[PBR] Petrobras: Q3 2026 Earnings Test Record Output, Subsidies and Dividends

Petrobras is the Brazilian state-controlled oil and gas company whose business centers on crude production from Brazil's deepwater and pre-salt fields, and it also runs most of Brazil's refining capacity[1][2]. Heading into its Q3 2026 earnings, the company has announced that it will release financial results for Q3 2026 (3Q26, the three months ended September 30, 2026) after the market closes on 2026-11-10 and will hold its earnings webcast on November 11[3]. The latest quarter with published financials is the second quarter of 2026: sales revenue was US$33.607 billion, up 59.8% from a year earlier, Brent averaged US$104.52 per barrel, Adjusted EBITDA excluding one-off events was US$19.959 billion and free cash flow was US$7.659 billion[4]. Third-quarter operating data were already published in the October 28 production and sales report, which showed record total oil and gas output of 3.512 million barrels of oil equivalent per day[5]. The company gives no quarterly guidance; its full-year projections are oil production of 2.5 million barrels per day ±4% and cash capital expenditure of US$16.9 billion ±5%[6], and on the second-quarter call management said production could reach the top of that range and capital spending would also land at the top of its range[7]. Third-quarter expectations compiled in the Drillr earnings calendar are US$1.23 of earnings per ADS and US$31.587 billion of revenue; the matching second-quarter expectations were US$1.52 and US$31.455 billion, against actual results of US$1.62 and US$33.607 billion[8].

Three things matter most in this report. First, own oil production reached a record 2.832 million barrels per day in the third quarter, up 5.3% from the second quarter[9], but crude exports slipped to 987,000 barrels per day and another 140,000 barrels per day were still in transit at quarter-end and will only be recognized in the fourth quarter[10]; the question is whether the E&P margin holds at the second quarter's 70% and pre-salt lifting cost stays at US$4.45 per barrel of oil equivalent[11], which will show whether growth comes from the company's own execution or from oil prices. Second, domestic diesel sales rose 14.4% and diesel imports climbed from 18,000 to 110,000 barrels per day[12][10]; because the company does not move domestic prices with international oil prices and government subsidies fill the gap, the test is whether refining and marketing gross profit excluding inventory effects holds near US$3.5 billion[13] and whether road-diesel subsidy revenue stays at or above US$1.923 billion[14], which decides how much of the high oil price stays with the company. Third, second-quarter free cash flow of US$7.659 billion produced a declared payout of US$3.406 billion at 45%[4][15], while subsidy receivables from the government had built up to US$2.021 billion by the end of June[16]; the question is whether third-quarter cash can fund both the formula-driven dividend and the year-end gross debt target of US$67 billion[17].

Company Background and Business Structure

Petrobras is a listed company partly owned by the Brazilian federal government, describes itself as one of the world's largest oil and gas producers, and works mainly in exploration and production, refining, power generation and trading[1]. Its common and preferred shares trade in Brazil, its American depositary receipts are listed on the New York Stock Exchange, and it reports to the US Securities and Exchange Commission on Form 20-F. As the controlling shareholder, the federal government can influence the company's fuel pricing through legislation and executive measures, and the annual report lists this as one of the main risks facing minority shareholders[18].

Most of the company's profit comes from the Exploration and Production (E&P) segment, while the Refining, Transportation and Marketing (RTM) segment turns that crude into domestic fuel. E&P produces oil and gas in Brazil's deep and ultra-deep waters; deepwater fields accounted for 98% of total production in 2025[19] and pre-salt fields for 82%[20], with core fields including Búzios and Mero in the Santos Basin, produced through owned or chartered floating production, storage and offloading units (FPSOs)[5]. Most E&P crude is sold to the company's own refineries at internal transfer prices: of E&P's US$59.537 billion of segment revenue in 2025, US$59.305 billion came from inter-segment sales[21]. The rest is exported; third-quarter crude exports were 987,000 barrels per day, and the share going to China rose from 35% in the second quarter to 40%[10][22]. RTM runs 10 refineries in Brazil with 1.813 million barrels per day of distillation capacity, about 79% of the country's refining capacity[2], and sells diesel, gasoline, jet fuel and liquefied petroleum gas to Brazilian distributors, importing the shortfall; in the third quarter it imported 129,000 barrels per day of crude and 204,000 barrels per day of oil products[10]. The company sets domestic prices based on market share and profitability and avoids passing short-term swings in international prices and exchange rates through to domestic prices[23], and since 2026 the government has supported this approach with subsidies[24].

The Gas and Low Carbon Energies (G&LCE) segment is much smaller; it sells natural gas and power and operates thermal plants, and in the second quarter its Brazilian natural gas sales price was US$9.97 per MMBtu and segment Adjusted EBITDA was US$419 million[25]. The three segments form one chain: pre-salt production carries mainly real-denominated costs and platform leases, crude goes to the company's refineries or to export, domestic fuel sales (including subsidies) and exports generate segment EBITDA, and free cash flow after capital spending is paid out at 45%, with the remainder used to repay leases and debt[26]. Among its equity-method holdings, the company owns 36.1% of the total capital and 47% of the voting capital of petrochemical producer Braskem, and in April it signed a joint-control agreement with Braskem's new shareholders[27].

Financial History and Current Position

The 2025 annual figures show that profit growth came mainly from currency rather than revenue. Sales revenue in 2025 was US$89.195 billion[21], and net income attributable to shareholders was US$19.634 billion, up 160.8% from US$7.528 billion in 2024, which the annual report attributes mainly to exchange gains from the real's appreciation against the dollar (the year-end rate moved from 6.19 to 5.50); Adjusted EBITDA was US$42.523 billion, operating cash flow US$36.047 billion and free cash flow US$16.528 billion[28]. Gross debt at the end of 2025 was US$69.793 billion, up from US$60.311 billion at the end of 2024 but still within the range set in the Business Plan[29]. Operationally, net exports rose by 147,000 barrels per day to 646,000 barrels per day in 2025[30], and lifting cost in Brazil was US$6.4 per barrel of oil equivalent[20].

The 2026 interim figures show that higher oil prices lifted revenue and cash at the same time. Sales revenue in the first half of 2026 was US$57.142 billion, up 35.7% year on year, with free cash flow of US$11.514 billion; second-quarter sales revenue was US$33.607 billion, up 59.8% year on year, and Brent averaged US$104.52 per barrel compared with US$67.82 a year earlier[4]. Second-quarter Adjusted EBITDA excluding one-off events was US$19.959 billion, 70% higher than in the first quarter, which the company attributes to higher exports enabled by higher production, the recognition in the second quarter of exports that were in transit during the first quarter, and higher Brent prices[31]; net income attributable to shareholders was US$10.428 billion, or US$11.073 billion excluding one-off events, which included a US$965 million export tax on crude oil and diesel[32]. Second-quarter operating cash flow was US$12.250 billion and free cash flow US$7.659 billion[4]; at the end of June gross debt was US$70.806 billion, consisting of US$25.834 billion of financial debt and US$44.972 billion of lease liabilities, net debt was US$60.388 billion, and net debt to trailing twelve-month Adjusted EBITDA was 1.14 times[33].

For the third quarter only operating data are available so far, and financial data will not arrive until 2026-11-10. The October 28 production and sales report showed total oil and gas production of 3.512 million barrels of oil equivalent per day, up 11.7% from the third quarter of 2025 and 5.3% from the second quarter[5]; own crude and NGL production was 2.832 million barrels per day, and the nine-month average was 2.702 million barrels per day[9], already above the top of the full-year projection of 2.5 million barrels per day ±4%[6]. Domestic oil product sales were 1.854 million barrels per day, up 6.4% from the second quarter, including 849,000 barrels per day of diesel[12].

Operating Model

Revenue roughly equals domestic product volume times domestic price, plus fuel subsidies, plus export volume times international price, plus natural gas and power sales. In the second quarter of 2026 domestic market revenue was US$20.693 billion, including US$7.584 billion of diesel, US$1.923 billion of road-diesel subsidy, US$3.013 billion of gasoline and US$1.893 billion of jet fuel; export revenue was US$12.665 billion, including US$10.381 billion of crude oil and US$1.879 billion of fuel oil[14]. Domestic prices are set by the company and lag international oil prices, export prices move with Brent, and crude that E&P sells to the company's own refineries is eliminated in the consolidated statements[21].

Profit is determined by the E&P and RTM segments, and opposing forces shift earnings between them. E&P Adjusted EBITDA roughly equals equity production times a Brent-linked price, minus lifting cost, platform leases and government take; it contributed US$15.874 billion in the second quarter at a 70% margin[11]. Higher production spreads fixed costs and lowers unit lifting cost, which is why pre-salt lifting cost fell 4.8% in the second quarter[34]. RTM profit equals domestic and export sales minus the cost of crude and imported products and refining costs, plus or minus the inventory turnover effect; it was US$3.562 billion in the second quarter, and G&LCE was US$419 million[35][25]. A rise in oil prices immediately lifts E&P revenue but squeezes the RTM spread while domestic prices lag, and subsidy revenue partly offsets that squeeze. Government take in the form of royalties and special participation rises with oil prices and was US$4.605 billion in the second quarter[11]; export taxes and similar items are treated as one-off events, which affect net income but are excluded from EBITDA excluding one-off events[32].

On the cash side, the key elements are the definition of free cash flow and the dividend formula. The company defines free cash flow as operating cash flow minus purchases of property, plant, equipment and intangible assets, without deducting lease payments; when gross debt is at or below US$75 billion, it pays shareholders 45% of free cash flow each quarter[26]. For 2026 the company projects cash capital expenditure of US$16.9 billion ±5% and lease payments of US$10.0 billion[6], and subsidy receivables and exports in transit at quarter-end are the main sources of working-capital swings; in the second quarter working capital absorbed US$3.2 billion, including US$1.9 billion of subsidy-related receivables[36]. This means profit turns into cash with a lag of one to two quarters: subsidies are recognized as revenue first and collected only when the government pays in installments, while exports in transit are recognized in the following quarter.

Industry and Competitive Position

In Brazil, Petrobras nearly monopolizes refining but faces competition from ethanol in gasoline. The company controls about 79% of Brazil's refining capacity[2], and in 2025 its gasoline A accounted for 37% of Brazil's Otto-cycle fuel market (gasoline plus ethanol), where the main competitors are hydrated ethanol and compressed natural gas[37]. Third-quarter gasoline sales fell 0.7% from the second quarter, partly because the mandatory anhydrous ethanol content of gasoline rose from 30% to 32% on August 1[38]. Fuel retailing is handled by independent distributors, and the company's domestic pricing power is subject to the influence of its controlling shareholder[18].

Upstream, the company's cost advantage is clear, but its constraints are also distinctive. Pre-salt fields are highly productive and cheap to operate, with pre-salt lifting cost of US$4.45 per barrel of oil equivalent in the second quarter[11], and the Business Plan says the portfolio's prospective breakeven Brent price averages US$25 per barrel[39]. On the export side, the company shifts crude between markets: in the third quarter China took 40% and Europe 18%, while the US share rose from 2% in the second quarter to 12% and India's fell from 22% to 8%[22]. Compared with international integrated oil companies, Petrobras faces two distinctive constraints: its controlling shareholder's influence over domestic fuel prices, and the large lease liabilities that come from relying mainly on chartered FPSOs, which stood at US$44.972 billion at the end of June, more than 60% of gross debt[33]. Because comparable financial data for peers are not available here, the comparison is limited to the costs and structure the company itself discloses.

Core Debates

Petrobras produced a record 2.832 million barrels per day of its own oil in the third quarter, up 5.3% from the second quarter. Will the November 10 results show that, after cargoes in transit, export taxes and currency effects, this extra volume still kept the E&P margin at the second quarter's 70% and pre-salt lifting cost at or below US$4.45 per barrel of oil equivalent?

This question matters because E&P is Petrobras's main source of profit, contributing about 85% of the company's second-quarter Adjusted EBITDA, or US$15.874 billion of US$18.615 billion[11]. Production growth comes from the ramp-up of newly started platforms and from seven existing platforms running above nameplate capacity, which add more than 100,000 barrels per day, with another 270,000 barrels per day of remaining ramp-up capacity in the second half[40][41]. If this output can turn into profit at a lower unit cost, growth is coming mainly from the company's own execution rather than only from higher oil prices.

Current evidence shows production is accelerating, but the source of profit still supports two readings. Third-quarter total production was 3.512 million barrels of oil equivalent per day, which the company attributes to its highest production efficiency in eight years, the ramp-up of P-78 and P-79 at Búzios, FPSO Alexandre de Gusmão reaching peak output at Mero and lower losses from maintenance shutdowns[5]. Pre-salt crude was 2.454 million barrels per day, post-salt fell to 341,000 barrels per day because of maintenance and natural decline, and own crude production was 2.832 million barrels per day, compared with 2.689 million in the second quarter and 2.520 million in the third quarter of 2025[9]. Pre-salt lifting cost fell 4.8% quarter on quarter to US$4.45 in the second quarter, from US$4.67 in the first quarter and US$3.83 a year earlier[34][11]; the E&P margin rose from 64% in the first quarter to 70%, and the company attributes the 70% quarter-on-quarter increase in overall Adjusted EBITDA to higher exports, recognition of first-quarter cargoes in transit and higher Brent[31]. An alternative reading is that much of the second-quarter margin jump came from Brent rising from US$80.61 to US$104.52 and the concentrated recognition of first-quarter cargoes[4]. Third-quarter crude exports slipped to 987,000 barrels per day from 996,000 in the second quarter, 140,000 barrels per day were in transit at quarter-end and will only be recognized in the fourth quarter[10], and the export tax could remain in force for up to 60 days after the provisional measure expired in July[42], so the third-quarter E&P margin could fall even with higher output.

The financial transmission runs as follows: platform ramp-ups and above-nameplate operation raise own crude production, internal sales and exports multiplied by Brent form E&P revenue, higher output spreads fixed costs and lowers pre-salt lifting cost, and the result shows up in E&P segment Adjusted EBITDA and margin. What remains unresolved is whether higher third-quarter output, after cargoes in transit, export taxes and currency effects, can deliver the same margin. Readers should watch whether the E&P margin is at least 70%, whether pre-salt lifting cost is no higher than US$4.45 per barrel of oil equivalent, whether crude export revenue moves in line with Brent relative to the second quarter's US$10.381 billion[14], and whether the company explains how cargoes in transit and the export tax affected the third quarter.

There are two observable falsifiers. If the E&P margin falls below the first quarter's 64%, or pre-salt lifting cost rises above the first quarter's US$4.67, the volume growth did not translate into profit and cost advantage. If fourth-quarter own crude production falls below the second quarter's 2.689 million barrels per day, the third-quarter record relied on unusually light maintenance rather than durable capacity gains; P-80 and P-82 sailed from the Singapore shipyard on September 30 and October 18 respectively and are scheduled to start up in 2027, so they will not change the fourth-quarter production base[43].

After the oil price spike, Petrobras has relied on government subsidies rather than price increases to keep Brazil supplied with fuel. With domestic diesel sales up 14.4% in the third quarter and diesel imports rising to 110,000 barrels per day, can the refining and marketing business hold gross profit excluding inventory effects at the second quarter's roughly US$3.5 billion, and can road-diesel subsidy revenue stay at or above US$1.923 billion?

This question matters because domestic fuel sales make up more than 60% of company revenue, with second-quarter domestic market revenue of US$20.693 billion[14]. Petrobras runs about 79% of Brazil's refining capacity[2] and prices under a strategy of not passing through short-term international swings[23], while the federal government is both its controlling shareholder and the funder of the subsidies[18]. Subsidies are recognized as revenue and export taxes as expenses, and this arrangement decides how much of the high oil price stays with the company and how much goes to domestic consumers and the treasury[24].

Second-quarter data show refining and marketing gross profit improving, while operating income came under pressure from freight and taxes. RTM sales revenue rose 45% quarter on quarter to US$32.351 billion, and Adjusted EBITDA was US$3.562 billion at an 11% margin, compared with US$3.848 billion and 17% in the first quarter and US$1.080 billion and 5% a year earlier[35]. Excluding an inventory turnover effect of US$1.7 billion, gross profit was about US$3.5 billion, versus about US$3.2 billion in the first quarter; refinery utilization rose by 6 percentage points and resale of imported products fell to a record low, but operating income was lower than in the first quarter, which the company attributes to higher selling expenses from freight costs and export-related taxes[13]. Second-quarter subsidy revenue was US$2.099 billion, including US$1.923 billion for road diesel, US$159 million for gasoline and US$17 million for liquefied petroleum gas[14][44]; subsidy receivables from the government were US$2.021 billion at the end of June[16], and cumulative receipts reached about R$16 billion by October 13[45]. In the third quarter domestic product sales were 1.854 million barrels per day and diesel sales were 849,000 barrels per day, up 14.4% from the second quarter, with record diesel output of 769,000 barrels per day[12]; the company attributes the diesel demand growth to summer crop planting and higher industrial activity[38]. Imports, however, rose from 156,000 to 333,000 barrels per day, including diesel imports that rose from 18,000 to 110,000 barrels per day[10]. An alternative reading is that second-quarter profit included spreads supported by lower-cost inventory, while more diesel imported at high international prices entered third-quarter sales; if domestic prices do not change and subsidy volumes do not grow with sales, RTM profit would fall. Conversely, if the R$1.00 per liter subsidy under Provisional Measure 1,391 began to be recognized in the third quarter[46], subsidy revenue could exceed the second quarter's, and the change in profit would come mainly from policy rather than operations.

The financial transmission runs as follows: after international oil prices rose, the company did not immediately adjust domestic prices; in the second quarter the average domestic base product price was US$114.60 per barrel, US$10.08 above Brent, compared with a premium of US$6.22 in the first quarter and US$15.14 a year earlier[4][35]. Federal subsidies are paid by volume, with Provisional Measure 1,363 setting R$1.12 per liter from June 1 to December 31[47], and are recognized as sales revenue; the imported share of seasonal diesel demand is bought at international prices and flows into RTM gross profit and Adjusted EBITDA; and export taxes of 12% on crude and 50% on diesel are booked under other taxes[24], amounting to US$965 million in the second quarter with US$579 million of export tax payable at the end of June[32][42], ultimately affecting reported net income. What remains unresolved is which of rising imports, lagging domestic prices and growing subsidy revenue has the largest effect. Readers should watch whether RTM gross profit excluding inventory effects is at least about US$3.5 billion, whether road-diesel subsidy revenue is at least US$1.923 billion, whether the domestic base product price premium over Brent is at least US$6.22 per barrel, whether the export tax is clearly below US$965 million, and whether the company discloses a subsidy extension or a domestic price change.

There are also two observable falsifiers. If gross profit excluding inventory effects falls below the first quarter's roughly US$3.2 billion, rising imports and lagging domestic prices are eroding profit. If the subsidies expire while international oil prices remain high, the company will have to choose between raising prices and giving up margin, and the current balance will break; on the first-quarter call management said the company does not pass extreme short-term international price volatility through to domestic consumers[48].

Petrobras generated US$7.66 billion of free cash flow in the second quarter, declared 45% of it as dividends under its policy, and cut gross debt to US$70.81 billion. In the third quarter, can subsidy receivables start to come back and capital spending stay within the top of the projected range, so that free cash flow holds at second-quarter levels and supports both the dividend and the year-end gross debt target of US$67 billion?

This question matters because Petrobras's dividend is set by formula: when gross debt is at or below US$75 billion, the company distributes 45% of free cash flow each quarter[26][29]. Third-quarter free cash flow therefore directly determines the dividend to be declared with the November 10 results, and whether the remaining cash can also reduce debt decides whether management's year-end gross debt target of US$67 billion is credible[17]. Subsidy revenue counts toward profit but is collected later, which has opened a new gap between profit and cash in 2026[16].

Second-quarter cash generation was strong, but part of it came from a one-time concentration of collections. Operating cash flow was US$12.250 billion, up 46% from the first quarter, but working capital absorbed US$3.2 billion, including US$1.9 billion of subsidy-related receivables and a US$0.8 billion reduction in trade payables[36]. Cash capital expenditure was US$4.559 billion in the second quarter and US$9.072 billion in the first half[49], and management said full-year spending would land at the top of the US$16.9 billion ±5% range, with P-80, P-82 and P-83 scheduled to start up in 2027[7][50]. In the second quarter the company repaid US$2.9 billion of loans, amortized US$2.7 billion of lease liabilities and paid US$1.5 billion to shareholders; gross debt fell 0.6% quarter on quarter, net debt was US$60.388 billion, and net debt to trailing twelve-month Adjusted EBITDA fell to 1.14 times[36][33]. Based on second-quarter free cash flow of US$7.659 billion, the company declared shareholder remuneration of R$17.4 billion, about US$3.406 billion, payable in November and December[51][15]; management said surplus cash would go first to accelerating high-return projects and then to faster debt reduction, and that extraordinary dividends are very unlikely[52]. An alternative reading is that the jump in second-quarter cash depended on Brent at US$104.52 and the concentrated collection of first-quarter cargoes in transit, while another 140,000 barrels per day were in transit at the end of the third quarter[10]; if subsidy receivables keep building and income taxes rise with profit, third-quarter free cash flow could be well below the second quarter's even if profit stays high.

The financial transmission runs as follows: E&P and RTM EBITDA minus income taxes and working-capital changes (subsidy receivables and exports in transit) gives operating cash flow; subtracting cash capital expenditure gives free cash flow, of which 45% is declared as shareholder remuneration; and the remaining cash, together with lease and debt repayments, determines gross debt. The free cash flow baselines are US$7.659 billion in the second quarter, US$3.855 billion in the first quarter, US$3.445 billion in the second quarter of 2025 and US$16.528 billion for full-year 2025[4][28]; the gross debt baselines are US$70.806 billion at the end of June, US$71.214 billion at the end of March and US$69.793 billion at the end of 2025[33][29]. What remains unresolved is how far the timing of subsidy collections and cargoes in transit will push third-quarter cash away from profit. Readers should watch whether free cash flow is at least US$7.659 billion, whether subsidy receivables at the end of September are below US$2.021 billion, whether cash capital expenditure is no higher than about US$4.35 billion (the quarterly average for the second half implied by the top of the full-year projection minus first-half spending), whether gross debt at the end of September is no higher than US$70.806 billion, and whether the declared dividend is about 45% of third-quarter free cash flow.

There are likewise two observable falsifiers. If third-quarter free cash flow falls below the first quarter's US$3.855 billion, the next dividend will shrink noticeably and debt reduction will slow. If gross debt at the end of September is above the end-of-March level of US$71.214 billion, reaching the US$67 billion year-end target would require heavy debt reduction in the fourth quarter; management's long-term goal is to bring gross debt down to US$65 billion by the end of the 2026-2030 plan period[17].

Risks and Falsifiers

The first risk comes from Braskem, which could divert cash away from dividends and debt reduction. Petrobras holds 36.1% of Braskem's total capital and 47% of its voting capital and signed a joint-control agreement with the new shareholders in April[27]. On the second-quarter call, analysts asked about reports that Braskem might enter court-supervised reorganization and that Petrobras might inject capital, and management said it was evaluating all options but could not disclose details[53]. A capital injection or guarantee would affect how cash is used after free cash flow; if the third-quarter report and call announce no capital injection, guarantee or new provision for Braskem, this concern does not hold for now.

The second risk is lower oil prices combined with regulatory change. Management believes Brent will return to the level assumed in the Business Plan, US$63 per barrel for 2026[52][54], and the plan's Brent breakeven for net debt neutrality is US$59 per barrel in 2026[55]; at the same time, proposed changes to Brazilian natural gas regulation could require the company to reassess existing and planned gas projects[56]. The exposure is to E&P and company-wide Adjusted EBITDA, which was US$18.615 billion in the second quarter at Brent of US$104.52 per barrel, and to the Gas and Low Carbon Energies segment, whose second-quarter Adjusted EBITDA was US$419 million[25]; if the fourth-quarter Brent average remains well above US$63 per barrel and the company does not adjust projects because of gas regulation, this risk has not materialized.

The third risk is that record third-quarter production fails to deliver profit. With 140,000 barrels per day of crude in transit at quarter-end[10], an export tax that could continue for up to 60 days after July[42], a stronger real and maintenance spending, the E&P margin could fall below the second quarter's 70%, and the market would read the volume growth as having brought no profit. The exposure is to second-quarter E&P segment Adjusted EBITDA of US$15.874 billion and crude export revenue of US$10.381 billion[11][14]; if the third-quarter E&P margin is at least 70% and pre-salt lifting cost is no higher than US$4.45 per barrel of oil equivalent, this risk is falsified.

The fourth risk is that the controlling shareholder shapes fuel pricing through subsidies, export taxes and a penalty framework[18][24]. The subsidy under Provisional Measure 1,363 runs to December 31[47], while Provisional Measure 1,391 lasts 30 days and can be extended once[46]; if international oil prices stay high while subsidies expire or shrink, the company must either raise prices and absorb political pressure or carry lagging domestic prices without subsidies. The exposure is to second-quarter subsidy revenue of US$2.099 billion, RTM segment Adjusted EBITDA of US$3.562 billion and export taxes of US$965 million[14][35]; if third-quarter road-diesel subsidy revenue is at least US$1.923 billion, RTM gross profit excluding inventory effects is at least about US$3.5 billion, and the company discloses a subsidy extension or the end of the export tax, this risk has not materialized.

The fifth risk is that cash is squeezed at once by subsidy receivables, capital spending and oil prices. If subsidy receivables keep building, capital spending runs at or above the top of the projection and Brent falls, third-quarter free cash flow could drop below the first quarter's US$3.855 billion[4]; under the 45% formula, the next declared dividend would shrink accordingly and the US$67 billion year-end gross debt target would be delayed[7]. The exposure is to second-quarter free cash flow of US$7.659 billion, the declared payout of US$3.406 billion and gross debt of US$70.806 billion at the end of June[51][33]; if third-quarter free cash flow is at least US$7.659 billion, subsidy receivables at the end of September are below US$2.021 billion and gross debt is no higher than US$70.806 billion, this risk is falsified[16].

What to Watch Next

• Pre-salt volume and E&P profit: the E&P segment margin and pre-salt lifting cost, against second-quarter levels of 70% and US$4.45 per barrel of oil equivalent. At least 70% with cost no higher than US$4.45 confirms the current reading; below 64% or above US$4.67 falsifies it.
• Pre-salt volume and E&P profit: crude export revenue and cargoes in transit, against second-quarter crude export revenue of US$10.381 billion and 140,000 barrels per day in transit at the end of September. Watch whether export revenue moves with Brent and whether the company explains the effect of cargoes in transit and the export tax; fourth-quarter own crude production below 2.689 million barrels per day falsifies the durability of the record.
• Domestic fuel profit under subsidies: RTM gross profit excluding inventory effects, against about US$3.5 billion in the second quarter and about US$3.2 billion in the first. At least about US$3.5 billion after higher diesel imports confirms; below about US$3.2 billion falsifies.
• Domestic fuel profit under subsidies: road-diesel subsidy revenue and export taxes, against US$1.923 billion and US$965 million in the second quarter. Watch whether subsidies grow with volume, whether export taxes fall and whether subsidies are extended or prices changed; subsidy revenue of at least US$1.923 billion with a clear drop in export taxes confirms.
• Free cash flow, dividend and debt: free cash flow and subsidy receivables, against US$7.659 billion in the second quarter and US$2.021 billion of receivables at the end of June. Watch whether subsidy collections begin and whether capital spending stays within about US$4.35 billion; free cash flow below US$3.855 billion falsifies.
• Free cash flow, dividend and debt: gross debt and the declared dividend, against US$70.806 billion at the end of June and a second-quarter payout of US$3.406 billion. Watch end-September gross debt and whether the dividend is about 45% of free cash flow; gross debt above US$71.214 billion falsifies.

Conclusion

Petrobras's results are driven by three forces: pre-salt volume growth and low costs determine how much E&P earns, domestic fuel pricing and government subsidies determine how much of the high oil price stays with the company, and the 45% dividend formula converts free cash flow directly into shareholder returns and room for debt reduction. The latest financial position comes from the second quarter of 2026: sales revenue of US$33.607 billion, Adjusted EBITDA excluding one-off events of US$19.959 billion, free cash flow of US$7.659 billion and gross debt of US$70.806 billion[4][33]. Own crude production already reached a record 2.832 million barrels per day in the third quarter[9], but cargoes in transit, export taxes, subsidy collections and rising diesel imports leave the relationship between production, profit and cash unresolved until November 10.

Between the second-quarter results on August 7, 2026 and October 30, the material found consisted only of news reports on production, subsidies and the share price, and no signed, verifiable independent assessment with a substantive view on the three questions above was found, so outside interpretations cannot be synthesized here; the judgments above rest entirely on the company's own disclosures and production data and have not yet been tested by independent analysis.

From here, if the third-quarter E&P margin is at least 70%, pre-salt lifting cost is no higher than US$4.45 per barrel of oil equivalent and RTM gross profit excluding inventory effects holds near US$3.5 billion, while free cash flow is at least US$7.659 billion, subsidy receivables begin to fall and end-September gross debt is no higher than US$70.806 billion, the reading that "volume turns into profit, subsidies protect margins and cash funds both dividends and debt reduction" would be materially strengthened. Conversely, if the E&P margin drops below 64%, gross profit excluding inventory effects falls below about US$3.2 billion, free cash flow falls below US$3.855 billion or gross debt rises above US$71.214 billion, the third-quarter production record will not have translated into equivalent profit and cash, and the current reading would need revision.

Sources

[1] PBR 20-F filed 2026-04-09 · company overview · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[2] PBR 20-F filed 2026-04-09 · refining capacity and share of Brazil · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[3] PBR 6-K filed 2026-10-14 (3Q26 results release dates) · 2026-10-14 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004918/pbr20261013_6k1.htm

[4] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · main items 2Q26 vs 1Q26 vs 2Q25 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[5] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · 3Q26 production record and drivers · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[6] PBR 6-K filed 2026-08-07 (2Q26 results webcast presentation) · monitoring of 2026 Business Plan projections · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004128/pbr20260806_6k1.htm

[7] PBR earnings call 2026-08-07 (2Q26 results) · guidance: production top of range, capex, opex · 2026-08-07 · earnings-call · https://gateway.drillr.ai/mcp/private

[8] Drillr earnings calendar (updated 2026-10-29) · PBR 2026-11-10 Q3 2026 estimates · 2026-10-29 · Drillr earnings calendar · https://gateway.drillr.ai/mcp/private

[9] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · E&P production table 3Q26 · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[10] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · net imports and exports 3Q26, exports in transit · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[11] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · E&P results and lifting cost 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[12] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · RTM sales and production table 3Q26 · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[13] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · RTM commentary: inventory effect, imports, export taxes 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[14] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · net revenues by product incl. subsidy programs 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[15] PBR 6-K filed 2026-08-07 (2Q26 interim financial statements, US$) · note 30 subsequent event: 2Q26 shareholder remuneration · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004133/pbrfs2q26usd_6k.htm

[16] PBR 6-K filed 2026-08-07 (2Q26 interim financial statements, US$) · note 9 trade receivables: fuel trading subsidy program · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004133/pbrfs2q26usd_6k.htm

[17] PBR earnings call 2026-05-12 (1Q26 results) · guidance: production, capex, opex, gross debt · 2026-05-12 · earnings-call · https://gateway.drillr.ai/mcp/private

[18] PBR 20-F filed 2026-04-09 · controlling shareholder and pricing risk · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[19] PBR 20-F filed 2026-04-09 · E&P: deepwater share of production · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[20] PBR 20-F filed 2026-04-09 · 2025 production vs goal, pre-salt share and lifting cost · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[21] PBR 20-F filed 2026-04-09 · 2025 income statement by segment · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[22] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · crude export destinations 3Q26 · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[23] PBR 20-F filed 2026-04-09 · commercial (pricing) strategy · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[24] PBR 20-F filed 2026-04-09 · Provisional Measure 1,340/2026: diesel subsidy and export taxes · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[25] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · Gas and Low Carbon Energies results 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[26] PBR 20-F filed 2026-04-09 · shareholder remuneration policy (45% of FCF) · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[27] PBR 6-K filed 2026-04-23 (new Braskem shareholders’ agreement) · 2026-04-23 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002489/pbr20260423_6k.htm

[28] PBR 20-F filed 2026-04-09 · 2025 consolidated financial performance · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[29] PBR 20-F filed 2026-04-09 · gross debt ceiling and year-end 2025 gross debt · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[30] PBR 20-F filed 2026-04-09 · 2025 Brazilian sales volumes and exports · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[31] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · consolidated results commentary 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[32] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · one-off events incl. export tax 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[33] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · debt metrics 30 June 2026 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[34] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · E&P lifting cost commentary 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[35] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · RTM results 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[36] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · operating cash flow and working capital 2Q26 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[37] PBR 20-F filed 2026-04-09 · gasoline competition with ethanol · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[38] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · domestic sales commentary 3Q26 · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[39] PBR 20-F filed 2026-04-09 · Business Plan 2026-30 lifting cost and TCPO · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[40] PBR earnings call 2026-08-07 (2Q26 results) · segment performance: E&P ramp-up and refining · 2026-08-07 · earnings-call · https://gateway.drillr.ai/mcp/private

[41] PBR 6-K filed 2026-08-07 (2Q26 results webcast presentation) · own oil production by quarter and above-nameplate platforms · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004128/pbr20260806_6k1.htm

[42] PBR 6-K filed 2026-08-07 (2Q26 interim financial statements, US$) · note 13.4 export tax on crude oil and diesel · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004133/pbrfs2q26usd_6k.htm

[43] PBR 6-K filed 2026-10-29 (3Q26 production and sales report) · P-80 and P-82 sail-away, 2027 start-up · 2026-10-29 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426005030/pbr20261028_6k.htm

[44] PBR 6-K filed 2026-08-07 (2Q26 interim financial statements, US$) · note 4 sales revenues: subsidy programs · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004133/pbrfs2q26usd_6k.htm

[45] PBR 6-K filed 2026-10-14 (subsidy installments received, cumulative R$ 16 billion) · 2026-10-14 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004920/pbr20261013_6k2.htm

[46] PBR 6-K filed 2026-09-21 (adherence to diesel subsidy MP 1,391) · 2026-09-21 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004612/pbr20260921_6k1.htm

[47] PBR 6-K filed 2026-06-02 (adherence to diesel subvention MP 1,363) · 2026-06-02 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426003269/pbr20260602_6k.htm

[48] PBR earnings call 2026-05-12 (1Q26 results) · domestic pricing and subsidies Q&A · 2026-05-12 · earnings-call · https://gateway.drillr.ai/mcp/private

[49] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · capex 2Q26 and cash basis · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[50] PBR 6-K filed 2026-08-07 (2Q26 financial performance report) · main E&P projects (Búzios 9-11, P-84, P-85) · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004129/pbrrmf2q26usd_6k.htm

[51] PBR 6-K filed 2026-08-07 (shareholder remuneration on 2Q26) · R$ 17.4 billion, 45% of FCF, paid Nov/Dec 2026 · 2026-08-07 · 6-K · https://www.sec.gov/Archives/edgar/data/1119639/000129281426004123/pbr20260806_6k.htm

[52] PBR earnings call 2026-08-07 (2Q26 results) · capital allocation and extraordinary dividends Q&A · 2026-08-07 · earnings-call · https://gateway.drillr.ai/mcp/private

[53] PBR earnings call 2026-08-07 (2Q26 results) · Braskem Q&A · 2026-08-07 · earnings-call · https://gateway.drillr.ai/mcp/private

[54] PBR 20-F filed 2026-04-09 · Business Plan 2026-30 price and crack-spread assumptions · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[55] PBR 20-F filed 2026-04-09 · Business Plan 2026-30 cash projections and breakeven · 2026-04-09 · 20-F · https://www.sec.gov/Archives/edgar/data/1119639/000129281426002168/pbrform20f_2025.htm

[56] PBR earnings call 2026-08-07 (2Q26 results) · risks: gas regulation, weather, opex, Brent · 2026-08-07 · earnings-call · https://gateway.drillr.ai/mcp/private