangible, intangible and right-of-use assets |
(15) |
|
|
|
|
Write-off of tangible and intangible assets and right-of-use assets |
(12) (13) (14) |
|
|
|
|
Share of (profit) loss of equity-accounted investments |
(16) (32) |
(
|
(
|
(
|
|
Net gain on disposal of assets |
|
(
|
(
|
(
|
|
Dividend income |
(32) |
(
|
(
|
(
|
|
Interest income |
|
(
|
(
|
(
|
|
Interest expense |
|
|
|
|
|
Income taxes |
(33) |
|
|
|
|
Other changes |
|
(
|
(
|
(
|
|
Cash flow from changes in working capital: |
|
|
|
(
|
|
- inventories |
|
|
|
(
|
|
- trade receivables |
|
|
|
(
|
|
- trade payables |
|
|
(
|
|
|
- provisions |
|
(
|
|
|
|
- other assets and liabilities |
|
|
|
(
|
|
Change in the provisions for employee benefits |
|
(
|
|
|
|
Dividends received |
|
|
|
|
|
Interest received |
|
|
|
|
|
Interest paid |
|
(
|
(
|
(
|
|
Income taxes paid, net of tax receivables received |
|
(
|
(
|
(
|
|
Net cash provided by operating activities |
|
|
|
|
|
- of which with related parties |
(36) |
(
|
(
|
|
|
Cash flow from investing activities |
|
(
|
(
|
(
|
|
- tangible assets |
(12) |
(
|
(
|
(
|
|
- prepaid right-of-use assets |
(13) |
(
|
|
(
|
|
- intangible assets |
(14) |
(
|
(
|
(
|
|
- consolidated subsidiaries and businesses net of cash and cash equivalents acquired |
(5) (27) |
(
|
(
|
(
|
|
- investments |
(16) |
(
|
(
|
(
|
|
- securities and financing receivables held for operating purposes |
|
(
|
(
|
(
|
|
- change in payables in relation to investing activities |
|
(
|
(
|
|
|
Cash flow from disposals |
|
|
|
|
|
- tangible assets |
|
|
|
|
|
- intangible assets |
|
|
|
|
|
- consolidated subsidiaries and businesses net of cash and cash equivalents disposed of |
(5) (27) |
|
|
(
|
|
- investments |
|
|
|
|
|
- securities and financing receivables held for operating purposes |
|
|
|
|
|
- change in receivables in relation to disposals |
|
(
|
|
|
|
Net change in securities and financing receivables held for non-operating purposes |
|
(
|
|
|
|
Net cash used in investing activities |
|
(
|
(
|
(
|
|
- of which with related parties |
(36) |
(
|
(
|
(
|
|
Increase in long-term financial debt |
(19) |
|
|
|
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Repayments of long-term financial debt |
(19) |
(
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(
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(
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Payments of lease liabilities |
(13) |
(
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(
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(
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Increase (decrease) in short-term financial debt |
(19) |
(
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(
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Dividends paid to Eni's shareholders |
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(
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(
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(
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Dividends paid to non-controlling interest |
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(
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(
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(
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Capital contribution by (reimbursement to) non-controlling interests |
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(
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Sale (purchase) of additional interests in consolidated subsidiaries |
|
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(
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Other contributions |
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Purchase of treasury shares |
(26) |
(
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(
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(
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Issuing effect of convertible bonds |
(26) |
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Issue of perpetual subordinated bonds |
(26) |
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Coupon payment on perpetual subordinated bonds |
(26) |
(
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(
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(
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Net cash used in financing activities |
|
(
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(
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(
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- of which with related parties |
(36) |
(
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(
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(
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Effect of exchange rate changes and other changes on cash and cash equivalents |
|
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(
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Net increase (decrease) in cash and cash equivalents |
|
(
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Cash and cash equivalents - beginning of the year |
(6) |
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Cash and cash equivalents - end of the year (a) |
(6) |
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(a) As of December 31, 2023, cash and cash equivalents included €
See the accompanying notes.
F-10
Notes on Consolidated Financial Statements
1 Significant accounting policies, estimates and judgments
Basis of preparation
The Consolidated Financial Statements of Eni SpA and its subsidiaries (collectively referred to as Eni or the Group) have been prepared on a going concern basis in accordance with International Financial Reporting Standards (IFRS) 1 as issued by the International Accounting Standards Board (IASB).
The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value as described in the accounting policies that follow. The principles of consolidation and the significant accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated.
The 2024 Consolidated Financial Statements included in the Annual Report on Form 20-F, were approved by the Eni’s Board of Directors on April 3, 2025.
The Consolidated Financial Statements are presented in euros and all values are rounded to the nearest million euros (€ million), except where otherwise indicated.
Significant accounting estimates and judgements
The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognized in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are based on complex judgements and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of reserves, impairment of financial and non-financial assets, leases, decommissioning and restoration liabilities, environmental liabilities, business combinations, employee benefits, revenue from contracts with customers, fair value measurements and income taxes. Although the Company uses its best estimates and judgements, actual results could differ from the estimates and assumptions used. The accounting estimates and judgments relevant for the preparation of the Consolidated Financial Statement are illustrated in the description of the respective accounting policy.
Significant accounting estimates and judgments made in assessing the impacts of climate-related risks
Significant accounting estimates and judgments made by management for the preparation of the 2024 Consolidated Financial Statements are affected by the effects of actions to address climate change and by the potential impact of the energy transition. In particular, the global pressure towards a low-carbon economy, increasingly restrictive regulatory requirements for oil&gas activities and hydrocarbons consumption, carbon pricing schemes, the technological evolution of alternative energy sources for transportation, as well as changes in consumer preferences could imply a structural decline of the demand for hydrocarbons in the medium-long term, an increase in operating costs and a higher risk of stranded assets for Eni.
The Eni strategy towards Carbon Neutrality, in line with the provisions of the scenarios compatible with maintaining global warming within the 1.5°C threshold, is composed of a series of actions and initiatives aimed to achieve carbon neutrality by 2050, through the Net Zero emissions for all Scope 1, 2 and 3 GHG emissions associated with Eni’s product portfolio. Scenarios adopted by management take into account policies, regulatory requirements and current and expected developments in technology and set out a development path of the future energy system, on the basis of an economic and demographic framework, analysis of existing and announced policies and technologies, identifying those which can reasonably reach maturity within the considered time horizon. Price variables reflect the best estimate by management of the fundamentals of several energy markets, which incorporates the ongoing and reasonably expected decarbonization trends, and are subject to continuous benchmarking with the views of market analysts and peers.
Such scenarios represent the basis for significant estimates and judgments relating to: (i) the assessment of the intention to continue exploration projects; (ii) the assessment of the recoverability of non-current assets and credit exposures towards National Oil Companies; (iii) the definition of useful lives and residual values of fixed assets; (iv) impacts on provisions (e.g. the anticipation of the expected timing of decommissioning and restoration costs).
Principles of consolidation
Subsidiaries
The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees.
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1 IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC). |
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F-11
Subsidiaries are fully recognized and included in the consolidated financial statement, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases, taking into account the appropriate eliminations of intragroup transactions (see the accounting policy for “Intragroup transactions”). Non-controlling interests are presented separately on the balance sheet within equity; the profit or loss and comprehensive income attributable to non-controlling interests are presented in specific line items, respectively, in the profit and loss account and in the statement of comprehensive income. Non-controlling interests also include subordinated perpetual bonds issued by subsidiaries for which the Group holds the unconditional right to defer repayment of principal and payment of coupons.
Taking into account the lack of any material 2 impact on the representation of the financial position and performance of the Group 3 , the Consolidated Financial Statements do not consolidate: (i) some subsidiaries that are immaterial, both individually and in the aggregate, and (ii) subsidiaries acting as sole operator in the management of oil and gas contracts on behalf of companies participating in a joint project. In the latter case, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenue and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized directly in the financial statements of the companies involved based on their own share.
When the proportion of the equity held by non-controlling interests changes, any difference between the consideration paid/received and the amount by which the related non-controlling interests are adjusted is attributed to Eni owners’ equity (within the line item “Retained earnings”). Moreover, in the event of the disposal of minority interests without loss of control, any put options on non-controlling interests, exercisable upon the occurrence of events not under the Group's control, result in the recognition of a liability, equal to the present value of the so-called redemption amount, as a balancing entry to Group equity.
The sale of equity interests with loss of control determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred net assets; (ii) any gain or loss recognized as a result of the remeasurement of any investment retained in the former subsidiary at its fair value; (iii) the estimate of fair value of any contingent consideration, to be settled in cash if specified future events occur or conditions are met; and (iv) any amount related to the former subsidiary previously recognized in other comprehensive income which may be reclassified subsequently to the profit and loss account 4 . Any investment retained in the former subsidiary is recognized at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria.
Interests in joint arrangements
Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
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. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.
A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement; in the Consolidated Financial Statements, Eni recognizes its share of the assets/liabilities and revenues/expenses of joint operations on the basis of its rights and obligations relating to the arrangements.
After the initial recognition, the assets/liabilities and revenues/expenses of the joint operations are measured in accordance with the applicable measurement criteria.
Immaterial joint operations structured through a separate vehicle are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost less any impairment losses.
Investments in associates
An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.
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2 According to IFRSs, information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general-purpose financial statements make on the basis of those financial statements. |
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3 Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”. |
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4 Conversely, any amount related to the former subsidiary previously recognized in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity. |
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F-12
The equity method of accounting
Investments in joint ventures, associates and immaterial unconsolidated subsidiaries, are accounted for using the equity method. 5
Under the equity method, investments are initially recognized at cost, allocating it, similarly to business combinations procedures, to the investee’s identifiable assets/liabilities; any excess of the cost of the investment over the share of the net fair value of the investee’s identifiable assets and liabilities is accounted for as goodwill, not separately recognized but included in the carrying amount of the investment. If this allocation is provisionally recognized at initial recognition, it can be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed at the acquisition date. Subsequently, with the aim of reflecting the Group’s share of the investee’s net assets and the related changes, the carrying amount is adjusted to reflect: (i) the investor’s share of the profit or loss of the investee after the date of acquisition, adjusted to account for depreciation, amortization and any impairment losses of the equity-accounted entity’s assets based on their fair values at the date of acquisition; and (ii) the investor’s share of the investee’s other comprehensive income. Conversely, the carrying amount is not adjusted for changes in the equity of the investee arising, for instance, from the issue by the investee of perpetual subordinated bonds or convertible bonds not subscribed by the Group. Distributions received from an equity-accounted investee reduce the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). Losses arising from the application of the equity method in excess of the carrying amount of the investment, recognized in the profit and loss account within “Income (Expense) from investments”, reduce the carrying amount, net of the related expected credit losses (see below), of any financing receivables towards the investee for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests), which are, in substance, an extension of the investment in the investee. The investor’s share of any losses of an equity-accounted investee that exceeds the carrying amount of the investment and any long-term interests (the so-called net investment), is recognized in a specific provision only to the extent that the investor has incurred legal or constructive obligations or made payments on behalf of the investee.
Whenever there is objective evidence of impairment (e.g. relevant breaches of contracts, significant financial difficulty, probable default of the counterparty, etc.), the carrying amount of the net investment, resulting from the application of the abovementioned measurement criteria, is tested for impairment by comparing it with the related recoverable amount, determined by adopting the criteria indicated in the accounting policy for “Impairment of non-financial assets”. When an impairment loss no longer exists or has decreased, any reversal of the impairment loss is recognized in the profit and loss account within “Income (Expense) from investments”. The impairment reversal of the net investment shall not exceed the previously recognized impairment losses.
The sale of equity interests with loss of joint control or significant influence over the investee determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognized as a result of the remeasurement of any investment retained in the former joint venture/associate at its fair value 6 ; and (iii) any amount related to the former joint venture/associate previously recognized in other comprehensive income which may be reclassified subsequently to the profit and loss account 7 . Any investment retained in the former joint venture/associate is recognized at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria.
Business combinations
Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is the sum of the acquisition-date fair value of the assets transferred, the liabilities incurred and the equity interests issued by the acquirer. The consideration transferred also includes the fair value of any assets or liabilities resulting from contingent considerations, contractually agreed and dependent upon the occurrence of specified future events.
The acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values 8 , unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the acquisition-date fair values of the identifiable assets acquired and liabilities assumed is recognized, on the balance sheet, as goodwill; conversely, a gain on a bargain purchase is recognized in the profit and loss account.
Any non-controlling interests are measured as the proportionate share in the recognized amounts of the acquiree’s identifiable net assets at the acquisition date excluding the portion of goodwill attributable to them (partial goodwill method). In a business combination achieved in stages, the purchase price is determined by summing the acquisition-date fair value of previously held equity interests in the acquiree and the consideration transferred for obtaining control; the previously held equity interests are remeasured at their acquisition-date fair value and the resulting gain or loss, if any, is recognized in the profit and loss account. Furthermore, on obtaining control, any amount recognized in other comprehensive income related to the previously held equity interests is reclassified to the profit and loss account, or in another item of equity when such amount may not be reclassified to the profit and loss account.
If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date.
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5 Joint ventures, associates and immaterial unconsolidated subsidiaries are accounted for at cost less any impairment losses, if this does not result in a misrepresentation of the Company's financial position and performance.
6 If the retained investment continues to be classified either as a joint venture or an associate and so accounted for using the equity method, no remeasurement at fair value is recognized in the profit and loss account.
7 Conversely, any amount related to the former joint venture/associate previously recognized in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.
8 Fair value measurement principles are described in the accounting policy for “Fair value measurements”.
F-13
Significant accounting estimates and judgments: investments and business combinations
The assessment of the existence of control, joint control, significant influence over an investee, as well as for joint operations, the assessment of the existence of enforceable rights to the investee’s assets and enforceable obligations for the investee’s liabilities imply that management makes complex judgments on the basis of the characteristics of the investee’s structure, arrangements between parties and other relevant facts and circumstances. Significant accounting estimates by management are required also for measuring the identifiable assets acquired and the liabilities assumed in a business combination at their acquisition-date fair values. For such measurement, to be performed also for the application of the equity method, Eni adopts the valuation techniques generally used by market participants taking into account the available information; for the most significant acquisitions, Eni engages external independent evaluators.
Intragroup transactions
All balances and transactions between consolidated companies, and not yet realized with third parties, including unrealized profits arising from such transactions have been eliminated 9 .
Unrealized profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity; such accounting treatment is applied also for transfer of businesses to equity-accounted entities (so-called downstream transactions). In both cases, the unrealized losses are not eliminated as the transaction provides evidence of an impairment loss of the asset transferred.
Foreign currency translation
The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency as well as the presentation currency of the Consolidated Financial Statements, are translated into euros using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows.
The cumulative resulting exchange differences are presented in the separate component of Eni owners’ equity “Cumulative currency translation differences” 10 . Cumulative amount of exchange differences relating to a foreign operation are reclassified to the profit and loss account when the entity disposes the entire interest in that foreign operation or when the partial disposal involves the loss of control, joint control or significant influence over the foreign operation. On a partial disposal that does not involve loss of control of a subsidiary that includes a foreign operation, the proportionate share of the cumulative exchange differences is reattributed to the non-controlling interests in that foreign operation. On a partial disposal of interests in joint arrangements or in associates that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account.
The financial statements of foreign operations which are translated into euros are denominated in the foreign operations’ functional currencies which generally is the U.S. dollar.
The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below:
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(currency amount for 1 €) |
Annual average exchange rate 2024 |
Exchange rate at December 31, 2024 |
Annual average exchange rate 2023 |
Exchange rate at December 31, 2023 |
Annual average exchange rate 2022 |
Exchange rate at December 31, 2022 |
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U.S. Dollar |
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Pound Sterling |
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Australian Dollar |
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Material accounting policies
The material accounting policies used in the preparation of the Consolidated Financial Statements are described below.
Oil and natural gas exploration, appraisal, development and production activities
Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting as described below.
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9 Exchange differences associated with intragroup monetary assets and liabilities arising from transactions between consolidated companies operating in different currencies are not eliminated.
10 When the foreign subsidiary is partially owned, the cumulative exchange difference, that is attributable to the non-controlling interests, is allocated to and recognized as part of “Non-controlling interest”.
F-14
Acquisition of exploration rights
Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalized within the line item “Intangible assets” as “exploration rights — unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortized, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that indicate the absence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognized in the profit and loss account as write-off. Lower value exploration rights are pooled and amortized on a straight-line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. Upon reclassification, as well as whether there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration rights are amortized according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortization”).
Acquisition of mineral interests
Costs incurred for the acquisition of mineral interests are capitalized in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows.
Acquired exploration potential is measured in accordance with the criteria illustrated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are amortized according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortization”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortized until classified as proved reserves; in case of a negative result of the subsequent appraisal activities, it is written off.
Exploration and appraisal expenditure
Geological and geophysical exploration costs are recognized as an expense as incurred.
Costs directly associated with an exploration well are initially recognized within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalized in the following 12-month (or a longer period of time according to the complexity of the project and to the associated investment level) period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalized if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project; on the contrary, the capitalized costs are recognized in the profit and loss account as write-off. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognized as unproved is reclassified to proved exploration and appraisal costs within tangible assets in progress. Upon reclassification, or when there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortization”).
Development costs
Development costs, including the costs related to unsuccessful and damaged development wells, are capitalized as “Tangible asset in progress — proved”. Development costs are incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. They are amortized, from the commencement of production, generally on a UOP basis. When development projects are unfeasible/not carried on, the related costs are written off when it is decided to abandon the project. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.
UOP depreciation, depletion and amortization
Proved oil and gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of proved oil and gas reserves, by applying to the depreciable amounts at the end of each quarter a rate representing the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil and gas reserves. Proved exploration rights and acquired proved mineral interests are amortized over proved reserves; proved exploration and appraisal costs and development costs are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves. Proved reserves are determined according to U.S. SEC rules that require the use of the yearly average oil and gas prices for assessing the economic producibility; material changes in reference prices could result in depreciation charges not reflecting the pattern in which the assets’ future economic benefits are expected to be consumed to the extent that, for example, certain non-current assets would be fully depreciated within a short term. In these cases, the reserves considered in determining the UOP rate are estimated on the basis of economic viability parameters, reasonable and consistent with management’s expectations of production, in order to recognize depreciation charges that more appropriately reflect the expected utilization of the assets concerned.
F-15
Production costs
Production costs are those costs incurred to operate and maintain wells and field equipment and are recognized as an expense as incurred.
Production Sharing Agreements and service contracts
Oil and gas reserves related to Production Sharing Agreements are determined on the basis of contractual terms related to the recovery of the contractor’s costs to undertake and finance exploration, development and production activities at its own risk (Cost Oil) and the Company’s stipulated share of the production remaining after such cost recovery (Profit Oil). Revenues from the sale of the lifted production, against both Cost Oil and Profit Oil, are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above-mentioned accounting policies. A similar scheme applies to the service contracts where the Group is entitled to a share of the production as consideration for the rendered service.
The Company’s share of production volumes and reserves includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenue, and a tax expense.
Plugging and abandonment of wells
Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalized, consistent with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis.
Significant accounting estimates and judgments: oil and natural gas activities
Engineering estimates of the oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be categorized as “proved”, the estimate of the reserves depends on a number of factors, assumptions and variables, including: (i) the quality of available geological and technical engineering data and their interpretation and judgment; (ii) projections regarding future rates of production and operating costs and development costs; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of the Company’s reservoirs after the date of the initial estimates which may drive substantial upward or downward revisions during the current period; and (v) changes in oil and natural gas commodity prices which could affect expected future cash flows and the quantities of the Company’s proved reserves since the estimates of reserves are based on prices existing as of the date when these estimates are made.
Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.
Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves. Similar uncertainties concern unproved reserves.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditures required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such capitalized costs are reviewed, at least, on an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery.
Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Proved reserves can be classified as developed or undeveloped. Volumes are classified into proved developed reserves as a consequence of development activity. Generally, reserves are booked as proved developed at the start of production. Major development projects typically take one to four years from the time of initial booking to the start of production.
Estimated reserves are used both in determining depreciation, amortization and depletion charges (see the accounting policy for “UOP depreciation, depletion and amortization”) and for the definition of future cash flows of oil and natural gas assets within the impairment test.
Property, plant and equipment
Property, plant and equipment are recognized using the cost model and initially stated at their purchase price or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management.
F-16
For assets that necessarily take a substantial period of time to get ready for their intended use, the purchase price or construction cost comprises the borrowing costs incurred in the period to get the asset ready for use that would have been avoided if the expenditure had not been made.
In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs; a corresponding amount is recognized as part of a specific provision (see the accounting policy for “Decommissioning and restoration liabilities”). Analogous approach is adopted for present obligations to realize social projects in oil and gas development areas.
Property, plant and equipment are not revalued for financial reporting purposes.
Expenditures on upgrading, revamping and reconversion are recognized as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary for running the business.
Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. Property, plant and equipment are depreciated on a systematic basis over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company.
When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life if it is significant and can be reasonably determined. Changes in the asset's useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, are accounted for prospectively.
Replacement costs of identifiable parts in complex assets are capitalized and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Non-removable leasehold improvements are depreciated over the earlier of the useful life of the improvements and the lease term. Expenditures for ordinary maintenance and repairs, other than replacements of identifiable components, which reintegrate, and do not increase the performance of the assets, are recognized as an expense as incurred.
The carrying amount of property, plant and equipment is derecognized on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognized in the profit and loss account.
Leases 11
A contract is, or contains, a lease, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration; such right exists whether, throughout the period of use, the customer has both the right to obtain substantially all of the economic benefits from use of the identified asset and the right to direct the use of the identified asset.
At the commencement date of the lease (i.e. the date on which the underlying asset is available for use), a lessee recognizes on the balance sheet an asset representing its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability representing its obligation to make lease payments during the lease term (hereinafter also referred as lease liability). 12 The lease term is the non-cancellable period of a contract, together with, if reasonably certain, periods covered by extension options or by the non-exercise of termination options.
In particular, the lease liability is initially recognized at the present value of the following lease payments 13 that are not paid at the commencement date: (i) fixed payments (including in-substance fixed payments), less any lease incentives receivable; (ii) variable lease payments that on an index or a rate 14 ; (iii) amounts expected to be payable by the lessee under residual value guarantees; (iv) the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and (v) payments of penalties for terminating the lease, if the lease term reflects the lessee exercising an option to terminate the lease. The lease payments are discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the lessee’s incremental borrowing rate. The latter is determined considering the term of the lease, the frequency and currency of the contractual lease payments, as well as the features of the lessee’s economic environment (reflected in the country risk premium assigned to each country where Eni operates).
After the initial recognition, the lease liability is measured on an amortized cost basis and is remeasured, normally, as an adjustment to the carrying amount of the related right-of-use asset, to reflect changes to the lease payments due, essentially, to: (i) modifications in the lease contract not accounted as a separate lease; (ii) changes in indexes or rates (used to determine the variable lease payments); or (iii) changes in the assessment of contractual options (e.g. options to purchase the underlying asset, extension or termination options).
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11 This accounting policy does not apply to leases to explore for and extract resources such as those for oil and gas rights, leases of land and any rights of way related to oil and gas activities.
12 Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognizing the lease payments associated with those leases as an expense on a straight-line basis over the lease term.
13 Eni does not separate non-lease components from lease components except for main contracts related to upstream activities (drilling rigs), which provide for single payments relating to both lease and non-lease components.
14 Conversely, the other kinds of variable lease payments (payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability but are recognized in the profit and loss account as operating expenses over the lease term.
F-17
The right-of-use asset is initially measured as the sum of: (i) the amount of the initial measurement of the lease liability; (ii) any initial direct costs incurred by the lessee 15 ; (iii) any lease payments made at or before the commencement date, less any lease incentives received; and (iv) an estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease. After the initial recognition, the right-of-use asset is adjusted for any accumulated depreciation 16 , any accumulated impairment losses (see the accounting policy for “Impairment of non-financial assets”) and any remeasurement of the lease liability.
The depreciation charges of the right-of-use asset and the interest expenses on the lease liability directly attributable to the construction of an asset are capitalized as part of the cost of such asset and subsequently recognized in the profit and loss account through depreciation/impairments or write-off, mainly in the case of exploration assets.
In the oil and gas activities, the operator of an unincorporated joint operation which enters into a lease contract as the sole signatory recognizes on the balance sheet: (i) the entire lease liability if, based on the contractual provisions and any other relevant facts and circumstances, it has primary responsibility for the liability towards the third-party supplier; and (ii) the entire right-of-use asset, unless, on the basis of the terms and conditions of the contract, there is a sublease with the followers.
The followers’ share of the right-of-use asset, recognized by the operator, will be recovered according to the joint operation’s contractual arrangements by billing the project costs attributable to the followers and collecting the related cash calls. Costs recovered from the followers are recognized as “Other income and revenues” in the profit and loss account and as net cash provided by operating activities in the statement of cash flows.
Differently, if a lease contract is signed by all the partners, Eni recognizes its share of the right-of-use asset and lease liability on the balance sheet based on its working interest.
If Eni does not have primary responsibility for the lease liability and, on the basis of the terms and conditions of the contract, there is not a sublease, it does not recognize any right-of-use asset and lease liability related to the lease contract.
When lease contracts are entered into by companies other than subsidiaries that act as operators on behalf of the other participating companies (the so-called operating companies), consistent with the provision to recover from the followers the costs related to the oil and gas activities, the participating companies recognize their share of the right-of-use assets and the lease liabilities based on their working interest, defined according to the expected use, to the extent that it is reliably determinable, of the underlying assets.
Significant accounting estimates and judgments: lease transactions
With reference to lease contracts, management makes significant estimates and judgments related to: (i) determining the lease term, considering all facts and circumstances that generate an economic incentive, or not, to exercise any extension and/or termination options; (ii) determining the lessee’s incremental borrowing rate; (iii) identifying and, where appropriate, separating non-lease components from lease components, where an observable stand-alone price is not readily available, taking into account also the analysis performed with external experts; (iv) recognizing lease contracts, for which the underlying assets are used in oil and gas activities (mainly drilling rigs and FPSOs), entered into as operator within an unincorporated joint operation, considering if the operator has primary responsibility for the liability towards the third-party supplier and the relationships with the followers; (v) identifying the variable lease payments and the related characteristics in order to include them in the measurement of the lease liability.
Intangible assets
Intangible assets are identifiable non-monetary assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill. An asset is classified as intangible when management is able to distinguish it clearly from goodwill.
Intangible assets are initially recognized at cost as determined by the criteria described in the accounting policy for “Property, plant and equipment” and they are never revalued for financial reporting purposes.
Intangible assets with finite useful lives are amortized on a systematic basis over their useful life; the amortization is carried out in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.
Goodwill and intangible assets with indefinite useful lives are not amortized. For the recoverability of the carrying amounts of goodwill and other intangible assets see the accounting policy for “Impairment of non-financial assets”.
Costs of obtaining a contract with a customer are recognized on the balance sheet if the Company expects to recover those costs. The carrying value of the intangible asset arising from those costs is amortized on a systematic basis, that is consistent with the transfer to the customer of the goods or services to which the asset relates, and is tested for impairment.
Costs of technological development activities, including development costs related to CCS Projects (Carbon, Capture and Storage) incurred before the construction of the physical infrastructure, are capitalized when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits.
The carrying amount of intangible assets is derecognized on disposal or when no future economic benefits are expected from its use or disposal; any arising gain or loss is recognized in the profit and loss account.
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15 Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained.
16 Depreciation charges are recognized on a systematic basis from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee by the end of the lease term, or if the cost of the right-of-use asset reflects that the lessee will exercise a purchase option, the right-of-use asset is depreciated from the commencement date to the end of the useful life of the underlying asset.
F-18
Impairment of non-financial assets
Non-financial assets (tangible assets, intangible assets and right-of-use assets) are tested for impairment whenever events or changes in circumstances indicate that the carrying amounts for those assets may not be recoverable.
The recoverability assessment is performed for each cash-generating unit (hereinafter also CGU) represented by the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or group of assets.
CGUs may include corporate assets which do not generate cash inflows independently of other assets or group of assets but which contribute to the future cash flows of more CGUs; the portions of corporate assets are allocated to a specific CGU or, if not possible, to a group of CGUs on a reasonable and consistent basis. Goodwill is tested for impairment at least annually, and whenever there is any indication of impairment, at the lowest level within the entity at which it is monitored for internal management purposes. Right-of-use assets, which generally do not generate cash inflows independently of other assets or groups of assets, are allocated to the CGU to which they belong; the right-of-use assets which cannot be fully attributed to a CGU are considered as corporate assets. The recoverability of the carrying amount of common facilities within the E&P operating segment is assessed by considering the set of recoverable amounts of the CGUs benefiting from the common facility.
The recoverability of a CGU is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the CGU’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the CGU and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal.
The value in use of CGUs which include material right-of-use assets is calculated, normally, by ignoring lease payments included in the measurement of the lease liabilities.
For impairment test purposes, cash outflows expected to be incurred to guarantee compliance with laws and regulations regarding CO 2 emissions (e.g. Emission Trading Scheme) or on a voluntary basis (e.g. cash outflows related to forestry certificates acquired or produced consistent with the Company’s decarbonization strategy – hereinafter also forestry) are taken into account.
In particular, in estimating value in use, the cash outflows for forestry projects 17 are included, consistent with the targets of the decarbonization strategy, within the expected operating cash outflows; in this regard, considering that the forestry projects can be developed in countries where Eni does not carry out operating activities and given the difficulty to allocate such cash outflows, on a reasonable and consistent basis, to CGUs of the relevant operating segment, the related discounted cash outflows are treated as a reduction of the headroom of the E&P operating segment.
For the determination of value in use, the estimated future cash flows are discounted using a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the estimated future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the CGU. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segment/business where the asset operates. In particular, for the assets belonging to the Global Gas & LNG Portfolio (GGP) operating segment, the Chemical business, the Biochemistry business, the Power business, E-Mobility, Retail Domestic and Renewable businesses, Fuel Sales, Biomethane and Green Refinery businesses, the Agri-Feedstock business, the CCUS business and Eni Rewind business, the riskiness is determined on the basis of a sample of comparable companies. For the E&P operating segment and REVT (Refining Evolution and Transformation) business, the riskiness is determined, on a residual basis, as the difference between the risk of Eni as a whole and the risk of other operating segments/business. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate derived, through an iteration process, from a post-tax valuation.
When the carrying amount of the CGU, including goodwill allocated thereto, determined taking into account any impairment loss of the non-current assets belonging to the CGU, exceeds its recoverable amount, the excess is recognized as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the CGU, up to the related recoverable amount.
When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account. The impairment reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. An impairment loss recognized for goodwill is not reversed in a subsequent period. 18
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17 For the recognition criteria of forestry certificates see the accounting policy for “Costs”.
18 Impairment losses recognized for goodwill in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized.
F-19
Grants related to assets
Government grants related to assets are recognized by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received.
Inventories
Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realizable value. Net realizable value is 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, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual selling price. Inventories which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell and any subsequent changes in fair value are recognized in the profit and loss account. Materials and other supplies held for use in production are not written down below cost if the finished products in which they will be incorporated are expected to be sold at or above cost.
The cost of inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted average cost method on a three-month basis, or on a different time period (e.g. monthly), when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost of inventories of the Chemical business is determined by applying the weighted average cost on an annual basis.
When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations are measured using the pricing formulas contractually defined. They are recognized within “Other assets” as “Deferred costs”, as a contra to “Trade and other payables” or, after settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn, the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, determined adopting the same criteria described for inventories.
Significant accounting estimates and judgments: impairment of non-financial assets
The assessment of the recoverability of non-financial assets depends on management estimates on highly uncertain and complex matters such as future commodity prices, future discount rates, future development costs and production costs, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply-and-demand conditions also with reference to the decarbonization process and the effects of changes in regulatory requirements. The definition of CGUs and the identification of their appropriate grouping for the purpose of testing for impairment the carrying amount of goodwill, corporate assets as well as common facilities within the E&P operating segment, require judgment by management. In particular, CGUs are identified considering, inter alia, how management monitors the entity’s operations (such as by business lines) or how management makes decisions about continuing or disposing of the entity’s assets and operations.
Similar remarks are valid for assessing the physical recoverability of assets recognized on the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses.
The definition of the expected future cash flows used for impairment analyses is based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review. With reference to commodity prices, management assumes the price scenario adopted for economic-financial projections and for the evaluation of investments over their entire life. The price scenario is approved by the Board of Directors (see point ‘Significant accounting estimates and judgments made in assessing the impacts of climate-related risks’). Moreover, the estimate of expected future cash flows, taking into consideration the current and the expected decarbonization trends, is performed taking into account: (i) the evolution of the future energy system, (ii) the fundamentals of the various energy markets, as well as (iii) the constant benchmarking with the views of market analysts and other specialized institutions.
For oil and natural gas properties, the expected future cash flows are estimated based on proved and probable reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. In limited cases (e.g. for mineral interests acquired from third parties as part of a business combination) the expected cash flows may take into account also the risk-adjusted possible reserves, if they are considered to determine the consideration transferred.
The estimate of the future rates of production is based on assumptions related to future commodity prices, operating costs, lifting and development costs, field decline rates and other factors.
More details on the main assumptions underlying the determination of the recoverable amount of non-financial assets are set out in note 15 – Reversals (Impairments) of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.
F-20
Financial instruments
Financial assets
Financial assets held by the Group are classified, on the basis of both contractual cash flow characteristics and the entity’s business model for managing them, in the following categories: (i) financial assets measured at amortized cost; and (ii) financial assets measured at fair value through profit or loss (hereinafter also FVTPL).
At initial recognition, a financial asset is measured at its fair value plus, in the case of a financial asset not at FVTPL, transaction costs that are directly attributable; at initial recognition, trade receivables that do not have a significant financing component are measured at their transaction price.
After initial recognition, financial assets whose contractual terms give rise to cash flows that are solely payments of principal and interest on the principal amount outstanding are measured at amortized cost if they are held within a business model whose objective is to hold financial assets in order to collect contractual cash flows (the so-called hold to collect business model). For financial assets measured at amortized cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses 19 (see the accounting policy for “Impairment of financial assets”) are recognized in the profit and loss account.
Financial assets represented by debt instruments that are not measured at amortized cost, are measured at FVTPL; financial assets held for trading, as well as the portfolios of financial assets managed and evaluated on a fair value basis, fall into this category. Interest income on such financial assets contributes to the related fair value measurement and is recognized in “Finance income (expense)”, within “Net finance income (expense) from financial assets at fair value through profit or loss”.
When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date.
Cash and cash equivalents
Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due, generally, up to three months, readily convertible to known amount of cash and subject to an insignificant risk of changes in value.
Impairment of financial assets
The expected credit loss model is adopted for the impairment of financial assets that are debt instruments but are not measured at FVTPL. 20
In particular, the expected credit losses are generally measured by multiplying: (i) the exposure to the counterparty’s credit risk net of any collateral held and other credit enhancements (Exposure At Default, EAD); (ii) the probability that the default of the counterparty occurs (Probability of Default, PD); and (iii) the percentage estimate of the exposure that will not be recovered in case of default (Loss Given Default, LGD), considering the past experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.).
With reference to trade and other receivables, Probabilities of Default of counterparties are determined by adopting the internal credit ratings already used for credit worthiness and are periodically reviewed using, inter alia, back-testing analyses; for government entities (e.g. National Oil Companies), the Probability of Default, represented essentially by the probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for the impairment review of non-financial assets.
For customers without internal credit ratings, the expected credit losses are measured by using a provision matrix, defined by grouping, where appropriate, receivables into adequate clusters to which apply expected loss rates defined on the basis of their historical credit loss experiences, adjusted, where appropriate, to take into account forward-looking information on credit risk of the counterparty or clusters of counterparties. 25
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19 Receivables and other financial assets measured at amortized cost are presented on the balance sheet net of their loss allowance.
20 The expected credit loss model is also adopted: (i) for issued financial guarantee contracts not measured at FVTPL; as well as (ii) for issued performance guarantees contracts. Expected credit losses recognized on issued guarantees are not material.
21 For credit exposures arising from intragroup transactions, the recovery rate is normally assumed equal to 100% taking into account, inter alia, the Group central treasury function which supports both financial and capital needs of subsidiaries.
F-21
Considering the characteristics of the reference markets, financial assets with more than
The financing receivables, granted to associates and joint ventures, for which settlement is neither planned nor likely to occur in the foreseeable future and which in substance form part of the entity’s net investment in these investees, are tested for impairment, first, on the basis of the expected credit loss model and, then, together with the carrying amount of the investment in the associate/joint venture, in accordance with the criteria indicated in the accounting policy for “The equity method of accounting”. In applying the expected credit loss model, any adjustments to the carrying amount of long-term interest that arise from applying the accounting policy for “The equity method of accounting” are not taken into account.
Significant accounting estimates and judgments: impairment of financial assets
Measuring impairment losses of financial assets requires management evaluation of complex and highly uncertain elements such as, for example, Probabilities of Default of counterparties, the assessment of any collateral or other credit enhancements, the expected exposure that will not be recovered in case of default, as well as the definition of customers’ clusters to be adopted.
Further details on the main assumptions underlying the measurement of expected credit losses of financial assets are provided in note 8 – Trade and other receivables.
Investments in equity instruments
Investments in equity instruments that are not held for trading are measured at fair value through other comprehensive income, without subsequent transfer of fair value changes to profit or loss on derecognition of these investments; conversely, dividends from these investments are recognized in the profit and loss account, within the line item “Income (Expense) from investments”, unless they clearly represent a recovery of part of the cost of the investment. In limited circumstances, an investment in equity instruments can be measured at cost if it is an appropriate estimate of fair value.
Financial liabilities
At initial recognition, financial liabilities, other than derivative financial instruments, are measured at their fair value, minus transaction costs that are directly attributable, and are subsequently measured at amortized cost.
The sustainability-linked bonds, i.e. financial liabilities featuring a potential increase in the related interest rate to reflect the borrower’s performance relative to certain sustainability targets (the so-called ESG metrics), are measured at amortized cost.
Generally, changes in the interest rate result in an update of the effective interest rate to be used for the recognition of interest expense.
The issue of a convertible bond into ordinary shares of the issuer (without substantial cash settlement option) determines the separate recognition of the components of the instrument represented by the debt component, measured at amortized cost, and by the conversion option, recognized in equity. Any eventually transaction costs are allocated proportionally between the financial liability and the equity instrument.
Significant judgments: financial liabilities
The Group’s companies can negotiate supplier finance arrangements (supply chain finance, payable finance, reverse factoring and similar agreements) with suppliers, to obtain extended payment terms, without the necessary and automatic involvement of a financial institution. In such cases, management judges whether or not payables towards suppliers have to be re-classified as financial liabilities from trade/investing activity payables. In order to make such judgment, management considers if the payment terms differ from the ones that are customary in the industry, any additional security is provided as part of the arrangement as well as any other facts and circumstances. The classification of a debt as financial determines: (i) upon reclassification/initial recognition of the liability, a non-monetary change with no impacts on the statement of cash flows; (ii) upon the settlement of the liability, the classification of the payment within net cash used in financing activities.
With reference to sustainability-linked bonds, management assesses whether the non-compliance with an ESG metric could adversely impact operations and, therefore, revenue generation and creditworthiness of the Company.
Derivative financial instruments and hedge accounting
Derivative financial instruments are assets and liabilities recognized and measured at their fair value.
F-22
With reference to the defined risk management objectives and strategy, the qualifying criteria for hedge accounting requires: (i) the existence of an economic relationship between the hedged item and the hedging instrument in order to offset the related value changes and the effects of counterparty credit risk do not dominate the economic relationship between the hedged item and the hedging instrument; and (ii) the definition of the relationship between the quantity of the hedged item and the quantity of the hedging instrument (the so-called hedge ratio) consistent with the entity’s risk management objectives, under a defined risk management strategy; the hedge ratio is adjusted, where appropriate, after taking into account any adequate rebalancing. A hedging relationship is discontinued prospectively, in its entirety or a part of it, when it no longer meets the risk management objectives on the basis of which it qualified for hedge accounting, it ceases to meet the other qualifying criteria or after rebalancing it.
When derivatives hedge the risk of changes in the fair value of the hedged items (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit or loss. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured.
When derivatives hedge the exposure to variability in cash flows of the hedged items (cash flow hedge, e.g. hedging the variability in the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the effective changes in the fair value of the derivatives are initially recognized in the equity reserve related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account.
If a hedged forecast transaction subsequently results in the recognition of a non-financial asset or a non-financial liability, the accumulated changes in fair value of hedging derivatives, recognized in equity, are included directly in the carrying amount of the hedged non-financial asset/liability (commonly referred to as a “basis adjustment”).
The changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognized in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognized in the profit and loss account line item “Other operating (expense) income”.
Derivatives embedded in financial assets are not accounted for separately; in such circumstances, the entire hybrid instrument is classified depending on the contractual cash flow characteristics of the financial instrument and the business model for managing it (see the accounting policy for “Financial assets”). Conversely, derivatives embedded in financial liabilities measured at amortized cost and/or non-financial assets are separated if the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract.
Eni assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows occurs.
Contracts to buy or sell commodities entered into and continued to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognized on an accrual basis (the so-called own use exemption).
Offsetting of financial assets and liabilities
Financial assets and liabilities are set off on the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realize the asset and settle the liability simultaneously).
Derecognition of financial assets and liabilities
Transferred financial assets are derecognized when the contractual rights to receive the cash flows from the financial assets expire or are transferred to another party. Financial liabilities are derecognized when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired.
Provisions, contingent liabilities and contingent assets
Provisions are recognized when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated.
The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties on the balance sheet date. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expected cash outflows determined taking into account the time value of money and the risks associated with the obligation. The change in provisions due to the passage of time is recognized within “Finance income (expense)” in the profit and loss account.
F-23
A provision for restructuring costs is recognized only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring.
Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognized in the same line item where the original provision was charged.
Contingent liabilities are: (i) possible obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent liabilities are not recognized in the financial statements but are disclosed.
Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not recognized in financial statements unless the realization of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements.
Decommissioning and restoration liabilities
Liabilities for decommissioning and restoration costs are recognized, together with a corresponding amount as part of the related property, plant and equipment, when the conditions indicated in the accounting policy for “Provisions, contingent liabilities and contingent assets” are met.
Such liabilities are reviewed regularly to take into account the changes in the expected costs to be incurred, contractual obligations, regulatory requirements and practices in force in the countries where the tangible assets are located.
The effects of any changes in the estimate of the liability are recognized generally as an adjustment to the carrying amount of the related property, plant and equipment; however, if the resulting decrease in the liability exceeds the carrying amount of the related asset, the excess is recognized in the profit and loss account.
Environmental liabilities
Environmental liabilities are recognized when the Group has a present obligation, legal or constructive, relating to environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. The liability is measured on the basis of the costs expected to be incurred in relation to the existing situation at the balance sheet date, considering virtually certain future developments in technology and legislation that are known.
Significant accounting estimates and judgments: decommissioning and restoration liabilities, environmental liabilities and other provisions
The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating the amount and the timing of the obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations.
Decommissioning and restoration provisions, recognized in the financial statements, include, essentially, the present value of the expected costs for decommissioning oil and natural gas facilities at the end of the economic lives of fields, well-plugging, abandonment and site restoration of the Exploration & Production operating segment.
Any decommissioning and restoration provisions associated with the other operating segments’ assets, given their indeterminate settlement dates, also considering the strategy to reconvert plants in order to produce low carbon products, are recognized when it is possible to make a reliable estimate of the discounted abandonment costs. In this regard, Eni performs periodic reviews for any changes in facts and circumstances that might require recognition of a decommissioning and restoration provision.
F-24
Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental liabilities are recognized when it becomes probable that an outflow of resources will be required to settle the obligation and such obligation can be reliably estimated. With reference to groundwater treatment plants, the enhancement of the know-how gained on water contamination trends, as well as the positions of the competent authorities, allows the definition of a predictive model for estimating the time horizon within which the operations of those plants will be terminated and, therefore, for estimating the cost of managing and monitoring them.
The reliable determinability is verified on the basis of the available information such as, for example, the approval or filing of the environmental projects to the relevant administrative authorities or the making of a commitment to the relevant administrative authorities, where supported by adequate estimates.
Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provisions already recognized, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.
Moreover, considering the significant time period covered by the environmental liabilities, further uncertainties associated with the estimate are related to the definition of: (i) the time-frame required to reduce contaminants; (ii) the future costs to be incurred for remediation activities; (iii) the discount and inflation rates.
In addition to environmental and decommissioning and restoration liabilities, Eni recognizes provisions primarily related to legal and trade proceedings. These provisions are estimated on the basis of complex managerial judgments.
Employee benefits
Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment.
Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. Under defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due.
The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits.
Net interest includes the interest cost on liabilities and interest income on plan assets. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognized in “Finance income (expense)”.
Remeasurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognized within the statement of comprehensive income. Remeasurements of the net defined benefit liability, recognized within other comprehensive income, are not reclassified subsequently to the profit and loss account.
Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of remeasurements are taken to profit and loss account in their entirety.
The liabilities for termination benefits are recognized at the earlier of the following dates: (a) when the entity can no longer withdraw the offer of those benefits; and (b) when the entity recognizes costs for a restructuring that involves the payment of termination benefits. Such liabilities are measured in accordance with the nature of the employee benefit. In particular, if the termination benefits are an enhancement to post-employment benefits, the related liability is measured in accordance with the requirements for post-employment benefits. Otherwise, liabilities for termination benefits are determined applying the requirements: (i) for short-term employee benefits, if the termination benefits are expected to be settled wholly before twelve months after the end of the annual reporting period in which the termination benefits are recognized; or (ii) for long-term benefits if the termination benefits are not expected to be settled wholly before twelve months after the end of the annual reporting period.
F-25
Share-based payments
The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistent with its actual remunerative nature ( Long-term share-based incentive plans for the managers of Eni and Employee Stock Ownership Plan ).
With reference to Long-term share-based incentive plans for the managers of Eni, the cost of the share-based incentive plan is measured by reference to the fair value of the equity instruments granted and the estimate of the number of shares that eventually vest; the cost is recognized on an accrual basis pro rata temporis over the vesting period, that is the period between the grant date and the settlement date. The fair value of the shares underlying the incentive plan is measured at the grant date, taking into account the estimate of achievement of market conditions (e.g. Total Shareholder Return), and is not adjusted in subsequent periods; when the achievement is linked also to non-market conditions, the number of shares expected to vest is adjusted during the vesting period to reflect the updated estimate of these conditions. If, at the end of the vesting period, the incentive plan does not vest because of failure to satisfy the performance conditions, the portion of cost related to market conditions is not reversed to the profit and loss account.
A similar accounting treatment is adopted with reference to the Employee Stock Ownership Plan, whose cost is determined on the basis of the fair value of shares at the grant date, it is allocated over the period of time (three years) required for the employee to acquire full ownership and availability of the shares granted.
Significant accounting estimates and judgments: employee benefits and share-based payments
Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates are based on the market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds) and on the expected inflation rates in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization, changes in health status of the participants and the contributions paid to health funds; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved.
The amount of the net defined benefit liability (asset), changes according to the remeasurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Similar to the approach followed for the fair value measurement of financial instruments, the fair value of the shares underlying the incentive plans is measured by using complex valuation techniques and identifying, through structured judgments, the assumptions to be adopted.
Further details on the share-based incentives plans for managers are provided in note 30 – Costs.
Equity instruments
Treasury shares
Treasury shares, including shares held to meet the future requirements of the share-based incentive plans and the Employee Stock Ownership Plan, are recognized as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognized in equity.
Hybrid bonds
The perpetual subordinated hybrid bonds are classified in the financial statements as equity instruments considering that the issuer has the unconditional right to defer, until the date of its own liquidation, the repayment of the principal amount and the payment of accrued interest 22 . Therefore, the issuer recognizes the cash received from the bondholders, net of costs incurred in issuing the hybrid bonds, as an increase in Eni owners’ equity; differently, the repayments of the principal amount and the payments of accrued interest (upon the arising of the related contractual payment obligation) are accounted for as a decrease in Eni owners’ equity.
Revenue from contracts with customers
Revenue from contracts with customers is recognized when the related performance obligation is satisfied, that is when a promised good or service is transferred to a customer. A promised good or service is transferred when (or as) the customer obtains control of it. Control can be transferred over time or at a point in time. With reference to the most important products sold by Eni, revenue is generally recognized for:
crude oil, upon shipment;
natural gas, LNG and electricity, upon delivery to the customer;
petroleum products sold to retail distribution networks, upon delivery to the service stations, whereas all other sales of petroleum products are recognized upon shipment; and
chemical products and other products, upon shipment.
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|
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22 The payment of accrued interest is required upon the occurrence of events under the issuer’s control such as, for example, a distribution of dividends to shareholders.
F-26
Revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers is recognized on the basis of the quantities actually lifted and sold (sales method); costs are recognized on the basis of the quantities actually sold.
Revenue is measured at the fair value of the consideration to which the Company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third parties. If the consideration promised in a contract includes a variable amount, the Company estimates the amount of consideration to which it will be entitled in exchange for transferring the promised goods and/or services to a customer; in particular, the amount of consideration can vary because of discounts, refunds, incentives, price concessions, performance bonuses, penalties or if the price is contingent on the occurrence or non-occurrence of future events.
If, in a contract, the Company grants a customer the option to acquire additional goods or services for free or at a discount (e.g. sales incentives, customer award points, etc.), this option gives rise to a separate performance obligation in the contract only if the option provides a material right to the customer that it would not receive without entering into that contract. When goods or services are exchanged for goods or services which are of a similar nature and value, the exchange is not regarded as a transaction which generates revenue.
Significant accounting estimates and judgments: revenue from contracts with customers
Revenue from sales of electricity and gas to retail customers includes the amount accrued for electricity and gas supplied between the date of the last invoiced meter reading (actual or estimated) of volumes consumed and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as internal estimates about volumes consumed by customers. Therefore, revenue is accrued as a result of a complex estimate based on the volumes distributed and allocated, communicated by third parties, likely to be adjusted, according to applicable regulations, within the fifth year following the one in which they are accrued, as well as on estimates about volumes consumed by customers. Considering the contractual obligations on the supply delivery points, revenue from sales of electricity and gas to retail customers includes costs for transportation and dispatching and in these cases the gross amount of consideration to which the Company is entitled is recognized.
Costs
Costs are recognized when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) and determined on the basis of market prices, are recognized in relation to the amounts of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights that exceed the amount necessary to meet regulatory obligations are recognized as intangible assets. Revenue related to emission quotas is recognized when they are sold. Emission rights held for trading are recognized within inventories. The costs incurred on a voluntary basis for the acquisition or production of forestry certificates, also taking into account the absence of an active market, are recognized in the profit and loss account when incurred.
The costs incurred for scientific research activities or technological development, which cannot be recognized (see also the accounting policy for “Intangible assets”), are included in the profit and loss account when they are incurred.
Exchange differences
Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognized. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realizable value are retranslated using the exchange rate at the date when the value is determined.
Dividends
Dividends are recognized when the right to receive payment of the dividend is established.
Dividends and interim dividends to owners are shown as changes in equity when the dividends are declared by, respectively, the shareholders’ meeting and the Board of Directors.
F-27
Income taxes
Current income taxes are determined on the basis of estimated taxable profit. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using the tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period.
Deferred tax assets and liabilities are recognized for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets are recognized when their recoverability is considered probable, i.e. when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognized to the extent that their recoverability is probable. The carrying amount of the deferred tax assets is reviewed, at least, on an annual basis.
Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognized if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.
If there is uncertainty over income tax treatments, if the company: (i) concludes it is probable that the taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognized in the financial statements consistent with the tax treatment used or planned to be used in its income tax filings; (ii) concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognized in the financial statements.
Deferred tax assets and liabilities are presented within non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognized in the line item “Deferred tax assets” and, if negative, in the line item “Deferred tax liabilities”.
When the results of transactions are recognized in other comprehensive income or directly in equity, the related current and deferred taxes are also recognized in other comprehensive income or directly in equity.
Significant accounting estimates and judgments: income taxes
The computation of income taxes involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. Although Eni aims to maintain a relationship with the taxation authorities characterized by transparency, dialogue and cooperation (e.g. by not using aggressive tax planning and by using, if available, procedures intended to eliminate or reduce tax litigations), there can be no assurance that there will not be a tax litigation with the taxation authorities where the legislation could be open to more than one interpretation. The resolution of tax disputes, through negotiations with relevant taxation authorities or through litigation, could take several years to complete. The estimate of liabilities related to uncertain tax treatments requires complex judgments by management. After the initial recognition, these liabilities are periodically reviewed for any changes in facts and circumstances.
Moreover, management makes complex judgments regarding mainly the assessment of the recoverability of deferred tax assets, related both to deductible temporary differences and unused tax losses, which requires estimates and evaluations about the amount and the timing of future taxable profits.
Assets held for sale and discontinued operations
Non-current assets and current and non-current assets included within disposal groups are classified as held for sale if their carrying amounts will be recovered principally through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or the disposal group is available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale.
Immediately before the initial classification of a non-current asset and/or a disposal group as held for sale, the non-current asset and/or the assets and liabilities in the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated or amortized and they are measured at the lower of the fair value less costs to sell and their carrying amount.
If an equity-accounted investment, or a portion of that investment meets the criteria to be classified as held for sale, it is no longer accounted for using the equity method.
F-28
Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale. Non-current assets classified as held for sale and disposal groups are considered a discontinued operation if they, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognized on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements.
If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortization, impairment losses and reversals that would have been recognized had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell.
Fair value measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement date (exit price).
Assets and liabilities measured at fair value are categorized into the fair value hierarchy which is defined on the basis of the significance of the inputs used to measure fair value. In particular, on the basis of the features of the inputs used in the measurement, the fair value hierarchy provides for the following levels:
a) Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;
b) Level 2: measurement based on inputs, other than quoted prices included within the previous point, that are observable for the asset or liability under measurement, either directly or indirectly;
c) Level 3: unobservable inputs for the asset or liability.
Significant accounting estimates and judgments: fair value
Fair value measurement, although based on the best available information and on the use of appropriate valuation techniques, is inherently uncertain, requires the use of professional judgment and could result in expected values other than the actual ones.
2 Primary financial statements
The primary financial statements are the same of the ones used in the previous reporting period.
F-29
3 Changes in accounting policies
The amendments to IFRSs, effective from January 1, 2024, did not have a material impact on the Consolidated Financial Statements.
4 IFRSs not yet effective
On August 15, 2023, the IASB issued the amendments to IAS 21 “The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability” aimed, substantially, to require the estimate of a spot exchange rate when a currency is not exchangeable into another currency. The amendments are effective for annual reporting periods beginning on or after January 1, 2025.
On April 9, 2024, the IASB issued IFRS 18 “Presentation and Disclosure in Financial Statements,” which replaces IAS 1. In particular, IFRS 18, in order to increase comparability and transparency of information: (i) requires the presentation of defined subtotals within the profit and loss account and introduces limited changes, essentially, to the statement of cash flows and to the balance sheet; (ii) introduces specific disclosure requirements about management-defined performance measures; and (iii) introduces new criteria for aggregation and disaggregation of information presented in the primary financial statements and disclosed in the notes. IFRS 18 shall be applied for annual reporting periods beginning on or after January 1, 2027.
On May 9, 2024, the IASB issued IFRS 19 “Subsidiaries without Public Accountability: Disclosures”, aimed to reduce disclosures requirements for the preparation of the separate (and, if applicable, consolidated) financial statements of companies (that are neither listed nor financial institutions) controlled, directly or indirectly, by a parent that produces consolidated financial statements that are available for public use and that comply with IFRSs. IFRS 19 shall be applied for annual reporting periods beginning on or after January 1, 2027.
On May 30, 2024, the IASB issued the amendments to IFRS 9 and IFRS 7 “Classification and Measurement of Financial Instruments” aimed, essentially, to clarify the timing of derecognition of financial liabilities settled through electronic payment systems and to provide clarifications about the classification of financial assets with environmental, social and governance features (for example, sustainability bonds). The amendments shall be applied for annual reporting periods beginning on or after January 1, 2026.
On July 18, 2024, the IASB issued the document “Annual Improvements to IFRS Standards – Volume 11”, which include, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2026.
On December 18, 2024 the IASB issued the amendments to IFRS 9 and IFRS 7 “Contracts Referencing Nature dependent Electricity” aimed essentially at: (i) clarifying the use of the “own-use exemption” for power purchase agreements from renewable sources; and (ii) allowing, subject to certain conditions being met, the designation of a cash flow hedge in the presence of contracts for the purchase or sale of electricity from renewable sources (settable on a net basis). The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2026.
Eni is currently reviewing the IFRSs not yet effective in order to determine the likely impact on the Consolidated Financial Statements.
F-30
5 Business combinations and other significant transactions
Acquisitions
In 2024, Eni closed several business combinations acquiring the control of third-party companies with an outlay of €
Exploration & Production
On January 31, 2024, Eni closed the
Plenitude
In 2024, Plenitude finalized minor acquisitions primarily in Spain for a total outlay of €
Enilive
On May 31, 2024, Eni finalized the
Information about the definitive purchase price allocation of business combinations made in 2023 is provided in note 27 ‐ Other Information.
F-31
Balance sheet values at the acquisition date of the business combinations realized in 2024 are shown in the following table:
|
(€ million) |
Exploration & Production - Neptune Energy Group |
Plenitude - Renewables and Retail |
Enilive - Atenoil |
Total |
|
Cash and cash equivalents |
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|
|
|
|
Current financial assets |
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|
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Other current assets |
|
|
|
|
|
Current assets |
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
Deferred tax assets |
|
|
|
|
|
Other non-current assets |
|
|
|
|
|
Non-current assets |
|
|
|
|
|
TOTAL ASSETS |
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|
|
|
Current financial liabilities |
|
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|
|
|
Other current liabilities |
|
|
|
|
|
Current liabilities |
|
|
|
|
|
Non-current financial liabilities |
|
|
|
|
|
Provisions |
|
|
|
|
|
Deferred tax liabilities |
|
|
|
|
|
Other non-current liabilities |
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
TOTAL LIABILITIES |
|
|
|
|
|
TOTAL NET ACQUISITIONS |
|
|
|
|
|
Goodwill |
|
|
|
|
|
Fair value of investments held before the acquisition of control |
|
(
|
|
(
|
|
Non-controlling interest |
|
(
|
|
(
|
|
TOTAL CASH CONSIDERATION OF THE TRANSACTION |
|
|
|
|
The acquisitions in 2024 contributed for €
Divestments
In 2024, Eni divested certain non-strategic oil assets as part of a portfolio analysis resulting in a review of its spending priorities reducing its commitments in development phases of long-lived assets and refocusing on core projects in line the Group’s financial framework of capital discipline, as well as the strategy of creating financially independent entities, geographically focused, aggregating its activities with those of other operators for maximizing synergies and cash generation opportunities. Divestments and transfers of business combination brought in cash proceeds of €
Exploration & Production
On August 22, 2024, Eni finalized the sale onshore oil & gas assets in Nigeria classified as held for sale in the 2023 financial statements. The transaction resulted in the sale of its wholly owned subsidiary Nigerian Agip Oil Co Ltd and the consequent exclusion from the scope of consolidation of net assets and liabilities for €
On October 3, 2024, Eni finalized th
e business combination with Ithaca Energy Plc of substantially all of its upstream assets in the UK. The combination was settled through the issue to Eni UK of such number of new ordinary shares representing approximately
Refining
On September 3, 2024, Eni finalized the
F-32
Balance sheet values of the divestments and/or business combinations realized in 2024 are shown in the following table:
|
(€ million) |
Exploration & Production - Nigerian Agip Oil Co Ltd |
Exploration & Production - Business combination Ithaca Energy Plc |
Refining - Eni Ecuador SA |
Total |
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Cash and cash equivalents |
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|
|
|
|
Other current assets |
|
|
|
|
|
Current assets |
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
Deferred tax assets |
|
|
|
|
|
Other non-current assets |
|
|
|
|
|
Non-current assets |
|
|
|
|
|
TOTAL ASSETS |
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|
|
Current financial liabilities |
|
|
|
|
|
Other current liabilities |
|
|
|
|
|
Current liabilities |
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|
|
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|
Non-current financial liabilities |
|
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|
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Other non-current liabilities |
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
TOTAL LIABILITIES |
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|
Equity attributable to Eni |
|
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TOTAL EQUITY |
|
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TOTAL LIABILITIES AND EQUITY |
|
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|
|
6 Cash and cash equivalents
Cash and cash equivalents of €
Expected credit losses on deposits with banks and financial institutions measured at amortized cost were immaterial.
Cash and cash equivalents mainly consisted of deposits in U.S. dollars for €
Restricted cash amounted to €
The average maturity of financial assets originally due within 3 months was
7 Financial assets at fair value through profit or loss
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Bonds issued by sovereign states |
|
|
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Other |
|
|
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Financial assets held for trading |
|
|
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Other financial assets at fair value through profit or loss |
|
|
|
Total financial assets at fair value through profit or loss |
|
|
The Company has established a liquidity reserve as part of its financial framework with a view of ensuring an adequate level of flexibility to the Group development plans and of copying with unexpected fund shortfalls or a sudden phase of credit crunch and restrictions in accessing financial markets. The management of this liquidity reserve is performed through trading activities with the aim of optimizing returns, within a predefined and authorized level of risk threshold, targeting the preservation of the invested capital and the ability to promptly convert it into cash.
F-33
Financial assets held for trading include securities subject to lending agreements of €
The breakdown by currency is provided below:
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Euro |
|
|
|
U.S. dollars |
|
|
|
Financial assets held for trading |
|
|
|
Euro |
|
|
|
U.S. dollars |
|
|
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Other financial assets at fair value through profit or loss |
|
|
|
|
|
|
The breakdown by issuing entity and credit rating is presented below:
|
|
Nominal value (€ million) |
Fair Value (€ million) |
Rating - Moody's |
Rating - S&P |
|
Quoted bonds issued by sovereign states |
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Fixed rate bonds |
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|
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|
|
Italy |
|
|
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|
|
United States of America |
|
|
|
|
|
Chile |
|
|
|
|
|
France |
|
|
|
|
|
Other (*) |
|
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|
|
|
|
|
|
|
|
Floating rate bonds |
|
|
|
|
|
Italy |
|
|
|
|
|
|
|
|
|
|
|
Total quoted bonds issued by sovereign states |
|
|
|
|
|
|
|
|
|
|
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Other Bonds |
|
|
|
|
|
Fixed rate bonds |
|
|
|
|
|
Quoted bonds issued by industrial companies |
|
|
|
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|
Quoted bonds issued by financial and insurance companies |
|
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Other bonds |
|
|
|
|
|
|
|
|
|
|
|
Floating rate bonds |
|
|
|
|
|
Quoted bonds issued by industrial companies |
|
|
|
|
|
Quoted bonds issued by financial and insurance companies |
|
|
|
|
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Other bonds |
|
|
|
|
|
|
|
|
|
|
|
Total other bonds |
|
|
|
|
|
|
|
|
|
|
|
Total financial assets held for trading |
|
|
|
|
|
|
|
|
|
|
|
Other financial assets at fair value through profit or loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*) Amounts included herein are lower than €
Other financial assets at fair value through profit or loss consisted of investments in Money Market funds.
The fair value hierarchy is level 1 for €
F-34
8 Trade and other receivables
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Trade receivables |
|
|
|
Receivables from joint ventures in exploration and production activities |
|
|
|
Receivables from divestments |
|
|
|
Other receivables |
|
|
|
Total trade and other receivables, net of allowance for doubtful accounts |
|
|
Generally, trade receivables do not bear interest and provide payment terms within
The decrease in trade receivables of €
In both 2024 and 2023 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk. The amount of receivables, primarily current trade receivables, discounted in 2024 is in line with the previous financial year.
At the balance sheet date net trade receivables were outstanding for €
The increase in receivables from joint ventures in exploration and production activities of €
Receivables from other counterparties comprised: (i) the recoverable amount of €
Trade and other receivables stated in euro for €
F-35
Credit risk exposure and expected losses relating to trade and other receivables has been prepared on the basis of internal ratings as follows:
|
|
Performing receivables |
Defaulted receivables |
Plenitude customers |
Total |
||
|
(€ million) |
Low risk |
Medium risk |
High risk |
|||
|
December 31, 2024 |
|
|
|
|
|
|
|
Business customers |
|
|
|
|
|
|
|
National Oil Companies and Public Administrations |
|
|
|
|
|
|
|
Other counterparties |
|
|
|
|
|
|
|
Gross amount |
|
|
|
|
|
|
|
Allowance for doubtful accounts |
(
|
(
|
(
|
(
|
(
|
(
|
|
Net amount |
|
|
|
|
|
|
|
Expected loss (% net of counterpart risk mitigation factors) |
|
|
|
|
|
|
|
December 31, 2023 |
|
|
|
|
|
|
|
Business customers |
|
|
|
|
|
|
|
National Oil Companies and Public Administrations |
|
|
|
|
|
|
|
Other counterparties |
|
|
|
|
|
|
|
Gross amount |
|
|
|
|
|
|
|
Allowance for doubtful accounts |
(
|
(
|
(
|
(
|
(
|
(
|
|
Net amount |
|
|
|
|
|
|
|
Expected loss (% net of counterpart risk mitigation factors) |
|
|
|
|
|
|
The classification of the Company’s customers and counterparties and the definition of the classes of counterparty risk are disclosed in note 1 – Significant accounting policies, estimates and judgments.
Recoverability of trade receivables for the supply of hydrocarbons, products and power to retail, business customers and national oil companies and of receivables towards partners in joint ventures of the Exploration & Production segment for cash calls (national oil companies, local private operators or international oil companies) is reviewed periodically at the close of each financial year to adjust the assessment to the current economic environment and business trends, as well as by factoring any possible increase in the counterparty risks.
The exposure to credit risk and expected losses relating to customers of Plenitude was assessed based on a provision matrix as follows:
|
|
Not-past due |
Past due |
Total |
|||
|
(€ million) |
from 0 to 3 months |
from 3 to 6 months |
from 6 to 12 months |
over 12 months |
||
|
December 31, 2024 |
|
|
|
|
|
|
|
Plenitude customers: |
|
|
|
|
|
|
|
- Retail |
|
|
|
|
|
|
|
- Middle |
|
|
|
|
|
|
|
- Other |
|
|
|
|
|
|
|
Gross amount |
|
|
|
|
|
|
|
Allowance for doubtful accounts |
(
|
(
|
(
|
(
|
(
|
(
|
|
Net amount |
|
|
|
|
|
|
|
Expected loss (%) |
|
|
|
|
|
|
|
December 31, 2023 |
|
|
|
|
|
|
|
Plenitude customers: |
|
|
|
|
|
|
|
- Retail |
|
|
|
|
|
|
|
- Middle |
|
|
|
|
|
|
|
- Other |
|
|
|
|
|
|
|
Gross amount |
|
|
|
|
|
|
|
Allowance for doubtful accounts |
(
|
(
|
(
|
(
|
(
|
(
|
|
Net amount |
|
|
|
|
|
|
|
Expected loss (%) |
|
|
|
|
|
|
F-36
The following table analyses the allowance for doubtful accounts for trade and other receivables:
|
(€ million) |
2024 |
2023 |
|
Allowance for doubtful accounts - beginning of the year |
|
|
|
Additions for trade and other performing receivables |
|
|
|
Additions for trade and other defaulted receivables |
|
|
|
Utilizations for trade and other performing receivables |
(
|
(
|
|
Utilizations for trade and other defaulted receivables |
(
|
(
|
|
Other changes |
|
(
|
|
Allowance for doubtful accounts - end of the year |
|
|
The allowance for doubtful accounts was determined considering mitigation factors of the counterparty risk amounting to €
Additions to allowance for doubtful accounts for trade and other performing receivables related to the Plenitude business line for €
Additions to allowance for doubtful accounts for trade and other defaulted receivables related to: (i) the Exploration & Production segment for €
Utilizations of allowance for doubtful accounts for trade and other performing and defaulted receivables amounted to €
Net (impairments) reversals of trade and other receivables are disclosed as follows:
|
(€ million) |
2024 |
2023 |
2022 |
|
New provisions |
(
|
(
|
(
|
|
Net credit losses |
(
|
(
|
(
|
|
Reversals |
|
|
|
|
Net (impairments) reversals of trade and other receivables |
(
|
(
|
|
Receivables with related parties are disclosed in note 36 – Transactions with related parties.
F-37
9 Current and non-current inventories
Current inventories are disclosed as follows:
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Raw and auxiliary materials and consumables |
|
|
|
Components and spare parts for drilling operations, plans and equipment |
|
|
|
Semi-finished, finished products and goods |
|
|
|
Other |
|
|
|
Current inventories |
|
|
Raw and auxiliary materials and consumables included oil-based feedstock and other consumables pertaining to refining and chemical activities.
Components to be consumed in drilling activities and spare parts of the Exploration & Production segment amounted to €
Semi-finished, finished products and goods included natural gas and oil products for €
Inventories are stated net of write-down provisions of €
Non-current inventories of €
10 I ncome tax receivables and payables
|
|
December 31, 2024 |
December 31, 2023 |
||||||
|
(€ million) |
Receivables |
Payables |
Receivables |
Payables |
||||
|
|
Current |
Non-current |
Current |
Non-current |
Current |
Non-current |
Current |
Non-current |
|
Income taxes |
|
|
|
|
|
|
|
|
Income taxes are described in note 33 — Income taxes.
The opening balance of current income tax payables included €
Non-current income tax payables include the likely outcome of pending litigation with tax authorities in relation to uncertain tax matters relating to foreign subsidiaries of the Exploration & Production segment for €
11 Other assets and liabilities
|
|
December 31, 2024 |
December 31, 2023 |
||||||
|
|
Assets |
Liabilities |
Assets |
Liabilities |
||||
|
(€ million) |
Current |
Non-current |
Current |
Non-current |
Current |
Non-current |
Current |
Non-current |
|
Fair value of derivative financial instruments |
|
|
|
|
|
|
|
|
|
Contract liabilities |
|
|
|
|
|
|
|
|
|
Other Taxes |
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value related to derivative financial instruments is disclosed in note 24 – Derivative financial instruments and hedge accounting.
Assets related to other taxes included VAT for €
F-38
Other assets included: (i) tax credits current of €
Contract liabilities included: (i) advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system from Val d'Agri to the Taranto refinery for €
Revenues recognized during the year related to contract liabilities stated at December 31, 2024, are indicated in note 29 – Revenues and other income.
Liabilities related to other current taxes include excise duties and consumer taxes for €
Other liabilities included: (i) non-current payables to factoring companies connected with the derecognition of the abovementioned tax credit deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings for €
Transactions with related parties are described in note 36 — Transactions with related parties.
F-39
12 Property, plant and equipment
|
(€ million) |
Land and buildings |
E&P wells, plant and machinery |
Other plant and machinery |
E&P exploration assets and appraisal |
E&P tangible assets in progress |
Other tangible assets in progress and advances |
Total |
|
2024 |
|
|
|
|
|
|
|
|
Net carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Depreciation capitalized |
|
|
|
|
|
|
|
|
Depreciation (*) |
(
|
(
|
(
|
|
|
|
(
|
|
Impairments |
(
|
(
|
(
|
|
(
|
(
|
(
|
|
Reversals |
|
|
|
|
|
|
|
|
Write-off |
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Currency translation differences |
|
|
|
|
|
|
|
|
Initial recognition and changes in estimates |
|
|
|
(
|
|
(
|
|
|
Changes in the scope of consolidation - included entities |
|
|
|
|
|
|
|
|
Changes in the scope of consolidation - excluded entities |
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Transfers |
|
|
|
(
|
(
|
(
|
|
|
Other changes |
7 |
(
|
(
|
(
|
|
|
|
|
Net carrying amount - end of the year |
|
|
|
|
|
|
|
|
Gross carrying amount - end of the year |
|
|
|
|
|
|
|
|
Provisions for depreciation and impairments |
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
Net carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Depreciation capitalized |
|
|
|
|
|
|
|
|
Depreciation (*) |
(
|
(
|
(
|
|
|
|
(
|
|
Impairments |
(
|
(
|
(
|
|
(
|
(
|
(
|
|
Reversals |
|
|
|
|
|
|
|
|
Write-off |
|
|
(
|
(
|
(
|
|
(
|
|
Currency translation differences |
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Initial recognition and changes in estimates |
|
|
|
|
|
|
|
|
Changes in the scope of consolidation - included entities |
|
|
|
|
|
|
|
|
Changes in the scope of consolidation - excluded entities |
|
|
(
|
|
|
|
(
|
|
Transfers |
|
|
|
(
|
(
|
(
|
|
|
Other changes |
(
|
(
|
(
|
(
|
|
(
|
(
|
|
Net carrying amount - end of the year |
|
|
|
|
|
|
|
|
Gross carrying amount - end of the year |
|
|
|
|
|
|
|
|
Provisions for depreciation and impairments |
|
|
|
|
|
|
|
(*) Before capitalization of depreciation of tangible assets
Capital expenditures included capitalized finance expenses of €
Capital expenditures primarily related to the Exploration & Production segment for €
In 2024, the Group entered into supplier financing agreements to purchase plants and equipment mainly in the Exploration & Production segment, which were recognized as additions to assets and to financing payables in the line item “Other changes” to reflect deferred payments terms. The amount of purchased items under supplier financing agreements outstanding at year-end was €
Capital expenditures by industry segment and geographical area of destination are reported in note 35 – Segment information and information by geographical area.
Depreciation other than that of oil&gas assets, relating to biorefineries, petrochemical plants, thermoelectric plants, photovoltaic or wind power systems, and other ancillary assets are calculated on a straight-line basis, based on their economic-technical lives.
F-40
The main depreciation rates adopted are included in the following ranges and have remained unchanged compared to 2023:
|
(%) |
|
|
|
|
Buildings |
|
- |
|
|
Refining and chemical plants |
|
- |
|
|
Gas pipelines and compression stations |
|
- |
|
|
Power plants |
|
- |
|
|
Other plant and machinery |
|
- |
|
|
Industrial and commercial equipment |
|
- |
|
|
Other assets |
|
- |
|
Plant and equipment used in the extraction and treatment of hydrocarbons were depreciated according to the UOP method, where depreciation depends on production of the estimated proved reserves according to the US Securities & Exchange Commission “SEC” criteria (see note 1 – Accounting standards, accounting estimates and significant judgements, section UOP depreciation, depletion and amortisation). The production plans associated with the existing assets gradually deplete the SEC proved reserves recorded at the balance sheet date, which are expected to be produced within about ten years.
Impairment losses of property, plant and equipment mainly related: (i) to oil&gas properties for €
Currency translation differences related to subsidiaries utilizing the U.S. dollar as functional currency (€
Initial recognition and change in estimates include the increase in the asset retirement cost of tangible assets in the Exploration & Production segment due to the increase in abandonment cost estimates, start of new projects, partially offset by the increase in discount rates.
Changes in the scope of consolidation related to the acquisition for €
Changes in the scope of consolidation for €
Other changes included the disposal of oil and gas assets in Alaska for €
Transfers from E&P tangible assets in progress to E&P UOP wells, plant and equipment related for €
Exploration and appraisal activities included write-offs for €
Exploration and appraisal activities related for €
Changes relating to suspended wells are reported below:
|
(€ million) |
2024 |
2023 |
2022 |
|
Costs for exploratory wells suspended - beginning of the year |
|
|
|
|
Increases for which is ongoing the determination of proved reserves |
|
|
|
|
Amounts previously capitalized and expensed in the year |
(
|
(
|
(
|
|
Reclassification to successful exploratory wells following the estimation of proved reserves |
(
|
(
|
(
|
|
Disposals |
(
|
(
|
(
|
|
Changes in the scope of consolidation |
|
|
(
|
|
Currency translation differences |
|
(
|
|
|
Other changes |
|
(
|
|
|
Costs for exploratory wells suspended - end of the year |
|
|
|
F-41
The following information relates to the stratification of the suspended wells pending final determination (ageing):
|
|
2024 |
2023 |
2022 |
|||
|
|
(€ million) |
(number of wells in Eni’s interest) |
(€ million) |
(number of wells in Eni’s interest) |
(€ million) |
(number of wells in Eni’s interest) |
|
Costs capitalized and suspended for exploratory well activity |
|
|
|
|
|
|
|
- within 1 year |
|
|
|
|
|
|
|
- between 1 and 3 years |
|
|
|
|
|
|
|
- beyond 3 years |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs capitalized for suspended wells |
|
|
|
|
|
|
|
- fields including wells drilled over the last 12 months |
|
|
|
|
|
|
|
- fields for which the delineation campaign is in progress |
|
|
|
|
|
|
|
- fields including commercial discoveries that are progressing to a FID |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Suspended wells costs pending a final investment decision amounted to €
The capitalized costs for suspended wells relating to fields including wells drilled over the last twelve months referred to
Unproved mineral interests, comprised of assets in progress of the Exploration & Production segment, include the purchase price allocated to unproved reserves following business combinations or acquisition of individual properties.
Unproved mineral interests were as follows:
|
(€ million) |
Congo |
Nigeria |
Turkmenistan |
USA |
Algeria |
Egypt |
United Arab Emirates |
Italy |
Indonesia |
Netherlands |
Total |
|
2024 |
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
|
|
|
Net (impairments) reversals |
(
|
|
|
|
|
(
|
|
|
|
|
(
|
|
Reclassification to Proved Mineral Interest |
|
(
|
|
(
|
(
|
(
|
(
|
|
|
|
(
|
|
Currency translation differences and other changes |
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amount - end of the year |
|
|
|
|
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
|
|
|
Net (impairments) reversals |
|
|
(
|
|
|
|
|
|
|
|
|
|
Reclassification to Proved Mineral Interest |
|
(
|
|
|
(
|
(
|
(
|
|
|
|
(
|
|
Currency translation differences and other changes |
(
|
(
|
(
|
(
|
(
|
|
(
|
|
(
|
|
(
|
|
Carrying amount - end of the year |
|
|
|
|
|
|
|
|
|
|
|
F-42
Unproved mineral interests comprised the net book value of the Oil Prospecting License 245 property (“OPL 245”), offshore Nigeria, whose exploration period expired on May 11, 2021. The property book value included €
Accumulated provisions for impairments amounted to €
Property, plant and equipment includes assets subject to operating leases for €
As of December 31, 2024, Eni pledged property, plant and equipment for €
Government grants recorded as a decrease of property, plant and equipment amounted to €
Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 28 – Guarantees, commitments and risks – Liquidity risk.
Property, plant and equipment under concession arrangements are described in note 28 – Guarantees, commitments and risks.
F-43
13 Right-of-use assets and lease liabilities
|
(€ million) |
Floating production storage and offloading vessels (FPSO) |
Drilling rig |
Naval facilities and related logistic bases for oil and gas transportation |
Motorway concessions and service stations |
Oil and gas distribution facilities |
Office buildings |
Vehicles |
Other |
Total |
|
2024 |
|
|
|
|
|
|
|
|
|
|
Net carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
|
Depreciation (a) |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Impairments |
|
|
(
|
(
|
(
|
|
|
(
|
(
|
|
Currency translation differences |
|
|
|
(
|
|
|
|
|
|
|
Changes in the scope of consolidation |
|
|
|
|
|
|
|
(
|
|
|
Other changes |
|
(
|
(
|
|
(
|
(
|
(
|
(
|
(
|
|
Net carrying amount - end of the year |
|
|
|
|
|
|
|
|
|
|
Gross carrying amount - end of the year |
|
|
|
|
|
|
|
|
|
|
Provisions for depreciation and impairment |
|
|
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
Net carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
|
|
Depreciation (a) |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Impairments |
|
|
(
|
|
(
|
|
|
(
|
(
|
|
Reversals |
|
|
|
|
|
|
|
|
|
|
Currency translation differences |
(
|
(
|
(
|
|
|
(
|
|
(
|
(
|
|
Changes in the scope of consolidation |
|
|
|
|
|
|
|
|
|
|
Other changes |
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Net carrying amount - end of the year |
|
|
|
|
|
|
|
|
|
|
Gross carrying amount - end of the year |
|
|
|
|
|
|
|
|
|
|
Provisions for depreciation and impairment |
|
|
|
|
|
|
|
|
|
(a) Before capitalization of depreciation of tangible and intangible assets.
Right-of-use assets (RoU) of €
The increase recorded in 2024 mainly referred to: (i) the Exploration & Production segment for €
The main leasing contracts signed for which the asset is not yet available concern: (i) a contract with a nominal value of €
Main future cash outflows potentially due not reflected in the measurements of lease liabilities related to options for the extension or termination of leases existing as of December 31, 2024 of: (i) ancillary assets in the upstream business for €
F-44
Liabilities for leased assets were as follows:
|
(€ million) |
Current portion of long-term lease liabilities |
Long-term lease liabilities |
Total |
|
2024 |
|
|
|
|
Carrying amount at the beginning of the year |
|
|
|
|
Additions |
|
|
|
|
Decreases |
(
|
(
|
(
|
|
Currency translation differences |
|
|
|
|
Changes in the scope of consolidation |
|
|
|
|
Other changes |
|
(
|
(
|
|
Carrying amount at the end of the year |
|
|
|
|
2023 |
|
|
|
|
Carrying amount at the beginning of the year |
|
|
|
|
Additions |
|
|
|
|
Decreases |
(
|
(
|
(
|
|
Currency translation differences |
(
|
(
|
(
|
|
Changes in the scope of consolidation |
|
|
|
|
Other changes |
|
(
|
(
|
|
Carrying amount at the end of the year |
|
|
|
Lease liabilities related for €
Total cash outflows for leases consisted of the following: (i) cash payments for the principal portion of the lease liability for €
Lease liabilities stated in U.S. dollars for €
Other changes in right-of-use assets and lease liabilities essentially related to early termination or renegotiation of lease contracts.
Liabilities for leased assets with related parties are described in note 36 — Transactions with related parties.
The amounts recognised in the profit and loss account consist of the following:
|
(€ million) |
2024 |
2023 |
2022 |
|
Other income and revenues |
|
|
|
|
Income from remeasurement of lease liabilities |
|
|
|
|
|
|
|
|
|
Purchases, services and other |
|
|
|
|
Expense from remeasurement of lease liabilities |
|
|
|
|
Short-term leases |
|
|
|
|
Low-value leases |
|
|
|
|
Variable lease payments not included in the measurement of lease liabilities |
|
|
|
|
Capitalized direct cost associated with self-constructed assets - tangible assets |
(
|
(
|
(
|
|
|
|
|
|
|
Depreciation, net impairments and write-off |
|
|
|
|
Depreciation of RoU leased assets |
|
|
|
|
Capitalized direct cost associated with self-constructed assets - tangible and intangible assets |
(
|
(
|
(
|
|
Impairments of RoU leased assets |
|
|
|
|
Reversals of RoU leased assets |
(
|
(
|
(
|
|
Write-off of RoU leased assets |
|
|
|
|
|
|
|
|
|
Finance income (expense) from leases |
|
|
|
|
Interests on lease liabilities |
(
|
(
|
(
|
|
Capitalized finance expense of RoU leased assets - tangible assets |
|
|
|
|
Net currency translation differences on lease liabilities |
(
|
|
(
|
|
|
(
|
(
|
(
|
F-45
14 Intangible assets
|
(€ million) |
Exploration rights |
Industrial patents and intellectual property rights |
Other intangible assets with definite useful lives |
Intangible assets with definite useful lives |
Goodwill |
Other intangible assets with indefinite useful lives |
Total |
|
2024 |
|
|
|
|
|
|
|
|
Net carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Depreciation capitalized |
|
|
|
|
|
|
|
|
Amortization (*) |
(
|
(
|
(
|
(
|
|
|
(
|
|
Impairments |
(
|
|
(
|
(
|
(
|
|
(
|
|
Write-off |
(
|
|
(
|
(
|
|
|
(
|
|
Changes in the scope of consolidation |
|
|
|
|
|
|
|
|
Currency translation differences |
|
|
|
|
|
|
|
|
Other changes |
(
|
|
(
|
(
|
|
|
(
|
|
Net carrying amount - end of the year |
|
|
|
|
|
|
|
|
Gross carrying amount - end of the year |
|
|
|
|
|
|
|
|
Provisions for amortization and impairment |
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
Net carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Amortization |
(
|
(
|
(
|
(
|
|
|
(
|
|
Impairments |
(
|
|
(
|
(
|
(
|
|
(
|
|
Reversals |
|
|
|
|
|
|
|
|
Write-off |
(
|
|
(
|
(
|
|
|
(
|
|
Changes in the scope of consolidation |
|
|
|
|
|
|
|
|
Currency translation differences |
(
|
|
(
|
(
|
|
|
(
|
|
Other changes |
(
|
|
|
|
(
|
|
|
|
Net carrying amount - end of the year |
|
|
|
|
|
|
|
|
Gross carrying amount - end of the year |
|
|
|
|
|
|
|
|
Provisions for amortization and impairment |
|
|
|
|
|
|
|
(*) Before capitalization of depreciation.
Exploration rights comprised the residual book value of signature bonuses and acquisition costs of exploration licenses relating to areas with proved reserves, which are amortized based on UOP criteria and are regularly reviewed for impairment. The costs of licenses with unproved reserves are also in this item and are suspended pending a final determination of the success of the exploration activity or until management confirms its commitment to the initiative. Additions for the year related to signature bonuses paid for the acquisition of new exploration acreage in Ivory Coast.
The breakdown of exploration rights by type of asset was as follows:
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Proved licence and leasehold property acquisition costs |
|
|
|
Unproved licence and leasehold property acquisition costs |
|
|
|
|
|
|
Industrial patents and intellectual property rights mainly regarded the acquisition and internal development of software and rights for the use of production processes and software.
Write-offs of €
Changes in the scope of consolidation of assets with a finite useful life comprised: (i) €
F-46
Other intangible assets comprised: (i) concessions, licenses, trademarks and similar items for €
The main amortization rates used were substantially unchanged from the previous year and ranged as follows:
|
(%) |
|
|
|
|
Exploration rights |
|
||
|
Concessions, licenses, trademarks and similar items |
|
- |
|
|
Industrial patents and intellectual property rights |
|
- |
|
|
Capitalized costs for customer acquisition |
|
- |
|
|
Other intangible assets |
|
- |
|
Cumulative impairment charges of goodwill at the end of the year amounted to €
The breakdown of goodwill by segment and business line is provided below:
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Plenitude |
|
|
|
Enilive |
|
|
|
Chemical |
|
|
|
Others |
|
|
|
|
|
|
Changes in the scope of consolidation of goodwill related to: (i) the acquisition of a network of service stations in Spain for €
Contributions recorded as decrease of intangible assets amounted to €
Information about the allocations of goodwill deriving from business combinations is provided in note 5 – Business combinations and other significant transactions.
Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition.
The Plenitude business line is engaged in the retail sale of natural gas and electricity, in the electricity generation from renewable sources and in installing and managing a charging network for electric vehicles. Plenitude has closed several acquisitions in past reporting years leading to the recognition of significant amounts of goodwill in each of those activities.
Goodwill allocated to the activity of the retail sale of natural gas and electricity amounted to €
F-47
The impairment review of the CGU Retail including goodwill, was performed by comparing the carrying amount to the value in use of the CGU, which was estimated based on the cash flows of the four-year plan approved by management and on a terminal value calculated as the perpetuity of the cash flow of the last year of the plan by assuming a nominal long-term growth rate equal to
The renewable business of Plenitude included a goodwill of €
Goodwill of the electric mobility business of Plenitude of €
F-48
15 Reversals (Impairments) of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonisation scenarios
The recoverability test of carrying amounts of oil&gas cash generating units (CGUs) is the most important of the critical accounting estimates in the preparation of Eni’s consolidated financial statements. This owes to the relative weight of the invested capital in the sector on total consolidated assets.
Future expected cash flows associated with the use of oil&gas assets are based on management’s judgment and subjective assumptions about highly uncertain matters like future hydrocarbons prices, assets’ useful lives, projections of future operating and capital expenditures, the volumes of reserves that will ultimately be recovered and costs of decommissioning oil&gas assets at the end of their useful lives. Furthermore, the recoverability of carrying amounts is still pending on the management’s commitment at allocating funds to continue reserves development, and hence is subject to possible changes to capital allocation priorities. The hydrocarbon prices are forecasted based on management’s expectations about future trends in demands and supplies of hydrocarbons in the long-term, which incorporate assumptions on several scenario variables, including the rate of macroeconomic growth, evolution in consumers’ preferences, changes in governments’ regulatory and political framework in response to climate change and preservation of the ecosystem, the pace of the energy transition, the role of technologies, and finally production plans of public oil&gas companies and production policies of the OPEC+ alliance. Eni’s forecast prices are constantly benchmarked against the market view of investment banks and energy consultants.
Below are the main price assumptions for assessing the recoverability of oil & gas assets, stated in 2023 real terms for comparability with the IEA scenario:
|
|
Nominal values |
|
|
Values in real terms 2023 |
|
|
|
|
2025 |
2025 |
2028 |
2030 |
2040 |
2050 |
|
Brent $/bbl |
|
|
|
|
|
|
|
TTF natural gas price $mmBtu |
|
|
|
|
|
|
This scenario does not differ significantly from the one adopted in the previous reporting year. Actual hydrocarbons prices utilized in the calculation of future revenues of oil&gas assets in the impairment review are derived from the main market benchmarks by applying specific price differentials estimated by the management to consider factors like crude qualities, different indexation mechanisms and regional price trends.
The discount rate of the future cash flows of the CGUs was estimated as the weighted average cost of equity (Ke) and net borrowings, based on the Capital Asset Pricing Model methodology. The cost of equity considers both a premium for the non-diversifiable market risk measured on the basis of the long-term returns of the S&P500, and an additional premium that considers exposure to operational risks of the countries of activity and the risks of the energy transition. For 2024, a Group cost of capital (“WACC”) of approximately
The impairment test was performed at all the Group’s oil&gas CGUs based on the price scenario of management and the country WACCs, substantially confirming the carrying amounts of the properties, with the exception of certain oil assets in Congo and Alaska that were aligned to their lower fair values (€
The value in use (VIU) of the oil&gas CGUs under the management’s scenario assumptions displayed a headroom (difference between VIU and book values) of approximately
The values-in-use of oil&gas assets estimated under the different stress-test scenarios exhibit in their entirety a headroom over the assets book values; however, it is possible the incurrence of impairment losses as shown in the table below.
F-49
The results of those sensitivity tests expressed in terms of cumulated headroom of the oil&gas CGUs over their corresponding book values and potential pre-tax income statement impacts are as follows:
|
|
Value in use of the O&G CGUs Headroom vs Carrying amounts |
Possible impacts on the profit and loss account |
Assumption at 2050 in real terms USD 2023 |
||
|
|
Tax-deductible CO 2 charges |
€ billion |
Brent price |
European gas price |
Cost of CO 2 |
|
Eni's scenario |
|
|
|
|
CO 2 costs projections in the EU/ETS + projections of forestry costs |
|
10% haircut of Eni's prices assumptions |
|
(
|
|
|
CO 2 costs projections in the EU/ETS + projections of forestry costs |
|
Eni's scenario with +1% increase in WACC |
|
(
|
|
|
CO 2 costs projections in the EU/ETS + projections of forestry costs |
|
IEA NZE 2050 scenario |
|
(
|
|
|
|
(*) Range of values depending on advanced or emerging economies with or without net zero commitments. For low-income economies a lower cost is expected.
These sensitivities do not consider possible actions to mitigate a changed price environment, such as rescheduling and/or cancellation of planned development activities, contractual renegotiations, costs efficiencies or actions aimed at accelerating the pay-back period.
Sensitivity was not applied to Chemicals and Gas power generation business lines considering the immateriality of the residual book values of property, plant and equipment (€
F-50
16 Investments
Equity-accounted investments
|
|
2024 |
2023 |
||||||
|
(€ million) |
Investments in unconsolidated entities controlled by Eni |
Joint ventures |
Associates |
Total |
Investments in unconsolidated entities controlled by Eni |
Joint ventures |
Associates |
Total |
|
Carrying amount - beginning of the year |
|
|
|
|
|
|
|
|
|
Additions and subscriptions |
|
|
|
|
|
|
|
|
|
Divestments and reimbursements |
(
|
(
|
(
|
(
|
|
|
|
|
|
Share of profit of equity-accounted investments |
|
|
|
|
|
|
|
|
|
Share of loss of equity-accounted investments |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Deduction for dividends |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Changes in the scope of consolidation |
|
|
|
|
|
|
(
|
(
|
|
Currency translation differences |
|
|
|
|
(
|
(
|
(
|
(
|
|
Other changes |
(
|
(
|
|
|
(
|
|
(
|
|
|
Carrying amount - end of the year |
|
|
|
|
|
|
|
|
Acquisitions and share capital increases mainly related: (i) for €
Divestments and reimbursements related: (i) for €
Share of profit from equity-accounted investments essentially referred to: (i) Azule Energy Holdings Ltd for €
Share of loss from equity-accounted investments essentially referred to: (i) St. Bernard Renewables Llc for €
Reduction for dividends related to: (i) Vår Energi ASA for €
Changes in the scope of consolidation referred for €
Other changes included the initial recognition of the fair value of the associate Ithaca Energy Plc (Eni’s interest
F-51
Net carrying amounts related to the following companies:
|
|
December 31, 2024 |
December 31, 2023 |
||
|
(€ million) |
Net carrying amount |
% of the investment |
Net carrying amount |
% of the investment |
|
Investments in unconsolidated entities controlled by Eni |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
Joint ventures |
|
|
|
|
|
Azule Energy Holdings Ltd |
|
|
|
|
|
St. Bernard Renewables Llc |
|
|
|
|
|
E&E Algeria Touat BV |
|
|
|
|
|
Saipem SpA |
|
|
|
|
|
SeaCorridor Srl |
|
|
|
|
|
Vårgrønn AS |
|
|
|
|
|
Mozambique Rovuma Venture SpA |
|
|
|
|
|
Cardón IV SA |
|
|
|
|
|
2023 Sol IX Llc |
|
|
|
|
|
GreenIT SpA |
|
|
|
|
|
Lotte Versalis Elastomers Co Ltd |
|
|
|
|
|
2022 Sol VII Llc |
|
|
|
|
|
Mangistau Power BV |
|
|
|
|
|
Hergo Renewables SpA |
|
|
|
|
|
LabAnalysis Environmental Scienze Srl |
|
|
|
|
|
Mangistau Renewables BV |
|
|
|
|
|
Società Oleodotti Meridionali SOM SpA |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
Associates |
|
|
|
|
|
Abu Dhabi Oil Refining Company (TAKREER) |
|
|
|
|
|
Ithaca Energy Plc |
|
|
|
|
|
QatarEnergy LNG NFE (5) |
|
|
|
|
|
Coral FLNG SA |
|
|
|
|
|
ADNOC Global Trading Ltd |
|
|
|
|
|
United Gas Derivatives Co |
|
|
|
|
|
Novis Renewables Holdings Llc |
|
|
|
|
|
Bluebell Solar Class A Holdings II Llc |
|
|
|
|
|
LG-Eni BioRefining Co Ltd |
|
|
|
|
|
Vår Energi ASA |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The carrying amount of Vår Energi ASA is equal to zero in relation to the application of the equity method of accounting which includes, among others, the recognition of distributed dividends.
The results of equity-accounted investments by segment are disclosed in note 35 – Segment information and information by geographical area.
As of December 31, 2024, the book and market values of Saipem SpA, Vår Energi ASA and Ithaca Energy Plc, listed equity-accounted companies, respectively, were as follows:
|
|
Saipem SpA |
Vår Energi ASA |
Ithaca Energy Plc |
|
Number of ordinary shares held |
|
|
|
|
% of the investment |
|
|
|
|
Share price (€) |
|
|
|
|
Market value (€ million) |
|
|
|
|
Book value (€ million) |
|
|
|
|
Market value vs Book value (€ million) |
|
|
|
As of December 31, 2024, the market capitalization of Saipem shares exceeded the book value of the investment; therefore, there was no indication of impairment from the point of view of the investor. The carrying amount was aligned with the corresponding share of the investee's net equity book value, less the fraction of the investee net assets corresponding to the equity component of a convertible bond.
The book value of St. Bernard Renewables Llc includes the recognition of goodwill of €
Additional information is included in note 37 – Other information about investments.
F-52
Other investments
|
(€ million) |
2024 |
2023 |
|
Carrying amount - beginning of the year |
|
|
|
Additions and subscriptions |
|
|
|
Change in the fair value with effect to OCI |
|
|
|
Currency translation differences |
|
(
|
|
Other changes |
(
|
(
|
|
Carrying amount - end of the year |
|
|
The fair value of the main non-controlling interests in non-listed investees on regulated markets, classified within level 3 of the fair value hierarchy, was estimated based on a methodology that combines future expected earnings and the sum-of-the-parts methodology (so-called residual income approach) and takes into account, inter alia, the following inputs: (i) expected net profits, as a gauge of the future profitability of the investees, derived from the business plans, but adjusted, where appropriate, to include the assumptions that market participants would incorporate; (ii) the cost of capital, adjusted to include the risk premium of the specific country (
Dividend income from these investments is disclosed in note 32 – Income (expense) from investments.
The investment book value as of December 31, 2024, primarily related to Nigeria LNG Ltd for €
17 Other financial assets
|
|
December 31, 2024 |
December 31, 2023 |
||
|
(€ million) |
Current |
Non-current |
Current |
Non-current |
|
Long-term financing receivables held for operating purposes |
|
|
|
|
|
Short-term financing receivables held for operating purposes |
|
|
|
|
|
|
|
|
|
|
|
Long-term financing receivables |
|
|
|
|
|
Short-term financing receivables |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities held for operating purposes |
|
|
|
|
|
|
|
|
|
|
Changes in allowance for doubtful accounts were as follows:
|
(€ million) |
2024 |
2023 |
|
Carrying amount at the beginning of the year |
|
|
|
Additions |
|
|
|
Deductions |
(
|
(
|
|
Currency translation differences |
|
(
|
|
Other changes |
(
|
(
|
|
Carrying amount at the end of the year |
|
|
Financing receivables held for operating purposes primarily related to funds provided to joint ventures and associates in the Exploration & Production segment (€
Financing receivables held for operating purposes due beyond five years amounted to €
The fair value of non-current financing receivables held for operating purposes of €
The recoverability of other long-term financial assets was assessed by considering the expected probability of default in the next twelve months only, as the creditworthiness suffered no significant deterioration in the reporting period.
F-53
Financing receivables held for non-operating purposes related to: (i) the joint venture Mozambique Rovuma Venture SpA (Eni’s interest
Financing receivables were denominated in U.S. dollar for €
Securities for €
The following table analyses securities per issuing entity:
|
|
Amortized cost (€ million) |
Nominal value (€ million) |
Fair Value (€ million) |
Nominal rate of return (%) |
Maturity date |
Rating - Moody's |
Rating - S&P |
|
Sovereign states |
|
|
|
|
|
|
|
|
Fixed rate bonds |
|
|
|
|
|
|
|
|
Italy |
|
|
|
from
|
|
|
|
|
Others (*) |
|
|
|
from
|
|
|
|
|
Floating rate bonds |
|
|
|
|
|
|
|
|
Italy |
|
|
|
from
|
|
|
|
|
Total sovereign states |
|
|
|
|
|
|
|
|
Other financial institutions |
|
|
|
|
|
|
|
|
European Bank of Investments |
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
(*) Amounts included herein are lower than €
Securities having maturity within
The fair value of securities was derived from quoted market prices.
Receivables with related parties are described in note 36 – Transactions with related parties.
F-54
18 Trade and other payables
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Trade payables |
|
|
|
Down payments and advances from joint ventures in exploration & production activities |
|
|
|
Payables for purchase of non-current assets |
|
|
|
Payables due to partners in exploration & production activities |
|
|
|
Other payables |
|
|
|
|
|
|
The increase in trade payables of €
Other payables included: (i) payables to factoring companies in relation to the derecognition of Eni's tax credits for €
Trade and other payables were denominated in euro for €
Because of the short-term maturity and conditions of remuneration of trade payables, the fair values approximated the carrying amounts.
Trade and other payables due to related parties are described in note 36 – Transactions with related parties.
19 Finance debt
|
|
December 31, 2024 |
December 31, 2023 |
||||||
|
|
Short-term debt |
Current portion of long-term debt |
Long-term debt |
Total |
Short-term debt |
Current portion of long-term debt |
Long-term debt |
Total |
|
(€ million) |
|
|
|
|
|
|
|
|
|
Banks |
|
|
|
|
|
|
|
|
|
Ordinary bonds |
|
|
|
|
|
|
|
|
|
Sustainability-linked convertible bonds |
|
|
|
|
|
|
|
|
|
Other financial institutions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Finance debt increased by €
As of December 31, 2024, finance debt included €
Other financial institutions included supplier finance arrangements (SFAs) as follows:
|
(€ million) |
Long-term SFAs |
Current portion of long-term debt SFAs |
Short-term SFAs |
Total |
|
Carrying amount at December 31, 2023 |
|
|
|
|
|
Cash flows |
|
(
|
(
|
(
|
|
Non-monetary increases |
|
|
|
|
|
Currency translation differences |
|
|
|
|
|
Other non-monetary changes |
(
|
|
|
|
|
Carrying amount at December 31, 2024 |
|
|
|
|
The payment terms for financial liabilities falling within the scope of the SFAs range between
Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the retention of a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees could be required to be agreed upon with the European Investment Bank. As of December 31, 2024, debts subjected to restrictive covenants amounted to €
Eni has in place a program for the issuance of Euro Medium Term Notes up to €
F-55
The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2024:
|
(€ million) |
Amount |
Discount on bond issue and accrued expense |
Total |
Currency |
Maturity |
Rate % |
|
Issuing entity |
|
|
|
|
|
|
|
Euro Medium Term Notes |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
(
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
(
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA - Sustainability-linked |
|
|
|
|
|
|
|
Eni SpA - Sustainability-linked |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other bonds |
|
|
|
|
|
|
|
Eni SpA |
|
(
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni SpA |
|
(
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
Eni USA Inc |
|
|
|
|
|
|
|
Eni SpA - Sustainability-linked - Retail |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-56
During 2024, new ordinary bonds in euro were issued by Eni SpA for a nominal value of €
As of December 31, 2024, Eni SpA had in place sustainability-linked bonds for a total nominal value of €
As of December 31, 2024, ordinary bonds maturing within 18 months amounted to €
Information relating to the senior unsecured sustainability-linked convertible bonds is as follows:
|
(€ million) |
Amount |
Discount on bond issue and accrued expense |
Total |
Currency |
Maturity |
Rate % |
|
Issuing entity |
|
|
|
|
|
|
|
Eni SpA - Convertible senior unsecured sustainability-linked bonds |
|
|
|
|
|
|
|
of which financial liabilities |
|
|
|
|
|
|
|
of which equity |
|
(
|
|
|
|
|
As of December 31, 2024, Eni SpA had in place a sustainability-linked senior unsecured convertible bond with an aggregate nominal amount of €
Sustainability-linked bonds and sustainability-linked convertible bonds are indexed to the achievement of sustainability targets related to the Net Carbon Footprint of the Upstream (Scope 1 and 2) and renewable energy installed capacity. In case the Company fails to reach each of the agreed targets, a step-up adjustment to the interest rates of the underlying financing is due to be applied.
The following table provides a breakdown by currency of finance debt and the related weighted average interest rates:
|
|
December 31, 2024 |
December 31, 2023 |
||||||
|
|
Short term debt (€ million) |
Weighted average rate (%) |
Long term debt and current portion of long-term debt (€ million) |
Weighted average rate (%) |
Short term debt (€ million) |
Weighted average rate (%) |
Long term debt and current portion of long-term debt (€ million) |
Weighted average rate (%) |
|
Euro |
|
|
|
|
|
|
|
|
|
U.S. dollar |
|
|
|
|
|
|
|
|
|
Other currencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-57
Eni retained committed borrowing facilities of €
As of December 31, 2024, Eni was in compliance with covenants and other contractual provisions in relation to borrowing facilities.
Fair value of long-term debt, including the current portion of long-term debt is described below:
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Ordinary bonds and sustainability-linked bonds |
|
|
|
Convertible sustainability-linked bonds |
|
|
|
Banks |
|
|
|
Other financial institutions |
|
|
|
|
|
|
Fair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from
Because of the short-term maturity and conditions of remuneration of short-term debt, the fair value approximated the carrying amount.
Changes in liabilities arising from financing activities
|
(€ million) |
Long-term debt and current portion of long-term debt |
Short-term debt |
Long-term and current portion of long-term lease liabilities |
Total |
|
2024 |
|
|
|
|
|
Carrying amount - beginning of the year |
|
|
|
|
|
Cash flows |
(
|
(
|
(
|
(
|
|
Currency translation differences |
|
(
|
|
|
|
Changes in the scope of consolidation |
|
|
|
|
|
Other non-monetary changes |
|
|
|
|
|
Carrying amount - end of the year |
|
|
|
|
|
2023 |
|
|
|
|
|
Carrying amount - beginning of the year |
|
|
|
|
|
Cash flows |
|
(
|
(
|
(
|
|
Currency translation differences |
(
|
|
(
|
(
|
|
Changes in the scope of consolidation |
|
|
|
|
|
Other non-monetary changes |
|
|
|
|
|
Carrying amount - end of the year |
|
|
|
|
Changes in the scope of consolidation related to the acquisition of
Other non-monetary changes include lease liabilities assumptions for €
Lease liabilities are described in note 13 – Right-of-use assets and lease liabilities.
Transactions with related parties are described in note 36 – Transactions with related parties.
F-58
20 Information on net borrowings
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
A. Cash |
|
|
|
B. Cash equivalents |
|
|
|
C. Other current financial assets |
|
|
|
D Liquidity (A+B+C) |
|
|
|
E. Current financial debt |
|
|
|
F. Current portion of non-current financial debt |
|
|
|
G. Current financial indebtedness (E+F) |
|
|
|
H. Net current financial indebtedness (G-D) |
(
|
(
|
|
I. Non-current financial debt |
|
|
|
J. Debt instruments |
|
|
|
K. Non‐current trade and other payables |
|
|
|
L. Non-current financial indebtedness (I+J+K) |
|
|
|
M. Total financial indebtedness (H+L) |
|
|
Net borrowings did not include €
Cash and cash equivalents include €
Other current financial assets include: (i) financial assets at fair value through profit or loss, disclosed in note 7 – Financial assets at fair value through profit or loss; (ii) financing receivables, disclosed in note 17 – Other financial assets.
Current and non-current debts are disclosed in note 19 – Finance debts.
Debt instruments included €
Current portion of non-current financial debt and non-current financial debt include lease liabilities of €
F-59
21 Provisions
|
(€ million) |
Provisions for site restoration, abandonment and social projects |
Environmental provisions |
Provisions for litigations |
Provisions for taxes other than income taxes |
Loss adjustments and actuarial provisions for Eni's insurance companies |
Provisions for losses on investments |
Provisions for OIL insurance coverage |
Other |
Total |
|
Carrying amount at December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
New or increased provisions |
|
|
|
|
|
|
|
|
|
|
Initial recognition and changes in estimates |
|
|
|
|
|
|
|
|
|
|
Accretion discount |
|
(
|
|
|
|
|
|
|
|
|
Reversal of utilized provisions |
(
|
(
|
(
|
(
|
(
|
|
|
(
|
(
|
|
Reversal of unutilized provisions |
(
|
(
|
(
|
(
|
|
(
|
(
|
(
|
(
|
|
Currency translation differences |
|
|
|
|
|
|
|
|
|
|
Change in scope of consolidation |
|
|
|
|
|
|
|
|
|
|
Other changes |
(
|
(
|
(
|
|
|
|
|
(
|
(
|
|
Carrying amount at December 31, 2024 |
|
|
|
|
|
|
|
|
|
The decommissioning provision comprised: (i) for €
In 2024, increases in the decommissioning provisions related to: (i) the revision of cost estimates relating to depleted oil & gas assets, whose book value has been completely written-down for €
Initial recognition and changes in cost estimates were primarily recognized at assets in UK, Italy, Ivory Coast and Libya. The provision also increased due to a reduction in discounting rates in relation to the downward movement of the yield curve and the reduction of the discount period (accretion of discount). The effect of the accretion of discount recognized through profit and loss was determined based on discount rates ranging from
F-60
Provisions for environmental risks included the estimated costs for environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. The provision was accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out environmental clean-up and remediation and the expected costs can be estimated reliably. The provision included the expected charges associated with strict liability related to obligations of cleaning up and remediating polluted areas that met the parameters set by law at the time when the pollution occurred but presently are no more in compliance with current environmental laws and regulations, or because Eni assumed the liability borne by other operators when the Company acquired or otherwise took over site operations. The prerequisite for the recognition of these environmental costs is the evaluation of the probability of their being incurred and the possibility of estimating them reliably. Provisions related: (i) for €
Litigation provisions comprised expected liabilities associated with legal proceedings and other matters arising from contractual claims, including arbitrations, fines and penalties due to antitrust proceedings and administrative matters. The provision was allocated on the basis of the best estimate of the existing liability at the balance sheet date and referred to the Exploration & Production segment for €
Provisions for uncertain tax matters related to the estimated losses that the Company expects to incur to settle tax litigations and tax claims pending with tax authorities in relation to uncertainties in applying rules in force and referred to the Exploration & Production segment for €
Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC represented the estimated liabilities accrued on the basis for third party claims. Against such liability were recorded receivables for €
Provisions for losses on investments included provisions relating to investments whose loss exceeds equity and primarily related to Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) for €
Provisions for the Everen insurance coverage included insurance premiums which will be charged to Eni in the next
Other provisions mainly related to claims, contingencies and commercial renegotiations aa part of the ordinary course of the business. Those provisions were outstanding mainly in the Global Gas & LNG Portfolio and Enilive business lines.
Based on the outlay forecasts in relation to the progress of the restoration and decommissioning activities of depleted oil assets, the short-term portion of the risk provisions amounts to approximately €
F-61
22 Provisions for employee benefits
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Italian defined benefit plans |
|
|
|
Foreign defined benefit plans |
|
|
|
FISDE, foreign medical plans and other |
|
|
|
Defined benefit plans |
|
|
|
Other benefit plans |
|
|
|
Provision for employee benefits |
|
|
The liability relating to Eni's commitment to cover the healthcare costs of personnel is determined, among other things, based on the contributions paid by the Company.
Other employee benefit plans related to deferred monetary incentive plans for €
Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:
|
|
2024 |
2023 |
||||||||||
|
(€ million) |
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Defined benefit plans |
Other benefit plans |
Total |
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Defined benefit plans |
Other benefit plans |
Total |
|
Present value of benefit liabilities at beginning of year |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Remeasurements: |
(
|
(
|
(
|
(
|
|
(
|
|
|
|
|
(
|
|
|
- actuarial (gains) losses due to changes in demographic assumptions |
|
(
|
|
(
|
|
(
|
|
|
|
|
(
|
|
|
- actuarial (gains) losses due to changes in financial assumptions |
|
(
|
|
(
|
|
(
|
|
|
|
|
|
|
|
- experience (gains) losses |
(
|
|
(
|
(
|
(
|
(
|
|
|
(
|
|
(
|
|
|
Past service cost and (gain) loss on settlements |
|
|
|
|
|
|
|
(
|
|
(
|
|
|
|
Plan contributions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
- employee contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefits paid |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Reclassification to liabilities directly associated with assets held for sale |
|
|
|
|
|
|
|
(
|
(
|
(
|
(
|
(
|
|
Currency translation differences and other changes |
|
|
(
|
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
|
Present value of benefit liabilities at end of year (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan assets at beginning of year |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on plan assets |
|
(
|
|
(
|
|
(
|
|
|
|
|
|
|
|
Administrative fees paid |
|
(
|
|
(
|
|
(
|
|
|
|
|
|
|
|
Plan contributions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
- employee contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
- employer contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefits paid |
|
(
|
|
(
|
|
(
|
|
(
|
|
(
|
|
(
|
|
Reclassification to liabilities directly associated with assets held for sale |
|
|
|
|
|
|
|
(
|
|
(
|
|
(
|
|
Currency translation differences and other changes |
|
|
|
|
|
|
|
(
|
|
(
|
|
(
|
|
Plan assets at end of year (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset ceiling at beginning of year |
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in asset ceiling |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset ceiling at end of year (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net liability recognized at end of year (a-b+c) |
|
|
|
|
|
|
|
|
|
|
|
|
F-62
Costs charged to the profit and loss account, valued using actuarial assumptions, consisted of the following:
|
(€ million) |
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Defined benefit plans |
Other benefit plans |
Total |
|
2024 |
|
|
|
|
|
|
|
Current service cost |
|
|
|
|
|
|
|
Past service cost and (gains) losses on settlements |
|
|
|
|
|
|
|
Interest cost (income), net: |
|
|
|
|
|
|
|
- interest cost on liabilities |
|
|
|
|
|
|
|
- interest income on plan assets |
|
(
|
|
(
|
|
(
|
|
Total interest cost (income), net |
|
|
|
|
|
|
|
- of which recognized in "Payroll and related cost" |
|
|
|
|
|
|
|
- of which recognized in "Financial income (expense)" |
|
|
|
|
|
|
|
Remeasurements for long-term plans |
|
|
|
|
|
|
|
Administrative fees paid |
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
- of which recognized in "Payroll and related cost" |
|
|
|
|
|
|
|
- of which recognized in "Financial income (expense)" |
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
Current service cost |
|
|
|
|
|
|
|
Past service cost and (gains) losses on settlements |
|
(
|
|
(
|
|
|
|
Interest cost (income), net: |
|
|
|
|
|
|
|
- interest cost on liabilities |
|
|
|
|
|
|
|
- interest income on plan assets |
|
(
|
|
(
|
|
(
|
|
Total interest cost (income), net |
|
|
|
|
|
|
|
- of which recognized in "Payroll and related cost" |
|
|
|
|
|
|
|
- of which recognized in "Financial income (expense)" |
|
|
|
|
|
|
|
Remeasurements for long-term plans |
|
|
|
|
(
|
(
|
|
Total |
|
|
|
|
|
|
|
- of which recognized in "Payroll and related cost" |
|
(
|
|
|
|
|
|
- of which recognized in "Financial income (expense)" |
|
|
|
|
|
|
F-63
Costs of defined benefit plans recognized in other comprehensive income consisted of the following:
|
|
2024 |
2023 |
||||||
|
(€ million) |
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Total |
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Total |
|
Actuarial (gains)/losses due to changes in demographic assumptions |
|
(
|
|
(
|
|
|
|
|
|
Actuarial (gains)/losses due to changes in financial assumptions |
|
(
|
|
(
|
|
|
|
|
|
Experience (gains) losses |
(
|
|
(
|
(
|
|
|
(
|
|
|
Return on plan assets |
|
|
|
|
|
|
|
|
|
Changes in asset ceiling |
|
|
|
|
|
|
|
|
|
Remeasurements |
(
|
(
|
(
|
(
|
|
|
|
|
Plan assets consisted of the following:
|
(€ million) |
Cash and cash equivalents |
Equity securities |
Debt securities |
Real estate |
Derivatives |
Investment funds |
Assets held by insurance companies |
Other |
Total |
|
December 31, 2024 |
|
|
|
|
|
|
|
|
|
|
Plan assets with a quoted market price |
|
|
|
|
|
|
|
|
|
|
Plan assets without a quoted market price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
Plan assets with a quoted market price |
|
|
|
|
|
|
|
|
|
|
Plan assets without a quoted market price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-64
The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2025 consisted of the following:
|
|
|
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Other benefit plans |
||||
|
2024 |
|
|
|
|
|
|
|
|
|
|
Discount rate |
(%) |
|
|
- |
|
|
|
- |
|
|
Rate of compensation increase |
(%) |
|
|
- |
|
|
|
|
|
|
Rate of price inflation |
(%) |
|
|
- |
|
|
|
|
|
|
Life expectations on retirement at age 65 |
(years) |
|
|
- |
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
Discount rate |
(%) |
|
|
- |
|
|
|
- |
|
|
Rate of compensation increase |
(%) |
|
|
- |
|
|
|
|
|
|
Rate of price inflation |
(%) |
|
|
- |
|
|
|
|
|
|
Life expectations on retirement at age 65 |
(years) |
|
|
- |
|
|
|
|
|
The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans:
|
|
|
Euro area |
Rest of Europe |
Africa |
Other areas |
Foreign defined benefit plans |
||||||||
|
2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
(%) |
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
Rate of compensation increase |
(%) |
|
- |
|
|
|
|
|
- |
|
|
|
- |
|
|
Rate of price inflation |
(%) |
|
|
|
|
- |
|
|
- |
|
|
|
- |
|
|
Life expectations on retirement at age 65 |
(years) |
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
(%) |
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
Rate of compensation increase |
(%) |
|
- |
|
|
|
|
|
- |
|
|
|
- |
|
|
Rate of price inflation |
(%) |
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
Life expectations on retirement at age 65 |
(years) |
|
- |
|
|
|
|
|
- |
|
|
|
- |
|
The effects of a possible change in the main actuarial assumptions at the end of the year are not material.
The contributions expected to be paid for employee benefit plans in the next year amounted to €
The following is an analysis by maturity date of the liabilities for employee benefit plans and their relative weighted average duration:
|
(€ million) |
Italian defined benefit plans |
Foreign defined benefit plans |
FISDE, foreign medical plans and other |
Other benefit plans |
|
December 31, 2024 |
|
|
|
|
|
2025 |
|
|
|
|
|
2026 |
|
|
|
|
|
2027 |
|
|
|
|
|
2028 |
|
|
|
|
|
2029 |
|
|
|
|
|
2030 and thereafter |
|
|
|
|
|
Weighted average duration (years) |
|
|
|
|
|
December 31, 2023 |
|
|
|
|
|
2024 |
|
|
|
|
|
2025 |
|
|
|
|
|
2026 |
|
|
|
|
|
2027 |
|
|
|
|
|
2028 |
|
|
|
|
|
2029 and thereafter |
|
|
|
|
|
Weighted average duration (years) |
|
|
|
|
F-65
23 Deferred tax assets and liabilities
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Deferred tax liabilities before offsetting |
|
|
|
Deferred tax assets available for offset |
(
|
(
|
|
Deferred tax liabilities |
|
|
|
Deferred tax assets before offsetting (net of accumulated write-down provisions) |
|
|
|
Deferred tax liabilities available for offset |
(
|
(
|
|
Deferred tax assets |
|
|
The most significant temporary differences giving rise to net deferred tax assets and liabilities are disclosed below:
|
(€ million) |
Carrying amount at December 31, 2024 |
Carrying amount at December 31, 2023 |
|
Deferred tax liabilities |
|
|
|
Accelerated tax depreciation |
|
|
|
Difference between the fair value and the carrying amount of assets acquired |
|
|
|
Site restoration and abandonment (tangible assets) |
|
|
|
Leasing |
|
|
|
Derivative financial instruments |
|
|
|
Application of the weighted average cost method in evaluation of inventories |
|
|
|
Other |
|
|
|
|
|
|
|
Deferred tax assets, gross |
|
|
|
Carry-forward tax losses |
(
|
(
|
|
Site restoration and abandonment (provisions for contingencies) |
(
|
(
|
|
Timing differences on depreciation and amortization |
(
|
(
|
|
Accruals for impairment losses and provisions for contingencies |
(
|
(
|
|
Impairment losses |
(
|
(
|
|
Derivative financial instruments |
(
|
(
|
|
Leasing |
(
|
(
|
|
Employee benefits |
(
|
(
|
|
Over/Under lifting |
(
|
(
|
|
Unrealized intercompany profits |
(
|
(
|
|
Other |
(
|
(
|
|
|
(
|
(
|
|
Accumulated write-downs of deferred tax assets |
|
|
|
Deferred tax assets, net |
(
|
(
|
F-66
The following table summarizes the changes in deferred tax liabilities and assets:
|
(€ million) |
Deferred tax liabilities before offsetting |
Deferred tax assets before offsetting, gross |
Accumulated write-downs of deferred tax assets |
Deferred tax assets before offsetting net of accumulated write-down provisions |
|
2024 |
|
|
|
|
|
Carrying amount - beginning of the year |
|
(
|
|
(
|
|
Additions |
|
(
|
|
(
|
|
Deductions |
(
|
|
(
|
|
|
Changes with effect to OCI |
(
|
|
|
|
|
Currency translation differences |
|
(
|
|
(
|
|
Change in scope of consolidation |
|
|
(
|
(
|
|
Other changes |
|
(
|
|
(
|
|
Carrying amount - end of the year |
|
(
|
|
(
|
|
2023 |
|
|
|
|
|
Carrying amount - beginning of the year |
|
(
|
|
(
|
|
Additions |
|
(
|
|
(
|
|
Deductions |
(
|
|
(
|
|
|
Changes with effect to OCI |
(
|
|
|
|
|
Currency translation differences |
(
|
|
(
|
|
|
Change in scope of consolidation |
|
(
|
|
(
|
|
Other changes |
(
|
|
(
|
|
|
Carrying amount - end of the year |
|
(
|
|
(
|
Changes in the scope of consolidation referred to the acquisition of the Neptune Energy group for €
Carry-forward tax losses amounted to €
The Italian tax law allows the carry-forward of tax losses indefinitely. Foreign tax laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. A tax rate of
Accumulated write-downs of deferred tax assets related to Italian companies for €
Deferred tax assets of Italian companies of €
Taxes are also described in note 33 – Income taxes.
F-67
24 Derivative financial instruments and hedge accounting
|
|
December 31, 2024 |
|
December 31, 2023 |
||||
|
|
Fair value asset |
Fair value liability |
Level of Fair value |
|
Fair value asset |
Fair value liability |
Level of Fair value |
|
(€ million) |
|
||||||
|
Non-hedging derivatives |
|
|
|
|
|
|
|
|
Derivatives on exchange rate |
|
|
|
|
|
|
|
|
- Currency swap |
|
|
2 |
|
|
|
2 |
|
- Interest currency swap |
|
|
2 |
|
|
|
2 |
|
- Outright |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives on interest rate |
|
|
|
|
|
|
|
|
- Interest rate swap |
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Derivatives on commodities |
|
|
|
|
|
|
|
|
- Over the counter |
|
|
2 |
|
|
|
2 |
|
- Future |
|
|
1 |
|
|
|
1 |
|
- Options |
|
|
2 |
|
|
|
2 |
|
- Other |
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value hedge derivatives |
|
|
|
|
|
|
|
|
Derivatives on interest rate |
|
|
|
|
|
|
|
|
- Interest rate swap |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives on exchange rate |
|
|
|
|
|
|
|
|
- Outright |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedge derivatives |
|
|
|
|
|
|
|
|
Derivatives on commodities |
|
|
|
|
|
|
|
|
- Over the counter |
|
|
2 |
|
|
|
2 |
|
- Future |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives on interest rate |
|
|
|
|
|
|
|
|
- Interest rate swap |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options |
|
|
|
|
|
|
|
|
- Other options |
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Gross amount |
|
|
|
|
|
|
|
|
Offsetting |
(
|
(
|
|
|
(
|
(
|
|
|
Net amount |
|
|
|
|
|
|
|
|
Of which: |
|
|
|
|
|
|
|
|
- current |
|
|
|
|
|
|
|
|
- non-current |
|
|
|
|
|
|
|
Eni is exposed to market risk, which is the risk that changes in prices of energy commodities, exchange rates and interest rates could reduce the future cash flows of highly probable future transactions or the fair value of the assets. Eni enters into financial and commodities derivatives traded on organized markets (like MTF and OTF) and into commodities derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) to reduce the market risk and, currencies or interest rates and, to a limited extent in compliance with internal authorization thresholds, with speculative purposes to profit from expected market trends.
Derivatives fair values were estimated based on market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace.
Fair-valued non-hedging derivatives mainly comprised forward sale contracts of natural gas for physical delivery which were not entitled to the own use exemption, as well as derivatives for proprietary trading activities.
F-68
Fair-valued cash flow hedges mainly related to commodity hedges and were entered into by the Global Gas & LNG Portfolio business line to hedge variability in future cash flows associated with highly probable future trade transactions of gas or electricity or on already contracted trades due to different indexation mechanisms of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The existence of a relationship between the hedged item and the hedging derivative is checked at inception to verify eligibility for hedge accounting by observing the offset in changes of the fair values at both the underlying commodity and the derivative. The hedging relationship is also stress-tested against the level of credit risk of the counterparty in the derivative transaction. The hedge ratio is defined consistently with the Company’s risk management objectives, under a defined risk management strategy. The hedging relationship is discontinued when it ceases to meet the qualifying criteria and the risk management objectives on the basis of which hedge accounting has initially been applied.
The effects of the measurement at fair value of cash flow hedge derivatives are given in note 26 – Equity. Information on hedged risks, the hedging policies are disclosed in note 28 – Guarantees, commitments and risks - Risk factors.
Eni entered into sustainability-linked interest rate swaps with leading banking institutions which provide for a cost adjustment mechanism linked to the achievement of certain sustainability targets. At December 31, 2024, the fair value of these contracts amounted to positive €
In 2024, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €
The offsetting of financial derivatives primarily related to Eni Global Energy Markets SpA.
During 2024, there were no transfers between the different hierarchy levels of fair value.
Hedging derivative instruments are disclosed below:
|
|
December 31, 2024 |
December 31, 2023 |
||||
|
|
Nominal amount of the hedging instrument |
Change in fair value (effective hedge) |
Change in fair value (ineffective hedge) |
Nominal amount of the hedging instrument |
Change in fair value (effective hedge) |
Change in fair value (ineffective hedge) |
|
(€ million) |
||||||
|
Cash flow hedge derivatives |
|
|
|
|
|
|
|
Derivatives on commodity |
|
|
|
|
|
|
|
- Over the counter |
|
(
|
|
|
|
|
|
- Future |
|
(
|
|
|
(
|
|
|
|
|
(
|
|
|
|
|
|
Other cash flow derivatives |
|
|
|
|
|
|
|
- Other |
|
(
|
|
|
(
|
|
|
|
|
(
|
|
|
(
|
|
|
|
|
(
|
|
|
|
|
|
Fair value hedge derivatives |
|
|
|
|
|
|
|
Derivatives on exchange rate |
|
|
|
|
|
|
|
- Outright |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives on interest rate |
|
|
|
|
|
|
|
- Interest rate swap |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-69
The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge and fair value hedge is provided below:
|
|
December 31, 2024 |
December 31, 2023 |
||||
|
(€ million) |
Change of the underlying item used for the calculation of hedging ineffectiveness |
CFH reserve |
Reclassification adjustments |
Change of the underlying item used for the calculation of hedging ineffectiveness |
CFH reserve |
Reclassification adjustments |
|
|
|
|
|
|
|
|
|
Cash flow hedge derivatives |
|
|
|
|
|
|
|
Commodity price risk |
|
|
|
|
|
|
|
- Planned sales |
|
(
|
(
|
(
|
|
(
|
|
|
|
(
|
(
|
(
|
|
(
|
|
Other cash flow derivatives |
|
|
|
|
|
|
|
- hedged flows |
|
(
|
|
(
|
(
|
|
|
|
|
(
|
|
(
|
(
|
|
|
|
December 31, 2024 |
||
|
(€ million) |
Nominal amount of the underlying item |
Cumulative changes of the underlying item |
Change of the underlying item |
|
Fair value hedge derivatives |
|
|
|
|
Derivatives on exchange rate |
|
|
|
|
- Investments |
|
(
|
(
|
|
Derivatives on interest rate |
|
|
|
|
- Financial liabilities |
|
|
|
More information is reported in note 28 — Guarantees, Commitments and Risks — Financial risks.
Effects recognized in other operating profit (loss)
Other operating profit (loss) related to derivative financial instruments on commodity was as follows:
|
(€ million) |
2024 |
2023 |
2022 |
|
Net income (loss) on cash flow hedging derivatives |
|
|
|
|
Net income (loss) on other derivatives |
(
|
|
(
|
|
|
(
|
|
(
|
Net income (loss) on cash flow hedging derivatives related to the ineffective portion of the hedging relationship on commodity derivatives was recognized through profit and loss.
Net income (loss) on other derivatives included the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading.
Effects recognized in finance income (loss)
|
(€ million) |
2024 |
2023 |
2022 |
|
Derivatives on exchange rate |
|
(
|
(
|
|
Derivatives on interest rate |
(
|
|
|
|
Options |
|
|
|
|
|
|
(
|
|
Net finance income from derivative financial instruments was recognized in connection with the fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS, as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing indexation of energy commodities.
More information is disclosed in note 36 – Transactions with related parties.
F-70
25 Assets held for sale and liabilities directly associated with assets held for sale
As of December 31, 2024, assets held for sale of €
During 2024, assets reclassified as held for sale in the 2023 relating to some oil permits in Congo and onshore assets in Nigeria were sold (see note 5 – Business combinations and other significant transactions).
26 Equity
Non-controlling interest
|
|
|
Profit (Loss) |
Equity |
||
|
(€ million) |
|
2024 |
2023 |
December 31, 2024 |
December 31, 2023 |
|
Eni Marine Services SpA |
|
|
|
|
|
|
Eni Plenitude Group |
|
|
|
|
|
|
EniPower Group |
|
|
|
|
|
|
Others |
|
|
|
|
|
|
|
|
|
|
|
|
In March 2024, Eni Plenitude SpA Società Benefit (Plenitude) and Energy Infrastructure Partners (EIP) closed an investment agreement, with EIP acquiring a non-controlling interest in Plenitude through a capital increase of €
Minority interests in Eni Marine Services SpA related to a perpetual subordinated bonds issued in US dollars to finance a Group’s major capital project. The perpetual subordinated bond was recognized among minority interests in consideration of the Group’s unconditional right to avoid transferring cash or other financial assets to the bondholders.
Equity attributable to equity holders of Eni
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Share capital |
|
|
|
Retained earnings |
|
|
|
Cumulative currency translation differences |
|
|
|
Other reserves and equity instruments: |
|
|
|
- Perpetual subordinated bonds |
|
|
|
- Legal reserve |
|
|
|
- Reserve for treasury shares |
|
|
|
- Reserve for OCI on cash flow hedging derivatives net of tax effect |
(
|
|
|
- Reserve for OCI on defined benefit plans net of tax effect |
(
|
(
|
|
- Reserve for OCI on equity-accounted investments |
|
|
|
- Reserve for OCI on other investments valued at fair value |
|
|
|
- Reserve for convertible bond issue |
|
|
|
Treasury shares |
(
|
(
|
|
Profit for the year |
|
|
|
|
|
|
Share capital
As of December 31, 2024, the parent company’s issued share capital consisted of €
F-71
On May 15, 2024, Eni’s Shareholders’ Meeting resolved: (i) to distribute available reserves by way of and in place of the payment of the dividend for the year 2024 of €
Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.
Perpetual subordinated hybrid bonds
The hybrid bonds are governed by the English law and are traded on the regulated market of the Luxembourg Stock Exchange. As of December 31, 2024, hybrid bonds amounted to €
The key characteristics of the hybrid bonds are: (i) an issue of €
Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.
Reserve for treasury shares
The reserve for treasury shares represents the reserve that was established in previous reporting periods to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings.
F-72
Reserves for Other Comprehensive Income
|
|
Reserve for OCI on cash flow hedge derivatives |
Reserve for OCI on defined benefit plans |
Reserve for OCI on equity-accounted investments* |
Reserve for OCI on investments valued at fair value |
||||
|
|
|
|
|
|
|
|
||
|
(€ million) |
Gross reserve |
Deferred tax liabilities |
Net reserve |
Gross reserve |
Deferred tax liabilities |
Net reserve |
||
|
Reserve as of December 31, 2023 |
|
(
|
|
(
|
|
(
|
|
|
|
Changes of the year |
(
|
|
(
|
|
(
|
|
(
|
|
|
Currency translation differences |
|
|
|
(
|
|
(
|
|
|
|
Changes in scope of consolidation |
|
|
|
(
|
|
(
|
|
|
|
Reclassification adjustments |
|
(
|
|
|
|
|
|
|
|
Reserve as of December 31, 2024 |
(
|
|
(
|
(
|
|
(
|
|
|
|
Reserve as of December 31, 2022 |
(
|
|
(
|
(
|
(
|
(
|
|
|
|
Changes of the year |
|
(
|
|
(
|
|
(
|
|
|
|
Currency translation differences |
|
|
|
(
|
|
(
|
|
|
|
Reversal to inventories adjustments |
(
|
|
(
|
|
|
|
|
|
|
Reclassification adjustments |
|
(
|
|
|
|
|
|
|
|
Reserve as of December 31, 2023 |
|
(
|
|
(
|
|
(
|
|
|
(*) Reserve for OCI on equity-accounted investments at December 31, 2024 includes €
Treasury shares
A total of
During 2024,
Distributable reserves
As of December 31, 2024, equity attributable to Eni included distributable reserves of approximately €
Reconciliation of profit and equity of the parent company Eni SpA to the consolidated profit and equity
|
|
Profit |
Shareholders’ equity |
||
|
(€ million) |
2024 |
2023 |
December 31, 2024 |
December 31, 2023 |
|
As recorded in Eni SpA's Financial Statements |
|
|
|
|
|
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company |
(
|
|
|
(
|
|
Consolidation adjustments: |
|
|
|
|
|
- difference between purchase cost and underlying carrying amounts of net equity |
|
|
|
|
|
- adjustments to comply with Group accounting policies |
(
|
(
|
|
|
|
- elimination of unrealized intercompany profits |
(
|
|
(
|
(
|
|
- deferred taxation |
|
|
(
|
(
|
|
|
|
|
|
|
|
Non-controlling interest |
(
|
(
|
(
|
(
|
|
As recorded in Consolidated Financial Statements |
|
|
|
53,184 |
F-73
27 Other information
Supplemental cash flow information
|
(€ million) |
2024 |
2023 |
2022 |
|
Investment in consolidated subsidiaries and businesses |
|
|
|
|
Current assets |
|
|
|
|
Non-current assets |
|
|
|
|
Net borrowings |
(
|
(
|
(
|
|
Current and non-current liabilities |
(
|
(
|
(
|
|
Net effect of investments |
|
|
|
|
Goodwill |
|
|
|
|
Fair value of investments held before the acquisition of control |
(
|
(
|
(
|
|
Non-controlling interests |
(
|
(
|
(
|
|
Purchase price |
|
|
|
|
less: |
|
|
|
|
Cash and cash equivalents acquired |
(
|
(
|
(
|
|
Consolidated subsidiaries and businesses net of cash and cash equivalent acquired |
|
|
|
|
|
|
|
|
|
Disposal of consolidated subsidiaries and businesses |
|
|
|
|
Current assets |
|
|
|
|
Non-current assets |
|
|
|
|
Net borrowings |
|
|
(
|
|
Current and non-current liabilities |
(
|
(
|
(
|
|
Net effect of disposals |
|
|
|
|
Current value of the stake held for business combinations |
(
|
(
|
(
|
|
Reclassification among other items of OCI |
|
(
|
(
|
|
Gain on disposal of business combinations |
|
|
|
|
Fair value of share capital held after the sale of control |
|
|
|
|
Credits for divestments |
|
(
|
(
|
|
Selling price |
|
|
|
|
less: |
|
|
|
|
Cash and cash equivalents sold |
(
|
(
|
(
|
|
Consolidated subsidiaries and businesses net of cash and cash equivalent disposed of before business combination |
|
|
(
|
F-74
Investments and disposals in 2024 are disclosed in note 5 – Business combinations and other significant transactions.
Business combinations and other significant transactions
The provisional and definitive price allocation of the net assets acquired in 2023 is shown below:
|
(€ million) |
HLS Bonete PV SLU e HLS Bonete Topco SLU (Provisional allocation) |
HLS Bonete PV SLU e HLS Bonete Topco SLU (Definitive allocation) |
Novamont SpA (Provisional allocation) |
Novamont SpA (Definitive allocation) |
|
Current assets |
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
Goodwill |
|
|
|
|
|
Current and non-current assets |
|
|
|
|
|
Cash and cash equivalent (Net borrowings) |
|
|
(
|
(
|
|
Current and non-current liabilities |
(
|
(
|
(
|
(
|
|
Total purchase price |
|
|
|
|
Following the definitive allocation of the 2023 business combinations, financial statements were not restated taking into account the immateriality of the changes.
F-75
28 Guarantees, commitments and risks
Guarantees
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Joint ventures |
|
|
|
Associates |
|
|
|
Others |
|
|
|
|
|
|
In the ordinary course of business, Eni issues guarantees on behalf of non-consolidated companies (joint ventures or associates) in relation to the fulfillment of contractual obligations, mainly autonomous contracts to guarantee the correct execution of works, participation in tenders and other commitments of companies relating to the Exploration & Production segment, as well as parent company guarantees to banks and financial institutions funding those non-consolidated entities in relation to the execution of capital projects in the interest of the Group (for example, projects for the development of reserves in the offshore Mozambique). Some guarantees have been issued to governments and state entities with the aim of insuring the counterparty against possible environmental damages or in relation to negligent conducts in the development of oil projects or failure to comply with contractual provisions. In case of guarantees for environmental damages or similar contractual breaches which do not provide a cap, the value reported reflects the management’s best estimate of potential maximum exposure. In case management would be unable to estimate the maximum amount of potential future payments, the adverse event is deemed to have only a remote possibility of occurrence or a negligible impact (as the case of the parent company guarantee issued on behalf of the jointly controlled entity Cardón IV in the event of a default on the supply of equity gas to the national oil company of Venezuela).
At December 31, 2024, the underlying commitment relating to the guarantees issued was €
Also on the basis of historical experience, management considers reasonably probable that such guarantees will not have significant effects on the economic results and cash flows of the consolidated financial statements.
F-76
Commitments and risks
|
(€ million) |
December 31, 2024 |
December 31, 2023 |
|
Commitments |
|
|
|
Risks |
|
|
|
|
|
|
Commitments related to: (i) parent company guarantees that were issued in connection with certain
contractual commitments for hydrocarbon exploration and production activities and quantified, based on the capital expenditures to be incurred, to be €
Risks related to: (i) assets of third parties under custody of Eni for €
Other commitments and risks
Other commitments include the agreements entered into for forestry initiatives, implemented within the low carbon strategy defined by the Company, concerning the commitments for the purchase until 2038 of carbon credits produced and certified according to international standards by subjects specialized in forest conservation programs.
In addition, Eni is exposed to non-quantifiable risks related to contractual guarantees issued in case of certain Eni transactions, including loss of control of subsidiaries and divestment of businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni or as result of Eni’s loss of control of formerly consolidated subsidiaries. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and cash flow.
Eni has in place long-term natural gas supply contracts with the Russian company Gazprom. During 2024 supplies to Eni, which has regularly recognized the minimum contractual quantities, were effectively reduced to zero as part of various trade disputes between the parties. Eni, having fulfilled its contractual commitments, expects this situation to continue in 2025 also considering that the external context has not undergone any changes.
In many jurisdictions, when a seller is divesting an oil&gas asset, decommissioning obligations relating to the assets sold could revert to the seller in the event the buyer fails to perform and satisfy those obligations when they become due. This contingency applies to Eni’s divestment of petroleum properties in Alaska to Hilcorp. In the case of the business combination with Ithaca, this kind of contingency is estimated to be remote considering the liquidity of the acquirer. In the divestment of the NAOC subsidiary, Eni has been relieved of any decommissioning or other environmental liabilities also in connection with obligations arisen before the disposal.
Risk factors
The following is the description of financial risks and their management. With reference to the issues related to credit risk, the parameters adopted for the determination of Expected Credit Loss have been updated to take into account the current energy crisis and the impacts associated with the conflicts between Russia and Ukraine and in the Middle East.
As of December 31, 2024, the Company retains liquidity reserves that management deems enough to meet the financial obligations due in the next
F-77
Financial risks
Financial risks are managed in respect of the guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the target of the risk management, the valuation methodology, the structure of limits, the relationship model and the hedging and mitigation instruments.
Market risk
Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected cash flows. The Company actively manages market risk in accordance with the aforementioned guidelines that provide a centralized model of handling finance, treasury and risk management transactions based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, as well as Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA, that are in charge to execute certain activities relating to commodity derivatives. In particular, Eni Corporate finance department manages Eni subsidiaries’ financing requirements, covering funding requirements and using available surpluses and the transactions concerning currencies and financial derivative different from commodities of Eni, while Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA execute the negotiation of commodity derivatives over the market. Eni SpA, Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA (also through the subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non-European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar brokerage platforms (i.e. SEF), as well as over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into these transactions through Eni Trade & Biofuels SpA, Eni Global Energy Markets SpA and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments in order to minimize exposure to market risks related to transactional exchange rates and interest rates, as well as to optimize exposure to commodity prices risk taking into account the currency in which commodities are quoted. Eni monitors that every activity in derivatives classified as risk-reducing is directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As proprietary trading is considered separately from the other activities in specific portfolios of Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA, their exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s guidelines provides that the valuation and control of market risk is performed on the basis of: maximum tolerable levels of risk exposure defined in terms of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon, and limits of strategy revision, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given and VaR, which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kind of market risks by transferring risk exposure to the parent company finance departments. Eni’s guidelines define rules to manage the commodity price risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of strategy revision, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA. Internal mandates to manage the commodity price risk provide for a mechanism of allocation of the Group’s maximum tolerable risk level to each business unit. In this framework, Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA, in addition to managing risk exposure associated with their own commercial activity and proprietary trading, pool the requests for negotiating commodity derivatives and execute them in the marketplace.
According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni decided to retain a cash reserve in which the amount of strategic liquidity is identified, to allow for any extraordinary needs to be met. The reserve is managed by Eni’s finance department, with the aim of optimizing performance while ensuring maximum protection of capital and its immediate liquidity within the limits assigned . The management of strategic liquidity is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity. The four different market risks, whose management and control have been summarized above, are described below.
F-78
Market risk - Exchange rate
Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than euro (mainly U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rate fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than euro are translated from their functional currency into euro. Generally, an appreciation of U.S. dollar versus euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries, which prepare financial statements in a currency other than euro, except for single transactions to be evaluated on a case-by-case basis.
Effective management of exchange rate risk is performed within Eni’s finance departments, which pool Group companies’ positions, offsetting the exposures of opposite sign arising from business activities involved and hedging the residual exposure in the market, maximizing the benefits of the netting activity. To manage the residual exposure, the guidelines admit different derivatives, such as swaps, forwards and options. Such derivatives are evaluated at fair value based on standard market valuation algorithms and market prices provided by specialized public info-providers. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a
Market risk - Interest rate
Changes in interest rates affect the market value of financial assets and liabilities of the Company valued at fair value and the level of finance expense and income. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in management’s “Finance plan”. Eni’s finance departments pool borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with the finance plan, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a
Market risk - Commodity
Price risk of commodities is identified as the possibility that fluctuations in the price of materials and basic products produce significant changes in Eni’s operating margins, determining an impact on the economic result such as to compromise the targets defined in the four-year plan and in the budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk management. These exposures include, for example, exposures associated with the program for the production of oil&gas reserves, long-term gas supply contracts for the portion not balanced by sales contracts (already stipulated or expected), the margin deriving from the chemical transformation process, the refining margin and long-term storage functional to the logistic-industrial activities; (ii) commercial exposure: concerns the exposures related to components underlying the contractual arrangements of industrial and commercial (contracted exposure) activities normally related to the time horizon of the four-year plan and budget, components not yet under contract but which will be with reasonable certainty (commitment exposure) and the related activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; (iii) proprietary trading exposure: transactions carried out autonomously for speculative purposes in the short term and normally not aimed at delivery with the intention of exploiting favorable price movements, spreads and/or volatility implemented autonomously and carried out regardless of the exposures of the commercial portfolio or physical and contractual assets. They are usually carried out in the short term, not necessarily aimed at the delivery and carried out by using financial or similar instruments in accordance with specific limits of authorized risk (VaR, stop loss). Strategic risk is not subject to systematic activity of management/hedging that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging activities related to strategic risks are delegated to the top management, previously authorized by the Board of Directors. With prior authorization from the Board of Directors, the exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of financial derivatives (by activating logics of internal market). With regard to exposures of a commercial nature, Eni's risk management target is to optimize the "core" activities and preserve the economic/financial results. Eni manages the commodity price risk through the trading units (Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA) and the exposure to commodity prices through Eni’s finance departments by using financial derivatives traded on the regulated markets, MTF, OTF and financial derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, power or emission certificates. Such financial derivatives are valued at fair value based on market prices provided from specialized sources and based on estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a
F-79
Market risk - Strategic liquidity
Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual investment funds) affect the value of these instruments in case of sale or when they are valued at fair value in the financial statements. The setting up and maintenance of the liquidity reserve are mainly aimed to guarantee a proper financial flexibility. Liquidity should allow Eni to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions) and must be dimensioned to provide a coverage of short-term debts and of medium and long-term finance debts due within a time horizon of
The following tables show amounts in terms of VaR, recorded in 2024 (compared with 2023), relating to interest rate and exchange rate risks in the first section and commodity price risk (aggregated by type of exposure). Regarding the management of strategic liquidity, the table reports the sensitivity to changes in interest rate.
(Value at risk - parametric method variance/covariance; holding period:
|
|
2024 |
2023 |
||||||
|
(€ million) |
High |
Low |
Average |
At year end |
High |
Low |
Average |
At year end |
|
Interest rate (a) |
|
|
|
|
|
|
|
|
|
Exchange rate (a) |
|
|
|
|
|
|
|
|
(a) Value at risk deriving from interest and exchange rates exposures includes the following finance departments: Eni Corporate Finance Department and Banque Eni SA. Value in 2023 is calculated with: holding period:
(Value at risk - Historic simulation method; holding period:
|
|
2024 |
2023 |
||||||
|
(€ million) |
High |
Low |
Average |
At year end |
High |
Low |
Average |
At year end |
|
Commercial exposures - Management Portfolio (a) |
|
|
|
|
|
|
|
|
|
Trading (b) |
|
|
|
|
|
|
|
|
(a) Refers to Global Gas & LNG Portfolio business area, Power Generation & Marketing, REVT, Plenitude, Eni Trading & Biofuels, Eni Global Energy Markets (commercial portfolio). VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the year considering all the volumes delivered in the year and the relevant financial hedging derivatives. Consequently, during the year the VaR pertaining to GGP, Power G&M, REVT and Plenitude during the year presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon.
(b) Cross-commodity proprietary trading, through financial instruments, refers to Eni Trading & Biofuels SpA and Eni Global Energy Markets SpA and Eni Trading & Shipping Inc.
(Sensitivity - Dollar value of 1 basis point - DVBP)
|
|
2024 |
2023 |
||||||
|
(€ million) |
High |
Low |
Average |
At year end |
High |
Low |
Average |
At year end |
|
Strategic liquidity - € Portfolio |
|
|
|
|
|
|
|
|
(Sensitivity - Dollar value of 1 basis point - DVBP)
|
|
2024 |
2023 |
||||||
|
($ million) |
High |
Low |
Average |
At year end |
High |
Low |
Average |
At year end |
|
Strategic liquidity - US dollar Portfolio |
|
|
|
|
|
|
|
|
F-80
Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to fulfill obligations. Eni defined credit risk management policies consistent with the nature and characteristics of the counterparties of commercial and financial transactions regarding the centralized finance model. The Company adopted a model to quantify and control the credit risk based on the evaluation of the expected credit loss which represents the probability of default and the capacity to recover credits in default that is estimated through the so-called Loss Given Default. In the credit risk management and control model, credit exposures are distinguished by commercial nature, in relation to sales contracts on commodities related to Eni’s businesses, and by financial nature, in relation to the financial instruments used by Eni, such as deposits, derivatives and real estate securities.
Credit risk for commercial exposures
Credit risk arising from commercial counterparties is managed by the business units and by the specialized corporate finance and dedicated administration departments and is operated based on formal procedures for the assessment of commercial counterparties, the monitoring of credit exposures, credit recovery activities and disputes. At a corporate level, the general guidelines and methodologies for quantifying and controlling customer’s risk are defined, in particular the riskiness of commercial counterparties is assessed through an internal rating model that combines different default factors deriving from economic variables, financial indicators, payment experiences and information from specialized primary info providers. The probability of default related to State Entities or their closely related counterparties (e.g. National Oil Company), essentially represented by the probability of late payments, is determined by using the country risk premiums adopted for the purposes of the determination of the WACCs for the impairment of non-financial assets. Finally, for retail positions without specific ratings, risk is determined by distinguishing customers in homogeneous risk clusters based on historical series of data relating to payments, periodically updated.
Credit risk for financial exposures
With regard to credit risk arising from financial counterparties essentially deriving from current and strategic use of liquidity and derivative contracts, Eni has established internal policies providing exposure control and concentration through maximum credit risk limits corresponding to different classes of financial counterparties based on ratings provided for by primary credit rating agencies. Credit risk arising from financial counterparties is managed by the Eni’s operating finance departments, Eni Global Energy Markets SpA, Eni Trade & Biofuels SpA and Eni Trading & Shipping Inc specifically for commodity derivatives transactions consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored by each counterpart and by group of belonging to check exposures against the limits assigned daily and the Expected Credit Loss analysis and the concentration periodically.
Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets in the marketplace. Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. Eni’s risk management targets include the maintaining of an adequate level of financial resources readily available to deal with external shocks (drastic changes in the scenario, restrictions on access to capital markets, etc.) or to ensure an adequate level of operational flexibility for the development projects of the Company. The strategic liquidity reserve is employed in short-term marketable financial assets, favoring investments with a very low risk profile. At present, the Group believes to have access to more than sufficient funding to meet the current foreseeable borrowing requirements due to available cash on hand financial assets and borrowing facilities and the access to a wide range of funding opportunities which can be activated through the credit system and capital markets.
Due to the continuing volatility of commodity markets and the related financial commitment linked to the margin of commodity derivatives, Eni consolidated its financial flexibility achieved in the last years through the activation of liquidity swaps in addition to new financing lines acquired.
Eni has in place a program for the issuance of Euro Medium Term Notes up to €
The Group has credit ratings of A- outlook Negative and A-2, respectively, for long and short-term debt, assigned by Standard & Poor’s; Baa1 outlook Stable and P-2, respectively, for long and short-term debt, assigned by Moody’s; A- outlook Stable and F1, respectively for long and short-term debt, assigned by Fitch. Eni’s credit rating is linked, in addition to the Company’s industrial fundamentals and trends in the trading environment, to the sovereign credit rating of Italy. Based on the methodologies used by the credit rating agencies, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. During 2024 Standard & Poor's revised Eni's outlook from Stable to Negative.
During 2024, Eni extended its Euro Commercial Paper program from €
F-81
Expected payments for financial debts, lease liabilities, trade and other payables
The table below summarizes the Group main contractual obligations for finance debt and lease liability repayments, including expected payments for interest charges and liabilities for derivative financial instruments.
|
|
Maturity year |
||||||
|
(€ million) |
2025 |
2026 |
2027 |
2028 |
2029 |
2030 and thereafter |
Total |
|
December 31, 2024 |
|
|
|
|
|
|
|
|
Financial liabilities |
|
|
|
|
|
|
|
|
Lease liabilities |
|
|
|
|
|
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on finance debt |
|
|
|
|
|
|
|
|
Interest on lease liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial guarantees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity year |
||||||
|
(€ million) |
2024 |
2025 |
2026 |
2027 |
2028 |
2029 and thereafter |
Total |
|
December 31, 2023 |
|
|
|
|
|
|
|
|
Financial liabilities |
|
|
|
|
|
|
|
|
Lease liabilities |
|
|
|
|
|
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on finance debt |
|
|
|
|
|
|
|
|
Interest on lease liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial guarantees |
|
|
|
|
|
|
|
Liabilities for leased assets including interest charges for €
The table below presents the timing of the expenditures for trade and other payables.
|
|
Maturity year |
|||
|
(€ million) |
2025 |
2026 - 2029 |
2030 and thereafter |
Total |
|
December 31, 2024 |
|
|
|
|
|
Trade payables |
|
|
|
|
|
Other payables and advances |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity year |
|||
|
(€ million) |
2024 |
2025 - 2028 |
2029 and thereafter |
Total |
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December 31, 2023 |
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Trade payables |
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Other payables and advances |
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F-82
Expected payments under contractual obligations 23
In addition to lease, financial, trade and other liabilities represented in the balance sheet, the Company is subject to non-cancellable contractual obligations or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in future reporting periods. These liabilities are valued based on the net cost for the company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligation and the contractual compensation/penalty in the event of non-performance.
The Company’s main contractual obligations at the balance sheet date comprise take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. The amounts due were calculated on the basis of the assumptions for gas prices and services included in the four-year industrial plan approved by the Company’s management and for subsequent years on the basis of management’s long-term assumptions.
The table below summarizes the Group principal contractual obligations for the main existing contractual obligations as of the balance sheet date, shown on an undiscounted basis. Amounts expected to be paid in 2025 for decommissioning oil&gas assets and for remediation activities are based on management’s estimates and do not represent financial obligations at the closing date.
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Maturity year |
||||||
|
(€ million) |
2025 |
2026 |
2027 |
2028 |
2029 |
2030 and thereafter |
Total |
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Decommissioning liabilities (a) |
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Environmental liabilities |
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Purchase obligations (b) |
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- Gas |
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. take-or-pay contracts |
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. ship-or-pay contracts |
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- Other purchase obligations |
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Other obligations |
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- Memorandum of intent - Val d’Agri |
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Total (c) |
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(a) Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of production life of fields, well-plugging, removal of the structures and site restoration.
(b) Represents any agreement to purchase goods or services that is enforceable and legally binding. For take-or-pay contracts with Gazprom, please refer to the section "Other commitments and risks".
(c) Expected payments under contractual obligations comprises obligations for site abandonment and restoration costs directly associated with assets held for sale for €
Capital investment and capital expenditure commitments
In the next four years, Eni expects capital investments and capital expenditures of €
The amounts shown in the table below include committed expenditures to execute certain environmental projects.
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|
Maturity year |
|||||
|
(€ million) |
2025 |
2026 |
2027 |
2028 |
2029 and thereafter |
Total |
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Committed projects |
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23 Contractual obligations related to employee benefits are indicated in note 22 - Provisions for employee benefits.
F-83
Other information about financial instruments
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2024 |
2023 |
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Carrying amount |
Income (expense) recognized in |
Carrying amount |
Income (expense) recognized in |
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(€ million) |
Profit and loss account |
OCI |
Profit and loss account |
OCI |
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Financial instruments at fair value with effects recognized in profit and loss account: |
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Financial assets at fair value through profit or loss (a) |
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Non-hedging and trading derivatives (b) |
(
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(
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Other investments valued at fair value (c) |
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Receivables and payables and other assets/liabilities valued at amortized cost: |
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Trade receivables and other (d) |
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(
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(
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Financing receivables (e) |
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Securities (a) |
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Trade payables and other (a) |
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(
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Financing payables (f) |
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(
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(
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Net assets (liabilities) for hedging derivatives (g) |
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(
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(
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(
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(
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(a) Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(b) In the profit and loss account, economic effects were recognized as loss within "Other operating income (loss)" for €
(c) Income or expense were recognized in the profit and loss account within "Income (expense) from investments - Dividends".
(d) Income or expense were recognized in the profit and loss account as net impairments within "Net (impairments) reversals of trade and other receivables" for €
(e) In the profit and loss account, income or expense were recognized as income within "Finance income (expense)", including interest income calculated on the basis of the effective interest rate of €
(f) In the profit and loss account, income or expense were recognized as expense within "Finance income (expense)", including interest expense calculated on the basis of the effective interest rate of €
(g) In the profit and loss account, income or expense were recognized within "Sales from operations" , "Purchase, services and other" and “Finance income (expense)".
Disclosures about the offsetting of financial instruments
|
(€ million) |
Gross amount of financial assets and liabilities |
Gross amount of financial assets and liabilities subject to offsetting |
Net amount of financial assets and liabilities |
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December 31, 2024 |
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Financial assets |
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Trade and other receivables |
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Other current assets |
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Other non-current assets |
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Financial liabilities |
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Trade and other liabilities |
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Other current liabilities |
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Other non-current liabilities |
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December 31, 2023 |
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Financial assets |
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Trade and other receivables |
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Other current assets |
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Other non-current assets |
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Financial liabilities |
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Trade and other liabilities |
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Other current liabilities |
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Other non-current liabilities |
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The offsetting of financial assets and liabilities related to: (i) receivables and payables pertaining to the Exploration & Production segment towards State entities for €
F-84
Legal Proceedings
Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, taking into account the existing risk provisions disclosed in note 21 — Provisions and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements.
In addition to proceedings arising in the ordinary course of business referred to above, Eni is party to other proceedings, and a description of the most significant proceedings currently pending is provided in the following paragraphs. Generally, and unless otherwise indicated, these legal proceedings have not been provisioned because Eni believes a negative outcome to be unlikely or because the amount of the provision cannot be estimated reliably.
1. Environment, health and safety
1.1 Criminal proceedings in the matters of environment, health and safety
(i) Eni Rewind SpA – Crotone omitted clean-up. In April 2017, the Public Prosecutor of Crotone initiated a criminal case relating to reclamation activities at the Crotone site. Meanwhile, the new clean-up project presented by the Company POB phase 2 was approved by the Italian Ministry for the Environment. By a court order of January 10, 2022, the judge of the preliminary hearing of Crotone ordered the performing of an independent technical assessment on the environmental status of the site which ascertained that Eni Rewind had carried out the environmental activities in its own areas in compliance with the granted authorizations. A decision of the Public Prosecutor is awaiting following the filing of this supplementary consultancy.
(ii) Eni Rewind SpA - Illegal landfill in Minciaredda area, Porto Torres site. In 2015, the Public Prosecutor of Sassari had initiated a criminal case for alleged crimes of unauthorized landfill management and environmental disaster concerning the landfill area, near the western border of the Porto Torres site (Minciaredda area), managed by Eni Rewind which was charged of being liable pursuant to Legislative Decree No. 231/01. This decree states the responsibility of legal entities for the crimes committed by their employees acting on behalf of them. The remediation and clean-up plan of the site filed by Eni Rewind was granted the necessary administrative authorization in July 2018. Upon conclusion of the investigations, the judge of the preliminary hearing resolved that the natural persons allegedly liable of the environmental crimes and the legal entity would stand trial. The court also resolved that Eni Rewind would be sued for civil liability. The region of Sardegna and other territorial administrations and NGOs were admitted in the proceeding as civil plaintiffs. Subsequently, Eni Rewind was acquitted due to the inability to proceed with the action against it pursuant to Legislative Decree No. 231/01 and definitively excluded from the criminal trial.
In the context of the criminal proceedings against the managers of Eni Rewind, however, on November 13, 2022, the Court of Sassari pronounced an acquittal sentence for the non-existence of the crime of illegal waste and for not having committed the crime of environmental disaster.
Due to the effects of the acquittal, the damage compensation claimed by the civil parties against the defendants and Eni Rewind were rejected. Since the public prosecutor and the civil parties have filed an appeal against the first instance sentence, the judgement is still pending against the Second Instance Court.
(iii) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA — Alleged environmental disaster. A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA relating to environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. The Raffineria di Gela SpA has been prosecuted for administrative offence pursuant to Legislative Decree No. 231/01. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, and pollution of the sea water near the coastal area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. The Public Prosecutor of Gela then merged into this proceeding the other investigations related to the pollution that occurred at the other sites of the Gela refinery as well as hydrocarbon spills at facilities of Eni Mediterranea Idrocarburi SpA. A first instance acquittal was issued in favor of the defendants and the Company.
F-85
(iv) Val d’Agri.
In March 2016, the Public Prosecutors of Potenza started a criminal investigation into alleged illegal handling of waste material produced at the Viggiano oil center (COVA), part of the Eni operated Val d’Agri oil complex
.
The Prosecutors ordered the house arrest of 5 Eni employees and the seizure of certain plants functional to the production activity of the Val d’Agri complex which, consequently, was shut down. From the commencement of the investigation, Eni has carried out several technical and environmental surveys, with the support of independent experts of international standing, who found a full compliance of the plant and the industrial process with the requirements of the applicable laws, as well as with best available technologies and international best practices. The Company implemented certain corrective measures to upgrade plants which were intended to address the claims made by the Public Prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those corrective measures were favorably reviewed by the Public Prosecutor. The Company restarted the plant in August 2016. In relation to the criminal proceeding, the Public Prosecutor’s Office requested the indictment of all the defendants for alleged illegal trafficking of waste, violation of the prohibition of mixing waste, unauthorized management of waste and other violations, and the Company for administrative offenses pursuant to Legislative Decree No. 231/01. The trial started in November 2017. At the conclusion of the preliminary hearings, the Court of Potenza, on March 10, 2021, acquitted all the defendants in relation to the allegation of false statements in an administrative deed, while in relation to the alleged administrative offenses, the Court found that there was no need to proceed due to the statute of limitations. Finally, in relation to the alleged crime of illegal trafficking of waste, the Court acquitted two former employees of the Southern District for not having committed the crime, convicted six former officials of the same District with suspension of the sentence and sentenced Eni pursuant to Legislative Decree No. 231/01 to pay a fine of €
(v) Proceeding Val d’Agri — Tank spill. In February 2017, following the detection of an oil leak from one of the tanks of the COVA, a criminal proceeding for alleged environmental disaster was commenced against some former COVA officers, the Operation Managers in charge since 2011 and the HSE Manager in charge at the time of the accident. Eni was investigated too, in relation to the same alleged crimes pursuant to Legislative Decree No. 231/01. In the same year, the Company promptly equipped all COVA tanks with double bottoms, complied with all regulatory requirements, carried out all necessary remediation and safety measures to ensure continuity of oil activities, after a brief shutdown, and provided compensation for damages to all the landlords of areas close to the COVA, which were affected by a spillover.
The Public Prosecutor, at the conclusion of the preliminary investigations, required the indictment for the employees and for Eni pursuant to Legislative Decree No. 231/01 At the outcome of the preliminary hearing the judge issued a sentence not to prosecute the Company for the events up to 2015 because the fact was not envisaged by the law as a crime to claim a legal entity liable for. With reference to the events subsequent to 2015, the judge acknowledged the nullity of the request for indictment, thus returning the documents to the Public Prosecutor.
Finally, the judge of the preliminary hearing approved to put on trial two Eni employees before the Court of Potenza, with the allegation of unnamed disaster. Several parties filed an application to bring a civil action and, pending assessment of the requests for exclusion presented by the defense with respect to the latter, the Court issued a summons decree from Eni, as civilly liable and Eni duly reconstituted itself. The two proceedings against natural persons - i.e., the ordinary trial and the immediate trial - were then combined by the Court into a single trial, currently pending in the initial phase.
As regards, the Company as an entity pursuant to Legislative Decree No. 231/01, the Public Prosecutor issued a new request for indictment, at the end of which the judge ordered the judgment against Eni SpA. The Court annulled this decree due to the indeterminacy of the indictment against the Company, returning the documents to the judge of preliminary hearing.
F-86
(vi) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA — Waste management of the landfill Camastra. In June 2018, the Public Prosecutor of Palermo (Sicily) notified Eni’s subsidiaries Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA of a criminal proceeding relating to allegations of unlawful disposal of industrial waste resulting from the reclaiming activities of soil, which were discharged at a landfill owned by a third party. The Prosecutor charged the then chief executive officers of the two subsidiaries, and the legal entities have been charged with the liability pursuant to Legislative Decree No. 231/01. The alleged wrongdoing related to the willful falsification of the waste certification for purpose of discharging at the landfill. The charges against the CEO of the Refinery of Gela SpA and the company itself were dismissed, while a request to put on trial the CEO of Eni Mediterranea Idrocarburi SpA and the company was approved. The proceeding is in progress before the Court of Agrigento, to which the proceeding has been transferred due to territorial jurisdiction.
(vii) Versalis SpA — Preventive seizure at the Priolo Gargallo plant. In February 2019, the Court of Syracuse at the request of the Public Prosecutor of Siracusa ordered the seizure of the Priolo/Gargallo plant as part of an ongoing investigation concerning the offenses of dangerous disposal of materials and environmental pollution, by the former plant manager of Priolo, as well as of Versalis, pursuant to Legislative Decree No. 231/01. The Public Prosecutor’s thesis, according to the consultants, is that the seized plants had points of emissions that do not comply with the Best Available Techniques (BAT), therefore resulting in violation of the applicable legislation, which determined the annulment of the seizure of the plants in March 2019, evaluating the plant improvements made by Versalis even before the seizure. In March 2021, a notice of conclusion of the preliminary investigations was thus notified, with the formulation by the Public Prosecutor of the allegations already previously stated. At present there is no news of further procedural developments.
(viii) Versalis SpA - Seizure of the treatment plant managed by IAS SpA - Priolo Gargallo. By the end of February 2022, the Public Prosecutor of Syracuse commenced a proceeding relating to alleged crimes of environmental disaster and violation of the legislation on discharges in relation to the industrial waste discharge system of the Versalis plant at the Priolo treatment plant managed by IAS SpA against two former directors of the Versalis plant in Priolo, as well as an employee of Versalis, having then a managerial role in Priolo Servizi.
The legal entities Versalis, Priolo Servizi and the other co-located companies were under investigation pursuant to Legislative Decree 231/01.
On June 15, 2022, the Judge for Preliminary Investigations ordered the seizure of the reclamation plant and the shareholding of IAS SpA, with the appointment of a judicial administrator of the assets subject to seizure. Subsequently, the investigations were enlarged to the current manager of the Versalis Plant and to the CEO of Priolo Servizi, who was an employee of Versalis SpA. Versalis SpA challenged the ‘Integrated Environmental Authorization' (“AIA”) issued to IAS before the Regional Administrative Court of Catania only for the part in which the provision is interpreted as imposing new and different limits on discharge, compared to those contained in the authorizations originally granted to the Eni’s subsidiary. In the meantime, the AIA issued for the management of the reclamation plant by IAS has been suspended by the Region of Sicily. Versalis therefore challenged before the TAR the provision to initiate a review of its AIA and, with a separate appeal, the provision of suspension of the AIA of IAS by the Region of Sicily. At the same time, the Public Prosecutor of Syracuse raised the question before the Third Instance Court which, following the hearing on May 7, 2024, declared the constitutional illegitimacy of the provision in the part in which it does not provide for the measures indicated therein to apply for a period of time not exceeding thirty-six months. A proceeding is pending before the Court of Rome relating to the authorization to continue the production activity. The proceeding was transferred to the Third Instance Court and Versalis also appealed. Meanwhile, the criminal proceeding is ongoing.
(ix) Eni SpA - Fatal accident Ancona offshore platform. On March 5, 2019, a fatal accident occurred at the Barbara F platform offshore of Ancona that resulted in the death of an Eni employee and the injury of two contractors. Two contract workers and the family of the Eni employee were all fully compensated. As part of the technical assessment of the incident, the Public Prosecutor of Ancona resolved to put under investigation two Eni employees. Also, the Company was put under investigation as entity liable pursuant to Legislative Decree No. 231/01, and two employees of the contractor company engaged in the work. At the outcome of the preliminary hearing, the Judge ordered the indictment for all the defendants and Eni. The proceeding is currently pending in the preliminary hearing phase.
F-87
(x) Raffineria di Gela SpA and Eni Rewind SpA - Groundwater pollution survey and reclamation process of the Gela site. Following complaints made by former contractors, the Public Prosecutor of Gela commenced a proceeding for allegations of environmental pollution, omitted clean-up, negligent personal injury and illegal waste management in the area of the Gela refinery, as part of the execution of clean-up of soil and groundwater as well as decommissioning activities in the area currently managed by Eni Rewind SpA, also on behalf of the companies Raffineria di Gela SpA, ISAF SpA (in liquidation) and Versalis SpA with respect to the efficiency and efficacy of the barrier system. The Public Prosecutor carried out various checks and investigations, and then proceeded with a preventive seizure, with reference to the plants used for the remediation of the site's underground water currently managed by Eni Rewind as well as the plant areas intended for the implementation of the groundwater remediation project. A judicial administrator was appointed to manage those facilities.
The judicial administrator filed an initial technical report in which he confirmed that the clean-up activities were being executed in compliance with the legislation and with a series of implementation improvements by the company in agreement with other parties in charge. The Public Prosecutor's Office also issued a summon decree. On January 29, 2025, following the first-instance hearing, the Court of Gela issued a sentence of acquittal "because the fact does not exist" against all the defendants, simultaneously ordering the revocation of the seizure and the appointment of the judicial administrator.
(xi) Eni Rewind SpA and Versalis SpA - Mantua. Environmental crime investigation . With regard to the Mantua site, where the company is executing duly authorized environmental activities, in August and September 2020, the Public Prosecutor notified the conclusion of a preliminary investigation relating to several criminal proceedings. Several employees of the Eni’s subsidiaries Versalis SpA and Eni Rewind SpA as well as of a third-party company Edison SpA were notified of being under investigation. Furthermore, the above-mentioned legal entities were being investigated pursuant to Legislative Decree No. 231/01. The Public Prosecutor is alleging, with respect to some specific areas related to the Mantua industrial hub, the crimes of unauthorized waste management, environmental damage and pollution, omitted communication of environmental contamination and omitted clean-up. Following the filing of defense briefs addressed to the investigating authority, the case has been dismissed against some individuals and archived. The Public Prosecutor’s Office then requested the indictment of the remaining defendants. During the Preliminary Hearing, the MITE, the Province of Mantua, the Municipality of Mantua and Mincio Regional Park were allowed in the trial as plaintiffs, while the companies Eni Rewind, Versalis and Edison were instead sued as civil parties and therefore they appeared in court. The Preliminary Hearing Phase ended with the provision of GUP, which ordered the indictment of all the defendants and of the abovementioned companies, with the exception of a former employee of Versalis and of two Edison employees. The proceeding is pending on the trial phase.
(xii) Eni SpA R&M Depot of Civitavecchia - Criminal proceedings for groundwater pollution. In the period in which Eni was in charge of the Civitavecchia storage hub (2008-2018), pending the approval of a characterization plan of the environmental status of the site, the Company, in coordination with public authorities, adopted measures to preserve the safety of the groundwaters and to pursue the clean-up process of the site until its disposal.
The Public Prosecutor of Civitavecchia contested, among others, the former manager of the Eni fuel storage hub of Civitavecchia, the alleged crime of environmental pollution. Eni is under investigation pursuant to Legislative Decree No. 231/01. The first instance proceeding is underway.
F-88
(xiii) Eni SpA R&M Genoa Pegli storage hub - Criminal proceeding for crude oil spill - September 2022 . Following a crude oil spill that occurred at the Genoa Pegli depot on September 27, 2022, the Public Prosecutor's Office of Genoa instituted criminal proceedings for the alleged crime of culpable environmental disaster, charged against four Eni employees, while the Company is charged with an administrative offense pursuant Legislative Decree No. 231/01. The proceeding is pending in the preliminary investigation phase.
(xiv) Sannazzaro Refinery - Proceeding in relation to alleged criminal environmental pollution and discharge - Public Prosecutor's Office of Pavia. A criminal proceeding is pending for alleged crimes of environmental pollution and lack of remediation against some pro-tempore directors and HSE managers of the refinery located at Sannazzaro de' Burgondi who are under investigation, as well as Eni SpA pursuant to the Legislative Decree no. 231/2001, in relation to the alleged crime of environmental pollution on site, with a seizure of the sewage treatment plant (TAE), and possible expansion of the area affected by possible pollution beyond the site's hydraulic barriers.
On November 28, 2023, the TAE plant was released from seizure. The Prosecutor's Office has ordered three unrepeatable technical investigations, during which further complaints regarding further environmental complaints. At the conclusion of the preliminary investigation phase, the allegations raised were confirmed.
(xv) Eni SpA - Pomezia depot – Involuntary environmental pollution. A criminal proceeding is ongoing concerning an alleged crime of pollution of the groundwater underlying the fuel depot in Pomezia attributable, according to the indictment, to product leaks from the tanks.
The Public Prosecutor's Office has appointed its consultants to carry out a technical review of the site to verify the state of environmental contaminations at the tanks. As a result of these assessments, two Eni's employees as well as Eni SpA pursuant to Legislative Decree no. 231/01 were notified of being under investigation for the alleged crime. Subsequently, the Public Prosecutor issued a request for indictment and, following the preliminary hearing, the trial was issued. The proceeding is pending at the stage of initiation of the first instance judgement.
(xvi) Eni SpA - Calenzano depot - explosion. The proceeding concerns the fatal accident which caused the death of five contractors of Eni due to an explosion occurred during the carrying out of operations at the fuel storage site in Calenzano (Florence) on December 9, 2024, and the consequential order of seizure of the site from the Judicial authorities. The proceeding was initially charged against unknown persons for aggravated multiple involuntary manslaughter, willful omission of precautions against accidents at work and unnamed disaster. The Public Prosecutor's Office appointed a pool of technical consultants to ascertain dynamics and causes of the event and identify any responsibilities and, in the course of the investigations carried out so far, several perquisitions were executed with the acquisition of all the requested documentation, spontaneously delivered by the Company. Recently, the Public Prosecutor's Office has notified a notice of investigation against the Employer and Manager of the Calenzano storage hub and other Managers and operators of technical operational areas related to the activities of the site, as well as two employees of a supplier, for the alleged crime of complicity in multiple involuntary manslaughter, complicity in multiple negligent personal injuries and complicity in unnamed negligent disaster, as well as against Eni SpA pursuant to Legislative Decree 231/01. At the same time, the Public Prosecutor's Office has requested a probatory incident from the Judge for Preliminary Investigations to carry out an expert assessment.
The Company is collecting all requests for compensation in relation to any material and non-material damage that has occurred for their settlement, regardless of any aspect of the merits of the matter. A provision has been accrued considering a preliminary estimate of the damages resulting from the event. The case is still pending in the preliminary investigation phase.
1.2 Civil and administrative proceedings in the matters of environment, health, safety and antitrust
(i)
Republic of Kazakhstan / Eni SpA, Agip Karachaganak BV et al.
The Republic of Kazakhstan (“Rok”) promoted an international arbitration against the consortium of international oil companies that manage the Karachaganak fields, pursuant to the Final Production Sharing Agreement which governs the project activities (Eni’s share
(ii) Republic of Kazakhstan/ Agip Caspian Sea BV et al.
The Republic of Kazakhstan (“Rok”) promoted a further international arbitration, pursuant to the North Caspian Sea Production Sharing Agreement “NCSPSA” against the Contractor (Eni’s share
(iii) Administrative proceeding – Novamont. In 2024, the Italian Competition and Market Authority (ACGM) initiated a proceeding against Novamont SpA, notifying its parent company Eni SpA for alleged abuse of a dominant position in the bioplastics market. In February 2025, AGCM sent the company a communication of the investigation results.
As of the date of filing of the Financial Statements, the investigation results are being analyzed for the purposes of the subsequent procedural phases. The Company believes it has valid defense elements to support the correctness of its actions.
(iv) Eni Rewind SpA — Versalis SpA — Eni SpA (R&M) — Augusta Harbor. The complex administrative dispute relating to the environmental status of the Augusta harbor commenced in September 2017 with a formal notice issued by the Ministry of the Environment against the companies operating at the Priolo petrochemical hub, including Eni Rewind, Polimeri Europa (now Versalis) and Eni (R&M), to present projects for sediments removal from the harbor on the basis of an alleged assessment of responsibility as per a ruling of the Regional Administrative Court of Catania in 2012. The Ministry on various occasions reiterated its own assessment about the environmental responsibility of the companies co-located at the Priolo hub with respect to the pollution of the harbor and warned them against carrying out remediation activities. Following various meetings held with the Ministry of the Environment, Eni Rewind offered to define and to plan for certain environmental remediation activities basing on updated environmental data. The Eni’s subsidiary also commenced activities to identify the persons responsible of the pollution of the harbor and their respective shares of liability.
In September 2020 Eni Rewind took part in the Investigation Services Conference convened by the Ministry of the Environment and the competent bodies and presented a review of the environmental status of the Rada which stated that the pollution was attributable to industrial activities of prior periods and that it would not spread into the surrounding environment.
F-89
Between the end of 2023 and the beginning of 2024, the Catania Regional Administrative Court issued a ruling on all the appeals presented by the operators, deeming them as inadmissible, because the injunction does not constitute an act suitable for having legal efficacy with respect to the appellants. The Court did not take a position on the existence of the pollution or otherwise did not make any conclusion about responsibility regarding the pollution of the harbor, limiting itself to highlighting the fact that the proceeding administration believes that the pollution is matter of fact. For this reason, on June 27, 2024, the Group companies challenged the TAR sentences limited to an interpretation of the same as confirming the existence of a final judgment on the responsibility for the contamination.
(v) Eni SpA – Eni Rewind SpA – Raffineria di Gela SpA – Claim for preventive technical inquiry and judgments on the merits. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and Eni Rewind SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified of a claim issued by the parents of children with birth defects in the Municipality of Gela between 1992 and 2007 for a total of 30 cases. The claim called for an inquiry aimed at determining any causality between the birth defects suffered by these children and any environmental pollution caused by the Gela site, quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. The same issue was the subject of previous criminal proceedings, of which one closed without determining any illegal behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. In May 2018, the Court issued a first instance judgment concerning one case. The Judge rejected the claim for damages, acknowledging the arguments of the defendant companies in relation to the absence of evidence concerning the existence of a causal link between the birth defects and the alleged industrial pollution. The judgment has been appealed by the claimants.
In June 2021 the Civil Court of Gela issued a second judgment rejecting the claim for compensation, recognizing the validity of the arguments of the defendant companies regarding the lack of evidence on the existence of a cause between the pathology and the alleged industrial pollution. The counterparties filed an appeal.
In relation to the first appeal promoted against the first ruling of the Court of Gela, the First Instance Court of Caltanissetta rejected the appeal proposed and accepted the one proposed incidentally by the Eni companies involved, concerning the regulation of litigation costs relating to the first instance proceedings and the reported incorrectness of the compensation made therein since the legal requirements were not met. The counterparty appealed to the Third Instance Court. In 2024, the Court of Gela issued two other sentences with which the plaintiffs' requests for compensation were rejected. The First Instance Court confirmed the rejection of the claims brought against Eni’s subsidiaries basing on lack of a causal link between the pathologies and the alleged industrial pollution.
(vi) Val d’Agri - Eni / Vibac. In September 2019 a claim was brought in the Court of Potenza against Eni. The plaintiffs are 80 people, living in different municipalities of the Val d’Agri area, who are complaining of economic, non-economic, biological and moral damages, all deriving from the presence of Eni’s oil facilities in the territory. The Judge has been asked to ascertain Eni's responsibility for causing emissions of polluting substances into the atmosphere. The plaintiffs have also requested that Eni be ordered to interrupt any polluting activity and be allowed to resume industrial activities on condition that all the necessary remediation measures be implemented to eliminate all of the alleged dangerous situations. Finally, they are asking Eni for compensation for damages. At the end of the trial phase, the Judge submitted to the parties the proposal for an extra-judicial settlement, fixing a deadline to present further proposals on the matter.
The parties did not adhere to the conciliatory proposal. The Judge deemed the case ripe for a decision and set the hearing to clarify the conclusions for July 10, 2026.
F-90
(vii) Eni Rewind SpA / Province of Vicenza – Clean-up process for Trissino site. On May 7, 2019, the Province of Vicenza issued a warning, imposing on certain individuals and companies as MITENI SpA in bankruptcy, Mitsubishi and ICI the obligation to clean-up the Trissino site where MITENI carried out its industrial activity. Based on the analysis carried out by administrative parties, significant concentrations of substances considered highly toxic and carcinogenic were allegedly discovered in groundwater and in surface water at this site. The analysis carried out by the Province of Vicenza with the direct involvement of the Istituto Superiore di Sanità reported the presence of these substances in the blood of about 53,000 people in the area. The Province warned some individuals, including a former employee who served between 1988 and 1996 as CEO of EniChem, a company that was subsequently acquired by Eni Rewind.
Eni Rewind was summoned as the “successor” of EniChem in several appeals before the Regional Administrative Court as the majority shareholder of MITENI, as well as liable for the potential contamination of Trissino plant (together with other subjects). The Province extended the proceeding also to Eni Rewind, which filed a counterclaim for having its position taken out of the procedure.
Eni Rewind appealed to a Regional Administrative Court against the Province claims and orders. Eni Rewind is carrying out the environmental interventions and has made itself available to carry out - as part of the project approved by the territorial administrations in charge- further anti-pollution interventions on a voluntary basis and without giving any acquiescence with respect to the liability charges for the pollution by chemical agents. The Province extended the identification of the person responsible for the pollution also to Manifatture Lane Marzotto & Figli Spa which challenged the relevant provision before the Regional Administrative Court. This act was also challenged by ICI3 and Eni Rewind in the part in which, unlike what was ordered by the Province towards the other companies identified as responsible for the pollution, it does not order Manifatture Lane Marzotto & Figli SpA to carry out the environmental interventions. With sentences issued in May 2024, the Regional Administrative Court ruled on the appeals brought by ICI3 and Mitsubishi regarding the measure to identify the person responsible for the pollution. The administrative judge rejected the appeals, deeming the Province's actions legitimate. Similarly, with a ruling dated December 27, 2024, the Regional Administrative Court also rejected Eni Rewind's appeal, confirming the identification measures adopted by the Province as responsible for the pollution. The Company is considering to appeal the sentence. Discussions are underway with the companies involved to reach a transaction agreement regarding cleanup and remediating costs of the site.
(viii) Eni SpA - Greenpeace Onlus, ReCommon APS and others - Climate dispute.
On May 9, 2023, the NGOs Greenpeace Onlus and ReCommon APS, together with 12 private citizens, summoned Eni, the Ministry of Economy and Finance (MEF) and an Italian agency, Cassa Depositi e Prestiti (CDP), before the Civil Court of Rome based on allegations of climate change responsibility. The plaintiffs claimed economic losses and other damages and requested that Eni revise its decarbonisation strategy (for example by reducing by
The parties appeared in Court, promptly filing deeds and documents. On June 10, 2024, the plaintiffs promoted a separate proceeding for the settlement of jurisdiction, remitting the final decision regarding the jurisdiction of the Court of Rome seized of the merits proceedings to the Third Instance Court. On July 11, 2024, the Court of Rome ordered the suspension of the proceedings on the merits until the definition of the jurisdiction regulation proposed by the plaintiffs. Eni promptly appeared before the Third Instance Court. The proceeding is ongoing.
F-91
(ix) Eni SpA - NAOC / Egbema Voice of Freedom Association - Request for compensation for damages.
On November 30, 2023, Eni SpA was notified of a summons relating to a claim advanced by Pastor Nicholas Evaristus Ukaonu, by the Advocates for Community Alternatives association and by the Egbema Voice of Freedom association, for alleged damages deriving from constructions created by NAOC in Nigeria in the territory of the communities represented by the associations. The Pastor and the associations ask for joint compensation from Eni and NAOC for approximately €
(x) Eni Rewind SpA/Calabria Region - Province and Municipality of Crotone - WWF Italy - ARCI and others (Regional Administrative Court of Catanzaro). A decree of the Ministry of the Environment of August 1, 2024 n. 27 ordered the beginning of excavations for the execution of the reclamation of the Site of National Interest of Crotone upon the occurrence of certain conditions and ordered the Calabria Region to start the procedure for removing the constraint from Single Regional Authorization Provision (“PAUR”), which authorized the construction of the D15 - preliminary deposit and D9 plants. Several public entities, as well as the WWF and ARCI associations have challenged the decree with a precautionary application before the Regional Administrative Court. The constraint imposed by the Region in the PAUR obliges Eni Rewind to dispose of waste outside the regional territory; various checks carried out by the Company and confirmed by public entities have confirmed that the only authorized plant capable of receiving hazardous waste from the reclamation is in Crotone. This conclusion was also substantially confirmed by scouting among foreign operators (provided for by the ministerial decree) from which it emerged that only 2 entities (out of almost 30 contacted) are available to accept the hazardous waste coming from the reclamation of the site of Crotone, in a context characterized by regulatory, administrative, timing and logistical uncertainties that are not compatible with the reclamation timetable. The Region's resistance to removing the restriction has so far prevented the start of remediation activities at the site. WWF and ARCI also challenged the order of the Ministry (dated September 24, 2024) requiring Eni Rewind to commence remediation activities. The Company carried out all the preparatory activities for the beginning of the works, implementing the provisions of the Decree. In January 2025, the local authorities warned Eni Rewind and the company in charge of the Crotone landfill not to sign the waste disposal contract and therefore, the remediation activities have yet to start. Eni Rewind (and Edison) appealed against these warnings to the Regional Administrative Court, which requested a report on the environmental remediation plan from the Ministry and set the hearing of the merits for June 18, 2025, together with the appeals against the warnings filed by Eni Rewind.
F-92
2. Settled proceedings
(i) Eni SpA R&M Refinery of Livorno - Criminal proceedings for incidents at work. On October 20, 2020, a notice was served at the Livorno refinery for Eni as entity subjected to preliminary investigations in the context of a criminal proceeding pending before the Public Prosecutor's Office of Livorno, in relation to an accident at work occurred in summer of 2019 at an electrical substation of the Refinery and as consequence two employees were injured. The company provided compensations. The allegation was aggravated by personal injury while the Company was accused of being liable pursuant to Legislative Decree No. 231/01.
In September 2021, the Public Prosecutor's Office issued a notice of conclusion of the preliminary investigations. Subsequently, the summons order was notified. Following the outcome of the first level of judgement, on March 12, 2024, the Court issued a sentence of acquittal of the accused natural persons and of Eni SpA pursuant to Legislative Decree. 231/01. The acquittal sentence was not contested and therefore became final.
(ii) Eni SpA - Eni Oil&Gas Inc - Climate change . Between 2017 and 2018, seven lawsuits were brought in the California state court by local government authorities and a fishermen's association against Eni SpA, a subsidiary (Eni Oil & Gas Inc – “EOG”) and several other companies, aimed at obtaining compensation for damages attributable to the increase in sea level and temperature as well as to hydrogeological instability.
On April 25, 2023, the Supreme Court assigned the six government-issued lawsuits to California State Courts. On December 14, 2023, the fishermen's association, having failed to obtain a referral to State Court, voluntarily withdrew from the case. On August 27, 2024, after the meeting before the Court of San Francisco of the remaining pending disputes, as part of the personal jurisdiction evaluation phase (aimed at verifying the effective existence of jurisdiction of the competent court with respect to the defendants), both Eni and EOG were definitively excluded from the relevant proceedings, having accepted the plaintiffs' proposal to conclude the case by settlement, without any admission of liability by Eni and without any possibility of change of mind on the part of the plaintiffs, committing themselves to pay only modest procedural costs.
(iii) OPL 245 Nigeria. In relation to the stipulation between Eni, the Government of the Federal Republic of Nigeria "FGN" and another international oil company of the Resolution Agreement of April 29, 2011 relating to the "Oil Prospecting Licence" of the offshore field identified in block 245, several investigations had been opened by the judicial authorities of Italy, UK and Nigeria concerning alleged crimes in the assignment of the block, including the crime of international corruption. The investigations involved some top managers of Eni and of the Company itself pursuant to Legislative Decree no. 231/01. Eni basing also on the findings of an internal review of the case performed by an independent US legal consultant appointed by the Company’s board of statutory auditors and by the Watch body considered the accusations groundless. The US Department of Justice carried out its own inquiry basing on the US FCPA and dismissed the case without any liability in 2019. The UK prosecutors dismissed the case due to lack of jurisdiction.
The proceeding in Italy established by the Public Prosecutor of Milan, which had requested the indictment of the Eni managers involved and of the Company, was resolved in a manner totally favorable to Eni with a sentence of acquittal for all the defendants because the fact did not exist. The appeal proceedings, promoted by the First Instance public prosecutors, and by the FGN as civil party, concluded during 2022, reaffirming the first instance acquittal sentence which therefore became final.
Finally, FGN, which in 2023 had promoted an appeal to the Third Instance Court against the ruling of the Court of Milan, requesting its annulment with referral to the competent civil judge for the sole purpose of civil rulings and damage compensation, withdrew the appeal to the Third Instance Court, as it was inferred from a letter signed by the Attorney General transmitted after two hearings of the ICSID arbitration held in London. This arbitration was promoted by Eni after the acquittal sentence to protect the investment, requesting the forced conversion of the exploration license (OPL 245) into an extractive license (OML) as well as $
The proceeding, mainly focused on the accusations against Nigerian individuals (including the Minister of Justice in office in 2011, at the time of the disputed facts), has involved NAE and Shell Nigeria Exploration and Production Company Limited (“SNEPCO”) as co-holders of the OPL 245 license. These Nigerian individuals were accused in 2011 of illicit corruption, which NAE and SNEPCO allegedly unlawfully facilitated. The beginning of the trial, originally scheduled for the end of March 2020, was postponed as a result of the closure of judicial offices in Nigeria due to the COVID-19 emergency and resumed at the beginning of 2021. During the proceedings, several witnesses were heard, mainly summoned at the request of the “Economic and Financial Crimes Commission” (“EFCC”). Considering the weakness of the evidence produced by the EFCC, the defendants presented a request for a declaration of no need to proceed, which the EFCC did not oppose for the part relating to the accusations made against NAE, SNEPCO and the Minister of Justice.
F-93
(iv) Enimed SpA – Criminal proceedings for alleged evasion of payment of the excise duty on flux products.
The criminal case derived from an investigation by the financial police of Ragusa which led to the verification in May 2020 of a series of incidents of theft of flux - an energy product used in suspension of excise duty - stolen directly from Enimed pipelines by arrested third parties flagrantly. As a result of the investigations, the Company was firstly charged with irregularities in the management of the diesel flux with alleged subtractions of indirect taxes (excise duties and VAT) equal to approximately €
(v) Eni SpA (R&M) – Taranto Refinery - Criminal proceedings for breach of excise assessment. The proceeding relates to the alleged lack of tax assessment of an energy product moved, under excise duty suspension, from a tank of the Taranto refinery.
At the end of the preliminary investigation phase, the former manager of the refinery and three other employees resulted under investigation for an alleged continued hypothesis of subtraction from the assessment of excise duties, due to multiple movements that took place in the period from June 30 to September 9, 2021, from the tank under investigation, the meter of which has been seized since October 13, 2021. Following the hearing on December 17, 2024, the Public Prosecutor of Taranto pronounced an acquittal sentence against all the defendants because the fact does not exist.
(vi) Eni SpA – Eni Rewind SpA – Priolo – Malformation civil lawsuits.
In February 2022 Eni Rewind was sued before the Court of Syracuse for compensation for damages (€
Eni Rewind filed an appearance in court filing a claim and indemnification against Edison, taking into account that the chlor-soda plant was received by Eni group as part of the Enimont transaction, therefore in a period following the alleged exposure to the mercury by the actors, which necessarily occurred between the years of birth 1972 and 1975. Following the incorporation of Edison SpA and the celebration of the respective hearings, the two proceedings are currently in the preliminary investigation phase. The proceeding has become immaterial.
F-94
Assets under concession arrangements
Eni operates under concession arrangements mainly in the Exploration & Production segment and the Enilive business line. In the Exploration & Production segment, contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. Pursuant to the assignment of mineral concessions, Eni sustains all the operational risks and costs related to the exploration and development activities and it is entitled to the productions realized. In respect of the mining concessions received, Eni pays royalties in accordance with the tax legislation in force in the country and is required to pay income taxes deriving from the exploitation of the concession. In production sharing agreement and service contracts, realized productions are defined based on contractual agreements with State oil companies, which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to the own portion of the realized productions (Profit Oil). In the Enilive business line, several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. In exchange for the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties based on quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration.
Environmental regulations
In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses or significant responsibilities because, at the current state of knowledge, it is impossible to forecast the effects of future developments taking into account, among other things, the following aspects: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.
Emission trading
From 2021, the fourth phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The award of free emission allowances is performed based on emission benchmarks defined at European level specific to each industrial segment, except for the electric power generation sector that is not eligible for allocations for no consideration. At the same time, emissions trading (UK ETS) was introduced in the United Kingdom, the rules of which are largely similar to those of the EU-ETS. This regulatory scheme implies for Eni’s plants subject to emission trading a lower assignment of emission permits compared to the emissions recorded in the relevant year and, consequently, the necessity of covering the amounts in excess by purchasing the relevant emission allowances on the open market. In 2024, the emissions of carbon dioxide from Eni’s plants were higher than the free allowances assigned to Eni. Against emissions of carbon dioxide amounting to approximately
F-95
29 Revenues and other income
Sales from operations
|
(€ million) |
Exploration & Production |
Global Gas & LNG Portfolio and Power |
Refining and Chemicals |
Enilive |
Plenitude |
Corporate and Other activities |
Total |
|
2024 |
|
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|
|
|
|
|
|
Sales from operations |
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|
|
|
|
Products sales and service revenues |
|
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|
Sales of crude oil |
|
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Sales of oil products |
|
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|
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|
Sales of natural gas and LNG |
|
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|
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Sales of petrochemical products |
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|
|
|
|
|
Sales of power |
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|
|
|
|
|
Sales of other products |
|
|
|
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|
|
|
|
Services |
|
|
|
|
|
|
|
|
Products sales and service revenues |
|
|
|
|
|
|
|
|
Transfer of goods/services |
|
|
|
|
|
|
|
|
Goods/Services transferred in a specific moment at a point in time |
|
|
|
|
|
|
|
|
Goods/Services transferred over a period of time |
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
Products sales and service revenues |
|
|
|
|
|
|
|
|
Sales of crude oil |
|
|
|
|
|
|
|
|
Sales of oil products |
|
|
|
|
|
|
|
|
Sales of natural gas and LNG |
|
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|
|
|
|
|
|
Sales of petrochemical products |
|
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|
|
|
|
|
|
Sales of power |
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Sales of other products |
|
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Services |
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|
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Products sales and service revenues |
|
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|
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|
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Transfer of goods/services |
|
|
|
|
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|
Goods/Services transferred in a specific moment at a point in time |
|
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Goods/Services transferred over a period of time |
|
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|
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|
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2022 |
|
|
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|
|
|
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|
Sales from operations |
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Products sales and service revenues |
|
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Sales of crude oil |
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Sales of oil products |
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Sales of natural gas and LNG |
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Sales of petrochemical products |
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Sales of power |
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Sales of other products |
|
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Services |
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Products sales and service revenues |
|
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Transfer of goods/services |
|
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Goods/Services transferred in a specific moment at a point in time |
|
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Goods/Services transferred over a period of time |
|
|
|
|
|
|
|
|
(€ million) |
2024 |
2023 |
2022 |
|
Revenues associated with contract liabilities at the beginning of the period |
|
|
|
|
Revenues associated with performance obligations totally or partially satisfied in previous years |
|
|
|
F-96
Sales from operations by industry segment and geographic area of destination are disclosed in note 35 – Segment information and information by geographic area.
Sales from operations with related parties are disclosed in note 36 – Transactions with related parties.
Other income and revenues
|
(€ million) |
2024 |
2023 |
2022 |
|
Gains from sale of assets and businesses |
|
|
|
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Other proceeds |
|
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|
Other proceeds include: (i) €
Other income and revenues with related parties are disclosed in note 36 – Transactions with related parties.
30 Costs
Purchase, services and other charges
|
(€ million) |
2024 |
2023 |
2022 |
|
Production costs - raw, ancillary and consumable materials and goods |
|
|
|
|
Production costs - services |
|
|
|
|
Lease expense and other |
|
|
|
|
Net provisions for contingencies |
|
|
|
|
Other expenses |
|
|
|
|
|
|
|
|
|
less: |
|
|
|
|
- capitalized direct costs associated with self-constructed assets - tangible assets |
(
|
(
|
(
|
|
- capitalized direct costs associated with self-constructed assets - intangible assets |
(
|
(
|
(
|
|
|
|
|
|
Purchase, services and other charges included geological and geophysical expenses for €
Costs incurred in connection with research and development activities and technological improvement expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €
Royalties on the extraction rights of hydrocarbons amounted to €
Additions to provisions net of reversal of unused provisions related to: (i) net additions to the environmental provision for €
Information about leases is disclosed in note 13 – Right-of-use assets and lease liabilities.
F-97
Payroll and related costs
|
(€ million) |
2024 |
2023 |
2022 |
|
Wages and salaries |
|
|
|
|
Social security contributions |
|
|
|
|
Cost related to employee benefit plans |
|
|
|
|
Other costs |
|
|
|
|
|
|
|
|
|
less: |
|
|
|
|
- capitalized direct costs associated with self-constructed assets - tangible assets |
(
|
(
|
(
|
|
- capitalized direct costs associated with self-constructed assets - intangible assets |
(
|
(
|
(
|
|
|
|
|
|
Other costs comprised provisions for redundancy incentives of €
Cost related to employee benefit plans are described in note 22 – Provisions for employee benefits.
Costs with related parties are disclosed in note 36 – Transactions with related parties.
Average number of employees
The Group average number and breakdown of employees by category is reported below:
|
|
2024 |
2023 |
2022 |
|||
|
(number) |
Subsidiaries |
Joint operations |
Subsidiaries |
Joint operations |
Subsidiaries |
Joint operations |
|
Senior managers |
|
|
|
|
|
|
|
Junior managers |
|
|
|
|
|
|
|
Employees |
|
|
|
|
|
|
|
Workers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The average number of employees was calculated as the average between the number of employees at the beginning and the end of the year.
The average number of senior managers included managers employed in foreign countries, whose position is comparable to a senior manager’s status.
Long-term share-based incentive plan for the Eni’s managers
Eni has in place a share-based compensation plan to retain its managers, with awards outstanding as of the balance sheet date.
On May 13, 2020 and on May 10, 2023, the Shareholders Meeting approved the Long-Term Shared-based Incentive Plan 2020-2022 and the similar 2023-2025 plan which award up to a maximum of
Each plan provides
The vesting features of those share-based compensation schemes are linked to achievement of Company’s preset targets of financial results, share appreciation as benchmarked against a peer group’s performance, and certain KPIs of environmental sustainability and emission reduction, in a proportion of
Depending on the performance of the parameters mentioned above, the number of shares that will vest free of charge after
F-98
The number of shares awarded at the grant date was: (i)
The estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plans (stochastic method for both Long-Term Monetary Incentive plan), taking into account the fair value of the Eni share at the grant date (between €
In 2024, the costs related to the long-term monetary incentive plan, recognized as a component of the payroll cost with contra-entry to equity reserves as they pertain to company employees, amounted to €
Employee Stock Ownership Plan
The Shareholders' Meeting held on May 15, 2024, authorized the adoption of an Employee Stock Ownership Plan, with the aim of strengthening motivation and retention across the company and the participation in the growth of corporate value, in line with the interests of the shareholders. The Plan provides for
For 2024, Eni awarded a one-time stock-based compensation for no consideration to
At the grant date (November 27, 2024), a total of
Consistent with the substantial nature of remuneration, pursuant to the provisions of international accounting standards, the cost of the plan is determined with reference to the fair value of the shares on the assignment date. The recording of the cost will take place pro-rata temporis over the three-year period.
Costs relating to the Employee Stock Ownership Plan, recognized as a component of payroll cost amounted to €
Compensation of key management personnel
Compensation, including contributions and collateral expenses, of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office during the year consisted of the following:
|
(€ million) |
2024 |
2023 |
2022 |
|
Wages and salaries |
|
|
|
|
Post-employment benefits |
|
|
|
|
Other long-term benefits |
|
|
|
|
Indemnities upon termination of employment |
|
|
|
|
|
|
|
|
Compensation of Directors and Statutory Auditors of Eni SpA
Compensation of Directors amounted to €
Compensation included emoluments and social security benefits due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group, even if not subject to personal income tax.
31 Finance income (expense)
|
(€ million) |
2024 |
2023 |
2022 |
|
Finance income |
|
|
|
|
Finance expense |
(
|
(
|
(
|
|
Net finance income (expense) from financial assets at fair value through profit or loss |
|
|
(
|
|
Income (expense) from derivative financial instruments |
|
(
|
|
|
Finance income (expense) |
(
|
(
|
(
|
F-99
The analysis of finance income (expense) was as follows:
|
(€ million) |
2024 |
2023 |
2022 |
|
Finance income (expense) related to net borrowings |
|
|
|
|
Interest and other finance expense on ordinary bonds |
(
|
(
|
(
|
|
Net finance income (expense) on financial assets held for trading |
|
|
(
|
|
Net income (expenses) on other financial assets valued at fair value with effects on profit and loss |
|
|
(
|
|
Interest and other expense due to banks and other financial institutions |
(
|
(
|
(
|
|
Interest expense on lease liabilities |
(
|
(
|
(
|
|
Interest from banks |
|
|
|
|
Interest and other income on financial receivables and securities held for non-operating purposes |
|
|
|
|
|
(
|
(
|
(
|
|
Exchange differences |
(
|
|
|
|
Income (expense) from derivative financial instruments |
|
(
|
|
|
Other finance income (expense) |
|
|
|
|
Interest and other income on financing receivables and securities held for operating purposes |
|
|
|
|
Capitalized finance expense |
|
|
|
|
Finance expense due to the passage of time (accretion discount) (a) |
(
|
(
|
(
|
|
Other finance income (expense) |
(
|
(
|
(
|
|
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
(a) The item relates to the increase in provisions for contingencies that are shown at present value in non-current liabilities.
Information about leases is disclosed in note 13 – Right-of-use assets and lease liabilities.
The analysis of derivative financial income (expense) is disclosed in note 24 – Derivative financial instruments and hedge accounting.
Finance income (expense) with related parties is disclosed in note 36 – Transactions with related parties.
32 Income (expense) from investments
Share of profit (loss) of equity-accounted investments
More information is provided in note 16 – Investments.
Share of profit or loss of equity accounted investments by industry segment is disclosed in note 35 – Segment information and information by geographical area.
Other gain (loss) from investments
|
(€ million) |
2024 |
2023 |
2022 |
|
Dividends |
|
|
|
|
Net gain (loss) on disposals |
|
|
|
|
Other net income (expense) |
|
|
|
|
|
|
|
|
Dividend income primarily related to Nigeria LNG Ltd for €
Gains on disposals for 2024 referred: (i) for €
Other net income for 2024 referred for €
F-100
Gains on disposals for 2023 referred to the capital gain realized from the sale to Snam of the
Gains on disposals for 2022 referred to the capital gains realized following the listing, through IPO on the Oslo Stock Exchange, of the investee Vår Energi ASA and subsequent sales made on the market.
Other net income for 2022 referred for €
33 Income taxes
|
(€ million) |
2024 |
2023 |
2022 |
|
Current taxes: |
|
|
|
|
- Italian subsidiaries |
(
|
|
|
|
- subsidiaries of the Exploration & Production segment - outside Italy |
|
|
|
|
- other subsidiaries - outside Italy |
|
|
|
|
|
|
|
|
|
Net deferred taxes: |
|
|
|
|
- Italian subsidiaries |
(
|
(
|
(
|
|
- subsidiaries of the Exploration & Production segment - outside Italy |
|
(
|
|
|
- other subsidiaries - outside Italy |
|
(
|
(
|
|
|
(
|
(
|
(
|
|
|
|
|
|
Current income taxes of Italian subsidiaries include the net effect of the use of tax-suspended reserves for €
Income taxes for 2022 included an extraordinary solidarity tax for the year 2022 (€
In 2023, Italy substantively enacted Pillar Two Model Rules, effective as from January 1, 2024, through Legislative Decree 209/2023 as mandated by EU Directive 2022/2523. The Pillar Two rules are designed to ensure large multinational enterprises (meeting certain conditions) pay a minimum level of tax on the income arising in each jurisdiction where they operate. The impact of Pillar Two rules on current income taxes for 2024 was immaterial. Eni has applied the exception, as set out in the amendments to IAS 12 Income Taxes, to recognizing and disclosing information about deferred tax assets and liabilities related to Pillar Two income taxes.
The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of
|
(€ million) |
2024 |
2023 |
2022 |
|
Profit (loss) before taxation |
|
|
|
|
Tax rate (IRES) (%) |
|
|
|
|
Statutory corporation tax charge (credit) on profit or loss |
|
|
|
|
Increase (decrease) resulting from: |
|
|
|
|
- higher tax charges related to subsidiaries outside Italy |
|
|
|
|
- tax effect on reserve distribution |
|
|
|
|
- impact pursuant to foreign tax effects of Italian entities |
|
|
|
|
- effect due to the tax regime provided for intercompany dividends |
|
|
|
|
- tax effects related to previous years |
|
|
(
|
|
- Italian regional income tax (IRAP) |
(
|
|
(
|
|
- effect of the valuation of the investments under the equity method |
(
|
(
|
|
|
- effect of reversals (impairments) of deferred tax assets |
(
|
(
|
(
|
|
- impact pursuant to (reversal) impairment of deferred tax assets |
(
|
(
|
(
|
|
- extraordinary contribution effect for companies in energy sector |
|
|
|
|
- other adjustments |
(
|
(
|
(
|
|
|
|
|
|
|
Effective tax charge |
|
|
|
F-101
The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €
Group’s effective tax rate amounted to
34 Earnings (loss) per share
Basic earnings (loss) per ordinary share are calculated by dividing profit (loss) for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.
Diluted earnings (loss) per share are calculated by dividing the profit (loss) of the period attributable to Eni’s shareholders by the weighted average number of shares fully diluted, excluding treasury shares, and including the number of potential shares to be issued. As of December 31, 2024, the shares that could be potentially issued related to the estimation of new shares that will vest in connection with the 2020-2022 and 2023-2025 long-term monetary incentive plans and the convertible bond issued in 2023.
In determining basic and diluted earnings (loss) per share, the net profit (loss) for the period attributable to Eni is adjusted to take into account the remuneration of perpetual subordinated bonds and the convertible bond, net of tax effect, calculated by using the amortized cost method.
Reconciliation of basic and diluted earnings (loss) per share was as follows:
|
|
|
2024 |
2023 |
2022 |
|
Weighted average number of shares used for basic earnings (loss) per share |
|
|
|
|
|
Potential shares to be issued for ILT incentive plan |
|
|
|
|
|
Potential shares to be issued for Sustainability-linked bond |
|
|
|
|
|
Weighted average number of shares used for diluted earnings (loss) per share |
|
|
|
|
|
Eni’s profit (loss) |
(€ million) |
|
|
|
|
Remuneration of subordinated perpetual bonds net of tax effect |
(€ million) |
(
|
(
|
(
|
|
Eni’s profit (loss) for basic earnings (loss) per share |
(€ million) |
|
|
|
|
Remuneration of Sustainability-linked bond net of tax effect |
(€ million) |
|
|
|
|
Eni’s profit (loss) for basic diluted earnings (loss) per share |
(€ million) |
|
|
|
|
Basic earnings (loss) per share |
(€ per share) |
|
|
|
|
Diluted earnings (loss) per share |
(€ per share) |
|
|
|
F-102
35 Segment information and information by geographic area
Segment information
Effective October 1, 2024, the Company reorganized its business activities into three business groups to increase the effectiveness of strategy execution.
the “Chief Transition & Financial Officer” business group, responsible for increasing the value of the two Eni’s subsidiaries, Plenitude and Enilive, which are engaged in growing the businesses related to the energy transition, mainly production of electricity from renewable sources and manufacturing of biofuels in synergy with the traditional activities of retail marketing of gas, power, and fuels. The goal of increasing the value of those two subsidiaries will be pursued also by means of third-party investments in the share capital of the entities and possibly by market offerings of shares and listing;
the “Global Natural Resources” business group, responsible for increasing the value of the oil&gas exploration and development activities and of wholesale gas, LNG and power activities by leveraging organic growth and with the support of trading activities, vertical integration and operational excellence. It is also in charge of developing the new CCS and agri-hub businesses;
the “Industrial Transformation” business group, responsible for implementing the restructuring and upgrading of the Chemical business, managed by the subsidiary Versalis, and of the oil-based refining business leveraging on proprietary technologies, product specialization and the criteria of the circular economy and by reducing the weight of business lines with challenged fundamentals (commodity chemicals and low-scale refineries). It is also in charge of managing environmental remediation activities conducted by the subsidiary Eni Rewind.
For financial reporting purposes, management evaluated that segmental reporting are presented based on the operating segments tracked by the by the Chief Operating Decision Maker (the CEO) to evaluate profit centers financial performance and resources allocation. Therefore, in compliance with the provisions of the international reporting standard that regulates the segment reporting (IFRS 8), the new reportable segments of Eni effective December 31, 2024, have been reorganized as follows with the restatement of comparative periods:
Exploration & Production : exploration, development and production of crude oil, condensates and natural gas. The business also engages in oil and products trading activities, designed to perform supply balancing transactions in the market with a view of ensuring the requested slate of crudes to the refining business and to stabilize or hedge commercial margins.
Global Gas & LNG Portfolio (GGP) and Power : wholesale supply and marketing of gas via pipeline, LNG, and electricity, as well as international transport activities. It includes gas, LNG, and electricity trading activities finalized to hedging and stabilizing the trade margins, as well as optimizing the gas asset portfolio. The results of the Power business operating segment relating to the production of electricity from thermoelectric plants have been included in this reportable segment because it presents similar economic returns and it is ancillary to the main business.
Refining and Chemicals : processing of crude oil to manufacture traditional refined products (fuels, bitumen, lubricants, etc.) and inter-company wholesale marketing of refined products to the Enilive operating segment and to third-party large accounts. The Chemicals operating segment, through Eni wholly owned subsidiary Versalis, engages in the production and marketing of basic petrochemical products, plastics and elastomers. Versalis is developing the business of manufacturing chemical products from renewable raw materials, bioplastics, and bio-based products through the recently acquired subsidiary Novamont. The results of operations of the Refining business and the Chemical business have been combined in a single reporting segment because the businesses exhibit similar economic characteristics.
Enilive : engages in the manufacturing of biofuels and in retail marketing activities of fuels through an extensive network of refueling outlets, also providing non-fuel products and services to drivers. It also engages in the wholesale supplies of fuels, bitumen and lubricants.
Plenitude : engages in the retail sales of gas, electricity and related services, production and wholesale sales of electricity from renewable plants, and is also building and managing a network of charging points for electric vehicles.
F-103
Corporate and Other activities : includes the main business support functions, in particular holding, central treasury, IT, human resources, real estate services, captive insurance activities, research and development, new technologies, business digitalization and the environmental activity managed by the subsidiary Eni Rewind. The segment also includes the businesses under development of projects to capture and store CO 2 at Eni’s depleted sites (CCUS), the agribusiness and initiatives for carbon offset (NBS), under development.
Segment information presented to the CEO (the Chief Operating Decision Maker, ex IFRS 8) includes: revenues, operating profit and directly attributable assets and liabilities.
According to the requirements of the international accounting standards regarding segment information in the event of a reorganization of business segments, the segment information for the 2023 and 2022 comparative periods have been restated for homogeneous comparison as follows. The main changes compared to 2023 concerned the allocation of oil trading in the E&P segment (previously in the Refining operating segment) and of the thermoelectric generation activity in the GGP operating segment (previously in the Plenitude and Power aggregate). Enilive is subject to separate exposure from the Refining & Chemicals aggregate.
As reported in 2023:
|
(€ million) |
|
Exploration & Production |
Global Gas & LNG Portfolio |
Enilive, Refining and Chemicals |
Plenitude & Power |
Corporate and Other activities |
Adjustments of intragroup profits |
Total |
|
|
|
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
|
(
|
(
|
(
|
(
|
(
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
Operating profit |
|
|
|
(
|
(
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
(
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
(
|
|
|
2022 |
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
|
(
|
(
|
(
|
(
|
(
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
Operating profit |
|
|
|
|
(
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
(
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
(
|
|
(a) Include assets/liabilities directly associated with the generation of operating profit.
As restated:
|
(€ million) |
Exploration & Production |
Global Gas & LNG Portfolio and Power |
Refining and Chemicals |
Enilive |
Plenitude |
Total reportable segments |
Corporate and Other activities |
Adjustments of intragroup profits |
Total |
|
2023 |
|
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
|
(
|
|
(
|
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
(
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
|
(
|
|
|
2022 |
|
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
|
(
|
|
(
|
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
(
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
|
(
|
|
(a) Include assets/liabilities directly associated with the generation of operating profit.
F-104
Segment Information
|
(€ million) |
Exploration & Production |
Global Gas & LNG Portfolio and Power |
Refining and Chemicals |
Enilive |
Plenitude |
Total reportable segments |
Corporate and Other activities |
Adjustments of intragroup profits |
Total |
|
2024 |
|
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
(
|
(
|
|
|
|
(
|
(
|
|
|
Net provisions for contingencies |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Depreciation and amortization |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Impairments of tangible and intangible assets and right-of-use assets |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Reversals of tangible and intangible assets and right-of-use assets |
|
|
|
|
|
|
|
|
|
|
Write-off of tangible and intangible assets and right-of-use assets |
(
|
|
|
|
(
|
(
|
(
|
|
(
|
|
Share of profit (loss) of equity-accounted investments |
|
|
|
(
|
(
|
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
(
|
|
|
Unallocated assets (b) |
|
|
|
|
|
|
|
|
|
|
Equity-accounted investments |
|
|
|
|
|
|
|
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
|
(
|
|
|
Unallocated liabilities (b) |
|
|
|
|
|
|
|
|
|
|
Capital expenditure in tangible and intangible assets |
|
|
|
|
|
|
|
(
|
|
|
2023 |
|
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
|
(
|
|
(
|
|
(
|
|
|
|
Net provisions for contingencies |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
Depreciation and amortization |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Impairments of tangible and intangible assets and right-of-use assets |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Reversals of tangible and intangible assets and right-of-use assets |
|
|
|
|
|
|
|
|
|
|
Write-off of tangible and intangible assets and right-of-use assets |
(
|
|
|
|
(
|
(
|
|
|
(
|
|
Share of profit (loss) of equity-accounted investments |
|
|
|
(
|
(
|
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
(
|
|
|
Unallocated assets (b) |
|
|
|
|
|
|
|
|
|
|
Equity-accounted investments |
|
|
|
|
|
|
|
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
|
(
|
|
|
Unallocated liabilities (b) |
|
|
|
|
|
|
|
|
|
|
Capital expenditure in tangible and intangible assets |
|
|
|
|
|
|
|
(
|
|
|
2022 |
|
|
|
|
|
|
|
|
|
|
Sales from operations including intersegment sales |
|
|
|
|
|
|
|
|
|
|
Less: intersegment sales |
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
Sales from operations |
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
|
(
|
|
(
|
|
(
|
|
|
|
Net provisions for contingencies |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Depreciation and amortization |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Impairments of tangible and intangible assets and right-of-use assets |
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
Reversals of tangible and intangible assets and right-of-use assets |
|
|
|
|
|
|
|
|
|
|
Write-off of tangible and intangible assets and right-of-use assets |
(
|
(
|
(
|
|
|
(
|
|
|
(
|
|
Share of profit (loss) of equity-accounted investments |
|
|
|
|
(
|
|
(
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
(
|
|
|
Unallocated assets (b) |
|
|
|
|
|
|
|
|
|
|
Equity-accounted investments |
|
|
|
|
|
11,066 |
|
|
|
|
Identifiable liabilities (a) |
|
|
|
|
|
|
|
(
|
|
|
Unallocated liabilities (b) |
|
|
|
|
|
|
|
|
|
|
Capital expenditure in tangible and intangible assets |
|
|
|
|
|
|
|
(
|
|
(a) Include assets/liabilities directly associated with the generation of operating profit.
(b) Include assets/liabilities not directly associated with the generation of operating profit.
F-105
Information by geographic area
Identifiable assets and investments by geographic area of origin
|
(€ million) |
Italy |
Other European Union |
Rest of Europe |
Americas |
Asia |
Africa |
Other areas |
Total |
|
2024 |
|
|
|
|
|
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
|
|
Capital expenditure in tangible and intangible assets |
|
|
|
|
|
|
|
|
|
2023 |
|
|
|
|
|
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
|
|
Capital expenditure in tangible and intangible assets |
|
|
|
|
|
|
|
|
|
2022 |
|
|
|
|
|
|
|
|
|
Identifiable assets (a) |
|
|
|
|
|
|
|
|
|
Capital expenditure in tangible and intangible assets |
|
|
|
|
|
|
|
|
(a) Include assets directly associated with the generation of operating profit.
Sales from operations by geographic area of destination
|
(€ million) |
2024 |
2023 |
2022 |
|
Italy |
|
|
|
|
Other European Union |
|
|
|
|
Rest of Europe |
|
|
|
|
Americas |
|
|
|
|
Asia |
|
|
|
|
Africa |
|
|
|
|
Other areas |
|
|
|
|
|
|
|
|
36 Transactions with related parties
In the ordinary course of its business, Eni enters into transactions mainly regarding:
a) Purchase, sale and supply of goods and services and the provision of financing to joint ventures, associates and non-consolidated subsidiaries;
b) purchase, sale and supply of goods and services to entities controlled by the Italian Government;
c) purchase, sale and supply of goods and services to companies related to Eni SpA through members of the Board of Directors. Most of these transactions are exempt from the application of the Eni internal procedure “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or standard conditions, or because they fall below the materiality threshold provided for by the procedure;
d) contributions to non-profit entities correlated to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation, established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as scientific and technological research; and (ii) Eni Enrico Mattei Foundation, established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge enrichment in the fields of economics, energy and environment, both at the national and international level.
Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business.
F-106
Transactions and balances with related parties
|
(€ million) |
|
|
|
|
|
|
|
|
|
December 31, 2024 |
|
2024 |
||||
|
Name |
Receivables and other assets |
Payables and other liabilities |
Guarantees |
|
Revenues |
Costs |
Other operating (expense) income |
|
Joint ventures and associates |
|
|
|
|
|
|
|
|
Agiba Petroleum Co |
|
|
|
|
|
|
|
|
Cardón IV SA |
|
|
|
|
|
(
|
|
|
Coral FLNG SA |
|
|
|
|
|
(
|
|
|
Azule Group |
|
|
|
|
|
|
|
|
Saipem Group |
|
|
|
|
|
|
|
|
SeaCorridor Group |
|
|
|
|
|
|
|
|
Vårgrønn Group |
|
|
|
|
|
|
|
|
Ithaca Energy Plc |
|
|
|
|
|
|
(
|
|
Karachaganak Petroleum Operating BV |
|
|
|
|
|
|
|
|
Lotte Versalis Elastomers Co Ltd |
|
|
|
|
|
|
|
|
Mellitah Oil & Gas BV |
|
|
|
|
|
|
|
|
Mozambique Rovuma Venture SpA |
|
|
|
|
|
|
|
|
Petrobel Belayim Petroleum Co |
|
|
|
|
|
|
|
|
Società Oleodotti Meridionali SpA |
|
|
|
|
|
|
|
|
Société Centrale Electrique du Congo SA |
|
|
|
|
|
|
|
|
Vår Energi ASA |
|
|
|
|
|
|
(
|
|
Other (*) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
|
Unconsolidated entities controlled by Eni |
|
|
|
|
|
|
|
|
Eni BTC Ltd |
|
|
|
|
|
|
|
|
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
|
Entities controlled by the Government |
|
|
|
|
|
|
|
|
Cassa Depositi e Prestiti Group |
|
|
|
|
|
|
|
|
Enel Group |
|
|
|
|
|
|
(
|
|
Italgas Group |
|
|
|
|
|
|
|
|
Snam Group |
|
|
|
|
|
|
|
|
Terna Group |
|
|
|
|
|
|
|
|
GSE - Gestore Servizi Energetici |
|
|
|
|
|
|
|
|
ITA Airways - Italia Trasporto Aereo SpA |
|
|
|
|
|
|
|
|
Other (*) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other related parties |
|
|
|
|
|
|
|
|
Groupement Sonatrach – Eni «GSE» |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*) Each individual amount included herein was lower than €
F-107
|
(€ million) |
|
|
|
|
|
|
|
|
|
December 31, 2023 |
|
2023 |
||||
|
Name |
Receivables and other assets |
Payables and other liabilities |
Guarantees |
|
Revenues |
Costs |
Other operating (expense) income |
|
Joint ventures and associates |
|
|
|
|
|
|
|
|
Agiba Petroleum Co |
|
|
|
|
|
|
|
|
Cardón IV SA |
|
|
|
|
|
|
|
|
Coral FLNG SA |
|
|
|
|
|
|
|
|
Azule Group |
|
|
|
|
|
|
|
|
Saipem Group |
|
|
|
|
|
|
|
|
SeaCorridor Group |
|
|
|
|
|
|
|
|
Vårgrønn Group |
|
|
|
|
|
|
|
|
Karachaganak Petroleum Operating BV |
|
|
|
|
|
|
|
|
Mellitah Oil & Gas BV |
|
|
|
|
|
|
|
|
Petrobel Belayim Petroleum Co |
|
|
|
|
|
|
|
|
Società Oleodotti Meridionali SpA |
|
|
|
|
|
|
|
|
Société Centrale Electrique du Congo SA |
|
|
|
|
|
|
|
|
Vår Energi ASA |
|
|
|
|
|
|
(
|
|
Other (*) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
|
Unconsolidated entities controlled by Eni |
|
|
|
|
|
|
|
|
Eni BTC Ltd |
|
|
|
|
|
|
|
|
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
|
Entities controlled by the Government |
|
|
|
|
|
|
|
|
Cassa Depositi e Prestiti Group |
|
|
|
|
|
|
|
|
Enel Group |
|
|
|
|
|
|
(
|
|
Italgas Group |
|
|
|
|
|
(
|
|
|
Snam Group |
|
|
|
|
|
|
|
|
Terna Group |
|
|
|
|
|
|
|
|
GSE - Gestore Servizi Energetici |
|
|
|
|
|
|
|
|
ITA Airways - Italia Trasporto Aereo SpA |
|
|
|
|
|
|
|
|
Other (*) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other related parties |
|
|
|
|
|
|
|
|
Groupement Sonatrach – Eni «GSE» |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*) Each individual amount included herein was lower than €
F-108
|
(€ million) |
|
|
|
|
|
|
|
|
|
December 31, 2022 |
|
2022 |
||||
|
Name |
Receivables and other assets |
Payables and other liabilities |
Guarantees |
|
Revenues |
Costs |
Other operating (expense) income |
|
Joint ventures and associates |
|
|
|
|
|
|
|
|
Agiba Petroleum Co |
|
|
|
|
|
|
|
|
Angola LNG Ltd |
|
|
|
|
|
|
|
|
Coral FLNG SA |
|
|
|
|
|
|
|
|
Azule Group |
|
|
|
|
|
|
|
|
Saipem Group |
|
|
|
|
|
|
|
|
Vårgrønn Group |
|
|
|
|
|
|
|
|
Karachaganak Petroleum Operating BV |
|
|
|
|
|
|
|
|
Mellitah Oil & Gas BV |
|
|
|
|
|
|
|
|
Petrobel Belayim Petroleum Co |
|
|
|
|
|
|
|
|
Société Centrale Electrique du Congo SA |
|
|
|
|
|
|
|
|
Società Oleodotti Meridionali SpA |
|
|
|
|
|
|
|
|
Vår Energi ASA |
|
|
|
|
|
|
(
|
|
Other (*) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
|
Unconsolidated entities controlled by Eni |
|
|
|
|
|
|
|
|
Eni BTC Ltd |
|
|
|
|
|
|
|
|
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
|
Entities controlled by the Government |
|
|
|
|
|
|
|
|
Cassa Depositi e Prestiti Group |
|
|
|
|
|
|
|
|
Enel Group |
|
|
|
|
|
|
|
|
Italgas Group |
|
|
|
|
|
|
|
|
Snam Group |
|
|
|
|
|
|
|
|
Terna Group |
|
|
|
|
|
|
(
|
|
GSE - Gestore Servizi Energetici |
|
|
|
|
|
|
|
|
ITA Airways - Italia Trasporto Aereo SpA |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other related parties |
|
|
|
|
|
|
|
|
Groupement Sonatrach – Eni «GSE» |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*) Each individual amount included herein was lower than €
The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:
Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach - Eni «GSE» and, limited to Karachaganak Petroleum Operating BV, purchase of crude oil by Eni Trade & Biofuels SpA; costs recovered from Eni associates are invoiced on the basis of costs incurred;
the residual debt relating to the payment of the consideration for the assignment of Cardón IV credits;
supply of upstream specialist services and a guarantee issued on a pro-quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant;
supply of upstream specialist services, purchase of crude oil and issue of guarantees against leasing contracts of FPSO vessels to Azule Group;
engineering, construction and drilling services by Saipem Group mainly for the Exploration & Production segment;
acquisition of transport services from SeaCorridor Group;
guarantees issued to Vårgrønn Group in relation to the participation in the Dogger Bank offshore wind project;
receivables relating to the business combination carried out in 2024 and the purchase of crude oil and condensate from Ithaca Energy Plc Group;
the purchase of elastomers from Lotte Versalis Elastomers Co Ltd;
the purchase of condensates and the supply of upstream specialized services to Mozambique Rovuma Venture SpA;
the sale of gas to Société Centrale Electrique du Congo SA;
advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system at the Taranto refinery;
F-109
guarantees issued in compliance with contractual agreements in the interest of Vår Energi ASA, the supply of upstream specialist services and maritime transport, the purchase of crude oil, condensates and gas and the realized part of forward contracts for the purchase of gas;
a guarantee issued granted to Eni BTC Ltd for the construction of an oil pipeline;
services for environmental restoration to Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation).
The most significant transactions with entities controlled by the Italian Government concerned:
activities aimed at ensuring operation, upgrading and efficiency of the plants provided to Ansaldo group (Cassa Depositi e Prestiti);
sale of fuel, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group;
acquisition of natural gas transportation, distribution and storage services with Snam Group and Italgas Group on the basis of the tariffs set by the Italian Regulatory Authority for Energy, Networks and Environment and purchase and with Snam Group the receivable for divestment relating to the sale of the
acquisition of electricity transmission services and sale and purchase of electricity for granting the system balancing based on prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with Terna Group;
sale and purchase of electricity, gas, environmental certificates, fair value of derivative financial instruments, sale of oil products and storage capacity with GSE - Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/12; the contribution to cover the charges deriving from the performance of OCSIT functions and activities and the contribution paid to GSE for the use of biomethane and other advanced biofuels in the transport sector;
the sale of jet fuel to ITA Airways - Italia Trasporto Aereo SpA.
Transactions with other related parties concerned:
provisions to pension funds managed by Eni of €
costs for contributions paid to the Supplementary Healthcare Fund for Managers of Eni Group Companies (FISDE) for €
contributions and service provisions to Eni Enrico Mattei Foundation for €
Financing transactions and balances with related parties
|
(€ million) |
|
|
|
|
|
|
|
|
|
December 31, 2024 |
|
2024 |
||||
|
Name |
Receivables |
Payables |
Guarantees |
|
Finance incomes and derivative financial instruments |
Finance Expenses |
Gain on disposals |
|
Joint ventures and associates |
|
|
|
|
|
|
|
|
Coral FLNG SA |
|
|
|
|
|
|
|
|
Coral South FLNG DMCC |
|
|
|
|
|
(
|
|
|
Saipem Group |
|
|
|
|
|
|
|
|
Mozambique Rovuma Venture SpA |
|
|
|
|
|
|
|
|
Pengerang Biorefinery Sdn Bhd |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unconsolidated entities controlled by Eni |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Entities controlled by the Government |
|
|
|
|
|
|
|
|
Cassa Depositi e Prestiti Group |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
(
|
|
|
|
|
|
|
|
|
(
|
|
Other related parties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(
|
F-110
|
(€ million) |
|
|
|
|
|
|
|
|
|
December 31, 2023 |
|
2023 |
||||
|
Name |
Receivables and cash and cash equivalents |
Payables |
Guarantees |
|
Finance incomes and derivative financial instruments |
Finance Expenses |
Gain on disposals |
|
Joint ventures and associates |
|
|
|
|
|
|
|
|
Coral FLNG SA |
|
|
|
|
|
|
|
|
Coral South FLNG DMCC |
|
|
|
|
|
|
|
|
Saipem Group |
|
|
|
|
|
|
|
|
Mozambique Rovuma Venture SpA |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unconsolidated entities controlled by Eni |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Entities controlled by the Government |
|
|
|
|
|
|
|
|
Cassa Depositi e Prestiti Group |
|
|
|
|
|
|
|
|
Snam Group |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(€ million) |
|
|
|
|
|
|
|
|
|
December 31, 2022 |
|
2022 |
||||
|
Name |
Receivables and cash and cash equivalents |
Payables |
Guarantees |
|
Finance incomes and derivative financial instruments |
Finance Expenses |
Gain on disposals |
|
Joint ventures and associates |
|
|
|
|
|
|
|
|
Coral FLNG SA |
|
|
|
|
|
|
|
|
Coral South FLNG DMCC |
|
|
|
|
|
|
|
|
Mozambique Rovuma Venture SpA |
|
|
|
|
|
|
|
|
Saipem Group |
|
|
|
|
|
|
|
|
Other (*) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unconsolidated entities controlled by Eni |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Entities controlled by the Government |
|
|
|
|
|
|
|
|
Enel Group |
|
|
|
|
|
|
|
|
Italgas Group |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*) Each individual amount included herein was lower than €
The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:
a financing loan granted to Coral FLNG SA for the construction of a floating gas liquefaction plant in Area 4 offshore Mozambique;
a bank debt guarantee issued on behalf of Coral South FLNG DMCC as part of the project financing of the Coral FLNG development project;
liabilities for leased assets towards Saipem Group related to long-term contracts for the use of drilling rigs
a financing loan granted to Mozambique Rovuma Venture SpA for the development of gas reserves offshore Mozambique;
a credit line granted to Pengerang Biorefinery Sdn Bhd for the construction of a biorefinery in Malaysia.
The most significant transactions with entities controlled by the Italian Government concerned:
finance debt for the realization of charging infrastructures for electric vehicles with Cassa e Depositi e Prestiti Group.
F-111
Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows
The impact of transactions and positions with related parties on the balance sheet accounts consisted of the following:
|
(€ million) |
|
|
|
|
|
|
|
|
December 31, 2024 |
December 31, 2023 |
||||
|
|
Total |
Related parties |
Impact % |
Total |
Related parties |
Impact % |
|
Cash and cash equivalents |
|
|
|
|
|
|
|
Other current financial assets |
|
|
|
|
|
|
|
Trade and other receivables |
|
|
|
|
|
|
|
Other current assets |
|
|
|
|
|
|
|
Other non-current financial assets |
|
|
|
|
|
|
|
Other non-current assets |
|
|
|
|
|
|
|
Short-term debt |
|
|
|
|
|
|
|
Current portion of long-term debt |
|
|
|
|
|
|
|
Current portion of non-current lease liabilities |
|
|
|
|
|
|
|
Trade and other payables |
|
|
|
|
|
|
|
Other current liabilities |
|
|
|
|
|
|
|
Long-term debt |
|
|
|
|
|
|
|
Non-current lease liabilities |
|
|
|
|
|
|
|
Other non-current liabilities |
|
|
|
|
|
|
The impact of transactions with related parties on the profit and loss accounts consisted of the following:
|
|
2024 |
|
2023 |
|
2022 |
||||||
|
|
Total |
Related parties |
Impact % |
|
Total |
Related parties |
Impact % |
|
Total |
Related parties |
Impact % |
|
Sales from operations |
|
|
|
|
|
|
|
|
|
|
|
|
Other income and revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Purchases, services and other |
(
|
(
|
|
|
(
|
(
|
|
|
(
|
(
|
|
|
Net (impairments) reversals of trade and other receivables |
(
|
(
|
|
|
(
|
|
.. |
|
|
(
|
.. |
|
Payroll and related costs |
(
|
|
.. |
|
(
|
(
|
|
|
(
|
(
|
|
|
Other operating income (expense) |
(
|
|
.. |
|
|
|
|
|
(
|
|
.. |
|
Finance income |
|
|
|
|
|
|
|
|
|
|
|
|
Finance expense |
(
|
(
|
|
|
(
|
(
|
|
|
(
|
(
|
|
|
Derivative financial instruments |
|
|
|
|
(
|
|
.. |
|
|
|
|
|
Other income (expense) from investments |
|
(
|
.. |
|
|
|
|
|
|
|
|
F-112
Main cash flows with related parties are provided below:
|
(€ million) |
2024 |
2023 |
2022 |
|
Revenues and other income |
|
|
|
|
Costs and other expenses |
(
|
(
|
(
|
|
Other operating income (loss) |
|
|
|
|
Net change in trade and other receivables and payables |
(
|
|
(
|
|
Net interests |
|
|
|
|
Net cash provided from operating activities |
(
|
(
|
|
|
Capital expenditure in tangible and intangible assets |
(
|
(
|
(
|
|
Disposal of investments |
|
|
|
|
Net change in accounts payable and receivable in relation to investments |
(
|
|
|
|
Change in financial receivables |
(
|
(
|
(
|
|
Net cash used in investing activities |
(
|
(
|
(
|
|
Change in financial and lease liabilities |
(
|
(
|
(
|
|
Net cash used in financing activities |
(
|
(
|
(
|
|
Change in cash and cash equivalents |
(
|
(
|
|
|
Total financial flows to related parties |
(
|
(
|
|
The impact of cash flows with related parties consisted of the following:
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
|
2024 |
2023 |
2022 |
||||||
|
|
Total |
Related parties |
Impact % |
Total |
Related parties |
Impact % |
Total |
Related parties |
Impact % |
|
Net cash provided from operating activities |
|
(
|
.. |
|
(
|
.. |
|
|
|
|
Net cash used in investing activities |
(
|
(
|
|
(
|
(
|
|
(
|
(
|
|
|
Net cash used in financing activities |
(
|
(
|
|
(
|
(
|
|
(
|
(
|
|
F-113
37 Other information about investments
Information on Eni’s investments as of December 31, 2024
The following section provides information about Eni’s consolidated subsidiaries as of December 31, 2024.
CONSOLIDATED SUBSIDIARIES
EXPLORATION & PRODUCTION
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni Natural Energies SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Oil Holdings BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni CCUS H. Ltd |
|
|
|
|
|
|
|
|
|
Burren Energy Plc |
|
|
|
|
|
|
|
|
|
Burren En. (Berm) Ltd |
|
|
|
|
|
|
|
|
|
Burren Energy Plc |
|
|
|
|
|
|
|
|
|
Eni UK Holding Plc |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
(..) |
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni UHL Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Oil Holdings BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
F-114
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni Petroleum Co Inc |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni E&P Holding BV |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. Holding NL BV |
|
|
|
|
|
|
|
|
|
Eni En. Australia Pty Ltd |
|
|
|
|
|
|
|
|
|
Eni En. Group Midco Ltd |
|
|
|
|
|
|
|
|
|
Eni En. Holding NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni Energy Finance Ltd |
|
|
|
|
|
|
|
|
|
Eni En. Holding NL BV |
|
|
|
|
F-115
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni Energy Group H. Ltd |
|
|
|
|
|
|
|
|
|
Eni En. International SAS |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. Group Midco Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Energy Group Ltd |
|
|
|
|
|
|
|
|
|
Eni Energy Group H. Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni Energy Group H. Ltd |
|
|
|
|
|
|
|
|
|
Eni Energy Group H. Ltd |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
F-116
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni Energy NL BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Marketing Inc |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
|
|
|
|
|
|
|
|
|
Eni Algeria Expl.BV |
|
|
|
|
|
|
|
|
|
Eni IS Exploration Ltd
|
|
|
|
|
|
|
|
|
|
Eni Algeria Expl.BV |
|
|
|
|
|
|
|
|
|
Eni ULX Ltd |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
(..) |
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
189
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni Algeria Expl.BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni Investments Plc |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
(..) |
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni Petroleum Co Inc |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Oil Holdings BV |
|
|
|
|
|
|
|
|
|
Eni ULT Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Natural Energies SpA |
|
|
|
|
|
|
|
|
|
Eni En. E&P Hold. NL BV |
|
|
|
|
F-117
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni America Ltd |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni ULX Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni BB Petroleum Inc |
|
|
|
|
|
|
|
|
|
EniProgetti SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni Mozamb. LNG H. BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni CCUS H. Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
|
|
|
|
|
|
|
|
|
Eni Petroleum Co Inc |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Oil Holdings BV |
|
|
|
|
F-118
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Burren En. (Berm) Ltd |
|
|
|
|
|
|
|
|
|
Eni ULT Ltd |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni UK Ltd |
(..) |
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni ULT Ltd |
|
|
|
|
|
|
|
|
|
Eni Petroleum Co Inc |
|
|
|
|
|
|
|
|
|
Eni Marketing Inc |
|
|
|
|
|
|
|
|
|
Eni Oil & Gas Inc |
|
|
|
|
|
|
|
|
|
Eni Venezuela E&P H. |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Oil Holdings BV |
(..) |
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni Indonesia Ltd |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni Canada Hold. Ltd |
|
|
|
|
|
|
|
|
|
FCP Partner Co ULC |
|
|
|
|
|
|
|
|
|
Eni Canada Hold. Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Lasmo Plc |
|
|
|
|
|
|
|
|
|
Eni CCUS H. Ltd |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni Oil Holdings BV |
|
|
|
|
|
|
|
|
|
Eni Energy NL BV |
|
|
|
|
F-119
GLOBAL GAS & LNG PORTFOLIO
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
Power
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
EniPower SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
F-120
REFINING AND CHEMICALS
Refining
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni International BV |
|
|
|
|
Chemicals
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Novamont SpA |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Finproject Asia Ltd |
|
|
|
|
|
|
|
|
|
BioBag International |
|
|
|
|
|
|
|
|
|
Novamont SpA |
|
|
|
|
|
|
|
|
|
BioBag International |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis Deutsch. GmbH |
|
|
|
|
|
|
|
|
|
Versalis International SA |
|
|
|
|
|
|
|
|
|
Finproject SpA |
|
|
|
|
|
|
|
|
|
Finproject SpA |
|
|
|
|
|
|
|
|
|
Versalis Asia Pacific |
|
|
|
|
|
|
|
|
|
Finproject SpA |
(..) |
|
|
|
|
|
|
|
|
Finproject SpA |
|
|
|
|
|
|
|
|
|
Finproject SpA |
|
|
|
|
|
|
|
|
|
Foam Creations (2008) |
|
|
|
|
|
|
|
|
|
Finproject SpA |
|
|
|
|
|
|
|
|
|
Novamont SpA |
|
|
|
|
|
|
|
|
|
Novamont SpA |
|
|
|
|
|
|
|
|
|
Novamont SpA |
|
|
|
|
|
|
|
|
|
Eni Petroleum Co Inc |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis International SA |
|
|
|
|
F-121
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis International SA |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis Deutsch. GmbH |
|
|
|
|
|
|
|
|
|
Dunastyr Zrt |
|
|
|
|
|
|
|
|
|
Versalis France |
|
|
|
|
|
|
|
|
|
Versalis International SA |
|
|
|
|
|
|
|
|
|
Versalis International SA |
|
|
|
|
|
|
|
|
|
Versalis SpA |
(..) |
|
|
|
|
|
|
|
|
Versalis Asia Pacific |
|
|
|
|
|
|
|
|
|
Versalis International SA |
(..) |
|
|
|
|
|
|
|
|
Versalis Asia Pacific |
|
|
|
|
|
|
|
|
|
Versalis SpA |
|
|
|
|
|
|
|
|
|
Versalis International SA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
ENILIVE AND PLENITUDE
Enilive
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
|
EniBioCh4in SpA |
|
|
|
|
|
|
|
|
|
EniBioCh4in SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
EniBioCh4in SpA |
|
|
|
|
|
|
|
|
|
EniBioCh4in SpA |
|
|
|
|
|
|
|
|
|
EniBioCh4in SpA |
|
|
|
|
|
|
|
|
|
EniBioCh4in SpA |
|
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
F-122
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
Aten Oil SLU |
|
|
|
|
|
|
|
|
Aten Oil SLU |
|
|
|
|
|
|
|
|
Aten Oil Setor SLU |
|
|
|
|
|
|
|
|
Aten Oil Setor SLU |
|
|
|
|
|
|
|
|
Enilive Iberia SLU |
|
|
|
|
|
|
|
|
Enilive Iberia SLU |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enilive Deutsch. GmbH |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enimoov Austria GmbH |
|
|
|
|
|
|
|
|
Enilive SpA |
(..) |
|
|
|
|
|
|
|
Enilive Deutsch. GmbH |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enilive SpA |
|
|
|
|
|
|
|
|
Enilive Austria GmbH |
|
|
|
|
|
|
|
|
Enilive Iberia SLU |
|
|
|
F-123
Plenitude
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Be Power SpA |
|
|
|
|
|
|
|
|
|
Be Charge Srl |
|
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Plen. En. Serv. SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
F-124
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Faren Srl |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
F-125
|
OUTSIDE ITALY |
|
|
|
|
|
|
|
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
Eni Plen. Op. Fr. SAS |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plen. Op. Fr. SAS |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Energy Solutions BV |
|
|
|
|
|
|
|
|
Krypton SAS |
|
|
|
|
|
|
|
|
Krypton SAS |
|
|
|
|
|
|
|
|
Krypton SAS |
|
|
|
|
|
|
|
|
Xenon SAS |
|
|
|
|
|
|
|
|
Xenon SAS |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. Op. Fr. SAS |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
Madrid (Spain) |
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni New Energy US Inc |
|
|
|
|
|
|
|
|
Brazoria HoldCo Llc |
|
|
|
|
|
|
|
|
Brazoria Class B |
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
Kellam Tax Eq. Partn. |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni New Energy US Inc |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni New Energy US Inc |
|
|
|
|
|
|
|
|
Corazon Tax Eq. Part. Llc |
|
|
|
|
|
|
|
|
Corazon En. Class B Llc |
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. T. S. Spain |
|
|
|
|
|
|
|
|
Eni G&P France SA |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Energías Amb. de Outes |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Third parties |
(..) |
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni New En. Aus. Pty Ltd |
|
|
|
|
|
|
|
|
Eni New En. Aus. Pty Ltd |
|
|
|
F-126
|
Company name |
Registered office |
Country of operation |
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
Eni New En. Aus. Pty Ltd |
|
|
|
|
|
|
|
|
Eni New Energy US Inc |
|
|
|
|
|
|
|
|
Eni New Energy US Inv.Inc |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni New Energy US Inc |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
Eni Plen. St. Italy Srl |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Italy SpA |
|
|
|
|
|
|
|
|
Eni Plen. Inv. Spain SLU |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Spain SLU |
|
|
|
|
|
|
|
|
Eni Plen. Ren. Spain SLU |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
|
|
|
|
Eni Plenitude SpA SB |
|
|
|
|
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|
|
Eni New Energy US H. Llc |
|
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|
|
HLS Bonete Topco SLU |
|
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|
Eni Plenitude SpA SB |
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Eni Plen. Op. Fr. SAS |
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Eni Plen. Inv. Colombia |
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Third parties |
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Eni New Energy US Inc |
|
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|
Kellam Solar Class B |
|
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Third parties |
|
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|
|
Eni Plenitude SpA SB |
|
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|
Eni Plen. Op. Fr. SAS |
|
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Eni Plenitude SpA SB |
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Holding Lanas Solar Sàrl |
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Eni Plen. Ren. Spain SLU |
|
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Eni Plen. Ren. Lux. Sàrl |
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Eni Plen. T. S. Spain |
|
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Eni Plen. Ren. Lux. Sàrl |
|
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|
Eni Plenitude SpA SB |
|
|
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|
F-127
|
Company name |
Registered office |
Country of operation |
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
Eni Plen. Ren. Lux. Sàrl |
|
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|
Eni Plen. Ren. Spain SLU |
|
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Eni Plenitude SpA SB |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
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Eni Plen. Renew. Hellas |
|
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Eni Plen. Renew. Hellas |
|
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Eni Plen. Renew. Hellas |
|
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|
Eni Plen. Ren. Spain SLU |
|
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|
Eni New Energy US Inc |
|
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Eni Plen. T. S. Spain |
|
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Eni Plen. T. S. Spain |
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|
Eni Plen. Op. Fr. SAS |
|
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|
F-128
CORPORATE AND OTHER ACTIVITIES
Corporate and financial companies
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
AGI SpA |
|
|
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|
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|
|
|
Eni SpA |
|
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|
Eni SpA |
|
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|
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|
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|
Eni SpA |
|
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|
Eni SpA |
|
|
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|
|
Eniverse |
|
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|
Third parties |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni International BV |
|
|
|
|
|
|
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|
Eni Oil Holdings BV |
|
|
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|
|
Eni Petroleum Co Inc |
|
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|
Eni SpA |
|
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|
Eni SpA |
|
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|
Eni SpA |
|
|
|
|
|
|
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|
|
Eni UK Ltd |
(..) |
|
|
|
|
|
|
|
|
Eni Petroleum Co Inc |
|
|
|
|
F-129
Other activities
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Third parties |
(..) |
|
|
|
JOINT OPERATIONS
EXPLORATION & PRODUCTION
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni En. Holding NL BV |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
GLOBAL GAS & LNG PORTFOLIO AND POWER
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni International BV |
|
|
|
(a) |
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
Eni Gas Liquef. BV |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
Damietta LNG |
|
|
|
|
|
|
|
|
|
Eni Gas Liquef. BV |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
Eni North Africa BV |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
(a) Equity ratio equal to the Eni's working interest.
POWER
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
EniPower SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
REFINING AND CHEMICALS
Refining
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Ecofuel SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
|
|
|
|
|
Eni SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
F-130
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Ecofuel SpA |
|
|
|
(a) |
|
|
|
|
|
Supermetanol CA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
(a)
ENILIVE AND PLENITUDE
ENILIVE
OUTSIDE ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
||||||
|
|
|
|
|
Enilive Deutsch. GmbH |
|
|
|
|
||||||
|
|
|
|
|
Third parties |
|
|
|
|
||||||
CORPORATE AND OTHER ACTIVITIES
Other activities
IN ITALY
|
Company name |
Registered office |
Country of operation |
|
Shareholders |
% Ownership |
|
% Equity ratio |
|
|
|
|
|
|
Eni Rewind SpA |
|
|
|
|
|
|
|
|
|
Third parties |
|
|
|
|
Information on Eni’s consolidated subsidiaries with significant non-controlling interest
The following section provides information about economic, equity and financial data, gross of intragroup elisions, relating to the Plenitude Group,
|
|
2024 |
2024 |
2023 |
|
(€ million) |
Plenitude Group |
EniPower Group |
EniPower Group |
|
Non-controlling interest (%) |
|
|
|
|
Current assets |
|
|
|
|
Non-current assets |
|
|
|
|
Current liabilities |
|
|
|
|
Non-current liabilities |
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
Profit |
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
|
|
Net cash used in investing activities |
(
|
(
|
(
|
|
Net cash used in financing activities |
(
|
(
|
(
|
|
Net increase (decrease) in cash and cash equivalents |
(
|
(
|
(
|
|
Profit attributable to non-controlling interest |
|
|
|
|
Dividends paid to minority interest |
|
|
|
Equity pertaining to non-controlling interests as of December 31, 2024, amounted to €
F-131
Changes in the ownership interest without loss of control
In 2024, Eni sold
In 2023, Eni purchased the entirety of third-party interests (
Principal joint ventures, joint operations and associates as of December 31, 2024
|
Company name |
Registered office |
Country of operation |
Segment |
% ownership |
% equity ratio |
|
Joint venture |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint Operation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
Exploration & Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-132
Main line items of profit and loss and balance sheet related to the joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below:
|
2024 |
|
|
|
|
|
|
(€ million) |
Azule Energy Holdings Ltd |
St. Bernard Renewables Llc |
E&E Algeria Touat BV |
Saipem SpA |
SeaCorridor Srl |
|
Current assets |
|
|
|
|
|
|
- of which cash and cash equivalent |
|
|
|
|
|
|
Non-current assets |
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
- of which current financial liabilities |
|
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
|
- of which non-current financial liabilities |
|
|
|
|
|
|
Total liabilities |
|
|
|
|
|
|
Net equity |
|
|
|
|
|
|
Eni’s % of the investment |
|
|
|
|
|
|
Book value of the investment |
|
|
|
|
|
|
Revenues and other income |
|
|
|
|
|
|
Operating expense |
(
|
(
|
(
|
(
|
(
|
|
Other operating profit (loss) |
|
(
|
|
|
|
|
Depreciation, amortization and impairments |
(
|
(
|
(
|
(
|
(
|
|
Operating profit (loss) |
|
(
|
|
|
|
|
Finance income (expense) |
(
|
(
|
|
(
|
|
|
Income (expense) from investments |
|
|
|
(
|
|
|
Profit (loss) before income taxes |
|
(
|
|
|
|
|
Income taxes |
(
|
|
(
|
(
|
(
|
|
Profit (loss) |
|
(
|
|
|
|
|
Other comprehensive income (loss) |
|
|
|
(
|
|
|
Total other comprehensive income (loss) |
|
|
|
|
|
|
Profit (loss) attributable to Eni |
|
(
|
|
|
|
|
Dividends received from the joint venture |
|
|
|
|
|
|
2023 |
|
|
|
|
|
(€ million) |
Azule Energy Holdings Ltd |
St. Bernard Renewables Llc |
Saipem |
SeaCorridor Srl |
|
Current assets |
|
|
|
|
|
- of which cash and cash equivalent |
|
|
|
|
|
Non-current assets |
|
|
|
|
|
Total assets |
|
|
|
|
|
Current liabilities |
|
|
|
|
|
- of which current financial liabilities |
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
- of which non-current financial liabilities |
|
|
|
|
|
Total liabilities |
|
|
|
|
|
Net equity |
|
|
|
|
|
Eni’s % of the investment |
|
|
|
|
|
Book value of the investment |
|
|
|
|
|
Revenues and other income |
|
|
|
|
|
Operating expense |
(
|
(
|
(
|
(
|
|
Other operating profit (loss) |
|
(
|
(
|
|
|
Depreciation, amortization and impairments |
(
|
(
|
(
|
(
|
|
Operating profit (loss) |
|
(
|
|
|
|
Finance income (expense) |
(
|
(
|
(
|
(
|
|
Income (expense) from investments |
|
|
|
|
|
Profit (loss) before income taxes |
|
(
|
|
|
|
Income taxes |
(
|
|
(
|
(
|
|
Profit (loss) |
|
(
|
|
|
|
Other comprehensive income (loss) |
(
|
(
|
|
(
|
|
Total other comprehensive income (loss) |
|
(
|
|
|
|
Profit (loss) attributable to Eni |
|
(
|
|
|
|
Dividends received from the joint venture |
|
|
|
|
F-133
The results for the year and the comprehensive income of the significant joint ventures are shown below:
|
|
2024 |
||||
|
(€ million) |
2023 Sol IX Llc |
GreenIT SpA |
Mozambique Rovuma Venture SpA |
Cardón IV SA |
Vårgrønn AS |
|
Profit (loss) |
|
|
|
(
|
(
|
|
Other comprehensive income (loss) |
|
(
|
|
|
|
|
Total other comprehensive income (loss) |
|
|
|
|
(
|
|
|
|
2023 |
|
|
(€ million) |
Mozambique Rovuma Venture SpA |
Cardón IV SA |
Vårgrønn AS |
|
Profit (loss) |
|
(
|
(
|
|
Other comprehensive income (loss) |
(
|
(
|
(
|
|
Total other comprehensive income (loss) |
|
(
|
(
|
Main line items of profit and loss and balance sheet related to the associates represented by the amounts included in the reports accounted under IFRS of each company are provided in the table below:
|
2024 |
|
|
|
|
|
(€ million) |
Abu Dhabi Oil Refining Company (TAKREER) |
Vår Energi ASA |
Ithaca Energy Plc |
QatarEnergy LNG NFE (5) |
|
Current assets |
|
|
|
|
|
- of which cash and cash equivalent |
|
|
|
|
|
Non-current assets |
|
|
|
|
|
Total assets |
|
|
|
|
|
Current liabilities |
|
|
|
|
|
- of which current financial liabilities |
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
- of which non-current financial liabilities |
|
|
|
|
|
Total liabilities |
|
|
|
|
|
Net equity |
|
|
|
|
|
Eni’s % of the investment |
|
|
|
|
|
Book value of the investment |
|
|
|
|
|
Revenues and other income |
|
|
|
|
|
Operating expense |
(
|
(
|
(
|
(
|
|
Other operating income (expense) |
(
|
|
|
|
|
Depreciation, amortization and impairments |
(
|
(
|
(
|
|
|
Operating profit (loss) |
|
|
|
(
|
|
Finance income (expense) |
(
|
(
|
(
|
|
|
Profit (loss) before income taxes |
(
|
|
|
(
|
|
Income taxes |
|
(
|
(
|
|
|
Profit (loss) |
(
|
|
|
(
|
|
Other comprehensive income (loss) |
|
(
|
|
|
|
Total other comprehensive income (loss) |
|
|
|
|
|
Profit (loss) attributable to Eni |
(
|
|
|
(
|
|
Dividends received from associates |
|
|
|
|
F-134
|
2023 |
|
|
|
|
(€ million) |
Abu Dhabi Oil Refining Company (Takreer) |
Vår Energi ASA |
QatarEnergy LNG NFE (5) |
|
Current assets |
|
|
|
|
- of which cash and cash equivalent |
|
|
|
|
Non-current assets |
|
|
|
|
Total assets |
|
|
|
|
Current liabilities |
|
|
|
|
- of which current financial liabilities |
|
|
|
|
Non-current liabilities |
|
|
|
|
- of which non-current financial liabilities |
|
|
|
|
Total liabilities |
|
|
|
|
Net equity |
|
|
|
|
Eni’s % of the investment |
|
|
|
|
Book value of the investment |
|
|
|
|
Revenues and other income |
|
|
|
|
Operating expense |
(
|
(
|
(
|
|
Other operating income (expense) |
(
|
|
|
|
Depreciation, amortization and impairments |
(
|
(
|
|
|
Operating profit (loss) |
|
|
(
|
|
Finance income (expense) |
(
|
(
|
|
|
Profit (loss) before income taxes |
|
|
(
|
|
Income taxes |
|
(
|
|
|
Profit (loss) |
|
|
(
|
|
Other comprehensive income (loss) |
(
|
(
|
(
|
|
Total other comprehensive income (loss) |
|
|
(
|
|
Profit (loss) attributable to Eni |
|
|
(
|
|
Dividends received from associates |
|
|
|
The results for the year and the comprehensive income of the significant associates are shown below:
|
|
2024 |
|
|
(€ million) |
ADNOC Global Trading Ltd |
Coral FLNG SA |
|
Profit (loss) |
|
(
|
|
Other comprehensive income (loss) |
|
|
|
Total other comprehensive income (loss) |
|
|
|
|
2023 |
|
|
(€ million) |
ADNOC Global Trading Ltd |
Coral FLNG SA |
|
Profit (loss) |
|
(
|
|
Other comprehensive income (loss) |
(
|
(
|
|
Total other comprehensive income (loss) |
|
(
|
F-135
38 Significant non-recurring events and operations
In 2024, in 2023 and 2022, Eni did not report any non-recurring events and operations.
39 Positions or transactions deriving from atypical and/or unusual operations
In 2024, in 2023 and 2022, no transactions deriving from atypical and/or unusual operations were reported.
40 Subsequent events
In January 2025, Eni issued
On March 6, 2025, Eni and the private equity fund KKR completed the investment transaction agreed in October 2024 with KKR acquiring a
On March 19, 2025, Eni and Vitol agreed on the economic terms and conditions of the farm-out to Vitol of a
At the end of March 2025, Eni was notified by the U.S. Department of State that prior authorization concerning in-kind repayment through oil supplies of gas produced and supplied in Venezuela to PDVSA have been withdrawn. Eni continues its transparent engagement with U.S. Authorities on the matter to identify options for ensuring that non-sanctioned gas supplies can be remunerated by PDVSA.
F-136
Supplemental oil and gas information (unaudited)
The following information prepared in accordance with “International Financial Reporting Standards” (IFRS) is presented based on the disclosure rules of the FASB Extractive Activities - Oil and Gas (Topic 932). Amounts related to minority interests are immaterial.
Capitalized costs
Capitalized costs represent the total expenditures for proved and unproved mineral properties and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization.
Capitalized costs by geographical area consist of the following:
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
2024 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Proved property |
19,272 |
3,242 |
43,769 |
30,245 |
14,379 |
15,223 |
16,212 |
1,626 |
143,968 |
|
Unproved property |
22 |
190 |
651 |
2,393 |
|
2,259 |
887 |
209 |
6,611 |
|
Support equipment and facilities |
339 |
29 |
2,012 |
837 |
138 |
14 |
26 |
13 |
3,408 |
|
Incomplete wells and other |
756 |
249 |
2,554 |
2,583 |
1,202 |
2,232 |
388 |
149 |
10,113 |
|
Gross Capitalized Costs |
20,389 |
3,710 |
48,986 |
36,058 |
15,719 |
19,728 |
17,513 |
1,997 |
164,100 |
|
Accumulated depreciation, depletion and amortization |
(16,541) |
(2,969) |
(36,505) |
(24,075) |
(5,441) |
(12,698) |
(14,273) |
(1,108) |
(113,610) |
|
Net Capitalized Costs consolidated subsidiaries (a) (b) |
3,848 |
741 |
12,481 |
11,983 |
10,278 |
7,030 |
3,240 |
889 |
50,490 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Proved property |
|
12,751 |
645 |
10,137 |
|
295 |
2,150 |
|
25,978 |
|
Unproved property |
|
1,178 |
149 |
88 |
|
|
|
|
1,415 |
|
Support equipment and facilities |
|
86 |
9 |
82 |
|
|
9 |
|
186 |
|
Incomplete wells and other |
|
4,989 |
22 |
2,246 |
|
370 |
249 |
|
7,876 |
|
Gross Capitalized Costs |
|
19,004 |
825 |
12,553 |
|
665 |
2,408 |
|
35,455 |
|
Accumulated depreciation, depletion and amortization |
|
(6,799) |
(140) |
(2,809) |
|
|
(1,644) |
|
(11,392) |
|
Net Capitalized Costs equity-accounted entities (a) (c) |
|
12,205 |
685 |
9,744 |
|
665 |
764 |
|
24,063 |
(a) The amounts include net capitalized financial charges totalling €830 million for consolidates subsidiaries and €996 million for equity-accounted entities.
(b) Includes allocation at fair value of the assets of Neptune Energy Group.
(c) Includes allocation at fair value of the assets of Neptune Energy Group and of Ithaca Energy in UK.
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
2023 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Proved property |
19,073 |
6,802 |
40,429 |
30,058 |
13,360 |
13,048 |
19,106 |
1,608 |
143,484 |
|
Unproved property |
22 |
325 |
651 |
2,280 |
7 |
1,480 |
859 |
197 |
5,821 |
|
Support equipment and facilities |
310 |
27 |
1,868 |
1,102 |
128 |
12 |
24 |
12 |
3,483 |
|
Incomplete wells and other |
1,006 |
354 |
2,146 |
2,510 |
1,062 |
1,834 |
511 |
83 |
9,506 |
|
Gross Capitalized Costs |
20,411 |
7,508 |
45,094 |
35,950 |
14,557 |
16,374 |
20,500 |
1,900 |
162,294 |
|
Accumulated depreciation, depletion and amortization |
(16,515) |
(6,390) |
(32,559) |
(24,796) |
(4,578) |
(10,853) |
(16,042) |
(1,060) |
(112,793) |
|
Net Capitalized Costs consolidated subsidiaries (a) (b) |
3,896 |
1,118 |
12,535 |
11,154 |
9,979 |
5,521 |
4,458 |
840 |
49,501 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Proved property |
|
8,585 |
119 |
27,267 |
|
278 |
2,030 |
|
38,279 |
|
Unproved property |
|
835 |
|
69 |
|
|
|
|
904 |
|
Support equipment and facilities |
|
50 |
8 |
257 |
|
|
7 |
|
322 |
|
Incomplete wells and other |
|
3,790 |
9 |
1,823 |
|
193 |
233 |
|
6,048 |
|
Gross Capitalized Costs |
|
13,260 |
136 |
29,416 |
|
471 |
2,270 |
|
45,553 |
|
Accumulated depreciation, depletion and amortization |
|
(4,364) |
(73) |
(20,707) |
|
|
(1,480) |
|
(26,624) |
|
Net Capitalized Costs equity-accounted entities (a) |
|
8,896 |
63 |
8,709 |
|
471 |
790 |
|
18,929 |
|
|
|
(a) The amounts include net capitalized financial charges totalling €709 million for consolidates subsidiaries and €658 million for equity-accounted entities.
(b) Includes allocation at fair value of the assets of the companies acquired by Chevron in Indonesia and by BP in Algeria.
F-137
Costs incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
2024 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Unproved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Exploration |
47 |
53 |
98 |
139 |
57 |
128 |
124 |
2 |
648 |
|
Development (a) |
445 |
340 |
1,168 |
3,250 |
252 |
1,012 |
760 |
101 |
7,328 |
|
Total costs incurred consolidated subsidiaries |
492 |
393 |
1,266 |
3,389 |
309 |
1,140 |
884 |
103 |
7,976 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Unproved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Exploration |
|
231 |
|
90 |
|
|
|
|
321 |
|
Development (b) |
|
1,850 |
15 |
1,191 |
|
157 |
(6) |
|
3,207 |
|
Total costs incurred equity-accounted entities |
|
2,081 |
15 |
1,281 |
|
157 |
(6) |
|
3,528 |
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
2023 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Unproved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Exploration |
12 |
55 |
328 |
189 |
9 |
277 |
138 |
1 |
1,009 |
|
Development (a) |
798 |
249 |
1,633 |
2,662 |
296 |
921 |
937 |
151 |
7,647 |
|
Total costs incurred consolidated subsidiaries |
810 |
304 |
1,961 |
2,851 |
305 |
1,198 |
1,075 |
152 |
8,656 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Unproved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Exploration |
|
92 |
|
46 |
|
|
|
|
138 |
|
Development (b) |
|
1,703 |
4 |
731 |
|
150 |
2 |
|
2,590 |
|
Total costs incurred equity-accounted entities |
|
1,795 |
4 |
777 |
|
150 |
2 |
|
2,728 |
|
|
|
|
|
|
|
|
|
|
|
|
2022 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
4 |
|
51 |
|
|
|
82 |
|
137 |
|
Unproved property acquisitions |
2 |
|
111 |
11 |
|
|
|
|
124 |
|
Exploration |
12 |
101 |
247 |
295 |
4 |
253 |
26 |
1 |
939 |
|
Development (a) |
216 |
(129) |
1,138 |
1,458 |
277 |
835 |
1,292 |
117 |
5,204 |
|
Total costs incurred consolidated subsidiaries |
234 |
(28) |
1,547 |
1,764 |
281 |
1,088 |
1,400 |
118 |
6,404 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Proved property acquisitions |
|
|
|
|
|
291 |
|
|
291 |
|
Unproved property acquisitions |
|
|
|
|
|
|
|
|
|
|
Exploration |
|
73 |
|
13 |
|
|
|
|
86 |
|
Development (b) |
|
1,690 |
(8) |
125 |
|
49 |
(9) |
|
1,847 |
|
Total costs incurred equity-accounted entities |
|
1,763 |
(8) |
138 |
|
340 |
(9) |
|
2,224 |
|
|
|
(a) Includes abandonment costs for €73 million in 2024, abandonment costs for €773 million in 2023, decrease of the assets for €307 million in 2022.
(b) Includes abandonment costs for €42 million in 2024, abandonment costs for €163 million in 2023, decrease of the assets for €111 million in 2022.
F-138
Results of operations from oil and gas producing activities
Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to fulfil Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.
Results of operations from oil and gas producing activities by geographical area consist of the following:
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
2024 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
- sales to consolidated entities |
1,256 |
524 |
1,590 |
1,984 |
1,747 |
3,171 |
1,364 |
|
11,636 |
|
- sales to third parties |
|
462 |
7,135 |
892 |
958 |
752 |
138 |
19 |
10,356 |
|
Total revenues |
1,256 |
986 |
8,725 |
2,876 |
2,705 |
3,923 |
1,502 |
19 |
21,992 |
|
Production costs |
(350) |
(328) |
(971) |
(617) |
(280) |
(392) |
(403) |
(25) |
(3,366) |
|
Transportation costs |
(4) |
(86) |
(65) |
(8) |
(175) |
(8) |
(15) |
|
(361) |
|
Production taxes |
(139) |
(1) |
(299) |
(276) |
|
(339) |
(73) |
|
(1,127) |
|
Exploration expenses |
(16) |
(158) |
(148) |
(54) |
(81) |
(243) |
(39) |
(2) |
(741) |
|
D.D. & A. and Provision for abandonment (a) |
(606) |
(440) |
(1,880) |
(2,121) |
(555) |
(1,142) |
(1,373) |
(52) |
(8,169) |
|
Other income (expenses) |
(179) |
(413) |
(330) |
(280) |
(168) |
(335) |
(45) |
(7) |
(1,757) |
|
Pretax income from producing activities |
(38) |
(440) |
5,032 |
(480) |
1,446 |
1,464 |
(446) |
(67) |
6,471 |
|
Income taxes |
73 |
134 |
(3,150) |
(347) |
(507) |
(1,283) |
39 |
23 |
(5,018) |
|
Results of operations from E&P activities of consolidated subsidiaries |
35 |
(306) |
1,882 |
(827) |
939 |
181 |
(407) |
(44) |
1,453 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
- sales to consolidated entities |
|
3,330 |
|
1,149 |
|
|
|
|
4,479 |
|
- sales to third parties |
|
1,213 |
162 |
1,682 |
|
|
669 |
|
3,726 |
|
Total revenues |
|
4,543 |
162 |
2,831 |
|
|
669 |
|
8,205 |
|
Production costs |
|
(711) |
(33) |
(621) |
|
|
(23) |
|
(1,388) |
|
Transportation costs |
|
(151) |
(15) |
|
|
|
(3) |
|
(169) |
|
Production taxes |
|
|
(2) |
(42) |
|
|
(148) |
|
(192) |
|
Exploration expenses |
|
(119) |
|
(7) |
|
|
|
|
(126) |
|
D.D. & A. and Provision for abandonment |
|
(1,150) |
(62) |
(864) |
|
|
(66) |
|
(2,142) |
|
Other income (expenses) |
|
37 |
(26) |
(127) |
|
(1) |
(333) |
|
(450) |
|
Pretax income from producing activities |
|
2,449 |
24 |
1,170 |
|
(1) |
96 |
|
3,738 |
|
Income taxes |
|
(1,839) |
(2) |
(456) |
|
|
(42) |
|
(2,339) |
|
Results of operations from E&P activities of equity-accounted entities |
|
610 |
22 |
714 |
|
(1) |
54 |
|
1,399 |
|
|
|
(a) Includes asset net impairment amounting to €2,203 million.
F-139
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
2023 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
- sales to consolidated entities |
1,475 |
862 |
1,477 |
1,745 |
1,845 |
2,970 |
1,661 |
1 |
12,036 |
|
- sales to third parties |
|
18 |
7,936 |
903 |
897 |
532 |
135 |
51 |
10,472 |
|
Total revenues |
1,475 |
880 |
9,413 |
2,648 |
2,742 |
3,502 |
1,796 |
52 |
22,508 |
|
Production costs |
(348) |
(202) |
(952) |
(656) |
(267) |
(304) |
(469) |
(25) |
(3,223) |
|
Transportation costs |
(3) |
(43) |
(68) |
(10) |
(178) |
(6) |
(19) |
|
(327) |
|
Production taxes |
(152) |
|
(300) |
(294) |
|
(326) |
(73) |
|
(1,145) |
|
Exploration expenses |
(12) |
(14) |
(245) |
(121) |
(2) |
(140) |
(152) |
(1) |
(687) |
|
D.D. & A. and Provision for abandonment (a) |
(886) |
(166) |
(1,979) |
(716) |
(601) |
(1,093) |
(1,531) |
(95) |
(7,067) |
|
Other income (expenses) |
(347) |
(117) |
(360) |
(128) |
(148) |
(263) |
(108) |
(7) |
(1,478) |
|
Pretax income from producing activities |
(273) |
338 |
5,509 |
723 |
1,546 |
1,370 |
(556) |
(76) |
8,581 |
|
Income taxes |
169 |
(292) |
(3,368) |
(391) |
(503) |
(1,150) |
369 |
19 |
(5,147) |
|
Results of operations from E&P activities of consolidated subsidiaries |
(104) |
46 |
2,141 |
332 |
1,043 |
220 |
(187) |
(57) |
3,434 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
- sales to consolidated entities |
|
2,911 |
|
958 |
|
|
|
|
3,869 |
|
- sales to third parties |
|
1,063 |
10 |
1,905 |
|
|
604 |
|
3,582 |
|
Total revenues |
|
3,974 |
10 |
2,863 |
|
|
604 |
|
7,451 |
|
Production costs |
|
(562) |
(6) |
(535) |
|
|
(20) |
|
(1,123) |
|
Transportation costs |
|
(102) |
(1) |
(26) |
|
|
(3) |
|
(132) |
|
Production taxes |
|
|
(2) |
(54) |
|
|
(126) |
|
(182) |
|
Exploration expenses |
|
(50) |
|
(37) |
|
|
|
|
(87) |
|
D.D. & A. and Provision for abandonment |
|
(1,116) |
(5) |
(1,314) |
|
(1) |
(68) |
|
(2,504) |
|
Other income (expenses) |
|
(78) |
(1) |
24 |
|
(4) |
(372) |
|
(431) |
|
Pretax income from producing activities |
|
2,066 |
(5) |
921 |
|
(5) |
15 |
|
2,992 |
|
Income taxes |
|
(1,614) |
6 |
(273) |
|
1 |
(56) |
|
(1,936) |
|
Results of operations from E&P activities of equity-accounted entities |
|
452 |
1 |
648 |
|
(4) |
(41) |
|
1,056 |
|
|
|
(a) Includes asset net impairment amounting to €1,036 million.
|
2022 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
- sales to consolidated entities |
1,952 |
1,854 |
2,095 |
4,434 |
1,602 |
2,982 |
1,683 |
3 |
16,605 |
|
- sales to third parties |
329 |
23 |
8,843 |
1,216 |
1,001 |
837 |
307 |
72 |
12,628 |
|
Total revenues |
2,281 |
1,877 |
10,938 |
5,650 |
2,603 |
3,819 |
1,990 |
75 |
29,233 |
|
Production costs |
(387) |
(189) |
(970) |
(871) |
(241) |
(326) |
(410) |
(21) |
(3,415) |
|
Transportation costs |
(3) |
(42) |
(55) |
(29) |
(147) |
(3) |
(16) |
|
(295) |
|
Production taxes |
(286) |
|
(330) |
(478) |
|
(421) |
(63) |
|
(1,578) |
|
Exploration expenses |
(11) |
(25) |
(268) |
(150) |
(6) |
(123) |
(21) |
(1) |
(605) |
|
D.D. & A. and Provision for abandonment (a) |
(449) |
(158) |
(1,995) |
(1,488) |
(434) |
(727) |
(707) |
(90) |
(6,048) |
|
Other income (expenses) |
(1,987) |
(98) |
1,577 |
(196) |
(127) |
(292) |
2 |
(4) |
(1,125) |
|
Pretax income from producing activities |
(842) |
1,365 |
8,897 |
2,438 |
1,648 |
1,927 |
775 |
(41) |
16,167 |
|
Income taxes |
337 |
(665) |
(3,932) |
(979) |
(524) |
(1,457) |
(41) |
47 |
(7,214) |
|
Results of operations from E&P activities of consolidated subsidiaries |
(505) |
700 |
4,965 |
1,459 |
1,124 |
470 |
734 |
6 |
8,953 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
- sales to consolidated entities |
|
2,937 |
|
572 |
|
|
|
|
3,509 |
|
- sales to third parties |
|
3,039 |
14 |
1,327 |
|
|
533 |
|
4,913 |
|
Total revenues |
|
5,976 |
14 |
1,899 |
|
|
533 |
|
8,422 |
|
Production costs |
|
(567) |
(6) |
(244) |
|
|
(24) |
|
(841) |
|
Transportation costs |
|
(131) |
(1) |
(9) |
|
|
|
|
(141) |
|
Production taxes |
|
|
(2) |
(15) |
|
|
(123) |
|
(140) |
|
Exploration expenses |
|
(44) |
|
(7) |
|
(13) |
|
|
(64) |
|
D.D. & A. and Provision for abandonment |
|
(1,121) |
(6) |
(628) |
|
(1) |
(63) |
|
(1,819) |
|
Other income (expenses) |
|
(64) |
|
(271) |
|
1 |
(234) |
|
(568) |
|
Pretax income from producing activities |
|
4,049 |
(1) |
725 |
|
(13) |
89 |
|
4,849 |
|
Income taxes |
|
(3,076) |
3 |
(21) |
|
|
(105) |
|
(3,199) |
|
Results of operations from E&P activities of equity-accounted entities |
|
973 |
2 |
704 |
|
(13) |
(16) |
|
1,650 |
|
|
|
(a) Includes asset net impairment amounting to €279 million.
F-140
Proved reserves of oil and natural gas
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves comply with Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities – Oil and Gas (Topic 932).
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2024, the average price for the marker Brent crude oil was $81 per barrel. Net proved reserves exclude interests and royalties owned by others.
Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
F-141
Eni has its proved reserves evaluated on a rotational basis by independent oil engineering companies 24 . The description of qualifications of the person primarily responsible of the reserves audit is included in the third-party audit report 25 . In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. Eni’s net equity share after cost recovery. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.
The volumes and monetary values of the reserves of certain joint venture and affiliated companies are certified on their behalf in a similar manner by independent petroleum engineering companies and provided to Eni 26 .
In 2024, an independent evaluation of about 40% 27 of Eni’s total proved reserves as of December 31, 2024, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.
In the three-year period from 2022 to 2024, 85% of Eni’s total proved reserves were subject to independent evaluation.
Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 57%, 55% and 54% of total proved reserves as of December 31, 2024, 2023 and 2022 respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves related to these contracts represent 2% of total proved reserves in barrels of oil equivalent for both 2024 and the years 2023 and 2022.
Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 1%, 2% and 3% of total proved reserves as of December 31, 2024, 2023 and 2022, respectively, on an oil equivalent basis; (ii) volumes of proved reserves of natural gas to be consumed in operations amounted to 2,380 BCF at 2024 year-end (2,338 BCF and 2,389 BCF respectively at 2023 and 2022 year-end); (iii) the quantities of hydrocarbons related to the Angola LNG plant owned by the JV Azule set up 50% with bp during the year.
Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development costs. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.
Proved undeveloped reserves
Proved undeveloped reserves as of December 31, 2024, totalled 2,787 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,192 mmBBL and of natural gas amounted to 8,343 BCF, mainly concentrated in Africa and Asia. Proved undeveloped reserves of consolidated subsidiaries amounted to 775 mmBBL of liquids and 4,489 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2024.
|
(mmboe) |
|
|
Proved undeveloped reserves as of December 31, 2023 |
2,419 |
|
Transfer to proved developed reserves |
(128) |
|
Extensions and discoveries |
367 |
|
Revisions of previous estimates |
107 |
|
Improved recovery |
|
|
Portfolio |
22 |
|
Proved undeveloped reserves as of December 31, 2024 |
2,787 |
|
|
|
24 For the past three years we have availed of the independent certification service of DeGolyer and Mac Naughton, Ryder Scott, and Sproule.
25 The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2024.
26 In 2024 Azule and Vår Energi.
27 In 2024, the volumes of Azule Energy and Vår Energi are included, for which Eni has requested a Third Party Letter.
F-142
In 2024, total proved undeveloped reserves increased by 368 mmboe (proved undeveloped reserves of consolidated companies decreased by 29 mmboe, while those of joint ventures and associates increased by 397 mmboe).
Main changes derived from:
i) Progress in conversion to proved developed reserves (-128 million boe) mainly related to the advancement of development activities, reservoir start-ups and project reviews related to Baleine in Ivory Coast, Azule Energy in Angola, Karachaganak in Kazakhstan, and Cassiopea in Italy;
ii) new discoveries and extensions amounting to 367 million boe, of which 51 million boe of liquids and 316 million boe of gas, are mainly the result of the recognition of reserves from the Coral North project (329 million boe), based on Eni's final investment decision, the status and commitment by the joint venture operating the project, and the reasonable expectation that the remaining formal approvals from the Mozambique government authorities will be obtained shortly. The development of the Coral North project is regulated under the terms and conditions of the Area 4 PSC awarded to the joint venture in 2006. In addition, the new discoveries and extensions also refer to the final investment decision and the obtaining of all approvals for the projects, of Bonga North in Nigeria (23 million boe) and Umm Shaif in the United Arab Emirates (15 million boe);
iii) revisions of previous estimates (107 million boe), mainly in liquids. Positive revisions mainly refer to the advancement of development activity in the United Arab Emirates (155 million boe) mainly in the Hail & Ghasha fields and in the United States (18 million boe). Negative revisions mainly refer to a reduction in Var Energi (-58 million boe) and Libya (-29 million boe);
iv) portfolio operations (+22 million boe), from the effect of the acquisition of Neptune, which brought new assets in Norway, Indonesia, and the UK, and from the business combination with Ithaca Energy (sale of UK assets to Ithaca Energy and acquisition of 37.17% stake in all assets in Ithaca Energy) and from the sale of assets in Alaska, Nigeria, and Congo.
Proved reserves of crude oil (including condensate and natural gas liquids)
|
(million barrels) |
|
|
|
|
|
|
|
|
|
|
2024 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2023 |
211 |
27 |
523 |
334 |
637 |
485 |
213 |
|
2,430 |
|
of which: developed |
136 |
24 |
326 |
225 |
576 |
240 |
163 |
|
1,690 |
|
undeveloped |
75 |
3 |
197 |
109 |
61 |
245 |
50 |
|
740 |
|
Purchase of Minerals in Place |
|
8 |
|
|
|
|
|
|
8 |
|
Revisions of Previous Estimates |
12 |
|
|
22 |
(6) |
105 |
52 |
|
185 |
|
Improved Recovery |
|
|
|
|
|
|
1 |
|
1 |
|
Extensions and Discoveries |
|
|
|
15 |
|
22 |
|
|
37 |
|
Production |
(10) |
(6) |
(65) |
(32) |
(40) |
(34) |
(21) |
|
(208) |
|
Sales of Minerals in Place |
|
(29) |
|
(71) |
|
|
(118) |
|
(218) |
|
Reserves at December 31, 2024 |
213 |
|
458 |
268 |
591 |
578 |
127 |
|
2,235 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2023 |
|
326 |
6 |
207 |
|
110 |
26 |
|
675 |
|
of which: developed |
|
167 |
6 |
107 |
|
|
26 |
|
306 |
|
undeveloped |
|
159 |
|
100 |
|
110 |
|
|
369 |
|
Purchase of Minerals in Place |
|
90 |
1 |
2 |
|
|
|
|
93 |
|
Revisions of Previous Estimates |
|
21 |
2 |
35 |
|
|
|
|
58 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
|
14 |
|
|
|
|
14 |
|
Production |
|
(44) |
(1) |
(32) |
|
|
(3) |
|
(80) |
|
Sales of Minerals in Place |
|
(2) |
|
|
|
|
|
|
(2) |
|
Reserves at December 31, 2024 |
|
391 |
8 |
226 |
|
110 |
23 |
|
758 |
|
Reserves at December 31, 2024 |
213 |
391 |
466 |
494 |
591 |
688 |
150 |
|
2,993 |
|
Developed |
129 |
207 |
299 |
290 |
539 |
233 |
104 |
|
1,801 |
|
consolidated subsidiaries |
129 |
|
291 |
187 |
539 |
233 |
81 |
|
1,460 |
|
equity-accounted entities |
|
207 |
8 |
103 |
|
|
23 |
|
341 |
|
Undeveloped |
84 |
184 |
167 |
204 |
52 |
455 |
46 |
|
1,192 |
|
consolidated subsidiaries |
84 |
|
167 |
81 |
52 |
345 |
46 |
|
775 |
|
equity-accounted entities |
|
184 |
|
123 |
|
110 |
|
|
417 |
F-143
|
(million barrels) |
|
|
|
|
|
|
|
|
|
|
2023 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2022 |
188 |
36 |
531 |
367 |
644 |
433 |
234 |
1 |
2,434 |
|
of which: developed |
139 |
32 |
336 |
212 |
585 |
231 |
171 |
1 |
1,707 |
|
undeveloped |
49 |
4 |
195 |
155 |
59 |
202 |
63 |
|
727 |
|
Purchase of Minerals in Place |
|
|
4 |
|
|
|
|
|
4 |
|
Revisions of Previous Estimates |
34 |
(2) |
58 |
(2) |
35 |
35 |
3 |
(1) |
160 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
|
|
|
50 |
|
|
50 |
|
Production |
(11) |
(7) |
(70) |
(31) |
(42) |
(31) |
(24) |
|
(216) |
|
Sales of Minerals in Place |
|
|
|
|
|
(2) |
|
|
(2) |
|
Reserves at December 31, 2023 |
211 |
27 |
523 |
334 |
637 |
485 |
213 |
|
2,430 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2022 |
|
350 |
8 |
235 |
|
100 |
27 |
|
720 |
|
of which: developed |
|
173 |
8 |
135 |
|
|
27 |
|
343 |
|
undeveloped |
|
177 |
|
100 |
|
100 |
|
|
377 |
|
Purchase of Minerals in Place |
|
|
|
2 |
|
|
|
|
2 |
|
Revisions of Previous Estimates |
|
9 |
(1) |
2 |
|
10 |
|
|
20 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
|
|
|
|
|
|
|
|
Production |
|
(32) |
(1) |
(32) |
|
|
(1) |
|
(66) |
|
Sales of Minerals in Place |
|
(1) |
|
|
|
|
|
|
(1) |
|
Reserves at December 31, 2023 |
|
326 |
6 |
207 |
|
110 |
26 |
|
675 |
|
Reserves at December 31, 2023 |
211 |
353 |
529 |
541 |
637 |
595 |
239 |
|
3,105 |
|
Developed |
136 |
191 |
332 |
332 |
576 |
240 |
189 |
|
1,996 |
|
consolidated subsidiaries |
136 |
24 |
326 |
225 |
576 |
240 |
163 |
|
1,690 |
|
equity-accounted entities |
|
167 |
6 |
107 |
|
|
26 |
|
306 |
|
Undeveloped |
75 |
162 |
197 |
209 |
61 |
355 |
50 |
|
1,109 |
|
consolidated subsidiaries |
75 |
3 |
197 |
109 |
61 |
245 |
50 |
|
740 |
|
equity-accounted entities |
|
159 |
|
100 |
|
110 |
|
|
369 |
|
(million barrels) |
|
|
|
|
|
|
|
|
|
|
2022 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2021 |
197 |
34 |
603 |
589 |
710 |
476 |
237 |
1 |
2,847 |
|
of which: developed |
146 |
34 |
389 |
435 |
641 |
262 |
164 |
1 |
2,072 |
|
undeveloped |
51 |
|
214 |
154 |
69 |
214 |
73 |
|
775 |
|
Purchase of Minerals in Place |
1 |
|
17 |
|
|
|
2 |
|
20 |
|
Revisions of Previous Estimates |
3 |
6 |
(24) |
(62) |
(34) |
(15) |
13 |
|
(113) |
|
Improved Recovery |
|
|
2 |
|
|
|
4 |
|
6 |
|
Extensions and Discoveries |
|
3 |
6 |
61 |
|
|
|
|
70 |
|
Production |
(13) |
(7) |
(73) |
(51) |
(32) |
(28) |
(22) |
|
(226) |
|
Sales of Minerals in Place |
|
|
|
(170) |
|
|
|
|
(170) |
|
Reserves at December 31, 2022 |
188 |
36 |
531 |
367 |
644 |
433 |
234 |
1 |
2,434 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2021 |
|
378 |
9 |
21 |
|
|
6 |
|
414 |
|
of which: developed |
|
175 |
9 |
9 |
|
|
6 |
|
199 |
|
undeveloped |
|
203 |
|
12 |
|
|
|
|
215 |
|
Purchase of Minerals in Place |
|
|
|
132 |
|
100 |
|
|
232 |
|
Revisions of Previous Estimates |
|
38 |
|
37 |
|
|
22 |
|
97 |
|
Improved Recovery |
|
|
|
4 |
|
|
|
|
4 |
|
Extensions and Discoveries |
|
4 |
|
54 |
|
|
|
|
58 |
|
Production |
|
(33) |
(1) |
(13) |
|
|
(1) |
|
(48) |
|
Sales of Minerals in Place |
|
(37) |
|
|
|
|
|
|
(37) |
|
Reserves at December 31, 2022 |
|
350 |
8 |
235 |
|
100 |
27 |
|
720 |
|
Reserves at December 31, 2022 |
188 |
386 |
539 |
602 |
644 |
533 |
261 |
1 |
3,154 |
|
Developed |
139 |
205 |
344 |
347 |
585 |
231 |
198 |
1 |
2,050 |
|
consolidated subsidiaries |
139 |
32 |
336 |
212 |
585 |
231 |
171 |
1 |
1,707 |
|
equity-accounted entities |
|
173 |
8 |
135 |
|
|
27 |
|
343 |
|
Undeveloped |
49 |
181 |
195 |
255 |
59 |
302 |
63 |
|
1,104 |
|
consolidated subsidiaries |
49 |
4 |
195 |
155 |
59 |
202 |
63 |
|
727 |
|
equity-accounted entities |
|
177 |
|
100 |
|
100 |
|
|
377 |
Main changes in proved reserves of crude oil (including condensates and natural gas liquids) reported in the tables above for the period 2024, 2023 and 2022 are discussed below.
F-144
Consolidated subsidiaries
Purchase of Minerals in Place
In 2022, 20 mmbbl were booked, mainly for the acquisition of the BHP share in Algeria and a share in some fields in the United States Gulf of Mexico.
In 2023, we had an acquisition of some BP assets in Algeria for 4 mmbbl.
In 2024, 8 mmbbl were obtained for the acquisition of the Neptune company.
Revisions of Previous Estimates
In 2022, revisions of previous estimates were negative of 113 mmbbl. The main positive revisions were in the United Arab Emirates (+23 mmbbl) particularly of the Umm Shaif field (19 mmbbl), the United States (+16 mmbbl) mainly at the Triton and Allegheny fields, and Libya (15 mmbbl) at the Wafa and Structure E fields. The main negative changes were in Nigeria (-70 mmbbl), Iraq (-39 mmbbl) and Kazakhstan (-34 mmbbl) due to price effect and Algeria (-23 mmbbl).
In 2023, revisions of previous estimates were +160 mmbbl. The main positive revisions were in Libya (+53 mmbbl) mainly in Area D and Bouri due to contractual changes and price effect; in Kazakhstan (+35 mmbbl) in Kashagan and Karachaganak fields mainly due to price effect; in Italy (+34 mmbbl) mainly in Val d'Agri and Gela; in Iraq (+24 mmbbl) in Zubair field due to price effect. The main negative changes were Nigeria (-8 mmbbl) mainly on NAOC fields; in the United States of America (-10 mmbbl) mainly on Triton, Oooguruk and Allegheny fields.
In 2024, revisions of previous estimates were +185 mmbbl. The main positive revisions were in the United Arab Emirates (+110 mmbbl) mainly in the Ghasha, Lower Zakum and Hail fields, due to availability of updated data from the new wells; in Algeria (+30 mmbbl) mainly in the Berkine North fields due to better performances. The main negative revisions were in Egypt (-31 mmbbl) mainly concentrated in the Belayim and Meleiha fields and considered the performance trends of the fields.
Improved Recovery
In 2022, 6 mmbbl were booked due to improved recovery mainly at the Mizton field in Mexico and the BRW field in Algeria.
In 2023, there were no increases due to improvements from assisted recovery.
In 2024, there was 1 mmbbl due to improvements from assisted recovery on the St. Malo field in the United States of America.
Extensions and Discoveries
In 2022, 70 mmbbl of new discoveries and extensions were realized mainly due to the final investment decision on the development of the Baleine field in Ivory Coast (59 mmbbl), the NAHE project in Algeria, and the Talbot field in the United Kingdom.
In 2023, new discoveries and extensions amounted to 50 mmbbl, mainly related to the United Arab Emirates following the final investment decision in the Hail and Ghasha project.
In 2024, new discoveries and extensions amounted to 37 mmbbl, mainly due to the final investment decision in the Umm Shaif projects in the United Arab Emirates (22 mmbbl) and Bonga North in Nigeria (15 mmbbl).
Sales of Minerals in Place
In 2022, 170 mmbbl were de-booked in connection to the contribution of Eni’s assets in Angola to the JV Azule set up 50% with bp and the sale of OML 11 in Nigeria.
In 2023, the divestment of 2 mmbbl mainly concerned the reduction of the share in the Ghasha concession in the United Arab Emirates.
In 2024, 218 mmbbl of divestments were recorded. Of these, 71 mmbbl were related to the sale of NAOC assets in Nigeria, 118 mmbbl to the sale of assets in Alaska, and the remainder were related to the sale of some minor fields in Congo and the results of the business combination with Ithaca Energy.
Equity-accounted entities
Purchase of Minerals in Place
In 2022, acquisitions amounted to 232 mmbbl due to the acquisition of a 50% stake in the JV Azule in Angola (132 mmbbl) and to Eni’s joining the NFE project in Qatar (100 mmbbl).
In 2023, the 2 mmbbl of acquisition of a share in Block 3/05a in Azule.
Acquisitions in 2024 amounted to 93 mmbbl and were mainly due to the business combination with Ithaca Energy and Vår Energi's acquisition of Neptune.
F-145
Revisions of Previous Estimates
In 2022, revisions were a positive 97 mmbbl, located mainly in Azule in Angola (+38 mmbbl), Vår Energi in Norway (+37 mmbbl) and Venezuela (+21 mmbbl).
In 2023, positive revisions of +20 mmbbl were mainly due to Qatar (+10 mmbbl) on the NFE field, Vår Energi in Norway (+9 mmbbl).
In 2024, revisions were positive by 58 mmbbl, affecting mainly Azule Energy and Vår Energi.
Extensions and Discoveries
In 2022, extensions and new discoveries of 58 mmbbl were reported by Azule in Angola and Vår Energi in Norway.
No extensions or new discoveries were recorded in 2023.
In 2024, extensions and new discoveries of 14 mmbbl were mainly the result of the inclusion of reserves from the Coral North project.
Sales of Minerals in Place
In 2022, sales of 37 mmbbl related to the IPO of Vår Energi in Norway.
In 2023, sales amounted to -1 mmbbl for the divestment of the Brage field in Vår Energi in Norway.
In 2024, divestments of 2 mmbbl involved assets of Vår Energi.
Proved reserves of natural gas
|
(billion cubic feet) |
|
|
|
|
|
|
|
|
|
|
2024 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2023 |
859 |
174 |
5,935 |
2,479 |
1,546 |
1,303 |
131 |
192 |
12,619 |
|
of which: developed |
653 |
167 |
3,181 |
1,350 |
1,546 |
725 |
107 |
58 |
7,787 |
|
undeveloped |
206 |
7 |
2,754 |
1,129 |
|
578 |
24 |
134 |
4,832 |
|
Purchase of Minerals in Place |
|
184 |
9 |
|
|
226 |
|
|
419 |
|
Revisions of Previous Estimates |
30 |
2 |
172 |
194 |
35 |
267 |
23 |
3 |
726 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
|
2 |
|
2 |
|
|
4 |
|
Production (a) |
(72) |
(71) |
(778) |
(164) |
(92) |
(215) |
(18) |
(5) |
(1,415) |
|
Sales of Minerals in Place |
|
(235) |
|
(580) |
|
|
(42) |
|
(857) |
|
Reserves at December 31, 2024 |
817 |
54 |
5,338 |
1,931 |
1,489 |
1,583 |
94 |
190 |
11,496 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2023 |
|
515 |
14 |
1,501 |
|
1,406 |
1,260 |
|
4,696 |
|
of which: developed |
|
359 |
14 |
1,036 |
|
|
1,260 |
|
2,669 |
|
undeveloped |
|
156 |
|
465 |
|
1,406 |
|
|
2,027 |
|
Purchase of Minerals in Place |
|
544 |
174 |
|
|
|
|
|
718 |
|
Revisions of Previous Estimates |
|
28 |
56 |
38 |
|
5 |
3 |
|
130 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
|
1,651 |
|
|
|
|
1,651 |
|
Production (b) |
|
(139) |
(22) |
(87) |
|
|
(104) |
|
(352) |
|
Sales of Minerals in Place |
|
(9) |
|
|
|
|
|
|
(9) |
|
Reserves at December 31, 2024 |
|
939 |
222 |
3,103 |
|
1,411 |
1,159 |
|
6,834 |
|
Reserves at December 31, 2024 |
817 |
993 |
5,560 |
5,034 |
1,489 |
2,994 |
1,253 |
190 |
18,330 |
|
Developed |
693 |
597 |
2,914 |
2,260 |
1,486 |
799 |
1,215 |
23 |
9,987 |
|
consolidated subsidiaries |
693 |
52 |
2,692 |
1,206 |
1,486 |
799 |
56 |
23 |
7,007 |
|
equity-accounted entities |
|
545 |
222 |
1,054 |
|
|
1,159 |
|
2,980 |
|
Undeveloped |
124 |
396 |
2,646 |
2,774 |
3 |
2,195 |
38 |
167 |
8,343 |
|
consolidated subsidiaries |
124 |
2 |
2,646 |
725 |
3 |
784 |
38 |
167 |
4,489 |
|
equity-accounted entities |
|
394 |
|
2,049 |
|
1,411 |
|
|
3,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Includes production volumes consumed in operations equal to 223 Bcf.
(b) Includes production volumes consumed in operations equal to 33 Bcf.
F-146
|
(billion cubic feet) |
|
|
|
|
|
|
|
|
|
|
2023 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2022 |
869 |
223 |
6,204 |
2,341 |
1,560 |
1,281 |
264 |
408 |
13,150 |
|
of which: developed |
695 |
214 |
3,402 |
1,306 |
1,560 |
796 |
195 |
223 |
8,391 |
|
undeveloped |
174 |
9 |
2,802 |
1,035 |
|
485 |
69 |
185 |
4,759 |
|
Purchase of Minerals in Place |
|
|
214 |
|
|
|
|
|
214 |
|
Revisions of Previous Estimates |
67 |
(10) |
326 |
294 |
79 |
112 |
5 |
(202) |
671 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
4 |
5 |
|
275 |
|
|
284 |
|
Production (a) |
(77) |
(39) |
(813) |
(161) |
(93) |
(187) |
(25) |
(14) |
(1,409) |
|
Sales of Minerals in Place |
|
|
|
|
|
(178) |
(113) |
|
(291) |
|
Reserves at December 31, 2023 |
859 |
174 |
5,935 |
2,479 |
1,546 |
1,303 |
131 |
192 |
12,619 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2022 |
|
646 |
9 |
1,562 |
|
1,490 |
1,355 |
|
5,062 |
|
of which: developed |
|
444 |
9 |
1,070 |
|
|
1,355 |
|
2,878 |
|
undeveloped |
|
202 |
|
492 |
|
1,490 |
|
|
2,184 |
|
Purchase of Minerals in Place |
|
|
|
|
|
|
|
|
|
|
Revisions of Previous Estimates |
|
(32) |
6 |
22 |
|
(84) |
7 |
|
(81) |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
|
|
|
|
|
|
|
|
|
Production (b) |
|
(97) |
(1) |
(83) |
|
|
(102) |
|
(283) |
|
Sales of Minerals in Place |
|
(2) |
|
|
|
|
|
|
(2) |
|
Reserves at December 31, 2023 |
|
515 |
14 |
1,501 |
|
1,406 |
1,260 |
|
4,696 |
|
Reserves at December 31, 2023 |
859 |
689 |
5,949 |
3,980 |
1,546 |
2,709 |
1,391 |
192 |
17,315 |
|
Developed |
653 |
526 |
3,195 |
2,386 |
1,546 |
725 |
1,367 |
58 |
10,456 |
|
consolidated subsidiaries |
653 |
167 |
3,181 |
1,350 |
1,546 |
725 |
107 |
58 |
7,787 |
|
equity-accounted entities |
|
359 |
14 |
1,036 |
|
|
1,260 |
|
2,669 |
|
Undeveloped |
206 |
163 |
2,754 |
1,594 |
|
1,984 |
24 |
134 |
6,859 |
|
consolidated subsidiaries |
206 |
7 |
2,754 |
1,129 |
|
578 |
24 |
134 |
4,832 |
|
equity-accounted entities |
|
156 |
|
465 |
|
1,406 |
|
|
2,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Includes production volumes consumed in operations equal to 206 Bcf.
(b) Includes production volumes consumed in operations equal to 33 Bcf.
|
2022 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2021 |
918 |
247 |
6,424 |
2,953 |
1,705 |
1,522 |
274 |
428 |
14,471 |
|
of which: developed |
729 |
242 |
4,437 |
1,759 |
1,705 |
971 |
210 |
266 |
10,319 |
|
undeveloped |
189 |
5 |
1,987 |
1,194 |
|
551 |
64 |
162 |
4,152 |
|
Purchase of Minerals in Place |
|
|
6 |
|
|
|
2 |
|
8 |
|
Revisions of Previous Estimates |
39 |
15 |
473 |
(285) |
(73) |
(53) |
17 |
(1) |
132 |
|
Improved Recovery |
|
|
1 |
|
|
|
|
|
1 |
|
Extensions and Discoveries |
|
7 |
89 |
154 |
|
|
|
|
250 |
|
Production (a) |
(88) |
(46) |
(789) |
(176) |
(72) |
(185) |
(29) |
(19) |
(1,404) |
|
Sales of Minerals in Place |
|
|
|
(305) |
|
(3) |
|
|
(308) |
|
Reserves at December 31, 2022 |
869 |
223 |
6,204 |
2,341 |
1,560 |
1,281 |
264 |
408 |
13,150 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Reserves at December 31, 2021 |
|
654 |
10 |
1,285 |
|
|
1,460 |
|
3,409 |
|
of which: developed |
|
457 |
10 |
165 |
|
|
1,460 |
|
2,092 |
|
undeveloped |
|
197 |
|
1,120 |
|
|
|
|
1,317 |
|
Purchase of Minerals in Place |
|
|
|
194 |
|
1,490 |
|
|
1,684 |
|
Revisions of Previous Estimates |
|
144 |
|
127 |
|
|
(10) |
|
261 |
|
Improved Recovery |
|
|
|
|
|
|
|
|
|
|
Extensions and Discoveries |
|
19 |
|
|
|
|
|
|
19 |
|
Production (b) |
|
(108) |
(1) |
(44) |
|
|
(95) |
|
(248) |
|
Sales of Minerals in Place |
|
(63) |
|
|
|
|
|
|
(63) |
|
Reserves at December 31, 2022 |
|
646 |
9 |
1,562 |
|
1,490 |
1,355 |
|
5,062 |
|
Reserves at December 31, 2022 |
869 |
869 |
6,213 |
3,903 |
1,560 |
2,771 |
1,619 |
408 |
18,212 |
|
Developed |
695 |
658 |
3,411 |
2,376 |
1,560 |
796 |
1,550 |
223 |
11,269 |
|
consolidated subsidiaries |
695 |
214 |
3,402 |
1,306 |
1,560 |
796 |
195 |
223 |
8,391 |
|
equity-accounted entities |
|
444 |
9 |
1,070 |
|
|
1,355 |
|
2,878 |
|
Undeveloped |
174 |
211 |
2,802 |
1,527 |
|
1,975 |
69 |
185 |
6,943 |
|
consolidated subsidiaries |
174 |
9 |
2,802 |
1,035 |
|
485 |
69 |
185 |
4,759 |
|
equity-accounted entities |
|
202 |
|
492 |
|
1,490 |
|
|
2,184 |
|
|
|
(a) Includes production volumes consumed in operations equal to 208 Bcf.
(b) Includes production volumes consumed in operations equal to 27 Bcf.
F-147
Main changes in proved reserves of natural gas reported in the tables above for 2024, 2023 and 2022 are discussed below.
Consolidated subsidiaries
Purchase of Minerals in Place
In 2022, acquisitions of 8 BCF cubic meters were made mainly for the acquisition of the BHP share in Algeria (6 BCF) and a share in some fields in the United States Gulf of Mexico.
In 2023, there was 214 BCF meters due to the acquisition of some BP assets in Algeria.
In 2024, 419 BCF were reported for the acquisition of the Neptune company in Indonesia, Netherlands and the United Kingdom.
Revisions of Previous Estimates
In 2022, total revisions were 132 BCF. The main positive revisions were in Congo (469 BCF) mainly at the Nené field, Libya (357 BCF) and Egypt (193 BCF). The main negative revisions were in Nigeria (-764 BCF), Algeria (-74 BCF) and Kazakhstan (-73 BCF).
In 2023, total revisions were +671 BCF. The main positive revisions were recorded in: Libya (+651 BCF) in Area D and Bouri due to contractual changes and price effect; in Congo (+237 BCF) mainly in Mboundi Gas and Nene; in Algeria (+178 BCF) mainly in Block 208-404. The main negative revisions were in Australia (-202 BCF) in the Blacktip field and in Egypt (-506 BCF) mainly for the reconfiguration of the Zohr project phase 2, which entailed a review of the compression design and a downward revision of the relevant reserves.
In 2024, total revisions were +726 BCF. The main revisions were in the United Arab Emirates (+256 BCF) mainly in the Hail and Ghasha fields due to availability of updated data from the new wells; in Algeria (+101 BCF) mainly in the In Amenas, In Salah, HBNS and Brn Silurian fields due to better performance; in Ivory Coast (+87 BCF) in the Baleine field due to better performance; and in Ghana (+76 BCF) in the Sankofa field as a result of the implementation of compression activities.
Improved Recovery
In 2022, we had 1 BCF of improved recoveries in Algeria on the BRW and BKNE Alpha fields.
In 2023 and 2024 there were no improvements from assisted recovery.
Extensions and Discoveries
In 2022, new discoveries and extensions amounted to 250 BCF and mainly related to the final investment decision in Baleine in Ivory Coast and Bashrush in Egypt.
In 2023, new discoveries and extensions were 284 BCF in United Arab Emirates (217 BCF) as a result of the final investment decision in the Hail and Ghasha project and Indonesia (59 BCF) for the final investment decision in Merakes East.
In 2024, new discoveries and extensions totalled 4 BCF, following the final investment decision in the Umm Shaif projects in the United Arab Emirates (2 BCF) and Bonga North in Nigeria (2 BCF).
Sales of Minerals in Place
In 2022, sales were 308 BCF in relation to the contribution of Eni’s assets in Angola to the JV Azule and 3 BFC related to Pakistan.
In 2023, divestments of 291 BCF were mainly due in the United States of America (113 BCF) for the divestment of Alliance assets and in the United Arab Emirates (177 BCF) for the reduction of the share in the Ghasha concession.
In 2024, divestments of 857 BCF were related to the sale of NAOC assets in Nigeria, the sale of assets in Alaska and some minor fields in Congo, and the results of the business combination with Ithaca Energy.
Equity-accounted entities
Purchase of Minerals in Place
In 2022, we had acquisitions for 1,684 BCF due to Eni’s entry into the NFE project in Qatar and the acquisition of a 50% stake in the JV Azule in Angola.
No purchase was made in 2023.
In 2024, acquisitions totalled 718 BCF due to Vår Energi's acquisition of Neptune and the business combination with Ithaca Energy.
Revisions of Previous Estimates
In 2022, revisions of previous estimates were 261 BCF, mainly due to Azule in Angola, Vår Energi in Norway, and Coral in Mozambique.
F-148
In 2023, revisions of previous estimates were -81 BCF mainly due to a positive revision in Mozambique (+77 BCF) in Coral South, Azule in Angola (-55 BCF) and Qatar (-84 BCF) on the NFE field.
In 2024, revisions of previous estimates were +130 BCF, located mainly in Algeria (+57 BCF) in the Touat field, in Mozambique (+46 BCF) in the Coral South field and in Vår Energi.
Extensions and Discoveries
In 2022, extensions and new discoveries were 19 BCF due to Vår Energi in Norway.
In 2023, there were no extensions or new relevant discoveries.
In 2024, extensions and new discoveries of 1,651 BCF were mainly the result of the Coral North project's reserve booking offshore Mozambique, based on the Company final investment decision, status of project maturity and commitment of all the JV partners, as well as the management’s reasonable expectation that remaining formal government approvals will be obtained shortly.
Sales of Minerals in Place
In 2022, sales of 63 BCF were due to the IPO of Vår Energi in Norway.
In 2023, divestments were 2 BCF in the Brage field in Vår Energi in Norway.
In 2024, disposals of 9 BCF were mainly related to portfolio activities of Vår Energi and Azule Energy.
Standardized measure of discounted future net cash flows
Estimated future cash inflows represent the revenues that would be received from production and were determined by applying the year-end average prices during the years ended. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil and Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.
The standardized measure of discounted future net cash flows by geographical area consists of the following:
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
December 31, 2024 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
20,844 |
570 |
66,540 |
30,478 |
40,322 |
49,205 |
9,164 |
742 |
217,865 |
|
Future production costs |
(8,273) |
(297) |
(14,034) |
(10,912) |
(6,786) |
(13,462) |
(3,994) |
(132) |
(57,890) |
|
Future development and abandonment costs |
(3,318) |
(417) |
(9,317) |
(4,942) |
(1,658) |
(7,547) |
(2,104) |
(280) |
(29,583) |
|
Future net inflow before income tax |
9,253 |
(144) |
43,189 |
14,624 |
31,878 |
28,196 |
3,066 |
330 |
130,392 |
|
Future income tax |
(2,088) |
(49) |
(21,879) |
(3,541) |
(8,505) |
(18,186) |
(387) |
(6) |
(54,641) |
|
Future net cash flows |
7,165 |
(193) |
21,310 |
11,083 |
23,373 |
10,010 |
2,679 |
324 |
75,751 |
|
10 % discount factor |
(2,995) |
60 |
(10,150) |
(4,102) |
(11,301) |
(5,826) |
(656) |
(96) |
(35,066) |
|
Standardized measure of discounted future net cash flows |
4,170 |
(133) |
11,160 |
6,981 |
12,072 |
4,184 |
2,023 |
228 |
40,685 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
39,301 |
1,846 |
31,708 |
|
18,602 |
7,397 |
|
98,854 |
|
Future production costs |
|
(10,169) |
(612) |
(7,702) |
|
(5,969) |
(1,882) |
|
(26,334) |
|
Future development and abandonment costs |
|
(7,279) |
(111) |
(4,289) |
|
(278) |
(191) |
|
(12,148) |
|
Future net inflow before income tax |
|
21,853 |
1,123 |
19,717 |
|
12,355 |
5,324 |
|
60,372 |
|
Future income tax |
|
(16,126) |
(205) |
(5,549) |
|
(9,018) |
(2,231) |
|
(33,129) |
|
Future net cash flows |
|
5,727 |
918 |
14,168 |
|
3,337 |
3,093 |
|
27,243 |
|
10 % discount factor |
|
(1,077) |
(285) |
(7,742) |
|
(2,119) |
(1,128) |
|
(12,351) |
|
Standardized measure of discounted future net cash flows |
|
4,650 |
633 |
6,426 |
|
1,218 |
1,965 |
|
14,892 |
|
Total consolidated subsidiaries and equity-accounted entities |
4,170 |
4,517 |
11,793 |
13,407 |
12,072 |
5,402 |
3,988 |
228 |
55,577 |
F-149
|
(€ million) |
|
|
|
|
|
|
|
|
|
|
December 31, 2023 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
22,724 |
3,926 |
72,835 |
35,147 |
40,081 |
40,622 |
14,951 |
707 |
230,993 |
|
Future production costs |
(8,848) |
(1,227) |
(15,439) |
(13,512) |
(6,475) |
(11,042) |
(5,852) |
(164) |
(62,559) |
|
Future development and abandonment costs |
(4,270) |
(824) |
(9,383) |
(7,757) |
(1,814) |
(7,437) |
(1,954) |
(355) |
(33,794) |
|
Future net inflow before income tax |
9,606 |
1,875 |
48,013 |
13,878 |
31,792 |
22,143 |
7,145 |
188 |
134,640 |
|
Future income tax |
(2,233) |
(1,274) |
(24,069) |
(4,729) |
(8,186) |
(16,348) |
(3,161) |
(8) |
(60,008) |
|
Future net cash flows |
7,373 |
601 |
23,944 |
9,149 |
23,606 |
5,795 |
3,984 |
180 |
74,632 |
|
10 % discount factor |
(3,325) |
(39) |
(10,467) |
(4,223) |
(11,668) |
(3,081) |
(1,462) |
(58) |
(34,323) |
|
Standardized measure of discounted future net cash flows |
4,048 |
562 |
13,477 |
4,926 |
11,938 |
2,714 |
2,522 |
122 |
40,309 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
29,387 |
168 |
22,954 |
|
19,108 |
7,519 |
|
79,136 |
|
Future production costs |
|
(7,128) |
(122) |
(6,202) |
|
(5,880) |
(1,925) |
|
(21,257) |
|
Future development and abandonment costs |
|
(5,221) |
(54) |
(2,972) |
|
(410) |
(179) |
|
(8,836) |
|
Future net inflow before income tax |
|
17,038 |
(8) |
13,780 |
|
12,818 |
5,415 |
|
49,043 |
|
Future income tax |
|
(12,548) |
(1) |
(3,254) |
|
(9,702) |
(2,263) |
|
(27,768) |
|
Future net cash flows |
|
4,490 |
(9) |
10,526 |
|
3,116 |
3,152 |
|
21,275 |
|
10 % discount factor |
|
(1,114) |
27 |
(4,508) |
|
(2,158) |
(1,237) |
|
(8,990) |
|
Standardized measure of discounted future net cash flows |
|
3,376 |
18 |
6,018 |
|
958 |
1,915 |
|
12,285 |
|
Total consolidated subsidiaries and equity-accounted entities |
4,048 |
3,938 |
13,495 |
10,944 |
11,938 |
3,672 |
4,437 |
122 |
52,594 |
|
December 31, 2022 |
Italy |
Rest of Europe |
North Africa |
Sub - Saharan Africa |
Kazakhstan |
Rest of Asia |
America |
Australia and Oceania |
Total |
|
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
38,968 |
7,609 |
85,036 |
48,292 |
53,529 |
45,179 |
21,233 |
1,525 |
301,371 |
|
Future production costs |
(10,267) |
(1,752) |
(17,846) |
(15,823) |
(7,844) |
(12,181) |
(5,950) |
(230) |
(71,893) |
|
Future development and abandonment costs |
(4,484) |
(1,296) |
(7,835) |
(10,057) |
(1,873) |
(4,562) |
(3,063) |
(377) |
(33,547) |
|
Future net inflow before income tax |
24,217 |
4,561 |
59,355 |
22,412 |
43,812 |
28,436 |
12,220 |
918 |
195,931 |
|
Future income tax |
(6,388) |
(3,087) |
(30,885) |
(7,990) |
(11,568) |
(21,227) |
(4,903) |
(81) |
(86,129) |
|
Future net cash flows |
17,829 |
1,474 |
28,470 |
14,422 |
32,244 |
7,209 |
7,317 |
837 |
109,802 |
|
10 % discount factor |
(7,141) |
(344) |
(11,738) |
(6,456) |
(16,087) |
(2,980) |
(3,443) |
(357) |
(48,546) |
|
Standardized measure of discounted future net cash flows |
10,688 |
1,130 |
16,732 |
7,966 |
16,157 |
4,229 |
3,874 |
480 |
61,256 |
|
Equity-accounted entities |
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
50,468 |
265 |
42,450 |
|
33,075 |
8,133 |
|
134,391 |
|
Future production costs |
|
(7,628) |
(123) |
(10,579) |
|
(9,749) |
(2,083) |
|
(30,162) |
|
Future development and abandonment costs |
|
(6,458) |
(57) |
(3,508) |
|
(560) |
(178) |
|
(10,761) |
|
Future net inflow before income tax |
|
36,382 |
85 |
28,363 |
|
22,766 |
5,872 |
|
93,468 |
|
Future income tax |
|
(27,333) |
(3) |
(8,117) |
|
(19,393) |
(2,469) |
|
(57,315) |
|
Future net cash flows |
|
9,049 |
82 |
20,246 |
|
3,373 |
3,403 |
|
36,153 |
|
10 % discount factor |
|
(2,501) |
(15) |
(9,058) |
|
(2,462) |
(1,416) |
|
(15,452) |
|
Standardized measure of discounted future net cash flows |
|
6,548 |
67 |
11,188 |
|
911 |
1,987 |
|
20,701 |
|
Total consolidated subsidiaries and equity-accounted entities |
10,688 |
7,678 |
16,799 |
19,154 |
16,157 |
5,140 |
5,861 |
480 |
81,957 |
F-150
Changes in standardized measure of discounted future net cash flows
Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2024, 2023 and 2022, were as follows:
|
(€ million) |
|
|
|
|
2024 |
Consolidated subsidiaries |
Equity-accounted entities |
Total |
|
Standardized measure of discounted future net cash flows at December 31, 2023 |
40,309 |
12,285 |
52,594 |
|
Increase (Decrease): |
|
|
|
|
- sales, net of production costs |
(17,581) |
(6,150) |
(23,731) |
|
- net changes in sales and transfer prices, net of production costs |
(5,380) |
89 |
(5,291) |
|
- extensions, discoveries and improved recovery, net of future production and development costs |
401 |
1,851 |
2,252 |
|
- changes in estimated future development and abandonment costs |
(2,959) |
(3,860) |
(6,819) |
|
- development costs incurred during the period that reduced future development costs |
6,649 |
4,824 |
11,473 |
|
- revisions of quantity estimates |
4,664 |
(2,467) |
2,197 |
|
- accretion of discount |
7,405 |
1,984 |
9,389 |
|
- net change in income taxes |
6,578 |
(1,654) |
4,924 |
|
- purchase of reserves in-place |
1,085 |
5,167 |
6,252 |
|
- sale of reserves in-place |
(2,947) |
(1) |
(2,948) |
|
- changes in production rates (timing) and other |
2,461 |
2,824 |
5,285 |
|
Net increase (decrease) |
376 |
2,607 |
2,983 |
|
Standardized measure of discounted future net cash flows at December 31, 2024 |
40,685 |
14,892 |
55,577 |
|
(€ million) |
|
|
|
|
2023 |
Consolidated subsidiaries |
Equity-accounted entities |
Total |
|
Standardized measure of discounted future net cash flows at December 31, 2022 |
61,256 |
20,701 |
81,957 |
|
Increase (Decrease): |
|
|
|
|
- sales, net of production costs |
(19,397) |
(5,426) |
(24,823) |
|
- net changes in sales and transfer prices, net of production costs |
(33,769) |
(19,785) |
(53,554) |
|
- extensions, discoveries and improved recovery, net of future production and development costs |
1,659 |
|
1,659 |
|
- changes in estimated future development and abandonment costs |
(4,684) |
(1,353) |
(6,037) |
|
- development costs incurred during the period that reduced future development costs |
6,691 |
2,517 |
9,208 |
|
- revisions of quantity estimates |
6,531 |
155 |
6,686 |
|
- accretion of discount |
10,627 |
3,033 |
13,660 |
|
- net change in income taxes |
12,675 |
14,753 |
27,428 |
|
- purchase of reserves in-place |
977 |
44 |
1,021 |
|
- sale of reserves in-place |
(845) |
(60) |
(905) |
|
- changes in production rates (timing) and other |
(1,412) |
(2,294) |
(3,706) |
|
Net increase (decrease) |
(20,947) |
(8,416) |
(29,363) |
|
Standardized measure of discounted future net cash flows at December 31, 2023 |
40,309 |
12,285 |
52,594 |
|
(€ million) |
|
|
|
|
2022 |
Consolidated subsidiaries |
Equity-accounted entities |
Total |
|
Standardized measure of discounted future net cash flows at December 31, 2021 |
44,615 |
7,281 |
51,896 |
|
Increase (Decrease): |
|
|
|
|
- sales, net of production costs |
(25,987) |
(4,912) |
(30,899) |
|
- net changes in sales and transfer prices, net of production costs |
56,002 |
24,343 |
80,345 |
|
- extensions, discoveries and improved recovery, net of future production and development costs |
1,519 |
2,139 |
3,658 |
|
- changes in estimated future development and abandonment costs |
(7,046) |
(3,169) |
(10,215) |
|
- development costs incurred during the period that reduced future development costs |
3,821 |
2,000 |
5,821 |
|
- revisions of quantity estimates |
(1,295) |
7,134 |
5,839 |
|
- accretion of discount |
7,226 |
1,510 |
8,736 |
|
- net change in income taxes |
(18,393) |
(21,676) |
(40,069) |
|
- purchase of reserves in-place |
765 |
10,200 |
10,965 |
|
- sale of reserves in-place |
(6,436) |
|
(6,436) |
|
- changes in production rates (timing) and other |
6,465 |
(4,149) |
2,316 |
|
Net increase (decrease) |
16,641 |
13,420 |
30,061 |
|
Standardized measure of discounted future net cash flows at December 31, 2022 |
61,256 |
20,701 |
81,957 |
F-151