EOG RESOURCES INC (EOG) FY 2023 MD&A

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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