EOG RESOURCES INC (EOG)

CIK: 0000821189. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-24.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=821189. Latest filing source: 0000821189-26-000054.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-24. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000821189.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

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Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-24. Report date: 2025-12-31.

ITEM 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

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 highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses on a comprehensive approach to developing acreage through industry cycles. EOG evaluates rate of return, net present value, margins, payback period and other key metrics. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-efficient basis, allowing EOG to maximize long-term growth in 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.

EOG realized net income of $4,980 million for 2025 as compared to net income of $6,403 million for 2024. At December 31, 2025, EOG's total estimated net proved reserves were 5,514 million barrels of oil equivalent (MMBoe), an increase of 766 MMBoe from December 31, 2024.  During 2025, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 187 million barrels (MMBbl), and net proved natural gas reserves increased by 3,470 billion cubic feet, or 579 MMBoe, in each case from December 31, 2024.

Recent Developments

Commodity Prices. Prices for crude oil and condensate, 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, the global supply of, and demand for, crude oil, NGLs and natural gas, the availability of other energy supplies and other factors, including tariffs, trade policies and agreements and trade barriers or other restrictions imposed by the U.S. government or other governments and the related impact of such measures on commodity and financial markets.

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 year ended December 31, 2025, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $64.78 per barrel and $3.43 per million British thermal units (MMBtu), respectively, representing a decrease of 14% and an increase of 51%, respectively, from the average NYMEX prices for the year ended December 31, 2024. 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.

Operating Efficiencies. EOG has undertaken (and continues to undertake) initiatives to increase its drilling, completions and operating efficiencies and improve the performance of its wells. Such initiatives include (among others): (i) EOG's downhole drilling motor program, which has resulted in increased footage drilled per day and, in turn, reduced drilling times; (ii) enhanced techniques for completing its wells, which has resulted in increased footage completed per day and pumping hours per day; (iii) drilling extended laterals, which have resulted in a decrease in cost per foot drilled; and (iv) EOG's self-sourced sand program, which has provided supply certainty and resulted in operational efficiencies in its well completion operations. In addition, EOG has entered into agreements with its service providers from time to time, when available and advantageous, to secure the costs and availability of certain drilling and completions services it utilizes as part of its operations.

EOG plans to continue with these initiatives and actions, though there can be no assurance that such efforts will be successful and sufficient to offset the impacts of any future inflationary pressures (such as from tariffs, other trade barriers or other macroeconomic factors) on EOG's operating costs and capital expenditures, cash flows and results of operations. Further, there can be no assurance that any such pressures or factors will not impact EOG's ability to conduct its future day-to-day drilling, completion and production operations. See ITEM 1A. Risk Factors, for related discussion.

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Operations

Several important developments have occurred since January 1, 2025.

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 and natural gas plays.

In 2025, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to 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 68% and 72% of EOG's United States production during 2025 and 2024, respectively. During 2025, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Utica play. EOG's major producing areas in the United States are in New Mexico, Texas and Ohio. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2025 United States operations.

On July 4, 2025, the One Big Beautiful Bill Act was signed into law, which primarily made permanent (generally with amendments) certain tax provisions of the 2017 Tax Cuts and Jobs Act. Included, among others, were changes to business tax provisions such as permanently restoring 100% bonus depreciation and full domestic research expensing. While the legislation reduced EOG's 2025 cash tax payments, it did not have a material impact on EOG's earnings.

On August 1, 2025, EOG completed its acquisition of Encino Acquisition Partners, LLC (Encino) for $5.7 billion, inclusive of Encino's net debt. The assets of Encino include 675,000 core net acres in the Utica play. The financial results of Encino have been included in EOG's consolidated financial statements beginning August 1, 2025. This acquisition impacted revenues and operating and other expenses as described in the Results of Operations section below. Additionally, see Note 16 to the Consolidated Financial Statements for further discussion of the acquisition.

In January 2026, EOG signed a purchase and sale agreement for the sale of its entire interest and related fixed assets in the northern Midland Basin for $165 million, subject to customary closing adjustments. The transaction closed on February 18, 2026. Crude oil production attributable to EOG's interest was approximately 4 MBbld for the quarter ended December 31, 2025.

Trinidad. In Trinidad, EOG continues to produce natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary under existing supply contracts. Crude oil and condensate are sold to both Heritage Petroleum Company Limited and BP Trinidad and Tobago LLC. In January 2025, EOG executed two production sharing contracts with the Government of Trinidad and Tobago for the Lower Reverse L and North Coast Marine Area 4(a) Blocks.

Other International. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) (Bapco) to evaluate a gas exploration prospect in the Kingdom of Bahrain. In August 2025, the government of the Kingdom of Bahrain approved the related concession agreement. As part of the transaction, EOG has a working interest in several producing legacy wells. EOG has commenced drilling of exploratory wells, which are expected to be completed in 2026.

In May 2025, a subsidiary of EOG was awarded a new oil exploration concession for Unconventional Onshore Block 3 (UCO3) by Abu Dhabi's Supreme Council for Financial and Economic Affairs. EOG holds a 100 percent equity interest and operatorship and, in coordination with Abu Dhabi National Oil Company (ADNOC), has commenced drilling operations to explore and appraise unconventional oil potential in the concession area. Following a three-year appraisal period, EOG may enter into a production concession in which ADNOC has the option to participate.

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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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 21% at December 31, 2025 and 14% at December 31, 2024.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2025, EOG maintained a strong financial and liquidity position, including $3.4 billion of cash and cash equivalents on hand and $3.0 billion of availability under its senior unsecured revolving credit facility (discussed below).

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 permitted eligible taxpayers to postpone certain tax filings and payments. In February 2025, EOG paid approximately $700 million of such federal tax payments related to the 2024 tax year.

On April 1, 2025, EOG repaid upon maturity the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025.

On July 1, 2025, EOG closed on its offering of $500 million aggregate principal amount of its 4.400% Senior Notes due 2028, $1.25 billion aggregate principal amount of its 5.000% Senior Notes due 2032, $1.25 billion aggregate principal amount of its 5.350% Senior Notes due 2036 and $500 million aggregate principal amount of its 5.950% Senior Notes due 2055 (collectively, the July Notes). Interest on the July Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. EOG received net proceeds of $3.47 billion from the issuance of the July Notes, which were used for general corporate purposes, including the payment of a portion of the consideration for the acquisition of Encino and related fees, costs and expenses.

On November 24, 2025, EOG closed on its offering of $750 million aggregate principal amount of its 4.400% Senior Notes due 2031 and $250 million aggregate principal amount of its 5.950% Senior Notes due 2055 (collectively, the November Notes). Interest on the November Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. EOG received net proceeds of $996 million from the issuance of the November Notes, which were used for general corporate purposes, including the repayment of the $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 discussed below.

On December 3, 2025, EOG entered into a new $3.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders, which has a scheduled maturity date of December 3, 2030. The New Facility replaced EOG's $1.9 billion senior unsecured Revolving Credit Agreement, dated as of June 7, 2023, with domestic and foreign lenders, which had a scheduled maturity date of June 7, 2028 and which was terminated by EOG (without penalty), effective as of December 3, 2025, in connection with the completion of the New Facility.

On December 24, 2025, EOG redeemed the $750 million aggregate principal amount of its 4.15% Senior Notes prior to their maturity in January 2026.

During 2025, EOG funded $13.6 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2.2 billion in dividends to common stockholders and paid $2.6 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities, issuances of senior notes and cash on hand.

Total anticipated 2026 capital expenditures are estimated to range from approximately $6.3 billion to $6.7 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 majority of 2026 expenditures will be focused on United States crude oil drilling activities. 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.

Management believes that 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.

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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 percent of annual net cash provided by operating activities before certain balance sheet-related changes, less total capital expenditures, to stockholders through a combination of regular 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.

Dividend Declarations. On February 27, 2025, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.975 per share paid on April 30, 2025, to stockholders of record as of April 16, 2025.

On May 1, 2025, the Board declared a quarterly cash dividend on the common stock of $0.975 per share paid on July 31, 2025, to stockholders of record as of July 17, 2025.

On May 30, 2025, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on October 31, 2025, to stockholders of record as of October 17, 2025. This represented an increase from the previous quarterly cash dividend which was $0.975 per share.

On November 6, 2025, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on January 30, 2026, to stockholders of record as of January 16, 2026.

On February 24, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share to be paid on April 30, 2026, to stockholders of record as of April 16, 2026.

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Results of Operations

This section discusses certain year-to-year comparisons between 2025 and 2024, which should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1. For discussion of certain year-to-year comparisons between 2024 and 2023, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, ITEM 7 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed on February 27, 2025, which is incorporated herein by reference.

Operating Revenues and Other

During 2025, total operating revenues decreased $1,066 million, or 4%, to $22,632 million from $23,698 million in 2024. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $90 million, or 1%, to $17,668 million in 2025 from $17,578 million in 2024. Revenues from the sales of crude oil and condensate and NGLs in 2025 were 84% of total revenues from sales of crude oil and condensate, NGLs and natural gas compared to 91% in 2024. During 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million compared to net gains of $204 million in 2024. Gathering, processing and marketing revenues decreased $886 million during 2025, to $4,914 million from $5,800 million in 2024. EOG recognized net losses on asset dispositions of $35 million in 2025 compared to net gains on asset dispositions of $16 million in 2024.

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Volume and price statistics for the years ended December 31, 2025, 2024 and 2023 were as follows (see Note 11 for segment financial information):

Year Ended December 31

2025

2024

2023

Crude Oil and Condensate Volumes (MBbld) (1)

United States

520.5 

490.6 

475.2 

Trinidad

1.4 

0.8 

0.6 

Total

521.9 

491.4 

475.8 

Average Crude Oil and Condensate Prices ($/Bbl) (2)

United States

$

65.65 

$

77.42 

$

79.18 

Trinidad

57.59 

64.43 

68.58 

Composite

65.63 

77.40 

79.17 

Natural Gas Liquids Volumes (MBbld) (1)

United States

288.2 

245.9 

223.8 

Total

288.2 

245.9 

223.8 

Average Natural Gas Liquids Prices ($/Bbl) (2)

United States

$

22.58 

$

23.40 

$

23.07 

Composite

22.58 

23.40 

23.07 

Natural Gas Volumes (MMcfd) (1)

United States

2,299 

1,728 

1,551 

Trinidad

230 

220 

160 

Other International (3)

4 

— 

— 

Total

2,533 

1,948 

1,711 

Average Natural Gas Prices ($/Mcf) (2)

United States

$

2.94 

$

1.99 

$

2.70 

Trinidad

3.78 

3.65 

3.65 

Other International (3)

3.28 

— 

— 

Composite

3.02 

2.17 

2.79 

Crude Oil Equivalent Volumes (MBoed) (4)

United States

1,191.8 

1,024.5 

957.5 

Trinidad

39.8 

37.6 

27.3 

Other International (3)

0.6 

— 

— 

Total

1,232.2 

1,062.1 

984.8 

Total MMBoe (4)

449.8 

388.7 

359.4 

(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 Consolidated Financial Statements).

(3)Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.

(4)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 in 2025 decreased $1,420 million, or 10%, to $12,501 million from $13,921 million in 2024, primarily due to a lower composite average crude oil and condensate price ($2,239 million), partially offset by an increase in production ($819 million). EOG's composite crude oil and condensate price for 2025 decreased 15% to $65.63 per barrel compared to $77.40 per barrel in 2024. Crude oil and condensate production in 2025 increased 6% to 522 MBbld as compared to 491 MBbld in 2024. The increased production was primarily in the Utica and the Permian Basin.

NGLs revenues in 2025 increased $270 million, or 13%, to $2,376 million from $2,106 million in 2024 primarily due to an increase in production ($356 million), partially offset by a lower composite average NGLs price ($86 million). EOG's composite average NGLs price decreased 4% to $22.58 per barrel in 2025 compared to $23.40 per barrel in 2024. NGLs production in 2025 increased 17% to 288 MBbld as compared to 246 MBbld in 2024. The increased production was primarily in the Utica and the Permian Basin.

Natural gas revenues in 2025 increased $1,240 million, or 80%, to $2,791 million from $1,551 million in 2024 primarily due to a higher composite natural gas price ($783 million) and an increase in natural gas deliveries ($457 million). EOG's composite average natural gas price increased 39% to $3.02 per Mcf in 2025 compared to $2.17 per Mcf in 2024. Natural gas deliveries in 2025 increased 30% to 2,533 MMcfd as compared to 1,948 MMcfd in 2024. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in the Utica and Dorado.

During 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million, which included net cash paid for settlements of NGLs and natural gas financial commodity derivative contracts of $56 million and losses of $79 million related to the Brent crude oil (Brent) linked gas sales contract. During 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $204 million, which included net cash received from settlements of natural gas financial commodity derivative contracts of $214 million and gains of $110 million related to the Brent linked gas sales contract.

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.

Gathering, processing and marketing revenues less marketing costs in 2025 increased $36 million compared to 2024, primarily due to higher margins on natural gas marketing activities and sand sales, partially offset by lower margins on crude oil marketing activities.

Operating and Other Expenses

During 2025, operating expenses of $16,247 million were $631 million higher than the $15,616 million incurred during 2024.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2025 and 2024:

2025

2024

Lease and Well

$

3.72 

$

4.04 

Gathering, Processing and Transportation Costs (GP&T)

4.74 

4.43 

Depreciation, Depletion and Amortization (DD&A) -

Oil and Gas Properties

9.34 

10.04 

Other Property, Plant and Equipment

0.58 

0.53 

General and Administrative (G&A)

1.82 

1.72 

Interest Expense, Net

0.52 

0.36 

Total (1)

$

20.72 

$

21.12 

(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 2025 compared to 2024 are set forth below.  See "Operating Revenues and Other" above for a discussion of 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 $1,675 million in 2025 increased $103 million from $1,572 million in 2024 primarily due to increased operating and maintenance costs ($89 million) in the United States and increased lease and well administrative expenses ($42 million), partially offset by decreased workovers expenditures ($38 million) in the United States.

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 increased $412 million to $2,134 million in 2025 compared to $1,722 million in 2024 primarily due to increased production in the Utica ($375 million) and the Permian Basin ($93 million), partially offset by decreased costs in the Eagle Ford play ($45 million) and the Powder River Basin ($14 million).

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 in 2025 increased $353 million to $4,461 million from $4,108 million in 2024.  DD&A expenses associated with oil and gas properties in 2025 were $298 million higher than in 2024. The increase primarily reflects increased production in the United States ($596 million) and Trinidad ($7 million), and increased unit rates in Trinidad ($8 million). This was partially offset by decreased unit rates in the United States ($197 million) and an adjustment to DD&A recorded in 2024 ($117 million) related to natural gas production used by EOG's domestic gathering systems. DD&A expenses associated with other property, plant and equipment in 2025 were $55 million higher than in 2024 primarily due to an increase in expense related to GP&T assets and equipment.

G&A expenses of $820 million in 2025 increased $151 million from $669 million in 2024 primarily due to increased professional services and other costs, including Encino acquisition-related costs ($100 million), employee-related costs ($47 million) and information systems costs ($10 million).

Interest expense, net of $235 million in 2025 increased $97 million from $138 million in 2024 primarily due to the issuance of the July Notes and the November Notes ($95 million), the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($50 million) and financing commitment costs related to the Encino acquisition ($6.5 million), partially offset by increased capitalized interest primarily related to the unproved leasehold acquired through the Encino acquisition ($40 million) and the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($12 million).

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Exploration costs of $236 million in 2025 increased $62 million from $174 million in 2024 primarily due to increased geological and geophysical expenditures in Trinidad ($27 million), the United Arab Emirates ($23 million) and the United States ($7 million) as well as increased administrative expenses ($11 million), partially offset by decreased delay rentals ($8 million).

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. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data (all Level 3 inputs as defined by the Fair Value Measurement Topic of the Financial Accounting Standards Board's (FASB) Accounting Standards Codification (ASC) (ASC 820)), are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in ASC 820. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

The following table represents impairments for the years ended December 31, 2025 and 2024 (in millions):

2025

2024

Proved properties

$

709 

$

295 

Unproved properties

61 

63 

Other assets

72 

31 

Firm commitment contracts

1 

2 

Total

$

843 

$

391 

Impairments of proved properties for the year ended December 31, 2025, were primarily due to the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window, mainly driven by play-specific economics and resource allocation.

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 revenues from sales of crude oil and condensate, NGLs and natural gas, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income in 2025 decreased $15 million to $1,234 million (7.0% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $1,249 million (7.1% of revenues from sales of crude oil and condensate, NGLs and natural gas) in 2024. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($60 million), partially offset by decreased state severance tax refunds ($30 million) and increased ad valorem/property taxes ($10 million), all in the United States.

Other income, net, was $212 million in 2025 compared to other income, net, of $274 million in 2024. The decrease of $62 million in 2025 was primarily due to a decrease in interest income.

Income taxes of $1,382 million in 2025 decreased from income taxes of $1,815 million in 2024 primarily due to decreased pretax income. The net effective tax rate for 2025 was unchanged from the prior year rate of 22%.

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Capital Resources and Liquidity

Liquidity Overview. At December 31, 2025, EOG maintained a strong financial and liquidity position, including $3.4 billion of cash and cash equivalents on hand and $3.0 billion of availability under the New Facility (which remains undrawn).

The primary sources of cash for EOG during the three-year period ended December 31, 2025, were funds generated from operations and net proceeds from the issuance of long-term debt. The primary uses of cash were exploration and development expenditures; funds used in operations; dividend payments to stockholders; share repurchases and other purchases of treasury stock; the acquisition of Encino; repayment of long-term debt; and other property, plant, and equipment expenditures.

See Notes 2 and 13 to the Consolidated Financial Statements for further discussion on our debt obligations, including the fair value of our senior notes.

Cash Flow. Net cash provided by operating activities of $10,044 million in 2025 decreased $2,099 million from $12,143 million in 2024 primarily due to an increase in net cash paid for income taxes and tax credit purchases ($1,090 million), an increase in cash operating expenses ($696 million), net cash paid for settlements of financial commodity derivative contracts of $56 million compared to net cash received of $214 million in 2024, an increase in net cash used in working capital and other assets and liabilities ($178 million), partially offset by an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($90 million).

Net cash used in investing activities of $10,936 million in 2025 increased by $4,969 million from $5,967 million in 2024 primarily due to the acquisition of Encino ($4,451 million), an increase in additions to oil and gas properties ($762 million) and a decrease in cash provided by working capital associated with investing activities ($297 million), partially offset by a decrease in additions to other property, plant and equipment ($540 million).

Net cash used in financing activities of $2,804 million in 2025 included share repurchases and other purchases of treasury stock ($2,564 million), repayments of long-term debt ($2,516 million) and dividend payments to stockholders ($2,161 million). Cash provided by financing activities in 2025 included long-term debt borrowings ($4,471 million). Net cash used in financing activities of $4,361 million in 2024 included share repurchases and other purchases of treasury stock ($3,246 million) and cash dividend payments ($2,087 million). Cash provided by financing activities in 2024 included long-term debt borrowings ($985 million).

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Total Expenditures

The table below sets out the components of total expenditures for the years ended December 31, 2025, 2024 and 2023 (in millions):

2025

2024

2023

Expenditure Category

Capital

Exploration and Development Drilling (1)

$

4,885 

$

4,534 

$

4,803 

Facilities

622 

606 

520 

Leasehold Acquisitions (2)

197 

230 

207 

Property Acquisitions (3)

7,003 

33 

16 

Capitalized Interest

86 

45 

33 

Subtotal

12,793 

5,448 

5,579 

Exploration Costs

236 

174 

181 

Dry Hole Costs

49 

14 

1 

Exploration and Development Expenditures

13,078 

5,636 

5,761 

Asset Retirement Costs (4)

146 

(2)

257 

Total Exploration and Development Expenditures

13,224 

5,634 

6,018 

Other Property, Plant and Equipment (5)

479 

1,019 

800 

Total Expenditures

$

13,703 

$

6,653 

$

6,818 

(1)Exploration and development drilling included $90 million related to non-cash development drilling in 2023.

(2)Leasehold acquisitions included $24 million, $85 million and $99 million related to non-cash property exchanges in 2025, 2024 and 2023, respectively.

(3)Property acquisitions for the year ended December 31, 2025, included $6,703 million related to the Encino acquisition. Property acquisitions included $24 million and $6 million related to non-cash property exchanges in 2024 and 2023, respectively.

(4)Asset retirement costs for the year ended December 31, 2025, included $52 million related to the Encino acquisition. Asset Retirement Costs for 2024 included a downward revision to asset retirement obligations of $83 million.

(5)Other property, plant and equipment included $137 million related to the acquisition of a gathering and processing system in South Texas and $134 million related to the acquisition of a gathering and processing system in the Powder River Basin in 2024 and 2023, respectively.

Exploration and development expenditures of $13,078 million for 2025 were $7,442 million higher than the prior year primarily due to increased property acquisitions (including Encino) ($6,970 million), increased development drilling expenditures ($405 million), increased exploration expenses ($62 million), increased capitalized interest ($41 million), increased dry hole costs ($35 million) and increased facility expenditures ($16 million), partially offset by decreased exploration drilling expenditures ($54 million) and decreased leasehold acquisitions ($33 million). The 2025 exploration and development expenditures of $13,078 million included $7,003 million in property acquisitions, $5,365 million in development drilling and facilities, $624 million in exploration and $86 million in capitalized interest. The 2024 exploration and development expenditures of $5,636 million included $4,944 million in development drilling and facilities, $614 million in exploration, $45 million in capitalized interest and $33 million in property acquisitions. The 2023 exploration and development expenditures of $5,761 million included $5,101 million in development drilling and facilities, $611 million in exploration, $33 million in capitalized interest and $16 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. 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. However, the adequacy of liquidity sources could be impacted by various factors, including general economic and market conditions, volatility in commodity prices or financial and capital markets and regulatory and other factors discussed in this report under ITEM 1A, Risk Factors.

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Financial Commodity and Other Derivative Transactions

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2025 (closed) and remaining for 2026 and thereafter, as of February 18, 2026 (inclusive of the contracts assumed, via novation, from Encino). Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). NGL volumes are presented in MBbld and prices are presented in $/Bbl.

Natural Gas Financial Price Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MMBtud in thousands)

Weighted Average Price

($/MMBtu)

February - July 2025 (closed)

NYMEX Henry Hub

725 

$

3.07 

August - December 2025 (closed)

NYMEX Henry Hub

1,225 

3.32 

January - February 2026 (closed)

NYMEX Henry Hub

460 

3.78 

March - June 2026

NYMEX Henry Hub

460 

3.78 

July - December 2026

NYMEX Henry Hub

450 

3.79 

Natural Gas Basis Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MMBtud in thousands)

Weighted Average Price

Differential

($/MMBtu)

January - December 2025 (closed)

NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)

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.

Natural Gas Collar Contracts

Contracts Sold

Weighted Average Price

($/MMBtu)

Period

Settlement Index

Volume

(MMBtud in thousands)

Ceiling Price

Floor Price

September 2025 (closed)

NYMEX Henry Hub

50 

$

4.65 

$

3.81 

October - December 2025 (closed)

NYMEX Henry Hub

60 

4.63 

3.76 

January - February 2026 (closed)

NYMEX Henry Hub

80 

4.28 

3.72 

March - June 2026

NYMEX Henry Hub

80 

4.28 

3.72 

July - December 2026

NYMEX Henry Hub

70 

4.23 

3.71 

January - December 2027

NYMEX Henry Hub

120 

4.41 

3.42 

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Ethane Financial Price Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MBbld)

Weighted Average Price

($/Bbl)

August - December 2025 (closed)

Mont Belvieu Ethane (non-Tet)

11 

$

10.46 

January 2026 (closed)

Mont Belvieu Ethane (non-Tet)

11 

10.94 

February - December 2026

Mont Belvieu Ethane (non-Tet)

11 

10.94 

Butane Financial Price Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MBbld)

Weighted Average Price

($/Bbl)

August - December 2025 (closed)

Mont Belvieu Butane (non-Tet)

7 

$

36.28 

Propane Financial Price Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MBbld)

Weighted Average Price

($/Bbl)

August - December 2025 (closed)

Mont Belvieu Propane (Tet)

13 

$

30.82 

January 2026 (closed)

Mont Belvieu Propane (Tet)

1 

30.24 

February - December 2026

Mont Belvieu Propane (Tet)

1 

30.24 

In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at February 18, 2026. 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. 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 ASC 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 Consolidated Statements of Income and Comprehensive Income.

Financing

EOG's debt-to-total capitalization ratio was 21% at December 31, 2025, compared to 14% at December 31, 2024.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2025 and 2024, respectively, EOG had outstanding $7,890 million and $4,640 million aggregate principal amount of senior notes, which had estimated fair values of $7,849 million and $4,441 million, respectively.  The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to EOG at year-end.  EOG's debt is at fixed interest rates.  While changes in interest rates affect the fair value of EOG's senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow.

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During 2025, EOG funded its capital program and operations by utilizing cash provided by operating activities, proceeds from the issuances of senior notes and cash on hand.  While EOG maintains the New Facility to back its commercial paper program (which replaced its prior $1.9 billion revolving credit facility), there were no borrowings outstanding at any time during 2025 under either facility and the amount outstanding at year-end was zero.  EOG considers the availability of the New Facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

Outlook

Pricing.  Crude oil, NGLs and natural gas prices have been volatile, and this volatility is expected to continue.  As a result of the many uncertainties associated with the world economic and political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future.  The market price of crude oil and condensate, NGLs and natural gas in 2026 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 18, 2026, the average 2026 NYMEX crude oil and natural gas prices were $63.23 per barrel and $3.84 per MMBtu, respectively, representing a decrease of 2% for crude oil and an increase of 12% for natural gas from the average NYMEX prices in 2025. See ITEM 1A, Risk Factors for additional discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.

Based on EOG's tax position, EOG's price sensitivity in 2026 for each $1.00 per barrel increase or decrease in crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $174 million for net income and $223 million for pretax cash flows from operating activities.  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 2026 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in natural gas price is approximately $64 million for net income and $83 million for pretax cash flows from operating activities.  For information regarding EOG's crude oil, NGLs and natural gas financial commodity derivative contracts through February 18, 2026, see "Financial Commodity and Other Derivative Transactions" above.

Capital. 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 the Delaware Basin play, Eagle Ford play, Dorado gas play and Utica play where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to focus on improving operating efficiencies. In addition, EOG expects to spend a portion of its anticipated 2026 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

The total anticipated 2026 capital expenditures of approximately $6.3 billion to $6.7 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, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its $3.0 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2026, crude oil and total crude oil equivalent production are expected to increase from 2025 levels. In addition, in 2026 EOG expects to (i) continue to undertake initiatives to increase its drilling, completion and operating efficiencies and improve the performance of its wells and (ii) when available and advantageous, enter into agreements with its service providers to secure the costs and availability of certain drilling and completions services it utilizes as part of its operations.

49

Cash Requirements. Certain of EOG's capital expenditures and operating costs are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASC "Leases (Topic 842)". In 2026, EOG anticipates the following cash requirements under these commitments (in millions):

Finance Leases (1)

$

30 

Operating Leases (1)

515 

Leases Effective, Not Commenced (1)

30 

Transportation and Storage Service Commitments (2) (3)

1,031 

Purchase and Service Obligations (3)

640 

Total Cash Requirements

$

2,246 

(1)    For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 17 to Consolidated Financial Statements.

(2)    Amounts exclude transportation and storage service commitments that meet the definition of a lease. Amounts shown are based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2025. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.

(3)    For years 2026 and beyond, $65 million of capital commitments have been made. For more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

In 2026, EOG has no senior notes maturing and EOG expects to pay interest of $393 million on senior notes. For more information on EOG's current and long-term debt, see Note 2 to Consolidated Financial Statements.

Cash requirements to settle the liability for EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 7 and 15, respectively, to Consolidated Financial Statements) are excluded because they are subject to estimates and the timing of settlement is unknown.

EOG expects to fund its exploration, development and exploitation activities, its cash return commitment, its debt service obligations and other cash requirements, both in 2026 and in future years, primarily from internally generated cash flows and cash on hand. As discussed above, EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under the New Facility and equity and debt offerings.

Summary of Critical Accounting Policies and Estimates

EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes.  EOG identifies certain accounting policies and estimates as critical based on, among other things, their impact on EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application.  Critical accounting policies and estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown.  Management routinely discusses the development, selection and disclosure of each of the critical accounting policies and estimates.  Following is a discussion of EOG's most critical accounting policies and estimates:

Proved Oil and Gas Reserves

EOG's engineers estimate proved oil and gas reserves in accordance with United States Securities and Exchange Commission (SEC) regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets.  Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be economically producible in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. 

50

The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir.  The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, crude oil and condensate, NGLs and natural gas prices, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.  Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.  For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward or downward, earnings will increase or decrease, respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base used includes only proved developed reserves. 

Impairments

Oil and gas lease acquisition costs are capitalized when incurred.  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. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. 

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data (all Level 3 inputs as defined by ASC 820), are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in ASC 820. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future.  During the five years ended December 31, 2025, WTI crude oil spot prices have fluctuated from approximately $47.47 per barrel to $123.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.21 per MMBtu to $23.86 per MMBtu.  Market prices for NGLs are influenced by the components extracted, including ethane, propane, butane and natural gasoline, among others, and the respective market pricing for each component.

EOG uses the five-year NYMEX futures strip for WTI crude oil and Henry Hub natural gas and the five-year Oil Price Information Services futures strip for NGLs components (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil, NGLs and natural gas prices. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and judgment, and are frequently revised (upwards and downwards) as more information becomes available.  In the future, if any combination of crude oil prices, NGLs prices, natural gas prices or estimated proved reserves diverge negatively from EOG's current estimates, impairment charges may be necessary.

These estimates, which factor into EOG's unproved and proved property impairment calculations, involve the use of various assumptions and judgment. Differing assumptions could impact the timing and amount of an impairment in any given period. Any impairment will decrease earnings in the period in which it is recognized. See Notes 13 and 14 to Consolidated Financial Statements for further discussion of impairments of oil and gas properties and other assets.

51

Business Combinations

EOG accounts for business combinations under the Business Combinations Topic of the ASC, which requires identifiable assets acquired and liabilities assumed to be recognized at their acquisition date fair values. In estimating the fair values of assets acquired and liabilities assumed, various assumptions are applied.

The most significant assumptions relate to the estimated fair values of proved and unproved crude oil and natural gas properties for which EOG utilized the Income Approach described in ASC 820. The assumptions made in performing the valuation under the Income Approach include future crude oil, NGLs and natural gas prices, future operating and development costs, anticipated production from reserves, a weighted average cost of capital rate and risk adjustment factors for proved undeveloped, probable and possible reserves.

The assumptions and inputs used in determining fair value estimates involve significant management judgment and are based on industry, market and economic conditions at the time of the acquisition. While these estimates are based on assumptions considered reasonable, they are inherently uncertain and actual results may differ.

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Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K 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 commodity and other derivative instruments and hedging activities; laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; and trade policies, tariffs, trade agreements and other trade restrictions;

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•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, EOG's ability to retain, 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;

•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 this Annual Report on Form 10-K 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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