Exxon Mobil Corporation (XOM), Financial Analysis

Insights derived from analysing SEC filings. Independent analysis of Exxon Mobil Corporation common stock, not a publication of the SEC. Figures are read from the Forms 10-K for FY2022 to FY2025, the Forms 10-Q for 2022, 2024, 2025 and 2026, the Forms 8-K and their quarterly earnings exhibits, the proxy statements of 2024 and 2026, Schedules 13D and 13G, Forms 13F and Forms 3, 4, 5 and 144 on the record for central index keys 34088 and 2115436, together with the comparable filings of five peers. Accession numbers for every filing used appear in the Sources appendix. Market prices are the last trade of 3 September 2026.

ExxonMobil earned $18.7bn in the first half of 2026 against $14.8bn in the same half of 2025, on total revenues and other income of $201.2bn against $164.6bn. The Form 10-Q for the June 2026 quarter, accession 0000034088-26-000093, attributes market conditions to supply disruptions in the Middle East and global refining capacity reductions, and puts the year to date Upstream price effect at $4,200m and the Energy Products refining margin effect at $5,530m, against $1,940m and $410m from advantaged volume growth. ExxonMobil's indicative refining margin averaged $22.6 a barrel in the half against $12.6 a year earlier, and oil equivalent production of 4,554 thousand barrels daily was 37 thousand below the same half of 2025. Distributions were covered 1.03 times by cash flow after capital spending in the half, the first period above one since 2023.

The full year behind that half was earned at a realised crude price of $65.18 a barrel against $76.23 in FY2024. Return on average capital employed was 9.3% against 12.7%, distributions of $37.5bn ran $13.9bn ahead of the cash operations left after capital spending, and cash and cash equivalents fell to $10.7bn at the end of 2025 from $23.2bn a year earlier. On that return the stock trades at 10.5 times EBITDA, against 5.1 times at Shell and 6.1 at TotalEnergies for the same return on capital.

One structural change runs through the filings. On 1 July 2026 a redomiciliation merger completed and ExxonMobil Holdings Corporation, a Texas corporation with central index key 2115436, replaced Exxon Mobil Corporation, a New Jersey corporation with central index key 34088, as the listed parent on a one for one share exchange approved by 71.2% of votes cast. Filings dated on or after that day sit under the new key. Chapter 5 sets it out.

1 Revenue & Business Model

ExxonMobil sells crude oil, natural gas and petroleum and chemical products at prevailing market prices. Total revenues and other income was $201,155m in the first half of 2026, 22.2% above the same half of 2025, on oil equivalent production of 4,554 thousand barrels daily against 4,591 and Brent at $92.56 a barrel against $71.74. FY2025 sales and other operating revenue was $323,905m, down 4.5% on FY2024, and total revenues and other income $332,238m, down 5.0%. The four reportable segments billed $444,825m between them before eliminations in FY2025, 37.4% more than the consolidated line, because Upstream bills about three fifths of its sales revenue inside the company rather than to a third party.

Oil equivalent production was 4,736 thousand barrels daily in FY2025, 9.3% above FY2024 and the highest level ExxonMobil reports in over forty years, while the realised crude price on consolidated volumes fell to $65.64 a barrel from $76.57. Applying the realised prices in the 10-K to consolidated subsidiary volumes, the value of ExxonMobil's own production fell $(4,072)m in FY2025: price took $(9,091)m out and volume put $5,727m back.

Net income attributable to ExxonMobil fell 14.4% to $28,844m in FY2025 against that 4.5% fall in sales and other operating revenue; in FY2024 revenue rose 1.4% and net income fell 6.5%. Table 1.3 carries the five year series.

1.1 How ExxonMobil earns the money

Note 1 of the FY2025 10-K states that ExxonMobil generally sells crude oil, natural gas, and petroleum and chemical products under short term agreements at prevailing market prices, recognises revenue when the customer takes control, and is typically paid within 30 days. Some natural gas sells under long term agreements with periodic price adjustments. There is no subscription base, no installed base and no recurring contract to smooth a cycle. ExxonMobil employed 58 thousand regular employees at the end of 2025, against 62 thousand at the end of 2023.

Table 1.1 Revenue model by reportable segment, FY2025

Refinery throughput was 3,979 thousand barrels daily in FY2025, across what ExxonMobil describes as the largest refining footprint among international oil companies, with Chemical Products sales of 21,303 thousand metric tons and Specialty Products sales of 7,791 thousand.

1.2 Segment revenue and the intersegment elimination

Table 1.2 Segment revenue and the intersegment elimination, $m

Three points of presentation matter for anyone comparing this table with the filings. The FY2023 10-K already used the four segment structure, so no recast applies across the five years and the FY2023 and FY2025 filings carry the same 2023 figures. The FY2024 and FY2025 filings adopted ASU 2023-07 and added an explicit elimination line; the FY2023 format carries none, and it reports Corporate and Financing intersegment revenue of $227m in 2021 and $241m in 2022 that the ASU 2023-07 reconciliation leaves out of the $(155,323)m elimination for 2022. The FY2023 format also gives no segment split of other income, so the one basis available for all five years is third party plus intersegment sales revenue, which is what Table 1.2 uses; on the newer basis, segment revenues and other income was $452,209m in FY2025 against $478,091m in FY2024. Corporate and Financing third party revenue is reported directly only to 2023, so the $111m and $85m above are the residual the FY2025 reconciliation implies.

Upstream is the largest part of the elimination. It billed $62,406m inside the company in FY2025, 61.3% of its own gross sales revenue and 51.6% of the total elimination. Energy Products billed $45,866m, 15.8% of its own revenue. The filings do not describe what those internal flows consist of. Chemical Products has raised its internal share from 26.0% in FY2021 to 31.3% in FY2025.

Upstream third party revenue grew at 15.9% a year over the four years while its intersegment billing grew at 5.6%, so a rising share of Upstream output leaves the group rather than moving to another segment. Upstream's third party share of consolidated revenue rose from 7.9% in FY2021 to 12.2% in FY2025, while Energy Products held at about 76%.

1.3 What sits inside the top line

Table 1.3 Consolidated revenue and what it contains, $m

Two features of the top line are disclosed and quantified. The first is duties. Note 1 states that taxes for which ExxonMobil is not an agent for the government are reported gross, inside both sales and other operating revenue and the other taxes and duties expense line. That line was $25,167m in FY2025, 7.8% of sales revenue, and $19,205m of the segment level total fell in Energy Products outside the United States. The filing does not say how much of the line is grossed up into revenue, so the 7.8% is an upper bound on the pass through, not a measured one.

The second is trading. Revenue outside the scope of ASC 606, which ExxonMobil describes as chiefly physically settled commodity contracts accounted for as derivatives, has grown at 19.4% a year and now carries 29.9% of sales revenue against 17.2% in FY2021. Revenue from contracts with customers was $228,968m in FY2021 and $226,909m in FY2025, a compound rate of (0.2)%. The ASC 606 share of sales revenue fell from 82.8% to 70.1% across the five years.

Income from equity affiliates is the third component. It fell from $11,463m in FY2022 to $5,064m in FY2025, and $4,340m of the FY2025 figure sat in Upstream outside the United States. ExxonMobil states that after tax earnings related to its Kazakhstan interests were approximately $1.1bn in 2025 on a combined share of oil and gas production of about 320 thousand oil equivalent barrels daily. It is equity accounted earnings rather than sales, so it flows to the top line with no matching cost.

1.4 Price against volume

Table 1.4 Volumes, realised prices and revenue per unit

Realised prices are ExxonMobil's own figures, calculated using sales quantities from its own production. Revenue per unit is derived from Table 1.2 and the volume rows above, and it runs above market product prices for two reasons the filings state: the sales volumes are reported net of purchase and sale contracts with the same counterparty while revenue is not, and duties sit inside revenue. The level is therefore an index, not a price.

Table 1.5 Price and volume in the change in the value of own production, $m

The decomposition applies consolidated subsidiary volumes and realisations from Item 2 of the 10-K, multiplies out, and splits the year on year change into a price term at prior year volumes, a volume term at prior year prices, and the residual. It covers 65.7% of Upstream gross sales revenue in FY2025; the rest is purchased volumes ExxonMobil markets, equity company production that reaches the income statement as equity earnings rather than sales, and other income.

Crude accounted for most of the price effect in FY2025. Its realisation fell $10.93 a barrel and took $(7,412)m out at prior year volumes, with bitumen a further $(1,077)m. Natural gas was flat at $3.15 per thousand cubic feet and added $40m. Volume added $5,727m, of which crude contributed $3,745m and natural gas liquids $1,127m as Permian barrels ramped. FY2024 was the mirror image: price cost $(2,608)m, of which natural gas was $(2,022)m, while volume added $13,847m.

The same split at segment level for FY2025 runs as follows. Energy Products lost $(29,283)m on unit revenue and recovered $10,030m on volume, a net $(20,199)m, which is the whole of the group's revenue decline and more. Upstream lost $(10,440)m on unit revenue against $9,633m from volume, netting $(1,778)m. Chemical Products lost $(4,706)m on unit revenue and recovered $3,362m on record volume.

1.5 Pioneer and the comparability break

ExxonMobil acquired Pioneer Natural Resources on 3 May 2024 for 545 million shares with a fair value of $63bn, plus $5bn of assumed debt. Of the $88bn of identifiable assets acquired, $84bn was property, plant and equipment; $1bn of goodwill was allocated to Upstream. Two thirds of a year of Pioneer sits in FY2024 and a full year in FY2025, so no two consecutive years are like for like on the United States Upstream lines.

Table 1.6 Pioneer Natural Resources, reported against pro forma, $m

Pioneer contributed $17,008m of sales and other operating revenue and $1,710m of net income between 3 May and 31 December 2024, 5.0% of that year's revenue. The pro forma table implies a further $8,159m in the four months before completion and $23,317m for the whole of 2023. On a pro forma basis FY2024 revenue fell 3.0%, against the 1.4% rise the reported figures show; measuring FY2025 against pro forma FY2024 gives (6.8)% rather than the reported (4.5)%.

The FY2025 10-K discloses no pro forma figure for FY2025 and does not separate Pioneer's FY2025 revenue, so the FY2025 against FY2024 comparison still carries four months of missing Pioneer in the base and cannot be corrected from the filings. Table 1.6 gives the shape of the change: long lived assets in the United States rose from $95,792m at the end of 2023 to $183,619m at the end of 2025, 91.7%, while those outside the United States moved from $119,148m to $115,754m, and the United States share of Upstream gross sales revenue rose from 35.6% to 50.1%.

Pioneer is not the whole of the volume growth. The volumes reconciliation in the MD&A puts growth and other at 685 thousand oil equivalent barrels daily in FY2024 and 525 thousand in FY2025, against divestments of 63 thousand and 133 thousand.

1.6 Revenue by region

Table 1.7 Revenue by region and by named country, $m

Geographic revenue is a two line disclosure plus a shrinking list of countries, and revenue is attributed to the primary country of operations rather than to the customer. The United States gained 4.8 points of revenue share over the four years and 19.5 points of long lived asset share, almost all of the asset move in FY2024 on the Pioneer purchase price allocation. Revenue earned outside the United States fell at 1.9% a year while United States revenue grew at 7.2%.

The FY2023 10-K named seven countries covering $111,520m of the $207,323m earned outside the United States, 53.8%. The FY2024 10-K named four. The FY2025 10-K names only Canada, at $27,363m, leaving $158,903m, or 85.3% of revenue earned outside the United States, attributed to no country at all. The filings state no reason and no figure was restated, and the later filings drop the dropped names from their prior year columns as well, so the history is reachable only through the older 10-K. France, at $13,743m in FY2024, left the list in the year ExxonMobil completed the divestment of its French refining and chemical entities, which explains that one name but not the United Kingdom, Singapore, Australia, Belgium and Germany. Named country coverage of revenue earned outside the United States fell from 53.8% in the FY2023 10-K to 14.7% in the FY2025 10-K.

The segment note gives a United States and non United States split for each segment. Energy Products earns 59.3% of its gross sales revenue outside the United States, Chemical Products 55.5%, Specialty Products 62.6%, and Upstream now only 49.9% against 64.4% in FY2021.

2 Financial Analysis & Ratios

ExxonMobil earned $18,708m in the first half of 2026 against $14,795m a year earlier, and $22,052m excluding identified items against $14,795m; the two quarters inside the half swung $10,342m between them on derivative timing and impairments. Distributions were covered 1.03 times by cash flow after capital spending in the half, against 0.63 times in 2025. Return on average capital employed was 9.3% in 2025 against 12.7% in 2024, on a realised crude price of $65.18 a barrel against $76.23, and shareholder distributions of $37.5bn ran $13.9bn ahead of the cash operations left after capital spending. Cash and cash equivalents were $10,681m at the end of 2025 against $23,187m a year earlier, and net debt to capital finished 2025 at 11.0% against 6.5%.

Two of the company's own measures are used here alongside US GAAP, with the reconciliation in Table 2.2. Return on average capital employed, as the FY2025 Form 10-K defines it: "The Corporation's total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed." Capital employed adds ExxonMobil's share of equity company net assets and debt to the consolidated balance sheet, so the denominator is wider than reported total assets less liabilities.

Earnings excluding identified items, as the same filing defines it: "Earnings (loss) excluding Identified Items are earnings (loss) excluding individually significant non-operational events with, typically, an absolute Corporate total earnings impact of at least $250 million in a given quarter." The exclusion removes four things: asset impairments, gains and losses on asset sales, discrete tax items, and severance, contractual and restructuring charges. It does not remove derivative mark to market timing effects, which management reports separately and which dominated both quarters of 2026 to date.

2.1 What changed in 2025

Revenue fell 5.0% to $332,238m as realised crude dropped to $65.18 a barrel from $76.23. Volume growth of 9.3% offset part of the price move on the top line and none of it on the bottom line. Depreciation and depletion including impairments rose 10.9% to $25,993m, production and manufacturing expenses 7.1% to $42,424m and selling, general and administrative expenses 11.5% to $11,128m, together $6,518m more than in FY2024, while purchases fell $15,206m alongside revenue.

Table 2.1 What changed between FY2024 and FY2025

Dollars in millions unless stated. Sources: Form 10-K for FY2025, accession 0000034088-26-000045, and the fourth quarter 2025 news release, accession 0000034088-26-000033. Two realised price series run through this document and both are ExxonMobil's own, taken from one table in Item 2 of the 10-K. This chapter uses the total rows, which add ExxonMobil's share of equity company volumes to consolidated subsidiaries: $65.18 a barrel of crude and $4.28 a thousand cubic feet of natural gas in FY2025, $66.96 and $5.21 in FY2021. Table 1.4 uses the consolidated subsidiaries rows of the same table, $65.64 and $3.15 in FY2025, $67.14 and $4.33 in FY2021, because the price and volume decomposition it feeds can only be struck on consolidated volumes. The gap is a difference of scope, not a disagreement about price.

The four segments moved in different directions. Energy Products added $3,390m as the indicative refining margin went from $11.5 a barrel in the first quarter to $18.3 in the fourth. Chemical Products lost $1,777m, with the 10-K putting the chemical margin driver at $(1.8)bn for the year, alongside impairments and the ramp up of the China chemical complex. Corporate and Financing charges rose to $3,590m from $1,372m on lower interest income as the cash balance was spent, on unfavourable foreign exchange, and on $419m of restructuring charges. Upstream lost $4,036m despite 403 thousand more barrels a day.

One reading trap in the 10-K financial summary: additions to property, plant and equipment show as $109,332m for 2024 because that line includes the non cash additions from the Pioneer acquisition. The cash flow statement figure, and the one used throughout, is $24,306m.

2.2 Return on capital

Return on average capital employed was 9.3% in 2025 against 12.7% in 2024 and 15.0% in 2023; excluding identified items, 9.7% against 12.6% and 16.1%. Across the five years average capital employed rose from $222,890m to $305,775m, a 37% increase, while earnings excluding financing costs went from $24,395m to $28,297m, a 16% increase, on a realised crude price of $66.96 a barrel in 2021 against $65.18 in 2025.

Two qualifications belong with that comparison. Realised natural gas was $5.21 per thousand cubic feet in 2021 against $4.28 in 2025, so gas worked against 2025. And the 2024 and 2025 capital base includes Pioneer assets whose production contribution builds over several years, so a single year ratio understates the eventual return if the acquisition performs. The direction of travel through those three years is nonetheless unbroken.

Returns computed straight from the audited statements move the same way and sit lower, because they use the reported balance sheet rather than the wider capital employed base: return on average total assets fell from 9.7% in 2023 to 6.4% in 2025, and return on average total equity from 18.0% to 11.1%.

2.3 Impairments and asset sale gains

Identified items swung reported earnings by between a positive $216m and a negative $3,361m over five years, on a base that ranged from $23.0bn to $55.7bn. Impairments alone totalled $10,457m after tax across the period and never fell below $608m in a year; asset sale gains ran the other way, totalling $3,407m.

Table 2.2 From US GAAP earnings to earnings excluding identified items, after tax

Dollars in millions unless stated. A negative value reduced reported earnings. Sources: Form 10-K for FY2025, accession 0000034088-26-000045, and Form 10-K for FY2023, accession 0000034088-24-000018. ExxonMobil's own component figures for FY2025 sum to $(1,266)m against its published total of $(1,265)m, a rounding difference inside the filing.

The 2025 charge was led by asset impairments, which touched all four product segments and Corporate, offset by $720m of Energy Products asset sale gains booked outside the United States. The FY2024 total was positive because the Argentina divestment gain outweighed the Nigeria divestment loss and a United States impairment.

2.4 Ratio analysis

Table 2.3 Ratio analysis, FY2021 to FY2025

Earnings before interest, tax and depreciation is income before income taxes plus interest expense plus depreciation and depletion, derived from the income statement. Interest cover is that figure divided by reported interest expense, which is net of capitalised interest and is therefore high by industrial standards. Sources as for Tables 2.1 and 2.2, with FY2022 balance sheet figures from Form 10-K accession 0000034088-23-000020.

Three ratios move most across the five years. Depreciation and depletion rose from 5.8% of revenue in 2022 to 7.8% in 2025. Asset turnover fell to 0.74 times, the lowest in the five years. Distribution cover fell below one in 2024 and to 0.63 times in 2025.

2.5 The cash chain

Operating cash flow has been broadly flat at $52bn to $55bn for three years while capital spending rose from $21.9bn to $28.4bn and distributions from $32.7bn to $37.5bn. The gap closed in 2023, went negative in 2024 and reached $(13.9)bn in 2025. Cash and cash equivalents fell from $31,568m at the end of 2023 to $23,187m at the end of 2024 and $10,681m at the end of 2025, and total debt rose $1.8bn in 2025 after three flat years.

On the company's own wider measure, cash flow from operations and asset sales was $55,128m in 2025 against $59,447m in 2023, and it reported free cash flow of $26.1bn for 2025 and $36.1bn for 2023, deducting cash capital expenditures of $28,997m. Cash capital expenditures are disclosed only from the FY2024 comparative onward, so Figure 2.3 uses additions to property, plant and equipment from the cash flow statement, reported for every year. Distributions here use the cash flow statement throughout, giving $37,504m against the company's stated $37.2bn; chapter 5 sets out the difference between the two buyback measures.

The 2025 Corporate Plan Update states a $20bn a year share repurchase pace through 2026. Net debt to earnings before interest, tax and depreciation was 0.48 times at the end of 2025 and interest cover 112.5 times. At the 2025 realised crude price of $65.18 a barrel, distributions of $37,504m exceeded cash flow after capital spending of $23,612m by $13,892m.

2.6 Earnings per barrel

Upstream earned $12.87 per oil equivalent barrel excluding identified items in 2025, on a realised crude price of $65.18 a barrel against $76.23 in 2024 and a production cost of $10.20 a barrel against $10.53. The peak across the five years was $28.90 in 2022 at $95.88 a barrel realised.

Depreciation and depletion per barrel produced was $15.04 in 2025 against $15.21 in 2021, while capital spending per barrel produced rose 84% across the five years, from $8.91 to $16.40. Across the whole company, net income per oil equivalent barrel produced was $16.69 in 2025 against $17.01 in 2021.

2.7 Gearing

At 30 June 2026 the company reports net debt to capital of 10.7%, with total debt of $42.4bn and cash of $10.6bn. It finished 2025 at 11.0% against 6.5% at the end of 2024. Total debt has been stable near $41bn to $44bn throughout the five years, so net debt moves with the cash balance rather than with borrowing: it rose from $10.0bn at the end of 2023 to $32.9bn at the end of 2025 as that cash funded the distribution shortfall.

2.8 First half 2026

Earnings in the first half of 2026 were $18,708m against $14,795m a year earlier, and $22,052m excluding identified items against $14,795m, first half 2025 carrying no identified items. Unsettled derivative positions moved in opposite directions across the two quarters, and over the half the disclosed timing effects reduced Upstream earnings by $870m and Energy Products earnings by $770m. Chapter 3 sets out the timing effect disclosure and the measure built on it.

Table 2.4 First half 2026 against first half 2025

Dollars in millions unless stated. Sources: Form 10-Q for Q2 2026, accession 0000034088-26-000093, Form 10-Q for Q1 2026, accession 0000034088-26-000067, and the second quarter 2025 news release, accession 0000034088-25-000040.

Management attributes the swing to market conditions rather than to the portfolio. The Q2 2026 Form 10-Q states: "Market conditions continued to be heavily influenced by supply disruptions in the Middle East and global refining capacity reductions during the second quarter of 2026." On margins it is more specific: "Global industry refining margins were sharply above the 10-year historical range due to unprecedented global refining capacity reductions." The same filing puts the second quarter Upstream price effect at an increase of $4,650m and the Energy Products margin effect at an increase of $3,180m, against a $1,060m Upstream and $310m Energy Products hit from Middle East volume disruption. Distribution cover recovered to 1.03 times in the half, the first period above one since 2023, with buybacks running at the guided pace of $10.0bn in six months.

A disclosure limitation and a scope difference both apply to this section. Every other figure in this chapter sits under the predecessor central index key, and no second quarter 2026 earnings release was filed under it: the most recent Item 2.02 report under that key is the first quarter release of 1 May 2026, accession 0000034088-26-000065, and the second quarter release of 31 July 2026 was filed by the successor as accession 0002115436-26-000006, as chapter 5 records. That release renamed the company's middle measure, so no second quarter figure is published under the name earnings excluding identified items. The $(3,344)m half year figure above is the total ExxonMobil itself publishes, taken from that release and matching Table 3.4. The four product segments whose identified items the Form 10-Q discloses account for $(3,181)m of it, and Corporate and Financing for the remaining $(163)m, being $(147)m of impairments and $(16)m of other items. The segment method applied to the first quarter yields $(706)m, the exact difference between $4,183m of GAAP earnings and $4,889m of earnings excluding identified items in the first quarter news release, because the first quarter carried no Corporate and Financing identified items. Timing effects are disclosed in the Form 10-Q only inside each segment's driver commentary, and not for Chemical Products or Specialty Products, so the half cannot be restated onto the company's own timing adjusted measure.

2.9 What the numbers say about the stock

In the first half of 2026 earnings excluding identified items rose 49.1% on a 0.8% fall in oil equivalent production, with the disclosed timing effects reducing rather than raising the result. The Form 10-Q describes the refining margin behind it as "sharply above the 10-year historical range", and the same Middle East supply disruption cost $1,370m of second quarter volume earnings. Distribution cover was 1.03 times in the half.

The two years behind it combine volume growth funded by acquisition with distributions of $36,333m in 2024 and $37,504m in 2025. Oil equivalent production of 4,736 thousand barrels daily in 2025 is the highest ExxonMobil reports in over forty years, production cost per oil equivalent barrel fell to $10.20 from $10.53, and net debt to capital was 11.0% at the year end. Return on average capital employed was 9.3%, the lowest of the five years; distributions were 107.9% of net income in 2024 and 130.0% in 2025; and at the 2025 realised crude price of $65.18 a barrel distributions exceeded cash flow after capital spending by $13.9bn, with cash and cash equivalents ending the year at $10,681m against $23,187m a year earlier.

3 MD&A & Management Commentary

ExxonMobil earned $14,525m in the June 2026 quarter against $7,082m a year earlier, and management's driver tables attribute the change as follows. Upstream price added $4,650m and Energy Products refining margin added $3,180m, $7,830m against a group increase of $7,443m. Advantaged volume growth and structural cost savings added $1,620m across the four segments, 22% of the move. Middle East volume disruption cost $1,480m and identified items $2,475m, both totalled across those four segments.

First half reported earnings were $18,708m and management's adjusted measure was $23,452m, a difference of $4,744m. A year earlier the adjusted figure sat $240m below the reported one. From the first quarter of 2026 the adjusted measure removes estimated timing effects on unsettled derivative positions as well as identified items; those timing effects were $(3,883)m in the March quarter and $2,483m in the June quarter.

On 9 December 2025 management raised the 2030 plan to $25bn of earnings growth and $35bn of cash flow growth against 2024, from $20bn and $30bn, and said it would do it with no increase in capital spending. The same update cut planned lower emission investment for 2025 to 2030 to about $20bn from up to $30bn.

3.1 What management flags

Table 3.1 Trends and risks ExxonMobil names itself, with the filing or call and the date

Three items on that list are new in 2026 and absent from the 2025 annual commentary: the Middle East disruption, the timing effect disclosure that grew out of it, and the refining capacity reductions. All three are market events. The list contains no company specific operational problem management raises against itself in 2026, and the only asset level issue named anywhere is Kazakhstan downtime in the March quarter.

3.2 The plan, and how the plan changed

Table 3.2 The corporate plan as published in December 2024 and as raised in December 2025

The plan update is not an EDGAR document. ExxonMobil filed a Form 8-K on 18 November 2025 giving notice that it would post the plan on its website on 9 December 2025, and the 10-K then cites the plan for the repurchase pace. The plan itself was never filed, so every figure in the table above was corroborated across two independent publications before use. The December 2024 cost savings figure is implied rather than published: the 2025 update states the plan increased by $2bn to $20bn.

Two lines in that table move in opposite directions. Earnings growth, cash flow growth, production and cost savings all rise. Lower emission investment falls by a third, from up to $30bn to about $20bn over the same six years. Management does not present the second as funding the first, and the capital line says the total envelope is unchanged. The reported spend is small either way: capital investment in the three Product Solutions businesses was $3.7bn in 2025 and other spend, which the 10-K says primarily reflects investments in the Low Carbon Solutions business, was $0.6bn. In the first half of 2026 that other line was $230m against $290m a year earlier.

The 2030 return on capital target of more than 17% is set against 9.3% delivered in 2025, down from 12.7% in 2024 and 15.0% in 2023. Average capital employed rose to $305,775m in 2025 from $278,102m, the Pioneer acquisition working through a full year. Holding capital flat, that target needs earnings excluding financing costs to rise about 83% from the 2025 level.

3.3 Structural cost savings against the stated target

Cumulative savings against 2019 reached $16.3bn at 30 June 2026, of which $1.2bn was added in the first half. That leaves $3.7bn to find by 2030, about $0.8bn a year, against a half year pace that annualises at $2.4bn and a 2025 outturn of $3.0bn.

Table 3.3 What the savings have and have not done to the cost base

Six years of savings have held the cost base flat rather than cut it. Cash operating expenses excluding energy and production taxes were $44.1bn in 2025 against $44.0bn in 2019, on a company that added Pioneer and Denbury in between. The disclosure is clear about the arithmetic: $15.1bn of structural reduction was consumed by $4.9bn of market cost and $10.3bn of activity. The first half of 2026 repeats the pattern at a smaller scale, with $1.2bn of savings against $2.3bn of market and activity cost, so the half on half cost line rose $1.1bn.

3.4 Reported earnings against the adjusted measure

Table 3.4 The bridge from reported to adjusted earnings, $m

The definition moved in 2026. Through 2025 the company published earnings excluding identified items, a measure that removed one off events and left derivative marks in. The first quarter 2026 release introduced a third line, earnings excluding identified items and estimated timing effects, and reported $8.8bn on it against $4.9bn on the older measure and $4.2bn on US GAAP. The second quarter release renamed that third line adjusted earnings and dropped the middle measure. The stated reason is that adjusted earnings better reflect the way management internally measures performance and manages the economic exposure of physical commodity contracts and their associated derivatives.

Management set out the mechanics before the quarter was reported. The Form 8-K of 8 April 2026 explains that hedged physical shipments sit in LIFO inventory while the financial derivative is marked to period end prices, that the mismatch unwinds over subsequent quarters, and that in periods of rising prices timing effects are typically negative. It also published the quarter end Brent print for each of the previous twelve quarters alongside the timing effect each produced, and guided the first quarter change at $(4.9)bn to $(3.5)bn against a reported $(3,883)m. The exclusion entered the headline measure for the first quarter of 2026, the quarter in which estimated timing effects were $(3,883)m, and the first half shows $23,452m adjusted against $18,708m reported.

The identified items are not derivative marks. Second quarter impairments of $1,079m fall mainly on an Energy Products asset outside the United States, $884m of the total, with $48m in Chemical Products and $147m in Corporate and Financing. Other identified items of $1,559m split into $1,365m of additions to financial reserves, almost all in US Upstream, and $194m of Middle East impacts. Corporate and Financing carries $163m of the half year total, $147m of impairments and $16m of other items, which is the part of the total the four product segment disclosure in the Form 10-Q does not reach, as section 2.8 notes. Full year 2025 carried $1,265m of identified items, of which $1,855m of impairments and $419m of restructuring charges were offset by a $720m gain on sale and $288m of tax items.

Table 3.5 Segment earnings, reported and adjusted, $m

Energy Products is where the two measures diverge most. The segment reported a $1,262m loss in the March quarter and $2,799m of adjusted earnings, then reported $5,465m in the June quarter against $4,099m adjusted. Over the half the reported figure is $4,203m and the adjusted figure $6,898m. Reported earnings rose 92% over the half and adjusted earnings rose 209%. The two measures disagree by $2,695m on the level.

3.5 The drivers management publishes

The driver tables split the change in each segment by cause. Upstream price contributed $4,650m on higher crude realisations, partly offset by lower gas realisations. Energy Products margin contributed $3,180m from higher refining margins, and estimated timing effects a further $2,560m. Against those, the Middle East volume line cost $1,060m in Upstream, $310m in Energy Products, $110m in Specialty Products and nothing named in Chemical Products.

Structural cost savings appear in every segment and total $330m of after tax earnings effect in the quarter, $170m of it in Upstream. Set against the $1.2bn of cumulative savings before tax added in the half, that is the scale management itself attaches to the cost programme inside a single quarter's earnings.

Expenses cut Upstream earnings by $690m in the quarter and $1,510m in the half, and management names higher depreciation as the reason in both. Depreciation and depletion including impairments was $15.5bn in the half against $11.8bn a year earlier.

3.6 Guidance against outturn

Table 3.6 Second quarter 2026 as set out on 7 July against as reported on 31 July, $bn

ExxonMobil sets out the quarter three weeks before it reports it, and every adjusting item the Form 8-K of 7 July 2026 named landed inside its stated range. The Upstream reserves line of $(1.199)bn sits one million dollars below a floor stated to one decimal place.

The market ranges in that filing cannot be scored. Management guided a quarter on quarter liquids price benefit of $3.5bn to $3.9bn in Upstream and refining margin of $2.0bn to $2.4bn in Energy Products, and the results present drivers against the prior year quarter instead, so the filings carry no sequential comparison with those ranges.

The 8 April 2026 supplement sized the first quarter timing effect at $(4.9)bn to $(3.5)bn, split between Upstream gas of $(0.8)bn to $(0.2)bn and Energy Products crude and products of $(4.1)bn to $(3.3)bn, put about $0.93 a share on the midpoint, and flagged that quarter end cash would fall by comparable margin postings. Reported timing effects were $(3,883)m and the March quarter cash balance fell to $8.4bn from $10.7bn.

3.7 Volumes, and what management commits to next

Table 3.7 Named volume milestones, as management states them

Production peaked in the December 2025 quarter at 4,988 koebd and has fallen 474 koebd since. Management attributes the fall to the Middle East disruption, set out in chapter 5, and states that Permian and Guyana growth mostly offsets it. Refinery throughput fell to 3,528 kbd in the half from 3,873 kbd, on reduced crude availability at Asia Pacific operations as well as the Middle East.

The 2030 target of 5.5 Moebd sits 986 koebd above the June 2026 quarter. Reaching it requires the Middle East volumes to come back, the fifth and sixth Guyana vessels and Hammerhead to arrive on schedule, and the Permian to grow from 1.6 Moebd in 2025 to about 2.5 Moebd, which is 9.3% a year and matches the compound rate the company itself publishes. Management has not restated the 2030 figure since the disruption began.

Commentary from the 31 July 2026 earnings call, a source outside EDGAR, sharpens two of these points. Neil A. Hansen, senior vice president and chief financial officer, said of Guyana that "we're going to see two times the level of free cash flow in 2030 than we saw in 2025". Darren Woods, chairman and chief executive, said of the refining backdrop that "I've never seen the available capacity relative to demand as low as it is today". On the cost programme, management said centralised organisations delivered close to half of this year's savings and repeated the $20bn by 2030 target. The two direct quotations above were corroborated across two independent transcript publications; the cost commentary was not consistently attributed between them and is given here in indirect form.

3.8 Capital, cash and the buyback

Table 3.8 Capital discipline measures against what management has committed to

First half cash capital expenditure of $12,974m is 44.7% of the top of the 2026 guide and 48.1% of the bottom, and $435m above the same period of 2025. Holding the range means spending $14.0bn to $16.0bn in the second half, up to $3.0bn more than the first. Management has repeated the range without change in the 10-K and both 10-Q filings.

Repurchases of $4,900m in the March quarter and $5,100m in the June quarter make $10,000m against a $20bn year, 66.7m shares at an average book cost of $149.93 a share, half the annual programme. Distributions of $18,600m in the half were covered 1.07 times by free cash flow of $19,935m, and the cover was built entirely in the June quarter: free cash flow was $2,699m in the March quarter against $9,200m distributed, and $17,236m in the June quarter against $9,400m.

Total debt rose to $47.7bn at 31 March from $43.5bn at year end, then fell to $42.4bn at 30 June. Net debt to capital ran 11.0%, 13.1% and 10.7% across the three dates. The March quarter cash outflow included margin postings against derivative positions, which the 8 April filing had flagged in advance. Management's commentary treats the pre and post redomiciliation entities as continuous and gives no separate financial effect.

4 Sector & Competitor Analysis

On the definitions in Table 4.2, ExxonMobil has the largest revenue of the six companies compared here and the lowest net debt to earnings before interest, tax, depreciation and amortisation. Sales and other operating revenue of $323.9bn for the year to 31 December 2025 fell 4.52%, against a peer median fall of 4.64%. Return on capital of 9.9% sits above the peer median of 9.5%. Net debt of $39.7bn is 0.58 times EBITDA, the lowest of the six and against a peer median of 0.89 times. The last trade on 3 September 2026 was $162.21, a market value of $667bn, 23.1 times reported diluted earnings and 10.5 times EBITDA against a peer median of 6.1 times. Return on capital here is rebuilt on one definition applied six times and is not ExxonMobil's published return on average capital employed of 9.3%.

Shell earns 9.5% on capital and trades at 5.1 times EBITDA. TotalEnergies earns 10.0% and trades at 6.1 times. ConocoPhillips earns 10.4% and trades at 7.2 times. ExxonMobil earns 9.9% and trades at 10.5 times, and Chevron earns 5.7% and trades at 11.3 times. Remove the impairment charges that sit inside the European EBITDA figures and Shell reads 5.4 times and BP 5.6 times, so the gap survives that adjustment. On the 2025 accounts the two American integrated majors are rated at roughly twice the multiple of the three European ones for the same return on capital. Reserve life, the Guyana and Permian growth path, and the political risk attached to each listing are all candidate explanations, and none of them can be tested from a single year of accounts.

4.1 The peer set and the rule that picks it

A company qualifies if it runs upstream oil and gas production inside a group that also refines and markets it, reports more than $50bn of annual revenue, and files with the Commission on Form 10-K or Form 20-F. The screen returns five companies beyond ExxonMobil. ConocoPhillips stretches the rule: it reports no refining or marketing segment, so it appears as the pure upstream reference point rather than as an integrated competitor. Equinor ASA and Eni SpA clear the tests and are excluded because a state shareholder sets the dividend and investment policy, which makes a return on capital comparison read as something other than management performance.

Table 4.1 The peer set, the framework each reports under, and the filing each figure is read from

Every peer figure comes from a year to 31 December 2025. All six close on the same date, so nothing in the comparison turns on an overlapping or a lagging fiscal period, and the whole set was earned at one Brent price deck.

4.2 What the 20-F filers, IFRS and the depositary receipts cost the comparison

Three of the six file on Form 20-F as foreign private issuers. That costs nothing on timing, because all three close on 31 December and filed within four months of the year end. It costs something on retrieval: the XBRL exhibit to the BP and TotalEnergies Form 20-F filings is 17MB and 30MB respectively and does not convert, so the income statement, balance sheet and net debt for those two are read from each company's fourth quarter and full year 2025 results, filed on Form 6-K. BP's release says: "The financial information shown in this publication, which was approved by the Board of Directors on 9 February 2026, is unaudited and does not constitute statutory financial statements. Audited financial information will be published in bp Annual Report and Form 20-F 2025." TotalEnergies labels every statement in its release unaudited. Those two rows of Table 4.2 therefore rest on unaudited figures that the audited Form 20-F later confirmed or restated; the audited statements have not been read here and cannot say which. Every other figure in the table is audited.

Leases. IFRS 16 puts every lease liability inside debt; US GAAP keeps operating leases outside it. Net debt here is all borrowings on the face of the balance sheet plus any lease liability presented outside them, less cash, so ExxonMobil's $6,834m of operating lease liabilities, Chevron's $5,985m and ConocoPhillips' $950m are added and the six sit on one footing. The cost sits on the other side of the ratio: ExxonMobil's $2,450m of operating lease cost stays inside operating expenses and is not added back to EBITDA, where the equivalent charge at the three IFRS filers is. ExxonMobil's leverage of 0.58 times is struck without that add back; adding the lease cost back gives 0.56 times.

Impairment. Shell and TotalEnergies fold impairment into depreciation, BP and ConocoPhillips present it separately, and both are added back so that EBITDA means the same thing six times. That carries back Shell's $3,175m and BP's $6,037m of 2025 impairment: excluding the add back, Shell trades at 5.4 times EBITDA rather than 5.1 and BP at 5.6 times rather than 4.7.

Operating profit. Neither framework gives a usable subtotal, so operating profit is rebuilt the same way for all six, as profit before income tax plus interest expense on borrowings. Currency is the one difference that does not arise: Shell, BP and TotalEnergies all present their consolidated statements in US dollars, so no translation enters Table 4.2.

Depositary receipts. Shell, BP and TotalEnergies trade in New York as American Depositary Shares, each representing two, six and one ordinary shares. Market value is the ordinary share count in the most recent filing multiplied by the ADS price divided by that ratio, so the depositary ratio never enters a multiple. The Shell ratio is on the cover of its Form 20-F; the BP ratio is implied by its own release, which reports 0.35 cents of basic earnings per ordinary share and $0.02 per ADS; the TotalEnergies ratio is confirmed by the Paris ordinary share at EUR 78.16 against the New York ADS at $89.25 on the same date, an implied 1.14 dollars to the euro.

One difference sits inside revenue itself. TotalEnergies alone deducts excise taxes on the face of the income statement, $18,852m against sales of $201,196m, so its revenue line is 9.4% smaller than the same business would report gross. ExxonMobil states the opposite policy: "Similar taxes, for which the Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other operating revenue” and “Other taxes and duties”)." It does not split the $25,167m of taxes other than income taxes into the sales based part and the rest. Chevron, ConocoPhillips, Shell and BP disclose no equivalent amount in the documents read here. Margins struck on revenue carry that spread, and it is the reason the gross and operating margin columns should be read as a band rather than a ranking.

4.3 The sector

The six sell into one price and none of them sets it. Brent averaged $69 a barrel in 2025, the year every figure in Table 4.2 was earned. The Energy Information Administration expects $87 for 2026 and $69 again for 2027, and attributes the rise to supply rather than demand: "We have increased our estimates of Middle East shut-in crude oil production in the coming months compared with our July forecast due to continued severe constraints on Strait of Hormuz transits, which we assume persist through August." World liquid fuels production falls from 106.1 million barrels a day in 2025 to 100.8 million in 2026 and recovers to 109.7 million in 2027, against consumption of 104.0, 102.7 and 105.0 million. Global inventories fell by 4.2 million barrels a day in the second quarter of 2026 and the Administration expects a further 3.8 million a day draw in the third.

The 2025 accounts were earned at a Brent average of $69 a barrel. The market prices in Table 4.2 are the last trade on 3 September 2026, struck in a quarter at $85. The Administration's forecast for 2027 is $69.

The sector is consolidating, and the filings date each step. Chevron acquired Hess Corporation on 18 July 2025 for approximately $48bn, issuing 301.25 million shares. Shell completed the acquisition of ARC Resources on 2 September 2026 for an equity value of about $13.9bn and an enterprise value of about $16.5bn, adding roughly 370 thousand barrels of oil equivalent a day, funded with $3.3bn of cash and $10.6bn of new shares. TotalEnergies agreed on 3 August 2026 to buy Shell's 4 GW onshore renewables business in Europe and to sell half of a 1.2 GW developed portfolio to an insurance account managed by KKR at an enterprise value of EUR 1.8bn. BP agreed on 19 March 2026 to sell the Gelsenkirchen refinery to Klesch Group.

4.4 Like for like comparison

Table 4.2 Peer comparison on one set of definitions, year to 31 December 2025

Definitions, applied identically six times. Revenue is the revenue from sales line on the face of the income statement, which is sales and other operating revenue at ExxonMobil, Chevron and BP, revenues at ConocoPhillips, revenue at Shell and revenues from sales after excise taxes at TotalEnergies; it excludes equity affiliate income, interest income and gains on disposal. Growth compares that line with the prior year as filed in the same document. Gross margin is revenue less purchases of crude oil, products and other goods, divided by revenue. Operating margin is profit before income tax plus interest expense on borrowings, divided by revenue. EBITDA is that same operating profit plus depreciation, depletion, amortisation and impairment as presented. Return on capital is operating profit after the company's own effective tax rate, divided by total equity including noncontrolling interests plus net debt. That column is rebuilt here so the six sit on one definition, and it is not any of the six companies' own published return: ExxonMobil's 9.86% in this table is not the 9.3% return on average capital employed it publishes and chapter 2 uses, and BP's 1.95% is not the 13.9% it publishes. Net debt is every borrowing on the face of the balance sheet plus any lease liability presented outside them, less cash and cash equivalents. Price to earnings uses profit attributable to the owners of the parent. Enterprise value is market value plus net debt plus noncontrolling interests at book. Every market price is the last trade recorded on 3 September 2026.

Four limits belong with those definitions. BP's price to earnings ratio reads n/a because BP earned $55m attributable to shareholders in 2025 after $6,037m of net impairment and losses on disposal, so the arithmetic returns 2,074 times and carries no information; Table 4.3 gives the number that does. BP's return on capital of 1.95% is depressed twice over, once by that impairment and again by the 83.3% effective tax rate the impairment produces, which the definition applies as filed rather than normalising. Chevron's 5.70% return on capital is struck on a capital base that includes Hess in full at 31 December 2025 while the earnings include Hess for five and a half months; Chevron's own pro forma for a full year of Hess is net income of $12,464m against the $12,299m reported, so the timing explains $165m and not the gap to the rest of the set. And ConocoPhillips' 62.1% gross margin and 22.92% operating margin are an upstream company's numbers, not an integrated company's; it buys almost nothing to resell, so its margin columns cannot be ranked against the other five.

ExxonMobil is the least leveraged of the six at 0.58 times against 0.98 times at both Chevron and BP. It converts the most cash: $51,970m from operations less $28,358m of capital expenditure leaves $23,612m, ahead of Shell's $21,948m and more than double BP's $9,960m, though each company's capital expenditure is its own investing line and the labels differ, so read that as an order of magnitude rather than a ranking. It reinvests at 1.09 times depreciation, against 0.83 at Shell and 0.61 at BP, with only TotalEnergies spending harder at 1.27 times. On operating margin it is inside a percentage point of Shell and TotalEnergies, and on revenue growth it is in the middle of a set where four of six shrank.

4.5 Reported earnings against core earnings

Every company in the set publishes a core earnings measure, and no two of the definitions are the same, so the levels are not strictly comparable. They are shown together because in one case the gap inverts the reading of Table 4.2 entirely.

Table 4.3 Reported earnings against each company's own core measure, year to 31 December 2025, $m

BP's underlying replacement cost profit of $7,485m against $55m attributable is a gap of $7,430m, made of $5,885m of pretax adjusting items, $1,351m of pretax inventory holding losses and the tax on both. On the core number BP trades at 15.2 times, alongside Shell at 13.9 and TotalEnergies at 12.7, and its own return on average capital employed for the year is 13.9%, against the 1.95% that the reported accounts produce.

At ExxonMobil, earnings excluding identified items of $30,109m are 4.4% above the $28,844m reported, and the multiple moves from 23.1 times to 22.2 times. Only Shell at 3.9% and ConocoPhillips at (3.1)% report a narrower gap between the two views of the year. ConocoPhillips is the only company whose core number is below its reported number, by $246m, with 2025 reported earnings including a $731m gain on asset sales. At TotalEnergies $2,460m of adjustment items lift earnings 18.7%.

4.6 What the balance sheet and the multiple say

ExxonMobil's enterprise value of $713.9bn is 10.5 times EBITDA of $67,864m, against Shell's $303.5bn at 5.1 times, TotalEnergies' $236.0bn at 6.1 times and BP's $171.0bn at 4.7 times. Three further figures sit alongside that multiple: net debt of $39.7bn against $306.3bn of capital employed, the lowest leverage in the set; capital expenditure at 1.09 times depreciation; and $23,612m of cash left after that spending. Shell at 9.50% and TotalEnergies at 10.01% return on capital trade at 5.1 and 6.1 times EBITDA, and the Energy Information Administration forecasts Brent at $69 in 2027, the level at which the 2025 earnings were made.

Two structural facts sit under the European discount and are visible in the filings. BP carries $20,948m of noncontrolling interests, 28.3% of its total equity, so a shareholder buying BP buys a smaller share of the group's assets than the headline market value suggests. Shell's share count in Table 4.2 is the 5,570,928,127 ordinary shares at 30 June 2026, before the shares issued on 2 September 2026 for ARC Resources; Shell's own announcement puts that issuance at about $10.6bn, so Shell's market value here is understated by roughly 4%, and its enterprise multiple correspondingly. Correcting for it moves Shell from 5.1 times to about 5.3 times, which does not change the conclusion.

5 Material Events & Contracts

One event in the twelve months to 4 September 2026 changed the listed entity. On 1 July 2026 ExxonMobil moved its state of incorporation from New Jersey to Texas through a redomiciliation merger, and ExxonMobil Holdings Corporation replaced Exxon Mobil Corporation as the listed company on a one for one share exchange. Shareholders approved it with 71.2% of votes cast, against 96.2%, 96.4% and 92.9% on the three other management proposals put to the meeting. The Form 10-Q states that the merger did not change the consolidated business, operations, assets, liabilities or financial reporting basis. Everything else in the log is operating: two floating rate note sales worth $281m between them, one redemption notice covering three XTO Energy series, $20.0bn of buybacks completed in 2025 and $10.0bn more in the first half of 2026, a chief financial officer and a chief accounting officer replaced, a Louisiana coastal erosion settlement, and a Middle East conflict that took about 6% off first quarter production while lifting the Brent marker 64% from the fourth quarter of 2025.

Nineteen current reports were filed in the window, fifteen by Exxon Mobil Corporation up to 1 July 2026 and four by ExxonMobil Holdings Corporation on and after that date. ExxonMobil is a domestic filer and files no Form 6-K. Five further material items reached the market through periodic filings and registration statements rather than a current report.

5.1 The twelve month event log

Table 5.1 Material events reported by ExxonMobil, 4 September 2025 to 4 September 2026

Six of the twenty four rows are financing, five are guidance and four each are results and leadership. Two current reports carry Item 1.01 for a material definitive agreement and two carry Item 2.01 for a completed acquisition or disposition, and all four of those belong to the same 1 July 2026 merger. No Item 4.02 nonreliance filing appears, and no current report announced a commercial acquisition or divestiture.

5.2 The redomiciliation

The merger changed the legal wrapper and nothing else. Each share of Exxon Mobil Corporation common stock, without par value, became one share of ExxonMobil Holdings Corporation common stock with a par value of $0.001, and every equity award carried across on unchanged terms. Shareholder rights moved from the New Jersey Business Corporation Act to the Texas Business Organizations Code. The new parent was deemed registered under Rule 12g-3(a) and trading began under the ticker XOM on 2 July 2026, with the New York Stock Exchange filing Form 25 to delist the old stock the same day.

The consequence for anyone reading the filings is a split record. Filings up to 30 June 2026 sit under Exxon Mobil Corporation, central index key 34088; filings dated on or after 1 July 2026 sit under ExxonMobil Holdings Corporation, central index key 2115436. The Form 10-Q for the June quarter is filed by both entities. The second quarter earnings release, the 7 July guidance filing and the August redemption notice sit under the new key alone, which is why the second quarter is the one period in this document whose current reports carry a different filer from every earlier one. The Form 10-Q states that the merger did not change the consolidated business, operations, assets, liabilities or financial reporting basis, and no figure in this document is affected.

The debt was handled by guarantee rather than by assumption. Under a second supplemental indenture dated 1 July 2026, ExxonMobil Holdings Corporation guaranteed, fully and unconditionally and on a senior unsecured basis, every payment and performance obligation of Exxon Mobil Corporation under the indenture of 20 March 2014 and the notes issued under it. Exxon Mobil Corporation remains the primary obligor and the notes remain its senior unsecured obligations. The shelf registration was amended the same day to add the new parent as co registrant and guarantor.

The old company was reduced to a subsidiary in the same filing: its charter cut authorised common stock from nine billion shares to one hundred, its by laws cut the board to between three and five directors, and twelve directors resigned in favour of Neil A. Chapman, Neil A. Hansen and Jack P. Williams, Jr. The directors and executive officers of the new listed parent are the same people who held those posts before the merger.

5.3 Financing

The buyback is the largest single use of cash in the window and it ran to plan. ExxonMobil completed $20.0bn of repurchases in 2025 and $10.0bn in the first half of 2026, on the $20bn pace the 2025 Corporate Plan Update set. Shares outstanding fell from 4,263 million at 30 June 2025 to 4,112 million at 30 June 2026, a reduction of 3.5%. The disclosed capacity that may yet be purchased fell from $28.5bn in July 2025 to $20.0bn at the year end reset and $10.2bn at 30 June 2026.

Two figures for 2025 repurchases sit side by side in the filings and differ. The cash flow statement line Common stock acquired reads $20,273m; the results release describes $20.0bn of share repurchases. The reconciling item is shares withheld from participants in the incentive programme for personal income taxes, which the issuer purchase tables separate out. In the fourth quarter of 2025 alone, 46,412,832 shares were purchased in total against 44,137,282 under publicly announced plans or programs. The same gap does not appear in the first half of 2026, where the two measures agree at $10.0bn.

Two floating rate issues priced in the window, $111,949,000 due 2075 and $169,312,000 due 2076, $281m in total, both under the indenture of 20 March 2014 with Deutsche Bank Trust Company Americas as trustee. The 2076 notes pay Compounded SOFR minus 0.450% quarterly, are repayable at holder option from 30 March 2027 at 98.000% of principal, and are callable by the issuer only from 30 March 2056 at 105.000%. Against that, long term debt fell from $34,241m at 31 December 2025 to $32,229m at 30 June 2026, short term borrowings of $5,500m were repaid and commercial paper rose $3,912m. On 28 August 2026 XTO Energy Inc. called three legacy series for redemption at par plus a make whole amount.

5.4 The Middle East disruption

The 8-K of 8 April 2026 sets out the Middle East disruption. Middle East assets are about 20% of group oil equivalent production and about 5% of refining and chemical capacity. Attacks in the first quarter damaged two Qatari LNG trains in which ExxonMobil holds an interest, assets that were about 3% of 2025 Upstream production, and the filing states that public reports indicate a prolonged repair period with no on site evaluation yet possible. Qatar LNG joint ventures were 628 koebd net in 2025 and Upper Zakum in the UAE 312 kbd net.

Management guided the first quarter production effect at about 6% against the fourth quarter of 2025. Reported production fell from 4,988 koebd to 4,594 koebd, a fall of 7.9%. Divestments, entitlement effects and base decline account for the difference: the year to date volume driver analysis attributes (16) koebd to net interest entitlements and (52) koebd to divestments against the same period of 2025.

The Brent marker rose from $63.69 a barrel in the fourth quarter of 2025 to $80.61 and then $104.52. Second quarter sales and other operating revenue of $114,529m was 44% above the $79,477m of a year earlier.

5.5 What the price move did to reported earnings

Reported earnings in the two 2026 quarters are not a clean read on trading, for the reason chapter 3 sets out: physical cargoes hedged with financial derivatives that are marked to period end prices while the physical inventory sits at LIFO cost. First quarter GAAP earnings of $4,183m carried $(3,883)m of estimated timing effects and $(706)m of identified items from settled hedges whose physical shipments the Middle East disruption prevented. In the second quarter the timing effect reversed to $2,483m, and GAAP earnings of $14,525m sat close to adjusted earnings of $14,680m.

Second quarter identified items of $(2,638)m split into $(1,079)m of impairments, mostly $(884)m in Energy Products outside the United States, and $(1,559)m of other items. Inside that other figure sit $1,365m of additions to financial reserves and $194m of Middle East impacts. The reserve additions land in United States Upstream, which carried $(1,183)m of the total, and the Louisiana coastal settlement effective 31 July 2026 is described as included within the second quarter reserve updates. Second quarter segment sales and other operating revenue of $114,503m sits $26m below the consolidated $114,529m, the difference being Corporate and Financing.

5.6 Projects, acquisitions and disposals

Neither Guyana nor the Permian is governed by a contract on file. Yellowtail, the fourth and largest Guyana development, started up in the third quarter of 2025, which ExxonMobil reports was four months ahead of schedule and under budget, adding an initial 250 koebd and taking installed Guyana capacity above 900 koebd. A final investment decision on Hammerhead, the seventh Stabroek project, followed in the same quarter for a further 150 koebd by 2029. Table 3.7 carries the production records the same filings report.

Three other project milestones fall inside the window. Bacalhau, the first operated development offshore Brazil, started up in the fourth quarter of 2025. Golden Pass LNG, 30% owned alongside QatarEnergy, produced first LNG from Train 1 on 30 March 2026 and loaded its first export cargo in April, lifting United States LNG exports about 5% against 2025. A final investment decision on a 120 KTA Proxxima blending expansion in Louisiana came in the second quarter of 2026.

More than 80,000 net Permian acres were bought from Sinochem Petroleum in the third quarter of 2025, inside $2.4bn of growth acquisitions that quarter and $2.6bn of acquisitions within 2025 cash capital expenditure of $29.0bn. Key assets were bought from Superior Graphite to enter battery anode materials, on undisclosed terms. Divestment proceeds were about $3.2bn in 2025 for about $1.1bn of after tax earnings, covering the Singapore retail fuels business, Mobil Argentina S.A., Product Solutions affiliates in France and certain United States assets. In the first half of 2026 divestment proceeds fell to about $0.6bn for about $0.1bn of earnings, and the cash flow line reads $649m against $1,999m a year earlier. No disposal in the window was large enough to require a current report.

5.7 Litigation

Two matters fill the whole litigation disclosure. Climate change proceedings brought by state and local governments across the United States and its territories remain outstanding, and the company states that it believes the legal and factual theories are meritless and a material adverse effect remote. The Louisiana coastal marsh erosion proceedings, open at the FY2025 annual report, were settled effective 31 July 2026, on terms the filing describes as not material, with the earnings effect inside the second quarter reserve updates, no admission of liability and no government sanctions.

No arbitration is disclosed anywhere in the window. A full text search of every ExxonMobil filing between 4 September 2025 and 4 September 2026 returns no use of the word. The Stabroek block right of first refusal dispute that ran through 2025 does not appear in the FY2025 annual report, in either 2026 quarterly report or in any current report, so it cannot be sourced or quantified from the filings.

Contingent exposure outside litigation is disclosed as a single number. Guarantees not related to debt, covering notes, loans and performance under contracts, totalled $6,852m at 31 December 2025 and $6,279m at 30 June 2026, of which third party obligations were $6,185m and $5,619m.

5.8 Governance and leadership

The finance leadership turned over twice. Kathryn A. Mikells announced on 8 December 2025 that she would retire as Chief Financial Officer effective 1 February 2026, after procedures for a health issue described as debilitating but not life threatening. Neil A. Hansen, then President of ExxonMobil Global Business Solutions, was elected in her place on an annual salary of $1.02m with no employment contract. On 28 April 2026 Len M. Fox announced his retirement as Vice President, Controller and Tax from 1 July 2026, and Susan Buchanan, by then President of Global Business Solutions, was elected Chief Accounting Officer from the same date.

The board turned over once at each end. Greg C. Garland joined as a nonemployee director from 3 November 2025 and went onto the Audit and Finance Committees with the standard initial grant of 8,000 restricted shares. Jeffrey W. Ubben announced on 18 February 2026 that he would not stand for reelection, for reasons unrelated to the company, and served until the May meeting. That took the board from thirteen to twelve. Chapter 6 carries the meeting itself.

5.9 Material contracts

Table 5.2 Material contracts named in filings inside the window

ExxonMobil files almost no commercial contracts. The FY2025 exhibit index runs to thirty two entries, of which sixteen are management contracts and compensatory plans and the rest are constitutional documents, policies, certifications and data files. There is no revolving credit agreement, no joint venture agreement, no production sharing agreement and no note indenture. The registrant states plainly that it has not filed the instruments defining the rights of holders of its long term debt and will furnish a copy to the Commission on request. Every contract in Table 5.2 above the aircraft agreement comes from a current report or a note, not from the exhibit list.

That has a consequence for anyone modelling the assets. The two assets that carry the growth case, the Stabroek block in Guyana and the Permian acreage, are described in the filings only through production numbers and project milestones. The governing fiscal terms are not on file. The same is true of the Qatari LNG joint ventures that the Middle East conflict disrupted, which are disclosed as working interest ranges of 24% to 30% and as 2025 volumes, and of Upper Zakum at 28%. Guarantees relating to performance under contracts are given as one aggregate of $6,279m at 30 June 2026 with no counterparty named.

5.10 What the record does not contain

No arbitration and no restatement appears in the window, and no Item 4.02 nonreliance filing was made. No commercial acquisition or divestiture triggered an Item 1.01 or Item 2.01 current report; the only two that carry those items are the two halves of the redomiciliation merger. The 2025 Corporate Plan Update of 9 December 2025, which set the $20bn 2026 buyback pace and the capital plans to 2030, was published through the company website and never filed, so its contents can be sourced only through the footnote references in later periodic reports. The dividend was raised once, by 4% to $1.03 a share declared on 31 October 2025, and held at $1.03 through the third quarter 2026 declaration.

6 Ownership, Voting Power & Annual Meeting

Exxon Mobil has one class of stock and one vote per share. There is no founder, family or dual class block, and no Schedule 13D has been filed on the common stock in the last two years. Three index groups held 972.8 million shares at 30 June 2026, 23.7% of the stock, and reported voting authority over 377.9 million of them, 9.2% of shares outstanding. The company reports 150 million shares enrolled in a Voluntary Retail Voting Program, which casts votes with the board on the day the proxy statement is filed. The 2026 ballot carried two shareholder proposals, both governance, which drew 15.2% and 23.5% of votes cast. It carried none in 2025. In January 2024 the company sued two proposal proponents.

6.1 One class, one vote

Economic ownership and voting power are separate columns in Table 6.1. They do not diverge by share class, because there is only one class: 9,000,000,000 common shares authorised, 4,156,559,415 outstanding at 28 February 2026, 3,862,865,019 in treasury, and none of the 200,000,000 authorised preferred shares issued. The certificate of incorporation gives each holder "one vote for each share of common stock held of record". The columns diverge only where a holder reports dispositive power over shares it does not report voting power over, which is what the index managers now do.

Table 6.1 Economic stake against reported voting power, on the disclosures the 2026 proxy statement uses

Percentages for the three named holders are struck on the 4,179,747,572 shares outstanding at 31 December 2025, as the proxy strikes them. The insider and retail rows are struck on the 4,156,559,415 shares outstanding at 28 February 2026. Chief executive Darren W. Woods holds 374,437 shares. No director or officer holds more than 0.01%.

The proxy's own table has a limitation the company discloses. Every schedule it relies on predates its 10 March 2026 measurement date, and two are stale. BlackRock's is as of 31 December 2023 and, in the proxy's words, "No subsequent amended report was filed." Vanguard's is as of 28 February 2025 and was superseded on 26 March 2026, when The Vanguard Group reported that after an internal realignment it no longer holds beneficial ownership of the shares its subsidiaries hold; the successor filings "have not yet been filed" as at the proxy date. Form 13F fills the gap, and Table 6.2 uses it.

6.2 The index block, and where the votes sit

Table 6.2 Index manager positions and reported voting authority, Form 13F at 30 June 2026

Percentages of outstanding are struck on 4,111,911,960 shares at 30 June 2026. BlackRock's stake is 8.1% on Form 13F against the 6.5% the proxy still carries from a schedule two years older. The gap between the two data sets is a filing lag, not a change of holder.

BlackRock reports sole or shared voting authority over 93.9% of its shares, Vanguard over 9.7% and State Street over 10.6%. The difference is a filing structure, not a measure of who prefers to vote: Vanguard's two largest reporting entities, holding 387.4 million shares between them, report voting authority of zero, while the voting sits with the funds and, increasingly, with clients who have taken it back. Read the column as reported authority, not as an assertion about behaviour.

Across the four quarters Vanguard and State Street held a combined 636 million to 644 million shares, a band of 1.4%. Their combined reported voting authority went from 169 million shares to 48 million in a single quarter and has since settled near 64 million. The move is State Street's. Its reported voting authority fell from 144.2 million shares at 30 September 2025 to 21.9 million at 31 December 2025, a drop of 122 million on a stake that barely changed. Vanguard's ran the other way by a smaller amount, from 25.1 million to 41.7 million, as the disaggregation put more of the group's shares into entities that do report voting authority.

6.3 Institutional coverage

The number of Form 13F reports naming the stock rose from 4,327 for the quarter to 30 September 2025 to 4,901 for the quarter to 31 March 2026, a gain of 13.3%. The 3,952 reports on file for the quarter to 30 June 2026 are provisional: filings and amendments for that period were still arriving when this data was pulled, so the quarter is not comparable with the three before it. Counts include amendments, so a manager that amends appears more than once.

Aggregate 13F shares held across the whole filer base is not stated here: the three largest payloads repeatedly dropped the data session. BlackRock's Form 13F reads n/a for the quarters ended 30 September 2025, 31 December 2025 and 31 March 2026 for the same reason; only the quarter ended 30 June 2026 came back.

6.4 Schedule 13D and 13G, two years

No Schedule 13D has been filed on Exxon Mobil common stock in the two years to 31 August 2026. Every event in Table 6.3 is a passive Schedule 13G by an index manager. Two schedules were filed within five weeks of each other in the spring of 2026: The Vanguard Group reported out to zero on 26 March 2026 and Vanguard Capital Management LLC reported in at 7.51% on 29 April 2026.

Table 6.3 Schedule 13D and 13G events on Exxon Mobil common stock, September 2024 to August 2026

BlackRock has not filed a schedule on this stock since 26 January 2024, when it reported 272,498,849 shares, 6.9%, with sole voting power over 254,681,764. Its Form 13F says it held 334,746,496 shares at 30 June 2026. State Street's August 2026 schedule reports 207,041,423 shares against 206,811,526 on its Form 13F for the same date. The 229,897 share difference is shares held outside the Form 13F reporting entity, not an error in either filing.

6.5 The 2026 annual meeting

The meeting was held on 27 May 2026 for holders of record on 1 April 2026. Turnout was the highest of the five years covered here: 3,636,885,465 of 4,144,455,560 shares, 87.8%, against 83.9% in 2025, 83.8% in 2024, 83.1% in 2023 and 80.4% in 2022. New Jersey law does not count abstentions as votes cast, so every percentage below is votes for over votes for plus against.

Table 6.4 2026 annual meeting results

The 96.2% against Item 1 is the lowest of the twelve nominees, Darren W. Woods, who is also chairman and chief executive. Gregory C. Garland led at 98.7%.

Item 4, moving the state of incorporation from New Jersey to Texas, drew the most votes against of the six items: 28.8%, 896.9 million shares. It is also the only item with a different broker non vote count, 493,518,532 against 479,646,841 elsewhere, because a merger is not a routine matter and brokers had no discretion.

The two shareholder proposals drew 15.2% and 23.5% of votes cast. Their proponents held 106 shares and 927,471 shares respectively. Table 6.4 gives each item a short descriptive name; the company's own labels in the Form 8-K carry its position on the proposal, Item 5 being listed as "Independent Chair, a proposal overwhelmingly defeated on 16 separate occasions since 2000". The 150 million shares enrolled in the Voluntary Retail Voting Program are 4.8% of the votes cast on Item 5, and by the design of the program they were cast with the board, on 8 April 2026, the day the proxy statement was filed. Participants who elected the carve out for merger transactions did not have their shares voted on Item 4.

6.6 The proposal ballot, and the company's response to it

Table 6.5 Shareholder proposals put to a vote, 2022 to 2026

Support has fallen on both measures at once: fewer proposals reach the ballot, and those that do draw less. The peak was 2022, when a report on scenario analysis carried with 51.0%, the only shareholder proposal to pass in the five years. A year later the ballot ran to twelve proposals and the best result was 36.4%, for direct methane measurement. By 2024 the ceiling was 20.8%, for a report on plastic production. In 2025 no shareholder proposal reached the ballot at all, and in 2026 two governance proposals reached it and no climate or environmental proposal did.

Two things visible in the filings move alongside that record. Exxon Mobil tightened its own screening of which proposals reach the ballot, and it took two proponents to court. The filings do not measure how much of the decline each explains.

In January 2024 Exxon Mobil sued Arjuna Capital and Follow This in the Fort Worth Division of the Northern District of Texas over a resubmitted emissions proposal. The 2024 proxy statement puts the company's case in its own words: it sued "two parties who masquerade as investors with legitimate economic interest in ExxonMobil's success and sought to resubmit a proposal overwhelmingly rejected by investors last year", and said the intent of the suit was to get clarity on what the rules require for a process it described as ripe for abuse. Both proponents withdrew the proposal. On the course of the case the filings carry only what Exxon Mobil itself put on the record. Its definitive additional materials of 24 May 2024 quote a Glass Lewis report stating that "the District Court denied the defendants' motion to dismiss the case as moot at this time. The court also dismissed Follow This, but not Arjuna Capital, from the case, for lack of personal jurisdiction". The same letter reports a joint response filed that day in which "ExxonMobil and Arjuna agree that an assessment of these factors does not clearly demonstrate good cause to transfer this case" out of Fort Worth.

Glass Lewis opposed lead director Joseph L. Hooley over the suit, and Mercy Investment Services and Wespath Investment Management ran a vote no campaign against him. His support fell from 91.0% in 2023 to 87.1% in 2024, the lowest of the twelve nominees that year and 4.5 points below the next lowest. It was 98.2% in 2025 and 98.0% in 2026.

The 2026 proxy statement sets out the screen the company now applies, again in its own words: "In the current regulatory environment in which the SEC has largely deferred to companies in evaluating which proposals were appropriate to include on the ballot, we chose to use a straight-forward approach based on our historical experience with SEC no-action letters on excluded proposals. The merits or legitimacy of proposals were not considered." The company adds that one of the two proposals it did include went on the ballot "not because our analysis showed that it complied with Rule 14a-8".

Three figures set the register. Index managers held 23.7% of the shares at 30 June 2026 and reported voting authority over 9.2%. The Voluntary Retail Voting Program holds 150 million shares, 3.6% of the total, cast with the board. The 2026 redomiciliation vote drew 28.8% against, compared with 3.8% on the director slate and 7.1% on executive pay.

7 Insider Activity

ExxonMobil insiders sold 17,460 shares into the market in the twelve months to 31 August 2026, worth $2,395,656 at a weighted average of $137.21, and bought none. The buy to sell ratio is 0.00, computed on open market transactions only, Form 4 codes P and S, and excluding awards, tax withholding on vesting and gifts. All seven sales came from one reporting person and one revocable trust. Of the 23 insiders who reported a transaction in the window, 22 reported no market trade at all.

Gross movement across every common stock line on Forms 4 in the window is 1,209,499 shares. Of that, 1,192,039 shares, 98.6%, never touched the market. Narrow the frame to disposals alone, 150,164 shares under codes F, G and S, and the market still accounts for only 11.6%.

7.1 Open market against award driven activity

The window carries 51 Table I lines. Seven are open market sales. Thirty seven are award driven, the annual performance share grant and the tax withholding that follows each vesting. Seven are gifts made for no consideration. Net of everything, insider holdings rose by 909,171 shares, against 1,059,000 shares awarded by the issuer in the window.

Performance shares are more than 70% of total direct compensation for named executive officers, and each award vests 50% five years after the grant date and 50% ten years after it, with no acceleration except on the death of the holder. Nonemployee directors take 2,500 restricted shares a year and 8,000 on first election; while they serve, those shares "remain unvested and, thus, cannot be sold or pledged". The 1,059,000 shares awarded in the window are therefore locked for years, and the 38,000 that went to directors cannot reach the market at all on the terms granted.

The award cycle is a single date. On 25 November 2025 the compensation committee approved 1,021,000 performance shares across eleven executive officers, valued at $118,384,950 using the $115.95 price the issuer applied to the tax withholding it ran the same day. Darren W. Woods took 225,000 of them, Neil A. Chapman and Jack P. Williams Jr. 117,800 each. Withholding across 25 and 30 November and 2 December removed 109,364 shares at a weighted average $115.88, worth $12,673,384, none of it sold by any reporting person. Gifts moved 23,675 shares gross, of which 335 stayed inside Neil A. Chapman's reported holdings as an indirect interest for a dependent child.

Table 7.1 Nonderivative transactions reported on Forms 4 with a transaction date between 1 September 2025 and 31 August 2026, four groups of routine lines aggregated

Shares are signed, positive acquired and negative disposed. Codes are A award, F withheld for tax, G gift, S open market sale. Price is the price stated on the form; grants and gifts carry no price. Four groups of routine lines are aggregated onto one row each: the 25 November 2025 performance share grant, the withholding that followed it, the twelve director grants of 2 January 2026 and the four Chapman gift lines of 18 December 2025. The three largest individual grants are shown as components of that total. Table 7.2 carries every line by code.

Table 7.2 Window volume by transaction type

Value for the officer award line uses the $115.95 price ExxonMobil applied to the tax withholding on the same grant date, since the form itself reports a nil price.

7.2 The sales

Darrin L. Talley, Vice President, Corporate Strategic Planning, sold 17,460 shares in seven trades between 15 December 2025 and 16 March 2026, all from a revocable trust held jointly with his spouse. The first sale is at $118.75, the last at $155.495 and the highest at $157.8201 on 2 March 2026. The trust holds 17,124 shares after the last sale. His direct holding of 250,300.3012 shares is untouched by any of the seven trades.

The trust balance needs a reconciling item, and the filer does not supply one. The Form 4 of 25 August 2025 reports 13,829 shares in the revocable trust. The first sale in the window implies 34,584 shares immediately before it, an increase of 20,755 with no intervening Form 4. Two other lines fall by the same total: the direct holding drops 17,460 shares between 2 and 15 December 2025, and a spousal brokerage line of 3,295 shares disappears from the holdings table. A change in the form of beneficial ownership that leaves pecuniary interest unchanged is exempt from Form 4 reporting under Rule 16a-13, which is consistent with the filings as made. The 17,460 shares later sold equal the fall in the direct holding exactly. That reading is inferred from the holdings tables and is not stated by the filer.

No Form 4 in the window carries the Rule 10b5-1 affirmation, so none of the seven sales is reported as made under a trading plan. No Form 144 covering ExxonMobil common stock was filed in the window. The only Form 144 filed under the company's central index key in that period, on 20 May 2026, names ExxonMobil as the reporting person selling ProPetro Holding Corp stock.

Fourteen Form 4 filings since 1 January 2016 carry a code P line, the most recent on 17 June 2024, when director Maria S. Dreyfus bought 18,310 shares at $109.251. Twenty six months passed between that trade and the close of the window without an insider paying cash for stock on the market.

7.3 Form 3 filings and the officer turnover

Four Form 3 filings landed in the window, all from officer or board changes ExxonMobil had already disclosed on Form 8-K and chapter 5 records. Four Form 4 filings in the window report no transaction and tick the box marking the reporting person as no longer subject to Section 16.

Table 7.3 Form 3 filings and Form 4 exit filings, twelve months to 31 August 2026

The three officer opening balances are large because two holding conventions sit side by side in ExxonMobil's filings. The Form 4 holding column includes unvested performance shares; the proxy ownership table excludes them. Woods shows 1,955,449 shares after the November grant on Form 4 and 374,437 in the proxy table at 28 February 2026. The two figures are not comparable.

The reporting entity changed on 1 July 2026, on the redomiciliation merger chapter 5 sets out. Every equity award carried over on the same terms and for the same number of shares. No Form 3, 4 or 5 has been filed under ExxonMobil Holdings Corporation, central index key 2115436, through 4 September 2026, so the last two months of the window carry no insider filing of any kind. The last reported transaction of any code is 16 March 2026.

ExxonMobil discloses one late Section 16 filing, a Form 3 for M.R. Crocker's initial holdings in 2025, caused by "administrative processing delays during the preliminary stages required to obtain filing credentials". No other delinquency is disclosed.

8 Risk Factors

Exxon Mobil added no risk factor and dropped none. The FY2025 10-K carries the same 23 risk factors under the same four category headings as the FY2024 10-K, and 20 of the 23 were reworded. What moved is the balance of emphasis. Item 1A grew to 5,057 words from 4,592, a rise of 465 words or 10.1%, and 217 of those added words, 46.7% of the total, went into two factors: oil and gas supply expansion, and regulatory and litigation exposure. Climate change and the energy transition took 62 added words, and it is the one category where the language softened rather than hardened. Neither 2026 Form 10-Q carries a Part II Item 1A section: both were read in full, and the only reference to Item 1A in either is a cross reference in the forward looking statements note back to the 2025 Form 10-K. Item 1A has not been updated since 18 February 2026.

Supply and demand gained 191 words, up 20.5%, and government and political factors gained 174, up 18.3%. Operational and other factors, the largest block in both years at 1,626 words, gained 38, up 2.4%, and holds three of the four risk factors that did not change at all. Word count measures emphasis, not probability or severity, and Exxon Mobil places no quantified exposure inside Item 1A.

8.1 The largest changes in Item 1A

Downside price risk now reaches reported earnings. The lead paragraph of Supply and Demand says a material fall in oil or gas prices could hurt "the Company's operations, results, financial condition, and proved reserves, especially in the Upstream segment". The FY2024 version of that sentence omitted results. The same edit runs through the upside sentence on refining and chemicals. That paragraph gained twelve words net, and it frames every other risk in the item.

The added supply risk is government policy. Other supply related factors gained 109 words, the largest single move in the item, and the added text is about supply that governments release. Exxon Mobil now flags "government policies and actions intended to boost or expand development of domestic or foreign oil and gas reserves or accelerate the pace of production reaching markets", including "access to previously unavailable, sanctioned, or protected oil and gas resources". A year ago the supply factor listed only the ways supply is reduced: OPEC quotas, emission policy, funding withdrawal, war, natural disasters, competitor outages and logistics. The FY2025 item adds the case in which sanctions relief and pro supply policy raise supply.

Litigation risk is generalised and the European Union clause is removed. Regulatory and litigation risks gained 108 words. The FY2024 filing ended with the statement that adoption of similar legal practices "has begun to be applied to some of our competitors in the European Union". That clause is gone. In its place sits "Other jurisdictions adopting similar models to impose liability schemes on our products or operations may present similar risks." Class actions are named where the FY2024 item said only litigation or arbitration, and the damages exposure widens from punitive awards alone to "large and unpredictable punitive and non-economic damage awards". The change is from a named jurisdiction to an unnamed class of jurisdictions.

Government subsidy risk is now two sided. The FY2024 filing named actors who "reduce or retract government incentives for emissions reductions". The FY2025 filing names actors who "pause, reduce, or retract" them, and adds a new clause about actions that "disrupt or impact reliability as a result of policy decisions on types and pricing of energy available". Read with the supply factor, the two items describe policy that can withdraw support from the low carbon portfolio and raise hydrocarbon supply. The filing says the growth and future returns of the Low Carbon Solutions business "will depend in part on the development of stable and supportive government policies and markets".

Artificial intelligence enters Item 1A on both sides of the ledger. Neither the phrase artificial intelligence nor AI appeared in the FY2024 item. It appears five times in FY2025: as a demand driver, in "increased demand for artificial intelligence (AI), including the construction and expansion of AI data centers"; as a technology the company must capture; and as a dimension of competition. Data centres appear four times, all as "low-carbon data centers", a business Exxon Mobil now lists alongside carbon capture, hydrogen, ammonia, lower emission fuels, Proxxima resin systems, carbon materials and lithium as a venture whose market must still develop.

The climate ambition is narrowed and made conditional. The net zero ambition applies to Scope 1 and 2 emissions "from our operated assets", replacing the FY2024 formulation of emissions from operations "where ExxonMobil is the operator". The company changed from having an objective to play a leading role in the energy transition to one that "seeks opportunities to play a leading role". Two sentences are new: "Without supportive policies and the innovations they drive, net zero will remain out of reach for society and for ExxonMobil. Society's progress continues to lag in these areas." Elsewhere the phrase energy transition falls from eight mentions to six, replaced by "in a lower-emissions future". Alongside this, the Reputation factor adds "divergent and evolving societal views and investor pressures regarding a future energy transition" as a risk in its own right.

Opposition groups enter Item 1A as a permitting and legal risk. Access limitations now says host countries restrict leasing, licensing or permitting "directly or indirectly through the influence on these processes by well-funded local or international groups opposing the development of these resources". Lack of legal certainty adds host governments that cannot hold a clear framework "in the face of pressure on their systems from well-funded local or international groups opposing development of their resources". Regulatory and litigation risks adds "concerted efforts to increase our legal exposure by groups opposed to the products we provide". This is a project timing and permitting risk that did not exist in the FY2024 item in any form. Exxon Mobil names no project, no country and no group, so the exposure cannot be sized from the filing.

Capital allocation and reserves changed least. Item 1A carries no risk factor on the dividend or on share repurchases in either year, and none on reserve replacement beyond the exploration and project factors. The only capital allocation language is in Reputation, where a perception persists that pursuing the transition ambition "may result in allocation of capital to investments with reduced returns". The one named deal reference in the FY2024 item, "including the acquisition of Pioneer", was deleted.

8.2 The change map

Exxon Mobil does not head each risk factor with a numbered caption. It sets four category headings and, inside them, 23 bold lead phrases that function as the risk factor names. Table 8.1 follows that structure. The category lead paragraphs, which carry substance in Supply and Demand in particular, are shown without a number.

Table 8.1 Item 1A risk factor change map, FY2025 10-K against FY2024 10-K

Status counts: 0 new, 20 reworded, 3 unchanged and 0 dropped, against 23 risk factors in each year. Unchanged means word for word identical; the change in words column carries the size of every rewording. Two headings were renamed with no equivalent change in substance: the third category loses its article, and the safety factor loses the word environmental.

Table 8.2 Language that entered and left Item 1A, FY2025 10-K against FY2024 10-K

8.3 What cannot be read from Item 1A

Exxon Mobil places no number inside Item 1A. There is no reserve balance, no goodwill or long lived asset carrying amount, no litigation provision and no insurance retention figure in the item in either year, so the change in disclosure can be measured only in language and in weight. The two largest additions, the supply expansion risk and the liability scheme risk, name no country, no case and no counterparty, so neither can be sized from the filing.

9 Stock Price, Scenarios & Sensitivity

XOM trades at $162.21, the last trade of 3 September 2026 and not a session close, which values the 4,111,911,960 shares on the cover page of the Form 10-Q for the quarter ended 30 June 2026 at $667.0bn. That is 23.2 times FY2025 earnings excluding identified items of $6.99 a share and 14.5 times the first half of 2026 annualised at $11.20. The stock has risen 34.8% since the last close of 2025 and 165.1% since the last close of 2021, and sits 8.1% below the March 2026 high of $176.41. Oil equivalent production in the first half of 2026 was 4,554 thousand barrels daily, 37 thousand below the same half of 2025, while Brent averaged $92.56 a barrel in the half against $71.74 a year earlier and the indicative refining margin $22.6 a barrel against $12.6.

Three scenarios below run to FY2029 from an FY2026 estimated base. The best case implies $165.85 a share, the base case $113.42 and the worst case $58.76. The last trade sits above the base case by 43.0% and inside 2.2% of the best case. These are illustrations of a stated set of operating assumptions, not price targets and not a recommendation.

9.1 Where the price has been

The stock has added 34.8% in the eight months since it closed 2025 at $120.34, while the Middle East supply disruption took Brent to $104.52 in the second quarter of 2026 and global refining capacity closures took the indicative refining margin to $29.0 a barrel. Brent realised was $69.06 for 2025. The year end closes behind that run were $107.57 for 2024, $99.98 for 2023, $110.30 for 2022 as Brent averaged above $80, and $61.19 for 2021.

Table 9.1 Observed valuation, last monthly close of each year over that year's earnings

The multiple moves against earnings in every year observed. The lowest multiple, 8.3 times, sits on the highest earnings, $13.26 a share in FY2022. The highest, 18.0 times, sits on the lowest, $6.70 in FY2025. Pairing a high multiple with peak earnings would count the cycle twice, so the scenarios below do the opposite: the best case carries the lowest exit multiple and the worst case the highest. Every multiple used sits inside the observed range.

9.2 The drivers the scenarios turn on

Table 9.2 Operating drivers, FY2023 to the six months ended 30 June 2026

One row of that table changes basis partway across. The company published earnings excluding identified items through FY2025 and replaced it with adjusted earnings, which also removes estimated timing effects, from the first quarter of 2026, as chapter 3 sets out; the three annual columns are the older measure and the two half year columns the newer one, so the row is not a continuous series and the FY2025 to H1 2026 step should not be read as one.

Upstream took $13,664m from 4,554 thousand barrels daily at Brent $92.56 in the first half of 2026, against $21,354m from 4,736 thousand barrels daily at Brent $69.06 across the whole of FY2025. Depreciation and depletion reached $15,460m in the first half alone, an annual rate of $30,920m, against $25,993m for FY2025 and $20,641m for FY2023. Earnings excluding identified items fell $8,463m between FY2023 and FY2025, a 21.9% decline, while production rose 9.3% between FY2024 and FY2025 and refinery throughput rose 2.0%.

9.3 Three scenarios to FY2029

Table 9.3 Scenario assumptions and outcomes, three years to FY2029

Every input in the top half of Table 9.3 is a number, so each case can be rebuilt from this chapter alone. The engine is anchored on the first half of 2026 annualised, the most recent complete basis of operation: Upstream adjusted earnings of $30,908m on 1,662 million barrels of oil equivalent, $18.59 a barrel, at Brent $92.56, Henry Hub $3.96 and TTF $13.62. From that anchor the deck moves earnings at the sensitivities ExxonMobil discloses for 2026: $700m after tax for each dollar a barrel on Brent, $900m for each dollar a million British thermal units on Henry Hub and $200m on TTF, each on Upstream consolidated plus equity company earnings and excluding derivatives.

The FY2026 starting point is an estimate built here, not company guidance. It takes the reported first half adjusted earnings of $23,452m and adds a second half run at Brent $88.00, Henry Hub $3.60, TTF $14.00, an indicative refining margin of $22.00 and production of 4,700 thousand barrels daily, giving $45,562m for the year and $10.96 a share on 4,156 million diluted shares. On that estimate the last trade is 14.8 times FY2026 earnings.

The base case breaks in two identified places. It breaks if Brent settles below about $70, which takes the value to $86.63 and is a level the company realised as recently as FY2025 at $69.06. It breaks again if the market pays less than 11.5 times FY2029 earnings, which takes the value to $100.33 and is a multiple the stock traded at in three of the five years in Table 9.1.

9.4 What the best case needs

The crude deck has to hold near $95 a barrel, and no filing supports that. ExxonMobil discloses no price forecast anywhere in its Form 10-K or its Form 10-Q. It is the largest input in this chapter, and one of only two that no filing supports; the other is the exit multiple. The disclosed sensitivity puts the $15 a barrel gap between the best and base decks at $10,500m of Upstream earnings a year at 2026 volumes, more than the whole of Chemical Products and Specialty Products combined in any year in Table 9.2. The best case deck of $95 sits below the $104.52 the company reported for the second quarter of 2026 and above the $82.62 it reported for FY2023.

Guyana and the Permian have to add about 850 thousand barrels a day net. This is the one growth axis the filings underwrite with dated numbers, in Table 3.7. The best case takes group production to 5,400 thousand barrels daily by FY2029 from 4,554 in the first half of 2026, an 846 thousand barrel increment smaller than the Permian plan adds on its own by 2030, which leaves Guyana to cover decline elsewhere in the portfolio.

Refining margins have to hold at $18.0 a barrel, against $11.5 in the first quarter of 2025. The indicative refining margin ran at $11.5 a barrel in the first quarter of 2025 and $29.0 in the second quarter of 2026, and ExxonMobil's own worldwide refining capacity fell from 4,658 thousand barrels daily in FY2023 to 4,336 in FY2025 while utilisation rose from 87% to 92%. The best case holds $18.0 a barrel, above the FY2025 average of $15.2 and well below the second quarter of 2026.

Chemicals have to leave the bottom of the cycle without a demand recovery. North American polyethylene averaged $818 a tonne through FY2025, when Chemical Products earned $800m on 21,303 thousand tonnes of sales, and $1,210 in the first half of 2026, when the segment earned $1,241m on volumes 2.1% lower than the same half of 2025. The best case assumes $1,200 a tonne holds, worth $2,610m of segment earnings, above the $2,025m the segment earned in FY2023 excluding identified items and below the $2,672m it earned in FY2024.

The capital programme and the buyback have to be funded from operations. At the base deck the arithmetic does not close: cash from operations of $64,490m less a $30,000m capital programme and $18,069m of dividends leaves $16,420m against a $20,000m buyback, a shortfall of $3,580m a year that has to come from the balance sheet. The best case is the only one of the three that funds a larger programme, $33,000m, and a larger buyback, $25,000m, out of operations, with $9,840m to spare. Net debt to capital was 10.7% at 30 June 2026.

Unit costs have to keep falling faster than depreciation rises. Depreciation rose from $20,641m in FY2023 to an annual rate of $30,920m in the first half of 2026, against structural cost savings running at about $2.4bn a year. A range of $1.50 a barrel on net unit cost and depreciation is worth $9.54 a share in the base case, marginally more than a range of 600 thousand barrels daily of production.

9.5 Core assumptions and what drives demand

Volume drivers are barrels produced, barrels refined and tonnes sold; price drivers are Brent, Henry Hub, TTF, the refining margin and the polyethylene marker. Price has been carrying results: between the first half of 2025 and the first half of 2026 production fell 37 thousand barrels daily and adjusted earnings rose 61.1%, on the company's newer measure applied to both halves. Revenue behaves the same way. A least squares fit of revenue against Brent over the four annual observations the filings supply on a common basis, FY2023 to FY2025 and the first half of 2026 annualised, gives $123,649m plus $2,874m for each dollar a barrel, with an R squared of 0.801. Every revenue figure in Table 9.3 comes from that fit.

The exit multiple is an assumption with no basis in any filing. It is bounded by the observed history in Table 9.1: 8.3 times reported earnings at the FY2022 year end, 18.0 times at the FY2025 year end, with a five year median of 11.4 times. The base case uses 13.0 times, between the FY2023 observation of 11.2 and the FY2024 observation of 13.7, which bracket the base case earnings level. No case assumes a multiple XOM has not traded at within the last five years.

9.6 Sensitivity

Table 9.4 One way sensitivity on the base case, value a share of $113.42

Twenty dollars a barrel on Brent is worth $53.58 a share, twice the three turn exit multiple range and three times the six dollar refining margin range. Everything downstream of the deck is small: the capital programme, the buyback pace, the polyethylene marker, throughput, TTF, Specialty Products and the corporate charge together span less than the exit multiple on its own. That ranking follows from the sensitivity ExxonMobil publishes, $700m after tax for each dollar a barrel, against a share count of 3,804 million in the base case, which is 18 cents a share of annual earnings for every dollar of Brent before any multiple is applied.

The grid spans the deck and the multiple. At $75 Brent no multiple inside the five year observed range reaches the current price; the best of that row is $130.80 at 17.0 times. At $85 it takes almost 17.0 times, the top of the observed range. At $95, close to what the company reported for the second quarter of 2026, it takes between 13.0 and 15.0 times. Only the $105 row clears the price at a multiple near the five year median of 11.4 times. The highest full year Brent in Table 9.2 is $82.62, against a half year figure of $92.56.

9.7 What the filings do not say

ExxonMobil publishes no revenue, margin, earnings or earnings a share guidance. The only forward numbers in its filings are those in Tables 3.2, 3.7 and 3.8: the 2026 capital range, the firm capital commitments, the repurchase pace, Permian production of about 2.5 Moebd by 2030, eight Guyana vessels by year end 2030 and $20bn of structural cost savings. Every figure for FY2027 to FY2029 here is an estimate built from the drivers in Table 9.2, not a company projection.

The Brent, Henry Hub and TTF sensitivities are the company's own point estimates for 2026 and are described in the Form 10-K as broad indicators only. They are used here across ranges wider than the point they were struck at, and they are not linear over such a range: production sharing entitlements return more barrels to ExxonMobil at lower prices, which cushions the downside the sensitivity implies. The Energy Products and Chemical Products sensitivities are derived in this chapter and are not disclosed. The Energy Products figure of $826m a year for each dollar a barrel comes from the second quarter 2026 driver analysis, which attributes $3,180m of segment earnings to a refining margin $15.4 a barrel above the same quarter of 2025.

Marker benchmark data appears in the investor relations data summaries only from the first quarter of 2025 forward, so the refining margin and polyethylene rows read n/a for FY2023 and FY2024. The FY2025 marker averages are simple averages of four disclosed quarters, not company disclosed annual figures. ExxonMobil discloses a United States natural gas realisation of $0.52 a thousand cubic feet for the second quarter of 2026 against a Henry Hub marker of $2.90, and gives no explanation of the gap; that figure is carried as reported and not adjusted.

The price series in Figure 9.1 is continuous across the 1 July 2026 redomiciliation, on the one for one exchange chapter 5 sets out. Second quarter 2026 results were released by the successor, so the Form 8-K carrying them sits under a different central index key from every earlier release used here.

Sources

Every SEC filing cited in this document, ExxonMobil's and its peers', is retrieved through the SEC-API.io MCP server. Accession numbers are given with each table and, for the material events, in Table 5.1. Three classes of source sit outside that credit and are identified as such where they are used: market prices, the 31 July 2026 earnings call, and the December 2025 Corporate Plan Update, which was never filed.

Exxon Mobil Corporation: Forms 10-K for FY2022 (0000034088-23-000020), FY2023 (0000034088-24-000018), FY2024 (0000034088-25-000010) and FY2025 (0000034088-26-000045); Forms 10-Q for the first, second and third quarters of 2022, 2024 and 2025, and for the first (0000034088-26-000067) and second (0000034088-26-000093) quarters of 2026; Forms 8-K carrying the quarterly news releases and investor relations data summaries for the fourth quarters of 2021, 2023 and 2025, the second quarter of 2025 (0000034088-25-000040), the first quarter of 2026 (0000034088-26-000065) and the second quarter of 2026 (0002115436-26-000006); the definitive proxy statements of 8 April 2026 (0001193125-26-147614) and of 2024, and the Forms 3, 4, 5 and 144, Schedules 13D and 13G and Forms 13F named in chapters 6 and 7.

Peer filings: the Form 10-K, 20-F and 6-K accessions listed in Table 4.1 and in chapter 4. Sector volumes and the Brent price path come from the US Energy Information Administration, Short Term Energy Outlook, published 11 August 2026. Share prices and the price history are market data and carry no named provider; every market price is the last trade recorded on 3 September 2026, not a closing price, and the same price is used for every calculation that needs one. The 31 July 2026 earnings call quotations and the December 2025 Corporate Plan Update, neither filed on EDGAR, were each corroborated across two independent publications.

Figures as read from the filings are held in model.py; every ratio, bridge, per barrel figure and scenario is derived in analysis.py.

Disclaimer

This document is not financial advice. It is a financial analysis derived from public filings and other public sources, prepared for information only. It is not a recommendation, an offer or a solicitation to buy or sell any security, and it does not take account of the objectives, financial situation or needs of any reader. The scenarios, sensitivities and implied values in chapter 9 are illustrations of stated assumptions, not forecasts and not price targets. Figures are as reported at the dates stated and may since have been restated, corrected or superseded; market prices are as at 3 September 2026 and change continuously. No representation is made that the analysis is complete or free of error. Anyone acting on it does so on their own judgement, and should consider taking advice from an appropriately authorised adviser.