EOG RESOURCES INC (EOG) FY 2022 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 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.

33

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.

34

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).

35

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.

36

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.

37

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.

38

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.

39

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.

40

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.

41

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).

42

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.

43

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).

44

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.

45

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.

46

_________________

(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.

47

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.

48

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.

49

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.

50

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.

51

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;

52

•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.

53