# EOG Resources, Inc. (EOG) — Narrative, third quarter 2026 All amounts are in US dollars. "Q3 2026" is the quarter ended September 30, 2026. ## Business *Source: Annual Report on Form 10-K for the fiscal year ended December 31, 2025, accession 0000821189-26-000054.* EOG Resources is one of the largest independent (non-integrated) crude oil and natural gas producers in the United States. It explores for, develops, produces and markets crude oil and condensate, natural gas liquids (NGLs) and natural gas, almost entirely from US onshore basins, with a smaller natural gas business offshore Trinidad and early-stage exploration in Bahrain and the United Arab Emirates. Nearly all of its revenue comes from selling the hydrocarbons it produces. Oil and NGLs together made up 84% of 2025 production revenue, down from 91% in 2024. A second, lower-margin revenue line, gathering, processing and marketing ($4.91 billion in 2025), comes from buying and reselling third-party oil and gas, from fees for gathering third-party gas, and from sales of EOG-owned sand. EOG uses that activity to fill firm pipeline capacity and spare capacity at its own facilities. The strategy is to be "among the highest return and lowest cost producers." EOG drills mostly prospects it generated internally, judges projects on rate of return and payback, and keeps the balance sheet conservative. It runs its own cost programs: a downhole drilling-motor program, faster completion techniques, extended laterals and self-sourced frac sand. **Scale.** At December 31, 2025, estimated net proved reserves were 5,514 million barrels of oil equivalent (MMBoe): 1,905 million barrels (MMBbl) of crude oil and condensate, 1,510 MMBbl of NGLs and 12,592 billion cubic feet of natural gas. About 99% were in the United States and 1% in Trinidad. Reserves rose 766 MMBoe during 2025, a year in which EOG also completed the Encino acquisition (described below). EOG produced 1,232.2 thousand barrels of oil equivalent per day (MBoed) in 2025 and employed about 3,400 people. **Segments.** For reporting, management treats all major US producing areas as one operating segment, and reports Trinidad and Other International separately. In the first nine months of 2026, the United States supplied $23.73 billion of the $24.09 billion in operating revenues. **US operating areas.** The 2025 output and 2026 plans for each area were: - **Delaware Basin (Permian, West Texas and New Mexico).** This is the largest area: 318.7 thousand barrels per day (MBbld) of oil, 199.4 MBbld of NGLs and 1,179 million cubic feet per day (MMcfd) of gas in 2025, from the Wolfcamp, Bone Spring and Leonard plays. EOG completed 393 net wells there in 2025 and planned about 300 for 2026. - **South Texas.** This area covers the Eagle Ford oil play (about 565,000 net acres) and the Dorado dry-gas play (about 160,000 net acres). It produced 121.3 MBbld of oil in 2025. EOG planned about 115 net Eagle Ford wells and 40 net Dorado wells for 2026. - **Appalachian Basin (Utica play, Ohio).** EOG holds about 1,100,000 net acres here, including 135,000 net mineral acres. Much of that position came with the Encino acquisition of August 1, 2025, which brought 675,000 core net acres for $5.7 billion, including Encino's net debt. EOG completed 55 net wells there in 2025 and planned about 85 for 2026. - **Rocky Mountain.** This area covers the Powder River and Williston basins. EOG completed 34 net wells there in 2025 and planned about 45 for 2026. **International.** Offshore Trinidad, EOG produced about 230 MMcfd of natural gas in 2025. It sells the gas to the National Gas Company of Trinidad and Tobago and its subsidiary, and sells condensate to Heritage Petroleum and BP Trinidad and Tobago. Under a 2024 farmout with BP Trinidad and Tobago, EOG is building the Coconut platform. In Bahrain, a 2025 exploration participation agreement with Bapco Energies covers a gas prospect and includes interests in producing legacy wells. In Abu Dhabi, EOG holds 100% of, and operates, the Unconventional Onshore Block 3 oil exploration concession awarded in May 2025. After a three-year appraisal, ADNOC has an option to participate in any production concession. **Marketing and customers.** Most US oil moves by pipeline to the Gulf Coast, Cushing, the Permian, the Northeast and the Midwest, and some is exported from Corpus Christi. Gas goes to markets across the United States and to the Dawn Hub in Ontario. Some gas is sold to a liquefaction facility near Corpus Christi at a price linked to the Platts Japan Korea Marker or Henry Hub, at EOG's election. Two refining-industry purchasers each took more than 10% of 2025 revenues. A 10-year contract signed in February 2024 to sell 180,000 MMBtu per day of domestic gas is indexed mainly to Brent crude. Deliveries begin in 2027, and EOG accounts for the contract as a mark-to-market derivative. **Capital return policy.** Starting with 2024, EOG has committed to return at least 70% of annual free cash flow to shareholders through regular dividends, special dividends and buybacks. Here free cash flow means operating cash flow before certain balance-sheet changes, minus total capital expenditures. ## Risk factors *Source: FY2025 Form 10-K, Item 1A, accession 0000821189-26-000054. The Q3 2026 Form 10-Q (accession 0000821189-26-000227) contains no Item 1A update.* These are the 10-K's risks most specific to EOG: - **Commodity prices drive almost everything.** Cash flow, reserves and the ability to pay dividends and buy back stock all depend on oil, NGL and gas prices. A sustained price decline can make wells uneconomic and force reserve write-downs and asset impairments. EOG estimates that each $1.00 per barrel change in oil (with the related NGL move) changes 2026 net income by about $175 million. Each $0.10 per Mcf change in gas changes it by about $61 million (sensitivities as of September 30, 2026). - **Most production is unhedged.** The 10-K says a majority of forecast 2026 production is exposed to market prices. EOG's hedges are mainly gas swaps and collars plus small NGL swaps, which cap upside on the hedged volumes and carry counterparty risk. - **Capital needs and access to financing.** EOG relies on cash flow, cash on hand and capital markets to fund drilling. Low prices, weaker credit markets, ratings changes, or lenders and investors pulling back from oil and gas for climate reasons could raise its borrowing costs or limit funding. - **Cost inflation may outrun efficiency gains.** Tariffs and other inflationary pressures could offset the savings from drilling-motor, completion, extended-lateral and sand programs. In the Q3 2026 10-Q, management added the Middle East conflict as a source of such pressure. - **Reserve estimates and replacement.** Reserve figures are judgment-based and may be revised down. Production declines unless EOG keeps finding or buying new reserves, and leasing or drilling bans could get in the way. - **Acquisition risk.** Due diligence may miss title or environmental defects, and acquired reserves, production or costs may disappoint. The Encino integration is the live example. - **Operational hazards.** These include blowouts, spills, pipeline ruptures, severe weather and cyber or physical attacks, and insurance may not cover every loss. Operations also need large amounts of water, and drought restrictions could raise costs. - **Takeaway and infrastructure constraints.** Selling production depends on third-party gathering, processing, pipeline, refining, liquefaction and export capacity. In newer plays that capacity may lag new production. - **Customer and counterparty credit.** Buyers and derivative counterparties may fail to pay or perform. Production in remote locations may then have no other buyer on acceptable terms. - **Regulation, climate policy and taxes.** Federal leasing and permitting limits, methane and greenhouse-gas rules, hydraulic-fracturing restrictions and climate disclosure mandates could raise costs or delay drilling. So could the loss of tax provisions such as the immediate deduction for intangible drilling costs, a global minimum tax or a carbon tax. Some of EOG's leases in New Mexico, North Dakota and Wyoming are on federal land. - **International exposure.** Operations in Trinidad, Bahrain and the UAE face higher taxes and royalties, forced contract renegotiation, expropriation, sovereign-immunity limits on enforcing claims, and currency restrictions. - **Cybersecurity and terrorism.** Attacks on EOG's own systems, or on third-party pipelines, exchanges and power grids, could halt production or sales. The 10-K adds that generative AI is making phishing and identity fraud more sophisticated. - **Dividends and buybacks are discretionary.** The Board can cut or stop dividends and repurchases at any time if cash flow after capital spending falls short. ## Management's discussion: fiscal 2025 *Source: FY2025 Form 10-K, Item 7, accession 0000821189-26-000054.* **Earnings fell as oil prices dropped, even though volumes grew strongly.** Net income was $4.98 billion in 2025, down from $6.40 billion in 2024. Total operating revenues fell 4% to $22.63 billion, mainly because gathering, processing and marketing revenue dropped $886 million. Revenue from EOG's own production edged up 1% to $17.67 billion. Average NYMEX oil fell 14% to $64.78 per barrel, while Henry Hub gas rose 51% to $3.43 per MMBtu. - **Crude oil and condensate.** Revenue fell 10% to $12.50 billion. EOG's realized price dropped 15% to $65.63 per barrel, while volumes rose 6% to 522 MBbld. - **NGLs.** Revenue rose 13% to $2.38 billion on 17% higher volumes (288 MBbld), despite a 4% lower price ($22.58 per barrel). - **Natural gas.** Revenue rose 80% to $2.79 billion. The realized price rose 39% to $3.02 per Mcf and deliveries rose 30% to 2,533 MMcfd, reflecting Permian associated gas and higher Utica and Dorado output. Total production rose to 1,232.2 MBoed from 1,062.1. The growth came mainly from the Utica, where Encino was consolidated from August 1, 2025, and from the Permian. **Costs grew with the larger asset base.** Operating expenses rose $631 million to $16.25 billion: - **Gathering, processing and transportation (GP&T)** rose $412 million to $2.13 billion, of which $375 million came from the Utica. - **Depreciation, depletion and amortization (DD&A)** rose $353 million to $4.46 billion. - **General and administrative (G&A)** rose $151 million to $820 million, including about $100 million of Encino-related costs. - **Impairments** totaled $843 million, against $391 million in 2024. That includes $709 million on proved properties, mainly writing down the Barnett Shale and Woodford Oil Window assets for "play-specific economics and resource allocation." EOG sold both positions in 2026. - **Interest expense** rose $97 million to $235 million on new debt. The effective tax rate was unchanged at 22%. **Encino acquisition.** On August 1, 2025, EOG bought Encino Acquisition Partners, a private Utica producer, for $4.47 billion in cash plus $1.2 billion of assumed senior notes. EOG redeemed those notes at closing for about $1.29 billion. No goodwill was recorded. **Cash flow and capital allocation.** Operating cash flow fell to $10.04 billion from $12.14 billion. The largest cause was a $1.09 billion increase in net cash paid for income taxes and tax-credit purchases. Separately, in February 2025 EOG paid about $700 million of 2024 federal taxes that IRS storm relief had allowed it to postpone. Total 2025 spending on exploration, development and other property was $13.6 billion including Encino. EOG paid $2.2 billion of dividends and bought back $2.6 billion of stock. The quarterly dividend rose from $0.975 to $1.02 per share in 2025. **Balance sheet.** EOG issued $3.5 billion of senior notes in July 2025 to help fund Encino and $1.0 billion in November 2025. It repaid $500 million of 3.15% notes at maturity in April 2025 and redeemed $750 million of 4.15% notes early in December 2025. A new $3.0 billion revolving credit facility maturing December 2030 replaced the prior $1.9 billion facility and was undrawn. Year-end cash was $3.4 billion. Senior notes outstanding were $7.89 billion, all at fixed rates, and debt-to-total capitalization rose to 21% from 14%. No notes mature in 2026. **2026 plan as set in February.** EOG budgeted $6.3–6.7 billion of capital spending, concentrated on the Delaware Basin, Eagle Ford, Dorado and Utica, and expected higher oil and total production than in 2025. In January 2026 it agreed to sell its northern Midland Basin position, which produced about 4 MBbld of oil, for $165 million. That sale closed on February 18, 2026. ## Current quarter: Q3 2026 *Sources: Quarterly Report on Form 10-Q for the quarter ended September 30, 2026, accession 0000821189-26-000227; the supplemental financial data furnished with the Q3 2026 results on Form 8-K, accession 0000821189-26-000226.* **Background: an oil-price windfall from the Middle East conflict.** Management says that, compared with its expectations at the start of 2026, EOG realized higher oil prices "as a result of the ongoing conflict in the Middle East." The conflict has also disrupted maritime transportation routes for these commodities. Average NYMEX oil for the first nine months was $83.62 per barrel, up 25% year on year, and Henry Hub gas averaged $3.60, up 6%. EOG's realized composite oil price peaked at $98.15 per barrel in Q2 2026, then eased to $86.72 in Q3. That compares with $65.95 in Q3 2025. **Q3 2026 against Q3 2025.** - **Revenue and earnings.** Total operating revenues rose 46% to $8.55 billion. Net income rose to $2.78 billion ($5.33 per diluted share) from $1.47 billion ($2.70). Operating income was $3.59 billion against $1.84 billion. - **Production revenue.** Revenue from EOG's own production rose 39% to $6.34 billion. Oil revenue rose 35% to $4.39 billion, mostly because of price ($1.05 billion of the $1.15 billion increase). Oil volumes rose 3% to 550.4 MBbld. - **NGLs and gas.** NGL revenue rose 42% to $858 million and gas revenue rose 53% to $1.09 billion. In both, about 15% higher volumes (357.1 MBbld of NGLs, 3,153 MMcfd of gas), mainly from the Utica and Permian, added to higher prices: $26.13 per barrel and $3.74 per Mcf. - **Total production** was 1,433.1 MBoed against 1,301.2. The prior-year quarter included only two months of Encino. - **Gains outside production.** EOG booked $242 million of gains on asset sales, against an $18 million loss a year earlier. It also booked $105 million of derivative gains, of which $68 million was on the Brent-linked gas contract. - **Unit costs** were roughly flat at $20.80 per barrel of oil equivalent (Boe), against $20.86. That figure covers lease and well, GP&T, DD&A, G&A and interest. GP&T rose $106 million, mostly in the Utica. G&A fell $43 million to $196 million as Encino deal costs dropped out. - **Taxes.** Taxes other than income rose $92 million to $401 million on higher severance taxes. The effective income tax rate rose to 22% from 19% because certain 2025 state tax benefits tied to Encino did not recur. **Q3 2026 against Q2 2026.** Diluted earnings per share rose to $5.33 from $5.15, but EOG's adjusted (non-GAAP) earnings per share fell to $4.87 from $5.07. Realized prices fell: revenue per Boe was $48.05, down from $50.52. In reported earnings, that decline was more than offset, mainly by larger asset-sale gains ($242 million, against $58 million in Q2) and higher mark-to-market derivative gains. EOG's adjusted measure strips out both. Adjusted net income was $2.54 billion. **Nine months.** Revenue was $24.09 billion, up 42%. Net income was $7.49 billion ($14.18 per diluted share), against $4.28 billion ($7.81). Operating cash flow was $11.45 billion, against $7.43 billion. That increase came from $4.92 billion more production revenue and $609 million less cash tax, partly offset by $895 million of higher cash operating costs. Total expenditures fell to $5.56 billion from $11.97 billion, which had included Encino. EOG reports free cash flow (non-GAAP) of $6.47 billion for the nine months and $2.18 billion for Q3. **Portfolio pruning.** EOG sold three non-core positions in 2026: - **Northern Midland Basin:** $165 million, closed February 18, 2026. - **Barnett Shale:** $220 million, agreed in July and closed September 15, 2026. - **Woodford Oil Window:** $180 million, closed October 19, 2026 (see Subsequent events). Asset-sale proceeds for the nine months were $394 million, with $331 million of net gains, mainly from the Barnett sale and Permian lease exchanges. The Barnett and Woodford interests together produced about 16 MBoed in Q3, of which about 2 MBbld was oil. EOG also finalized the Encino purchase price allocation in Q3, adding $30 million to oil and gas properties. **Operations.** Drilling concentrated on the Delaware Basin, Eagle Ford and Utica. Oil and NGLs fell to about 66% of US volumes in the first nine months, from 69% a year earlier, as gas from the Utica grew. In Trinidad, EOG finished the Mento drilling program, started a new multiyear program and continued work toward putting the Coconut platform into service. In the UAE, crude oil production began in June 2026. **Shareholder returns.** On May 20, 2026, the Board doubled the buyback authorization from $10 billion to $20 billion. - **Buybacks.** In the first nine months EOG repurchased 19.8 million shares for about $2.70 billion. That included about 7.05 million shares in Q3 at an average of $142.99. About $10.6 billion of the authorization remained at September 30. Shares outstanding fell to 518.5 million on October 29, 2026, from 536.5 million in February. - **Dividends.** EOG paid $1.02 per share each quarter, $1.63 billion in total for the nine months. **Balance sheet.** At September 30, 2026: - Cash was $5.75 billion, up from $3.40 billion at year-end. - Total debt was $7.92 billion, with $7.89 billion of fixed-rate senior notes. - Debt-to-total capitalization was 19%. On EOG's non-GAAP net-debt basis it was 6.2%. - The $3.0 billion revolver was undrawn. **Outlook (as of the Q3 10-Q).** EOG kept its 2026 capital budget at $6.3–6.7 billion. Relative to 2025, it expects full-year oil production up about 5% and total production up about 14%. Gas hedges for November–December 2026 are 450,000 MMBtu per day of swaps at $3.79 plus 70,000 MMBtu per day of collars. For 2027, 120,000 MMBtu per day of collars sit between a $3.42 floor and a $4.41 ceiling. Deliveries under the Brent-linked gas contract begin in 2027. EOG valued that contract at $229 million at September 30. ## Subsequent events *Source: Q3 2026 Form 10-Q (Note 12, Note 3 and Item 2), accession 0000821189-26-000227.* - **Woodford Oil Window divestiture closed.** During Q3 2026, EOG agreed to sell its entire interest and related fixed assets in the Woodford Oil Window for $180 million, subject to customary closing adjustments. The sale closed on October 19, 2026. The filing does not name the buyer. - **Dividend increase.** On November 5, 2026, the Board raised the quarterly dividend from $1.02 to $1.10 per share. The first payment at the new rate is due January 29, 2027, to holders of record on January 15, 2027. - **Nothing else disclosed.** Beyond the Woodford sale and the dividend increase, the 10-Q reports no post-quarter acquisitions, borrowings or note issuances.