Expensive, Overvalued and Overlooked: Oil Majors' Earnings Week

In 2020 the oil majors were tested by a collapse in the oil price, and they made very different choices. Six years on, their share prices still reflect those choices, and I think the market has got some of them wrong.

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Every oil major tells investors it is disciplined. The market has heard that before, and prefers to look at what each company did when it was tested. The test came in 2020. With Brent below $20 and demand collapsing, Shell cut its dividend by two-thirds in April, its first cut since the Second World War. In August BP halved its payout and promised to shrink its oil and gas output by 40% by the end of the decade, stop exploring in new countries and become an "integrated energy company". ExxonMobil and TotalEnergies kept their dividends whole. Exxon borrowed to do it, cut spending everywhere except Guyana, Brazil and the Permian, and lost three board seats to the activist hedge fund Engine No. 1 the following year for its trouble.

Six years on, their respective share prices read like a verdict on those choices. Exxon is worth $756 billion and trades at almost 16x 28E earnings. Shell and TotalEnergies trade at around 10x, BP at 12x earnings but only 4x EBITDA.

All five shares are up more than 40% in a year, on Brent that averaged $104 in the second quarter and $97 in the third, so this is not a story about who is winning the oil price. It is about which companies the market believes will still have the barrels, and the judgement to develop them, in ten years' time.

My argument is not the conventional one. Exxon carries a premium because it never stopped being an oil company. Shell and BP did, and BP went further, trying to turn itself into something else entirely.

That does not mean the multiples sort the five neatly into good companies and bad ones. Exxon is expensive, but it has largely earned its rating. BP is cheap, but for reasons of its own making. Chevron is paying Exxon prices for barrels it bought rather than found, while TotalEnergies, the European that never stopped being an oil company, is still valued as though it had. Shell is the one I would question most. Judged on its reserves, which is how anyone who has spent a career in reservoirs would judge it, Shell is the most overvalued of the five.

Three things stand out. The American premium, 55% to 60% on both earnings and EBITDA, is far too wide to be an accounting artefact or a listing effect alone. BP, cheapest on EBITDA, is not cheapest on earnings: by 2028 its price-to-earnings ratio is above both its European peers', so something between BP's operating profit and its shareholders is absorbing the value the headline multiple appears to offer. And Shell, with a reserve life of less than eight years, trades on a higher earnings multiple, and at a market value $100 billion larger, than TotalEnergies, which has one of the longest. That last comparison is the one the market should find most uncomfortable.

ExxonMobil: it found its future and bought it too

In London the Exxon premium is often explained away as geography: deeper US capital markets, index money, a home crowd. That is part of it. The larger part is that Exxon is the only one of the five that has both found and bought its future, and kept its nerve while doing so.

Guyana is the case in point. Exxon signed the Stabroek licence in 1999 and held it for sixteen years before the Liza discovery in 2015, through a maritime border dispute with Suriname and Venezuela's claim to two-thirds of Guyana's territory. Shell held a quarter of the block and walked away in 2014, a year before Liza. Exxon now operates more than 11 billion barrels of discovered resource with a 45% interest, and it has stayed through a Venezuelan navy interception of one of its survey vessels in 2018, a disputed Guyanese election in 2020 and Caracas's 2023 referendum on annexing the Essequibo region. Exxon got lucky in Guyana. But it deserved that luck: it stuck with the country when that was neither fashionable nor safe, and was still there when the rock delivered.

It has also bought well, though not always. XTO, its $41 billion bet on US shale gas in 2010, was a poor acquisition and sits at the root of the $20 billion write-down Exxon took on North American gas in 2020. Pioneer, bought for about $60 billion in 2024, looks a much better one: it made Exxon the Permian's largest producer, and the basin is expected to supply about 2.5 million boepd of a group target of 5.5 million by 2030. The company's 2030 plan promises $35 billion more cash flow than in 2024 at a $65 oil price, without higher capital spending.

At 15.7 times 2028 earnings Exxon is expensive, and buying it means paying today for delivery that is still years away. But it is expensive in the way a good asset is expensive. The caveat, which I return to below, is that a growing share of that future rests on the Permian, and I am less sure than the market is about how long shale barrels last.

What the write-downs reveal

The cleanest measure of management across a cycle is how much "adjusted" profit a company keeps once impairments and write-offs are counted. Adjusted earnings show what the assets made. Reported earnings show what management did with them.

Between 2020 and 2025 Exxon and Chevron kept 85% and 89% of their adjusted earnings as reported profit. Shell and TotalEnergies kept about 70%, losing heavily to the pandemic and their exits from Russia. BP kept less than 1%: underlying replacement cost profit of $65 billion over six years, and reported profit attributable to shareholders of $0.5 billion.

The companies' own return figures hide this. On BP's definition, which excludes adjusting items, its return on average capital employed averaged 14% over the period, higher than Exxon's 11%, which is measured on reported earnings. Write-downs are where capital-allocation decisions finally show up in the accounts, which is precisely why management prefers investors to look past them.

Worse still, those write-downs reduce the capital employed against which future profits are measured, potentially flattering subsequent returns. BP can therefore report impressive returns on capital even after destroying substantial amounts of shareholder value.

The mechanics are worth spelling out, because a write-down flatters the return three times over. First, it is classed as an adjusting item, so it never touches the underlying profit on which BP's return is calculated. Second, it removes the impaired assets from the balance sheet, shrinking the capital employed that future profit is divided by. Third, a smaller asset base carries less depreciation, so underlying profit in later years rises even though nothing in the field has changed.

A simple illustration makes the point. A business earning $10 billion on $100 billion of capital returns 10%. Write off $25 billion and the same $10 billion becomes a 13% return, before the lower depreciation charge adds anything. The shareholders are $25 billion poorer, and the return on capital has improved.

None of this is unique to BP. Exxon's $20 billion impairment in 2020 flatters its later returns too. The difference is scale and repetition, and the fact that Exxon's measure takes the write-down through reported earnings in the year it happens, whereas BP's leaves it out altogether. For BP the effect compounds: each strategic reversal writes off capital, and each write-off makes the next set of returns look better. It is one of the least discussed features of the company's numbers, and one of the most important.

BP: a good company that takes disastrous shortcuts

I hold BP shares, and I do not think BP is a bad company. Its deepwater position in the Gulf of America is among the best in the industry, its trading business is first class, and Kaskida and Tiber in the Gulf, and Bumerangue in Brazil, are substantial discoveries. Its problem has never been the rocks. It is that BP has been poorly led for years now, and has made big mistakes that have hobbled it again and again. Each was an attempt to take a shortcut to somewhere its better-led peers reached by knowing how to run an oil company, and three of them define the company.

The first was Macondo, a failure of operating through shortcuts. The investigations into the 2010 Deepwater Horizon blowout, which killed eleven men, found a string of decisions that saved time and money at the expense of safety margins, and in 2014 a federal judge found BP grossly negligent. The bill, more than $65 billion before tax, forced BP to sell a large part of its upstream portfolio and left it smaller and more cautious for a decade.

The second was Russia, a shortcut through political instability. TNK-BP, and then the 19.75% of Rosneft it took in 2013, gave BP reserves and production it had not had to find: around a third of its output and an even larger share of its reserves, booked in a country where property rights meant what the Kremlin said they meant. When Russia invaded Ukraine in 2022 BP walked away and took a charge of about $24 billion.

The third was the transition, and in my view it was the most expensive of the three. In 2020 BP said it would cut oil and gas production by 40%, stop exploring in new countries and pour capital into low-carbon energy. It bought Archaea Energy, a US biogas producer, for $4.1 billion in 2022, and put it up for sale this August.

This was a shortcut too: a way of not being an oil company, which meant BP did not have to face up to what it was, or to how poorly it had been competing with its peers as one. It softened the targets in 2023 and abandoned them in February 2025. Along the way it booked more than $24 billion of impairments and exploration write-offs in 2020 alone, further impairments in every year since, and has flagged up to $4.5 billion more for this quarter, mainly on low-carbon businesses it bought or built.

Every one of those shortcuts reflects failures of management and board oversight. BP has had four chief executives since 2020, one of them interim, and repeated changes in its chairmanship. Albert Manifold was removed as chairman in May 2026, with Ian Tyler appointed permanently in September. Meg O'Neill, who took over as CEO in April, is the first chief executive in a long time to arrive with a record of running a large upstream business, and her early moves, simplifying the organisation back towards a conventional upstream and downstream model, are the right ones. She has said herself that BP has written off too much value. My concern is less with her than with whether the board can resist a fourth shortcut when the next fashionable one comes along.

The damage shows up in what reaches shareholders.

Only about 31% of BP's forecast 2027 EBITDA is expected to become net income attributable to shareholders, against 40% at Shell and 54% at Exxon. The leakage has identifiable causes: an underlying tax rate of 42% in 2025, the cost of $12 billion of hybrid bonds, and a rising share of profit going to minority interests, $1.2 billion in 2025 against $0.8 billion a year earlier, as BP sold stakes in pipelines and Castrol to raise cash. It raised $28.7 billion from disposals between 2020 and 2025 and has a $20 billion programme to 2027. Selling minority stakes cuts debt today and earnings tomorrow.

How much of the discount is earned? Most of it. To trade on Shell's like-for-like EV/EBITDA multiple, BP's shares would need to rise by about 26%, which at its current earnings multiple requires converting about 39% of EBITDA into net income rather than 31%, almost exactly Shell's ratio.

The October trading statement is encouraging: BP guided net debt down by about $8 billion in the quarter, to $13.5 billion to $14.5 billion. Friday's cash-flow statement should establish how much of that improvement came from operating cash generation rather than disposals and other balance-sheet movements. Confirmation that the reduction was principally driven by operating cash flow would be the strongest evidence yet that BP's deleveraging is coming from the business itself.

This is also why I treat BP's headline targets with caution. The reset O'Neill inherited promises a return on average capital employed above 16% by 2027. That return excludes adjusting items, is measured on a capital base the write-downs have already shrunk, and is helped by the lower depreciation that follows an impairment. In other words, part of the improvement it promises has already been manufactured by the losses. A better test is cash: free cash flow per share, and how much of it reaches ordinary shareholders after hybrid coupons and minority interests. On that measure, the conversion figures above tell a much less flattering story.

What BP must deliver is not complicated. It has to run the oil company it already has, convert its discoveries on time (Kaskida's first oil is due in 2029, more than two decades after discovery) and stop looking for the next shortcut. The discount will close on delivery, not on targets. BP has set ambitious targets before.

Shell: producing itself out

Shell is the market's favourite European major, and I think it is the most overrated and overvalued of the five. On the surface the case for it is persuasive. Costs have been cut, weak businesses sold and net debt reduced by about $30 billion. Shell has announced at least $3 billion of buybacks in each of the last 19 quarters, and over 2020–25 it generated more free cash flow than Exxon did.

A reservoir engineer reads those numbers differently. Strong returns and generous distributions have come at the expense of the reserve base. Shell's proved reserves fell from 9.62 billion barrels of oil equivalent at the end of 2024 to 8.12 billion at the end of 2025. Its headline reserve replacement ratio for the year was minus 40%, and 55% averaged over three years; excluding acquisitions and disposals the figures were 73% and 84%.

Disposals explain the headline, but not the organic number, and the organic number is the one that matters. Reserve life is now under eight years, the lowest in more than a decade. That is not a countdown to exhaustion: proved reserves move with prices, sanctions and maturing projects, and every engineer knows a company holds more than its SEC book. But a company that persistently produces more than it replaces is producing itself out, and no amount of cost-cutting or buybacks solves that. Some of the cash the market applauds is simply the cash released by not replacing what it produces, so part of what shareholders receive is a return of their capital presented as a return on it. Strip away the polish and that is a harvest strategy, with the distributions funded by running down the asset that generates them

The root cause, in my view, is that Shell is bad at exploration, even though it spends a great deal on it. The problem is converting exploration spending into economic, commercial barrels, and that conversion has been poor for years.

When I asked Shell geoscientists and managers in my network why, the answer I heard most often was, to paraphrase, that it is “exploration by committee”. To me that explains a great deal. Good exploration depends on conviction: a team that believes in a play the rest of the industry has passed over, and a leadership willing to back it. A committee does the opposite.

Committees spread responsibility and water down risk until only the consensus prospects survive, and those are the ones everyone else has already looked at. Committees are good at avoiding blame, not at finding oil, and Shell’s record suggests little good comes of that approach.

Any explorer has failures, and no single dry hole proves anything. What concerns me is the record of expenditure against commercial resources added, and several decisions illustrate the problem. Shell held a quarter of Guyana’s Stabroek block and walked away in 2014, a year before Exxon found Liza. In India, it sold its remaining interest in Rajasthan to Cairn for just $7.25 million in 2002; Cairn subsequently discovered the giant Mangala oilfield. At the other extreme, Shell spent approximately $7 billion exploring offshore Alaska before abandoning the campaign in 2015 without a single commercial discovery.

Namibia is a more complicated case. Shell wrote off around $400 million in January 2025 after concluding that its discoveries could not then be confirmed as commercially developable. However, it has not abandoned the basin. Its Merlin-1X well delivered encouraging results in June 2026, and Shell continues to evaluate the commercial potential of its acreage. It would therefore be premature to count Namibia as another exploration failure just yet.

Shell deserves credit for its continued commitment to exploration and the substantial expenditure it devotes to it. My criticism is not how much it spends, but how effectively that money is deployed. The problem is its poor record of turning exploration expenditure into commercial discoveries and ultimately producing reserves.

Shell’s answer to a shrinking reserve base has been to buy instead. It completed the acquisition of ARC Resources in September for about $16.5 billion including debt, and paid roughly three-quarters of the price in new Shell shares. So a company that has spent four years buying back its equity is now issuing it to buy the barrels its own drill bit did not find. ARC brings real Montney production and inventory, but it buys duration rather than creating it, and it adds unconventional decline exposure of its own. Its roughly 2 billion barrels are also a proved-plus-probable estimate, which cannot simply be added to Shell’s SEC proved reserves.

Then there is trading. Shell's LNG business is a genuinely valuable physical franchise, combining upstream gas, liquefaction, shipping and long-term contracts, and it would be wrong to dismiss it as a trading book. But its trading and optimisation desks make very large profits in volatile markets, which is exactly what the past four years have provided, and Shell does not disclose enough to let investors separate those earnings from the more durable profits of the physical assets. My view is that Shell leans on LNG trading too heavily, that trading has been papering over the cracks in its upstream, and that the market is capitalising exceptional trading conditions as though they were a permanent source of earnings. I would not.

This is why I read the market's pricing of Shell differently from the consensus. The obvious objection to calling Shell overvalued is that it does not look expensive: 10.4x 2028 earnings and the highest free cash flow yield of the five. But a cash yield is only as good as the reinvestment it leaves out. Shell's share price implies free cash flow that shrinks very slightly forever, which looks undemanding. Flat cash flow, however, needs flat production, and flat production needs reserves to be replaced.

On its organic record Shell does not replace them, so the true sustainable yield is lower than the headline once the cost of renewal, whether by drill bit or by acquisition, is charged against it. A 9% yield from a portfolio that needs substantial replenishment is worth less than a 7% yield backed by long-life resources and a visible development pipeline. That is the comparison with TotalEnergies, which has a reserve life of more than twelve years, replaced 116% of its production last year and is growing into the next decade, yet trades on a lower earnings multiple and at a market value $100 billion smaller. If either European deserves a premium, it is not Shell. Its multiple prices a going concern; its reserve book describes a harvest.

Chevron bought its future

I quite like Chevron. It is a well-run operator with a long record of capital discipline: when Occidental outbid it for Anadarko in 2019, Chevron walked away with a $1 billion break fee rather than overpay. Its Permian position rests largely on legacy acreage carrying low royalties, and the Tengiz expansion in Kazakhstan is finally complete.

I should also say that Mike Wirth, Chevron’s chief executive, has occasionally liked my articles on LinkedIn, including my piece on Occidental, though understandably not the ones that mention CVX. I have no wish to upset him unnecessarily, and what follows is meant to be firm but fair.

The difference from Exxon is where its future has come from. Since Anadarko, Chevron has built its growth largely through acquisitions: Noble Energy in 2020, PDC Energy in 2023 and, for $53 billion, Hess, completed in July 2025 after Exxon’s attempt to block the deal in arbitration failed. There is nothing wrong with buying reserves rather than finding them, and Hess was a good deal. The best evidence is that Exxon tried to establish pre-emption rights: as Stabroek’s operator, Exxon knows the block better than anyone, and it went to arbitration to secure that claim. But buying into a discovered basin means paying the seller for the exploration risk already taken out. Hess was bought largely for its 30% of Stabroek, which makes Chevron a partner in Guyana rather than the operator of a basin Exxon found, and in my view Chevron’s own exploration has not yet produced anything on that scale.

The market prices Chevron as though that does not matter. At 16.9x 2028 earnings it is dearer than Exxon at 15.7, despite a return on capital employed of 6.6% in 2025 against Exxon’s 9.3%, a reserve life under eight years against Exxon’s twelve, and the highest oil-price gearing of the five: at $60 Brent its 2028 multiple rises to almost 22 times.

On a write-down-adjusted basis the two trade at about the same multiple, around 19 times, so investors are paying much the same price for a weaker recent record and for growth that was bought rather than built. That is a judgement on the share price, not on the management. Of the two Americans, Chevron, not Exxon, looks the more expensive.

The shale question for both the Americans

There is a risk that both American valuations share, and I think the market underrates it. Both companies increasingly depend on the Permian: Exxon plans about 2.5 million boepd there by 2030, and Chevron has reached 1 million boepd.

My worry is resource duration. Shale wells decline steeply, operators drill their best rock first, and SEC rules allow proved undeveloped reserves to be booked only for wells scheduled within five years, so proved shale reserves describe the next drilling programme rather than the life of the play. In fairness, that cuts both ways: Exxon may hold considerably more resource than its proved book shows, and shale technology has surprised the sceptics repeatedly.

But the question that matters is how much economically competitive inventory remains at realistic long-term prices, once well spacing, interference and parent-child effects are allowed for, and Permian well productivity has largely stopped improving as the industry moves from core to secondary acreage. I expect reserve durations in onshore US shale to disappoint, and the market, which values both companies as long-duration businesses, to discover that their inventory depletes faster than their plans imply. Guyana is a multi-decade conventional resource that produces for years on modest sustaining capital. The Permian is a treadmill that has to be fed with new wells every year, and I suspect it is shorter than it looks. That matters more for Chevron, which has no Exxon-scale offset of its own making.

TotalEnergies: the European that never stopped

If Exxon's premium rewards a company that stayed an oil company, TotalEnergies is the European that did the same but has not been paid for it. It kept its dividend whole in 2020 while Shell and BP cut theirs. It changed its name and built a power business, but unlike BP it never tried to fund the transition by shrinking its hydrocarbons, and it kept exploring and developing: Brazil, GranMorgu offshore Suriname, sanctioned in 2024, the restart of Mozambique LNG, one of the industry's deepest LNG portfolios and, further out, the Venus discovery in Namibia, though Venus has yet to prove commercial.

Its reserve life is more than twelve years, it replaced 116% of its production in 2025, it is targeting oil and gas growth of about 3% a year, and its company-reported return on capital averaged 15% over 2020–25, the highest of the five. Its power investments still have to show that they can earn proper returns, and that is a fair question. But it is a question about the margin of the business, not its foundations.

Shareholders have been rewarded accordingly. In dollars and with dividends reinvested, TotalEnergies has returned about 15% a year over ten years, against roughly 13% for both Shell and Exxon. All of Exxon's return came in the past five years, since its shares went nowhere between 2016 and 2021; its premium rewards a recent run of delivery rather than a long record. BP is the outlier on both horizons: a dollar invested ten years ago is worth about $1.44 today, against $3.38 to $4.00 in any of the other four.

Yet TotalEnergies trades at 9.8x 2028 earnings, offers a shareholder yield of 7.2%, and is priced for cash flow growth of about 1% a year. Some discount is warranted: security in northern Mozambique, emerging-market fiscal risk, a Paris listing with a shallower pool of energy capital than New York, and the same Russian write-offs as Shell. But of all five valuations, this is the discount I find hardest to defend, and the clearest sign that the market still lumps the European majors together when their reserve books say they are very different businesses.

Results week is not the verdict

Shell and TotalEnergies report on Thursday; BP, Exxon and Chevron on Friday. The third quarter was a downstream quarter: crude eased about 7% from the second quarter while refining margins roughly doubled, BP's indicator margin rising from $29.6 to $46.7 a barrel and Shell's from $24 to $42. Exxon's own published factors point to adjusted earnings of about $17 billion, against $14.7 billion in the second quarter, and Eni set the tone for Europe on 23 October by lifting its buyback by 12% and adding a special dividend. The headline numbers will flatter everyone.

The questions worth asking are about barrels and boards. Will Shell simply raise its buyback again, or say something credible about replacing reserves organically? The first is easy; only the second would change my view.

BP has already indicated that volatile trading conditions and stronger refining margins will provide a substantial boost to earnings and cash flow. The question is what happens to that money. Will the board use it to strengthen the balance sheet and restore shareholder distributions, or will it find another way to destroy shareholder value?

Can Chevron demonstrate that Hess is earning an adequate return on the price it paid? And is there any evidence in Exxon’s or Chevron’s Permian operations that well productivity is deteriorating or the quality of the remaining drilling inventory is declining?

Expensive, cheap, and overvalued

The market is very good at pricing this year's cash. It is less good at pricing reserves and judgement, which is where the differences between these five companies really lie. Any ranking also has to survive more than one oil price. Consensus already has every company earning less in 2028 than in 2026; at $60 Brent, Chevron's 2028 multiple rises to almost 22 times and Exxon's to 18, while Shell and TotalEnergies stay near 11. The order that follows holds across that range, which is one reason I have some confidence in it.

Exxon is expensive but not overvalued. It never stopped being an oil company, it found Guyana and stuck with it, and it bought Pioneer; my reservation is how long its shale barrels will last. Chevron pays Exxon's price for growth it bought rather than found, with the same shale exposure and less to fall back on. BP is cheap but not undervalued: a good company hobbled by three shortcuts, whose discount will close only when new leadership proves it can run the oil company it already has, and its board proves it can resist a fourth mistake. TotalEnergies, the European that kept faith with oil, is the most underrated of the five.

And Shell is the one I would question hardest. It is a business producing itself out, flattering its distributions with depletion and its earnings with trading, and priced as though neither were true. Anyone who has worked a reservoir knows the test that eventually applies to every oil company: it is worth what it can keep producing, not what it can pay out this year.

Notes on the data

Forecasts are MarketScreener consensus estimates published before third-quarter results; prices are closes on 26 October 2026; sterling converted at $1.3319. Track-record figures are from each company's annual results for 2020–2025, using its own headline measures: reported net income attributable to shareholders, and adjusted earnings as each defines them (ExxonMobil earnings excluding identified items, Chevron adjusted earnings, Shell adjusted earnings, BP underlying replacement cost profit, TotalEnergies adjusted net income). The gap between the two includes impairments and inventory effects. Company ROACE definitions differ and are not directly comparable. Shareholder returns are calculated from dividend-adjusted month-end prices in US dollars. Market-implied growth uses consensus 2028 free cash flow and a 9% cost of equity. EV/EBITDA remains imperfectly comparable between US GAAP and IFRS reporters. Views on exploration performance, LNG trading and shale reserve duration are the author's own.

Sources: MarketScreener valuation pages for all five companies; share prices from Digrin; annual results releases for ExxonMobil, Chevron, Shell, TotalEnergies and bp (2021, 2023, 2025); ExxonMobil 2030 corporate plan and 3Q 2026 earnings considerations; bp strategy reset, third-quarter 2026 trading statement and 2025 Form 20-F; Shell 2025 annual report and reserves statement; Shell ARC Resources acquisition disclosures; Chevron sensitivities and Hess completion announcement; Eni third-quarter results; Wood Mackenzie reserve-life data via Reuters; bp announcements on the Archaea Energy sale (August 2026); reporting of Shell's $400 million Namibia write-down (January 2025) and its 2014 exit from the Stabroek block (OilNOW).

Disclosure: At the time of publication, the author holds shares in BP. Figures reflect information available before third-quarter results. This article represents analysis and opinion, not investment advice.