Exxon Mobil

ExxonMobil's second-quarter 2026 adjusted earnings fell slightly short of expectations. Earnings and cash flow significantly improved as timing effects from mark-to-market derivative requirements unwound during the quarter. Shareholders' return guidance was unchanged.

Why it matters: In the current environment, earnings are likely to be messy as uncertainty translates into commodity price volatility, lost volumes, and results that may differ from benchmarks. However, Exxon's underlying progress on portfolio improvement continues while it's well-positioned to capitalize on the current environment, particularly historically high refining margins. The company continues to high-grade its portfolio, reaching $16.3 billion in cumulative structural cost savings since 2019 and on track for its $20 billion 2030 target. Total upstream production was 4.5 million oil-equivalent barrels per day, flat with a year ago, despite record Permian production of more than 1.8 mboe/d, due to lost Middle East volumes.

The bottom line: Our $156 fair value estimate and narrow-moat Rating are unchanged. Given Exxon's larger Qatar position, it has a relatively high exposure to the Strait of Hormuz closure. The impact from the closure is about 750 mboe/d relative to 2025 levels or about 15% of global production. However, as the quarter shows, the price impact is largely offsetting the volume impact. Importantly, Exxon is perhaps best positioned among peers to benefit from the currently strong refining margins given its relatively large downstream footprint. Also, in the event of the strait opening, refining margins are likely to prove stickier than oil and natural gas prices given the high number of global refining outages and now low inventory levels that need to be rebuilt.

Shares are trading at our fair value. Commodity prices will likely fall in the wake of a deal that fully opens the strait, weighing on shares. However, we'd view this as a buying opportunity given prices are unlikely to revert to prewar levels soon and Exxon will continue to increase its earnings capacity in the years to come.

We are increasing our fair value estimate to $156 per share from $142 to reflect higher oil and gas prices since our last update. Our forecast also includes the company's updated 2030 guidance for higher earnings and lower capital spending.

This implies a forward enterprise value/EBITDA multiple of 6.0 times our 2026 EBITDA forecast of $102 billion. Our fair value estimate is derived using Morningstar’s standard three-stage discounted cash flow methodology. This methodology derives a terminal value using our assumptions for long-term earnings growth and return on new invested capital. This valuation methodology also incorporates our moat rating, which reflects how long we expect a given firm to deliver excess returns on invested capital from a discounted cash flow analysis.

In our DCF model, we assume Brent prices of $87 per barrel in 2026 and $76 per barrel in 2027. Our long-term oil price assumption is $65 per barrel. We assume a weighted average cost of capital of 7.4%.

We assume Exxon’s production will grow over the next five years, approaching its target of 5.5 mmboe/d in 2030, but it could be lower due to divestments, which we do not explicitly model. Otherwise, we include margin expansion on higher prices and the addition of higher-margin volumes, mainly from the Permian and Guyana. We forecast steady earnings growth in the downstream and chemical segments as new projects and capacity come online over the next five years. Exxon expects to add another $9 billion in earnings from these segments by 2030, relative to 2024 levels, which we largely include in our model.

Exxon earns a Narrow Morningstar Economic Moat Rating even as we forecast narrower future excess returns than achieved historically. However, we expect a material improvement from the weak levels of 2015-20, sufficient to maintain a narrow moat.

We continue to see Exxon’s integrated model as a source of competitive advantage. Historically, we rated Exxon as the highest-quality integrated firm, given its ability to capture economic rents along the oil and gas value chain. While its peers operate a similar business model with the same goal, they have largely failed to replicate Exxon’s success, as evidenced by their comparatively lower margins and returns. Although Exxon continues to operate a highly integrated model and has aligned its management structure to do so, its lead in return on capital employed, a key performance metric among the group, has eroded as upstream performance waned. However, we consider the integration of lower-cost assets, particularly in the downstream and chemical segments, as an element of its cost advantage moat source that is still intact.

Aside from the secular decline in commodity prices from earlier levels, the erosion of Exxon’s returns is largely attributable to its pursuit of production volume growth through acquisitions and investment in higher-cost assets like oil sands. The most notable and ill-timed acquisition was the purchase of XTO Energy, an unconventional natural gas firm, in 2010 for $41 billion. Ultimately, Exxon wrote off most of the acquisition when it impaired its North American dry gas assets in the past several years. Exxon has recorded over $24 billion in upstream impairments since 2016 as natural gas prices fell from the time of the deal. The impairments reflect Exxon’s view that future natural gas prices will remain lower than when the deal was struck and be insufficient to earn an appropriate return on these assets.

Exxon’s reserves and reserve life have also declined as lower prices (reserves are booked at year-end based on average prices for the year) have required it to remove higher-cost reserves from its proved reserve balances. The low prices in 2020 ($42/bbl Brent) resulted in Exxon’s proved reserves falling to 15.2 billion boe from 22.4 billion boe at year-end 2019. This demonstrates the marginal amount of reserves the company has acquired, discovered, and developed recently.

The decline was primarily from the debooking of bitumen reserves, largely tied to the Kearl oil sands mining project, which totaled 4.6 billion barrels or nearly 20% of total reserves in 2015. However, even at higher prices, these reserves are not economical. Exxon only booked bitumen reserves of 701 million barrels in 2016 and 1.0 billion barrels in 2017, when oil prices averaged $45/bbl and $54/bbl, respectively. Although they were largely restored in 2018 ($71/bbl) and 2019 ($64/bbl), they were removed again in 2020, falling to 81 million barrels at the end of 2020, or less than 1% of total reserves. With higher average prices in 2022, they increased to 2.4 billion barrels.

Whether or not the bitumen reserves are booked is a technical matter; based on prices, they could grow or decline in any given year. The important thing is that the bulk of Exxon’s bitumen resources are not able to deliver excess returns below our midcycle price of $65/bbl, indicating that a large portion of reserves over the last 10 years do not qualify as a low-cost resource.

Removal of North American dry gas reserves also contributed to the decline in total reserves. After reserves peaked at 26.3 trillion cubic feet in 2011 shortly after close of the XTO deal, they fell steadily to 19.0 Tcf in 2019 and collapsed to 13.4 Tcf at year-end 2020, reflecting the steady decline in US natural gas prices. Exxon’s reserves and reserve life fell to 15.2 billion boe and 10.4 years in 2020 from an average of 23.9 billion and 15.8 years, respectively, the last 10 years.

The erosion of asset competitiveness during the last decade, demonstrated by impairments and debookings, helps explain the decline in upstream ROCEs from an average of 22% from 2010 to 2014 to an average of 6% from 2015 to 2019. Exxon’s upstream assets were not built for the lower prices of those years.

The impairments and reserve bookings suggest Exxon’s upstream does not have a narrow moat, given our midcycle price assumptions. Moat ratings, however, are forward-looking, and although reserve base quality has declined in the last 10 years, it does not tell the whole story of where Exxon is going.

Although we expect overall returns to remain low, we see relatively high incremental returns on new invested capital.

Exxon has reduced and focused its capital budget on the highest-return areas, primarily Guyana and the Permian. Exxon estimates Guyana and Permian can deliver 10% returns at oil prices down to $35/bbl, which is supported by third-party researcher Rystad. Neither of these assets is yet fully reflected in reserve bookings. However, in this case, reserve disclosures are less useful for projecting future returns and evaluating moats than explaining the past. For perspective, Exxon has reported discoveries of 11 billion boe (about 5 billion net, excluding government take) in Guyana, but its Canada/other Americas segment, which excludes oil sands and includes Guyana, has total reserve bookings of about 1.1 billion boe, including only 1.2 billion of new discoveries booked in the last six years.

Reserve bookings are even less applicable for evaluating Exxon’s Permian position. For unconventional acreage, reserves are only booked once wells are drilled, leaving all undrilled acreage with zero associated reserve bookings. This explains why when Exxon estimated Permian net resource to be 10 billion boe, 70% liquids, total US booked reserves were only 4.1 billion boe. Exxon has booked 3.5 billion barrels of liquid reserves in the US since 2015 as it has drilled wells. Its most recent recoverable resource estimate in the Permian, including Pioneer, is 18 billion barrels.

The company's current reserve base largely does not reflect Guyana and Permian's potential to uplift returns. Both regions are expected to be the primary driver of new volumes during the next five years while commanding nearly 40% of upstream spending the next five years by Rystad’ s estimates, although the Permian spending will depend on oil prices, given its flexibility. These areas will constitute 70% of upstream spending, including LNG, according to Exxon.

In Guyana, Exxon expects to have eight floating production storage and offloading units with a gross capacity of 1.7 mmb/d in 2030, compared with 1 FPSO and 30 mboe/d net in 2020. Meanwhile, Permian production should rise to 2.5 mmboe/d in 2030, compared with 550 mboe/d in 2022, largely due to the addition of Pioneer's assets.

In total, we expect upstream earnings per barrel to increase to $13/bbl at $65/bbl, well below historical levels at higher prices but higher than the $10/bbl in 2018 when oil prices were $71/bbl Brent. The implied margin expansion is largely due to the mix shift as Exxon adds higher-margin volumes from Guyana, but also a reduction in North American nonassociated dry gas production by 50% by 2025. The large amount of domestic natural gas production from the XTO acquisition dragged on returns, contributing to US upstream ROCEs averaging less than 1% in 2015-19, including impairments. As these volumes fall and are backfilled by higher-return Permian liquids volumes, returns should improve for the US upstream segment. Assuming modest growth in capital employed and the associated earnings improvement, we estimate Exxon can improve total upstream ROCEs to nearly 13% within our forecast period, below historical levels, but enough to earn a narrow economic moat for the segment.

Exxon's downstream and chemicals position remains strong and is set to improve as well. Recent performance has been uneven, with market margins swinging from historically poor to historically high levels in 2022. Ultimately, we expect margins to revert to midcycle levels during our forecast. Meanwhile, investments are going toward improving yields of higher-value products, which should lead to margin expansion and a higher midcycle earnings capacity than in the past.

The size and physical integration of Exxon’s refining and chemical manufacturing operations create an unequaled advantage peers cannot easily replicate. Approximately 80% of its refining capacity is integrated with chemical manufacturing facilities. The integrated network delivers wider margins and returns than peers, thanks to a low-cost position derived from economies of scale and the ability to process a variety of feedstocks into the highest-value products. Combining the two should also provide greater value as transportation fuel demand wanes and chemical demand grows during the next decade.

Exxon's combined downstream and chemical segments’ returns on capital employed have historically far outpaced the group average, and while returns have been below upstream’ s at times, they have been much more consistent. In contrast to upstream returns, which have steadily declined since 2014 when oil prices broke below $100/bbl, downstream and chemical returns have remained volatile but in line with historical averages. From 2010 to 2014, downstream and chemical combined returns averaged 18% compared with 17% from 2015 to 2019. We expect the combined segments’ returns to steadily recover from 2020 troughs and reach 20% by the end of our forecast based on improved market conditions and investments in increasing high-margin products.

Our decision to maintain our narrow moat rating, considering Exxon's relatively weak top-line ROIC, contrasts our decision to downgrade our moat ratings for other integrated firms with similarly weak top-line ROIC profiles. In these latter cases, uncertainty around future strategies related to the energy transition and the amount of investment in oil and gas are too great to maintain a narrow moat. Exxon is only committing a relatively small amount of capital ($20 billion by 2030) to low-carbon technologies and not reorienting its business model away from oil and gas production. This investment will also depend on developing marketable products and policy support while going toward areas where Exxon has or can develop expertise. Also, while Exxon’s top-line ROICs and excess returns look similarly weak, we view its underlying reinvestments as more attractive.

This strategy to keep focus on hydrocarbons holds risk as well, but over the next decade, we do not see a material decline in global oil and gas demand as likely. Given that hydrocarbons require investment in existing and new fields to maintain global supply, we have a greater level of confidence in what Exxon’s returns will be a decade from now as opposed to firms that are investing in lower-return, highly competitive areas such as renewable power generation.

Exxon is exposed to several environmental, social, and governance-related risks. Still, in our view, these do not imperil its moat rating as most fall outside the 10-year narrow moat window or are not probable or material enough risk to cause material value destruction. Exxon’s primary ESG risk stems from carbon emissions in its operations and use of its products, emissions, effluents, and waste generated in operations, such as oil spills and poor community relations.

The risk from carbon emissions is most likely to materialize through a carbon tax, which increases the price of end products to consumers, reducing demand over time and threatening Exxon’s core business. We expect carbon taxes to gain greater adoption over time, but think the impact on hydrocarbon demand remains more than a decade away.

According to our estimates, Exxon’s upstream greenhouse gas intensity is rather high for its peer group at 27.8 kg CO2e/boe (2024) due to its oil sand operations. However, it has improved emissions intensity during the last five years while investing to reduce methane leakage and flaring. It has introduced emission reduction targets, including reducing corporate-wide greenhouse gas intensity by 20%-30% by 2030 from 2016 levels and achieving net zero Scope 1 and 2 emissions from operated assets by 2050. However, about 90% of emissions from oil and natural gas occur during combustion (Scope 3), which the company can do little about.

Oil spills are an ever-present risk for oil companies operating offshore and can devastate a firm's value, as BP’s Macondo incident in the Gulf of Mexico shows. While oil companies regularly cause spills, most are immaterial in size, and associated fines and cleanup costs are manageable. Large spills such as Macondo are rare and do not factor into our scenario modeling.

Lastly, global oil companies such as Exxon often operate in frontier areas such as Guyana, Mozambique, and Papua New Guinea, where new oil and gas development can cause friction with local communities. Poor community relations can cause development delays, higher costs, or concession disputes. In more mature areas such as Nigeria, Exxon has experienced social unrest that disrupted operations. These risks come with the territory and are manageable, in our view. A delay or disruption of any one project is unlikely to materially affect the value of a firm of Exxon’s size.

Exxon responded to shareholder concerns by hiring outside managers in key roles, appointing new board members, and increasing disclosures.

Exxon will see its portfolio mix shift toward liquids pricing as gas volumes decline and new oil projects come online. Cash margins are expected to improve as a result, thanks to increased volumes from Permian and Guyana.

With coordination between upstream and downstream operations, as well as integrated refining and chemical facilities, Exxon achieves a high level of integration that creates value instead of simply owning the assets.

Exxon's increased spending to grow volumes risks resulting in lower returns as it did previously. The timing could be off, given the current global oversupply and soft demand. Lower oil prices would result in lower-than-expected earnings.

Despite activist pressure and new board members, Exxon has not sufficiently reduced hydrocarbon investment levels and continues developing long-life projects with a high risk of becoming stranded.

Exxon's low-carbon investments could disappoint, as delays and lack of government support erode expected returns.