EOG Resources (NYSE: EOG) 2025 results show lower profit but higher output

Q: How did EOG Resources (EOG) perform financially in 2025?

EOG Resources generated 2025 net income of $4,980 million with diluted earnings per share of 9.12 . Total operating revenues and other were $22,632 million , while revenues from crude oil, NGLs and natural gas sales totaled $17,668 million , roughly flat versus 2024 sales revenue.

Q: How did EOG Resources’ 2025 earnings compare to 2024 results?

EOG’s 2025 net income of $4,980 million was below 2024 net income of $6,403 million . Diluted EPS decreased from 11.25 in 2024 to 9.12 in 2025, reflecting weaker commodity realizations, higher exploration and impairment costs, and impacts from the company’s enlarged asset base.

Q: What were EOG Resources’ production volumes in 2025?

In 2025 EOG produced an average of 1,232.2 thousand barrels of oil equivalent per day , totaling 449.8 million barrels of oil equivalent for the year. This was higher than 2024’s 388.7 million barrels of oil equivalent , driven mainly by U.S. growth in oil, natural gas liquids and natural gas volumes.

Q: How much did EOG Resources spend on capital and what was free cash flow in 2025?

EOG reported 2025 capital expenditures (non-GAAP) of $6,294 million . After adjusting cash flow from operations, the company generated $4,663 million of free cash flow (non-GAAP). These figures show EOG funded a sizable investment program while still producing meaningful surplus cash for the year.

Q: What impact did the Encino acquisition have on EOG Resources in 2025?

The Encino acquisition added $6,703 million of proved property costs and 678 million barrels of oil equivalent of reserves. This helped increase total proved reserves to 5,514 million barrels of oil equivalent at year-end 2025, while also contributing to higher capital spending and a greater net debt balance.

Q: What is EOG Resources’ leverage and liquidity position at the end of 2025?

At December 31, 2025 , EOG reported $7,936 million of current and long-term debt and $3,396 million of cash, resulting in $4,540 million of net debt. The net debt-to-total capitalization ratio was 13.2% , indicating a moderate level of financial leverage following recent acquisitions.

Filing Impact

(High)

Filing Sentiment

(Neutral)

Form Type

8-K

Rhea-AI Filing Summary

EOG Resources reported full-year 2025 results showing higher production but lower earnings versus 2024. Crude oil equivalent volumes rose to 1,232.2 thousand barrels of oil equivalent per day and 449.8 million barrels of oil equivalent for the year, up from 388.7 million barrels of oil equivalent in 2024.

Despite this growth, 2025 net income declined to $4,980 million with diluted EPS of 9.12, compared with $6,403 million and 11.25 in 2024. Total operating revenues and other were $22,632 million, down from $23,698 million, while revenues from sales of crude oil, NGLs and natural gas edged up to $17,668 million.

The company completed the Encino acquisition, recording $6,703 million of proved property costs and adding 678 million barrels of oil equivalent of reserves, helping lift year-end total proved reserves to 5,514 million barrels of oil equivalent. Capital expenditures (non-GAAP) were $6,294 million and 2025 free cash flow was $4,663 million. Year-end net debt was $4,540 million, with a net debt-to-total capitalization ratio of 13.2%, and cash and cash equivalents were $3,396 million.

Insights

Production and reserves grew in 2025, while earnings and leverage moved less favorably.

EOG expanded its operational scale in 2025. Crude oil equivalent volumes reached 449.8 million barrels of oil equivalent, and total proved reserves increased to 5,514 million barrels of oil equivalent, helped by the Encino acquisition and strong U.S. additions.

Financially, lower commodity realizations weighed on profitability. Net income fell to $4,980 million with diluted EPS of 9.12, versus $6,403 million and 11.25 in 2024, even as revenues from product sales were broadly stable at $17,668 million. Operating costs and impairments also influenced the earnings decline.

Cash generation remained solid: free cash flow (non-GAAP) was $4,663 million after $6,294 million of capital expenditures. However, the Encino transaction increased balance-sheet leverage. Net debt rose to $4,540 million and net debt-to-total capitalization to 13.2% at December 31, 2025. Subsequent filings may provide more detail on how this larger asset base and higher leverage affect returns.

02/24/2026 - 04:18 PM

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 24, 2026

_______________

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Delaware	1-9743	47-0684736
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

713-651-7000

(Registrant's telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	EOG	New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

EOG RESOURCES, INC.

Item 2.02 Results of Operations and Financial Condition.

On February 24, 2026, EOG Resources, Inc. issued a press release announcing fourth quarter 2025 financial and operational results and first quarter and full year 2026 forecast and benchmark commodity pricing information (see Item 7.01 below). A copy of this release is attached as Exhibit 99.1 to this filing and is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 7.01 Regulation FD Disclosure.

Accompanying the press release announcing fourth quarter 2025 financial and operational results attached hereto as Exhibit 99.1 is first quarter and full year 2026 forecast and benchmark commodity pricing information for EOG Resources, Inc., which information is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

99.1 Press Release of EOG Resources, Inc. dated February 24, 2026 (including the accompanying first quarter and full year 2026 forecast and benchmark commodity pricing information).

104 Cover Page Interactive Data File (formatted as Inline XBRL).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		EOG RESOURCES, INC. (Registrant)



Date: February 24, 2026	By:	/s/ ANN D. JANSSEN Ann D. Janssen Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

EXHIBIT 99.1


Table of Contents

Fourth Quarter 2025
Supplemental Financial and Operating Data			Page

Income Statements			12
Volumes and Prices			13
Balance Sheets			14
Cash Flow Statements			15
Non-GAAP Financial Measures			16
Adjusted Net Income			17
Net Income Per Share			21
Adjusted Net Income Per Share			23
Cash Flow from Operations and Free Cash Flow			25
Net Debt-to-Total Capitalization Ratio			27
Proved Reserves and Reserve Replacement Data			28
Reserve Replacement Cost Data			29
Revenues, Costs and Margins Per Barrel of Oil Equivalent			32
Additional Key Financial Information			36


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	2,991	12,501
Natural Gas Liquids	513	515	524	554	2,106	572	534	604	666	2,376
Natural Gas	382	303	372	494	1,551	637	600	707	847	2,791
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	237	(47)	79	(65)	204	(191)	107	116	(19)	13
Gathering, Processing and Marketing	1,459	1,519	1,481	1,341	5,800	1,340	1,247	1,178	1,149	4,914
Gains (Losses) on Asset Dispositions, Net	26	20	(7)	(23)	16	(1)	—	(18)	(16)	(35)
Other, Net	26	23	28	23	100	19	16	17	20	72
Total	6,123	6,025	5,965	5,585	23,698	5,669	5,478	5,847	5,638	22,632

Operating Expenses
Lease and Well	396	390	392	394	1,572	401	396	431	447	1,675
Gathering, Processing and Transportation Costs	413	423	445	441	1,722	440	455	587	652	2,134
Exploration Costs	45	34	43	52	174	41	74	71	50	236
Dry Hole Costs	1	5	—	8	14	34	11	—	4	49
Impairments	19	81	15	276	391	44	39	71	689	843
Marketing Costs	1,404	1,490	1,500	1,323	5,717	1,325	1,216	1,134	1,120	4,795
Depreciation, Depletion and Amortization	1,074	984	1,031	1,019	4,108	1,013	1,053	1,169	1,226	4,461
General and Administrative	162	151	167	189	669	171	186	239	224	820
Taxes Other Than Income	338	337	283	291	1,249	341	301	309	283	1,234
Total	3,852	3,895	3,876	3,993	15,616	3,810	3,731	4,011	4,695	16,247

Operating Income	2,271	2,130	2,089	1,592	8,082	1,859	1,747	1,836	943	6,385
Other Income, Net	62	66	76	70	274	65	55	59	33	212
Income Before Interest Expense and Income Taxes	2,333	2,196	2,165	1,662	8,356	1,924	1,802	1,895	976	6,597
Interest Expense, Net	33	36	31	38	138	47	51	71	66	235
Income Before Income Taxes	2,300	2,160	2,134	1,624	8,218	1,877	1,751	1,824	910	6,362
Income Tax Provision	511	470	461	373	1,815	414	406	353	209	1,382
Net Income	1,789	1,690	1,673	1,251	6,403	1,463	1,345	1,471	701	4,980

Dividends Declared per Common Share	0.9100	0.9100	0.9100	0.9750	3.7050	0.9750	1.9950	—	1.0200	3.9900
Net Income Per Share
Basic	3.11	2.97	2.97	2.25	11.31	2.66	2.48	2.72	1.31	9.17
Diluted	3.10	2.95	2.95	2.23	11.25	2.65	2.46	2.70	1.30	9.12
Average Number of Common Shares
Basic	575	569	564	557	566	550	543	541	537	543
Diluted	577	572	568	561	569	553	546	544	539	546


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		544.5		520.5
Trinidad	0.6		0.6		1.2		1.1		0.8		1.2		1.1		1.6		1.5		1.4
Other International (c)	—		—		—		—		—		—		—		—		0.1		—
Total	487.4		490.7		493.0		494.6		491.4		502.1		504.2		534.5		546.1		521.9

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	$	59.54	$	65.65
Trinidad	67.50		70.75		63.15		60.47		64.43		61.12		54.50		57.74		57.07		57.59
Other International (c)	—		—		—		—		—		—		—		—		63.98		—
Composite	78.45		82.69		76.92		71.66		77.40		72.87		64.82		65.95		59.54		65.63

Natural Gas Liquids Volumes (MBbld) (A)
United States	231.7		244.8		254.3		252.5		245.9		241.7		258.4		309.3		342.1		288.2
Total	231.7		244.8		254.3		252.5		245.9		241.7		258.4		309.3		342.1		288.2

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	$	21.15	$	22.58
Composite	24.32		23.11		22.42		23.85		23.40		26.29		22.70		21.25		21.15		22.58

Natural Gas Volumes (MMcfd) (A)
United States	1,658		1,668		1,745		1,840		1,728		1,834		1,977		2,511		2,859		2,299
Trinidad	200		204		225		252		220		246		252		230		195		230
Other International (C)	—		—		—		—		—		—		—		4		11		4
Total	1,858		1,872		1,970		2,092		1,948		2,080		2,229		2,745		3,065		2,533

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	$	2.94
Trinidad	3.54		3.48		3.68		3.86		3.65		3.78		3.65		3.80		3.94		3.78
Other International (C)	—		—		—		—		—		—		—		3.27		3.29		3.28
Composite	2.26		1.78		2.05		2.57		2.17		3.41		2.96		2.80		3.00		3.02

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		1,363.0		1,191.8
Trinidad	34.1		34.5		38.6		43.0		37.6		42.1		43.2		39.8		34.2		39.8
Other International (C)	—		—		—		—		—		—		—		0.7		1.8		0.6
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		1,399.0		1,232.2

Total MMBoe (D)	93.6		95.3		99.0		100.8		388.7		98.1		103.2		119.7		128.7		449.8

(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 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2025).

(C)Production volumes from 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	3,396
Accounts Receivable, Net	2,688	2,657	2,545	2,650	2,621	2,504	2,680	2,681
Inventories	1,154	1,069	1,038	985	897	934	945	1,014
Assets from Price Risk Management Activities	110	4	—	—	—	—	19	18
Other (A)	684	642	460	503	563	591	646	547
Total	9,928	9,803	10,165	11,230	10,680	9,245	7,820	7,656

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	89,857
Other Property, Plant and Equipment	5,768	6,078	6,314	6,418	6,510	6,616	6,772	6,832
Total Property, Plant and Equipment	79,124	80,693	82,201	83,509	84,942	86,755	95,073	96,689
Less: Accumulated Depreciation, Depletion and Amortization	(46,047)	(47,049)	(48,075)	(49,297)	(50,310)	(51,394)	(52,488)	(54,348)
Total Property, Plant and Equipment, Net	33,077	33,644	34,126	34,212	34,632	35,361	42,585	42,341
Deferred Income Taxes	38	44	42	39	44	39	37	39
Other Assets	1,753	1,733	1,818	1,705	1,626	1,639	1,757	1,763
Total Assets	44,796	45,224	46,151	47,186	46,982	46,284	52,199	51,799

Current Liabilities
Accounts Payable	2,389	2,436	2,290	2,464	2,353	2,266	2,944	2,904
Accrued Taxes Payable	786	600	855	1,007	668	348	392	299
Dividends Payable	523	516	513	539	534	1,081	550	544
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	27
Current Portion of Operating Lease Liabilities	318	303	338	315	318	360	433	472
Other	223	231	344	381	290	257	452	445
Total	4,273	4,628	4,406	5,354	5,719	5,175	4,815	4,691

Long-Term Debt	3,757	3,250	3,742	4,220	3,464	3,458	7,667	7,909
Other Liabilities	2,533	2,456	2,480	2,395	2,368	2,398	2,496	2,512
Deferred Income Taxes	5,597	5,731	5,949	5,866	5,915	6,015	6,936	6,854
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par	206	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	6,027
Accumulated Other Comprehensive Loss	(8)	(8)	(9)	(4)	(4)	(7)	(5)	(7)
Retained Earnings	23,897	25,071	26,231	26,941	27,869	28,131	29,603	29,765
Common Stock Held in Treasury	(1,647)	(2,329)	(2,912)	(3,882)	(4,650)	(5,245)	(5,497)	(6,158)
Total Stockholders' Equity	28,636	29,159	29,574	29,351	29,516	29,238	30,285	29,833
Total Liabilities and Stockholders' Equity	44,796	45,224	46,151	47,186	46,982	46,284	52,199	51,799

(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	701	4,980
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	1,074	984	1,031	1,019	4,108	1,013	1,053	1,169	1,226	4,461
Impairments	19	81	15	276	391	44	39	71	689	843
Stock-Based Compensation Expenses	45	45	58	51	199	50	53	53	60	216
Deferred Income Taxes	199	128	220	(80)	467	44	105	278	(84)	343
(Gains) Losses on Asset Dispositions, Net	(26)	(20)	7	23	(16)	1	—	18	16	35
Other, Net	9	3	2	3	17	11	11	2	3	27
Dry Hole Costs	1	5	—	8	14	34	11	—	4	49
Mark-to-Market Financial Commodity and Other Derivative Contracts (Gains) Losses, Net	(237)	47	(79)	65	(204)	191	(107)	(116)	19	(13)
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	55	79	61	19	214	(38)	(24)	27	(21)	(56)
Other, Net	—	—	—	—	—	—	—	—	(1)	(1)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	58	33	109	(99)	101	48	122	133	(3)	300
Inventories	117	75	30	37	259	76	(45)	4	(84)	(49)
Accounts Payable	(58)	29	(159)	152	(36)	(129)	(107)	5	(40)	(271)
Accrued Taxes Payable	319	(185)	256	151	541	(339)	(321)	28	(103)	(735)
Other Assets	(161)	42	197	(34)	44	(43)	(43)	(28)	97	(17)
Other Liabilities	(71)	(20)	108	6	23	(96)	(52)	155	10	17
Changes in Components of Working Capital Associated with Investing Activities	(229)	(127)	59	(85)	(382)	(41)	(8)	(159)	123	(85)
Net Cash Provided by Operating Activities	2,903	2,889	3,588	2,763	12,143	2,289	2,032	3,111	2,612	10,044
Investing Cash Flows
Acquisition of Encino Acquisition Partners, LLC, Net of Cash Acquired	—	—	—	—	—	—	—	(4,464)	13	(4,451)
Additions to Oil and Gas Properties	(1,485)	(1,357)	(1,263)	(1,248)	(5,353)	(1,381)	(1,699)	(1,492)	(1,543)	(6,115)
Additions to Other Property, Plant and Equipment	(350)	(313)	(239)	(117)	(1,019)	(102)	(94)	(171)	(112)	(479)
Proceeds from Sales of Assets	9	10	—	4	23	12	4	5	3	24
Changes in Components of Working Capital Associated with Investing Activities	229	127	(59)	85	382	41	8	159	(123)	85
Net Cash Used in Investing Activities	(1,597)	(1,533)	(1,561)	(1,276)	(5,967)	(1,430)	(1,781)	(5,963)	(1,762)	(10,936)
Financing Cash Flows
Long-Term Debt Borrowings	—	—	—	985	985	—	—	3,472	999	4,471
Long-Term Debt Repayments	—	—	—	—	—	—	(500)	(1,266)	(750)	(2,516)
Dividends Paid	(525)	(520)	(533)	(509)	(2,087)	(538)	(528)	(545)	(550)	(2,161)
Treasury Stock Purchased	(759)	(699)	(795)	(993)	(3,246)	(806)	(602)	(479)	(677)	(2,564)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	—	11	—	11	22	—	11	—	12	23
Debt Issuance and Other Financing Costs	—	—	—	(2)	(2)	—	(7)	(7)	(11)	(25)
Repayment of Finance Lease Liabilities	(8)	(9)	(8)	(8)	(33)	(8)	(9)	(8)	(7)	(32)
Net Cash Used in Financing Activities	(1,292)	(1,217)	(1,336)	(516)	(4,361)	(1,352)	(1,635)	1,167	(984)	(2,804)
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)	(134)	(3,696)
Cash and Cash Equivalents at Beginning of Period	5,278	5,292	5,431	6,122	5,278	7,092	6,599	5,216	3,530	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	3,396	3,396

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.

	4Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	910	(209)	701	1.30
Adjustments:
Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	19	(4)	15	0.03
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)	(21)	4	(17)	(0.03)
Add: Losses on Asset Dispositions, Net	16	(4)	12	0.02
Add: Certain Impairments (2)	646	(140)	506	0.94
Add: Acquisition-related costs (3)	8	(3)	5	0.01
Adjustments to Net Income	668	(147)	521	0.97

Adjusted Net Income (Non-GAAP)	1,578	(356)	1,222	2.27

Average Number of Common Shares
Basic				537
Diluted				539

(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 December 31, 2025, such amount was $21 million.

(2)Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation).

(3)Consists of Encino acquisition-related G&A costs ($8 million).


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

	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).


	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

(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.


	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 (2)	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

(2)Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.


Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	FY 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	6,362	(1,382)	4,980	9.12
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(13)	3	(10)	(0.02)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)	(56)	12	(44)	(0.08)
Add: Losses on Asset Dispositions, Net	35	(8)	27	0.05
Add: Certain Impairments (2)	657	(140)	517	0.95
Add: Acquisition-related costs (3)	94	(16)	78	0.14
Adjustments to Net Income	717	(149)	568	1.04

Adjusted Net Income (Non-GAAP)	7,079	(1,531)	5,548	10.16

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 twelve months ended December 31, 2025, such amount was $56 million.

(3)Consists of Encino acquisition-related G&A costs ($88 million) and financing commitment costs ($6 million).


	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 (2)	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.

(2)Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.


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

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

Realized Prices
4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	34.99
Less: 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(38.05)
Subtotal	(3.06)
Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	128.7
Total Change in Revenue	(394)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	87
Change in Net Income	(307)
Change in Diluted Earnings per Share		(0.57)

Volumes
4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	128.7
Less: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	(119.7)
Subtotal	9.0
Multiplied by: 4Q 2025 Composite Average Margin per Boe (GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)	6.70
Change in Margin	60
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(13)
Change in Net Income	47
Change in Diluted Earnings per Share		0.09

Certain Operating Costs per Boe
3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	20.27
Less: 4Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	(19.81)
Subtotal	0.46
Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	128.7
Change in Before-Tax Net Income	59
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	(13)
Change in Net Income	46
Change in Diluted Earnings per Share		0.09
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
4Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	(19)
Less: Income Tax Benefit (Provision)	4
After Tax - (a)	(15)
Less: 3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	116
Less: Income Tax Benefit (Provision)	(25)
After Tax - (b)	91
Change in Net Income - (a) - (b)	(106)
Change in Diluted Earnings per Share		(0.20)

Other (1)		(0.81)

4Q 2025 Net Income per Share (GAAP) - Diluted		1.30

4Q 2025 Average Number of Common Shares - Diluted	539

(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.


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)

FY 2024 Net Income per Share (GAAP) - Diluted		11.25

Realized Prices
FY 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	39.28
Less: FY 2024 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(45.22)
Subtotal	(5.94)
Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)	449.8
Total Change in Revenue	(2,672)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	588
Change in Net Income	(2,084)
Change in Diluted Earnings per Share		(3.82)

Volumes
FY 2025 Crude Oil Equivalent Volumes (MMBoe)	449.8
Less: FY 2024 Crude Oil Equivalent Volumes (MMBoe)	(388.7)
Subtotal	61.1
Multiplied by: FY 2025 Composite Average Margin per Boe (GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)	13.31
Change in Margin	813
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(179)
Change in Net Income	634
Change in Diluted Earnings per Share		1.16

Certain Operating Costs per Boe
FY 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	20.76
Less: FY 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	(20.20)
Subtotal	0.56
Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)	449.8
Change in Before-Tax Net Income	252
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	(55)
Change in Net Income	197
Change in Diluted Earnings per Share		0.36

Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
FY 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	13
Less: Income Tax Benefit (Provision)	(3)
After Tax - (a)	10
Less: FY 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	204
Less: Income Tax Benefit (Provision)	(44)
After Tax - (b)	160
Change in Net Income - (a) - (b)	(150)
Change in Diluted Earnings per Share		(0.27)

Other (1)		0.44

FY 2025 Net Income per Share (GAAP) - Diluted		9.12

FY 2025 Average Number of Common Shares - Diluted	546


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)

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

Realized Prices
4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	34.99
Less: 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(38.05)
Subtotal	(3.06)
Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	128.7
Total Change in Revenue	(394)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	87
Change in Net Income	(307)
Change in Diluted Earnings per Share		(0.57)

Volumes
4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	128.7
Less: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)	(119.7)
Subtotal	9.0
Multiplied by: 4Q 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)	11.78
Change in Margin	106
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(23)
Change in Net Income	83
Change in Diluted Earnings per Share		0.15

Certain Operating Costs per Boe
3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	19.70
Less: 4Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	(19.75)
Subtotal	(0.05)
Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	128.7
Change in Before-Tax Net Income	(6)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	1
Change in Net Income	(5)
Change in Diluted Earnings per Share		(0.01)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
4Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	(21)
Less: Income Tax Benefit (Provision)	4
After Tax - (a)	(17)
Less: 3Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	27
Less: Income Tax Benefit (Provision)	(5)
After Tax - (b)	22
Change in Net Income - (a) - (b)	(39)
Change in Diluted Earnings per Share		(0.07)

Other (1)		0.06

4Q 2025 Adjusted Net Income per Share (Non-GAAP)		2.27

4Q 2025 Average Number of Common Shares - Diluted	539

(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.


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)

FY 2024 Adjusted Net Income per Share (Non-GAAP) - Diluted		11.62

Realized Prices
FY 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	39.28
Less: FY 2024 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(45.22)
Subtotal	(5.94)
Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)	449.8
Total Change in Revenue	(2,672)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	588
Change in Net Income	(2,084)
Change in Diluted Earnings per Share		(3.82)

Volumes
FY 2025 Crude Oil Equivalent Volumes (MMBoe)	449.8
Less: FY 2024 Crude Oil Equivalent Volumes (MMBoe)	(388.7)
Subtotal	61.1
Multiplied by: FY 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)	14.97
Change in Margin	915
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(201)
Change in Net Income	714
Change in Diluted Earnings per Share		1.31

Certain Operating Costs per Boe
FY 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	20.74
Less: FY 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	(20.01)
Subtotal	0.73
Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)	449.8
Change in Before-Tax Net Income	328
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	(72)
Change in Net Income	256
Change in Diluted Earnings per Share		0.47

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
FY 2025 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts	(56)
Less: Income Tax Benefit (Provision)	12
After Tax - (a)	(44)
FY 2024 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts	214
Less: Income Tax Benefit (Provision)	(46)
After Tax - (b)	168
Change in Net Income - (a) - (b)	(212)
Change in Diluted Earnings per Share		(0.39)

Other (1)		0.97

FY 2025 Adjusted Net Income per Share (Non-GAAP)		10.16

FY 2025 Average Number of Common Shares - Diluted	546


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, third and fourth 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, third and fourth 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	2,612	10,044

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(58)	(33)	(109)	99	(101)	(48)	(122)	(133)	3	(300)
Inventories	(117)	(75)	(30)	(37)	(259)	(76)	45	(4)	84	49
Accounts Payable	58	(29)	159	(152)	36	129	107	(5)	40	271
Accrued Taxes Payable	(319)	185	(256)	(151)	(541)	339	321	(28)	103	735
Other Assets	161	(42)	(197)	34	(44)	43	43	28	(97)	17
Other Liabilities	71	20	(108)	(6)	(23)	96	52	(155)	(10)	(17)
Changes in Components of Working Capital Associated with Investing Activities	229	127	(59)	85	382	41	8	159	(123)	85
Add:
Acquisition-Related Costs (1), Net of Tax	—	—	—	—	—	—	10	58	5	73
Adjusted Cash Flow from Operations (Non-GAAP)	2,928	3,042	2,988	2,635	11,593	2,813	2,496	3,031	2,617	10,957
Less:
Total Capital Expenditures (Non-GAAP) (2)	(1,703)	(1,668)	(1,497)	(1,358)	(6,226)	(1,484)	(1,523)	(1,648)	(1,639)	(6,294)
Free Cash Flow (Non-GAAP)	1,225	1,374	1,491	1,277	5,367	1,329	973	1,383	978	4,663

(1) Consists of Encino acquisition-related G&A costs of $12 million, $68 million and $8 million (each before tax) for the three months ended June 30, 2025, three months ended September 30, 2025 and three months ended December 31, 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	1,730	13,703
Less:
Asset Retirement Costs	(21)	60	(11)	(26)	2	(13)	(14)	(86)	(33)	(146)
Non-Cash Leasehold Acquisition Costs (3)	(31)	(34)	(17)	(3)	(85)	(9)	(2)	(3)	(10)	(24)
Acquisition Costs of Properties (3)	(21)	(5)	—	(7)	(33)	1	(270)	(6,736)	2	(7,003)
Acquisition Costs of Other Property, Plant and Equipment	(131)	(1)	(5)	—	(137)	—	—	—	—	—
Exploration Costs	(45)	(34)	(43)	(52)	(174)	(41)	(74)	(71)	(50)	(236)
Total Capital Expenditures (Non-GAAP)	1,703	1,668	1,497	1,358	6,226	1,484	1,523	1,648	1,639	6,294


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

		FY 2023		FY 2022	FY 2021

Net Cash Provided by Operating Activities (GAAP)		11,340		11,093	8,791

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		38		347	821
Inventories		231		534	13
Accounts Payable		119		(90)	(456)
Accrued Taxes Payable		(61)		113	(312)
Other Assets		(39)		364	136
Other Liabilities		(184)		266	116
Changes in Components of Working Capital Associated with Investing Activities	(295)	(375)	200
Adjusted Cash Flow from Operations (Non-GAAP)	11,149	12,252	9,309
Less:
Total Capital Expenditures (Non-GAAP) (a)		(6,041)		(4,607)	(3,755)
Free Cash Flow (Non-GAAP)		5,108		7,645	5,554

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

Total Expenditures (GAAP)		6,818		5,610	4,255
Less:
Asset Retirement Costs		(257)		(298)	(127)
Non-Cash Development Drilling		(90)		—	—
Non-Cash Leasehold Acquisition Costs (3)		(99)		(127)	(45)
Non-Cash Finance Leases		—		—	(74)
Acquisition Costs of Properties (3)		(16)		(419)	(100)
Acquisition Costs of Other Property, Plant and Equipment		(134)		—	—
Exploration Costs		(181)		(159)	(154)
Total Capital Expenditures (Non-GAAP)		6,041		4,607	3,755

(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.

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

Total Stockholders' Equity - (a)	29,833		30,285		29,238		29,516		29,351

Current and Long-Term Debt (GAAP) - (b)	7,936		7,694		4,236		4,744		4,752
Less: Cash	(3,396)		(3,530)		(5,216)		(6,599)		(7,092)
Net Debt (Non-GAAP) - (c)	4,540		4,164		(980)		(1,855)		(2,340)

Total Capitalization (GAAP) - (a) + (b)	37,769		37,979		33,474		34,260		34,103

Total Capitalization (Non-GAAP) - (a) + (c)	34,373		34,449		28,258		27,661		27,011

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	21.0	%	20.3	%	12.7	%	13.8	%	13.9	%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	13.2	%	12.1	%	-3.5	%	-6.7	%	-8.7	%


Proved Reserves and Reserve Replacement Data
(Unaudited)

2025 Net Proved Reserves Reconciliation Summary	United States		Trinidad		Other International		Total
Crude Oil and Condensate (MMBbl)
Beginning Reserves	1,868		2		—		1,870
Revisions	(10)		—		—		(10)
Purchases in Place	158		—		—		158
Extensions, Discoveries and Other Additions	77		1		—		78
Sales in Place	—		—		—		—
Production	(190)		(1)		—		(191)
Ending Reserves	1,903		2		—		1,905

Natural Gas Liquids (MMBbl)
Beginning Reserves	1,358		—		—		1,358
Revisions	9		—		—		9
Purchases in Place	200		—		—		200
Extensions, Discoveries and Other Additions	48		—		—		48
Sales in Place	—		—		—		—
Production	(105)		—		—		(105)
Ending Reserves	1,510		—		—		1,510

Natural Gas (Bcf)
Beginning Reserves	8,878		244		—		9,122
Revisions	798		9		—		807
Purchases in Place	2,340		—		—		2,340
Extensions, Discoveries and Other Additions	1,184		77		—		1,261
Sales in Place	(1)		—		—		(1)
Production	(851)		(86)		—		(937)
Ending Reserves	12,348		244		—		12,592

Oil Equivalents (MMBoe)
Beginning Reserves	4,706		42		—		4,748
Revisions	131		2		—		133
Purchases in Place	749		—		—		749
Extensions, Discoveries and Other Additions	322		14		—		336
Sales in Place	—		—		—		—
Production	(437)		(15)		—		(452)
Ending Reserves	5,471		43		—		5,514

Net Proved Developed Reserves (MMBoe)
At December 31, 2024	2,542		24		—		2,566
At December 31, 2025	3,317		29		—		3,346

2025 Exploration and Development Expenditures ($ Millions)

Acquisition Cost of Unproved Properties	195		2		—		197
Exploration Costs	349		79		85		513
Development Costs	5,213		147		5		5,365
Total Drilling	5,757		228		90		6,075
Acquisition Cost of Proved Properties	6,977		—		26		7,003
Asset Retirement Costs	98		35		13		146
Total Exploration and Development Expenditures	12,832		263		129		13,224
Gathering, Processing and Other	470		5		4		479
Total Expenditures	13,302		268		133		13,703
Proceeds from Sales in Place	(24)		—		—		(24)
Net Expenditures	13,278		268		133		13,679

Reserve Replacement Costs ($ / Boe) *
All-in Total, Net of Revisions (GAAP)	10.68		16.44		—		10.86
All-in Total, Net of Revisions (Non-GAAP)	12.29		12.25		—		12.44
All-in Total, Excluding Revisions Due to Price (GAAP)	11.32		16.44		—		11.50
All-in Total, Excluding Revisions Due to Price (Non-GAAP)	14.45		12.25		—		14.54

Reserve Replacement *
All-in Total, Net of Revisions and Dispositions	275	%	107	%	0	%	269	%
All-in Total, Net of Revisions and Dispositions (Adjusted)	104	%	107	%	0	%	104	%
All-in Total, Excluding Revisions Due to Price	259	%	107	%	0	%	254	%
All-in Total, Excluding Revisions Due to Price (Adjusted)	88	%	107	%	0	%	89	%

* See following reconciliation schedule for calculation methodology


Reserve Replacement Cost Data
(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2025	United States		Trinidad		Other International		Total

Total Costs Incurred in Exploration and Development Activities (GAAP)	12,832		263		129		13,224
Less: Asset Retirement Costs	(98)		(35)		(13)		(146)
Non-Cash Acquisition Costs of Unproved Properties	(24)		—		—		(24)
Total Acquisition Costs of Proved Properties	(6,977)		—		(26)		(7,003)
Exploration Expenses	(160)		(32)		(44)		(236)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP)	5,573		196		46		5,815

Total Costs Incurred in Exploration and Development Activities (GAAP) - (a)	12,832		263		129		13,224
Less: Asset Retirement Costs	(98)		(35)		(13)		(146)
Non-Cash Acquisition Costs of Unproved Properties	(24)		—		—		(24)
Non-Cash Acquisition Costs of Proved Properties	—		—		—		—
Certain Acquisition Costs of Proved Properties 1	(6,972)		—		—		(6,972)
Exploration Expenses	(160)		(32)		(44)		(236)
Total Exploration and Development Expenditures (Non-GAAP) - (b)	5,578		196		72		5,846

Total Expenditures (GAAP)	13,302		268		133		13,703
Less: Asset Retirement Costs	(98)		(35)		(13)		(146)
Non-Cash Acquisition Costs of Unproved Properties	(24)		—		—		(24)
Non-Cash Acquisition Costs of Proved Properties	—		—		—		—
Exploration Expenses	(160)		(32)		(44)		(236)
Total Cash Expenditures (Non-GAAP)	13,020		201		76		13,297

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	68		—		—		68
Revisions Other Than Price	63		2		—		65
Purchases in Place	749		—		—		749
Extensions, Discoveries and Other Additions - (d)	322		14		—		336
Total Proved Reserve Additions - (e)	1,202		16		—		1,218
Less: Acquisition Related Purchases 2	(748)		—		—		(748)
Adjusted Total Proved Reserve Additions - (f)	454		16		—		470
Sales in Place	—		—		—		—
Net Proved Reserve Additions From All Sources - (g)	1,202		16		—		1,218
Adjusted Net Proved Reserve Additions From All Sources - (h)	454		16		—		470

Production - (i)	437		15		—		452

Reserve Replacement Costs ($ / Boe)
All-in Total, Net of Revisions (GAAP) - (a / e)	10.68		16.44		—		10.86
All-in Total, Net of Revisions (Non-GAAP) - (b / f)	12.29		12.25		—		12.44
All-in Total, Excluding Revisions Due to Price (GAAP) - (a / (e - c))	11.32		16.44		—		11.50
All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (b / (f - c))	14.45		12.25		—		14.54

Reserve Replacement
All-in Total, Net of Revisions and Dispositions - (g / i)	275	%	107	%	0	%	269	%
All-in Total, Net of Revisions and Dispositions (Adjusted) - (h / i)	104	%	107	%	0	%	104	%
All-in Total, Excluding Revisions Due to Price - ((g - c) / i)	259	%	107	%	0	%	254	%
All-in Total, Excluding Revisions Due to Price (Adjusted) - ((h - c) / i)	88	%	107	%	0	%	89	%

(1)Includes $6,703 million for the Encino acquisition and $269 million of proved properties adjacent to EOG’s core acreage in the Eagle Ford play.

(2)Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG’s core acreage in the Eagle ford play.


Reserve Replacement Cost Data (Continued)
(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2025

Proved Developed Reserve Replacement Costs ($ / Boe)			Total
Total Costs Incurred in Exploration and Development Activities (GAAP) - (k)			13,224
Less: Asset Retirement Costs			(146)
Acquisition Costs of Unproved Properties			(197)
Acquisition Costs of Proved Properties			(7,003)
Exploration Expenses			(236)
Drillbit Exploration and Development Expenditures (Non-GAAP) - (l)			5,642

Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe)			336
Add: Conversion of Proved Undeveloped Reserves to Proved Developed			503
Less: Proved Undeveloped Extensions and Discoveries			(264)
Proved Developed Reserves - Extensions and Discoveries (MMBoe)			575

Total Proved Reserves - Revisions (MMBoe)			133
Less: Proved Undeveloped Reserves - Revisions			(21)
Proved Developed - Revisions Due to Price			(19)
Proved Developed Reserves - Revisions Other Than Price (MMBoe)			93

Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (m)			668

Proved Developed Reserves - Acquisitions (MMBoe) (n)			545

Proved Developed Reserves - Extensions and Discoveries plus Revisions Other Than Price plus Acquisitions (MMBoe) (o)			1,213

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) - (k / o)			10.90

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) - (l / m)			8.45


Reserve Replacement Cost Data (Continued)
In millions of USD, except reserves and ratio data (Unaudited)

The following table reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics (and the non-GAAP measures used in calculating such statistics) provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics (and the non-GAAP measures used in calculating such statistics) are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

	2025	2024	2023	2022	2021

Total Costs Incurred in Exploration and Development Activities (GAAP)	13,224	5,634	6,018	5,229	3,969
Less: Asset Retirement Costs	(146)	2	(257)	(298)	(127)
Non-Cash Acquisition Costs of Unproved Properties	(24)	(85)	(99)	(127)	(45)
Total Acquisition Costs of Proved Properties	(7,003)	(33)	(16)	(419)	(100)
Non-Cash Development Drilling	—	—	(90)	—	—
Exploration Expenses	(236)	(174)	(181)	(159)	(154)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a)	5,815	5,344	5,375	4,226	3,543

Total Costs Incurred in Exploration and Development Activities (GAAP) - (b)	13,224	5,634	6,018	5,229	3,969
Less: Asset Retirement Costs	(146)	2	(257)	(298)	(127)
Non-Cash Acquisition Costs of Unproved Properties	(24)	(85)	(99)	(127)	(45)
Non-Cash Acquisition Costs of Proved Properties	—	(24)	(6)	(26)	(5)
Non-Cash Development Drilling	—	—	(90)	—	—
Certain Acquisition Costs of Proved Properties 1	(6,972)	—	—	—	—
Exploration Expenses	(236)	(174)	(181)	(159)	(154)
Total Exploration and Development Expenditures (Non-GAAP) - (c)	5,846	5,353	5,385	4,619	3,638

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (d)	68	(146)	(110)	11	194
Revisions Other Than Price	65	215	139	325	(308)
Purchases in Place	749	6	2	16	9
Extensions, Discoveries and Other Additions - (e)	336	580	607	560	952
Total Proved Reserve Additions (GAAP) - (f)	1,218	655	638	912	847
Less: Acquisition Related Purchases 2	(748)	—	—	—	—
Total Proved Reserve Additions (Non-GAAP) - (g)	470	655	638	912	847
Sales in Place	—	(14)	(17)	(88)	(11)
Net Proved Reserve Additions From All Sources (GAAP)	1,218	641	621	824	836

Production	452	391	361	333	309

Reserve Replacement Costs ($ / Boe)
All-in Total, Net of Revisions (GAAP) - (b / f)	10.86	8.60	9.43	5.73	4.69
All-in Total, Net of Revisions (Non-GAAP) - (c / g)	12.44	8.17	8.44	5.06	4.30
All-in Total, Excluding Revisions Due to Price (GAAP) - (b / ( f - d))	11.50	7.03	8.05	5.80	6.08
All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (c / ( g - d))	14.54	6.68	7.20	5.13	5.57

(1)Includes $6,703 million for the Encino acquisition and $269 million of proved properties adjacent to EOG’s core acreage in the Eagle Ford play.

(2)Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG’s core acreage in the Eagle ford play.


Definitions
$/Boe			U.S. Dollars per barrel of oil equivalent
MMBoe			Million barrels of oil equivalent


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.

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

Volume - Million Barrels of Oil Equivalent - (a)	128.7	119.7	103.2	98.1	100.8

Total Operating Revenues and Other - (b)	5,638	5,847	5,478	5,669	5,585
Total Operating Expenses - (c)	4,695	4,011	3,731	3,810	3,993
Operating Income - (d)	943	1,836	1,747	1,859	1,592

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate	2,991	3,243	2,974	3,293	3,261
Natural Gas Liquids	666	604	534	572	554
Natural Gas	847	707	600	637	494
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e)	4,504	4,554	4,108	4,502	4,309

Operating Costs
Lease and Well	447	431	396	401	394
Gathering, Processing and Transportation Costs (1)	652	587	455	440	441
General and Administrative (GAAP)	224	239	186	171	189
Less: Certain Items (see Endnotes 2 & 3 to 4Q 2025 earnings release)	(8)	(68)	(12)	—	—
General and Administrative (Non-GAAP) (2)	216	171	174	171	189
Taxes Other Than Income (GAAP)	283	309	301	341	291
Add: Severance Tax Refund	—	—	—	—	—
Taxes Other Than Income (Non-GAAP) (3)	283	309	301	341	291
Interest Expense, Net	66	71	51	47	38
Less: Acquisition-Related Financing Commitment Costs	—	—	(6)	—	—
Interest Expense, Net (Non-GAAP) (4)	66	71	45	47	38
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	1,672	1,637	1,389	1,400	1,353
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	1,664	1,569	1,371	1,400	1,353

Depreciation, Depletion and Amortization (DD&A)	1,226	1,169	1,053	1,013	1,019

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	2,898	2,806	2,442	2,413	2,372
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	2,890	2,738	2,424	2,413	2,372

Exploration Costs	50	71	74	41	52
Dry Hole Costs	4	—	11	34	8
Impairments	689	71	39	44	276
Total Exploration Costs (GAAP)	743	142	124	119	336
Less: Certain Impairments (5)	(646)	—	(11)	—	(254)
Total Exploration Costs (Non-GAAP)	97	142	113	119	82

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	3,641	2,948	2,566	2,532	2,708
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) - (k)	2,987	2,880	2,537	2,532	2,454

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	863	1,606	1,542	1,970	1,601
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))	1,517	1,674	1,571	1,970	1,855


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

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

Composite Average Operating Revenues and Other per Boe - (b) / (a)	43.81	48.85	53.08	57.79	55.41
Composite Average Operating Expenses per Boe - (c) / (a)	36.48	33.51	36.15	38.84	39.62
Composite Average Operating Income per Boe - (d) / (a)	7.33	15.34	16.93	18.95	15.79

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a)	34.99	38.05	39.80	45.88	42.74

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	12.99	13.67	13.46	14.26	13.42

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	22.00	24.38	26.34	31.62	29.32

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)	22.52	23.44	23.66	24.58	23.53

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]	12.47	14.61	16.14	21.30	19.21

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)	28.29	24.63	24.86	25.79	26.86

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]	6.70	13.42	14.94	20.09	15.88

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

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)	12.93	13.10	13.30	14.26	13.42

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]	22.06	24.95	26.50	31.62	29.32

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)	22.46	22.87	23.50	24.58	23.53

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]	12.53	15.18	16.30	21.30	19.21

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)	23.21	24.06	24.59	25.79	24.34

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]	11.78	13.99	15.21	20.09	18.40


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

	2025	2024	2023	2022	2021

Volume - Million Barrels of Oil Equivalent - (a)	449.8	388.7	359.4	331.5	302.5

Total Operating Revenues and Other - (b)	22,632	23,698	24,186	25,702	18,642
Total Operating Expenses - (c)	16,247	15,616	14,583	15,736	12,540
Operating Income (Loss) - (d)	6,385	8,082	9,603	9,966	6,102

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate	12,501	13,921	13,748	16,367	11,125
Natural Gas Liquids	2,376	2,106	1,884	2,648	1,812
Natural Gas	2,791	1,551	1,744	3,781	2,444
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e)	17,668	17,578	17,376	22,796	15,381

Operating Costs
Lease and Well	1,675	1,572	1,454	1,331	1,135
Gathering, Processing and Transportation Costs (1)	2,134	1,722	1,620	1,587	1,422
General and Administrative (GAAP)	820	669	640	570	511
Less: Certain Items (see Endnote 7 to Additional Key Financial Information below)	(88)	(10)	—	(16)	—
General and Administrative (Non-GAAP) (2)	732	659	640	554	511
Taxes Other Than Income (GAAP)	1,234	1,249	1,284	1,585	1,047
Add: Severance Tax Refund	—	31	—	115	—
Taxes Other Than Income (Non-GAAP) (3)	1,234	1,280	1,284	1,700	1,047
Interest Expense, Net	235	138	148	179	178
Less: Acquisition-Related Financing Commitment Costs	(6)	—	—	—	—
Interest Expense, Net (Non-GAAP) (4)	229	138	148	179	178
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	6,098	5,350	5,146	5,252	4,293
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	6,004	5,371	5,146	5,351	4,293

Depreciation, Depletion and Amortization (DD&A)	4,461	4,108	3,492	3,542	3,651

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	10,559	9,458	8,638	8,794	7,944
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	10,465	9,479	8,638	8,893	7,944

Exploration Costs	236	174	181	159	154
Dry Hole Costs	49	14	1	45	71
Impairments	843	391	202	382	376
Total Exploration Costs (GAAP)	1,128	579	384	586	601
Less: Certain Impairments (5)	(657)	(291)	(42)	(113)	(15)
Total Exploration Costs (Non-GAAP)	471	288	342	473	586

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	11,687	10,037	9,022	9,380	8,545
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) - (k)	10,936	9,767	8,980	9,366	8,530

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	5,981	7,541	8,354	13,416	6,836
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))	6,732	7,811	8,396	13,430	6,851


Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
	2025	2024	2023	2022	2021

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

Composite Average Operating Revenues and Other per Boe - (b) / (a)	50.32	60.97	67.30	77.53	61.63
Composite Average Operating Expenses per Boe - (c) / (a)	36.12	40.18	40.58	47.47	41.46
Composite Average Operating Income (Loss) per Boe - (d) / (a)	14.20	20.79	26.72	30.06	20.17

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a)	39.28	45.22	48.34	68.77	50.84

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	13.54	13.76	14.31	15.84	14.19

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	25.74	31.46	34.03	52.93	36.65

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)	23.46	24.33	24.03	26.53	26.26

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]	15.82	20.89	24.31	42.24	24.58

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)	25.97	25.82	25.10	28.30	28.25

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]	13.31	19.40	23.24	40.47	22.59

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

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)	13.34	13.82	14.31	16.14	14.19

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]	25.94	31.40	34.03	52.63	36.65

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)	23.26	24.39	24.03	26.83	26.26

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]	16.02	20.83	24.31	41.94	24.58

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)	24.31	25.13	24.98	28.26	28.20

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]	14.97	20.09	23.36	40.51	22.64

(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.	2025 Actual		2024 Actual		2023 Actual		2022 Actual		2021 Actual

Crude Oil and Condensate Volumes (MBod)
United States	520.5		490.6		475.2		460.7		443.4
Trinidad	1.4		0.8		0.6		0.6		1.5
Other International	—		—		—		—		0.1
Total	521.9		491.4		475.8		461.3		445.0
Natural Gas Liquids Volumes (MBbld)
Total	288.2		245.9		223.8		197.7		144.5
Natural Gas Volumes (MMcfd)
United States	2,299		1,728		1,551		1,315		1,210
Trinidad	230		220		160		180		217
Other International1	4		—		—		—		9
Total	2,533		1,948		1,711		1,495		1,436
Crude Oil Equivalent Volumes (MBoed)
United States	1,191.8		1,024.5		957.5		877.5		789.6
Trinidad	39.8		37.6		27.3		30.7		37.7
Other International1	0.6		—		—		—		1.6
Total	1,232.2		1,062.1		984.8		908.2		828.9
Benchmark Price
Oil (WTI) ($/Bbl)	64.78		75.72		77.61		94.23		67.96
Natural Gas (HH) ($/Mcf)	3.43		2.27		2.74		6.64		3.85
Crude Oil and Condensate - above (below) WTI2 ($/Bbl)
United States	0.87		1.70		1.57		2.99		0.58
Trinidad	(7.19)		(11.29)		(9.03)		(8.07)		(11.70)
Other International1	0.36		—		—		—		—
Natural Gas Liquids - Realizations as % of WTI
Total	34.9	%	30.9	%	29.7	%	39.0	%	50.5	%
Natural Gas - above (below) NYMEX Henry Hub3 ($/Mcf)
United States	(0.49)		(0.28)		(0.04)		0.63		1.03
Natural Gas Realizations4 ($/Mcf)
Trinidad	3.78		3.65		3.65		4.43		3.40
Other International1	3.28		—		—		—		—
Total Expenditures (GAAP) ($MM)	13,703		6,653		6,818		5,610		4,255
Capital Expenditures5 (non-GAAP) ($MM)	6,294		6,226		6,041		4,607		3,755
Operating Unit Costs ($/Boe)
Lease and Well	3.72		4.04		4.05		4.02		3.75
Gathering, Processing and Transportation Costs6	4.74		4.43		4.50		4.78		4.70
General and Administrative (GAAP)	1.82		1.72		1.78		1.72		1.69
General and Administrative (non-GAAP)7	1.63		1.70		1.78		1.67		1.69
Cash Operating Costs (GAAP)	10.28		10.19		10.33		10.52		10.14
Cash Operating Costs (non-GAAP)7	10.09		10.17		10.33		10.47		10.14
Depreciation, Depletion and Amortization	9.92		10.57		9.72		10.69		12.07
Expenses ($MM)
Exploration and Dry Hole	285		188		182		204		225
Impairment (GAAP)	843		391		202		382		376
Impairment (excluding certain impairments (non-GAAP))8	186		100		160		269		361
Capitalized Interest	86		45		33		36		33
Net Interest	235		138		148		179		178
Net Interest (non-GAAP)9	229		—		—		—		—
TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)
(GAAP)	7.0	%	7.1	%	7.4	%	7.0	%	6.8	%
(non-GAAP)7	7.0	%	7.3	%	7.4	%	7.5	%	6.8	%
Income Taxes
Effective Rate	21.7	%	22.1	%	21.6	%	21.7	%	21.4	%
Current Tax Expense ($MM)	1,039		1,348		1,415		2,208		1,393

Additional Key Financial Information

(Continued)

Endnotes

1)Production volumes from Bahrain operations; realized price represents contract price less Bapco’s processing and distribution costs.

2)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.

3)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.

4)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.

5)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.

6)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.

7)Cash Operating Costs consist of LOE, GP&T and G&A. G&A (non-GAAP) for fiscal year 2025 excludes costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). In addition, 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 acquisition-related costs and consulting fees on G&A and total Cash Operating Costs for fiscal year 2025, 2024 and 2022 was $(0.19), $(0.02) and $(0.05), respectively.

8)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). Impairments (non-GAAP) for FY 2025 are adjusted from Impairments (GAAP) for FY 2025 by excluding $657 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). Impairments (non-GAAP) for FY 2024 are adjusted from Impairments (GAAP) for FY 2024 by excluding $291 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

9)Net Interest for fiscal year 2025 excludes financing commitment costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per-Boe impact of such cost for fiscal year 2025 is $(0.01).

Source: View Original Filing on SEC EDGAR

FAQ

How did EOG Resources (EOG) perform financially in 2025?

EOG Resources generated 2025 net income of $4,980 million with diluted earnings per share of 9.12. Total operating revenues and other were $22,632 million, while revenues from crude oil, NGLs and natural gas sales totaled $17,668 million, roughly flat versus 2024 sales revenue.

How did EOG Resources’ 2025 earnings compare to 2024 results?

EOG’s 2025 net income of $4,980 million was below 2024 net income of $6,403 million. Diluted EPS decreased from 11.25 in 2024 to 9.12 in 2025, reflecting weaker commodity realizations, higher exploration and impairment costs, and impacts from the company’s enlarged asset base.

What were EOG Resources’ production volumes in 2025?

In 2025 EOG produced an average of 1,232.2 thousand barrels of oil equivalent per day, totaling 449.8 million barrels of oil equivalent for the year. This was higher than 2024’s 388.7 million barrels of oil equivalent, driven mainly by U.S. growth in oil, natural gas liquids and natural gas volumes.

How much did EOG Resources spend on capital and what was free cash flow in 2025?

EOG reported 2025 capital expenditures (non-GAAP) of $6,294 million. After adjusting cash flow from operations, the company generated $4,663 million of free cash flow (non-GAAP). These figures show EOG funded a sizable investment program while still producing meaningful surplus cash for the year.

What impact did the Encino acquisition have on EOG Resources in 2025?

The Encino acquisition added $6,703 million of proved property costs and 678 million barrels of oil equivalent of reserves. This helped increase total proved reserves to 5,514 million barrels of oil equivalent at year-end 2025, while also contributing to higher capital spending and a greater net debt balance.

What is EOG Resources’ leverage and liquidity position at the end of 2025?

At December 31, 2025, EOG reported $7,936 million of current and long-term debt and $3,396 million of cash, resulting in $4,540 million of net debt. The net debt-to-total capitalization ratio was 13.2%, indicating a moderate level of financial leverage following recent acquisitions.

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