Analysis of the Form 10-K | Fiscal year ended 31/12/2025
FY2025, ended 31/12/2025. Data as of the fiscal year end. Market data: closing price of US$120.34 on 31/12/2025 and 4.18 billion shares outstanding, both supplied by the user. All amounts in US$ million unless stated.
What the company sells, to whom and how it is paid comes first. ExxonMobil finds and produces crude oil and natural gas, refines and trades fuels, and makes petrochemicals and specialty products. It sells mostly commodities at prevailing market prices under short-term agreements, with payment "typically due within 30 days" (Note 1). Four reportable segments carry the business: Upstream (exploration and production), Energy Products (fuels, aromatics, catalysts and licensing), Chemical Products (olefins, polyolefins, intermediates) and Specialty Products (lubricants, basestocks, synthetics, elastomers and resins). Low Carbon Solutions sits inside Corporate and Financing "until the business is established with a material level of assets and revenue".
External revenue badly describes where the money is made. Upstream sells most of its output to the other segments, so it shows only 12.2% of external sales but produced 74.0% of net income.
| Revenue by segment (external sales) | FY2025 | % of total | FY2024 | FY2023 | YoY FY2025 |
|---|---|---|---|---|---|
| Upstream | 39,389 | 12.16% | 37,131 | 25,574 | +6.08% |
| Energy Products | 244,451 | 75.47% | 260,856 | 268,383 | −6.29% |
| Chemical Products | 22,209 | 6.86% | 22,896 | 22,265 | −3.00% |
| Specialty Products | 17,771 | 5.49% | 18,253 | 18,407 | −2.64% |
| Other (residual) | 85 | 0.03% | 111 | 68 | n.m. |
| Total | 323,905 | 100.00% | 339,247 | 334,697 | −4.52% |
Energy Products carries three quarters of external revenue because refining resells purchased crude as fuel, and its revenue fell 6.29% with product prices. Upstream external sales grew 6.08% on higher volumes, while its prices fell.
| Revenue by geography | FY2025 | % of total | FY2024 | FY2023 | YoY FY2025 |
|---|---|---|---|---|---|
| United States | 137,639 | 42.49% | 138,657 | 127,374 | −0.73% |
| Non-U.S. | 186,266 | 57.51% | 200,590 | 207,323 | −7.14% |
| Total | 323,905 | 100.00% | 339,247 | 334,697 | −4.52% |
Canada is the only non-U.S. country disclosed separately, at 27,363. Regular employees fell from 60.9 thousand to 57.9 thousand. The signatories changed: Neil A. Hansen became Chief Financial Officer on 1 February 2026, and the proxy records the previous CFO's last day as 31 January 2026. Two items are new this year: restructuring charges of 419, booked in Corporate and Financing with no explanatory note, and a 364-day revolving credit facility of 7.0 billion set up in the fourth quarter.
The fact that frames the rest is that the revenue line is mostly purchased crude and products passed through refineries plus excise taxes, and the profit sits in a segment whose external sales are small.
Cyclical. The document states that "the oil, gas, and petrochemical businesses are fundamentally commodity businesses". Two figures confirm it. Upstream lost 6.1 billion of earnings to "lower realizations" in 2025, and Chemical Products earnings fell from 2,577 to 800 as margins stayed "deeply bottom-of-cycle". It is not an asset play, because the value of the assets depends on the same prices that drive earnings; it is not a turnaround, because net income was 28,844.
Three questions decide this case.
The pairs that govern the model, one per segment that moved the year: Upstream volume (oil-equivalent production) with earnings per barrel produced; Energy Products refinery throughput with earnings per barrel processed; Chemical Products tonnes sold with earnings per tonne.
Mute metrics for this company: gross margin (no cost of goods sold is presented, and revenue embeds purchased crude and excise taxes), revenue growth (it moves with pass-through prices), the price/earnings-to-growth ratio, R&D productivity (1,228 against 323,905 of revenue), and dilution from stock compensation, which is small against the buyback. The sections that go deep are 3-quinquies, 3-septies and 5-bis, with 3-bis on reserves.
The question is what the document shows about protection from competition, and the evidence is cost and scale rather than pricing. Average production cost was US$10.20 per oil-equivalent barrel against a realized crude price of US$65.18. Non-U.S. Upstream earned a 17.7% return on average capital employed even at 2025 prices. Proved reserves of 19,311 million oil-equivalent barrels cover 10.96 years of the 2025 production recorded in the reserves tables. The company also claims "the largest refining footprint among international oil companies" and "over 8 thousand active patents"; these are statements of the company, not measurements.
Two figures limit the case. Chemical Products earned 2.7% on its capital, so integration did not shield that segment from oversupply. U.S. Upstream, where Pioneer was added, earned 4.3%. Whether the advantage is widening or narrowing cannot be established from the document.
There is none on the main products, and the figures say so. Realized crude fell 14.50%, and Brent fell 14.49% over the same year. The document describes refining and chemical earnings as "primarily determined by margin capture rather than absolute price levels". The only segment whose unit earnings held is Specialty Products: about 367 dollars per tonne in 2025, between the 357 of 2023 and the 398 of 2024. Its return on capital employed was 35.4%. It is 9.9% of 2025 net income.
Pioneer closed on 3 May 2024, so 2025 carries twelve months of it against eight in 2024, and the document does not report Pioneer's 2025 contribution. The cleanest comparison it allows is against the unaudited pro forma 2024, which assumes Pioneer was owned all year. Against that base, revenue was 6.76% lower and net income 16.34% lower. On volumes, the reconciliation attributes 525 thousand barrels per day of growth to "Growth/Other" and subtracts 133 for divestments. Divested businesses in 2025 (France refining and chemicals, Singapore retail fuels, Argentina, U.S. assets) are named, but their revenue and earnings are not.
Costs grew while revenue fell. Against revenue down 4.5%, production and manufacturing expenses rose 7.1% and SG&A 11.5%. Depreciation rose 10.9% and exploration 21.9%. Part of this is new capacity entering the cost base (full-year Pioneer, Tengiz depreciation, the China complex ramp-up), which the driver analysis names. Per unit the picture differs: production cost per barrel fell 3.1%. The company also reports cash operating expenses excluding energy taxes of 44.1 billion, level with its 2019 figure of 44.0 billion. Inflation and new activity were offset by 15.1 billion of cumulative savings (a non-GAAP company measure). The company runs a larger volume on a flat cash cost base; the earnings did not follow because price fell faster.
The question for the income statement is which lines moved the 14.4% fall in net income.
| FY2025 | FY2024 | FY2023 | Δ 25/24 | Δ 24/23 | |
|---|---|---|---|---|---|
| Sales and other operating revenue | 323,905 | 339,247 | 334,697 | −4.5% | +1.4% |
| Income from equity affiliates | 5,064 | 6,194 | 6,385 | −18.2% | −3.0% |
| Other income | 3,269 | 4,144 | 3,500 | −21.1% | +18.4% |
| Crude oil and product purchases | 184,248 | 199,454 | 193,029 | −7.6% | +3.3% |
| Production and manufacturing | 42,424 | 39,609 | 36,885 | +7.1% | +7.4% |
| SG&A | 11,128 | 9,976 | 9,919 | +11.5% | +0.6% |
| Depreciation and depletion (incl. impairments) | 25,993 | 23,442 | 20,641 | +10.9% | +13.6% |
| Exploration | 1,007 | 826 | 751 | +21.9% | +10.0% |
| Non-service pension | 400 | 121 | 714 | n.m. | n.m. |
| Interest expense | 603 | 996 | 849 | −39.5% | +17.3% |
| Other taxes and duties | 25,167 | 26,288 | 29,011 | −4.3% | −9.4% |
| Income before income taxes | 41,268 | 48,873 | 52,783 | −15.6% | −7.4% |
| Income tax | 11,504 | 13,810 | 15,429 | −16.7% | −10.5% |
| Noncontrolling interests | 920 | 1,383 | 1,344 | −33.5% | +2.9% |
| Net income attributable | 28,844 | 33,680 | 36,010 | −14.4% | −6.5% |
| Diluted EPS (US$) | 6.70 | 7.84 | 8.89 | −14.5% | −11.8% |
| EBIT (construction) | 41,871 | 49,869 | 53,632 | −16.0% | −7.0% |
| EBITDA (construction) | 67,864 | 73,311 | 74,273 | −7.4% | −1.3% |
The income statement has no gross profit or operating income line. EBIT is built here as pre-tax income plus interest expense; it is not a company figure, it includes income from equity affiliates (which is after the affiliates' own taxes) and other income, and it serves only to put interest and enterprise value on a common footing. EBITDA adds back depreciation and depletion, including impairments.
Net income fell by 4,836, and Upstream accounts for 4,036 of it. Energy Products added 3,390 on better refining margins, Chemical Products lost 1,777, and Corporate and Financing lost 2,218.
The balance sheet question is how much debt stands ahead of the shareholder and how fast it changed.
| 31/12/2025 | 31/12/2024 | |
|---|---|---|
| Cash and cash equivalents (unrestricted) | 10,681 | 23,029 |
| Bank loans | 3 | 63 |
| Commercial paper | 3,059 | — |
| Long-term debt due within one year | 6,234 | 4,892 |
| Long-term debt (incl. finance leases and other obligations 6,313 / 3,951) | 34,241 | 36,755 |
| Total debt (operating leases excluded) | 43,537 | 41,710 |
| Net debt | 32,856 | 18,681 |
| Operating lease liabilities (outside debt) | 6,834 | 6,478 |
| ExxonMobil share of equity | 259,386 | 263,705 |
| Noncontrolling interests | 7,240 | 6,901 |
| Net debt / (net debt + total equity) | 11.0% | 6.5% |
Net debt rose by 14,175 in one year, almost entirely through lower cash; gross debt rose only 1,827. Including operating leases, debt would be 50,371.
The cash flow question is how much of the earnings arrived as cash and where it went.
| FY2025 | FY2024 | FY2023 | |
|---|---|---|---|
| Cash from operations | 51,970 | 55,022 | 55,369 |
| Additions to PP&E (capex) | 28,358 | 24,306 | 21,919 |
| Free cash flow (CFO − capex) | 23,612 | 30,716 | 33,450 |
| Stock-based compensation cost | ~1,000 | ~800 | ~600 |
| Free cash flow less SBC | ~22,612 | ~29,916 | ~32,850 |
| Dividends to ExxonMobil shareholders | 17,231 | 16,704 | 14,941 |
| Buybacks (cash) | 20,273 | 19,629 | 17,748 |
| Income taxes paid in cash | 11,563 | 13,293 | 15,473 |
Free cash flow here uses additions to PP&E from the cash flow statement. The company's "Cash Capex" (28,997) adds net advances to equity companies and nets inflows from partners; it lowers free cash flow by 639 and is not used as the base.
Owner earnings, built from net income including noncontrolling interests plus every non-cash line of the cash flow statement less capex, equal 31,340 before working capital and 23,612 after it. Stock compensation is not subtracted again, since net income already bears it. Owner earnings without working capital exceed free cash flow by 7,728, which is exactly the working capital the business absorbed in 2025 (mostly inventory and receivables). The report uses the version with working capital, which here equals free cash flow, because a refiner that must carry more crude to sell its products is committing capital.
Stock compensation is not the dilution question here. Compensation cost was about 1.0 billion, 4.9% of the cash spent on buybacks.
The metrics answer two questions: what the capital earns, and how much strain the debt puts on earnings.
| FY2025 | FY2024 | FY2023 | |
|---|---|---|---|
| ROCE, company definition | 9.3% | 12.7% | 15.0% |
| ROIC (construction, year-end capital) | 10.08% | 12.37% | 17.06% |
| Debt / EBITDA | 0.64x | 0.57x | 0.56x |
| Net debt / EBITDA | 0.48x | 0.25x | 0.13x |
| EBIT / interest expense | 69.4x | 50.1x | 63.2x |
| EBIT / total cash interest paid | 23.9x | 26.2x | 30.9x |
| Free cash flow / net income | 81.9% | 91.2% | 92.9% |
ROIC is a construction: NOPAT (EBIT times one minus the consolidated book tax rate of 27.88%) over invested capital (total debt plus total equity less cash). On average capital it is 10.26%. The company's ROCE of 9.3% is lower because its capital base adds ExxonMobil's share of equity-company debt and its numerator excludes all financing items, including a net financing gain in 2025 (section 6).
Interest coverage has two legitimate bases and they diverge. Interest expense on the income statement fell 39.5% while total cash interest paid fell only 7.8%. The gap comes from capitalization: the capitalized share of interest paid rose from 67.2% to 87.6%. On cash interest, coverage fell. Long-term debt equals 1.19 years of 2025 net income, and cash interest equals 4.2% of EBIT.
The multiples use the closing price of US$120.34 on 31/12/2025 and 4.18 billion shares, both supplied by the user: the price date matches the fiscal year end so that numerator and denominator describe the same moment. Market capitalization is 503,021 and enterprise value 543,117 (adding total debt and noncontrolling interests, subtracting cash; operating leases and the 2,793 share of equity-company debt are excluded).
| Multiple at US$120.34 | Value |
|---|---|
| P/E on FY2025 EPS | 17.96x |
| P/E on earnings excluding Identified Items | 17.21x |
| P/E on FY2023–FY2025 average EPS (7.81) | 15.41x |
| P/E on the highest EPS of the three years (FY2023, 8.89) | 13.54x |
| Price / free cash flow | 21.30x (free cash flow yield 4.69%) |
| EV / EBITDA | 8.00x |
| EBIT / EV | 7.71% |
| Price / book value per share | 1.94x |
| Dividend yield (US$4.00 paid) | 3.32% |
| Dividends plus buybacks / market capitalization | 7.46% |
At this price a buyer pays about 18 times 2025 earnings and 21 times 2025 free cash flow. The company handed back cash equal to 7.46% of its market value, while the business generated free cash flow equal to 4.69% of it; the difference came out of the balance sheet.
The notes selected below are those flagged by the auditor or by management as critical estimates, or those above 5% of assets, revenue or pre-tax income.
Proved reserves and upstream PP&E (critical audit matter). Upstream PP&E is 228,235 net, 50.8% of total assets, and its depreciation of 21.4 billion depends on proved reserves through the unit-of-production method. The auditor's matter cites "the significant judgment by management, including the use of management's specialists". Two movements in 2025 show the discretion: consolidated revisions cut 929 million barrels (5.5% of opening consolidated reserves), and "approximately 1.0 GOEB of proved undeveloped reserves which no longer met the SEC definition" were reclassified, "primarily in the United States". The document does not say why they no longer met the definition. Lower SEC prices, a slower development schedule or the five-year development rule would all move reserves down and per-barrel depreciation up; the document gives no sensitivity.
Impairments and unproved property. Impairments were about 2.0 billion before tax (Upstream 1.6), including assets written down to fair value as held for sale and "the optimization of materials and supply inventory". Tests use "the assumptions developed in the Corporate Plan" for prices and margins, which are not disclosed, and the company states it is "not practicable to reasonably estimate the existence or range of any potential future impairment charges". Unproved property costs are 47,892, 10.7% of total assets, assessed against "future development plans, the estimated economic chance of success". They fell by 7,189 in 2025 while proved property costs rose 5,386, a shift the document does not explain. Suspended exploratory wells total 3,286, of which 959 have been capitalized for more than ten years. Write-offs rose to 432 in 2025 from 69 a year earlier.
Income taxes. The company's effective rate fell to 31% from 33% "due primarily to favorable one-time items", which are not quantified. The consolidated book rate was 27.88%. The largest reconciling line is the United Arab Emirates rate differential of 3,405, eight points of the rate; the UAE alone took 5,000 of cash taxes. Cash taxes were within 59 of the expense. The valuation allowance on deferred tax assets is 2,649 (up 133), against 4,740 of tax-loss assets whose expiry is not given. Unrecognized tax benefits are 4,131, with U.S. federal years open since 2010; favorable resolution would lower the rate, and the company says unfavorable resolution "generally would not increase" it.
Asset retirement obligations. The liability is 12,518. Upward cost revisions added 1,154 in 2025. Revisions were also upward in 2024 and 2023 (689 and 1,636), so the estimate has risen in each year shown. Discount and inflation rates are not disclosed. Payments are guided at 1.3 billion in 2026 and 1.5 billion in 2027.
Pensions and other postretirement benefits. Net underfunding is 6,352, of which 4,508 is other postretirement benefits, and most of it sits in unfunded plans that the company pays from its own cash. A cut of half a point in the expected return on assets would add about 150 million of annual pension cost. The document states that all obligations "are fully supported by the financial strength of the Corporation" and does not discuss their ranking against other creditors.
Litigation. Climate-change suits by U.S. state and local governments and Louisiana coastal suits carry no accrual and no estimate of possible loss; the company judges a material adverse outcome "remote". No figure exists for these cases. Environmental liabilities on the balance sheet are 0.9 billion.
Debt. Maturities are modest against cash flow: 6,234 falls due in 2026 and about 2.5 billion in 2027. The years 2028 and 2029 carry about 1.7 billion each, and 2030 about 5.3 billion. Notes are fixed-coupon; some are swapped to floating through fair value hedges of undisclosed notional. No covenants are described, and there are no convertible instruments.
Stock-based compensation. Cost was 1.0 billion, with 2.7 billion not yet recognized over a weighted 4.6 years. Awards are restricted stock units that vest half after three and half after seven years for most employees, and after five and ten years for senior executives.
Revenue presentation. Excise-type taxes for which the company is not the government's agent are reported gross, inside both revenue and "other taxes and duties" (25,167). 96,996 of revenue (29.9%) is outside the revenue standard, mainly physically settled commodity derivatives, and trading results enter revenue net (a gain of 1.1 billion in 2025). Contract liabilities and remaining performance obligations are "not significant" or "fully constrained", so no backlog measure exists.
Inventories at LIFO. Replacement cost exceeds the LIFO carrying value by about 7 billion, down from about 10 billion. LIFO effects added 0.3 billion to 2025 net income. A drawdown of old layers would release part of that gap into earnings, and the document does not say how much of the 2025 change came from the France divestment.
Commitments outside the balance sheet. Take-or-pay and unconditional purchase obligations total 54.1 billion, with 6.3 billion due in 2026. Firm capital commitments are 8.5 billion for 2026 and 8.0 billion beyond. Guarantees are 6,852, and leases not yet commenced add 3.8 billion. These are capacity and spending already promised that do not appear in capex or debt.
Equity companies. Investments of 32,653 produced income of 5,064. Their cash dividends ran 3,006 above those earnings, a jump analysed in 3-quater that the document does not explain. Goodwill and intangibles are not broken out: the only goodwill figure is about 1 billion from Pioneer, and no impairment headroom is disclosed. Related-party disclosures are limited to equity companies (10% of their revenues are sales to ExxonMobil) and, in the proxy, four relatives of executives employed at pay between US$120,000 and US$500,000. Subsequent events: a quarterly dividend of US$1.03 declared on 29 January 2026 and the CFO change.
The notes move the reading in one direction: half the asset base depends on reserves estimates whose 2025 revisions were negative, and the price assumptions that protect those assets from impairment are not published.
This section explains what sits inside the large lines. PP&E is 66.7% of total assets and investments and advances 10.1%. Receivables (9.9%) and crude and product inventories (5.1%) also exceed the five-percent line. On the funding side, equity is 59.4% and accounts payable and accruals 13.6%. Deferred tax liabilities (9.0%), long-term debt (7.6%) and other long-term obligations (5.8%) complete the list.
PP&E (299,373) is carried at cost less 270,686 of accumulated depreciation; three quarters of it is Upstream, covered in 3-bis. Investments and advances (45,317) are mainly equity-method stakes in LNG, pipeline and petrochemical ventures. They include advances of 6,130 to those ventures, of which 3,938 are valued with unobservable (level 3) inputs. Receivables of 44,562 include 8,818 of "other" receivables, and part of the trade balance comes from physically settled derivatives. Accounts payable (60,911) include 8,694 owed to equity companies. Deferred tax liabilities (40,216) arise mainly from PP&E (41,427 of gross liabilities), and include about 16 billion recorded on the Pioneer acquisition. Other long-term obligations of 26,178 contain long-term asset retirement obligations (11.3 billion) and long-term operating lease liabilities (4,892). The remaining 9,986 is itemized only in part: the fair value note places other long-term financial liabilities of 364 and part of the derivative liabilities in this line, and nothing breaks down the rest.
Goodwill and intangibles are not separately reported; "Other assets, including intangibles" (20,908) also holds operating lease right-of-use assets (7,224), deferred tax assets (3,759) and overfunded pension assets. Cash of 10,681 carries no restriction at year end (158 was restricted a year earlier), so net debt uses all of it.
| Working capital in days (year-end balances, 365 days) | FY2025 | FY2024 |
|---|---|---|
| Days of trade receivables (on revenue) | 40.3 | 38.0 |
| Days of crude and product inventory (on purchases) | 45.5 | 35.6 |
| Days of trade payables (on purchases) | 71.4 | 66.1 |
| Cash conversion cycle | 14.4 | 7.4 |
Only two balance sheets are presented, so this is a single comparison. Inventory days rose by ten because the LIFO carrying value rose 18.2% while purchases fell 7.6%. At replacement cost (carrying value plus the disclosed LIFO gap) inventory moved only from about 29,444 to about 29,979, so most of the 18.2% rise is the LIFO carrying value moving toward current prices rather than a larger replacement value of stock. The document does not split the change into volume and price.
Equity contains treasury stock of 258,395 at cost, nearly equal to the 259,386 of ExxonMobil's equity itself. Return on year-end equity is 11.12%; with treasury stock added back to equity, so that past buybacks do not shrink the denominator, it is 5.57%. Retained earnings rose 11,591 in 2025 and 16,976 in 2024, the difference being lower net income and higher dividends. That line understates the capital the company keeps, because buybacks reduce treasury stock rather than retained earnings; read alone, the stagnation would mislead.
Of total assets, 12.3% are cash and receivables with near-contractual values. PP&E at depreciated cost is 66.7%, depreciated at a rate set by management's reserves estimates, and level 3 financial assets add 5,738. Little of the balance sheet rests on an observable market price.
Cash from operations of 51,970 starts from net income including minorities of 29,764 and adds depreciation and depletion of 25,993. Working capital took 7,728, mostly inventory (4,300) and receivables (3,042), and the remaining lines net to a small positive. One line stands out: dividends from equity companies exceeded their booked earnings by 3,006, against 191 in 2024. Without that line, cash from operations would have fallen 10.7% rather than 5.5%.
Free cash flow fell by 7,104, and the increase in working capital absorbed (5,902) explains 83.1% of that fall. Before working capital, owner earnings fell only 3.7%. The direction matters: working capital depressed 2025 free cash flow rather than flattering it, and a reversal would lift 2026 free cash flow without any change in the business.
The question here is whether the capital added since 2023 is earning, and what each share received from it.
| Per share (average diluted shares) | FY2025 | FY2024 | FY2023 | Δ 2023–2025 |
|---|---|---|---|---|
| Revenue | 75.24 | 78.93 | 82.60 | −8.9% |
| Net income | 6.70 | 7.84 | 8.89 | −24.6% |
| Free cash flow | 5.49 | 7.15 | 8.26 | −33.6% |
| Equity | 60.25 | 61.36 | 50.54 | +19.2% |
| Average diluted shares (million) | 4,305 | 4,298 | 4,052 | +6.2% |
Total net income fell 19.9% over the two years and per-share net income fell 24.6%: the average share count rose 6.2% because the Pioneer shares outweighed the buybacks. Equity per share rose because the shares were issued at a market price well above book value. The company's year-end book value per share (62.07) uses year-end shares and is higher than the 60.25 shown here.
Incremental return. Between 2023 and 2025, NOPAT fell by 7,756 while invested capital rose by 76,939, so the incremental return is negative 10.1%. This is two years of data and a single point, and it mostly measures price. Using the company's own sensitivity of about 700 million after tax per dollar of Brent, the fall in Brent between 2023 and 2025 is worth about 9.5 billion of Upstream earnings, more than the whole fall in NOPAT. The incremental capital is therefore not shown to be destroying value; at 2025 prices it is not shown to be earning either. U.S. Upstream, where Pioneer's assets sit, earned 4.3% on 118 billion of average capital employed.
Reinvestment and implied growth. In 2025 net reinvestment (capex less depreciation, plus net advances to equity companies, plus working capital) was 10,820, or 35.8% of NOPAT. At a 10.08% return that implies growth of about 3.6%; operating profit (EBIT) actually fell 16.0%. The gap is price, not a failure of reinvestment. Depreciation in 2025 also contains about 2.0 billion of impairments, which reduces measured net reinvestment.
On how much of its earnings the company can reinvest at that return, 2025 gives a plain answer: it distributed 130.0% of net income and reinvested about a third of NOPAT. At these settings ExxonMobil does not compound its return inside the business; it pays it out, and in 2025 paid more than it earned. That describes a business run for distribution, and it means the per-share outcome depends on the price paid for buybacks (section 5-bis) rather than on retained earnings compounding.
What would remain if growth stopped. The document does not separate maintenance from growth capex. Using depreciation as a proxy for maintenance, cash from operations before working capital (59,698) less depreciation (25,993) leaves 33,705. The proxy is weak in this business: the document says tight-oil plays "have higher initial decline rates", and most 2025 Upstream capex went to Permian and Guyana growth. Growth spending here is in capex, not in selling expenses.
Self-financing. Over three years, free cash flow totalled 87,778. Net debt flows were an outflow of 5,198, and no shares were sold for cash; 68,196 of shares were issued as acquisition consideration (Pioneer and Denbury). The company financed itself internally in cash terms and used its own stock for acquisitions.
Capital intensity. Capex was 1.09 times depreciation in 2025, after 1.04 and 1.06 in the two earlier years. Removing the roughly 2.0 billion of impairments from 2025 depreciation lifts the ratio to 1.18. Cumulative capex was 75.7% of cumulative net income. Capacity is expanding modestly, and the expansion is concentrated in Permian, Guyana and LNG.
Operating return on enterprise value. EBIT over EV is 7.71% at the given price.
A price/earnings-to-growth ratio is omitted: earnings fell in both years, and on two years the figure would mean nothing. R&D spending of 3,094 over three years is spent, not capitalized, and is too small against revenue to measure.
Each comparison sets two growth rates side by side for 2025 against 2024, with the gap in percentage points.
Five of the six comparisons diverge by more than five points, and one of them, the allowance, moves in the reassuring direction. None shows an allowance being thinned or revenue running ahead of cash. Two of them (capitalized interest, and cash from operations without the affiliate dividends) suggest that the reported interest line and the reported cash flow both look better than the underlying run-rate.
The sector is integrated oil and gas with refining and petrochemicals: energy, commodities and heavy industry. The useful metrics are volumes, realized prices, unit costs, reserves and their replacement, utilization, and the price sensitivity the company discloses.
The metric that governs the model is a pair: how many barrels the company produces and how much it earns on each. Upstream earnings per barrel is the Upstream segment's net income divided by oil-equivalent production for the year. It is not a company measure; it is built from two published figures, segment earnings in Note 3 and production in Item 2 (gas converted at six thousand cubic feet per barrel, 365 days). It mixes price, cost, tax and depreciation in one number, and that is the point: it is what each barrel left for shareholders.
| Upstream | FY2025 | FY2024 | FY2023 |
|---|---|---|---|
| Production (thousand oil-equivalent barrels per day) | 4,736 | 4,333 | 3,738 |
| Earnings per barrel produced (US$) | 12.35 | 16.05 | 15.62 |
| Realized crude price (US$/bbl) | 65.18 | 76.23 | 77.92 |
| Production cost (US$/boe) | 10.20 | 10.53 | 10.63 |
Volume rose 9.3% and earnings per barrel fell 23.1%. The company's driver analysis decomposes the 2,928 fall in Upstream earnings before identified items:
The mechanism is visible: volume growth and cost savings together added 3.3 billion, and price took nearly twice that. At 2023's Brent and 2025 volumes, the disclosed sensitivity puts Upstream earnings at about 30.8 billion, so roughly 31% of the earnings that a 2023 price would have produced was absent in 2025. The sensitivity is stated for 2026, excludes derivatives, and ignores how production-sharing contracts return barrels to the company when prices fall (price-related entitlement effects added 45 thousand barrels per day in 2025).
What the document does not publish: earnings or unit costs for Permian, Guyana or LNG separately; Pioneer's 2025 contribution; per-field decline rates; and the price deck used in impairment tests.
Energy Products: throughput and earnings per barrel processed. Throughput was 3,979 thousand barrels per day, against 3,900 in 2024. Earnings per barrel processed were US$5.11, against US$2.83 and US$8.18. Volume barely moved (+2.0%) and unit earnings rose 80.6%: the year was margin, which the company attributes to "robust demand and supply disruptions" (+1.8 billion). It also contains a 720 gain on non-U.S. asset sales, inside net identified items of 483; before identified items the figure is US$4.78. The document does not give a realized refining margin, so the earnings per barrel is the only unit measure.
Chemical Products: tonnes sold and earnings per tonne. Sales rose 9.9% to 21,303 thousand tonnes. Earnings per tonne fell from about US$133 to about US$38, or US$50 before identified items. The document states the cause in one line: margins were "below the 10-year historical range (2010-2019), as capacity additions have far exceeded demand growth". In the same year ExxonMobil started up its own China complex with "a combined capacity of over 2.5 million metric tons per year", equal to 11.7% of its 2025 chemical sales. Non-U.S. chemical volumes grew 16.0% while non-U.S. chemical earnings turned to a loss of 103. The company is adding capacity at the bottom of its own cycle, on the stated premise that the plant serves Chinese demand "currently being met with imports".
Specialty Products earns about US$367 per tonne on flat volumes and moved earnings by 195; it is described in section 2. Corporate and Financing moved earnings by 2,218 but has no volume to pair with.
Proved reserves are 19,311 million barrels, 36% of them undeveloped, and cover 10.96 years of the production recorded in the reserves tables. Organic reserve replacement (extensions plus revisions over production, a construction) was 64.8% in 2025. It was 153.3% in 2024 and 45.4% in 2023, so the single year says little. Refinery utilization is not disclosed as a percentage. The standardized measure of discounted future cash flows fell 19.7% to 149,129; the company says it "does not provide a reliable estimate" of value and it is not used here.
Standard metrics that are not meaningful for this company: gross margin, revenue growth, days of receivables as a credit signal (much of the balance is commodity trading), the price/earnings-to-growth ratio, and R&D productivity.
The risks below come from the risk factors and notes of the document, in order of weight for this case; three of them have already materialized in 2025.
The first three risks are linked: a lower price reduces free cash flow, widens the gap with distributions, and raises the chance that reserves are revised and assets impaired in the same year.
The document does not declare which risk factors were added or removed, and the prior-year 10-K was not provided. The comparison is not possible.
Who controls the company, and who checks it, is set out in the 10-K and the proxy. Darren W. Woods is Chairman and Chief Executive Officer; the board keeps the roles combined, with an independent Lead Director (Joseph L. Hooley). Neil A. Hansen became CFO on 1 February 2026. Three holders report more than five percent: The Vanguard Group (10.4%), BlackRock (6.5%) and State Street (5.1%), on filings of different dates. Directors and executive officers together own 1,315,797 shares, about 0.03%; the CEO owns 374,437 shares. PricewaterhouseCoopers has audited the company "since 1934". The proxy reports no related-person transactions beyond four relatives of executives employed at pay between US$120,000 and US$500,000, and one late Form 3 filing. A new "Voluntary Retail Voting Program" lets retail holders give a standing instruction to vote with the board's recommendations; the proxy states that about 38% of shares are held by individual investors.
1. Capital allocation. The three years in the document show where the money came from and where it went.
| FY2023–FY2025, cash | US$ million |
|---|---|
| Cash from operations | 162,361 |
| Asset sales and returns of investments | 12,223 |
| Collections of advances, other investing | 6,894 |
| Capex | (74,583) |
| Investments and advances to equity companies | (10,427) |
| Dividends to ExxonMobil shareholders | (48,876) |
| Buybacks | (57,650) |
| Net debt repaid | (5,198) |
| Noncontrolling interests, contingent payments, cash acquired, FX (net) | (3,728) |
| Change in cash | (18,984) |
Operations supplied 162,361 and shareholders received 106,526, or 121.4% of three-year free cash flow. The gap was closed by asset sales and by running down cash. The composition shifted in 2025: buybacks stayed at about 20 billion while free cash flow fell by 7.1 billion, so the share of distributions funded from the balance sheet rose. The largest capital decision of the period was non-cash: Pioneer, paid with 545 million shares valued at 63,352 plus 5 billion of assumed debt. Pioneer was recorded at about 84 billion of PP&E and about 1 billion of goodwill; no impairment of Pioneer assets is reported.
The decisions of 2025, read together, point one way. The company sold refining and chemicals in France, retail fuels in Singapore, Argentina and U.S. assets (proceeds 3.2 billion), and exited Thailand upstream. It started a wholly owned chemical complex in China, sanctioned Hammerhead in Guyana, funded Gorgon Stage 3, and bought graphite technology for battery materials. It cut headcount by 3,000 and booked 419 of restructuring. It kept buybacks at 20 billion while cash fell 12.3 billion. It issued 3,059 of commercial paper and set up a 7.0 billion 364-day credit line. The resulting balance sheet enters 2026 with 10,681 of cash against 9,296 of short-term debt. Ahead of it stand 8.5 billion of firm capex commitments and a stated 20 billion buyback. Portfolio decisions moved capital toward U.S. and Guyana Upstream and toward chemicals in Asia, away from European refining. The financing decisions moved the cost of the 2025 distribution onto the balance sheet. Next year's statements will show whether the second movement continues.
2. Buybacks. In 2025 the company bought 180.1 million shares for 20 billion under its program, an average of US$111.05. The same purchases appear as 182 million shares at 20,467 in the equity statement, which includes shares withheld for taxes and the excise tax, and as 20,273 of cash; the document does not split the differences. The year-end close of US$120.34 is 8.4% above that average, so the year's purchases were made below the closing price.
Measured against what each share produced, the price rose year after year.
| Buyback average price vs per-share results (construction) | FY2025 | FY2024 | FY2023 |
|---|---|---|---|
| Average price paid (US$) | 111.05 | 114.37 | 109.05 |
| Multiple of free cash flow per share | 20.2x | 16.0x | 13.2x |
| Free cash flow yield bought | 4.94% | 6.25% | 7.57% |
| Multiple of EPS | 16.6x | 14.6x | 12.3x |
The multiple is built by dividing the average price paid by that year's free cash flow per share (FY2023 uses the equity-statement average). It measures what the company paid for its own cash flow, with the limit that one year's free cash flow is a cyclical figure. Spending rose from about 18 billion to 20 billion while the multiple rose by half, so buybacks were not sized to the price paid. In 2025 free cash flow left 6,381 after dividends, and the rest of the buyback came from cash on hand.
3. Net dilution. In 2025, 8 million shares were issued for compensation and 182 million repurchased, a net reduction of 174 million. The buyback was returning capital, not covering stock awards. Over three years the picture reverses. The company repurchased 517 million shares for 57,650 in cash. It issued 591 million for Pioneer and Denbury, so the count ended 2.4% above its level at the end of 2022.
The Pioneer shares were valued at US$116.24 each, about 16.3 times 2024 free cash flow per share, against buybacks at 16.0 times in the same year: the company sold and bought its own stock at almost the same multiple. What it bought with the shares can be estimated only crudely. Pioneer contributed 1,710 of net income in its eight months of 2024, and the pro forma statement adds 796 for the months before closing. On 68,352 of consideration including debt, that is a return of about 3.7% at 2024 prices. The 2023 pro forma figures give 4.7%. The 2024 buybacks bought earnings at a 6.85% yield. The comparison is a construction on a single year, and the proxy states that synergies of "approximately $4.0 billion" were identified, "doubling initial expectations"; synergies are not reported in the financial statements, and Pioneer's 2025 results are not disclosed.
4. Accounting aggressiveness. The company excludes "Identified Items" from its adjusted earnings. Over 2023–2025 they sum to a net charge of 3,611, and impairments appear in every year, totalling 5,503, or 19.1% of 2025 net income. A charge that appears in every column is a recurring cost of a portfolio that is constantly pruned. Adjusted earnings ran above GAAP by 1,265 in 2025 and by 2,562 in 2023. They ran below it by 216 in 2024.
5. Governance signals in the document. Internal control was found effective, with no material weakness, no restatement and no change of auditor. The proxy notes one late insider filing.
Remuneration and incentives (proxy attached). Over 70% of executive pay is restricted stock units that vest half after five years and half after ten; grants are sized by a committee assessment that reviews safety, return on capital employed, cash flow from operations and asset sales, and shareholder return relative to BP, Chevron, Shell and TotalEnergies. The annual bonus moves by two-thirds of the "% change in annual earnings", based on a November estimate. The 2025 bonus program was cut 10%. GAAP net income fell 14.36%, and two-thirds of that is 9.6%. Earnings excluding Identified Items fell 10.03%, and two-thirds of that is 6.7%. The cut is closer to the GAAP figure; the proxy does not name the earnings measure. One metric deserves notice: cash flow from operations and asset sales counts divestment proceeds as performance. CEO compensation in the Summary Compensation Table was 32,998,628, against 44,052,537 in 2024.
The document contains admissions, but in the language of accounting rather than of judgement. It writes off assets: "Impairments in 2025 totaled $2.0 billion after-tax, including a write-down to fair value of Upstream oil and gas assets held for sale and charges associated with the optimization of materials and supply inventory." It records that about 1.0 billion barrels "no longer met the SEC definition of proved reserves", without saying why. It expensed 432 of suspended exploration wells. It booked 419 of restructuring with no narrative at all. Nowhere does it say that a project, an acquisition or a forecast went worse than planned; the narrative sections describe 2025 as record production and cost discipline.
The question is which accounting choices move reported earnings and where the document contradicts itself. The company uses successful-efforts accounting for exploration, LIFO for inventories, and fair value through earnings for commodity derivatives, without hedge accounting. It adopted ASU 2023-09 on income tax disclosure prospectively, so the 2025 rate reconciliation is not comparable line by line with the earlier years. No restatement occurred. The critical audit matter is in 3-bis.
Four choices move reported earnings. Derivative timing effects added about 1.0 billion in 2025 (0.6 billion in Upstream, 0.4 billion in Energy Products) and will reverse when the underlying physical sales settle. LIFO added 0.3 billion. Capitalizing 87.6% of interest paid kept 1,534 out of the income statement. Divestments added about 1.1 billion after tax, booked before tax in other income, and only 720 of it is classified as an identified item.
Two disclosures in the same document do not reconcile. The return-on-capital table shows financing items after tax producing a net gain of 547 in 2025, against a net cost of 1,554 in 2024. The swing comes from a line called "All other financing costs – net", at +2,072. The MD&A says Corporate and Financing expenses rose to 3.6 billion "mainly due to higher financing costs". The document does not explain what "All other financing costs" contains. Impairments are given as about 2.0 billion before tax in Note 9 and as "$2.0 billion after-tax" in the critical estimates section. Identified Items show 1,855 after tax, and no reconciliation is offered.
GAAP net income was 28,844 and earnings excluding Identified Items 30,109. Impairments (1,855) and restructuring (419) are excluded as charges. A gain on sale (720) and tax items (288) are excluded as credits. The consolidated book tax rate of 3-bis sits above the 21% U.S. rate because 73% of pre-tax income is earned outside the United States.
Each item below is anchored to a project or programme the document declares.
The volume catalysts are dated and largely funded; what they earn will depend on price, which none of them controls.
The 10-K does not restate the previous year's targets, so most comparisons rely on statements made in this year's filing and proxy about earlier plans.
| Item | Stated | Realized | Gap |
|---|---|---|---|
| Share repurchases | 20 billion pace for 2025 (implied by "continue its share repurchase program with a $20 billion repurchase pace") | "completed share repurchases of $20 billion in 2025" | None; the statement dates from 9 December 2025, so it does not test an earlier forecast |
| 2030 emission-intensity plans | Corporate GHG and flaring intensity plans for 2030 | "already achieved" for GHG and flaring; methane expected "later this year" | Ahead on two of three |
| Cost savings vs 2019 | 20 billion by 2030 | 15.1 billion cumulative, 3.0 billion in 2025 | 4.9 billion to go |
| Pioneer synergies (proxy) | "initial expectations", not quantified | "approximately $4.0 billion" identified | Not verifiable in the financial statements |
| Yellowtail start-up (proxy) | final investment decision schedule | "four months ahead of FID schedule" | Ahead |
| Distributions (proxy) | — | "$37.2 billion", against 37,504 in cash (dividends 17,231 plus buybacks 20,273) | The proxy counts buybacks at the 20 billion book value |
Capex guidance for 2025 and production targets set a year earlier are not reported in the document, so those comparisons are not possible.
Assume that three years from now this investment has lost capital permanently. Three mechanisms in the document could have produced that.
No probability is attached to these scenarios.
The question is what would remain for the shareholder if growth stopped.
| 31/12/2025 | |
|---|---|
| Equity less the only disclosed goodwill (~1 billion, Pioneer) | ~258,386; ~US$61.83 per year-end share |
| Equity less all "Other assets, including intangibles" (upper bound of the deduction) | 238,478; US$57.07 per share |
| Working capital / current ratio | 11,052 / 1.15x (21,683 / 1.31x a year earlier) |
| Cash per share | US$2.56 |
| Cash less gross debt per share | −US$7.86 |
| Assets at near-contractual value (cash and receivables) | 12.3% of total assets |
Per-share amounts use the 4,179 million year-end shares from the equity statement. If revenue stopped growing and margins returned to the average of the three years, tangible equity would not protect the shareholder, because it consists mostly of PP&E whose value depends on the same prices and reserves estimates; cash and working capital are thin against short-term debt. What protects the shareholder is the low leverage of section 3 and debt maturities that are small against cash from operations.
The three questions of section 1-bis receive these answers from the numbers already shown.
The 2025 result is mostly a price result: in Upstream, price took 6.1 billion and volume and cost savings returned 3.3 billion (3-septies). Chemicals sit at the bottom of the company's own description of the cycle, and refining recovered. The price of US$120.34 equals 18.0 times 2025 earnings. Against the three-year average it is 15.4 times, and against the best year in the document 13.5 times. Brent in all three years was between US$69 and US$83, so the average is not a full cycle, and the document places 2025 crude "near the middle" of its ten-year range. On that evidence 2025 earnings are neither a peak nor a trough on oil.
Whether the capital added since 2023 earns cannot be settled from this document. The incremental return is negative, but price explains more than the whole decline. The parts that can be seen point both ways: non-U.S. Upstream earns 17.7% and refining 19.7%, while U.S. Upstream, where Pioneer sits, earns 4.3% and chemicals 2.7%. Pioneer cost about 68 billion and earned about 3.7% on a pro forma 2024 basis, below the 6.85% earnings yield the company paid on its own shares that year. The critical audit matter and 1.0 billion barrels of reclassified reserves mean the asset base itself depends on estimates.
The distribution was not paid from the business in 2025. Shareholders received 158.8% of free cash flow, and the shortfall came from cash. Net leverage of 0.48 times EBITDA leaves room to continue for some time, but the cash left against short-term debt (5-bis) is thinner than a year earlier.
The reading holds if price recovers toward the 2023–2024 level, if the working capital absorbed in 2025 returns, and if U.S. Upstream returns rise as Permian volumes grow on a lower unit cost. It falls if prices stay at 2025 levels and the buyback pace continues, because then net debt rises each year, or if reserves revisions and impairments repeat on the U.S. assets.
The document does not say why 1.0 billion barrels left proved undeveloped reserves, what price deck supports the carrying value of upstream assets, or what Pioneer earned in 2025. Nor does it say why equity companies paid 3,006 more in dividends than they earned, what the 419 restructuring charge covers, or what "All other financing costs – net" contains. Each answer would change the reading of one of the three decisive questions.
At US$120.34 the market pays for 2025 earnings that were reduced by price, not by operations, and for capital additions of the last three years that have not yet shown a return on the evidence in the document. The price implies that the shareholder receives a free cash flow yield of 4.69% on current results while the company returns 7.46% in cash; the difference is paid from the balance sheet, which has room for it but less than a year ago. Whether that difference closes depends on the oil price and on the U.S. Upstream assets, and the FY2026 statements will show which.
Items to monitor in the FY2026 statements:
None of these items carries a level that would change the reading; each is the line where the answer to one of the three decisive questions will be written next year.
Report based on the Exxon Mobil Corporation Form 10-K for the fiscal year ended 31/12/2025 (signed on 18/02/2026, the date of the auditor's report; the filing date itself is not stated in the document) and the 2026 Proxy Statement. The multiples use the closing price of US$120.34 on 31/12/2025 and 4.18 billion shares outstanding, both supplied by the user. This report is for analytical purposes only and does not constitute investment advice.
1.1 Upstream share of external sales = 39,389 / 323,905 = 12.16%
1.2 Upstream share of net income = 21,354 / 28,844 = 74.0%
1.3 Revenue change = 323,905 / 339,247 − 1 = −4.52%
1.4 Segment shares FY2025: 244,451 / 323,905 = 75.47%; 22,209 / 323,905 = 6.86%; 17,771 / 323,905 = 5.49%; 85 / 323,905 = 0.03%
1.5 U.S. share = 137,639 / 323,905 = 42.49%; non-U.S. = 186,266 / 323,905 = 57.51%
1.6 Segment YoY: 39,389 / 37,131 − 1 = +6.08%; 244,451 / 260,856 − 1 = −6.29%; 22,209 / 22,896 − 1 = −3.00%; 17,771 / 18,253 − 1 = −2.64%; U.S. 137,639 / 138,657 − 1 = −0.73%; non-U.S. 186,266 / 200,590 − 1 = −7.14%
1b.1 Distributions = 17,231 + 20,273 = 37,504
1b.2 Free cash flow = 51,970 − 28,358 = 23,612
1b.3 Change in unrestricted cash = 10,681 − 23,029 = −12,348
1b.4 Capex 2023–2025 = 28,358 + 24,306 + 21,919 = 74,583
1b.5 Pioneer consideration incl. debt = 63,352 + 5,000 = 68,352
2.1 Reserves life = 19,311 / (1,478 + 284) = 19,311 / 1,762 = 10.96 years
2.2 Realized crude change = 65.18 / 76.23 − 1 = −14.50%; Brent change = 69.06 / 80.76 − 1 = −14.49%
2.3 Specialty earnings per tonne = 2,857 / 7.791 = US$366.7; 2024: 3,052 / 7.666 = 398.1; 2023: 2,714 / 7.597 = 357.2
2.4 Specialty share of net income = 2,857 / 28,844 = 9.9%
2.5 Revenue vs pro forma 2024 = 323,905 / 347,406 − 1 = −6.76%; net income = 28,844 / 34,476 − 1 = −16.34%
2.6 Cost growth: 42,424 / 39,609 − 1 = +7.1%; 11,128 / 9,976 − 1 = +11.5%; 25,993 / 23,442 − 1 = +10.9%; 1,007 / 826 − 1 = +21.9%
2.7 Unit cost change = 10.20 / 10.53 − 1 = −3.13%
3.1 EBIT = 41,268 + 603 = 41,871; 2024: 48,873 + 996 = 49,869; 2023: 52,783 + 849 = 53,632
3.2 EBITDA = 41,871 + 25,993 = 67,864; 2024: 49,869 + 23,442 = 73,311; 2023: 53,632 + 20,641 = 74,273
3.3 Net income change by segment: 21,354 − 25,390 = −4,036; 7,423 − 4,033 = +3,390; 800 − 2,577 = −1,777; 2,857 − 3,052 = −195; −3,590 − (−1,372) = −2,218; total −4,836
3.4 Net debt = 43,537 − 10,681 = 32,856; 2024: 41,710 − 23,029 = 18,681; change +14,175
3.5 Net debt to capital = 32,856 / (32,856 + 266,626) = 11.0%; 2024: 18,681 / (18,681 + 270,606) = 6.5%
3.6 Debt incl. operating leases = 43,537 + 6,834 = 50,371; gross debt change = 43,537 − 41,710 = 1,827
3.7 FCF less SBC = 23,612 − 1,000 = 22,612 (approximate; SBC given in rounded billions)
3.8 Cash Capex effect = 28,997 − 28,358 = 639
3.9 Owner earnings without working capital = 51,970 + 7,728 − 28,358 = 31,340; with working capital = 51,970 − 28,358 = 23,612. Built as net income incl. NCI 29,764 + D&D 25,993 + deferred tax 765 − 64 − 1,430 + 3,006 − 1,113 + 2,777 − capex 28,358 (= 31,340), then − working capital 7,728
3.10 SBC / buyback = 1,000 / 20,273 = 4.9%
3.11 Book tax rate = 11,504 / 41,268 = 27.88%; NOPAT = 41,871 × (1 − 0.2788) = 30,199
3.12 Invested capital = 43,537 + 266,626 − 10,681 = 299,482; 2024: 41,710 + 270,606 − 23,029 = 289,287; 2023: 41,573 + 212,538 − 31,568 = 222,543
3.13 ROIC year-end = 30,199 / 299,482 = 10.08%; 2024: 35,778 / 289,287 = 12.37%; 2023: 37,955 / 222,543 = 17.06%; average 2025 = 30,199 / ((299,482 + 289,287) / 2) = 10.26%
3.14 Debt / EBITDA = 43,537 / 67,864 = 0.64x; net = 32,856 / 67,864 = 0.48x; 2024: 41,710 / 73,311 = 0.57x, 18,681 / 73,311 = 0.25x; 2023: 41,573 / 74,273 = 0.56x, 10,005 / 74,273 = 0.13x
3.15 Coverage = 41,871 / 603 = 69.4x; 49,869 / 996 = 50.1x; 53,632 / 849 = 63.2x; on cash interest: 41,871 / 1,752 = 23.9x; 49,869 / 1,900 = 26.2x; 53,632 / 1,736 = 30.9x
3.16 Capitalized share of interest = 1,534 / 1,752 = 87.6%; 2024: 1,276 / 1,900 = 67.2%; cash interest change = 1,752 / 1,900 − 1 = −7.8%
3.17 Long-term debt in years of net income = 34,241 / 28,844 = 1.19; cash interest / EBIT = 1,752 / 41,871 = 4.2%
3.18 FCF / net income = 23,612 / 28,844 = 81.9%; 30,716 / 33,680 = 91.2%; 33,450 / 36,010 = 92.9%
3.19 Market capitalization = 120.34 × 4,180 = 503,021; EV = 503,021 + 43,537 + 7,240 − 10,681 = 543,117
3.20 P/E = 120.34 / 6.70 = 17.96x; EPS ex-items = 30,109 / 4,305 = 6.994, P/E = 120.34 / 6.994 = 17.21x; average EPS = (6.70 + 7.84 + 8.89) / 3 = 7.81, P/E = 15.41x; peak = 120.34 / 8.89 = 13.54x
3.21 P/FCF = 503,021 / 23,612 = 21.30x; yield = 4.69%; EV/EBITDA = 543,117 / 67,864 = 8.00x; EBIT/EV = 41,871 / 543,117 = 7.71%; P/B = 120.34 / 62.07 = 1.94x
3.22 Dividend yield = 4.00 / 120.34 = 3.32%; distribution yield = 37,504 / 503,021 = 7.46%
3b.1 Upstream PP&E / total assets = 228,235 / 448,980 = 50.8%
3b.2 Consolidated revisions / opening consolidated reserves = −929 / 16,955 = −5.5%
3b.3 Unproved property / total assets = 47,892 / 448,980 = 10.7%; change = 47,892 − 55,081 = −7,189; proved property change = 41,112 − 35,726 = +5,386
3b.4 Cash vs book tax = 11,563 − 11,504 = 59
3b.5 Pension net = −1,474 − 370 − 4,508 = −6,352
3b.6 Revenue outside ASC 606 = 96,996 / 323,905 = 29.9%
3b.7 Commitments beyond 2025: firm capex 8.5 + 8.0 = 16.5 billion; leases not commenced 3.0 + 0.8 = 3.8 billion
3t.1 Shares of total assets: 299,373 / 448,980 = 66.7%; 45,317 / 448,980 = 10.1%; 44,562 / 448,980 = 9.9%; 22,979 / 448,980 = 5.1%; liabilities and equity: 266,626 / 448,980 = 59.4%; 60,911 / 448,980 = 13.6%; 40,216 / 448,980 = 9.0%; 34,241 / 448,980 = 7.6%; 26,178 / 448,980 = 5.8%
3t.0 Upstream share of PP&E = 228,235 / 299,373 = 76.2%
3t.2 Unexplained other long-term obligations = 26,178 − 11,300 − 4,892 = 9,986
3t.3 Receivable days = 35,744 / 323,905 × 365 = 40.3; 2024: 35,282 / 339,247 × 365 = 38.0
3t.4 Inventory days = 22,979 / 184,248 × 365 = 45.5; 2024: 19,444 / 199,454 × 365 = 35.6
3t.5 Payable days = 36,049 / 184,248 × 365 = 71.4; 2024: 36,145 / 199,454 × 365 = 66.1
3t.6 Cycle = 40.3 + 45.5 − 71.4 = 14.4; 2024: 38.0 + 35.6 − 66.1 = 7.4
3t.7 Inventory at approximate replacement cost = 22,979 + 7,000 = 29,979; 2024: 19,444 + 10,000 = 29,444; change +1.8%
3t.8 ROE year-end = 28,844 / 259,386 = 11.12%; with treasury added = 28,844 / (259,386 + 258,395) = 5.57%
3t.9 Retained earnings change = 482,494 − 470,903 = 11,591; 470,903 − 453,927 = 16,976
3t.10 Cash and receivables share = (10,681 + 44,562) / 448,980 = 12.3%; level 3 assets = 3,938 + 1,800 = 5,738
3q.1 Working capital = −3,042 − 4,300 − 164 − 222 = −7,728
3q.2 CFO without excess affiliate dividends = 51,970 − 3,006 = 48,964; 2024: 55,022 − 191 = 54,831; change = −10.7%; reported change = 51,970 / 55,022 − 1 = −5.5%
3q.3 Deferred tax gap = 968 − 765 = 203; income taxes payable change = 2,123 − 4,055 = −1,932
3q.4 Non-cash PP&E additions = 31,476 − 28,358 = 3,118
3q.5 FCF decline = 30,716 − 23,612 = 7,104; change in working capital absorbed = 7,728 − 1,826 = 5,902; share = 5,902 / 7,104 = 83.1%
3q.6 Owner earnings before working capital change = 31,340 / 32,542 − 1 = −3.7% (2024: 30,716 + 1,826 = 32,542)
3qq.1 Per share: revenue 323,905 / 4,305 = 75.24; 339,247 / 4,298 = 78.93; 334,697 / 4,052 = 82.60; FCF 23,612 / 4,305 = 5.49; 30,716 / 4,298 = 7.15; 33,450 / 4,052 = 8.26; equity 259,386 / 4,305 = 60.25; 263,705 / 4,298 = 61.36; 204,802 / 4,052 = 50.54
3qq.2 Changes 2023–2025: 75.24 / 82.60 − 1 = −8.9%; 6.70 / 8.89 − 1 = −24.6%; 5.485 / 8.255 − 1 = −33.6%; 60.25 / 50.54 − 1 = +19.2%; shares 4,305 / 4,052 − 1 = +6.2%; net income 28,844 / 36,010 − 1 = −19.9%
3qq.3 Incremental return = (30,199 − 37,955) / (299,482 − 222,543) = −7,756 / 76,939 = −10.1%
3qq.4 Price effect on Upstream = (82.62 − 69.06) × 700 = 9,492
3qq.5 Reinvestment = 28,358 − 25,993 + (4,133 − 3,406) + 7,728 = 10,820; rate = 10,820 / 30,199 = 35.8%; implied growth = 35.8% × 10.08% = 3.6%; EBIT change = 41,871 / 49,869 − 1 = −16.0%
3qq.6 Distributions / net income = 37,504 / 28,844 = 130.0%
3qq.7 No-growth proxy = (51,970 + 7,728) − 25,993 = 33,705
3qq.8 Three-year FCF = 162,361 − 74,583 = 87,778; net debt flows = 53 − 5,012 − 239 = −5,198; shares issued for acquisitions = 63,352 + 4,844 = 68,196
3qq.9 Capex / D&D = 28,358 / 25,993 = 1.09; 24,306 / 23,442 = 1.04; 21,919 / 20,641 = 1.06; excluding impairments = 28,358 / (25,993 − 2,000) = 1.18; cumulative capex / net income = 74,583 / 98,534 = 75.7%
3s.1 Inventory 22,979 / 19,444 − 1 = +18.2%; revenue −4.5%; gap 22.7 points; purchases 184,248 / 199,454 − 1 = −7.6%
3s.2 Trade receivables 35,744 / 35,282 − 1 = +1.3%; gap 5.8 points
3s.3 Allowance 270 / 162 − 1 = +66.7%; gross receivables (35,744 + 270) / (35,282 + 162) − 1 = +1.6%; gap 65.1 points
3s.4 Trade payables 36,049 / 36,145 − 1 = −0.3%; gap vs purchases 7.4 points
3s.5 Capitalized interest 1,534 / 1,276 − 1 = +20.2%; interest expense 603 / 996 − 1 = −39.5%; gap 59.7 points
3s.6 CFO −5.5% vs revenue −4.5%: gap 1.0 point; adjusted CFO −10.7%: gap 6.2 points
3sp.1 Annual production = 4,736 × 365 / 1,000 = 1,728.6 million boe; 2024: 4,333 × 0.365 = 1,581.5; 2023: 3,738 × 0.365 = 1,364.4
3sp.2 Upstream earnings per barrel = 21,354 / 1,728.6 = US$12.35; 25,390 / 1,581.5 = 16.05; 21,308 / 1,364.4 = 15.62; change = −23.1%; volume = 4,736 / 4,333 − 1 = +9.3%
3sp.3 Driver sum = −6.1 + 1.9 − 0.7 + 1.4 − 0.6 + 0.6 + 0.6 = −2.9 billion = 22,247 − 25,175 = −2,928
3sp.4 Upstream at 2023 Brent = 21,354 + 9,492 = 30,846; share absent = 9,492 / 30,846 = 30.8%
3sp.5 Energy Products earnings per barrel = 7,423 / (3,979 × 0.365) = 7,423 / 1,452.3 = US$5.11; 4,033 / 1,423.5 = 2.83; 12,142 / 1,484.8 = 8.18; ex-items 6,940 / 1,452.3 = 4.78 (identified items +483 = impairments −266 + gain on sale +720 + tax +28); change 5.11 / 2.83 − 1 = +80.6%; throughput 3,979 / 3,900 − 1 = +2.0%
3sp.6 Chemical earnings per tonne = 800 / 21.303 = US$37.6; 2,577 / 19.392 = 132.9; 1,637 / 19.382 = 84.5; ex-items 1,070 / 21.303 = 50.2; change 37.6 / 132.9 − 1 = −71.7%; volume 21,303 / 19,392 − 1 = +9.9%; non-U.S. volume 14,326 / 12,354 − 1 = +16.0%
3sp.7 China capacity / sales = 2,500 / 21,303 = 11.7%
3sp.8 Organic reserve replacement 2025 = (2,048 − 929 + 23) / 1,762 = 64.8%; 2024 = (1,915 + 521 + 46) / (1,355 + 264) = 153.3%; 2023 = (1,065 − 553 + 124) / (1,121 + 281) = 45.4%
3sp.9 PUD share = 7,007 / 19,311 = 36.3%; standardized measure change = 149,129 / 185,664 − 1 = −19.7%
4.1 Distributions over FCF = 37,504 − 23,612 = 13,892
4.2 Kazakhstan share of production = 320 / 4,736 = 6.8%
4.3 Taxes / net income = 40,434 / 28,844 = 1.40
5b.1 Sources and uses: 162,361 + 12,223 + 6,894 − 74,583 − 10,427 − 48,876 − 57,650 − 5,198 − 3,728 = −18,984; other line = −2,124 (NCI dividends) − 2,389 (NCI changes) + 244 (NCI inflows) − 174 (contingent) + 754 (cash acquired) − 39 (FX) = −3,728
5b.2 Distributions / three-year FCF = 106,526 / 87,778 = 121.4%
5b.3 Average buyback price = 20,000 / 180.1 = US$111.05; 2024: 19,100 / 167 = 114.37; 2023: 17,993 / 165 = 109.05; equity statement 2025: 20,467 / 182 = 112.46; close vs average = 120.34 / 111.05 − 1 = +8.4%
5b.4 Buyback multiple = 111.05 / 5.485 = 20.2x (yield 4.94%); 114.37 / 7.147 = 16.0x (6.25%); 109.05 / 8.255 = 13.2x (7.57%); EPS multiple = 111.05 / 6.70 = 16.6x; 114.37 / 7.84 = 14.6x; 109.05 / 8.89 = 12.3x; FCF after dividends 2025 = 23,612 − 17,231 = 6,381
5b.5 Net share change 2025 = 8 − 182 = −174 million; three years: 4,179 / 4,082 − 1 = +2.4% (repurchased 165 + 170 + 182 = 517; issued 46 + 545 = 591; compensation 8 + 7 + 8 = 23)
5b.6 Pioneer issue price = 63,352 / 545 = US$116.24; multiple = 116.24 / 7.147 = 16.3x
5b.7 Pioneer return = (1,710 + (34,476 − 33,680)) / (63,352 + 5,000) = 2,506 / 68,352 = 3.7%; 2023: (39,211 − 36,010) / 68,352 = 3,201 / 68,352 = 4.7%; 2024 buyback earnings yield = 7.84 / 114.37 = 6.85%
5b.8 Identified Items 2023–2025 = −1,265 + 216 − 2,562 = −3,611; impairments = −1,855 − 608 − 3,040 = −5,503; share of 2025 net income = 5,503 / 28,844 = 19.1%
5b.9 Bonus check: GAAP 28,844 / 33,680 − 1 = −14.36%, × 2/3 = −9.6%; ex-items 30,109 / 33,464 − 1 = −10.03%, × 2/3 = −6.7%
6.1 Timing effects = 0.6 + 0.4 = 1.0 billion
6.2 Financing items (ROCE table) = −1,360 − 165 + 2,072 = +547; 2024 = −1,554
6.3 Identified Items 2025 = −1,855 − 419 + 720 + 288 = −1,266 (−1,265 as reported, rounding)
6.4 Non-U.S. share of pre-tax income = 30,268 / 41,268 = 73.3%
8.1 Distributions in cash = 17,231 + 20,273 = 37,504; proxy basis = 17.2 + 20.0 = 37.2 billion
8.2 Cost savings remaining = 20.0 − 15.1 = 4.9 billion
8t.1 Equity less Pioneer goodwill = 259,386 − 1,000 = 258,386; per share = 258,386 / 4,179 = 61.83
8t.2 Equity less other assets incl. intangibles = 259,386 − 20,908 = 238,478; per share = 57.07
8t.3 Working capital = 83,382 − 72,330 = 11,052; current ratio = 83,382 / 72,330 = 1.15
8t.4 Cash per share = 10,681 / 4,179 = 2.56; net of debt = (10,681 − 43,537) / 4,179 = −7.86
9.1 Volume and cost contribution = 1.9 + 1.4 = 3.3 billion
9.2 Distributions / FCF = 37,504 / 23,612 = 158.8%
The full data table behind this report — every line item with its source in the filing and the arithmetic checks — is published separately: Exxon Mobil Corporation FY2025 data table.