EOG RESOURCES INC (EOG)

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 $6,403 million during 2024 as compared to net income of $7,594 million for 2023. At December 31, 2024, EOG's total estimated net proved reserves were 4,748 million barrels of oil equivalent (MMBoe), an increase of 250 MMBoe from December 31, 2023.  During 2024, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 218 million barrels (MMBbl), and net proved natural gas reserves increased by 192 billion cubic feet, or 32 MMBoe, in each case from December 31, 2023.

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 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 year ended December 31, 2024, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $75.72 per barrel and $2.27 per million British thermal units (MMBtu), respectively, representing decreases of 2% and 17%, respectively, from the average NYMEX prices for the year ended December 31, 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.

Inflationary Pressures, Operational Efficiencies & Related Initiatives/Actions. During 2024, EOG continued to see diminished inflationary pressures on its operating costs and capital expenditures (e.g., for fuel, wellbore tubulars, facilities manufactured using steel, labor and drilling and completion services) and, in certain circumstances, has seen declines in prices. However, because the market for such materials, services and labor continues to fluctuate, there can be no assurance that the inflationary pressures experienced by EOG in prior periods will not resume. Further, the timing and impact of any future price changes on EOG's operating costs and capital expenditures is uncertain.

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EOG has undertaken (and continues to undertake) initiatives to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, mitigate the inflationary pressures experienced in prior periods. 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 has resulted in a decrease in cost per foot drilled; and (iv) EOG's self-sourced sand program, which has resulted in cost savings for the sand utilized 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 completion 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 offset, largely or at all, the impacts of any future inflationary pressures (such as from tariffs) on EOG's operating costs and capital expenditures, cash flows and results of operations. Further, there can be no assurance that the factors contributing to any such future inflationary pressures 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.

Climate Change. For a 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. EOG will continue to monitor and assess any climate change-related developments 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.

Operations

Several important developments have occurred since January 1, 2024.

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 2024, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance and, in turn, mitigate the inflationary pressures on its operating costs and capital expenditures experienced in prior periods. 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 72% and 73% of EOG's United States production during 2024 and 2023, respectively. During 2024, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico and Texas. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2024 United States operations.

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) and Banyan and Sercan Areas have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and crude oil and condensate which is sold to Heritage Petroleum Company Limited.

During 2024, EOG completed one net developmental well and one net exploratory well from the Osprey B platform in the Modified U(a) Block. EOG also completed two net exploratory wells from the Oilbird platform in the SECC Block, drilled a deep Teak, Saaman and Poui (TSP Deep) exploratory well which allowed EOG to retain a 50% working interest in the TSP Deep Area and recompleted one net well in the Sercan Area. EOG also completed construction and installation of the Mento platform in the Ska, Mento and Reggae Area and commenced pipeline and associated tie-in installations that will connect the Mento platform to the Pelican platform. In 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 and signed a farmout agreement with BP Trinidad and Tobago LLC, which allows EOG to earn a 50% working interest to develop the Coconut field in the Coconut Area located within the East Mayaro and South East Galeota exploration and production licenses. Additionally, EOG was selected as the preferred bidder in the Lower Reverse L and North Coast Marine Area 4(a) Blocks in respect of the 2023 shallow water offshore bid round.

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Other International. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) to evaluate a gas exploration project in the Kingdom of Bahrain, with drilling anticipated to commence in the second half of 2025. The transaction, which includes a concession agreement with the Kingdom of Bahrain, is subject to further government approvals, which the parties anticipate receiving in the second half of 2025.

In November 2021, a subsidiary of EOG was granted an exploration permit for the WA-488-P Block, located offshore Western Australia. The company has deferred drilling plans to further evaluate the prospect.

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

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 14% at December 31, 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 December 31, 2024, EOG maintained a strong financial and liquidity position, including $7.1 billion of cash and cash equivalents on hand and $1.9 billion of availability under its senior unsecured revolving credit facility (discussed below).

On November 21, 2024, EOG closed on its offering of $1.0 billion aggregate principal amount of its 5.650% Senior Notes due 2054 (the Notes). EOG received net proceeds of $985 million from the issuance of the Notes, which will be used for general corporate purposes, including (i) the repayment of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 and (ii) the funding of future capital expenditures.

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.

During 2024, EOG funded $6.7 billion ($109 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2.1 billion in dividends to common stockholders and paid $3.2 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities and cash on hand.

Total anticipated 2025 capital expenditures are estimated to range from approximately $6.0 billion to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses. The majority of 2025 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 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.

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.

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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.

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 paid on January 31, 2025, to stockholders of record as of January 17, 2025.

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

Results of Operations

This section discusses certain year-to-year comparisons between 2024 and 2023, 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 2023 and 2022, 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, 2023, filed on February 22, 2024, which is incorporated herein by reference.

Operating Revenues and Other

During 2024, operating revenues decreased $488 million, or 2%, to $23,698 million from $24,186 million in 2023. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $202 million, or 1%, to $17,578 million in 2024 from $17,376 million in 2023. Revenues from the sales of crude oil and condensate and NGLs in 2024 were 91% of total revenues from sales of crude oil and condensate, NGLs and natural gas compared to 90% in 2023. During 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $204 million compared to net gains of $818 million in 2023. Gathering, processing and marketing revenues decreased $6 million during 2024, to $5,800 million from $5,806 million in 2023. EOG recognized net gains on asset dispositions of $16 million in 2024 compared to net gains on asset dispositions of $95 million in 2023.

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Volume and price statistics for the years ended December 31, 2024, 2023 and 2022 were as follows:

(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)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.

(4)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

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Crude oil and condensate revenues in 2024 increased $173 million, or 1%, to $13,921 million from $13,748 million in 2023, primarily due to an increase in production ($491 million), partially offset by a lower composite average crude oil and condensate price ($318 million). EOG's composite crude oil and condensate price for 2024 decreased 2% to $77.40 per barrel compared to $79.17 per barrel in 2023. Crude oil and condensate production in 2024 increased 3% to 491 MBbld as compared to 476 MBbld in 2023. The increased production was primarily in the Permian Basin and Utica.

NGLs revenues in 2024 increased $222 million, or 12%, to $2,106 million from $1,884 million in 2023 primarily due to an increase in production ($192 million) and a higher composite average NGLs price ($30 million). EOG's composite average NGLs price increased 1% to $23.40 per barrel in 2024 compared to $23.07 per barrel in 2023. NGLs production in 2024 increased 10% to 246 MBbld as compared to 224 MBbld in 2023. The increased production was primarily in the Permian Basin.

Natural gas revenues in 2024 decreased $193 million, or 11%, to $1,551 million from $1,744 million in 2023 primarily due to a lower composite natural gas price ($435 million), partially offset by an increase in natural gas deliveries ($242 million). EOG's composite average natural gas price decreased 22% to $2.17 per Mcf in 2024 compared to $2.79 per Mcf in 2023. Natural gas deliveries in 2024 increased 14% to 1,948 MMcfd as compared to 1,711 MMcfd in 2023. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Trinidad.

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. The net gains of $204 million included gains of $110 million related to the Brent crude oil (Brent) linked gas sales contract. During 2023, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $818 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial commodity derivative contracts of $112 million.

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 in 2024 decreased $14 million compared to 2023, primarily due to lower margins on sand sales and natural gas marketing activities, partially offset by higher margins on crude oil marketing activities.

Operating and Other Expenses

During 2024, operating expenses of $15,616 million were $1,033 million higher than the $14,583 million incurred during 2023.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2024 and 2023:

(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 2024 compared to 2023 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 $1,572 million in 2024 increased $118 million from $1,454 million in 2023 primarily due to increased operating and maintenance costs ($81 million), increased lease and well administrative expenses ($27 million) and increased workovers expenditures ($13 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 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 $102 million to $1,722 million in 2024 compared to $1,620 million in 2023 primarily due to increased production in the Permian Basin ($91 million) and the Utica ($35 million), partially offset by decreased costs in the Powder River Basin due to reduced operating and maintenance expenses ($17 million), the Eagle Ford play due to lower volumes and reduced third-party fees ($11 million) and the Barnett Shale due to lower gas volumes and operating costs ($5 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 2024 increased $616 million to $4,108 million from $3,492 million in 2023.  DD&A expenses associated with oil and gas properties in 2024 were $583 million higher than in 2023. The increase primarily reflects increased production in the United States ($233 million) and Trinidad ($26 million), and increased unit rates in the United States ($166 million) and in Trinidad ($35 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 in 2024 were $33 million higher than in 2023 primarily due to an increase in expense related to GP&T assets and equipment.

G&A expenses of $669 million in 2024 increased $29 million from $640 million in 2023 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and information systems.

Interest expense, net of $138 million in 2024 decreased $10 million from $148 million in 2023 primarily due to an increase in capitalized interest ($12 million) and the repayment in March 2023 of the $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023 ($7 million), partially offset by the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($7 million).

Exploration costs of $174 million in 2024 decreased $7 million from $181 million in 2023 primarily due to decreased geological and geophysical expenditures in the United States ($22 million), partially offset by increased administrative expenses ($9 million) and increased delay rentals ($6 million).

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Impairments include: amortization of individually insignificant unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; individually significant unproved oil and gas property costs; and other assets.  Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term.  Unproved properties with individually significant acquisition costs are reviewed individually for impairment. 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 FASB's Fair Value Measurement Topic of the 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, 2024 and 2023 (in millions):

Impairments of proved properties for the year ended December 31, 2024, were primarily due to the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

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 2024 decreased $35 million to $1,249 million (7.1% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $1,284 million (7.4% of revenues from sales of crude oil and condensate, NGLs and natural gas) in 2023. The decrease in taxes other than income was primarily due to increased state severance tax refunds ($18 million), decreased ad valorem/property taxes ($14 million) and decreased severance/production taxes ($5 million), all in the United States.

Other income, net, was $274 million in 2024 compared to other income, net, of $234 million in 2023. The increase of $40 million in 2024 was primarily due to an increase in interest income.

Income taxes of $1,815 million in 2024 decreased from income taxes of $2,095 million in 2023 primarily due to decreased pretax income. The net effective tax rate for 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 three-year period ended December 31, 2024, were funds generated from operations and, to a lesser extent, net proceeds from the issuance of long-term debt and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; purchases of treasury stock; net cash paid for settlements of financial commodity derivative contracts; other property, plant and equipment expenditures; and repayment of debt.

Net cash provided by operating activities of $12,143 million in 2024 increased $803 million from $11,340 million in 2023 primarily due to a decrease in net cash paid for income taxes ($450 million), an increase in net cash received from settlements of financial commodity derivative contracts ($326 million), an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($202 million) and a decrease in net cash used in working capital and other assets and liabilities ($197 million), partially offset by the return in 2023 of cash collateral posted for financial commodity derivative contracts ($324 million) and an increase in cash operating expenses ($185 million).

Net cash used in investing activities of $5,967 million in 2024 decreased by $373 million from $6,340 million in 2023 primarily due to a decrease in net cash used in working capital associated with investing activities ($677 million) and a decrease in additions to oil and gas properties ($32 million); partially offset by an increase in additions to other property, plant and equipment ($219 million) and a decrease in proceeds from the sales of assets ($117 million).

Net cash used in financing activities of $4,361 million in 2024 included purchases of treasury stock ($3,246 million), cash dividend payments ($2,087 million) and repayment of finance lease liabilities ($33 million). Cash provided by financing activities in 2024 included long-term debt borrowings ($985 million) and proceeds from stock options exercised and employee stock purchase plan activity ($22 million).

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Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2024, 2023 and 2022 (in millions):

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

(2)Leasehold acquisitions included $85 million, $99 million and $127 million related to non-cash property exchanges in 2024, 2023 and 2022, respectively.

(3)Property acquisitions included $24 million, $6 million and $26 million related to non-cash property exchanges in 2024, 2023 and 2022, respectively.

(4)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 $5,636 million for 2024 were $125 million lower than the prior year primarily due to decreased development drilling expenditures ($249 million), partially offset by increased facility expenditures ($86 million), increased leasehold acquisitions ($23 million) and increased property acquisitions ($17 million). 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 2022 exploration and development expenditures of $4,931 million included $3,962 million in development drilling and facilities, $514 million in exploration, $419 million in property acquisitions and $36 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors.  EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant.  While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG. Further, EOG believes that its sources of liquidity are adequate for other near-term and long-term funding requirements, including its cash return commitment, debt service obligations, repayments of debt maturities and other commitment and contingencies. 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, 2024 (closed) and remaining for 2025, as of February 21, 2025. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

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(1)    This settlement index is used to fix the differential between pricing at the Houston Ship Channel and 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 crude oil (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 14% at December 31, 2024, compared to 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 December 31, 2024 and 2023, respectively, EOG had outstanding $4,640 million and $3,640 million aggregate principal amount of senior notes, which had estimated fair values of $4,441 million and $3,574 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.

During 2024, EOG funded its capital program and operations by utilizing cash provided by operating activities and cash on hand.  While EOG maintains a $1.9 billion senior unsecured revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2024 and the amount outstanding at year-end was zero.  EOG considers the availability of its $1.9 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

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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 2025 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 21, 2025, the average 2025 NYMEX crude oil and natural gas prices were $69.58 per barrel and $4.26 per MMBtu, respectively, representing a decrease of 8% for crude oil and an increase of 88% for natural gas from the average NYMEX prices in 2024. 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 2025 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 $159 million for net income and $204 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 2025 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 $33 million for net income and $42 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 21, 2025, 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 mitigate any future inflationary pressures (such as from tariffs) through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2025 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

The total anticipated 2025 capital expenditures of approximately $6.0 billion to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses, 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 $1.9 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2025, crude oil and total crude oil equivalent production are expected to increase from 2024 levels. In 2025, EOG expects to continue to focus on mitigating any future inflationary pressures (such as from tariffs) on operating costs through efficiency improvements.

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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 2025, EOG anticipates the following cash requirements under these commitments (in millions):

(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, 2024. 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 more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

In 2025, EOG has $500 million aggregate principal amount of senior notes maturing, which are expected to be repaid with proceeds from its November 2024 Notes offering discussed above. Additionally in 2025, EOG expects to pay interest of $209 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 and other cash requirements, both in 2025 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 its $1.9 billion senior unsecured revolving credit 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 recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

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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 the FASB's Fair Value Measurement Topic of the 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.

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, 2024, WTI crude oil spot prices have fluctuated from approximately $(36.98) 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 judgement. 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 disclosures of impairments of oil and gas properties and other assets.

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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 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 or safety 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, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;

•the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

•the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;

•the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;

•the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;

•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;

•the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;

•the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases;

•the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

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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 ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;

•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;

•competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;

•the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;

•the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

•weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;

•the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

•EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

•the extent to which EOG is successful in its completion of planned asset dispositions;

•the extent and effect of any hedging activities engaged in by EOG;

•the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

•the economic and financial impact of epidemics, pandemics or other public health issues;

•geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;

•the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and

•the other factors described under ITEM 1A, Risk Factors of 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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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 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.

EOG realized net income of $7,594 million during 2023 as compared to net income of $7,759 million for 2022. At December 31, 2023, EOG's total estimated net proved reserves were 4,498 million barrels of oil equivalent (MMBoe), an increase of 260 MMBoe from December 31, 2022.  During 2023, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 204 million barrels (MMBbl), and net proved natural gas reserves increased by 339 billion cubic feet or 57 MMBoe, in each case from December 31, 2022.

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 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 year ended December 31, 2023, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $77.61 per barrel and $2.74 per million British thermal units (MMBtu), respectively, representing decreases of 18% and 59%, respectively, from the average NYMEX prices for the year ended December 31, 2022. 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.

Inflation Considerations; Availability of Materials, Labor & Services. Beginning in the second half of 2021 and continuing, to a lesser degree, through the first three months of 2023, EOG, similar to other companies in its industry, experienced inflationary pressures on its operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars and facilities manufactured using steel), labor and drilling and completion services. Such inflationary pressures resulted from (i) supply chain disruptions caused by the COVID-19 pandemic and the resulting limited availability of certain materials and products manufactured using such materials; (ii) increased demand for fuel and steel; (iii) increased demand for drilling and completion services coupled with a limited number of available service providers, resulting in increased competition for such services among EOG and other companies in its industry; (iv) labor shortages; and (v) other factors, including the ongoing conflict between Russia and the Ukraine which began in late February 2022. Beginning in the second quarter of 2023, EOG has seen these inflationary pressures diminish and, in certain circumstances, seen a decline in prices. However, the market for such materials, services and labor continues to fluctuate and, as a result, the timing and impact of any price changes on EOG's future operating costs and capital expenditures is uncertain.

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Such inflationary pressures on EOG's operating costs and capital expenditures have, in turn, impacted its cash flows and results of operations. However, by virtue of its continued focus on increasing its drilling, completion and operating efficiencies and improving the performance of its wells, as well as the flexibility provided by its multi-basin drilling portfolio, EOG has, to date, been able to largely offset such impacts. Such inflationary pressures resulted in an increase of less than 10 percent in its fiscal year 2023 well costs (i.e., its costs for drilling, completions and well-site facilities) versus fiscal year 2022. Accordingly, such increase in EOG's fiscal year 2023 well costs did not have a material impact on EOG's full-year 2023 cash flows. Further, such inflationary pressures and the factors contributing to such inflationary pressures (described above) have not, to date, impacted EOG's liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.

The initiatives EOG has undertaken (and continues to undertake) to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, mitigate such inflationary pressures, 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; and (iii) EOG's self-sourced sand program, which has resulted in continued cost savings for the sand utilized in its well completion operations. In addition, EOG enters into agreements with its service providers from time to time, when available and advantageous, to secure the costs and availability of certain drilling and completion 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 offset, largely or at all, the impacts of any future inflationary pressures on EOG's operating costs and capital expenditures, cash flows and results of operations. Further, there can be no assurance that the factors contributing to any future inflationary pressures 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.

Climate Change. For a 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. EOG will continue to monitor and assess any climate change-related developments 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.

Operations

Several important developments have occurred since January 1, 2023.

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 2023, EOG continued to focus on increasing drilling, completion and operating efficiencies, to improve well performance and, as is further discussed above, to mitigate inflationary pressures on its operating costs and capital expenditures. 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 73% and 75% of EOG's United States production during 2023 and 2022, respectively. During 2023, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico and Texas. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2023 United States operations.

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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 its subsidiary (NGC), and crude oil and condensate which is sold to Heritage Petroleum Company Limited.

In the fourth quarter of 2023, EOG completed two net developmental wells and one net exploratory well from the recently installed Osprey B platform in the Modified U(a) Block. Additionally, in 2023, EOG completed the design phase for the platform and related facilities in the Mento Area and commenced construction of such platform and related facilities.

Also, EOG sold its equity interest in its ammonia plant investments in the first quarter of 2023.

Other International. In November 2021, a subsidiary of EOG was granted an exploration permit for the WA-488-P Block, located offshore Western Australia. In 2023, EOG continued to prepare for the drilling of an exploration well subject to regulatory approvals and equipment availability.

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

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 12% at December 31, 2023 and 17% at December 31, 2022.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2023, EOG maintained a strong financial and liquidity position, including $5.3 billion of cash and cash equivalents on hand and $1.9 billion of availability under its senior unsecured revolving credit facility (discussed below).

On June 7, 2023, EOG entered into a $1.9 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders. The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of June 27, 2019, with domestic and foreign lenders, which had a scheduled maturity date of June 27, 2024, and was terminated by EOG (without penalty), effective as of June 7, 2023, in connection with the completion of the New Facility.

On March 15, 2023, EOG repaid upon maturity the $1,250 million aggregate principal amount of its 2.625% Senior Notes due 2023 (2023 Notes).

During 2023, EOG funded $6.6 billion ($195 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $3.4 billion in dividends to common stockholders, repaid the 2023 Notes and paid $1.0 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities and cash on hand.

Total anticipated 2024 capital expenditures are estimated to range from approximately $6.0 billion to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses. The majority of 2024 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 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.

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Cash Return Framework. In May 2022, EOG announced the addition of quantitative guidance to its cash return framework - specifically, a commitment to return a minimum of 60% 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. On November 2, 2023, EOG announced an increase in such 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 related discussion regarding our 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 23, 2023, EOG's Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.825 per share paid on April 28, 2023, to stockholders of record as of April 14, 2023. The Board also declared on such date a special dividend on the common stock of $1.00 per share paid on March 30, 2023, to stockholders of record as of March 16, 2023.

On May 4, 2023, the Board declared a quarterly cash dividend on the common stock of $0.825 per share paid on July 31, 2023, to stockholders of record as of July 17, 2023.

On August 3, 2023, the Board declared a quarterly cash dividend on the common stock of $0.825 per share paid on October 31, 2023, to stockholders of record as of October 17, 2023.

On November 2, 2023, the Board (i) increased the quarterly cash dividend on the common stock from the previous $0.825 per share to $0.91 per share, effective beginning with the dividend paid on January 31, 2024, to stockholders of record as of January 17, 2024, and (ii) declared a special cash dividend on the common stock of $1.50 per share, paid on December 29, 2023, to stockholders of record as of December 15, 2023.

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

Results of Operations

This section discusses certain year-to-year comparisons between 2023 and 2022, 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 2022 and 2021, 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, 2022, filed on February 23, 2023, which is incorporated herein by reference.

Operating Revenues and Other

During 2023, operating revenues decreased $1,516 million, or 6%, to $24,186 million from $25,702 million in 2022. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $5,420 million, or 24%, to $17,376 million in 2023 from $22,796 million in 2022. Revenues from the sales of crude oil and condensate and NGLs in 2023 were 90% of total wellhead revenues compared to 83% in 2022. During 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $818 million compared to net losses of $3,982 million in 2022. Gathering, processing and marketing revenues decreased $890 million during 2023, to $5,806 million from $6,696 million in 2022. EOG recognized net gains on asset dispositions of $95 million in 2023 compared to net gains on asset dispositions of $74 million in 2022.

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Wellhead volume and price statistics for the years ended December 31, 2023, 2022 and 2021 were as follows:

(1)    Thousand barrels per day or million cubic feet per day, as applicable.

(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

(3)Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).

(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.

(5)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

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Wellhead crude oil and condensate revenues in 2023 decreased $2,619 million, or 16%, to $13,748 million from $16,367 million in 2022, due primarily to a lower composite average wellhead crude oil and condensate price ($3,134 million), partially offset by an increase in production ($515 million). EOG's composite wellhead crude oil and condensate price for 2023 decreased 19% to $79.17 per barrel compared to $97.21 per barrel in 2022. Wellhead crude oil and condensate production in 2023 increased 3% to 476 MBbld as compared to 461 MBbld in 2022. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play.

NGLs revenues in 2023 decreased $764 million, or 29%, to $1,884 million from $2,648 million in 2022 primarily due to a lower composite average wellhead NGLs price ($1,117 million), partially offset by an increase in production ($353 million). EOG's composite average wellhead NGLs price decreased 37% to $23.07 per barrel in 2023 compared to $36.70 per barrel in 2022. NGLs production in 2023 increased 13% to 224 MBbld as compared to 198 MBbld in 2022. The increased production was primarily in the Permian Basin.

Wellhead natural gas revenues in 2023 decreased $2,037 million, or 54%, to $1,744 million from $3,781 million in 2022 primarily due to a lower composite wellhead natural gas price ($2,583 million), partially offset by an increase in natural gas deliveries ($546 million). EOG's composite average wellhead natural gas price decreased 60% to $2.79 per Mcf in 2023 compared to $6.93 per Mcf in 2022. Natural gas deliveries in 2023 increased 14% to 1,711 MMcfd as compared to 1,495 MMcfd in 2022. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher deliveries in the Dorado gas play, partially offset by lower natural gas deliveries in Trinidad and decreased production of associated natural gas from the Eagle Ford play.

During 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $818 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $112 million. During 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $3,982 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $3,501 million.

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 in 2023 decreased $64 million compared to 2022, primarily due to lower margins on natural gas marketing activities.

Operating and Other Expenses

During 2023, operating expenses of $14,583 million were $1,153 million lower than the $15,736 million incurred during 2022.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2023 and 2022:

(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, transportation costs, gathering and processing costs, DD&A, G&A and interest expense, net for 2023 compared to 2022 are set forth below.  See "Operating Revenues and Other" above for a discussion of production 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 $1,454 million in 2023 increased $123 million from $1,331 million in 2022 primarily due to higher operating and maintenance costs in the United States ($65 million) and in Trinidad ($8 million), higher lease and well administrative expenses in the United States ($43 million), and higher workovers expenditures in the United States ($8 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease or an aggregation point on EOG's gathering system to a downstream point of sale.  Transportation costs include transportation fees, storage and terminal fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs. Transportation costs also include operating and maintenance expenses associated with EOG-owned transportation assets.

Transportation costs of $957 million in 2023 decreased $9 million from $966 million in 2022 primarily due to decreased transportation costs related to production from the Eagle Ford play ($37 million) and the Rocky Mountain area ($6 million), partially offset by increased transportation costs related to production from the Permian Basin ($20 million), the Dorado gas play ($9 million) and the Mid-Continent area ($5 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees and certain NGLs fractionation fees paid to third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

Gathering and processing costs increased $42 million to $663 million in 2023 compared to $621 million in 2022 primarily due to increased gathering and processing fees related to production from the Permian Basin ($33 million) and increased operating and maintenance expenses related to production from the Rocky Mountain area ($14 million) and the Permian Basin ($10 million), partially offset by decreased operating and maintenance expenses related to production from the Eagle Ford play ($14 million) and decreased gathering and processing fees related to production from the Rocky Mountain area ($13 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.

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DD&A expenses in 2023 decreased $50 million to $3,492 million from $3,542 million in 2022.  DD&A expenses associated with oil and gas properties in 2023 were $64 million lower than in 2022 primarily due to lower unit rates in the United States ($373 million), partially offset by an increase in production in the United States ($299 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to favorable well performance, lower expected future operating costs and reserve additions at lower costs per Boe. DD&A expenses associated with other property, plant and equipment in 2023 were $14 million higher than in 2022 primarily due to an increase in expense related to gathering assets and equipment.

G&A expenses of $640 million in 2023 increased $70 million from $570 million in 2022 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and information systems and other services.

Interest expense, net of $148 million in 2023 decreased $31 million from $179 million in 2022 primarily due to the repayment in March 2023 of the $1,250 million aggregate principal amount of the 2023 Notes.

Exploration costs of $181 million in 2023 increased $22 million from $159 million in 2022 primarily due to increased administrative expenses ($10 million) and increased geological and geophysical expenditures ($8 million), both in the United States.

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. When circumstances indicate that a proved property 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 estimates 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, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  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, 2023 and 2022 (in millions):

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 in 2023 decreased $301 million to $1,284 million (7.4% of wellhead revenues) from $1,585 million (7.0% of wellhead revenues) in 2022. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($357 million) and decreased ad valorem/property taxes ($34 million), partially offset by decreased state severance tax refunds ($99 million), all in the United States.

Other income, net, was $234 million in 2023 compared to other income, net, of $114 million in 2022. The increase of $120 million in 2023 was primarily due to an increase in interest income ($155 million), partially offset by the absence of equity income due to the sale of EOG's equity interest in ammonia plant investments in Trinidad in the first quarter of 2023 ($46 million).

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EOG recognized an income tax provision of $2,095 million in 2023 compared to an income tax provision of $2,142 million in 2022 primarily due to decreased pretax income. The net effective tax rate for 2023 was unchanged from the prior year rate of 22%.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2023, were funds generated from operations and, to a lesser extent, proceeds from asset sales.  The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; net cash paid for settlements of financial commodity derivative contracts; repayment of debt; other property, plant and equipment expenditures; and purchases of treasury stock.

Net cash provided by operating activities of $11,340 million in 2023 increased $247 million from $11,093 million in 2022 primarily due to a decrease in net cash paid for settlements of financial commodity derivative contracts ($3,389 million), a decrease in net cash paid for income taxes ($1,246 million), a decrease in net cash used in working capital and other assets and liabilities ($590 million) and net cash provided by a change in collateral posted for financial commodity derivative contracts ($508 million), partially offset by a decrease in wellhead revenues ($5,420 million).

Net cash used in investing activities of $6,340 million in 2023 increased by $1,284 million from $5,056 million in 2022 primarily due to an increase in additions to oil and gas properties ($766 million); an increase in additions to other property, plant and equipment ($419 million) and a decrease in proceeds from the sales of assets ($209 million); partially offset by a decrease in net cash used in working capital associated with investing activities ($80 million) and a decrease in other investing activities ($30 million).

Net cash used in financing activities of $5,694 million in 2023 included cash dividend payments ($3,386 million), a repayment of long-term debt ($1,250 million), purchases of treasury stock ($1,038 million) and repayment of finance lease liabilities ($32 million). Cash provided by financing activities in 2023 included proceeds from stock options exercised and employee stock purchase plan activity ($20 million).

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Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2023, 2022 and 2021 (in millions):

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

(2)Leasehold acquisitions included $99 million, $127 million and $45 million related to non-cash property exchanges in 2023, 2022 and 2021, respectively.

(3)Property acquisitions included $6 million, $26 million and $5 million related to non-cash property exchanges in 2023, 2022 and 2021, respectively.

(4)Other property, plant and equipment in 2023 included $134 million related to the acquisition of a gathering and processing system in the Powder River Basin. Other property, plant and equipment in 2021 included non-cash additions of $74 million, primarily related to finance lease transactions for storage facilities.

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Exploration and development expenditures of $5,761 million for 2023 were $830 million higher than the prior year. The increase was primarily due to increased exploration and development drilling expenditures in the United States ($1,079 million), increased facility expenditures ($109 million) and increased exploration and development drilling expenditures in Trinidad ($51 million), partially offset by decreased property acquisitions ($403 million). 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 2022 exploration and development expenditures of $4,931 million included $3,962 million in development drilling and facilities, $514 million in exploration, $419 million in property acquisitions and $36 million in capitalized interest. The 2021 exploration and development expenditures of $3,842 million included $3,172 million in development drilling and facilities, $537 million in exploration, $100 million in property acquisitions and $33 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors.  EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant.  While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Financial Commodity Derivative Transactions

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2023 (closed) and remaining for 2024 and thereafter, as of February 16, 2024. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

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(1)    This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

Financing

EOG's debt-to-total capitalization ratio was 12% at December 31, 2023, compared to 17% at December 31, 2022.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2023 and 2022, respectively, EOG had outstanding $3,640 million and $4,890 million aggregate principal amount of senior notes, which had estimated fair values of $3,574 million and $4,740 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.

During 2023, EOG funded its capital program and operations by utilizing cash provided by operating activities and cash on hand.  While EOG maintains a $1.9 billion senior unsecured revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2023 and the amount outstanding at year-end was zero.  EOG considers the availability of its $1.9 billion senior unsecured revolving credit 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 and the relative competitive relationships of the various energy sources in the view of consumers, 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 2024 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 16, 2024, the average 2024 NYMEX crude oil and natural gas prices were $75.81 per barrel and $2.28 per MMBtu, respectively, representing a decrease of 2% for crude oil and a decrease of 17% for natural gas from the average NYMEX prices in 2023. 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.

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Based on EOG's tax position, EOG's price sensitivity in 2024 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $151 million for net income and $193 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 2024 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 wellhead natural gas price is approximately $27 million for net income and $35 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 16, 2024, see "Financial Commodity 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 its Delaware Basin, 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 lessen inflationary pressure through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2024 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

The total anticipated 2024 capital expenditures of approximately $6.0 billion to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses, 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 $1.9 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2024, crude oil and total crude oil equivalent production are expected to increase from 2023 levels. In 2024, EOG expects to continue to focus on mitigating inflationary pressure on operating costs through efficiency improvements.

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 2024, EOG anticipates the following cash requirements under these commitments (in millions):

(1)    For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 18 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, 2023. 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 more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

In 2024, EOG has no senior notes maturing and EOG expects to pay interest of $158 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 any unrecognized tax benefits, EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 7, and 15, respectively, to Consolidated Financial Statements) are excluded because they are subject to estimates and the timing of settlement is unknown.

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EOG expects to fund its exploration, development and exploitation activities and other cash requirements, both in 2024 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 its $1.9 billion senior unsecured revolving credit 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 recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

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 and continual reassessment of the viability of production under varying economic conditions.  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 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.  Lease rentals are expensed as incurred.

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When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group.  If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, 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 the Fair Value Measurement Topic of the ASC.  In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.  Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future.

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, 2023, WTI crude oil spot prices have fluctuated from approximately $(36.98) per barrel to $123.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.33 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.

See Notes 13 and 14 to Consolidated Financial Statements for further disclosures of impairments of oil and gas properties and other assets.

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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 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;

•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;

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•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 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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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 with proved reserves in the United States and Trinidad.  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 and capital costs 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.

EOG realized net income of $7,759 million during 2022 as compared to net income of $4,664 million for 2021. At December 31, 2022, EOG's total estimated net proved reserves were 4,238 million barrels of oil equivalent (MMBoe), an increase of 491 MMBoe from December 31, 2021.  During 2022, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 429 million barrels (MMBbl), and net proved natural gas reserves increased by 369 billion cubic feet or 62 MMBoe, in each case from December 31, 2021.

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 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 year ended December 31, 2022, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $94.23 per barrel and $6.64 per million British thermal units (MMBtu), respectively, representing increases of 39% and 72%, respectively, from the average NYMEX prices for the year ended December 31, 2021. 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.

The increases in crude oil and natural gas prices during 2022 were due to numerous factors, including the continued recovery in demand for crude oil, natural gas and NGLs from the impacts of the COVID-19 pandemic; low worldwide inventory levels; continued supply restraint by OPEC+ (a consortium of OPEC (Organization of Petroleum Exporting Countries) and certain non-OPEC global producers); and the impact resulting from the ongoing conflict between Russia and Ukraine.

Inflation Considerations; Availability of Materials, Labor & Services. Beginning in the second half of 2021 and continuing throughout 2022, EOG, similar to other companies in its industry, has experienced inflationary pressures on its operating and capital costs - namely the costs of fuel, steel (i.e., wellbore tubulars and facilities manufactured using steel), labor and drilling and completion services. Such inflationary pressures have resulted from (i) supply chain disruptions caused by the COVID-19 pandemic and the resulting limited availability of certain materials and products manufactured using such materials; (ii) increased demand for fuel and steel; (iii) increased demand for drilling and completion services coupled with a limited number of available service providers, resulting in increased competition for such services among EOG and other companies in its industry; (iv) labor shortages; and (v) other factors, including the ongoing conflict between Russia and the Ukraine which began in late February 2022.

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Such inflationary pressures on EOG's operating and capital costs have, in turn, impacted its cash flows and results of operations. However, by virtue of its continued focus on increasing its drilling, completion and operating efficiencies and improving the performance of its wells, as well as the flexibility provided by its multi-basin drilling portfolio, EOG has been able to largely offset such impacts. EOG currently expects such inflationary pressures to result in an increase of approximately 10 percent in its fiscal year 2023 well costs (i.e., its costs for drilling, completions and well-site facilities) versus fiscal year 2022. Accordingly, such expected increase in EOG's fiscal year 2023 well costs is not expected to have a material impact on EOG's full-year 2023 results of operations. Further, such inflationary pressures and the factors contributing to such inflationary pressures (described above) are not expected to impact EOG's liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.

The initiatives EOG has undertaken (and continues to undertake) to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, partially mitigate such inflationary pressures, 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; and (iii) EOG's self-sourced sand program, which has resulted in continued costs savings for the sand utilized in its well completion operations. In addition, EOG enters into agreements with its service providers from time to time, when available and advantageous, to secure the costs and availability of certain of the drilling and completion 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 offset, largely or at all, the impacts of any future inflationary pressures on EOG's operating and capital costs, cash flows and results of operations. Further, there can be no assurance that the factors contributing to any future inflationary pressures 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.

Climate Change. For a 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. EOG will continue to monitor and assess any climate change-related developments 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.

Operations

Several important developments have occurred since January 1, 2022.

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 2022, EOG continued to focus on increasing drilling, completion and operating efficiencies, to improve well performance and, as is further discussed above, to partially mitigate inflationary pressures on its operating and capital costs. 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 75% of EOG's United States production during both 2022 and 2021. During 2022, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico and Texas. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2022 United States operations.

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Trinidad. In the Republic of Trinidad and Tobago (Trinidad), EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, 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 its subsidiary (NGC), and crude oil and condensate which is sold to Heritage Petroleum Company Limited (Heritage), with the exception of the Modified U(b) Block in which the company ceased to have an interest in the production of natural gas and crude oil and condensate in the fourth quarter of 2022. In July 2022, EOG amended the natural gas sales contract with NGC to extend the term and provide for an increase in price realizations if index prices for certain commodities exceed specified levels. The pricing component of this amendment was effective September 2020.

In March 2021, EOG signed a farmout agreement with Heritage, which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast of Trinidad. In 2022, EOG drilled one net exploratory well, which was determined to be unsuccessful.

Also in 2022, EOG completed the design, fabrication and installation of a platform and related facilities for its previously announced discovery in the Modified U(a) Block. Additionally in 2022, EOG completed the drilling of, and put on production, two net exploratory wells from a pre-existing platform in the Modified U(a) Block. In 2023, EOG expects to complete three developmental and two exploratory wells in the Modified U(a) Block. Additionally, EOG expects to make progress on the design and construction of a platform and related facilities 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. In 2022, EOG continued preparing for the drilling of an exploration well, the timing of which will depend on obtaining regulatory approvals and subsequent equipment availability.

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

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 17% at December 31, 2022 and 19% at December 31, 2021.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

During 2022, EOG funded $5.3 billion ($153 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations) and paid $5.1 billion in dividends to common stockholders, primarily by utilizing net cash provided from its operating activities.

Total anticipated 2023 capital expenditures are estimated to range from approximately $5.8 billion to $6.2 billion, excluding acquisitions, non-cash transactions and exploration costs. The majority of 2023 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 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.

Cash Return Framework. On May 5, 2022, EOG announced the addition of quantitative guidance to its cash return framework - specifically, a commitment to return a minimum of 60% 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 related discussion regarding our payment of dividends, see ITEM 1A, Risk Factors, and ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, of EOG's Annual Report on Form 10-K for the year ended December 31, 2022, filed on February 23, 2023 (EOG's 2022 Annual Report).

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Dividend Declarations. On February 24, 2022, EOG's Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.75 per share paid on April 29, 2022, to stockholders of record as of April 15, 2022. The Board also declared on such date a special dividend of $1.00 per share paid on March 29, 2022, to stockholders of record as of March 15, 2022.

On May 5, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share paid on July 29, 2022, to stockholders of record as of July 15, 2022. The Board also declared on such date a special dividend of $1.80 per share paid on June 30, 2022, to stockholders of record as of June 15, 2022.

On August 4, 2022, the Board declared a special dividend on the common stock of $1.50 per share paid on September 29, 2022, to stockholders of record as of September 15, 2022.

On September 29, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share paid on October 31, 2022, to stockholders of record as of October 17, 2022.

On November 3, 2022, the Board (i) increased the quarterly cash dividend on the common stock from the previous $0.75 per share to $0.825 per share, effective beginning with the dividend paid on January 31, 2023, to stockholders of record as of January 17, 2023, and (ii) declared a special cash dividend on the common stock of $1.50 per share, paid on December 30, 2022, to stockholders of record as of December 15, 2022.

On February 23, 2023, the Board declared a quarterly cash dividend on the common stock of $0.825 per share to be paid on April 28, 2023, to stockholders of record as of April 14, 2023. The Board also declared on such date a special dividend on the common stock of $1.00 per share to be paid on March 30, 2023, to stockholders of record as of March 16, 2023.

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2022, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Operating Revenues and Other

During 2022, operating revenues increased $7,060 million, or 38%, to $25,702 million from $18,642 million in 2021. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $7,415 million, or 48%, to $22,796 million in 2022 from $15,381 million in 2021. Revenues from the sales of crude oil and condensate and NGLs in 2022 were approximately 83% of total wellhead revenues compared to 84% in 2021. During 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $3,982 million compared to net losses of $1,152 million in 2021. Gathering, processing and marketing revenues increased $2,408 million during 2022, to $6,696 million from $4,288 million in 2021. EOG recognized net gains on asset dispositions of $74 million in 2022 compared to net gains on asset dispositions of $17 million in 2021.

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Wellhead volume and price statistics for the years ended December 31, 2022, 2021 and 2020 were as follows:

(1)    Thousand barrels per day or million cubic feet per day, as applicable.

(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.

(3)Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).

(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.

(5)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contact with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

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2022 compared to 2021. Wellhead crude oil and condensate revenues in 2022 increased $5,242 million, or 47%, to $16,367 million from $11,125 million in 2021, due primarily to a higher composite average wellhead crude oil and condensate price ($4,831 million) and an increase in production ($411 million). EOG's composite wellhead crude oil and condensate price for 2022 increased 42% to $97.21 per barrel compared to $68.50 per barrel in 2021. Wellhead crude oil and condensate production in 2022 increased 4% to 461 MBbld as compared to 445 MBbld in 2021. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play and the Rocky Mountain area.

NGLs revenues in 2022 increased $836 million, or 46%, to $2,648 million from $1,812 million in 2021 primarily due to an increase in production ($666 million) and a higher composite average wellhead NGLs price ($170 million). EOG's composite average wellhead NGLs price increased 7% to $36.70 per barrel in 2022 compared to $34.35 per barrel in 2021. NGLs production in 2022 increased 37% to 198 MBbld as compared to 145 MBbld in 2021. The increased production was primarily in the Permian Basin.

Wellhead natural gas revenues in 2022 increased $1,337 million, or 55%, to $3,781 million from $2,444 million in 2021, primarily due to a higher composite wellhead natural gas price ($1,234 million) and an increase in natural gas deliveries ($103 million). EOG's composite average wellhead natural gas price increased 49% to $6.93 per Mcf in 2022 compared to $4.66 per Mcf in 2021. Natural gas deliveries in 2022 increased 4% to 1,495 MMcfd as compared to 1,436 MMcfd in 2021. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher deliveries in the Dorado gas play, partially offset by lower natural gas volumes due to the sale of certain legacy natural gas assets in the Rocky Mountain area in the first quarter of 2022, lower natural gas volumes in Trinidad and decreased production of associated natural gas from the Eagle Ford play.

During 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $3,982 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $3,501 million. During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $1,152 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $638 million.

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 in 2022 increased $46 million compared to 2021, primarily due to higher margins on natural gas marketing activities, partially offset by lower margins on crude oil and condensate marketing activities.

2021 compared to 2020. Wellhead crude oil and condensate revenues in 2021 increased $5,339 million, or 92%, to $11,125 million from $5,786 million in 2020, due primarily to a higher composite average wellhead crude oil and condensate price ($4,852 million) and an increase in production ($487 million). EOG's composite wellhead crude oil and condensate price for 2021 increased 77% to $68.50 per barrel compared to $38.63 per barrel in 2020. Wellhead crude oil and condensate production in 2021 increased 9% to 445 MBbld as compared to 409 MBbld in 2020. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play.

NGLs revenues in 2021 increased $1,144 million, or 171%, to $1,812 million from $668 million in 2020 primarily due to a higher composite average wellhead NGLs price ($1,104 million) and an increase in production ($40 million). EOG's composite average wellhead NGLs price increased 156% to $34.35 per barrel in 2021 compared to $13.41 per barrel in 2020. NGLs production in 2021 increased 6% to 145 MBbld as compared to 136 MBbld in 2020. The increased production was primarily in the Permian Basin.

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Wellhead natural gas revenues in 2021 increased $1,607 million, or 192%, to $2,444 million from $837 million in 2020, primarily due to a higher composite wellhead natural gas price ($1,486 million) and an increase in natural gas deliveries ($121 million). EOG's composite average wellhead natural gas price increased 155% to $4.66 per Mcf in 2021 compared to $1.83 per Mcf in 2020. Natural gas deliveries in 2021 increased 15% to 1,436 MMcfd as compared to 1,252 MMcfd in 2020. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas volumes in Trinidad, partially offset by lower natural gas volumes associated with the dispositions of the Marcellus Shale assets in the third quarter of 2020 and the China assets in the second quarter of 2021.

During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $1,152 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $638 million. During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million, which included net cash received from settlements of crude oil, NGLs and natural gas financial derivative contracts of $1,071 million.

Gathering, processing and marketing revenues less marketing costs in 2021 increased $230 million compared to 2020, primarily due to higher margins on crude oil and condensate and natural gas marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May and June 2020 deliveries under fixed price arrangements.

Operating and Other Expenses

2022 compared to 2021.  During 2022, operating expenses of $15,736 million were $3,196 million higher than the $12,540 million incurred during 2021.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2022 and 2021:

(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, transportation costs, gathering and processing costs, DD&A and G&A for 2022 compared to 2021 are set forth below.  See "Operating Revenues and Other" above for a discussion of production volumes.

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Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property.  Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses.  Operating and maintenance costs include, among other things, pumping services, produced water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power.  Workovers are operations to restore or maintain production from existing wells.

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

Lease and well expenses of $1,331 million in 2022 increased $196 million from $1,135 million in 2021 primarily due to higher operating and maintenance costs in the United States ($172 million) and higher workovers expenditures in the United States ($27 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease or an aggregation point on EOG's gathering system to a downstream point of sale.  Transportation costs include transportation fees, storage and terminal fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $966 million in 2022 increased $103 million from $863 million in 2021 primarily due to increased transportation costs related to production from the Permian Basin ($98 million), the Eagle Ford play ($10 million) and the Dorado gas play ($7 million), partially offset by decreased transportation costs related to production from the Rocky Mountain area ($8 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees and certain NGLs fractionation fees paid to third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

Gathering and processing costs increased $62 million to $621 million in 2022 compared to $559 million in 2021 primarily due to increased gathering and processing fees related to production from the Permian Basin ($66 million) and increased operating and maintenance expenses related to production from the Permian Basin ($43 million) and the Eagle Ford play ($7 million), partially offset by decreased gathering and processing fees related to production from the Eagle Ford play ($30 million) and due to the sale of certain legacy natural gas assets in the Rocky Mountain area in the first quarter of 2022 ($28 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 2022 decreased $109 million to $3,542 million from $3,651 million in 2021.  DD&A expenses associated with oil and gas properties in 2022 were $117 million lower than in 2021 primarily due to lower unit rates in the United States ($472 million) and lower production in Trinidad ($15 million), partially offset by an increase in production in the United States ($375 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to higher average crude oil, NGLs and natural gas prices used in the prior year's reserve estimation process and to reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $570 million in 2022 increased $59 million from $511 million in 2021 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses, and professional and other services.

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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. When circumstances indicate that a proved property 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 estimates 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, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  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, 2022 and 2021 (in millions):

Impairments of unproved oil and gas properties included charges of $38 million in 2021 due to the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

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 in 2022 increased $538 million to $1,585 million (7.0% of wellhead revenues) from $1,047 million (6.8% of wellhead revenues) in 2021. The increase in taxes other than income was primarily due to increased severance/production taxes ($514 million), increased ad valorem/property taxes ($130 million) and increased payroll taxes ($7 million), partially offset by increased state severance tax refunds ($119 million), all in the United States.

Other income, net, was $114 million in 2022 compared to other income, net, of $9 million in 2021. The increase of $105 million in 2022 was primarily due to an increase in interest income ($81 million) and higher equity income from ammonia plants in Trinidad ($28 million).

EOG recognized an income tax provision of $2,142 million in 2022 compared to an income tax provision of $1,269 million in 2021, primarily due to increased pretax income. The net effective tax rate for 2022 increased to 22% from 21% in 2021.

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2021 compared to 2020.  During 2021, operating expenses of $12,540 million were $964 million lower than the $11,576 million incurred during 2020.  The following table presents the costs per Boe for the years ended December 31, 2021 and 2020:

(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, transportation costs, gathering and processing costs, DD&A, G&A and net interest expense for 2021 compared to 2020 are set forth below.  See "Operating Revenues and Other" above for a discussion of production volumes.

Lease and well expenses of $1,135 million in 2021 increased $72 million from $1,063 million in 2020 primarily due to higher operating and maintenance costs in the United States ($33 million) and in Trinidad ($5 million), higher workovers expenditures in the United States ($25 million) and higher lease and well administrative expenses in the United States ($12 million); partially offset by lower operating and maintenance costs in Canada ($6 million) and as a result of the disposition of all of the China assets in the second quarter of 2021 ($5 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

Transportation costs of $863 million in 2021 increased $128 million from $735 million in 2020 primarily due to increased transportation costs in the Permian Basin ($121 million) and the Rocky Mountain area ($22 million), partially offset by decreased transportation costs in the Eagle Ford play ($13 million).

Gathering and processing costs increased $100 million to $559 million in 2021 compared to $459 million in 2020 primarily due to increased gathering and processing fees related to production from the Permian Basin ($51 million) and the Rocky Mountain area ($10 million), increased operating costs in the Permian Basin ($26 million) and the Rocky Mountain area ($7 million) and increased administrative expenses in the United States ($15 million); partially offset by decreased gathering and processing fees in the Eagle Ford play ($5 million).

DD&A expenses in 2021 increased $251 million to $3,651 million from $3,400 million in 2020. DD&A expenses associated with oil and gas properties in 2021 were $235 million higher than in 2020 primarily due to an increase in production in the United States ($307 million) and Trinidad ($12 million) and higher unit rates in Trinidad ($14 million), partially offset by lower unit rates in the United States ($85 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies. DD&A expenses associated with other property, plant and equipment in 2021 were $15 million higher than in 2020 primarily due to an increase in expense related to storage assets.

G&A expenses of $511 million in 2021 increased $27 million from $484 million in 2020 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and increased information system costs ($54 million); partially offset by a decrease in idle equipment and termination fees ($46 million).

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Net interest expense of $178 million in 2021 was $27 million lower than 2020 primarily due to repayment in February 2021 of the $750 million aggregate principal amount of 4.100% Senior Notes due 2021 ($29 million), repayment in June 2020 of the $500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($9 million), repayment in April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($3 million) and lower interest payments for late royalty payments on Oklahoma properties ($6 million), partially offset by the issuance in April 2020 of the $750 million aggregate principal amount of 4.950% Senior Notes due 2050 ($11 million) and $750 million aggregate principal amount of 4.375% Senior Notes due 2030 ($10 million).

Exploration costs of $154 million in 2021 increased $8 million from $146 million in 2020 primarily due to increased geological and geophysical expenditures in the United States.

The following table represents impairments for the years ended December 31, 2021 and 2020 (in millions):

Impairments of proved properties in 2020 were primarily due to the decline in commodity prices and were primarily related to the write-down to fair value of legacy and non-core natural gas, crude oil and combo plays in the United States. Impairments of unproved oil and gas properties included charges of $38 million in 2021 due to the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman and $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. Impairments of other assets in 2020 were primarily for the write-down to fair value of sand and crude-by-rail assets and a commodity price-related write-down of other assets. Impairments of firm commitment contracts in 2020 were a result of the decision to exit the Horn River Basin in Canada.

Taxes other than income in 2021 increased $569 million to $1,047 million (6.8% of wellhead revenues) from $478 million (6.6% of wellhead revenues) in 2020. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($522 million), increased severance/production taxes in Trinidad ($7 million) and decreased state severance tax refunds ($39 million).

EOG recognized an income tax provision of $1,269 million in 2021 compared to an income tax benefit of $134 million in 2020, primarily due to increased pretax income. The net effective tax rate for 2021 increased to 21% from 18% in 2020. The higher effective tax rate is mostly due to taxes attributable to EOG's foreign operations and stock-based compensation tax deficiencies increasing the effective tax rate on pretax income in 2021 and decreasing the effective tax rate on pretax loss in 2020.

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Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2022, were funds generated from operations and proceeds from asset sales.  The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; net repayment of debt; net cash paid for settlements of financial commodity derivative contracts; other property, plant and equipment expenditures; and net collateral posted for financial commodity derivative contracts.

2022 compared to 2021.  Net cash provided by operating activities of $11,093 million in 2022 increased $2,302 million from $8,791 million in 2021 primarily due to an increase in wellhead revenues ($7,415 million), partially offset by an increase in net cash paid for settlements of financial commodity derivative contracts ($2,863 million); an increase in net cash paid for income taxes ($1,361 million); and an increase in cash operating expenses ($982 million).

Net cash used in investing activities of $5,056 million in 2022 increased by $1,637 million from $3,419 million in 2021 primarily due to an increase in additions to oil and gas properties ($981 million), net cash used in working capital associated with investing activities in 2022 ($375 million) compared to net cash provided by working capital associated with investing activities in 2021 ($200 million); an increase in additions to other property, plant and equipment ($169 million); and an increase in other investing activities ($30 million), partially offset by an increase in proceeds from the sales of assets ($118 million).

Net cash used in financing activities of $5,273 million in 2022 included cash dividend payments ($5,148 million), purchases of treasury stock in connection with stock compensation plans ($118 million) and repayment of finance lease liabilities ($35 million). Cash provided by financing activities in 2022 included proceeds from stock options exercised and employee stock purchase plan activity ($28 million).

2021 compared to 2020. Net cash provided by operating activities of $8,791 million in 2021 increased $3,783 million from $5,008 million in 2020 primarily due to an increase in wellhead revenues ($8,090 million) and an increase in gathering, processing and marketing revenues less marketing costs ($230 million); partially offset by an increase in net cash paid for settlements of financial commodity derivative contracts ($1,709 million); an increase in net cash paid for income taxes ($1,320 million); net cash used in working capital in 2021 ($817 million) compared to net cash provided by working capital in 2020 ($193 million); and an increase in cash operating expenses ($882 million).

Net cash used in investing activities of $3,419 million in 2021 increased by $71 million from $3,348 million in 2020 primarily due to an increase in additions to oil and gas properties ($394 million), partially offset by net cash provided by working capital associated with investing activities in 2021 ($200 million) compared to net cash used in working capital associated with investing activities in 2020 ($75 million); an increase in proceeds from the sales of assets ($39 million); and a decrease in additions to other property, plant and equipment ($9 million).

Net cash used in financing activities of $3,493 million in 2021 included cash dividend payments ($2,684 million), repayments of long-term debt ($750 million), purchases of treasury stock in connection with stock compensation plans ($41 million) and repayment of finance lease liabilities ($37 million). Cash provided by financing activities in 2021 included proceeds from stock options exercised and employee stock purchase plan activity ($19 million).

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Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2022, 2021 and 2020 (in millions):

(1)Leasehold acquisitions included $127 million, $45 million and $197 million related to non-cash property exchanges in 2022, 2021 and 2020, respectively.

(2)Property acquisitions included $26 million, $5 million and $15 million related to non-cash property exchanges in 2022, 2021 and 2020, respectively.

(3)Other property, plant and equipment included non-cash additions of $74 million and $174 million, primarily related to finance lease transactions for storage facilities in 2021 and 2020, respectively.

Exploration and development expenditures of $4,931 million for 2022 were $1,089 million higher than the prior year. The increase was primarily due to increased exploration and development drilling expenditures in the United States ($763 million) and increased property acquisitions ($319 million). The 2022 exploration and development expenditures of $4,931 million included $3,962 million in development drilling and facilities, $514 million in exploration, $419 million in property acquisitions and $36 million in capitalized interest. The 2021 exploration and development expenditures of $3,842 million included $3,172 million in development drilling and facilities, $537 million in exploration, $100 million in property acquisitions and $33 million in capitalized interest. The 2020 exploration and development expenditures of $3,601 million included $2,905 million in development drilling and facilities, $530 million in exploration, $135 million in property acquisitions and $31 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors.  EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant.  While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

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Financial Commodity Derivative Transactions

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2022 (closed) and remaining for 2023 and thereafter, as of February 16, 2023. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

_________________

(1)    In the second quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October 2022 - December 2023 crude oil financial price swap contracts which were open at that time. EOG paid net cash of $593 million for the settlement of these contracts.

(2)    In the third quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its January 2023 - March 2023 crude oil financial price swap contracts which were open at that time. EOG paid net cash of $63 million for the settlement of these contracts.

_________________

(1)    This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.

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_________________

(1)    In the second quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October 2022 - December 2023 natural gas financial price swap contracts which were open at that time. EOG paid net cash of $735 million for the settlement of these contracts.

_________________

(1)    This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

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Financing

EOG's debt-to-total capitalization ratio was 17% at December 31, 2022, compared to 19% at December 31, 2021.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At both December 31, 2022 and 2021, EOG had outstanding $4,890 million aggregate principal amount of senior notes which had estimated fair values of $4,740 million and $5,577 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.

During 2022, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities and cash on hand.  While EOG maintains a $2.0 billion revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2022 and the amount outstanding at year-end was zero.  EOG considers the availability of its $2.0 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

Foreign Currency Exchange Rate Risk

During 2022, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, Australia, Oman and Canada.  EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against foreign currency exchange rate risk.

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 availabilities of other energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, 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 2023 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 16, 2023, the average 2023 NYMEX crude oil and natural gas prices were $75.99 per barrel and $3.05 per MMBtu, respectively, representing a decrease of 19% for crude oil and a decrease of 54% for natural gas from the average NYMEX prices in 2022. 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.

Including the impact of EOG's crude oil and NGLs financial derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2023 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $137 million for net income and $175 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 2023 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 wellhead natural gas price is approximately $35 million for net income and $44 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 16, 2023, see "Financial Commodity 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 its Delaware Basin, Eagle Ford play, Rocky Mountain area and Dorado gas 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 lessen inflationary pressure through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2023 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

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The total anticipated 2023 capital expenditures of approximately $5.8 billion to $6.2 billion, excluding acquisitions, non-cash transactions and exploration costs, 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 $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2023, crude oil and total crude oil equivalent production are expected to increase from 2022 levels. In 2023, EOG expects to continue to focus on mitigating inflationary pressure on operating costs through efficiency improvements.

Cash Requirements. Certain of EOG's capital expenditures and operating expenses are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASC "Leases (Topic 842)". In 2023, EOG anticipates the following cash requirements under these commitments (in millions):

(1)    For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 18 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, 2022. 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 more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

In 2023, EOG has $1.25 billion of senior notes maturing, which are expected to be repaid with cash on hand. Additionally, in 2023, EOG expects to pay interest of $175 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 unrecognized tax benefits, EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 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 and other cash requirements, both in 2023 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 its $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.

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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 recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

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 and continual reassessment of the viability of production under varying economic conditions.  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."

Oil and Gas Exploration and Development Costs

EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves.  If commercial quantities of proved reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.  The concept of sufficient progress is subject to significant judgment and may require further operational actions or require additional approvals from government agencies or partners in oil and gas operations, among other factors, the timing of which may delay management's determinations. See Note 16 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.

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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 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.  Lease rentals are expensed as incurred.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group.  If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, 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 the Fair Value Measurement Topic of the ASC.  In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.  Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future.

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, 2022, WTI crude oil spot prices have fluctuated from approximately $(36.98) per barrel to $123.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.33 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.

See Notes 13 and 14 to Consolidated Financial Statements for further disclosures of impairments of oil and gas properties and other assets.

Income Taxes

Income taxes are accounted for using the asset and liability approach.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis.  EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate.  Significant assumptions used in estimating future taxable income include future crude oil, NGLs and natural gas prices and levels of capital reinvestment.  Changes in such assumptions or changes in tax laws and regulations could materially affect the recognized amounts of valuation allowances. See Note 6 to Consolidated Financial Statements.

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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, 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, or pay and/or increase dividends 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;

•the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, 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;

•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;

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•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 ad 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, 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 conflict), 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 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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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 with proved reserves in the United States and Trinidad.  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 and capital costs 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 deliver 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 $4,664 million during 2021 as compared to a net loss of $605 million for 2020. At December 31, 2021, EOG's total estimated net proved reserves were 3,747 million barrels of oil equivalent (MMBoe), an increase of 527 MMBoe from December 31, 2020.  During 2021, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 50 million barrels (MMBbl), and net proved natural gas reserves increased by 2,862 billion cubic feet or 477 MMBoe, in each case from December 31, 2020.

Recent Developments

Commodity Prices. In 2020, the COVID-19 pandemic and the measures taken to address and limit the spread of the virus adversely affected the economies and financial markets of the world, resulting in an economic downturn beginning in early 2020 that negatively impacted global demand and prices for crude oil and condensate, NGLs and natural gas. In response, OPEC+, a consortium of OPEC (Organization of Petroleum Exporting Countries) and certain non-OPEC global producers (Russia, Kazakhstan and others), agreed to voluntarily curtail crude oil supplies beginning in April 2020 with a schedule to bring back some of these curtailments through April 2021. Certain other non-OPEC+ countries also curtailed production and/or reduced investments in existing and new crude oil projects. This response started the process of balancing supply with demand.

In 2021, the effects of global COVID-19 mitigation efforts, including extensive global fiscal stimulus and the availability of vaccines, tempered by new COVID-19 variant strains and corresponding containment measures in certain parts of the world, have resulted in overall increased demand for crude oil and condensate, NGLs and natural gas. See ITEM 1A, Risk Factors for discussion of risks related to the COVID-19 pandemic.

During 2021 and into early 2022, OPEC+ continued their schedule of gradually returning all curtailed production through 2022 in response to expected increases in demand for crude oil. The continuing rebalancing of crude oil demand and supply resulting from improving or stabilizing conditions in certain economies and financial markets of the world, combined with the continuing actions taken by OPEC+, had a positive impact on crude oil prices in 2021. Prices for crude oil and condensate and NGLs returned to prepandemic levels in the first quarter of 2021, while natural gas prices returned to pre-pandemic levels at the beginning of 2021.

As a result of the many uncertainties associated with (i) the world economic and political environment, (ii) the COVID-19 pandemic and its continuing effect on the economies and financial markets of the world and (iii) any future actions by the members of OPEC+, and the effect of these uncertainties on worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs and natural gas prices in the future. However, prices for crude oil and condensate, NGLs and natural gas have historically been volatile, and this volatility is expected to continue. For related discussion, see ITEM 1A, Risk Factors.

EOG will continue to monitor future market conditions and adjust its capital allocation strategy and production outlook accordingly in order to maximize shareholder value while maintaining its strong financial position.

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Climate Change. For a 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. EOG will continue to monitor and assess any climate change-related developments 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.

Operations

Several important developments have occurred since January 1, 2021.

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, to a lesser extent, liquids-rich natural gas plays.

During 2021, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. Such efficiencies resulted in lower operating, drilling and completion costs in 2021. 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 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 75% and 76% of United States production during 2021 and 2020, respectively. During 2021, drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford oil play and Rocky Mountain area. EOG's major producing areas in the United States are in Texas and New Mexico. EOG faced interruptions to sales in certain markets due to disruptions throughout the United States from Winter Storm Uri in the first quarter of 2021. Winter Storm Uri also negatively impacted Lease and Well, Transportation and Gathering and Processing Costs in the first quarter of 2021. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2021 United States operations.

Trinidad. In the Republic of Trinidad and Tobago (Trinidad), EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, 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 its subsidiary, and crude oil and condensate which is sold to Heritage Petroleum Company Limited (Heritage).

In March 2021, EOG signed a farmout agreement with Heritage, which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast of Trinidad. EOG continues to make progress on the design and fabrication of a platform and related facilities for its previously announced discovery in the Modified U(a) Block.

In 2022, EOG expects to drill one net exploratory well in the EOG Area in addition to three development wells and one exploratory well in the Modified U(a) Block.

Other International. In Australia, on April 22, 2021, a subsidiary of EOG entered into a purchase and sale agreement to acquire a 100% interest in the WA-488-P Block, located offshore Western Australia. The transaction was closed in the fourth quarter of 2021 including the transfer of the petroleum exploration permit for that block. In 2022, EOG will continue preparing for the drilling of an exploration well which is expected to commence in 2023.

In the Sultanate of Oman (Oman), a Royal Decree was issued on March 9, 2021, and EOG became a participant in the Exploration and Production Sharing Agreement for Block 49, holding a 50% working interest. EOG's partner in Block 49 completed the drilling and testing of one net exploratory well, which was determined to be a dry hole. EOG notified its partner and the Ministry of Energy and Minerals of its intention to withdraw from Block 49. In Block 36, where EOG holds a 100% working interest, EOG drilled two net exploratory wells and completed one net exploratory well. There was a discovery of natural gas in Block 36, but the well results did not yield sufficient projected returns for EOG to move forward with the project. EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021. In 2022, EOG expects to exit Block 36.

In May 2021, EOG closed the sale of its subsidiary which held all of its assets in the China Sichuan Basin (China). Net production was approximately 25 million cubic feet per day (MMcfd) of natural gas prior to the sale. EOG no longer has any operations or assets in China.

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

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 19% at December 31, 2021 and 22% at December 31, 2020.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On February 1, 2021, EOG repaid upon maturity the $750 million aggregate principal amount of its 4.100% Senior Notes due 2021 (2021 Notes).

During 2021, EOG funded $4.1 billion ($124 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2,684 million in dividends to common stockholders and repaid the 2021 Notes, primarily by utilizing net cash provided from its operating activities and net proceeds of $231 million from the sale of assets.

Total anticipated 2022 capital expenditures are estimated to range from approximately $4.3 billion to $4.7 billion, excluding acquisitions and non-cash transactions. The majority of 2022 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 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.

Dividend Declarations and Share Repurchase Authorization. On February 25, 2021, EOG's Board increased the quarterly cash dividend on the common stock from the previous $0.375 per share to $0.4125 per share, effective beginning with the dividend paid on April 30, 2021, to stockholders of record as of April 16, 2021.

On May 6, 2021, EOG's Board declared a special cash dividend on the common stock of $1.00 per share. The special cash dividend, which was in addition to the quarterly cash dividend, was paid on July 30, 2021 to stockholders of record as of July 16, 2021.

On November 4, 2021, EOG's Board (i) further increased the quarterly cash dividend on the common stock from the previous $0.4125 per share to $0.75 per share, effective beginning with the dividend paid on January 28, 2022, to stockholders of record as of January 14, 2022, (ii) declared a special cash dividend on the common stock of $2.00 per share, paid on December 30, 2021, to stockholders of record as of December 15, 2021, (iii) established a new share repurchase authorization to allow for the repurchase by EOG of up to $5 billion of the common stock and (iv) revoked and terminated the share repurchase authorization established by the Board in September 2001. See ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities for additional discussion.

On February 24, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share payable April 29, 2022, to stockholders of record as of April 15, 2022. The Board also declared a special dividend of $1.00 per share payable March 29, 2022, to stockholders of record as of March 15, 2022.

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Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2021, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Operating Revenues and Other

During 2021, operating revenues increased $7,610 million, or 69%, to $18,642 million from $11,032 million in 2020. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $8,090 million, or 111%, to $15,381 million in 2021 from $7,291 million in 2020. Revenues from the sales of crude oil and condensate and NGLs in 2021 were approximately 84% of total wellhead revenues compared to 89% in 2020. During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $1,152 million compared to net gains of $1,145 million in 2020. Gathering, processing and marketing revenues increased $1,705 million during 2021, to $4,288 million from $2,583 million in 2020. EOG recognized net gains on asset dispositions of $17 million in 2021 compared to net losses on asset dispositions of $47 million in 2020.

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Wellhead volume and price statistics for the years ended December 31, 2021, 2020 and 2019 were as follows:

(1)    Thousand barrels per day or million cubic feet per day, as applicable.

(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.

(3)Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).

(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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2021 compared to 2020. Wellhead crude oil and condensate revenues in 2021 increased $5,339 million, or 92%, to $11,125 million from $5,786 million in 2020, due primarily to a higher composite average wellhead crude oil and condensate price ($4,852 million) and an increase in production ($487 million). EOG's composite wellhead crude oil and condensate price for 2021 increased 77% to $68.50 per barrel compared to $38.63 per barrel in 2020. Wellhead crude oil and condensate production in 2021 increased 9% to 445 MBbld as compared to 409 MBbld in 2020. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford oil play.

NGLs revenues in 2021 increased $1,144 million, or 171%, to $1,812 million from $668 million in 2020 primarily due to a higher composite average wellhead NGLs price ($1,104 million) and an increase in production ($40 million). EOG's composite average wellhead NGLs price increased 156% to $34.35 per barrel in 2021 compared to $13.41 per barrel in 2020. NGL production in 2021 increased 6% to 145 MBbld as compared to 136 MBbld in 2020. The increased production was primarily in the Permian Basin.

Wellhead natural gas revenues in 2021 increased $1,607 million, or 192%, to $2,444 million from $837 million in 2020, primarily due to a higher composite wellhead natural gas price ($1,486 million) and an increase in natural gas deliveries ($121 million). EOG's composite average wellhead natural gas price increased 155% to $4.66 per Mcf in 2021 compared to $1.83 per Mcf in 2020. Natural gas deliveries in 2021 increased 15% to 1,436 MMcfd as compared to 1,252 MMcfd in 2020. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas volumes in Trinidad, partially offset by lower natural gas volumes associated with the dispositions of the Marcellus Shale assets in the third quarter of 2020 and the China assets in the second quarter of 2021.

During 2021, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $1,152 million, which included net cash paid for settlements of crude oil, NGL and natural gas financial derivative contracts of $638 million. During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million, which included net cash received from settlements of crude oil, NGL and natural gas financial derivative contracts of $1,071 million.

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 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 in 2021 increased $230 million compared to 2020, primarily due to higher margins on crude oil and condensate and natural gas marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May and June 2020 deliveries under fixed price arrangements.

2020 compared to 2019. Wellhead crude oil and condensate revenues in 2020 decreased $3,827 million, or 40%, to $5,786 million from $9,613 million in 2019, due primarily to a lower composite average wellhead crude oil and condensate price ($2,860 million) and a decrease in production ($967 million). EOG's composite wellhead crude oil and condensate price for 2020 decreased 33% to $38.63 per barrel compared to $57.72 per barrel in 2019. Wellhead crude oil and condensate production in 2020 decreased 10% to 409 MBbld as compared to 456 MBbld in 2019. The decreased production was primarily in the Eagle Ford oil play and the Rocky Mountain area, partially offset by increased production in the Permian Basin.

NGLs revenues in 2020 decreased $116 million, or 15%, to $668 million from $784 million in 2019 primarily due to a lower composite average wellhead NGLs price ($130 million), partially offset by an increase in production ($13 million). EOG's composite average wellhead NGLs price decreased 16% to $13.41 per barrel in 2020 compared to $16.03 per barrel in 2019. NGL production in 2020 increased 1% to 136 MBbld as compared to 134 MBbld in 2019. The increased production was primarily in the Permian Basin, partially offset by decreased production of associated NGLs in the Eagle Ford oil play.

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Wellhead natural gas revenues in 2020 decreased $347 million, or 29%, to $837 million from $1,184 million in 2019, primarily due to a lower composite wellhead natural gas price ($251 million) and a decrease in natural gas deliveries ($96 million). EOG's composite average wellhead natural gas price decreased 23% to $1.83 per Mcf in 2020 compared to $2.38 per Mcf in 2019. Natural gas deliveries in 2020 decreased 8% to 1,252 MMcfd as compared to 1,366 MMcfd in 2019. The decrease in production was primarily due to lower natural gas volumes in Trinidad, the Marcellus Shale and the Rocky Mountain area, partially offset by increased production of associated natural gas from the Permian Basin.

During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million, which included net cash received for settlements of crude oil, NGL and natural gas financial derivative contracts of $1,071 million. During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million, which included net cash received for settlements of crude oil and natural gas financial derivative contracts of $231 million.

Gathering, processing and marketing revenues less marketing costs in 2020 decreased $124 million compared to 2019, primarily due to lower margins on crude oil and condensate marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May and June 2020 deliveries under fixed price arrangements.

Operating and Other Expenses

2021 compared to 2020.  During 2021, operating expenses of $12,540 million were $964 million higher than the $11,576 million incurred during 2020.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2021 and 2020:

(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, transportation costs, gathering and processing costs, DD&A, G&A and net interest expense for 2021 compared to 2020 are set forth below.  See "Operating Revenues and Other" above for a discussion of production 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, salt 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.

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Lease and well expenses of $1,135 million in 2021 increased $72 million from $1,063 million in 2020 primarily due to higher operating and maintenance costs in the United States ($33 million) and in Trinidad ($5 million), higher workovers expenditures in the United States ($25 million) and higher lease and well administrative expenses in the United States ($12 million); partially offset by lower operating and maintenance costs in Canada ($6 million) and as a result of the disposition of all of the China assets in the second quarter of 2021 ($5 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease or an aggregation point on EOG's gathering system to a downstream point of sale.  Transportation costs include transportation fees, storage and terminal fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $863 million in 2021 increased $128 million from $735 million in 2020 primarily due to increased transportation costs in the Permian Basin ($121 million) and the Rocky Mountain area ($22 million), partially offset by decreased transportation costs in the Eagle Ford oil play ($13 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees and certain NGLs fractionation fees paid to third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

Gathering and processing costs increased $100 million to $559 million in 2021 compared to $459 million in 2020 primarily due to increased gathering and processing fees related to production from the Permian Basin ($51 million) and the Rocky Mountain area ($10 million), increased operating costs in the Permian Basin ($26 million) and the Rocky Mountain area ($7 million) and increased administrative expenses in the United States ($15 million); partially offset by decreased gathering and processing fees in the Eagle Ford oil play ($5 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 2021 increased $251 million to $3,651 million from $3,400 million in 2020.  DD&A expenses associated with oil and gas properties in 2021 were $235 million higher than in 2020 primarily due to an increase in production in the United States ($307 million) and Trinidad ($12 million) and higher unit rates in Trinidad ($14 million), partially offset by lower unit rates in the United States ($85 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies. DD&A expenses associated with other property, plant and equipment in 2021 were $15 million higher than in 2020 primarily due to an increase in expense related to storage assets.

G&A expenses of $511 million in 2021 increased $27 million from $484 million in 2020 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and increased information system costs ($54 million); partially offset by a decrease in idle equipment and termination fees ($46 million).

Net interest expense of $178 million in 2021 was $27 million lower than 2020 primarily due to repayment in February 2021 of the $750 million aggregate principal amount of 4.100% Senior Notes due 2021 ($29 million), repayment in June 2020 of the $500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($9 million), repayment in April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($3 million) and lower interest payments for late royalty payments on Oklahoma properties ($6 million), partially offset by the issuance in April 2020 of the $750 million aggregate principal amount of 4.950% Senior Notes due 2050 ($11 million) and $750 million aggregate principal amount of 4.375% Senior Notes due 2030 ($10 million).

Exploration costs of $154 million in 2021 increased $8 million from $146 million in 2020 primarily due to increased geological and geophysical expenditures in the United States.

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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. When circumstances indicate that a proved property 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 estimates 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, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  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, 2021 and 2020 (in millions):

Impairments of proved properties in 2020 were primarily due to the decline in commodity prices and were primarily related to the write-down to fair value of legacy and non-core natural gas, crude oil and combo plays in the United States. Impairments of unproved oil and gas properties included charges of $38 million in 2021 due to the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman and $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. Impairments of other assets in 2020 were primarily for the write-down to fair value of sand and crude-by-rail assets and a commodity price-related write-down of other assets. Impairments of firm commitment contracts in 2020 were a result of the decision to exit the Horn River Basin in Canada.

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 in 2021 increased $569 million to $1,047 million (6.8% of wellhead revenues) from $478 million (6.6% of wellhead revenues) in 2020. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($522 million), increased severance/production taxes in Trinidad ($7 million) and decreased state severance tax refunds ($39 million).

EOG recognized an income tax provision of $1,269 million in 2021 compared to an income tax benefit of $134 million in 2020, primarily due to increased pretax income. The net effective tax rate for 2021 increased to 21% from 18% in 2020. The higher effective tax rate is mostly due to taxes attributable to EOG's foreign operations and stock-based compensation tax deficiencies increasing the effective tax rate on pretax income in 2021 and decreasing the effective tax rate on pretax loss in 2020.

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2020 compared to 2019.  During 2020, operating expenses of $11,576 million were $2,105 million lower than the $13,681 million incurred during 2019.  The following table presents the costs per Boe for the years ended December 31, 2020 and 2019:

(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, transportation costs, gathering and processing costs, DD&A, G&A and net interest expense for 2020 compared to 2019 are set forth below.  See "Operating Revenues and Other" above for a discussion of production volumes.

Lease and well expenses of $1,063 million in 2020 decreased $304 million from $1,367 million in 2019 primarily due to lower operating and maintenance costs in the United States ($157 million) and in Canada ($25 million), lower workovers expenditures in the United States ($103 million) and lower lease and well administrative expenses in the United States ($12 million). Lease and well expenses decreased in the United States primarily due to decreased operating activities resulting from decreased production, efficiency improvements and service cost reductions.

Transportation costs of $735 million in 2020 decreased $23 million from $758 million in 2019 primarily due to decreased transportation costs in the Fort Worth Basin Barnett Shale ($27 million), the Rocky Mountain area ($24 million) and the Eagle Ford oil play ($20 million), partially offset by increased transportation costs in the Permian Basin ($56 million).

Gathering and processing costs decreased $20 million to $459 million in 2020 compared to $479 million in 2019 primarily due to decreased operating costs in the Eagle Ford ($16 million) and decreased gathering and processing fees in the Eagle Ford oil play ($9 million) and the Fort Worth Basin Barnett Shale ($5 million); partially offset by increased gathering and processing fees in the Permian Basin ($15 million).

DD&A expenses in 2020 decreased $350 million to $3,400 million from $3,750 million in 2019. DD&A expenses associated with oil and gas properties in 2020 were $390 million lower than in 2019 primarily due to a decrease in production in the United States ($222 million) and Trinidad ($22 million) and lower unit rates in the United States ($150 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies. DD&A expenses associated with other property, plant and equipment in 2020 were $40 million higher than in 2019 primarily due to an increase in expense related to gathering and storage assets and equipment.

G&A expenses of $484 million in 2020 decreased $5 million from $489 million in 2019 primarily due to decreased employee-related expenses ($43 million) and professional and other services ($7 million), partially offset by idle equipment and termination fees ($46 million).

Net interest expense of $205 million in 2020 was $20 million higher than 2019 primarily due to the issuance of the Notes in April 2020 ($51 million) and lower capitalized interest ($7 million), partially offset by repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($21 million), repayment in June 2020 of the $500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($13 million) and repayment in April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($10 million).

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Exploration costs of $146 million in 2020 increased $6 million from $140 million in 2019 primarily due to increased geological and geophysical expenditures in the United States ($15 million), partially offset by decreased general and administrative expenses in the United States ($8 million).

The following table represents impairments for the years ended December 31, 2020 and 2019 (in millions):

Impairments of proved properties were primarily due to the write-down to fair value of legacy and non-core natural gas and crude oil and combo plays in 2020 and legacy natural gas assets in 2019.

Taxes other than income in 2020 decreased $322 million to $478 million (6.6% of wellhead revenues) from $800 million (6.9% of wellhead revenues) in 2019. The decrease in taxes other than income was primarily due to decreased severance/production taxes in the United States ($232 million), decreased ad valorem/property taxes in the United States ($51 million) and a state severance tax refund ($27 million).

Other income, net, was $10 million in 2020 compared to other income, net, of $31 million in 2019. The decrease of $21 million in 2020 was primarily due to a decrease in interest income.

In response to the economic impacts of the COVID-19 pandemic, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act) into law on March 27, 2020. The CARES Act provides economic support to individuals and businesses through enhanced loan programs, expanded unemployment benefits, and certain payroll and income tax relief, among other provisions. The primary tax benefit of the CARES Act for EOG was the acceleration of approximately $150 million of additional refundable alternative minimum tax (AMT) credits into tax year 2019. These credits originated from AMT paid by EOG in years prior to 2018 and were reflected as a deferred tax asset and a non-current receivable as of December 31, 2019 since they had been expected to either offset future current tax liabilities or be refunded on a declining balance schedule through 2021. The $150 million of additional refundable AMT credits was received in July 2020.

Further pandemic relief was contained in the Consolidated Appropriations Act of 2021 (the CA Act) which was signed into law by the President of the United States on December 27, 2020. In addition, the CA Act provided government funding and limited corporate income tax relief primarily related to making permanent or extending certain tax provisions, none of which were a material benefit for EOG.

EOG recognized an income tax benefit of $134 million in 2020 compared to an income tax provision of $810 million in 2019, primarily due to decreased pretax income. The net effective tax rate for 2020 decreased to 18% from 23% in 2019. The lower effective tax rate is mostly due to taxes attributable to EOG's foreign operations and increased stock-based compensation tax deficiencies.

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Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2021, were funds generated from operations, net proceeds from the issuance of long-term debt, net cash received from settlements of commodity derivative contracts and proceeds from asset sales.  The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; repayments of debt; net cash paid for settlements of commodity derivative contracts and other property, plant and equipment expenditures.

2021 compared to 2020.  Net cash provided by operating activities of $8,791 million in 2021 increased $3,783 million from $5,008 million in 2020 primarily due to an increase in wellhead revenues ($8,090 million) and an increase in gathering, processing and marketing revenues less marketing costs ($230 million); partially offset by an increase in net cash paid for settlements of commodity derivative contracts ($1,709 million); an increase in net cash paid for income taxes ($1,320 million); net cash used in working capital in 2021 ($817 million) compared to net cash provided by working capital in 2020 ($193 million); and an increase in cash operating expenses ($882 million).

Net cash used in investing activities of $3,419 million in 2021 increased by $71 million from $3,348 million in 2020 primarily due to an increase in additions to oil and gas properties ($394 million), partially offset by net cash provided by working capital associated with investing activities in 2021 ($200 million) compared to net cash used in working capital associated with investing activities in 2020 ($75 million); an increase in proceeds from the sales of assets ($39 million); and a decrease in additions to other property, plant and equipment ($9 million).

Net cash used in financing activities of $3,493 million in 2021 included cash dividend payments ($2,684 million), repayments of long-term debt ($750 million), purchases of treasury stock in connection with stock compensation plans ($41 million) and repayment of finance lease liabilities ($37 million). Cash provided by financing activities in 2021 included proceeds from stock options exercised and employee stock purchase plan activity ($19 million).

2020 compared to 2019. Net cash provided by operating activities of $5,008 million in 2020 decreased $3,155 million from $8,163 million in 2019 primarily due to a decrease in wellhead revenues ($4,291 million); unfavorable changes in working capital and other assets and liabilities ($166 million); a decrease in gathering, processing and marketing revenues less marketing costs ($123 million) and an increase in net cash paid for income taxes ($86 million); partially offset by an increase in cash received for settlements of commodity derivative contracts ($840 million) and a decrease in cash operating expenses ($641 million).

Net cash used in investing activities of $3,348 million in 2020 decreased by $2,829 million from $6,177 million in 2019 primarily due to a decrease in additions to oil and gas properties ($2,908 million); an increase in proceeds from the sale of assets ($52 million); a decrease in additions to other property, plant and equipment ($49 million); and a decrease in other investing activities ($10 million); partially offset by an unfavorable change in working capital associated with investing activities ($190 million).

Net cash used in financing activities of $359 million in 2020 included repayments of long-term debt ($1,000 million), cash dividend payments ($821 million), repayment of finance lease liabilities ($19 million) and purchases of treasury stock in connection with stock compensation plans ($16 million). Cash provided by financing activities in 2020 included long-term debt borrowings ($1,484 million) and proceeds from stock options exercised and employee stock purchase plan activity ($16 million).

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Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2021, 2020 and 2019 (in millions):

(1)Leasehold acquisitions included $45 million, $197 million and $98 million related to non-cash property exchanges in 2021, 2020 and 2019, respectively.

(2)Property acquisitions included $5 million, $15 million and $52 million related to non-cash property exchanges in 2021, 2020 and 2019, respectively.

(3)Other property, plant and equipment included non-cash additions of $74 million and $174 million, primarily related to finance lease transactions for storage facilities in 2021 and 2020, respectively.

Exploration and development expenditures of $3,842 million for 2021 were $241 million higher than the prior year. The increase was primarily due to increased exploration and development drilling expenditures in the United States ($267 million) and increased facilities expenditures ($58 million), partially offset by decreased exploration and development drilling expenditures in Trinidad ($61 million), decreased leasehold acquisitions ($50 million) and decreased property acquisitions ($35 million). The 2021 exploration and development expenditures of $3,842 million included $3,172 million in development drilling and facilities, $537 million in exploration, $100 million in property acquisitions and $33 million in capitalized interest. The 2020 exploration and development expenditures of $3,601 million included $2,905 million in development drilling and facilities, $530 million in exploration, $135 million in property acquisitions and $31 million in capitalized interest. The 2019 exploration and development expenditures of $6,442 million included $5,513 million in development drilling and facilities, $511 million in exploration, $380 million in property acquisitions and $38 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors.  EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant.  While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

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Commodity Derivative Transactions

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2021 (closed) and remaining for 2022 and thereafter, as of February 18, 2022. Crude oil and NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

(1)    This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.

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(1)    In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of its 2022 natural gas price swap contracts which were open at that time. EOG received net cash of $0.6 million for the settlement of these contracts.

(1)    This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

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In connection with its financial commodity derivative contracts, EOG had $1.4 billion of collateral posted at February 18, 2022. EOG expects this collateral to be applied to the settlement of financial commodity derivative contracts if market prices remain above contract prices or returned to EOG if market prices decrease below contract prices.

Financing

EOG's debt-to-total capitalization ratio was 19% at December 31, 2021, compared to 22% at December 31, 2020.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2021 and 2020, respectively, EOG had outstanding $4,890 million and $5,640 million aggregate principal amount of senior notes which had estimated fair values of $5,577 million and $6,505 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.

During 2021, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities, cash on hand and proceeds from asset sales.  While EOG maintains a $2.0 billion revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2021 and the amount outstanding at year-end was zero.  EOG considers the availability of its $2.0 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

Foreign Currency Exchange Rate Risk

During 2021, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, Australia, Oman, Canada and, through May 2021, in China.  EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against foreign currency exchange rate risk.

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 availabilities of other energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, 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 2022 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, 2022, the average 2022 NYMEX crude oil and natural gas prices were $84.45 per barrel and $4.61 per MMBtu, respectively, representing an increase of 24% for crude oil and an increase of 20% for natural gas from the average NYMEX prices in 2021. 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.

Including the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2022 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 $107 million for net income and $138 million for pretax cash flows from operating activities.  Including the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2022 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 wellhead natural gas price is approximately $15 million for net income and $19 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, 2022, see "Commodity Derivative Transactions" above.

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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 its Delaware Basin, Eagle Ford oil play, Rocky Mountain area and Dorado gas 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 offset inflationary pressure through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2022 capital expenditures on leasing acreage, evaluating new prospects, long-term transportation infrastructure and environmental projects.

The total anticipated 2022 capital expenditures of approximately $4.3 billion to $4.7 billion, excluding acquisitions and non-cash transactions, 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 $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2022, total crude oil, NGLs and natural gas production is expected to return to prepandemic levels. In 2022, EOG expects to continue to focus on mitigating inflationary pressure on operating costs through efficiency improvements.

Cash Requirements. Certain of EOG's capital expenditures and operating expenses are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASU 2016-02. In 2022, EOG anticipates the following cash requirements under these commitments (in millions):

(1)    For more information on contracts that meet the definition of a lease under ASU 2016-02, see Note 18 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, 2021. 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 more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

In 2022, EOG has no senior notes maturing and expects to pay interest of $191 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 unrecognized tax benefits, EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 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 and other cash requirements, both in 2022 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 its $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.

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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 recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

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 and continual reassessment of the viability of production under varying economic conditions.  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."

Oil and Gas Exploration and Development Costs

EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves.  If commercial quantities of proved reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.  The concept of sufficient progress is subject to significant judgment and may require further operational actions or require additional approvals from government agencies or partners in oil and gas operations, among other factors, the timing of which may delay management's determinations. See Note 16 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.

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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 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.  Lease rentals are expensed as incurred.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group.  If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, 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 the Fair Value Measurement Topic of the ASC.  In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.  Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future.

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, 2021, WTI crude oil spot prices have fluctuated from approximately $(36.98) per barrel to $85.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.33 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.

See Notes 13 and 14 to Consolidated Financial Statements for further disclosures of impairments of oil and gas properties and other assets.

Income Taxes

Income taxes are accounted for using the asset and liability approach.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis.  EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate.  Significant assumptions used in estimating future taxable income include future crude oil, NGLs and natural gas prices and levels of capital reinvestment.  Changes in such assumptions or changes in tax laws and regulations could materially affect the recognized amounts of valuation allowances. See Note 6 to Consolidated Financial Statements.

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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, 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 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 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, or pay and/or increase dividends 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 these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. 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, operating and capital costs 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 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;

•the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, 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;

•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 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 and natural gas; laws and regulations with respect to 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; 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;

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•EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs 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 and other personnel, facilities, equipment, materials (such as water 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, 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, including the COVID-19 pandemic;

•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 conflict), 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 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.