[E] Eni: Q3 2026 Earnings Test for Output Growth as Oil Prices Fall

Eni (NYSE: E), the Italian integrated oil and gas company, earns most of its profit from global oil and gas exploration and production and also runs gas and LNG trading, biofuels, refining and chemicals, and retail gas and power; its Q3 2026 earnings call is scheduled for 2026-10-23 and will cover the third quarter of 2026, ending September 30, 2026[1]. In the latest disclosed period, the second quarter of 2026, Eni produced 1,789 thousand barrels of oil equivalent per day (kboe/d), up 7% year on year, while group proforma adjusted EBIT doubled to €5.375 billion, adjusted net profit reached €2.333 billion, adjusted cash flow from operations before working capital (CFFO) was €4.469 billion and net borrowings before lease liabilities stood at €11.271 billion on June 30[2]. With those results, the company raised its full-year 2026 adjusted CFFO guidance to about €15 billion, assuming Brent at $85 per barrel, its Standard Eni Refining Margin (SERM) at $14 per barrel and TTF gas at €50 per MWh, and lifted its underlying production growth guidance from 3%–4% to about 5%[3]; it also expanded the 2026 buyback to €3.4 billion, confirmed a €1.1 per share dividend and said that if the full-year SERM stays above $9, an extraordinary dividend would be defined in October and paid in the fourth quarter[4]. Drillr's earnings calendar, updated September 23, lists third-quarter reference figures of 1.838 in earnings per share and 25.544 billion in revenue, but the fields carry no currency or per-share label; for the second quarter the same source showed 1.878 expected against 1.76 actual, while Investing.com reported on results day that Eni's adjusted net profit beat expectations, so the calendar figures serve only as a rough reference[1][5].

Three things matter most in the Q3 2026 results. First, can upstream output hold above 1.78 million boe/d and can E&P profit stay above the first quarter's €3.357 billion? Second-quarter E&P proforma adjusted EBIT was €4.769 billion, about 89% of the group total, but production was essentially flat against the first quarter's 1,798 kboe/d, the profit jump came mainly from oil prices, and Eni expects Brent to ease in the second half for a full-year average of $85[2][6][7]. Second, can the refining business turn high benchmark margins into reported profit? SERM averaged $8.3 per barrel in the second quarter, up 74% year on year, yet refinery utilization was only 74% and the refining and chemicals segment still lost €40 million, while both the $14 full-year SERM assumption and the extraordinary dividend trigger depend on stronger margins in the second half[8][9]. Third, can operating cash flow fund both shareholder returns and deleveraging? In the first half, working capital absorbed €1.516 billion, free cash flow was only €873 million and net borrowings rose by about €1.74 billion, while the third quarter adds the $2 billion Ares contribution and the Plenitude deconsolidation, so readers need to see how much of any debt reduction comes from operations[10][11][12].

Company Background and Business Structure

Eni is a European integrated energy company whose profit center is upstream; it was founded in 1953, is headquartered in Rome, and the Italian state holds a controlling stake through the Ministry of Economy and Finance and Cassa Depositi e Prestiti, with each NYSE ADS representing two ordinary shares listed in Milan[13]. The company had 32,349 employees at the end of 2025, and its chief executive is Claudio Descalzi[13]. In recent years it has pursued a "satellite model," placing upstream assets and transition businesses in separately financed joint ventures or subsidiaries, bringing in outside capital and booking its share of profit; examples include Vår Energi, Azule, Ithaca, Searah, formed with Malaysia's Petronas in May 2026, and Plenitude, the retail and renewables subsidiary that has brought in capital from Ares and others[14][15].

Eni reports five segments, and Exploration & Production (E&P) is by far the largest source of profit. E&P produces oil and gas in North Africa, sub-Saharan Africa, Norway, Kazakhstan, Indonesia and Malaysia, Mexico and elsewhere, and it also includes crude marketing, shipping and trading; production available for sale averaged 1,594 kboe/d in 2025, of which 1,143 came from consolidated subsidiaries and 451 from equity-accounted entities, with North Africa at 485 (Egypt 227, Libya 155, Algeria 101) and Kazakhstan at 152[16]. Global Gas & LNG Portfolio and Power (GGP) buys pipeline gas and LNG from Algeria, Nigeria, Congo, Norway and other sources and sells mainly to wholesale customers in Italy and Europe; its gas sales were 24.65 bcm in the first half of 2026[17]. Enilive makes biofuels at Venice and Gela in Italy and through the Chalmette joint venture in the United States and runs a network of service stations in Italy and selected European markets, while Plenitude sells retail gas and power and develops renewables, with about 10 million retail points of delivery in Europe at the end of 2025, 8 million of them in Italy[13], and 6.0 GW of installed renewable capacity at the end of the second quarter of 2026[2]. The Refining, Chemicals and Sites in transformation segment covers refineries in Italy and abroad as well as the Versalis chemicals business.

Joint ventures and accounting scope shape how Eni's statements should be read. Of the €5.375 billion in second-quarter group proforma adjusted EBIT, consolidated subsidiaries contributed €3.516 billion and the main joint ventures and associates €1.859 billion, including €1.793 billion within E&P[9]; in the first half, Eni's share of adjusted operating profit at its main joint ventures was €2.867 billion, up 56%, including €1.920 billion from Vår Energi and €463 million from Azule Energy, but these entities return cash to Eni only as dividends, which were €558 million in the half, and their production was 546 kboe/d[18]. Plenitude has been classified as a discontinued operation since the first quarter of 2026[19], and Eni plans to deconsolidate it in the third quarter while keeping about 65%[12]; Searah is a 50-50 joint venture with Petronas, and at closing Eni deconsolidated €3.240 billion of net assets, recognized a €4.850 billion equity interest and booked a €2.088 billion gain from the business combination[14]. Eni also generally does not hedge the future cash flow from selling its production, and production sharing agreements accounted for 60% of its proved reserves at the end of 2025[20].

Financial History and Current Position

In fiscal 2025, Eni's revenue and profit edged lower as oil prices fell. Under IFRS, 2025 sales from operations were €82.151 billion (€88.797 billion in 2024 and €93.717 billion in 2023), operating profit was €5.010 billion (€5.238 billion in 2024 and €8.257 billion in 2023) and net profit attributable to shareholders was €2.608 billion (€2.624 billion in 2024)[21]. By segment, operating profit was €6.302 billion in E&P, €1.770 billion in GGP and €652 million in Enilive and Plenitude combined, while refining and chemicals lost €2.485 billion[22]; net cash from operating activities was €13.330 billion[23]. The average Brent price fell 14.5% in 2025, which Eni estimates cut E&P operating profit by about €1.8 billion and cash flow by about €1.6 billion[20], yet production available for sale still rose from 1,572 kboe/d in 2024 to 1,594[16]. Eni returned €5 billion to shareholders in 2025, comprising a €1.05 per share dividend totaling €3.15 billion and a €1.8 billion buyback[24].

In the first half of 2026, the Middle East conflict lifted oil prices and Eni's profit rose sharply with them. Brent averaged $92.57 in the first half, up from $71.74 a year earlier[25]; in the first quarter, group proforma adjusted EBIT was €3.536 billion, E&P was €3.357 billion, adjusted net profit was €1.302 billion and production was 1,798 kboe/d, below the 1,839 of the fourth quarter of 2025[6]. In the second quarter, group proforma adjusted EBIT rose 100% to €5.375 billion, E&P reached €4.769 billion, adjusted net profit was €2.333 billion and reported net profit was €3.319 billion[2]; the higher reported figure included a €2.088 billion Searah business-combination gain, net of €1.287 billion in impairments[14][9].

Cash and the balance sheet improved much more slowly than profit. Adjusted CFFO was €2.878 billion in the first quarter and €4.469 billion in the second, a 61% year-on-year increase in the second quarter, and first-half organic capital expenditure was €3.710 billion[2]; but working capital absorbed €1.516 billion in the first half, and free cash flow was only €873 million, down from €1.687 billion a year earlier[10]. Net borrowings before lease liabilities were €11.271 billion on June 30, up about €1.74 billion from €9.528 billion at the end of 2025, with proforma gearing at 10%[6][2]; first-half shareholder distributions were €2.53 billion, of which €1.6 billion were dividends and €0.9 billion buybacks[11]. By September 14, 2026, the new buyback had purchased 69,995,483 shares for about €1.580 billion, equal to 2.31% of share capital[26].

Operating Model

Trading inflates Eni's revenue, but its profit drivers are concentrated in upstream volumes and prices. E&P revenue is set mainly by equity production multiplied by realized prices: first-quarter liquids output was 862 thousand barrels per day and natural gas 4,893 million cubic feet per day[27], while first-half liquids were 847 thousand barrels per day, gas was 4,950 million cubic feet per day and the average realization was $66.49 per boe, up from $55.45 a year earlier[25]. Eni notes that much of its gas is sold at fixed prices or indexed to oil, so oil prices move profit far more than gas prices do; production sharing agreements provide a partial offset, with Eni's entitlement volumes moving inversely by up to about 1 kboe/d for each $1 change in Brent[20]. GGP earns its revenue by optimizing the gap between purchase and sale contracts, and in the first half the closure of the Strait of Hormuz cut Qatari supply by 1.15 bcm, replaced by extra volumes from Algeria, Nigeria, Congo and Norway[17].

Eni manages profit through proforma adjusted EBIT, and three factors drive its quarterly changes: oil prices and volumes, how much refining margin it captures, and the biofuel premium. By segment in the second quarter, E&P contributed €4.769 billion, GGP and Power €503 million, Enilive €295 million, Plenitude €226 million, refining and chemicals minus €40 million, and corporate items and consolidation adjustments minus €378 million[9][2]. E&P profit moves with Brent within the same quarter: it was €2.795 billion in the fourth quarter of 2025 at $63.69 Brent and €3.357 billion in the first quarter at $80.61[27][6], then rose to €4.769 billion in the second quarter at roughly $104.5, a figure derived from the first-half average[25][2]. Enilive's first-half proforma adjusted EBIT was €433 million, nearly double the €224 million of a year earlier[28]. Moving from proforma EBIT to adjusted net profit also requires deducting joint-venture interest and taxes and group income taxes, and the group tax rate was 36.9% in the second quarter[9].

Adjusted CFFO is the base for Eni's shareholder returns, and cash flows out in turn to capital spending, working capital, distributions and portfolio investments. First-half adjusted CFFO was €7.347 billion, with joint-venture profit counted only through dividends[2][18]; E&P capital expenditure was €1.526 billion in the second quarter and €3.141 billion in the first half[29], and full-year gross capex is guided at about €7 billion, with net capex below €5 billion[3]. The payout rules are set out in the 2025 annual report: if conditions beat the $70 Brent budget, up to 60% of the incremental cash flow is returned through buybacks until full-year Brent reaches $90; above $90, or when gas prices or refining margins run 50% above budget, 100% of the increment goes out as an extraordinary dividend[24]. Eni's stated sensitivities are about €110 million of full-year CFFO for each $1 change in Brent, about €80 million for each $1 in SERM and about €30 million for each €1 per MWh in European gas prices[4]. Portfolio deals will dominate the third-quarter cash picture: Ares's $2 billion contribution to an upstream partnership is due in the third quarter, the sale of a 10% stake in the Baleine field is near completion[12], and the Plenitude deconsolidation will remove about €2.6 billion of net debt[30].

Several measurement limits in this model deserve the reader's attention. There is no single-quarter table for second-quarter Brent and realized prices, so the figures of roughly $104.5 per barrel and about $77 per boe are approximations derived from the first-half and first-quarter data; refining and chemicals are reported together within one segment, refining profit on its own appears only as a rounded figure in the text, and the SERM calculation method was changed in 2026, with the first-quarter figure revised to $10.1[8]. Since Plenitude became a discontinued operation, consolidated, discontinued and non-GAAP measures coexist, and after the third-quarter deconsolidation the scope of proforma EBIT, CFFO and net borrowings will all change[15].

Industry and Competitive Position

Among European integrated oil companies such as Shell, TotalEnergies, BP and Equinor, Eni stands out for exploration, its satellite model and production growth. About 38% of second-quarter E&P proforma adjusted EBIT came from joint ventures, where outside capital shares development spending[9]; underlying production grew 11% in the first half, and the company raised its full-year growth guidance to about 5%[31][3]. On the second-quarter call, management said none of its last 10 major upstream projects had run over budget[32]. In gas, a large increase in US liquefaction capacity and weak European demand have left the market oversupplied, European hub prices reacted only weakly to the Hormuz crisis, and GGP profit depends more on portfolio optimization and contract renegotiations[17].

Eni's weaknesses are just as clear, and they come from the same asset structure as its strengths. European chemicals are far less cost-competitive than producers in China, the United States and the Middle East, and Eni has launched a restructuring of its main petrochemical hubs[33], while the refining and chemicals segment posted a €2.485 billion operating loss in 2025[22]. Profit depends heavily on Brent, with each $1 moving full-year operating cash flow by about €110 million[34]; political and contract risk in North Africa, Kazakhstan and Venezuela is also above the peer average, and a sulfur fine in Kazakhstan remains in international arbitration[32]. The available materials do not include like-for-like quarterly peer data, so this comparison can only be qualitative.

Core Debates

As Brent retreats from roughly $104 in the second quarter, can Eni's production growth hold output above 1.78 million boe/d and keep upstream profit from falling below the first-quarter level?

This debate sets the floor for third-quarter profit, because E&P produced about 89% of second-quarter group proforma adjusted EBIT. First-half group proforma adjusted EBIT rose 40%, driven by both higher output and higher oil prices[2], and Eni itself expects the price component to fade in the second half, with Brent averaging $85 for the full year[7]. The third quarter is the first period in which the two can be separated: at $80.61 Brent in the first quarter, E&P profit was €3.357 billion, the closest price anchor[27][6]. The current baselines are second-quarter production of 1,789 kboe/d, E&P profit of €4.769 billion, E&P joint-venture adjusted EBIT of €1.793 billion and Brent of roughly $104.5, derived from the $92.57 first-half average[9][25].

Evidence that growth can cushion profit comes from output gains and joint ventures, but the counter-evidence is equally specific. Second-quarter production rose 7% year on year, underlying growth on the company's basis was 11%, and full-year guidance moved from 3%–4% to about 5%[31][3]; Searah was formed only on May 31, so it contributed just one month to the second quarter[14]; and Eni's share of operating profit at its main joint ventures rose 56% in the first half[18]. On the other side, second-quarter output did not grow from the first quarter's 1,798 or the 1,839 of the fourth quarter of 2025[6], upstream project cost inflation has risen from 3%–4% before the conflict to 4%–6%[32], and the third quarter will exclude the 10% Baleine stake[12]. An alternative reading is that second-quarter profit was mostly price, output has settled on a plateau of 1.79 to 1.80 million boe/d, and if Brent returns to $70–80 in the third quarter, E&P profit could approach or fall below the first-quarter level, leaving the growth story to new projects after 2027.

In this debate, price moves first and volume follows. Brent and gas contract prices set realizations and therefore E&P revenue at consolidated subsidiaries; new project ramp-ups and portfolio deals change equity production and spread unit costs; joint-venture output and oil prices set joint-venture adjusted EBIT, which feeds into E&P proforma adjusted EBIT, group EBIT and adjusted net profit. When oil prices fall, production sharing agreements raise Eni's entitlement barrels by about 1 kboe/d for each $1, which offsets only part of the drop[20]. Price effects reach profit within the quarter, while new projects need several quarters to ramp up, so third-quarter profit will first test how large the impact of lower prices is.

The Q3 2026 results need to show whether Searah's first full quarter and new projects can lift output off its plateau. Readers should check whether third-quarter production is at least 1,780 kboe/d and whether Eni reaffirms about 5% underlying growth; whether E&P profit stays at or above €3.357 billion with Brent near the first-quarter level; whether joint-venture EBIT holds above €1.3 billion after Searah's first full quarter; and how the 6-K explains the effect of the Baleine sale and Searah on reported production. If output falls below 1,750 kboe/d and is attributed to project delays, or if full-year underlying growth guidance is cut, the case that growth can cushion upstream profit is refuted; upstream cost inflation or new impairments eroding adjusted profit would also weaken it.

With Middle East supply disruptions lifting benchmark refining margins, can Eni turn them into reported profit, returning refining and chemicals to positive earnings in the third quarter, raising utilization and setting the promised extraordinary dividend?

Refining and biofuels are the only Eni businesses that could improve while oil prices fall, and they also decide whether the extraordinary dividend is paid. Eni has said that as long as the full-year SERM stays at or above $9 per barrel, the extraordinary dividend will be defined in October[4]; the first-half SERM was only $9.1, so the $14 full-year assumption implies close to $19 in the second half, and the third quarter is the first test[8]. The current baselines are a second-quarter SERM of $8.3 per barrel, average refinery utilization of 74%, refining and chemicals proforma adjusted EBIT of minus €40 million and Enilive at €295 million, with the extraordinary dividend amount not yet set[9].

Second-quarter results already show some margin capture, but underused capacity and logistics costs are offsetting the high benchmark. On the supportive side, SERM rose 74% year on year in the second quarter, refining proforma adjusted EBIT turned positive at about €80 million, the Versalis loss narrowed 65% to about €70 million and Enilive more than doubled its profit[31]; full-year Enilive EBITDA guidance was raised to €1.3 billion[3]; and the refining and chemicals segment loss narrowed from €260 million in the first quarter to €40 million[6]. On the other side, throughput outside Italy fell 35% year on year because the Hormuz closure made feedstock unavailable, and second-quarter utilization was 10 percentage points below the 84% of a year earlier[8]; management acknowledged that high freight and logistics costs leave realized margins $2–3 per barrel below the benchmark[32]; and Eni changed the SERM calculation to reflect market dislocation and revised the first-quarter figure. An alternative reading is that the high SERM reflects the same crisis that leaves Eni short of feedstock and unable to run its plants fully, so reported capture will stay discounted; part of the Versalis improvement came from temporary supply disruptions and would reverse as the crisis eases.

The transmission in this debate runs from global product supply all the way to shareholder returns. Middle East product outages and refinery closures in the Atlantic Basin lift middle distillate cracks and therefore SERM; refinery throughput multiplied by the margin after freight and crude differential discounts determines refining EBIT[8]; and tight fossil diesel supply lifts prices for HVO and sustainable aviation fuel, improving Enilive's biorefining margin[28]. A full-year SERM above $9 triggers the extraordinary dividend, and each $1 of SERM moves full-year CFFO by about €80 million[4]. Margins reach profit within the quarter, but the extraordinary dividend is set in October on a full-year view, so third-quarter margins will feed directly into the fourth-quarter payout decision.

The Q3 2026 results need to show whether high benchmark margins become segment profit and a specific extraordinary dividend amount. Readers should check whether third-quarter SERM is at least $14 and whether the method changes again; whether utilization returns above 80% and feedstock returns to overseas refineries; whether refining and chemicals turns to a profit of at least €75 million; whether Enilive stays above €250 million; and whether the extraordinary dividend amount and its basis are announced in October. A SERM below $9, a high SERM with a continued segment loss, or no dividend decision in October would each weaken the capture case; a reversal of the Versalis gains as supply disruptions ease would also be a negative signal.

As oil prices retreat, can Eni hold its €15 billion full-year operating cash flow guidance while executing the €3.4 billion buyback, setting an extraordinary dividend and bringing net debt down?

This debate tests whether high payouts and low leverage can coexist while oil prices fall. Eni's shareholder returns follow adjusted CFFO by formula: 60% of cash flow above the €11.5 billion budget goes to buybacks, and all of the increment from Brent above $90 or from gas prices or refining margins 50% above budget goes out as an extraordinary dividend[4][24]. First-half CFFO ran well above budget, yet net borrowings rose; the third quarter brings portfolio cash and the Plenitude deconsolidation at the same time, making it the first test window. The current baselines are second-quarter adjusted CFFO of €4.469 billion, organic capex of €1.838 billion and net borrowings of €11.271 billion at the end of June[2], plus €1.580 billion of buybacks executed by September 14[26].

Operating cash flow itself is strong, but first-half distributions already exceeded free cash flow. On the supportive side, second-quarter adjusted CFFO rose 61% year on year, and Investing.com reported on results day that it was 15% above analyst expectations[2][5]; full-year guidance was raised to €15 billion, and proforma gearing of 10% sits at the low end of the 10%–15% target range[3]; the $2 billion Ares contribution is due in the third quarter[12], and the Plenitude deconsolidation will remove about €2.6 billion of net debt[30]. On the other side, working capital absorbed €1.516 billion in the first half and free cash flow was only €873 million, down from €1.687 billion a year earlier[10]; net borrowings rose by about €1.74 billion, and shareholder distributions of €2.53 billion exceeded free cash flow[11]; and meeting full-year guidance requires about €7.65 billion of CFFO in the second half, while Eni expects Brent to ease for a full-year average of $85, implying about $77 in the second half, well below the second quarter[7]. An alternative reading is that any fall in net borrowings will come mainly from asset sales and deconsolidation rather than operating cash, so the high payouts are effectively consuming one-off portfolio cash.

The order of cash transmission shows which item will come under pressure first. Segment profits add up to adjusted CFFO, with joint ventures counted only through dividends; after organic capex, the remainder is free cash flow, which pays the dividend (€1.1 per share in 2026), the buyback (€3.4 billion, capped at €4 billion) and any extraordinary dividend[4]; together with working-capital swings and portfolio cash from the Ares contribution, the Baleine sale and the Plenitude deconsolidation, that determines net borrowings and gearing[12]. Each $1 by which Brent falls short of the assumption removes about €110 million of full-year CFFO, a pressure that shows up within the quarter, while transaction cash arrives only once.

The Q3 2026 results need to separate operating cash from transaction cash before anyone can judge whether operations support the payouts. Readers should check whether third-quarter adjusted CFFO is at least €3.83 billion and whether the €15 billion guidance holds; whether organic capex stays within €1.5 billion to €2 billion; whether net borrowings fall below €9.528 billion and whether Eni separates operating and transaction cash; and whether the €3.4 billion buyback is maintained or raised and an extraordinary dividend amount is announced. CFFO below €3.4 billion or a guidance cut, a lower buyback plan, or net borrowings that still rise after the transactions would each show that payouts exceed what operating cash can bear; continued working-capital absorption would also weaken the case.

Risks and Falsifiers

The first risk is geopolitical and contract exposure in the Middle East and other producing countries. The Hormuz closure cut Qatari supply to Eni by 1.15 bcm in the first half[17], overseas refineries processed less because feedstock was unavailable[8], a Kazakh sulfur fine remains in international arbitration, and investment in Venezuela is still subject to contract negotiation and legacy regulatory issues[32]. The exposed line is GGP's full-year proforma adjusted EBIT guidance of more than €1.4 billion, which relies on substitute supply and trading optimization[3]; in 2025, production available for sale was 152 kboe/d in Kazakhstan and 63 kboe/d in Venezuela[16]. If the third-quarter 6-K and call add no new references to Middle East shutdowns or adverse arbitration developments, and GGP keeps its full-year guidance above €1.4 billion, this risk has not materialized.

The second risk is a major change in third-quarter reporting scope, which reduces comparability with consensus figures and with the prior year. The planned Plenitude deconsolidation, equity accounting for Searah, the sale of 10% of Baleine and the $2 billion Ares contribution will all change the scope of profit, cash and debt at once[15][12]. Second-quarter reported net profit of €3.319 billion was about €1 billion above adjusted net profit of €2.333 billion, mainly because of the €2.088 billion Searah remeasurement gain, alongside €1.287 billion of impairments; Plenitude's €226 million of second-quarter proforma adjusted EBIT will also leave the consolidated scope[9]. If the third-quarter 6-K separately shows how the Plenitude deconsolidation and the Searah and Ares transactions affect EBIT, CFFO and net borrowings, and provides adjusted figures comparable with the third quarter of 2025, this risk is largely resolved.

The third risk is that production growth stalls on a plateau of 1.79 to 1.80 million boe/d. Second-quarter output was essentially flat sequentially, the third quarter excludes the 10% Baleine stake, and if new projects ramp up more slowly than planned, profit will follow falling oil prices more directly[31]. The exposure is the €4.769 billion of second-quarter E&P proforma adjusted EBIT; on the annual report's basis, each $1 of Brent moves full-year operating cash flow by about €110 million, so a return from the derived $104.5 to around $80 equals roughly €2.7 billion of full-year cash flow[34]. If third-quarter production is at least 1,780 kboe/d and E&P profit is at least €3.357 billion with Brent no higher than in the first quarter, this risk is refuted.

The fourth risk is a gap between benchmark and reported refining margins. High freight, narrowing crude differentials and feedstock shortages leave Eni's realized refining margin $2–3 per barrel below SERM and constrain overseas refinery runs, so high benchmark margins may not become segment profit[32][33]. Using Eni's sensitivity of about €80 million of full-year CFFO for each $1 of SERM, a $2–3 capture discount equals €160 million to €240 million a year, and the segment still lost €40 million in the second quarter[4]. If refining and chemicals proforma adjusted EBIT is at least €75 million with third-quarter SERM at or above $14, and utilization is at least 80%, this risk is refuted.

The fifth risk is that shareholder returns depend on one-off cash. First-half distributions of €2.53 billion exceeded €873 million of free cash flow, and net borrowings rose by about €1.74 billion[11][10]; if second-half CFFO falls with oil prices, buybacks and the extraordinary dividend will lean more on the Ares contribution, asset sales and the Plenitude deconsolidation. The exposure is the €3.4 billion buyback (capped at €4 billion) plus the €1.1 per share dividend, and each $1 by which Brent falls short of the assumption removes about €110 million of full-year CFFO[4]. If third-quarter adjusted CFFO is at least €3,830 million and operating cash makes a positive contribution to the fall in net borrowings, this risk is refuted.

What to Watch Next

• Production growth versus oil prices: third-quarter output against the second quarter's 1,789 kboe/d and the roughly 5% underlying growth guidance; at least 1,780 confirms the cushion, while below 1,750 with delays cited refutes it.
• E&P profit: against €4.769 billion in the second quarter and €3.357 billion in the first quarter at $80.61 Brent; at least €3.357 billion with Brent near first-quarter levels confirms the case.
• E&P joint-venture EBIT: against €1.793 billion in the second quarter; holding above €1.3 billion after Searah's first full quarter confirms the case.
• Refining capture: SERM against $8.3 and utilization against 74% in the second quarter; SERM of at least $14 and utilization above 80% support capture, while SERM below $9 refutes it.
• Refining and chemicals and Enilive profit: against minus €40 million and €295 million in the second quarter; a segment profit of at least €75 million confirms capture, while a high SERM with a continued loss refutes it, and Enilive should hold above €250 million.
• Extraordinary dividend: not yet set, with Eni saying it will be defined in October and paid in the fourth quarter; no decision in October refutes the capture case.
• Adjusted CFFO: against €4.469 billion in the second quarter and the €15 billion full-year guidance; at least €3.83 billion confirms, while below €3.4 billion or a guidance cut refutes.
• Net borrowings and buybacks: against €11.271 billion at the end of June and €1.580 billion of buybacks through September 14; net borrowings below €9.528 billion with operating and transaction cash shown separately confirm, while rising debt after the transactions or a lower buyback refutes.

Conclusion

Eni's results are driven by upstream oil and gas volumes and prices, while refining, biofuels and gas trading shape the marginal change in profit. E&P produced about 89% of second-quarter group proforma adjusted EBIT, Eni guides to about €15 billion of full-year CFFO on assumptions of $85 Brent and a $14 SERM, and net borrowings were €11.271 billion at the end of June with proforma gearing at 10%[2][3]. The central unresolved relationship is whether, as oil prices come down from second-quarter highs, production growth, refining margin capture and operating cash flow can together support upstream profit, the extraordinary dividend and the €3.4 billion buyback without relying on asset sales and the Plenitude deconsolidation to bring net debt down.

Independent coverage after the second-quarter results looks at Eni on two different time horizons. On results day, Maria Ponnezhath of Investing.com described the quarter as a broad beat: adjusted net profit of €2.3 billion topped expectations, cash flow from operations before working capital of €4.5 billion was 15% above analyst expectations, upstream output was 3% above the market's aggregate estimate, and the shares rose 4.8% after Eni raised its CFFO guidance and buyback[5]; the report speaks to the cash-and-payout and production-growth debates but does not address the $14 SERM assumption behind the €15 billion guidance, against an actual first-half SERM of only $9.1. In September, Sultan Khalid of Insider Monkey argued that Eni's 25-year Junin 5 contract with Venezuela is a long-term growth opportunity, while placing the biggest concern on execution: local roads, wells, pipelines, processing facilities, power systems and export infrastructure are dilapidated and will need substantial time and capital to rebuild, and Eni is increasing its exposure to a market with a history of sanctions, instability and government intervention[35]. Both pieces value Eni's growth, but the first focuses on quarterly cash already delivered and the second on the execution and political risk carried by longer-term growth; neither is original sell-side research, so they serve only as outside interpretations and do not represent a market consensus.

The combination that would most strengthen the current understanding is third-quarter output of at least 1,780 kboe/d with the roughly 5% growth guidance reaffirmed, E&P profit of at least €3.357 billion despite lower Brent, a refining and chemicals profit of at least €75 million with an extraordinary dividend defined in October, and adjusted CFFO of at least €3.83 billion with operating cash contributing positively to lower net borrowings. Conversely, if output drops below 1,750 kboe/d, SERM stays high while the segment still loses money, CFFO falls below €3.4 billion or full-year guidance is cut, and net borrowings fall only on transaction cash, that would indicate Eni's high payouts rest more on peak oil prices and one-off cash than on durable operating improvement.

Sources

[1] Drillr earnings calendar (updated 2026-09-23) · E 2026-10-23 call and 3Q26 estimates · 2026-09-23 · Drillr earning_call_calendar

[2] E 6-K filed 2026-08-04 · 2Q26 key operating and financial results · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[3] E 6-K filed 2026-08-04 · outlook 2026 raised guidance · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[4] E 6-K filed 2026-08-04 · 2026 distributions, extraordinary dividend and sensitivities · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[5] Investing.com 2026-07-29 · Eni shares surge on raised cash flow guidance and buyback · 2026-07-29 · Investing.com · https://uk.investing.com/news/earnings/eni-shares-surge-on-raised-cash-flow-guidance-and-buyback-4794095

[6] E 6-K filed 2026-04-24 · 1Q26 key operating and financial results (with 4Q25 column) · 2026-04-24 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[7] E 6-K filed 2026-08-06 · oil market risk and 2H26 price view · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[8] E 6-K filed 2026-08-04 · 2Q26 refining and chemicals operating data · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[9] E 6-K filed 2026-08-04 · 2Q26 proforma adjusted EBIT reconciliation by segment · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[10] E 6-K filed 2026-08-06 · 1H26 summarized cash flow statement · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[11] E 6-K filed 2026-08-06 · 1H26 net borrowings bridge and buyback · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[12] E 6-K filed 2026-08-04 · 2Q26 portfolio actions and Plenitude deconsolidation timing · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[13] E 20-F filed 2026-03-23 · reportable segments description · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[14] E 6-K filed 2026-08-06 · Searah JV business combination · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[15] E 6-K filed 2026-08-06 · Plenitude reorganization and discontinued operation · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[16] E 20-F filed 2026-03-23 · 2025 production available for sale by country · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[17] E 6-K filed 2026-08-06 · GGP market risk and gas supply mix · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[18] E 6-K filed 2026-08-06 · main JV/associates 1H26 · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[19] E 6-K filed 2026-04-24 · Plenitude discontinued-operation accounting · 2026-04-24 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[20] E 20-F filed 2026-03-23 · commodity price exposure and 2025 Brent impact · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[21] E 20-F filed 2026-03-23 · FY2025 consolidated profit and loss · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[22] E 20-F filed 2026-03-23 · FY2025 operating profit by segment · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[23] E 20-F filed 2026-03-23 · 2025 capital expenditure by segment and operating cash flow · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[24] E 20-F filed 2026-03-23 · shareholder remuneration policy and 2026 plan · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[25] E 6-K filed 2026-08-06 · 1H26 E&P production and prices · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[26] E 6-K filed 2026-09-23 · buyback progress to 14 September 2026 · 2026-09-23 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[27] E 6-K filed 2026-04-24 · 1Q26 production and prices · 2026-04-24 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[28] E 6-K filed 2026-08-06 · 1H26 non-GAAP results by segment and biorefining volumes · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[29] E 6-K filed 2026-08-04 · 2Q26 capital expenditure by segment · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[30] E 1Q26 earnings call 2026-04-24 · Drillr structured summary · 2026-04-24 · earnings-call · https://www.eni.com/en-IT/investors/results-and-reports.html

[31] E 6-K filed 2026-08-04 · 2Q26 strategic and financial highlights · 2026-08-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[32] E 2Q26 earnings call 2026-07-29 · Drillr structured summary of risks and Q&A · 2026-07-29 · earnings-call · https://www.eni.com/en-IT/investors/results-and-reports.html

[33] E 6-K filed 2026-08-06 · refining and chemicals business environment · 2026-08-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=6-K&dateb=&owner=include&count=40

[34] E 20-F filed 2026-03-23 · 2026 planning scenario and sensitivities · 2026-03-23 · 20-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001002242&type=20-F&dateb=&owner=include&count=40

[35] Insider Monkey 2026-09-07 · Eni (E) is Betting Billions on Venezuela's Massive Oil Reserves · 2026-09-07 · Insider Monkey · https://finance.yahoo.com/energy/articles/eni-e-betting-billions-venzuela-222155266.html