EOG Resources Reports Third Quarter 2025 Results

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Nov 06, 2025, 16:15 ET

HOUSTON, Nov. 6, 2025 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported third quarter 2025 results. The attached supplemental financial tables and schedules for the reconciliation of non–GAAP measures to GAAP measures and related definitions and discussion, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

Key Financial Results In millions of USD, except per–share, per–Boe and ratio data
GAAP	3Q 2025	2Q 2025	1Q 2025	4Q 2024	3Q 2024
Total Revenue	5,847	5,478	5,669	5,585	5,965
Net Income	1,471	1,345	1,463	1,251	1,673
Net Income Per Share	2.70	2.46	2.65	2.23	2.95
Net Cash Provided by Operating Activities	3,111	2,032	2,289	2,763	3,588
Total Expenditures	8,544	1,883	1,546	1,446	1,573
Current and Long–Term Debt	7,694	4,236	4,744	4,752	3,776
Cash and Cash Equivalents	3,530	5,216	6,599	7,092	6,122
Debt–to–Total Capitalization	20.3 %	12.7 %	13.8 %	13.9 %	11.3 %
Cash Operating Costs ($/Boe)	10.50	10.05	10.31	10.15	10.15

Non–GAAP
Adjusted Net Income	1,472	1,268	1,586	1,535	1,644
Adjusted Net Income Per Share	2.71	2.32	2.87	2.74	2.89
Adjusted CFO¹	3,031	2,496	2,813	2,635	2,988
Capital Expenditures	1,648	1,523	1,484	1,358	1,497
Free Cash Flow	1,383	973	1,329	1,277	1,491
Net Debt	4,164	(980)	(1,855)	(2,340)	(2,346)
Net Debt–to–Total Capitalization	12.1 %	(3.5 %)	(6.7 %)	(8.7 %)	(8.6 %)
Cash Operating Costs ($/Boe) ^2,3	9.93	9.94	10.31	10.15	10.05

Third Quarter Highlights

Earned adjusted net income of $1.5 billion, or $2.71 per share
Generated $1.4 billion of free cash flow
Paid $545 million in regular dividends and repurchased $440 million of shares
Oil, NGLs and natural gas production above guidance midpoints
Capital expenditures and per–unit operating costs better than guidance midpoints
Closed on the acquisition of Encino Acquisition Partners (Encino)

Third Quarter 2025 Highlights and Cash Return

Volumes and Capital Expenditures

Volumes	3Q 2025	3Q 2025 Guidance Midpoint	2Q 2025	1Q 2025	4Q 2024	3Q 2024
Crude Oil and Condensate (MBod)	534.5	532.4	504.2	502.1	494.6	493.0
Natural Gas Liquids (MBbld)	309.3	305.0	258.4	241.7	252.5	254.3
Natural Gas (MMcfd)	2,745	2,735	2,229	2,080	2,092	1,970
Total Crude Oil Equivalent (MBoed)	1,301.2	1,293.3	1,134.1	1,090.4	1,095.7	1,075.7

Capital Expenditures ($MM)	1,648	1,650	1,523	1,484	1,358	1,497

From Ezra Yacob, Chairman and Chief Executive Officer
"EOG delivered another quarter of strong operational performance. Third quarter oil, gas, and NGL volumes exceeded the midpoints of our guidance. Higher volumes, combined with lower–than–expected per–unit cash operating costs and DD&A, helped drive outstanding financial results.

We generated substantial free cash flow of $1.4 billion, which helped support nearly $1.0 billion of cash return to shareholders, including $440 million of opportunistic share repurchases. As of quarter–end, we have committed to return 89% of our estimated annual free cash flow to shareholders, with the potential to return additional cash over the balance of the year.

Our ability to deliver operational excellence quarter after quarter is the result of EOG's unique culture and the quality of our multi–basin portfolio. EOG's foundational assets, the Delaware Basin, Eagle Ford, and Utica, are delivering strong returns, exceeding our expectations. In the Utica, the integration of the Encino assets is proceeding exceptionally well, with continued incremental efficiency gains. Our emerging and international assets are also performing well, with strong well results in Dorado, the Powder River Basin, and Trinidad, along with continued progress in our exploration prospects in Bahrain and the UAE.

Our business has never been stronger. Our pristine balance sheet provides unmatched flexibility to continue to improve our high–return, long–duration asset base while delivering significant cash returns through commodity price cycles. EOG has never been better positioned to create long–term value for our shareholders."

Regular Dividend and Third Quarter Share Repurchases
The Board of Directors today declared a dividend of $1.02 per share on EOG's common stock. The dividend will be payable January 30, 2026, to shareholders of record as of January 16, 2026. This dividend represents an indicated annual rate of $4.08 per share. EOG has never suspended or reduced its regular dividend.

During the third quarter, the company repurchased 3.8 million shares for $440 million under its share repurchase authorization. EOG has $4.0 billion remaining on its current share buyback authorization.

Third Quarter 2025 Financial Performance

Prices

NGL and natural gas prices decreased in 3Q compared with 2Q, partially offset by higher crude oil & condensate prices

Volumes

Oil production of 534.5 MBod was above the midpoint of the guidance range
NGL production of 309.3 MBbld was above the midpoint of the guidance range
Natural gas production of 2,745 MMcfd was above the midpoint of the guidance range
Total company equivalent production of 1,301.2 MBoed was above the midpoint of the guidance range

Per–Unit Costs

LOE, non–GAAP G&A and DD&A costs decreased in 3Q compared to 2Q, while GP&T costs increased. Encino acquisition–related costs increased GAAP G&A costs in 3Q compared to 2Q

Hedges

Mark–to–market hedge gains increased GAAP earnings per share in 3Q compared with 2Q
Cash received to settle hedges increased adjusted non–GAAP earnings per share in 3Q compared with 2Q

Free Cash Flow

Adjusted cash flow from operations was $3.0 billion
Incurred $1.6 billion of capital expenditures
Generated $1.4 billion of free cash flow

Cash Return and Working Capital

Paid $545 million in regular dividends
Repurchased $440 million of stock
Closed on the acquisition of Encino for $5.7 billion, subject to post–closing adjustments
Issued $3.5 billion of senior notes in conjunction with the Encino acquisition

Third Quarter 2025 Operating Performance

Lease and Well

QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower workover expenses
Guidance Midpoint: Lower primarily due to lower workover expenses and operating and maintenance costs

General and Administrative (Non–GAAP)

QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower employee–related expenses
Guidance Midpoint: Lower primarily due to lower employee–related expenses

Gathering, Processing and Transportation Costs

QoQ: Increased primarily due to the impact of higher Utica production from the integration of Encino operations
Guidance Midpoint: Lower primarily due to lower natural gas gathering and processing fees

Depreciation, Depletion and Amortization

QoQ: Decreased primarily due to the impact of higher Utica production and well mix
Guidance Midpoint: Lower primarily due to the addition of lower–cost reserves

Third Quarter 2025 Results vs Guidance
(Unaudited)
See "Endnotes" below for related discussion and definitions.		3Q 2025
	3Q 2025	Guidance Midpoint ⁶	Variance	2Q 2025	1Q 2025	4Q 2024	3Q 2024
Crude Oil and Condensate Volumes (MBod)
United States	532.9	531.0	1.9	503.1	500.9	493.5	491.8
Trinidad	1.6	1.4	0.2	1.1	1.2	1.1	1.2
Total	534.5	532.4	2.1	504.2	502.1	494.6	493.0
Natural Gas Liquids Volumes (MBbld)
Total	309.3	305.0	4.3	258.4	241.7	252.5	254.3
Natural Gas Volumes (MMcfd)
United States	2,511	2,525	(14)	1,977	1,834	1,840	1,745
Trinidad	230	210	20	252	246	252	225
Other International⁷	4	0	4	0	0	0	0
Total	2,745	2,735	10	2,229	2,080	2,092	1,970

Total Crude Oil Equivalent Volumes (MBoed)	1,301.2	1,293.3	7.9	1,134.1	1,090.4	1,095.7	1,075.7
Total MMBoe	119.7	119.0	0.7	103.2	98.1	100.8	99.0

Benchmark Price
Oil (WTI) ($/Bbl)	64.95			63.71	71.42	70.28	75.16
Natural Gas (HH) ($/Mcf)	3.07			3.44	3.66	2.79	2.16

Crude Oil and Condensate – above (below) WTI ⁸ ($/Bbl)
United States	1.02	0.80	0.22	1.13	1.48	1.40	1.79
Trinidad	(7.21)	(5.00)	(2.21)	(9.21)	(10.30)	(9.81)	(12.01)
Natural Gas Liquids – Realizations as % of WTI
Total	32.7 %	34.0 %	(1.3 %)	35.6 %	36.8 %	33.9 %	29.8 %
Natural Gas – above (below) NYMEX Henry Hub ⁹ ($/Mcf)
United States	(0.36)	(0.40)	0.04	(0.57)	(0.30)	(0.40)	(0.32)
Natural Gas Realizations ($/Mcf)
Trinidad	3.80	3.60	0.20	3.65	3.78	3.86	3.68
Other International⁷	3.27	0.00	3.27	0.00	0.00	0.00	0.00

Total Expenditures (GAAP) ($MM)	8,544			1,883	1,546	1,446	1,573
Capital Expenditures (non–GAAP) ($MM)	1,648	1,650	(2)	1,523	1,484	1,358	1,497

Operating Unit Costs ($/Boe)
Lease and Well	3.60	3.70	(0.10)	3.84	4.09	3.91	3.96
Gathering, Processing and Transportation Costs⁵	4.90	5.10	(0.20)	4.41	4.48	4.37	4.50
General and Administrative (GAAP)	2.00	1.50	0.50	1.80	1.74	1.87	1.69
General and Administrative (non–GAAP)^2,3	1.43	1.50	(0.07)	1.69	1.74	1.87	1.59
Cash Operating Costs (GAAP)	10.50	10.30	0.20	10.05	10.31	10.15	10.15
Cash Operating Costs (non–GAAP)^2,3	9.93	10.30	(0.37)	9.94	10.31	10.15	10.05
Depreciation, Depletion and Amortization	9.77	9.85	(0.08)	10.20	10.32	10.11	10.42

Expenses ($MM)
Exploration and Dry Hole	71	75	(4)	85	75	60	43
Impairment (GAAP)	71			39	44	276	15
Impairment (excluding certain impairments (non–GAAP))¹⁰	71	70	1	28	44	23	15
Capitalized Interest	27	21	6	11	12	13	12
Net Interest (GAAP)	71	83	(12)	51	47	38	31
Net Interest (non–GAAP)¹¹	71	83	(12)	45	47	38	31

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)
(GAAP)	6.8 %	7.5 %	(0.7 %)	7.3 %	7.6 %	6.8 %	6.5 %
(non–GAAP)³	6.8 %	7.5 %	(0.7 %)	7.3 %	7.6 %	6.8 %	7.2 %
Income Taxes
Effective Rate	19.4 %	20.5 %	(1.1 %)	23.2 %	22.1 %	23.0 %	21.6 %
Current Tax Expense ($MM)	75	180	(105)	301	370	454	240

Fourth Quarter and Full‐Year 2025 Guidance¹²
(Unaudited)
See "Endnotes" below for related discussion and definitions .	4Q 2025 Guidance Range			4Q 2025 Midpoint	FY 2025 Guidance Range			FY 2025 Midpoint
Crude Oil and Condensate Volumes (MBod)
United States	541.4	–	546.0	543.7	518.7	–	521.9	520.3
Trinidad	1.1	–	1.5	1.3	1.1	–	1.5	1.3
Total	542.5	–	547.5	545.0	519.8	–	523.4	521.6
Natural Gas Liquids Volumes (MBbld)
Total	315.5	–	330.5	323.0	280.0	–	286.0	283.0
Natural Gas Volumes (MMcfd)
United States	2,740	–	2,840	2,790	2,250	–	2,310	2,280
Trinidad	190	–	210	200	220	–	240	230
Total	2,930	–	3,050	2,990	2,470	–	2,550	2,510
Crude Oil Equivalent Volumes (MBoed)
United States	1,313.6	–	1,349.8	1,331.7	1,173.7	–	1,192.9	1,183.3
Trinidad	32.8	–	36.5	34.7	37.8	–	41.5	39.7
Total	1,346.4	–	1,386.3	1,366.4	1,211.5	–	1,234.4	1,223.0
Crude Oil and Condensate – above (below) WTI ⁸ ($/Bbl)
United States	(0.50)	–	1.00	0.25	0.35	–	1.35	0.85
Trinidad	(5.25)	–	(2.75)	(4.00)	(8.40)	–	(6.90)	(7.65)
Natural Gas Liquids – Realizations as % of WTI
Total	28.0 %	–	38.0 %	33.0 %	31.5 %	–	36.5 %	34.0 %
Natural Gas – above (below) NYMEX Henry Hub ⁹ ($/Mcf)
United States	(0.80)	–	(0.10)	(0.45)	(0.95)	–	0.05	(0.45)
Natural Gas Realizations ($/Mcf)
Trinidad	3.00	–	4.20	3.60	3.40	–	3.90	3.65

Capital Expenditures ¹³ ($MM)	1,600	–	1,700	1,650	6,200	–	6,400	6,300

Operating Unit Costs ($/Boe)
Lease and Well	3.50	–	4.00	3.75	3.70	–	3.90	3.80
Gathering, Processing and Transportation Costs⁵	4.75	–	5.25	5.00	4.65	–	4.85	4.75
General and Administrative	1.40	–	1.70	1.55	1.45	–	1.65	1.55
Cash Operating Costs	9.65	–	10.95	10.30	9.80	–	10.40	10.10
Depreciation, Depletion and Amortization	9.25	–	10.25	9.75	9.70	–	10.30	10.00
Expenses ($MM)
Exploration and Dry Hole	40	–	80	60	270	–	310	290
Impairment (excluding certain impairments)¹⁰	30	–	110	70	180	–	260	220
Capitalized Interest	34	–	38	36	85	–	89	87
Net Interest	64	–	68	66	228	–	232	230

TOTI (% of revenues from sales of crude oil and
condensate, NGLs and natural gas)	6.0 %	–	8.0 %	7.0 %	6.5 %	–	8.5 %	7.5 %
Income Taxes
Effective Rate	20.0 %	–	25.0 %	22.5 %	19.0 %	–	24.0 %	21.5 %
Current Tax Expense ($MM)	220	–	320	270	970	–	1,070	1,020

Third Quarter 2025 Results Webcast
Friday, November 7, 2025, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/investors

About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com.

Investor Contacts
Pearce Hammond 713–571–4684
Neel Panchal 713–571–4884
Shelby O'Connor 713–571–4560

Media Contact
Kimberly Ehmer 713–571–4676

Endnotes
1)	Cash flow from operations before changes in working capital and certain acquisition–related costs.
2)	Cash Operating Costs consist of LOE, GP&T and G&A. Excludes Encino acquisition–related G&A costs of $68 million for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per–Boe impact of such Encino acquisition–related costs on G&A and total Cash Operating Costs for 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Third Quarter 2025 Results vs Guidance" above. G&A per Boe (GAAP) for 3Q 2025 was $2.00 and for 2Q 2025 was $1.80.
3)	Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non–GAAP) and G&A (non–GAAP) for 3Q 2024 exclude a state severance tax refund and related consulting fees, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per–Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024 was $(0.10) as set forth in "Third Quarter 2025 Results vs Guidance" above.
4)	Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.
5)	Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line–item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.
6)	GAAP and non–GAAP distinctions apply solely to actual results and do not pertain to EOG's third quarter 2025 guidance midpoint disclosures.
7)	Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distribution costs.
8)	EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.
9)	EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.
10)	In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).
11)	Net interest expense (non–GAAP) excludes Encino acquisition–related financing commitment costs of $6 million in 2Q 2025.
12)	The forecast items for the fourth quarter and full year 2025 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8–K filing, replaces and supersedes any previously issued guidance or forecast.
13)	The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non–Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

Glossary
Acq	Acquisitions
Adjusted CFO	Cash flow from operations before changes in working capital and certain acquisition–related costs
ATROR	After–tax rate of return
Bbl	Barrel
Bn	Billion
Boe	Barrels of oil equivalent
Bopd	Barrels of oil per day
CAGR	Compound annual growth rate
Capex	Capital expenditures
CO2e	Carbon dioxide equivalent
DD&A	Depreciation, Depletion and Amortization
Disc	Discoveries
Divest	Divestitures
EPS	Earnings per share
Ext	Extensions
GAAP	Generally Accepted Accounting Principles
G&A	General and administrative expense
G&P	Gathering and processing
GHG	Greenhouse gas
GP&T	Gathering, processing & transportation expense
HH	Henry Hub
LOE	Lease operating expense, or lease and well expense
MBbld	Thousand barrels of liquids per day
MBod	Thousand barrels of oil per day
MBoe	Thousand barrels of oil equivalent
MBoed	Thousand barrels of oil equivalent per day
Mcf	Thousand cubic feet of natural gas
MMBoe	Million barrels of oil equivalent
MMcfd	Million cubic feet of natural gas per day
NGLs	Natural gas liquids
NYMEX	U.S. New York Mercantile Exchange
OTP	Other than price
QoQ	Quarter over quarter
TOTI	Taxes other than income
USD	United States dollar
WTI	West Texas Intermediate
YoY	Year over year
$MM	Million United States dollars
$/Bbl	U.S. Dollars per barrel
$/Boe	U.S. Dollars per barrel of oil equivalent
$/Mcf	U.S. Dollars per thousand cubic feet

This press release and any accompanying disclosures may include forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG's acquisition of Encino Acquisition Partners, LLC (Encino) are forward–looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward–looking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino's assets and operations or the strategic rationale for, or anticipated benefits of, EOG's acquisition of Encino, in each case are forward–looking statements. Forward–looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward–looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward–looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward–looking statements include, among others:

the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs),
natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
the success of EOG's cost–mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;
the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;
the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights–of–way, and EOG's ability to retain mineral licenses, concessions and leases;
the impact of, and changes in, government policies, laws and regulations, including climate change–related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions–related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
the impact of climate change–related legislation, policies and initiatives; climate change–related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;
the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety–related initiatives and achieve its related targets, goals, ambitions and initiatives;
EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations);
EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
the extent to which EOG's third–party–operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;
the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent to which EOG is successful in its completion of planned asset dispositions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
the economic and financial impact of epidemics, pandemics or other public health issues;
geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and
the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10–K for the fiscal year ended December 31, 2024, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10–Q or Current Reports on Form 8–K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward–looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward–looking statements. EOG's forward–looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward–looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

Historical Non–GAAP Financial Measures:
Reconciliation schedules and definitions for the historical non–GAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com.

Cautionary Notice Regarding Forward–Looking Non–GAAP Financial Measures:
In addition, this press release and any accompanying disclosures may include or reference certain forward–looking, non–GAAP financial measures, such as free cash flow, adjusted cash flow from operations and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward–looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward–looking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward–looking, non–GAAP financial measures to the respective most directly comparable forward–looking GAAP financial measures without unreasonable efforts. The unavailable information could have a significant impact on our ultimate results. However, management believes these forward–looking, non–GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward–looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates.

Oil and Gas Reserves:
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release or any accompanying disclosures that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10–K for the fiscal year ended December 31, 2024 (and any updates to such disclosure set forth in EOG's subsequent Quarterly Reports on Form 10–Q or Current Reports on Form 8–K), available from EOG at P.O. Box 4362, Houston, Texas 77210–4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1–800–SEC–0330 or from the SEC's website at www.sec.gov.

Income Statements
In millions of USD, except share data (in millions) and per share data (Unaudited)
	2024					2025
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year
Operating Revenues and Other
Crude Oil and Condensate	3,480	3,692	3,488	3,261	13,921	3,293	2,974	3,243		9,510
Natural Gas Liquids	513	515	524	554	2,106	572	534	604		1,710
Natural Gas	382	303	372	494	1,551	637	600	707		1,944
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	237	(47)	79	(65)	204	(191)	107	116		32
Gathering, Processing and Marketing	1,459	1,519	1,481	1,341	5,800	1,340	1,247	1,178		3,765
Gains (Losses) on Asset Dispositions, Net	26	20	(7)	(23)	16	(1)	—	(18)		(19)
Other, Net	26	23	28	23	100	19	16	17		52
Total	6,123	6,025	5,965	5,585	23,698	5,669	5,478	5,847		16,994

Operating Expenses
Lease and Well	396	390	392	394	1,572	401	396	431		1,228
Gathering, Processing and Transportation Costs	413	423	445	441	1,722	440	455	587		1,482
Exploration Costs	45	34	43	52	174	41	74	71		186
Dry Hole Costs	1	5	—	8	14	34	11	—		45
Impairments	19	81	15	276	391	44	39	71		154
Marketing Costs	1,404	1,490	1,500	1,323	5,717	1,325	1,216	1,134		3,675
Depreciation, Depletion and Amortization	1,074	984	1,031	1,019	4,108	1,013	1,053	1,169		3,235
General and Administrative	162	151	167	189	669	171	186	239		596
Taxes Other Than Income	338	337	283	291	1,249	341	301	309		951
Total	3,852	3,895	3,876	3,993	15,616	3,810	3,731	4,011		11,552

Operating Income	2,271	2,130	2,089	1,592	8,082	1,859	1,747	1,836		5,442
Other Income, Net	62	66	76	70	274	65	55	59		179
Income Before Interest Expense and Income Taxes	2,333	2,196	2,165	1,662	8,356	1,924	1,802	1,895		5,621
Interest Expense, Net	33	36	31	38	138	47	51	71		169
Income Before Income Taxes	2,300	2,160	2,134	1,624	8,218	1,877	1,751	1,824		5,452
Income Tax Provision	511	470	461	373	1,815	414	406	353		1,173
Net Income	1,789	1,690	1,673	1,251	6,403	1,463	1,345	1,471		4,279

Dividends Declared per Common Share	0.9100	0.9100	0.9100	0.9750	3.7050	0.9750	1.9950	—		2.9700
Net Income Per Share
Basic	3.11	2.97	2.97	2.25	11.31	2.66	2.48	2.72		7.85
Diluted	3.10	2.95	2.95	2.23	11.25	2.65	2.46	2.70		7.81
Average Number of Common Shares
Basic	575	569	564	557	566	550	543	541		545
Diluted	577	572	568	561	569	553	546	544		548

Volumes and Prices
(Unaudited)
	2024					2025
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States	486.8	490.1	491.8	493.5	490.6	500.9	503.1	532.9		512.4
Trinidad	0.6	0.6	1.2	1.1	0.8	1.2	1.1	1.6		1.3
Total	487.4	490.7	493.0	494.6	491.4	502.1	504.2	534.5		513.7

Average Crude Oil and Condensate Prices ($/Bbl) ^(B)
United States	$ 78.46	$ 82.71	$ 76.95	$ 71.68	$ 77.42	$ 72.90	$ 64.84	$ 65.97		$ 67.83
Trinidad	67.50	70.75	63.15	60.47	64.43	61.12	54.50	57.74		57.80
Composite	78.45	82.69	76.92	71.66	77.40	72.87	64.82	65.95		67.81

Natural Gas Liquids Volumes (MBbld) ^(A)
United States	231.7	244.8	254.3	252.5	245.9	241.7	258.4	309.3		270.0
Total	231.7	244.8	254.3	252.5	245.9	241.7	258.4	309.3		270.0

Average Natural Gas Liquids Prices ($/Bbl) ^(B)
United States	$ 24.32	$ 23.11	$ 22.42	$ 23.85	$ 23.40	$ 26.29	$ 22.70	$ 21.25		$ 23.20
Composite	24.32	23.11	22.42	23.85	23.40	26.29	22.70	21.25		23.20

Natural Gas Volumes (MMcfd) ^(A)
United States	1,658	1,668	1,745	1,840	1,728	1,834	1,977	2,511		2,110
Trinidad	200	204	225	252	220	246	252	230		243
Other International ^(C)	—	—	—	—	—	—	—	4		1
Total	1,858	1,872	1,970	2,092	1,948	2,080	2,229	2,745		2,354

Average Natural Gas Prices ($/Mcf) ^(B)
United States	$ 2.10	$ 1.57	$ 1.84	$ 2.39	$ 1.99	$ 3.36	$ 2.87	$ 2.71		$ 2.94
Trinidad	3.54	3.48	3.68	3.86	3.65	3.78	3.65	3.80		3.74
Other International ^(C)	—	—	—	—	—	—	—	3.27		3.27
Composite	2.26	1.78	2.05	2.57	2.17	3.41	2.96	2.80		3.03

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States	994.7	1,013.0	1,037.1	1,052.7	1,024.5	1,048.3	1,090.9	1,260.7		1,134.1
Trinidad	34.1	34.5	38.6	43.0	37.6	42.1	43.2	39.8		41.7
Other International	—	—	—	—	—	—	—	0.7		0.2
Total	1,028.8	1,047.5	1,075.7	1,095.7	1,062.1	1,090.4	1,134.1	1,301.2		1,176.0

Total MMBoe ^(D)	93.6	95.3	99.0	100.8	388.7	98.1	103.2	119.7		321.0

(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 10 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025).
(C)	Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distribution costs.
(D)	Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

Balance Sheets
In millions of USD (Unaudited)
	2024				2025
	MAR	JUN	SEP	DEC	MAR	JUN	SEP	DEC
Current Assets
Cash and Cash Equivalents	5,292	5,431	6,122	7,092	6,599	5,216	3,530
Accounts Receivable, Net	2,688	2,657	2,545	2,650	2,621	2,504	2,680
Inventories	1,154	1,069	1,038	985	897	934	945
Assets from Price Risk Management Activities	110	4	—	—	—	—	19
Other ^(A)	684	642	460	503	563	591	646
Total	9,928	9,803	10,165	11,230	10,680	9,245	7,820

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	73,356	74,615	75,887	77,091	78,432	80,139	88,301
Other Property, Plant and Equipment	5,768	6,078	6,314	6,418	6,510	6,616	6,772
Total Property, Plant and Equipment	79,124	80,693	82,201	83,509	84,942	86,755	95,073
Less: Accumulated Depreciation, Depletion and Amortization	(46,047)	(47,049)	(48,075)	(49,297)	(50,310)	(51,394)	(52,488)
Total Property, Plant and Equipment, Net	33,077	33,644	34,126	34,212	34,632	35,361	42,585
Deferred Income Taxes	38	44	42	39	44	39	37
Other Assets	1,753	1,733	1,818	1,705	1,626	1,639	1,757
Total Assets	44,796	45,224	46,151	47,186	46,982	46,284	52,199

Current Liabilities
Accounts Payable	2,389	2,436	2,290	2,464	2,353	2,266	2,944
Accrued Taxes Payable	786	600	855	1,007	668	348	392
Dividends Payable	523	516	513	539	534	1,081	550
Liabilities from Price Risk Management Activities	—	8	32	116	276	85	17
Current Portion of Long-Term Debt	34	534	34	532	1,280	778	27
Current Portion of Operating Lease Liabilities	318	303	338	315	318	360	433
Other	223	231	344	381	290	257	452
Total	4,273	4,628	4,406	5,354	5,719	5,175	4,815

Long-Term Debt	3,757	3,250	3,742	4,220	3,464	3,458	7,667
Other Liabilities	2,533	2,456	2,480	2,395	2,368	2,398	2,496
Deferred Income Taxes	5,597	5,731	5,949	5,866	5,915	6,015	6,936
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par	206	206	206	206	206	206	206
Additional Paid in Capital	6,188	6,219	6,058	6,090	6,095	6,153	5,978
Accumulated Other Comprehensive Loss	(8)	(8)	(9)	(4)	(4)	(7)	(5)
Retained Earnings	23,897	25,071	26,231	26,941	27,869	28,131	29,603
Common Stock Held in Treasury	(1,647)	(2,329)	(2,912)	(3,882)	(4,650)	(5,245)	(5,497)
Total Stockholders' Equity	28,636	29,159	29,574	29,351	29,516	29,238	30,285
Total Liabilities and Stockholders' Equity	44,796	45,224	46,151	47,186	46,982	46,284	52,199


(A)	Effective October 1, 2024, EOG combined Income Taxes Receivable into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets.

Cash Flow Statements
In millions of USD (Unaudited)
	2024					2025
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	1,789	1,690	1,673	1,251	6,403	1,463	1,345	1,471		4,279
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	1,074	984	1,031	1,019	4,108	1,013	1,053	1,169		3,235
Impairments	19	81	15	276	391	44	39	71		154
Stock-Based Compensation Expenses	45	45	58	51	199	50	53	53		156
Deferred Income Taxes	199	128	220	(80)	467	44	105	278		427
(Gains) Losses on Asset Dispositions, Net	(26)	(20)	7	23	(16)	1	—	18		19
Other, Net	9	3	2	3	17	11	11	2		24
Dry Hole Costs	1	5	—	8	14	34	11	—		45
Mark-to-Market Financial Commodity and Other Derivative Contracts (Gains) Losses, Net	(237)	47	(79)	65	(204)	191	(107)	(116)		(32)
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	55	79	61	19	214	(38)	(24)	27		(35)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	58	33	109	(99)	101	48	122	133		303
Inventories	117	75	30	37	259	76	(45)	4		35
Accounts Payable	(58)	29	(159)	152	(36)	(129)	(107)	5		(231)
Accrued Taxes Payable	319	(185)	256	151	541	(339)	(321)	28		(632)
Other Assets	(161)	42	197	(34)	44	(43)	(43)	(28)		(114)
Other Liabilities	(71)	(20)	108	6	23	(96)	(52)	155		7
Changes in Components of Working Capital Associated with Investing Activities	(229)	(127)	59	(85)	(382)	(41)	(8)	(159)		(208)
Net Cash Provided by Operating Activities	2,903	2,889	3,588	2,763	12,143	2,289	2,032	3,111		7,432
Investing Cash Flows
Acquisition of Encino Acquisition Partners, LLC, Net of Cash Acquired	—	—	—	—	—	—	—	(4,464)		(4,464)
Additions to Oil and Gas Properties	(1,485)	(1,357)	(1,263)	(1,248)	(5,353)	(1,381)	(1,699)	(1,492)		(4,572)
Additions to Other Property, Plant and Equipment	(350)	(313)	(239)	(117)	(1,019)	(102)	(94)	(171)		(367)
Proceeds from Sales of Assets	9	10	—	4	23	12	4	5		21
Changes in Components of Working Capital Associated with Investing Activities	229	127	(59)	85	382	41	8	159		208
Net Cash Used in Investing Activities	(1,597)	(1,533)	(1,561)	(1,276)	(5,967)	(1,430)	(1,781)	(5,963)		(9,174)
Financing Cash Flows
Long-Term Debt Borrowings	—	—	—	985	985	—	—	3,472		3,472
Long-Term Debt Repayments	—	—	—	—	—	—	(500)	(1,266)		(1,766)
Dividends Paid	(525)	(520)	(533)	(509)	(2,087)	(538)	(528)	(545)		(1,611)
Treasury Stock Purchased	(759)	(699)	(795)	(993)	(3,246)	(806)	(602)	(479)		(1,887)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	—	11	—	11	22	—	11	—		11
Debt Issuance and Other Financing Costs	—	—	—	(2)	(2)	—	(7)	(7)		(14)
Repayment of Finance Lease Liabilities	(8)	(9)	(8)	(8)	(33)	(8)	(9)	(8)		(25)
Net Cash Used in Financing Activities	(1,292)	(1,217)	(1,336)	(516)	(4,361)	(1,352)	(1,635)	1,167		(1,820)
Effect of Exchange Rate Changes on Cash	—	–	–	(1)	(1)	—	1	(1)		—
Increase (Decrease) in Cash and Cash Equivalents	14	139	691	970	1,814	(493)	(1,383)	(1,686)		(3,562)
Cash and Cash Equivalents at Beginning of Period	5,278	5,292	5,431	6,122	5,278	7,092	6,599	5,216		7,092
Cash and Cash Equivalents at End of Period	5,292	5,431	6,122	7,092	7,092	6,599	5,216	3,530		3,530

Non-GAAP Financial Measures

To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Adjusted Cash Flow from Operations, Free Cash Flow, Net Debt and related statistics.

A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com.

As further discussed in the tables on the following pages, EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance.

EOG believes that the non-GAAP measures presented, when viewed in combination with its financial results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial performance with the financial performance of other companies in the industry and (ii) analyzing EOG's financial performance across periods.

The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP.

In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices.

Direct ATROR

The calculation of EOG's direct after-tax rate of return (ATROR) is based on EOG's net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG's direct net costs incurred in drilling or acquiring such well(s). As such, EOG's direct ATROR for a particular well(s) or play cannot be calculated from EOG's consolidated financial statements.

Adjusted Net Income
In millions of USD, except share data (in millions) and per share data (Unaudited)

The following tables adjust reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the net unrealized mark-to-market (gains) losses from these and other derivative transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets)), to add back costs associated with the Encino acquisition and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non- recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	3Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,824	(353)	1,471	2.70
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(116)	25	(91)	(0.16)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	27	(5)	22	0.04
Add: Losses on Asset Dispositions, Net	18	(6)	12	0.02
Add: Acquisition-related costs ⁽²⁾	68	(10)	58	0.11
Adjustments to Net Income	(3)	4	1	0.01

Adjusted Net Income (Non-GAAP)	1,821	(349)	1,472	2.71

Average Number of Common Shares
Basic				541
Diluted				544


(1)	Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2025, such amount was $27 million.
(2)	Consists of Encino acquisition-related G&A costs ($68 million).

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)

	2Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,751	(406)	1,345	2.46
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(107)	23	(84)	(0.16)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	(24)	5	(19)	(0.03)
Add: Certain Impairments	11	—	11	0.02
Add: Acquisition-related costs ⁽²⁾	18	(3)	15	0.03
Adjustments to Net Income	(102)	25	(77)	(0.14)

Adjusted Net Income (Non-GAAP)	1,649	(381)	1,268	2.32

Average Number of Common Shares
Basic				543
Diluted				546


(1)	Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2025, such amount was $24 million.
(2)	Consists of Encino acquisition-related G&A costs ($12 million) and financing commitment costs ($6 million).

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)

	1Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,877	(414)	1,463	2.65
Adjustments:
Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	191	(41)	150	0.26
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	(38)	8	(30)	(0.05)
Add: Losses on Asset Dispositions, Net	1	2	3	0.01
Adjustments to Net Income	154	(31)	123	0.22

Adjusted Net Income (Non-GAAP)	2,031	(445)	1,586	2.87

Average Number of Common Shares
Basic				550
Diluted				553


(1)	Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2025, such amount was $38 million.

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)

	4Q 2024
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,624	(373)	1,251	2.23
Adjustments:
Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	65	(14)	51	0.10
Net Cash Received from Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	19	(4)	15	0.03
Add: Losses on Asset Dispositions, Net	23	(4)	19	0.03
Add: Certain Impairments	254	(55)	199	0.35
Adjustments to Net Income	361	(77)	284	0.51

Adjusted Net Income (Non-GAAP)	1,985	(450)	1,535	2.74

Average Number of Common Shares
Basic				557
Diluted				561


(1)	Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2024, such amount was $19 million.

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)

	3Q 2024
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	2,134	(461)	1,673	2.95
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(79)	17	(62)	(0.11)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	61	(13)	48	0.08
Add: Losses on Asset Dispositions, Net	7	(2)	5	0.01
Less: Severance Tax Refund	(31)	7	(24)	(0.04)
Add: Severance Tax Consulting Fees	10	(2)	8	0.01
Less: Interest on Severance Tax Refund	(5)	1	(4)	(0.01)
Adjustments to Net Income	(37)	8	(29)	(0.06)

Adjusted Net Income (Non-GAAP)	2,097	(453)	1,644	2.89

Average Number of Common Shares
Basic				564
Diluted				568


(1)	Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2024, such amount was $61 million.

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	FY 2024
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	8,218	(1,815)	6,403	11.25
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(204)	44	(160)	(0.28)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	214	(46)	168	0.30
Less: Gains on Asset Dispositions, Net	(16)	3	(13)	(0.02)
Add: Certain Impairments	291	(57)	234	0.41
Less: Severance Tax Refund	(31)	7	(24)	(0.04)
Add: Severance Tax Consulting Fees	10	(2)	8	0.01
Less: Interest on Severance Tax Refund	(5)	1	(4)	(0.01)
Adjustments to Net Income	259	(50)	209	0.37

Adjusted Net Income (Non-GAAP)	8,477	(1,865)	6,612	11.62

Average Number of Common Shares
Basic				566
Diluted				569

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was $214 million.

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	FY 2023
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	9,689	(2,095)	7,594	13.00
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net	(818)	176	(642)	(1.09)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	(112)	24	(88)	(0.15)
Less: Gains on Asset Dispositions, Net	(95)	20	(75)	(0.13)
Add: Certain Impairments	42	(6)	36	0.06
Adjustments to Net Income	(983)	214	(769)	(1.31)

Adjusted Net Income (Non-GAAP)	8,706	(1,881)	6,825	11.69

Average Number of Common Shares
Basic				581
Diluted				584

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2023, such amount was $112 million.

Net Income per Share
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

2Q 2025 Net Income per Share (GAAP) - Diluted		2.46

Realized Prices
3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	38.05
Less: 2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(39.80)
Subtotal	(1.75)
Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	119.7
Total Change in Revenue	(209)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	46
Change in Net Income	(163)
Change in Diluted Earnings per Share		(0.30)

Volumes
3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	119.7
Less: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe)	(103.2)
Subtotal	16.5
Multiplied by: 3Q 2025 Composite Average Margin per Boe (GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)	13.42
Change in Margin	221
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(49)
Change in Net Income	172
Change in Diluted Earnings per Share		0.32

Certain Operating Costs per Boe
2Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	20.25
Less: 3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	(20.27)
Subtotal	(0.02)
Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	119.7
Change in Before-Tax Net Income	(2)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	1
Change in Net Income	(1)
Change in Diluted Earnings per Share		0.00

Net Income Per Share (Continued)
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	116
Less: Income Tax Benefit (Provision)	(25)
After Tax - (a)	91
Less: 2Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	107
Less: Income Tax Benefit (Provision)	(23)
After Tax - (b)	84
Change in Net Income - (a) - (b)	7
Change in Diluted Earnings per Share		0.01

Other ⁽¹⁾		0.21

3Q 2025 Net Income per Share (GAAP) - Diluted		2.70

3Q 2025 Average Number of Common Shares - Diluted	544

(1)

Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

Adjusted Net Income Per Share
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

2Q 2025 Adjusted Net Income per Share (Non-GAAP) - Diluted		2.32

Realized Prices
3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	38.05
Less: 2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(39.80)
Subtotal	(1.75)
Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	119.7
Total Change in Revenue	(209)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	46
Change in Net Income	(163)
Change in Diluted Earnings per Share		(0.30)

Volumes
3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	119.7
Less: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe)	(103.2)
Subtotal	16.5
Multiplied by: 3Q 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)	13.99
Change in Margin	231
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(51)
Change in Net Income	180
Change in Diluted Earnings per Share		0.33

Certain Operating Costs per Boe
2Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	20.14
Less: 3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	(19.70)
Subtotal	0.44
Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	119.7
Change in Before-Tax Net Income	53
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	(12)
Change in Net Income	41
Change in Diluted Earnings per Share		0.08

Adjusted Net Income Per Share (Continued)
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
3Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	27
Less: Income Tax Benefit (Provision)	(5)
After Tax - (a)	22
Less: 2Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	(24)
Less: Income Tax Benefit (Provision)	5
After Tax - (b)	(19)
Change in Net Income - (a) - (b)	41
Change in Diluted Earnings per Share		0.08

Other ⁽¹⁾		0.20

3Q 2025 Adjusted Net Income per Share (Non-GAAP)		2.71

3Q 2025 Average Number of Common Shares - Diluted	544

(1)

Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

Cash Flow from Operations and Free Cash Flow
In millions of USD (Unaudited)

The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Adjusted Cash Flow from Operations (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing Activities (or Investing and Financing Activities, as applicable) and certain other adjustments to exclude certain non-recurring items and other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Adjusted Cash Flow from Operations (Non-GAAP) (see below reconciliation) for such period less the Total Capital Expenditures (Non-GAAP) (see below reconciliation) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. As indicated in the tables below, EOG is (1) in addition to its customary working capital-related adjustments, adjusting Net Cash Provided by Operating Activities (GAAP) to add back certain non-recurring acquisition-related costs incurred during the second and third quarters of 2025 and (2) now presenting such adjusted measure as "Adjusted Cash Flow from Operations (Non-GAAP)" (instead of "Cash Flow from Operations Before Changes in Working Capital (Non-GAAP)" as reported in prior periods); the presentation below with respect to the second and third quarters of 2025 and the prior periods shown has been conformed.
	2024					2025
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year

Net Cash Provided by Operating Activities (GAAP)	2,903	2,889	3,588	2,763	12,143	2,289	2,032	3,111		7,432

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(58)	(33)	(109)	99	(101)	(48)	(122)	(133)		(303)
Inventories	(117)	(75)	(30)	(37)	(259)	(76)	45	(4)		(35)
Accounts Payable	58	(29)	159	(152)	36	129	107	(5)		231
Accrued Taxes Payable	(319)	185	(256)	(151)	(541)	339	321	(28)		632
Other Assets	161	(42)	(197)	34	(44)	43	43	28		114
Other Liabilities	71	20	(108)	(6)	(23)	96	52	(155)		(7)
Changes in Components of Working Capital Associated with Investing Activities	229	127	(59)	85	382	41	8	159		208
Add:
Acquisition-Related Costs ⁽¹⁾, Net of Tax	—	—	—	—	—	—	10	58		68
Adjusted Cash Flow from Operations (Non- GAAP)	2,928	3,042	2,988	2,635	11,593	2,813	2,496	3,031		8,340
Less:
Total Capital Expenditures (Non-GAAP) ⁽²⁾	(1,703)	(1,668)	(1,497)	(1,358)	(6,226)	(1,484)	(1,523)	(1,648)		(4,655)
Free Cash Flow (Non-GAAP)	1,225	1,374	1,491	1,277	5,367	1,329	973	1,383		3,685

(1) Consists of Encino acquisition-related G&A costs of $12 million and $68 million (each before tax) for the three months ended June 30, 2025 and three months ended September 30, 2025, respectively.
(2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

	2024					2025
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year

Total Expenditures (GAAP)	1,952	1,682	1,573	1,446	6,653	1,546	1,883	8,544		11,973
Less:
Asset Retirement Costs	(21)	60	(11)	(26)	2	(13)	(14)	(86)		(113)
Non-Cash Leasehold Acquisition Costs ⁽³⁾	(31)	(34)	(17)	(3)	(85)	(9)	(2)	(3)		(14)
Acquisition Costs of Properties ⁽³⁾	(21)	(5)	—	(7)	(33)	1	(270)	(6,736)		(7,005)
Acquisition Costs of Other Property, Plant and Equipment	(131)	(1)	(5)	—	(137)	—	—	—		—
Exploration Costs	(45)	(34)	(43)	(52)	(174)	(41)	(74)	(71)		(186)
Total Capital Expenditures (Non-GAAP)	1,703	1,668	1,497	1,358	6,226	1,484	1,523	1,648		4,655

Cash Flow from Operations and Free Cash Flow (Continued)
In millions of USD (Unaudited)

	FY 2023	FY 2022

Net Cash Provided by Operating Activities (GAAP)	11,340	11,093

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	38	347
Inventories	231	534
Accounts Payable	119	(90)
Accrued Taxes Payable	(61)	113
Other Assets	(39)	364
Other Liabilities	(184)	266
Changes in Components of Working Capital Associated with Investing Activities	(295)	(375)
Adjusted Cash Flow from Operations (Non-GAAP)	11,149	12,252
Less:
Total Capital Expenditures (Non-GAAP) ^(a)	(6,041)	(4,607)
Free Cash Flow (Non-GAAP)	5,108	7,645

(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

Total Expenditures (GAAP)	6,818	5,610
Less:
Asset Retirement Costs	(257)	(298)
Non-Cash Development Drilling	(90)	—
Non-Cash Leasehold Acquisition Costs ⁽³⁾	(99)	(127)
Acquisition Costs of Properties ⁽³⁾	(16)	(419)
Acquisition Costs of Other Property, Plant and Equipment	(134)	—
Exploration Costs	(181)	(159)
Total Capital Expenditures (Non-GAAP)	6,041	4,607

(3)	Line item descriptions revised (from descriptions shown in EOG's previously published tables) to more accurately describe the costs reflected therein; previously reported cost amounts not impacted by such changes in presentation.

Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited)

The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

	September 30, 2025	June 30, 2025	March 31, 2025	December 31, 2024	September 30, 2024

Total Stockholders' Equity - (a)	30,285	29,238	29,516	29,351	29,574

Current and Long-Term Debt (GAAP) - (b)	7,694	4,236	4,744	4,752	3,776
Less: Cash	(3,530)	(5,216)	(6,599)	(7,092)	(6,122)
Net Debt (Non-GAAP) - (c)	4,164	(980)	(1,855)	(2,340)	(2,346)

Total Capitalization (GAAP) - (a) + (b)	37,979	33,474	34,260	34,103	33,350

Total Capitalization (Non-GAAP) - (a) + (c)	34,449	28,258	27,661	27,011	27,228

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	20.3 %	12.7 %	13.8 %	13.9 %	11.3 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	12.1 %	-3.5 %	-6.7 %	-8.7 %	-8.6 %

Revenues, Costs and Margins Per Barrel of Oil Equivalent
In millions of USD, except Boe and per Boe amounts (Unaudited)

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	3Q 2025	2Q 2025	1Q 2025	4Q 2024	3Q 2024

Volume - Million Barrels of Oil Equivalent - (a)	119.7	103.2	98.1	100.8	99.0

Total Operating Revenues and Other - (b)	5,847	5,478	5,669	5,585	5,965
Total Operating Expenses - (c)	4,011	3,731	3,810	3,993	3,876
Operating Income - (d)	1,836	1,747	1,859	1,592	2,089

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate	3,243	2,974	3,293	3,261	3,488
Natural Gas Liquids	604	534	572	554	524
Natural Gas	707	600	637	494	372
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e)	4,554	4,108	4,502	4,309	4,384

Operating Costs
Lease and Well	431	396	401	394	392
Gathering, Processing and Transportation Costs ⁽¹⁾	587	455	440	441	445
General and Administrative (GAAP)	239	186	171	189	167
Less: Certain Items (see Endnotes 2 & 3 to 3Q 2025 earnings release)	(68)	(12)	—	—	(10)
General and Administrative (Non-GAAP)⁽²⁾	171	174	171	189	157
Taxes Other Than Income (GAAP)	309	301	341	291	283
Add: Severance Tax Refund	—	—	—	—	31
Taxes Other Than Income (Non-GAAP)⁽³⁾	309	301	341	291	314
Interest Expense, Net	71	51	47	38	31
Less: Acquisition-Related Financing Commitment Costs	—	(6)	—	—	—
Interest Expense, Net (Non-GAAP)⁽⁴⁾	71	45	47	38	31
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	1,637	1,389	1,400	1,353	1,318
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	1,569	1,371	1,400	1,353	1,339

Depreciation, Depletion and Amortization (DD&A)	1,169	1,053	1,013	1,019	1,031

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	2,806	2,442	2,413	2,372	2,349
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	2,738	2,424	2,413	2,372	2,370

Exploration Costs	71	74	41	52	43
Dry Hole Costs	—	11	34	8	—
Impairments	71	39	44	276	15
Total Exploration Costs (GAAP)	142	124	119	336	58
Less: Certain Impairments ⁽⁵⁾	—	(11)	—	(254)	—
Total Exploration Costs (Non-GAAP)	142	113	119	82	58

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	2,948	2,566	2,532	2,708	2,407
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k)	2,880	2,537	2,532	2,454	2,428

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	1,606	1,542	1,970	1,601	1,977
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))	1,674	1,571	1,970	1,855	1,956


Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	3Q 2025	2Q 2025	1Q 2025	4Q 2024	3Q 2024
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe - (b) / (a)	48.85	53.08	57.79	55.41	60.25
Composite Average Operating Expenses per Boe - (c) / (a)	33.51	36.15	38.84	39.62	39.15
Composite Average Operating Income per Boe - (d) / (a)	15.34	16.93	18.95	15.79	21.10

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a)	38.05	39.80	45.88	42.74	44.31

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	13.67	13.46	14.26	13.42	13.32

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	24.38	26.34	31.62	29.32	30.99

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)	23.44	23.66	24.58	23.53	23.74

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]	14.61	16.14	21.30	19.21	20.57

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)	24.63	24.86	25.79	26.86	24.33

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]	13.42	14.94	20.09	15.88	19.98

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)	13.10	13.30	14.26	13.42	13.53

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]	24.95	26.50	31.62	29.32	30.78

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)	22.87	23.50	24.58	23.53	23.95

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]	15.18	16.30	21.30	19.21	20.36

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)	24.06	24.59	25.79	24.34	24.54

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]	13.99	15.21	20.09	18.40	19.77

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	2024	2023	2022

Volume - Million Barrels of Oil Equivalent - (a)	388.7	359.4	331.5

Total Operating Revenues and Other - (b)	23,698	24,186	25,702
Total Operating Expenses - (c)	15,616	14,583	15,736
Operating Income (Loss) - (d)	8,082	9,603	9,966

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate	13,921	13,748	16,367
Natural Gas Liquids	2,106	1,884	2,648
Natural Gas	1,551	1,744	3,781
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e)	17,578	17,376	22,796

Operating Costs
Lease and Well	1,572	1,454	1,331
Gathering, Processing and Transportation Costs⁽¹⁾	1,722	1,620	1,587
General and Administrative (GAAP)	669	640	570
Less: Severance Tax Consulting Fees	(10)	—	(16)
General and Administrative (Non-GAAP)⁽²⁾	659	640	554
Taxes Other Than Income (GAAP)	1,249	1,284	1,585
Add: Severance Tax Refund	31	—	115
Taxes Other Than Income (Non-GAAP)⁽³⁾	1,280	1,284	1,700
Interest Expense, Net	138	148	179
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	5,350	5,146	5,252
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	5,371	5,146	5,351

Depreciation, Depletion and Amortization (DD&A)	4,108	3,492	3,542

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	9,458	8,638	8,794
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	9,479	8,638	8,893

Exploration Costs	174	181	159
Dry Hole Costs	14	1	45
Impairments	391	202	382
Total Exploration Costs (GAAP)	579	384	586
Less: Certain Impairments ⁽⁵⁾	(291)	(42)	(113)
Total Exploration Costs (Non-GAAP)	288	342	473

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	10,037	9,022	9,380
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k)	9,767	8,980	9,366

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	7,541	8,354	13,416
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))	7,811	8,396	13,430


Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
	2024	2023	2022

Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe - (b) / (a)	60.97	67.30	77.53
Composite Average Operating Expenses per Boe - (c) / (a)	40.18	40.58	47.47
Composite Average Operating Income (Loss) per Boe - (d) / (a)	20.79	26.72	30.06

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a)	45.22	48.34	68.77

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	13.76	14.31	15.84

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	31.46	34.03	52.93

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)	24.33	24.03	26.53

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]	20.89	24.31	42.24

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)	25.82	25.10	28.30

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]	19.40	23.24	40.47

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)	13.82	14.31	16.14

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]	31.40	34.03	52.63

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)	24.39	24.03	26.83

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]	20.83	24.31	41.94

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)	25.13	24.98	28.26

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]	20.09	23.36	40.51

(1)	Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.
(2)	EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring.
(3)	EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring.
(4)	EOG believes excluding the above-referenced items from Interest Expense, Net is appropriate and provides useful information to investors, as EOG views such items as non-recurring.
(5)	In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).

Additional Key Financial Information
(Unaudited)

See "Endnotes" below for related discussion and definitions.	2024 Actual	2023 Actual	2022 Actual

Crude Oil and Condensate Volumes (MBod)
United States	490.6	475.2	460.7
Trinidad	0.8	0.6	0.6
Total	491.4	475.8	461.3
Natural Gas Liquids Volumes (MBbld)
Total	245.9	223.8	197.7
Natural Gas Volumes (MMcfd)
United States	1,728	1,551	1,315
Trinidad	220	160	180
Total	1,948	1,711	1,495
Crude Oil Equivalent Volumes (MBoed)
United States	1,024.5	957.5	877.5
Trinidad	37.6	27.3	30.7
Total	1,062.1	984.8	908.2

Benchmark Price
Oil (WTI) ($/Bbl)	75.72	77.61	94.23
Natural Gas (HH) ($/Mcf)	2.27	2.74	6.64

Crude Oil and Condensate - above (below) WTI¹ ($/Bbl)
United States	1.70	1.57	2.99
Trinidad	(11.29)	(9.03)	(8.07)
Natural Gas Liquids - Realizations as % of WTI
Total	30.9 %	29.7 %	39.0 %

Natural Gas - above (below) NYMEX Henry Hub² ($/Mcf)
United States	(0.28)	(0.04)	0.63
Natural Gas Realizations³($/Mcf)
Trinidad	3.65	3.65	4.43

Total Expenditures (GAAP) ($MM)	6,653	6,818	5,610
Capital Expenditures⁴ (non-GAAP) ($MM)	6,226	6,041	4,607

Operating Unit Costs ($/Boe)
Lease and Well	4.04	4.05	4.02
Gathering, Processing and Transportation Costs⁵	4.43	4.50	4.78
General and Administrative (GAAP)	1.72	1.78	1.72
General and Administrative (non-GAAP)⁶	1.70	1.78	1.67
Cash Operating Costs (GAAP)	10.19	10.33	10.52
Cash Operating Costs (non-GAAP)⁶	10.17	10.33	10.47
Depreciation, Depletion and Amortization	10.57	9.72	10.69

Expenses ($MM)
Exploration and Dry Hole	188	182	204
Impairment (GAAP)	391	202	382
Impairment (excluding certain impairments (non-GAAP))⁷	100	160	269
Capitalized Interest	45	33	36
Net Interest	138	148	179

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)
(GAAP)	7.1 %	7.4 %	7.0 %
(non-GAAP)⁶	7.3 %	7.4 %	7.5 %
Income Taxes
Effective Rate	22.1 %	21.6 %	21.7 %
Current Tax Expense ($MM)	1,348	1,415	2,208

Additional Key Information
(Continued)
Endnotes

1)	EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

2)	EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.

3)	The full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited.

4)	Capital Expenditures includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. Capital Expenditures excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

5)	Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

6)	Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non-GAAP) and G&A (non-GAAP) for fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for fiscal year 2024 and fiscal year 2022 was $(0.02) and $(0.05), respectively.

7)	In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).