EOG RESOURCES Q1 FY26 earnings call EOG

EOG refined its 2026 plan to increase oil and NGL production while holding capex at $6.5 billion, reallocating from Dorado dry gas toward foundational oil plays as oil prices spiked and gas softened. Management stressed the changes are modest — pulling Dorado to just under a frac fleet (exit rate ~800 MMcf/d vs a ~1 Bcf/d target), adding 5 net completions in the Delaware and 10 net in the Utica, largely from DUC inventory that had gotten ahead of completions. The reallocation is weighted to 2H 2026 and required essentially no new equipment, showcasing multi-basin flexibility. The raised full-year guide (+2,000 bbl/d oil, +6,000 bbl/d NGL) also reflects a genuine Q1 volume beat.

Management called the Iran conflict the most significant development for the business, estimating ~900 million barrels removed from global markets through June 2026 via Strait of Hormuz disruption. Even a quick resolution leaves a multi-year inventory rebuild, SPR replenishment, limited spare capacity and a higher geopolitical risk premium — a constructive, volatile oil backdrop with a higher floor. On gas, near-term pressure^📎 persists with Lower-48 storage above the 5-year average, but medium/long-term demand is expected to grow at a 3–5% CAGR through decade-end on rising LNG feed-gas and electricity demand, with prior global LNG oversupply fears reduced by damaged infrastructure abroad.

The regular dividend ($4.08/share annualized, never cut in 28 years, ~9% 3-year CAGR) is the foundation, supplemented lately by opportunistic buybacks, which management increasingly prefers over special dividends given the direct link between share-count reduction and dividend-growth capacity. EOG has repurchased over $7.1 billion since 2023, cutting share count more than 10%, with $2.9 billion remaining on authorization. Management is wary of procyclical buying at elevated prices and would rather build some cash for countercyclical deployment; net-debt-zero is not a target but is achievable in coming years. The 70% minimum return is designed to keep the program disciplined.

EOG holds 250,000 bbl/d of crude export capacity out of Corpus Christi, selling cargo-by-cargo with the flexibility to price domestic or Brent-linked; recent volatility let it sell numerous cargoes at premiums. On gas, the Cheniere LNG agreement ramps to the full 420,000 MMBtu/d in Q2, priced at JKM or Henry Hub at EOG's monthly election, plus a further 300,000 MMBtu/d of Henry Hub-linked feed gas — nearing ~1 Bcf/d of LNG exposure. Waha exposure is under 7% but still dented Q1 gas realizations; relief is expected around Q4 with new Permian egress.

Q1 volumes, per-unit cash operating costs and DD&A all beat guidance midpoints despite a major winter storm and third-party downtime. Drilled feet per day rose 22% in the Utica, 13% in the Powder River Basin and 12% in the Eagle Ford versus the 2025 average; completed feet per day led at Delaware +17% and Eagle Ford +12%, aided by ~20% higher max frac pumping rate per fleet since 2023. EOG targets 2–3 mile laterals in the Delaware and 3–4 mile in the Utica and Eagle Ford. The Janus Delaware processing plant averaged 300 MMcf/d (94% utilization) since November 2025 and hit a record 316 MMcf/d at 100% utilization in March, lowering Delaware GP&T costs.

EOG is in the exploration phase in the UAE (carbonate mudrock, ADNOC partnership) and Bahrain (tight gas sand, Bapco partnership), rock types similar to its domestic unconventional plays. UAE's potential exit from OPEC is seen as immaterial to EOG, which expects returns — not quotas — to drive any development. Management expressed strong confidence in partner alignment and contract sanctity even amid the regional conflict; some staff were repositioned and timelines slipped slightly, with initial results now expected in 2H 2026. The 2026 plan was designed with flexibility given the dynamic situation.

The ~year-old Encino acquisition increased EOG's oil production by roughly 10% and is now managed as one Utica asset, delivering consistent-to-upside productivity and margin/well-cost improvement, with staggered landing zones in the thicker north showing good results. A separate Eagle Ford bolt-on — described as a needle-in-a-haystack with near-zero production fitting EOG's acreage like a jigsaw piece — was quickly tied into infrastructure and has already yielded a number of high-return wells within its first year. Management reiterated that getting deals done at prices where all-in returns compete (against a ~10–12% production drag) is the perennial challenge, favoring countercyclical timing.