Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EOG RESOURCES, INC.

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States and the Republic of Trinidad and Tobago (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.

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

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

For the first nine months of 2023, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $77.37 per barrel and $2.69 per million British thermal units (MMBtu), respectively, representing decreases of 21% and 60%, respectively, from the average NYMEX prices for the same period in 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 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 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 and capital costs is uncertain.

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, to date, been able to largely offset such impacts. EOG currently expects such inflationary pressures to result in an increase of no more 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 third quarter 2023 cash flows, and EOG currently does not expect such increase to have a material impact on its 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 results of operations, liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.

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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 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.

Climate Change. For discussion of climate change matters and related regulatory matters, including potential developments related to climate change and the potential impacts and risks of such developments on EOG, see ITEM 1A. Risk Factors and the related discussion in ITEM 1. Business - Regulation of EOG's Annual Report on Form 10-K for the year ended December 31, 2022, filed on February 23, 2023 (EOG's 2022 Annual Report). 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.

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

During the first nine months of 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 and capital costs (e.g., costs for fuel and tubulars). 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 the first nine months of 2023 and 2022, respectively. During the first nine months of 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.

Trinidad. In 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), 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).

EOG commenced drilling in the third quarter of 2023 from the recently completed platform in the Modified U(a) Block. From this platform, EOG expects to complete two net developmental wells and one net exploratory well in the fourth quarter of 2023 and, in the first quarter of 2024, complete one net development well and one net exploratory well. Additionally, in the first nine months of 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 in the third quarter of 2023.

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 the first nine months of 2023, EOG continued to prepare for the drilling of an exploration well which is expected to commence in 2024, subject to statutory approvals and 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.

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2023 Capital and Operating Plan**.** Total 2023 capital expenditures are estimated to range from approximately $5.9 billion to $6.1 billion, including facilities and gathering, processing, transportation and other expenditures, and excluding acquisitions, non-cash transactions and exploration costs. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States drilling activity in the Delaware Basin, 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 to mitigate inflationary pressures on its operating and capital costs (e.g., costs for fuel and tubulars) through drilling, completion and operating efficiency gains; see the above related discussion. Full-year 2023 total crude oil, NGLs and natural gas production is expected to increase modestly versus 2022. In addition, EOG plans to continue to spend a portion of its anticipated 2023 capital expenditures on leasing acreage, evaluating new prospects, transportation infrastructure and environmental projects.

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

Capital Structure**.** One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 12% and 17% at September 30, 2023 and December 31, 2022, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At September 30, 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.

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.

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 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 2022 Annual Report. For discussion regarding our share repurchases conducted during the third quarter of 2023 and our share repurchase authorization, see Part II, Item 2. Unregistered Sales of Equity Securities and Use of Proceeds in this Quarterly Report on Form 10-Q.

Dividend Declarations. On February 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.

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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 payable 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, payable on December 29, 2023, to stockholders of record as of December 15, 2023.

Share Repurchases. In November 2021, the Board established a new share repurchase authorization that allows for the repurchase by EOG of up to $5 billion of its common stock (November 2021 Authorization). Under the November 2021 Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases is at the discretion of EOG's management and depends on a variety of factors, including the trading price of EOG's common stock, corporate and regulatory requirements, and other market and economic conditions. Repurchased shares are held as treasury shares and are available for general corporate purposes. The November 2021 Authorization has no time limit, does not require EOG to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time. During the three and nine months ended September 30, 2023, EOG repurchased 0.5 million and 6.2 million shares of common stock, respectively, for approximately $60.9 million and $671.1 million (inclusive of transaction fees and commissions), respectively, pursuant to the November 2021 Authorization. As of September 30, 2023, approximately $4.3 billion remained available for repurchases under the November 2021 Authorization. Included in the Treasury Stock Repurchased amounts on the Condensed Consolidated Statements of Stockholders' Equity for the nine months ended September 30, 2023, is $5.2 million of estimated federal excise taxes.

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Results of Operations

The following review of operations for the three months ended September 30, 2023 and 2022 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10‑Q.

Three Months Ended September 30, 2023 vs. Three Months Ended September 30, 2022

Operating Revenues. During the third quarter of 2023, operating revenues decreased $1,381 million, or 18%, to $6,212 million from $7,593 million for the same period of 2022. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the third quarter of 2023 decreased $1,402 million, or 23%, to $4,635 million from $6,037 million for the same period of 2022. EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $43 million for the third quarter of 2023 compared to net losses of $18 million for the same period of 2022. Gathering, processing and marketing revenues for the third quarter of 2023 decreased $83 million, or 5%, to $1,478 million from $1,561 million for the same period of 2022. Net gains on asset dispositions were $35 million for the third quarter of 2023 compared to net losses of $21 million for the same period of 2022.

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Wellhead volume and price statistics for the three-month periods ended September 30, 2023 and 2022 were as follows:


	Three Months Ended September 30,
	2023		2022
Crude Oil and Condensate Volumes (MBbld) (1)
United States	482.8		464.6
Trinidad	0.5		0.5
Total	483.3		465.1
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States	$	83.61	$	96.05
Trinidad	71.38		84.98
Composite	83.60		96.04
Natural Gas Liquids Volumes (MBbld) (1)
United States	231.1		209.3
Total	231.1		209.3
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States	$	23.56	$	36.02
Natural Gas Volumes (MMcfd) (1)
United States	1,562		1,306
Trinidad	142		163
Total	1,704		1,469
Average Natural Gas Prices ($/Mcf) (2)
United States	$	2.59	$	9.35
Trinidad	3.41		7.45		(4)
Composite	2.66		9.14
Crude Oil Equivalent Volumes (MBoed) (3)
United States	974.2		891.6
Trinidad	24.3		27.6
Total	998.5		919.2

Total MMBoe (3)	91.9		84.6

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

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

(3)Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

(4)Includes revenue adjustment of $3.37 per Mcf ($0.37 per Mcf of EOG's composite wellhead natural gas price) 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 for the third quarter of 2023 decreased $392 million, or 10%, to $3,717 million from $4,109 million for the same period of 2022. The decrease was due to a lower composite average price ($556 million), partially offset by an increase of 18.2 MBbld, or 4%, in wellhead crude oil and condensate production ($164 million). Increased production was primarily in the Permian Basin. EOG's composite wellhead crude oil and condensate price for the third quarter of 2023 decreased 13% to $83.60 per barrel compared to $96.04 per barrel for the same period of 2022.

NGL revenues for the third quarter of 2023 decreased $192 million, or 28%, to $501 million from $693 million for the same period of 2022 due to a lower composite average price ($264 million), partially offset by an increase of 21.8 MBbld, or 10%, in NGL deliveries ($72 million). Increased production was primarily from the Permian Basin. EOG's composite NGL price for the third quarter of 2023 decreased 35% to $23.56 per barrel compared to $36.02 per barrel for the same period of 2022.

Wellhead natural gas revenues for the third quarter of 2023 decreased $818 million, or 66%, to $417 million from $1,235 million for the same period of 2022. The decrease was due to a lower composite average price ($1,019 million), partially offset by an increase in natural gas deliveries ($201 million). Natural gas deliveries for the third quarter of 2023 increased 235 MMcfd, or 16%, compared to the same period of 2022 due primarily to increased production of associated natural gas from the Permian Basin and higher deliveries in the Dorado gas play and the Rocky Mountain area, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the third quarter of 2023 decreased 71% to $2.66 per Mcf compared to $9.14 per Mcf for the same period of 2022.

During the third quarter of 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $43 million compared to net losses of $18 million for the same period of 2022. During the third quarter of 2023, net cash received from settlements of financial commodity derivative contracts was $23 million compared to net cash paid for settlements of financial commodity derivative contracts of $847 million for the same period of 2022.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand primarily in order to balance the timing of firm purchase agreements with completion operations. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2023 increased $155 million as compared to the same period of 2022 primarily due to higher margins on crude oil marketing activities, partially offset by lower margins on natural gas marketing activities.

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Operating and Other Expenses. For the third quarter of 2023, operating expenses of $3,655 million were $274 million lower than the $3,929 million incurred during the third quarter of 2022. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2023 and 2022:


	Three Months Ended September 30,
	2023		2022
Lease and Well	$	4.02	$	3.96
Transportation Costs	2.61		3.04
Gathering and Processing Costs	1.81		1.97
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	9.31		10.24
Other Property, Plant and Equipment	0.47		0.47
General and Administrative (G&A)	1.75		1.92
Interest Expense, Net	0.39		0.48
Total (1)	$	20.36	$	22.08

(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, DD&A and interest expense, net for the three months ended September 30, 2023, compared to the same period of 2022, are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

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

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

Lease and well expenses of $369 million for the third quarter of 2023 increased $34 million from $335 million for the same prior year period primarily due to increased lease and well administrative expenses ($22 million), increased operating and maintenance costs ($8 million) and increased workover expenditures ($4 million), all in the United States. Lease and well expenses increased in the United States primarily due to increased operating activities resulting in 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 $240 million for the third quarter of 2023 decreased $17 million from $257 million for the same prior year period primarily due to decreased transportation costs related to production from the Eagle Ford play ($9 million), the Permian Basin ($5 million) and the Rocky Mountain area ($4 million).

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DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the third quarter of 2023 decreased $8 million to $898 million from $906 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2023 were $11 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($92 million), partially offset by increased production in the United States ($78 million) and increased unit rates in Trinidad ($4 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to favorable well performance, increased ethane recovery and reserve additions at lower costs per Boe during the quarter.

Interest expense, net of $36 million for the third quarter of 2023 decreased $5 million compared to the same prior year period primarily due to the repayment in March 2023 of the $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023.

Exploration costs of $43 million for the third quarter of 2023 increased $8 million from $35 million for the same prior year period due primarily to increased administrative expenses 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 asset. 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. 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 third quarter of 2023 and 2022 (in millions):


	Three Months Ended September 30,
	2023		2022
Proved properties	$	23	$	45
Unproved properties	30		49
Firm commitment contracts	1		—
Total	$	54	$	94

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the third quarter of 2023 increased $7 million to $341 million (7.4% of wellhead revenues) from $334 million (5.5% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to state severance tax refunds received in 2022 ($115 million), partially offset by decreased severance/production taxes ($95 million) and decreased ad valorem/property taxes ($16 million), all in the United States.

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Other income, net was $52 million for the third quarter of 2023 compared to other income, net of $40 million for the same prior year period. The change of $12 million in the third quarter of 2023 was primarily due to increased interest income ($27 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 ($9 million).

EOG recognized an income tax provision of $543 million for the third quarter of 2023 compared to an income tax provision of $809 million for the third quarter of 2022, primarily due to decreased pretax income. The net effective tax rate for the third quarter of 2023 decreased to 21% from 22% for the third quarter of 2022.

Nine Months Ended September 30, 2023 vs. Nine Months Ended September 30, 2022

Operating Revenues. During the first nine months of 2023, operating revenues decreased $1,154 million, or 6%, to $17,829 million from $18,983 million for the same period of 2022. Total wellhead revenues for the first nine months of 2023 decreased $4,980 million, or 28%, to $12,819 million from $17,799 million for the same period of 2022. During the first nine months of 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $520 million compared to net losses of $4,215 million for the same period of 2022. Gathering, processing and marketing revenues for the first nine months of 2023 decreased $866 million, or 17%, to $4,333 million from $5,199 million for the same period of 2022. Net gains on asset dispositions were $95 million for the first nine months of 2023 compared to net gains of $101 million for the same period of 2022.

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Wellhead volume and price statistics for the nine-month periods ended September 30, 2023 and 2022 were as follows:


	Nine Months Ended September 30,
	2023		2022
Crude Oil and Condensate Volumes (MBbld)
United States	472.0		459.2
Trinidad	0.6		0.7
Total	472.6		459.9
Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States	$	78.69	$	101.16
Trinidad	68.37		88.84
Composite	78.67		101.14
Natural Gas Liquids Volumes (MBbld)
United States	219.7		200.6
Total	219.7		200.6
Average Natural Gas Liquids Prices ($/Bbl) (1)
United States	$	23.35	$	39.29
Natural Gas Volumes (MMcfd)
United States	1,517		1,293
Trinidad	154		192
Total	1,671		1,485
Average Natural Gas Prices ($/Mcf) (1)
United States	$	2.70	$	7.68
Trinidad	3.59		4.55		(2)
Composite	2.78		7.28
Crude Oil Equivalent Volumes (MBoed)
United States	944.6		875.3
Trinidad	26.2		32.6
Total	970.8		907.9

Total MMBoe	265.0		247.8

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

(2) Includes revenue adjustment of $0.96 per Mcf ($0.12 per Mcf of EOG's composite wellhead natural gas price) 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 for the first nine months of 2023 decreased $2,546 million, or 20%, to $10,151 million from $12,697 million for the same period of 2022 due to a lower composite average price ($2,900 million), partially offset by an increase of 12.7 MBbld, or 3%, in wellhead crude oil and condensate production ($354 million). Increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play and the Rocky Mountain area. EOG's composite wellhead crude oil and condensate price for the first nine months of 2023 decreased 22% to $78.67 per barrel compared to $101.14 per barrel for the same period of 2022.

NGL revenues for the first nine months of 2023 decreased $751 million, or 35%, to $1,400 million from $2,151 million for the same period of 2022 due to a lower composite average price ($955 million), partially offset by an increase of 19.1 MBbld, or 10%, in NGL deliveries ($204 million). Increased production was primarily from the Permian Basin, partially offset by decreased production from the Eagle Ford play. EOG's composite NGL price for the first nine months of 2023 decreased 41% to $23.35 per barrel compared to $39.29 per barrel for the same period of 2022.

Wellhead natural gas revenues for the first nine months of 2023 decreased $1,683 million, or 57%, to $1,268 million from $2,951 million for the same period of 2022. The decrease was due to a lower composite average price ($2,054 million), partially offset by an increase in natural gas deliveries ($371 million). Natural gas deliveries for the first nine months of 2023 increased 186 MMcfd, or 13%, compared to the same period of 2022 due primarily 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. EOG's composite wellhead natural gas price for the first nine months of 2023 decreased 62% to $2.78 per Mcf compared to $7.28 per Mcf for the same period of 2022.

During the first nine months of 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $520 million compared to net losses of $4,215 million for the same period of 2022. During the first nine months of 2023, net cash paid for settlements of financial commodity derivative contracts was $130 million. Net cash paid for settlements of financial commodity derivative contracts was $3,257 million for the same period of 2022.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2023 decreased $35 million as compared to the same period of 2022 primarily due to lower margins on natural gas marketing activities.

Operating and Other Expenses. For the first nine months of 2023, operating expenses of $10,730 million were $1,140 million lower than the $11,870 million incurred during the same period of 2022. The following table presents the costs per Boe for the nine-month periods ended September 30, 2023 and 2022:


	Nine Months Ended September 30,
	2023		2022
Lease and Well	$	4.06	$	3.94
Transportation Costs	2.69		2.94
Gathering and Processing Costs	1.83		1.87
DD&A -
Oil and Gas Properties	9.19		10.28
Other Property, Plant and Equipment	0.48		0.47
G&A	1.69		1.67
Interest Expense, Net	0.43		0.55
Total (1)	$	20.37	$	21.72

(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 interest expense, net for the nine months ended September 30, 2023, compared to the same period of 2022 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

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Lease and well expenses of $1,076 million for the first nine months of 2023 increased $99 million from $977 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($54 million) and Trinidad ($6 million) and increased lease and well administrative expenses in the United States ($37 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs of $712 million for the first nine months of 2023 decreased $17 million from $729 million for the same prior year period primarily due to decreased transportation costs related to production from the Eagle Ford play ($32 million) and the Rocky Mountain area ($9 million), partially offset by increased transportation costs related to production from the Permian Basin ($18 million) and the Dorado gas play ($6 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 NGL 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 $22 million to $485 million for the first nine months of 2023 compared to $463 million for the same prior year period primarily due to increased gathering and processing fees related to production from the Permian Basin ($20 million) and increased operating and maintenance expenses related to production from the Rocky Mountain area ($11 million) and the Permian Basin ($9 million), partially offset by decreased gathering and processing fees related to production from the Rocky Mountain area ($12 million) and decreased operating and maintenance expenses related to production from the Eagle Ford play ($12 million).

DD&A expenses for the first nine months of 2023 decreased $102 million to $2,562 million from $2,664 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2023 were $113 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($315 million) and decreased production in Trinidad ($9 million), partially offset by increased production in the United States ($195 million) and increased unit rates in Trinidad ($10 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to favorable well performance, increased ethane recovery and reserves added at lower cost per Boe during the year. DD&A expenses associated with other property, plant and equipment for the first nine months of 2023 were $11 million higher than the same prior year period primarily due to an increase in expenses related to gathering and processing assets and equipment.

G&A expenses of $448 million for the first nine months of 2023 increased $34 million from $414 million for the same prior year period primarily due to increased employee-related costs.

Interest expense, net of $113 million for the first nine months of 2023 decreased $24 million compared to the same prior year period primarily due to the repayment in March 2023 of the $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023 ($19 million) and decreased interest expense on certain royalty payments ($7 million).

Exploration costs of $140 million for the first nine months of 2023 increased $25 million from $115 million for the same prior year period due primarily to increased geological and geophysical expenditures ($16 million) and increased administrative expenses ($10 million), both in the United States.

The following table represents impairments for the nine-month periods ended September 30, 2023 and 2022 (in millions):


	Nine Months Ended September 30,
	2023		2022
Proved properties	$	26	$	59
Unproved properties	95		157
Other assets	—		23
Firm commitment contracts	2		1
Total	$	123	$	240

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Taxes other than income for the first nine months of 2023 decreased $213 million to $983 million (7.7% of wellhead revenues) from $1,196 million (6.7% of wellhead revenues) for the same prior year period. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($322 million), partially offset by decreased state severance tax refunds ($112 million), all in the United States.

Other income, net was $168 million for the first nine months of 2023 compared to other income, net of $66 million for the same prior year period. The change of $102 million in the first nine months of 2023 was primarily due to increased interest income ($134 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 ($37 million).

EOG's income tax provision of $1,548 million for the first nine months of 2023 decreased from an income tax provision of $1,560 million for the first nine months of 2022. The net effective tax rate for the first nine months of 2023 was unchanged from the prior year tax rate of 22%.

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the nine months ended September 30, 2023, were funds generated from operations and proceeds from sales of assets. The primary uses of cash were exploration and development expenditures; funds used in operations; dividend payments to stockholders; repayment of maturing debt; purchases of treasury stock; and other property, plant and equipment expenditures. During the first nine months of 2023, EOG's cash balance decreased $646 million to $5,326 million from $5,972 million at December 31, 2022.

Net cash provided by operating activities of $8,236 million for the first nine months of 2023 increased $587 million compared to the same period of 2022 primarily due to a decrease in net cash paid for settlements of financial commodity derivative contracts ($3,127 million), a decrease in net cash paid for income taxes ($1,183 million), net cash provided by a change in collateral posted for financial commodity derivative contracts ($870 million) and a decrease in net cash used in working capital and other assets and liabilities ($543 million), partially offset by a decrease in wellhead revenues ($4,980 million).

Net cash used in investing activities of $4,841 million for the first nine months of 2023 increased $1,182 million compared to the same period of 2022 due to an increase in additions to oil and gas properties ($635 million), an increase in additions to other property, plant and equipment ($390 million), a decrease in proceeds from the sale of assets ($175 million) and an increase in net cash used in working capital associated with investing activities ($12 million), partially offset by a decrease in other investing activities ($30 million).

Net cash used in financing activities of $4,041 million for the first nine months of 2023 included cash dividend payments ($2,041 million), repayments of long-term debt ($1,250 million), purchases of treasury stock ($728 million) and repayment of finance lease liabilities ($24 million). Net cash used in financing activities of $3,926 million for the first nine months of 2022 included cash dividend payments ($3,821 million), purchases of treasury stock in connection with stock compensation plans ($95 million) and repayment of finance lease liabilities ($27 million).

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Total Expenditures. For the full-year 2023, EOG's updated budget for exploration and development and other property, plant and equipment expenditures is estimated to range from approximately $5.9 billion to $6.1 billion, excluding acquisitions, non-cash transactions and exploration costs. The table below sets out components of total expenditures for the nine-month periods ended September 30, 2023 and 2022 (in millions):


	Nine Months Ended September 30,
	2023		2022
Expenditure Category
Capital
Exploration and Development Drilling (1)	$	3,619	$	2,599
Facilities	373		291
Leasehold Acquisitions (2)	153		148
Property Acquisitions (3)	9		398
Capitalized Interest	24		26
Subtotal	4,178		3,462
Exploration Costs	140		115
Dry Hole Costs	1		41
Exploration and Development Expenditures	4,319		3,618
Asset Retirement Costs	227		209
Total Exploration and Development Expenditures	4,546		3,827
Other Property, Plant and Equipment (4)	638		248
Total Expenditures	$	5,184	$	4,075

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

(2) Leasehold acquisitions included $60 million and $107 million for the nine-month periods ended September 30, 2023 and 2022, respectively, related to non-cash property exchanges.

(3) Property acquisitions included $9 million and $6 million for the nine-month periods ended September 30, 2023 and 2022, respectively, related to non-cash property exchanges.

(4) Other Property, Plant and Equipment included $134 million for the nine-month period ended September 30, 2023, related to the acquisition of a gathering and processing system in the Powder River Basin.

Exploration and development expenditures of $4,319 million for the first nine months of 2023 were $701 million higher than the same period of 2022 primarily due to increased exploration and development drilling expenditures in the United States ($986 million) and increased facilities expenditures ($82 million), partially offset by decreased property acquisitions ($389 million). Exploration and development expenditures for the first nine months of 2023 of $4,319 million consisted of $3,836 million in development drilling and facilities, $450 million in exploration, $24 million in capitalized interest and $9 million in property acquisitions. Exploration and development expenditures for the first nine months of 2022 of $3,618 million consisted of $2,822 million in development drilling and facilities, $398 million in property acquisitions, $372 million in exploration and $26 million in capitalized interest.

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

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Financial Commodity Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2022 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts on the Condensed Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities on the Condensed Consolidated Statements of Cash Flows.

The total fair value of EOG's financial commodity derivative contracts was reflected on the Condensed Consolidated Balance Sheets at September 30, 2023, as a net liability of $277 million.

As discussed in "Operating Revenues," the net cash received from settlements of financial commodity derivative contracts during the third quarter of 2023 was $23 million and the net cash paid for the settlements of financial commodity derivatives during the first nine months of 2023 was $130 million.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2023 to October 31, 2023 (closed) and outstanding as of October 31, 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).


Crude Oil Financial Price Swap Contracts
		Contracts Sold			Contracts Purchased
Period	Settlement Index	Volume (MBbld)	Weighted Average Price ($/Bbl)		Volume (MBbld)	Weighted Average Price ($/Bbl)

January - March 2023 (closed)	NYMEX West Texas Intermediate (WTI)	95	$	67.90	6	$	102.26
April - May 2023 (closed)	NYMEX WTI	91	67.63		2	98.15
June 2023 (closed)	NYMEX WTI	2	69.10		2	98.15


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

January - November 2023 (closed)	NYMEX Henry Hub	300	$	3.36
December 2023	NYMEX Henry Hub	300	3.36
January - December 2024	NYMEX Henry Hub	725	3.07
January - December 2025	NYMEX Henry Hub	725	3.07

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

January - October 2023 (closed)	NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)	135	$	0.01
November - December 2023	NYMEX Henry Hub HSC Differential	135	0.01
January - December 2024	NYMEX Henry Hub HSC Differential	10	0.00
January - December 2025	NYMEX Henry Hub HSC Differential	10	0.00

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

In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at November 1, 2023. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX WTI and Henry Hub prices.

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward‐looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward‐looking statements. In particular, statements, express or implied, concerning EOG's future financial or operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward‐looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of inflationary pressures on EOG's operating costs and capital expenditures;
the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax and emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

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the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG's day-to-day operations;
the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets 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, 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 EOG's Annual Report on Form 10-K for the year ended December 31, 2022, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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PART I. FINANCIAL INFORMATION

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