Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

76K characters. Original on sec.gov · Markdown

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 Trinidad. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term growth in shareholder value and maintain a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.

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 2022, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $98.14 per barrel and $6.77 per million British thermal units (MMBtu), respectively, representing increases of 51% and 113%, respectively, from the average NYMEX prices for the same period in 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 the first nine months of 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 through the first nine months of 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. EOG currently expects such inflationary pressures and contributing factors to continue into 2023.

-23-

Such inflationary pressures on EOG's operating 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 less than 10 percent in its fiscal year 2022 well costs (i.e., its costs for drilling, completions and well-site facilities) versus fiscal year 2021. Accordingly, such increase in EOG's fiscal year 2022 well costs has not, to date, had a material impact on EOG's results of operations, and EOG currently does not expect such increase to have a material impact on its full-year 2022 results of operations. Further, such inflationary pressures and the factors contributing to such inflationary pressures (described above) have not, to date, impacted EOG's liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.

The initiatives EOG has undertaken (and continues to undertake) to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, mitigate such inflationary pressures, include (among others): (i) EOG's downhole drilling motor program, which has resulted in increased footage drilled per day and, in turn, reduced drilling times; (ii) enhanced techniques for completing its wells, which has resulted in increased footage completed per day and pumping hours per day; and (iii) EOG's self-sourced sand program, which has resulted in continued 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 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.

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 2022, 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 the 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 the first nine months of 2022 and 2021, respectively. During the first nine months of 2022, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford oil play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico and Texas.

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). 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 the first nine months of 2022, EOG prepared for and drilled one net exploratory well, which was determined to be unsuccessful.

-24-

Also, in the first nine months of 2022, EOG continued to make progress on the design, fabrication and installation of the platform and related facilities for its previously-announced discovery in the Modified U(a) Block. In the fourth quarter of 2022, EOG expects to complete the installation of the platform and facilities and commence the development drilling campaign in the Modified U(a) Block. Additionally, in the first nine months of 2022, EOG commenced the drilling of one net exploratory well from a pre-existing platform in the Modified U(a) Block, which was in progress at September 30, 2022. In the fourth quarter of 2022, EOG also expects to complete and put on production one net exploratory well that was started in the third quarter of 2022 and to drill one additional net exploratory well from the same platform.

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 2022, EOG continued to prepare for the drilling of an exploration well which is expected to commence in 2023, subject to statutory approvals.

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.

2022 Capital and Operating Plan**.** Total 2022 capital expenditures are estimated to range from approximately $4.5 billion to $4.7 billion, including facilities and gathering, processing 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 oil play, Rocky Mountain area and Dorado gas play where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to mitigate recent inflationary pressures on its operating and capital costs (e.g., costs for fuel and tubulars) through efficiency gains; see above related discussion. Full-year 2022 total crude oil, NGLs and natural gas production is expected to return to pre-pandemic levels. In addition, EOG plans to continue to spend a portion of its anticipated 2022 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 18% and 19% at September 30, 2022 and December 31, 2021, 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, 2022, EOG maintained a strong financial and liquidity position, including $5.3 billion of cash and cash equivalents on hand and $2.0 billion of availability under its senior unsecured revolving credit facility.

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.

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.

-25-

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 payable 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, payable on December 30, 2022, to stockholders of record as of December 15, 2022.

Cash Return Framework. Also 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, 2021, filed on February 24, 2022 (EOG's 2021 Annual Report).

Results of Operations

The following review of operations for the three months ended September 30, 2022 and 2021 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, 2022 vs. Three Months Ended September 30, 2021

Operating Revenues and Other. During the third quarter of 2022, operating revenues increased $2,828 million, or 59%, to $7,593 million from $4,765 million for the same period of 2021. 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 2022 increased $1,992 million, or 49%, to $6,037 million from $4,045 million for the same period of 2021. EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $18 million for the third quarter of 2022 compared to net losses of $494 million for the same period of 2021. Gathering, processing and marketing revenues for the third quarter of 2022 increased $375 million, or 32%, to $1,561 million from $1,186 million for the same period of 2021. Net losses on asset dispositions were $21 million for the third quarter of 2022 compared to net gains of $1 million for the same period of 2021.

-26-

Wellhead volume and price statistics for the three-month periods ended September 30, 2022 and 2021 were as follows:


	Three Months Ended September 30,
	2022			2021
Crude Oil and Condensate Volumes (MBbld) (1)
United States	464.6			448.3
Trinidad	0.5			1.2
Other International (2)	—			—
Total	465.1			449.5
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	96.05		$	70.88
Trinidad	84.98			60.19
Other International (2)	—			—
Composite	96.04			70.85
Natural Gas Liquids Volumes (MBbld) (1)
United States	209.3			157.9
Total	209.3			157.9
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	36.02		$	37.72
Composite	36.02			37.72
Natural Gas Volumes (MMcfd) (1)
United States	1,306			1,210
Trinidad	163			212
Other International (2)	—			—
Total	1,469			1,422
Average Natural Gas Prices ($/Mcf) (3)
United States	$	9.35		$	4.50
Trinidad	7.45		(5)	3.39
Other International (2)	—			—
Composite	9.14			4.34
Crude Oil Equivalent Volumes (MBoed) (4)
United States	891.6			807.9
Trinidad	27.6			36.5
Other International (2)	—			—
Total	919.2			844.4

Total MMBoe (4)	84.6			77.7

(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 the Condensed 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 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.

-27-

Wellhead crude oil and condensate revenues for the third quarter of 2022 increased $1,180 million, or 40%, to $4,109 million from $2,929 million for the same period of 2021. The increase was due to a higher composite average price ($1,087 million) and an increase of 15.6 MBbld, or 3%, in wellhead crude oil and condensate production ($93 million). Increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford oil play and the Rocky Mountain area. EOG's composite wellhead crude oil and condensate price for the third quarter of 2022 increased 36% to $96.04 per barrel compared to $70.85 per barrel for the same period of 2021.

NGL revenues for the third quarter of 2022 increased $145 million, or 26%, to $693 million from $548 million for the same period of 2021 due to an increase of 51.4 MBbld, or 33%, in NGL deliveries ($177 million), partially offset by a lower composite average price ($32 million). Increased production was primarily from the Permian Basin. EOG's composite NGL price for the third quarter of 2022 decreased 5% to $36.02 per barrel compared to $37.72 per barrel for the same period of 2021.

Wellhead natural gas revenues for the third quarter of 2022 increased $667 million, or 117%, to $1,235 million from $568 million for the same period of 2021. The increase was due to a higher average composite price ($650 million) and an increase in natural gas deliveries ($17 million). Natural gas deliveries for the third quarter of 2022 increased 47 MMcfd, or 3%, compared to the same period of 2021 due primarily to higher deliveries in the Dorado gas play and increased production of associated natural gas from the Permian Basin, partially offset by lower natural gas deliveries in Trinidad and 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. EOG's composite wellhead natural gas price for the third quarter of 2022 increased 111% to $9.14 per Mcf compared to $4.34 per Mcf for the same period of 2021.

During the third quarter of 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $18 million compared to net losses of $494 million for the same period of 2021. During the third quarter of 2022, net cash paid for settlements of financial commodity derivative contracts was $847 million, of which $63 million was related to the early termination of certain contracts scheduled to settle after December 31, 2022. Net cash paid for settlements of financial commodity derivative contracts was $293 million for the same period of 2021.

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

Gathering, processing and marketing revenues less marketing costs for the third quarter of 2022 decreased $62 million as compared to the same period of 2021 primarily due to lower margins on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.

-28-

Operating and Other Expenses. For the third quarter of 2022, operating expenses of $3,929 million were $635 million higher than the $3,294 million incurred during the third quarter of 2021. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, 2022 and 2021:


	Three Months Ended September 30,
	2022		2021
Lease and Well	$	3.96	$	3.48
Transportation Costs	3.04		2.82
Gathering and Processing Costs	1.97		1.87
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	10.24		11.47
Other Property, Plant and Equipment	0.47		0.46
General and Administrative (G&A)	1.92		1.83
Interest Expense, Net	0.48		0.62
Total (1)	$	22.08	$	22.55

(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 the three months ended September 30, 2022, compared to the same period of 2021, are set forth below. See "Operating Revenues and Other" 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 $335 million for the third quarter of 2022 increased $65 million from $270 million for the same prior year period primarily due to increased operating and maintenance costs ($60 million) and increased workover expenditures ($8 million), both 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 $257 million for the third quarter of 2022 increased $38 million from $219 million for the same prior year period primarily due to increased transportation costs related to production from the Permian Basin.

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.

-29-

Gathering and processing costs increased $22 million to $167 million for the third quarter of 2022 compared to $145 million for the same prior year period primarily due to increased gathering and processing fees related to production from the Permian Basin ($22 million) and increased operating and maintenance expenses related to production from the Permian Basin ($14 million) and the Eagle Ford oil play ($5 million), partially offset by decreased gathering and processing fees related to production from the Eagle Ford oil play ($11 million) and due to the sale of certain legacy natural gas assets in the Rocky Mountain area in the first quarter of 2022 ($9 million).

G&A expenses of $162 million for the third quarter of 2022 increased $20 million from $142 million for the same prior year period primarily due to increased professional and other services.

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 2022 decreased $21 million to $906 million from $927 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of 2022 were $24 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($108 million) and decreased production in Trinidad ($4 million), partially offset by increased production in the United States ($89 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to higher average crude oil, NGL and natural gas prices used in the reserve estimation process and to reserves added at lower costs as a result of increased efficiencies.

Exploration costs of $35 million for the third quarter of 2022 decreased $9 million from $44 million for the same prior year period due primarily to decreased geological and geophysical expenditures in the United States.

Interest expense, net of $41 million for the third quarter of 2022 decreased $7 million compared to the same prior year period primarily due to decreased interest expense on certain royalty payments.

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 2022 and 2021 (in millions):


	Three Months Ended September 30,
	2022		2021
Proved properties	$	45	$	13
Unproved properties	49		69


Total	$	94	$	82

-30-

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 2022 increased $57 million to $334 million (5.5% of wellhead revenues) from $277 million (6.8% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes ($145 million) and increased ad valorem/property taxes ($27 million), partially offset by increased state severance tax refunds ($116 million), all in the United States.

Other income, net was $40 million for the third quarter of 2022 compared to other income, net of $6 million for the same prior year period. The change of $34 million in the third quarter of 2022 was primarily due to increased interest income ($30 million) and higher equity income from ammonia plants in Trinidad ($4 million).

EOG recognized an income tax provision of $809 million for the third quarter of 2022 compared to an income tax provision of $334 million for the third quarter of 2021, primarily due to increased pretax income. The net effective tax rate for the third quarter of 2022 decreased to 22% from 23% for the third quarter of 2021.

Nine Months Ended September 30, 2022 vs. Nine Months Ended September 30, 2021

Operating Revenues. During the first nine months of 2022, operating revenues increased $6,385 million, or 51%, to $18,983 million from $12,598 million for the same period of 2021. Total wellhead revenues for the first nine months of 2022 increased $7,094 million, or 66%, to $17,799 million from $10,705 million for the same period of 2021. During the first nine months of 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $4,215 million compared to net losses of $1,288 million for the same period of 2021. Gathering, processing and marketing revenues for the first nine months of 2022 increased $2,143 million, or 70%, to $5,199 million from $3,056 million for the same period of 2021. Net gains on asset dispositions were $101 million for the first nine months of 2022 compared to net gains of $46 million for the same period of 2021.

-31-

Wellhead volume and price statistics for the nine-month periods ended September 30, 2022 and 2021 were as follows:


	Nine Months Ended September 30,
	2022			2021
Crude Oil and Condensate Volumes (MBbld)
United States	459.2			441.3
Trinidad	0.7			1.7
Other International	—			0.1
Total	459.9			443.1
Average Crude Oil and Condensate Prices ($/Bbl) (1)
United States	$	101.16		$	65.18
Trinidad	88.84			54.33
Other International	—			42.36
Composite	101.14			65.14
Natural Gas Liquids Volumes (MBbld)
United States	200.6			140.4
Total	200.6			140.4
Average Natural Gas Liquids Prices ($/Bbl) (1)
United States	$	39.29		$	32.07
Composite	39.29			32.07
Natural Gas Volumes (MMcfd)
United States	1,293			1,170
Trinidad	192			221
Other International	—			12
Total	1,485			1,403
Average Natural Gas Prices ($/Mcf) (1)
United States	$	7.68		$	4.30
Trinidad	4.55		(2)	3.38
Other International	—			5.67
Composite	7.28			4.17
Crude Oil Equivalent Volumes (MBoed)
United States	875.3			776.8
Trinidad	32.6			38.5
Other International	—			2.0
Total	907.9			817.3

Total MMBoe	247.8			223.1

(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.

-32-

Wellhead crude oil and condensate revenues for the first nine months of 2022 increased $4,818 million, or 61%, to $12,697 million from $7,879 million for the same period of 2021 due to a higher composite average price ($4,525 million) and an increase of 16.8 MBbld, or 4%, in wellhead crude oil and condensate production ($293 million). Increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford oil play and the Rocky Mountain area. EOG's composite wellhead crude oil and condensate price for the first nine months of 2022 increased 55% to $101.14 per barrel compared to $65.14 per barrel for the same period of 2021.

NGL revenues for the first nine months of 2022 increased $922 million, or 75%, to $2,151 million from $1,229 million for the same period of 2021 due to an increase of 60.2 MBbld, or 43%, in NGL deliveries ($527 million) and a higher composite average price ($395 million). Increased production was primarily from the Permian Basin. EOG's composite NGL price for the first nine months of 2022 increased 23% to $39.29 per barrel compared to $32.07 per barrel for the same period of 2021.

Wellhead natural gas revenues for the first nine months of 2022 increased $1,354 million, or 85%, to $2,951 million from $1,597 million for the same period of 2021. The increase was due to a higher composite wellhead natural gas price ($1,262 million) and an increase in natural gas deliveries ($92 million). Natural gas deliveries for the first nine months of 2022 increased 82 MMcfd, or 6%, compared to the same period of 2021 due primarily to higher deliveries in the Dorado gas play and increased production of associated natural gas from the Permian Basin, 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 deliveries in Trinidad and lower natural gas volumes associated with the disposition of the China assets in the second quarter of 2021. EOG's composite wellhead natural gas price for the first nine months of 2022 increased 75% to $7.28 per Mcf compared to $4.17 per Mcf for the same period of 2021.

During the first nine months of 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $4,215 million compared to net losses of $1,288 million for the same period of 2021. During the first nine months of 2022, net cash paid for settlements of financial commodity derivative contracts was $3,257 million, of which $1,391 million was related to the early termination of certain contracts. Such early termination payments included $307 million to terminate contracts scheduled to settle in the second half of 2022 and $1,084 million to terminate contracts scheduled to settle after December 31, 2022. Net cash paid for settlements of financial commodity derivative contracts was $516 million for the same period of 2021.

Gathering, processing and marketing revenues less marketing costs for the first nine months of 2022 increased $125 million as compared to the same period of 2021 primarily due to higher margins on natural gas marketing activities.

Operating and Other Expenses. For the first nine months of 2022, operating expenses of $11,870 million were $2,846 million higher than the $9,024 million incurred during the same period of 2021. The following table presents the costs per Boe for the nine-month periods ended September 30, 2022 and 2021:


	Nine Months Ended September 30,
	2022		2021
Lease and Well	$	3.94	$	3.63
Transportation Costs	2.94		2.85
Gathering and Processing Costs	1.87		1.85
DD&A -
Oil and Gas Properties	10.28		11.79
Other Property, Plant and Equipment	0.47		0.49
G&A	1.67		1.67
Interest Expense, Net	0.55		0.63
Total (1)	$	21.72	$	22.91

(1)Total excludes exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

-33-

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 the nine months ended September 30, 2022, compared to the same period of 2021 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

Lease and well expenses of $977 million for the first nine months of 2022 increased $167 million from $810 million for the same prior year period primarily due to increased operating and maintenance costs ($135 million) and increased workover expenditures ($32 million), both 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 of $729 million for the first nine months of 2022 increased $94 million from $635 million for the same prior year period primarily due to increased transportation costs related to production from the Permian Basin ($75 million), the Eagle Ford oil play ($14 million) and the Dorado gas play ($7 million).

Gathering and processing costs increased $51 million to $463 million for the first nine months of 2022 compared to $412 million for the same prior year period primarily due to increased gathering and processing fees related to production from the Permian Basin ($54 million) and increased operating and maintenance expenses related to production from the Permian Basin ($34 million) and the Eagle Ford oil play ($7 million), partially offset by decreased gathering and processing fees related to production from the Eagle Ford oil play ($28 million) and due to the sale of certain legacy natural gas assets in the Rocky Mountain area in the first quarter of 2022 ($19 million).

G&A expenses of $414 million for the first nine months of 2022 increased $42 million from $372 million for the same prior year period primarily due to increased professional and other services ($22 million) and employee-related costs ($21 million).

DD&A expenses for the first nine months of 2022 decreased $77 million to $2,664 million from $2,741 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of 2022 were $81 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($379 million) and in Trinidad ($7 million), decreased production in Trinidad ($10 million) and decreased production associated with the disposition of the China assets in the second quarter of 2021 ($5 million), partially offset by increased production in the United States ($321 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to higher average crude oil, NGL and natural gas prices used in the reserve estimation process and to reserves added at lower costs as a result of increased efficiencies.

The following table represents impairments for the nine-month periods ended September 30, 2022 and 2021 (in millions):


	Nine Months Ended September 30,
	2022		2021
Proved properties	$	59	$	13
Unproved properties	157		155
Other assets	23		—
Firm commitment contracts	1		2
Total	$	240	$	170

-34-

Taxes other than income for the first nine months of 2022 increased $465 million to $1,196 million (6.7% of wellhead revenues) from $731 million (6.8% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes ($492 million), increased ad valorem/property taxes ($84 million) and increased payroll taxes ($6 million), partially offset by increased state severance tax refunds ($118 million), all in the United States.

Other income, net was $66 million for the first nine months of 2022 compared to other income, net of zero for the same prior year period. The change of $66 million in the first nine months of 2022 was primarily due to increased interest income ($36 million) and higher equity income from ammonia plants in Trinidad ($27 million).

EOG recognized an income tax provision of $1,560 million for the first nine months of 2022 compared to an income tax provision of $755 million for the first nine months of 2021, primarily due to increased pretax income. The net effective tax rate for the first nine months of 2022 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, 2022, were funds generated from operations and proceeds from sales of assets. The primary uses of cash were funds used in operations; dividend payments to stockholders; exploration and development expenditures; net cash paid for settlements of financial commodity derivative contracts; net collateral posted for financial commodity derivative contracts; and other property, plant and equipment expenditures. During the first nine months of 2022, EOG's cash balance increased $63 million to $5,272 million from $5,209 million at December 31, 2021.

Net cash provided by operating activities of $7,649 million for the first nine months of 2022 increased $2,024 million compared to the same period of 2021 primarily due to an increase in wellhead revenues ($7,094 million) and an increase in gathering, processing and marketing revenues less marketing costs ($125 million), partially offset by an increase in net cash paid for settlements of financial commodity derivative contracts ($2,741 million), an unfavorable change in net cash paid for income taxes ($1,284 million), an increase in cash operating expenses ($832 million), net cash used in working capital and other assets and liabilities in the first nine months of 2022 ($999 million) compared to net cash used in working capital and other assets and liabilities in the first nine months of 2021 ($590 million) and an increase in net collateral posted for financial commodity derivative contracts ($238 million).

Net cash used in investing activities of $3,659 million for the first nine months of 2022 increased $1,077 million compared to the same period of 2021 due to an increase in additions to oil and gas properties ($701 million), net cash used in working capital associated with investing activities in the first nine months of 2022 ($301 million) compared to net cash provided by working capital associated with investing activities in the first nine months of 2021 ($100 million), an increase in additions to other property, plant and equipment ($101 million) and an increase in other investing activities ($30 million), partially offset by an increase in proceeds from the sale of assets ($156 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). Net cash used in financing activities of $2,079 million for the first nine months of 2021 included cash dividend payments ($1,278 million), repayments of long-term debt ($750 million), purchases of treasury stock in connection with stock compensation plans ($33 million) and repayment of finance lease liabilities ($27 million).

-35-

Total Expenditures. For the year 2022, EOG's updated budget for exploration and development and other property, plant and equipment expenditures is estimated to range from approximately $4.5 billion to $4.7 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, 2022 and 2021 (in millions):


	Nine Months Ended September 30,
	2022		2021
Expenditure Category
Capital
Exploration and Development Drilling	$	2,599	$	2,097
Facilities	291		287
Leasehold Acquisitions (1)	148		194
Property Acquisitions (2)	398		99
Capitalized Interest	26		24
Subtotal	3,462		2,701
Exploration Costs	115		112
Dry Hole Costs	41		28
Exploration and Development Expenditures	3,618		2,841
Asset Retirement Costs	209		56
Total Exploration and Development Expenditures	3,827		2,897
Other Property, Plant and Equipment (3)	248		221
Total Expenditures	$	4,075	$	3,118

(1) Leasehold acquisitions included $107 million and $37 million for the nine-month periods ended September 30, 2022 and 2021, respectively, related to non-cash property exchanges.

(2) Property acquisitions included $6 million and $4 million for the nine-month periods ended September 30, 2022 and 2021, respectively, related to non-cash property exchanges.

(3) Other property, plant and equipment included $74 million of non-cash additions for the nine-month period ended September 30, 2021, primarily related to finance lease transactions for storage facilities.

Exploration and development expenditures of $3,618 million for the first nine months of 2022 were $777 million higher than the same period of 2021 primarily due to increased exploration and development drilling expenditures in the United States ($520 million) and increased property acquisitions ($299 million), partially offset by decreased leasehold acquisitions ($46 million) and decreased exploration and development drilling expenditures in Other International ($21 million). 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. Exploration and development expenditures for the first nine months of 2021 of $2,841 million consisted of $2,299 million in development drilling and facilities, $419 million in exploration, $99 million in property acquisitions and $24 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.

-36-

Financial Commodity Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2021 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 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, net of associated collateral posted, was reflected on the Condensed Consolidated Balance Sheets at September 30, 2022, as a net liability of $642 million.

As discussed in "Operating Revenues and Other," the net cash paid for settlements of financial commodity derivative contracts during the third quarter and first nine months of 2022 was $847 million and $3,257 million, respectively, of which $63 million and $1,391 million, respectively, during the third quarter and first nine months of 2022 was related to the early termination of certain contracts; see the below summary tables for further discussion.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2022 to October 28, 2022 (closed) and outstanding as of October 28, 2022. Crude oil and NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

-37-


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 2022 (closed)	NYMEX West Texas Intermediate (WTI)	140	$	65.58	—	$	—
April - June 2022 (closed)	NYMEX WTI	140	65.62		—	—
July - September 2022 (closed)	NYMEX WTI	140	65.59		—	—
October - December 2022 (closed) (1)	NYMEX WTI	53	66.11		—	—
October - December 2022	NYMEX WTI	87	65.41		87	88.85
January - March 2023 (closed) (1) (2)	NYMEX WTI	55	67.96		—	—
January - March 2023	NYMEX WTI	95	67.90		6	102.26
April - May 2023 (closed) (1)	NYMEX WTI	29	68.28		—	—
April - May 2023	NYMEX WTI	91	67.63		2	98.15
June 2023 (closed) (1)	NYMEX WTI	118	67.77		—	—
June 2023	NYMEX WTI	2	69.10		2	98.15
July - September 2023 (closed) (1)	NYMEX WTI	100	70.15		—	—
October - December 2023 (closed) (1)	NYMEX WTI	69	69.41		—	—

(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.


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

January - November 2022 (closed)	NYMEX WTI Roll Differential (1)	125	$	0.15
December 2022	NYMEX WTI Roll Differential (1)	125	0.15

(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.

-38-


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

January - September 2022 (closed)	NYMEX Henry Hub	725	$	3.57
October - December 2022 (closed) (1)	NYMEX Henry Hub	425	3.05
October - November 2022 (closed)	NYMEX Henry Hub	300	4.32
December 2022	NYMEX Henry Hub	300	4.32
January - December 2023 (closed) (1)	NYMEX Henry Hub	425	3.05
January - 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

(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.


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

January - September 2022 (closed)	NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)	210	$	0.01
October - December 2022	NYMEX Henry Hub HSC Differential (1)	210	0.01
January - December 2023	NYMEX Henry Hub HSC Differential (1)	135	0.01
January - December 2024	NYMEX Henry Hub HSC Differential (1)	10	0.00
January - December 2025	NYMEX Henry Hub HSC Differential (1)	10	0.00

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

In connection with its financial commodity derivative contracts, EOG had $623 million of collateral posted at November 2, 2022. EOG expects this collateral to be applied to the settlement of financial commodity derivative contracts if market prices remain above contract prices. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX WTI and Henry Hub prices.

-39-

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 operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward‐looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

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

-40-

the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
the availability and cost of, and competition in the oil and gas exploration and production industry for, employees and other personnel, facilities, equipment, materials (such as water, sand and tubulars) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent to which EOG is successful in its completion of planned asset dispositions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
acts of war and terrorism and responses to these acts; and
the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2021 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.

-41-

PART I. FINANCIAL INFORMATION

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