EOG Resources, Inc. (EOG) Earnings

Management highlights

- **Financial Performance & Shareholder Returns** • Q2 2026 delivered record adjusted EPS, adjusted cash flow per share, and free cash flow, driven by both strong oil prices and consistent high-quality operational execution. • Returned $1.8 billion to shareholders in Q2 2026: $540 million via the regular dividend (which has not been cut or suspended in 28 years) and $1.3 billion via opportunistic share repurchases. $11.7 billion remains available under the current share repurchase authorization. • EOG maintains a commitment to returning at least 70% of annual free cash flow to investors, and closed Q2 with $4.9 billion in cash and net debt of $3 billion, for a very strong, flexible balance sheet with a WTI break-even price below $50 per barrel for the full 2026 plan. - **Commodity Market Outlooks** • For oil: Supply disruptions from the Iran conflict have reduced global commercial and strategic inventories; near-term demand reductions are viewed as temporary rationing that will normalize over time. Energy security as a national priority is expected to drive structural inventory restocking and higher long-term demand, supporting prices above mid-cycle levels with upside skewed volatility. • For natural gas: North American demand is strengthening driven by growing LNG exports, rising electricity demand, industrial growth, and grid reliability needs. EOG's medium to long-term outlook is constructive, and the company holds a low-cost natural gas position well positioned to capture this demand growth. - **Operational Excellence & Exploration Progress** • Organic exploration is highlighted as a core competitive advantage for EOG, enabled by proprietary geological data and decades of drilling expertise across multiple basins. EOG is a first mover in international unconventional development, partnering with ADNOC (UAE) and BAPCO (Bahrain). • UAE exploration: Two 1-mile lateral wells came online in June 2026, averaging over 25,000 barrels of oil per well in the first 30 days of natural flow, exceeding early expectations. EOG will target 2+ mile laterals for additional wells this year, and has already replicated domestic operational best practices (such as in-basin surface sand processing) to cut costs. The exploration program covers a 900,000-acre concession. • Bahrain operations: Activity has been intermittent due to the ongoing regional conflict, with employee safety as the top priority; results are still targeted for H2 2026 if conditions allow. • Domestic operational efficiency: Slight service cost inflation has been largely mitigated, with EOG still on track to achieve a low single-digit full-year reduction in well costs. EOG's in-house drilling motor program has delivered large efficiency gains: 70% higher average drilled footage per motor run since 2023, with 20-64% gains across basins compared to third-party motors, eliminating potential costs of $100,000-$250,000 per motor failure.

Guidance

• Full-year 2026 capital expenditure guidance is maintained at $6.5 billion, unchanged from prior guidance. • Full-year 2026 production guidance is updated to 5% oil production growth and 14% total production growth, reflecting year-to-date operational performance. • The 2026 full-year plan is projected to generate $8 billion in free cash flow at strip pricing using guidance midpoints. • No final 2027 capital and production plan has been finalized; EOG expects 2027 to align with its three-year scenario of low single-digit oil growth (based on a $60-$80 WTI price range) and will retain flexibility to adjust based on market conditions through the end of 2026.

Segment performance

EOG does not break out formal separate product segment financials with revenue contribution percentages in this call. Aggregate company performance for Q2 2026 is as follows: adjusted earnings per share of $5.07, adjusted cash flow from operations per share of $8.29, and record free cash flow of $2.8 billion. Total production volumes came in above the guidance midpoint, with nearly 500 barrels of oil per day contributed by initial production from the UAE exploration wells, which are reported in the Other International segment. Capital expenditures for Q2 came in below the guidance midpoint due to operational timing shifts primarily in the Gulf region. Operational performance by core domestic basin is outlined below: 1. Delaware Basin: Year-to-date drilling feet per day increased 13% and completed lateral feet per day increased 5% year-over-year, leading to a $15 per foot reduction in direct well costs, which now average less than $710 per foot. The Janus gas processing plant (current capacity 300 million cubic feet per day, expandable by another 300 million cubic feet per day) has averaged >99% utilization year-to-date, delivering a net back uplift of more than 65 cents per MCF. 2. Eagleford: Year-to-date drilling feet per day increased 4% and completed lateral feet per day increased 11% year-over-year, cutting direct well costs to less than $525 per foot, the lowest in EOG's history in the play. EOG has identified an Austin chalk sweet spot on 60,000 net acres (leased at an average of $1,200 per acre) with drilled wells achieving <1 year payout at $65 WTI, adding 1 year of two-mile lateral drilling inventory at current activity levels. 3. Dorado: Direct well costs are less than $700 per foot, 7% lower year-over-year, after 16% longer lateral lengths were implemented in 2026. The Verde gas pipeline has delivered a 50 cent per MCF net back uplift year-to-date. 4. Utica: The Zeno acquisition has exceeded the $150 million synergy target ahead of schedule, with direct well costs driven below $600 per foot. In-basin sand supply chain optimization is expected to be completed by the end of 2026, and proprietary in-house production optimizers have delivered a 5% improvement in base production and 5% reduction in downtime.

Risks & headwinds

• Ongoing regional conflict in the Middle East has caused intermittent operational disruptions in Bahrain, and creates uncertainty around the trajectory and duration of oil supply disruptions that contribute to near-term oil price volatility. • Geopolitical risk and regulatory uncertainty are key considerations for all international exploration projects, requiring risk-adjusted return hurdles that account for political stability, rule of law, and partner alignment. • Canada's unconventional resources face existing egress (takeaway capacity) constraints that represent a key barrier to development, even where the resource base is attractive. • Early-stage international exploration projects have higher initial well costs that will require maturation of local oilfield service capacity and application of EOG's operational best practices to reduce over time.

Analyst Q&A

• Q: Given the 2026 capital shift to oil over gas that proved correct, and management's constructive oil price outlook at current forward curves, will EOG continue this capital shift for 2027? /

  A: The 2026 plan is unchanged, and the prior capital reallocation to oil has already positioned EOG well for 2027. It is too early to finalize 2027 specifics, but given current market fundamentals pointing to a need for incremental oil supply, 2027 is expected to align with EOG's existing three-year plan of low single-digit oil growth, with full optionality to adjust based on evolving macro conditions. (201 characters)

• Q: What are the next steps and timeline for the UAE exploration program, and are there mandatory work requirements to move to commercial development? /

  A: The program is in a 3-year exploration phase with ADNOC holding a back-in option, with no strict mandatory timelines for commercialization. EOG will continue gathering data from initial wells, monitor long-term production performance after artificial lift is installed, test repeatability across different geologic areas of the 900,000-acre concession, and wait for local unconventional service capacity to mature before moving toward commercial development. (297 characters)

• Q: What is the outlook for the new Austin chalk sweet spot in Eagleford, including leasing status and capital allocation versus core Eagleford development? /

  A: EOG has already leased most of the identified 60,000-acre sweet spot at $1,200 per acre, with 12 drilled wells confirming <1 year payout and >100% returns at $65 WTI, which is competitive with core Eagleford assets. The play adds 1 full year of drilling inventory at current activity levels and will be mixed evenly into existing Eagleford capital allocation, developed over the next several years. (291 characters)

• Q: How do early UAE unconventional results compare to U.S. plays, and what are expected well cost trends there? /

  A: Geologically, the UAE play is analogous to Eagleford, with matching rock type, product mix, API gravity, and gas-oil ratio matching pre-drill models. Initial well costs are higher at this early exploration stage, but costs are expected to decline over time as EOG applies domestic best practices, brings in specialized unconventional equipment, and develops local in-basin supply chains like surface sand processing. The average total vertical depth is around 10,000 feet. (301 characters)

• Q: What is EOG's outlook for natural gas, and does exploration have a commodity bias based on this outlook? /

  A: EOG remains constructive on natural gas, forecasting 3-5% compound annual demand growth through the end of the decade driven by rising LNG exports, AI-related electricity demand growth, industrial reshoring, and baseload grid reliability needs. Exploration is primarily return-driven, but EOG has a slight bias toward oil opportunities due to oil's generally higher margins compared to gas, and will only pursue high-return gas opportunities that compete with existing inventory. (310 characters)