{"url_path":"/sec/e/10-k/2026/item-18","section_key":"item-18","section_title":"Item 18 FINANCIAL STATEMENTS","topic":"sec","document":{"doc_type":"20-F","doc_date":"2026-03-23","source_url":"https://www.sec.gov/Archives/edgar/data/1002242/0001554855-26-000390-index.html","accession_number":"0001554855-26-000390","cik":"0001002242","ticker":"E","issuer_name":"ENI SPA","edgar_url":"https://www.sec.gov/Archives/edgar/data/1002242/0001554855-26-000390-index.html","primary_entity_key":"0001002242","primary_entity_name":"ENI SPA"},"word_count":80014,"has_tables":true,"body_markdown":"Item 18. FINANCIAL STATEMENTS\n\nIndex to Financial Statements:\n\n​​\n\n \n\nPage\n\n[Report of Independent Registered Public Accounting Firm (PCAOB ID:00030)](#TOC_67c29aa4c8016158)\n\nF-1\n\n[Consolidated Balance Sheet as of December 31, 2025 and December 31, 2024](#TOC_df52596c75c83295)\n\nF-4\n\n[Consolidated Profit and Loss Account for the years ended December 31, 2025, 2024 and 2023](#TOC_2ec29ca9df40b5f7)\n\nF-5\n\n[Consolidated Statement of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023](#TOC_ad0c18103470c636)\n\nF-6\n\n[Consolidated Statement of Changes in Equity for the years ended December 31, 2025, 2024 and 2023](#TOC_e40575d13c633d36)\n\nF-7\n\n[Consolidated Statement of Cash Flows for the years ended December 31, 2025, 2024 and 2023](#TOC_c99ac96b3d13f34a)\n\nF-10\n\n[Notes on Consolidated Financial Statements](#TOC_18cf65215902ed0c)\n\nF-12\n\n \n\n188\n\n[Table of Contents](#TOC_TableofContent) \n\n[Item 19. EXHIBITS](#TOC)\n\n1.\n\n[By-laws of Eni SpA](ex1_1.htm)\n\n2.\n\n[Description of securities registered under Section 12 of the Exchange Act](ex2_2.htm)\n\n8.\n\nList of subsidiaries (see Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements)\n\n11.\n\n[Code of Ethics (incorporated by reference to Exhibit 11 to Form 20-F 2019 (File No. 001-14090) filed on April 2, 2020)](https://www.sec.gov/Archives/edgar/data/1002242/000110465920042364/tm1923634d3_ex11.htm)\n\n11.2\n\n[Insider trading policy and procedure (incorporated by reference to Exhibit 11.2 to Form 20-F 2024 (File No. 001-14090) filed on April 4, 2025)](https://www.sec.gov/Archives/edgar/data/1002242/000155485525000286/ex112_3.htm)\n\nCertifications:\n\n12.1.\n\n[Certifications pursuant to Rule 13a-14(a) of the Securities Exchange Act](ex121_4.htm)\n\n12.2. \n\n[Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act](ex122_5.htm)\n\n13.1.\n\n[Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)](ex131_6.htm)\n\n13.2.\n\n[Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)](ex132_7.htm)\n\n15.a(i)\n\n[Excerpt of the pages and sections of the report on the 2026 remuneration policy and remuneration paid 2025 prepared in accordance with Italian listing standards incorporated herein by reference](ex15AI_8.htm)\n\n15.a(ii)\n\n[Report of Ryder Scott Co](ex15AII_9.htm)\n\n15.a(iii)\n\n[Report of Sproule](ex15AIII_10.htm)\n\n15.a(iv) \n\n[Report of DeGolyer and MacNaughton](ex15AIV_11.htm)\n\n15.a(v)\n\n[Report of DeGolyer and MacNaughton](ex15AV_12.htm)\n\n97\n\n[Executive Compensation Clawback policy (incorporated by reference to Exhibit 97 to Form 20-F 2024 (File No. 001-14090) filed on April 4, 2025)](https://www.sec.gov/Archives/edgar/data/1002242/000155485525000286/ex97_13.htm)\n\n99\n\n[EU Taxonomy](ex99_14.htm)\n\n101.INS  \n\nInline 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\n\n101.SCH \n\nInline XBRL Taxonomy Extension Schema\n\n101.CAL \n\nInline XBRL Taxonomy Extension Schema Calculation Linkbase \n\n101.DEF \n\nInline XBRL Taxonomy Extension Schema Definition Linkbase\n\n101.LAB\n\nInline XBRL Taxonomy Extension Schema Label Linkbase\n\n101.PRE\n\nInline XBRL Taxonomy Extension Schema Presentation Linkbase\n\n104.\n\nCover Page Interactive Date File (formatted as Inline XBRL and contained in Exhibit 101)\n\n \n\n189\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nSIGNATURES\n\nThe 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.\n\n Date: March 23, 2026\n\n \n\n \n\n \n\nEni SpA\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n/s/ FRANCESCO ESPOSITO\n\n \n\n \n\nFrancesco Esposito\n\n \n\n \n\nTitle: Head of Accounting and\n\n \n\n \n\nFinancial Statements\n\n \n\n190\n\nReport of Independent Registered Public Accounting Firm\n\n \n\nTo the Board of Directors and Shareholders of Eni SpA\n\n \n\nOpinions on the Financial Statements and Internal Control over Financial Reporting\n\n \n\nWe have audited the accompanying consolidated balance sheet of Eni SpA and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, 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, 2025, 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, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).\n\n \n\nIn 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 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, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. \n\n \n\nBasis for Opinions\n\n \n\nThe 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.\n\n \n\nWe 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.\n\n \n\nOur 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.\n\n \n\nAs described in Management’s Annual Report on Internal Control over Financial Reporting, management has excluded 58 entities from its assessment of internal control over financial reporting as of December 31, 2025 because they were acquired by the Company in several purchase business combinations during 2025. We have also excluded these 58 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 1% and 0% of consolidated total assets and consolidated total revenues, respectively, as of and for the year ended December 31, 2025.\n\n \n\nDefinition and Limitations of Internal Control over Financial Reporting\n\n \n\nA 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.\n\n \n\nBecause 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.\n\n \n\nF-1\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCritical Audit Matters\n\n \n\nThe 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.\n\n \n\nThe Impact of Estimated Proved Oil and Natural Gas Reserves on E&P Property, Plant and Equipment, Net\n\n \n\nAs described in Notes 1 and 12 to the consolidated financial statements, the Company’s consolidated net property, plant and equipment (PP&E) was €50.5 billion as of December 31, 2025, of which €41.0 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 €5.3 billion for the year ended December 31, 2025. 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, depreciation of investments relating to mineral activities is generally calculated using the unit of production (UOP) method. In particular: (i) exploration rights and mineral titles acquired related to proved reserves are amortised considering total proved reserves; (ii) capitalised exploration, appraisal and development costs related to production facilities are amortised considering proved developed reserves and facilities are depreciated considering total proved reserves; (iii) for owned floating facilities, depreciation is calculated using the UOP method considering the recovery of 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”).\n\n \n\nThe 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.\n\n \n\nAddressing 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 (i) evaluating the process related to the reserve estimates including certain data, methods and assumptions used by management’s specialists and (ii) evaluating and testing, on a sample basis, the relevance and reliability of geological and technical engineering data used by management’s specialists to develop the reserve estimates.\n\n \n\nRecoverability Assessment of Certain E&P Property, Plant and Equipment, Net\n\n \n\nAs described in Notes 1 and 12 to the consolidated financial statements, the Company’s consolidated net PP&E was €50.5 billion as of December 31, 2025, of which €41.0 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 €1.1 billion for the year ended December 31, 2025. 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.\n\n \n\nF-2\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe 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.\n\n \n\nAddressing 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, future development costs and production costs, and the discount rates. 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 (i) evaluating the process related to the reserve estimates including certain data, methods and assumptions used by management’s specialists; (ii) evaluating and testing, on a sample basis, the relevance and reliability of geological and technical engineering data used by the specialists to develop the reserve estimates; (iii) evaluating the appropriateness of the value in use models; (iv) evaluating the reasonableness of the future commodity prices including the effects of inflation assumption; and (v) evaluating the reasonableness of the discount rates assumption.\n\n \n\n/s/ PricewaterhouseCoopers SpA\n\nRome, Italy\n\nMarch 23, 2026\n\n \n\nWe have served as the Company’s auditor since 2019.\n\n \n\nF-3\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED BALANCE SHEET\n\n(€ million)\n\n \n\n \n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n \n\nNote\n\nTotal amount\n\nof which with related parties\n\nTotal amount\n\nof which with related parties\n\nASSETS\n\n \n\n \n\n \n\n \n\n \n\nCurrent assets\n\n \n\n \n\n \n\n \n\n \n\nCash and cash equivalents\n\n(6)\n\n8,100\n\n \n\n8,183\n\n \n\nFinancial assets at fair value through profit or loss\n\n(7)\n\n6,991\n\n \n\n6,797\n\n \n\nOther current financial assets\n\n(17)\n\n3,710\n\n2,357\n\n1,085\n\n48\n\nTrade and other receivables\n\n(8)\n\n12,436\n\n1,375\n\n16,901\n\n1,601\n\nInventories\n\n(9)\n\n5,143\n\n \n\n6,259\n\n \n\nIncome tax receivables\n\n(10)\n\n539\n\n \n\n695\n\n \n\nOther current assets\n\n(11) (24)\n\n3,943\n\n76\n\n3,662\n\n54\n\n \n\n \n\n40,862\n\n \n\n43,582\n\n \n\nNon-current assets\n\n \n\n \n\n \n\n \n\n \n\nProperty, plant and equipment\n\n(12)\n\n50,536\n\n \n\n59,864\n\n \n\nRight-of-use assets\n\n(13)\n\n5,184\n\n \n\n5,822\n\n \n\nIntangible assets\n\n(14)\n\n6,022\n\n \n\n6,434\n\n \n\nInventory - Compulsory stock\n\n(9)\n\n1,187\n\n \n\n1,595\n\n \n\nEquity-accounted investments\n\n(16) (37)\n\n13,155\n\n \n\n14,150\n\n \n\nOther investments\n\n(16)\n\n1,329\n\n \n\n1,395\n\n \n\nOther non-current financial assets\n\n(17)\n\n1,109\n\n612\n\n3,215\n\n2,380\n\nDeferred tax assets\n\n(23)\n\n6,716\n\n \n\n6,322\n\n \n\nIncome tax receivables\n\n(10)\n\n125\n\n \n\n129\n\n \n\nOther non-current assets\n\n(11) (24)\n\n2,839\n\n207\n\n4,011\n\n142\n\n \n\n \n\n88,202\n\n \n\n102,937\n\n \n\nAssets held for sale\n\n(25)\n\n8,005\n\n \n\n420\n\n \n\nTOTAL ASSETS\n\n \n\n137,069\n\n \n\n146,939\n\n \n\nLIABILITIES AND EQUITY\n\n \n\n \n\n \n\n \n\n \n\nCurrent liabilities\n\n \n\n \n\n \n\n \n\n \n\nShort-term debt\n\n(19)\n\n4,929\n\n265\n\n4,238\n\n136\n\nCurrent portion of long-term debt\n\n(19)\n\n3,434\n\n128\n\n4,582\n\n21\n\nCurrent portion of long-term lease liabilities\n\n(13)\n\n1,263\n\n108\n\n1,279\n\n152\n\nTrade and other payables\n\n(18)\n\n20,261\n\n4,283\n\n22,092\n\n4,017\n\nIncome tax payables\n\n(10)\n\n343\n\n \n\n587\n\n \n\nOther current liabilities\n\n(11) (24)\n\n4,039\n\n86\n\n5,049\n\n34\n\n \n\n \n\n34,269\n\n \n\n37,827\n\n \n\nNon-current liabilities\n\n \n\n \n\n \n\n \n\n \n\nLong-term debt\n\n(19)\n\n20,139\n\n52\n\n21,570\n\n79\n\nLong-term lease liabilities\n\n(13)\n\n4,437\n\n40\n\n5,174\n\n31\n\nProvisions\n\n(21)\n\n14,580\n\n \n\n15,774\n\n \n\nProvisions for employee benefits\n\n(22)\n\n596\n\n \n\n681\n\n \n\nDeferred tax liabilities\n\n(23)\n\n4,805\n\n \n\n5,581\n\n \n\nIncome tax payables\n\n(10)\n\n40\n\n \n\n40\n\n \n\nOther non-current liabilities\n\n(11) (24)\n\n3,390\n\n462\n\n4,449\n\n520\n\n \n\n \n\n47,987\n\n \n\n53,269\n\n \n\nLiabilities directly associated with assets held for sale\n\n(25)\n\n2,026\n\n \n\n195\n\n \n\nTOTAL LIABILITIES\n\n \n\n84,282\n\n \n\n91,291\n\n \n\nShare capital\n\n \n\n4,005\n\n \n\n4,005\n\n \n\nRetained earnings\n\n \n\n33,209\n\n \n\n32,552\n\n \n\nCumulative currency translation differences\n\n \n\n1,936\n\n \n\n8,081\n\n \n\nOther reserves and equity instruments\n\n \n\n8,964\n\n \n\n8,406\n\n \n\nTreasury shares\n\n \n\n(2,782)\n\n \n\n(2,883)\n\n \n\nProfit\n\n \n\n2,608\n\n \n\n2,624\n\n \n\nEquity attributable to equity holders of Eni\n\n \n\n47,940\n\n \n\n52,785\n\n \n\nNon-controlling interest\n\n \n\n4,847\n\n \n\n2,863\n\n \n\nTOTAL EQUITY\n\n(26)\n\n52,787\n\n \n\n55,648\n\n \n\nTOTAL LIABILITIES AND EQUITY\n\n \n\n137,069\n\n \n\n146,939\n\n \n\n \n\nSee the accompanying notes.\n\n \n\nInformation about the definitive purchase price allocation of business combinations made in 2024 is provided in note 27 ‐ Other Information.\n\n \n\nF-4\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED PROFIT AND LOSS ACCOUNT\n\n(€ million except as otherwise stated)\n\n \n\n \n\n \n\n2025\n\n2024\n\n2023\n\n \n\nNote\n\nTotal amount\n\nof which  with related parties\n\nTotal amount\n\nof which  with related parties\n\nTotal amount\n\nof which  with related parties\n\nSales from operations\n\n \n\n82,151\n\n2,973\n\n88,797\n\n2,997\n\n93,717\n\n4,322\n\nOther income and revenues\n\n \n\n1,478\n\n285\n\n2,417\n\n279\n\n1,099\n\n156\n\nREVENUES AND OTHER INCOME\n\n(29)\n\n83,629\n\n \n\n91,214\n\n \n\n94,816\n\n \n\nPurchases, services and other\n\n(30)\n\n(67,056)\n\n(17,769)\n\n(71,114)\n\n(17,404)\n\n(73,836)\n\n(15,885)\n\nNet (impairments) reversals of trade and other receivables\n\n(8)\n\n(11)\n\n(1)\n\n(168)\n\n(2)\n\n(249)\n\n5\n\nPayroll and related costs\n\n(30)\n\n(3,229)\n\n17\n\n(3,262)\n\n3\n\n(3,136)\n\n(8)\n\nOther operating income (expense)\n\n(24)\n\n641\n\n(264)\n\n(352)\n\n201\n\n478\n\n17\n\nDepreciation and amortization\n\n(12) (13) (14)\n\n(7,349)\n\n \n\n(7,600)\n\n \n\n(7,479)\n\n \n\nNet (impairments) reversals of tangible, intangible and right-of-use assets\n\n(15)\n\n(1,582)\n\n \n\n(2,900)\n\n \n\n(1,802)\n\n \n\nWrite-off of tangible and intangible assets\n\n(12) (13) (14)\n\n(33)\n\n \n\n(580)\n\n \n\n(535)\n\n \n\nOPERATING PROFIT (LOSS)\n\n \n\n5,010\n\n \n\n5,238\n\n \n\n8,257\n\n \n\nFinance income\n\n(31)\n\n7,196\n\n215\n\n7,715\n\n198\n\n7,417\n\n155\n\nFinance expense\n\n(31)\n\n(8,170)\n\n(77)\n\n(8,980)\n\n(57)\n\n(8,113)\n\n(28)\n\nNet finance income (expense) from financial assets at fair value through profit or loss\n\n(31)\n\n235\n\n \n\n388\n\n \n\n284\n\n \n\nDerivative financial instruments\n\n(24) (31)\n\n(80)\n\n \n\n278\n\n \n\n(61)\n\n1\n\nFINANCE INCOME (EXPENSE)\n\n \n\n(819)\n\n \n\n(599)\n\n \n\n(473)\n\n \n\nShare of profit (loss) from equity-accounted investments\n\n \n\n1,161\n\n \n\n866\n\n \n\n1,336\n\n \n\nOther gain (loss) from investments\n\n \n\n426\n\n(18)\n\n984\n\n(12)\n\n1,108\n\n445\n\nINCOME (EXPENSE) FROM INVESTMENTS\n\n(16) (32)\n\n1,587\n\n \n\n1,850\n\n \n\n2,444\n\n \n\nPROFIT BEFORE INCOME TAXES\n\n \n\n5,778\n\n \n\n6,489\n\n \n\n10,228\n\n \n\nIncome taxes\n\n(33)\n\n(3,020)\n\n \n\n(3,725)\n\n \n\n(5,368)\n\n \n\nPROFIT\n\n \n\n2,758\n\n \n\n2,764\n\n \n\n4,860\n\n \n\nAttributable to Eni\n\n \n\n2,608\n\n \n\n2,624\n\n \n\n4,771\n\n \n\nAttributable to non-controlling interest\n\n(26)\n\n150\n\n \n\n140\n\n \n\n89\n\n \n\nEarnings per share (€ per share)\n\n(34)\n\n \n\n \n\n \n\n \n\n \n\n \n\nBasic\n\n \n\n0.78\n\n \n\n0.79\n\n \n\n1.41\n\n \n\nDiluted\n\n \n\n0.78\n\n \n\n0.78\n\n \n\n1.40\n\n \n\n \n\nSee the accompanying notes.\n\n \n\nF-5\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME\n\n(€ million)\n\n \n\n \n\nNote\n\n2025\n\n2024\n\n2023\n\nProfit\n\n \n\n2,758\n\n2,764\n\n4,860\n\nOther items of comprehensive income (loss)\n\n \n\n \n\n \n\n \n\nItems that are not reclassified to profit or loss in later periods:\n\n \n\n \n\n \n\n \n\nRemeasurements of defined benefit plans\n\n(26)\n\n(9)\n\n8\n\n(31)\n\nShare of other comprehensive income (loss) on equity-accounted investments\n\n(26)\n\n \n\n1\n\n(2)\n\nChange of minor investments measured at fair value with effects to OCI\n\n(26)\n\n(30)\n\n62\n\n45\n\nTax effect\n\n(26)\n\n2\n\n(4)\n\n10\n\n \n\n \n\n(37)\n\n67\n\n22\n\nItems that may be reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n \n\nCurrency translation differences\n\n(26)\n\n(6,410)\n\n3,066\n\n(2,010)\n\nChange in the fair value of cash flow hedging derivatives\n\n(26)\n\n865\n\n(912)\n\n541\n\nShare of other comprehensive income (loss) on equity-accounted investments\n\n(26)\n\n65\n\n(69)\n\n54\n\nTax effect\n\n(26)\n\n(258)\n\n263\n\n(158)\n\n \n\n \n\n(5,738)\n\n2,348\n\n(1,573)\n\nTotal other items of comprehensive income (loss)\n\n \n\n(5,775)\n\n2,415\n\n(1,551)\n\nTotal comprehensive income\n\n \n\n(3,017)\n\n5,179\n\n3,309\n\nAttributable to Eni\n\n \n\n(2,874)\n\n4,962\n\n3,220\n\nAttributable to non-controlling interest\n\n \n\n(143)\n\n217\n\n89\n\n \n\nSee the accompanying notes.\n\n \n\nF-6\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED STATEMENT OF CHANGES IN EQUITY\n\n(€ million)\n\n \n\n \n\n \n\nEquity attributable to equity holders of Eni\n\n \n\n \n\n \n\nNote\n\nShare capital\n\nRetained earnings\n\nCumulative  currency translation differences\n\nOther reserves and equity instruments\n\nTreasury shares\n\nProfit (loss) for the year\n\nTotal\n\nNon-controlling interest\n\nTotal equity\n\nBalance at December 31, 2024\n\n(26)\n\n4,005\n\n32,552\n\n8,081\n\n8,406\n\n(2,883)\n\n2,624\n\n52,785\n\n2,863\n\n55,648\n\nProfit for the year\n\n \n\n \n\n \n\n \n\n \n\n \n\n2,608\n\n2,608\n\n150\n\n2,758\n\nOther items of comprehensive income (loss)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRemeasurements of defined benefit plans net of tax effect\n\n(26)\n\n \n\n \n\n \n\n(9)\n\n \n\n \n\n(9)\n\n2\n\n(7)\n\nChange of minor investments measured at fair value with effects to OCI\n\n(26)\n\n \n\n \n\n \n\n(32)\n\n \n\n \n\n(32)\n\n2\n\n(30)\n\nItems that are not reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n \n\n(41)\n\n \n\n \n\n(41)\n\n4\n\n(37)\n\nCurrency translation differences\n\n(26)\n\n \n\n \n\n(6,144)\n\n \n\n \n\n \n\n(6,144)\n\n(266)\n\n(6,410)\n\nChange in the fair value of cash flow hedge derivatives net of tax effect\n\n(26)\n\n \n\n \n\n \n\n630\n\n \n\n \n\n630\n\n(23)\n\n607\n\nShare of “Other comprehensive income (loss)” on equity-accounted investments\n\n(26)\n\n \n\n \n\n \n\n73\n\n \n\n \n\n73\n\n(8)\n\n65\n\nItems that may be reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n(6,144)\n\n703\n\n \n\n \n\n(5,441)\n\n(297)\n\n(5,738)\n\nTotal comprehensive income (loss) of the year\n\n \n\n \n\n \n\n(6,144)\n\n662\n\n \n\n2,608\n\n(2,874)\n\n(143)\n\n(3,017)\n\nDividend distribution of Eni SpA\n\n(26)\n\n \n\n(3,081)\n\n \n\n \n\n \n\n \n\n(3,081)\n\n \n\n(3,081)\n\nDividend distribution of other companies\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n(275)\n\n(275)\n\nAllocation of 2024 profit\n\n \n\n \n\n2,624\n\n \n\n \n\n \n\n(2,624)\n\n \n\n \n\n \n\nCapital contribution by non-controlling interests\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n709\n\n709\n\nPurchase of treasury shares\n\n(26)\n\n \n\n(1,881)\n\n \n\n1,881\n\n(1,881)\n\n \n\n(1,881)\n\n \n\n(1,881)\n\nCancellation of treasury shares\n\n(26)\n\n \n\n \n\n \n\n(1,908)\n\n1,908\n\n \n\n \n\n \n\n \n\nLong-term share-based incentive plan\n\n(26) (30)\n\n \n\n35\n\n \n\n(74)\n\n74\n\n \n\n35\n\n \n\n35\n\nIssuing of perpetual subordinated bonds\n\n(26)\n\n \n\n \n\n \n\n1,500\n\n \n\n \n\n1,500\n\n \n\n1,500\n\nRepurchase of perpetual subordinated bonds\n\n(26)\n\n \n\n \n\n \n\n(1,500)\n\n \n\n \n\n(1,500)\n\n \n\n(1,500)\n\nCoupon payment on perpetual subordinated bonds\n\n(26)\n\n \n\n(310)\n\n \n\n \n\n \n\n \n\n(310)\n\n \n\n(310)\n\nChange in non‐controlling interest\n\n(26)\n\n \n\n3,417\n\n(35)\n\n(5)\n\n \n\n \n\n3,377\n\n1,695\n\n5,072\n\nTransactions with holders of equity instruments\n\n \n\n \n\n804\n\n(35)\n\n(106)\n\n101\n\n(2,624)\n\n(1,860)\n\n2,129\n\n269\n\nOther changes\n\n \n\n \n\n(147)\n\n34\n\n2\n\n \n\n \n\n(111)\n\n(2)\n\n(113)\n\nOther changes in equity\n\n \n\n \n\n(147)\n\n34\n\n2\n\n \n\n \n\n(111)\n\n(2)\n\n(113)\n\nBalance at December 31, 2025\n\n(26)\n\n4,005\n\n33,209\n\n1,936\n\n8,964\n\n(2,782)\n\n2,608\n\n47,940\n\n4,847\n\n52,787\n\n \n\nSee the accompanying notes.\n\n \n\nF-7\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED STATEMENT OF CHANGES IN EQUITY\n\ncontinued\n\n(€ million)\n\n \n\n \n\n \n\nEquity attributable to equity holders of Eni\n\n \n\n \n\n \n\nNote\n\nShare capital\n\nRetained earnings\n\nCumulative\n\ncurrency translation\n\ndifferences\n\nOther reserves and equity instruments\n\nTreasury shares\n\nProfit for the year\n\nTotal\n\nNon-controlling interest\n\nTotal equity\n\nBalance at December 31, 2023\n\n \n\n4,005\n\n32,988\n\n5,238\n\n8,515\n\n(2,333)\n\n4,771\n\n53,184\n\n460\n\n53,644\n\nProfit for the year\n\n \n\n \n\n \n\n \n\n \n\n \n\n2,624\n\n2,624\n\n140\n\n2,764\n\nOther items of comprehensive income\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRemeasurements of defined benefit plans net of tax effect\n\n(26)\n\n \n\n \n\n \n\n4\n\n \n\n \n\n4\n\n \n\n4\n\nShare of “Other comprehensive income” on equity-accounted investments\n\n(26)\n\n \n\n \n\n \n\n1\n\n \n\n \n\n1\n\n \n\n1\n\nChange of minor investments measured at fair value with effects to OCI\n\n(26)\n\n \n\n \n\n \n\n62\n\n \n\n \n\n62\n\n \n\n62\n\nItems that are not reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n \n\n67\n\n \n\n \n\n67\n\n \n\n67\n\nCurrency translation differences\n\n(26)\n\n \n\n \n\n2,992\n\n(2)\n\n \n\n \n\n2,990\n\n76\n\n3,066\n\nChange in the fair value of cash flow hedge derivatives net of tax effect\n\n(26)\n\n \n\n \n\n \n\n(648)\n\n \n\n \n\n(648)\n\n(1)\n\n(649)\n\nShare of “Other comprehensive income” on equity-accounted investments\n\n(26)\n\n \n\n \n\n \n\n(71)\n\n \n\n \n\n(71)\n\n2\n\n(69)\n\nItems that may be reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n2,992\n\n(721)\n\n \n\n \n\n2,271\n\n77\n\n2,348\n\nTotal comprehensive income for the year\n\n \n\n \n\n \n\n2,992\n\n(654)\n\n \n\n2,624\n\n4,962\n\n217\n\n5,179\n\nDividend distribution of Eni SpA\n\n(26)\n\n \n\n(3,067)\n\n \n\n \n\n \n\n \n\n(3,067)\n\n \n\n(3,067)\n\nDividend distribution of other companies\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n(50)\n\n(50)\n\nAllocation of 2023 profit\n\n \n\n \n\n4,771\n\n \n\n \n\n \n\n(4,771)\n\n \n\n \n\n \n\nCapital contribution by non-controlling interests\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n1\n\n1\n\nPurchase of treasury shares\n\n(26)\n\n \n\n(2,003)\n\n \n\n2,003\n\n(2,003)\n\n \n\n(2,003)\n\n \n\n(2,003)\n\nCancellation of treasury shares\n\n(26)\n\n \n\n \n\n \n\n(1,375)\n\n1,375\n\n \n\n \n\n \n\n \n\nLong-term share-based incentive plan\n\n(26) (30)\n\n \n\n24\n\n \n\n(78)\n\n78\n\n \n\n24\n\n \n\n24\n\nIssuing of perpetual subordinated bonds\n\n(26)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n1,848\n\n1,848\n\nCoupon payment on perpetual subordinated bonds\n\n(26)\n\n \n\n(138)\n\n \n\n \n\n \n\n \n\n(138)\n\n \n\n(138)\n\nChange in non‐controlling interest\n\n(26)\n\n \n\n196\n\n \n\n \n\n \n\n \n\n196\n\n392\n\n588\n\nTransactions with holders of equity instruments\n\n \n\n \n\n(217)\n\n \n\n550\n\n(550)\n\n(4,771)\n\n(4,988)\n\n2,191\n\n(2,797)\n\nOther changes\n\n \n\n \n\n(219)\n\n(149)\n\n(5)\n\n \n\n \n\n(373)\n\n(5)\n\n(378)\n\nOther changes in equity\n\n \n\n \n\n(219)\n\n(149)\n\n(5)\n\n \n\n \n\n(373)\n\n(5)\n\n(378)\n\nBalance at December 31, 2024\n\n(26)\n\n4,005\n\n32,552\n\n8,081\n\n8,406\n\n(2,883)\n\n2,624\n\n52,785\n\n2,863\n\n55,648\n\n \n\nSee the accompanying notes.\n\n \n\nF-8\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED STATEMENT OF CHANGES IN EQUITY\n\ncontinued\n\n(€ million)\n\n \n\n \n\n \n\nEquity attributable to equity holders of Eni\n\n \n\n \n\n \n\n \n\nShare capital\n\nRetained earnings\n\nCumulative\n\ncurrency translation\n\ndifferences\n\nOther reserves and equity instruments\n\nTreasury shares\n\nProfit for the year\n\nTotal\n\nNon-controlling interest\n\nTotal equity\n\nBalance at December 31, 2022\n\n \n\n4,005\n\n23,455\n\n7,564\n\n8,785\n\n(2,937)\n\n13,887\n\n54,759\n\n471\n\n55,230\n\nProfit for the year\n\n \n\n \n\n \n\n \n\n \n\n \n\n4,771\n\n4,771\n\n89\n\n4,860\n\nOther items of comprehensive income\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRemeasurements of defined benefit plans net of tax effect\n\n \n\n \n\n \n\n \n\n(21)\n\n \n\n \n\n(21)\n\n \n\n(21)\n\nShare of “Other comprehensive income” on equity-accounted investments\n\n \n\n \n\n \n\n \n\n(2)\n\n \n\n \n\n(2)\n\n \n\n(2)\n\nChange of minor investments measured at fair value with effects to OCI\n\n \n\n \n\n \n\n \n\n45\n\n \n\n \n\n45\n\n \n\n45\n\nItems that are not reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n \n\n22\n\n \n\n \n\n22\n\n \n\n22\n\nCurrency translation differences\n\n \n\n \n\n \n\n(2,001)\n\n(9)\n\n \n\n \n\n(2,010)\n\n \n\n(2,010)\n\nChange in the fair value of cash flow hedge derivatives net of tax effect\n\n \n\n \n\n \n\n \n\n383\n\n \n\n \n\n383\n\n \n\n383\n\nShare of “Other comprehensive income (loss)” on equity-accounted investments\n\n \n\n \n\n \n\n \n\n54\n\n \n\n \n\n54\n\n \n\n54\n\nItems that may be reclassified to profit or loss in later periods\n\n \n\n \n\n \n\n(2,001)\n\n428\n\n \n\n \n\n(1,573)\n\n \n\n(1,573)\n\nTotal comprehensive income for the year\n\n \n\n \n\n \n\n(2,001)\n\n450\n\n \n\n4,771\n\n3,220\n\n89\n\n3,309\n\nDividend distribution of Eni SpA\n\n \n\n \n\n(3,005)\n\n \n\n \n\n \n\n \n\n(3,005)\n\n \n\n(3,005)\n\nDividend distribution of other companies\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n(36)\n\n(36)\n\nAllocation of 2022 profit\n\n \n\n \n\n13,887\n\n \n\n \n\n \n\n(13,887)\n\n \n\n \n\n \n\nReimbursement to non-controlling interests\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n(16)\n\n(16)\n\nPurchase of treasury shares\n\n \n\n \n\n(1,837)\n\n \n\n1,837\n\n(1,837)\n\n \n\n(1,837)\n\n \n\n(1,837)\n\nCancellation of treasury shares\n\n \n\n \n\n \n\n \n\n(2,400)\n\n2,400\n\n \n\n \n\n \n\n \n\nLong-term share-based incentive plan\n\n \n\n \n\n20\n\n \n\n(41)\n\n41\n\n \n\n20\n\n \n\n20\n\nCoupon payment on perpetual subordinated bonds\n\n \n\n \n\n(138)\n\n \n\n \n\n \n\n \n\n(138)\n\n \n\n(138)\n\nChange in non‐controlling interest\n\n \n\n \n\n47\n\n \n\n \n\n \n\n \n\n47\n\n(47)\n\n \n\nTransactions with holders of equity instruments\n\n \n\n \n\n8,974\n\n \n\n(604)\n\n604\n\n(13,887)\n\n(4,913)\n\n(99)\n\n(5,012)\n\nIssuing effect of convertible bonds\n\n \n\n \n\n \n\n \n\n79\n\n \n\n \n\n79\n\n \n\n79\n\nOther changes\n\n \n\n \n\n559\n\n(325)\n\n(195)\n\n \n\n \n\n39\n\n(1)\n\n38\n\nOther changes in equity\n\n \n\n \n\n559\n\n(325)\n\n(116)\n\n \n\n \n\n118\n\n(1)\n\n117\n\nBalance at December 31, 2023\n\n \n\n4,005\n\n32,988\n\n5,238\n\n8,515\n\n(2,333)\n\n4,771\n\n53,184\n\n460\n\n53,644\n\n \n\nSee the accompanying notes.\n\n \n\nF-9\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCONSOLIDATED STATEMENT OF CASH FLOWS\n\n(€ million)\n\n \n\n \n\nNote\n\n2025\n\n2024\n\n2023\n\nProfit\n\n \n\n2,758\n\n2,764\n\n4,860\n\nAdjustments to reconcile profit (loss) to net cash provided by operating activities:\n\n \n\n \n\n \n\n \n\nDepreciation and amortization\n\n(12) (13) (14)\n\n7,349\n\n7,600\n\n7,479\n\nNet impairments (reversals) of tangible, intangible and right-of-use assets\n\n(15)\n\n1,582\n\n2,900\n\n1,802\n\nWrite-off of tangible and intangible assets\n\n(12) (13) (14)\n\n33\n\n580\n\n535\n\nShare of (profit) loss of equity-accounted investments\n\n(16) (32)\n\n(1,161)\n\n(866)\n\n(1,336)\n\nNet gain on disposal of assets\n\n \n\n(99)\n\n(601)\n\n(441)\n\nDividend income\n\n(32)\n\n(242)\n\n(227)\n\n(255)\n\nInterest income\n\n \n\n(444)\n\n(497)\n\n(517)\n\nInterest expense\n\n \n\n1,256\n\n1,245\n\n1,000\n\nIncome taxes\n\n(33)\n\n3,020\n\n3,725\n\n5,368\n\nOther changes\n\n \n\n(515)\n\n(158)\n\n(700)\n\nCash flow from changes in working capital\n\n \n\n2,735\n\n1,286\n\n1,811\n\n- inventories\n\n \n\n916\n\n68\n\n1,792\n\n- trade receivables\n\n \n\n3,214\n\n1,145\n\n3,322\n\n- trade payables\n\n \n\n(835)\n\n110\n\n(4,823)\n\n- provisions\n\n \n\n(554)\n\n(87)\n\n97\n\n- other assets and liabilities\n\n \n\n(6)\n\n50\n\n1,423\n\nChange in the provisions for employee benefits\n\n \n\n(79)\n\n(105)\n\n1\n\nDividends received\n\n \n\n1,785\n\n1,946\n\n2,255\n\nInterest received\n\n \n\n358\n\n456\n\n459\n\nInterest paid\n\n \n\n(1,269)\n\n(1,130)\n\n(919)\n\nIncome taxes paid, net of tax receivables received\n\n \n\n(3,737)\n\n(5,826)\n\n(6,283)\n\nNet cash provided by operating activities\n\n \n\n13,330\n\n13,092\n\n15,119\n\n- of which with related parties\n\n(36)\n\n(11,375)\n\n(11,508)\n\n(7,011)\n\nCash flow from investing activities\n\n \n\n(9,999)\n\n(11,782)\n\n(12,404)\n\n- tangible assets\n\n(12)\n\n(8,702)\n\n(7,999)\n\n(8,739)\n\n- prepaid right-of-use assets\n\n(13)\n\n \n\n(5)\n\n \n\n- intangible assets\n\n(14)\n\n(527)\n\n(486)\n\n(476)\n\n- consolidated subsidiaries and businesses net of cash and cash equivalents acquired\n\n(5) (27)\n\n(196)\n\n(1,795)\n\n(1,277)\n\n- investments\n\n(16)\n\n(682)\n\n(798)\n\n(1,315)\n\n- securities and financing receivables held for operating purposes\n\n \n\n(89)\n\n(185)\n\n(388)\n\n- change in payables in relation to investing activities\n\n \n\n197\n\n(514)\n\n(209)\n\nCash flow from disposals\n\n \n\n2,040\n\n2,496\n\n845\n\n- tangible assets\n\n \n\n1,414\n\n1,354\n\n122\n\n- intangible assets\n\n \n\n4\n\n21\n\n32\n\n- consolidated subsidiaries and businesses net of cash and cash equivalents disposed of\n\n(5) (27)\n\n118\n\n887\n\n395\n\n- investments\n\n \n\n135\n\n526\n\n47\n\n- securities and financing receivables held for operating purposes\n\n \n\n98\n\n69\n\n32\n\n- change in receivables in relation to disposals\n\n \n\n271\n\n(361)\n\n217\n\nNet change in securities and financing receivables held for non-operating purposes\n\n \n\n(1,339)\n\n(531)\n\n2,194\n\nNet cash used in investing activities\n\n \n\n(9,298)\n\n(9,817)\n\n(9,365)\n\n- of which with related parties\n\n(36)\n\n(3,181)\n\n(3,140)\n\n(1,695)\n\n \n\nF-10\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n \n\nNote\n\n2025\n\n2024\n\n2023\n\nIncrease in long-term financial debt\n\n(19)\n\n1,884\n\n3,516\n\n4,971\n\nRepayments of long-term financial debt\n\n(19)\n\n(4,163)\n\n(4,748)\n\n(3,161)\n\nPayments of lease liabilities\n\n(13)\n\n(1,250)\n\n(1,205)\n\n(963)\n\nIncrease (decrease) in short-term financial debt\n\n(19)\n\n(276)\n\n(61)\n\n(1,495)\n\nDividends paid to Eni's shareholders\n\n \n\n(3,080)\n\n(3,068)\n\n(3,046)\n\nDividends paid to non-controlling interest\n\n \n\n(277)\n\n(45)\n\n(36)\n\nCapital contribution (reimbursement) by non-controlling interests\n\n \n\n709\n\n589\n\n(16)\n\nSale (purchase) of additional interests in consolidated subsidiaries\n\n \n\n5,072\n\n \n\n(60)\n\nOther contributions\n\n \n\n9\n\n14\n\n \n\nPurchase of treasury shares\n\n(26)\n\n(1,896)\n\n(2,012)\n\n(1,803)\n\nEffect of issuance of convertible bonds\n\n(26)\n\n \n\n \n\n79\n\nNet issuance (repayment) of perpetual subordinated bonds\n\n(26)\n\n(18)\n\n1,778\n\n \n\nCoupon payment on perpetual subordinated bonds\n\n(26)\n\n(310)\n\n(138)\n\n(138)\n\nNet cash used in financing activities\n\n \n\n(3,596)\n\n(5,380)\n\n(5,668)\n\n- of which with related parties\n\n(36)\n\n(407)\n\n(20)\n\n(162)\n\nEffect of exchange rate changes and other changes on cash and cash equivalents\n\n \n\n(198)\n\n83\n\n(62)\n\nNet increase (decrease) in cash and cash equivalents\n\n \n\n238\n\n(2,022)\n\n24\n\nCash and cash equivalents - beginning of the year\n\n(6)\n\n8,183\n\n10,205\n\n10,181\n\nCash and cash equivalents - end of the year (a)\n\n(6)\n\n8,421\n\n8,183\n\n10,205\n\n \n\n(a) As of December 31, 2025, cash and cash equivalents included €321 million of cash and cash equivalents of consolidated subsidiaries held for sale that are reported in the item \"Assets held for sale\" (€12 million at December 31, 2023).\n\n \n\nSee the accompanying notes.\n\n \n\nF-11\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nNotes on Consolidated Financial Statements\n\n1 Significant accounting policies, estimates and judgments\n\nBasis of preparation\n\nThe 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).\n\nThe 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. The principles of consolidation and the significant accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated.\n\nThe 2025 Consolidated Financial Statements included in the Annual Report on Form 20-F, were approved by the Eni’s Board of Directors on March 18, 2026.\n\nThe Consolidated Financial Statements are presented in euros and all values are rounded to the nearest million euros (€ million), except where otherwise indicated.\n\n \n\nSignificant accounting estimates and judgements\n\nThe 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.\n\n \n\nSignificant accounting estimates and judgments made in assessing the impacts of climate-related risks\n\nSignificant accounting estimates and judgments made by management for the preparation of the 2025 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.\n\nThe Eni s decarbonization plan 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 energy products. 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.\n\n \n\nSuch 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).\n\n \n\nPrinciples of consolidation\n\n \n\nSubsidiaries\n\nThe 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.\n\n \n\n \n\n1 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).\n\n \n\nF-12\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nSubsidiaries 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.\n\nTaking into account the lack of any material2 impact on the representation of the financial position and performance of the Group3, 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.\n\nWhen 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.\n\nThe 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 account4. 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.\n\n \n\nInterests in joint arrangements\n\nJoint 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.\n\nA 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”.\n\nA 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.\n\nAfter the initial recognition, the assets/liabilities and revenues/expenses of the joint operations are measured in accordance with the applicable measurement criteria.\n\nImmaterial 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.\n\n \n\nInvestments in associates\n\nAn 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”.\n\n \n\n \n\n2 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.\n\n3 Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”.\n\n4 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.\n\n \n\nF-13\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe equity method of accounting5\n\nUnder the equity method, investments are initially recognized at cost, allocating it 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; any excess amount is recognized in the profit and loss account. 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.\n\nWhenever 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 considering 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.\n\nThe 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 value6; 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 account7. 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.\n\n \n\nBusiness combinations\n\nBusiness 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.\n\nThe acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values8, 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.\n\nAny 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.\n\nIf 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.\n\n \n\n \n\n5 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.\n\n6 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.\n\n7 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.\n\n8 Fair value measurement principles are described in the accounting policy for “Fair value measurements”.\n\n \n\nF-14\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nSignificant accounting estimates and judgments: investments and business combinations\n\nThe 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.\n\n \n\nIntragroup transactions\n\nAll balances and transactions between consolidated companies, and not yet realized with third parties, including unrealized profits arising from such transactions have been eliminated9.\n\nUnrealized 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.\n\n \n\nForeign currency translation \n\nThe 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.\n\nThe 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.\n\nExchange differences arising from intragroup credit/debit, the repayment or payment of which is neither planned nor probable in the foreseeable future, are recognized in the statement of comprehensive income (loss).\n\nThe 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.\n\nExchange gains and losses arising on intra-group foreign currency borrowings, for which settlement is neither planned nor likely to occur in the foreseeable future, are reported in other comprehensive income.\n\n \n\nThe main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below:\n\n(currency amount for 1 €)\n\nAnnual average exchange rate 2025\n\nExchange rate at December 31, 2025\n\nAnnual average exchange rate 2024\n\nExchange rate at December 31, 2024\n\nAnnual average exchange rate 2023\n\nExchange rate at December 31, 2023\n\nU.S. Dollar\n\n1.13\n\n1.18\n\n1.08\n\n1.04\n\n1.08\n\n1.11\n\nPound Sterling\n\n0.86\n\n0.87\n\n0.85\n\n0.83\n\n0.87\n\n0.87\n\nAustralian Dollar\n\n1.75\n\n1.76\n\n1.64\n\n1.68\n\n1.63\n\n1.63\n\n \n\nMaterial accounting policies\n\nThe material accounting policies used in the preparation of the Consolidated Financial Statements are described below.\n\n \n\nOil and natural gas exploration, appraisal, development and production activities\n\nOil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting as described below.\n\n \n\n \n\n \n\n9 Exchange differences associated with intragroup monetary assets and liabilities are not eliminated.\n\n10 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”.\n\n \n\nF-15\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nAcquisition of exploration rights and mineral interest\n\nCosts 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.\n\nCosts 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.\n\nExpenditure 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.\n\nFrom 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”).\n\nExploration and appraisal expenditure\n\nGeological and geophysical exploration costs are recognized as an expense as incurred.\n\nCosts 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 only 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. 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”).\n\nDevelopment and production costs\n\nDevelopment costs, including the costs related to unsuccessful and damaged development wells, are capitalized as “Tangible asset in progress — proved”. These costs 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”.\n\nProduction costs are those costs incurred to operate and maintain wells and field equipment and are recognized as an expense as incurred.\n\nUOP depreciation, depletion and amortization11\n\nDepreciation of investments relating to mineral activities is generally calculated using the UOP method12, determined on the basis of the different types of hydrocarbon reserves in order to ensure adequate representation of the methods used to obtain the economic benefits associated with the use of the assets being depreciated. In particular: i) exploration rights and mineral titles acquired related to ‘proved’ reserves are amortised considering total proved reserves; ii) capitalised exploration, appraisal and development costs related to production facilities are amortised considering proved developed reserves; iii) facilities, based on their size, are depreciated considering total proved reserves and also probable developed reserves that are reasonably recoverable from existing production facilities and mineral rights; iv) for owned floating facilities (FLNG, FPSO), depreciation is calculated using the UOP method, or straight-line method, considering the duration of the concessions and the recovery of proved and probable reserves. In the event of significant changes in market prices that result in estimates of reserves and related depreciation rates that are not aligned with the methods used to obtain the expected future economic benefits from these assets, the reserves used to determine the UOP depreciation rate are estimated on the basis of reasonable economic parameters consistent with the production forecasts defined by management, in order to better reflect the expected methods of obtaining future economic benefits from these assets.\n\n \n\n \n\n \n\n11 In relation to the consolidation of the upstream investment model based on proximity exploration and development and phased development, which extends the useful life of facilities, and in relation to the increasing use of vessels with economic lives linked to the exploitation of probable reserves, starting from the second half of 2025, the methods for determining the UOP depreciation rates of upstream facilities have been updated to also consider, where appropriate, probable reserves whose recovery does not require significant additional investments. The update, as a change in estimate, has only prospective effects.\n\n12 Rate obtained from 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 itself.\n\n \n\nF-16\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nProduction Sharing Agreements and service contracts\n\nOil 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.\n\nThe 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.\n\nPlugging and abandonment of wells\n\nCosts 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.\n\nSignificant accounting estimates and judgments: oil and natural gas activities\n\nEngineering 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.\n\nLower 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.\n\nMany 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.\n\nThe 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.\n\nField 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.\n\nEstimated 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.\n\n \n\nProperty, plant and equipment\n\nProperty, 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.\n\n \n\nF-17\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nFor 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.\n\nIn 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.\n\nProperty, plant and equipment are not revalued for financial reporting purposes.\n\nProperty, 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.\n\nWhen 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.\n\nExpenditures 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.\n\nReplacement 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.\n\nThe 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.\n\n \n\nLeases13\n\nA 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.\n\nAt the date on which the underlying asset is available for use (i.e. commencement date of the lease), a lessee recognizes an asset for its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability for its obligation to make lease payments during the lease term (hereinafter also referred as lease liability).14 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.\n\nIn particular, the lease liability is initially recognized at the present value of the following lease payments15 that are not paid at the commencement date: (i) fixed payments, less any lease incentives receivable; (ii) variable lease payments that on an index or a rate16; (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).\n\nAfter 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 the exercise of the contractual options.\n\n \n\n \n\n \n\n13 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.\n\n14 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.\n\n15 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.\n\n16 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.\n\n \n\nF-18\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe 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; (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 also for any accumulated depreciation17, any accumulated impairment losses (see the accounting policy for “Impairment of non-financial assets”).\n\nThe 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.\n\nIn 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.\n\nThe 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.\n\nDifferently, 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.\n\nIf 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.\n\nWhen 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.\n\nSignificant accounting estimates and judgments: lease transactions\n\nWith 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.\n\n \n\nIntangible assets\n\nIntangible 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.\n\nIntangible 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.\n\nIntangible 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”.\n\nGoodwill 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”.\n\nCosts 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.\n\nCosts 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.\n\nThe 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.\n\n \n\n \n\n17 Depreciation charges are recognized on a systematic basis from the commencement date to the end of the useful life of the right-of-use. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee at the lease term, or if the lessee is reasonably certain that he 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.\n\n \n\nF-19\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nImpairment of non-financial assets\n\nNon-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.\n\nThe 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.\n\nCGUs 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. 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. 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.\n\nThe 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.\n\nThe 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.\n\nFor impairment test purposes, cash outflows expected to be incurred to guarantee compliance with laws and regulations regarding CO2 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.\n\nIn particular, in estimating value in use, the cash outflows for forestry projects 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.\n\nFor 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 segment and businesses different from E&P and REVT (Refining Evolution and Transformation), the related riskiness is determined on the basis of a sample of comparable companies. For the E&P operating segment and REVT 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.\n\nWhen 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.\n\nWhen 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.\n\n \n\nF-20\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nGrants related to assets\n\nGovernment 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.\n\n \n\nInventories\n\nInventories, 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.\n\nThe 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.\n\nWhen 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.\n\n \n\nSignificant accounting estimates and judgments: impairment of non-financial assets\n\nThe 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. Judgement by management is required also in 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. 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.\n\nSimilar 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.\n\nThe 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, this 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.\n\nFor 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.\n\nThe 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.\n\nMore details on the main assumptions underlying the determination of the recoverable amount of non-financial assets are set out in note 15 – Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.\n\n \n\nF-21\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nFinancial instruments\n\nFinancial assets\n\nFinancial 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).\n\nAt 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.\n\nAfter 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 (see the accounting policy for “Impairment of financial assets”) are recognized in the profit and loss account.\n\nFinancial 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”.\n\nWhen 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.\n\n \n\nCash and cash equivalents\n\nCash 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.\n\nImpairment of financial assets\n\nThe expected credit loss model is adopted for the impairment of financial assets that are debt instruments but are not measured at FVTPL.18\n\nIn 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.).\n\nWith 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.\n\nFor 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.\n\n \n\n \n\n18 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.\n\n \n\nF-22\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nConsidering the characteristics of the reference markets, financial assets with more than 180 days past due or, in any case, with counterparties undergoing litigation, restructuring or renegotiation, are considered to be in default. Counterparties are considered undergoing litigation when judicial/legal proceedings aimed to recover a receivable have been activated or are going to be activated. Impairment losses of trade and other receivables are recognized in the profit and loss account, net of any impairment reversal, within the line item of the profit and loss account “Net (impairments) reversals of trade and other receivables”.\n\nThe 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.\n\nSignificant accounting estimates and judgments: impairment of financial assets\n\nMeasuring 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.\n\nFurther details on the main assumptions underlying the measurement of expected credit losses of financial assets are provided in note 8 – Trade and other receivables.\n\nInvestments in equity instruments\n\nInvestments 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.\n\nFinancial liabilities\n\nAt 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.\n\nThe 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.\n\nGenerally, changes in the interest rate result in an update of the effective interest rate to be used for the recognition of interest expense.\n\nThe 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.\n\nSignificant judgments: financial liabilities\n\nThe 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.\n\nWith 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.\n\n \n\nDerivative financial instruments and hedge accounting\n\nDerivative financial instruments are assets and liabilities recognized and measured at their fair value.\n\n \n\nF-23\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nWith 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.\n\nWhen 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.\n\nWhen 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.\n\nIf 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”).\n\nThe 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”.\n\nDerivatives 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.\n\nEni 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.\n\nContracts 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).\n\n \n\nOffsetting of financial assets and liabilities\n\nFinancial assets and liabilities are set off 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).\n\n \n\nDerecognition of financial assets and liabilities\n\nTransferred 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.\n\n \n\nProvisions and contingent liabilities\n\nProvisions 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.\n\nThe amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation. 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.\n\n \n\nF-24\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nA 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.\n\nProvisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates.\n\nContingent 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.\n\nDecommissioning and restoration liabilities\n\nLiabilities for decommissioning and restoration costs are recognized, together with a corresponding amount as part of the related property, plant and equipment.\n\nSuch 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.\n\nThe 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.\n\nEnvironmental liabilities\n\nEnvironmental liabilities are recognized when the Group has an obligation, 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. 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.\n\nSignificant accounting estimates and judgments: decommissioning and restoration liabilities, environmental liabilities and other provisions\n\nThe 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.\n\nDecommissioning 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.\n\nAny 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.\n\n \n\nF-25\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nMoreover, 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. 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.\n\nThe 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.\n\nManagement, 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.\n\nMoreover, 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.\n\nIn 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.\n\n \n\nEmployee benefits\n\nEmployee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment.\n\nPost-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; as a consequence, the related cost is recognized in profit and loss in the competence period.\n\nThe 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.\n\nNet 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)”.\n\nRemeasurements 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.\n\nObligations for long-term benefits are determined by adopting actuarial assumptions. The effects of remeasurements are taken to profit and loss account in their entirety.\n\nThe 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.\n\n \n\nF-26\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nShare-based payments\n\nThe 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).\n\nWith 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.\n\nA 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.\n\nSignificant accounting estimates and judgments: employee benefits and share-based payments\n\nDefined 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.\n\nThe 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.\n\nFurther details on the share-based incentives plans for managers are provided in note 30 – Costs.\n\n \n\nEquity instruments\n\nTreasury shares\n\nTreasury 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.\n\nHybrid bonds\n\nThe 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 interest19. 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 or in non-controlling interests when these instruments are issued by subsidiaries (see point “Subsidiaries”); 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.\n\n \n\nRevenue from contracts with customers\n\nRevenue 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:\n\n         crude oil, upon shipment;\n\n         natural gas, LNG and electricity, upon delivery to the customer;\n\n         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\n\n         chemical products and other products, upon shipment.\n\n \n\n \n\n19 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.\n\n \n\nF-27\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nRevenue 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.\n\nRevenue is measured at 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.\n\nIf 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.\n\nIf, 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.\n\nWhen 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.\n\n \n\nSignificant accounting estimates and judgments: revenue from contracts with customers\n\nRevenue 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.\n\n \n\nCosts associated with emission quotas\n\nCosts associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) and determined on the basis of market prices, spot or forward, 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.\n\n \n\nExchange differences\n\nRevenues 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.\n\n \n\nDividends\n\nDividends are recognized when the right to receive payment of the dividend is established.\n\nDividends 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.\n\n \n\nF-28\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nIncome taxes\n\nCurrent 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.\n\nDeferred 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.\n\nRelating 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.\n\nIf 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.\n\nDeferred tax assets and liabilities 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”.\n\nWhen 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.\n\nSignificant accounting estimates and judgments: income taxes\n\nThe 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.\n\nMoreover, 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.\n\n \n\nAssets held for sale\n\nNon-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.\n\nImmediately 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.\n\n \n\nF-29\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nAny 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.\n\nIf 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.\n\n \n\nFair value measurements\n\nFair 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 at the measurement date (exit price).\n\nAssets 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:\n\na)       Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;\n\nb)       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;\n\nc)       Level 3: unobservable inputs for the asset or liability.\n\nSignificant accounting estimates and judgments: fair value\n\nFair 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.\n\n \n\n2 Primary financial statements\n\nThe primary financial statements are the same of the ones used in the previous reporting period.\n\n \n\nF-30\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n3 Changes in accounting policies\n\nThe amendments to IFRSs, effective from January 1, 2025, did not have a material impact on the Consolidated Financial Statements.\n\n \n\n4 IFRSs not yet effective\n\nOn April 9, 2024, the IASB issued IFRS 18 “Presentation and Disclosure in Financial Statements,” which replaces IAS 1. In order to increase comparability and transparency of information, IFRS 18: (i) requires the profit and loss account to be divided into five sections (operating, investing, financing, income taxes and discontinued operation) and the mandatory presentation of operating profit or loss and profit or loss before financing and income tax; ; (ii) with reference to statement of cash flows: (a) generally requires the presentation of interests and dividends paid as cash flows from financing activities; (b) provides, in general terms, for the presentation of interests and dividends received as cash flows from investing activities; (c) identifies the operating profit or loss as the starting point when presenting cash flows from operating activities under the indirect method; (iii) requires the disclosure of the management performance measures and their reconciliation with the most directly comparable subtotals required by IFRS; and (iv) strengthens the guidance on the aggregation and disaggregation of information presented in the primary financial statements and in the notes. IFRS 18 shall be applied for annual reporting periods beginning on or after January 1, 2027. During 2025, analyses were initiated to identify the areas affected by the new provisions and the related impacts.\n\nOn 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.\n\nOn 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.\n\nOn 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.\n\nOn November 13, 2025, the IASB issued amendments to IAS 21 “Translation to a Hyperinflationary Presentation Currency”, aimed at clarifying how financial statements should be translated from a non-hyperinflationary currency to a hyperinflationary one. The amendments are effective for annual reporting periods beginning on or after January 1, 2027.\n\nEni is currently reviewing the IFRSs not yet effective in order to determine the likely impact on the Consolidated Financial Statements.\n\n \n\nF-31\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n5 Business combinations and other significant transactions\n\n \n\nAcquisitions\n\n \n\nPlenitude\n\n \n\nOn December 22, 2025, Plenitude finalized the acquisition from Neoen, of a portfolio of 52 operating renewable generation plants and one operating battery, for a total of approximately 760 MW of installed capacity located throughout France. The total cash consideration of the transaction amounted to €234 million with acquisition of: (i) current and non-current assets for €1,040 million; (ii) net borrowings for €724 million, of which cash and cash equivalents for €38 million; (iv) current and non-current liabilities for €82 million. In the case of subsidiaries acquired exclusively for the purpose of sale/contribution, the Group, in applying the so-called short-cut method, does not fully consolidate the individual assets and liabilities, but instead separately presents assets and liabilities subject to future sale/contribution in the balance sheet.\n\n \n\nInformation about the definitive purchase price allocation of business combinations made in 2024 is provided in note 27 ‐ Other Information.\n\n \n\nDivestments\n\n \n\nCorporate and other activities\n\nOn December 18, 2025, Eni finalized the sale of a 49.99% stake in Eni CCUS Holding Ltd to the private equity fund Global Infrastructure Partners (GIP). Eni CCUS Holding Ltd acts as the holding company for the operating companies of the CCUS business, controlling 100% of Liverpool Bay CCS Ltd, Eni Netherlands CCUS BV, Bacton CCS Ltd, and Eni Tellus CCS Ltd. The transaction resulted in the exclusion from the scope of consolidation of net assets and liabilities for €222 million, of which other current financial assets for €45 million and cash and cash equivalents of €40 million, the realization of a capital gain for €46 million and the fair value of the retained stake of €27 million. Based on the agreements between the partners, joint control of the entity post-transfer was established.\n\nF-32\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nBalance sheet values of the divestments carried out in 2025 are shown in the following table:\n\n \n\n(€ million)\n\nEni CCUS Holding Ltd\n\nOther divestments\n\nTotal\n\nCash and cash equivalents\n\n40\n\n \n\n40\n\nOther current financial assets\n\n45\n\n \n\n45\n\nOther current assets\n\n84\n\n1\n\n85\n\nCurrent assets\n\n169\n\n1\n\n170\n\nProperty, plant and equipment\n\n222\n\n2\n\n224\n\nDeferred tax assets\n\n5\n\n \n\n5\n\nOther non-current assets\n\n428\n\n \n\n428\n\nNon-current assets\n\n655\n\n2\n\n657\n\nTOTAL ASSETS\n\n824\n\n3\n\n827\n\nCurrent financial liabilities\n\n \n\n \n\n \n\nOther current liabilities\n\n190\n\n1\n\n191\n\nCurrent liabilities\n\n190\n\n1\n\n191\n\nNon-current financial liabilities\n\n407\n\n \n\n407\n\nOther non-current liabilities\n\n5\n\n \n\n5\n\nNon-current liabilities\n\n412\n\n \n\n412\n\nTOTAL LIABILITIES\n\n602\n\n1\n\n603\n\nEquity attributable to Eni\n\n222\n\n2\n\n224\n\nTOTAL EQUITY\n\n222\n\n2\n\n224\n\nTOTAL LIABILITIES AND EQUITY\n\n824\n\n3\n\n827\n\n \n\n6 Cash and cash equivalents\n\nCash and cash equivalents of €8,100 million (€8,183 million at December 31, 2024) included financial assets with maturity of up to three months at the date of inception amounting to €5,304 million (€4,816 million at December 31, 2024) and mainly included deposits with financial institutions, having notice of more than 48 hours, valued at amortized cost and with a non-significant expected credit loss.\n\nCash and cash equivalents mainly consisted of deposits in U.S. dollars for €4,713 million and in euro for €2,607 million (€5,269 million and €2,402 million at December 31, 2024, respectively) representing the use of cash on hand in the market for the financial needs of the Group.\n\nRestricted cash amounted to €1 million (€54 million at December 31, 2024) in relation to foreclosure measures by third parties and obligations relating to the payment of debts.\n\nThe average maturity of financial assets originally due within 3 months was 10 days with an effective interest rate of 3.92% for bank deposits in U.S. dollars (€2,934 million) and 7 days with an effective interest rate of 2.21% for bank deposits in euros (€1,923 million).\n\n \n\n7 Financial assets at fair value through profit or loss\n\n \n\n(€ million)\n\nDecember 31,\n\n2025\n\nDecember 31,\n\n2024\n\nFinancial assets held for trading\n\n \n\n \n\nBonds issued by sovereign states\n\n734\n\n965\n\nOther securities\n\n6,168\n\n5,474\n\n \n\n6,902\n\n6,439\n\nOther financial assets at fair value through profit or loss\n\n \n\n \n\nOther securities\n\n89\n\n358\n\n \n\n89\n\n358\n\n \n\n6,991\n\n6,797\n\n \n\nThe 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.\n\n \n\nF-33\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nFinancial assets held for trading include securities subject to lending agreements of €579 million (€738 million at December 31, 2024).\n\n \n\nThe breakdown by currency is provided below:\n\n \n\n(€ million)\n\nDecember 31,\n\n2025\n\nDecember 31,\n\n2024\n\nFinancial assets held for trading\n\n \n\n \n\nEuro\n\n4,458\n\n4,230\n\nU.S. dollars\n\n2,444\n\n2,209\n\n \n\n6,902\n\n6,439\n\nOther financial assets at fair value through profit or loss\n\n \n\n \n\nEuro\n\n \n\n162\n\nU.S. dollars\n\n89\n\n196\n\n \n\n89\n\n358\n\n \n\n6,991\n\n6,797\n\n \n\nThe breakdown by issuing entity and credit rating is presented below:\n\n \n\n \n\nNominal value (€ million)\n\nFair Value\n\n(€ million)\n\nRating - Moody's\n\nRating - S&P\n\nQuoted bonds issued by sovereign states\n\n \n\n \n\n \n\n \n\nFixed rate bonds\n\n \n\n \n\n \n\n \n\nItaly\n\n56\n\n57\n\nBaa2\n\nBBB+\n\nUnited States of America\n\n483\n\n481\n\nAa1\n\nAA+\n\nFrance\n\n65\n\n65\n\nAa3\n\nA+\n\nOther (*)\n\n125\n\n124\n\nfrom Aaa to Baa2\n\nfrom AAA to BBB-\n\n \n\n729\n\n727\n\n \n\n \n\nFloating rate bonds\n\n \n\n \n\n \n\n \n\nItaly\n\n7\n\n7\n\nBaa2\n\nBBB+\n\n \n\n7\n\n7\n\n \n\n \n\nTotal quoted bonds issued by sovereign states\n\n736\n\n734\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOther Bonds\n\n \n\n \n\n \n\n \n\nFixed rate bonds\n\n \n\n \n\n \n\n \n\nQuoted bonds issued by industrial companies\n\n2,909\n\n2,940\n\nfrom Aaa to Ba2\n\nfrom AAA to BB\n\nQuoted bonds issued by financial and insurance companies\n\n1,086\n\n1,098\n\nfrom Aa1 to Baa3\n\nfrom AA+ to BBB-\n\nOther bonds\n\n355\n\n363\n\nfrom Aaa to Ba1\n\nfrom AAA to BB+\n\n \n\n4,350\n\n4,401\n\n \n\n \n\nFloating rate bonds\n\n \n\n \n\n \n\n \n\nQuoted bonds issued by industrial companies\n\n608\n\n612\n\nfrom Aa2 to Ba1\n\nfrom AA to BB+\n\nQuoted bonds issued by financial and insurance companies\n\n867\n\n873\n\nfrom Aa1 to Baa2\n\nfrom AA+ to BBB\n\nOther bonds\n\n280\n\n282\n\nfrom Aaa to Baa2\n\nfrom AAA to BBB\n\n \n\n1,755\n\n1,767\n\n \n\n \n\nTotal other bonds\n\n6,105\n\n6,168\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nTotal financial assets held for trading\n\n6,841\n\n6,902\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOther financial assets at fair value through profit or loss\n\n85\n\n89\n\nfrom Aaa to Baa1\n\nfrom AAA to BBB+\n\n \n\n \n\n \n\n \n\n \n\n \n\n6,926\n\n6,991\n\n \n\n \n\n(*) Amounts included herein are lower than €50 million.\n\nOther financial assets at fair value through profit or loss consisted of investments in Money Market funds.\n\nThe fair value hierarchy for financial assets held for trading is level 1 for €6,297 million and level 2 for €605 million. The fair value hierarchy for other financial assets measured at fair value with effects to profit or loss is level 2. During 2025, there were no significant transfers between the different hierarchy levels of fair value.\n\n \n\nF-34\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n8 Trade and other receivables\n\n \n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nTrade receivables\n\n8,986\n\n12,562\n\nReceivables from joint ventures in exploration and production activities\n\n1,238\n\n1,754\n\nReceivables from divestments\n\n209\n\n527\n\nOther receivables\n\n2,003\n\n2,058\n\nTotal trade and other receivables net of allowance for doubtful accounts\n\n12,436\n\n16,901\n\n \n\nGenerally, trade receivables do not bear interest and provide payment terms within 180 days.\n\nThe decrease in trade receivables of €3,576 million referred to the Global Gas & LNG Portfolio and Power segment for €1,621 million, to the Exploration & Production segment for €903 million and to the Plenitude business line for €821 million. The decrease in the Global Gas & LNG Portfolio and Power segment and the Plenitude business line reflected the decline in the prices of energy commodities, which decreased the nominal value of the receivables. The decrease in the Exploration & Production segment is due to crude oil trading activity, part of the reporting segment, due to price effects and to working capital optimization actions.\n\nAs part of its ordinary working capital management, Eni carries out non-recourse factoring transactions, mainly of trade receivables maturing in 2026. The transactions discounted in 2025 increased by €420 million compared to December 31, 2024.\n\nAt the balance sheet date, net trade receivables were outstanding for €498 million (€1,256 million at December 31, 2024) relating to supplies of equity hydrocarbons to Egyptian state-owned oil companies. During the year, a significant reduction in overdue receivables was recorded thanks to the completion of the regularization plan agreed with the Egyptian authorities in 2024 on the outstanding balance at that date. The accumulated impairment provisions corresponding to the amount recovered through the recovery plan were entirely reversed to the income statement.\n\nThe decrease in receivables from joint ventures in exploration and production activities of €516 million mainly related to cash calls from Eni’s partners in operated projects.\n\nReceivables from other counterparties comprised: (i) the recoverable amount of €881 million (€690 million at December 31, 2024) of overdue trade receivables owed by the state-owned oil company of Venezuela, PDVSA, in relation to equity volumes of natural gas supplied by the joint venture Cardón IV SA, equally participated by Eni and Repsol sold by the venture to its shareholders. The recoverable value (nominal value of $2,300 million, corresponding to €1,956 million, with exclusion of accrued interest income) is estimated by discounting the expected stream of repayments at the cost of capital of the E&P segment adjusted to include Venezuela’s specific country risk premium (WACC adjusted). The increase included the update of the estimate of recoverability of the receivables and reflects a context of substantial cessation of in-kind reimbursements during 2025 due to the revocation of authorizations by the US Authorities. The assessment performed in the 2025 financial statements factored in the recent developments occurred in the Country in early 2026 and the initiatives undertaken by the U.S. administration with the issuance of general licenses to certain international oil companies, including Eni. Those developments have improved the prospects of recovering the overdue trade receivables compared to the previous context characterized by a substantial embargo of the USA over Venezuelan crude oil and products; (ii) prepayments for services of €404 million (€362 million at December 31, 2024); (iii) €243 million of receivables outstanding at December 31, 2024 relating to amounts to be received from customers following the triggering of the take-or-pay clause of long-term natural gas supply contracts. These receivables were offset against the debt for the related supply.\n\nTrade and other receivables stated in euro for €6,880 million and U.S. dollars for €5,178 million (€9,173 million and €7,270 million at December 31, 2024, respectively).\n\n \n\nF-35\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCredit risk exposure and expected losses relating to trade and other receivables have been prepared on the basis of internal ratings as follows:\n\n \n\n \n\nPerforming receivables\n\nDefaulted receivables\n\nPlenitude customers\n\nTotal\n\n(€ million)\n\nLow risk\n\nMedium Risk\n\nHigh Risk\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\n \n\n \n\nBusiness customers\n\n1,846\n\n4,240\n\n250\n\n942\n\n \n\n7,278\n\nNational Oil Companies and Public Administrations\n\n226\n\n589\n\n258\n\n2,655\n\n \n\n3,728\n\nOther counterparties\n\n1,471\n\n246\n\n12\n\n349\n\n1,978\n\n4,056\n\nGross amount\n\n3,543\n\n5,075\n\n520\n\n3,946\n\n1,978\n\n15,062\n\nAllowance for doubtful accounts\n\n(8)\n\n(18)\n\n(12)\n\n(2,034)\n\n(554)\n\n(2,626)\n\nNet amount\n\n3,535\n\n5,057\n\n508\n\n1,912\n\n1,424\n\n12,436\n\nExpected loss (% net of counterpart risk mitigation factors)\n\n0.2\n\n0.4\n\n2.3\n\n51.5\n\n28.0\n\n17.4\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\n \n\n \n\nBusiness customers\n\n3,545\n\n5,138\n\n253\n\n700\n\n \n\n9,636\n\nNational Oil Companies and Public Administrations\n\n369\n\n733\n\n214\n\n3,503\n\n \n\n4,819\n\nOther counterparties\n\n1,505\n\n610\n\n1\n\n255\n\n2,860\n\n5,231\n\nGross amount\n\n5,419\n\n6,481\n\n468\n\n4,458\n\n2,860\n\n19,686\n\nAllowance for doubtful accounts\n\n(10)\n\n(27)\n\n(12)\n\n(2,162)\n\n(574)\n\n(2,785)\n\nNet amount\n\n5,409\n\n6,454\n\n456\n\n2,296\n\n2,286\n\n16,901\n\nExpected loss (% net of counterpart risk mitigation factors)\n\n0.2\n\n0.4\n\n2.6\n\n48.5\n\n20.1\n\n14.1\n\n \n\nDefaulted receivables related to National Oil Companies and Public Administrations included receivables owed by the Venezuelan state oil company PDVSA for gas supplies produced by the Cardón IV SA joint venture, stated at the recoverable amount.\n\nThe 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.\n\nRecoverability 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.\n\nThe exposure to credit risk and expected losses relating to customers of Plenitude were assessed based on a provision matrix as follows:\n\n \n\nNot-past due\n\nPast due\n\nTotal\n\n(€ million)\n\nfrom 0\n\nto 3 months\n\nfrom 3\n\nto 6 months\n\nfrom 6\n\nto 12 months\n\nover\n\n12 months\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\n \n\n \n\nPlenitude customers:\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Retail\n\n812\n\n91\n\n51\n\n127\n\n281\n\n1,362\n\n- Middle\n\n385\n\n15\n\n2\n\n8\n\n105\n\n515\n\n- Other\n\n96\n\n3\n\n1\n\n1\n\n \n\n101\n\nGross amount\n\n1,293\n\n109\n\n54\n\n136\n\n386\n\n1,978\n\nAllowance for doubtful accounts\n\n(46)\n\n(25)\n\n(40)\n\n(95)\n\n(348)\n\n(554)\n\nNet amount\n\n1,247\n\n84\n\n14\n\n41\n\n38\n\n1,424\n\nExpected loss (%)\n\n3.6\n\n22.9\n\n74.1\n\n69.9\n\n90.2\n\n28.0\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\n \n\n \n\nPlenitude customers:\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Retail\n\n1,573\n\n114\n\n60\n\n127\n\n219\n\n2,093\n\n- Middle\n\n470\n\n16\n\n4\n\n17\n\n132\n\n639\n\n- Other\n\n123\n\n2\n\n1\n\n1\n\n1\n\n128\n\nGross amount\n\n2,166\n\n132\n\n65\n\n145\n\n352\n\n2,860\n\nAllowance for doubtful accounts\n\n(74)\n\n(38)\n\n(45)\n\n(99)\n\n(318)\n\n(574)\n\nNet amount\n\n2,092\n\n94\n\n20\n\n46\n\n34\n\n2,286\n\nExpected loss (%)\n\n3.4\n\n28.8\n\n69.2\n\n68.3\n\n90.3\n\n20.1\n\n \n\nF-36\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe following table analyses the allowance for doubtful accounts for trade and other receivables:\n\n(€ million)\n\n2025\n\n2024\n\nAllowance for doubtful accounts - beginning of the year\n\n2,785\n\n2,338\n\nAdditions for trade and other performing receivables\n\n150\n\n136\n\nAdditions for trade and other defaulted receivables\n\n117\n\n243\n\nUtilizations for trade and other performing receivables\n\n(21)\n\n(85)\n\nUtilizations for trade and other defaulted receivables\n\n(416)\n\n(324)\n\nOther changes\n\n11\n\n477\n\nAllowance for doubtful accounts - end of the year\n\n2,626\n\n2,785\n\n \n\nThe allowance for doubtful accounts was determined considering mitigation factors of the counterparty risk amounting to €2,775 million (€3,292 million at December 31, 2024), which included escrow accounts, insurance policies, sureties and bank guarantees.\n\nAdditions to allowance for doubtful accounts for trade and other performing receivables related to the Plenitude business line for €112 million (€92 million in 2024), mainly in the retail business.\n\nAdditions to allowance for doubtful accounts for trade and other defaulted receivables related to: (i) the Exploration & Production segment for €75 million (€150 million in 2024) and mainly concerned receivables for the supply of hydrocarbons to state company and receivables towards joint operators for cash calls in oil projects operated by Eni; (ii) the Refining business line for €17 million; (iii) the Plenitude business line for €9 million (€64 million in 2024).\n\nUtilizations of allowance for doubtful accounts for trade and other performing and defaulted receivables amounted to €437 million and mainly related to: (i) the Exploration & Production segment for €265 million; (ii) the Plenitude business line for €138 million; (iii) to the Global Gas & LNG Portfolio business line for €8 million essentially as consequence of the reduction in credit exposures due to the changed market conditions.\n\nNet (impairments) reversals of trade and other receivables are disclosed as follows:\n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nNew provisions\n\n(267)\n\n(379)\n\n(502)\n\nNet credit losses\n\n(117)\n\n(57)\n\n(98)\n\nReversals\n\n373\n\n268\n\n351\n\nNet (impairments) reversals of trade and other receivables\n\n(11)\n\n(168)\n\n(249)\n\n \n\nReceivables with related parties are disclosed in note 36 – Transactions with related parties.\n\n \n\nF-37\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n9 Current and non-current inventories\n\n \n\nCurrent inventories are disclosed as follows:\n\n(€ million)\n\nDecember 31, 2025\n\nDecember 31, 2024\n\nRaw and auxiliary materials and consumables\n\n1,001\n\n1,436\n\nComponents and spare parts for drilling operations, plans and equipment\n\n1,288\n\n1,721\n\nSemi-finished, finished products and goods\n\n2,816\n\n3,092\n\nOther\n\n38\n\n10\n\nCurrent inventories\n\n5,143\n\n6,259\n\n \n\nRaw and auxiliary materials and consumables included oil-based feedstock and other consumables pertaining to refining and chemical activities.\n\n \n\nComponents to be consumed in drilling activities and maintenance of plants and infrastructure of the Exploration & Production segment amounted to €1,257 million (€1,685 million at December 31, 2024).\n\n \n\nSemi-finished, finished products and goods included stocks of natural gas and oil products for €2,141 million (€2,164 million at December 31, 2024) and chemical products for €617 million (€742 million at December 31, 2024).\n\n \n\nInventories are stated net of write-down provisions of €656 million (€567 million at December 31, 2024).\n\n \n\nNon-current inventories of €1,187 million (€1,595 million at December 31, 2024) are held for compliance purposes and related to Italian subsidiaries for €1,165 million (€1,575 million at December 31, 2024) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.\n\n \n\n10 Income tax receivables and payables\n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nReceivables\n\nPayables\n\nReceivables\n\nPayables\n\n \n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nIncome taxes\n\n539\n\n125\n\n343\n\n40\n\n695\n\n129\n\n587\n\n40\n\nIncome taxes are described in note 33 — Income taxes.\n\nNon-current income tax payables include a provision for 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 €28 million (€34 million at December 31, 2024).\n\n \n\n11 Other assets and liabilities\n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n \n\nAssets\n\nLiabilities\n\nAssets\n\nLiabilities\n\n(€ million)\n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nFair value of derivative financial instruments\n\n791\n\n81\n\n827\n\n146\n\n874\n\n88\n\n1,921\n\n153\n\nContract liabilities\n\n \n\n \n\n788\n\n520\n\n \n\n \n\n552\n\n655\n\nOther Taxes\n\n919\n\n24\n\n1,589\n\n47\n\n850\n\n147\n\n1,749\n\n48\n\nOther\n\n2,233\n\n2,734\n\n835\n\n2,677\n\n1,938\n\n3,776\n\n827\n\n3,593\n\n \n\n3,943\n\n2,839\n\n4,039\n\n3,390\n\n3,662\n\n4,011\n\n5,049\n\n4,449\n\n \n\nThe fair value related to derivative financial instruments is disclosed in note 24 – Derivative financial instruments and hedge accounting.\n\nAssets related to other taxes included VAT for €763 million, of which €746 million are current, and advances made in December (€847 million at December 31, 2024, of which current €711 million).\n\n \n\nF-38\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOther assets included: (i) tax credits current of €1,412 million (€1,210 million at December 31, 2024) and non-current of €1,570 million (€2,298 million at December 31, 2024) deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings; (ii) an asset of €550 million (€732 million at December 31,2024) recorded based on an agreement with an Italian operator to share past and expected environmental expenses incurred and fully provisioned by Eni at certain Italian industrial hub, under decommissioning, which were jointly operated in past years; (iii) underlifting positions of the Exploration & Production segment of €199 million (€318 million at December 31, 2024); (iv) non-current receivables from divestment activities for €169 million (€144 million at December 31, 2024); (v) gas volumes prepayments that were made in previous years due to take-or-pay obligations in relation to the Company's long-term supply contracts, whose underlying current portion Eni plans to recover within 12 months for €2 million and beyond 12 months for €85 million (€3 million and €295 respectively at December 31, 2024).\n\nContract 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 €496 million (€486 million at December 31, 2024); (ii) prepaid electronic fuel vouchers for €346 million (€331 million at December 31, 2024); (iii) advances received from customers for future gas supplies for €227 million (€65 million at December 31, 2024); (iv) advances received from Engie SA, relating to a long-term agreement for supplying natural gas and electricity for €44 million (€218 million at December 31, 2024), of which current for €12 million (€55 million at December 31, 2024).\n\nRevenues recognized during the year related to contract liabilities stated at December 31, 2025, are indicated in note 29 – Revenues and other income.\n\nLiabilities related to other current taxes include excise duties and consumer taxes for €811 million (€895 million at December 31, 2024) and VAT liabilities for €384 million (€405 million at December 31, 2024).\n\nOther liabilities included: (i) non-current payables to factoring companies connected with the derecognition of tax credits deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings for €1,422 million (€2,104 million at December 31, 2024); (ii) current overlifting imbalances of the Exploration & Production segment for €267 million (€396 million at December 31, 2024); (iii) a put option recognized by Eni to EIP fund, which acquired a non-controlling interest of Plenitude, by subscribing a reserved capital increase of €588 million in March 2024 and a €209 million reserved capital increase in March 2025. The put option valorizes Eni’s commitment to repurchase at fair value enough shares of Plenitude held by EIP as required to pay down the financial debt incurred by EIP for the transaction. The book value of the put option is stated at the present value of Eni's maximum financial commitment equal to €541 million (€392 million as of December 31, 2024). The expiry date is 2027; (iv) the value of gas paid and undrawn by customers due to the triggering of the take-or-pay clause provided for by the relevant long-term contracts for €57 million is expected to be drawn beyond the next 12 months (€303 million at December 31, 2024); (v) payables related to investing activities for €49 million (€96 million at December 31, 2024).\n\nTransactions with related parties are described in note 36 — Transactions with related parties.\n\n \n\nF-39\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n12 Property, plant and equipment\n\n(€ million)\n\nLand and buildings\n\nE&P wells, plant and machinery\n\nOther plant and machinery\n\nE&P exploration assets and appraisal\n\nE&P tangible assets in progress\n\nOther tangible assets in progress and advances\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nNet carrying amount - beginning of the year\n\n1,142\n\n38,229\n\n4,491\n\n1,742\n\n11,296\n\n2,964\n\n59,864\n\nAdditions\n\n24\n\n70\n\n532\n\n384\n\n6,080\n\n1,612\n\n8,702\n\nDepreciation capitalized\n\n \n\n \n\n \n\n8\n\n259\n\n \n\n267\n\nDepreciation (*)\n\n(60)\n\n(5,295)\n\n(614)\n\n \n\n \n\n \n\n(5,969)\n\nImpairments\n\n(10)\n\n(822)\n\n(225)\n\n \n\n(307)\n\n(374)\n\n(1,738)\n\nReversals\n\n \n\n30\n\n109\n\n \n\n24\n\n42\n\n205\n\nWrite-off\n\n \n\n \n\n(1)\n\n(13)\n\n \n\n(2)\n\n(16)\n\nCurrency translation differences\n\n(2)\n\n(4,092)\n\n(132)\n\n(178)\n\n(1,065)\n\n(24)\n\n(5,493)\n\nInitial recognition and changes in estimates\n\n(2)\n\n75\n\n11\n\n(8)\n\n174\n\n29\n\n279\n\nChanges in the scope of consolidation\n\n10\n\n \n\n5\n\n \n\n \n\n(224)\n\n(209)\n\nTransfers\n\n40\n\n7,382\n\n815\n\n(128)\n\n(7,254)\n\n(855)\n\n \n\nOther changes\n\n(5)\n\n(2,023)\n\n(317)\n\n(258)\n\n(3,261)\n\n508\n\n(5,356)\n\nNet carrying amount - end of the year\n\n1,137\n\n33,554\n\n4,674\n\n1,549\n\n5,946\n\n3,676\n\n50,536\n\nGross carrying amount - end of the year\n\n4,444\n\n115,147\n\n33,421\n\n1,549\n\n8,355\n\n6,276\n\n169,192\n\nProvisions for depreciation and impairments\n\n3,307\n\n81,593\n\n28,747\n\n \n\n2,409\n\n2,600\n\n118,656\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nNet carrying amount - beginning of the year\n\n1,111\n\n37,421\n\n4,588\n\n1,568\n\n9,682\n\n1,929\n\n56,299\n\nAdditions\n\n31\n\n20\n\n255\n\n419\n\n5,546\n\n1,728\n\n7,999\n\nDepreciation capitalized\n\n \n\n \n\n \n\n28\n\n260\n\n \n\n288\n\nDepreciation (*)\n\n(57)\n\n(5,668)\n\n(575)\n\n \n\n \n\n \n\n(6,300)\n\nImpairments\n\n(9)\n\n(1,705)\n\n(371)\n\n \n\n(669)\n\n(382)\n\n(3,136)\n\nReversals\n\n \n\n107\n\n92\n\n \n\n74\n\n30\n\n303\n\nWrite-off\n\n \n\n(1)\n\n(1)\n\n(414)\n\n(5)\n\n(1)\n\n(422)\n\nCurrency translation differences\n\n1\n\n2,071\n\n49\n\n91\n\n554\n\n8\n\n2,774\n\nInitial recognition and changes in estimates\n\n \n\n35\n\n6\n\n(4)\n\n62\n\n(2)\n\n97\n\nChanges in the scope of consolidation - included entities\n\n12\n\n1,314\n\n3\n\n97\n\n1,090\n\n70\n\n2,586\n\nChanges in the scope of consolidation - excluded entities\n\n(1)\n\n(822)\n\n(17)\n\n(25)\n\n(486)\n\n \n\n(1,351)\n\nTransfers\n\n47\n\n6,865\n\n566\n\n(6)\n\n(6,859)\n\n(613)\n\n \n\nOther changes\n\n7\n\n(1,408)\n\n(104)\n\n(12)\n\n2,047\n\n197\n\n727\n\nNet carrying amount - end of the year\n\n1,142\n\n38,229\n\n4,491\n\n1,742\n\n11,296\n\n2,964\n\n59,864\n\nGross carrying amount - end of the year\n\n4,412\n\n139,117\n\n33,226\n\n1,742\n\n14,589\n\n5,490\n\n198,576\n\nProvisions for depreciation and impairments\n\n3,270\n\n100,888\n\n28,735\n\n \n\n3,293\n\n2,526\n\n138,712\n\n(*) Before capitalization of depreciation of tangible assets\n\n \n\nCapital expenditures included capitalized finance expenses of €120 million (€220 million in 2024) related to the Exploration & Production segment for €76 million (€173 million in 2024) at an average interest rate of 3.2% (3.5% at December 31, 2024).\n\nCapital expenditures primarily related to the Exploration & Production segment for €6,666 million (€6,033 million in 2024).\n\nInvestments for the purchase of plant and equipment under supplier financing arrangements which resulted in the classification of the related debt as financial liabilities were recorded in the line item “Other changes” (€1,371 million).\n\nCapital expenditures by industry segment and geographical area of destination are reported in note 35 – Segment information and information by geographical area.\n\nDepreciation 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.\n\n \n\nF-40\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe main depreciation rates adopted are included in the following ranges and have remained substantially unchanged compared to 2024:\n\n(%)\n\n \n\nBuildings\n\n2 - 10\n\nRefining and chemical plants\n\n3 - 17\n\nGas pipelines and compression stations\n\n4 - 12\n\nPower plants\n\n3 - 5\n\nOther plant and machinery\n\n6 - 12\n\nIndustrial and commercial equipment\n\n5 - 25\n\nOther assets\n\n10 - 20\n\nPlant and equipment used for the extraction and treatment of hydrocarbons were depreciated according to the UOP method, using as a basis for calculation the proved reserves estimated according to the criteria of the U.S. SEC, as well as volumes of unproved reserves in the case of facilities used in phased development projects or common facilities (see note 1 – Accounting standards, accounting estimates and significant judgements, section UOP depreciation, depletion and amortization). The production plans associated with the existing assets gradually deplete the SEC proved reserves recorded at the balance sheet date, as well as the additional volumes of unproved reserves, which are expected to be produced within approximately thirteen years.\n\nNet impairment losses of property, plant and equipment mainly related: (i) to oil&gas properties in Congo (€332 million) and Ivory Coast (€179 million), which were aligned to the sale price as part of the E&P portfolio rationalization program as well as oil & gas properties in Italy, Turkmenistan, United Arab Emirates and USA in relation to reserve revisions and commodity price forecasts (total €564 million); (ii) expenditures incurred for compliance and stay-in-business at CGUs in the Refining and traditional Chemicals segment were completely written-off because those CGUs were impaired in previous reporting periods and continued lacking any profitability prospects, as well as polyethylene plants due to a structurally deteriorated profitability outlook (€413 million). In the three-year period 2023-2025, Eni booked impairment charges at all its oil-based petrochemicals complexes, driven by challenged market fundamentals, competitive disadvantages of the European industrial sector resulting from higher operating and energy costs compared to other geographies, and rising competitive pressures from operators benefiting of larger scale and lower feedstock costs amid global overcapacities. A transformation and industrial reconversion plan for Eni's chemical segment is underway, leveraging proprietary technologies and the development of profitable business lines such as biochemistry, recycled chemicals and compounding, while traditional sites that are no longer competitive are being shut down or reconverted to transition businesses.\n\n \n\nMore information about Eni’s impairment review and the sensitivity of the outcome to different commodities scenarios is reported in note 15 – Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.\n\nCurrency translation differences related to subsidiaries utilizing the U.S. dollar as functional currency (€5,445 million).\n\nInitial 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 and start of new projects, partially offset by the decrease in discount rates, particularly of the U.S. dollar.\n\nChanges in the scope of consolidation related to the divestment of €222 million in connection with the loss of control of Eni CCUS Holding Ltd. Further information on the transaction is provided in note 5 – Business combinations and other significant transactions.\n\nOther changes include: (i) the sale of oil and gas assets in Ivory Coast for €1,160 million; (ii) the reclassification of oil and gas assets in Indonesia and in the United Arab Emirates to assets held for sale for €5,850 million, which are planned to be contributed in exchange of shareholdings in newly established equity-accounted entities with other operators in 2026, as well as in Congo and Ivory Coast in connection with ongoing divestments procedures. The carrying amounts of these portions of undivided properties have been aligned with the expected fair value of the sale. Further information is provided in note 25 – Assets held for sale and directly associated liabilities.\n\nTransfers from E&P tangible assets in progress to E&P UOP wells, plant and equipment related for €6,280 million to the commissioning of wells, plants and equipment primarily in Congo, Ivory Coast, Egypt, Kazakhstan, Indonesia, Italy, Algeria and Mexico.\n\nExploration and appraisal activities included write-offs for €13 million of previously capitalized exploration wells pending economic and technical evaluation in Oman, Algeria and Nigeria.\n\nExploration and appraisal activities related for €1,441 million to the costs of suspended exploration wells pending final determination of commerciality based on management’s continuing commitment and for €108 million to costs of exploration wells in progress at the end of the year.\n\nChanges relating to suspended wells are reported below:\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nCosts for exploratory wells suspended - beginning of the year\n\n1,662\n\n1,391\n\n1,085\n\nIncreases for which is ongoing the determination of proved reserves\n\n347\n\n485\n\n834\n\nAmounts previously capitalized and expensed in the year\n\n(11)\n\n(362)\n\n(388)\n\nReclassification to successful exploratory wells following the estimation of proved reserves\n\n(128)\n\n(4)\n\n(72)\n\nDisposals\n\n(79)\n\n(7)\n\n(3)\n\nChanges in the scope of consolidation\n\n \n\n76\n\n \n\nCurrency translation differences\n\n(167)\n\n83\n\n(40)\n\nOther changes\n\n(183)\n\n \n\n(25)\n\nCosts for exploratory wells suspended - end of the year\n\n1,441\n\n1,662\n\n1,391\n\n \n\nF-41\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe following information relates to the stratification of the suspended wells pending final determination (ageing):\n\n \n\n2025\n\n2024\n\n2023\n\n \n\n(€ million)\n\n(number of wells in Eni’s interest)\n\n(€ million)\n\n(number of wells in Eni’s interest)\n\n(€ million)\n\n(number of wells in Eni’s interest)\n\nCosts capitalized and suspended for exploratory well activity\n\n \n\n \n\n \n\n \n\n \n\n \n\n- within 1 year\n\n218\n\n5.8\n\n253\n\n4.4\n\n417\n\n7.9\n\n- between 1 and 3 years\n\n419\n\n8.3\n\n604\n\n11.3\n\n347\n\n6.1\n\n- beyond 3 years\n\n804\n\n16.0\n\n805\n\n18.2\n\n627\n\n14.5\n\n \n\n1,441\n\n30.1\n\n1,662\n\n33.9\n\n1,391\n\n28.5\n\nCosts capitalized for suspended wells\n\n \n\n \n\n \n\n \n\n \n\n \n\n- fields including wells drilled over the last 12 months\n\n218\n\n5.8\n\n253\n\n4.4\n\n417\n\n7.9\n\n- fields for which the delineation campaign is in progress\n\n826\n\n13.3\n\n1,053\n\n16.1\n\n804\n\n14.0\n\n- fields including commercial discoveries that are progressing to a FID\n\n397\n\n11.0\n\n356\n\n13.4\n\n170\n\n6.6\n\n \n\n1,441\n\n30.1\n\n1,662\n\n33.9\n\n1,391\n\n28.5\n\n \n\nThe capitalized costs for suspended wells relating to fields including wells drilled over the last twelve months referred to ten leases for which the evaluation of results is still in progress.\n\nThe capitalized costs for suspended wells relating to fields for which the delineation campaign is in progress referred for approximately €520 million to nine leases for which appraising activities and negotiations are ongoing to unlock the subsequent project phases; the remaining amounts are related to five leases for which drilling activities are underway or firmly planned for the near future.\n\nSuspended wells costs pending a final investment decision primarily related to initiatives in Congo, Nigeria and United Arab Emirates.\n\nUnproved 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.\n\nUnproved mineral interests were as follows:\n\n \n\n(€ million)\n\nCongo\n\nNigeria\n\nUSA\n\nAlgeria\n\nEgypt\n\nUnited Arab Emirates\n\nItaly\n\nIndonesia\n\nNetherlands\n\nTunisia\n\nAustralia\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCarrying amount - beginning of the year\n\n16\n\n981\n\n77\n\n187\n\n3\n\n445\n\n2\n\n848\n\n120\n\n \n\n \n\n2,679\n\nAdditions\n\n \n\n27\n\n \n\n63\n\n \n\n \n\n \n\n115\n\n \n\n7\n\n3\n\n215\n\nNet (impairments) reversals\n\n(4)\n\n \n\n(36)\n\n \n\n \n\n(22)\n\n(2)\n\n \n\n(8)\n\n \n\n \n\n(72)\n\nReclassification to Proved Mineral Interest\n\n \n\n(20)\n\n \n\n(100)\n\n \n\n(54)\n\n \n\n(804)\n\n(88)\n\n \n\n \n\n(1,066)\n\nCurrency translation differences and other changes\n\n(3)\n\n(114)\n\n(8)\n\n(20)\n\n(1)\n\n(137)\n\n \n\n(124)\n\n \n\n \n\n19\n\n(388)\n\nCarrying amount - end of the year\n\n9\n\n874\n\n33\n\n130\n\n2\n\n232\n\n \n\n35\n\n24\n\n7\n\n22\n\n1,368\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCarrying amount - beginning of the year\n\n429\n\n924\n\n23\n\n215\n\n2\n\n475\n\n2\n\n89\n\n \n\n \n\n \n\n2,159\n\nAdditions\n\n \n\n \n\n \n\n \n\n15\n\n \n\n \n\n709\n\n120\n\n \n\n \n\n844\n\nNet (impairments) reversals\n\n(421)\n\n \n\n74\n\n \n\n(5)\n\n \n\n \n\n \n\n \n\n \n\n \n\n(352)\n\nReclassification to Proved Mineral Interest\n\n \n\n(2)\n\n(24)\n\n(40)\n\n(9)\n\n(58)\n\n \n\n \n\n \n\n \n\n \n\n(133)\n\nCurrency translation differences and other changes\n\n8\n\n59\n\n4\n\n12\n\n \n\n28\n\n \n\n50\n\n \n\n \n\n \n\n161\n\nCarrying amount - end of the year\n\n16\n\n981\n\n77\n\n187\n\n3\n\n445\n\n2\n\n848\n\n120\n\n \n\n \n\n2,679\n\n \n\nF-42\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nUnproved 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 book value of €1,141 million included €835 million as the purchase price paid in 2011 to the Nigerian Government to acquire a 50% interest in the asset and the subsequent capitalized exploration costs and pre-development costs. A lengthy and complex criminal proceeding before the Court of Milan was definitively resolved in favor of Eni, which related to alleged crimes of international corruption regarding the purchase of the license. An arbitration started by Eni before an ICSID tribunal (the International Centre for Settlement of Investment Disputes) to protect the value of the investment, claiming the Company’s right to obtain the conversion of the license into an Oil Mining Lease has been put on hold as the parties have been exploring a possible agreement to set economic terms and conditions to develop the property’s reserves. The agreement was signed in early March 2026, with the parties waiving all pending claims relating to the asset, including the arbitration proceedings. The estimated recoverable value of the asset, based on the agreed economic terms of development of the license reserves, has confirmed the resilience of the book value.\n\nThe reclassification of unproved mineral interests to proved mineral interests mainly referred to Indonesia following the final investment decision of some projects with the consequent recognition of proved reserves.\n\n \n\nAccumulated provisions for impairments amounted to €20,250 million (€22,205 million at December 31, 2024).\n\nProperty, plant and equipment include assets subject to operating leases for €270 million, essentially relating to service stations of the Enilive business line.\n\nAs of December 31, 2025, Eni pledged property, plant and equipment for €24 million to guarantee payments of excise duties (same amount as of December 31, 2024).\n\nGovernment grants recorded as a decrease of property, plant and equipment amounted to €99 million (€88 million at December 31, 2024).\n\nContractual commitments related to the purchase of property, plant and equipment are disclosed in note 28 – Guarantees, commitments and risks – Liquidity risk.\n\nProperty, plant and equipment under concession arrangements are described in note 28 – Guarantees, commitments and risks.\n\n \n\nF-43\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n13 Right-of-use assets and lease liabilities\n\n \n\n(€ million)\n\nFloating production storage and offloading vessels (FPSO)\n\nDrilling rig\n\nNaval facilities and related logistic bases for oil and gas transportation\n\nMotorway concessions and service stations\n\nOil and gas distribution facilities\n\nOffice buildings\n\nVehicles\n\nOther\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nNet carrying amount - beginning of the year\n\n2,606\n\n419\n\n1,005\n\n452\n\n36\n\n487\n\n21\n\n796\n\n5,822\n\nAdditions\n\n \n\n266\n\n566\n\n91\n\n10\n\n138\n\n20\n\n59\n\n1,150\n\nDepreciation (*)\n\n(176)\n\n(248)\n\n(496)\n\n(76)\n\n(20)\n\n(120)\n\n(10)\n\n(98)\n\n(1,244)\n\nImpairments\n\n \n\n \n\n \n\n(11)\n\n(1)\n\n \n\n \n\n(2)\n\n(14)\n\nCurrency translation differences\n\n(295)\n\n(32)\n\n(14)\n\n1\n\n \n\n(10)\n\n \n\n(36)\n\n(386)\n\nOther changes\n\n(1)\n\n(53)\n\n(44)\n\n(7)\n\n(2)\n\n(3)\n\n(5)\n\n(29)\n\n(144)\n\nNet carrying amount - end of the year\n\n2,134\n\n352\n\n1,017\n\n450\n\n23\n\n492\n\n26\n\n690\n\n5,184\n\nGross carrying amount - end of the year\n\n2,844\n\n1,309\n\n2,490\n\n954\n\n101\n\n1,142\n\n53\n\n999\n\n9,892\n\nProvisions for depreciation and impairment\n\n710\n\n957\n\n1,473\n\n504\n\n78\n\n650\n\n27\n\n309\n\n4,708\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nNet carrying amount - beginning of the year\n\n1,977\n\n449\n\n724\n\n492\n\n17\n\n580\n\n17\n\n578\n\n4,834\n\nAdditions\n\n630\n\n294\n\n690\n\n59\n\n53\n\n52\n\n19\n\n317\n\n2,114\n\nDepreciation (*)\n\n(146)\n\n(342)\n\n(391)\n\n(79)\n\n(22)\n\n(132)\n\n(14)\n\n(73)\n\n(1,199)\n\nImpairments\n\n \n\n \n\n(4)\n\n(21)\n\n(10)\n\n \n\n \n\n(5)\n\n(40)\n\nCurrency translation differences\n\n145\n\n19\n\n5\n\n(1)\n\n \n\n7\n\n \n\n18\n\n193\n\nChanges in the scope of consolidation\n\n \n\n38\n\n \n\n \n\n \n\n5\n\n1\n\n(2)\n\n42\n\nOther changes\n\n \n\n(39)\n\n(19)\n\n2\n\n(2)\n\n(25)\n\n(2)\n\n(37)\n\n(122)\n\nNet carrying amount - end of the year\n\n2,606\n\n419\n\n1,005\n\n452\n\n36\n\n487\n\n21\n\n796\n\n5,822\n\nGross carrying amount - end of the year\n\n3,217\n\n1,235\n\n2,095\n\n873\n\n97\n\n1,067\n\n57\n\n1,049\n\n9,690\n\nProvisions for depreciation and impairment\n\n611\n\n816\n\n1,090\n\n421\n\n61\n\n580\n\n36\n\n253\n\n3,868\n\n \n\n(*) Before capitalization of depreciation of tangible and intangible assets  \n\n \n\nRight-of-use assets (RoU) of €5,184 million mainly related: (i) for €3,634 million (€4,266 million at December 31, 2024) to the Exploration & Production segment and mainly comprised leases of certain FPSO vessels and platforms used in the development of the OCTP offshore projects in Ghana, Area 1 in Mexico and Baleine in Ivory Coast, for a duration between 11 and 15 years including the renewal option, as well as the multi-year rental of drilling rigs, in relation to the lease component only and the rental of naval vessels for shipping activities; (ii) for €538 million (€519 million at December 31, 2024) to the Enilive business line relating to highways concessions, leases of land and of service stations for sale of oil products, equipment rentals with EVS (Eni Virtual Station) cloud architecture for the integrated management of service stations and car fleet dedicated to the car sharing business; (iii) for €532 million (€476 million at December 31, 2024) to the Corporate and Other activities segment mainly regarding property rental contracts (real estate and IT).\n\n \n\nThe increase referred to: (i) the Exploration & Production segment for €860 million relating to vessels and related logistics equipment for oil & gas transport (€535 million) of which €115 million relating to Eni Trade & Biofuels SpA and the rental of drilling rigs for €266 million. Main contracts concerned assets in Congo, Italy and Mexico; (ii) the Enilive business line for new contracts and extension of existing contracts relating highways concessions, land leases, service station leases and car fleet dedicated to the car sharing business for €141 million; (iii) the Corporate and Other activities segment for €122 million, mainly referred to the extensions of Italian property leasing contracts for €94 million.\n\n \n\n Leasing contracts signed for which the asset is not yet available essentially concern a contract with a nominal value of €331 million relating to lease of Italian office buildings with an expiry date of 20 years.\n\n \n\nMain 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, 2025 of: (i) ancillary assets in the upstream business for €830 million; (ii) service stations for sale of oil products of €153 million; (iii) Italian office property leases of €166 million.\n\n \n\nF-44\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nLiabilities for leased assets were as follows:\n\n(€ million)\n\nCurrent portion of long-term lease liabilities\n\nLong-term lease liabilities\n\nTotal\n\n2025\n\n \n\n \n\n \n\nCarrying amount at the beginning of the year\n\n1,279\n\n5,174\n\n6,453\n\nAdditions\n\n \n\n1,150\n\n1,150\n\nDecreases\n\n(1,240)\n\n(10)\n\n(1,250)\n\nCurrency translation differences\n\n(73)\n\n(349)\n\n(422)\n\nOther changes\n\n1,297\n\n(1,528)\n\n(231)\n\nCarrying amount at the end of the year\n\n1,263\n\n4,437\n\n5,700\n\n2024\n\n \n\n \n\n \n\nCarrying amount at the beginning of the year\n\n1,128\n\n4,208\n\n5,336\n\nAdditions\n\n \n\n2,109\n\n2,109\n\nDecreases\n\n(1,194)\n\n(11)\n\n(1,205)\n\nCurrency translation differences\n\n36\n\n175\n\n211\n\nChanges in the scope of consolidation\n\n35\n\n15\n\n50\n\nOther changes\n\n1,274\n\n(1,322)\n\n(48)\n\nCarrying amount at the end of the year\n\n1,279\n\n5,174\n\n6,453\n\n \n\nLease liabilities related for €761 million (€616 million at December 31, 2024) to the portion of the liabilities attributable to joint operators in Eni-led projects which will be recovered through partner billing process.\n\n \n\nTotal cash outflows for leases consisted of the following: (i) cash payments for the main portion of the lease liability for €1,250 million; (ii) cash payments for the interest portion of €324 million.\n\nLease liabilities stated in U.S. dollars for €3,788 million and in euro for €1,703 million (€4,510 million and €1,723 million at December 31, 2024, respectively).\n\nOther changes in right-of-use assets and lease liabilities essentially related to early termination or renegotiation of lease contracts.\n\nLiabilities for leased assets with related parties are described in note 36 — Transactions with related parties.\n\nThe amounts recognised in the profit and loss account consisted of the following:\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nOther income and revenues\n\n \n\n \n\n \n\nIncome from remeasurement of lease liabilities\n\n22\n\n14\n\n17\n\n \n\n22\n\n14\n\n17\n\nPurchases, services and other\n\n \n\n \n\n \n\nExpense from remeasurement of lease liabilities\n\n2\n\n3\n\n3\n\nShort-term leases\n\n69\n\n81\n\n59\n\nLow-value leases\n\n39\n\n37\n\n37\n\nVariable lease payments not included in the measurement of lease liabilities\n\n24\n\n22\n\n20\n\nCapitalized direct cost associated with self-constructed assets - tangible assets\n\n(4)\n\n(5)\n\n(5)\n\n \n\n130\n\n138\n\n114\n\nDepreciation, net impairments and write-offs\n\n \n\n \n\n \n\nDepreciation of RoU leased assets\n\n1,244\n\n1,199\n\n973\n\nCapitalized direct cost associated with self-constructed assets - tangible and intangible assets\n\n(260)\n\n(277)\n\n(199)\n\nImpairments of RoU leased assets\n\n14\n\n40\n\n41\n\nReversals of RoU leased assets\n\n(2)\n\n(4)\n\n(5)\n\nWrite-off of RoU leased assets\n\n \n\n3\n\n \n\n \n\n996\n\n961\n\n810\n\nFinance income (expense) from leases\n\n \n\n \n\n \n\nInterests on lease liabilities\n\n(348)\n\n(314)\n\n(267)\n\nCapitalized finance expense of RoU leased assets - tangible assets\n\n7\n\n17\n\n11\n\nNet currency translation differences on lease liabilities\n\n62\n\n(36)\n\n19\n\n \n\n(279)\n\n(333)\n\n(237)\n\n \n\nF-45\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n14 Intangible assets\n\n \n\n(€ million)\n\nExploration rights\n\nIndustrial patents and intellectual property rights\n\nOther intangible assets with definite useful lives\n\nIntangible assets with definite useful lives\n\nGoodwill\n\nOther intangible assets with indefinite useful lives\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nNet carrying amount - beginning of the year\n\n534\n\n397\n\n2,310\n\n3,241\n\n3,167\n\n26\n\n6,434\n\nAdditions\n\n7\n\n14\n\n506\n\n527\n\n \n\n \n\n527\n\nDepreciation capitalized\n\n \n\n \n\n6\n\n6\n\n \n\n \n\n6\n\nDepreciation (*)\n\n(4)\n\n(98)\n\n(307)\n\n(409)\n\n \n\n \n\n(409)\n\nImpairments\n\n \n\n \n\n(45)\n\n(45)\n\n \n\n \n\n(45)\n\nReversals\n\n \n\n \n\n8\n\n8\n\n \n\n \n\n8\n\nWrite-off\n\n(17)\n\n \n\n \n\n(17)\n\n \n\n \n\n(17)\n\nChanges in the scope of consolidation\n\n \n\n \n\n(428)\n\n(428)\n\n2\n\n \n\n(426)\n\nCurrency translation differences\n\n(54)\n\n \n\n(21)\n\n(75)\n\n \n\n \n\n(75)\n\nOther changes\n\n(20)\n\n39\n\n5\n\n24\n\n(5)\n\n \n\n19\n\nNet carrying amount - end of the year\n\n446\n\n352\n\n2,034\n\n2,832\n\n3,164\n\n26\n\n6,022\n\nGross carrying amount - end of the year\n\n869\n\n2,215\n\n5,235\n\n8,319\n\n \n\n \n\n \n\nProvisions for amortization and impairment\n\n423\n\n1,863\n\n3,201\n\n5,487\n\n \n\n \n\n \n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nNet carrying amount - beginning of the year\n\n663\n\n450\n\n2,107\n\n3,220\n\n3,133\n\n26\n\n6,379\n\nAdditions\n\n14\n\n31\n\n441\n\n486\n\n \n\n \n\n486\n\nDepreciation capitalized\n\n \n\n \n\n4\n\n4\n\n \n\n \n\n4\n\nDepreciation (*)\n\n(6)\n\n(98)\n\n(289)\n\n(393)\n\n \n\n \n\n(393)\n\nImpairments\n\n(10)\n\n \n\n(12)\n\n(22)\n\n(9)\n\n \n\n(31)\n\nWrite-off\n\n(153)\n\n \n\n(2)\n\n(155)\n\n \n\n \n\n(155)\n\nChanges in the scope of consolidation\n\n \n\n \n\n73\n\n73\n\n36\n\n \n\n109\n\nCurrency translation differences\n\n31\n\n \n\n12\n\n43\n\n \n\n \n\n43\n\nOther changes\n\n(5)\n\n14\n\n(24)\n\n(15)\n\n7\n\n \n\n(8)\n\nNet carrying amount - end of the year\n\n534\n\n397\n\n2,310\n\n3,241\n\n3,167\n\n26\n\n6,434\n\nGross carrying amount - end of the year\n\n1,197\n\n2,166\n\n5,190\n\n8,553\n\n \n\n \n\n \n\nProvisions for amortization and impairment\n\n663\n\n1,769\n\n2,880\n\n5,312\n\n \n\n \n\n \n\n(*) Before capitalization of depreciation of intangible assets.\n\n \n\nExploration 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 primarily in Ivory Coast.\n\n \n\nThe breakdown of exploration rights by type of asset was as follows:\n\n \n\n(€ million)\n\nDecember 31,\n\n2025\n\nDecember 31,\n\n2024\n\nProved licence and leasehold property acquisition costs\n\n61\n\n79\n\nUnproved licence and leasehold property acquisition costs\n\n385\n\n455\n\n \n\n446\n\n534\n\nIndustrial patents and intellectual property rights mainly regarded the acquisition and internal development of software and rights for the use of production processes and software.\n\nWrite-offs of €17 million related to the abandonment of underlying initiatives.\n\nChanges in the scope of consolidation of assets with a finite useful life comprised the divestments of Eni CCUS Holding Ltd. Further information on the transaction is provided in note 5 – Business combinations and other significant transactions.\n\n \n\nF-46\n\n[Table of Contents](#TOC_TableofContent)\n\nOther intangible assets comprised: (i) concessions, licenses, trademarks and similar items for €1,096 million (€1,154 million at December 31, 2024), of which €891 million relating to relating to the Plenitude business line essentially for activities in relation to renewable energy sources (€898 million at December 31, 2024); (ii) customer acquisition costs relating to the Plenitude business line for €469 million (€412 million at December 31, 2024); (iii) customer relationship for €75 million recognized following the acquisition of Finproject group from the Chemicals business line (€84 million at December 31, 2024).\n\nThe main amortization rates used were substantially unchanged from the previous year and ranged as follows:\n\n(%)\n\n \n\nExploration rights  \n\nUOP\n\nConcessions, licenses, trademarks and similar items  \n\n3 - 33\n\nIndustrial patents and intellectual property rights\n\n20 - 33\n\nCapitalized costs for customer acquisition\n\n17 - 33\n\nOther intangible assets\n\n3 - 20\n\n \n\nCumulative impairment charges of goodwill at the end of the year amounted to €2,642 million.\n\nThe breakdown of goodwill by segment and business line is provided below:\n\n(€ million)\n\nDecember 31,\n\n2025\n\nDecember 31,\n\n2024\n\nPlenitude\n\n2,916\n\n2,916\n\nEnilive\n\n116\n\n121\n\nChemical\n\n119\n\n117\n\nOthers\n\n13\n\n13\n\n \n\n3,164\n\n3,167\n\nChanges in the scope of consolidation of goodwill related to the consolidation of ​​ Tecnofilm SpA, incorporated during the year by Finproject SpA.\n\nOther changes relating to goodwill concern the definitive allocation of some acquisitions made in 2024, the allocation of which had been made on a provisional basis (see note 27 – Other information).\n\nContributions recorded as decrease in intangible assets amounted to €8 million (€37 million at December 31, 2024).\n\nGoodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition.\n\nThe 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.\n\nGoodwill allocated to the activity of the retail sale of natural gas and electricity amounted to €1,220 million and to test its recoverability has been allocated to a single CGU encompassing all European retail markets where Plenitude is operating considering the significant cross-market synergies and geographic integration. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU comprising the book value of the allocated goodwill.\n\n \n\nF-47\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe 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 2026-2030 industrial 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 zero, unchanged from the previous year. These cash flows were discounted by using the post-tax WACCs of the retail business in each country of operation, with post-tax values in a range of 4.3% - 4.8%, corresponding to 5.5% - 6.6% pre-tax. There are currently no reasonable assumptions of changes in the discount rate, growth rate, profitability or volumes that would lead to zeroing the headroom amounting to about €8 billion of the value in use of the CGU Retail with respect to its book value, including the allocated goodwill.\n\nThe renewable business of Plenitude included a goodwill of €978 million related to the business combinations made in Italy and in other European markets where operations are being developed (Spain, France, Greece). The recoverability of goodwill was tested by grouping the assets by homogeneous CGUs, corresponding to geographical areas, taking into account technical, economic, and contractual aspects. The recoverability of goodwill was assessed with reference to the entire CGU. The impairment test to verify the recoverability of the carrying amounts, including the allocated goodwill, was performed based on the calculation of the value in use using the discounted cash flow method, which includes, for the first four years of the projection, the business plan approved by management. For the following years the projection coincides with the economic-technical life of the plants using normalized cash flows. Cash flows were determined on the basis of wholesale electricity price forecasts estimated by management, differentiated by geographical area; for Italy an average price of approximately €106/kWh in the five-year plan 2026-2030 and of about €111/kWh for long-term prices. Cash flows have been discounted at sector and country-specific post-tax WACCs, which were comprised in a range of 5.5% - 8.9%, corresponding to 7% - 11.1% pre-tax. This test has confirmed the recoverability of the book values of the complex of plants generating renewable electricity, including the allocated goodwill. The headroom of €695 million is reduced to zero in case of a 1.4 percentage point increase in the WACC, or a reduction in power prices of approximately 14%.\n\nGoodwill of the electric mobility business of Plenitude of €718 million was recognized in connection with the acquisition in 2021 of the entire share capital of Be Charge (now Plenitude On The Road), which engages in building and managing a network of charging infrastructures for electric mobility. This goodwill was tested for recoverability based on the calculation of the value in use through explicit cash flow projections for ten-years and a terminal value incorporating a normalized cash flow projection of the last year, using a nominal growth rate risked with respect to the projections on the development of the electric vehicle market provided by primary info-providers. The cash flow was discounted at a post-tax WACC of 9.2%, corresponding to 12.8% pre-tax. This test confirmed the recoverability of the allocated book values ​​including the allocated goodwill and showed a headroom of about €1 billion which would go to zero by assuming a 3.7% increase in the post-tax WACC and would remain positive even by assuming a zero-growth rate.\n\n \n\nF-48\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n15 Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios\n\nClimate change and energy transition\n\nThe recoverability test of the carrying amounts of oil&gas cash generating units (CGUs) is the most important of the critical accounting estimates utilized in the preparation of Eni’s consolidated financial statements. This is due to the relative weight of the invested capital in the E&P operating segment on total consolidated assets and because of the highly judgmental nature of assumptions utilized by the management in the impairment review process.\n\nEstimation of future expected cash flows associated with the use of oil&gas assets is based on management’s assessment 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 to allocating funds to develop reserves 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 short to the long-term, which incorporate assumptions about the evolution of several scenario variables, including macroeconomic growth, changes in consumers’ preferences, modifications 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. Short-term price forecasts will also incorporate risks and uncertainties of the current macroeconomic outlook and geopolitical factors (like the ongoing crisis in the Middle East and other macroeconomic risks such as the impact of international trade disputes on growth and other factors).\n\nClimate change and the energy transition risk were taken into full consideration as part of the recoverability test of the carrying amounts of oil&gas CGUs, including the evaluation of exploration assets and unproved mineral interests. They may have significant impacts on the value of Eni’s oil&gas properties and on similar properties that may be recognized in the future. Considering the exposure of its oil&gas assets to the transition risk, the Company has adopted strict return criteria when making a final investment decision to mitigate the risks of having stranded assets in the future and of recognizing possible impairment charges in the profit and loss account once a new capital project is capitalized among property, plant and equipment. Each material capital budgeting investment project, including in the exploration and acquisition of oil and gas resources, is subject to an evaluation that takes into consideration the objectives of the Paris Agreement, in view of each new project contributing to enhance the resilience of the Company’s portfolio in terms of reduction of the average carbon intensity and improvement of profitability metrics.\n\nEconomic returns and expected cash flows are estimated based on the management’s assumptions about future commodity prices which are set in the industrial plan approved by the Board, as well as management’s forecast of operating and development costs, future production volumes and timing and costs of decommissioning. Furthermore, future cash flows of oil&gas assets discount the expected expenditures to reduce emissions or to have projects already carbon neutral for scope 1&2 emissions from the onset, in line with the Company’s goal of achieving net zero CO2 emissions for scope 1&2 of the whole oil&gas assets portfolio by 2030. The 2026 forecast marginally discounts current geopolitical risks.\n\nAs result of this evaluation process and the Company’s focus on value creation and cash generation over volume, Eni’s capital allocation prioritizes new oil&gas projects featuring: (i) low breakeven prices, translating into an average Brent breakeven price of around $35 per barrel for the portfolio of new oil&gas projects; (ii) internal rate of returns “IRR” exceeding an internally defined threshold comprising the cost of the capital to the Group “WACC” of 6% post-tax plus a country risk premium and a further step-up to cover exploration projects and generate an extra-return; (iii) ability to reduce the average carbon intensity of the portfolio (scope 1&2); (iv) resilience to the transition risk, which is measured in terms of change to projects’ IRR when applying an internally estimated cost per emitted ton of CO2 (internal threshold in $/tCO2).\n\nThe recent asset rationalization comprising the disposal of certain long-life oilfields characterized by high expected future expenditures and above-average carbon intensity, including Alaska, Nigeria and Congo onshore fields, has further strengthened the risk profile and resilience of the oil&gas portfolio, reducing exposure to assets at risk of becoming stranded in the long-term.\n\nThe impairment test of Eni’s oil&gas assets is prepared in coherence with the main technical and economic assumptions of the industrial plan approved by the Board of Directors, including commodity price assumptions.\n\nThe principles applied in determining the recoverable amounts of oil&gas CGU are as follows:\n\n- the future cash flows were determined using the assumptions included in the industrial plan 2026-2030 and in the long-term plan of the Company approved by the Board of Directors. These assumptions, including operational costs, development expenditures, estimation of oil and gas reserves, future volumes produced and marketed, and timing and costs of decommissioning oil&gas plants and facilities represent the best estimate from the Company Management of economic and technical conditions over the remaining life of the assets;\n\nThe oil and gas price projections adopted by the Company are based on the following assumptions:\n\n- oil demand experienced sustained growth post-Covid crisis, driven by a global economic recovery, and has continued growing throughout 2025. By 2030, oil consumption is expected to continue to grow, supported by population growth and rising living standards, particularly in emerging countries. Growth after 2030 is expected to be more moderate due to the gradual diffusion of low-carbon technologies. Therefore, in this context of moderate demand growth driven by emerging countries and assuming continued capital discipline on part of the majority of international oil companies, the approaching to maximum sustainable capacity by member countries of the OPEC+ alliance and a levelling off of shale oil production in the United States, our scenario anticipates a gradual recovery in crude oil prices, which are expected to reach $68/bbl in 2026 and then reach $75/bbl by 2030 (all prices in 2025 real terms);\n\nF-49\n\n[Table of Contents](#TOC_TableofContent)\n\n- beyond 2030, we project a linear decline of approximately 1.7% per year, to $65 in 2040 and $53 in 2050 (all prices in real terms 2025), which discounts the risks of energy transition and of a possible slowdown in the growth rate or a contraction in global oil demand post-2030.\n\nThe average Brent price over the period 2026-2050 thus stands at $65/bbl in real terms 2025.\n\n \n\n \n\n \n\n2026\n\n2027\n\n2028-2030\n\n2050\n\nBrent $/bbl\n\n68\n\n66\n\n75\n\n53\n\n \n\nFor natural gas, the transition fuel, the price projections adopted by the Company assume a less tense global gas market in the coming years. Rising demand, also driven by growing electricity needs particularly in new consumption segments (e.g., data centers, AI), is expected to be accompanied by increased LNG production capacity, with new projects to be completed in the next few years, especially in the United States and Qatar. In this context, the gas prices used to determine the value in use of the CGUs whose revenues are indexed to gas spot prices are as follows (in real terms 2025):\n\n \n\n \n\n \n\n \n\n \n\n2026\n\n2027-2029\n\n2030-2050\n\nTTF Europe $/Mbtu\n\n \n\n11.8\n\n8.5\n\n7.5\n\nGas prices for LNG projects and in the Group main geographies are mainly indexed to the price of crude oil.\n\nThe future operational costs were determined by considering the existing technologies, the fluctuation of prices for petroleum services in line with market developments and the internal cost reduction programs effectively implemented.\n\nThe determination of value in use also considers on all identified CGU the expected expenditures to improve energy efficiency and reduce the carbon footprint (CO2 emissions scope 1&2). Furthermore, any residual emissions after the efficiency actions are expected to be offset by carbon credit compensation, the expenses of which are considered in the evaluation of the headroom of the overall Eni’s E&P segment. CGUs in geographies that are part of emission trading schemes include in their respective cash flow future expenses for emission allowances.\n\nThe future cash flows are estimated over a period consistent with the life of the CGUs. They are elaborated post-tax and take into account specific risks related to the CGUs’ assets. They are discounted by applying a 6% post-tax discount rate (unchanged from 2024), this rate being the weighted-average cost of the capital to the Group estimated from market data and future projections of the mix of funds employed to finance the invested capital. This rate is adjusted to factor a risk premium specific to each country where the group operates (WACC Adjusted). The value in use calculated by discounting the above post-tax cash flows is not materially different from the value in use calculated by discounting pre-tax cash flows using a pre-tax discount rate determined by an iterative computation from the post-tax value in use. These pre-tax discount rates generally range from 9% to 15% in the case of assets impaired in 2025.\n\nIn applying the methodology described, €564 million of impairment losses were recognized in the 2025 financial statements at assets mainly in Turkmenistan, the United Arab Emirates and USA and gas assets in Italy due to reserve estimate revisions and price effects.\n\nAsset impairments are subject to sensitivity testing. In particular, upstream assets are stress-tested by assuming the following changes in estimation parameters:\n\n- a decrease of 10% in hydrocarbon prices, over the duration of the cash flows projections;\n\n- an increase of 100 basis point in the discount rate of future cash flows;\n\n- consideration of the price curves and CO2 costs of the IEA’s Net Zero Scenario 2050 for all assets.\n\n \n\nValue in use of the O&G CGUs\n\nHeadroom vs Carrying amounts\n\n \n\nPossible impairment losses through profit and loss account\n\n \n\n \n\nTax-deductible CO2 charges\n\n \n\n€ billion\n\n \n\nEni's scenario\n\n63%\n\n \n\n \n\n \n\n10% haircut of Eni's prices assumptions\n\n45%\n\n \n\n(1)\n\n \n\nEni's scenario with +1% increase in WAAC\n\n53%\n\n \n\n(0.2)\n\n \n\nIEA NZE 2050 scenario\n\n18%\n\n \n\n(3.4)\n\n \n\n \n\nF-50\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe sensitivities scope includes the activities of Eni subsidiaries and joint ventures driven by Eni; the assets of the independent equity-owned entities Vår Energi ASA, Ithaca Energy Plc, and Azule Energy Holdings Ltd are excluded, as are assets held for sale (Indonesia, Congo, a stake in Ivory Coast, and certain assets in the UAE).\n\nThe sensitivities do not consider potential value recovery actions, such as rescheduling and/or cancellation of planned development activities, contract renegotiations, cost effects, or actions to accelerate the payback period. The sensitivity analysis was not applied to the business line of gas-fired power generation plants, due to the insignificant carrying amounts of tangible assets (€887 million) and their residual economic-technical lives, and to the Biorefining business line (€2,711 million) that is not exposed to transition risk. No impact can be associated with refineries and petrochemical plants, given that their carrying amounts have been completely impaired.\n\nThe characteristics of Eni’ s portfolio, the fast-track and phased development approach in producing reserves and absence of exposure to unconventional projects mitigate the risk of having stranded assets in the future if a structural decline in demand for hydrocarbons occurs due to stricter global environmental regulations and constraints and a resulting change in consumer preferences. The Company will continue to review price assumptions as the energy transition progresses and this may result in additional impairment charges in the future.\n\nGiven the characteristics of the Company's oil and gas assets, their stated amounts in the balance sheet will be almost entirely amortized by 2035. Accordingly, Eni does not anticipate significant changes in the useful lives of its existing oil and gas assets that could represent a significant valuation factor with an impact on its consolidated financial statements in the future.\n\nOther assets exposed to transition risk, including refineries and petrochemical plants, were completely written down in previous years and are largely undergoing industrial conversion and reconfiguration processes, requiring new investments that will be capitalized when incurred in future reporting periods. Any decommissioning provisions are recognized for permanently closed refining plants and petrochemical complexes, whose conversion is deemed uneconomical. In 2025, the only Versalis CGU with a book value related to the polyethylene plants (€151 million) and was completely impaired.\n\nOther risks\n\nThe energy transition may bring forward asset retirement obligations of certain oil and gas assets, thereby increasing the present value of the associated provisions.\n\nAsset retirement obligations, which result from a legal or constructive obligation, are recognized based on a reasonable estimate in the period in which the obligation arises. The associated asset retirement costs are capitalized as part of the carrying amount of the underlying asset and depreciated over the useful life of this asset.\n\nAn entity is required to measure changes in the liability for an asset retirement obligation due to the passage of time (accretion) by applying a discount rate to the amount of liability. Given the long-term nature of expenditures related to our asset retirement obligations, the rate is determined by reference to the rates of treasury bonds having comparable duration as that of the liability. The increase of the provision due to the passage of time is recognized as “Other financial expense”.\n\nThe discount rate used for the valuation of asset retirement obligation ranged 2-5.2% in 2025, slightly lower in 2024 for the U.S. dollar, higher for the euro (expenses are estimated at current currency values with an inflation rate between 2% and 2.4%).\n\nThe provision is sensitive to the number of discounting years. Given that the assumptions adopted represented management’s best estimates of the timing of decommissioning and asset retirement, assuming that the cost incurrence is brought forward by five years compared to the statutory assumption to account for transition risk, this would result in an increase in the provision’s book value of approximately €1.2 billion.\n\nIn upstream activities, in application of its internal procedures, Eni regularly reviews, on an asset-by-asset basis, the estimate of its future asset retirement costs, as well as the date at which work will be performed.\n\nThe Company will continue to review its estimates of both costs and the maturity of commitments on a regular basis and will take into account any significant impact that may result from changes in these parameters in the future.\n\nA maturity schedule of these obligations is presented in Note 28 - Guarantees, commitments and risks.\n\n \n\nF-51\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n16 Investments\n\nEquity-accounted investments\n\n \n\n2025\n\n2024\n\n(€ million)\n\nInvestments in unconsolidated entities controlled by Eni\n\nJoint ventures\n\nAssociates\n\nTotal\n\nInvestments in unconsolidated entities controlled by Eni\n\nJoint ventures\n\nAssociates\n\nTotal\n\nCarrying amount - beginning of the year\n\n82\n\n9,449\n\n4,619\n\n14,150\n\n53\n\n8,250\n\n4,327\n\n12,630\n\nAdditions and subscriptions\n\n21\n\n399\n\n175\n\n595\n\n35\n\n450\n\n242\n\n727\n\nDivestments and reimbursements\n\n \n\n(84)\n\n(20)\n\n(104)\n\n(2)\n\n(291)\n\n(33)\n\n(326)\n\nShare of profit of equity-accounted investments\n\n4\n\n664\n\n746\n\n1,414\n\n5\n\n795\n\n402\n\n1,202\n\nShare of loss of equity-accounted investments\n\n(9)\n\n(102)\n\n(141)\n\n(252)\n\n(12)\n\n(123)\n\n(181)\n\n(316)\n\nDeduction for dividends\n\n(1)\n\n(573)\n\n(938)\n\n(1,512)\n\n(3)\n\n(655)\n\n(1,094)\n\n(1,752)\n\nChanges in the scope of consolidation\n\n(13)\n\n138\n\n \n\n125\n\n8\n\n635\n\n7\n\n650\n\nCurrency translation differences\n\n(1)\n\n(940)\n\n(478)\n\n(1,419)\n\n \n\n461\n\n206\n\n667\n\nOther changes\n\n9\n\n65\n\n84\n\n158\n\n(2)\n\n(73)\n\n743\n\n668\n\nCarrying amount - end of the year\n\n92\n\n9,016\n\n4,047\n\n13,155\n\n82\n\n9,449\n\n4,619\n\n14,150\n\n \n\nAcquisitions and share capital increases mainly related: (i) for €111 million the acquisition in the Plenitude business line of stakes in the two joint ventures 2024 Sol XV Llc (Plenitude 37.98%) and 2024 Sol XVI Llc (Plenitude 32.07%) owners of two operating photovoltaic plants and an electricity storage plant under construction in California (United States), with a total installed capacity of approximately 245 MW in Plenitude's share; (ii) for €108 million to the capital increase of QatarEnergy LNG NFE (5) (Eni’s interest 25%) which participates with a 12.5% stake in the North Field East (NFE) project, ensuring Eni a 3.125% stake in the Qatar megaproject for the development of LNG; (iii) the increase of a further 12% stake in E&E Algeria Touat BV (Eni's interest 66%) for €62 million; (iv) the acquisition of 2025 Bateria II Llc (Plenitude 33.92%) for €55 million; (v) for €45 million to the capital increase of LG-Eni BioRefining Co Ltd (Enilive 49%) engaged in the construction of a biorefining plant in South Korea; (vi) for €30 million to the capital increase of Vårgrønn AS, the joint venture (Plenitude 65%) which owns the 20% stake in the Doggerbank A, B and C offshore wind projects in the United Kingdom; (vii) for €29 million to the capital increase of Lotte Versalis Elastomers Co Ltd (Versalis 50%).\n\n \n\nDivestments and reimbursements related for €83 million to the capital reimbursement by E&E Algeria Touat BV.\n\n \n\nShare of profit from equity-accounted investments essentially referred to: (i) Vår Energi ASA for €602 million, which includes the excess of the dividend distributed over the net equity of the investee attributable to Eni; (ii) Azule Energy Holdings Ltd for €415 million; (iii) ADNOC Global Trading Ltd for €96 million; (iv) Saipem SpA for €71 million; (v) Cardón IV SA for €62 million.\n\nShare of loss from equity-accounted investments essentially referred to: (i) St. Bernard Renewables Llc for €58 million; (ii) Vårgrønn AS for €35 million.\n\nReduction for dividends related to: (i) Vår Energi ASA for €653 million; (ii) Azule Energy Holdings Ltd for €386 million; (iii) Ithaca Energy Plc for €161 million; (iv) SeaCorridor Srl for €95 million; (v) Saipem SpA for 72 million; (vi) Abu Dhabi Oil Refining Company (TAKREER) for €56 million; (v) ADNOC Global Trading Ltd for €49 million.\n\nThe change in the scope of consolidation included €138 million of the initial recognition of the investment in the joint venture Eni CCUS Holding Ltd, following the business combination with GIP, resulting in Eni contributing to the venture the CCUS assets in the UK and the Netherlands. The book value of the newly established joint venture corresponds to the fair value of the interest of 49.99% acquired by the other shareholder. The venture will be accounted for using the equity method going forward.\n\n \n\nF-52\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nNet carrying amounts related to the following companies:\n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nNet carrying amount\n\n% of the  investment\n\nNet carrying amount\n\n% of the  investment\n\nInvestments in unconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\nOther\n\n92\n\n \n\n82\n\n \n\n \n\n92\n\n \n\n82\n\n \n\nJoint ventures\n\n \n\n \n\n \n\n \n\nAzule Energy Holdings Ltd\n\n4,634\n\n50.00\n\n5,211\n\n50.00\n\nE&E Algeria Touat BV\n\n671\n\n66.00\n\n646\n\n54.00\n\nSt. Bernard Renewables Llc\n\n657\n\n50.00\n\n806\n\n50.00\n\nSaipem SpA\n\n581\n\n21.80\n\n528\n\n21.61\n\nSeaCorridor Srl\n\n411\n\n50.10\n\n485\n\n50.10\n\nVårgrønn AS\n\n374\n\n65.00\n\n406\n\n65.00\n\nCardón IV SA\n\n370\n\n50.00\n\n351\n\n50.00\n\nMozambique Rovuma Venture SpA\n\n366\n\n35.71\n\n382\n\n35.71\n\nGreenIT SpA\n\n140\n\n51.00\n\n111\n\n51.00\n\nEni CCUS Holding Ltd\n\n136\n\n50.01\n\n \n\n \n\n2023 Sol IX Llc\n\n131\n\n73.62\n\n149\n\n73.59\n\nLotte Versalis Elastomers Co Ltd\n\n81\n\n50.00\n\n61\n\n50.00\n\nMangistau Power BV\n\n75\n\n51.00\n\n51\n\n51.00\n\n2024 Sol XV Llc\n\n67\n\n47.47\n\n \n\n \n\n2022 Sol VII Llc\n\n53\n\n75.24\n\n61\n\n75.26\n\n2025 Bateria II Llc\n\n53\n\n33.92\n\n \n\n \n\nHergo Renewables SpA\n\n35\n\n65.00\n\n33\n\n65.00\n\nMangistau Renewables BV\n\n35\n\n51.00\n\n21\n\n51.00\n\n2024 Sol XVI Llc\n\n31\n\n40.58\n\n \n\n \n\nSocietà Oleodotti Meridionali SOM SpA\n\n13\n\n70.00\n\n18\n\n70.00\n\nLabAnalysis Environmental Scienze Srl\n\n \n\n \n\n26\n\n30.00\n\nOther\n\n102\n\n \n\n103\n\n \n\n \n\n9,016\n\n \n\n9,449\n\n \n\nAssociates\n\n \n\n \n\n \n\n \n\nAbu Dhabi Oil Refining Company (Takreer)\n\n1,980\n\n20.00\n\n2,275\n\n20.00\n\nQatarEnergy LNG NFE (5)\n\n661\n\n25.00\n\n633\n\n25.00\n\nIthaca Energy Plc\n\n486\n\n35.92\n\n725\n\n37.17\n\nADNOC Global Trading Ltd\n\n192\n\n20.00\n\n165\n\n20.00\n\nCoral FLNG SA\n\n184\n\n25.00\n\n231\n\n25.00\n\nLG-Eni BioRefining Co Ltd\n\n93\n\n49.00\n\n56\n\n49.00\n\nUnited Gas Derivatives Co\n\n71\n\n33.33\n\n79\n\n33.33\n\nNovis Renewables Holdings Llc\n\n66\n\n49.00\n\n74\n\n49.00\n\nBluebell Solar Class A Holdings II Llc\n\n62\n\n99.00\n\n72\n\n99.00\n\nLabAnalysis Environmental Scienze Srl\n\n26\n\n30.00\n\n \n\n \n\nVår Energi ASA\n\n \n\n63.04\n\n \n\n63.04\n\nOther\n\n226\n\n \n\n309\n\n \n\n \n\n4,047\n\n \n\n4,619\n\n \n\n \n\n13,155\n\n \n\n14,150\n\n \n\n \n\nThe carrying amount of Vår Energi ASA is equal to zero in relation to the application of the equity method of accounting owing to the reduction for the dividends distributed to shareholders.\n\nThe results of equity-accounted investments by segment are disclosed in note 35 – Segment information and information by geographical area.\n\nAs of December 31, 2025, the book and market values of Saipem SpA, Vår Energi ASA and Ithaca Energy Plc, listed equity-accounted companies, respectively, were as follows:\n\n \n\n \n\nSaipem SpA\n\nVår Energi ASA\n\nIthaca Energy Plc\n\nNumber of ordinary shares held\n\n \n\n422,920,192\n\n1,573,713,749\n\n594,048,748\n\n% of the investment\n\n \n\n21.80\n\n63.04\n\n35.92\n\nShare price\n\n(€)\n\n2.425\n\n2.787\n\n1.899\n\nMarket value\n\n(€ million)\n\n1,025\n\n4,386\n\n1,128\n\nBook value\n\n(€ million)\n\n581\n\n \n\n486\n\nMarket value vs Book value\n\n(€ million)\n\n444\n\n4,386\n\n642\n\nAdditional information is included in note 37 – Other information about investments.\n\n \n\nF-53\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOther investments\n\n(€ million)\n\n2025\n\n2024\n\nCarrying amount - beginning of the year\n\n1,395\n\n1,256\n\nAdditions and subscriptions\n\n87\n\n71\n\nChange in the fair value with effect to OCI\n\n(30)\n\n62\n\nCurrency translation differences\n\n(108)\n\n56\n\nOther changes\n\n(15)\n\n(50)\n\nCarrying amount - end of the year\n\n1,329\n\n1,395\n\nThe 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 (6%) in which each investee operates. A stress test based on a 1% change in the cost of capital considered in the valuation did not produce significant changes at the fair value.\n\nDividend income from these investments is disclosed in note 32 – Income (expense) from investments.\n\n \n\nAcquisitions and subscriptions include €50 million for the acquisition of a minority stake in BF International Best Fields Best Food Ltd (Eni’s interest 10.58%).\n\nThe investment book value as of December 31, 2025, primarily related to Nigeria LNG Ltd for €607 million (€690 million at December 31, 2024), Saudi European Petrochemical Co “IBN ZAHR” for €110 million (€127 million at December 31, 2024) and Darwin LNG Pty Ltd for €84 million (€96 million at December 31, 2024).\n\n \n\n17 Other financial assets\n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nCurrent\n\nNon-current\n\nCurrent\n\nNon-current\n\nLong-term financing receivables held for operating purposes\n\n1\n\n910\n\n1\n\n1,044\n\n \n\n1\n\n910\n\n1\n\n1,044\n\nLong-term financing receivables held for non-operating purposes\n\n3,067\n\n136\n\n44\n\n2,109\n\nShort-term financing receivables held for non-operating purposes\n\n642\n\n \n\n1,040\n\n \n\n \n\n3,709\n\n136\n\n1,084\n\n2,109\n\n \n\n3,710\n\n1,046\n\n1,085\n\n3,153\n\nSecurities held for operating purposes\n\n \n\n63\n\n \n\n62\n\nTotal net of impairment provisions\n\n3,710\n\n1,109\n\n1,085\n\n3,215\n\n \n\nChanges in allowance for doubtful accounts were as follows:\n\n \n\n(€ million)\n\n2025\n\n2024\n\nCarrying amount at the beginning of the year\n\n427\n\n383\n\nAdditions\n\n1\n\n26\n\nDeductions\n\n(2)\n\n(3)\n\nCurrency translation differences\n\n(47)\n\n24\n\nOther changes\n\n(2)\n\n(3)\n\nCarrying amount at the end of the year\n\n377\n\n427\n\n \n\nFinancing receivables held for operating purposes primarily related to loans provided to joint ventures and associates in the Exploration & Production segment (€741 million) to execute capital projects of interest to Eni. These receivables are long-term interests in the initiatives funded. The main amounts were towards Coral FLNG SA (Eni’s interest 25%) for €417 million (€522 million at December 31, 2024), operating a floating gas liquefaction plant in Area 4, offshore Mozambique.\n\nFinancing receivables held for operating purposes due beyond five years amounted to €90 million (€214 million at December 31, 2024).\n\nThe fair value of non-current financing receivables held for operating purposes of €910 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from 1.9% to 4.8% (1.7% and 4.8% at December 31, 2024).\n\nThe recoverability of other long-term financial assets was assessed by considering the expected probability of default in the next twelve months only, as creditworthiness suffered no significant deterioration in the reporting period.\n\n \n\nF-54\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nFinancing receivables held for non-operating purposes related to: (i) the joint venture Mozambique Rovuma Venture SpA (Eni’s interest 35.71%) for €2,318 million (€1,769 million at December 31, 2024) engaged in production and development of natural gas reserves in the Coral discovery prospect offshore, located in the subarea of exclusive exploitation of the concessionaires of the larger Area 4. This receivable is not part of the long-term interest in the upstream initiative; (ii) €710 million of receivables from co-ventures arising from the reallocation of working interest in ongoing development projects in Area 4 offshore Mozambique; (iii) restricted deposits in escrow to guarantee transactions on derivative contracts for €495 million (€937 million at December 31, 2024), referred to the Global Gas & LNG Portfolio business line for €463 million (€907 million at December 31, 2024).\n\nFinancing receivables were denominated in U.S. dollar for €4,325 million and in euro for €307 million (€3,351 million and €855 million at December 31, 2024, respectively).\n\nSecurities for €18 million (€11 million at December 31, 2024) were pledged as guarantee of the deposit for gas cylinders as provided for by the Italian law.\n\nThe following table analyses securities per issuing entity:\n\n \n\nAmortized cost (€ million)\n\nNominal value\n\n(€ million)\n\nFair Value\n\n(€ million)\n\nNominal rate of return (%)\n\nMaturity date\n\nRating - Moody's\n\nRating - S&P\n\nSovereign states\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFixed rate bonds\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nItaly\n\n18\n\n18\n\n17\n\nfrom 0 to 3.6\n\nfrom 2026 to 2035\n\nBaa2\n\nBBB+\n\nOthers (*)\n\n31\n\n31\n\n31\n\nfrom 0 to 5.0\n\nfrom 2026 to 2030\n\nfrom Aa1 to Baa2\n\nfrom AA+ to BBB-\n\nFloating rate bonds\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nItaly\n\n11\n\n11\n\n11\n\nfrom 2.6 to 2.9\n\nfrom 2026 to 2029\n\nBaa2\n\nBBB+\n\nTotal sovereign states\n\n60\n\n60\n\n59\n\n \n\n \n\n \n\n \n\nOther financial institutions\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nEuropean Bank of Investments\n\n3\n\n3\n\n3\n\n3.75\n\n2026\n\nAaa\n\nAAA\n\nTotal\n\n63\n\n63\n\n62\n\n \n\n \n\n \n\n \n\n(*) Amounts included herein are lower than €10 million.\n\n \n\nSecurities having maturity within five years amounted to €49 million.\n\n \n\nThe fair value of securities was derived from quoted market prices.\n\n \n\nReceivables with related parties are described in note 36 – Transactions with related parties.\n\n \n\nF-55\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n18 Trade and other payables \n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nTrade payables\n\n13,901\n\n15,170\n\nDown payments and advances from joint ventures in exploration & production activities\n\n714\n\n767\n\nPayables for purchase of non-current assets\n\n1,666\n\n1,939\n\nPayables due to partners in exploration & production activities\n\n1,114\n\n1,377\n\nOther payables\n\n2,866\n\n2,839\n\n \n\n20,261\n\n22,092\n\n \n\nThe decrease in trade payables of €1,269 million referred to Global Gas & LNG Portfolio business line for €1,929 million following lower gas purchases and, on the increase, to the Enilive business line for €374 million.\n\nTrade payables include debts under credit letters with payment terms aligned with commercial ones and with fixed commissions.\n\nOther payables included: (i) payables to factoring companies in relation to the derecognition of Eni's tax credits for €1,322 million (€1,129 million at December 31, 2024); (ii) payroll payables for €260 million (€268 million at December 31, 2024); (iii) payables for social security contributions for €124 million (€120 million at December 31, 2024).\n\nTrade and other payables were denominated in euro for €10,937 million and in U.S. dollar for €8,994 million (€11,487 million and €10,047 million at December 31, 2024, respectively), with a carrying amount substantially aligned with fair value.\n\nTrade and other payables due to related parties are described in note 36 – Transactions with related parties.\n\n \n\n19 Finance debt \n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nShort-term debt\n\nCurrent portion of long-term debt\n\nLong-term debt\n\nTotal\n\nShort-term debt\n\nCurrent portion of long-term debt\n\nLong-term debt\n\nTotal\n\nBanks\n\n3,394\n\n330\n\n1,268\n\n4,992\n\n2,941\n\n269\n\n921\n\n4,131\n\nOrdinary bonds\n\n \n\n2,320\n\n17,855\n\n20,175\n\n \n\n2,695\n\n19,641\n\n22,336\n\nSustainability-linked convertible bonds\n\n \n\n9\n\n939\n\n948\n\n \n\n9\n\n928\n\n937\n\nOther financial institutions\n\n1,535\n\n775\n\n77\n\n2,387\n\n1,297\n\n1,609\n\n80\n\n2,986\n\n \n\n4,929\n\n3,434\n\n20,139\n\n28,502\n\n4,238\n\n4,582\n\n21,570\n\n30,390\n\n \n\nFinance debt decreased by €1,888 million as disclosed in table “Changes in liabilities arising from financing activities” detailed at the end of this paragraph.\n\nAs of December 31, 2025, finance debt included €200 million (€300 million at December 31, 2024) of sustainability-linked financial contracts with leading banking institutions which provide for an adjustment of the funding cost linked to the achievement of certain sustainability targets, which are disclosed in the comment of ordinary bonds.\n\nOther financial institutions included supplier finance arrangements (SFAs) as follows:\n\n(€ million)\n\nLong-term SFAs\n\nCurrent SFAs and current portion of long-term SFAs\n\nTotal\n\nCarrying amount at December 31, 2024\n\n26\n\n2,542\n\n2,568\n\nCash flows\n\n \n\n(2,249)\n\n(2,249)\n\nNon-monetary increases\n\n12\n\n1,430\n\n1,442\n\nCurrency translation differences\n\n \n\n(174)\n\n(174)\n\nOther non-monetary changes\n\n(18)\n\n16\n\n(2)\n\nCarrying amount at December 31, 2025\n\n20\n\n1,565\n\n1,585\n\nCarrying amount at December 31, 2023\n\n92\n\n893\n\n985\n\nCash flows\n\n \n\n(844)\n\n(844)\n\nNon-monetary increases\n\n451\n\n1,788\n\n2,239\n\nCurrency translation differences\n\n2\n\n92\n\n94\n\nOther non-monetary changes\n\n(519)\n\n613\n\n94\n\nCarrying amount at December 31, 2024\n\n26\n\n2,542\n\n2,568\n\n \n\nF-56\n\n[Table of Contents](#TOC_TableofContent)\n\nThe payment terms for financial liabilities falling within the scope of the SFAs range between 145 and 450 days, compared to the terms of other comparable commercial debt not falling within the scope of the agreement which are between 30 and 60 days. Eni formally has no information on the timing of the settlement made by the bank to the suppliers. The main transactions falling within the scope of the SFA agreements mainly concern: (i) within the Congo project, the construction of the floating LNG production vessel Nguya, which entered into service at the end of 2025 allowing the liquefaction capacity of the project to be increased up to 3 MTPA from the current 0.6 MTPA; (ii) EPC contracts for plant reconversion, laying of submarine lines and contracts for transportation and installation of subsea lines and cables; (iii) production facilities offshore Mexico (Area 1); (iv) the contract for transportation and installation of pipelines and umbilicals and subsea production system for the Baleine Phase II project offshore Ivory Coast.\n\nEni 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, 2025, debts subjected to restrictive covenants amounted to €981 million (€613 million at December 31, 2024). Eni was in compliance with those covenants.\n\nEni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €12.8 billion were drawn as of December 31, 2025.\n\nThe following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2025:\n\n(€ million)\n\nAmount\n\nDiscount on bond issue and accrued expense\n\nTotal\n\nCurrency\n\nMaturity\n\nRate (%)\n\nIssuing entity\n\n \n\n \n\n \n\n \n\n \n\n \n\nEuro Medium Term Notes\n\n \n\n \n\n \n\n \n\n \n\n \n\nEni SpA\n\n1,250\n\n24\n\n1,274\n\nEUR\n\n2033\n\n4.250\n\nEni SpA\n\n1,000\n\n49\n\n1,049\n\nEUR\n\n2029\n\n3.625\n\nEni SpA\n\n1,000\n\n26\n\n1,026\n\nEUR\n\n2034\n\n3.875\n\nEni SpA\n\n1,000\n\n14\n\n1,014\n\nEUR\n\n2026\n\n1.500\n\nEni SpA\n\n1,000\n\n11\n\n1,011\n\nEUR\n\n2031\n\n2.000\n\nEni SpA\n\n1,000\n\n7\n\n1,007\n\nEUR\n\n2026\n\n1.250\n\nEni SpA\n\n1,000\n\n4\n\n1,004\n\nEUR\n\n2030\n\n0.625\n\nEni SpA\n\n800\n\n5\n\n805\n\nEUR\n\n2028\n\n1.625\n\nEni SpA\n\n750\n\n10\n\n760\n\nEUR\n\n2027\n\n1.500\n\nEni SpA\n\n750\n\n(2)\n\n748\n\nEUR\n\n2034\n\n1.000\n\nEni SpA\n\n638\n\n8\n\n646\n\nUSD\n\n2027\n\nvariable\n\nEni SpA\n\n600\n\n \n\n600\n\nEUR\n\n2028\n\n1.125\n\nEni SpA\n\n100\n\n4\n\n104\n\nEUR\n\n2028\n\n5.441\n\nEni SpA\n\n75\n\n \n\n75\n\nEUR\n\n2043\n\n3.875\n\nEni SpA\n\n70\n\n1\n\n71\n\nEUR\n\n2032\n\n4.000\n\nEni SpA\n\n50\n\n \n\n50\n\nEUR\n\n2031\n\n4.800\n\nEni SpA - Sustainability-linked\n\n1,000\n\n \n\n1,000\n\nEUR\n\n2028\n\n0.375\n\nEni SpA - Sustainability-linked\n\n750\n\n16\n\n766\n\nEUR\n\n2027\n\n3.625\n\n \n\n12,833\n\n177\n\n13,010\n\n \n\n \n\n \n\nOther bonds\n\n \n\n \n\n \n\n \n\n \n\n \n\nEni SpA\n\n1,063\n\n(21)\n\n1,042\n\nUSD\n\n2054\n\n5.950\n\nEni SpA\n\n851\n\n8\n\n859\n\nUSD\n\n2028\n\n4.750\n\nEni SpA\n\n851\n\n2\n\n853\n\nUSD\n\n2029\n\n4.250\n\nEni SpA\n\n851\n\n7\n\n858\n\nUSD\n\n2034\n\n5.500\n\nEni SpA\n\n851\n\n(7)\n\n844\n\nUSD\n\n2035\n\n5.750\n\nEni SpA\n\n298\n\n1\n\n299\n\nUSD\n\n2040\n\n5.700\n\nEni USA Inc\n\n340\n\n3\n\n343\n\nUSD\n\n2027\n\n7.300\n\nEni SpA - Sustainability-linked - Retail\n\n2,000\n\n67\n\n2,067\n\nEUR\n\n2028\n\n4.300\n\n \n\n7,105\n\n60\n\n7,165\n\n \n\n \n\n \n\n \n\n19,938\n\n237\n\n20,175\n\n \n\n \n\n \n\n \n\nF-57\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nDuring 2025, new ordinary bonds in euro were issued by Eni SpA for a nominal value of €851 million.\n\nAs of December 31, 2025, Eni SpA had in place sustainability-linked bonds for a total nominal value of €3,750 million. In case the Company misses those targets, a step-up mechanism will be applied, providing for a marginal increase in the interest rate.\n\nAs of December 31, 2025, nominal value of ordinary bonds maturing within 18 months amounted to €3,500 million.\n\n \n\nInformation relating to the senior unsecured sustainability-linked convertible bonds is as follows:\n\n \n\n(€ million)\n\nAmount\n\nDiscount on bond issue and accrued expense\n\nTotal\n\nCurrency\n\nMaturity\n\nRate (%)\n\nIssuing entity\n\n \n\n \n\n \n\n \n\n \n\n \n\nEni SpA - Convertible senior unsecured sustainability-linked bonds\n\n1,000\n\n27\n\n1,027\n\nEUR\n\n2030\n\n2.950\n\nof which financial liabilities\n\n920\n\n28\n\n948\n\nEUR\n\n \n\n \n\nof which equity\n\n80\n\n(1)\n\n79\n\nEUR\n\n \n\n \n\n \n\nAs of December 31, 2025, Eni SpA had in place a sustainability-linked senior unsecured convertible bond with an aggregate nominal amount of €1,000 million. The bonds will be convertible into Eni existing ordinary shares bought under the share buyback program approved by the Shareholders’ Meeting held on May 10, 2023. The bonds will mature in 7 years. The conversion price is €17.5513.\n\n \n\nSustainability-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.\n\n \n\nThe following table provides a breakdown by currency of finance debt and the related weighted average interest rates:\n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n \n\nShort-term debt (€ million)\n\nWeighted average rate (%)\n\nLong-term debt and current portion of long-term debt (€ million)\n\nWeighted average rate (%)\n\nShort-term debt (€ million)\n\nWeighted average rate (%)\n\nLong-term debt and current portion of long-term debt\n\n(€ million)\n\nWeighted average rate (%)\n\nEuro\n\n4,449\n\n2.1\n\n16,959\n\n2.5\n\n3,518\n\n3.0\n\n19,547\n\n2.5\n\nU.S. dollar\n\n437\n\n3.0\n\n6,612\n\n4.9\n\n707\n\n4.8\n\n6,603\n\n5.3\n\nOther currencies\n\n43\n\n1.7\n\n2\n\n2.7\n\n13\n\n2.2\n\n2\n\n2.7\n\n \n\n4,929\n\n \n\n23,573\n\n \n\n4,238\n\n \n\n26,152\n\n \n\n \n\nF-58\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nAs of December 31, 2025, Eni retained committed borrowing facilities of €9,012 million (€9,001 million at December 31, 2024), of which €9,000 undrawn. Those facilities bore interest rates reflecting prevailing conditions in the marketplace.\n\n \n\nAs of December 31, 2025, Eni was in compliance with covenants and other contractual provisions in relation to borrowing facilities.\n\n \n\nFair value of long-term debt, including the current portion of long-term debt is described below:\n\n(€ million)\n\nDecember 31,\n\n2025\n\nDecember 31,\n\n2024\n\nOrdinary bonds and sustainability-linked bonds\n\n20,119\n\n21,026\n\nConvertible sustainability-linked bonds\n\n1,071\n\n973\n\nBanks\n\n1,608\n\n1,143\n\nOther financial institutions\n\n852\n\n1,689\n\n \n\n23,650\n\n24,831\n\n \n\nFair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from 1.9% to 4.8% (1.7% and 4.8% at December 31, 2024).\n\n \n\nBecause of the short-term maturity and conditions of remuneration of short-term debt, the fair value approximated the carrying amount.\n\n \n\nChanges in liabilities arising from financing activities\n\n \n\n(€ million)\n\nLong-term debt and current portion of long-term debt\n\nShort-term debt\n\nLong-term and current portion of long-term lease liabilities\n\nTotal\n\nCarrying amount at December 31, 2024\n\n26,152\n\n4,238\n\n6,453\n\n36,843\n\nCash flows\n\n(2,279)\n\n(276)\n\n(1,250)\n\n(3,805)\n\nCurrency translation differences\n\n(586)\n\n201\n\n(484)\n\n(869)\n\nChanges in the scope of consolidation\n\n470\n\n4\n\n \n\n474\n\nOther non-monetary changes\n\n(184)\n\n762\n\n981\n\n1,559\n\nCarrying amount at December 31, 2025\n\n23,573\n\n4,929\n\n5,700\n\n34,202\n\nCarrying amount at December 31, 2023\n\n24,637\n\n4,092\n\n5,336\n\n34,065\n\nCash flows\n\n(1,232)\n\n(61)\n\n(1,205)\n\n(2,498)\n\nCurrency translation differences\n\n232\n\n(303)\n\n247\n\n176\n\nChanges in the scope of consolidation\n\n855\n\n12\n\n50\n\n917\n\nOther non-monetary changes\n\n1,660\n\n498\n\n2,025\n\n4,183\n\nCarrying amount at December 31, 2024\n\n26,152\n\n4,238\n\n6,453\n\n36,843\n\nChanges in the scope of consolidation related to the acquisition of Plenitude Production France SAS for €762 million and the loss of control of Eni CCUS Holding Ltd for €298 million.\n\nOther non-monetary changes include €1,442 million of trade payables on which payment term extensions have been negotiated, resulting in the classification of the debt as financial, lease liabilities assumptions for €1,150 million and, as a decrease, €762 the reclassification to assets held for sale of Plenitude Production France SAS.\n\nLease liabilities are described in note 13 – Right-of-use assets and lease liabilities.\n\nTransactions with related parties are described in note 36 – Transactions with related parties.\n\n \n\nF-59\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n20 Information on net borrowings\n\n \n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nA.\n\nCash\n\n2,796\n\n3,367\n\nB.\n\nCash equivalents\n\n5,304\n\n4,816\n\nC.\n\nOther current financial assets\n\n10,700\n\n7,881\n\nD.\n\nLiquidity (A+B+C)\n\n18,800\n\n16,064\n\nE.\n\nCurrent financial debt\n\n7,258\n\n6,942\n\nF.\n\nCurrent portion of non-current financial debt\n\n2,368\n\n3,157\n\nG.\n\nCurrent financial indebtedness (E+F)\n\n9,626\n\n10,099\n\nH.\n\nNet current financial indebtedness (G-D)\n\n(9,174)\n\n(5,965)\n\nI.\n\nNon-current financial debt\n\n5,782\n\n6,175\n\nJ.\n\nDebt instruments\n\n18,756\n\n20,527\n\nK.\n\nNon‐current trade and other payables\n\n \n\n \n\nL.\n\nNon-current financial indebtedness (I+J+K)\n\n24,538\n\n26,702\n\nM.\n\nTotal financial indebtedness (H+L)\n\n15,364\n\n20,737\n\n \n\nNet borrowings did not include €136 million of non-current financing receivables (€2,109 million at December 31, 2024).\n\nOther 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.\n\n \n\nCurrent and non-current debts are disclosed in note 19 – Finance debts.\n\n \n\nDebt instruments included €38 million (€42 million at December 31, 2024) of positive fair value hedge derivative contracts entered to hedge fixed rate bonds.\n\n \n\nCurrent portion of non-current financial debt and non-current financial debt include lease liabilities of €1,263 million and €4,437 million (€1,279 million and €5,174 million at December 31, 2024, respectively). More information on lease liabilities is reported in note 13 – Right-of-use assets and lease liabilities.\n\n \n\nF-60\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n21 Provisions\n\n \n\n(€ million)\n\nProvisions for site restoration, abandonment and social projects\n\nEnvironmental provisions\n\nProvisions for litigations\n\nProvisions for taxes other than income taxes\n\nLoss adjustments and actuarial provisions for Eni's insurance companies\n\nProvisions for losses on investments\n\nProvisions for EVEREN insurance coverage\n\nOther\n\nTotal\n\nCarrying amount at December 31, 2024\n\n9,712\n\n3,700\n\n594\n\n158\n\n229\n\n234\n\n86\n\n1,061\n\n15,774\n\nNew or increased provisions\n\n135\n\n641\n\n353\n\n19\n\n89\n\n6\n\n23\n\n404\n\n1,670\n\nInitial recognition and changes in estimates\n\n279\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n279\n\nAccretion discount\n\n290\n\n(40)\n\n \n\n \n\n \n\n \n\n \n\n \n\n250\n\nReversal of utilized provisions\n\n(824)\n\n(671)\n\n(175)\n\n(18)\n\n(132)\n\n \n\n(1)\n\n(135)\n\n(1,956)\n\nReversal of unutilized provisions\n\n(144)\n\n(42)\n\n(85)\n\n \n\n \n\n(5)\n\n(1)\n\n(238)\n\n(515)\n\nCurrency translation differences\n\n(554)\n\n(4)\n\n(36)\n\n(8)\n\n \n\n(5)\n\n(1)\n\n(17)\n\n(625)\n\nOther changes\n\n(272)\n\n(42)\n\n26\n\n22\n\n2\n\n7\n\n(7)\n\n(33)\n\n(297)\n\nCarrying amount at December 31, 2025\n\n8,622\n\n3,542\n\n677\n\n173\n\n188\n\n237\n\n99\n\n1,042\n\n14,580\n\n \n\nProvisions for site restoration, abandonment and social projects mainly comprised: (i) for €7,557 million the present value of the estimated costs that the Company expects to incur for dismantling oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, site clean-up and environmental restoration; (ii) for €507 million the estimated costs for social projects in the Exploration & Production segment, relating for €230 million to the estimated costs for social projects as part of the commitments between Eni SpA and the Basilicata region in relation to the oil development program in the Val d’Agri concession area; (iii) for €442 million the estimate for decommissioning and dismantling costs of refining plants for which there are no prospects of economic reuse or reconversion into transition processes, in the current market context, as well as fuel distribution outlets.\n\nIn 2025, 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 €79 million; (ii) cost estimates for dismantling and removing refining plants and fuel distribution for €55 million for which management has assessed the absence of economic prospectives in the current market context. Reversal of unutilized provisions mainly concerned a downstream plant in Italy for which negotiations are underway for the sale to third parties.\n\nInitial recognition and changes in cost estimates include the updated estimates of site decommissioning and restoration costs (primarily in Italy and Algeria) partly offset by an increased yield curve for the euro. The effect of the accretion of discount recognized through profit and loss was determined based on discount rates ranging from 1.7% to 5.6% (from 1.8% to 5.3% at December 31, 2024). Utilizations of the decommissioning provision mainly related to advance in decommissioning activities in Italy for €253 million, in the United Kingdom for €243 million and in Libya for €111 million. Other changes included the reclassification to liabilities directly associated with assets held for sale of the Exploration & Production segment for €231 million. Main expenditures associated with decommissioning operations are expected to be incurred over a fifty-year period, with utilizations essentially starting after 12 months. Further information on the uncertainty relating to the estimation of the times of dismantling and restoration of hydrocarbon extraction plants is reported in note 15 - Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.\n\n \n\nF-61\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nProvisions 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 to date are no more in compliance with current environmental laws and regulations, or because Eni assumed the liability borne by other operators at the time of acquisition or otherwise took over the 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 €294 million to remediation activities at brownfield sites in Italy and costs related to groundwater cleanups; (ii) for €191 million to refining plants, storage sites, fuel distribution outlets and oil pipelines; (iii) for €78 million to remediation activities at petrochemical plants. Reversal of utilized provisions related to the progress of environmental remediation and restoration operations. At December 31, 2025, environmental provisions related to Eni Rewind SpA for €2,251 million and to the Refining and Chemical segment for €750 million.\n\nLitigation 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 €282 million. The provision also included the estimate provisions in certain antitrust proceedings.\n\nProvisions 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 €142 million. In particular, charges mainly relate to the dispute regarding the taxation of Italian local administrations on Eni offshore platforms located in common territorial waters.\n\nLoss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance SpA represented the estimated liabilities accrued on the basis for third party claims. Against such liability were recorded receivables for €34 million towards insurance companies for reinsurance contracts.\n\nProvisions 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 €176 million.\n\nProvisions for the Everen insurance coverage included insurance premiums which will be charged to Eni in the next five years by the mutual insurance company in which Eni participates together with other oil companies.\n\nOther provisions mainly related to claims, contingencies and commercial renegotiations as part of the ordinary course of the business. Those provisions were outstanding mainly in the Global Gas & LNG Portfolio and Enilive business lines.\n\nBased 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 €1.7 billion.\n\n \n\nF-62\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n22 Provisions for employee benefits\n\n \n\n(€ million)\n\nDecember 31,\n\n2025\n\nDecember 31,\n\n2024\n\nItalian defined benefit plans\n\n143\n\n151\n\nForeign defined benefit plans\n\n89\n\n108\n\nFISDE, foreign medical plans and other\n\n112\n\n112\n\nDefined benefit plans\n\n344\n\n371\n\nOther benefit plans\n\n252\n\n310\n\nProvision for employee benefits\n\n596\n\n681\n\n \n\nThe 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.\n\n \n\nOther employee benefit plans related to deferred monetary incentive plans for €139 million (€134 million at December 31, 2024), expansion contracts for €51 million (€86 million at December 31, 2024), isopensione plans (a post-retirement benefit plan applicable to a specific category of employees) of Eni Plenitude SpA for €28 million (€47 million at December 31, 2024), Jubilee Awards for €18 million (€25 million at December 31, 2024) and other long-term plans for €16 million (€18 million at December 31, 2024).\n\n \n\nPresent value of employee benefits, estimated by applying actuarial techniques, consisted of the following:\n\n \n\n \n\n2025\n\n2024\n\n(€ million)\n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans and other\n\nDefined benefit plans\n\nOther benefit plans\n\nTotal\n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans and other\n\nDefined benefit plans\n\nOther benefit plans\n\nTotal\n\nPresent value of benefit liabilities at beginning of year\n\n151\n\n369\n\n112\n\n632\n\n310\n\n942\n\n156\n\n380\n\n118\n\n654\n\n353\n\n1,007\n\nCurrent service cost\n\n1\n\n6\n\n2\n\n9\n\n57\n\n66\n\n1\n\n12\n\n2\n\n15\n\n56\n\n71\n\nInterest cost\n\n5\n\n17\n\n3\n\n25\n\n8\n\n33\n\n5\n\n18\n\n4\n\n27\n\n11\n\n38\n\nRemeasurements:\n\n(4)\n\n7\n\n(2)\n\n1\n\n(8)\n\n(7)\n\n(1)\n\n(22)\n\n(2)\n\n(25)\n\n1\n\n(24)\n\n- actuarial (gains) losses due to changes in demographic assumptions\n\n \n\n(7)\n\n \n\n(7)\n\n \n\n(7)\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n(1)\n\n- actuarial (gains) losses due to changes in financial assumptions\n\n(1)\n\n \n\n(1)\n\n(2)\n\n(3)\n\n(5)\n\n \n\n(22)\n\n \n\n(22)\n\n5\n\n(17)\n\n- experience (gains) losses\n\n(3)\n\n14\n\n(1)\n\n10\n\n(5)\n\n5\n\n(1)\n\n1\n\n(2)\n\n(2)\n\n(4)\n\n(6)\n\nPast service cost and (gain) loss on settlements\n\n \n\n1\n\n5\n\n6\n\n(9)\n\n(3)\n\n \n\n9\n\n \n\n9\n\n3\n\n12\n\nPlan contributions:\n\n \n\n1\n\n \n\n1\n\n \n\n1\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n- employee contributions\n\n \n\n1\n\n \n\n1\n\n \n\n1\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\nBenefits paid\n\n(11)\n\n(31)\n\n(8)\n\n(50)\n\n(105)\n\n(155)\n\n(10)\n\n(85)\n\n(8)\n\n(103)\n\n(113)\n\n(216)\n\nReclassification to liabilities directly associated with assets held for sale\n\n \n\n(16)\n\n \n\n(16)\n\n(1)\n\n(17)\n\n \n\n \n\n \n\n \n\n \n\n \n\nCurrency translation differences and other changes\n\n1\n\n(7)\n\n \n\n(6)\n\n \n\n(6)\n\n \n\n55\n\n(2)\n\n53\n\n(1)\n\n52\n\nPresent value of benefit liabilities at end of year (a)\n\n143\n\n347\n\n112\n\n602\n\n252\n\n854\n\n151\n\n369\n\n112\n\n632\n\n310\n\n942\n\nPlan assets at beginning of year\n\n \n\n263\n\n \n\n263\n\n \n\n263\n\n \n\n261\n\n \n\n261\n\n \n\n261\n\nInterest income\n\n \n\n18\n\n \n\n18\n\n \n\n18\n\n \n\n14\n\n \n\n14\n\n \n\n14\n\nReturn on plan assets\n\n \n\n(8)\n\n \n\n(8)\n\n \n\n(8)\n\n \n\n(17)\n\n \n\n(17)\n\n \n\n(17)\n\nAdministrative fees paid\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n(1)\n\nPlan contributions:\n\n \n\n21\n\n \n\n21\n\n \n\n21\n\n \n\n25\n\n \n\n25\n\n \n\n25\n\n- employee contributions\n\n \n\n1\n\n \n\n1\n\n \n\n1\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n- employer contributions\n\n \n\n20\n\n \n\n20\n\n \n\n20\n\n \n\n23\n\n \n\n23\n\n \n\n23\n\nBenefits paid\n\n \n\n(24)\n\n \n\n(24)\n\n \n\n(24)\n\n \n\n(25)\n\n \n\n(25)\n\n \n\n(25)\n\nReclassification to liabilities directly associated with assets held for sale\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n(1)\n\n \n\n \n\n \n\n \n\n \n\n \n\nCurrency translation differences and other changes\n\n \n\n(8)\n\n \n\n(8)\n\n \n\n(8)\n\n \n\n6\n\n \n\n6\n\n \n\n6\n\nPlan assets at end of year (b)\n\n \n\n260\n\n \n\n260\n\n \n\n260\n\n \n\n263\n\n \n\n263\n\n \n\n263\n\nAsset ceiling at beginning of year\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\nChange in asset ceiling\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nAsset ceiling at end of year (c)\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\n \n\n2\n\nNet liability recognized at end of year (a-b+c)\n\n143\n\n89\n\n112\n\n344\n\n252\n\n596\n\n151\n\n108\n\n112\n\n371\n\n310\n\n681\n\n \n\nF-63\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCosts charged to the profit and loss account, valued using actuarial assumptions, consisted of the following:\n\n \n\n(€ million)\n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans and other\n\nDefined benefit plans\n\nOther\n\nbenefit plans\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\nCurrent service cost\n\n1\n\n6\n\n2\n\n9\n\n57\n\n66\n\nPast service cost and (gains) losses on settlements\n\n \n\n1\n\n5\n\n6\n\n(9)\n\n(3)\n\nInterest cost (income), net:\n\n \n\n \n\n \n\n \n\n \n\n \n\n- interest cost on liabilities\n\n5\n\n17\n\n3\n\n25\n\n8\n\n33\n\n- interest income on plan assets\n\n \n\n(18)\n\n \n\n(18)\n\n \n\n(18)\n\nTotal interest cost (income), net\n\n5\n\n(1)\n\n3\n\n7\n\n8\n\n15\n\n- of which recognized in Payroll and related cost\n\n \n\n \n\n \n\n \n\n8\n\n8\n\n- of which recognized in Financial income (expense)\n\n5\n\n(1)\n\n3\n\n7\n\n \n\n7\n\nRemeasurements for long-term plans\n\n \n\n \n\n \n\n \n\n(8)\n\n(8)\n\nAdministrative fees paid\n\n \n\n1\n\n \n\n1\n\n \n\n1\n\nTotal\n\n6\n\n7\n\n10\n\n23\n\n48\n\n71\n\n- of which recognized in Payroll and related cost\n\n1\n\n8\n\n7\n\n16\n\n48\n\n64\n\n- of which recognized in Financial income (expense)\n\n5\n\n(1)\n\n3\n\n7\n\n \n\n7\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\nCurrent service cost\n\n1\n\n12\n\n2\n\n15\n\n56\n\n71\n\nPast service cost and (gains) losses on settlements\n\n \n\n9\n\n \n\n9\n\n3\n\n12\n\nInterest cost (income), net:\n\n \n\n \n\n \n\n \n\n \n\n \n\n- interest cost on liabilities\n\n5\n\n18\n\n4\n\n27\n\n11\n\n38\n\n- interest income on plan assets\n\n \n\n(14)\n\n \n\n(14)\n\n \n\n(14)\n\nTotal interest cost (income), net\n\n5\n\n4\n\n4\n\n13\n\n11\n\n24\n\n- of which recognized in Payroll and related cost\n\n \n\n \n\n \n\n \n\n11\n\n11\n\n- of which recognized in Financial income (expense)\n\n5\n\n4\n\n4\n\n13\n\n \n\n13\n\nRemeasurements for long-term plans\n\n \n\n \n\n \n\n \n\n1\n\n1\n\nAdministrative fees paid\n\n \n\n1\n\n \n\n1\n\n \n\n1\n\nTotal\n\n6\n\n26\n\n6\n\n38\n\n71\n\n109\n\n- of which recognized in Payroll and related cost\n\n1\n\n22\n\n2\n\n25\n\n71\n\n96\n\n- of which recognized in Financial income (expense)\n\n5\n\n4\n\n4\n\n13\n\n \n\n13\n\n \n\nF-64\n\n[Table of Contents](#TOC_TableofContent)\n\nCosts of defined benefit plans recognized in other comprehensive income consisted of the following: \n\n \n\n2025\n\n2024\n\n(€ million)\n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans and other\n\nTotal\n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans and other\n\nTotal\n\nActuarial (gain)/loss due to changes in demographic assumptions\n\n \n\n(7)\n\n \n\n(7)\n\n \n\n(1)\n\n \n\n(1)\n\nActuarial (gain)/loss due to changes in financial assumptions\n\n(1)\n\n \n\n(1)\n\n(2)\n\n \n\n(22)\n\n \n\n(22)\n\nExperience (gain)/loss\n\n(3)\n\n14\n\n(1)\n\n10\n\n(1)\n\n1\n\n(2)\n\n(2)\n\nReturn on plan assets\n\n \n\n8\n\n \n\n8\n\n \n\n17\n\n \n\n17\n\nChanges in asset ceiling\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRemeasurements\n\n(4)\n\n15\n\n(2)\n\n9\n\n(1)\n\n(5)\n\n(2)\n\n(8)\n\n \n\nPlan assets consisted of the following: \n\n(€ million)\n\nCash and cash equivalents\n\nEquity securities\n\nDebt securities\n\nReal estate\n\nDerivatives\n\nInvestment funds\n\nAssets held by insurance companies\n\nOther\n\nTotal\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nPlan assets with a quoted market price:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- with a quoted market price\n\n9\n\n24\n\n126\n\n11\n\n41\n\n \n\n4\n\n15\n\n230\n\n- without a quoted market price\n\n \n\n \n\n \n\n \n\n \n\n \n\n30\n\n \n\n30\n\n \n\n9\n\n24\n\n126\n\n11\n\n41\n\n \n\n34\n\n15\n\n260\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nPlan assets with a quoted market price:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- with a quoted market price\n\n4\n\n25\n\n125\n\n11\n\n43\n\n1\n\n32\n\n19\n\n260\n\n- without a quoted market price\n\n \n\n \n\n \n\n \n\n \n\n \n\n3\n\n \n\n3\n\n \n\n4\n\n25\n\n125\n\n11\n\n43\n\n1\n\n35\n\n19\n\n263\n\n \n\nF-65\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for the following year consisted of:\n\n \n\n \n\n \n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans\n\nand other\n\nOther benefit plans\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nDiscount rate\n\n(%)\n\n3.2\n\n1.3\n\n-\n\n20.5\n\n3.2\n\n2.4\n\n-\n\n3.2\n\nRate of compensation increase\n\n(%)\n\n3.0\n\n2.0\n\n-\n\n19.7\n\n \n\n \n\n \n\n \n\nRate of price inflation\n\n(%)\n\n2.0\n\n1.0\n\n-\n\n14.0\n\n2.0\n\n \n\n \n\n2.0\n\nLife expectations on retirement at age 65\n\n(years)\n\n \n\n14\n\n-\n\n24\n\n24\n\n \n\n \n\n \n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nDiscount rate\n\n(%)\n\n3.1\n\n1.1\n\n-\n\n26.1\n\n3.1\n\n2.8\n\n-\n\n3.1\n\nRate of compensation increase\n\n(%)\n\n3.0\n\n2.0\n\n-\n\n15.0\n\n \n\n \n\n \n\n \n\nRate of price inflation\n\n(%)\n\n2.0\n\n1.0\n\n-\n\n14.0\n\n2.0\n\n \n\n \n\n2.0\n\nLife expectations on retirement at age 65\n\n(years)\n\n \n\n14\n\n-\n\n24\n\n24\n\n \n\n \n\n \n\n \n\nThe following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans:\n\n \n\n \n\nEuro\n\narea\n\nRest of\n\nEurope\n\nAfrica\n\nOther\n\nareas\n\nForeign defined benefit plans\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nDiscount rate\n\n(%)\n\n3.4\n\n-\n\n4.2\n\n1.3\n\n-\n\n5.5\n\n4.0\n\n-\n\n20.5\n\n \n\n1.3\n\n-\n\n20.5\n\nRate of compensation increase\n\n(%)\n\n2.0\n\n-\n\n3.4\n\n \n\n \n\n2.8\n\n5.0\n\n-\n\n19.7\n\n \n\n2.0\n\n-\n\n19.7\n\nRate of price inflation\n\n(%)\n\n \n\n \n\n2.0\n\n1.0\n\n-\n\n3.1\n\n3.0\n\n-\n\n14.0\n\n \n\n1.0\n\n-\n\n14.0\n\nLife expectations on retirement at age 65\n\n(years)\n\n21\n\n-\n\n23\n\n22\n\n-\n\n24\n\n14\n\n-\n\n18\n\n \n\n14\n\n-\n\n24\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nDiscount rate\n\n(%)\n\n3.2\n\n-\n\n3.6\n\n1.1\n\n-\n\n5.5\n\n3.3\n\n-\n\n26.1\n\n7.1\n\n1.1\n\n-\n\n26.1\n\nRate of compensation increase\n\n(%)\n\n2.0\n\n-\n\n3.4\n\n \n\n \n\n2.8\n\n5.0\n\n-\n\n15.0\n\n5.0\n\n2.0\n\n-\n\n15.0\n\nRate of price inflation\n\n(%)\n\n \n\n \n\n2.0\n\n1.0\n\n-\n\n3.5\n\n3.0\n\n-\n\n14.0\n\n3.5\n\n1.0\n\n-\n\n14.0\n\nLife expectations on retirement at age 65\n\n(years)\n\n21\n\n-\n\n23\n\n23\n\n-\n\n24\n\n14\n\n-\n\n18\n\n \n\n14\n\n-\n\n24\n\n \n\nThe effects of a possible change in the main actuarial assumptions at the end of the year are not material.\n\nThe contributions expected to be paid for employee benefit plans in the next year amounted to €130 million, of which €40 million related to defined benefit plans.\n\nThe following is an analysis by maturity date of the liabilities for employee benefit plans and their relative weighted-average duration:\n\n(€ million)\n\n \n\nItalian defined benefit plans\n\nForeign defined benefit plans\n\nFISDE, foreign medical plans and other\n\nOther benefit plans\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\n \n\n2026\n\n \n\n18\n\n17\n\n8\n\n90\n\n2027\n\n \n\n16\n\n25\n\n8\n\n79\n\n2028\n\n \n\n17\n\n19\n\n8\n\n64\n\n2029\n\n \n\n18\n\n21\n\n7\n\n5\n\n2030\n\n \n\n18\n\n20\n\n7\n\n3\n\n2031 and thereafter\n\n \n\n56\n\n245\n\n74\n\n11\n\nWeighted average duration (years)\n\n \n\n5.8\n\n12.4\n\n10.9\n\n2.1\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\n \n\n2025\n\n \n\n19\n\n24\n\n8\n\n108\n\n2026\n\n \n\n16\n\n26\n\n7\n\n92\n\n2027\n\n \n\n16\n\n21\n\n7\n\n80\n\n2028\n\n \n\n17\n\n16\n\n7\n\n13\n\n2029\n\n \n\n18\n\n19\n\n7\n\n5\n\n2030 and thereafter\n\n \n\n65\n\n263\n\n76\n\n12\n\nWeighted average duration (years)\n\n \n\n6.1\n\n13.1\n\n11.3\n\n2.1\n\n \n\nF-66\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n23 Deferred tax assets and liabilities\n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nDeferred tax liabilities before offsetting\n\n6,937\n\n8,724\n\nDeferred tax assets available for offset\n\n(2,132)\n\n(3,143)\n\nDeferred tax liabilities\n\n4,805\n\n5,581\n\nDeferred tax assets before offsetting (net of accumulated write-down provisions)\n\n8,848\n\n9,465\n\nDeferred tax liabilities available for offset\n\n(2,132)\n\n(3,143)\n\nDeferred tax assets\n\n6,716\n\n6,322\n\nThe most significant temporary differences giving rise to net deferred tax assets and liabilities are disclosed below:\n\n(€ million)\n\nDecember 31, 2025\n\nDecember 31, 2024\n\nDeferred tax liabilities\n\n \n\n \n\nAccelerated tax depreciation\n\n4,875\n\n5,755\n\nLeasing\n\n297\n\n354\n\nSite restoration and abandonment (tangible assets)\n\n269\n\n368\n\nDifference between the fair value and the carrying amount of assets acquired\n\n108\n\n858\n\nDerivative financial instruments\n\n80\n\n44\n\nApplication of the weighted average cost method in evaluation of inventories\n\n20\n\n20\n\nOther\n\n1,288\n\n1,325\n\n \n\n6,937\n\n8,724\n\nDeferred tax assets\n\n \n\n \n\nCarry-forward tax losses\n\n(4,746)\n\n(5,018)\n\nSite restoration and abandonment (provisions for contingencies)\n\n(1,953)\n\n(2,148)\n\nTiming differences on depreciation and amortization\n\n(1,738)\n\n(1,847)\n\nAccruals for impairment losses and provisions for contingencies\n\n(1,329)\n\n(1,432)\n\nAsset Impairment losses\n\n(1,378)\n\n(1,320)\n\nDerivative financial instruments\n\n(104)\n\n(352)\n\nLeasing\n\n(268)\n\n(338)\n\nEmployee benefits\n\n(134)\n\n(151)\n\nOver/Under lifting\n\n(89)\n\n(120)\n\nUnrealized intercompany profits\n\n(71)\n\n(77)\n\nOther\n\n(1,193)\n\n(1,313)\n\n \n\n(13,003)\n\n(14,116)\n\nAccumulated write-downs of deferred tax assets\n\n4,155\n\n4,651\n\nDeferred tax assets, net of accumulated write-downs\n\n(8,848)\n\n(9,465)\n\n \n\nF-67\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe following table summarizes the changes in deferred tax liabilities and assets:\n\n(€ million)\n\nDeferred tax liabilities before offsetting\n\nDeferred tax assets before offsetting,  gross\n\nAccumulated  write-downs of deferred tax  assets\n\nDeferred tax assets before offsetting net of accumulated write-down provisions\n\nAt December 31, 2024\n\n8,724\n\n(14,116)\n\n4,651\n\n(9,465)\n\nAdditions\n\n506\n\n(2,628)\n\n528\n\n(2,100)\n\nDeductions\n\n(600)\n\n1,469\n\n(60)\n\n1,409\n\nChanges with effect to OCI\n\n77\n\n173\n\n \n\n173\n\nCurrency translation differences\n\n(897)\n\n679\n\n(245)\n\n434\n\nChange in scope of consolidation\n\n1\n\n3\n\n \n\n3\n\nOther changes\n\n(874)\n\n1,417\n\n(719)\n\n698\n\nAt December 31, 2025\n\n6,937\n\n(13,003)\n\n4,155\n\n(8,848)\n\nAt December 31, 2023\n\n8,461\n\n(13,909)\n\n5,668\n\n(8,241)\n\nAdditions\n\n946\n\n(1,862)\n\n457\n\n(1,405)\n\nDeductions\n\n(1,042)\n\n2,176\n\n(1,663)\n\n513\n\nChanges with effect to OCI\n\n(351)\n\n92\n\n \n\n92\n\nCurrency translation differences\n\n484\n\n(384)\n\n121\n\n(263)\n\nChange in scope of consolidation\n\n193\n\n156\n\n(168)\n\n(12)\n\nOther changes\n\n33\n\n(385)\n\n236\n\n(149)\n\nAt December 31, 2024\n\n8,724\n\n(14,116)\n\n4,651\n\n(9,465)\n\n \n\nCarry-forward tax losses amounted to €18,575 million, of which €15,432 million can be carried forward indefinitely. Carry-forward tax losses were €10,841 million at Italian subsidiaries and €7,734 million at foreign subsidiaries. Deferred tax assets gross of accumulated write-downs recognized on these losses amounted to €2,602million and €2,144 million, respectively.\n\nThe 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 24% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses. The corresponding average rate for foreign subsidiaries was 27.7%.\n\nAccumulated write-downs of deferred tax assets related to Italian companies for €2,134 million and non-Italian companies for €2,021 million.\n\nTaxes are also described in note 33 – Income taxes.\n\n \n\nF-68\n\n[Table of Contents](#TOC_TableofContent) \n\n \n\n24 Derivative financial instruments and hedge accounting\n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nFair value  asset\n\nFair value liability\n\nLevel of Fair value\n\nFair value  asset\n\nFair value liability\n\nLevel of Fair value\n\nNon-hedging derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on interest rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Interest rate swap\n\n41\n\n18\n\n2\n\n20\n\n27\n\n2\n\n- Other\n\n1\n\n \n\n2\n\n \n\n \n\n \n\n \n\n42\n\n18\n\n \n\n20\n\n27\n\n \n\nDerivatives on exchange rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Currency swap\n\n26\n\n72\n\n2\n\n233\n\n33\n\n2\n\n- Interest currency swap\n\n5\n\n2\n\n2\n\n \n\n125\n\n2\n\n- Outright\n\n \n\n11\n\n2\n\n3\n\n24\n\n2\n\n \n\n31\n\n85\n\n \n\n236\n\n182\n\n \n\nDerivatives on commodities\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Over the counter\n\n633\n\n767\n\n2\n\n632\n\n923\n\n2\n\n- Future\n\n816\n\n999\n\n1\n\n1,429\n\n1,538\n\n1\n\n- Options\n\n11\n\n22\n\n1\n\n61\n\n111\n\n2\n\n- Other\n\n6\n\n \n\n2\n\n \n\n8\n\n2\n\n \n\n1,466\n\n1,788\n\n \n\n2,122\n\n2,580\n\n \n\n \n\n1,539\n\n1,891\n\n \n\n2,378\n\n2,789\n\n \n\nFair value hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on interest rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Interest rate swap\n\n38\n\n \n\n2\n\n42\n\n \n\n2\n\n \n\n38\n\n \n\n \n\n42\n\n \n\n \n\nDerivatives on exchange rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Outright\n\n \n\n \n\n \n\n2\n\n \n\n1\n\n \n\n \n\n \n\n \n\n2\n\n \n\n \n\n \n\n38\n\n \n\n \n\n44\n\n \n\n \n\nCash flow hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on commodities\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Over the counter\n\n167\n\n \n\n2\n\n20\n\n335\n\n2\n\n- Future\n\n256\n\n89\n\n1\n\n28\n\n421\n\n1\n\n- Other\n\n5\n\n105\n\n2\n\n \n\n \n\n \n\n \n\n428\n\n194\n\n \n\n48\n\n756\n\n \n\n \n\n428\n\n194\n\n \n\n48\n\n756\n\n \n\nOptions\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Other options\n\n \n\n21\n\n2\n\n \n\n37\n\n2\n\n \n\n \n\n21\n\n \n\n \n\n37\n\n \n\nGross amount\n\n2,005\n\n2,106\n\n \n\n2,470\n\n3,582\n\n \n\nOffsetting\n\n(1,133)\n\n(1,133)\n\n \n\n(1,508)\n\n(1,508)\n\n \n\nNet amount\n\n872\n\n973\n\n \n\n962\n\n2,074\n\n \n\n- current\n\n791\n\n827\n\n \n\n874\n\n1,921\n\n \n\n- non-current\n\n81\n\n146\n\n \n\n88\n\n153\n\n \n\nEni 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, currencies or interest rates and, to a limited extent in compliance with internal authorization thresholds, with speculative purposes to profit from expected market trends.\n\nDerivatives fair values were estimated based on market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace.\n\nFair-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.\n\n \n\nF-69\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nFair-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 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.\n\nThe 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.\n\nIn 2025, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €2,326 million was hedged by using, in a fair value hedge relationship, positive exchange differences for €262 million resulting on a portion of bonds denominated in U.S. dollars amounting to €2,010 million.\n\nThe offsetting of financial derivatives primarily related to Eni Global Energy Markets SpA and Eni Trade & Biofuels SpA. \n\nDuring 2025, there were no transfers between the different hierarchy levels of fair value.\n\n \n\nHedging derivative instruments are disclosed below:\n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nNominal  amount of the hedging instrument\n\nChange in fair value (effective hedge)\n\nChange in fair value (ineffective hedge)\n\nNominal  amount of the hedging instrument\n\nChange in fair value (effective hedge)\n\nChange in fair value (ineffective hedge)\n\nCash flow hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on commodity\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Over the counter\n\n1,506\n\n448\n\n2\n\n1,753\n\n(524)\n\n13\n\n- Future\n\n3,472\n\n184\n\n1\n\n3,375\n\n(499)\n\n13\n\n \n\n4,978\n\n632\n\n3\n\n5,128\n\n(1,023)\n\n26\n\nOther cash flow hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Other\n\n \n\n \n\n \n\n348\n\n(12)\n\n \n\n \n\n \n\n \n\n \n\n348\n\n(12)\n\n \n\n \n\n4,978\n\n632\n\n3\n\n5,476\n\n(1,035)\n\n26\n\nFair value hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on interest rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Interest rate swap\n\n1,962\n\n(4)\n\n \n\n1,981\n\n42\n\n1\n\n \n\n1,962\n\n(4)\n\n \n\n1,981\n\n42\n\n1\n\nDerivatives on exchange rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Outright\n\n \n\n \n\n \n\n43\n\n2\n\n \n\n \n\n \n\n \n\n \n\n43\n\n2\n\n \n\n \n\n1,962\n\n(4)\n\n \n\n2,024\n\n44\n\n1\n\n \n\nF-70\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge and fair value hedge is provided below:\n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nChange of the underlying item used for the calculation of hedging ineffectiveness\n\nCFH reserve\n\nReclassification adjustments\n\nChange of the underlying item used for the calculation of hedging ineffectiveness\n\nCFH reserve\n\nReclassification adjustments\n\nCash flow hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nCommodity price risk\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Planned sales\n\n(600)\n\n10\n\n(233)\n\n1,023\n\n(850)\n\n(123)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOther cash flow hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\n- hedged flows\n\n(26)\n\n24\n\n \n\n12\n\n(12)\n\n \n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nNominal amount of the underlying item\n\nCumulative changes of the underlying item\n\nChanges of the underlying item\n\nNominal\n\namount of the underlying item\n\nCumulative changes of the underlying item\n\nChanges of the underlying item\n\nFair value hedge derivatives\n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on interest rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Financial liabilities\n\n2,008\n\n39\n\n(5)\n\n2,066\n\n44\n\n44\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nDerivatives on exchange rate\n\n \n\n \n\n \n\n \n\n \n\n \n\n- Investments\n\n \n\n \n\n \n\n43\n\n(2)\n\n(2)\n\n \n\nMore information is reported in note 28 — Guarantees, Commitments and Risks — Financial risks.\n\n \n\nEffects recognized in other operating profit (loss)\n\n \n\nOther operating profit (loss) related to derivative financial instruments on commodity was as follows:\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nNet income (loss) on cash flow hedging derivatives\n\n3\n\n26\n\n6\n\nNet income (loss) on other derivatives\n\n638\n\n(378)\n\n472\n\n \n\n641\n\n(352)\n\n478\n\nNet 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.\n\n \n\nNet 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.\n\nEffects recognized in finance income (loss)\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nDerivatives on exchange rate\n\n(86)\n\n310\n\n(63)\n\nDerivatives on interest rate\n\n6\n\n(32)\n\n2\n\n \n\n(80)\n\n278\n\n(61)\n\nNet 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.\n\nMore information is disclosed in note 36 – Transactions with related parties.\n\n \n\nF-71\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n25 Assets held for sale and liabilities directly associated with assets held for sale\n\nAs of December 31, 2025, assets held for sale of €8,005 million (€420 million at 31 December, 2024) and directly associated liabilities of €2,026 million (€195 million at 31 December, 2024) mainly concerned oil&gas assets in Indonesia, United Arab Emirates, Congo and Ivory Coast, which book value was aligned to the expected fair value, amounting to €6,924 million and €1,182 million, respectively. More information is provided in note 12 – Property, plant and equipment. The company Plenitude Production France SAS, acquired in December 2025 and comprising assets and liabilities of €1,078 million and €844 million respectively, falls within the category of subsidiaries acquired exclusively for the purpose of sale.\n\nDuring 2025, assets reclassified as held for sale in the 2024 relating to some oil&gas assets in Congo.\n\n \n\n26 Equity\n\nNon-controlling interest\n\n \n\nProfit (Loss)\n\nEquity\n\n(€ million)\n\n2025\n\n2024\n\nDecember 31,\n\n 2025\n\nDecember 31,\n\n2024\n\nEni Plenitude Group\n\n6\n\n54\n\n1,816\n\n491\n\nEni Marine Services SpA\n\n \n\n \n\n1,701\n\n1,924\n\nEnilive Group\n\n87\n\n \n\n860\n\n \n\nEniPower Group\n\n64\n\n85\n\n457\n\n446\n\nOthers\n\n(7)\n\n1\n\n13\n\n2\n\n \n\n150\n\n140\n\n4,847\n\n2,863\n\nOn March 6, 2025, Eni and the private equity fund KKR finalized KKR's investment in a 25% minority stake in its subsidiary Enilive, with total proceeds for Eni of €2,968 million, including a €500 million capital increase. Subsequently, on April 11, 2025, Eni and KKR completed a similar transaction for an additional 5% investment for €601 million. Following the transaction, KKR holds a total stake of 30% of Enilive’s share capital.\n\nOn March 31, 2025, Energy Infrastructure Partners (EIP) completed an increase in Plenitude's share capital, reaching a total of 10%. EIP's stake was increased through a capital increase of €209 million, which, taking into account the €588 million paid in March 2024, brings the total investment to approximately €800 million. On November 4, Eni and the private equity fund Ares Capital finalized a 20% minority interest in Plenitude's share capital for €2,003 million.\n\nMinority interests in Eni Marine Services SpA related to perpetual subordinated bonds issued in U.S. dollars to finance a Group’s major capital project in Congo. The perpetual subordinated bonds were recognized among minority interests in consideration of the Group’s unconditional right to avoid transferring cash or other financial assets to the bondholders. The carrying amount at December 31, 2025, was adjusted to the EUR/USD exchange rate, resulting in a decrease of €223 million.\n\n \n\nEquity attributable to equity holders of Eni\n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nShare capital\n\n4,005\n\n4,005\n\nRetained earnings\n\n33,209\n\n32,552\n\nCumulative currency translation differences\n\n1,936\n\n8,081\n\nOther reserves and equity instruments:\n\n \n\n \n\n- Perpetual subordinated bonds\n\n5,000\n\n5,000\n\n- Legal reserve\n\n959\n\n959\n\n- Reserve for treasury shares\n\n2,782\n\n2,883\n\n- Reserve for OCI on cash flow hedging derivatives net of tax effect\n\n42\n\n(612)\n\n- Reserve for OCI on defined benefit plans net of tax effect\n\n(94)\n\n(91)\n\n- Reserve for OCI on equity-accounted investments\n\n92\n\n28\n\n- Reserve for OCI on other investments valued at fair value\n\n104\n\n160\n\n- Reserve for convertible bond issue\n\n79\n\n79\n\nTreasury shares\n\n(2,782)\n\n(2,883)\n\nProfit for the year\n\n2,608\n\n2,624\n\n \n\n47,940\n\n52,785\n\n \n\nShare capital\n\nAs of December 31, 2025, the parent company’s issued share capital consisted of €4,005,358,876 (same amount as of December 31, 2024) represented by 3,146,765,114 ordinary shares without nominal value (3,284,490,525 ordinary shares at December 31, 2024).\n\n \n\nF-72\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOn May 14, 2025, 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 2025 of €1.05 per share in four tranches, in September 2025 (€0.26 per share), November 2025 (€0.26 per share), March 2026 (€0.26 per share) and May 2026 (€0.27 per share); (ii) to authorize the Board of Directors pursuant to and for the purposes of Art. 2357 of the Italian Civil Code to proceed with the purchase of shares of the Company, in multiple tranches, for a period up to April 30, 2026, in a maximum number of shares to be purchased equal to 315,000,000 ordinary shares for a total outlay of up to €3.5 billion; (iii) to authorize the Board of Directors to cancel up to a maximum of 315,000,000 treasury shares which will eventually be acquired based on the shareholders' authorization of the previous point. In execution of these resolutions, as of December 31, 2025, 102,255,755 treasury shares have been acquired for a total value of €1,520 million.\n\n \n\nCumulative foreign currency translation differences\n\nThe cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.\n\nPerpetual subordinated hybrid bonds\n\nThe hybrid bonds are governed by the English law and are traded on the regulated market of the Luxembourg Stock Exchange. As of December 31, 2025, hybrid bonds amounted to €5 billion (same amount as at December 31, 2024).\n\nThe key characteristics of the hybrid bonds are: (i) an issue of €1.5 billion perpetual 9-year subordinated non-call hybrid notes with a re-offer price of 100% and an annual fixed coupon of 3.375% until the first reset date of October 13, 2029. As from such date, unless it has been redeemed in whole on or before the first reset date, which is the last day for the first optional redemption, the bond will bear interest per annum determined according to the relevant 5-year Euro Mid Swap rate plus an initial spread of 364.1 basis points, increased by additional 25 basis points as from October 13, 2034 and a subsequent increase of additional 75 basis points as from October 13, 2049; (ii) an issue of €1 billion subordinated hybrid perpetual bond with a 6-year non-call period, with a re-offer price at issuance of 100% and an annual coupon of 2% until the first reset date scheduled for May 11, 2027. If the early repayment has not taken place by the first reset date, which coincides with the last early repayment date, this bond pays annual interest equal to the reference five-year Euro Mid Swap rate increased by an initial margin of 220.4 basis points, increased by a further margin of 25 basis points starting from May 11, 2032 and a subsequent increase of a further 75 basis points starting from May 11, 2047; (iii) an issue of €1 billion subordinated hybrid perpetual bond with a 9-year non-call period, with a re-offer price at issuance of 99.607% and an annual coupon of 2.75% until the first reset date scheduled for May 11, 2030. If the early repayment has not taken place by the first reset date, which coincides with the last early repayment date, this bond pays annual interest equal to the reference five-year Euro Mid Swap rate increased by an initial margin of 277.1 basis points, increased by a further margin of 25 basis points starting from May 11, 2035 and a subsequent increase of a further 75 basis points starting from May 11, 2050; (iv) a subordinated hybrid perpetual issue of €900 million, with a re-offer price at issuance of 99.354% and an annual coupon of 4.5% until the first reset date scheduled 6.25 years after issuance (April 21, 2031). If the early repayment has not occurred, the annual coupon will be reset starting from April 21, 2031 and every 5 years thereafter, with a rate equal to the 5-year Euro Mid Swap in effect from time to time plus an initial spread of 208.3 basis points. This spread will be further increased by 25 basis points starting from April 21, 2036 and by a subsequent increase of a further 75 basis points starting from April 21, 2051; (v) a subordinated hybrid perpetual issue of €600 million, with a re-offer price at issuance of 99.114% and an annual coupon of 4.875% until the first reset date scheduled 9.25 years after issuance (April 21, 2034). If the early repayment has not occurred, the annual coupon will be reset starting from April 21, 2034 and every 5 years thereafter, with a rate equal to the 5-year Euro Mid Swap in effect from time to time plus an initial spread of 239.9 basis points. This spread will be further increased by 25 basis points starting from April 21, 2039 and by a subsequent increase of a further 75 basis points starting from April 21, 2054.\n\n \n\nLegal reserve\n\nThis 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.\n\nReserve for treasury shares\n\nThe 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.\n\n \n\nF-73\n\n[Table of Contents](#TOC_TableofContent)\n\nReserves for Other Comprehensive Income\n\n \n\nReserve for OCI on cash flow hedge derivatives\n\nReserve for OCI on  defined benefit plans\n\nReserve for OCI on equity-accounted investments (*)\n\nReserve for OCI on investments valued at fair value\n\n(€ million)\n\nGross reserve\n\nDeferred tax liabilities\n\nNet reserve\n\nGross reserve\n\nDeferred tax liabilities\n\nNet reserve\n\nReserve as of December 31, 2024\n\n(861)\n\n249\n\n(612)\n\n(121)\n\n30\n\n(91)\n\n28\n\n160\n\nChanges of the year\n\n661\n\n(197)\n\n464\n\n(11)\n\n2\n\n(9)\n\n73\n\n(32)\n\nCurrency translation differences\n\n3\n\n(1)\n\n2\n\n1\n\n(1)\n\n \n\n \n\n(19)\n\nChanges in scope of consolidation\n\nand non-controlling interest\n\n27\n\n(9)\n\n18\n\n8\n\n(2)\n\n6\n\n(9)\n\n(5)\n\nReversal to inventories adjustments\n\n5\n\n(1)\n\n4\n\n \n\n \n\n \n\n \n\n \n\nReclassification adjustments\n\n233\n\n(67)\n\n166\n\n \n\n \n\n \n\n \n\n \n\nReserve as of December 31, 2025\n\n68\n\n(26)\n\n42\n\n(123)\n\n29\n\n(94)\n\n92\n\n104\n\nReserve as of December 31, 2023\n\n50\n\n(14)\n\n36\n\n(94)\n\n6\n\n(88)\n\n98\n\n98\n\nChanges of the year\n\n(1,034)\n\n299\n\n(735)\n\n8\n\n(4)\n\n4\n\n(70)\n\n62\n\nCurrency translation differences\n\n \n\n \n\n \n\n(5)\n\n3\n\n(2)\n\n \n\n \n\nChanges in scope of consolidation\n\n \n\n \n\n \n\n(30)\n\n25\n\n(5)\n\n \n\n \n\nReclassification adjustments\n\n123\n\n(36)\n\n87\n\n \n\n \n\n \n\n \n\n \n\nReserve as of December 31, 2024\n\n(861)\n\n249\n\n(612)\n\n(121)\n\n30\n\n(91)\n\n28\n\n160\n\n(*) Reserve for OCI on equity-accounted investments at December 31, 2025 includes €1 million relating to defined benefit plans (same amount as of December 31, 2024)\n\nTreasury shares\n\nA total of 189,083,769 of Eni’s ordinary shares (203,137,967 at December 31, 2024) were held in treasury for a total cost of €2,782 million (€2,883 million at December 31, 2024).\n\nDuring 2025, 128,453,526 shares were acquired, for a total value of €1,881 million, as part of the completion of the 2024 buy-back plan and the execution of the €1.8 billion 2025 program 84% completed at the balance sheet date, in compliance with the shareholders' authorizations; 137,725,411 treasury shares have been cancelled for a total value of €1,908 million and 1,492,968 treasury shares were assigned free of charge to Eni managers, following the conclusion of the Vesting Period as required by the “Long-Term Monetary Incentive Plan 2020-2022” approved by Eni's Shareholders' Meeting of May 13, 2020 and 3,289,345 treasury shares were assigned free of charge to Eni employees as provided for in the 2024-2026 Employee Stock Ownership Plan approved by the Shareholders’ Meeting on May 15, 2024. The vesting and performance conditions of long-term incentive plans are reported in note 30 – Costs.\n\n \n\nDistributable reserves\n\nAs of December 31, 2025, equity attributable to Eni included distributable reserves of approximately €38 billion.\n\n \n\nReconciliation of profit and equity of the parent company Eni SpA to the consolidated profit and equity\n\n \n\n \n\nProfit\n\nShareholders’ equity\n\n(€ million)\n\n2025\n\n2024\n\nDecember 31, 2025\n\nDecember 31, 2024\n\nAs recorded in Eni SpA's Financial Statements\n\n4,429\n\n6,419\n\n50,986\n\n50,735\n\nExcess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company\n\n(1,643)\n\n(2,029)\n\n1,643\n\n4,338\n\nConsolidation adjustments:\n\n \n\n \n\n \n\n \n\n- difference between purchase cost and underlying carrying amounts of net equity\n\n \n\n \n\n153\n\n153\n\n- adjustments to comply with Group accounting policies\n\n(285)\n\n(1,722)\n\n425\n\n1,240\n\n- elimination of unrealized intercompany profits\n\n219\n\n(80)\n\n(301)\n\n(537)\n\n- deferred taxation\n\n38\n\n176\n\n(119)\n\n(281)\n\n \n\n2,758\n\n2,764\n\n52,787\n\n55,648\n\nNon-controlling interest\n\n(150)\n\n(140)\n\n(4,847)\n\n(2,863)\n\nAs recorded in Consolidated Financial Statements\n\n2,608\n\n2,624\n\n47,940\n\n52,785\n\n \n\nF-74\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n27 Other information\n\n \n\nSupplemental cash flow information\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nInvestment in consolidated subsidiaries and businesses\n\n \n\n \n\n \n\nCurrent assets\n\n \n\n486\n\n408\n\nNon-current assets\n\n1,040\n\n3,863\n\n1,985\n\nNet borrowings\n\n(724)\n\n(468)\n\n(91)\n\nCurrent and non-current liabilities\n\n(82)\n\n(1,825)\n\n(622)\n\nNet effect of investments\n\n234\n\n2,056\n\n1,680\n\nGoodwill\n\n \n\n33\n\n25\n\nFair value of investments held before the acquisition of control\n\n \n\n(28)\n\n(271)\n\nNon-controlling interests\n\n \n\n(1)\n\n(2)\n\nPurchase price\n\n234\n\n2,060\n\n1,432\n\nless:\n\n \n\n \n\n \n\nCash and cash equivalents acquired\n\n(38)\n\n(265)\n\n(155)\n\nConsolidated subsidiaries and businesses net of cash and cash equivalent acquired\n\n196\n\n1,795\n\n1,277\n\n \n\n \n\n \n\n \n\nDisposal of consolidated subsidiaries and businesses\n\n \n\n \n\n \n\nCurrent assets\n\n85\n\n802\n\n130\n\nNon-current assets\n\n657\n\n2,695\n\n153\n\nNet borrowings\n\n(322)\n\n101\n\n180\n\nCurrent and non-current liabilities\n\n(196)\n\n(2,267)\n\n(124)\n\nNet effect of disposals\n\n224\n\n1,331\n\n339\n\nCurrent value of the stake held for business combinations\n\n(138)\n\n(788)\n\n(580)\n\nReclassification among other items of OCI\n\n \n\n \n\n(7)\n\nGain on disposal of business combinations\n\n45\n\n379\n\n427\n\nFair value of share capital held after the sale of control\n\n27\n\n118\n\n414\n\nCredits for divestments\n\n \n\n \n\n(173)\n\nSelling price\n\n158\n\n1,040\n\n420\n\nless:\n\n \n\n \n\n \n\nCash and cash equivalents sold\n\n(40)\n\n(153)\n\n(25)\n\nConsolidated subsidiaries and businesses net of cash and cash equivalent disposed of before business combination\n\n118\n\n887\n\n395\n\n \n\nF-75\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nInvestments and disposals in 2025 are disclosed in note 5 – Business combinations and other significant transactions.\n\nBusiness combinations and other significant transactions\n\nThe provisional and definitive price allocation of the net assets acquired in 2024 is shown below:\n\n(€ million)\n\nPlenitude - Renewable energies and retail\n\n(Provisional allocation)\n\nPlenitude - Renewable energies and retail\n\n(Definitive allocation)\n\nEnilive - Atenoil\n\n(Provisional allocation)\n\nEnilive - Atenoil\n\n(Definitive allocation)\n\nCurrent assets\n\n5\n\n5\n\n5\n\n5\n\nProperty, plant and equipment\n\n71\n\n71\n\n14\n\n30\n\nGoodwill\n\n5\n\n5\n\n28\n\n23\n\nOther non-current assets\n\n52\n\n52\n\n23\n\n17\n\nCash and cash equivalent\n\n(Net borrowings)\n\n(53)\n\n(53)\n\n(10)\n\n(10)\n\nCurrent and non-current liabilities\n\n(5)\n\n(5)\n\n(10)\n\n(15)\n\nNet effects of investments\n\n75\n\n75\n\n50\n\n50\n\nFollowing the definitive allocation of the 2024 business combinations, financial statements were not restated taking into account the immateriality of the changes.\n\n \n\nF-76\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n28 Guarantees, commitments and risks\n\n \n\nGuarantees\n\n \n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nAssociates\n\n6,694\n\n9,063\n\nJoint ventures\n\n1,473\n\n165\n\nOthers\n\n634\n\n424\n\n \n\n8,801\n\n9,652\n\n \n\nIn 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. 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 reported value 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).\n\n \n\nThe decrease of €851 million was mainly due to the termination of the guarantees issued to banks and to the Mozambican State oil company ENH on behalf of the financing consortium for the development of gas reserves of the Coral discovery (€1,710 million). This decrease was partially offset by the issuance of new guarantees in connection with the sale of 49.99% of CCUS activities in the United Kingdom and the Netherlands to a private equity fund (€1,218 million).\n\n \n\nAt December 31, 2025, the underlying commitment relating to the guarantees issued was €5,223 million (€5,790 million at December 31, 2024), which takes into account the progress of the activities and the repaid obligations.\n\n \n\nAlso 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.\n\n \n\nF-77\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCommitments and risks\n\n \n\n(€ million)\n\nDecember 31,  2025\n\nDecember 31,  2024\n\nCommitments\n\n77,006\n\n84,129\n\nRisks\n\n856\n\n1,046\n\n \n\n77,862\n\n85,175\n\n \n\nCommitments 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 €72,797 million (€79,858 million at December 31, 2024). The decrease of €7,061 million was mainly due to currency translation differences and the closure of the parent company guarantee relating to Eni RAK BV (€1,924 million); (ii) a parent company guarantee of €3,402 million (€3,849 million at December 31, 2024) issued on behalf of Eni Abu Dhabi Refining & Trading BV following the Share Purchase Agreement to acquire from Abu Dhabi National Oil Company (ADNOC) a 20% equity interest in ADNOC Refining and the set-up of the joint venture ADNOC Global Trading Ltd dedicated to marketing petroleum products. The parent company guarantee will remain in force as long as the shareholding is maintained; (iii) commitments in the Plenitude business line for the purchase of renewable energy projects in Italy and Spain for €560 million (€246 million at December 31, 2024).\n\nRisks related to: (i) assets of third parties under custody of Eni for €610 million (€772 million at December 31, 2024); (ii) contractual assurances given to acquirers of certain divestments and businesses of Eni for €236 million (€264 million at December 31, 2024).\n\nOther commitments and risks\n\nOther 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 experts specialized in forest conservation programs.\n\nIn addition, following the sale of equity investments and businesses or loss of control transactions, Eni is exposed to non-quantifiable risks 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 risks will not have a material adverse effect on Eni’s results of consolidated financial statements.\n\nRegarding take-or-pay supply contracts with Russian state-owned companies (Gazprom and its affiliates), since 2023, Eni has ceased to withdraw natural gas from existing contracts with Gazprom for sale in EU markets due to various commercial disputes between the parties. Eni expects this situation to continue into 2026.\n\nIn relation to oil and gas asset sales, including transactions concluded in previous years, decommissioning obligations may revert to the seller if the buyer fails to fulfill these obligations.\n\nRisk factors\n\nThe 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.\n\nAs of December 31, 2025, the Company retains liquidity reserves that management deems enough to meet the financial obligations due in the next eighteen months.\n\n \n\nF-78\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nFinancial risks\n\n \n\nFinancial 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.\n\nMarket risk\n\n \n\nMarket 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 derivatives 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 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 to minimize exposure to market risks related to transactional exchange rates and interest rates, as well as to optimize exposure to commodity prices risk considering 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, 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’s Group operating 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.\n\n \n\nAccording 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.\n\n \n\nF-79\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nMarket risk - Exchange rate\n\nExchange 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 risk management objective is to minimize transactional exchange rate risk and optimize economic exchange rate risk associated with commodity price risk. The risk arising from the accrual of operating income in foreign currency or from the conversion of 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.\n\nEffective management of exchange rate risk is performed within Eni’s finance department, which pools 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 resulting from the centralization of Eni's exchange rate risk positions within the Eni Corporate Finance Structures is calculated on a daily basis according to the parametric approach (variance/covariance), adopting a confidence level of 99% and a 1-day holding period.\n\nMarket risk - Interest rate\n\nChanges 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.\n\nEni’s interest rate risk management policy is to minimize the risk in pursuit of the financial structure objectives defined and approved in management’s Financial Plan. Eni’s finance department pools borrowing requirements of the Group companies to manage net positions and fund portfolio developments consistent with the Financial Plan, thereby maintaining a level of risk exposure within prescribed limits. Eni enters 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 by specialized sources. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 1-day holding period.\n\n \n\nMarket risk - Commodity\n\nCommodity price risk is identified as the possibility that fluctuations in the price of raw materials and basic products produce significant changes in Eni’s operating margins, determining an impact on the economic result such as compromising 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 2026-2030 industrial 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 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 department 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 95% confidence level and a 1-day holding period.\n\n \n\nF-80\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nMarket risk - Strategic liquidity\n\nMarket 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 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 24 months. In order to manage the investment activity of the strategic liquidity, Eni defined a specific investment policy with aims and constraints in terms of the type of financial instruments that can be invested in, and operational limits, as well as governance guidelines regulating management and control systems. In particular, strategic liquidity management is regulated in terms of VaR (measured based on a parametrical methodology with a one-day holding period and a 99% confidence level), stop loss and other operating limits in terms of concentration, issuing entity, business segment, country of emission, duration, ratings and type of investing instruments in portfolio, aimed to minimize market and liquidity risks. Financial leverage or short selling is not allowed. As of 31 December 2025, the average rating of the Strategic liquidity investment portfolio was A/A-, in line compared to the end of 2024.\n\nThe following tables show amounts in terms of VaR, recorded in 2025 (compared with 2024), 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 the interest rate.\n\n(Value at risk - parametric method variance/covariance; holding period: 1 day; confidence level: 99%)\n\n \n\n \n\n2025\n\n \n\n2024\n\n(€ million)\n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\n \n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\nInterest rate (a)\n\n10.29\n\n4.45\n\n7.48\n\n4.45\n\n \n\n13.03\n\n3.92\n\n5.95\n\n7.50\n\nExchange rate (a)\n\n7.99\n\n0.07\n\n2.07\n\n0.43\n\n \n\n5.47\n\n0.07\n\n1.65\n\n0.69\n\n \n\n(a) Value at Risk deriving from interest and exchange rates exposures includes the following finance departments: Eni Corporate Finance Department and Banque Eni SA.\n\n \n\n(Value at risk - Historic simulation method; holding period: 1 day; confidence level: 95%)\n\n \n\n \n\n2025\n\n \n\n2024\n\n(€ million)\n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\n \n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\nCommercial exposures - Management Portfolio (a)\n\n34.93\n\n2.79\n\n16.37\n\n2.79\n\n \n\n69.66\n\n6.20\n\n24.10\n\n6.32\n\nTrading (b)\n\n1.34\n\n0.30\n\n0.63\n\n0.37\n\n \n\n1.74\n\n0.21\n\n0.53\n\n0.31\n\n \n\n(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 Balance Sheet year, including 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.\n\n(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.\n\n \n\n(Sensitivity - Dollar value of 1 basis point - DVBP)\n\n \n\n \n\n2025\n\n \n\n2024\n\n(€ million)\n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\n \n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\nStrategic liquidity - € Portfolio\n\n0.64\n\n0.53\n\n0.58\n\n0.54\n\n \n\n0.60\n\n0.20\n\n0.40\n\n0.60\n\n \n\n(Sensitivity - Dollar value of 1 basis point - DVBP)\n\n \n\n \n\n2025\n\n \n\n2024\n\n($ million)\n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\n \n\nHigh\n\nLow\n\nAverage\n\nAt year end\n\nStrategic liquidity - US dollar Portfolio\n\n0.18\n\n0.12\n\n0.15\n\n0.16\n\n \n\n0.20\n\n0.10\n\n0.10\n\n0.10\n\n \n\nF-81\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCredit risk\n\nCredit 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.\n\nCredit risk for commercial exposures\n\nCredit 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.\n\nCredit risk for financial exposures\n\nRegarding 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 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 groups to which it belongs, to check exposures against the limits assigned daily and the Expected Credit Loss analysis and the concentration periodically.\n\nLiquidity risk\n\nLiquidity risk is the risk that suitable sources of funding for the Group may not be available (funding liquidity risk), or the Group is unable to sell its assets in the marketplace (asset liquidity risk). 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.\n\nEni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €12.8 billion were drawn as of December 31, 2025.\n\nIn 2025, Standard & Poor’s assigned to the Group credit ratings of A- outlook Negative and A-2, respectively, for long and short-term debt; Moody's revised Eni's rating from Baa1 to A3 outlook Stable and assigned a rating of P-2 for short-term debt; Fitch assigned credit ratings A- outlook Stable and F1, respectively for long and short-term debt. Eni’s credit rating is linked, in addition to the Company’s industrial fundamentals and trends in the trading environment, to the Italy’s sovereign rating.\n\nAs of December 31, 2025, available committed borrowing facilities amounted to €9 billion.\n\n \n\nF-82\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nExpected payments for financial debts, lease liabilities, trade and other payables\n\n \n\nThe 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.\n\n \n\nMaturity year\n\n(€ million)\n\n2026\n\n2027\n\n2028\n\n2029\n\n2030\n\n2031 and thereafter\n\nTotal\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFinancial liabilities\n\n7,982\n\n2,793\n\n5,492\n\n1,944\n\n2,139\n\n7,908\n\n28,258\n\nLease liabilities\n\n1,250\n\n751\n\n581\n\n478\n\n434\n\n2,241\n\n5,735\n\nFair value of derivative instruments\n\n827\n\n41\n\n23\n\n14\n\n12\n\n56\n\n973\n\n \n\n10,059\n\n3,585\n\n6,096\n\n2,436\n\n2,585\n\n10,205\n\n34,966\n\nInterest on finance debt\n\n811\n\n699\n\n595\n\n418\n\n360\n\n2,529\n\n5,412\n\nInterest on lease liabilities\n\n302\n\n244\n\n206\n\n176\n\n150\n\n553\n\n1,631\n\n \n\n1,113\n\n943\n\n801\n\n594\n\n510\n\n3,082\n\n7,043\n\nFinancial guarantees\n\n4\n\n \n\n \n\n \n\n \n\n \n\n4\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nMaturity year\n\n(€ million)\n\n2025\n\n2026\n\n2027\n\n2028\n\n2029\n\n2030 and thereafter\n\nTotal\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFinancial liabilities\n\n8,370\n\n2,410\n\n2,815\n\n5,568\n\n2,018\n\n8,916\n\n30,097\n\nLease liabilities\n\n1,261\n\n781\n\n663\n\n572\n\n468\n\n2,688\n\n6,433\n\nFair value of derivative instruments\n\n1,921\n\n31\n\n6\n\n48\n\n4\n\n64\n\n2,074\n\n \n\n11,552\n\n3,222\n\n3,484\n\n6,188\n\n2,490\n\n11,668\n\n38,604\n\nInterest on finance debt\n\n880\n\n705\n\n661\n\n552\n\n369\n\n2,786\n\n5,953\n\nInterest on lease liabilities\n\n336\n\n284\n\n248\n\n212\n\n184\n\n708\n\n1,972\n\n \n\n1,216\n\n989\n\n909\n\n764\n\n553\n\n3,494\n\n7,925\n\nFinancial guarantees\n\n1,106\n\n \n\n \n\n \n\n \n\n \n\n1,106\n\n \n\nLiabilities for leased assets including interest charges for €1,082 million (€925 million at December 31, 2024) pertained to the share of joint operators participating in unincorporated joint operation operated by Eni which will be recovered through a partner-billing process.\n\nThe €1,102 million decrease in financial guarantees was due to the termination of independent contracts issued to banks and the Mozambican state oil company ENH on behalf of the consortium of financiers with which the project financing for the development of the Coral discovery's gas reserves was structured.\n\nThe table below presents the timing of the expenditures for trade and other payables.\n\n \n\n \n\nMaturity year\n\n(€ million)\n\n2026\n\n2027 - 2030\n\n2031 and thereafter\n\nTotal\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\nTrade payables\n\n13,901\n\n \n\n \n\n13,901\n\nOther payables and advances\n\n6,360\n\n74\n\n111\n\n6,545\n\n \n\n20,261\n\n74\n\n111\n\n20,446\n\n \n\n \n\n \n\n \n\n \n\n \n\nMaturity year\n\n(€ million)\n\n2025\n\n2026 - 2029\n\n2030 and thereafter\n\nTotal\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\nTrade payables\n\n15,170\n\n \n\n \n\n15,170\n\nOther payables and advances\n\n6,922\n\n59\n\n121\n\n7,102\n\n \n\n22,092\n\n59\n\n121\n\n22,272\n\n \n\nF-83\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nExpected payments under contractual obligations23\n\nIn 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.\n\nThe 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 2026-2030 industrial plan approved by the Company’s management and for subsequent years on the basis of management’s long-term assumptions.\n\nThe 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 2026 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.\n\n \n\n \n\nMaturity year\n\n(€ million)\n\n2026\n\n2027\n\n2028\n\n2029\n\n2030\n\n2031 and thereafter\n\nTotal\n\nDecommissioning liabilities (a)\n\n911\n\n748\n\n581\n\n539\n\n565\n\n10,362\n\n13,706\n\nEnvironmental liabilities\n\n812\n\n563\n\n438\n\n341\n\n319\n\n1,099\n\n3,572\n\nPurchase obligations (b)\n\n16,750\n\n13,397\n\n12,393\n\n11,372\n\n9,068\n\n62,467\n\n125,447\n\n- Gas\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n. take-or-pay contracts\n\n14,757\n\n12,643\n\n11,756\n\n11,138\n\n8,901\n\n62,230\n\n121,425\n\n. ship-or-pay contracts\n\n632\n\n271\n\n254\n\n225\n\n159\n\n211\n\n1,752\n\n- Other purchase obligations\n\n1,361\n\n483\n\n383\n\n9\n\n8\n\n26\n\n2,270\n\nOther obligations\n\n6\n\n15\n\n \n\n \n\n \n\n \n\n21\n\n- Memorandum of intent - Val d’Agri\n\n6\n\n15\n\n \n\n \n\n \n\n \n\n21\n\nTotal (c)\n\n18,479\n\n14,723\n\n13,412\n\n12,252\n\n9,952\n\n73,928\n\n142,746\n\n \n\n(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.\n\n(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\".\n\n(c) Expected payments under contractual obligations comprise obligations for site abandonment and restoration costs directly associated with assets held for sale for €404 million.\n\n \n\nCapital investment and capital expenditure commitments\n\nIn the 2026-2030 industrial plan, Eni expects investments and capital expenditures of €29 billion. The table below summarizes Eni’s full-life capital expenditure commitments for property, plant and equipment and capital projects at the closing date. A project is considered to be committed when it has received the appropriate level of internal management approval and for which procurement contracts have usually already been awarded or are being awarded.\n\nThe amounts shown in the table below include committed expenditures to execute certain environmental projects.\n\n \n\nMaturity year\n\n(€ million)\n\n2026\n\n2027\n\n2028\n\n2029\n\n2030\n\n2031 and thereafter\n\n Total\n\nCommitted projects\n\n6,250\n\n4,847\n\n3,932\n\n2,871\n\n1,984\n\n304\n\n20,188\n\n \n\n \n\n23 Contractual obligations related to employee benefits are indicated in note 22 - Provisions for employee benefits.\n\n \n\nF-84\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOther information about financial instruments\n\n \n\n \n\n2025\n\n \n\n2024\n\n \n\nCarrying amount\n\nIncome (expense) recognized in\n\n \n\nCarrying amount\n\nIncome (expense) recognized in\n\n(€ million)\n\nProfit and loss account\n\nOCI\n\n \n\nProfit and loss account\n\nOCI\n\nFinancial instruments at fair value with effects recognized in profit and loss account\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFinancial assets at fair value through profit or loss (a)\n\n6,991\n\n235\n\n \n\n \n\n6,797\n\n388\n\n \n\nNon-hedging and trading derivatives (b)\n\n(18)\n\n559\n\n \n\n \n\n(1,119)\n\n(73)\n\n \n\nOther investments valued at fair value (c)\n\n1,329\n\n242\n\n(30)\n\n \n\n1,395\n\n227\n\n62\n\nReceivables and payables and other assets/liabilities valued at amortized cost\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nTrade receivables and other (d)\n\n13,216\n\n(18)\n\n \n\n \n\n17,753\n\n(106)\n\n \n\nFinancing receivables (e)\n\n4,756\n\n(49)\n\n \n\n \n\n4,238\n\n233\n\n \n\nSecurities (a)\n\n63\n\n1\n\n \n\n \n\n62\n\n1\n\n \n\nTrade payables and other (a)\n\n20,446\n\n \n\n \n\n \n\n22,273\n\n(153)\n\n \n\nFinancing payables (f)\n\n28,502\n\n(296)\n\n \n\n \n\n30,390\n\n(1,176)\n\n \n\nNet assets (liabilities) for hedging derivatives (g)\n\n(83)\n\n(262)\n\n865\n\n \n\n7\n\n(95)\n\n(912)\n\n \n\n \n\n(a) Income or expense were recognized in the profit and loss account within \"Finance income (expense)\".\n\n(b) In the profit and loss account, economic effects were recognized as income within \"Other operating income (loss)\" for €641 million (loss for €352 million in 2024) and in the \"Finance income (expense)\".\n\n(c) Income or expense were recognized in the profit and loss account within \"Income (expense) from investments - Dividends\".\n\n(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 €11 million (net impairments for €168 million in 2024) and as expense within \"Finance income (expense)\" for €7 million (income for €62 million in 2024), including interest income calculated on the basis of the effective interest rate of €26 million (interest income for €27 million in 2024).\n\n(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 €222 million (interest income for €175 million in 2024) and net reversals for €1 million (net impairments for €22 million in 2024).\n\n(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 €861 million (interest expense for €897 million in 2024).\n\n(g) In the profit and loss account, income or expense were recognized within \"Sales from operations\", \"Purchase, services and other\" and “Finance income (expense)\".\n\n \n\nDisclosures about the offsetting of financial instruments\n\n(€ million)\n\nGross amount of financial assets and liabilities\n\nGross amount of financial assets and liabilities subject to offsetting\n\nNet amount of financial assets and liabilities\n\nDecember 31, 2025\n\n \n\n \n\n \n\nFinancial assets\n\n \n\n \n\n \n\nTrade and other receivables\n\n17,017\n\n4,581\n\n12,436\n\nOther current assets\n\n5,076\n\n1,133\n\n3,943\n\nOther non-current assets\n\n2,852\n\n13\n\n2,839\n\nFinancial liabilities\n\n \n\n \n\n \n\nTrade and other liabilities\n\n24,842\n\n4,581\n\n20,261\n\nOther current liabilities\n\n5,172\n\n1,133\n\n4,039\n\nOther non-current liabilities\n\n3,403\n\n13\n\n3,390\n\nDecember 31, 2024\n\n \n\n \n\n \n\nFinancial assets\n\n \n\n \n\n \n\nTrade and other receivables\n\n21,330\n\n4,429\n\n16,901\n\nOther current assets\n\n5,182\n\n1,520\n\n3,662\n\nOther non-current assets\n\n4,012\n\n1\n\n4,011\n\nFinancial liabilities\n\n \n\n \n\n \n\nTrade and other liabilities\n\n26,521\n\n4,429\n\n22,092\n\nOther current liabilities\n\n6,569\n\n1,520\n\n5,049\n\nOther non-current liabilities\n\n4,450\n\n1\n\n4,449\n\n \n\nThe offsetting of financial assets and liabilities related to: (i) receivables and payables pertaining to the Exploration & Production segment towards State entities for €4,581 million (€4,429 million at December 31, 2024); (ii) other current and non-current assets and liabilities for derivative financial instruments of €1,133 million (€1,508 million at December 31, 2024) and other assets and liabilities for €13 million (same amount as of December 31, 2024).\n\n \n\nF-85\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nLegal Proceedings\n\n \n\nEni 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.\n\n \n\nIn 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 has not determined that a negative outcome is probable or because the amount of the provision cannot be estimated reliably.\n\n \n\n1. Environment, health and safety\n\n \n\n1.1 Criminal proceedings in the matters of environment, health and safety\n\n \n\n(i) Eni Rewind SpA – Illegal landfill in Minciaredda area – Porto Torres site. In 2015, the Public Prosecutor of Sassari 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 natural persons allegedly liable of 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.\n\n \n\nIn 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.\n\n \n\nDue 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\n\n \n\n(ii) 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. 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 with 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. The proceeding was appealed by the Gela Public Prosecutor's Office. The case is pending to the First Instance Court of Caltanissetta.\n\n \n\n(iii) 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 full compliance of the plant and the industrial process with the requirements of the applicable laws, as well as with best available technologies and best international 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 €700,000, with the contextual confiscation of a sum of €44,248,071 deemed to constitute the unfair profit obtained from the crime, from which Eni will deduct the amount incurred for the plant upgrade carried out in 2016. Following the filing of the merits of the sentence by the Court, an appeal was promptly filed against all the condemnations. On February 19, 2026, the Court of Potenza issued a judgment of acquittal against Eni, pursuant to Legislative Decree No. 231/01, and its employees, also revoking the confiscation which had been ordered as an alleged unjust profit from the crime.\n\n \n\nF-86\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(iv) 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 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.\n\n \n\nThe 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 after 2015, the judge acknowledged the nullity of the request for indictment, thus returning the documents to the Public Prosecutor.\n\n \n\nFinally, 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.\n\n \n\nAs 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, remanding the trial to the preliminary stage, where the Public Prosecutor added the charges. Following the hearing, the judge ordered the Company to be sent for trial before the Court of Potenza.\n\n \n\n(v) 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 was transferred to the Court of Agrigento for territorial jurisdiction. On November 26, 2025, following the preliminary hearing, the Court of Agrigento issued a ruling acquitting EniMed’s acting CEO and the company itself, pursuant to Legislative Decree No. 231/01.\n\n \n\nF-87\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(vi) 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 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.\n\n \n\n(vii) 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.\n\n \n\nOn 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. The order by the judge of preliminary investigations of Syracuse denying authorization to continue production was subsequently revoked by the Court, allowing the petrochemical plant and wastewater treatment plant to operate normally. Meanwhile, the criminal proceeding is ongoing.\n\n \n\n(viii) 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 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 above-mentioned companies, with the exception of a former employee of Versalis and of two Edison employees. The proceeding is pending on the trial phase.\n\n \n\n(ix) 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.\n\n \n\nThe 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.\n\n \n\nF-88\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(x) 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.\n\n \n\n(xi) 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.\n\n \n\nOn November 28, 2023, the TAE plant was released from seizure. The Prosecutor's Office has ordered three unrepeatable technical investigations, during which there are further complaints regarding further environmental complaints. At the conclusion of the preliminary investigation phase, the allegations raised were confirmed.\n\n \n\n(xii) Eni SpA – Pomezia depot – Involuntary environmental pollution. A criminal proceeding is ongoing concerning an alleged crime of pollution of groundwater underlying the fuel depot in Pomezia attributable, according to the indictment, to product leaks from the tanks.\n\n \n\nThe Public Prosecutor's Office has appointed its consultants to carry out a technical review of the site to verify the state of environmental contamination 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.\n\n \n\nF-89\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(xiii) 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.\n\n \n\nThe 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 an estimate of the damage resulting from the event. The case is still pending in the preliminary investigation phase.\n\n \n\n(xiv) Enimed SpA – attempted environmental pollution. The investigation involves the last three CEOs of Enimed SpA and its employees who, since 2020, have held the positions of HSE and Permitting Manager, OPEM and TECEM Manager, Central Manager, Field Manager, and Plant Manager, as well as Enimed pursuant to Legislative Decree 231/01, for the alleged crime of complicity in attempted environmental pollution for having allegedly failed, each within their respective areas of responsibility, to adopt the appropriate precautions necessary to prevent the environmental dispersion, which did not occur, of the so-called fluxing product. On January 14, 2025, the Public Prosecutor's Office od Gela issued a notice of conclusion of the preliminary investigations and subsequently requested indictment. The proceedings are pending at the preliminary hearing stage.\n\n \n\n1.2 Civil and administrative proceedings in the matters of environment, health, safety and antitrust\n\n \n\n(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 29.25%). Rok is claiming a revision of the cost recovery of the companies in the period 2010-2020 and formally started the proceedings in March 2023 with the appointment of an arbitrator. In April 2024, Rok presented its statements of claim, and the proceeding is now underway. Regarding some of the objections raised by RoK, the arbitral tribunal issued a partial award partly in favor of RoK and partly in favor of the consortium, without quantification. Eni is evaluating the merit of these requests and therefore it is not possible to reliably estimate the outcome of the proceedings.\n\n(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 16.67%). The Claims advanced by the Republic refer to alleged violations of the NCSPSA, including cost recovery exceptions and failure to pursue development opportunities. In February 2026, the consortium initiated an ICSID arbitration to protect its investment in the face of RoK's complaints regarding sulfur management. Eni is continuing to evaluate the merit of the arbitration claims in light of the available investigative evidence and, therefore, it is not possible to estimate the outcome of the proceedings.\n\n(iii) Novamont SpA – Proceedings by the Italian Antitrust Authority against Novamont SpA and Eni SpA for alleged abuse of dominant position in the market of bioplastics. In 2024, ACGM initiated a proceeding against Novamont SpA, also notifying Eni SpA, for alleged abuse of dominant position in the bioplastics market, specifically bio compounds to produce plastic bags for large-scale retailers. On June 24, 2025, AGCM, confirming the charges formalized at the conclusion of the investigation against Novamont and Eni SpA, the latter for the period following the date of acquisition of control (October 18, 2023), imposed an administrative fine of €32 million (of which approximately €2 million jointly and severally between the two companies) for alleged abuses of dominant position in the relevant markets between January 1, 2018, and December 31, 2023. AGCM warned Novamont and Eni to cease their alleged behavior in violation of antitrust rules and provide proof of this to the Authority within a specified deadline. The Company believes to have valid arguments supporting the correctness of its actions to be asserted in the subsequent stages of opposition to the AGCM's decision; therefore, an appeal has been filed with the Regional Administrative Court of Lazio. A provision has been set aside to address this dispute.\n\n \n\nF-90\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(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 of 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 based on updated environmental data. The Eni’s subsidiary also commenced activities to identify the persons responsible for the pollution of the harbor and their respective shares of liability.\n\nIn 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 pollution was attributable to industrial activities of prior periods and that it would not spread into the surrounding environment.\n\nBetween 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.\n\n \n\n(v) 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.\n\nThe 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.\n\n \n\n(vi) 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 such 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.\n\nEni 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.\n\nEni Rewind appealed to a Regional Administrative Court against the Province claims and orders. Eni Rewind is carrying out 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 appealed the sentence. Discussions are underway with the companies involved to reach a transaction agreement regarding cleanup and remediating costs of the site.\n\n \n\nF-91\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(vii) 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 45% its emissions by 2030 compared to 2020 levels, or other appropriate measures to comply with the Paris Agreement) as well as the cessation of any harmful conducts.\n\n \n\nThe 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 appeared before the Third Instance Court. On January 30, 2026, the judge rejected the plaintiff's request to open an investigation phase. The proceeding is ongoing.\n\n \n\n(viii) 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 €48 million in addition to the execution of works which, according to the plaintiff, would be necessary to avoid and contain flooding caused by constructions created by NAOC. The application submitted reiterates complaints made in past years, including in 2017 before the National Contact Point envisaged by the OECD Guidelines addressed to Multinational enterprises, where an ad hoc conciliation procedure was initiated which ended with an agreement between the parties. The first hearing was held on December 10, 2024. At the hearing the judge unsuccessfully attempted conciliation and subsequently each party recalled what was deduced in the documents and Eni requested that the case be decided without further preliminary investigation. The Judge reserved the sentence.\n\n \n\nF-92\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(ix) 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 restrictions 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 work, 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. The ruling of the Regional Administrative Court of June 2025, while supporting the institutions’ position, does not represent a negative development, since the Ministry has initiated a procedure aimed at defining the modalities for the continuation of the environmental interventions.\n\n \n\n(x) Eni SpA – Proceedings by the Italian Antitrust Authority against Eni SpA for alleged collusion on fixing the price of the \"bio component\" of automotive fuels. A proceeding is pending before the Italian Antitrust Authority (AGCM), which involves Eni SpA and, since January 1, 2023, its subsidiary Enilive SpA, which took over the parent company in managing the retail fuel sales business, for alleged collusion with competitors in the Italian retail market of automotive fuel aimed at fixing the cost of the bio component of fuels sold in Italy, in violation of antitrust regulations. The Authority believes that the agreement was implemented through information exchanges and other initiatives with a view to coordinating final sales prices. The Authority formalized the charges against Eni and its subsidiary upon conclusion of the preliminary investigation. The Company filed its defense briefs. On September 26, 2025, the AGCM imposed a significant fine to Eni for alleged collusive commercial practices in violation of the competition laws. Eni believes that the findings of the Authority are groundless and that the Company has always been conducting the business in a transparent way and in full compliance with applicable competition rules. On November 25, 2025, Eni filed a judicial appeal with the Regional Administrative Court of Lazio. Risk provision has been accrued for this proceeding.\n\n \n\nF-93\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n2. Settled proceedings\n\n \n\n(i) Eni Rewind SpA – Crotone omitted clean-up. The criminal proceeding initiated in 2017 by the Public Prosecutor of Crotone regarding alleged crimes related to site remediation activities carried out by Eni Rewind was dismissed without any charges being filed against Eni.\n\n(ii) Eni SpA – Fatal accident Ancona offshore platform. The criminal proceeding relating to a fatal accident that occurred on an Eni platform in 2019 involving two contractors concluded with the definitive acquittal of Eni employees under investigation and of the entity itself under investigation pursuant to Legislative Decree No. 231/01.\n\n(iii) Raffineria di Gela SpA and Eni Rewind SpA – Groundwater pollution survey and reclamation process of the Gela site. The criminal proceedings brought by the Gela Public Prosecutor's Office against the subsidiaries Eni Rewind SpA / Raffineria di Gela SpA and some of their employees have been concluded. The charges related to alleged crimes of environmental pollution, omitted clean-up, negligent personal injury and illegal waste management, in connection with the decommissioning and clean-up of several abandoned areas of the Gela Refinery, carried out by Eni Rewind, including on behalf of other co-located companies. The Gela Court acquitted all defendants on the grounds that the facts were unfounded. The ruling was not appealed and is therefore final.\n\n \n\n(iv) Eni SpA – Eni Rewind SpA – Raffineria di Gela SpA – Claim for preventive technical inquiry and judgments on the merits. The civil proceeding seeking compensation for the alleged causality between certain pathologies and the alleged industrial pollution at the Gela site was concluded without any charges being filed against Eni.\n\n \n\nF-94\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nAssets under concession arrangements\n\n \n\nEni operates under concession arrangements mainly in the Exploration & Production segment and in 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.\n\n \n\nEnvironmental regulations\n\n \n\nIn 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.\n\n \n\nEmission trading\n\n \n\nFrom 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 2025, 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 16.4 million tonnes, Eni was awarded free emission allowances of 5.1 million tonnes, determining a deficit of 11.3 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market, with delivery in 2026.\n\n \n\nF-95\n\n[Table of Contents](#TOC_TableofContent)\n\n29 Revenues and other income\n\n \n\nSales from operations\n\n \n\n(€ million)\n\nExploration & Production\n\nGlobal Gas & LNG Portfolio and Power\n\nRefining and Chemicals\n\nEnilive\n\nPlenitude\n\nCorporate and  Other activities\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nSales from operations\n\n37,109\n\n13,102\n\n5,223\n\n16,337\n\n10,118\n\n262\n\n82,151\n\nSales of crude oil\n\n27,394\n\n \n\n7\n\n \n\n \n\n \n\n27,401\n\nSales of oil products\n\n4,316\n\n \n\n1,526\n\n15,818\n\n \n\n \n\n21,660\n\nSales of natural gas and LNG\n\n4,899\n\n9,982\n\n1\n\n \n\n3,640\n\n \n\n18,522\n\nSales of petrochemical products\n\n \n\n \n\n2,954\n\n \n\n \n\n \n\n2,954\n\nSales of power\n\n \n\n2,534\n\n1\n\n \n\n3,994\n\n \n\n6,529\n\nSales of other products\n\n49\n\n2\n\n370\n\n88\n\n77\n\n63\n\n649\n\nServices\n\n451\n\n584\n\n364\n\n431\n\n2,407\n\n199\n\n4,436\n\nProducts sales and service revenues\n\n37,109\n\n13,102\n\n5,223\n\n16,337\n\n10,118\n\n262\n\n82,151\n\nTransfer of goods/services\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nGoods/Services transferred in a specific moment\n\n36,694\n\n12,945\n\n5,169\n\n16,337\n\n10,111\n\n138\n\n81,394\n\nGoods/Services transferred over a period of time\n\n415\n\n157\n\n54\n\n \n\n7\n\n124\n\n757\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nSales from operations\n\n38,875\n\n15,061\n\n5,881\n\n18,670\n\n10,124\n\n186\n\n88,797\n\nSales of crude oil\n\n28,151\n\n \n\n \n\n \n\n \n\n \n\n28,151\n\nSales of oil products\n\n4,058\n\n \n\n1,518\n\n18,165\n\n \n\n \n\n23,741\n\nSales of natural gas and LNG\n\n6,039\n\n12,480\n\n2\n\n \n\n3,620\n\n \n\n22,141\n\nSales of petrochemical products\n\n253\n\n \n\n3,667\n\n \n\n \n\n \n\n3,920\n\nSales of power\n\n \n\n2,244\n\n1\n\n \n\n4,073\n\n \n\n6,318\n\nSales of other products\n\n40\n\n16\n\n326\n\n62\n\n67\n\n7\n\n518\n\nServices\n\n334\n\n321\n\n367\n\n443\n\n2,364\n\n179\n\n4,008\n\nProducts sales and service revenues\n\n38,875\n\n15,061\n\n5,881\n\n18,670\n\n10,124\n\n186\n\n88,797\n\nTransfer of goods/services\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nGoods/Services transferred in a specific moment\n\n38,557\n\n14,963\n\n5,844\n\n18,670\n\n10,124\n\n61\n\n88,219\n\nGoods/Services transferred over a period of time\n\n318\n\n98\n\n37\n\n \n\n \n\n125\n\n578\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nSales from operations\n\n37,961\n\n19,468\n\n6,188\n\n18,877\n\n11,040\n\n183\n\n93,717\n\nSales of crude oil\n\n25,685\n\n \n\n \n\n \n\n \n\n \n\n25,685\n\nSales of oil products\n\n5,219\n\n \n\n1,847\n\n18,442\n\n \n\n \n\n25,508\n\nSales of natural gas and LNG\n\n5,881\n\n16,638\n\n \n\n \n\n4,431\n\n \n\n26,950\n\nSales of petrochemical products\n\n766\n\n \n\n3,619\n\n \n\n \n\n \n\n4,385\n\nSales of power\n\n \n\n2,420\n\n \n\n \n\n4,832\n\n \n\n7,252\n\nSales of other products\n\n44\n\n38\n\n305\n\n28\n\n91\n\n3\n\n509\n\nServices\n\n366\n\n372\n\n417\n\n407\n\n1,686\n\n180\n\n3,428\n\nProducts sales and service revenues\n\n37,961\n\n19,468\n\n6,188\n\n18,877\n\n11,040\n\n183\n\n93,717\n\nTransfer of goods/services\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nGoods/Services transferred in a specific moment\n\n37,626\n\n19,383\n\n6,147\n\n18,645\n\n11,040\n\n64\n\n92,905\n\nGoods/Services transferred over a period of time\n\n335\n\n85\n\n41\n\n232\n\n \n\n119\n\n812\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nRevenues associated with contract liabilities at the beginning of the period\n\n287\n\n87\n\n642\n\nRevenues associated with performance obligations totally or partially satisfied in previous years\n\n(128)\n\n7\n\n1,087\n\n \n\nAs a result of international sanctions against Russian upstream companies, joint operators of Eni in operated projects, in application of the contractual clauses that regulate the related JOA, Eni has taken over the ownership of the rights and obligations of the sanctioned partner, thus proceeding to acquire the production shares, revenues of €87 million, costs pertaining to the partner and suspending the economic margin of the operations.\n\n \n\nF-96\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nSales from operations by industry segment and geographic area of destination are disclosed in note 35 – Segment information and information by geographic area.\n\n \n\nSales from operations with related parties are disclosed in note 36 – Transactions with related parties.\n\n \n\nOther income and revenues\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nGains from sale of assets and businesses\n\n25\n\n48\n\n27\n\nOther proceeds\n\n1,453\n\n2,369\n\n1,072\n\n \n\n1,478\n\n2,417\n\n1,099\n\n \n\nOther proceeds include: (i) €160 million (€194 million and €121 million in 2024 and 2023, respectively) related to the recovery of the cost share of right-of-use assets pertaining to partners of unincorporated joint operations operated by Eni; (ii) in 2024, €1,048 million relating to the agreement with an Italian operator to share environmental expenses which provides Eni with a reimbursement for past and future costs already allocated to environmental provision.\n\n \n\nOther income and revenues with related parties are disclosed in note 36 – Transactions with related parties.\n\n \n\n30 Costs\n\n \n\nPurchase, services and other charges\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nProduction costs - raw, ancillary and consumable materials and goods\n\n51,014\n\n54,204\n\n58,170\n\nProduction costs - services\n\n12,433\n\n12,217\n\n11,512\n\nLease expense and other\n\n1,356\n\n1,512\n\n1,432\n\nNet provisions for contingencies\n\n1,117\n\n1,397\n\n1,369\n\nOther expenses\n\n1,694\n\n2,073\n\n1,746\n\n \n\n67,614\n\n71,403\n\n74,229\n\nless:\n\n \n\n \n\n \n\n- capitalized direct costs associated with self-constructed assets - tangible assets\n\n(368)\n\n(227)\n\n(367)\n\n- capitalized direct costs associated with self-constructed assets - intangible assets\n\n(190)\n\n(62)\n\n(26)\n\n \n\n67,056\n\n71,114\n\n73,836\n\n \n\nPurchase, services and other charges included geological and geophysical expenses of Exploration & Production segment for €174 million (€186 million and €205 million in 2024 and 2023, respectively).\n\n \n\nCosts 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 €207 million (€178 million and €166 million in 2024 and 2023, respectively).\n\n \n\nRoyalties on the extraction rights of hydrocarbons amounted to €984 million (€1,122 million and €1,138 million in 2024 and 2023, respectively).\n\n \n\nCharges to provisions related to: (i) environmental provisions for €559 million (€848 million and €559 million in 2024 and 2023, respectively); (ii) reversal of decommissioning provisions for €9 million (net additions of €300 million and €305 million in 2024 and 2023, respectively); (iii) a €268 million increase in legal proceedings provisions (net additions of €40 million and net reversals of €87 million in 2024 and 2023, respectively). More information is provided in note 21 – Provisions. Net additions to provisions by segment are disclosed in note 35 – Segment information and information by geographical area.\n\n \n\nInformation about leases is disclosed in note 13 – Right-of-use assets and lease liabilities.\n\n \n\nF-97\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nPayroll and related costs\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nWages and salaries\n\n2,620\n\n2,665\n\n2,427\n\nSocial security contributions\n\n541\n\n527\n\n497\n\nCost related to employee benefit plans\n\n64\n\n96\n\n156\n\nOther costs\n\n135\n\n123\n\n196\n\n \n\n3,360\n\n3,411\n\n3,276\n\nless:\n\n \n\n \n\n \n\n- capitalized direct costs associated with self-constructed assets - tangible assets\n\n(116)\n\n(139)\n\n(131)\n\n- capitalized direct costs associated with self-constructed assets - intangible assets\n\n(15)\n\n(10)\n\n(9)\n\n \n\n3,229\n\n3,262\n\n3,136\n\n \n\nOther costs comprised provisions for redundancy incentives of €70 million (€66 million and €56 million in 2024 and 2023, respectively) and costs for defined contribution plans of €110 million (€104 million and €102 million in 2024 and 2023, respectively).\n\n \n\nCost related to employee benefit plans are described in note 22 – Provisions for employee benefits.\n\n \n\nCosts with related parties are disclosed in note 36 – Transactions with related parties.\n\n \n\nAverage number of employees\n\n \n\nThe average number of employees of the companies included in the consolidation area, and the breakdown by category is reported as follows:\n\n \n\n \n\n2025\n\n2024\n\n2023\n\n(number)\n\nSubsidiaries\n\nJoint operations\n\nSubsidiaries\n\nJoint operations\n\nSubsidiaries\n\nJoint operations\n\nSenior managers\n\n902\n\n18\n\n933\n\n19\n\n944\n\n19\n\nJunior managers\n\n9,315\n\n89\n\n9,257\n\n90\n\n9,157\n\n84\n\nEmployees\n\n15,965\n\n452\n\n16,086\n\n431\n\n15,810\n\n420\n\nWorkers\n\n5,414\n\n266\n\n5,719\n\n282\n\n5,937\n\n294\n\n \n\n31,596\n\n825\n\n31,995\n\n822\n\n31,848\n\n817\n\n \n\nThe average number of employees was calculated as the average between the number of employees at the beginning and the end of the year.\n\n \n\nThe average number of senior managers included managers employed in foreign countries, whose position is comparable to a senior manager’s status.\n\n \n\nLong-term share-based incentive plan for Eni’s managers\n\n \n\nThe main terms of the incentive plans for Eni executives with shares whose awards are in place at the end of the 2025 financial year are set out below.\n\n \n\nTwo long-term incentive plans, 2020-2022 and 2023-2025, ratified by the Shareholders' Meeting, are in place. These plans provide for the award of up to 20 million and 16 million treasury shares, respectively, each divided into three annual awards, which are intended for Eni's CEO and the executives of Eni and its subsidiaries who qualify as “senior managers deemed critical for the business”, selected among those who are in charge of tasks directly linked to the Group results or of strategic clout to the business. The Plans provide the granting of Eni shares for no consideration to eligible managers after a three-year vesting period under the condition that they would remain in office until vesting.\n\n \n\nThe vesting characteristics of the Plans are linked to the achievement of the objectives established by the Company in terms of financial results, appreciation of the shares compared to a group of Eni's competitors (\"Peer Group\") and achievement of certain environmental sustainability and emissions reduction KPIs.\n\n \n\nDepending on the performance of the parameters mentioned above, the number of shares that will vest free of charge after three years may range between 0% and 180% of the initial award. The plans include lock-up and claw back clauses.\n\n \n\nThe number of shares awarded at the grant date upon achievement of the vesting conditions was 5.78 shares, with a weighted average fair value of €10.6 per share.\n\n \n\nF-98\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plans (stochastic method), taking into account the fair value of the Eni share at the grant date, reduced by dividends expected along the vesting period, considering the volatility of the stock, the forecasts relating to the trend of the performance parameters, as well as the lower value attributable to the shares considering the lock-up clause.\n\n \n\nThe costs related to the long-term monetary incentive plan, recognized as a component of the payroll cost with counterpart in equity reserves as they pertain to company employees, amounted to €20 million (€23 million and €20 million in 2024 and 2023, respectively).\n\n \n\nEmployee Stock Ownership Plan\n\n \n\nThe 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 participation in the growth of corporate value, in line with the interests of the shareholders. The Plan provides for three annual awards in the period 2024-2026 intended for employees of Eni and its subsidiaries.\n\n \n\nFor 2025, Eni has awarded shares for no consideration to employees in Italy (as in 2024) and abroad. A three-year lock-up period applies to each award.\n\n \n\nAt the grant date (November 27, 2025), a total of 3,289,345 shares were issued, and at the 2024 grant date (November 27, 2024), 3,102,700 shares.\n\n \n\nCosts relating to the Employee Stock Ownership Plan, recognized as a component of payroll cost amounted to €15 million (€1 million in 2024) with counterpart in equity reserves.\n\n \n\nCompensation for key management personnel\n\n \n\nCompensation, 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:\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nWages and salaries\n\n24\n\n39\n\n35\n\nPost-employment benefits\n\n2\n\n4\n\n3\n\nOther long-term benefits\n\n16\n\n23\n\n19\n\n \n\n42\n\n66\n\n57\n\n \n\nCompensation of Directors and Statutory Auditors of Eni SpA\n\n \n\nCompensation of Directors amounted to €11.8 million, €12.9 million and €13.9 million in 2025, 2024 and 2023, respectively. Compensation of Statutory Auditors amounted to €0.5 million, €0.5 million and €0.6 million in 2025, 2024 and 2023, respectively.\n\n \n\nCompensation included emoluments and social security benefits and social assistance 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.\n\n \n\n31 Finance income (expense)\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nFinance income\n\n7,196\n\n7,715\n\n7,417\n\nFinance expense\n\n(8,170)\n\n(8,980)\n\n(8,113)\n\nNet finance income (expense) from financial assets at fair value through profit or loss\n\n235\n\n388\n\n284\n\nIncome (expense) from derivative financial instruments\n\n(80)\n\n278\n\n(61)\n\nFinance income (expense)\n\n(819)\n\n(599)\n\n(473)\n\n \n\nF-99\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe analysis of finance income (expense) was as follows:\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nFinance income (expense) related to net borrowings\n\n \n\n \n\n \n\nInterest and other finance expense on ordinary bonds\n\n(774)\n\n(827)\n\n(667)\n\nNet finance income (expense) on financial assets held for trading\n\n243\n\n367\n\n250\n\nNet expenses on other financial assets valued at fair value with effects on profit and loss\n\n(8)\n\n21\n\n34\n\nInterest and other expense due to banks and other financial institutions\n\n(252)\n\n(358)\n\n(207)\n\nInterest on lease liabilities\n\n(348)\n\n(314)\n\n(267)\n\nInterest from banks\n\n191\n\n294\n\n356\n\nInterest and other income on financial receivables and securities held for non-operating purposes\n\n205\n\n161\n\n14\n\n \n\n(743)\n\n(656)\n\n(487)\n\nExchange differences\n\n133\n\n(38)\n\n255\n\nIncome (expense) from derivative financial instruments\n\n(80)\n\n278\n\n(61)\n\nOther finance income (expense)\n\n \n\n \n\n \n\nInterest and other income on financing receivables and securities held for operating purposes\n\n39\n\n44\n\n153\n\nCapitalized finance expense\n\n122\n\n222\n\n94\n\nFinance expense due to the passage of time (accretion discount) (a)\n\n(250)\n\n(261)\n\n(341)\n\nOther finance income (expense)\n\n(40)\n\n(188)\n\n(86)\n\n \n\n(129)\n\n(183)\n\n(180)\n\n \n\n(819)\n\n(599)\n\n(473)\n\n(a) The item relates to the increase in provisions for contingencies that are shown at present value in non-current liabilities.\n\n \n\nInformation about leases is disclosed in note 13 – Right-of-use assets and lease liabilities.\n\n \n\nThe analysis of derivative financial instruments is disclosed in note 24 – Derivative financial instruments and hedge accounting.\n\n \n\nFinance income (expense) with related parties is disclosed in note 36 – Transactions with related parties.\n\n \n\n32 Income (expense) from investments\n\n \n\nShare of profit (loss) of equity-accounted investments\n\n \n\nMore information is provided in note 16 – Investments.\n\n \n\nShare of profit or loss of equity accounted investments by industry segment is disclosed in note 35 – Segment information and information by geographical area.\n\n \n\nOther gain (loss) from investments\n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nDividends\n\n242\n\n227\n\n255\n\nNet gain (loss) on disposals\n\n77\n\n562\n\n430\n\nOther net income (expense)\n\n107\n\n195\n\n423\n\n \n\n426\n\n984\n\n1,108\n\n \n\nDividend income primarily related to Nigeria LNG Ltd for €156 million (€166 million in 2024 and €179 million in 2023) and to Saudi European Petrochemical Co 'IBN ZAHR' for €21 million (€22 million in 2024 and €55 million in 2023).\n\n \n\nGains on disposals referred: (i) for €46 million to the capital gain realized from the sale to Global Infrastructure Partners of 49.99% of the capital of Eni CCUS Holding Ltd, which operates, through its subsidiaries Liverpool Bay and Bacton projects in the United Kingdom and the L10-CCS project in the Netherlands; (ii) for €32 million in the capital gain realized from the sale of 1.27% of the capital of Ithaca Energy Plc through an accelerated bookbuilding process aimed at institutional investors.\n\n \n\nOther net income referred for €86 million to a capital gain generated by the allocation of the purchase price of an additional share in E&E Algeria Touat BV and for €27 million to gains from the fair value measurement of the stake retained in Eni CCUS Holding Ltd.\n\n \n\nF-100\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nGains on disposals for 2024 referred for €371 million to the capital gain realized from the sale of the 100% stake of Nigerian Agip Oil Co Ltd to Oando Plc and €166 million in the capital gain realized from the sale of 10% of the capital of Saipem SpA through an accelerated bookbuilding process aimed at institutional investors. These gains included the realization of effects recognized in comprehensive income for €9 million.\n\n \n\nOther net income for 2024 referred for €118 million to the fair value measurement on Ithaca Energy Plc business combination.\n\n \n\nGains on disposals for 2023 referred to the capital gain realized from the sale to Snam of the 49.9% stake of SeaCorridor Srl and other net income for 2023 referred to the capital gain from the fair value measurement of the retained share of SeaCorridor Srl.\n\n \n\n33 Income taxes \n\n \n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nCurrent taxes\n\n \n\n \n\n \n\n- Italian subsidiaries\n\n6\n\n(255)\n\n97\n\n- subsidiaries of the Exploration & Production segment - outside Italy\n\n3,671\n\n4,946\n\n5,349\n\n- other subsidiaries - outside Italy\n\n128\n\n22\n\n185\n\n \n\n3,805\n\n4,713\n\n5,631\n\nNet deferred taxes\n\n \n\n \n\n \n\n- Italian subsidiaries\n\n(379)\n\n(1,433)\n\n(137)\n\n- subsidiaries of the Exploration & Production segment - outside Italy\n\n(279)\n\n294\n\n(22)\n\n- other subsidiaries - outside Italy\n\n(127)\n\n151\n\n(104)\n\n \n\n(785)\n\n(988)\n\n(263)\n\n \n\n3,020\n\n3,725\n\n5,368\n\nCurrent income taxes of Italian subsidiaries include foreign taxes for €118 million.\n\n \n\nIn 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 2025 and 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.\n\n \n\nThe reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (same amount in 2024 and 2023) and the effective tax charge is the following:\n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nProfit (loss) before taxation\n\n5,778\n\n6,489\n\n10,228\n\nTax rate (IRES) (%)\n\n24.0\n\n24.0\n\n24.0\n\nStatutory corporation tax charge (credit) on profit or loss\n\n1,387\n\n1,557\n\n2,455\n\nIncrease (decrease) resulting from:\n\n \n\n \n\n \n\n- higher tax charges related to subsidiaries outside Italy\n\n1,692\n\n3,452\n\n3,036\n\n- Italian regional income tax (IRAP)\n\n56\n\n(15)\n\n91\n\n- tax effect on reserve distribution\n\n50\n\n147\n\n106\n\n- impact pursuant to foreign tax effects of Italian entities\n\n47\n\n108\n\n14\n\n- effect due to the tax regime provided for intercompany dividends\n\n46\n\n82\n\n7\n\n- tax effects related to previous years\n\n9\n\n6\n\n48\n\n- effect of the valuation of the investments under the equity method\n\n(30)\n\n(30)\n\n(26)\n\n- impact pursuant to (reversal) impairment of deferred tax assets\n\n(260)\n\n(1,470)\n\n(221)\n\n- effect of gains from sale / business combination\n\n \n\n(38)\n\n(96)\n\n- other adjustments\n\n23\n\n(74)\n\n(46)\n\n \n\n1,633\n\n2,168\n\n2,913\n\nEffective tax charge\n\n3,020\n\n3,725\n\n5,368\n\n \n\nF-101\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nThe higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €1,653 million (€3,403 million and €3,026 million in 2024 and 2023, respectively).\n\n \n\nGroup’s effective tax rate amounted to 52.3% (57.4% in 2024 and 52.5% in 2023). This amount is due to the greater weight on consolidated pre-tax profit from the results obtained in foreign Exploration & Production jurisdictions with tax rates higher than the Group average.             \n\n \n\n34 Earnings (loss) per share\n\n \n\nBasic earnings per ordinary share are calculated by dividing profit 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.\n\n \n\nDiluted earnings per share are calculated by dividing the profit 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, 2025, the shares that could be potentially issued related to the estimation of new shares that will vest in connection with the 2023-2025 long-term monetary incentive plans and the convertible bond issued in 2023.\n\n \n\nIn determining basic and diluted earnings per share, the net profit 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.\n\n \n\nReconciliation of basic and diluted earnings per share was as follows:\n\n \n\n \n\n \n\n2025\n\n2024\n\n2023\n\nWeighted average number of shares used for basic earnings per share\n\n \n\n3,024,753,353\n\n3,167,006,396\n\n3,303,766,512\n\nPotential shares to be issued for ILT incentive plan\n\n \n\n6,350,799\n\n6,369,161\n\n6,352,583\n\nPotential shares to be issued for Sustainability-linked bond\n\n \n\n56,975,836\n\n56,975,836\n\n17,014,702\n\nWeighted average number of shares used for diluted earnings per share\n\n \n\n3,088,079,988\n\n3,230,351,393\n\n3,327,133,797\n\n \n\n \n\n \n\n \n\n \n\nEni’s profit\n\n(€ million)\n\n2,608\n\n2,624\n\n4,771\n\nRemuneration of subordinated perpetual bonds net of tax effect\n\n(€ million)\n\n(237)\n\n(132)\n\n(109)\n\nEni’s profit for basic earnings per share\n\n(€ million)\n\n2,371\n\n2,492\n\n4,662\n\nRemuneration of Sustainability-linked bond net of tax effect\n\n(€ million)\n\n31\n\n31\n\n9\n\nEni’s profit for diluted earnings per share\n\n(€ million)\n\n2,402\n\n2,523\n\n4,671\n\nBasic earnings per share\n\n(€ per share)\n\n0.78\n\n0.79\n\n1.41\n\nDiluted earnings per share\n\n(€ per share)\n\n0.78\n\n0.78\n\n1.40\n\n \n\nF-102\n\n[Table of Contents](#TOC_TableofContent) \n\n \n\n35 Segment information and information by geographic area\n\nSegment information \n\nEni's segment information is determined on the basis of the operating segments whose results are periodically reviewed by the Chief Operating Decision Maker (the CEO) for performance evaluation and resource allocation decisions.\n\nFor financial reporting purposes, consistent with applicable accounting standards, management has considered that the decision-making processes for resource allocation and the CEO's assessment of financial/industrial performance are conducted at a lower level of aggregation than the groupings described. Therefore, in compliance with the provisions of IFRS 8, which regulates the segment reporting, Eni’s reportable segments as of December 31, 2025, have been defined as follows considering the operating segments that flow into the three groupings:\n\n         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 on the market for refining and stabilize or hedge commercial margins.\n\n         Global Gas & LNG Portfolio (GGP) and Power: wholesale supply and marketing of natural gas via pipeline, international transport activities, and the purchase and marketing of equity and third-party LNG. It includes gas trading activities finalized to hedging and stabilizing commercial margins, as well as optimizing the gas asset portfolio. The results of the Power business operating which involves the generation and wholesale of electricity from thermoelectric plants, which offers similar economic returns given the similar industrial dynamics related to gas and electricity demand have been included in this reportable segment. It includes trading of CO2 emission certificates and forward electricity sales for the purposes of hedging and optimizing margins.\n\n         Refining and Chemicals: processing crude oil for the production of conventional fuels, carried out by the \"Refining\" operating segment, and the production of petroleum-based chemicals, carried out by the subsidiary Versalis and its subsidiaries. These activities have been combined into a single reportable segment because they offer similar economic returns, exposure to common market dynamics, and common industrial process structures. Versalis is active in the production of bioplastics through its subsidiary Novamont and in compounding chemistry.\n\n \n\n         Enilive: engages in the manufacturing of biofuels from renewable raw materials and in retail marketing activities of traditional and biofuels through an extensive network of refueling outlets, also providing non-fuel products and services to drivers with a view to sustainable mobility. It also engages in wholesale fuels, bitumen and lubricants.\n\n \n\n         Plenitude: engages in the retail sales of gas, electricity and related services, production and wholesale of electricity from renewable energy plants, and is also building and managing a network of charging points for electric vehicles.\n\n         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 remediation activity managed by the subsidiary Eni Rewind. The segment also includes activities related to CCUS, agri-business, forest conservation and bioenergy production projects, currently under development.\n\n​Segment information presented to the CEO (the Chief Operating Decision Maker, ex IFRS 8) includes: revenues, operating profit and directly attributable assets and liabilities.\n\n \n\nF-103\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nSegment Information\n\n(€ million)\n\nExploration & Production\n\nGlobal Gas & LNG Portfolio and Power\n\nRefining  and Chemicals\n\nEnilive\n\nPlenitude\n\nTotal reportable segments\n\nCorporate and  Other activities\n\nAdjustments of intragroup profits\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nSales from operations including intersegment sales\n\n50,367\n\n17,120\n\n18,179\n\n19,120\n\n10,168\n\n114,954\n\n \n\n \n\n \n\n- less: intersegment sales\n\n(13,258)\n\n(4,018)\n\n(12,956)\n\n(2,783)\n\n(50)\n\n(33,065)\n\n \n\n \n\n \n\nSales from operations\n\n37,109\n\n13,102\n\n5,223\n\n16,337\n\n10,118\n\n81,889\n\n262\n\n \n\n82,151\n\nOperating profit\n\n6,302\n\n1,770\n\n(2,485)\n\n499\n\n153\n\n6,239\n\n(1,499)\n\n270\n\n5,010\n\nNet provisions for contingencies\n\n(335)\n\n93\n\n(346)\n\n(42)\n\n(43)\n\n(673)\n\n(491)\n\n47\n\n(1,117)\n\nDepreciation and amortization\n\n(6,061)\n\n(279)\n\n(146)\n\n(294)\n\n(451)\n\n(7,231)\n\n(153)\n\n35\n\n(7,349)\n\nImpairments of tangible and intangible assets and right-of-use assets\n\n(1,135)\n\n(17)\n\n(482)\n\n(60)\n\n(7)\n\n(1,701)\n\n(96)\n\n \n\n(1,797)\n\nReversals of tangible and intangible assets and right-of-use assets\n\n54\n\n35\n\n31\n\n60\n\n \n\n180\n\n35\n\n \n\n215\n\nWrite-off of tangible and intangible assets\n\n(30)\n\n \n\n(1)\n\n \n\n(2)\n\n(33)\n\n \n\n \n\n(33)\n\nShare of profit (loss) of equity-accounted investments\n\n1,116\n\n32\n\n120\n\n(53)\n\n(33)\n\n1,182\n\n(21)\n\n \n\n1,161\n\nIdentifiable assets (a)\n\n60,407\n\n4,988\n\n6,377\n\n6,117\n\n13,622\n\n91,511\n\n2,630\n\n(253)\n\n93,888\n\nUnallocated assets (b)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n43,181\n\nEquity-accounted investments\n\n7,562\n\n417\n\n2,354\n\n796\n\n1,139\n\n12,268\n\n887\n\n \n\n13,155\n\nIdentifiable liabilities (a)\n\n19,934\n\n4,691\n\n4,153\n\n3,303\n\n5,490\n\n37,571\n\n5,239\n\n(90)\n\n42,720\n\nUnallocated liabilities (b)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n41,562\n\nCapital expenditure in tangible and intangible assets\n\n6,678\n\n109\n\n663\n\n468\n\n764\n\n8,682\n\n587\n\n(40)\n\n9,229\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nSales from operations including intersegment sales\n\n54,440\n\n18,876\n\n21,210\n\n21,139\n\n10,179\n\n125,844\n\n \n\n \n\n \n\n- less: intersegment sales\n\n(15,565)\n\n(3,815)\n\n(15,329)\n\n(2,469)\n\n(55)\n\n(37,233)\n\n \n\n \n\n \n\nSales from operations\n\n38,875\n\n15,061\n\n5,881\n\n18,670\n\n10,124\n\n88,611\n\n186\n\n \n\n88,797\n\nOperating profit\n\n6,715\n\n(909)\n\n(1,681)\n\n282\n\n1,307\n\n5,714\n\n(371)\n\n(105)\n\n5,238\n\nNet provisions for contingencies\n\n(282)\n\n(11)\n\n(478)\n\n(48)\n\n(81)\n\n(900)\n\n(484)\n\n(13)\n\n(1,397)\n\nDepreciation and amortization\n\n(6,353)\n\n(267)\n\n(161)\n\n(284)\n\n(424)\n\n(7,489)\n\n(144)\n\n33\n\n(7,600)\n\nImpairments of tangible and intangible assets and right-of-use assets\n\n(2,385)\n\n(195)\n\n(458)\n\n(117)\n\n(1)\n\n(3,156)\n\n(51)\n\n \n\n(3,207)\n\nReversals of tangible and intangible assets and right-of-use assets\n\n182\n\n94\n\n3\n\n \n\n5\n\n284\n\n23\n\n \n\n307\n\nWrite-off of tangible and intangible assets\n\n(576)\n\n \n\n \n\n \n\n(3)\n\n(579)\n\n(1)\n\n \n\n(580)\n\nShare of profit (loss) of equity-accounted investments\n\n904\n\n44\n\n73\n\n(43)\n\n(47)\n\n931\n\n(65)\n\n \n\n866\n\nIdentifiable assets (a)\n\n67,572\n\n7,421\n\n7,228\n\n5,893\n\n13,588\n\n101,702\n\n2,712\n\n(457)\n\n103,957\n\nUnallocated assets (b)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n42,982\n\nEquity-accounted investments\n\n8,348\n\n488\n\n2,621\n\n899\n\n1,019\n\n13,375\n\n775\n\n \n\n14,150\n\nIdentifiable liabilities (a)\n\n20,627\n\n7,230\n\n4,253\n\n2,995\n\n5,883\n\n40,988\n\n4,881\n\n(49)\n\n45,820\n\nUnallocated liabilities (b)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n45,471\n\nCapital expenditure in tangible and intangible assets\n\n6,055\n\n110\n\n632\n\n416\n\n887\n\n8,100\n\n408\n\n(23)\n\n8,485\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nSales from operations including intersegment sales\n\n55,773\n\n24,168\n\n23,061\n\n21,780\n\n11,102\n\n135,884\n\n \n\n \n\n \n\n- less: intersegment sales\n\n(17,812)\n\n(4,700)\n\n(16,873)\n\n(2,903)\n\n(62)\n\n(42,350)\n\n \n\n \n\n \n\nSales from operations\n\n37,961\n\n19,468\n\n6,188\n\n18,877\n\n11,040\n\n93,534\n\n183\n\n \n\n93,717\n\nOperating profit\n\n8,693\n\n2,626\n\n(2,121)\n\n585\n\n(659)\n\n9,124\n\n(948)\n\n81\n\n8,257\n\nNet provisions for contingencies\n\n(354)\n\n(206)\n\n(352)\n\n(33)\n\n(73)\n\n(1,018)\n\n(339)\n\n(12)\n\n(1,369)\n\nDepreciation and amortization\n\n(6,271)\n\n(295)\n\n(142)\n\n(261)\n\n(404)\n\n(7,373)\n\n(140)\n\n34\n\n(7,479)\n\nImpairments of tangible and intangible assets and right-of-use assets\n\n(1,419)\n\n(14)\n\n(732)\n\n(38)\n\n(7)\n\n(2,210)\n\n(52)\n\n \n\n(2,262)\n\nReversals of tangible and intangible assets\n\n376\n\n52\n\n6\n\n \n\n \n\n434\n\n26\n\n \n\n460\n\nWrite-off of tangible and intangible assets\n\n(531)\n\n \n\n \n\n \n\n(5)\n\n(536)\n\n1\n\n \n\n(535)\n\nShare of profit (loss) of equity-accounted investments\n\n1,012\n\n49\n\n381\n\n(38)\n\n(55)\n\n1,349\n\n(13)\n\n \n\n1,336\n\nIdentifiable assets (a)\n\n64,504\n\n7,688\n\n7,186\n\n6,081\n\n12,692\n\n98,151\n\n1,891\n\n(378)\n\n99,664\n\nUnallocated assets (b)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n42,942\n\nEquity-accounted investments\n\n6,780\n\n534\n\n2,724\n\n858\n\n664\n\n11,560\n\n1,070\n\n \n\n12,630\n\nIdentifiable liabilities (a)\n\n21,461\n\n6,637\n\n3,910\n\n2,900\n\n5,436\n\n40,344\n\n4,578\n\n(56)\n\n44,866\n\nUnallocated liabilities (b)\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n44,096\n\nCapital expenditure in tangible and intangible assets\n\n7,135\n\n119\n\n556\n\n428\n\n636\n\n8,874\n\n360\n\n(19)\n\n9,215\n\n(a)      Include assets/liabilities directly associated with the generation of operating profit. Does not include financial assets and liabilities, investments, income tax assets and liabilities.\n\n(b)      Include assets/liabilities not directly associated with the generation of operating profit.\n\n \n\nF-104\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nInformation by geographic area\n\nIdentifiable assets and investments by geographic area of origin\n\n(€ million)\n\nItaly\n\nOther European Union\n\nRest of Europe\n\nAmericas\n\nAsia\n\nAfrica\n\nOther areas\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nIdentifiable assets (a)\n\n26,971\n\n8,662\n\n2,531\n\n5,796\n\n18,460\n\n29,859\n\n1,609\n\n93,888\n\nCapital expenditure in tangible and intangible assets\n\n1,829\n\n673\n\n388\n\n260\n\n2,486\n\n3,476\n\n117\n\n9,229\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nIdentifiable assets (a)\n\n29,787\n\n7,704\n\n4,709\n\n6,470\n\n21,232\n\n32,624\n\n1,431\n\n103,957\n\nCapital expenditure in tangible and intangible assets\n\n2,009\n\n673\n\n308\n\n556\n\n1,519\n\n3,276\n\n144\n\n8,485\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nIdentifiable assets (a)\n\n30,026\n\n6,962\n\n5,124\n\n7,658\n\n17,855\n\n30,928\n\n1,111\n\n99,664\n\nCapital expenditure in tangible and intangible assets\n\n2,006\n\n485\n\n235\n\n609\n\n1,471\n\n4,105\n\n304\n\n9,215\n\n \n\n(a)   Include assets directly associated with the generation of operating profit.\n\nSales from operations by geographic area of destination\n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nItaly\n\n28,647\n\n30,994\n\n33,450\n\nOther European Union\n\n15,979\n\n15,975\n\n18,271\n\nRest of Europe\n\n14,866\n\n16,493\n\n18,476\n\nAmericas\n\n6,215\n\n7,908\n\n7,004\n\nAsia\n\n9,675\n\n9,114\n\n7,404\n\nAfrica\n\n6,731\n\n8,285\n\n9,057\n\nOther areas\n\n38\n\n28\n\n55\n\n \n\n82,151\n\n88,797\n\n93,717\n\n \n\n36 Transactions with related parties\n\nIn the ordinary course of its business, Eni enters into transactions mainly regarding:\n\na)       Purchase, sale and supply of goods and services and the provision of financing to joint ventures, associates and non-consolidated subsidiaries;\n\nb)       purchase, sale and supply of goods and services to entities controlled by the Italian Government;\n\nc)       contributions to Eni Foundation and Eni Enrico Mattei Foundation, non-corporate entities attributable to Eni, which pursue humanitarian, cultural, and research initiatives. Transactions with these entities are immaterial.\n\nThere were no material transactions involving Directors, Statutory Auditors or their affiliates.\n\n \n\nTransactions with related parties were conducted in the interest of the Group and, with exception of those with entities whose aim is to develop humanitarian, cultural, and scientific initiatives, are related to the ordinary course of Eni’s business.\n\n \n\nF-105\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nTransactions and balances with related parties\n\n \n\nDecember 31, 2025\n\n \n\n2025\n\n(€ million)\n\nReceivables and other assets\n\nPayables and other liabilities\n\nGuarantees\n\n \n\nRevenues\n\nCosts\n\nOther operating (expense) income\n\nJoint ventures and associates\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nAgiba Petroleum Co\n\n3\n\n135\n\n \n\n \n\n1\n\n333\n\n \n\nCardón IV SA\n\n1\n\n134\n\n \n\n \n\n4\n\n \n\n \n\nCoral FLNG SA\n\n12\n\n \n\n1,247\n\n \n\n21\n\n \n\n \n\nEni CCUS Holding\n\n118\n\n \n\n1,218\n\n \n\n \n\n \n\n \n\nAzule Group\n\n119\n\n361\n\n2,939\n\n \n\n93\n\n1,643\n\n \n\nSaipem Group\n\n41\n\n136\n\n9\n\n \n\n9\n\n536\n\n \n\nSeaCorridor Group\n\n67\n\n19\n\n \n\n \n\n2\n\n266\n\n \n\nVårgrønn Group\n\n1\n\n \n\n678\n\n \n\n1\n\n \n\n \n\nIn Salah Gas Ltd\n\n \n\n57\n\n \n\n \n\n \n\n279\n\n \n\nIthaca Energy Plc\n\n146\n\n73\n\n \n\n \n\n12\n\n535\n\n(553)\n\nKarachaganak Petroleum Operating BV\n\n27\n\n119\n\n \n\n \n\n2\n\n992\n\n \n\nLotte Versalis Elastomers Co Ltd\n\n8\n\n13\n\n \n\n \n\n3\n\n61\n\n \n\nMellitah Oil & Gas BV\n\n56\n\n241\n\n \n\n \n\n10\n\n1,031\n\n \n\nPetrobel Belayim Petroleum Co\n\n13\n\n470\n\n \n\n \n\n5\n\n778\n\n \n\nSociete' Centrale Electrique du Congo SA\n\n91\n\n \n\n \n\n \n\n79\n\n \n\n \n\nSocietà Oleodotti Meridionali SpA\n\n22\n\n500\n\n \n\n \n\n25\n\n16\n\n \n\nSt. Bernard Renewables Llc\n\n1\n\n \n\n98\n\n \n\n1\n\n9\n\n \n\nVår Energi ASA\n\n26\n\n1,321\n\n1,948\n\n \n\n61\n\n5,523\n\n(1)\n\nOther (*)\n\n78\n\n65\n\n26\n\n \n\n108\n\n224\n\n \n\n \n\n830\n\n3,644\n\n8,163\n\n \n\n437\n\n12,226\n\n(554)\n\nUnconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nIndustria Siciliana Acido Fosforico - ISAF SpA (in liquidation)\n\n170\n\n1\n\n \n\n \n\n9\n\n \n\n \n\nVME Oilfield Chemicals Llc\n\n \n\n \n\n112\n\n \n\n \n\n \n\n \n\nOther\n\n19\n\n10\n\n21\n\n \n\n21\n\n14\n\n \n\n \n\n189\n\n11\n\n133\n\n \n\n30\n\n14\n\n \n\n \n\n1,019\n\n3,655\n\n8,296\n\n \n\n467\n\n12,240\n\n(554)\n\nEntities controlled by the Government\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCassa Depositi e Prestiti Group\n\n22\n\n19\n\n \n\n \n\n \n\n87\n\n \n\nEnel Group\n\n89\n\n183\n\n \n\n \n\n45\n\n650\n\n66\n\nItalgas Group\n\n2\n\n190\n\n \n\n \n\n7\n\n718\n\n \n\nSnam Group\n\n110\n\n247\n\n \n\n \n\n77\n\n1,086\n\n \n\nTerna Group\n\n62\n\n75\n\n \n\n \n\n266\n\n343\n\n5\n\nGSE - Gestore Servizi Energetici\n\n112\n\n100\n\n \n\n \n\n2,147\n\n1,861\n\n219\n\nITA Airways - Italia Trasporto Aereo SpA\n\n3\n\n \n\n \n\n \n\n99\n\n \n\n \n\nOther (*)\n\n23\n\n51\n\n \n\n \n\n97\n\n \n\n \n\n \n\n423\n\n865\n\n \n\n \n\n2,738\n\n4,745\n\n290\n\nOther related parties\n\n \n\n4\n\n \n\n \n\n1\n\n39\n\n \n\nGroupement Sonatrach – Eni «GSE»\n\n216\n\n307\n\n \n\n \n\n52\n\n729\n\n \n\nTotal\n\n1,658\n\n4,831\n\n8,296\n\n \n\n3,258\n\n17,753\n\n(264)\n\n \n\n(*) Each individual amount included herein was lower than €50 million.\n\n \n\nF-106\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n \n\nDecember 31, 2024\n\n \n\n2024\n\n(€ million)\n\nReceivables and other assets\n\nPayables and other liabilities\n\nGuarantees\n\n \n\nRevenues\n\nCosts\n\nOther operating (expense) income\n\nJoint ventures and associates\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nAgiba Petroleum Co\n\n4\n\n126\n\n \n\n \n\n \n\n256\n\n \n\nCardón IV SA\n\n1\n\n77\n\n \n\n \n\n4\n\n(2)\n\n \n\nCoral FLNG SA\n\n12\n\n \n\n1,411\n\n \n\n15\n\n(3)\n\n \n\nAzule Group\n\n59\n\n399\n\n3,343\n\n \n\n76\n\n2,290\n\n \n\nSaipem Group\n\n41\n\n186\n\n9\n\n \n\n52\n\n1,253\n\n \n\nSeaCorridor Group\n\n105\n\n27\n\n \n\n \n\n1\n\n242\n\n \n\nVårgrønn Group\n\n1\n\n \n\n886\n\n \n\n \n\n \n\n \n\nIthaca Energy Plc\n\n188\n\n76\n\n \n\n \n\n \n\n366\n\n(138)\n\nKarachaganak Petroleum Operating BV\n\n31\n\n292\n\n \n\n \n\n \n\n1,198\n\n \n\nLotte Versalis Elastomers Co Ltd\n\n6\n\n14\n\n \n\n \n\n3\n\n51\n\n \n\nMellitah Oil & Gas BV\n\n56\n\n52\n\n \n\n \n\n11\n\n523\n\n \n\nMozambique Rovuma Venture SpA\n\n26\n\n2\n\n \n\n \n\n31\n\n53\n\n \n\nPetrobel Belayim Petroleum Co\n\n23\n\n509\n\n \n\n \n\n \n\n562\n\n \n\nSocietà Oleodotti Meridionali SpA\n\n12\n\n491\n\n \n\n \n\n16\n\n11\n\n \n\nSociété Centrale Electrique du Congo SA\n\n97\n\n \n\n \n\n \n\n104\n\n \n\n \n\nVår Energi ASA\n\n30\n\n828\n\n1,918\n\n \n\n48\n\n5,047\n\n(57)\n\nOther (*)\n\n37\n\n71\n\n120\n\n \n\n74\n\n187\n\n \n\n \n\n729\n\n3,150\n\n7,687\n\n \n\n435\n\n12,034\n\n(195)\n\nUnconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nEni BTC Ltd\n\n \n\n \n\n195\n\n \n\n \n\n \n\n \n\nIndustria Siciliana Acido Fosforico - ISAF SpA (in liquidation)\n\n161\n\n3\n\n \n\n \n\n10\n\n \n\n \n\nOther\n\n16\n\n7\n\n11\n\n \n\n27\n\n18\n\n \n\n \n\n177\n\n10\n\n206\n\n \n\n37\n\n18\n\n \n\n \n\n906\n\n3,160\n\n7,893\n\n \n\n472\n\n12,052\n\n(195)\n\nEntities controlled by the Government\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCassa Depositi e Prestiti Group\n\n3\n\n25\n\n \n\n \n\n \n\n65\n\n \n\nEnel Group\n\n33\n\n153\n\n \n\n \n\n46\n\n798\n\n(28)\n\nItalgas Group\n\n1\n\n186\n\n \n\n \n\n5\n\n612\n\n \n\nSnam Group\n\n196\n\n436\n\n \n\n \n\n219\n\n1,342\n\n \n\nTerna Group\n\n104\n\n116\n\n \n\n \n\n386\n\n350\n\n10\n\nGSE - Gestore Servizi Energetici\n\n201\n\n110\n\n \n\n \n\n1,805\n\n1,548\n\n414\n\nITA Airways - Italia Trasporto Aereo SpA\n\n13\n\n \n\n \n\n \n\n238\n\n \n\n \n\nOther (*)\n\n23\n\n66\n\n \n\n \n\n71\n\n \n\n \n\n \n\n574\n\n1,092\n\n \n\n \n\n2,770\n\n4,715\n\n396\n\nOther related parties\n\n1\n\n3\n\n \n\n \n\n2\n\n37\n\n \n\nGroupement Sonatrach – Eni «GSE»\n\n316\n\n316\n\n \n\n \n\n32\n\n599\n\n \n\nTotal\n\n1,797\n\n4,571\n\n7,893\n\n \n\n3,276\n\n17,403\n\n201\n\n(*) Each individual amount included herein was lower than €50 million.\n\n \n\nF-107\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n \n\nDecember 31, 2023\n\n \n\n2023\n\n(€ million)\n\nReceivables and other assets\n\nPayables and other liabilities\n\nGuarantees\n\n \n\nRevenues\n\nCosts\n\nOther operating (expense) income\n\nJoint ventures and associates\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nAgiba Petroleum Co\n\n1\n\n194\n\n \n\n \n\n \n\n308\n\n \n\nCardón IV SA\n\n24\n\n142\n\n \n\n \n\n4\n\n1\n\n \n\nCoral FLNG SA\n\n4\n\n \n\n1,327\n\n \n\n6\n\n \n\n \n\nAzule Group\n\n113\n\n475\n\n3,156\n\n \n\n86\n\n2,146\n\n \n\nSaipem Group\n\n5\n\n235\n\n9\n\n \n\n6\n\n768\n\n \n\nSeaCorridor Group\n\n29\n\n29\n\n \n\n \n\n1\n\n357\n\n \n\nVårgrønn Group\n\n \n\n \n\n1,321\n\n \n\n \n\n \n\n \n\nKarachaganak Petroleum Operating BV\n\n17\n\n250\n\n \n\n \n\n \n\n1,183\n\n \n\nMellitah Oil & Gas BV\n\n49\n\n20\n\n \n\n \n\n16\n\n517\n\n \n\nPetrobel Belayim Petroleum Co\n\n58\n\n885\n\n \n\n \n\n \n\n870\n\n \n\nSocietà Oleodotti Meridionali SpA\n\n11\n\n473\n\n \n\n \n\n19\n\n12\n\n \n\nSociété Centrale Electrique du Congo SA\n\n74\n\n \n\n \n\n \n\n79\n\n \n\n \n\nVår Energi ASA\n\n51\n\n764\n\n2,013\n\n \n\n58\n\n4,487\n\n(165)\n\nOther (*)\n\n62\n\n73\n\n19\n\n \n\n83\n\n203\n\n \n\n \n\n498\n\n3,540\n\n7,845\n\n \n\n358\n\n10,852\n\n(165)\n\nUnconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nEni BTC Ltd\n\n \n\n \n\n183\n\n \n\n \n\n \n\n \n\nIndustria Siciliana Acido Fosforico - ISAF SpA (in liquidation)\n\n152\n\n4\n\n1\n\n \n\n12\n\n \n\n \n\nOther\n\n13\n\n10\n\n12\n\n \n\n13\n\n30\n\n \n\n \n\n165\n\n14\n\n196\n\n \n\n25\n\n30\n\n \n\n \n\n663\n\n3,554\n\n8,041\n\n \n\n383\n\n10,882\n\n(165)\n\nEntities controlled by the Government\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCassa Depositi e Prestiti Group\n\n5\n\n33\n\n \n\n \n\n2\n\n69\n\n \n\nEnel Group\n\n95\n\n168\n\n \n\n \n\n93\n\n497\n\n(109)\n\nItalgas Group\n\n1\n\n149\n\n \n\n \n\n8\n\n(20)\n\n \n\nSnam Group\n\n245\n\n352\n\n \n\n \n\n1,157\n\n1,625\n\n \n\nTerna Group\n\n85\n\n61\n\n \n\n \n\n400\n\n317\n\n8\n\nGSE - Gestore Servizi Energetici\n\n230\n\n219\n\n \n\n \n\n2,104\n\n1,875\n\n283\n\nITA Airways - Italia Trasporto Aereo SpA\n\n5\n\n \n\n \n\n \n\n238\n\n \n\n \n\nOther (*)\n\n11\n\n68\n\n \n\n \n\n52\n\n38\n\n \n\n \n\n677\n\n1,050\n\n \n\n \n\n4,054\n\n4,401\n\n182\n\nOther related parties\n\n1\n\n2\n\n \n\n \n\n1\n\n36\n\n \n\nGroupement Sonatrach – Eni «GSE»\n\n222\n\n212\n\n \n\n \n\n40\n\n569\n\n \n\nTotal\n\n1,563\n\n4,818\n\n8,041\n\n \n\n4,478\n\n15,888\n\n17\n\n(*) Each individual amount included herein was lower than €50 million.   \n\nThe most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:\n\n         Eni’s share of expenses incurred to develop oil fields billed by 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 billed on the basis of costs incurred;\n\n         the residual debt relating to the payment of the consideration for the repurchase of Cardón IV trade receivables towards the state company PDVSA;\n\n         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;\n\n         guarantees issued to Eni CCUS Holding in connection with the sale of the CCUS assets in the United Kingdom and the Netherlands;\n\n         supply of upstream specialist services, purchase of crude oil and issue of guarantees against leasing contracts of FPSO vessels to Azule Group;\n\n         engineering, construction and drilling services by Saipem Group mainly for the Exploration & Production segment;\n\n         acquisition of transport services from SeaCorridor Group;\n\n         guarantees issued to Vårgrønn Group mainly in relation to the participation in the Dogger Bank offshore wind project;\n\n \n\n         the sale of gas to In Salah Gas Ltd;\n\n         receivables relating to the business combination carried out in 2024, the purchase of crude oil and condensate and the execution of commodity derivative contracts from Ithaca Energy Plc Group;\n\n \n\nF-108\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n         the purchase of elastomers from Lotte Versalis Elastomers Co Ltd;\n\n         advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system at the Taranto refinery;\n\n         the sale of gas to Société Centrale Electrique du Congo SA;\n\n         guarantees issued pro rata on behalf of St. Bernard Renewables LLC in favor of suppliers for feedstock purchasing transactions;\n\n         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;\n\n         services for environmental restoration to Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation).\n\nThe most significant transactions with entities controlled by the Italian Government concerned:\n\n         activities aimed at ensuring operation, upgrading and efficiency of the plants provided to Ansaldo group (Cassa Depositi e Prestiti);\n\n         sale of fuel and combustibles, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group;\n\n         acquisition of distribution, transportation 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, as well as, from the Snam Group, the receivable for divestment relating to the sale of the 49.9% share capital of SeaCorridor Srl and the purchase and sale of natural gas for granting the system balancing on the basis of prices referred to the quotations of the main energy commodities;\n\n         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;\n\n         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 (Energy Services Operator) 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;\n\n         the sale of jet fuel to ITA Airways - Italia Trasporto Aereo SpA.\n\nTransactions with other related parties concerned:\n\n         provisions to pension funds managed by Eni of €25 million and debts for contributions to be paid for €3 million;\n\n         costs for contributions paid to the Supplementary Healthcare Fund for Managers of Eni Group Companies (FISDE) for €5 million and debts for contributions to be paid for €1 million;\n\n         contributions and service provisions to Eni Enrico Mattei Foundation for €4 million and to Eni Foundation for €5 million, and revenues from the Eni Foundation for €1 million.\n\n \n\nFinancing transactions and balances with related parties\n\n \n\nDecember 31, 2025\n\n \n\n2025\n\n(€ million)\n\nReceivables and cash and cash equivalents\n\nPayables\n\nGuarantees\n\n \n\nFinance incomes and derivative financial instruments\n\nFinance Expenses\n\nGain on disposals\n\nJoint ventures and associates\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCoral FLNG SA\n\n417\n\n \n\n \n\n \n\n20\n\n \n\n \n\nE&E Algeria Touat BV\n\n \n\n56\n\n \n\n \n\n \n\n \n\n \n\nEni CCUS Holding\n\n123\n\n \n\n \n\n \n\n \n\n \n\n \n\nSaipem Group\n\n \n\n247\n\n \n\n \n\n \n\n11\n\n \n\nMozambique Rovuma Venture SpA\n\n2,318\n\n91\n\n \n\n \n\n147\n\n11\n\n \n\nOther (*)\n\n70\n\n57\n\n4\n\n \n\n45\n\n49\n\n \n\n \n\n2,928\n\n451\n\n4\n\n \n\n212\n\n71\n\n \n\nUnconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOther (*)\n\n41\n\n55\n\n \n\n \n\n2\n\n1\n\n \n\n \n\n41\n\n55\n\n \n\n \n\n2\n\n1\n\n \n\nEntities controlled by the Government\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCassa Depositi e Prestiti Group\n\n \n\n52\n\n \n\n \n\n \n\n2\n\n \n\nOther\n\n \n\n35\n\n \n\n \n\n1\n\n3\n\n(18)\n\n \n\n \n\n87\n\n \n\n \n\n1\n\n5\n\n(18)\n\nTotal\n\n2,969\n\n593\n\n4\n\n \n\n215\n\n77\n\n(18)\n\n(*) Each individual amount included herein was lower than €50 million. \n\n \n\nF-109\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n \n\nDecember 31, 2024\n\n \n\n2024\n\n(€ million)\n\nReceivables and cash and cash equivalents\n\nPayables\n\nGuarantees\n\n \n\nFinance incomes and derivative financial instruments\n\nFinance Expenses\n\nGain on disposals\n\nJoint ventures and associates\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCoral FLNG SA\n\n522\n\n \n\n \n\n \n\n24\n\n \n\n \n\nCoral South FLNG DMCC\n\n \n\n \n\n1,539\n\n \n\n \n\n(1)\n\n \n\nSaipem Group\n\n \n\n222\n\n \n\n \n\n1\n\n \n\n \n\nMozambique Rovuma Venture SpA\n\n1,769\n\n58\n\n \n\n \n\n132\n\n11\n\n \n\nPengerang Biorefinery Sdn Bhd\n\n60\n\n \n\n \n\n \n\n \n\n \n\n \n\nOther\n\n37\n\n39\n\n2\n\n \n\n38\n\n41\n\n \n\n \n\n2,388\n\n319\n\n1,541\n\n \n\n195\n\n51\n\n \n\nUnconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOther\n\n40\n\n36\n\n \n\n \n\n2\n\n2\n\n \n\n \n\n40\n\n36\n\n \n\n \n\n2\n\n2\n\n \n\nEntities controlled by the Government\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCassa Depositi e Prestiti Group\n\n \n\n53\n\n \n\n \n\n \n\n \n\n \n\nOther\n\n \n\n7\n\n \n\n \n\n1\n\n4\n\n(12)\n\n \n\n \n\n60\n\n \n\n \n\n1\n\n4\n\n(12)\n\nOther related parties\n\n \n\n4\n\n \n\n \n\n \n\n \n\n \n\nTotal\n\n2,428\n\n419\n\n1,541\n\n \n\n198\n\n57\n\n(12)\n\n \n\n \n\nDecember 31, 2023\n\n \n\n2023\n\n(€ million)\n\nReceivables and cash and cash equivalents\n\nPayables\n\nGuarantees\n\n \n\nFinance incomes and derivative financial instruments\n\nFinance Expenses\n\nGain on disposals\n\nJoint ventures and associates\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCoral FLNG SA\n\n453\n\n \n\n \n\n \n\n15\n\n \n\n \n\nCoral South FLNG DMCC\n\n \n\n \n\n1,448\n\n \n\n \n\n \n\n \n\nSaipem Group\n\n \n\n56\n\n \n\n \n\n \n\n8\n\n \n\nMozambique Rovuma Venture SpA\n\n1,339\n\n170\n\n \n\n \n\n101\n\n \n\n \n\nOther\n\n49\n\n13\n\n1\n\n \n\n39\n\n14\n\n1\n\n \n\n1,841\n\n239\n\n1,449\n\n \n\n155\n\n22\n\n1\n\nUnconsolidated entities controlled by Eni\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOther\n\n7\n\n38\n\n \n\n \n\n1\n\n1\n\n \n\n \n\n7\n\n38\n\n \n\n \n\n1\n\n1\n\n \n\nEntities controlled by the Government\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCassa Depositi e Prestiti Group\n\n \n\n56\n\n \n\n \n\n \n\n2\n\n \n\nSnam Group\n\n \n\n \n\n \n\n \n\n \n\n \n\n443\n\nOther\n\n14\n\n2\n\n \n\n \n\n \n\n3\n\n1\n\n \n\n14\n\n58\n\n \n\n \n\n \n\n5\n\n444\n\nTotal\n\n1,862\n\n335\n\n1,449\n\n \n\n156\n\n28\n\n445\n\n \n\nThe most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:\n\n         a financing loan granted to Coral FLNG SA for the construction of a floating gas liquefaction plant in Area 4 offshore Mozambique;\n\n         a cash deposit with Group finance companies for E&E Algeria Touat BV;\n\n         a financing loan granted by Eni UK to Bacton CCS, part of the Eni CCS Holding group, as part of the agreement with GIP;\n\n         a bank debt guarantee issued on behalf of Coral South FLNG DMCC as part of the project financing of the Coral FLNG development project;\n\n         liabilities for leased assets towards Saipem Group related to long-term contracts for the use of drilling rigs\n\n         a financing loan granted to Mozambique Rovuma Venture SpA for the development of gas reserves offshore Mozambique;\n\nThe most significant transactions with entities controlled by the Italian Government concerned:\n\n         finance debt for the realization of charging infrastructures for electric vehicles with Cassa e Depositi e Prestiti Group.\n\n \n\nF-110\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nImpact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows\n\n \n\nThe impact of transactions and positions with related parties on the balance sheet accounts consisted of the following:\n\n \n\n \n\nDecember 31, 2025\n\nDecember 31, 2024\n\n(€ million)\n\nTotal\n\nRelated  parties\n\nImpact %\n\nTotal\n\nRelated  parties\n\nImpact %\n\nOther current financial assets\n\n3,710\n\n2,357\n\n63.53\n\n1,085\n\n48\n\n4.42\n\nTrade and other receivables\n\n12,436\n\n1,375\n\n11.06\n\n16,901\n\n1,601\n\n9.47\n\nOther current assets\n\n3,943\n\n76\n\n1.93\n\n3,662\n\n54\n\n1.47\n\nOther non-current financial assets\n\n1,109\n\n612\n\n55.18\n\n3,215\n\n2,380\n\n74.03\n\nOther non-current assets\n\n2,839\n\n207\n\n7.29\n\n4,011\n\n142\n\n3.54\n\nShort-term debt\n\n4,929\n\n265\n\n5.38\n\n4,238\n\n136\n\n3.21\n\nCurrent portion of long-term debt\n\n3,434\n\n128\n\n3.73\n\n4,582\n\n21\n\n0.46\n\nCurrent portion of non-current lease liabilities\n\n1,263\n\n108\n\n8.55\n\n1,279\n\n152\n\n11.88\n\nTrade and other payables\n\n20,261\n\n4,283\n\n21.14\n\n22,092\n\n4,017\n\n18.18\n\nOther current liabilities\n\n4,039\n\n86\n\n2.13\n\n5,049\n\n34\n\n0.67\n\nLong-term debt\n\n20,139\n\n52\n\n0.26\n\n21,570\n\n79\n\n0.37\n\nNon-current lease liabilities\n\n4,437\n\n40\n\n0.90\n\n5,174\n\n31\n\n0.60\n\nOther non-current liabilities\n\n3,390\n\n462\n\n13.63\n\n4,449\n\n520\n\n11.69\n\nThe impact of transactions with related parties on the profit and loss accounts consisted of the following:\n\n \n\n2025\n\n2024\n\n2023\n\n(€ million)\n\nTotal\n\nRelated parties\n\nImpact %\n\nTotal\n\nRelated parties\n\nImpact %\n\nTotal\n\nRelated parties\n\nImpact %\n\nSales from operations\n\n82,151\n\n2,973\n\n3.62\n\n88,797\n\n2,997\n\n3.38\n\n93,717\n\n4,322\n\n4.61\n\nOther income and revenues\n\n1,478\n\n285\n\n19.28\n\n2,417\n\n279\n\n11.54\n\n1,099\n\n156\n\n14.19\n\nPurchases, services and other\n\n(67,056)\n\n(17,769)\n\n26.50\n\n(71,114)\n\n(17,404)\n\n24.47\n\n(73,836)\n\n(15,885)\n\n21.51\n\nNet (impairments) reversals of trade and other receivables\n\n(11)\n\n(1)\n\n9.09\n\n(168)\n\n(2)\n\n1.19\n\n(249)\n\n5\n\n..\n\nPayroll and related costs\n\n(3,229)\n\n17\n\n..\n\n(3,262)\n\n3\n\n..\n\n(3,136)\n\n(8)\n\n0.26\n\nOther operating income (expense)\n\n641\n\n(264)\n\n..\n\n(352)\n\n201\n\n..\n\n478\n\n17\n\n3.56\n\nFinance income\n\n7,196\n\n215\n\n2.99\n\n7,715\n\n198\n\n2.57\n\n7,417\n\n155\n\n2.09\n\nFinance expense\n\n(8,170)\n\n(77)\n\n0.94\n\n(8,980)\n\n(57)\n\n0.63\n\n(8,113)\n\n(28)\n\n0.35\n\nDerivative financial instruments\n\n(80)\n\n \n\n \n\n278\n\n \n\n \n\n(61)\n\n1\n\n..\n\nOther income (expense) from investments\n\n426\n\n(18)\n\n..\n\n984\n\n(12)\n\n..\n\n1,108\n\n445\n\n40.16\n\n \n\nF-111\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nMain cash flows with related parties are provided below:\n\n(€ million)\n\n2025\n\n2024\n\n2023\n\nRevenues and other income\n\n3,258\n\n3,276\n\n4,478\n\nCosts and other expenses\n\n(15,198)\n\n(15,056)\n\n(13,539)\n\nOther operating income (loss)\n\n(264)\n\n201\n\n17\n\nNet change in trade and other receivables and payables\n\n691\n\n(61)\n\n1,916\n\nNet interests\n\n138\n\n132\n\n117\n\nNet cash provided from operating activities\n\n(11,375)\n\n(11,508)\n\n(7,011)\n\nCapital expenditure in tangible and intangible assets\n\n(2,555)\n\n(2,347)\n\n(2,349)\n\nDisposal of investments\n\n \n\n \n\n440\n\nNet change in accounts payable and receivable in relation to investments\n\n93\n\n(292)\n\n504\n\nChange in financial receivables\n\n(719)\n\n(501)\n\n(290)\n\nNet cash used in investing activities\n\n(3,181)\n\n(3,140)\n\n(1,695)\n\nChange in financial and lease liabilities\n\n(407)\n\n(20)\n\n(162)\n\nNet cash used in financing activities\n\n(407)\n\n(20)\n\n(162)\n\nChange in cash and cash equivalents\n\n \n\n(3)\n\n(7)\n\nTotal financial flows to related parties\n\n(14,963)\n\n(14,671)\n\n(8,875)\n\nThe impact of cash flows with related parties consisted of the following:\n\n \n\n2025\n\n2024\n\n2023\n\n(€ million)\n\nTotal\n\nRelated parties\n\nImpact %\n\nTotal\n\nRelated parties\n\nImpact %\n\nTotal\n\nRelated parties\n\nImpact %\n\nNet cash provided from operating activities\n\n13,330\n\n(11,375)\n\n..\n\n13,092\n\n(11,508)\n\n..\n\n15,119\n\n(7,011)\n\n..\n\nNet cash used in investing activities\n\n(9,298)\n\n(3,181)\n\n34.21\n\n(9,817)\n\n(3,140)\n\n31.99\n\n(9,365)\n\n(1,695)\n\n18.10\n\nNet cash used in financing activities\n\n(3,596)\n\n(407)\n\n11.32\n\n(5,380)\n\n(20)\n\n0.37\n\n(5,668)\n\n(162)\n\n2.86\n\n \n\nF-112\n\n[Table of Contents](#TOC_TableofContent)\n\n37 Other information about investments\n\nInformation on Eni’s investments as of December 31, 2025\n\nThe following section provides information about Eni’s consolidated subsidiaries as of December 31, 2025.\n\n \n\nCONSOLIDATED SUBSIDIARIES\n\nEXPLORATION & PRODUCTION\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Marine Services SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Mediterranea Idrocarburi SpA\n\nGela (CL)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Mozambico SpA\n\nSan Donato Milanese (MI)\n\nMozambique\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Natural Energies Mozambico Srl\n\nSan Donato Milanese (MI)\n\nMozambique\n\n \n\nEni Natural Energies SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Natural Energies SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEniProgetti SpA\n\nVenezia Marghera (VE)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Trade & Biofuels SpA\n\nRome\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nFloaters SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nSocietà Petrolifera Italiana SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n99.96\n\n \n\n99.96\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n0.04\n\n \n\n \n\n \n\n \n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nAgip Caspian Sea BV\n\nAmsterdam (Netherlands)\n\nKazakhstan\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nAgip Energy and Natural Resources (Nigeria) Ltd\n\nAbuja (Nigeria)\n\nNigeria\n\n \n\nEni International BV\n\n95.00\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Oil Holdings BV\n\n5.00\n\n \n\n \n\n \n\nAgip Karachaganak BV\n\nAmsterdam (Netherlands)\n\nKazakhstan\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nBurren Energy (Bermuda) Ltd\n\nHamilton (Bermuda)\n\nUnited Kingdom\n\n \n\nBurren Energy Plc\n\n100.00\n\n \n\n100.00\n\n \n\nBurren Energy Congo Ltd\n\nRoad Town (British Virgin Islands)\n\nRepublic of the Congo\n\n \n\nBurren En. (Berm) Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nBurren Energy India Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nBurren Energy Plc\n\n100.00\n\n \n\n100.00\n\n \n\nBurren Energy Plc\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni UK Holding Plc\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni UK Ltd\n\n(..)\n\n \n\n \n\n \n\nEni Abu Dhabi BV\n\nAmsterdam (Netherlands)\n\nUnited Arab Emirates\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Albania BV\n\nAmsterdam (Netherlands)\n\nAlbania\n\n \n\nEni Netherlands Hold. BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Algeria Exploration BV\n\nAmsterdam (Netherlands)\n\nAlgeria\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Algeria Production BV\n\nAmsterdam (Netherlands)\n\nAlgeria\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Ambalat Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni America Ltd\n\nDover (USA)\n\nUSA\n\n \n\nEni UHL Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Argentina Exploración y Explotación SA\n\nBuenos Aires (Argentina)\n\nArgentina\n\n \n\nEni International BV\n\n95.00\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Oil Holdings BV\n\n5.00\n\n \n\n \n\n \n\nEni Arguni I Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Australia BV\n\nAmsterdam (Netherlands)\n\nAustralia\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Australia Ltd\n\nLondon (United Kingdom)\n\nAustralia\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-113\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni BB Petroleum Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Petroleum Co Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni BTC Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Bukat Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Canada Holding Ltd\n\nCalgary (Canada)\n\nCanada\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni China BV\n\nAmsterdam (Netherlands)\n\nChina\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Congo SAU\n\nPointe-Noire (Republicof the Congo)\n\nRepublic of the Congo\n\n \n\nEni E&P Holding BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Côte d'Ivoire Ltd\n\nLondon (United Kingdom)\n\nIvory Coast\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Cyprus Ltd\n\nNicosia (Cyprus)\n\nCyprus\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni East Ganal Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni East Med BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni East Sepinggan Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Alam El Shawish BV\n\nThe Hague (Netherlands)\n\nEgypt\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Arguni I BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Ashrafi BV\n\nThe Hague (Netherlands)\n\nEgypt\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Australia Pty Ltd\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni En. Holding NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Bonaparte Pty Ltd\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni En. Australia Pty Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy E&P Holding Netherlands BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni En. Holding NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy East Ganal BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy East Sepinggan BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Egypt BV\n\nThe Hague (Netherlands)\n\nEgypt\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Facilities Netherlands BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni Energy NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Germany BV\n\nThe Hague (Netherlands)\n\nGermany\n\n \n\nEni Energy NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Group Holdings Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni En. Group Midco Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Group Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-114\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Energy Group Midco Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni Energy Group Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Holding Netherlands BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Hydrogen BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni Energy NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Jakarta BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Muara Bakau BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Netherlands Administration BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni Energy NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Netherlands BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy North Ganal BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy North West El Amal BV\n\nThe Hague (Netherlands)\n\nEgypt\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Participation Netherlands BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni Energy NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Russia BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy Touat Holding BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Energy West Ganal BV\n\nThe Hague (Netherlands)\n\nIndonesia\n\n \n\nEni En. E&P Hold. NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Exploration & Production Holding BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Ganal Deepwater Ltd\n\nHamilton (Bermuda)\n\nIndonesia\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Ganal Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Gas & Power LNG Australia BV\n\nAmsterdam (Netherlands)\n\nAustralia\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Ghana Exploration and Production Ltd\n\nAccra (Ghana)\n\nGhana\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni GoM Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni Marketing Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Hewett Ltd\n\nAberdeen (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni UK Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni In Amenas Ltd\n\nAberdeen (United Kingdom)\n\nAlgeria\n\n \n\nEni Algeria Expl.BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni In Salah Ltd\n\nNassau (Bahamas)\n\nAlgeria\n\n \n\nEni IS Exploration Ltd\n\n60.48\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Algeria Expl.BV\n\n39.52\n\n \n\n \n\n \n\nEni Indonesia Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni ULX Ltd\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-115\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Indonesia Ots 1 Ltd\n\nGeorge Town (Cayman Islands)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni International NA NV Sàrl\n\nLuxembourg (Luxembourg)\n\nUnited Kingdom\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Investments Plc\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni SpA\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni UK Ltd\n\n(..)\n\n \n\n \n\n \n\nEni Iraq BV\n\nAmsterdam (Netherlands)\n\nIraq\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni IS Exploration Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni Algeria Expl.BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Isatay BV\n\nAmsterdam (Netherlands)\n\nKazakhstan\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni JPDA 03-13 Ltd\n\nLondon (United Kingdom)\n\nAustralia\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni JPDA 06-105 Pty Ltd\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Kenya BV\n\nAmsterdam (Netherlands)\n\nKenya\n\n \n\nEni Netherlands Hold. BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Lasmo Plc\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni Investments Plc\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni UK Ltd\n\n(..)\n\n \n\n \n\n \n\nEni LNS Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni UK Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Makassar Ltd\n\nHamilton (Bermuda)\n\nIndonesia\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Marketing Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Petroleum Co Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni México S. de RL de CV\n\nMexico City (Mexico)\n\nMexico\n\n \n\nEni International BV\n\n99.69\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Oil Holdings BV\n\n0.31\n\n \n\n \n\n \n\nEni Middle East Ltd\n\nLondon (United Kingdom)\n\nUnited Arab Emirates\n\n \n\nEni ULT Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Mozambique LNG Holding BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Muara Bakau BV\n\nAmsterdam (Netherlands)\n\nIndonesia\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Natural Energies Congo SAU\n\nPointe-Noire (Republic of the Congo)\n\nRepublic of the Congo\n\n \n\nEni Natural Energies SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Natural Energies Côte d'Ivoire SA\n\nAbidjan (Ivory Coast)\n\nIvory Coast\n\n \n\nEni Natural Energies SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Natural Energies Kenya EPZ Ltd\n\nKinango (Kenya)\n\nKenya\n\n \n\nEni Natural Energies SpA\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-116\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Natural Energies Vietnam Llc\n\nHo Chi Minh City (Vietnam)\n\nVietnam\n\n \n\nEni Natural Energies SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni North Africa BV\n\nAmsterdam (Netherlands)\n\nLibya\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni North Ganal Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Oil & Gas Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni America Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Oil Algeria Ltd\n\nLondon (United Kingdom)\n\nAlgeria\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Oil Holdings BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni ULX Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Oman BV\n\nAmsterdam (Netherlands)\n\nOman\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Peri Mahakam Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Petroleum Co Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni SpA\n\n60.06\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni International BV\n\n39.94\n\n \n\n \n\n \n\nEni Petroleum US Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni BB Petroleum Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEniProgetti Egypt Ltd\n\nCairo (Egypt)\n\nEgypt\n\n \n\nEniProgetti SpA\n\n99.00\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni SpA\n\n1.00\n\n \n\n \n\n \n\nEni Qatar BV\n\nAmsterdam (Netherlands)\n\nQatar\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni RAK BV\n\nAmsterdam (Netherlands)\n\nUnited Arab Emirates\n\n \n\nEni Netherlands Hold. BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Rapak Deepwater Ltd\n\nHamilton (Bermuda)\n\nIndonesia\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Rapak Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Rovuma Basin BV\n\nAmsterdam (Netherlands)\n\nMozambique\n\n \n\nEni Mozamb. LNG H. BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Sharjah BV\n\nAmsterdam (Netherlands)\n\nUnited Arab Emirates\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Timor 22-23 BV\n\nAmsterdam (Netherlands)\n\nEast Timor\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni TNS Ltd\n\nAberdeen (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni UK Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni Trading & Shipping Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Petroleum Co Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Transporte y Suministro México S. de RL de CV\n\nMexico City (Mexico)\n\nMexico\n\n \n\nEni International BV\n\n99.90\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Oil Holdings BV\n\n0.10\n\n \n\n \n\n \n\nEni Tunisia BV\n\nAmsterdam (Netherlands)\n\nTunisia\n\n \n\nEni Netherlands Hold. BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Turkmenistan Ltd\n\nHamilton (Bermuda)\n\nTurkmenistan\n\n \n\nBurren En. (Berm) Ltd\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-117\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni UHL Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni ULT Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni UK Holding Plc\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni Lasmo Plc\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni UK Ltd\n\n(..)\n\n \n\n \n\n \n\nEni UK Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni ULT Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nEni ULX Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni ULT Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni US Operating Co Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Petroleum Co Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni USA Gas Marketing Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni Marketing Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni USA Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Oil & Gas Inc\n\n100.00\n\n \n\n100.00\n\n \n\nEni Venezuela BV\n\nAmsterdam (Netherlands)\n\nVenezuela\n\n \n\nEni Venezuela E&P H.\n\n100.00\n\n \n\n100.00\n\n \n\nEni Venezuela E&P Holding SA\n\nBruxelles (Belgium)\n\nBelgium\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Vietnam BV\n\nAmsterdam (Netherlands)\n\nVietnam\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni West Ganal Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nEni West Timor Ltd\n\nLondon (United Kingdom)\n\nIndonesia\n\n \n\nEni Indonesia Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nExport LNG Ltd\n\nHong Kong (Hong Kong)\n\nHong Kong\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nFirst Calgary Petroleums LP\n\nWilmington (USA)\n\nAlgeria\n\n \n\nEni Canada Hold. Ltd\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nFCP Partner Co ULC\n\n0.01\n\n \n\n \n\n \n\nFirst Calgary Petroleums Partner Co ULC\n\nCalgary (Canada)\n\nCanada\n\n \n\nEni Canada Hold. Ltd\n\n100.00\n\n \n\n100.00\n\n \n\nIeoc Production BV\n\nAmsterdam (Netherlands)\n\nEgypt\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nLasmo Sanga Sanga Ltd\n\nHamilton (Bermuda)\n\nIndonesia\n\n \n\nEni Lasmo Plc\n\n100.00\n\n \n\n100.00\n\n \n\nNigerian Agip Exploration Ltd\n\nAbuja (Nigeria)\n\nNigeria\n\n \n\nEni International BV\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Oil Holdings BV\n\n0.01\n\n \n\n \n\n \n\nProduction North Sea Netherlands Ltd\n\nWilmington (USA)\n\nNetherlands\n\n \n\nEni Energy NL BV\n\n100.00\n\n \n\n100.00\n\n \n\nPT Eni Natural Energies Indonesia\n\nJakarta (Indonesia)\n\nIndonesia\n\n \n\nEni Natural Energies SpA\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nENE Italia\n\n0.01\n\n \n\n \n\n \n\n \n\nF-118\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nGLOBAL GAS & LNG PORTFOLIO\n\n \n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Global Energy Markets SpA\n\nRome\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nLNG Shipping SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nOUTSIDE ITALY\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni España Comercializadora de Gas SAU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni G&P Trading BV\n\nAmsterdam (Netherlands)\n\nTurkey\n\n \n\nEni Netherlands Hold. BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Gas Liquefaction BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni Netherlands Hold. BV\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nPower\n\n \n\nIN ITALY\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEniPower SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n51.00\n\n \n\n51.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n49.00\n\n \n\n \n\n \n\nEniPower Mantova SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniPower SpA\n\n86.50\n\n \n\n44.12\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n13.50\n\n \n\n \n\n \n\n \n\nF-119\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nREFINING AND CHEMICALS \n\nRefining\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEcofuel SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Abu Dhabi Refining & Trading BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n  100.00\n\n \n\n100.00\n\n \n\n \n\nChemicals\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nVersalis SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nFinproject SpA\n\nMorrovalle (MC)\n\nItaly\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\nNovamont SpA\n\nNovara\n\nItaly\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis Oilfield Solutions Srl (former Rewave Srl)\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nBioBag Americas Inc\n\nDunedin (USA)\n\nUSA\n\n \n\nBioBag International\n\n100.00\n\n \n\n100.00\n\n \n\nBioBag International AS\n\nIndre Østfold (Norway)\n\nNorway\n\n \n\nNovamont SpA\n\n100.00\n\n \n\n100.00\n\n \n\nDagöplast AS\n\nHiiumaa (Estonia)\n\nEstonia\n\n \n\nBioBag International\n\n100.00\n\n \n\n100.00\n\n \n\nDunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság\n\nBudapest (Hungary)\n\nHungary\n\n \n\nVersalis SpA\n\n96.34\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nVersalis Deutsch. GmbH\n\n1.83\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nVersalis International SA\n\n1.83\n\n \n\n \n\n \n\nFinproject India Pvt Ltd\n\nJaipur (India)\n\nIndia\n\n \n\nVersalis Asia Pacific\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nFinproject SpA\n\n(..)\n\n \n\n \n\n \n\nFinproject Romania Srl\n\nValea Lui Mihai (Romania)\n\nRomania\n\n \n\nFinproject SpA\n\n100.00\n\n \n\n100.00\n\n \n\nFoam Creations (2008) Inc\n\nQuebec City (Canada)\n\nCanada\n\n \n\nFinproject SpA\n\n100.00\n\n \n\n100.00\n\n \n\nFoam Creations México SA de CV\n\nLeón (Mexico)\n\nMexico\n\n \n\nFoam Creations (2008)\n\n53.23\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nFinproject SpA\n\n46.77\n\n \n\n \n\n \n\nNovamont France SAS\n\nParis (France)\n\nFrance\n\n \n\nNovamont SpA\n\n100.00\n\n \n\n100.00\n\n \n\nNovamont Iberia SLU\n\nCornellà de Llobregat (Spain)\n\nSpain\n\n \n\nNovamont SpA\n\n100.00\n\n \n\n100.00\n\n \n\nNovamont North America Inc\n\nShelton (USA)\n\nUSA\n\n \n\nNovamont SpA\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis Americas Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Petroleum Co Inc\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis Asia Pacific Pte Ltd\n\nSingapore (Singapore)\n\nSingapore\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis Congo Sarlu\n\nPointe-Noire (Republic of the Congo)\n\nRepublic of the Congo\n\n \n\nVersalis Oilfield S. Srl\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis Deutschland GmbH\n\nEschborn (Germany)\n\nGermany\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis France SAS\n\nMardyck (France)\n\nFrance\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis International Côte d'Ivoire Sarlu\n\nAbidjan (Ivory Coast)\n\nIvory Coast\n\n \n\nVersalis Oilfield S. Srl\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-120\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nVersalis International SA\n\nBruxelles (Belgium)\n\nBelgium\n\n \n\nVersalis SpA\n\n59.00\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nVersalis Deutsch. GmbH\n\n23.71\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nDunastyr Zrt\n\n14.43\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nVersalis France\n\n2.86\n\n \n\n \n\n \n\nVersalis Kimya Ticaret Limited Sirketi\n\nIstanbul (Turkey)\n\nTurkey\n\n \n\nVersalis International SA\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis México S. de RL de CV\n\nMexico City (Mexico)\n\nMexico\n\n \n\nVersalis Oilfield S. Srl\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nVersalis SpA\n\n(..)\n\n \n\n \n\n \n\nVersalis Pacific Trading (Shanghai) Co Ltd\n\nShanghai (China)\n\nChina\n\n \n\nVersalis Asia Pacific\n\n100.00\n\n \n\n100.00\n\n \n\nVersalis UK Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nVersalis SpA\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nENILIVE AND PLENITUDE\n\nEnilive \n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEnilive SpA\n\nRome\n\nItaly\n\n \n\nEni SpA\n\n70.00\n\n \n\n70.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n30.00\n\n \n\n \n\n \n\nBioraffineria di Gela SpA\n\nGela (CL)\n\nItaly\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnimoov SpA\n\nRome\n\nItaly\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nAten Oil SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEnilive Iberia SLU\n\n100.00\n\n \n\n70.00\n\n \n\nEni Energy (Shanghai) Co Ltd\n\nShanghai (China)\n\nChina\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnilive Austria GmbH\n\nWien (Austria)\n\nAustria\n\n \n\nEnilive SpA\n\n75.00\n\n \n\n70.83\n\n \n\n \n\n \n\n \n\n \n\nEnilive Deutsch. GmbH\n\n25.00\n\n \n\n \n\n \n\nEnilive Benelux BV\n\nRotterdam (Netherlands)\n\nNetherlands\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnilive Deutschland GmbH\n\nMunich (Germany)\n\nGermany\n\n \n\nEnilive SpA\n\n89.00\n\n \n\n73.30\n\n \n\n \n\n \n\n \n\n \n\nEni International BV\n\n11.00\n\n \n\n \n\n \n\nEnilive France Sàrl\n\nLyon (France)\n\nFrance\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnilive Iberia SLU\n\nAlcobendas (Spain)\n\nSpain\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnilive Marketing Austria GmbH\n\nWien (Austria)\n\nAustria\n\n \n\nEnimoov Austria GmbH\n\n99.99\n\n \n\n70.83\n\n \n\n \n\n \n\n \n\n \n\nEnilive SpA\n\n(..)\n\n \n\n \n\n \n\nEnilive Schmiertechnik GmbH\n\nWurzburg (Germany)\n\nGermany\n\n \n\nEnilive Deutsch. GmbH\n\n100.00\n\n \n\n73.30\n\n \n\nEnilive Suisse SA\n\nLausanne (Switzerland)\n\nSwitzerland\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnilive US Inc\n\nDover (USA)\n\nUSA\n\n \n\nEnilive SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnimoov Austria GmbH\n\nWien (Austria)\n\nAustria\n\n \n\nEnilive Austria GmbH\n\n100.00\n\n \n\n70.83\n\n \n\n \n\nF-121\n\n[Table of Contents](#TOC_TableofContent)\n\nPlenitude\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Plenitude SpA Società Benefit\n\nMilan\n\nItaly\n\n \n\nEni SpA\n\n70.00\n\n \n\n70.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n30.00\n\n \n\n \n\n \n\nAgrikroton Srl - Società Agricola\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEnerkall Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Miniwind Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Italy SpA\n\nMilan\n\nItaly\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Società Agricola Bio Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Solar II Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Storage Italy Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEvolvere Venture SpA\n\nMilan\n\nItaly\n\n \n\nPlen. En. Serv. SpA\n\n100.00\n\n \n\n70.00\n\n \n\nFotovoltaica Pietramontecorvino Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nFV4P Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nGemsa Solar Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nGPC Due Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nGreen Parity Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nLugo Società Agricola Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nPlenitude Energy Services SpA\n\nMilan\n\nItaly\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nPlenitude On The Road Srl (former Be Charge Srl)\n\nMilan\n\nItaly\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nSocietà Agricola Casemurate Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nSocietà Agricola Forestale Pianura Verde Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nSocietà Agricola L'Albero Azzurro Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nTimpe Muzzunetti 2 Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n70.00\n\n \n\n49.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n30.00\n\n \n\n \n\n \n\nWind Salandra Srl\n\nCesena (FC)\n\nItaly\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nF-122\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOUTSIDE ITALY\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nAdriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana\n\nLjubljana (Slovenia)\n\nSlovenia\n\n \n\nEni Plenitude SpA SB\n\n51.00\n\n \n\n35.70\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n49.00\n\n \n\n \n\n \n\nAleria Solar SAS\n\nBastia (France)\n\nFrance\n\n \n\nEni Plen. Op. Fr. SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAlmazara Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nAlpinia Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nArgenta Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nArgon SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Op. Fr. SAS\n\n100.00\n\n \n\n70.00\n\n \n\nArmadura Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nAthies-Samoussy Solar PV1 SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nKrypton SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAthies-Samoussy Solar PV2 SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nKrypton SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAthies-Samoussy Solar PV3 SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nKrypton SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAthies-Samoussy Solar PV4 SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nXenon SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAthies-Samoussy Solar PV5 SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nXenon SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAtlante Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nAzursol Est SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nAzursol Sud SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nBelle Magiocche Solaire SAS\n\nBastia (France)\n\nFrance\n\n \n\nEni Plen. Op. Fr. SAS\n\n100.00\n\n \n\n70.00\n\n \n\nBoceto Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nBrazoria Class B Member Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nBrazoria County Solar Project Llc\n\nDover (USA)\n\nUSA\n\n \n\nBrazoria HoldCo Llc\n\n100.00\n\n \n\n66.05\n\n \n\nBrazoria HoldCo Llc\n\nDover (USA)\n\nUSA\n\n \n\nBrazoria Class B\n\n94.36\n\n \n\n66.05\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n5.64\n\n \n\n \n\n \n\nBrown Chapel Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nBT Kellam Solar Llc\n\nAustin (USA)\n\nUSA\n\n \n\nKellam Tax Eq. Partn.\n\n100.00\n\n \n\n65.73\n\n \n\nBurlington Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nCattlemen Class A Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne de la Verte Epine SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne de l'Orvin SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne des Ailes de Foulzy SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne de Viersat SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne du Pays entre Madon et Moselle SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n91.00\n\n \n\n63.70\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n9.00\n\n \n\n \n\n \n\nCentrale Eolienne la Garenne SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne Largeasse SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne le Mont de Malan SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne les Hauts Chemins SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne Neo Avel SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Eolienne Terrajeaux SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Photovoltaique de Mer SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Antugnac 2 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Prod. France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Arue 1 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Arue 2 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Arue 3 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Cessieu Nord Isere SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Corbas 1 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nF-123\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nCentrale Solaire Corbas 3 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Helys SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n60.00\n\n \n\n42.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n40.00\n\n \n\n \n\n \n\nCentrale Solaire le Bernardan 2 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Prod. France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire les Huchanes SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Prod. France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Morcenx 1 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Morcenx 2 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Morhange 2 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 6 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 8 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 9 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 10 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 11 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 12 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 18 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 19 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 20 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 21 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 24 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 26 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 28 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 31 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 34 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 38 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 43 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Orion 50 SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Prod. France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Poullignac SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n86.51\n\n \n\n60.55\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n13.49\n\n \n\n \n\n \n\nCentrale Solaire Saint Avit SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrale Solaire Valenciennes Aerodrome SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nCentrales Solaires Delta SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nChapitel Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nChimney Creek Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nCorazon Energy Class B Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nCorazon Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nCorazon Tax Eq. Part. Llc\n\n100.00\n\n \n\n66.81\n\n \n\nCorazon Tax Equity Partnership Llc\n\nDover (USA)\n\nUSA\n\n \n\nCorazon En. Class B Llc\n\n95.45\n\n \n\n66.81\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n4.55\n\n \n\n \n\n \n\nCornisa Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nDaviess County Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nDelta Stockage SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Prod. France SAS\n\n70.00\n\n \n\n49.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n30.00\n\n \n\n \n\n \n\nEagle Springs Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nEkain Renovables SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. T. S. Spain\n\n100.00\n\n \n\n70.00\n\n \n\nEmery Bull Creek Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nEnera Conseil SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nEni Plenitude France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nEnergías Ambientales de Outes SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nF-124\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni New Energy US Holding Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n99.00\n\n \n\n70.00\n\n \n\n \n\n \n\n \n\n \n\nEni New Energy US Inv.Inc\n\n1.00\n\n \n\n \n\n \n\nEni New Energy US Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni New Energy US Investing Inc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude France SAS (former Eni Gas & Power France SA)\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Iberia SLU\n\nSantander (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Investment Colombia SAS\n\nBogotà (Colombia)\n\nColombia\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Investment Spain SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Operations France SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Australia Pty Ltd (former Eni New Energy Australia Pty Ltd)\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Batchelor Pty Ltd (former Eni New Energy Batchelor Pty Ltd)\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni Plen Ren Aus. Pty Ltd\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables France SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Hellas Single Member SA\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Holding BV (former Eni Energy Solutions BV)\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Katherine Pty Ltd (former Eni New Energy Katherine Pty Ltd)\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni Plen Ren Aus. Pty Ltd\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Luxembourg Sàrl\n\nLuxembourg (Luxembourg)\n\nLuxembourg\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Manton Dam Pty Ltd (former Eni New Energy Manton Dam Pty Ltd)\n\nPerth (Australia)\n\nAustralia\n\n \n\nEni Plen Ren Aus. Pty Ltd\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Renewables Spain SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n63.67\n\n \n\n70.00\n\n \n\n \n\n \n\n \n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n30.05\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nEnergías Amb. de Outes\n\n6.28\n\n \n\n \n\n \n\nEni Plenitude Rooftop France SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Technical Services Colombia SAS\n\nBogotà (Colombia)\n\nColombia\n\n \n\nEni Plen. Ren. Italy SpA\n\n60.00\n\n \n\n42.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n40.00\n\n \n\n \n\n \n\nEni Plenitude Technical Services Romania Srl\n\nCluj-Napoca (Romania)\n\nRomania\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEni Plenitude Technical Services Spain SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Italy SpA\n\n100.00\n\n \n\n70.00\n\n \n\nEolica Cuellar de la Sierra SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Inv. Spain SLU\n\n100.00\n\n \n\n70.00\n\n \n\nEoliennes Chemin Vert SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nEoliennes Courcome SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nEstanque Redondo Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nFive Mile Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nFlat Bayou Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nFortaleza Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nFotovoltaica Fotozar 5 SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Spain SLU\n\n100.00\n\n \n\n70.00\n\n \n\nFotovoltaica Fotozar 6 SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Spain SLU\n\n100.00\n\n \n\n70.00\n\n \n\nGarita Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nGas Supply Company Thessaloniki - Thessalia SA\n\nThessaloniki (Greece)\n\nGreece\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nGolden Acres Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nF-125\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nGranville Invest SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nGuajillo Energy Storage Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nHanks Crossing Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nHolding Lanas Solar Sàrl\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Op. Fr. SAS\n\n100.00\n\n \n\n70.00\n\n \n\nHuisache Solar Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nInveese SAS\n\nBogotá (Colombia)\n\nColombia\n\n \n\nEni Plen. Inv. Colombia\n\n75.00\n\n \n\n52.50\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n25.00\n\n \n\n \n\n \n\nKellam Solar Class B Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nKellam Tax Equity Partnership Llc\n\nDover (USA)\n\nUSA\n\n \n\nKellam Solar Class B\n\n93.90\n\n \n\n65.73\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n6.10\n\n \n\n \n\n \n\nKillington SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nKrypton SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Op. Fr. SAS\n\n100.00\n\n \n\n70.00\n\n \n\nLadronera Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nLanas Solar SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nHolding Lanas Solar Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nLone Pine Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nMaristella Directorship SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Spain SLU\n\n100.00\n\n \n\n70.00\n\n \n\nMembrio Solar SLU\n\nLodosa (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nMiburia Trade SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. T. S. Spain\n\n100.00\n\n \n\n70.00\n\n \n\nMuddy Creek Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nOlea Solar SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nParc Eolien des Avaloirs SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nPlenitude Kazakhstan Llp (former Arm Wind Llp)\n\nAstana (Kazakhstan)\n\nKazakhstan\n\n \n\nEni Plen. Ren. Hold. BV\n\n100.00\n\n \n\n70.00\n\n \n\nPlenitude Production France SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nPlenitude Zephyr France SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Prod. France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nPlumlee SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nPOP Solar SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Ren. Lux. Sàrl\n\n100.00\n\n \n\n70.00\n\n \n\nQuiver River Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nRenopool 1 SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Spain SLU\n\n100.00\n\n \n\n70.00\n\n \n\nRichwood Invest SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plenitude SpA SB\n\n100.00\n\n \n\n70.00\n\n \n\nSandrini 100 Class B Member Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nSandrini 200 Class B Member Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nSandrini BESS Class B Member Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nSASU PV Les Poulettes SAS\n\nLevallois-Perret (France)\n\nFrance\n\n \n\nPlen. Zephyr France SAS\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV1 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV2 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nF-126\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nSKGRPV3 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV4 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV5 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV6 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV7 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV8 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV9 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV12 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV13 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV14 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV15 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV16 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV17 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV19 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSKGRPV20 Single Member Private Company\n\nAthens (Greece)\n\nGreece\n\n \n\nEni Plen. Renew. Hellas\n\n100.00\n\n \n\n70.00\n\n \n\nSouth Triangle Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nTallahatchie Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nTantalio Renovables SLU\n\nMadrid (Spain)\n\nSpain\n\n \n\nEni Plen. Ren. Spain SLU\n\n100.00\n\n \n\n70.00\n\n \n\nTimber Road Blue Harvest Class A Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US Inc\n\n100.00\n\n \n\n70.00\n\n \n\nTurner Creek Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nWatertown Energy Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni New Energy US H. Llc\n\n100.00\n\n \n\n70.00\n\n \n\nWind Grower SLU\n\nOurense (Spain)\n\nSpain\n\n \n\nEni Plen. T. S. Spain\n\n100.00\n\n \n\n70.00\n\n \n\nWind Hero SLU\n\nOurense (Spain)\n\nSpain\n\n \n\nEni Plen. T. S. Spain\n\n100.00\n\n \n\n70.00\n\n \n\nXenon SAS\n\nArgenteuil (France)\n\nFrance\n\n \n\nEni Plen. Op. Fr. SAS\n\n100.00\n\n \n\n70.00\n\n \n\n \n\nF-127\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCORPORATE AND OTHER ACTIVITIES\n\nCorporate and financial companies\n\nIN ITALY \n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nAgenzia Giornalistica Italia SpA\n\nRome\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nD-Share SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nAGI SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEniBioCh4in Aprilia Srl\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniBioCh4in SpA\n\n100.00\n\n \n\n85.00\n\n \n\nEniBioCh4in Grupellum Società Agricola Srl\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniBioCh4in SpA\n\n98.00\n\n \n\n83.30\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n2.00\n\n \n\n \n\n \n\nEniBioCh4in Jonica Srl\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniBioCh4in SpA\n\n100.00\n\n \n\n85.00\n\n \n\nEniBioCh4in Pannellia BioGas Srl Società Agricola\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniBioCh4in SpA\n\n100.00\n\n \n\n85.00\n\n \n\nEniBioCh4in Po Energia Srl Società Agricola\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniBioCh4in SpA\n\n100.00\n\n \n\n85.00\n\n \n\nEniBioCh4in Quadruvium Srl Società Agricola\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniBioCh4in SpA\n\n100.00\n\n \n\n85.00\n\n \n\nEniBioCh4in SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEnilive SpA\n\n50.00\n\n \n\n85.00\n\n \n\n \n\n \n\n \n\n \n\nEni SpA\n\n50.00\n\n \n\n \n\n \n\nEni Corporate University SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni Insurance SpA\n\nRome\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEniServizi SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEniverse Ventures Srl\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEnivibes Srl\n\nVimodrone (MI)\n\nItaly\n\n \n\nEniverse\n\n76.00\n\n \n\n76.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n24.00\n\n \n\n \n\n \n\nServizi Aerei SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nOUTSIDE ITALY\n\n \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nBanque Eni SA\n\nBruxelles (Belgium)\n\nBelgium\n\n \n\nEni International BV\n\n99.90\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni Oil Holdings BV\n\n0.10\n\n \n\n \n\n \n\nEni International BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni SpA\n\n100.00\n\n \n\n100.00\n\n \n\nEni International Resources Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\n \n\nEni SpA\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nEni UK Ltd\n\n(..)\n\n \n\n \n\n \n\nEni Netherlands Holding BV\n\nAmsterdam (Netherlands)\n\nNetherlands\n\n \n\nEni International BV\n\n100.00\n\n \n\n100.00\n\n \n\nEni Next Llc\n\nDover (USA)\n\nUSA\n\n \n\nEni Petroleum Co Inc\n\n100.00\n\n \n\n100.00\n\n \n\n \n\nF-128\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOther activities \n\nIN ITALY   \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nEni Rewind SpA\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEni SpA\n\n99.99\n\n \n\n100.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n(..)\n\n \n\n \n\n \n\n \n\nJOINT OPERATIONS\n\nEXPLORATION & PRODUCTION\n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nNOGAT BV\n\nThe Hague (Netherlands)\n\nNetherlands\n\n \n\nEni En. Holding NL BV\n\n15.00\n\n \n\n15.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n85.00\n\n \n\n \n\n \n\nGLOBAL GAS & LNG PORTFOLIO AND POWER\n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nBlue Stream Pipeline Co BV\n\nAmsterdam (Netherlands)\n\nRussia\n\n \n\nEni International BV\n\n50.00\n\n \n\n74.62\n\n(a)\n\n \n\n \n\n \n\n \n\nThird parties\n\n50.00\n\n \n\n \n\n \n\nDamietta LNG (DLNG) SAE\n\nDamietta (Egypt)\n\nEgypt\n\n \n\nEni Gas Liquef. BV\n\n50.00\n\n \n\n50.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n50.00\n\n \n\n \n\n \n\nDLNG Service SAE\n\nDamietta (Egypt)\n\nEgypt\n\n \n\nDamietta LNG\n\n98.00\n\n \n\n50.00\n\n \n\n \n\n \n\n \n\n \n\nEni Gas Liquef. BV\n\n1.00\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n1.00\n\n \n\n \n\n \n\nGreenStream BV\n\nAmsterdam (Netherlands)\n\nLibya\n\n \n\nEni North Africa BV\n\n50.00\n\n \n\n50.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n50.00\n\n \n\n \n\n \n\n \n\n(a) Equity ratio equal to the Eni's working interest.\n\n \n\nPOWER\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nSocietà EniPower Ferrara Srl\n\nSan Donato Milanese (MI)\n\nItaly\n\n \n\nEniPower SpA\n\n51.00\n\n \n\n26.01\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n49.00\n\n \n\n \n\n \n\n \n\nREFINING AND CHEMICALS \n\nRefining\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nCostiero Gas Livorno SpA\n\nLivorno\n\nItaly\n\n \n\nEcofuel SpA\n\n65.00\n\n \n\n65.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n35.00\n\n \n\n \n\n \n\nRaffineria di Milazzo ScpA\n\nMilazzo (ME)\n\nItaly\n\n \n\nEni SpA\n\n50.00\n\n \n\n50.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n50.00\n\n \n\n \n\n \n\n \n\nF-129\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nSupermetanol CA\n\nJose Puerto La Cruz (Venezuela)\n\nVenezuela\n\n \n\nEcofuel SpA\n\n34.51\n\n \n\n50.00\n\n(a)\n\n \n\n \n\n \n\n \n\nSupermetanol CA\n\n30.07\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n35.42\n\n \n\n \n\n \n\n \n\n(a) Equity ratio equal to the Eni's working interest.\n\n \n\nENILIVE AND PLENITUDE\n\nENILIVE\n\nOUTSIDE ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nBayernoil Raffineriegesellschaft mbH\n\nVohburg (Germany)\n\nGermany\n\n \n\nEnilive Deutsch. GmbH\n\n20.00\n\n \n\n14.66\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n80.00\n\n \n\n \n\n \n\n \n\nCORPORATE AND OTHER ACTIVITIES\n\nOther activities\n\nIN ITALY\n\nCompany name\n\nRegistered office\n\nCountry of operation\n\n \n\nShareholders\n\n% Ownership\n\n \n\n% Equity ratio\n\n \n\nHEA SpA\n\nBologna\n\nItaly\n\n \n\nEni Rewind SpA\n\n50.00\n\n \n\n50.00\n\n \n\n \n\n \n\n \n\n \n\nThird parties\n\n50.00\n\n \n\n \n\n \n\n \n\nInformation on Eni’s consolidated subsidiaries with significant non-controlling interest\n\nThe following section provides information about economic, equity and financial data, gross of intragroup elisions, relating to Enilive Group, 70% owned by Eni, the Plenitude Group, 70% owned by Eni, and EniPower group, 51% owned by Eni. The ownership of the non-controlling interest corresponds to voting rights.\n\n \n\n \n\nEnilive Group\n\nPlenitude Group\n\nEniPower Group\n\n(€ million)\n\n2025\n\n2025\n\n2024\n\n2025\n\n2024\n\nNon controlling interest (%)\n\n30.00\n\n30.00\n\n7.58\n\n49.00\n\n49.00\n\nCurrent assets\n\n5,607\n\n3,725\n\n4,571\n\n851\n\n695\n\nNon-current assets\n\n4,683\n\n12,053\n\n11,185\n\n927\n\n934\n\nCurrent liabilities\n\n5,605\n\n4,482\n\n4,626\n\n839\n\n709\n\nNon-current liabilities\n\n1,786\n\n5,351\n\n5,156\n\n29\n\n31\n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues\n\n19,120\n\n10,168\n\n10,179\n\n1,142\n\n962\n\nProfit\n\n344\n\n(3)\n\n803\n\n126\n\n167\n\nTotal comprehensive income\n\n268\n\n(158)\n\n821\n\n126\n\n167\n\n \n\n \n\n \n\n \n\n \n\n \n\nNet cash provided by operating activities\n\n771\n\n1,196\n\n916\n\n206\n\n178\n\nNet cash used in investing activities\n\n(542)\n\n(1,206)\n\n(1,389)\n\n(77)\n\n(92)\n\nNet cash used in financing activities\n\n435\n\n(13)\n\n(85)\n\n1\n\n(18)\n\nNet increase (decrease) in cash and cash equivalents\n\n773\n\n104\n\n(23)\n\n21\n\n(9)\n\nProfit attributable to non-controlling interest\n\n87\n\n6\n\n54\n\n64\n\n85\n\nDividends paid to minority interest\n\n212\n\n9\n\n5\n\n56\n\n41\n\nEquity pertaining to non-controlling interests as of December 31, 2025, amounted to €4,847 million (€2,863 million December 31, 2024) and includes the perpetual subordinated bond of Eni Marine Services SpA of €1,701 million. More information is reported in note 26 – Equity – Non-controlling interest.\n\n \n\nF-130\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nChanges in the ownership interest without loss of control\n\nOn March 6, 2025, Eni and the private equity fund KKR finalized KKR's investment in a 25% minority stake in its subsidiary Enilive, with total proceeds for Eni of €2,968 million, including a capital increase of €500 million. Subsequently, on April 11, 2025, Eni and KKR completed a similar transaction for an additional 5% investment for approximately €601 million. Following the transaction, KKR holds a total stake of 30% of Enilive’s share capital.\n\nOn March 31, 2025, Energy Infrastructure Partners (EIP) completed an increase in Plenitude's share capital, reaching a total stake of 10%. EIP's increase was achieved through a capital increase of approximately €209 million, which, taking into account the of €588 million paid in March 2024, brings the total investment to approximately €800 million. On November 4, Eni and the private equity fund Ares Capital finalized an investment in a 20% minority stake in Plenitude for €2,003 million.\n\nPrincipal joint ventures, joint operations and associates as of December 31, 2025 \n\nCompany name\n\nRegistered office\n\nCountry of operation\n\nSegment\n\n% ownership\n\n% equity ratio\n\nJoint venture\n\n \n\n \n\n \n\n \n\n \n\n2023 Sol IX Llc\n\nWilmington (USA)\n\nUSA\n\nPlenitude\n\n73.62\n\n73.62\n\nAzule Energy Holdings Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\nExploration & Production\n\n50.00\n\n50.00\n\nCardón IV SA\n\nCaracas (Venezuela)\n\nVenezuela\n\nExploration & Production\n\n50.00\n\n50.00\n\nEni CCUS Holding Ltd\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\nExploration & Production\n\n50.01\n\n50.01\n\nE&E Algeria Touat BV\n\nThe Hague (Netherlands)\n\nAlgeria\n\nExploration & Production\n\n66.00\n\n66.00\n\nGreenIT SpA\n\nSan Donato Milanese (MI) (Italy)\n\nItaly\n\nPlenitude\n\n51.00\n\n51.00\n\nMozambique Rovuma Venture SpA\n\nSan Donato Milanese (MI) (Italy)\n\nMozambique\n\nExploration & Production\n\n35.71\n\n35.71\n\nSaipem SpA\n\nMilan (Italy)\n\nItaly\n\nCorporate and financial companies\n\n21.19\n\n21.80\n\nSeaCorridor Srl\n\nSan Donato Milanese (MI) (Italy)\n\nItaly\n\nGlobal Gas & LNG Portfolio\n\n50.10\n\n50.10\n\nSt. Bernard Renewables Llc\n\nWilmington (USA)\n\nUSA\n\nEnilive\n\n50.00\n\n50.00\n\nVårgrønn AS\n\nStavanger (Norway)\n\nNorway\n\nPlenitude\n\n65.00\n\n65.00\n\nJoint Operation\n\n \n\n \n\n \n\n \n\n \n\nDamietta LNG (DLNG) SAE\n\nDamietta (Egypt)\n\nEgypt\n\nGlobal Gas & LNG Portfolio\n\n50.00\n\n50.00\n\nGreenStream BV\n\nAmsterdam (Netherlands)\n\nLibya\n\nGlobal Gas & LNG Portfolio\n\n50.00\n\n50.00\n\nBlue Stream Pipeline Co BV\n\nAmsterdam(Netherlands)\n\nRussia\n\nGlobal Gas & LNG Portfolio\n\n50.00\n\n50.00\n\nAssociates\n\n \n\n \n\n \n\n \n\n \n\nADNOC Global Trading Ltd\n\nAbu Dhabi (United Arab Emirates)\n\nUnited Arab Emirates\n\nRefining\n\n20.00\n\n20.00\n\nAbu Dhabi Oil Refining Company (Takreer)\n\nAbu Dhabi (United Arab Emirates)\n\nUnited Arab Emirates\n\nRefining\n\n20.00\n\n20.00\n\nCoral FLNG SA\n\nMaputo (Mozambique)\n\nMozambique\n\nExploration & Production\n\n25.00\n\n25.00\n\nIthaca Energy Plc\n\nLondon (United Kingdom)\n\nUnited Kingdom\n\nExploration & Production\n\n35.92\n\n35.92\n\nQatarEnergy LNG NFE (5)\n\nDoha (Qatar)\n\nQatar\n\nExploration & Production\n\n25.00\n\n25.00\n\nVår Energi ASA\n\nSandnes (Norvegia)\n\nNorway\n\nExploration & Production\n\n63.04\n\n63.04\n\n \n\nF-131\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nMain 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:\n\n \n\n2025\n\n(€ million)\n\nAzule Energy Holdings Ltd\n\nSt. Bernard Renewables Llc\n\nE&E Algeria Touat BV\n\nSaipem SpA\n\nSeaCorridor Srl\n\nCurrent assets\n\n3,394\n\n395\n\n117\n\n9,122\n\n114\n\n- of which cash and cash equivalent\n\n507\n\n23\n\n56\n\n1,707\n\n80\n\nNon-current assets\n\n21,678\n\n1,310\n\n1,224\n\n5,425\n\n578\n\nTotal assets\n\n25,072\n\n1,705\n\n1,341\n\n14,547\n\n692\n\nCurrent liabilities\n\n4,295\n\n116\n\n33\n\n8,393\n\n93\n\n- of which current financial liabilities\n\n1,744\n\n116\n\n \n\n1,012\n\n29\n\nNon-current liabilities\n\n9,657\n\n309\n\n291\n\n3,410\n\n140\n\n- of which non-current financial liabilities\n\n4,956\n\n308\n\n \n\n2,094\n\n123\n\nTotal liabilities\n\n13,952\n\n425\n\n324\n\n11,803\n\n233\n\nNet equity\n\n11,120\n\n1,280\n\n1,017\n\n2,744\n\n459\n\nEni’s share of the investment (%)\n\n50.00\n\n50.00\n\n66.00\n\n21.80\n\n50.10\n\nGoodwill, Group capital gains and perpetual subordinated bonds\n\n(926)\n\n17\n\n \n\n(17)\n\n181\n\nBook value of the investment\n\n4,634\n\n657\n\n671\n\n581\n\n411\n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues and other income\n\n3,917\n\n999\n\n287\n\n15,508\n\n343\n\nOperating expense\n\n(822)\n\n(961)\n\n(90)\n\n(13,792)\n\n(44)\n\nOther operating profit (loss)\n\n(47)\n\n(75)\n\n \n\n \n\n \n\nDepreciation, amortization and impairments\n\n(2,188)\n\n(57)\n\n(88)\n\n(1,037)\n\n(47)\n\nOperating profit (loss)\n\n860\n\n(94)\n\n109\n\n679\n\n252\n\nFinance income (expense)\n\n(268)\n\n2\n\n(3)\n\n(189)\n\n(1)\n\nIncome (expense) from investments\n\n289\n\n(24)\n\n \n\n28\n\n28\n\nProfit (loss) before income taxes\n\n881\n\n(116)\n\n106\n\n518\n\n279\n\nIncome taxes\n\n(238)\n\n \n\n(53)\n\n(207)\n\n(214)\n\nProfit (loss)\n\n643\n\n(116)\n\n53\n\n311\n\n65\n\nOther comprehensive income (loss)\n\n(1,212)\n\n(182)\n\n(115)\n\n156\n\n(24)\n\nTotal other comprehensive income (loss)\n\n(569)\n\n(298)\n\n(62)\n\n467\n\n41\n\nProfit (loss) attributable to Eni\n\n415\n\n(58)\n\n35\n\n71\n\n32\n\n \n\n \n\n \n\n \n\n \n\n \n\nDividends received from the joint venture\n\n386\n\n \n\n \n\n72\n\n95\n\n \n\nF-132\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n \n\n2024\n\n \n\n(€ million)\n\nAzule Energy Holdings Ltd\n\nSt. Bernard Renewables Llc\n\nE&E Algeria Touat BV\n\nSaipem\n\nSpA\n\nSeaCorridor\n\nSrl\n\nCurrent assets\n\n3,181\n\n313\n\n130\n\n9,675\n\n134\n\n- of which cash and cash equivalent\n\n549\n\n72\n\n55\n\n2,158\n\n89\n\nNon-current assets\n\n23,042\n\n1,577\n\n1,497\n\n4,844\n\n580\n\nTotal assets\n\n26,223\n\n1,890\n\n1,627\n\n14,519\n\n714\n\nCurrent liabilities\n\n3,505\n\n99\n\n54\n\n8,564\n\n126\n\n- of which current financial liabilities\n\n1,182\n\n \n\n \n\n796\n\n \n\nNon-current liabilities\n\n9,796\n\n217\n\n376\n\n3,431\n\n15\n\n- of which non-current financial liabilities\n\n3,297\n\n215\n\n \n\n2,220\n\n1\n\nTotal liabilities\n\n13,301\n\n316\n\n430\n\n11,995\n\n141\n\nNet equity\n\n12,922\n\n1,574\n\n1,197\n\n2,524\n\n573\n\nEni’s share of the investment (%)\n\n50.00\n\n50.00\n\n54.00\n\n21.61\n\n50.10\n\nGoodwill, Group capital gains and perpetual subordinated bonds\n\n(1,250)\n\n19\n\n \n\n(17)\n\n198\n\nBook value of the investment\n\n5,211\n\n806\n\n646\n\n528\n\n485\n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues and other income\n\n4,961\n\n1,220\n\n290\n\n14,552\n\n332\n\nOperating expense\n\n(1,261)\n\n(1,134)\n\n(98)\n\n(13,224)\n\n(45)\n\nOther operating profit (loss)\n\n \n\n(93)\n\n \n\n1\n\n \n\nDepreciation, amortization and impairments\n\n(1,479)\n\n(72)\n\n(105)\n\n(723)\n\n(44)\n\nOperating profit (loss)\n\n2,221\n\n(79)\n\n87\n\n606\n\n243\n\nFinance income (expense)\n\n(474)\n\n(11)\n\n \n\n(85)\n\n6\n\nIncome (expense) from investments\n\n208\n\n \n\n \n\n(25)\n\n29\n\nProfit (loss) before income taxes\n\n1,955\n\n(90)\n\n87\n\n496\n\n278\n\nIncome taxes\n\n(751)\n\n \n\n(13)\n\n(190)\n\n(189)\n\nProfit (loss)\n\n1,204\n\n(90)\n\n74\n\n306\n\n89\n\nOther comprehensive income (loss)\n\n572\n\n99\n\n72\n\n(124)\n\n11\n\nTotal other comprehensive income (loss)\n\n1,776\n\n9\n\n146\n\n182\n\n100\n\nProfit (loss) attributable to Eni\n\n602\n\n(45)\n\n40\n\n75\n\n45\n\n \n\n \n\n \n\n \n\n \n\n \n\nDividends received from the joint venture\n\n427\n\n \n\n \n\n \n\n95\n\n \n\nF-133\n\n[Table of Contents](#TOC_TableofContent)\n\nThe results for the year and the comprehensive income of the significant joint ventures are shown below:\n\n \n\n2025\n\n(€ million)\n\n2023 Sol IX Llc\n\nGreenIT SpA\n\nMozambique Rovuma Venture SpA\n\nCardón IV SA\n\nVårgrønn AS\n\nProfit (loss)\n\n \n\n5\n\n100\n\n125\n\n(54)\n\nOther comprehensive income (loss)\n\n(24)\n\n(1)\n\n(131)\n\n(87)\n\n(42)\n\nTotal other comprehensive income (loss)\n\n(24)\n\n4\n\n(31)\n\n38\n\n(96)\n\n \n\n \n\n2024\n\n(€ million)\n\n2023 Sol IX Llc\n\nGreenIT SpA\n\nMozambique Rovuma Venture SpA\n\nCardón IV SA\n\nVårgrønn AS\n\nProfit (loss)\n\n1\n\n4\n\n47\n\n(18)\n\n(57)\n\nOther comprehensive income (loss)\n\n8\n\n(2)\n\n64\n\n47\n\n26\n\nTotal other comprehensive income (loss)\n\n9\n\n2\n\n111\n\n29\n\n(31)\n\n \n\nMain 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:\n\n \n\n2025\n\n(€ million)\n\nAbu Dhabi Oil Refining Company (TAKREER)\n\nVår Energi ASA\n\nIthaca Energy Plc\n\nQatarEnergy LNG NFE (5)\n\nCurrent assets\n\n5,730\n\n1,533\n\n980\n\n \n\n- of which cash and cash equivalent\n\n6\n\n595\n\n154\n\n \n\nNon-current assets\n\n15,401\n\n20,705\n\n6,194\n\n2,863\n\nTotal assets\n\n21,131\n\n22,238\n\n7,174\n\n2,863\n\nCurrent liabilities\n\n4,857\n\n2,316\n\n1,242\n\n151\n\n- of which current financial liabilities\n\n \n\n199\n\n62\n\n \n\nNon-current liabilities\n\n6,373\n\n19,446\n\n3,758\n\n70\n\n- of which non-current financial liabilities\n\n5,995\n\n5,067\n\n1,243\n\n \n\nTotal liabilities\n\n11,230\n\n21,762\n\n5,000\n\n221\n\nNet equity\n\n9,901\n\n476\n\n2,174\n\n2,642\n\nEni’s share of the investment (%)\n\n20.00\n\n63.04\n\n35.92\n\n25.00\n\nGoodwill, Group capital gains and perpetual subordinated bonds\n\n \n\n(300)\n\n(295)\n\n \n\nBook value of the investment\n\n1,980\n\n \n\n486\n\n661\n\n \n\n \n\n \n\n \n\n \n\nRevenues and other income\n\n23,417\n\n7,164\n\n2,607\n\n \n\nOperating expense\n\n(21,341)\n\n(1,409)\n\n(815)\n\n(12)\n\nOther operating income (expense)\n\n(831)\n\n \n\n \n\n \n\nDepreciation, amortization and impairments\n\n(755)\n\n(1,888)\n\n(824)\n\n \n\nOperating profit (loss)\n\n490\n\n3,867\n\n968\n\n(12)\n\nFinance income (expense)\n\n(381)\n\n73\n\n(226)\n\n(2)\n\nIncome (expense) from investments\n\n \n\n \n\n \n\n \n\nProfit (loss) before income taxes\n\n109\n\n3,940\n\n742\n\n(14)\n\nIncome taxes\n\n7\n\n(3,061)\n\n(809)\n\n4\n\nProfit (loss)\n\n116\n\n879\n\n(67)\n\n(10)\n\nOther comprehensive income (loss)\n\n(1,308)\n\n80\n\n(128)\n\n(310)\n\nTotal other comprehensive income (loss)\n\n(1,192)\n\n959\n\n(195)\n\n(320)\n\nProfit (loss) attributable to Eni\n\n23\n\n602\n\n(15)\n\n(3)\n\n \n\n \n\n \n\n \n\n \n\nDividends received from the associate\n\n56\n\n653\n\n161\n\n \n\n \n\nF-134\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n \n\n2024\n\n(€ million)\n\nAbu Dhabi Oil Refining Company (TAKREER)\n\nVår Energi ASA\n\nIthaca Energy Plc\n\nQatarEnergy LNG NFE (5)\n\nCurrent assets\n\n6,719\n\n1,219\n\n946\n\n \n\n- of which cash and cash equivalent\n\n47\n\n268\n\n170\n\n \n\nNon-current assets\n\n18,130\n\n19,822\n\n7,036\n\n2,658\n\nTotal assets\n\n24,849\n\n21,041\n\n7,982\n\n2,658\n\nCurrent liabilities\n\n3,835\n\n1,825\n\n1,320\n\n60\n\n- of which current financial liabilities\n\n \n\n68\n\n31\n\n \n\nNon-current liabilities\n\n9,640\n\n18,415\n\n3,775\n\n67\n\n- of which non-current financial liabilities\n\n6,543\n\n5,795\n\n994\n\n \n\nTotal liabilities\n\n13,475\n\n20,240\n\n5,095\n\n127\n\nNet equity\n\n11,374\n\n801\n\n2,887\n\n2,531\n\nEni’s share of the investment (%)\n\n20.00\n\n63.04\n\n37.17\n\n25.00\n\nGoodwill, Group capital gains and perpetual subordinated bonds\n\n \n\n(505)\n\n(348)\n\n \n\nBook value of the investment\n\n2,275\n\n \n\n725\n\n633\n\n \n\n \n\n \n\n \n\n \n\nRevenues and other income\n\n12,879\n\n6,884\n\n703\n\n \n\nOperating expense\n\n(11,985)\n\n(1,375)\n\n(134)\n\n(6)\n\nOther operating income (expense)\n\n(386)\n\n \n\n \n\n \n\nDepreciation, amortization and impairments\n\n(338)\n\n(1,884)\n\n(367)\n\n \n\nOperating profit (loss)\n\n170\n\n3,625\n\n202\n\n(6)\n\nFinance income (expense)\n\n(332)\n\n(455)\n\n(66)\n\n1\n\nProfit (loss) before income taxes\n\n(162)\n\n3,170\n\n136\n\n(5)\n\nIncome taxes\n\n \n\n(2,759)\n\n(118)\n\n1\n\nProfit (loss)\n\n(162)\n\n411\n\n18\n\n(4)\n\nOther comprehensive income (loss)\n\n708\n\n(125)\n\n100\n\n138\n\nTotal other comprehensive income (loss)\n\n546\n\n286\n\n118\n\n134\n\nProfit (loss) attributable to Eni\n\n(32)\n\n259\n\n7\n\n(1)\n\n \n\n \n\n \n\n \n\n \n\nDividends received from the associate\n\n269\n\n627\n\n69\n\n \n\nThe results for the year and the comprehensive income of the significant associates are shown below:\n\n \n\n2025\n\n(€ million)\n\nADNOC Global Trading Ltd\n\nCoral FLNG SA\n\nProfit (loss)\n\n481\n\n(84)\n\nOther comprehensive income (loss)\n\n(106)\n\n(104)\n\nTotal other comprehensive income (loss)\n\n375\n\n(188)\n\n \n\n \n\n2024\n\n(€ million)\n\nADNOC Global Trading Ltd\n\nCoral FLNG SA\n\nProfit (loss)\n\n563\n\n(33)\n\nOther comprehensive income (loss)\n\n48\n\n57\n\nTotal other comprehensive income (loss)\n\n611\n\n24\n\n \n\nF-135\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n38 Significant non-recurring events and operations\n\nIn 2025, in 2024 and 2023, Eni did not report any non-recurring events and operations.\n\n \n\n39 Positions or transactions deriving from atypical and/or unusual operations\n\nIn 2025, in 2024 and 2023, no transactions deriving from atypical and/or unusual operations were reported.\n\n \n\n40 Subsequent events\n\nAfter the balance sheet date and as the Iran conflict unfolded, oil, gas and refined products supply from the Middle East have been impacted. Commodity markets showed high volatility, creating uncertainty with regards to prices for oil and gas and refining margins. As at the date of these Consolidated Financial Statements, the conflict has not resulted in a material impact on Eni’s financial position and results of operations. The scale and duration of the conflict remain uncertain but could affect Eni's result, cash flow and financial condition.\n\n \n\nOn March 19, 2026, Eni initiated a reorganization of Plenitude's shareholding structure, together with the existing shareholders Ares Alternative Credit (affiliates of Ares Management Corporation) and Energy Infrastructure Partners. The aim is to establish a new governance framework based on joint control between Eni and Ares, resulting in the deconsolidation of Plenitude from Eni's financial statements. The transaction is subject to the approval of the competent authorities.\n\n \n\nF-136\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nSupplemental oil and gas information (unaudited)\n\nThe 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.\n\nCapitalized costs\n\nCapitalized 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.\n\nCapitalized costs by geographical area consist of the following:\n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProved property\n\n19,413\n\n2,878\n\n37,204\n\n17,659\n\n13,229\n\n15,150\n\n11,961\n\n1,447\n\n118,941\n\nUnproved property\n\n22\n\n102\n\n544\n\n957\n\n \n\n1,260\n\n341\n\n207\n\n3,433\n\nSupport equipment and facilities\n\n339\n\n27\n\n1,853\n\n752\n\n125\n\n13\n\n24\n\n12\n\n3,145\n\nIncomplete wells and other\n\n727\n\n323\n\n2,846\n\n1,598\n\n731\n\n2,754\n\n375\n\n125\n\n9,479\n\nGross Capitalized Costs\n\n20,501\n\n3,330\n\n42,447\n\n20,966\n\n14,085\n\n19,177\n\n12,701\n\n1,791\n\n134,998\n\nAccumulated depreciation, depletion and amortization\n\n(17,215)\n\n(2,712)\n\n(30,329)\n\n(11,343)\n\n(5,351)\n\n(11,981)\n\n(9,843)\n\n(915)\n\n(89,689)\n\nNet Capitalized Costs consolidated subsidiaries (a)\n\n3,286\n\n618\n\n12,118\n\n9,623\n\n8,734\n\n7,196\n\n2,858\n\n876\n\n45,309\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProved property\n\n \n\n19,073\n\n717\n\n9,731\n\n \n\n261\n\n1,910\n\n \n\n31,692\n\nUnproved property\n\n \n\n205\n\n173\n\n76\n\n \n\n \n\n \n\n \n\n454\n\nSupport equipment and facilities\n\n \n\n96\n\n10\n\n73\n\n \n\n \n\n8\n\n \n\n187\n\nIncomplete wells and other\n\n \n\n1,053\n\n22\n\n2,731\n\n \n\n455\n\n221\n\n \n\n4,482\n\nGross Capitalized Costs\n\n \n\n20,427\n\n922\n\n12,611\n\n \n\n716\n\n2,139\n\n \n\n36,815\n\nAccumulated depreciation, depletion and amortization\n\n \n\n(7,803)\n\n(192)\n\n(3,377)\n\n \n\n \n\n(1,518)\n\n \n\n(12,890)\n\nNet Capitalized Costs equity-accounted entities (a) (b)\n\n \n\n12,624\n\n730\n\n9,234\n\n \n\n716\n\n621\n\n \n\n23,925\n\n(a) The amounts include net capitalized financial charges totalling €747 million for consolidates subsidiaries and €1,075 million for equity-accounted entities.\n\n(b) The amounts include the allocation at fair value of (i) the acquisition of an additional 12% stake in E&E Algeria Touat BV; (ii) the acquisition by Ithaca of JAPEX UK Limited and a stake of 46.25% of Spirit Energy; the acquisition by Var Energi of Ekofisk PPF's assets.\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProved property\n\n19,272\n\n3,242\n\n43,769\n\n30,245\n\n14,379\n\n15,223\n\n16,212\n\n1,626\n\n143,968\n\nUnproved property\n\n22\n\n190\n\n651\n\n2,393\n\n \n\n2,259\n\n887\n\n209\n\n6,611\n\nSupport equipment and facilities\n\n339\n\n29\n\n2,012\n\n837\n\n138\n\n14\n\n26\n\n13\n\n3,408\n\nIncomplete wells and other\n\n756\n\n249\n\n2,554\n\n2,583\n\n1,202\n\n2,232\n\n388\n\n149\n\n10,113\n\nGross Capitalized Costs\n\n20,389\n\n3,710\n\n48,986\n\n36,058\n\n15,719\n\n19,728\n\n17,513\n\n1,997\n\n164,100\n\nAccumulated depreciation, depletion and amortization\n\n(16,541)\n\n(2,969)\n\n(36,505)\n\n(24,075)\n\n(5,441)\n\n(12,698)\n\n(14,273)\n\n(1,108)\n\n(113,610)\n\nNet Capitalized Costs consolidated subsidiaries (a) (c)\n\n3,848\n\n741\n\n12,481\n\n11,983\n\n10,278\n\n7,030\n\n3,240\n\n889\n\n50,490\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProved property\n\n \n\n12,751\n\n645\n\n10,137\n\n \n\n295\n\n2,150\n\n \n\n25,978\n\nUnproved property\n\n \n\n1,178\n\n149\n\n88\n\n \n\n \n\n \n\n \n\n1,415\n\nSupport equipment and facilities\n\n \n\n86\n\n9\n\n82\n\n \n\n \n\n9\n\n \n\n186\n\nIncomplete wells and other\n\n \n\n4,989\n\n22\n\n2,246\n\n \n\n370\n\n249\n\n \n\n7,876\n\nGross Capitalized Costs\n\n \n\n19,004\n\n825\n\n12,553\n\n \n\n665\n\n2,408\n\n \n\n35,455\n\nAccumulated depreciation, depletion and amortization\n\n \n\n(6,799)\n\n(140)\n\n(2,809)\n\n \n\n \n\n(1,644)\n\n \n\n(11,392)\n\nNet Capitalized Costs equity-accounted entities (a) (b)\n\n \n\n12,205\n\n685\n\n9,744\n\n \n\n665\n\n764\n\n \n\n24,063\n\n \n\n \n\n \n\n(a) The amounts include net capitalized financial charges totalling €830 million for consolidates subsidiaries and €996 million for equity-accounted entities.\n\n(b) Includes allocation at fair value of the assets of Neptune Energy Group.\n\n(c) Includes allocation at fair value of the assets of Neptune Energy Group and of Ithaca Energy in UK.\n\n \n\nF-137\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nCosts incurred\n\nCosts incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:\n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProved property acquisitions\n\n \n\n \n\n3\n\n68\n\n \n\n \n\n \n\n \n\n71\n\nUnproved property acquisitions\n\n \n\n \n\n7\n\n26\n\n \n\n115\n\n \n\n3\n\n151\n\nExploration\n\n19\n\n15\n\n152\n\n101\n\n2\n\n217\n\n62\n\n4\n\n572\n\nDevelopment (a)\n\n177\n\n53\n\n2,346\n\n1,842\n\n195\n\n1,935\n\n560\n\n162\n\n7,270\n\nTotal costs incurred consolidated subsidiaries\n\n196\n\n68\n\n2,508\n\n2,037\n\n197\n\n2,267\n\n622\n\n169\n\n8,064\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProved property acquisitions\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nUnproved property acquisitions\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExploration\n\n \n\n258\n\n \n\n135\n\n \n\n \n\n \n\n \n\n393\n\nDevelopment (b)\n\n \n\n1,761\n\n26\n\n1,440\n\n \n\n133\n\n10\n\n \n\n3,370\n\nTotal costs incurred equity-accounted entities\n\n \n\n2,019\n\n26\n\n1,575\n\n \n\n133\n\n10\n\n \n\n3,763\n\n \n\n \n\n(a) Includes abandonment costs for €318 million in 2025.\n\n(b) Includes abandonment costs for €87 million in 2025.\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExploration\n\n47\n\n53\n\n98\n\n139\n\n57\n\n128\n\n124\n\n2\n\n648\n\nDevelopment (a)\n\n445\n\n340\n\n1,168\n\n3,250\n\n252\n\n1,012\n\n760\n\n101\n\n7,328\n\nTotal costs incurred consolidated subsidiaries\n\n492\n\n393\n\n1,266\n\n3,389\n\n309\n\n1,140\n\n884\n\n103\n\n7,976\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExploration\n\n \n\n231\n\n \n\n90\n\n \n\n \n\n \n\n \n\n321\n\nDevelopment (b)\n\n \n\n1,850\n\n15\n\n1,191\n\n \n\n157\n\n(6)\n\n \n\n3,207\n\nTotal costs incurred equity-accounted entities\n\n \n\n2,081\n\n15\n\n1,281\n\n \n\n157\n\n(6)\n\n \n\n3,528\n\n \n\n \n\n(a) Includes abandonment costs for €73 million in 2024.\n\n(b) Includes abandonment costs for €42 million in 2024.\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExploration\n\n12\n\n55\n\n328\n\n189\n\n9\n\n277\n\n138\n\n1\n\n1,009\n\nDevelopment (a)\n\n798\n\n249\n\n1,633\n\n2,662\n\n296\n\n921\n\n937\n\n151\n\n7,647\n\nTotal costs incurred consolidated subsidiaries\n\n810\n\n304\n\n1,961\n\n2,851\n\n305\n\n1,198\n\n1,075\n\n152\n\n8,656\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExploration\n\n \n\n92\n\n \n\n46\n\n \n\n \n\n \n\n \n\n138\n\nDevelopment (b)\n\n \n\n1,703\n\n4\n\n731\n\n \n\n150\n\n2\n\n \n\n2,590\n\nTotal costs incurred equity-accounted entities\n\n \n\n1,795\n\n4\n\n777\n\n \n\n150\n\n2\n\n \n\n2,728\n\n \n\n \n\n \n\n(a) Includes abandonment costs for €773 million in 2023.\n\n(b) Includes abandonment costs for €163 million in 2023\n\n \n\nF-138\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nResults of operations from oil and gas producing activities\n\nResults 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.\n\n \n\nResults of operations from oil and gas producing activities by geographical area consist of the following: \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- sales to consolidated entities\n\n1,226\n\n17\n\n1,318\n\n2,190\n\n1,450\n\n2,986\n\n1,159\n\n1\n\n10,347\n\n- sales to third parties\n\n \n\n249\n\n5,650\n\n902\n\n815\n\n398\n\n159\n\n30\n\n8,203\n\nTotal revenues\n\n1,226\n\n266\n\n6,968\n\n3,092\n\n2,265\n\n3,384\n\n1,318\n\n31\n\n18,550\n\nProduction costs\n\n(376)\n\n(97)\n\n(1,025)\n\n(617)\n\n(231)\n\n(411)\n\n(257)\n\n(23)\n\n(3,037)\n\nTransportation costs\n\n(4)\n\n(18)\n\n(63)\n\n(3)\n\n(170)\n\n(7)\n\n(10)\n\n \n\n(275)\n\nProduction taxes\n\n(114)\n\n(1)\n\n(246)\n\n(234)\n\n \n\n(293)\n\n(100)\n\n \n\n(988)\n\nExploration expenses\n\n(21)\n\n(10)\n\n(60)\n\n(28)\n\n(2)\n\n(53)\n\n(33)\n\n(4)\n\n(211)\n\nD.D. & A. and Provision for abandonment (a)\n\n(792)\n\n(119)\n\n(1,669)\n\n(1,639)\n\n(569)\n\n(1,152)\n\n(684)\n\n(116)\n\n(6,740)\n\nOther income (expenses)\n\n(219)\n\n(25)\n\n(273)\n\n(146)\n\n(78)\n\n(381)\n\n(57)\n\n(46)\n\n(1,225)\n\nPretax income from producing activities\n\n(300)\n\n(4)\n\n3,632\n\n425\n\n1,215\n\n1,087\n\n177\n\n(158)\n\n6,074\n\nIncome taxes\n\n114\n\n101\n\n(2,190)\n\n(332)\n\n(419)\n\n(512)\n\n(86)\n\n47\n\n(3,277)\n\nResults of operations from E&P activities of consolidated subsidiaries\n\n(186)\n\n97\n\n1,442\n\n93\n\n796\n\n575\n\n91\n\n(111)\n\n2,797\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- sales to consolidated entities\n\n \n\n3,849\n\n \n\n703\n\n \n\n \n\n \n\n \n\n4,552\n\n- sales to third parties\n\n \n\n1,483\n\n186\n\n1,609\n\n \n\n \n\n652\n\n \n\n3,930\n\nTotal revenues\n\n \n\n5,332\n\n186\n\n2,312\n\n \n\n \n\n652\n\n \n\n8,482\n\nProduction costs\n\n \n\n(871)\n\n(36)\n\n(676)\n\n \n\n \n\n(25)\n\n \n\n(1,608)\n\nTransportation costs\n\n \n\n(187)\n\n(13)\n\n \n\n \n\n \n\n(2)\n\n \n\n(202)\n\nProduction taxes\n\n \n\n \n\n(2)\n\n(31)\n\n \n\n \n\n(147)\n\n \n\n(180)\n\nExploration expenses\n\n \n\n(138)\n\n \n\n(14)\n\n \n\n \n\n \n\n \n\n(152)\n\nD.D. & A. and Provision for abandonment\n\n \n\n(1,352)\n\n(63)\n\n(1,012)\n\n \n\n(1)\n\n(67)\n\n \n\n(2,495)\n\nOther income (expenses)\n\n \n\n163\n\n(1)\n\n34\n\n \n\n(2)\n\n(305)\n\n \n\n(111)\n\nPretax income from producing activities\n\n \n\n2,947\n\n71\n\n613\n\n \n\n(3)\n\n106\n\n \n\n3,734\n\nIncome taxes\n\n \n\n(2,288)\n\n(31)\n\n(206)\n\n \n\n1\n\n(13)\n\n \n\n(2,537)\n\nResults of operations from E&P activities of equity-accounted entities\n\n \n\n659\n\n40\n\n407\n\n \n\n(2)\n\n93\n\n \n\n1,197\n\n \n\n \n\n \n\n(a) Includes asset net impairment amounting to €1,081 million.\n\n \n\nF-139\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- sales to consolidated entities\n\n1,256\n\n524\n\n1,590\n\n1,984\n\n1,747\n\n3,171\n\n1,364\n\n \n\n11,636\n\n- sales to third parties\n\n \n\n462\n\n7,135\n\n892\n\n958\n\n752\n\n138\n\n19\n\n10,356\n\nTotal revenues\n\n1,256\n\n986\n\n8,725\n\n2,876\n\n2,705\n\n3,923\n\n1,502\n\n19\n\n21,992\n\nProduction costs\n\n(350)\n\n(328)\n\n(971)\n\n(617)\n\n(280)\n\n(392)\n\n(403)\n\n(25)\n\n(3,366)\n\nTransportation costs\n\n(4)\n\n(86)\n\n(65)\n\n(8)\n\n(175)\n\n(8)\n\n(15)\n\n \n\n(361)\n\nProduction taxes\n\n(139)\n\n(1)\n\n(299)\n\n(276)\n\n \n\n(339)\n\n(73)\n\n \n\n(1,127)\n\nExploration expenses\n\n(16)\n\n(158)\n\n(148)\n\n(54)\n\n(81)\n\n(243)\n\n(39)\n\n(2)\n\n(741)\n\nD.D. & A. and Provision for abandonment (a)\n\n(606)\n\n(440)\n\n(1,880)\n\n(2,121)\n\n(555)\n\n(1,142)\n\n(1,373)\n\n(52)\n\n(8,169)\n\nOther income (expenses)\n\n(179)\n\n(413)\n\n(330)\n\n(280)\n\n(168)\n\n(335)\n\n(45)\n\n(7)\n\n(1,757)\n\nPretax income from producing activities\n\n(38)\n\n(440)\n\n5,032\n\n(480)\n\n1,446\n\n1,464\n\n(446)\n\n(67)\n\n6,471\n\nIncome taxes\n\n73\n\n134\n\n(3,150)\n\n(347)\n\n(507)\n\n(1,283)\n\n39\n\n23\n\n(5,018)\n\nResults of operations from E&P activities of consolidated subsidiaries\n\n35\n\n(306)\n\n1,882\n\n(827)\n\n939\n\n181\n\n(407)\n\n(44)\n\n1,453\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- sales to consolidated entities\n\n \n\n3,330\n\n \n\n1,149\n\n \n\n \n\n \n\n \n\n4,479\n\n- sales to third parties\n\n \n\n1,213\n\n162\n\n1,682\n\n \n\n \n\n669\n\n \n\n3,726\n\nTotal revenues\n\n \n\n4,543\n\n162\n\n2,831\n\n \n\n \n\n669\n\n \n\n8,205\n\nProduction costs\n\n \n\n(711)\n\n(33)\n\n(621)\n\n \n\n \n\n(23)\n\n \n\n(1,388)\n\nTransportation costs\n\n \n\n(151)\n\n(15)\n\n \n\n \n\n \n\n(3)\n\n \n\n(169)\n\nProduction taxes\n\n \n\n \n\n(2)\n\n(42)\n\n \n\n \n\n(148)\n\n \n\n(192)\n\nExploration expenses\n\n \n\n(119)\n\n \n\n(7)\n\n \n\n \n\n \n\n \n\n(126)\n\nD.D. & A. and Provision for abandonment\n\n \n\n(1,150)\n\n(62)\n\n(864)\n\n \n\n \n\n(66)\n\n \n\n(2,142)\n\nOther income (expenses)\n\n \n\n37\n\n(26)\n\n(127)\n\n \n\n(1)\n\n(333)\n\n \n\n(450)\n\nPretax income from producing activities\n\n \n\n2,449\n\n24\n\n1,170\n\n \n\n(1)\n\n96\n\n \n\n3,738\n\nIncome taxes\n\n \n\n(1,839)\n\n(2)\n\n(456)\n\n \n\n \n\n(42)\n\n \n\n(2,339)\n\nResults of operations from E&P activities of equity-accounted entities\n\n \n\n610\n\n22\n\n714\n\n \n\n(1)\n\n54\n\n \n\n1,399\n\n \n\n \n\n \n\n(a) Includes asset net impairment amounting to €2,203 million.\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest\nof Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- sales to consolidated entities\n\n1,475\n\n862\n\n1,477\n\n1,745\n\n1,845\n\n2,970\n\n1,661\n\n1\n\n12,036\n\n- sales to third parties\n\n \n\n18\n\n7,936\n\n903\n\n897\n\n532\n\n135\n\n51\n\n10,472\n\nTotal revenues\n\n1,475\n\n880\n\n9,413\n\n2,648\n\n2,742\n\n3,502\n\n1,796\n\n52\n\n22,508\n\nProduction costs\n\n(348)\n\n(202)\n\n(952)\n\n(656)\n\n(267)\n\n(304)\n\n(469)\n\n(25)\n\n(3,223)\n\nTransportation costs\n\n(3)\n\n(43)\n\n(68)\n\n(10)\n\n(178)\n\n(6)\n\n(19)\n\n \n\n(327)\n\nProduction taxes\n\n(152)\n\n \n\n(300)\n\n(294)\n\n \n\n(326)\n\n(73)\n\n \n\n(1,145)\n\nExploration expenses\n\n(12)\n\n(14)\n\n(245)\n\n(121)\n\n(2)\n\n(140)\n\n(152)\n\n(1)\n\n(687)\n\nD.D. & A. and Provision for abandonment (a)\n\n(886)\n\n(166)\n\n(1,979)\n\n(716)\n\n(601)\n\n(1,093)\n\n(1,531)\n\n(95)\n\n(7,067)\n\nOther income (expenses)\n\n(347)\n\n(117)\n\n(360)\n\n(128)\n\n(148)\n\n(263)\n\n(108)\n\n(7)\n\n(1,478)\n\nPretax income from producing activities\n\n(273)\n\n338\n\n5,509\n\n723\n\n1,546\n\n1,370\n\n(556)\n\n(76)\n\n8,581\n\nIncome taxes\n\n169\n\n(292)\n\n(3,368)\n\n(391)\n\n(503)\n\n(1,150)\n\n369\n\n19\n\n(5,147)\n\nResults of operations from E&P activities of consolidated subsidiaries\n\n(104)\n\n46\n\n2,141\n\n332\n\n1,043\n\n220\n\n(187)\n\n(57)\n\n3,434\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevenues:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n- sales to consolidated entities\n\n \n\n2,911\n\n \n\n958\n\n \n\n \n\n \n\n \n\n3,869\n\n- sales to third parties\n\n \n\n1,063\n\n10\n\n1,905\n\n \n\n \n\n604\n\n \n\n3,582\n\nTotal revenues\n\n \n\n3,974\n\n10\n\n2,863\n\n \n\n \n\n604\n\n \n\n7,451\n\nProduction costs\n\n \n\n(562)\n\n(6)\n\n(535)\n\n \n\n \n\n(20)\n\n \n\n(1,123)\n\nTransportation costs\n\n \n\n(102)\n\n(1)\n\n(26)\n\n \n\n \n\n(3)\n\n \n\n(132)\n\nProduction taxes\n\n \n\n \n\n(2)\n\n(54)\n\n \n\n \n\n(126)\n\n \n\n(182)\n\nExploration expenses\n\n \n\n(50)\n\n \n\n(37)\n\n \n\n \n\n \n\n \n\n(87)\n\nD.D. & A. and Provision for abandonment\n\n \n\n(1,116)\n\n(5)\n\n(1,314)\n\n \n\n(1)\n\n(68)\n\n \n\n(2,504)\n\nOther income (expenses)\n\n \n\n(78)\n\n(1)\n\n24\n\n \n\n(4)\n\n(372)\n\n \n\n(431)\n\nPretax income from producing activities\n\n \n\n2,066\n\n(5)\n\n921\n\n \n\n(5)\n\n15\n\n \n\n2,992\n\nIncome taxes\n\n \n\n(1,614)\n\n6\n\n(273)\n\n \n\n1\n\n(56)\n\n \n\n(1,936)\n\nResults of operations from E&P activities of equity-accounted entities\n\n \n\n452\n\n1\n\n648\n\n \n\n(4)\n\n(41)\n\n \n\n1,056\n\n \n\n \n\n \n\n(a) Includes asset net impairment amounting to €1,036 million.\n\n \n\nF-140\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nProved reserves of oil and natural gas\n\nEni’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).\n\nProved 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.\n\nExisting 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. In 2025, the average price for the marker Brent crude oil was $70 per barrel. Net proved reserves exclude interests and royalties owned by others.\n\nProved 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.\n\n \n\nF-141\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nEni has its proved reserves evaluated on a rotational basis by independent oil engineering companies24. The description of qualifications of the person primarily responsible of the reserves audit is included in the third-party audit report25. 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.\n\nThe 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 Eni26.\n\nIn 2025, an independent evaluation of about 36%27 of Eni’s total proved reserves as of December 31, 2025, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three-year period from 2023 to 2025, 82% of Eni’s total proved reserves were subject to independent evaluation.\n\nEni 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 60%, 57% and 55% of total proved reserves as of December 31, 2025, 2024 and 2023 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 in the three-year period 2023-2025.\n\nOil 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%, 1% and 2% of total proved reserves as of December 31, 2025, 2024 and 2023, respectively, on an oil equivalent basis; (ii) volumes of proved reserves of natural gas to be consumed in operations amounted to 2,614 BCF at 2025 year-end (2,380 BCF and 2,338 BCF respectively at 2024 and 2023 year-end); (iii) the quantities of hydrocarbons related to the Angola LNG plant owned by the JV Azule set up 50% with bp.\n\nNumerous 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.\n\nProved undeveloped reserves\n\nProved undeveloped reserves as of December 31, 2025, amount to 3,027 mmBOE, of which 1,082 mmBBL of liquids and 288 BCF of natural gas, mainly in Africa and Asia.\n\nProved undeveloped reserves of consolidated subsidiaries amounted to 805 mmBBL of liquids and 6,359 BCF of natural gas. The table below provides a summary of changes in total proved undeveloped reserves for 2025.\n\n(mmboe)\n\n \n\nProved undeveloped reserves as of December 31, 2024\n\n2,787\n\nTransfer to proved developed reserves\n\n(370)\n\nExtensions and discoveries\n\n585\n\nRevisions of previous estimates\n\n23\n\nImproved recovery\n\n26\n\nPortfolio\n\n(24)\n\nProved undeveloped reserves as of December 31, 2025\n\n3,027\n\n \n\n \n\n \n\n24 For the past three years we have availed of the independent certification service of DeGolyer and Mac Naughton, Ryder Scott, and Sproule.\n\n25 The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2025.\n\n26 In 2025 Azule and Vår Energi.\n\n27 In 2025, the volumes of Azule Energy and Vår Energi are included, for which Eni has requested a Third Party Letter.\n\n \n\nF-142\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nIn 2025, proved undeveloped reserves increased by 240 mmboe (proved undeveloped reserves of consolidated companies increased by 388 mmboe, while those of joint ventures and associates decreased by 148 mmboe). Main changes derived from:\n\ni) progress in the conversion to Proved Reserves (-370 mmboe), mainly due to the advancement of development activities, field start-ups, and the review of projects related to assets in Vår Energi in Norway, the United Arab Emirates, and Azule Energy in Angola;\n\nii) new discoveries and extensions totalling 585 million boe, including 97 mmboe of liquids and 488 mmboe of gas, resulting from the progress of the activity in Kutei Basin in Indonesia (563 mmboe), in Sarb field in the United Arab Emirates (13 mmboe), and minor projects in the Netherlands, Norway, and Angola;\n\niii) revisions to previous estimates (23 mmboe), excluding conversion to developed reserves, mainly relate to: the progress of development activities in the United Arab Emirates (54 mmboe), in Vår Energi in Norway (53 mmboe) and in Egypt (41 mmboe). The downward revisions mainly relate to a reduction in Libya (-37 mmboe) and Azule Energy in Angola (-63 mmboe);\n\niv) improved recovery for 26 mmboe in Iraq at the Zubair field;\n\nv) portfolio operations (-24 mmboe), mainly due to the sale of 30% of Baleine in Côte d'Ivoire and assets in Congo, offset by the acquisition of a stake in Bonga in Nigeria.\n\nProved reserves of crude oil (including condensate and natural gas liquids)\n\n(million barrels)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2024\n\n213\n\n \n\n458\n\n268\n\n591\n\n578\n\n127\n\n \n\n2,235\n\nof which: developed\n\n129\n\n \n\n291\n\n187\n\n539\n\n233\n\n81\n\n \n\n1,460\n\nundeveloped\n\n84\n\n \n\n167\n\n81\n\n52\n\n345\n\n46\n\n \n\n775\n\nPurchase of Minerals in Place\n\n \n\n \n\n \n\n7\n\n \n\n \n\n \n\n \n\n7\n\nRevisions of Previous Estimates\n\n(7)\n\n \n\n123\n\n37\n\n7\n\n48\n\n7\n\n \n\n215\n\nImproved Recovery\n\n \n\n \n\n \n\n7\n\n \n\n26\n\n \n\n \n\n33\n\nExtensions and Discoveries\n\n \n\n \n\n \n\n \n\n \n\n96\n\n \n\n \n\n96\n\nProduction\n\n(9)\n\n \n\n(64)\n\n(39)\n\n(42)\n\n(35)\n\n(23)\n\n \n\n(212)\n\nSales of Minerals in Place\n\n \n\n \n\n \n\n(28)\n\n \n\n \n\n \n\n \n\n(28)\n\nReserves at December 31, 2025\n\n197\n\n \n\n517\n\n252\n\n556\n\n713\n\n111\n\n \n\n2,346\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2024\n\n \n\n391\n\n8\n\n226\n\n \n\n110\n\n23\n\n \n\n758\n\nof which: developed\n\n \n\n207\n\n8\n\n103\n\n \n\n \n\n23\n\n \n\n341\n\nundeveloped\n\n \n\n184\n\n \n\n123\n\n \n\n110\n\n \n\n \n\n417\n\nPurchase of Minerals in Place\n\n \n\n3\n\n \n\n \n\n \n\n \n\n \n\n \n\n3\n\nRevisions of Previous Estimates\n\n \n\n39\n\n(2)\n\n(6)\n\n \n\n1\n\n \n\n \n\n32\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n10\n\n \n\n1\n\n \n\n \n\n \n\n \n\n11\n\nProduction\n\n \n\n(62)\n\n(1)\n\n(29)\n\n \n\n \n\n(3)\n\n \n\n(95)\n\nSales of Minerals in Place\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2025\n\n \n\n381\n\n5\n\n192\n\n \n\n111\n\n20\n\n \n\n709\n\nReserves at December 31, 2025\n\n197\n\n381\n\n522\n\n444\n\n556\n\n824\n\n131\n\n \n\n3,055\n\nDeveloped\n\n123\n\n295\n\n344\n\n314\n\n523\n\n274\n\n100\n\n \n\n1,973\n\nconsolidated subsidiaries\n\n123\n\n \n\n339\n\n202\n\n523\n\n274\n\n80\n\n \n\n1,541\n\nequity-accounted entities\n\n \n\n295\n\n5\n\n112\n\n \n\n \n\n20\n\n \n\n432\n\nUndeveloped\n\n74\n\n86\n\n178\n\n130\n\n33\n\n550\n\n31\n\n \n\n1,082\n\nconsolidated subsidiaries\n\n74\n\n \n\n178\n\n50\n\n33\n\n439\n\n31\n\n \n\n805\n\nequity-accounted entities\n\n \n\n86\n\n \n\n80\n\n \n\n111\n\n \n\n \n\n277\n\n \n\nF-143\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(million barrels)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2023\n\n211\n\n27\n\n523\n\n334\n\n637\n\n485\n\n213\n\n \n\n2,430\n\nof which: developed\n\n136\n\n24\n\n326\n\n225\n\n576\n\n240\n\n163\n\n \n\n1,690\n\nundeveloped\n\n75\n\n3\n\n197\n\n109\n\n61\n\n245\n\n50\n\n \n\n740\n\nPurchase of Minerals in Place\n\n \n\n8\n\n \n\n \n\n \n\n \n\n \n\n \n\n8\n\nRevisions of Previous Estimates\n\n12\n\n \n\n \n\n22\n\n(6)\n\n105\n\n52\n\n \n\n185\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n1\n\n \n\n1\n\nExtensions and Discoveries\n\n \n\n \n\n \n\n15\n\n \n\n22\n\n \n\n \n\n37\n\nProduction\n\n(10)\n\n(6)\n\n(65)\n\n(32)\n\n(40)\n\n(34)\n\n(21)\n\n \n\n(208)\n\nSales of Minerals in Place\n\n \n\n(29)\n\n \n\n(71)\n\n \n\n \n\n(118)\n\n \n\n(218)\n\nReserves at December 31, 2024\n\n213\n\n \n\n458\n\n268\n\n591\n\n578\n\n127\n\n \n\n2,235\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2023\n\n \n\n326\n\n6\n\n207\n\n \n\n110\n\n26\n\n \n\n675\n\nof which: developed\n\n \n\n167\n\n6\n\n107\n\n \n\n \n\n26\n\n \n\n306\n\nundeveloped\n\n \n\n159\n\n \n\n100\n\n \n\n110\n\n \n\n \n\n369\n\nPurchase of Minerals in Place\n\n \n\n90\n\n1\n\n2\n\n \n\n \n\n \n\n \n\n93\n\nRevisions of Previous Estimates\n\n \n\n21\n\n2\n\n35\n\n \n\n \n\n \n\n \n\n58\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n \n\n14\n\n \n\n \n\n \n\n \n\n14\n\nProduction\n\n \n\n(44)\n\n(1)\n\n(32)\n\n \n\n \n\n(3)\n\n \n\n(80)\n\nSales of Minerals in Place\n\n \n\n(2)\n\n \n\n \n\n \n\n \n\n \n\n \n\n(2)\n\nReserves at December 31, 2024\n\n \n\n391\n\n8\n\n226\n\n \n\n110\n\n23\n\n \n\n758\n\nReserves at December 31, 2024\n\n213\n\n391\n\n466\n\n494\n\n591\n\n688\n\n150\n\n \n\n2,993\n\nDeveloped\n\n129\n\n207\n\n299\n\n290\n\n539\n\n233\n\n104\n\n \n\n1,801\n\nconsolidated subsidiaries\n\n129\n\n \n\n291\n\n187\n\n539\n\n233\n\n81\n\n \n\n1,460\n\nequity-accounted entities\n\n \n\n207\n\n8\n\n103\n\n \n\n \n\n23\n\n \n\n341\n\nUndeveloped\n\n84\n\n184\n\n167\n\n204\n\n52\n\n455\n\n46\n\n \n\n1,192\n\nconsolidated subsidiaries\n\n84\n\n \n\n167\n\n81\n\n52\n\n345\n\n46\n\n \n\n775\n\nequity-accounted entities\n\n \n\n184\n\n \n\n123\n\n \n\n110\n\n \n\n \n\n417\n\n \n\n(million barrels)\n\nItaly\n\nRest of Europe\n\nNorth Africa\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2022\n\n188\n\n36\n\n531\n\n367\n\n644\n\n433\n\n234\n\n1\n\n2,434\n\nof which: developed\n\n139\n\n32\n\n336\n\n212\n\n585\n\n231\n\n171\n\n1\n\n1,707\n\nundeveloped\n\n49\n\n4\n\n195\n\n155\n\n59\n\n202\n\n63\n\n \n\n727\n\nPurchase of Minerals in Place\n\n \n\n \n\n4\n\n \n\n \n\n \n\n \n\n \n\n4\n\nRevisions of Previous Estimates\n\n34\n\n(2)\n\n58\n\n(2)\n\n35\n\n35\n\n3\n\n(1)\n\n160\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n \n\n \n\n \n\n50\n\n \n\n \n\n50\n\nProduction\n\n(11)\n\n(7)\n\n(70)\n\n(31)\n\n(42)\n\n(31)\n\n(24)\n\n \n\n(216)\n\nSales of Minerals in Place\n\n \n\n \n\n \n\n \n\n \n\n(2)\n\n \n\n \n\n(2)\n\nReserves at December 31, 2023\n\n211\n\n27\n\n523\n\n334\n\n637\n\n485\n\n213\n\n \n\n2,430\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2022\n\n \n\n350\n\n8\n\n235\n\n \n\n100\n\n27\n\n \n\n720\n\nof which: developed\n\n \n\n173\n\n8\n\n135\n\n \n\n \n\n27\n\n \n\n343\n\nundeveloped\n\n \n\n177\n\n \n\n100\n\n \n\n100\n\n \n\n \n\n377\n\nPurchase of Minerals in Place\n\n \n\n \n\n \n\n2\n\n \n\n \n\n \n\n \n\n2\n\nRevisions of Previous Estimates\n\n \n\n9\n\n(1)\n\n2\n\n \n\n10\n\n \n\n \n\n20\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProduction\n\n \n\n(32)\n\n(1)\n\n(32)\n\n \n\n \n\n(1)\n\n \n\n(66)\n\nSales of Minerals in Place\n\n \n\n(1)\n\n \n\n \n\n \n\n \n\n \n\n \n\n(1)\n\nReserves at December 31, 2023\n\n \n\n326\n\n6\n\n207\n\n \n\n110\n\n26\n\n \n\n675\n\nReserves at December 31, 2023\n\n211\n\n353\n\n529\n\n541\n\n637\n\n595\n\n239\n\n \n\n3,105\n\nDeveloped\n\n136\n\n191\n\n332\n\n332\n\n576\n\n240\n\n189\n\n \n\n1,996\n\nconsolidated subsidiaries\n\n136\n\n24\n\n326\n\n225\n\n576\n\n240\n\n163\n\n \n\n1,690\n\nequity-accounted entities\n\n \n\n167\n\n6\n\n107\n\n \n\n \n\n26\n\n \n\n306\n\nUndeveloped\n\n75\n\n162\n\n197\n\n209\n\n61\n\n355\n\n50\n\n \n\n1,109\n\nconsolidated subsidiaries\n\n75\n\n3\n\n197\n\n109\n\n61\n\n245\n\n50\n\n \n\n740\n\nequity-accounted entities\n\n \n\n159\n\n \n\n100\n\n \n\n110\n\n \n\n \n\n369\n\nMain changes in proved reserves of crude oil (including condensates and natural gas liquids) reported in the tables above for the period 2025, 2024 and 2023 are discussed below.\n\n \n\nF-144\n\n[Table of Contents](#TOC_TableofContent)\n\nConsolidated subsidiaries\n\n \n\nPurchase of Minerals in Place\n\n \n\nIn 2023, we had an acquisition of some BP assets in Algeria for 4 mmbbl.\n\nIn 2024, 8 mmbbl were obtained for the acquisition of the Neptune company.\n\nIn 2025, 7 mmbbl were acquired following an increase in the stake in Bonga field in Nigeria.\n\nRevisions of Previous Estimates\n\nIn 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.\n\nIn 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.\n\nIn 2025, revisions to previous estimates amount to +215 mmbbl. The main positive revisions relate to the renewal of licenses in Egypt in the Sinai area (+76 mmbbl) and Algeria in the Zek area (+40 mmbbl), to activities in the United Arab Emirates, mainly in the Lower Zakum field (+43 mmbbl), and in the Baleine field in Côte d'Ivoire (+29 mmbbl). The main negative revisions relate to fields in the United States (-9 mmbbl).\n\nImproved Recovery\n\nIn 2023, there were no increases due to improvements from assisted recovery.\n\nIn 2024, there was 1 mmbbl due to improvements from assisted recovery on the St. Malo field in the United States of America.\n\nIn 2025, improved recovery amounted to 33 mmbbl for activities in Zubair field in Iraq and Baleine field in Côte d'Ivoire.\n\nExtensions and Discoveries\n\nIn 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.\n\nIn 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).\n\nIn 2025, new discoveries and extensions amount to 96 mmbbl, due to the final investment decision in the Kutei Basin in Indonesia.\n\nSales of Minerals in Place\n\nIn 2023, the divestment of 2 mmbbl mainly concerned the reduction of the share in the Ghasha concession in the United Arab Emirates.\n\nIn 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.\n\nIn 2025, sales of 28 mmbbl were recorded, linked to the sale of the 30% stake in the Baleine field in Côte d'Ivoire and assets in Congo.\n\nEquity-accounted entities\n\nPurchase of Minerals in Place\n\n \n\nIn 2023, the 2 mmbbl of acquisition of a share in Block 3/05a in Azule.\n\nIn 2024 acquisitions amounted to 93 mmbbl and were mainly due to the business combination with Ithaca Energy and Vår Energi's acquisition of Neptune.\n\nIn 2025, acquisitions amounted to 3 mmbbl, mainly in Vår Energi in Norway and Ithaca Energy in the United Kingdom.\n\n \n\nF-145\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nRevisions of Previous Estimates\n\nIn 2023, positive revisions of +20 mmbbl were mainly due to Qatar (+10 mmbbl) on the NFE field, Vår Energi in Norway (+9 mmbbl).\n\nIn 2024, revisions were positive by 58 mmbbl, affecting mainly Azule Energy and Vår Energi.\n\nIn 2025, revisions were positive for 32 mmbbl, mainly concerning Azule Energy and Vår Energi.\n\n \n\nExtensions and Discoveries\n\nNo extensions or new discoveries were recorded in 2023.\n\nIn 2024, extensions and new discoveries of 14 mmbbl were mainly the result of the inclusion of reserves from the Coral North project.\n\nIn 2025, extensions and new discoveries of 11 mmbbl are mainly the result of the booking of new reserves in Vår Energi in Norway.\n\nSales of Minerals in Place\n\nIn 2023, sales amounted to -1 mmbbl for the divestment of the Brage field in Vår Energi in Norway.\n\nIn 2024, divestments of 2 mmbbl involved assets of Vår Energi.\n\nNo sales recorded in 2025.\n\nProved reserves of natural gas\n\n(billion cubic feet)\n\nItaly\n\nRest of Europe\n\nNorth\n\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest\n\nof Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2024\n\n817\n\n54\n\n5,338\n\n1,931\n\n1,489\n\n1,583\n\n94\n\n190\n\n11,496\n\nof which: developed\n\n693\n\n52\n\n2,692\n\n1,206\n\n1,486\n\n799\n\n56\n\n23\n\n7,007\n\nundeveloped\n\n124\n\n2\n\n2,646\n\n725\n\n3\n\n784\n\n38\n\n167\n\n4,489\n\nPurchase of Minerals in Place\n\n \n\n \n\n \n\n1\n\n \n\n \n\n \n\n \n\n1\n\nRevisions of Previous Estimates\n\n(90)\n\n24\n\n382\n\n134\n\n(1)\n\n146\n\n3\n\n(119)\n\n479\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n27\n\n \n\n \n\n \n\n2,513\n\n \n\n \n\n2,540\n\nProduction (a)\n\n(76)\n\n(24)\n\n(668)\n\n(179)\n\n(89)\n\n(233)\n\n(17)\n\n(9)\n\n(1,295)\n\nSales of Minerals in Place\n\n \n\n \n\n \n\n(223)\n\n \n\n \n\n \n\n \n\n(223)\n\nReserves at December 31, 2025\n\n651\n\n81\n\n5,052\n\n1,664\n\n1,399\n\n4,009\n\n80\n\n62\n\n12,998\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2024\n\n \n\n939\n\n222\n\n3,103\n\n \n\n1,411\n\n1,159\n\n \n\n6,834\n\nof which: developed\n\n \n\n545\n\n222\n\n1,054\n\n \n\n \n\n1,159\n\n \n\n2,980\n\nundeveloped\n\n \n\n394\n\n \n\n2,049\n\n \n\n1,411\n\n \n\n \n\n3,854\n\nPurchase of Minerals in Place\n\n \n\n91\n\n41\n\n \n\n \n\n \n\n \n\n \n\n132\n\nRevisions of Previous Estimates\n\n \n\n149\n\n14\n\n70\n\n \n\n7\n\n10\n\n \n\n250\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n218\n\n \n\n2\n\n \n\n \n\n \n\n \n\n220\n\nProduction (b)\n\n \n\n(168)\n\n(28)\n\n(98)\n\n \n\n \n\n(106)\n\n \n\n(400)\n\nSales of Minerals in Place\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2025\n\n \n\n1,229\n\n249\n\n3,077\n\n \n\n1,418\n\n1,063\n\n \n\n7,036\n\nReserves at December 31, 2025\n\n651\n\n1,310\n\n5,301\n\n4,741\n\n1,399\n\n5,427\n\n1,143\n\n62\n\n20,034\n\nDeveloped\n\n524\n\n737\n\n2,811\n\n2,321\n\n1,396\n\n920\n\n1,119\n\n37\n\n9,865\n\nconsolidated subsidiaries\n\n524\n\n45\n\n2,562\n\n1,099\n\n1,396\n\n920\n\n56\n\n37\n\n6,639\n\nequity-accounted entities\n\n \n\n692\n\n249\n\n1,222\n\n \n\n \n\n1,063\n\n \n\n3,226\n\nUndeveloped\n\n127\n\n573\n\n2,490\n\n2,420\n\n3\n\n4,507\n\n24\n\n25\n\n10,169\n\nconsolidated subsidiaries\n\n127\n\n36\n\n2,490\n\n565\n\n3\n\n3,089\n\n24\n\n25\n\n6,359\n\nequity-accounted entities\n\n \n\n537\n\n \n\n1,855\n\n \n\n1,418\n\n \n\n \n\n3,810\n\n \n\n \n\n \n\n(a) Includes production volumes consumed in operations equal to 217 Bcf.\n\n(b) Includes production volumes consumed in operations equal to 36 Bcf.\n\n \n\nF-146\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(billion cubic feet)\n\nItaly\n\nRest of Europe\n\nNorth\n\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest\n\nof Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2023\n\n859\n\n174\n\n5,935\n\n2,479\n\n1,546\n\n1,303\n\n131\n\n192\n\n12,619\n\nof which: developed\n\n653\n\n167\n\n3,181\n\n1,350\n\n1,546\n\n725\n\n107\n\n58\n\n7,787\n\nundeveloped\n\n206\n\n7\n\n2,754\n\n1,129\n\n \n\n578\n\n24\n\n134\n\n4,832\n\nPurchase of Minerals in Place\n\n \n\n184\n\n9\n\n \n\n \n\n226\n\n \n\n \n\n419\n\nRevisions of Previous Estimates\n\n30\n\n2\n\n172\n\n194\n\n35\n\n267\n\n23\n\n3\n\n726\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n \n\n2\n\n \n\n2\n\n \n\n \n\n4\n\nProduction (a)\n\n(72)\n\n(71)\n\n(778)\n\n(164)\n\n(92)\n\n(215)\n\n(18)\n\n(5)\n\n(1,415)\n\nSales of Minerals in Place\n\n \n\n(235)\n\n \n\n(580)\n\n \n\n \n\n(42)\n\n \n\n(857)\n\nReserves at December 31, 2024\n\n817\n\n54\n\n5,338\n\n1,931\n\n1,489\n\n1,583\n\n94\n\n190\n\n11,496\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2023\n\n \n\n515\n\n14\n\n1,501\n\n \n\n1,406\n\n1,260\n\n \n\n4,696\n\nof which: developed\n\n \n\n359\n\n14\n\n1,036\n\n \n\n \n\n1,260\n\n \n\n2,669\n\nundeveloped\n\n \n\n156\n\n \n\n465\n\n \n\n1,406\n\n \n\n \n\n2,027\n\nPurchase of Minerals in Place\n\n \n\n544\n\n174\n\n \n\n \n\n \n\n \n\n \n\n718\n\nRevisions of Previous Estimates\n\n \n\n28\n\n56\n\n38\n\n \n\n5\n\n3\n\n \n\n130\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n \n\n1,651\n\n \n\n \n\n \n\n \n\n1,651\n\nProduction (b)\n\n \n\n(139)\n\n(22)\n\n(87)\n\n \n\n \n\n(104)\n\n \n\n(352)\n\nSales of Minerals in Place\n\n \n\n(9)\n\n \n\n \n\n \n\n \n\n \n\n \n\n(9)\n\nReserves at December 31, 2024\n\n \n\n939\n\n222\n\n3,103\n\n \n\n1,411\n\n1,159\n\n \n\n6,834\n\nReserves at December 31, 2024\n\n817\n\n993\n\n5,560\n\n5,034\n\n1,489\n\n2,994\n\n1,253\n\n190\n\n18,330\n\nDeveloped\n\n693\n\n597\n\n2,914\n\n2,260\n\n1,486\n\n799\n\n1,215\n\n23\n\n9,987\n\nconsolidated subsidiaries\n\n693\n\n52\n\n2,692\n\n1,206\n\n1,486\n\n799\n\n56\n\n23\n\n7,007\n\nequity-accounted entities\n\n \n\n545\n\n222\n\n1,054\n\n \n\n \n\n1,159\n\n \n\n2,980\n\nUndeveloped\n\n124\n\n396\n\n2,646\n\n2,774\n\n3\n\n2,195\n\n38\n\n167\n\n8,343\n\nconsolidated subsidiaries\n\n124\n\n2\n\n2,646\n\n725\n\n3\n\n784\n\n38\n\n167\n\n4,489\n\nequity-accounted entities\n\n \n\n394\n\n \n\n2,049\n\n \n\n1,411\n\n \n\n \n\n3,854\n\n \n\n \n\n \n\n(a) Includes production volumes consumed in operations equal to 223 Bcf.\n\n(b) Includes production volumes consumed in operations equal to 33 Bcf.\n\n \n\n(billion cubic feet)\n\nItaly\n\nRest of Europe\n\nNorth\n\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest of Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\n2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2022\n\n869\n\n223\n\n6,204\n\n2,341\n\n1,560\n\n1,281\n\n264\n\n408\n\n13,150\n\nof which: developed\n\n695\n\n214\n\n3,402\n\n1,306\n\n1,560\n\n796\n\n195\n\n223\n\n8,391\n\nundeveloped\n\n174\n\n9\n\n2,802\n\n1,035\n\n \n\n485\n\n69\n\n185\n\n4,759\n\nPurchase of Minerals in Place\n\n \n\n \n\n214\n\n \n\n \n\n \n\n \n\n \n\n214\n\nRevisions of Previous Estimates\n\n67\n\n(10)\n\n326\n\n294\n\n79\n\n112\n\n5\n\n(202)\n\n671\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n4\n\n5\n\n \n\n275\n\n \n\n \n\n284\n\nProduction (a)\n\n(77)\n\n(39)\n\n(813)\n\n(161)\n\n(93)\n\n(187)\n\n(25)\n\n(14)\n\n(1,409)\n\nSales of Minerals in Place\n\n \n\n \n\n \n\n \n\n \n\n(178)\n\n(113)\n\n \n\n(291)\n\nReserves at December 31, 2023\n\n859\n\n174\n\n5,935\n\n2,479\n\n1,546\n\n1,303\n\n131\n\n192\n\n12,619\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nReserves at December 31, 2022\n\n \n\n646\n\n9\n\n1,562\n\n \n\n1,490\n\n1,355\n\n \n\n5,062\n\nof which: developed\n\n \n\n444\n\n9\n\n1,070\n\n \n\n \n\n1,355\n\n \n\n2,878\n\nundeveloped\n\n \n\n202\n\n \n\n492\n\n \n\n1,490\n\n \n\n \n\n2,184\n\nPurchase of Minerals in Place\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nRevisions of Previous Estimates\n\n \n\n(32)\n\n6\n\n22\n\n \n\n(84)\n\n7\n\n \n\n(81)\n\nImproved Recovery\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nExtensions and Discoveries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProduction (b)\n\n \n\n(97)\n\n(1)\n\n(83)\n\n \n\n \n\n(102)\n\n \n\n(283)\n\nSales of Minerals in Place\n\n \n\n(2)\n\n \n\n \n\n \n\n \n\n \n\n \n\n(2)\n\nReserves at December 31, 2023\n\n \n\n515\n\n14\n\n1,501\n\n \n\n1,406\n\n1,260\n\n \n\n4,696\n\nReserves at December 31, 2023\n\n859\n\n689\n\n5,949\n\n3,980\n\n1,546\n\n2,709\n\n1,391\n\n192\n\n17,315\n\nDeveloped\n\n653\n\n526\n\n3,195\n\n2,386\n\n1,546\n\n725\n\n1,367\n\n58\n\n10,456\n\nconsolidated subsidiaries\n\n653\n\n167\n\n3,181\n\n1,350\n\n1,546\n\n725\n\n107\n\n58\n\n7,787\n\nequity-accounted entities\n\n \n\n359\n\n14\n\n1,036\n\n \n\n \n\n1,260\n\n \n\n2,669\n\nUndeveloped\n\n206\n\n163\n\n2,754\n\n1,594\n\n \n\n1,984\n\n24\n\n134\n\n6,859\n\nconsolidated subsidiaries\n\n206\n\n7\n\n2,754\n\n1,129\n\n \n\n578\n\n24\n\n134\n\n4,832\n\nequity-accounted entities\n\n \n\n156\n\n \n\n465\n\n \n\n1,406\n\n \n\n \n\n2,027\n\n \n\n \n\n \n\n(a) Includes production volumes consumed in operations equal to 206 Bcf.\n\n(b) Includes production volumes consumed in operations equal to 33 Bcf.\n\n \n\nF-147\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nMain changes in proved reserves of natural gas reported in the tables above for 2025, 2024 and 2023 are discussed below.\n\nConsolidated subsidiaries\n\nPurchase of Minerals in Place\n\n \n\nIn 2023, there was 214 BCF meters due to the acquisition of some BP assets in Algeria.\n\nIn 2024, 419 BCF were reported for the acquisition of the Neptune company in Indonesia, Netherlands and the United Kingdom.\n\nIn 2025, 1 BCF was recorded for the acquisition of a stake in Bonga asset in Nigeria.\n\nRevisions of Previous Estimates\n\n \n\nIn 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.\n\nIn 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.\n\nIn 2025, total revisions amounted to +479 BCF. The main positive revisions were recorded in Algeria (+146 BCF) for the renewal of the Zek concessions, in Libya (+145 BCF) mainly in Area D, offset by negative revisions in Blacktip in Australia (-119 BCF) and in Italy (-90 BCF), mainly in the offshore Adriatic and the offshore Sicily.\n\nImproved Recovery\n\n \n\nIn 2023, 2024 and 2025 there were no improvements from assisted recovery.\n\n \n\nExtensions and Discoveries\n\n \n\nIn 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.\n\nIn 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).\n\nIn 2025, new discoveries and extensions amounted to 2,540 BCF, mainly due to the progress and execution of the activities in Kutei Basin in Indonesia (2,445 BCF) and in Sarb field in the United Arab Emirates (68 BCF).\n\nSales of Minerals in Place\n\n \n\nIn 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.\n\nIn 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.\n\nIn 2025, sales of 223 BCF are linked to the sale of the 30% stake in Baleine in Côte d'Ivoire and assets in Congo.\n\nEquity-accounted entities\n\nPurchase of Minerals in Place\n\nNo purchase was made in 2023.\n\nIn 2024, acquisitions totalled 718 BCF due to Vår Energi's acquisition of Neptune and the business combination with Ithaca Energy.\n\nIn 2025, acquisitions amounted to 132 BCF relating to Vår Energi in Norway, a stake in Touat in Algeria, and assets in Ithaca Energy in the United Kingdom.\n\n \n\nRevisions of Previous Estimates\n\n \n\nIn 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.\n\nIn 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.\n\n \n\nF-148\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\nIn 2025, revisions to previous estimates amount to (+250 BCF), mainly located in Vår Energi in Norway (+125 BCF), in Mozambique (69 BCF), and minor revisions in the United Kingdom and in Algeria.\n\n \n\nExtensions and Discoveries\n\nIn 2023, there were no extensions or new relevant discoveries.\n\nIn 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.\n\nIn 2025, extensions and new discoveries of 220 BCF are mainly the result of the registration of new reserves in Vår Energi in Norway (208 BCF) and minor projects in Ithaca Energy in the United Kingdom.\n\nSales of Minerals in Place\n\nIn 2023, divestments were 2 BCF in the Brage field in Vår Energi in Norway.\n\nIn 2024, disposals of 9 BCF were mainly related to portfolio activities of Vår Energi and Azule Energy.\n\nNo sales were recorded in 2025.\n\nStandardized measure of discounted future net cash flows\n\nEstimated 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 expenditure 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.\n\nThe standardized measure of discounted future net cash flows by geographical area consists of the following:\n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth\n\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest\n\nof Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\nDecember 31, 2025\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFuture cash inflows\n\n16,507\n\n703\n\n54,711\n\n23,122\n\n29,040\n\n60,156\n\n6,334\n\n240\n\n190,813\n\nFuture production costs\n\n(7,531)\n\n(363)\n\n(12,974)\n\n(8,627)\n\n(5,351)\n\n(13,520)\n\n(3,098)\n\n(48)\n\n(51,512)\n\nFuture development and abandonment costs\n\n(3,341)\n\n(501)\n\n(9,319)\n\n(3,234)\n\n(1,224)\n\n(14,961)\n\n(1,246)\n\n(156)\n\n(33,982)\n\nFuture net inflow before income tax\n\n5,635\n\n(161)\n\n32,418\n\n11,261\n\n22,465\n\n31,675\n\n1,990\n\n36\n\n105,319\n\nFuture income tax\n\n(1,389)\n\n(27)\n\n(15,537)\n\n(2,250)\n\n(6,222)\n\n(17,768)\n\n(98)\n\n(2)\n\n(43,293)\n\nFuture net cash flows\n\n4,246\n\n(188)\n\n16,881\n\n9,011\n\n16,243\n\n13,907\n\n1,892\n\n34\n\n62,026\n\n10% discount factor\n\n(1,963)\n\n77\n\n(8,428)\n\n(3,244)\n\n(7,773)\n\n(9,320)\n\n(402)\n\n(13)\n\n(31,066)\n\nStandardized measure of discounted future net cash flows\n\n2,283\n\n(111)\n\n8,453\n\n5,767\n\n8,470\n\n4,587\n\n1,490\n\n21\n\n30,960\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFuture cash inflows\n\n \n\n34,001\n\n1,528\n\n21,853\n\n \n\n15,807\n\n5,912\n\n \n\n79,101\n\nFuture production costs\n\n \n\n(9,475)\n\n(445)\n\n(5,475)\n\n \n\n(5,155)\n\n(1,547)\n\n \n\n(22,097)\n\nFuture development and abandonment costs\n\n \n\n(8,515)\n\n(75)\n\n(2,401)\n\n \n\n(145)\n\n(193)\n\n \n\n(11,329)\n\nFuture net inflow before income tax\n\n \n\n16,011\n\n1,008\n\n13,977\n\n \n\n10,507\n\n4,172\n\n \n\n45,675\n\nFuture income tax\n\n \n\n(11,851)\n\n(229)\n\n(3,186)\n\n \n\n(7,515)\n\n(1,742)\n\n \n\n(24,523)\n\nFuture net cash flows\n\n \n\n4,160\n\n779\n\n10,791\n\n \n\n2,992\n\n2,430\n\n \n\n21,152\n\n10% discount factor\n\n \n\n(845)\n\n(231)\n\n(5,489)\n\n \n\n(1,792)\n\n(815)\n\n \n\n(9,172)\n\nStandardized measure of discounted future net cash flows\n\n \n\n3,315\n\n548\n\n5,302\n\n \n\n1,200\n\n1,615\n\n \n\n11,980\n\nTotal consolidated subsidiaries and equity-accounted entities\n\n2,283\n\n3,204\n\n9,001\n\n11,069\n\n8,470\n\n5,787\n\n3,105\n\n21\n\n42,940\n\n \n\nF-149\n\n[Table of Contents](#TOC_TableofContent)\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth\n\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest\n\nof Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\nDecember 31, 2024\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFuture cash inflows\n\n20,844\n\n570\n\n66,540\n\n30,478\n\n40,322\n\n49,205\n\n9,164\n\n742\n\n217,865\n\nFuture production costs\n\n(8,273)\n\n(297)\n\n(14,034)\n\n(10,912)\n\n(6,786)\n\n(13,462)\n\n(3,994)\n\n(132)\n\n(57,890)\n\nFuture development and abandonment costs\n\n(3,318)\n\n(417)\n\n(9,317)\n\n(4,942)\n\n(1,658)\n\n(7,547)\n\n(2,104)\n\n(280)\n\n(29,583)\n\nFuture net inflow before income tax\n\n9,253\n\n(144)\n\n43,189\n\n14,624\n\n31,878\n\n28,196\n\n3,066\n\n330\n\n130,392\n\nFuture income tax\n\n(2,088)\n\n(49)\n\n(21,879)\n\n(3,541)\n\n(8,505)\n\n(18,186)\n\n(387)\n\n(6)\n\n(54,641)\n\nFuture net cash flows\n\n7,165\n\n(193)\n\n21,310\n\n11,083\n\n23,373\n\n10,010\n\n2,679\n\n324\n\n75,751\n\n10% discount factor\n\n(2,995)\n\n60\n\n(10,150)\n\n(4,102)\n\n(11,301)\n\n(5,826)\n\n(656)\n\n(96)\n\n(35,066)\n\nStandardized measure of discounted future net cash flows\n\n4,170\n\n(133)\n\n11,160\n\n6,981\n\n12,072\n\n4,184\n\n2,023\n\n228\n\n40,685\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFuture cash inflows\n\n \n\n39,301\n\n1,846\n\n31,708\n\n \n\n18,602\n\n7,397\n\n \n\n98,854\n\nFuture production costs\n\n \n\n(10,169)\n\n(612)\n\n(7,702)\n\n \n\n(5,969)\n\n(1,882)\n\n \n\n(26,334)\n\nFuture development and abandonment costs\n\n \n\n(7,279)\n\n(111)\n\n(4,289)\n\n \n\n(278)\n\n(191)\n\n \n\n(12,148)\n\nFuture net inflow before income tax\n\n \n\n21,853\n\n1,123\n\n19,717\n\n \n\n12,355\n\n5,324\n\n \n\n60,372\n\nFuture income tax\n\n \n\n(16,126)\n\n(205)\n\n(5,549)\n\n \n\n(9,018)\n\n(2,231)\n\n \n\n(33,129)\n\nFuture net cash flows\n\n \n\n5,727\n\n918\n\n14,168\n\n \n\n3,337\n\n3,093\n\n \n\n27,243\n\n10% discount factor\n\n \n\n(1,077)\n\n(285)\n\n(7,742)\n\n \n\n(2,119)\n\n(1,128)\n\n \n\n(12,351)\n\nStandardized measure of discounted future net cash flows\n\n \n\n4,650\n\n633\n\n6,426\n\n \n\n1,218\n\n1,965\n\n \n\n14,892\n\nTotal consolidated subsidiaries and equity-accounted entities\n\n4,170\n\n4,517\n\n11,793\n\n13,407\n\n12,072\n\n5,402\n\n3,988\n\n228\n\n55,577\n\n \n\n(€ million)\n\nItaly\n\nRest of Europe\n\nNorth\n\nAfrica\n\nSub - Saharan Africa\n\nKazakhstan\n\nRest\n\nof Asia\n\nAmerica\n\nAustralia and Oceania\n\nTotal\n\nDecember 31, 2023\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nConsolidated subsidiaries\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFuture cash inflows\n\n22,724\n\n3,926\n\n72,835\n\n35,147\n\n40,081\n\n40,622\n\n14,951\n\n707\n\n230,993\n\nFuture production costs\n\n(8,848)\n\n(1,227)\n\n(15,439)\n\n(13,512)\n\n(6,475)\n\n(11,042)\n\n(5,852)\n\n(164)\n\n(62,559)\n\nFuture development and abandonment costs\n\n(4,270)\n\n(824)\n\n(9,383)\n\n(7,757)\n\n(1,814)\n\n(7,437)\n\n(1,954)\n\n(355)\n\n(33,794)\n\nFuture net inflow before income tax\n\n9,606\n\n1,875\n\n48,013\n\n13,878\n\n31,792\n\n22,143\n\n7,145\n\n188\n\n134,640\n\nFuture income tax\n\n(2,233)\n\n(1,274)\n\n(24,069)\n\n(4,729)\n\n(8,186)\n\n(16,348)\n\n(3,161)\n\n(8)\n\n(60,008)\n\nFuture net cash flows\n\n7,373\n\n601\n\n23,944\n\n9,149\n\n23,606\n\n5,795\n\n3,984\n\n180\n\n74,632\n\n10% discount factor\n\n(3,325)\n\n(39)\n\n(10,467)\n\n(4,223)\n\n(11,668)\n\n(3,081)\n\n(1,462)\n\n(58)\n\n(34,323)\n\nStandardized measure of discounted future net cash flows\n\n4,048\n\n562\n\n13,477\n\n4,926\n\n11,938\n\n2,714\n\n2,522\n\n122\n\n40,309\n\nEquity-accounted entities\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nFuture cash inflows\n\n \n\n29,387\n\n168\n\n22,954\n\n \n\n19,108\n\n7,519\n\n \n\n79,136\n\nFuture production costs\n\n \n\n(7,128)\n\n(122)\n\n(6,202)\n\n \n\n(5,880)\n\n(1,925)\n\n \n\n(21,257)\n\nFuture development and abandonment costs\n\n \n\n(5,221)\n\n(54)\n\n(2,972)\n\n \n\n(410)\n\n(179)\n\n \n\n(8,836)\n\nFuture net inflow before income tax\n\n \n\n17,038\n\n(8)\n\n13,780\n\n \n\n12,818\n\n5,415\n\n \n\n49,043\n\nFuture income tax\n\n \n\n(12,548)\n\n(1)\n\n(3,254)\n\n \n\n(9,702)\n\n(2,263)\n\n \n\n(27,768)\n\nFuture net cash flows\n\n \n\n4,490\n\n(9)\n\n10,526\n\n \n\n3,116\n\n3,152\n\n \n\n21,275\n\n10% discount factor\n\n \n\n(1,114)\n\n27\n\n(4,508)\n\n \n\n(2,158)\n\n(1,237)\n\n \n\n(8,990)\n\nStandardized measure of discounted future net cash flows\n\n \n\n3,376\n\n18\n\n6,018\n\n \n\n958\n\n1,915\n\n \n\n12,285\n\nTotal consolidated subsidiaries and equity-accounted entities\n\n4,048\n\n3,938\n\n13,495\n\n10,944\n\n11,938\n\n3,672\n\n4,437\n\n122\n\n52,594\n\n \n\nF-150\n\n[Table of Contents](#TOC_TableofContent)\n\nChanges in standardized measure of discounted future net cash flows\n\nChanges in standardized measure of discounted future net cash flows for the years ended December 31, 2025, 2024 and 2023, were as follows:\n\n(€ million)\n\nConsolidated subsidiaries\n\nEquity-accounted entities\n\nTotal\n\n2025\n\n \n\n \n\n \n\nStandardized measure of discounted future net cash flows at December 31, 2024\n\n40,685\n\n14,892\n\n55,577\n\nIncrease (Decrease):\n\n \n\n \n\n \n\n- sales, net of production costs\n\n(14,835)\n\n(6,488)\n\n(21,323)\n\n- net changes in sales and transfer prices, net of production costs\n\n(9,662)\n\n(4,685)\n\n(14,347)\n\n- extensions, discoveries and improved recovery, net of future production and development costs\n\n5,243\n\n1,544\n\n6,787\n\n- changes in estimated future development and abandonment costs\n\n(4,126)\n\n(2,528)\n\n(6,654)\n\n- development costs incurred during the period that reduced future development costs\n\n5,835\n\n2,635\n\n8,470\n\n- revisions of quantity estimates\n\n4,012\n\n2,341\n\n6,353\n\n- accretion of discount\n\n6,307\n\n2,076\n\n8,383\n\n- net change in income taxes\n\n2,638\n\n2,750\n\n5,388\n\n- purchase of reserves in-place\n\n33\n\n820\n\n853\n\n- sale of reserves in-place\n\n(1,075)\n\n \n\n(1,075)\n\n- changes in production rates (timing) and other\n\n(4,095)\n\n(1,377)\n\n(5,472)\n\nNet increase (decrease)\n\n(9,725)\n\n(2,912)\n\n(12,637)\n\nStandardized measure of discounted future net cash flows at December 31, 2025\n\n30,960\n\n11,980\n\n42,940\n\n \n\n(€ million)\n\nConsolidated subsidiaries\n\nEquity-accounted entities\n\nTotal\n\n2024\n\n \n\n \n\n \n\nStandardized measure of discounted future net cash flows at December 31, 2023\n\n40,309\n\n12,285\n\n52,594\n\nIncrease (Decrease):\n\n \n\n \n\n \n\n- sales, net of production costs\n\n(17,581)\n\n(6,150)\n\n(23,731)\n\n- net changes in sales and transfer prices, net of production costs\n\n(5,380)\n\n89\n\n(5,291)\n\n- extensions, discoveries and improved recovery, net of future production and development costs\n\n401\n\n1,851\n\n2,252\n\n- changes in estimated future development and abandonment costs\n\n(2,959)\n\n(3,860)\n\n(6,819)\n\n- development costs incurred during the period that reduced future development costs\n\n6,649\n\n4,824\n\n11,473\n\n- revisions of quantity estimates\n\n4,664\n\n(2,467)\n\n2,197\n\n- accretion of discount\n\n7,405\n\n1,984\n\n9,389\n\n- net change in income taxes\n\n6,578\n\n(1,654)\n\n4,924\n\n- purchase of reserves in-place\n\n1,085\n\n5,167\n\n6,252\n\n- sale of reserves in-place\n\n(2,947)\n\n(1)\n\n(2,948)\n\n- changes in production rates (timing) and other\n\n2,461\n\n2,824\n\n5,285\n\nNet increase (decrease)\n\n376\n\n2,607\n\n2,983\n\nStandardized measure of discounted future net cash flows at December 31, 2024\n\n40,685\n\n14,892\n\n55,577\n\n \n\n(€ million)\n\nConsolidated subsidiaries\n\nEquity-accounted entities\n\nTotal\n\n2023\n\n \n\n \n\n \n\nStandardized measure of discounted future net cash flows at December 31, 2022\n\n61,256\n\n20,701\n\n81,957\n\nIncrease (Decrease):\n\n \n\n \n\n \n\n- sales, net of production costs\n\n(19,397)\n\n(5,426)\n\n(24,823)\n\n- net changes in sales and transfer prices, net of production costs\n\n(33,769)\n\n(19,785)\n\n(53,554)\n\n- extensions, discoveries and improved recovery, net of future production and development costs\n\n1,659\n\n \n\n1,659\n\n- changes in estimated future development and abandonment costs\n\n(4,684)\n\n(1,353)\n\n(6,037)\n\n- development costs incurred during the period that reduced future development costs\n\n6,691\n\n2,517\n\n9,208\n\n- revisions of quantity estimates\n\n6,531\n\n155\n\n6,686\n\n- accretion of discount\n\n10,627\n\n3,033\n\n13,660\n\n- net change in income taxes\n\n12,675\n\n14,753\n\n27,428\n\n- purchase of reserves in-place\n\n977\n\n44\n\n1,021\n\n- sale of reserves in-place\n\n(845)\n\n(60)\n\n(905)\n\n- changes in production rates (timing) and other\n\n(1,412)\n\n(2,294)\n\n(3,706)\n\nNet increase (decrease)\n\n(20,947)\n\n(8,416)\n\n(29,363)\n\nStandardized measure of discounted future net cash flows at December 31, 2023\n\n40,309\n\n12,285\n\n52,594\n\n \n\nF-151"}