E

• Core Strategic Pillars • Diversification: Broad geographic and business diversification has limited material impact from Middle East market volatility. 2026 actions have increased exposure to Asia and South America, expanded transition-related businesses, and opened new opportunities in trading, critical minerals, and stationary batteries. • Dual Growth Engine: Combines industry-leading organic upstream production growth with rapid expansion of low-carbon energy businesses. • Financial Strength & Satellite Model: Over 60% of 2026 original planned targets have been met year-to-date. The satellite model de-risks the balance sheet by attracting third-party capital for expansion into new technologies and geographies.

• Upstream Operational Updates • 2026 exploration success has added over 1 billion barrels of new resources, with major discoveries in Angola, Côte d'Ivoire, Libya, Egypt, and Indonesia. New acreage positions have been secured in Uruguay, Timor-Leste, and Gambia. Three major projects (Balen Phase III, Genk North, Kronos) have received sanctions. • Two new regional upstream clusters are being built: The Seara Business Combination (completed June 2026) created Eni's largest satellite platform in the Pacific, with initial production exceeding 300,000 barrels per day and a clear path to 800,000 barrels per day by 2030. In the Americas, significant opportunities are advanced in Argentina and Venezuela, complementing existing positions in Mexico and the U.S. • In Venezuela: Negotiations for new CUNIN5 and CoroCoro contracts are in the final stage, and a gas export agreement for the Perla Field has been finalized. Total gross recoverable resource potential exceeds 5.5 billion barrels.

• Financial Updates • Pro forma gearing declined to 10% at quarter end, reaching the lower end of the company's target range. Cash flow from operations was 4.5 billion euro in Q2, up over 60% year-on-year. Full-year 2026 gross capex remains guided at ~7 billion euro, with net capex reduced to below 5 billion euro.

• Underlying 2026 oil and gas production growth has been revised upward to exceed 5%, above the upper end of the previous 3-4% range.
• GGP full-year 2026 pro forma EBIT guidance has been raised to over 1.4 billion euro, a 40% increase from the initial guidance, with additional upside potential in H2 2026.
• Eni Live full-year 2026 pro forma adjusted EBITDA guidance has been revised up 18% to 1.3 billion euro.
• Plenitude and Eni Live combined full-year 2026 pro forma EBITDA guidance was increased from 2.4 billion euro to 2.6 billion euro.
• The 2026 share repurchase program guidance has been raised to 3.4 billion euro, a 127% increase from the initial 1.5 billion euro guidance, with a combined investor yield of ~10%. A ceiling of 4 billion euro applies if cash prices remain above trigger levels.
• A potential special dividend will be determined in Q4 2026, triggered if full-year average oil price exceeds $90 per barrel, refining margins exceed 50% of original budget assumptions, and TTS margins exceed 50% of original budget assumptions.

1. Upstream (Exploration & Production): Delivered 8% year-on-year reported production growth in H1 2026 (11% underlying growth), fully offsetting Middle East volume losses via project execution. 2. GGP (Gas & LNG): Generated pro forma EBIT of over €0.47 billion in Q2 2026, exceeding performance expectations. 3. Plenitude and Eni Live: Generated €607 million pro forma EBITDA in Q2 2026, and €1.13 billion in H1 2026. Refinery utilization recovered after first half turnaround activities. 4. Chemicals: Narrowed losses quarter-over-quarter, with a greater than 100 million euro year-over-year improvement in Q2 2026, in line with transformation targets. 5. Overall: Q2 2026 pro forma EBIT was 5.4 billion euro, net income was 2.3 billion euro (both doubling year-on-year); H1 2026 pro forma EBIT increased 40% year-on-year.

• Ongoing geopolitical volatility in the Middle East (including the Gulf crisis and Hormuz Strait disruption) creates energy market fragility, delays European natural gas storage replenishment, and increases the risk of price volatility and cost inflation for upstream projects.
• Ongoing arbitration in Kazakhstan over a sulfur fine, with enforcement actions paused pending international tribunal proceedings, creates regulatory and policy uncertainty.
• Upstream project cost inflation has increased from 3-4% pre-conflict to 4-6% post-Middle East conflict, driven by higher fuel costs and supply chain dislocation.
• Venezuelan investment remains subject to ongoing contract negotiation and legacy regulatory uncertainty, requiring prudent risk management despite encouraging recent progress.
• European natural gas market conditions remain fragile, with uncertain price trajectory depending on geopolitical evolution and winter weather.

Q: What is Eni's 2030 upstream production growth outlook, and what is the outlook for European natural gas in H2 2026? / A: Eni has accelerated project FIDs and moved several projects previously planned beyond 2030 into the 2030 planning window. Eni confirms 4% cumulative annual upstream production growth to 2030, supported by 54 advanced organic projects from 10+ years of prior exploration. For H2 2026 European gas, Eni's base case aligns with current forward curves, but notes the market is fragile due to geopolitical risk and delayed storage replenishment, creating upside potential for prices that Eni is positioned to capture.

Q: What is the status of Venezuela contract negotiations, what fiscal structure is Eni targeting, and why is Eni's realized refining margin below the publicly quoted CERM benchmark? / A: Negotiations are progressing openly and transparently with the Venezuelan government and PDVSA, and are in the final stage for CUNIN5. The new contract will be a PSC-style structure that protects Eni's investment, unlike older fiscal terms. PDVSA has honored existing gas supply agreements, and Eni is ready to mobilize drilling rigs immediately after contract signing. Eni's quoted benchmark CERM assumes normalized logistics and crude differentials; current high freight and logistics costs create a $2-$3 per barrel discount between the benchmark and Eni's actual realized margin.

Q: How is Eni able to grow upstream production without increasing total capex, and what is the outlook for chemical earnings? / A: Eni delivers consistent on-time, on-budget project execution, with no cost overruns on the last 10 major upstream projects. It also farms out stakes via its satellite model to generate incremental income that offsets new project development costs, allowing expansion without higher gross capex. For chemicals, losses narrowed more than 100 million euro year-over-year in Q2, with full-year transformation cost savings tracking 10% above the 250 million euro target (to hit 280-300 million euro). Margins improved in Q2 due to temporary product shortages from Middle East export disruptions, with ongoing performance improvements expected from transformation efforts going forward.

Q: What triggers the potential special dividend, and is buyback still the preferred use for excess cash? / A: The special dividend is triggered if three conditions are met full-year: average Brent price over $90 per barrel, refining margins 50% above the original budget assumption, and TTS margins 50% above the original budget assumption. As of mid-year, prices are already near or above these triggers. A decision will be made in Q4 based on full-year price and cash generation outcomes. If triggers are met, there will also likely be an additional share buyback beyond the current 3.4 billion euro guidance, up to the 4 billion euro ceiling, while still adhering to the 60% of operating cash flow payout limit.