Business segment information

12 Months Ended

Dec. 31, 2025

Note 3 Business segment information

Description of the business segments

Financial information by business segment is reported in accordance with the internal reporting system and shows internal segment information that is used to manage and measure the performance of TotalEnergies and which is reviewed by the main operational decision-making body of the Company, namely the Executive Committee.

The operational profit and assets are broken down by business segment prior to the consolidation and inter-segment adjustments.

Sales prices between business segments approximate market prices.

The reporting structure for the business segments’ financial information is based on the following five business segments:

an Exploration & Production segment that encompasses the activities of exploration and production of oil and natural gas, as well as carbon storage activities, conducted in about 50 countries;

an Integrated LNG segment covering the integrated gas chain (including upstream and midstream LNG activities), biogas and synthetic methane activities, as well as gas trading;

an Integrated Power segment covering generation, storage, electricity trading and B2B-B2C distribution of gas and electricity;

a Refining & Chemicals segment constituting a major industrial hub comprising the activities of refining, petrochemicals and specialty chemicals. This segment also includes the activities of oil supply, trading and marine shipping, as well as hydrogen activities previously reported within the Integrated LNG segment;

a Marketing & Services segment including the global activities of supply and marketing in the field of petroleum products;

In addition the Corporate segment includes holdings operating and financial activities.

This segment reporting has been prepared in accordance with IFRS 8 and according to the same principles as the internal reporting followed by the TotalEnergies’s Executive Committee.

Definition of the indicators

Adjusted Net Operating Income

TotalEnergies measures performance at the segment level on the basis of adjusted net operating income. Adjusted net operating income comprises operating income of the relevant segment after deducting the amortization and the depreciation of intangible assets other than mineral interest, translation adjustments and gains or losses on the sale of assets, as well as all other income and expenses related to capital employed (dividends from nonconsolidated companies, income from equity affiliates and capitalized interest expenses) and after income taxes applicable to the above, excluding the effect of the adjustments describe below.

The income and expenses not included in net operating income adjusted that are included in net income TotalEnergies share are interest expenses related to net financial debt, after applicable income taxes (net cost of net debt), non-controlling interests, and the adjusted items.

Adjustment items include:

a) Special items

Due to their unusual nature or particular significance, certain transactions qualifying as “special items” are excluded from the business segment figures. In general, special items relate to transactions that are significant, infrequent or unusual. However, in certain instances, transactions such as restructuring costs or assets disposals, which are not considered to be representative of the normal course of business, may qualify as special items although they may have occurred in prior years or are likely to occur in following years.

b) The inventory valuation effect

In accordance with IAS 2, TotalEnergies values inventories of petroleum products in its financial statements according to the First-in, First-Out (FIFO) method and other inventories using the weighted-average cost method. Under the FIFO method, the cost of inventory is based on the historic cost of acquisition or manufacture rather than the current replacement cost. In volatile energy markets, this can have a significant distorting effect on the reported income. Accordingly, the adjusted results of the Refining & Chemicals and Marketing & Services segments are presented according to the replacement cost method. This method is used to assess the segments’ performance and facilitate the comparability of the segments’ performance with those of its main competitors.

In the replacement cost method, which approximates the Last-In, First-Out (LIFO) method, the variation of inventory values in the statement of income is, depending on the nature of the inventory, determined using either the month-end prices differential between one period and another or the average prices of the period rather than the historical value. The inventory valuation effect is the difference between the results under the FIFO and the replacement cost methods.

c) Effect of changes in fair value

The effect of changes in fair value presented as an adjustment item reflects for trading inventories and storage contracts, differences between internal measures of performance used by TotalEnergies’ Executive Committee and the accounting for these transactions under IFRS.

IFRS requires that trading inventories be recorded at their fair value using period end spot prices. In order to best reflect the management of economic exposure through derivative transactions, internal indicators used to measure performance include valuations of trading inventories based on forward prices.

TotalEnergies, in its trading activities, enters into storage contracts, whose future effects are recorded at fair value in TotalEnergies’ internal economic performance. IFRS precludes recognition of this fair value effect.

Furthermore, TotalEnergies enters into derivative instruments to risk manage certain operational contracts or assets. Under IFRS, these derivatives are recorded at fair value while the underlying operational transactions are recorded as they occur. Internal indicators defer the fair value on derivatives to match with the transaction occurrence.

A) Information by business segment


		Exploration						Refining		Marketing
For the year ended December 31, 2025		&		Integrated		Integrated		&		&
(M$)		Production		LNG		Power		Chemicals		Services		Corporate		Intercompany		Total
External sales		5,590		10,096		19,587		87,207		78,708		8		–		201,196
Intersegment sales		35,234		8,945		2,696		27,817		734		132		(75,558)		–
Excise taxes		–		–		–		(770)		(18,082)		–		–		(18,852)
Revenues from sales		40,824		19,041		22,283		114,254		61,360		140		(75,558)		182,344
Operating expenses		(17,335)		(15,085)		(20,859)		(110,737)		(58,697)		(918)		75,558		(148,073)
Depreciation, depletion and impairment of tangible assets and mineral interests		(8,419)		(1,608)		(622)		(1,606)		(932)		(125)		–		(13,312)
Net income (loss) from equity affiliates and other items		971		2,104		422		49		93		(82)		–		3,557
Tax on net operating income		(7,677)		(720)		(133)		(352)		(608)		245		–		(9,245)
Adjustments^(a)		(35)		(377)		(1,124)		(770)		(157)		(93)		–		(2,556)
Adjusted net operating income		8,399		4,109		2,215		2,378		1,373		(647)		–		17,827
Adjustments^(a)																(2,556)
Net cost of net debt																(1,914)
Non-controlling interests																(230)
NET INCOME - TotalEnergies SHARE																13,127
^(a) Adjustments include special items, inventory valuation effect and the effect of changes in fair value.

The management of balance sheet positions (including margin calls) related to centralized markets access for LNG, gas and power activities has been fully included in the Integrated LNG segment.

Effects of changes in the fair value of gas and LNG positions are allocated to the net operating income of Integrated LNG segment.

Effects of changes in the fair value of power positions are allocated to the net operating income of Integrated Power segment.

 

Exploration

 

Refining

 

Marketing

 

For the year ended December 31, 2025

Integrated

(M$)

Production

LNG

Power

Chemicals

Services

Corporate

Intercompany

Total

Total expenditures

10,523

3,520

5,367

1,537

937

316

–

22,200

Total divestments

1,723

512

1,366

100

328

–

4,069

Cash flow from operating activities

14,949

5,173

2,374

3,459

2,835

(1,447)

–

27,343



		Exploration						Refining		Marketing
For the year ended December 31, 2024		&		Integrated		Integrated		&		&
(M$)		Production		LNG		Power		Chemicals		Services		Corporate		Intercompany		Total
External sales		5,655		9,885		22,127		93,515		83,341		27		–		214,550
Intersegment sales		38,546		10,591		2,348		31,480		819		268		(84,052)		–
Excise taxes		–		–		–		(784)		(18,156)		–		–		(18,940)
Revenues from sales		44,201		20,476		24,475		124,211		66,004		295		(84,052)		195,610
Operating expenses		(19,124)		(15,530)		(22,936)		(120,424)		(63,551)		(1,010)		84,052		(158,523)
Depreciation, depletion and impairment of tangible assets and mineral interests		(8,001)		(1,251)		(344)		(1,442)		(870)		(117)		–		(12,025)
Net income (loss) from equity affiliates and other items		325		2,051		(837)		(114)		1,457		92		–		2,974
Tax on net operating income		(8,466)		(1,073)		(255)		(414)		(526)		89		–		(10,645)
Adjustments^(a)		(1,069)		(196)		(2,070)		(343)		1,154		(59)		–		(2,583)
Adjusted net operating income		10,004		4,869		2,173		2,160		1,360		(592)		–		19,974
Adjustments^(a)																(2,583)
Net cost of net debt																(1,360)
Non-controlling interests																(273)
NET INCOME - TotalEnergies SHARE																15,758
^(a) Adjustments include special items, inventory valuation effect and the effect of changes in fair value.

The management of balance sheet positions (including margin calls) related to centralized markets access for LNG, gas and power activities has been fully included in the Integrated LNG segment.

Effects of changes in the fair value of gas and LNG positions are allocated to the net operating income of Integrated LNG segment.

Effects of changes in the fair value of power positions are allocated to the net operating income of Integrated Power segment.

 

Exploration

 

Refining

 

Marketing

 

For the year ended December 31, 2024

Integrated

(M$)

Production

LNG

Power

Chemicals

Services

Corporate

Intercompany

Total

Total expenditures

9,225

3,912

5,328

1,896

1,190

199

–

21,750

Total divestments

840

425

1,431

366

1,328

–

4,418

Cash flow from operating activities

17,388

5,185

2,972

3,808

2,901

(1,400)

–

30,854


		Exploration						Refining		Marketing
For the year ended December 31, 2023		&		Integrated		Integrated		&		&
(M$)		Production		LNG		Power		Chemicals		Services		Corporate		Intercompany		Total
External sales		6,561		12,086		27,337		101,203		89,909		32		–		237,128
Intersegment sales		42,595		14,789		4,126		36,581		631		206		(98,928)		–
Excise taxes		–		–		–		(841)		(17,342)		–		–		(18,183)
Revenues from sales		49,156		26,875		31,463		136,943		73,198		238		(98,928)		218,945
Operating expenses		(20,355)		(21,569)		(28,763)		(130,899)		(70,497)		(878)		98,928		(174,033)
Depreciation, depletion and impairment of tangible assets and mineral interests		(8,493)		(1,288)		(281)		(1,685)		(905)		(110)		–		(12,762)
Net income (loss) from equity affiliates and other items		(307)		2,194		(345)		(42)		2,208		(28)		–		3,680
Tax on net operating income		(10,095)		(810)		(394)		(938)		(1,246)		271		–		(13,212)
Adjustments^(a)		(1,036)		(798)		(173)		(1,275)		1,300		(84)		–		(2,066)
Adjusted net operating income		10,942		6,200		1,853		4,654		1,458		(423)		–		24,684
Adjustments^(a)																(2,066)
Net cost of net debt																(1,108)
Non-controlling interests																(126)
NET INCOME - TotalEnergies SHARE																21,384
^(a) Adjustments include special items, inventory valuation effect and the effect of changes in fair value.

The management of balance sheet positions (including margin calls) related to centralized markets access for LNG, gas and power activities has been fully included in the Integrated LNG segment.

Effects of changes in the fair value of gas and LNG positions are allocated to the net operating income of Integrated LNG segment.

Effects of changes in the fair value of power positions are allocated to the net operating income of Integrated Power segment.

 

Exploration

 

Refining

 

Marketing

 

For the year ended December 31, 2023

Integrated

(M$)

Production

LNG

Power

Chemicals

Services

Corporate

Intercompany

Total

Total expenditures

12,378

3,410

5,497

2,149

1,273

153

–

24,860

Total divestments

5,118

290

661

196

2,132

–

8,406

Cash flow from operating activities

18,531

8,442

3,573

7,957

1,957

219

–

40,679

B) Additional information on adjustment items

The main adjustment items for 2025 are the following:

An “Inventory valuation effect” amounting to $(617) million in net operating income for the Refining & Chemicals and Marketing & Services segments;

An “Effect of changes in fair value” amounting to $(665) million in net operating income for the Integrated LNG and Integrated Power segments;

“Asset impairment and provisions charges” of $(1,162) million in net operating income consisting mainly of the impairment and provision related to the adaptation project of the Antwerp platform for the Refining & Chemicals segment, of the disposal of the Gato do Mato project as part of an asset swap with Shell in Brazil for the Exploration & Production segment, and of impairment of offshore wind projects, notably in Asia (Taiwan, Korea) and Europe (United Kingdom, Germany and Denmark) for the Integrated Power segment (refer to Note 3.C “Asset impairment”);

“Gains (losses) on disposals of assets” for an amount of $487 million in net operating income generated on the sale of a 45% operated interest in two unconventional oil and gas blocks, located in the Vaca Muerta area, in Argentina, on the sale of the non‑operated interest in the West Ekofisk fields in Norway, and the sale of the non‑operated 12.5% interest in the OML118 Production Sharing Contract (PSC) in Nigeria for the Exploration & Production segment;

“Other items” amounted to $(538) million in net operating income notably related to the impacts of the Energy Profits Levy in the United Kingdom on deferred tax and to provisions for onerous midstream contracts for the Exploration & Production segment.

The detail of the adjustment items is presented in the table below.

Adjustments to net operating income

For the year ended December 31, 2025

Exploration &

Integrated

Refining &

Marketing &

(M$)

 

Production

 

LNG

 

Power

 

Chemicals

 

Services

Corporate

 

Total

Inventory valuation effect

–

(528)

(89)

–

(617)

Effect of changes in fair value

–

(246)

(419)

–

(665)

Restructuring charges

(49)

–

(12)

–

(61)

Asset impairment and provisions charges

(200)

(50)

(662)

(200)

(50)

–

(1,162)

Gains (losses) on disposals of assets

563

(59)

(12)

–

(5)

–

487

Other items

(349)

(22)

(31)

(30)

(13)

(93)

(538)

TOTAL

(35)

(377)

(1,124)

(770)

(157)

(93)

(2,556)

Adjustments to net operating income

For the year ended December 31, 2024

Exploration &

Integrated

Refining &

Marketing &

(M$)

 

Production

 

LNG

 

Power

 

Chemicals

 

Services

Corporate

 

Total

Inventory valuation effect

–

(276)

(110)

–

(386)

Effect of changes in fair value

–

(84)

(864)

–

(948)

Restructuring charges

–

(11)

(6)

(10)

–

(27)

Asset impairment and provisions charges^(a)

(982)

(10)

(965)

(4)

(17)

–

(1,978)

Gains (losses) on disposals of assets^(b)

–

(11)

1,300

–

1,372

Other items^(c)

(141)

(102)

(259)

(46)

(9)

(59)

(616)

TOTAL

(1,069)

(196)

(2,070)

(343)

1,154

(59)

(2,583)

(a)	Refer to Note 3.C “Asset impairment”

(b)	Refer to Note 6.1 “Other income and other expense”

(c)	"Other items" include $(0.6) billion in net operating income mainly consisting of the impacts of the contribution on inframarginal annuity in France and deferred tax adjustments related to rates changes.

Adjustments to net operating income

For the year ended December 31, 2023

Exploration &

Integrated

Refining &

Marketing &

(M$)

 

Production

 

LNG

 

Power

 

Chemicals

 

Services

Corporate

 

Total

Inventory valuation effect

–

(586)

(108)

–

(694)

Effect of changes in fair value

–

(547)

559

–

Restructuring charges

–

(5)

(51)

–

(56)

Asset impairment and provisions charges^(a)

(926)

(124)

(773)

(359)

(115)

–

(2,297)

Gains (losses) on disposals of assets^(b)

431

–

1,616

–

2,047

Other items^(c)

(541)

(127)

(279)

(93)

(84)

(1,078)

TOTAL

(1,036)

(798)

(173)

(1,275)

1,300

(84)

(2,066)

(a)	Refer to Note 3.C “Asset impairment”

(b)	Refer to Note 6.1 “Other income and other expense”

(c)	"Other items" include $0.4 billion of revaluation of the previously held share of Total Eren and $(1.5) billion mainly consisting of the impacts of the European solidarity contribution, the contribution on inframarginal annuity in France and the devaluation of the Argentine peso.

C) Asset impairment

Accounting principles

The recoverable amounts of intangible assets and property, plant and equipment are tested for impairment as soon as any indication of impairment exists. This test is performed at least annually for goodwill.

The recoverable amount is the higher of the fair value (less costs to sell) or the value in use.

Assets are grouped into cash-generating units (or CGUs) and tested. A CGU is a homogeneous set of assets that generates cash inflows that are largely independent of the cash inflows from other groups of assets.

The value in use of a CGU is determined by reference to the discounted expected future cash flows of these assets, based upon Management’s expectation of future economic and operating conditions. When this value is less than the carrying amount of the CGU, an impairment loss is recorded. This loss is allocated first to goodwill with a corresponding amount in “Other expenses”. Any further losses are then allocated to property, plant and mineral interests with a corresponding amount in “Depreciation, depletion and impairment of tangible assets and mineral interests” and to other intangible assets with a corresponding amount in “Other expenses”.

Impairment losses recognized in prior periods can be reversed up to the original carrying amount, had the impairment loss not been recognized. Impairment losses recognized on goodwill cannot be reversed.

Investments in associates or joint ventures are tested for impairment whenever indication of impairment exists. If any objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs to sell and value in use. If the carrying amount exceeds the recoverable amount, an impairment loss is recorded in “Net income (loss) from equity affiliates”.

For the financial year 2025, asset impairments were recorded for an amount of $(1,162) million in net operating income and $(1,156) million in net income, TotalEnergies share. These impairments were qualified as adjustment items of the net operating income and net income, TotalEnergies share.

Impairments relate to certain cash-generating units (CGUs) for which indicators of impairment have been identified, due to changes in operating conditions or the economic environment of the activities concerned.

Principles for determining value in use of a CGU

The principles applied in determining the recoverable amounts are as follows:

the future cash flows were determined using the assumptions included in the 2026 budget and in the long-term plan of the Company approved by the Executive Committee and the Board of Directors. These assumptions, in particular including operational costs, estimation of oil and gas reserves, future volumes produced and marketed, represent the best estimate from the Company Management of economic and technical conditions over the remaining life of the assets;

the oil and gas price scenarios have been established based on data on global energy demand from the IEA's World Energy Outlook, the latest edition of which was published in November 2025, and on its own supply and demand assessments; they take into account assumptions about the evolution of core indicators of the upstream activity (demand for hydrocarbons in different markets, investment forecasts, decline in production fields, changes in oil & gas reserves and supply by area and by nature of oil & gas products), of the downstream activity (changes in refining capacity and demand for petroleum products) and by integrating “climate” challenge;

these price scenarios, first prepared within the Strategy & Markets Division, are also reviewed with the Company segments which bring their own expertise. They also integrate studies issued by international agencies, banks and independent consultants. They are then approved by the Executive Committee and the Board of Directors;

the IEA’s World Energy Outlook 2025 presents three scenarios that are key references for the Company: the CPS (Current Policies Scenario), the STEPS (Stated Policies Scenario), and the NZE (Net Zero Emissions by 2050) long-term scenario, as well as APS scenario from the IAE’s World Energy Outlook 2024;

o

the CPS scenario only includes climate actions already implemented to date around the world;

o

the STEP scenario encompasses a broader set of measures, including those that have been officially announced but not yet adopted;

o

The NZE scenario follows a different logic: it is a normative scenario that starts from the objective (net-zero emissions by 2050, without exceeding the CO₂ budget) and then constructs the energy pathways leading to it.

o

As a reminder, the APS 2024 scenario took into account all climate ambitions declared worldwide to date, including NDCs (Nationally Determined Contributions) and carbon-neutrality targets, and was compatible with the Paris Agreement.

the IEA's NZE scenario is understood as the set of actions to be taken for the global energy sector to achieve net-zero CO₂ emissions by 2050 and to be compatible with a +1.5°C scenario by 2100. This normative scenario is therefore not predictive of oil demand, and even less so of the price scenarios it proposes, particularly in the medium term (2030). Indeed, this scenario predicts that oil demand will peak in 2024 and decrease by 33% between 2024 and 2035, whereas according to the IEA’s latest projections, oil demand in 2025 would be higher than in 2024 and continue to grow until 2029. According to projections from other energy companies or external consultants, demand is expected to remain broadly stable until 2035 (a plateau around 2027–2033 according to WoodMac);

beyond 2030, the oil price trajectory retained by the Company converges in the long term, to the price retained in 2050 by the IEA's NZE scenario, i.e $25.7₂₀₂₅/b. The prices retained for gas, the transition fuel, stabilize until 2040 at lower levels than current prices before converging towards the IEA's NZE scenario prices in 2050.

The oil price trajectories adopted by the Company are based on the following assumptions:

Oil demand experienced sustained growth post-Covid crisis, accompanying the global economic recovery, which generated strong tensions on energy prices from mid-2021, exacerbated in 2022 by the war in Ukraine. In 2023, global oil demand exceeded its pre-Covid 2019 level. This increase was stimulated by the lifting of lockdown measures in China, enabling the recovery of industrial activity, particularly in the petrochemical sector, as well as the rise in air travel. In 2025, demand continued to expand, but at a slightly slower rate, reflecting macroeconomic uncertainty and the slowdown in the petrochemical sector. By 2030, oil consumption is expected to keep growing, supported by population growth and rising living standards, particularly in emerging countries. However, this growth is expected to gradually slow down due to moderate global economic growth and the accelerated deployment in some regions of low-carbon substitute technologies. Some recent forecasts anticipate an oil-demand peak before 2030 in China, while demand for certain petroleum products, such as gasoline and diesel, may already have peaked there. However, increasing oil demand in other Asian countries, particularly India, is partly taking over.

On the supply side, after a decade marked by strong U.S. production growth (accounting for 90% of global supply increases), the decision by the OPEC+ group of producers, to begin lifting part of the oil-production restrictions in May 2025 is reshaping global oil-supply trajectories. The expected increase in OPEC+ output and the impact of higher tariffs on trade had downward impacts on oil prices.

Brent is trading between $60₂₀₂₅/b and $70₂₀₂₅/b. In 2026, demand is expected to continue rising, and production capacity should be sufficient to meet it, although downward trends on prices may begin in 2026 to weigh on U.S. production levels. In this context, the selected scenario anticipates prices back toward $70₂₀₂₅/b.

Beyond 2030, given technological developments, particularly in the transport sector, the growth in oil demand would be low before reaching a plateau, and the selected price scenario decreases linearly to reach $50₂₀₂₅/b in 2040 and then $25.7₂₀₂₅/b in 2050, in line with the NZE scenario.

The average Brent prices over the period 2026-2050 thus stands at $51.8₂₀₂₅/b.

For natural gas, the transition fuel, the price trajectory adopted by the Company is based on the following assumptions:

Following the 2022/23 supply shock, natural gas markets underwent a gradual rebalancing in 2024 and 2025. During this period, the supply–demand balance remained tight and prices stayed well above their historical levels. This limited demand growth, particularly in Asian markets that are more price-sensitive. Global gas demand returned to structural growth in 2024, mainly in Europe and North America, and continued to grow in 2025, albeit at a slower pace. The Company anticipates that in 2026 prices will remain higher than pre-crisis levels in Asian and European hubs. Thereafter, natural gas demand is expected to be driven by the same fundamentals as oil: rising demand in the Asia-Pacific region and declining overall natural gas demand in Europe, although LNG demand should grow in Europe due to declining domestic production and ban on Russian gas imports from 2027. Natural gas demand should also be supported by its substitution for coal in power generation and by its role as a flexible, dispatchable source capable of offsetting the intermittency and seasonality of renewable energies. The abundant global gas supply and the upcoming wave of increased liquefied natural gas capacity (expected between 2027 and 2030) are likely to limit the potential for higher gas prices. Beyond 2040, with the rise of renewable energies including battery storage, gas demand is expected to stabilize.

Natural gas prices are thus expected to fall from $3.4₂₀₂₅/Mbtu in 2026 to $3.0₂₀₂₅/Mbtu in 2027 in the United States, and then stabilize at these levels until 2040, supported by domestic demand driven by electricity generation, particularly for data centers, and by the growing volumes of LNG exports.

In Europe and Asia, due to the rapid increase in LNG offer, prices should generally adjust downward until 2029/2030 in order to stimulate price-elastic demand, particularly in some Asian countries such as India. However, the partly inelastic nature of domestic U.S. natural gas and electricity demand (gas-to-power) may act as a brake on the decline in feedgas prices for LNG terminals, limiting the reduction in LNG prices in Europe in particular, despite rising volumes. As seen in previous market cycles, the continued growth of LNG demand in Europe and Asia should allow the market to rebalance around 2030. Thus, prices in Europe and Asia could fall from $9.7₂₀₂₅/ Mbtu and $10.7₂₀₂₅/Mbtu in 2026 to $6.5₂₀₂₅/Mbtu and $7.5₂₀₂₅/ Mbtu respectively in 2029/2030, before rising again to $8.0₂₀₂₅/Mbtu and $9.0₂₀₂₅/ Mbtu and stabilizing at these levels until 2040.

Natural gas prices would then converge in 2050 toward the IEA’s NZE scenario levels: $2.3₂₀₂₅/ Mbtu in the United States, $4.1₂₀₂₅/Mbtu in Europe, and $5.0₂₀₂₅/Mbtu in Asia, respectively.

The future operational costs were determined by taking into account the existing technologies, the fluctuation of prices for petroleum services in line with market developments and the internal cost reduction programs effectively implemented.

The determination of value in use also takes into account on all identified assets the impact of their CO₂ emissions. Future scope 1 and 2 emissions of the assets concerned over the life of the assets are valued at $100/t or the applicable price in a given country, if it is higher, incorporating the existing free emission rights scheme in Europe. Beyond 2031, the CO₂ price is inflated by 2% per year.

The future cash flows are estimated over a period consistent with the life of the assets of the CGUs. They are prepared post-tax and take into account specific risks related to the CGUs' assets. They are discounted using an 7% post-tax discount rate, this rate being the weighted-average cost of TotalEnergies capital estimated from historical market data. This rate was 7% in 2024 and 8% in 2023. The value in use calculated by discounting the above post-tax cash flows using an 7% post-tax discount rate is not materially different from the value in use calculated by discounting pre-tax cash flows using a pre-tax discount rate determined by an iterative computation from the post-tax value in use. These pre-tax discount rates generally range from 7% to 14%.

Impairment losses recognized by segment

The CGUs of the Exploration & Production segment are defined as oil and gas fields or groups of oil and gas fields with industrial assets enabling the production, treatment and evacuation of the oil and gas. For the financial year 2025, the Company recorded impairments of assets over CGUs of the Exploration & Production segment for $(200) million in net income, TotalEnergies share.

Impairments recognized in 2025 are mainly related to the disposal of the Gato do Mato project as part of an asset swap with Shell in Brazil.

As for sensitivities of the Exploration & Production segment:

A 1-percentage‑point decrease in the discount rate would have no impact on TotalEnergies’ net income;

An increase of 1 percentage point in the discount rate would have an additional negative impact of $0.5 billion on TotalEnergies’ net income;

A 10% decrease in hydrocarbon prices over the entire duration of the plan (resulting in an average oil price of around $47₂₀₂₅/b) would have an additional negative impact of $0.6 billion on TotalEnergies’ net income;

A 20% decrease in hydrocarbon prices over the entire duration of the plan (resulting in an average oil price of around $41₂₀₂₅/b) would have an additional negative impact of $2.6 billion on TotalEnergies’ net income;

taking into account a CO₂ cost applied to future Scope 1 and 2 emissions of $200/t, inflated by 2%/year beyond 2031 for all assets would have an additional negative impact of $0.2 billion on net income, TotalEnergies share.

The CGUs of the Integrated LNG segment are subsidiaries or groups of subsidiaries organized by activity or geographical area, and by fields or groups of fields for upstream LNG activities. For the financial year 2025, the Company recorded impairments on CGUs in the Integrated LNG segment for $(50) million in net income, TotalEnergies share.

As for sensitivities of the Integrated LNG:

a decrease by 1 point in the discount rate would have no impact in net income, TotalEnergies share;

an increase by 1 point in the discount rate would have an additional negative impact of $0.6 billion in net income, TotalEnergies share;

a decrease of 10% of the oil and gas prices over the duration of the plan would have an additional negative impact of $2.0 billion in net income, TotalEnergies share;

a decrease of 20% of the oil and gas prices over the duration of the plan would have an additional negative impact of $6.6 billion in net income, TotalEnergies share;

taking into account a CO₂ cost applied to future scope 1 and 2 emissions of $200/t inflated by 2%/year beyond 2031 for all assets would have an additional negative impact of approximately $0.8 billion in net income, TotalEnergies share.

The CGUs of the Integrated Power segment are subsidiaries or groups of subsidiaries organized by activity or geographical area. For the financial year 2025, the Company recorded impairments on CGUs in the Integrated Power segment for $(656) million in net income, TotalEnergies share. Impairments recognized mainly relate to offshore wind projects, notably in Asia (Taiwan, Korea) and in Europe (United Kingdom, Germany and Denmark).

As for sensitivities of the Integrated Power:

a decrease by 1 point in the discount rate would have no impact in net income, TotalEnergies share.

an increase by 1 point in the discount rate would have an additional negative impact of $0.3 billion in net income, TotalEnergies share.

In the event of an increase in the CO₂ price, the value of Integrated Power assets would increase as a result of higher electricity prices.

The CGUs of the Refining & Chemicals segment are subsidiaries or groups of subsidiaries organized by activity (grouping together the operational activities of refining and petrochemicals) and by relevant geographical area. Future cash flows are based on the gross contribution margin (calculated on the basis of net sales after purchases of crude oil and refined products, the effect of inventory valuation and variable costs). The other activities of the segment are global divisions, each division gathering a set of businesses or homogeneous products for strategic, commercial and industrial plans. Future cash flows are determined from the specific margins of these activities, unrelated to the price of oil.

For the financial year 2025, the Company has recorded impairments on CGUs in the Refining & Chemicals segment for an amount of $(200) million in net income TotalEnergies share.

The impairments recognized in 2025 are mainly related to the Antwerp NC2 steam cracker shutdown project.

As for sensitivities of the Refining & Chemicals segment:

an increase by 1 point in the discount rate would not have any additional negative impact in the net income, TotalEnergies share.

a decrease of 10% of the refining margins (could be in link with the increase of CO₂ cost) would have an additional negative impact of $0.8 billion in net income, TotalEnergies share.

The CGUs of the Marketing & Services segment are subsidiaries or groups of subsidiaries organized by relevant geographical area.

For the financial year 2025, the Company recorded impairments on the CGUs of the Marketing & Services segment for $(50) million in net income, TotalEnergies share.

Impairments recognized in years 2024 and 2023

For the financial year 2024, asset impairments were recognized in the Exploration & Production, Integrated LNG, Integrated Power, Refining & Chemicals, and Marketing & Services segments, with a negative impact of $(1,977) million in net income, TotalEnergies share.

Impairments recognized on CGUs in the Exploration & Production segment amounted to $(982) million in net income, TotalEnergies share, and were mainly related to the exit from blocks 11B/12B and 5/6/7 in South Africa.

Those recognized on CGUs in the Integrated Power segment totaled $(965) million in net income, TotalEnergies share, and mainly concerned the Company’s minority interests in SunPower and Maxeon.

These impairments were classified as adjustment items to the net income, TotalEnergies share.

For the financial year 2023, the Company recorded impairments in the Exploration & Production, Integrated LNG, Integrated Power, Refining & Chemicals, and Marketing & Services segments with an impact of $(2,166) million in net income, TotalEnergies share.

Impairments recorded on the CGUs of the Exploration & Production segment amounted to $(881) million in net income, TotalEnergies share, mainly related to the Company's upstream assets in Kenya and Congo, and also Al Shaheen in Qatar related to temporary tax effects.

Those recorded on the CGUs of the Integrated Power segment amounted to $(773) million in net income, TotalEnergies share, mainly concerning the Yunlin offshore wind project in Taiwan and the goodwill and customer portfolios of gas-electricity marketing activities in Belgium, Spain and France.

Impairments recorded on the CGUs of the Refining & Chemicals segment amounted to $(273) million in net income, TotalEnergies share, mainly related to the divestment projects of Naphtachimie to INEOS and the Natref refinery in South Africa.

Finally, the impairments recorded on the CGUs of the Integrated LNG segment amounted to $(124) million in net income, TotalEnergies share, and those recorded on the CGUs of the Marketing & Services segment amounted to $(115) million in net income, TotalEnergies share.

These impairments were qualified as adjustments items of the net income, TotalEnergies share.