Exxon’s Refineries Outearned Its Oil Wells, and No One Will Say What Maintenance Costs

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Clark Savage20

ExxonMobil made $7.169 billion refining and $7.088 billion pumping oil in the third quarter, the first time in at least six years the refineries won, with its Gulf Coast crude units at 100%. What it costs to keep them there is the one number neither ExxonMobil nor Chevron will publish.

By Energy News Beat | Oct. 30, 2026 | ExxonMobil and Chevron third-quarter 2026 results, both released Oct. 30; EIA data through August 2026; all figures in U.S. dollars

ExxonMobil earned $7.169 billion from refining in the third quarter and $7.088 billion from producing oil and gas. Refining won by $81 million, and by enough that Reuters found no quarter in at least six years when that had happened.

Group earnings were $15.413 billion, or $3.72 a share; adjusted, $4.23 against the $4.08 analysts compiled by LSEG expected.

The release credits “strong operational performance including 100% crude unit utilization at our U.S. Gulf Coast refineries and the second-highest U.S. Gulf Coast diesel production on record.” It does not say what it costs to keep them there.

Both companies just posted their best refining profits in years running plants at 98% to 100% of crude capacity, the regime that wears equipment out and forces turnarounds. Neither publishes a maintenance or turnaround-spend line. Both cut downstream capital before the boom. And schedule trackers have logged refiners moving planned 2026 maintenance into 2027. The bill is being deferred, not cancelled.

A third of the profit on a tenth of the capital

Energy Products took $2.006 billion of ExxonMobil’s $19.976 billion in cash capital spending through nine months, 10.0%, and produced $11.372 billion of $34.121 billion in earnings, 33.3%. Upstream took $16.645 billion and produced $20.752 billion: 83.3% and 60.8%. Appendix C shows the arithmetic.

That ratio is not proof of neglect. Refining is less capital-hungry per barrel than a deepwater field, and capex reflects projects sanctioned earlier. But the cash engine and budget point different ways. Chevron’s downstream is starker still: $653 million of $12.612 billion in capex, 5.2%, produced $8.982 billion of $24.206 billion in earnings, 37.1%.

Chart 1. ExxonMobil segment share of nine-month 2026 cash capital spending versus share of earnings. Sources: ExxonMobil 3Q26 Supplement Data; Energy News Beat calculation, arithmetic in Appendix C2.

The cut came before the boom

In 2025, the last full year before the war, Energy Products capex was $1.707 billion, down 23.0% from $2.218 billion in 2024, and 5.9% of the company’s $28.997 billion total against 8.6% a year earlier. Chevron’s downstream capex fell from $1.773 billion in 2023 to $928 million in 2025, a 47.7% cut.

The U.S. figure is the exception: U.S. Energy Products capex tripled, from $463 million to $1.386 billion, up 199%, tracking the Gulf Coast reconfiguration. The company does not split that between maintenance and growth.

Nor has the plan changed since the fighting started. The $27 billion to $29 billion 2026 budget came from the Dec. 9, 2025 corporate plan, eleven weeks before the war began Feb. 28, 2026, and investor relations head Jim Chapman told the Q3 call ExxonMobil will skip its December plan update. As Reuters columnist Ron Bousso wrote Friday, it is telling that the majors’ dividend policies and capital spending plans have remained largely unchanged since the start of the war.

Chart 2. ExxonMobil Energy Products cash capital spending, full years 2024 and 2025 and nine months of 2026. Sources: ExxonMobil 2025 Form 10-K; 3Q26 Supplement Data.

Running flat out

Five utilization measures circulate; none substitutes for another. EIA’s monthly survey put U.S. utilization at 97.6% in August 2026; its weekly survey read 92.8% for the week ended Oct. 23. Chevron reported crude utilization of 98% at its U.S. refineries. ExxonMobil reported 100% crude unit utilization at its U.S. Gulf Coast refineries, crude units only, Gulf Coast only. Its global fuels utilization is lower, quoted as a record year to date excluding Middle East impacts.

EIA’s own analysis put utilization averaging more than 95% of capacity between May and September, the highest for those months since 1998, and noted output was only the highest since 2019 because refining capacity has fallen 4% since then. The capacity report shows which pieces leave: distillation down 263,000 barrels a calendar day, or 1.43%; coking down 4.90%; hydrotreating down 2.51%; fluid catalytic cracking down 2.85%. The diesel-making units are retiring fastest.

Chart 4. U.S. refinery utilization by month, January 2024 through August 2026, against a 95% reference line. Source: EIA, series MOPUEUS2, released Oct. 30, 2026.

The bill is moving to 2027

IIR Energy compared the Feb. 1 calendar with Sept. 9: fall 2026 planned crude outages 144,000 barrels a day lower, fall 2027 283,000 barrels a day higher, with work at 10 crude units across seven refineries. Morgan Stanley’s Oct. 20 outlook has capacity sidelined for planned work 3.4 million barrels a day higher by 2Q27. Valero’s chief operating officer cited consultants putting about 1.5 million barrels a day of turnarounds deferred globally. The IEA puts global refining investment at just over $40 billion in 2026, about 15% below 2025, roughly half of it maintenance.

Gibson’s late-August report said the only confirmed turnaround on the PADD 3 slate was Exxon’s Beaumont facility, an FCC and at least two hydrotreaters running roughly 45 days from early December into mid-January. ExxonMobil is not idle: IIR tracked the 180,000 barrel-a-day Crude Unit A at Beaumont and the 108,000 barrel-a-day Crude Pipe Still 3 at Baytown in the first quarter.

The precedent: after a 24-week run above 95% in 1998, U.S. utilization fell to about 86% by mid-October as plants went into emergency maintenance. That is a precedent, not a forecast. Nor does everything get cut: inspection intervals under API 510, API 570 and API 653 carry legal and insurance consequences. What compresses is the opportunistic scope.

The honest counter-case

Chevron’s downstream chief told the Q3 call that more than 80% of its U.S. refinery turnarounds over the last two years finished with first-quartile duration, and that Pasadena’s debottlenecking added approximately 15% capacity at nominal cost. ExxonMobil reports turnaround costs down about 30% per asset and work 50% faster.

Those are real operational gains. Longer run lengths may be genuine engineering, and the 2027 bulge may be a planned cycle rather than a backlog. Public disclosure cannot distinguish genuine run-length extension from accumulated deferral. That is the honest finding: the question cannot be settled because the line does not exist.

Consumer and investor views

For a household, full-out refining cuts both ways. It buys supply: those Gulf Coast plants produced the second-highest volume of diesel on record. What it costs you is cushion. A system at 97.6% with 4% less capacity than in 2019 has nowhere to go but price when a compressor fails, and next autumn’s catch-up is when distillate tightens again. Woods said the quiet part out loud in August: “The utilization that we’ve seen can’t be sustained for the long term.”

For an investor, the tell is the capital line, not the earnings line. ExxonMobil generated $19.109 billion of free cash flow through nine months, returned $9.4 billion, cut net debt to $22.1 billion, $8 billion of it in the quarter, and pencilled in $20 billion of 2027 buybacks. Company-wide spending runs at 0.90 times depreciation, a whole-company ratio dominated by Upstream, not a refining measure.

If the per-asset gains are real, that harvest is sustainable. If they are partly deferral, the catch-up arrives as capex in 2027 and 2028, the same stretch when Morgan Stanley expects 3.4 million barrels a day of extra planned downtime.

What we could not verify, and what to watch

  • The Q3 2026 Forms 10-Q were not on file. ExxonMobil’s latest is dated 3, 2026, Chevron’s Aug. 6. Watch them for maintenance language and subsequent events.
  • No EIA statistic exists for average U.S. refinery age. The agency publishes none, so any “average refinery is 50-plus years old” figure belongs to trade press, not EIA.
  • Utilization here covers five unblended scopes: EIA monthly U.S. 97.6% (August), EIA weekly U.S. 92.8%, Chevron U.S. crude 98%, ExxonMobil U.S. Gulf Coast crude units 100%, and ExxonMobil global fuels, lower and quoted excluding Middle East impacts.
  • No summed annual maintenance figure appears here. If one is added, label it an Energy News Beat calculation.
  • Marathon’s 2026 El Paso turnaround, about $130 million over 45 days with 206,000 work hours, is a trade estimate, not a filing.

 

STU’S TAKE

Opinion. Every number is linked to its source.

Two refineries outearned the oil wells that feed them, and the company will not tell you what it costs to keep those refineries running. That is the story.

I have been around this industry long enough to be suspicious of a cost reduction that arrives in the same breath as a record run rate. ExxonMobil’s $2.006 billion of Energy Products capex against $11.372 billion of Energy Products earnings is not a scandal. It is a choice about where capital goes, and the answer is upstream, debt and buybacks.

The part that should make you sit up is the calendar. 144,000 barrels a day of planned fall 2026 crude work moved, and 283,000 barrels a day of it now sits in fall 2027. Work does not evaporate. It waits, and it usually comes back bigger.

I will not pretend the other side is empty. Chevron’s 80%-plus first-quartile turnaround durations and ExxonMobil’s 30% per-asset cost reduction are what good engineering looks like. If they have genuinely stretched run lengths, my worry is misplaced and the 2027 bulge is just a cycle.

But you cannot tell from outside, because there is no maintenance line. Not in the release, not in the 10-K, not in the presentation. Valero tells you 86% of its quarterly capex was sustaining. ExxonMobil and Chevron tell you nothing. That asymmetry is the finding.

So watch two numbers. When the 2027 capital plan lands in January, see whether downstream gets more than a rounding error. And when the fourth quarter prints, see whether the maintenance hit lands at the top of the $770 million to $1,030 million range. If both rise, the deferral was real and the bill is arriving.

 

 

Appendix

Sources, verbatim excerpts, data tables and methodology notes for “Exxon’s Refineries Outearned Its Oil Wells, and No One Will Say What Maintenance Costs.”

A. Sources (all accessed Oct. 30, 2026)

B. Verbatim excerpts

ExxonMobil 3Q26 release, on the quarter’s refining performance: “strong operational performance including 100% crude unit utilization at our U.S. Gulf Coast refineries and the second-highest U.S. Gulf Coast diesel production on record.” Link

Prepared remarks, on the refining program: “That includes investing approximately $17 billion in refining since 2019 to expand capacity and improve product mix and profitability.” Link

Prepared remarks: “We’ve increased crude processing capacity by nearly 10% since 2019.” Link

Prepared remarks, on Gulf Coast distillate: “grown distillate production by approximately 40%” and “we anticipate these investments across the U.S. will increase distillate production by another 100 thousand barrels per day.” Link

Prepared remarks, on turnaround performance: “We’ve also improved turnaround performance, reducing costs by approximately 30% and completing work 50% faster than previous turnaround cycles.” Link

Prepared remarks, fourth-quarter outlook: “We expect scheduled maintenance to be higher than in the third quarter for Product Solutions, with a corresponding impact on operating performance.” Link

Presentation slide 20, footnote 5, defining the turnaround comparison: “Turnaround improvement based on comparison to prior cycle turnaround for the same asset.” Link

Darren Woods, Q3 call, on brownfield expansions: they “bring on capacity at half the cost, roughly, of grassroots facility.” Link

Darren Woods, Q3 call, on Beaumont: “In 2023, we completed a $2 billion expansion that added the equivalent of a medium-sized refinery. That investment paid for itself in about 3 years.” Link

Jim Chapman, Q3 call, on the December plan: “unlike the approach of the last several years, we do not plan to host a formal corporate plan update event in December.” Link

Darren Woods to CNBC on Aug. 4, as reported by Reuters: “The utilization that we’ve seen can’t be sustained for the long term. So I think this refining challenge is going to be with the world for a while.” Link

Ron Bousso, Reuters, Oct. 30: “it is telling that the majors’ dividend policies and capital spending plans have remained largely unchanged since the start of the war.” Link

Chevron vice chairman Mark Nelson, Q3 call: “More than 80% of Chevron’s U.S. refinery turnarounds over the last two years were completed with first-quartile duration.” Link

Nelson, Q3 call, on Pasadena: “we accelerated debottlenecking to increase refinery capacity by approximately 15% at nominal cost.” Link

EIA, Today in Energy, Oct. 22, 2026, as quoted: utilization “averaging more than 95% of capacity between May and September, the highest for those months since 1998.” Link

Gibson, Aug. 28, 2026: “The only confirmed turnaround on the PADD 3 slate is Exxon’s Beaumont facility, covering an FCC and at least two hydrotreaters, running for roughly 45 days from early December to mid-January.” Link

IIR Energy, Sept. 17, 2026, on the deferral: a “measurable uptick in maintenance deferrals.” Link

Valero, Q3 call, on sustaining capital: “Capital investments for the quarter were $432 million, with $371 million for sustaining operations.” Link

IEA, World Energy Investment 2026: refining investment will “drop to just over USD 40 billion, about a 15% decrease from 2025. About half of spending is for upgrades and greenfield projects, and the other half is for maintenance at existing facilities.” Link

C. Data tables

C1. ExxonMobil cash capital and equipment expenditures by segment, nine months 2026 versus nine months 2025 ($ millions)

Segment 9M 2026 9M 2025 Change
Upstream United States 10,820 12,233 −1,413
Upstream Non-U.S. 5,825 6,043 −218
Upstream total 16,645 18,276 −1,631
Energy Products United States 1,386 463 +923
Energy Products Non-U.S. 620 789 −169
Energy Products total 2,006 1,252 +754
Chemical Products 736 845 −109
Specialty Products 221 316 −95
Corporate and Financing 368 445 −77
Worldwide total 19,976 21,134 −1,158

 

Source: ExxonMobil 3Q26 Supplement Data.

C2. The four percentages in the article, shown step by step

Ratio Numerator Denominator Result
Energy Products share of cash capex $2,006M $19,976M 2,006 ÷ 19,976 = 0.10042 = 10.0%
Energy Products share of earnings $11,372M $34,121M 11,372 ÷ 34,121 = 0.33329 = 33.3%
Upstream share of cash capex $16,645M $19,976M 16,645 ÷ 19,976 = 0.83325 = 83.3%
Upstream share of earnings $20,752M $34,121M 20,752 ÷ 34,121 = 0.60818 = 60.8%
Chevron downstream share of capex $653M $12,612M 653 ÷ 12,612 = 0.05178 = 5.2%
Chevron downstream share of earnings $8,982M $24,206M 8,982 ÷ 24,206 = 0.37106 = 37.1%
U.S. Energy Products capex growth $1,386M − $463M $463M 923 ÷ 463 = 1.994 = +199%
Energy Products capex change, 2025 vs 2024 $1,707M − $2,218M $2,218M −511 ÷ 2,218 = −0.2304 = −23.0%
Energy Products share of 2025 company capex $1,707M $28,997M 1,707 ÷ 28,997 = 0.05887 = 5.9%
Energy Products share of 2024 company capex $2,218M $25,647M 2,218 ÷ 25,647 = 0.08648 = 8.6%
Chevron downstream capex change, 2025 vs 2023 $928M − $1,773M $1,773M −845 ÷ 1,773 = −0.4766 = −47.7%
Company capex as a multiple of DD&A $19,976M $22,263M 19,976 ÷ 22,263 = 0.8973 = 0.90x
Valero sustaining capital share of quarterly capex $371M $432M 371 ÷ 432 = 0.8588 = 86%

 

Sources: ExxonMobil 3Q26 Supplement Data, ExxonMobil 2025 Form 10-K, Chevron 3Q26 release, Chevron 2025 Form 10-K, Valero Q3 call. All ratios are Energy News Beat calculations from the companies’ published line items. DD&A is depreciation, depletion and amortization for the nine months ended Sept. 30, 2026.

C3. Product Solutions scheduled-maintenance estimated earnings impact by quarter ($ millions)

Segment 4Q25 1Q26 2Q26 3Q26 4Q26e
Energy Products 230 680 770 590 770–1,030
Chemical Products 170 120 170 140 (in range)
Specialty Products 40 20 30 30 (in range)
Product Solutions total about 440 about 820 about 970 about 760 770–1,030
Upstream, for reference 260 150 260 290 180–260

 

Source: ExxonMobil 3Q26 Earnings Presentation, slide 20, “4Q26 maintenance outlook.” The 4Q26e column is company guidance, based on mid-October refining margins, forward estimates and operating expenses related to turnaround and planned maintenance activities (footnote 2). These are estimated earnings impacts, not spending figures, and are not comparable to a maintenance budget.

C4. U.S. refinery utilization by month, percent of operable capacity

Month 2024 2025 2026
January 86.1 87.1 91.4
February 82.7 85.2 89.0
March 88.7 89.5 91.6
April 89.5 90.8 90.1
May 93.5 94.3 94.0
June 94.2 95.6 96.5
July 92.4 95.8 96.5
August 94.0 95.4 97.6
September 90.4 93.2 not yet published
October 89.7 88.1 not yet published
November 91.6 93.4 not yet published
December 93.0 95.7 not yet published

 

Source: U.S. EIA, Monthly Refinery Report, series MOPUEUS2, released Oct. 30, 2026. September through December 2026 had not been published at the time of writing.

C5. U.S. refining capacity by unit type, latest annual report versus the prior year (barrels per calendar day)

Unit type Prior year Latest Change Percent
Crude distillation 18,423,493 18,160,493 −263,000 −1.43%
Coking 2,937,715 2,793,645 −144,070 −4.90%
Hydrotreating 17,440,634 17,002,116 −438,518 −2.51%
Fluid catalytic cracking 5,491,059 5,334,708 −156,351 −2.85%
Operating refineries (count) 132 130 −2 −1.52%

 

Source: U.S. EIA, Refinery Capacity Report. Percent changes computed by Energy News Beat from the published capacity totals.

C6. Chevron downstream cash capital spending, full years ($ millions)

Year Downstream capex Company total capex Downstream share
2023 1,773 — —
2024 1,694 — —
2025 928 — —
9M 2026 653 12,612 5.2%

 

Source: Chevron 2025 Form 10-K for the full-year figures; Chevron 3Q26 release for nine months 2026. Chevron does not publish a downstream sustaining-capital split.

D. Background and methodology

Scope. This article covers ExxonMobil’s and Chevron’s third-quarter 2026 results, both released Oct. 30, 2026, and the refining maintenance question that follows from them. ExxonMobil reports refining inside its Energy Products segment, which also includes fuels marketing, trading, aromatics and catalysts and licensing. Segment earnings are therefore not a pure refining number, and the article says so.

The refining-versus-drilling comparison is a same-column comparison of segment earnings in the third quarter: Energy Products $7,169 million against Upstream $7,088 million, a difference of $81 million, both from the 3Q26 Supplement Data. Reuters reported Oct. 30 that this was the first time in at least six years that ExxonMobil earned more from refining than from upstream. Chevron’s third-quarter downstream earnings also reached their highest point over the same six-year span.

Utilization scopes. Five separate measures appear in this article and are never blended: the EIA monthly survey (97.6% in August 2026), the EIA weekly survey (92.8% for the week ended Oct. 23, 2026), Chevron’s U.S. crude utilization (98%), ExxonMobil’s U.S. Gulf Coast crude unit utilization (100%, crude units only), and ExxonMobil’s global fuels utilization, which the company describes as a record year to date excluding Middle East impacts and which the article does not quantify.

Turnaround costs. The approximately 30% cost reduction and 50% faster completion are per-asset, like-for-like comparisons against the prior cycle turnaround for the same asset, per footnote 5 of the 3Q26 Earnings Presentation. They are not a 30% reduction in a maintenance budget, and the article does not present them that way.

Maintenance estimates. The $770 million to $1,030 million fourth-quarter figure is an estimated earnings impact, not capital spending. It combines the Energy Products, Chemical Products and Specialty Products segments, as shown on slide 20 of the presentation.

Disclosure. Neither company publishes a maintenance, sustaining-capital or turnaround-spend line in any document reviewed: the 3Q26 release, prepared remarks, presentation, supplement, the 2025 Form 10-K, or the Q2 2026 Form 10-Q. The Q3 2026 Forms 10-Q were not on file as of the evening of Oct. 30, 2026; EDGAR showed ExxonMobil’s most recent 10-Q dated Aug. 3, 2026 and Chevron’s dated Aug. 6, 2026.

Precedent. The 1998 episode is offered as a historical precedent, not a forecast. After a 24-week run above 95% utilization, U.S. utilization fell to about 86% by mid-October as facilities went into emergency maintenance, per Mansfield Energy.

What could not be verified

  • A published maintenance, sustaining-capital or turnaround-spend total for either company. None exists in the documents reviewed, which is the point of the article.
  • Any EIA statistic on the average age of a U.S. refinery. EIA publishes none, so no such figure is attributed to the agency here.
  • A company-stated global fuels utilization percentage for ExxonMobil. The company describes a record year to date excluding Middle East impacts without giving a number, so none is given.
  • A cost or timeline for the additional 100,000 barrels a day of U.S. distillate capacity, or for the Baytown reconfiguration. Neither has been disclosed.
  • Whether the 2027 turnaround bulge reflects genuine run-length limits or accumulated deferral. Public disclosure cannot distinguish the two, which is the honest finding of the piece.
  • A verbatim transcript of Valero’s third-quarter call. The only record reached was an AI-written summary, so Valero’s deferral comment is paraphrased and attributed rather than set as a direct quotation.
  • A barrel-per-day capacity figure for the Marathon El Paso unit. The trade report gives 206,000 work hours over roughly 45 days, which is what the article uses; the cost is a trade estimate, not a filing.

 

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