Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States of America (United States) with proved reserves in the United States and the Republic of Trinidad and Tobago (Trinidad). EOG is focused on being among the lowest-cost, highest-return and lowest-emissions producers, playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating costs and capital expenditures and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to maximize long-term shareholder value and maintain a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.

Commodity Prices**.** Prices for crude oil and condensate, natural gas liquids (NGLs) and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the world political and economic environment and the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors.

The market prices of crude oil and condensate, NGLs and natural gas impact the amount of cash generated from EOG's operating activities, which, in turn, impact EOG's financial position and results of operations.

For the first nine months of 2024, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $77.55 per barrel and $2.10 per million British thermal units (MMBtu), respectively, representing an increase of 0.2% and a decrease of 22%, respectively, from the average NYMEX prices for the same period in 2023. Market prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

Based on EOG's tax position, EOG's price sensitivity as of September 30, 2024, for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $153 million for net income and $196 million for pretax cash flows from operating activities, in each case for the full-year 2024.

Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for which prices have not (as of September 30, 2024) been determined under long-term marketing contracts, EOG's price sensitivity as of September 30, 2024, for each $0.10 per thousand cubic feet increase or decrease in wellhead natural gas price, is approximately $27 million for net income and $34 million for pretax cash flows from operating activities, in each case for the full-year 2024.

Inflation Considerations. As further discussed in EOG's Annual Report on Form 10-K for the year ended December 31, 2023, filed on February 22, 2024 (EOG's 2023 Annual Report), EOG has, beginning in the second quarter of 2023, seen the inflationary pressures on its operating costs and capital expenditures (i.e., costs of fuel, steel, labor and drilling and completion services) diminish and, in certain circumstances, EOG has seen a decline in prices.

Despite such declining prices, EOG plans to continue its focus on increasing its drilling, completion and operating efficiencies and improving the performance of its wells. Such focus and the related initiatives EOG has undertaken, together with the flexibility provided by its multi-basin drilling portfolio, allowed EOG to largely offset the inflationary pressures it experienced beginning in the second half of 2021 and through the first three months of 2023.

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However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on EOG's operating costs and capital expenditures. Further, EOG expects the market for drilling and completion services and related labor and materials will continue to fluctuate and, as a result, there can be no assurance regarding the timing and impact of any future price changes on EOG's operating costs and capital expenditures and, in turn, on EOG's cash flows, results of operations, liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.

Climate Change. For discussion of climate change matters and related regulatory matters, including potential developments related to climate change and the potential impacts and risks of such developments on EOG, see ITEM 1A, Risk Factors and the related discussion in ITEM 1, Business - Regulation of EOG's 2023 Annual Report. EOG will continue to monitor and assess any climate change-related developments, including the SEC's climate-related disclosure rules adopted in March 2024, that could impact EOG and the oil and gas industry, to determine the impact on its business and operations, and take appropriate actions where necessary.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and condensate, NGLs and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil plays and natural gas plays.

During the first nine months of 2024, EOG continued to (i) focus on improving well performance and operating efficiencies, (ii) evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and (iii) look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical or bolt-on acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 72% and 73% of EOG's United States production during the first nine months of 2024 and 2023, respectively. During the first nine months of 2024, EOG's drilling and completion activities occurred primarily in the Delaware Basin play and the Eagle Ford play. EOG's major producing areas in the United States are in New Mexico and Texas.

Trinidad. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a), the Banyan Field and the Sercan Area have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited, and crude oil and condensate which is sold to Heritage Petroleum Company Limited.

During the first nine months of 2024, EOG completed one net developmental well and one net exploratory well from the recently installed Osprey B platform in the Modified U(a) Block. EOG also completed one net exploratory well and is currently completing another exploratory well from the Oilbird platform in the SECC Block. In June 2024, EOG relinquished its rights to a portion of the contract area governed by the Trinidad Northern Area License located offshore the southwest coast of Trinidad. In July 2024, EOG signed a farmout agreement with BP Trinidad and Tobago LLC, which allows EOG to earn a 50% working interest to develop the Coconut gas field in the East Mayaro and South East Galeota Areas. Additionally, EOG is currently in discussions with the Government of Trinidad and Tobago regarding the potential award of the Lower Reverse L and NCMA 4(a) Blocks in respect of the 2023 shallow water bid round. In the fourth quarter of 2024, EOG expects to recomplete two wells in the Sercan Area and also drill an exploratory well in the deep Teak, Samaan and Poui Area. Additionally, EOG expects to complete construction and installation of the platform and commence pipeline installation in the Mento Area.

Other International. In November 2021, a subsidiary of EOG was granted an exploration permit for the WA-488-P Block, located offshore Western Australia. During the first nine months of 2024, EOG continued to prepare for the drilling of an exploration well in this block.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploration opportunities in countries where crude oil and natural gas reserves have been identified.

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2024 Capital and Operating Plan**.** Total 2024 capital expenditures are estimated to range from approximately $6.1 billion to $6.3 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. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States drilling activity in its plays where it generates the highest rates of return - specifically, in the Delaware Basin, Eagle Ford, Utica and Rocky Mountain area. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to focus on improving operating efficiencies; see the above related discussion. Full-year 2024 total crude oil, NGLs and natural gas production is expected to increase modestly versus 2023. In addition, EOG plans to continue to spend a portion of its anticipated 2024 capital expenditures on leasing acreage, evaluating new prospects, transportation infrastructure and environmental projects.

Management continues to believe EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.

Capital Structure**.** One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 11% at September 30, 2024 and 12% at December 31, 2023. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At September 30, 2024, EOG maintained a strong financial and liquidity position, including $6.1 billion of cash and cash equivalents on hand and $1.9 billion of availability under its senior unsecured revolving credit facility. At September 30, 2024, the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 was classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt.

The Internal Revenue Service previously announced tax relief related to 2024 severe weather events occurring in various Texas counties, including Harris County where EOG's corporate offices are located. The tax relief permits eligible taxpayers to postpone certain tax filings and payments.

EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings. For related discussion, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity included in EOG's 2023 Annual Report.

Cash Return Framework. In November 2023, EOG announced an increase in its cash return commitment - specifically, a commitment, effective beginning with fiscal year 2024, to return a minimum of 70% of annual net cash provided by operating activities before certain balance sheet-related changes, less total capital expenditures, to stockholders, through a combination of quarterly dividends, special dividends and share repurchases.

For discussion regarding EOG's payment of dividends and share repurchases, see ITEM 1A, Risk Factors and ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities in EOG's 2023 Annual Report and Part II, Item 2, Unregistered Sales of Equity Securities and Use of Proceeds in this Quarterly Report on Form 10-Q.

Dividend Declarations. On February 22, 2024, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.91 per share paid on April 30, 2024, to stockholders of record as of April 16, 2024.

On May 2, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share paid on July 31, 2024, to stockholders of record as of July 17, 2024.

On August 1, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share paid on October 31, 2024, to stockholders of record as of October 17, 2024.

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On November 7, 2024, the Board increased the quarterly cash dividend on the common stock from the previous $0.91 per share to $0.975 per share, effective beginning with the dividend payable on January 31, 2025, to stockholders of record as of January 17, 2025.

Share Repurchases. In November 2021, the Board established a new share repurchase authorization that allows for the repurchase by EOG of up to $5 billion of its common stock (Share Repurchase Authorization). During the three and nine months ended September 30, 2024, EOG repurchased 6.1 million and 18.0 million shares of common stock for approximately $758 million and $2,198 million (inclusive of transaction fees and commissions), respectively, pursuant to the Share Repurchase Authorization. As of September 30, 2024, approximately $1.8 billion remained available for repurchases under the Share Repurchase Authorization. Included in the Treasury Stock Repurchased amounts on the Condensed Consolidated Statements of Stockholders' Equity for the three and nine months ended September 30, 2024, are $7 million and $20 million, respectively, of estimated federal excise taxes. Subsequent to September 30, 2024, the Board increased the Share Repurchase Authorization from $5 billion to $10 billion, effective November 7, 2024.

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, and other market and economic conditions. 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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Results of Operations

The following review of operations for the three months and nine months ended September 30, 2024 and 2023 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10‑Q.

Three Months Ended September 30, 2024 vs. Three Months Ended September 30, 2023

Operating Revenues. During the third quarter of 2024, operating revenues decreased $247 million, or 4%, to $5,965 million from $6,212 million for the same period of 2023. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the third quarter of 2024 decreased $251 million, or 5%, to $4,384 million from $4,635 million for the same period of 2023. EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $79 million for the third quarter of 2024 compared to net gains of $43 million for the same period of 2023. Gathering, processing and marketing revenues for the third quarter of 2024 increased $3 million to $1,481 million from $1,478 million for the same period of 2023. Net losses on asset dispositions were $7 million for the third quarter of 2024 compared to net gains of $35 million for the same period of 2023.

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Wellhead volume and price statistics for the three-month periods ended September 30, 2024 and 2023 were as follows:


	Three Months Ended September 30,
	2024		2023
Crude Oil and Condensate Volumes (MBbld) (1)
United States	491.8		482.8
Trinidad	1.2		0.5
Total	493.0		483.3
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States	$	76.95	$	83.61
Trinidad	63.15		71.38
Composite	76.92		83.60
Natural Gas Liquids Volumes (MBbld) (1)
United States	254.3		231.1
Total	254.3		231.1
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States	$	22.42	$	23.56
Natural Gas Volumes (MMcfd) (1)
United States	1,745		1,562
Trinidad	225		142
Total	1,970		1,704
Average Natural Gas Prices ($/Mcf) (2)
United States	$	1.84	$	2.59
Trinidad	3.68		3.41
Composite	2.05		2.66
Crude Oil Equivalent Volumes (MBoed) (3)
United States	1,037.1		974.2
Trinidad	38.6		24.3
Total	1,075.7		998.5

Total MMBoe (3)	99.0		91.9

(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 12 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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Wellhead crude oil and condensate revenues for the third quarter of 2024 decreased $229 million, or 6%, to $3,488 million from $3,717 million for the same period of 2023. The decrease was due to a lower composite average price ($317 million), partially offset by an increase of 9.7 MBbld, or 2%, in wellhead crude oil and condensate production ($88 million). Increased production was primarily from the Utica. EOG's composite wellhead crude oil and condensate price for the third quarter of 2024 decreased 8% to $76.92 per barrel compared to $83.60 per barrel for the same period of 2023.

NGL revenues for the third quarter of 2024 increased $23 million, or 5%, to $524 million from $501 million for the same period of 2023 due to an increase of 23.2 MBbld, or 10%, in NGL deliveries ($51 million), partially offset by a lower composite average price ($28 million). Increased production was primarily from the Permian Basin. EOG's composite NGL price for the third quarter of 2024 decreased 5% to $22.42 per barrel compared to $23.56 per barrel for the same period of 2023.

Wellhead natural gas revenues for the third quarter of 2024 decreased $45 million, or 11%, to $372 million from $417 million for the same period of 2023. The decrease was due to a lower composite average price ($114 million), partially offset by an increase in natural gas deliveries ($69 million). Natural gas deliveries for the third quarter of 2024 increased 266 MMcfd, or 16%, compared to the same period of 2023 due primarily to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the third quarter of 2024 decreased 23% to $2.05 per Mcf compared to $2.66 per Mcf for the same period of 2023.

During the third quarter of 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $79 million compared to net gains of $43 million for the same period of 2023. The net gains of $79 million included gains of $15 million related to the Brent crude oil (Brent) linked gas sales contract. During the third quarter of 2024, net cash received from settlements of financial commodity derivative contracts was $61 million compared to net cash received from settlements of financial commodity derivative contracts of $23 million for the same period of 2023.

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. EOG sells sand primarily in order to balance the timing of firm purchase agreements with completion operations. 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.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2024 decreased $114 million as compared to the same period of 2023 primarily due to lower margins on crude oil marketing activities.

Operating and Other Expenses. For the third quarter of 2024, operating expenses of $3,876 million were $221 million higher than the $3,655 million incurred during the third quarter of 2023. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2024 and 2023:


	Three Months Ended September 30,
	2024		2023
Lease and Well	$	3.96	$	4.02
Gathering, Processing and Transportation Costs (GP&T)	4.50		4.42
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	9.89		9.31
Other Property, Plant and Equipment	0.53		0.47
General and Administrative (G&A)	1.69		1.75
Interest Expense, Net	0.31		0.39
Total (1)	$	20.88	$	20.36

(1)Total excludes exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

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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 September 30, 2024, compared to the same period of 2023, are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

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 $392 million for the third quarter of 2024 increased $23 million from $369 million for the same prior year period primarily due to increased operating and maintenance costs ($18 million) and increased lease and well administrative expenses ($6 million), both in the United States. Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

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 $445 million for the third quarter of 2024 increased $39 million from $406 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Permian Basin and Utica.

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 third quarter of 2024 increased $133 million to $1,031 million from $898 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2024 were $123 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($54 million) and in Trinidad ($8 million), and increased unit rates in the United States ($50 million) and in Trinidad ($11 million). DD&A expenses associated with other property, plant and equipment for the third quarter of 2024 were $10 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 $167 million for the third quarter of 2024 increased $6 million from $161 million for the same prior year period primarily due to increased professional and other services costs.

Interest expense, net of $31 million for the third quarter of 2024 decreased $5 million compared to the same prior year period primarily due to higher capitalized interest.

Impairments include: amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; 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.

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The following table sets forth impairments for the third quarter of 2024 and 2023 (in millions):


	Three Months Ended September 30,
	2024		2023
Proved properties	$	1	$	23
Unproved properties	14		30
Other assets	—		—
Firm commitment contracts	—		1
Total	$	15	$	54

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 third quarter of 2024 decreased $58 million to $283 million (6.5% of wellhead revenues) from $341 million (7.4% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to increased state severance tax refunds ($30 million) and decreased severance/production taxes ($25 million), all in the United States.

Other income, net of $76 million for the third quarter of 2024 increased $24 million from $52 million for the same prior year period. The increase was primarily due to increased interest income.

Income taxes of $461 million for the third quarter of 2024 decreased from income taxes of $543 million for the third quarter of 2023 primarily due to decreased pretax income. The net effective tax rate for the third quarter of 2024 increased to 22% from 21% for the third quarter of 2023.

Nine Months Ended September 30, 2024 vs. Nine Months Ended September 30, 2023

Operating Revenues. During the first nine months of 2024, operating revenues increased $284 million, or 2%, to $18,113 million from $17,829 million for the same period of 2023. Total wellhead revenues for the first nine months of 2024 increased $450 million, or 4%, to $13,269 million from $12,819 million for the same period of 2023. During the first nine months of 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $269 million compared to net gains of $520 million for the same period of 2023. Gathering, processing and marketing revenues for the first nine months of 2024 increased $126 million, or 3%, to $4,459 million from $4,333 million for the same period of 2023. Net gains on asset dispositions were $39 million for the first nine months of 2024 compared to net gains of $95 million for the same period of 2023.

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Wellhead volume and price statistics for the nine-month periods ended September 30, 2024 and 2023 were as follows:


	Nine Months Ended September 30,
	2024		2023
Crude Oil and Condensate Volumes (MBbld)
United States	489.6		472.0
Trinidad	0.8		0.6
Total	490.4		472.6
Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States	$	79.36	$	78.69
Trinidad	66.22		68.37
Composite	79.34		78.67
Natural Gas Liquids Volumes (MBbld)
United States	243.7		219.7
Total	243.7		219.7
Average Natural Gas Liquids Prices ($/Bbl) (1)
United States	$	23.25	$	23.35
Natural Gas Volumes (MMcfd)
United States	1,691		1,517
Trinidad	209		154
Total	1,900		1,671
Average Natural Gas Prices ($/Mcf) (1)
United States	$	1.84	$	2.70
Trinidad	3.57		3.59
Composite	2.03		2.78
Crude Oil Equivalent Volumes (MBoed)
United States	1,015.0		944.6
Trinidad	35.8		26.2
Total	1,050.8		970.8

Total MMBoe	287.9		265.0

(1) Excludes the impact of financial commodity and other derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements).

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Wellhead crude oil and condensate revenues for the first nine months of 2024 increased $509 million, or 5%, to $10,660 million from $10,151 million for the same period of 2023 due to an increase of 17.8 MBbld, or 4%, in wellhead crude oil and condensate production ($420 million) and a higher composite average price ($89 million). Increased production was primarily in the Permian Basin and Utica. EOG's composite wellhead crude oil and condensate price for the first nine months of 2024 increased 1% to $79.34 per barrel compared to $78.67 per barrel for the same period of 2023.

NGL revenues for the first nine months of 2024 increased $152 million, or 11%, to $1,552 million from $1,400 million for the same period of 2023 due to an increase of 24.0 MBbld, or 11%, in NGL deliveries ($159 million), partially offset by a lower composite average price ($7 million). Increased production was primarily from the Permian Basin. EOG's composite NGL price for the first nine months of 2024 decreased to $23.25 per barrel compared to $23.35 per barrel for the same period of 2023.

Wellhead natural gas revenues for the first nine months of 2024 decreased $211 million, or 17%, to $1,057 million from $1,268 million for the same period of 2023. The decrease was due to a lower composite average price ($393 million), partially offset by an increase in natural gas deliveries ($182 million). Natural gas deliveries for the first nine months of 2024 increased 229 MMcfd, or 14%, compared to the same period of 2023 due primarily to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the first nine months of 2024 decreased 27% to $2.03 per Mcf compared to $2.78 per Mcf for the same period of 2023.

During the first nine months of 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $269 million compared to net gains of $520 million for the same period of 2023. The net gains of $269 million included gains of $148 million related to the Brent linked gas sales contract. During the first nine months of 2024, net cash received from settlements of financial commodity derivative contracts was $195 million. Net cash paid for settlements of financial commodity derivative contracts was $130 million for the same period of 2023.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2024 decreased $68 million as compared to the same period of 2023 primarily due to lower margins on crude oil marketing activities, sand sales and natural gas marketing activities.

Operating and Other Expenses. For the first nine months of 2024, operating expenses of $11,623 million were $893 million higher than the $10,730 million incurred during the same period of 2023. The following table presents the costs per Boe for the nine-month periods ended September 30, 2024 and 2023:


	Nine Months Ended September 30,
	2024		2023
Lease and Well	$	4.09	$	4.06
GP&T	4.45		4.52
DD&A -
Oil and Gas Properties	10.20		9.19
Other Property, Plant and Equipment	0.53		0.48
G&A	1.67		1.69
Interest Expense, Net	0.35		0.43
Total (1)	$	21.29	$	20.37

(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 nine months ended September 30, 2024, compared to the same period of 2023 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

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Lease and well expenses of $1,178 million for the first nine months of 2024 increased $102 million from $1,076 million for the same prior year period primarily due to increased operating and maintenance costs ($71 million), increased lease and well administrative expenses ($19 million) and increased workover expenditures ($14 million), all in the United States. Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

GP&T costs of $1,281 million for the first nine months of 2024 increased $84 million from $1,197 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Permian Basin and Utica.

DD&A expenses for the first nine months of 2024 increased $527 million to $3,089 million from $2,562 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2024 were $502 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($185 million) and in Trinidad ($18 million), and increased unit rates in the United States ($147 million) and in Trinidad ($30 million). In addition, the recording of an adjustment to DD&A ($117 million) primarily related to natural gas production used by EOG's domestic gathering systems also contributed to the variance. DD&A expenses associated with other property, plant and equipment for the first nine months of 2024 were $25 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 $480 million for the first nine months of 2024 increased $32 million from $448 million for the same prior year period primarily due to increased employee-related costs ($20 million), professional and other services costs ($9 million) and information systems costs ($8 million).

Interest expense, net of $100 million for the first nine months of 2024 decreased $13 million compared to the same prior year period primarily due to higher capitalized interest ($8 million) and the repayment in March 2023 of the $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023 ($7 million).

Exploration costs of $122 million for the first nine months of 2024 decreased $18 million from $140 million for the same prior year period due primarily to decreased geological and geophysical expenditures ($27 million), partially offset by increased administrative expenses ($6 million) and delay rentals ($3 million).

The following table sets forth impairments for the nine-month periods ended September 30, 2024 and 2023 (in millions):


	Nine Months Ended September 30,
	2024		2023
Proved properties	$	36	$	26
Unproved properties	48		95
Other assets	30		—
Firm commitment contracts	1		2
Total	$	115	$	123

Taxes other than income for the first nine months of 2024 decreased $25 million to $958 million (7.2% of wellhead revenues) from $983 million (7.7% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to increased state severance tax refunds ($30 million) and decreased ad valorem/property taxes ($21 million), partially offset by increased severance/production taxes ($24 million), all in the United States.

Other income, net of $204 million for the first nine months of 2024 increased $36 million from $168 million for the same prior year period. The increase was primarily due to increased interest income.

Income taxes of $1,442 million for the first nine months of 2024 decreased from income taxes of $1,548 million for the first nine months of 2023 primarily due to decreased pretax income. The net effective tax rate for the first nine months of 2024 was unchanged from the prior year rate of 22%.

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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2024, were funds generated from operations and, to a lesser extent, net cash received from settlements of financial commodity derivative contracts. The primary uses of cash were exploration and development expenditures; funds used in operations; dividend payments to stockholders; purchases of treasury stock; and other property, plant and equipment expenditures. During the first nine months of 2024, EOG's cash balance increased $844 million to $6,122 million from $5,278 million at December 31, 2023.

Net cash provided by operating activities of $9,380 million for the first nine months of 2024 increased $1,144 million compared to the same period of 2023 primarily due to an increase in wellhead revenues ($450 million), a decrease in net cash used in working capital and other assets and liabilities ($450 million), an increase in net cash received from settlements of financial commodity derivative contracts ($325 million), and a decrease in net cash paid for income taxes ($289 million), partially offset by the return of cash collateral posted for financial commodity derivative contracts in the first nine months of 2023 ($324 million) and an increase in cash operating expenses ($153 million).

Net cash used in investing activities of $4,691 million for the first nine months of 2024 decreased $150 million compared to the same period of 2023 due to a decrease in cash used in working capital associated with investing activities ($610 million), partially offset by an increase in additions to other property, plant and equipment ($264 million), a decrease in proceeds from the sale of assets ($116 million) and an increase in additions to oil and gas properties ($80 million).

Net cash used in financing activities of $3,845 million for the first nine months of 2024 included purchases of treasury stock ($2,253 million), cash dividend payments ($1,578 million) and repayment of finance lease liabilities ($25 million). Net cash used in financing activities of $4,041 million for the first nine months of 2023 included cash dividend payments ($2,041 million), repayments of long-term debt ($1,250 million), purchases of treasury stock ($728 million) and repayment of finance lease liabilities ($24 million).

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Total Expenditures. For the full-year 2024, EOG's updated budget for exploration and development and other property, plant and equipment expenditures is estimated to range from approximately $6.1 billion to $6.3 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 nine-month periods ended September 30, 2024 and 2023 (in millions):


	Nine Months Ended September 30,
	2024		2023
Expenditure Category
Capital
Exploration and Development Drilling (1)	$	3,512	$	3,619
Facilities	430		373
Leasehold Acquisitions (2)	205		153
Property Acquisitions (3)	26		9
Capitalized Interest	32		24
Subtotal	4,205		4,178
Exploration Costs	122		140
Dry Hole Costs	6		1
Exploration and Development Expenditures	4,333		4,319
Asset Retirement Costs (4)	(28)		227
Total Exploration and Development Expenditures	4,305		4,546
Other Property, Plant and Equipment (5)	902		638
Total Expenditures	$	5,207	$	5,184

(1) Exploration and development drilling included $85 million for the nine-month period ended September 30, 2023, related to non-cash development drilling.

(2) Leasehold acquisitions included $82 million and $60 million for the nine-month periods ended September 30, 2024 and 2023, respectively, related to non-cash property exchanges.

(3) Property acquisitions included $24 million and $9 million for the nine-month periods ended September 30, 2024 and 2023, respectively, related to non-cash property exchanges.

(4) Asset Retirement Costs for the nine-month period ended September 30, 2024 included a downward revision to asset retirement obligations of $84 million.

(5) Other Property, Plant and Equipment included $137 million related to the acquisition of a gathering system in South Texas and $134 million related to the acquisition of a gathering and processing system in the Powder River Basin for the nine-month periods ended September 30, 2024 and 2023, respectively.

Exploration and development expenditures of $4,333 million for the first nine months of 2024 were $14 million higher than the same period of 2023 primarily due to increased facilities expenditures ($57 million) and increased leasehold acquisitions ($52 million), partially offset by decreased development drilling expenditures ($92 million). Exploration and development expenditures for the first nine months of 2024 of $4,333 million consisted of $3,797 million in development drilling and facilities, $478 million in exploration, $32 million in capitalized interest and $26 million in property acquisitions. Exploration and development expenditures for the first nine months of 2023 of $4,319 million consisted of $3,836 million in development drilling and facilities, $450 million in exploration, $24 million in capitalized interest and $9 million in property acquisitions.

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.

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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 2023 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 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 September 30, 2024, as a net asset of $77 million.

As discussed in "Operating Revenues," the net cash received from settlements of financial commodity derivative contracts during the third quarter and first nine months of 2024 was $61 million and $195 million, respectively.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2024 to October 31, 2024 (closed) and outstanding as of October 31, 2024. 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
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price ($/MMBtu)

January - November 2024 (closed)	NYMEX Henry Hub	725	$	3.07
December 2024	NYMEX Henry Hub	725	3.07
January - December 2025	NYMEX Henry Hub	725	3.07


Natural Gas Basis Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price Differential ($/MMBtu)

January - October 2024 (closed)	NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)	10	$	0.00
November - December 2024	NYMEX Henry Hub HSC Differential	10	0.00
January - December 2025	NYMEX Henry Hub HSC Differential	10	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 November 6, 2024. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX Henry Hub prices.

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Natural Gas Sales Linked to Brent Crude Oil. 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. It was determined that this agreement meets the definition of a derivative under the Derivatives and Hedging Topic of the Accounting Standards Codification and does not qualify for the normal purchases and normal sales scope exception. As such, this agreement is accounted for as a derivative using the mark-to-market accounting method. Changes in the fair value are recognized as gains or losses in the period of change on the Condensed Consolidated Statements of Income and Comprehensive Income.

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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 and statements regarding the plans and objectives of EOG's management for future operations, 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 EOG's future financial or operating results and returns or 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, safety matters or other ESG (environmental/social/governance) matters, pay and/or increase regular and/or special dividends or repurchase shares 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, extent 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 recovery 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 inflationary 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 prevention 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;
the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;

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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 and 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 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 policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG's day-to-day operations;
the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets, ambitions and initiatives;
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, 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, including its impact on crude oil and natural gas demand, and weather-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 duration and 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;
acts of war and terrorism and responses to these acts; 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, 2023, 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.

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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

Previous: Item 1. FINANCIAL STATEMENTS · Next: Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK