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EOG Resources Reports Second Quarter 2025 Results and Updates 2025 Guidance

By PR Newswire | August 07, 2025, 4:15 PM

HOUSTON, Aug. 7, 2025 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second quarter 2025 results and updated its 2025 guidance. 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

2Q 2025



1Q 2025



4Q 2024



3Q 2024



2Q 2024



Total Revenue

5,478



5,669



5,585



5,965



6,025



Net Income

1,345



1,463



1,251



1,673



1,690



Net Income Per Share

2.46



2.65



2.23



2.95



2.95



Net Cash Provided by Operating Activities

2,032



2,289



2,763



3,588



2,889



Total Expenditures

1,883



1,546



1,446



1,573



1,682



Current and Long-Term Debt

4,236



4,744



4,752



3,776



3,784



Cash and Cash Equivalents

5,216



6,599



7,092



6,122



5,431



Debt-to-Total Capitalization

12.7 %



13.8 %



13.9 %



11.3 %



11.5 %



Cash Operating Costs ($/Boe)

10.05



10.31



10.15



10.15



10.11













Non-GAAP









Adjusted Net Income

1,268



1,586



1,535



1,644



1,807



Adjusted Net Income Per Share

2.32



2.87



2.74



2.89



3.16



Adjusted CFO1

2,496



2,813



2,635



2,988



3,042



Capital Expenditures

1,523



1,484



1,358



1,497



1,668



Free Cash Flow

973



1,329



1,277



1,491



1,374



Net Debt

(980)



(1,855)



(2,340)



(2,346)



(1,647)



Net Debt-to-Total Capitalization

(3.5 %)



(6.7 %)



(8.7 %)



(8.6 %)



(6.0 %)



Cash Operating Costs ($/Boe)2,3

9.94



10.31



10.15



10.05



10.11



Second Quarter Highlights

  • Earned adjusted net income of $1.3 billion, or $2.32 per share
  • Generated $1.0 billion of free cash flow
  • Paid $528 million in regular dividends and repurchased $600 million of shares
  • Oil, NGLs and natural gas production above guidance midpoints
  • Capital expenditures and per-unit operating costs better than guidance midpoints
  • Completed $3.5 billion debt offering to fund the acquisition of Encino Acquisition Partners (Encino)

2025 Guidance Update

  • Updated 2025 guidance after close of Encino acquisition

Volumes and Capital Expenditures







2Q 2025



















Volumes

2Q 2025



Guidance

Midpoint



1Q 2025



4Q 2024



3Q 2024



2Q 2024



Crude Oil and Condensate (MBod)

504.2



502.1



502.1



494.6



493.0



490.7



Natural Gas Liquids (MBbld)

258.4



251.0



241.7



252.5



254.3



244.8



Natural Gas (MMcfd)

2,229



2,170



2,080



2,092



1,970



1,872



Total Crude Oil Equivalent (MBoed)

1,134.1



1,114.8



1,090.4



1,095.7



1,075.7



1,047.5













Capital Expenditures ($MM)

1,523



1,550



1,484



1,358



1,497



1,668



From Ezra Yacob, Chairman and Chief Executive Officer

"EOG delivered excellent second quarter results, with oil, gas, and NGL volumes exceeding the midpoints of our guidance. At the same time, we maintained our focus on cost discipline, with capital expenditures, cash operating costs, and DD&A all coming in below guidance. Strong operational execution across our multi-basin portfolio continues to be the foundation of our success.

"Our operational excellence translated into strong financial performance. EOG generated $973 million in free cash flow during the quarter. We continued to deliver on our cash return commitment by returning $1.1 billion to shareholders, including $600 million of share repurchases. The regular dividend remains our top cash return priority. The 5% increase in our regular quarterly dividend, announced in tandem with the Encino acquisition, reflects both our continued confidence in our business and the positive impact we expect from the transaction.

"With the close of the Encino acquisition, the Utica is now positioned as a foundational asset for EOG. We have updated our full year 2025 guidance, which reflects both capital discipline and our high conviction in the quality and potential of this asset. Our focus is on optimizing the development of the play as we integrate Encino with our operations.

"EOG has never been better positioned to create long-term value for shareholders. The expansion of our portfolio through the Encino acquisition, our entry into Bahrain and the UAE, as well as strong exploration progress across our domestic portfolio and in Trinidad, has significantly enhanced our industry-leading asset base. We continue to improve our resource base while also maintaining one of the strongest balance sheets in the industry. Our multi- basin portfolio, operational excellence, and financial strength provide us unmatched flexibility to deliver high returns and significant cash return to shareholders through commodity price cycles."

Previously Announced Regular Dividend and Second Quarter Share Repurchases

On May 30, 2025, the Board of Directors declared a dividend of $1.02 per share on EOG's common stock. The dividend will be payable on October 31, 2025, to shareholders of record as of October 17, 2025. The indicated annual rate is $4.08 per share.

During the second quarter, the company repurchased 5.4 million shares for $600 million under its share repurchase authorization. EOG has $4.5 billion remaining on its current share buyback authorization.

2025 Guidance

2025 Guidance Update

Full year guidance has been updated after the close of the Encino acquisition. The revised outlook also incorporates strong year-to-date operational performance and the impact of recently enacted U.S. tax legislation.

Total capital expenditures for 2025 are now expected to range from $6.2 to $6.4 billion delivering full year average oil production of 521 MBod and average total production of 1,224 MBoed.

Second Quarter 2025 Financial Performance

Prices

  • Crude oil, NGL and natural gas prices decreased in 2Q compared with 1Q

Volumes

  • Oil production of 504,200 Bopd was above the midpoint of the guidance range and up from 1Q
  • NGL production was above the midpoint of the guidance range and up 7% from 1Q
  • Natural gas production was above the midpoint of the guidance range and up 7% from 1Q
  • Total company equivalent production was above the midpoint of the guidance range and increased 4% from 1Q

Per-Unit Costs

  • LOE, GP&T, DD&A and non-GAAP G&A costs decreased in 2Q compared to 1Q. Encino acquisition-related costs increased GAAP G&A costs in 2Q compared to 1Q

Hedges

  • Mark-to-market hedge gains increased GAAP earnings per share in 2Q compared with 1Q
  • Decreased cash paid to settle hedges increased adjusted non-GAAP earnings per share in 2Q compared with 1Q

Free Cash Flow

  • Adjusted cash flow from operations was $2.5 billion
  • Incurred $1.5 billion of capital expenditures
  • This resulted in $1.0 billion of free cash flow

Cash Return and Working Capital

  • Paid $528 million in regular dividends
  • Repurchased $600 million of stock
  • Repaid $500 million of Senior Notes upon maturity
  • Acquired Eagle Ford bolt-on acreage for approximately $270 million

Second Quarter 2025 Operating Performance

Lease and Well

  • QoQ: Decreased primarily due to lower maintenance costs and water handling expenses
  • Guidance Midpoint: Lower primarily due to lower maintenance costs, water handling expenses and workover expenses

General and Administrative

  • QoQ: Decreased primarily due to lower professional fees
  • Guidance Midpoint: Lower primarily due to lower professional fees

Gathering, Processing and Transportation Costs

  • QoQ: Decreased primarily due to lower natural gas gathering and processing fees and operating expenses
  • Guidance Midpoint: Lower primarily due to lower natural gas gathering and processing fees and compression fuel-related costs

Depreciation, Depletion and Amortization

  • QoQ: Decreased primarily due to well mix
  • Guidance Midpoint: Lower primarily due to well mix

 

Second Quarter 2025 Results vs Guidance



(Unaudited)



See "Endnotes" below for related discussion and definitions.





2Q 2025



























2Q 2025



Guidance

Midpoint7



Variance



1Q 2025



4Q 2024



3Q 2024



2Q 2024





Crude Oil and Condensate Volumes (MBod)











United States

503.1



501.3



1.8



500.9



493.5



491.8



490.1





Trinidad

1.1



0.8



0.3



1.2



1.1



1.2



0.6





Total

504.2



502.1



2.1



502.1



494.6



493.0



490.7





Natural Gas Liquids Volumes (MBbld)











Total

258.4



251.0



7.4



241.7



252.5



254.3



244.8





Natural Gas Volumes (MMcfd)











United States

1,977



1,930



47



1,834



1,840



1,745



1,668





Trinidad

252



240



12



246



252



225



204





Total

2,229



2,170



59



2,080



2,092



1,970



1,872

















Total Crude Oil Equivalent Volumes (MBoed)

1,134.1



1,114.8



19.3



1,090.4



1,095.7



1,075.7



1,047.5





Total MMBoe

103.2



101.4



1.8



98.1



100.8



99.0



95.3

















Benchmark Price











Oil (WTI) ($/Bbl)

63.71











71.42



70.28



75.16



80.55





Natural Gas (HH) ($/Mcf)

3.44











3.66



2.79



2.16



1.89

















Crude Oil and Condensate - above (below) WTI8 ($/Bbl)











United States

1.13



1.30



(0.17)



1.48



1.40



1.79



2.16





Trinidad

(9.21)



(9.50)



0.29



(10.30)



(9.81)



(12.01)



(9.80)





Natural Gas Liquids - Realizations as % of WTI











Total

35.6 %



34.0 %



1.6 %



36.8 %



33.9 %



29.8 %



28.7 %





Natural Gas - above (below) NYMEX Henry Hub9 ($/Mcf)











United States

(0.57)



(0.45)



(0.12)



(0.30)



(0.40)



(0.32)



(0.32)





Natural Gas Realizations ($/Mcf)











Trinidad

3.65



3.60



0.05



3.78



3.86



3.68



3.48

















Total Expenditures (GAAP) ($MM)

1,883











1,546



1,446



1,573



1,682





Capital Expenditures (non-GAAP) ($MM)

1,523



1,550



(27)



1,484



1,358



1,497



1,668

















Operating Unit Costs ($/Boe)











Lease and Well

3.84



4.15



(0.31)



4.09



3.91



3.96



4.09





Gathering, Processing and Transportation Costs6

4.41



4.55



(0.14)



4.48



4.37



4.50



4.44





General and Administrative (GAAP)

1.80



1.75



0.05



1.74



1.87



1.69



1.58





General and Administrative (non-GAAP)2,3

1.69



1.75



(0.06)



1.74



1.87



1.59



1.58





Cash Operating Costs (GAAP)

10.05



10.45



(0.40)



10.31



10.15



10.15



10.11





Cash Operating Costs (non-GAAP)2,3

9.94



10.45



(0.51)



10.31



10.15



10.05



10.11





Depreciation, Depletion and Amortization

10.20



10.30



(0.10)



10.32



10.11



10.42



10.32

















Expenses ($MM)











Exploration and Dry Hole

85



70



15



75



60



43



39





Impairment (GAAP)

39











44



276



15



81





Impairment (excluding certain impairments (non-GAAP)10

28



70



(42)



44



23



15



46





Capitalized Interest

11



12



(1)



12



13



12



10





Net Interest (GAAP)

51



43



8



47



38



31



36





Net Interest (non-GAAP)5

45



43



2



47



38



31



36















TOTI (% of revenues from sales of crude oil and

condensate, NGLs and natural gas)











(GAAP)

7.3 %



8.0 %



(0.7 %)



7.6 %



6.8 %



6.5 %



7.5 %





(non-GAAP)3

7.3 %



8.0 %



(0.7 %)



7.6 %



6.8 %



7.2 %



7.5 %





Income Taxes











Effective Rate

23.2 %



22.5 %



0.7 %



22.1 %



23.0 %



21.6 %



21.7 %





Current Tax Expense ($MM)

301



260



41



370



454



240



341





 

Third Quarter and Full-Year 2025 Guidance11

(Unaudited)



See "Endnotes" below for related discussion and definitions.

3Q 2025



3Q 2025



FY 2025



FY 2025





Guidance Range



Midpoint



Guidance Range



Midpoint



Crude Oil and Condensate Volumes (MBod)

























United States

528.7

-

533.3



531.0



517.6

-

521.4



519.5



Trinidad

1.2

-

1.6



1.4



1.1

-

1.5



1.3



Total

529.9

-

534.9



532.4



518.7

-

522.9



520.8



Natural Gas Liquids Volumes (MBbld)

























Total

297.5

-

312.5



305.0



279.0

-

289.0



284.0



Natural Gas Volumes (MMcfd)

























United States

2,475

-

2,575



2,525



2,240

-

2,340



2,290



Trinidad

200

-

220



210



215

-

235



225



Total

2,675

-

2,795



2,735



2,455

-

2,575



2,515



Crude Oil Equivalent Volumes (MBoed)

























United States

1,238.7

-

1,275.0



1,256.9



1,169.9

-

1,200.4



1,185.2



Trinidad

34.5

-

38.3



36.4



36.9

-

40.7



38.8



Total

1,273.2

-

1,313.3



1,293.3



1,206.8

-

1,241.1



1,224.0



Crude Oil and Condensate - above (below) WTI8 ($/Bbl)



United States

0.05

-

1.55



0.80



(0.15)

-

1.85



0.85



Trinidad

(5.75)

-

(4.25)



(5.00)



(8.00)

-

(6.00)



(7.00)



Natural Gas Liquids - Realizations as % of WTI



Total

29.0 %

-

39.0 %



34.0 %



30.0 %

-

40.0 %



35.0 %



 

Natural Gas - above (below) NYMEX Henry Hub9 ($/Mcf)



United States

(0.75)

-

(0.05)



(0.40)



(1.40)

-

0.60



(0.40)



Natural Gas Realizations ($/Mcf)

























Trinidad

3.25

-

3.95



3.60



3.10

-

4.10



3.60





























Capital Expenditures12 ($MM)

1,600

-

1,700



1,650



6,200

-

6,400



6,300





























Operating Unit Costs ($/Boe)

























Lease and Well

3.45

-

3.95



3.70



3.55

-

4.05



3.80



Gathering, Processing and Transportation Costs6

4.85

-

5.35



5.10



4.65

-

5.15



4.90



General and Administrative

1.35

-

1.65



1.50



1.50

-

1.80



1.65



Cash Operating Costs

9.65

-

10.95



10.30



9.70

-

11.00



10.35



Depreciation, Depletion and Amortization

9.35

-

10.35



9.85



9.55

-

10.55



10.05



 

Expenses ($MM)

























Exploration and Dry Hole

55

-

95



75



270

-

310



290



Impairment (excluding certain impairments)10

30

-

110



70



180

-

260



220



Capitalized Interest

19

-

23



21



68

-

72



70



Net Interest

81

-

85



83



248

-

252



250









TOTI (% of revenues from sales of crude oil and





condensate, NGLs and natural gas)

6.5 %

-

8.5 %



7.5 %



6.5 %

-

8.5 %



7.5 %



Income Taxes

























Effective Rate

18.0 %

-

23.0 %



20.5 %



20.0 %

-

25.0 %



22.5 %



Current Tax Expense ($MM)

130

-

230



180



1,040

-

1,240



1,140



Second Quarter 2025 Results Webcast

Friday, August 8, 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 $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 2Q 2025 was ($0.11) as set forth in "Second Quarter 2025 Results vs Guidance" above. G&A per Boe (GAAP) 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 "Second 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 and 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)

Net interest expense (non-GAAP) excludes Encino acquisition-related financing commitment costs of $6 million for 2Q 2025.

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)

GAAP and non-GAAP distinctions apply solely to actual results and do not pertain to EOG's second quarter 2025 guidance midpoint disclosure.

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)

The forecast items for the third 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.

12)

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





6,267

Natural Gas Liquids

513

515

524

554

2,106



572

534





1,106

Natural Gas

382

303

372

494

1,551



637

600





1,237

Gains (Losses) on Mark-to-Market

     Financial Commodity and Other

     Derivative Contracts, Net

237

(47)

79

(65)

204



(191)

107





(84)

Gathering, Processing and Marketing

1,459

1,519

1,481

1,341

5,800



1,340

1,247





2,587

Gains (Losses) on Asset Dispositions,

     Net

26

20

(7)

(23)

16



(1)





(1)

Other, Net

26

23

28

23

100



19

16





35

Total

6,123

6,025

5,965

5,585

23,698



5,669

5,478





11,147

























Operating Expenses























Lease and Well

396

390

392

394

1,572



401

396





797

Gathering, Processing and

     Transportation Costs

413

423

445

441

1,722



440

455





895

Exploration Costs

45

34

43

52

174



41

74





115

Dry Hole Costs

1

5

8

14



34

11





45

Impairments

19

81

15

276

391



44

39





83

Marketing Costs

1,404

1,490

1,500

1,323

5,717



1,325

1,216





2,541

Depreciation, Depletion and

     Amortization

1,074

984

1,031

1,019

4,108



1,013

1,053





2,066

General and Administrative

162

151

167

189

669



171

186





357

Taxes Other Than Income

338

337

283

291

1,249



341

301





642

Total

3,852

3,895

3,876

3,993

15,616



3,810

3,731





7,541

























Operating Income

2,271

2,130

2,089

1,592

8,082



1,859

1,747





3,606

Other Income, Net

62

66

76

70

274



65

55





120

Income Before Interest Expense and

     Income Taxes

2,333

2,196

2,165

1,662

8,356



1,924

1,802





3,726

Interest Expense, Net

33

36

31

38

138



47

51





98

Income Before Income Taxes

2,300

2,160

2,134

1,624

8,218



1,877

1,751





3,628

Income Tax Provision

511

470

461

373

1,815



414

406





820

Net Income

1,789

1,690

1,673

1,251

6,403



1,463

1,345





2,808

























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





5.13

Diluted

3.10

2.95

2.95

2.23

11.25



2.65

2.46





5.11

Average Number of Common Shares























Basic

575

569

564

557

566



550

543





547

Diluted

577

572

568

561

569



553

546





549

 

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





502.0

Trinidad

0.6

0.6

1.2

1.1

0.8



1.2

1.1





1.1

Total

487.4

490.7

493.0

494.6

491.4



502.1

504.2





503.1

























Average Crude Oil and Condensate Prices

($/Bbl) (B)























United States

$ 78.46

$ 82.71

$ 76.95

$ 71.68

$ 77.42



$ 72.90

$ 64.84





$ 68.84

Trinidad

67.50

70.75

63.15

60.47

64.43



61.12

54.50





57.84

Composite

78.45

82.69

76.92

71.66

77.40



72.87

64.82





68.81

























Natural Gas Liquids Volumes (MBbld) (A)























United States

231.7

244.8

254.3

252.5

245.9



241.7

258.4





250.1

Total

231.7

244.8

254.3

252.5

245.9



241.7

258.4





250.1

























Average Natural Gas Liquids Prices ($/Bbl) (B)























United States

$ 24.32

$ 23.11

$ 22.42

$ 23.85

$ 23.40



$ 26.29

$ 22.70





$ 24.42

Composite

24.32

23.11

22.42

23.85

23.40



26.29

22.70





24.42

























Natural Gas Volumes (MMcfd) (A)























United States

1,658

1,668

1,745

1,840

1,728



1,834

1,977





1,906

Trinidad

200

204

225

252

220



246

252





249

Total

1,858

1,872

1,970

2,092

1,948



2,080

2,229





2,155

























Average Natural Gas Prices ($/Mcf) (B)























United States

$ 2.10

$ 1.57

$ 1.84

$ 2.39

$ 1.99



$ 3.36

$ 2.87





$ 3.10

Trinidad

3.54

3.48

3.68

3.86

3.65



3.78

3.65





3.71

Composite

2.26

1.78

2.05

2.57

2.17



3.41

2.96





3.17

























Crude Oil Equivalent Volumes (MBoed) (C)























United States

994.7

1,013.0

1,037.1

1,052.7

1,024.5



1,048.3

1,090.9





1,069.7

Trinidad

34.1

34.5

38.6

43.0

37.6



42.1

43.2





42.7

Total

1,028.8

1,047.5

1,075.7

1,095.7

1,062.1



1,090.4

1,134.1





1,112.4

























Total MMBoe (C)

93.6

95.3

99.0

100.8

388.7



98.1

103.2





201.3





























(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 June 30, 2025).

(C)

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





Accounts Receivable, Net

2,688

2,657

2,545

2,650



2,621

2,504





Inventories

1,154

1,069

1,038

985



897

934





Assets from Price Risk Management Activities

110

4







Other (A)

684

642

460

503



563

591





Total

9,928

9,803

10,165

11,230



10,680

9,245

























Property, Plant and Equipment



















Oil and Gas Properties (Successful Efforts Method)

73,356

74,615

75,887

77,091



78,432

80,139





Other Property, Plant and Equipment

5,768

6,078

6,314

6,418



6,510

6,616





Total Property, Plant and Equipment

79,124

80,693

82,201

83,509



84,942

86,755





Less: Accumulated Depreciation, Depletion and

     Amortization

(46,047)

(47,049)

(48,075)

(49,297)



(50,310)

(51,394)





Total Property, Plant and Equipment, Net

33,077

33,644

34,126

34,212



34,632

35,361





Deferred Income Taxes

38

44

42

39



44

39





Other Assets

1,753

1,733

1,818

1,705



1,626

1,639





Total Assets

44,796

45,224

46,151

47,186



46,982

46,284

























Current Liabilities



















Accounts Payable

2,389

2,436

2,290

2,464



2,353

2,266





Accrued Taxes Payable

786

600

855

1,007



668

348





Dividends Payable

523

516

513

539



534

1,081





Liabilities from Price Risk Management Activities

8

32

116



276

85





Current Portion of Long-Term Debt

34

534

34

532



1,280

778





Current Portion of Operating Lease Liabilities

318

303

338

315



318

360





Other

223

231

344

381



290

257





Total

4,273

4,628

4,406

5,354



5,719

5,175

























Long-Term Debt

3,757

3,250

3,742

4,220



3,464

3,458





Other Liabilities

2,533

2,456

2,480

2,395



2,368

2,398





Deferred Income Taxes

5,597

5,731

5,949

5,866



5,915

6,015





Commitments and Contingencies







































Stockholders' Equity



















Common Stock, $0.01 Par

206

206

206

206



206

206





Additional Paid in Capital

6,188

6,219

6,058

6,090



6,095

6,153





Accumulated Other Comprehensive Loss

(8)

(8)

(9)

(4)



(4)

(7)





Retained Earnings

23,897

25,071

26,231

26,941



27,869

28,131





Common Stock Held in Treasury

(1,647)

(2,329)

(2,912)

(3,882)



(4,650)

(5,245)





Total Stockholders' Equity

28,636

29,159

29,574

29,351



29,516

29,238





Total Liabilities and Stockholders' Equity

44,796

45,224

46,151

47,186



46,982

46,284









(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





2,808

Items Not Requiring (Providing) Cash























Depreciation, Depletion and Amortization

1,074

984

1,031

1,019

4,108



1,013

1,053





2,066

Impairments

19

81

15

276

391



44

39





83

Stock-Based Compensation Expenses

45

45

58

51

199



50

53





103

Deferred Income Taxes

199

128

220

(80)

467



44

105





149

(Gains) Losses on Asset Dispositions, Net

(26)

(20)

7

23

(16)



1





1

Other, Net

9

3

2

3

17



11

11





22

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)





84

Net Cash Received from (Payments for)

     Settlements of Financial Commodity

     Derivative Contracts

55

79

61

19

214



(38)

(24)





(62)

Changes in Components of Working Capital and

     Other Assets and Liabilities























Accounts Receivable

58

33

109

(99)

101



48

122





170

Inventories

117

75

30

37

259



76

(45)





31

Accounts Payable

(58)

29

(159)

152

(36)



(129)

(107)





(236)

Accrued Taxes Payable

319

(185)

256

151

541



(339)

(321)





(660)

Other Assets

(161)

42

197

(34)

44



(43)

(43)





(86)

Other Liabilities

(71)

(20)

108

6

23



(96)

(52)





(148)

Changes in Components of Working Capital

     Associated with Investing Activities

(229)

(127)

59

(85)

(382)



(41)

(8)





(49)

Net Cash Provided by Operating Activities

2,903

2,889

3,588

2,763

12,143



2,289

2,032





4,321

Investing Cash Flows























Additions to Oil and Gas Properties

(1,485)

(1,357)

(1,263)

(1,248)

(5,353)



(1,381)

(1,699)





(3,080)

Additions to Other Property, Plant and

     Equipment

(350)

(313)

(239)

(117)

(1,019)



(102)

(94)





(196)

Proceeds from Sales of Assets

9

10

4

23



12

4





16

Changes in Components of Working Capital

     Associated with Investing Activities

229

127

(59)

85

382



41

8





49

Net Cash Used in Investing Activities

(1,597)

(1,533)

(1,561)

(1,276)

(5,967)



(1,430)

(1,781)





(3,211)

Financing Cash Flows























Long-Term Debt Borrowings

985

985







Long-Term Debt Repayments



(500)





(500)

Dividends Paid

(525)

(520)

(533)

(509)

(2,087)



(538)

(528)





(1,066)

Treasury Stock Purchased

(759)

(699)

(795)

(993)

(3,246)



(806)

(602)





(1,408)

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)

Repayment of Finance Lease Liabilities

(8)

(9)

(8)

(8)

(33)



(8)

(9)





(17)

Net Cash Used in Financing Activities

(1,292)

(1,217)

(1,336)

(516)

(4,361)



(1,352)

(1,635)





(2,987)

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)





(1,876)

Cash and Cash Equivalents at Beginning of Period

5,278

5,292

5,431

6,122

5,278



7,092

6,599





7,092

Cash and Cash Equivalents at End of Period

5,292

5,431

6,122

7,092

7,092



6,599

5,216





5,216

 

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)), 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.



















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)

































2Q 2024



Before

Tax



Income Tax

Impact



After

Tax



Diluted

Earnings per

Share

















Reported Net Income (GAAP)

2,160



(470)



1,690



2.95

Adjustments:















Losses on Mark-to-Market Financial Commodity and Other Derivative

     Contracts, Net

47



(10)



37



0.07

Net Cash Received from Settlements of Financial Commodity

     Derivative Contracts (1)

79



(17)



62



0.11

Less: Gains on Asset Dispositions, Net

(20)



5



(15)



(0.03)

Add: Certain Impairments

35



(2)



33



0.06

Adjustments to Net Income

141



(24)



117



0.21

















Adjusted Net Income (Non-GAAP)

2,301



(494)



1,807



3.16

















Average Number of Common Shares















Basic













569

Diluted













572





(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 June 30, 2024, such amount was $79 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)









1Q 2025 Net Income per Share (GAAP) - Diluted





2.65









Realized Prices







2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and

     Natural Gas per Boe

39.80





Less: 1Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and

     Natural Gas per Boe

(45.88)





Subtotal

(6.08)





Multiplied by: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe)

103.2





Total Change in Revenue

(627)





Add: Income Tax Benefit (Provision) Imputed (based on 22%)

138





Change in Net Income

(489)





Change in Diluted Earnings per Share





(0.90)









Volumes







2Q 2025 Crude Oil Equivalent Volumes (MMBoe)

103.2





Less: 1Q 2025 Crude Oil Equivalent Volumes (MMBoe)

(98.1)





Subtotal

5.1





Multiplied by: 2Q 2025 Composite Average Margin per Boe (GAAP) (Including Total

     Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"

     schedule below)

14.94





Change in Margin

76





Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(17)





Change in Net Income

59





Change in Diluted Earnings per Share





0.11









Certain Operating Costs per Boe







1Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

20.63





Less: 2Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.25)





Subtotal

0.38





Multiplied by: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe)

103.2





Change in Before-Tax Net Income

39





Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(9)





Change in Net Income

30





Change in Diluted Earnings per Share





0.05

 

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





2Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative

     Contracts

107





Less: Income Tax Benefit (Provision)

(23)





After Tax - (a)

84





Less: 1Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative

     Contracts

(191)





Less: Income Tax Benefit (Provision)

41





After Tax - (b)

(150)





Change in Net Income - (a) - (b)

234





Change in Diluted Earnings per Share





0.43









Other (1)





0.12









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





2.46









2Q 2025 Average Number of Common Shares - Diluted

546

















(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 and 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)









1Q 2025 Adjusted Net Income per Share (Non-GAAP) - Diluted





2.87









Realized Prices







2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and

     Natural Gas per Boe

39.80





Less: 1Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and

     Natural Gas per Boe

(45.88)





Subtotal

(6.08)





Multiplied by: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe)

103.2





Total Change in Revenue

(627)





Add: Income Tax Benefit (Provision) Imputed (based on 22%)

138





Change in Net Income

(489)





Change in Diluted Earnings per Share





(0.90)









Volumes







2Q 2025 Crude Oil Equivalent Volumes (MMBoe)

103.2





Less: 1Q 2025 Crude Oil Equivalent Volumes (MMBoe)

(98.1)





Subtotal

5.1





Multiplied by: 2Q 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)

15.21





Change in Margin

78





Add: Income Tax Benefit (Provision) Imputed (based on 22%)

(17)





Change in Net Income

61





Change in Diluted Earnings per Share





0.11









Certain Operating Costs per Boe







1Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

20.63





Less: 2Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.14)





Subtotal

0.49





Multiplied by: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe)

103.2





Change in Before-Tax Net Income

51





Add: Income Tax Benefit (Provision) Imputed (based on 22%)

(11)





Change in Net Income

40





Change in Diluted Earnings per Share





0.07

 

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





2Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative

     Contracts

(24)





Less: Income Tax Benefit (Provision)

5





After Tax - (a)

(19)





1Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative

     Contracts

(38)





Less: Income Tax Benefit (Provision)

8





After Tax - (b)

(30)





Change in Net Income - (a) - (b)

11





Change in Diluted Earnings per Share





0.02









Other (1)





0.15









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





2.32









2Q 2025 Average Number of Common Shares - Diluted

546

















(1)

Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments and 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 quarter 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 quarter 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





4,321

























Adjustments:























Changes in Components of Working Capital

     and Other Assets and Liabilities























Accounts Receivable

(58)

(33)

(109)

99

(101)



(48)

(122)





(170)

Inventories

(117)

(75)

(30)

(37)

(259)



(76)

45





(31)

Accounts Payable

58

(29)

159

(152)

36



129

107





236

Accrued Taxes Payable

(319)

185

(256)

(151)

(541)



339

321





660

Other Assets

161

(42)

(197)

34

(44)



43

43





86

Other Liabilities

71

20

(108)

(6)

(23)



96

52





148

Changes in Components of Working Capital

     Associated with Investing Activities

229

127

(59)

85

382



41

8





49

Add:























Acquisition-Related Costs (1), Net of Tax



10





10

Adjusted Cash Flow from Operations (Non-

GAAP)

2,928

3,042

2,988

2,635

11,593



2,813

2,496





5,309

Less:























Total Capital Expenditures (Non-GAAP) (2)

(1,703)

(1,668)

(1,497)

(1,358)

(6,226)



(1,484)

(1,523)





(3,007)

Free Cash Flow (Non-GAAP)

1,225

1,374

1,491

1,277

5,367



1,329

973





2,302

























(1) Consists of Encino acquisition-related G&A costs of $12 million (before tax) for the three months ended June 30, 2025.

(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





3,429

Less:























Asset Retirement Costs

(21)

60

(11)

(26)

2



(13)

(14)





(27)

Non-Cash Acquisition Costs of

     Unproved Properties

(31)

(34)

(17)

(3)

(85)



(9)

(2)





(11)

Acquisition Costs of Proved Properties

(21)

(5)

(7)

(33)



1

(270)





(269)

Acquisition Costs of Other Property,

     Plant and Equipment

(131)

(1)

(5)

(137)







Exploration Costs

(45)

(34)

(43)

(52)

(174)



(41)

(74)





(115)

Total Capital Expenditures (Non-GAAP)

1,703

1,668

1,497

1,358

6,226



1,484

1,523





3,007

 

Cash Flow from Operations and Free Cash Flow

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 Acquisition Costs of Unproved Properties









(99)



(127)

Acquisition Costs of Proved Properties









(16)



(419)

Acquisition Costs of Other Property, Plant and Equipment









(134)



Exploration Costs









(181)



(159)

Total Capital Expenditures (Non-GAAP)









6,041



4,607

















 

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.























June 30,

2025



March 31,

2025



December 31,

2024



September 30,

2024



June 30,

2024





















Total Stockholders' Equity - (a)

29,238



29,516



29,351



29,574



29,159





















Current and Long-Term Debt (GAAP) - (b)

4,236



4,744



4,752



3,776



3,784

Less: Cash

(5,216)



(6,599)



(7,092)



(6,122)



(5,431)

Net Debt (Non-GAAP) - (c)

(980)



(1,855)



(2,340)



(2,346)



(1,647)





















Total Capitalization (GAAP) - (a) + (b)

33,474



34,260



34,103



33,350



32,943





















Total Capitalization (Non-GAAP) - (a) + (c)

28,258



27,661



27,011



27,228



27,512





















Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]

12.7 %



13.8 %



13.9 %



11.3 %



11.5 %





















Net Debt-to-Total Capitalization (Non-GAAP) - (c)

/ [(a) + (c)]

-3.5 %



-6.7 %



-8.7 %



-8.6 %



-6.0 %

 

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.























2Q 2025



1Q 2025



4Q 2024



3Q 2024



2Q 2024





















Volume - Million Barrels of Oil Equivalent - (a)

103.2



98.1



100.8



99.0



95.3





















Total Operating Revenues and Other - (b)

5,478



5,669



5,585



5,965



6,025

Total Operating Expenses - (c)

3,731



3,810



3,993



3,876



3,895

Operating Income - (d)

1,747



1,859



1,592



2,089



2,130





















Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas



















Crude Oil and Condensate

2,974



3,293



3,261



3,488



3,692

Natural Gas Liquids

534



572



554



524



515

Natural Gas

600



637



494



372



303

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural

     Gas - (e)

4,108



4,502



4,309



4,384



4,510





















Operating Costs



















Lease and Well

396



401



394



392



390

Gathering, Processing and Transportation Costs (1)

455



440



441



445



423

General and Administrative (GAAP)

186



171



189



167



151

Less: Certain Items (see Endnotes 2 & 3 to 2Q 2025 earnings release)

(12)







(10)



General and Administrative (Non-GAAP) (3)

174



171



189



157



151

Taxes Other Than Income (GAAP)

301



341



291



283



337

Add: Severance Tax Refund







31



Taxes Other Than Income (Non-GAAP) (4)

301



341



291



314



337

Interest Expense, Net

51



47



38



31



36

Less: Acquisition-Related Financing Commitment Costs

(6)









Interest Expense, Net (Non-GAAP) (5)

45



47



38



31



36

Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs)

     - (f)

1,389



1,400



1,353



1,318



1,337

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration

     Costs) - (g)

1,371



1,400



1,353



1,339



1,337





















Depreciation, Depletion and Amortization (DD&A)

1,053



1,013



1,019



1,031



984





















Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)

2,442



2,413



2,372



2,349



2,321

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)

2,424



2,413



2,372



2,370



2,321





















Exploration Costs

74



41



52



43



34

Dry Hole Costs

11



34



8





5

Impairments

39



44



276



15



81

Total Exploration Costs (GAAP)

124



119



336



58



120

Less: Certain Impairments (2)

(11)





(254)





(35)

Total Exploration Costs (Non-GAAP)

113



119



82



58



85





















Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)

2,566



2,532



2,708



2,407



2,441

Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-

     GAAP)) - (k)

2,537



2,532



2,454



2,428



2,406





















Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural

     Gas less Total Operating Cost (GAAP) (including Total Exploration Costs

     (GAAP))

1,542



1,970



1,601



1,977



2,069

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))

1,571



1,970



1,855



1,956



2,104

 

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)









































2Q 2025



1Q 2025



4Q 2024



3Q 2024



2Q 2024

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







































Composite Average Operating Revenues and Other per Boe - (b) / (a)

53.08



57.79



55.41



60.25



63.22

Composite Average Operating Expenses per Boe - (c) / (a)

36.15



38.84



39.62



39.15



40.87

Composite Average Operating Income per Boe - (d) / (a)

16.93



18.95



15.79



21.10



22.35





















Composite Average Revenue from Sales of Crude Oil and Condensate,

     NGLs, and Natural Gas per Boe - (e) / (a)

39.80



45.88



42.74



44.31



47.31





















Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -

     (f) / (a)

13.46



14.26



13.42



13.32



14.03





















Composite Average Margin per Boe (excluding DD&A and Total Exploration

     Costs) - [(e) / (a) - (f) / (a)]

26.34



31.62



29.32



30.99



33.28





















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

23.66



24.58



23.53



23.74



24.35





















Composite Average Margin per Boe (excluding Total Exploration Costs) -

     [(e) / (a) - (h) / (a)]

16.14



21.30



19.21



20.57



22.96





















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

24.86



25.79



26.86



24.33



25.61





















Composite Average Margin per Boe (including Total Exploration Costs) -

[(e) / (a) - (j) / (a)]

14.94



20.09



15.88



19.98



21.70





















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







































Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -

     (g) / (a)

13.30



14.26



13.42



13.53



14.03





















Composite Average Margin per Boe (excluding DD&A and Total Exploration

     Costs) - [(e) / (a) - (g) / (a)]

26.50



31.62



29.32



30.78



33.28





















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

23.50



24.58



23.53



23.95



24.35





















Composite Average Margin per Boe (excluding Total Exploration Costs) -

     [(e) / (a) - (i) / (a)]

16.30



21.30



19.21



20.36



22.96





















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

24.59



25.79



24.34



24.54



25.24





















Composite Average Margin per Boe (including Total Exploration Costs) -

[(e) / (a) - (k) / (a)]

15.21



20.09



18.40



19.77



22.07





















 

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) (3)









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) (4)









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 (2)









(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)

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).

(3)

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.

(4)

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.

(5)

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.

 

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).

 

View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-second-quarter-2025-results-and-updates-2025-guidance-302524793.html

SOURCE EOG Resources, Inc.

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