TotalEnergies SE (TTE) FY2025 20-F and Q2 FY2026 6-K Summary

Business

From the FY2025 Form 20-F, accession 0001104659-26-035876, and its Exhibit 15.1.

TotalEnergies is a global integrated energy company. It produces and sells oil and biofuels, natural gas and liquefied natural gas (LNG), biogas and low-carbon hydrogen, and electricity from renewable and gas-fired plants. Its customers range from LNG and power buyers to industrial clients and motorists at its service stations, across about 120 countries. Most of its earnings still come from producing and selling hydrocarbons. In 2025 its business segments earned $18,474 million of adjusted net operating income. Exploration & Production contributed $8,399 million and Integrated LNG $4,109 million. The rest came from Refining & Chemicals ($2,378 million), Integrated Power ($2,215 million) and Marketing & Services ($1,373 million). Group sales were $201,196 million.

TotalEnergies SE is a French Société Européenne headquartered at La Défense (Courbevoie), near Paris. Its shares trade on Euronext Paris and, as ordinary shares rather than ADRs, on the New York Stock Exchange under TTE. At the end of 2025 it had 101,513 employees, produced 2,529 thousand barrels of oil equivalent per day (kboe/d), and held 11.2 billion boe of proved reserves, more than 12 years of production. The company calls its strategy a "two-pillar" model: hydrocarbons, with a growing weight of LNG, and electricity. It aims to grow both while lowering the emissions of its own operations.

It reports five operating segments, plus a Corporate segment for holding and financing activities:

• Exploration & Production (E&P) explores for and produces oil and natural gas in about 50 countries, and runs the company's carbon-storage activities. It produced 1,990 kboe/d in 2025. Production costs were $5.0/boe, and the company aims to keep them below $5/boe. New projects are tested against a $50/b oil price and a $100/t CO2 price.
• Integrated LNG covers the integrated gas chain: upstream gas feeding liquefaction plants, midstream LNG, biogas, and gas and LNG trading. From January 1, 2026 it also includes LNG bunkering. It produced 539 kboe/d for LNG in 2025 and sold 43.9 Mt of LNG. TotalEnergies describes itself as the world's third-largest LNG player, with a 44 Mt portfolio and about 10% of the global market. It also calls itself the leading LNG importer into Europe and the largest exporter of US LNG, at more than 19 Mt in 2025. It expects LNG sales to reach about 60 Mt by 2030.
• Integrated Power generates electricity from solar, wind, gas-fired flexible plants and storage, trades power, and sells gas and electricity to business and household customers. Net power production was 48.1 TWh in 2025, up 17%. Gross installed renewable capacity was 34.1 GW at year-end, and the segment served about 6.0 million power clients and 2.7 million gas clients. The target is 100-120 TWh of net production by 2030.
• Refining & Chemicals covers refining, petrochemicals and specialty chemicals, together with oil supply, trading and shipping, and hydrogen. Refining capacity was about 1.8 Mb/d at year-end 2025, and throughput averaged 1,526 kb/d.
• Marketing & Services supplies and markets fuels, lubricants and mobility services, including EV charging and biofuels such as sustainable aviation fuel. It has nearly 13,000 branded service stations and about 90,000 charging points. It calls its retail network the largest in France and in Africa. Sales were 1,276 kb/d in 2025.

Russia. TotalEnergies operates no field or LNG plant in Russia. It holds 20.02% of Yamal LNG, an equity-accounted stake carried at $5,835 million at the end of 2025. Its share of production there was 111 kboe/d in 2025. It still owns 19.4% of Novatek, but has not equity-accounted that stake since the fourth quarter of 2022. Its other Russian assets were fully impaired in 2022.

India. Its holdings in Adani Group companies include 17.25% of Adani Green Energy and 37.4% of Adani Total Gas. Together they represented $3.6 billion of capital employed (2.5% of the group total) at the end of 2025, and $398 million of 2025 net operating income.

Risk factors

From Exhibit 15.1 (point 3.1) and Item 5 of the FY2025 Form 20-F, accession 0001104659-26-035876.

The risks the company considers most significant, in condensed form:

• Commodity prices and margins. Results move with oil and gas prices, refining margins and the dollar. The company's 2026 sensitivities are:
  • a $10/b change in average liquids prices moves adjusted net operating income by about $2.3 billion and cash flow from operations excluding working capital (CFFO) by about $2.8 billion;
  • a $2/MBtu change in the European gas price (TTF) moves both by about $0.4 billion;
  • a $1/b change in the European refining margin marker (ERM) moves them by about $0.3 billion and $0.4 billion respectively;
  • a $0.10/€ move in the exchange rate shifts adjusted net operating income by about $0.1 billion.

Floating-rate debt averaged about $15.9 billion in 2025, so a 1-point move in rates changes adjusted net income by about $0.1 billion. A long stretch of low prices could force project deferrals, reserve write-downs and asset impairments.

• Geopolitical and operating-country risk. In 2025, 34% of oil and gas production came from the Middle East and North Africa, 17% from sub-Saharan Africa (notably Nigeria) and 13% from South America, all regions with political or security instability. In Mozambique, Mozambique LNG was under force majeure from 2021; this was lifted at the end of 2025. Yemen LNG (39.62%) has been shut since 2015. The company also flags protectionism, and sanctions regimes that could restrict financing or technology access. A breach of US sanctions could bring measures such as a ban on using the US dollar, the currency of most of its financing.
• Middle East conflict (since February 28, 2026). The 20-F states that production shut in Qatar, Iraq and offshore UAE represented about 15% of total oil and gas production. Because Middle Eastern barrels carry higher taxes, that 15% of volume represents about 10% of upstream cash flow. The company estimates that an $8/b rise in Brent offsets the expected 2026 cash-flow loss from these assets at $60/b. It put the hit to its LNG trading volumes at about 1.5 Mt for the rest of 2026.
• Russia. Further sanctions could impair the remaining Yamal LNG investment.
• Energy transition, demand and regulation. If the energy transition moves faster than expected, demand for its products could fall, and new climate or fiscal rules could raise costs or strand assets. Governments where it operates can renegotiate contracts, raise taxes and royalties, or expropriate assets. Climate litigation, including French duty-of-vigilance suits, could seek to block new oil and gas projects or force faster production cuts.
• Reserves, impairments and carbon cost. Profitability depends on replacing reserves at low cost. Under the IEA Net Zero (NZE) price scenario, the present value of the company's upstream and downstream assets would be about 10% lower than in its reference case. A CO2 price of $200/t instead of its $100/t base case would cut the discounted value of all its assets by about 15%.
• Access to capital. Investor and lender policies that exclude fossil fuels could make financing scarcer or more expensive.
• Physical climate risk. Water scarcity, rising seas and extreme weather could damage facilities and disrupt operations.
• Major accidents. At year-end 2025 the company had identified 175 sites and operating zones more exposed to major industrial accidents. Its third-party liability insurance may not cover the full cost of a major event.
• Project delivery and acquisitions. Growth depends on delivering large, capital-intensive projects on time and on budget. Acquisitions totalled $3.9 billion in 2025 and carry integration and hidden-liability risk.
• Partners and supply chain. Almost all upstream projects run through partnerships, some with partners exposed to financial-market or legal risk; the company names Clearway Energy and the Adani Group. US authorities' November 2024 indictment of certain Adani Group executives did not target Adani Green Energy itself. Even so, TotalEnergies will make no new financial contributions to Adani entities until the matter is clarified. Its supply chain spans more than 100,000 suppliers in more than 150 countries.
• Cybersecurity. Several million attacks were blocked in 2025, and ransomware attacks through suppliers are singled out as a leading threat.
• People and technology. The company may struggle to keep the skills its transition requires, or to adapt quickly enough to digital change and artificial intelligence.

Management's discussion of fiscal 2025

From Item 5 of the FY2025 Form 20-F, accession 0001104659-26-035876.

Lower oil prices drove 2025 results down. Brent averaged $69.1/b, down 14% from $80.8/b, and the company's average liquids realization fell 14% to $66.2/b. Its gas realization rose 3% to $5.72/MBtu and its LNG price fell 7% to $9.14/MBtu. Production growth softened the blow. Output rose nearly 4% to 2,529 kboe/d, helped by start-ups and ramp-ups at Mero-2, -3 and -4 (Brazil), Anchor and Ballymore (US), Fenix (Argentina) and Tyra (Denmark), net of a 3% natural decline. Management says this accretive growth offset $5/b of the $11/b price decline.

Against 2024:

• net income (TotalEnergies share) fell 17% to $13,127 million;
• adjusted net income fell 15% to $15,587 million;
• fully diluted EPS was $5.78, against $6.69;
• cash flow from operating activities fell 11% to $27,343 million;
• CFFO fell 7% to $27,839 million;
• return on average capital employed (ROACE) was 12.6%, against 14.8%.

By segment:

• E&P: adjusted net operating income fell 16% to $8,399 million, and CFFO fell 8% to $15,646 million.
• Integrated LNG: adjusted net operating income fell 16% to $4,109 million. Production and sales grew about 10%, but lower average LNG prices and low market volatility limited trading gains.
• Integrated Power: adjusted net operating income was $2,215 million, up 2%. CFFO was flat at $2,558 million, in line with guidance; production activities generated 55% of it and marketing and trading 45%.
• Refining & Chemicals: adjusted net operating income rose 10% to $2,378 million. Higher refining margins (ERM $7.1/b versus $5.3/b) outweighed weaker petrochemical margins, and refinery utilization improved to 86% from 83%.
• Marketing & Services: adjusted net operating income was stable at $1,373 million. Unit margins rose while volumes fell 5% as the company dropped low-margin sales.

Investment and portfolio. Net investments were $17,091 million, including organic investments of $16,812 million. Acquisitions totalled $3,923 million, mainly interests in 12 offshore blocks in Malaysia, the completion of the VSB acquisition, renewable projects in Canada, the Dominican Republic and Uganda, and a further 10% of the Moho field in the Republic of the Congo. Divestments brought in $3,644 million. They included the non-operated stake in the Bonga field in Nigeria, part of Block SK408 in Malaysia, 50% stakes in renewable portfolios in the US, Greece, Portugal and France, a 1.7% stake in Adani Green Energy, and the fuel distribution business in Brazil.

The company also struck three agreements during 2025:

• to merge its UK North Sea assets with NEO NEXT;
• to acquire a 40% operated interest in the PEL83 licence offshore Namibia (Mopane discovery) from Galp;
• to acquire 50% of a portfolio of EPH's flexible power plants in Europe with more than 14 GW of gross capacity.

Balance sheet and shareholder returns. At year-end 2025:

• cash and cash equivalents were $26,202 million;
• non-current financial debt was $48,995 million, up from $43,533 million;
• shareholders' equity was $117,523 million;
• gearing, the company's net-debt-to-capital ratio excluding leases, was 14.7%, against 8.3% a year earlier.

Over the year the company bought back 122.6 million shares, 5.56% of its capital; the annual report puts 2025 buybacks at $7.5 billion. It cancelled 202.2 million treasury shares, leaving 2,206,585,543 shares outstanding. The 2025 dividend was set at €3.40 per share ($3.97 at the May 29, 2026 rate), up 5.6% in euro terms.

2026 outlook (as given in March 2026). Management targeted:

• 5% growth in total energy production;
• 3% growth in oil and gas output, from start-ups including Lapa (Brazil), Ratawi (Iraq), North Field East (Qatar), TFT II & South (Algeria) and Tilenga (Uganda);
• about 25% growth in electricity output, to more than 60 TWh, helped by the EPH deal;
• LNG sales above 44 Mt, with Costa Azul (Mexico) and North Field East starting up;
• net investments of about $15 billion, of which about $3 billion in low-carbon energies;
• Integrated Power cash flow above $3 billion;
• a cash-savings plan raised to $12.5 billion over 2026-2030;
• gearing around 15% at end-2026;
• cash flow above $26 billion, assuming $60/b Brent, $10/MBtu TTF and a $5/b ERM;
• share buybacks of $3-6 billion for an oil price of $60-70/b, with $750 million authorized for the first quarter.

Current quarter: second quarter of 2026

From the second-quarter and first-half 2026 results, Form 6-K accession 0001104659-26-086078 (Exhibits 99.1-99.3); the Masdar agreement is from Form 6-K accession 0001104659-26-054533, Exhibit 99.1.

The Middle East conflict dominated the quarter, cutting volumes while lifting prices. Brent averaged $103.8/b, up 28% on the first quarter and up from $67.9/b a year earlier. Liquids realizations rose to $91.6/b, LNG to $10.20/MBtu, and the European refining margin to $13.5/b, against $4.7/b a year earlier.

Hydrocarbon production fell 4% year on year to 2,395 kboe/d. The conflict cut output by an average of 210 kboe/d, an 8-point drag. The other drivers were:

• +4% from start-ups and ramp-ups at Mero-3, Mero-4 and Lapa SW (Brazil), Anchor and Ballymore (US), Begonia and Clov Phase 3 (Angola) and Mabruk (Libya);
• +3% from better plant availability;
• −1% from pricing effects;
• −2% from natural decline.

Excluding the conflict, production grew more than 4%.

Group results for the quarter:

• Net income (TotalEnergies share) was $5,438 million, against $5,810 million in the first quarter and $2,687 million a year earlier.
• Adjusted net income rose 12% on the quarter to $6,027 million, against $3,578 million a year earlier. Adjusting items of about $(0.6) billion were mainly inventory and fair-value effects and restructuring charges.
• Fully diluted EPS was $2.41, against $1.17 a year earlier.
• Sales were $61,771 million.
• Cash flow: operating cash flow was $10,858 million and CFFO $9,804 million, up 14% on the quarter. The gap between the two reflects a $1.2 billion decrease in working capital, mainly because hydrocarbon prices fell at quarter-end, particularly on inventories.

For the first half:

• net income rose 72% to $11,248 million;
• adjusted net income rose 47% to $11,421 million;
• CFFO rose 35% to $18,380 million.

Segments in the quarter:

• E&P: adjusted net operating income rose 25% on the quarter to $3,231 million. The average liquids selling price rose $17.9/b, less than Brent's $22.7/b rise, because more cargoes were lifted late in the quarter as the market weakened. The result was also affected by the accounting for production not yet lifted. Segment production was 1,845 kboe/d, down 5% on the first quarter.
• Integrated LNG: adjusted net operating income fell 39% on the quarter to $807 million, because gas trading underperformed in a flat-to-bearish European market. LNG production fell 9% on the quarter as Qatari volumes were shut in, and LNG sales were 10.7 Mt.
• Integrated Power: adjusted net operating income was $533 million, in line with the first quarter. CFFO rose to $721 million as the EPH assets began contributing. Net power output rose 28% year on year to 14.8 TWh, and gross installed renewable capacity reached 37.4 GW.
• Refining & Chemicals: adjusted net operating income was $1,800 million, against $389 million a year earlier and up 13% on the quarter. The segment captured higher refining and petrochemical margins, while oil trading results matched the strong first quarter. Throughput fell 12% on the quarter to 1,426 kb/d and utilization was 80%. Part of the fall was a deliberate choice to maximize distillates given their higher margins, and three events also weighed:
  • a planned shutdown at Donges (France);
  • an early-April incident at the SATORP refinery in Saudi Arabia (37.5%), which has run at 70% of capacity since early May;
  • a June storm-related shutdown at Port Arthur (US).
• Marketing & Services: adjusted net operating income was $500 million, up 21% year on year on higher unit margins. Volumes fell 8% after the sale of the Burkina Faso retail network and weaker demand at higher prices.

Portfolio moves in the half. On March 30, 2026 the company completed the merger of its UK upstream business with NEO NEXT. The resulting NEO NEXT+ is jointly controlled: TotalEnergies holds 47.5%, HitechVision 28.875% and Repsol UK 23.625%. On April 29 it completed the purchase of 50% of EPH's Western European flexible-generation platform, now the TTEP joint venture. TTEP has 14 GW of gas, biomass and battery capacity installed or under construction in Italy, the UK, Ireland, the Netherlands and France. TotalEnergies paid for it with 95.4 million new shares, about 4.2% of its capital, issued for €5,147.5 million ($6.02 billion at the April 29, 2026 rate). Both stakes are equity-accounted. On April 2 the company also signed a binding agreement with Masdar to form a $2.2 billion 50/50 joint venture merging the two companies' onshore renewable activities in nine Asian countries, with 3 GW in operation and 6 GW in advanced development. Closing is subject to regulatory approvals and conditions.

Second-quarter divestments brought in $1,388 million, mainly:

• the non-operated interest in the Marjoram gas field in Malaysia;
• farm-downs of German battery-storage projects;
• non-core sales in gas, renewables and power, and in Marketing & Services.

In January the company signed a new agreement to sell its 10% interest in Nigeria's Renaissance JV to Vaaris, and those assets are held for sale. First-half adjustment items included $1,148 million of impairments and provisions. These relate mainly to agreements with US federal authorities on offshore wind leases and to a strategic review of renewables outside key markets.

Financing and capital returns. In January 2026 the company issued $3.5 billion of US senior bonds in three tranches:

• $1,500 million at 4.248%, due 2031;
• $1,250 million at 4.569%, due 2033;
• $750 million at 4.857%, due 2036.

In February it issued €1,500 million of 3.79% perpetual subordinated notes ($1.77 billion at the February 26, 2026 rate). It also redeemed a 2.50% euro bond that matured in March 2026.

At June 30, 2026:

• non-current financial debt was $49,525 million and current financial debt $13,538 million;
• shareholders' equity was $128,408 million;
• gearing was 13.1%, down from 15.5% at March 31.

Over the twelve months to June 30, ROACE was 13.9% and return on equity 15.9%. The company bought back 16.9 million shares for $1.5 billion in the quarter, and $2.25 billion in the first half. Issued capital stood at 2,281,656,714 shares, of which 57,468,046 were held in treasury. On April 28 the board set the first 2026 interim dividend at €0.90 per share, paid in October 2026.

Legal. On June 25, 2026 the Paris Judicial Court ruled on the duty-of-vigilance climate case. It rejected claims seeking to bar new oil and gas projects or force production cuts. It did, however, order TotalEnergies to add customers' (Scope 3) emissions to its vigilance plan within six months, and the company is appealing. A related Belgian suit is stayed pending the Paris ruling. Kazakhstan's 2024 arbitration claim over the North Caspian production-sharing contract remains unresolved. The company says it cannot yet assess the possible financial consequences.

Outlook (as of July 23, 2026):

• Oil was trading above $80/b early in the third quarter, in volatile markets tied to security in the Strait of Hormuz.
• Refining margins were at historically high levels.
• European gas forwards were around $16-20/MBtu, and the company expects an average LNG price above $11.5/MBtu in the third quarter.
• Excluding the Middle East, third-quarter production should grow in line with the 3% annual guidance.
• The conflict's drag is now estimated at 5-10% of total production as regional output restarts, but lifting still depends on exports through the Strait of Hormuz.
• Refinery utilization is expected at 80-85%, with SATORP back to nominal capacity at the end of the third quarter.
• Net investment guidance of $15 billion for 2026 is confirmed.

The company identified no impairment indicators from the conflict at June 30. Apart from SATORP, it reported no damage to its assets.

Subsequent events

From note 8 and Exhibit 99.2 of Form 6-K accession 0001104659-26-086078, and Form 6-K press releases in accessions 0001104659-26-089374, 0001104659-26-104017 and 0001104659-26-112504; the terms of the Galp agreement are from Form 6-K accession 0001104659-26-013065.

The interim financial statements report no post-balance-sheet events with a material impact on them. Developments after June 30, 2026:

• Marjoram divestment. On July 2 TotalEnergies announced the divestment of its 85% interest in Block 2E offshore Malaysia (a net 8.5% of the Marjoram gas field) to INPEX for $350 million; the second-quarter results already record the disposal among the quarter's $1,388 million of divestments.
• Distributed solar exit (July 9). It completed the sale of all its distributed solar assets, about 170 MW of mainly rooftop installations in seven European countries, to Amarenco and AMPYR Distributed Energy. No price was disclosed.
• Second 2026 interim dividend (July 22). The board declared €0.90 per share ($1.03 at the July 22, 2026 rate), payable in January 2027. That matches the first 2026 interim and is 5.9% above each 2025 payment in euro terms.
• Shell renewables acquisition and KKR sale (announced August 3). TotalEnergies agreed to buy Shell's entire onshore renewables business in Europe. It comprises 500 MW in operation or under construction, mainly in Italy and the Netherlands, and a 3.5 GW pipeline in Italy, the UK and Spain. No price was disclosed, and closing is expected by end-2026 subject to approvals. Separately, it agreed to sell a 50% stake in a 1.2 GW solar and wind portfolio in Germany, Spain, France and Poland to an insurance account managed by KKR. The portfolio's enterprise value is €1.8 billion ($2.07 billion at the August 3, 2026 rate), and closing is expected in 2026.
• Arctic LNG 2 exit (August 27). TotalEnergies completed the transfer of its 10% interest to NordLine, a Novatek subsidiary. It keeps the right to be repaid about $1.3 billion of shareholder loans, subject to sanctions.
• Namibia PEL83 entry completed (September 3). TotalEnergies completed the transaction agreed with Galp in December 2025 and became operator of the PEL83 licence offshore Namibia, which holds the Mopane discovery, with a 40% operated interest acquired from Galp. No cash price was given. In exchange, Galp acquired a 10% interest in PEL56, which holds the Venus discovery, and a 9.39% interest in PEL91. Under the December 9, 2025 agreement, TotalEnergies also carries 50% of Galp's capital expenditure for the exploration and appraisal of Mopane and the first development on PEL83, to be repaid from 50% of Galp's future cash flows from the project.
• Grandpuits plastics recycling plant (September 11). As part of a restructuring of Plastic Energy's shareholding, TotalEnergies agreed to acquire Plastic Energy's 35% interest in the Grandpuits advanced plastics recycling plant from Plastic Energy's new shareholder, which the release does not name. TotalEnergies already held the other 65%, and the plant is now wholly owned by it. No price was disclosed.
• GIP infrastructure deal (September 18). TotalEnergies signed a partnership with Global Infrastructure Partners (part of BlackRock) covering some African oil and gas infrastructure. GIP contributes $1.8 billion of capital, and TotalEnergies pays it a throughput-based tariff for up to 15 years.
• New gas projects. The company took four final investment decisions, all for production starting between 2028 and 2030:
  • Umm Shaif Gas Cap in Abu Dhabi (20%, July 21), targeting more than 600 million cubic feet per day by 2030;
  • Cronos offshore Cyprus (50%, with Eni as operator, July 28), with production from 2028 to be liquefied in Egypt;
  • Ima in Nigeria (40%, operator, September 23), from 2028, to supply Nigeria LNG;
  • Absheron Full Field in Azerbaijan (35%, operator, September 26), raising output to 6 billion cubic metres a year from 2029.
• Strategy update (September 28). The company confirmed its 2030 targets:
  • 4% annual growth in energy production;
  • more than 3% annual oil and gas growth;
  • 100-120 TWh of electricity;
  • free cash flow growth of about $10 billion from 2025 to 2030 at a constant price deck.

It expects Integrated Power to break even on free cash flow in 2026, turn positive in 2027, and reach 12% ROACE by 2030. Net investments are planned at $14-17 billion a year over 2027-2032. The board adopted a policy of raising the dividend more than 5% a year for fiscal 2026-2030 and of returning at least 40% of cash flow to shareholders. With gearing expected below 10% by end-2026, it authorized buybacks of $2.5 billion for the fourth quarter of 2026 and $2-2.5 billion for the first quarter of 2027.