EOG Resources

EOG's total daily production rose to 1,410 mboe/d, up 2% sequentially and ahead of guidance and our expectations, though cash operating costs were a bit ahead of our forecast due to higher general and administrative costs. Still, capex of $1.6 billion was lower than both expected and guidance.

Why it matters: Shares declined by nearly 5%, but we attribute this to the broader macroeconomic environment as the market anticipates a potential Strait of Hormuz deal. But we think the earnings report was broadly a bit better than expected, while guidance was in line. More importantly, capital-efficient production helped EOG deliver free cash flow of $2.8 billion, better than we expected, of which EOG returned $1.8 billion to shareholders, meaning management returned nearly two-thirds of free cash flow to shareholders. Management leaned into share repurchases this quarter, as roughly 70% of the capital returns came in the form of buybacks at an average repurchase price of $135, roughly a 10% discount to value. We like this cash use as it allows shareholders to deepen their ownership at attractive prices.

The bottom line: We don't expect to meaningfully change our $150 fair value estimate for narrow-moat EOG. The stock trades in 3-star territory, but our Medium Uncertainty Rating means we need a slimmer margin of safety relative to other E&Ps. We maintain our Exemplary Capital Allocation Rating. Not only does management exercise capital discipline, but it also diligently leans into capital returns. Disciplined organic investments help its return on capital relative to the industry, while its inorganic investments are smartly countercyclical. EOG's crown jewel Delaware Basin asset underpins our cost advantage moat source, and strong execution has helped reduce its well costs there. But we think management has been intelligent with its other investments in its Utica gas play and its international portfolio as US shale matures.

We maintain our fair value estimate of $150 per share, as new guidance doesn't change our long-term view. EOG has executed well in the Delaware Basin, which has helped to reduce its well costs in the region. Additionally, we think management has made good decisions with its other investments in its Utica gas play and its international portfolio as US shale matures.

We assume oil (West Texas Intermediate) prices in 2026 and 2027 will average $81 and $72 per barrel, respectively. In the same periods, natural gas (Henry Hub) prices are expected to average $3.10 and $3.49 per thousand cubic feet. Terminal prices are defined by our long-term midcycle price estimates (currently $65/bbl Brent, $60/bbl WTI, and $3.70/mcf natural gas).

Our fair value implies enterprise value/EBITDA multiples of 5.2 times for 2026 and 5.8 times for 2027. We assume 2026 production of 1,407 thousand barrels of oil equivalent per day, slightly above the midpoint of guidance. Our assumed production levels drive 2026 EBITDA to $16.7 billion, and we expect free cash flow to reach $8.5 billion in the same period. We estimate 2027 total production, EBITDA, and free cash flow at 1,474 mboe/d, $14.9 billion, and $7.1 billion, respectively.

We assign EOG a Narrow Morningstar Economic Moat Rating based on cost advantage. EOG is primarily a US-based exploration and production company dedicated to the production of hydrocarbons in oil, natural gas liquids, and natural gas, though a plurality of its production volumes come from oil. Hydrocarbons are commodity products and therefore don’t exhibit pricing power, switching costs, or other moat sources that depend on either meaningful differentiation or a market niche. Consequently, moats are relatively rare in our E&P coverage. However, low-cost E&P producers, or those that maintain production costs well below the industry’s long-term marginal cost, can command a moat over their higher-cost counterparts. EOG’s breakeven oil price of less than $35 per barrel falls well below our estimated marginal cost of production at $65 per barrel of Brent and below the independent group average of just over $39 per barrel.

Prime Acreage Creates Cost Advantage

While technology can drive operational improvements (through longer laterals, for example), the breakthroughs the industry saw from the prior decade have been largely realized and are theoretically replicable. Instead, EOG and other narrow-moat E&Ps maintain their cost advantage primarily through access to low-cost resources with intrinsically low extraction costs. Even as the entire US E&P industry has shifted its focus toward generating excess returns on capital following years of overexpansion during the shale revolution, EOG has long since focused on containing costs and enhancing productivity.

EOG has furthered these goals by prioritizing the drilling of locations it classifies as premium, or those locations it believes would elicit a 30% wellhead internal rate of return at flat pricing of $45 West Texas Intermediate and $2.50 Henry Hub natural gas. Following a fourfold increase of these so-called premium locations from their initial 3,000 count, by 2021, EOG pivoted toward drilling locations it classifies as double premium, or locations it believes would now elicit a 60% wellhead internal rate of return at flat pricing of $45 West Texas Intermediate and $2.50 Henry Hub natural gas. By management’s own admission, it has roughly 10 years’ worth of double premium drilling inventory. We estimate EOG has roughly 25 years’ worth left of total inventory, of which a substantial minority comes from double premium inventory.

EOG enjoys this inventory partly due to its enviable position in a portion of Texas’ Permian Basin known as the Delaware Basin. At nearly half of its mix, it boasts a leading presence in the Delaware Basin with over 5,500 gross wells, which is more than any other US E&P firm we cover. The Permian exhibits some of the lowest supply costs among US shale plays, which allows for more efficient well production relative to other plays.

Among the US E&P firms we cover, EOG extracts among the highest volumes of hydrocarbons at 1,232 thousand barrels of oil equivalent per day in 2025. While reservoir quality matters most, we think well production matters because it allows E&P firms to spread their fixed costs and elicit higher margins as volumes rise.

In EOG’s case, leading well production allows EOG to enjoy some of the lowest cash operating costs in our US E&P coverage. In fact, since 2016, on a rolling quarterly basis, EOG’s cash operating costs are on average over 20% lower than its US E&P industry peer set. At year-end 2023, EOG ranked second in cash operating costs behind narrow-moat-rated Diamondback.

Given the company's very low-cost structure, our midcycle oil price of $65 Brent per barrel would have to fall by over 18% for EOG to start falling below our cost of capital. This is a harsh exercise since it would assume no incremental adjustments to production. We view this scenario as unlikely. This factor, coupled with its remaining quality inventory and an incentive compensation structure that penalizes EOG’s management for subpar returns on capital employed, gives us sufficient confidence that EOG will likely exceed its hurdle rate over the next 10 years.

EOG remains among the most technically proficient operators in the business. Initial production rates from its shale wells consistently exceed industry averages.

EOG avoids expensive mergers and acquisitions and uses proven exploration techniques to identify new prospects before the rest of the industry.

EOG's multibasin portfolio enables it to shift capital as market conditions dictate, prioritizing oil or gas volumes as appropriate and sidestepping areas where well costs have overheated.

The double premium portion of EOG's inventory could run out after 10-15 years if the company fails to replace the locations it drills with new opportunities.

EOG's scale is a double-edge sword; it must work harder to maintain a larger production base and drilling inventory.

A warmer winter means an excess surplus of gas that will still punish near-term pricing and pressure EOG's results.