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EOG RESOURCES INC - Quarter Report: 2025 June (Form 10-Q)

Interest Expense, Net    Interest Income   

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EOG RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

 $ $ $ NGLs    Natural Gas    Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net()  ()Gathering, Processing and Marketing    Gains on Asset Dispositions, Net    Other, Net    Operating Revenues and Other    Lease and Well  ()Gathering, Processing and Transportation Costs   Marketing Costs   Depreciation, Depletion and Amortization   General and Administrative   Taxes Other Than Income   
Other Segment Items (2)
   Operating Income (Loss)  () Interest Income Other Income Interest Expense, Net()Income Before Income Taxes$ Other Segment Disclosures:Additions to Oil and Gas Properties, Excluding Dry Hole Costs    
(1)Thousand barrels per day or million cubic feet per day, as applicable.
(2)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).
(3)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.

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Crude oil and condensate revenues for the second quarter of 2025 decreased $718 million, or 19%, to $2,974 million from $3,692 million for the same period of 2024. The decrease was due to a lower composite average price ($826 million), partially offset by an increase of 13.5 MBbld, or 3%, in crude oil and condensate production ($108 million). Increased production was primarily from the Permian Basin and Utica. EOG's composite crude oil and condensate price for the second quarter of 2025 decreased 22% to $64.82 per barrel compared to $82.69 per barrel for the same period of 2024.

NGL revenues for the second quarter of 2025 increased $19 million, or 4%, to $534 million from $515 million for the same period of 2024 due to an increase of 13.6 MBbld, or 6%, in NGL deliveries ($30 million), partially offset by a lower composite average price ($11 million). Increased production was primarily from the Permian Basin and Utica. EOG's composite NGL price for the second quarter of 2025 decreased 2% to $22.70 per barrel compared to $23.11 per barrel for the same period of 2024.

Natural gas revenues for the second quarter of 2025 increased $297 million, or 98%, to $600 million from $303 million for the same period of 2024. The increase was due to a higher composite average price ($238 million) and an increase in natural gas deliveries ($59 million). Natural gas deliveries for the second quarter of 2025 increased 357 MMcfd, or 19%, compared to the same period of 2024 due primarily to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Dorado and Trinidad. EOG's composite natural gas price for the second quarter of 2025 increased 66% to $2.96 per Mcf compared to $1.78 per Mcf for the same period of 2024.

During the second quarter of 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $107 million compared to net losses of $47 million for the same period of 2024. The net gains of $107 million included losses of $59 million related to the Brent crude oil (Brent) linked gas sales contract. During the second quarter of 2025, net cash paid for settlements of financial commodity derivative contracts was $24 million compared to net cash received from settlements of financial commodity derivative contracts of $79 million for the same period of 2024.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Operating and Other Expenses.  For the second quarter of 2025, operating expenses of $3,731 million were $164 million lower than the $3,895 million incurred during the second quarter of 2024.  The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2025 and 2024:

Three Months Ended
June 30,
 20252024
Lease and Well$3.84 $4.09 
Gathering, Processing and Transportation Costs (GP&T)4.41 4.44 
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties9.58 9.80 
Other Property, Plant and Equipment0.62 0.52 
General and Administrative (G&A)1.80 1.58 
Interest Expense, Net0.49 0.38 
Total (1)
$20.74 $20.81 
(1)Total excludes exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, GP&T, DD&A, G&A and interest expense, net for the three months ended June 30, 2025, compared to the same period of 2024, are set forth below. See "Operating Revenues and Other" above for a discussion of volumes.
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Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, produced water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $396 million for the second quarter of 2025 increased $6 million from $390 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($8 million) and increased lease and well administrative expenses ($3 million), partially offset by decreased workover expenditures in the United States ($5 million).

GP&T costs represent costs to process and deliver hydrocarbon products from the lease to a downstream point of sale. GP&T costs include operating and maintenance expenses from EOG-owned assets, fees paid to third-party operators and administrative expenses associated with operating EOG's GP&T assets. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

GP&T costs of $455 million for the second quarter of 2025 increased $32 million from $423 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Permian Basin and Utica, partially offset by a decrease in GP&T costs in the Eagle Ford.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the second quarter of 2025 increased $69 million to $1,053 million from $984 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2025 were $55 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($68 million) and in Trinidad ($8 million), partially offset by decreased unit rates in the United States ($17 million) and in Trinidad ($4 million). DD&A expenses associated with other property, plant and equipment for the second quarter of 2025 were $14 million higher than the same prior year period primarily due to an increase in expenses related to GP&T assets and equipment.

G&A expenses of $186 million for the second quarter of 2025 increased $35 million from $151 million for the same prior year period primarily due to increased professional services and other costs, including Encino acquisition-related costs ($19 million), and employee-related costs ($15 million).

Interest expense, net of $51 million for the second quarter of 2025 increased $15 million compared to the same prior year period primarily due to the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($14 million) and financing commitment costs related to the acquisition of Encino ($6.5 million), partially offset by the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($4 million).

Exploration costs of $74 million for the second quarter of 2025 increased $40 million from $34 million for the same prior year period primarily due to geological and geophysical expenditures in the United Arab Emirates ($22 million), the United States ($8 million) and Trinidad ($6 million).


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Impairments include: amortization of individually insignificant unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; individually significant unproved oil and gas property costs; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment.

The following table sets forth impairments for the second quarter of 2025 and 2024 (in millions):

Three Months Ended
June 30,
 20252024
Proved properties$12 $33 
Unproved properties12 17 
Other Assets14 30 
Firm commitment contracts1 1 
Total$39 $81 

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the second quarter of 2025 decreased $36 million to $301 million (7.3% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $337 million (7.5% of revenues from sales of crude oil and condensate, NGLs and natural gas) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes in the United States.

Other income, net of $55 million for the second quarter of 2025 decreased $11 million from $66 million for the same prior year period. The decrease was primarily due to decreased interest income.

Income taxes of $406 million for the second quarter of 2025 decreased from $470 million for the second quarter of 2024 primarily due to decreased pretax income.  The net effective tax rate for the second quarter of 2025 increased to 23% from 22% for the second quarter of 2024.

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Six Months Ended June 30, 2025 vs. Six Months Ended June 30, 2024

Operating Revenues and Other. During the first six months of 2025, operating revenues decreased $1,001 million, or 8%, to $11,147 million from $12,148 million for the same period of 2024. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas for the first six months of 2025 decreased $275 million, or 3%, to $8,610 million from $8,885 million for the same period of 2024. During the first six months of 2025, EOG recognized net losses on the mark-to-market of financial commodity and other derivative contracts of $84 million compared to net gains of $190 million for the same period of 2024. Gathering, processing and marketing revenues for the first six months of 2025 decreased $391 million, or 13%, to $2,587 million from $2,978 million for the same period of 2024.

Volume and price statistics for the six-month periods ended June 30, 2025 and 2024 were as follows:

Six Months Ended
June 30,
 20252024
Crude Oil and Condensate Volumes (MBbld)
United States502.0 488.4 
Trinidad1.1 0.6 
Total503.1 489.0 
Average Crude Oil and Condensate Prices ($/Bbl) (1)
  
United States$68.84 $80.59 
Trinidad57.84 69.11 
Composite68.81 80.58 
Natural Gas Liquids Volumes (MBbld)
United States250.1 238.3 
Total250.1 238.3 
Average Natural Gas Liquids Prices ($/Bbl) (1)
  
United States$24.42 $23.70 
Natural Gas Volumes (MMcfd)
United States1,906 1,663 
Trinidad249 202 
Total2,155 1,865 
Average Natural Gas Prices ($/Mcf) (1)
  
United States$3.10 $1.84 
Trinidad3.71 3.51 
Composite3.17 2.02 
Crude Oil Equivalent Volumes (MBoed)
United States1,069.7 1,003.9 
Trinidad42.7 34.3 
Total1,112.4 1,038.2 
Total MMBoe201.3 188.9 
(1)    Excludes the impact of financial commodity and other derivative instruments (see Note 10 to the Condensed Consolidated Financial Statements).

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Crude oil and condensate revenues for the first six months of 2025 decreased $905 million, or 13%, to $6,267 million from $7,172 million for the same period of 2024 due to a lower composite average price ($1,074 million), partially offset by an increase of 14.1 MBbld, or 3%, in crude oil and condensate production ($169 million). Increased production was primarily in the Permian Basin, Utica and Rocky Mountain area. EOG's composite crude oil and condensate price for the first six months of 2025 decreased 15% to $68.81 per barrel compared to $80.58 per barrel for the same period of 2024.

NGL revenues for the first six months of 2025 increased $78 million, or 8%, to $1,106 million from $1,028 million for the same period of 2024 due to an increase of 11.8 MBbld, or 5%, in NGL deliveries ($45 million) and a higher composite average price ($33 million). Increased production was primarily from the Permian Basin and Utica. EOG's composite NGL price for the first six months of 2025 increased 3% to $24.42 per barrel compared to $23.70 per barrel for the same period of 2024.

Natural gas revenues for the first six months of 2025 increased $552 million, or 81%, to $1,237 million from $685 million for the same period of 2024. The increase was due to a higher composite average price ($449 million) and an increase in natural gas deliveries ($103 million). Natural gas deliveries for the first six months of 2025 increased 290 MMcfd, or 16%, compared to the same period of 2024 due primarily to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Dorado and Trinidad. EOG's composite natural gas price for the first six months of 2025 increased 57% to $3.17 per Mcf compared to $2.02 per Mcf for the same period of 2024.

During the first six months of 2025, EOG recognized net losses on the mark-to-market of financial commodity and other derivative contracts of $84 million compared to net gains of $190 million for the same period of 2024. The net losses of $84 million included losses of $53 million related to the Brent linked gas sales contract. During the first six months of 2025, net cash payments for settlements of financial commodity derivative contracts was $62 million. Net cash received from settlements of financial commodity derivative contracts was $134 million for the same period of 2024.

Gathering, processing and marketing revenues less marketing costs for the first six months of 2025 decreased $38 million as compared to the same period of 2024 primarily due to lower margins on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.

Operating and Other Expenses. For the first six months of 2025, operating expenses of $7,541 million were $206 million lower than the $7,747 million incurred during the same period of 2024. The following table presents the costs per Boe for the six-month periods ended June 30, 2025 and 2024:

Six Months Ended
June 30,
 20252024
Lease and Well$3.96 $4.16 
GP&T4.45 4.42 
DD&A -
Oil and Gas Properties9.65 10.37 
Other Property, Plant and Equipment0.61 0.52 
G&A1.77 1.66 
Interest Expense, Net0.49 0.37 
Total (1)
$20.93 $21.50 
(1)Total excludes exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, GP&T, DD&A, G&A, and interest expense, net for the six months ended June 30, 2025, compared to the same period of 2024 are set forth below. See "Operating Revenues" above for a discussion of volumes.

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Lease and well expenses of $797 million for the first six months of 2025 increased $11 million from $786 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($21 million) and Trinidad ($5 million) and increased lease and well administrative expenses ($9 million), partially offset by decreased workover expenditures in the United States ($24 million).

GP&T costs of $895 million for the first six months of 2025 increased $59 million from $836 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Permian Basin and Utica, partially offset by a decrease in GP&T costs in the Eagle Ford.

DD&A expenses for the first six months of 2025 increased $8 million to $2,066 million from $2,058 million for the same prior year period. DD&A expenses associated with other property, plant and equipment for the first six months of 2025 were $25 million higher than the same prior year period primarily due to an increase in expenses related to GP&T assets and equipment. DD&A expenses associated with oil and gas properties for the first six months of 2025 were $17 million lower than the same prior year period. The decrease primarily reflects an adjustment to DD&A recorded in 2024 ($117 million) related to natural gas production used by EOG's domestic gathering systems, as well as decreased unit rates in the United States ($31 million). This was partially offset by increased production in the United States ($112 million) and in Trinidad ($15 million), as well as increased unit rates in Trinidad ($7 million).

G&A expenses of $357 million for the first six months of 2025 increased $44 million from $313 million for the same prior year period primarily due to increased professional services and other costs, including Encino acquisition-related costs ($23 million), employee-related costs ($16 million) and information systems costs ($4 million).

Interest expense, net of $98 million for the first six months of 2025 increased $29 million compared to the same prior year period primarily due to the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($29 million) and financing commitment costs related to the acquisition of Encino ($6.5 million), partially offset by the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($4 million).

Exploration costs of $115 million for the first six months of 2025 increased $36 million from $79 million for the same prior year period due primarily to geological and geophysical expenditures in the United Arab Emirates ($22 million), the United States ($6 million) and Trinidad ($6 million).

The following table sets forth impairments for the six-month periods ended June 30, 2025 and 2024 (in millions):

Six Months Ended
June 30,
 20252024
Proved properties$44 $35 
Unproved properties24 34 
Other assets14 30 
Firm commitment contracts1 1 
Total$83 $100 

Taxes other than income for the first six months of 2025 decreased $33 million to $642 million (7.5% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $675 million (7.6% of revenues from sales of crude oil and condensate, NGLs and natural gas) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($30 million) and decreased ad valorem/property taxes ($5 million), all in the United States.

Other income, net of $120 million for the first six months of 2025 decreased $8 million from $128 million for the same prior year period. The decrease was primarily due to decreased interest income.

Income taxes of $820 million for the first six months of 2025 decreased from income taxes of $981 million for the first six months of 2024 primarily due to decreased pretax income. The net effective tax rate for the first six months of 2025 increased to 23% from 22% for the first six months of 2024.
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Capital Resources and Liquidity

Liquidity Overview. At June 30, 2025, EOG maintained a strong financial and liquidity position, including $5.2 billion of cash and cash equivalents on hand and $1.9 billion of availability under its senior unsecured revolving credit facility (which remained undrawn).

The primary source of cash for EOG during the six months ended June 30, 2025, was funds generated from operations. The primary uses of cash were exploration and development expenditures; funds used in operations; dividend payments to stockholders; purchases of treasury stock; repayments of long-term debt and other property, plant and equipment expenditures. During the first six months of 2025, EOG's cash balance decreased $1,876 million to $5,216 million from $7,092 million at December 31, 2024.

See Notes 8 and 9 to the Condensed Consolidated Financial Statements for further discussion of our debt obligations, including the fair value of our senior notes.

Cash Flow. Net cash provided by operating activities of $4,321 million for the first six months of 2025 decreased $1,471 million compared to the same period of 2024 primarily due to an increase in net cash paid for income taxes ($853 million), a decrease in revenues from sales of crude oil and condensate, NGLs and natural gas ($275 million), net cash paid for settlements of financial commodity derivative contracts of $62 million compared to net cash received of $134 million for the first six months of 2024, an increase in cash operating expenses ($104 million) and a decrease in gathering, processing and marketing revenue less marketing costs ($38 million).

Net cash used in investing activities of $3,211 million for the first six months of 2025 increased $81 million compared to the same period of 2024 primarily due to a decrease in cash provided by working capital associated with investing activities ($307 million) and an increase in additions to oil and gas properties ($238 million), partially offset by a decrease in additions to other property, plant and equipment ($467 million).

Net cash used in financing activities of $2,987 million for the first six months of 2025 included purchases of treasury stock ($1,408 million), dividend payments to stockholders ($1,066 million) and repayments of long-term debt ($500 million). Net cash used in financing activities of $2,509 million for the first six months of 2024 included purchases of treasury stock ($1,458 million) and dividend payments to stockholders ($1,045 million).

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Total Expenditures. For the full-year 2025, EOG's updated budget for exploration and development and other property, plant and equipment expenditures is estimated to range from approximately $6.2 billion to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses. The table below sets out components of total expenditures for the six-month periods ended June 30, 2025 and 2024 (in millions):

Six Months Ended
June 30,
20252024
Expenditure Category
Capital
Exploration and Development Drilling$2,366 $2,431 
Facilities305 304 
Leasehold Acquisitions (1)
83 144 
Property Acquisitions (2)
269 26 
Capitalized Interest23 20 
Subtotal3,046 2,925 
Exploration Costs115 79 
Dry Hole Costs45 6 
Exploration and Development Expenditures3,206 3,010 
Asset Retirement Costs (3)
27 (39)
Total Exploration and Development Expenditures3,233 2,971 
Other Property, Plant and Equipment (4)
196 663 
Total Expenditures$3,429 $3,634 
(1)    Leasehold acquisitions included $11 million and $65 million for the six-month periods ended June 30, 2025 and 2024, respectively, related to non-cash property exchanges.
(2)    Property acquisitions included $24 million for the six-month period ended June 30, 2024, related to non-cash property exchanges.
(3)    Asset Retirement Costs for the six-month period ended June 30, 2024 included a downward revision to asset retirement obligations of $84 million.
(4)    Other Property, Plant and Equipment included $132 million related to the acquisition of a gathering system in South Texas for the six-month period ended June 30, 2024.

Exploration and development expenditures of $3,206 million for the first six months of 2025 were $196 million higher than the same period of 2024 primarily due to increased property acquisitions ($243 million), increased dry hole costs ($39 million) and exploration costs in the United Arab Emirates ($23 million), partially offset by decreased exploration and development drilling expenditures in Trinidad ($67 million) and decreased leasehold acquisitions ($61 million). Exploration and development expenditures for the first six months of 2025 of $3,206 million consisted of $2,680 million in development drilling and facilities, $269 million in property acquisitions, $234 million in exploration and $23 million in capitalized interest. Exploration and development expenditures for the first six months of 2024 of $3,010 million consisted of $2,629 million in development drilling and facilities, $335 million in exploration, $26 million in property acquisitions and $20 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors. EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG. Further, EOG believes that its sources of liquidity are adequate for other near-term and long-term funding requirements, including its cash return commitment, debt service obligations, repayments of debt maturities and other commitment and contingencies.


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Financial Commodity and Other Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2024 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity and other derivative contracts as accounting hedges and, accordingly, accounts for financial commodity and other derivative contracts using the mark-to-market accounting method, including the Brent linked gas sales contract. Under this accounting method, changes in the fair value of outstanding financial and other derivative instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts on the Condensed Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities on the Condensed Consolidated Statements of Cash Flows.

The total fair value of EOG's financial commodity and other derivative contracts was reflected on the Condensed Consolidated Balance Sheets at June 30, 2025, as a net liability of $29 million.

As discussed in "Operating Revenues and Other," the net cash paid for settlements of financial commodity derivative contracts during the second quarter and first six months of 2025 was $24 million and $62 million, respectively.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2025 to July 31, 2025 (closed) and outstanding as of July 31, 2025. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

Natural Gas Financial Price Swap Contracts
Contracts Sold
PeriodSettlement IndexVolume
(MMBtud in thousands)		Weighted Average Price ($/MMBtu)
February - August 2025 (closed)
NYMEX Henry Hub725 $3.07 
September - December 2025
NYMEX Henry Hub725 3.07 


Natural Gas Basis Swap Contracts
Contracts Sold
PeriodSettlement IndexVolume
(MMBtud in thousands)		Weighted Average Price Differential
 ($/MMBtu)
January - July 2025 (closed)
NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)
10 $0.00 
August - December 2025
NYMEX Henry Hub HSC Differential10 0.00 
(1)    This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at July 31, 2025. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX Henry Hub prices.

Natural Gas Sales Linked to Brent Crude Oil. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2024 Annual Report, in February 2024, EOG entered into a 10-year agreement, commencing in 2027, to sell 180,000 MMBtud of its domestic natural gas production, with 140,000 MMBtud to be sold at a price indexed to Brent and the remaining volumes to be sold at a price indexed to Brent or a U.S. Gulf Coast gas index.
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Encino Financial Commodity Derivative Contracts. In connection with the acquisition of Encino, EOG assumed (via novation) certain natural gas and NGLs financial derivative contracts from Encino. Presented below is a summary of such contracts outstanding as of August 1, 2025. Natural gas volumes are presented in MMBtud and prices are presented in $/MMBtu. NGLs volumes are presented in thousands of barrels per day (MBbld) and prices are presented in dollars per barrel ($/Bbl).

Ethane Financial Price Swap Contracts
Contracts Sold
PeriodSettlement IndexVolume
(MBbld)		Weighted Average Price ($/Bbl)
August - December 2025Mont Belvieu Ethane (non-Tet)11 $10.46 
January - December 2026Mont Belvieu Ethane (non-Tet)11 10.94 


Butane Financial Price Swap Contracts
Contracts Sold
PeriodSettlement IndexVolume
(MBbld)		Weighted Average Price ($/Bbl)
August - December 2025Mont Belvieu Butane (non-Tet)7 $36.28 


Propane Financial Price Swap Contracts
Contracts Sold
PeriodSettlement IndexVolume
(MBbld)		Weighted Average Price ($/Bbl)
August - December 2025Mont Belvieu Propane (Tet)13 $30.82 
January - December 2026Mont Belvieu Propane (Tet)1 30.24 


Natural Gas Financial Price Swap Contracts
Contracts Sold
PeriodSettlement IndexVolume
(MMBtud in thousands)		Weighted Average Price ($/MMBtu)
September - December 2025NYMEX Henry Hub500 $3.67 
January - June 2026NYMEX Henry Hub460 3.78 
July - December 2026NYMEX Henry Hub450 3.79 

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Natural Gas Collar Contracts
Contracts Sold
Weighted Average Price ($/MMBtu)
PeriodSettlement IndexVolume
(MMBtud in thousands)		Ceiling PriceFloor Price
September 2025NYMEX Henry Hub50 $4.65 $3.81 
October - December 2025NYMEX Henry Hub60 4.63 3.76 
January - June 2026NYMEX Henry Hub80 4.28 3.72 
July - December 2026NYMEX Henry Hub70 4.23 3.71 
January - December 2027NYMEX Henry Hub120 4.36 3.44 

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes 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
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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 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.

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PART I.  FINANCIAL INFORMATION


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
EOG RESOURCES, INC.

EOG's exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk is discussed in (i) the "Financial Commodity and Other Derivative Transactions," "Financing" and "Outlook" sections of "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" included in EOG's Annual Report on Form 10-K for the year ended December 31, 2024, filed on February 27, 2025 (EOG's 2024 Annual Report); and (ii) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements included in EOG's 2024 Annual Report. For updated information regarding EOG's financial commodity and other derivative contracts and physical commodity contracts, see (i) Note 10, "Risk Management Activities" to EOG's Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q; (ii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating Revenues and Other" in this Quarterly Report on Form 10-Q; and (iii) "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financial Commodity and Other Derivative Transactions" in this Quarterly Report on Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES
EOG RESOURCES, INC.

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this Quarterly Report on Form 10-Q (Evaluation Date). Based on this evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of the Evaluation Date in ensuring that information that is required to be disclosed in the reports EOG files or furnishes under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms and (ii) accumulated and communicated to EOG's management, as appropriate, to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting. There were no changes in EOG's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act) that occurred during the quarterly period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

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PART II. OTHER INFORMATION

EOG RESOURCES, INC.

ITEM 1.    LEGAL PROCEEDINGS

See Part I, Item 1, Note 7 to Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Item 103 of Regulation S-K promulgated under the Securities Exchange Act of 1934 (as amended, Exchange Act) requires disclosure regarding certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that EOG reasonably believes will exceed a specified threshold. Pursuant to such item, EOG will be using a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required. EOG believes proceedings under this threshold are not material to EOG's business and financial condition (the choice of this threshold does not imply that matters with potential monetary sanctions in excess of $1 million are necessarily material to EOG's business or financial condition). Applying this threshold, there are no environmental proceedings to disclose for the quarter ended June 30, 2025.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth, for the periods indicated, EOG's share repurchase activity:
Period
Total
Number of
Shares Purchased (1)
Average
Price Paid Per Share
Total Value of
Shares Purchased as
Part of Publicly
Announced Plans or Programs (2)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (3)
April 1, 2025 - April 30, 20255,432,214 $110.57 $599,999,989 $4,461,500,362 
May 1, 2025 - May 31, 20253,003 110.77 — 4,461,500,362 
June 1, 2025 - June 30, 20259,942 121.58 — 4,461,500,362 
Total5,445,159 110.59 $599,999,989  
(1)Includes 5,427,166 shares repurchased during the quarter ended June 30, 2025, at an average price of $110.55 per share (inclusive of commissions and transaction fees), pursuant to the Share Repurchase Authorization (as defined and further discussed below); such repurchases count against the Share Repurchase Authorization. The share repurchases effected during the period April 1, 2025 through April 30, 2025 were made pursuant to a Rule 10b5-1 trading plan entered into by EOG on March 27, 2025. Also includes 17,993 total shares that were withheld by or returned to EOG during the quarter ended June 30, 2025, at an average price of $120.43 per share, (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options; such shares do not count against the Share Repurchase Authorization.
(2)In November 2021, EOG's Board of Directors (Board) established a new share repurchase authorization allowing for the repurchase by EOG of up to $5 billion of its common stock and, in November 2024, increased such share repurchase authorization from $5 billion to $10 billion, effective November 7, 2024 (Share Repurchase Authorization). As of June 30, 2025, (i) EOG had repurchased an aggregate 46,117,268 shares at a total cost of $5,538,499,638 (inclusive of commissions and transaction fees) under the Share Repurchase Authorization and (ii) an additional $4,461,500,362 of shares remained available for repurchases under the Share Repurchase Authorization.
(3)Under the Share Repurchase Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases is at the discretion of EOG's management and depends on a variety of factors, including the trading price of EOG's common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and EOG's anticipated future capital expenditures and other commitments requiring cash. Repurchased shares are held as treasury shares and are available for general corporate purposes. The Share Repurchase Authorization has no time limit, does not require EOG to repurchase a specific number of shares and may be modified, suspended or terminated by the Board at any time.

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ITEM 5. OTHER INFORMATION

, , EOG's , his written Rule 10b5-1 trading arrangement, dated August 30, 2024, in respect of EOG's common stock. The description of such trading arrangement set forth in Item II, Part 5 of EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2024 is incorporated herein by reference.

On , Mr. Leitzell a new written Rule 10b5-1 trading arrangement in respect of EOG's common stock that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) promulgated under the Securities Exchange Act of 1934 (as amended). The arrangement, which was adopted in accordance with EOG's Insider Trading Policy and at a time when Mr. Leitzell was not in possession of material, non-public information regarding EOG, provides for the sale by Mr. Leitzell of:

(1)up to shares currently held by Mr. Leitzell;
(2)55% of the net shares to be received by Mr. Leitzell upon the vesting of 5,665 shares of restricted stock previously granted to him;
(3)65% of the net shares to be received by Mr. Leitzell upon the vesting of 4,841 shares of restricted stock previously granted to him; and
(4)28% of the net shares to be received by Mr. Leitzell upon the vesting of 8,497 restricted stock units with performance-based conditions (performance units) previously granted to him;

in each case, during the specific time periods and subject to the limit price (i.e., trigger price) conditions set forth in the arrangement (and subject to EOG's withholding of shares in satisfaction of the tax withholding obligations arising upon such vestings). Mr. Leitzell's Rule 10b5-1 trading arrangement will commence following the applicable cooling-off period and will terminate upon the earlier of (i) the completion of all sales specified in the trading arrangement and (ii) .

During the quarter ended June 30, 2025, no other Section 16 officer of EOG, and no director of EOG, or any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (in each case, as defined in Item 408(a) of Regulation S-K).


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ITEM 6.  EXHIBITS
Exhibit No.  
Description
    2.1#
-
    3.1(a)-
    3.1(b)-
    3.1(c)-
    3.1(d)-
    3.1(e)-
    3.1(f)-
    3.1(g)-
    3.1(h)-
    3.1(i)-
    3.1(j)-
    3.1(k)-
    3.1(l)-
    3.1(m)-
    3.1(n)-
    3.2-
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Exhibit No.Description
      4.1-
      4.2-
      4.3-
      4.4-
      4.5-
    10.1-
    31.1-
    31.2-
    32.1-
    32.2-
  101.INS-Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
*101.SCH-Inline XBRL Schema Document.
*101.CAL-Inline XBRL Calculation Linkbase Document.
*101.DEF-Inline XBRL Definition Linkbase Document.
*101.LAB-Inline XBRL Label Linkbase Document.
*101.PRE-Inline XBRL Presentation Linkbase Document.
  104-Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Statements of Income and Comprehensive Income - Three Months and Six Months Ended June 30, 2025 and 2024, (ii) the Condensed Consolidated Balance Sheets - June 30, 2025 and December 31, 2024, (iii) the Condensed Consolidated Statements of Stockholders' Equity - Three Months and Six Months Ended June 30, 2025 and 2024, (iv) the Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2025 and 2024 and (v) the Notes to Condensed Consolidated Financial Statements.

# Certain schedules and exhibits (and similar attachments) have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.
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SIGNATURES



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


  EOG RESOURCES, INC.
  (Registrant)
   
   
   
Date: August 7, 2025By:
/s/ ANN D. JANSSEN
Ann D. Janssen
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Duly Authorized Officer)
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