PR Newswire | Nov 4, 2021 04:16PM EDT

Dividend 82% and Declares $2.00 per Share Special Dividend

11/04 15:15 CDT

EOG Resources Reports Excellent Third Quarter 2021 Results; Raises Regular Dividend 82% and Declares $2.00 per Share Special Dividend HOUSTON, Nov. 4, 2021

HOUSTON, Nov. 4, 2021 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported third quarter 2021 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

KeyFinancialResults

In millions of USD, except per-share and ratio data

3Q 2021 2Q 2021 3Q 2020

Total Revenue 4,765 4,139 2,246

Net Income (Loss) 1,095 907 (42)

Net Income (Loss) Per Share 1.88 1.55 (0.07)

Net Cash Provided by Operating Activities 2,196 1,559 1,214GAAP Total Expenditures 962 1,089 646

Current and Long-Term Debt 5,117 5,125 5,721

Cash and Cash Equivalents 4,293 3,880 3,066

Debt-to-Total Capitalization 19.0 % 19.7 % 22.1 %

Adjusted Net Income 1,264 1,012 252

Adjusted Net Income Per Share 2.16 1.73 0.43

Discretionary Cash Flow 2,296 2,030 1,261

Non-GAAP Cash Capital Expenditures before Acquisitions 935 972 499

Free Cash Flow 1,361 1,058 762

Net Debt 824 1,245 2,655

Net Debt-to-Total Capitalization 3.6 % 5.6 % 11.6 %

Third Quarter 2021 Highlights

* Increased regular dividend 82% to an indicated annual rate of $3.00 per share * Declared special dividend of $2.00 per share * Updated share repurchase authorization * Earned adjusted net income of $1.3 billion, or $2.16 per share * Generated $1.4 billion of free cash flow * Capital expenditures near low end of guidance range driven by sustainable cost reductions * Oil and NGL production above high end of guidance ranges * Total per-unit cash operating costs below guidance midpoint

Volumes and Capital Expenditures

3Q 2021Wellhead Volumes 3Q 2021 Guidance 2Q 2021 3Q 2020 Midpoint

Crude Oil and Condensate (MBod) 449.5 444.5 448.6 377.6

Natural Gas Liquids (MBbld) 157.9 140.0 138.5 140.1

Natural Gas (MMcfd) 1,422 1,410 1,445 1,190

Total Crude Oil Equivalent (MBoed) 844.4 819.5 828.0 716.0

Cash Capital Expenditures before Acquisitions ($MM) 935 1,000 972 499

From Ezra Yacob, Chief Executive Officer"EOG delivered exceptionally strong earnings and free cash flow in the third quarter driven by our double premium investment program. We extended our track record of reliable execution with better than expected production, capital expenditures, operating costs and product prices.

"For the second time this year, we've increased our dividend rate. This quarter's 82 percent raise brings our indicated annual rate to $3.00 per share, doubling the dividend compared to last year. Our high-return investment program, first spurred by our shift to a premium investment standard in 2016 and followed by the double premium standard instituted last year, has positioned the company to step up our cash return to shareholders. The sizable increase in the regular dividend closes the gap between the prior dividend level and the significant improvement in EOG's profitability since 2016. It should also be taken as a signal of our confidence that we can continue improving in the future.

"We also continue to deliver on our other cash return priorities, with a second special dividend to be paid this year and an update to our share repurchase authorization. Share repurchases provide the opportunity to create additional value for stockholders when executed prudently and at the right time. We remain firmly committed to our long-term free cash flow priorities.

"EOG has never been in better shape. Our high-return business model is sustainable for the long term, underpinned by a deep inventory of double premium drilling locations. We also remain optimistic about the potential of new exploration plays to improve the overall quality of our inventory. Our financial and operational results, our world-class assets as well as our continued progress on exploration are a testament to the strength of EOG's underlying business, all driven by our talented employees and unique culture. We are well positioned to be one of the lowest cost and lowest emissions producers and generate superior cash returns, free cash flow growth and long-term shareholder value."

Third Quarter 2021 Financial Performance

Adjusted Earnings per Share 3Q 2021 vs 2Q 2021

Prices and HedgesNatural gas, crude oil and NGL prices increased significantly in 3Q compared with 2Q, partially offset by an increase in cash paid for hedge settlements in 3Q of $100 million compared with 2Q.

VolumesTotal company crude oil production of 449,500 Bopd was above the high end of the guidance range due to better well productivity. Increased extraction of ethane boosted NGL production 14% higher than 2Q while contributing to slightly lower natural gas production, along with declines related to plant downtime in Trinidad. Total company equivalent volumes increased 2% compared with 2Q.

Per-Unit CostsPer-unit cash operating costs in 3Q were 5% below the midpoint of the guidance range, primarily due to lower than forecasted lease and well and transportation costs. Compared with 2Q, per-unit cash operating costs increased 3% due to higher gathering and processing and general and administrative costs. In addition, per-unit taxes other than income increased compared with 2Q due to higher product prices.

Change in Cash 3Q 2021 vs 2Q 2021

Free Cash FlowEOG generated discretionary cash flow (net cash provided by operating activities before exploration costs and changes in working capital) of $2.3 billion in 3Q. The company incurred $935 million of cash capital expenditures before acquisitions, resulting in $1.4 billion of free cash flow.

Capital ExpendituresCash capital expenditures before acquisitions of $935 million were near the low end of the guidance range due to lower well costs from sustainable efficiency improvements. EOG was able to offset inflationary pressures with efficiency improvements in many areas. In particular, the application of "super-zipper" completion techniques, faster drilling times, lower-cost sand sourcing and the addition of infrastructure to procure lower-cost water all contributed to the overall cost reductions.

Third Quarter 2021 Operating Performance

Lease and WellPer-unit LOE costs were $0.32 below the guidance mid-point due to lower water handling and compression costs. Per-unit LOE costs were $0.10 below 2Q due to overall efficiency improvements. Per- unit costs were in-line with 3Q 2020.

Transportation, Gathering and ProcessingPer-unit transportation costs were below the guidance mid- point due to lower than expected NGL and oil transportation fees. Per-unit G&P costs increased from 2Q due to higher fuel prices while transportation costs were in-line with 2Q. Per-unit transportation and G&P costs increased 3% and 7%, respectively, compared with 3Q 2020 due to increased fuel prices and higher storage and terminal fees.

General and AdministrativePer-unit G&A costs were in line with the guidance midpoint. Per-unit G&A costs were above 2Q due to seasonally higher employee related costs. Per-unit G&A costs decreased from 3Q 2020 as increased production volumes more than offset increased employee related costs.

Depreciation, Depletion and AmortizationPer-unit DD&A costs were slightly below the guidance midpoint and declined 2% and 4% compared with 2Q 2021 and 3Q 2020, respectively, due to the addition of reserves from new wells at lower finding costs.

Free Cash Flow Allocation Actions

Declared $0.75 per Share Regular Dividend - 82% Increase to $3.00 per Share Indicated Annual Rate

The Board of Directors today declared a regular dividend of $0.75 per share on EOG's Common Stock. The dividend is payable January 28, 2022 to stockholders of record as of January 14, 2022. The new dividend represents a $3.00 per share indicated annual rate, an 82% increase from the previous level. The annual cash commitment towards the dividend is $785 million higher and reflects EOG's low cost of supply, robust cash flow generation and strong balance sheet. A growing, sustainable dividend is the company's primary mode of returning cash to shareholders. EOG has a long track record of delivering against this objective as the company has never suspended or reduced its regular dividend.

$2.00 per Share Special DividendThe Board of Directors today also declared a special dividend of $2.00 per share on EOG's Common Stock. The dividend is payable December 30, 2021 to stockholders of record as of December 15, 2021. EOG has now committed to return $2.7 billion of cash to stockholders in 2021, representing approximately 30 percent of expected 2021 discretionary cash flow.

Share Repurchase AuthorizationIn addition, the Board of Directors today updated EOG's share repurchase authorization to $5 billion. The updated authorization is consistent with EOG's long-standing cash flow priorities and complements existing avenues to return cash to shareholders through regular and special dividends. The repurchase authorization enables EOG to opportunistically increase per-share value for stockholders.

Third Quarter 2021 Results vs Guidance

(Unaudited)

3Q 2021Crude Oil and Condensate Volumes (MBod) 3Q 2021 Guidance Variance 2Q 2021 1Q 2021 4Q 2020 3Q 2020 Midpoint

United States 448.3 443.5 4.8 446.9 428.7 442.4 376.6

Trinidad 1.2 1.0 0.2 1.7 2.2 2.3 1.0

Other International 0.0 0.0 0.0 0.0 0.1 0.1 0.0

Total 449.5 444.5 5.0 448.6 431.0 444.8 377.6

Natural Gas Liquids Volumes (MBbld)

Total 157.9 140.0 17.9 138.5 124.3 141.4 140.1

Natural Gas Volumes (MMcfd)

United States 1,210 1,200 10 1,199 1,100 1,075 1,008

Trinidad 212 210 2 233 217 192 151

Other International 0 0 0 13 25 25 31

Total 1,422 1,410 12 1,445 1,342 1,292 1,190

Total Crude Oil Equivalent Volumes (MBoed) 844.4 819.5 24.9 828.0 778.9 801.5 716.0

Total MMBoe 77.7 75.4 2.3 75.3 70.1 73.7 65.9

Benchmark Price

Oil (WTI) ($/Bbl) 70.55 66.06 57.80 42.67 40.94

Natural Gas (HH) ($/Mcf) 4.01 2.83 2.69 2.65 1.94

Crude Oil and Condensate - above (below) WTI ($/Bbl)

United States 0.33 0.30 0.03 0.10 0.27 (0.81) (0.75)

Trinidad (10.36) (7.50) (2.86) (9.80) (8.03) (9.76) (15.53)

Natural Gas Liquids - Realizations as % of WTI 53.5% 50.0% 3.5% 44.1% 48.5% 41.1% 35.0%

Natural Gas - above (below) NYMEX Henry Hub ($/Mcf)

United States 0.49 0.30 0.19 0.16 2.83 (0.36) (0.45)

Natural Gas Realizations ($/Mcf)

Trinidad 3.39 3.35 0.04 3.37 3.38 3.57 2.35

Total Expenditures (GAAP) ($MM) 962 1,089 1,067 1,107 646

Capital Expenditures (non-GAAP) ($MM) 935 1,000 (65) 972 945 828 499

Operating Unit Costs ($/Boe)

Lease and Well 3.48 3.80 (0.32) 3.58 3.85 3.54 3.45

Transportation Costs 2.82 3.00 (0.18) 2.84 2.88 2.64 2.74

Gathering and Processing 1.87 1.90 (0.03) 1.70 1.98 1.62 1.74

General and Administrative 1.83 1.80 0.03 1.59 1.57 1.54 1.89

Cash Operating Costs 10.00 10.50 (0.50) 9.71 10.28 9.34 9.82

Depreciation, Depletion and Amortization 11.93 12.00 (0.07) 12.13 12.84 11.81 12.49

Expenses ($MM)

Exploration and Dry Hole 48 40 8 49 44 40 51

Impairment (GAAP) 82 44 44 143 79

Impairment (excluding certain impairments (non-GAAP)) 69 85 (16) 43 43 57 52

Capitalized Interest 8 8 0 8 8 7 7

Net Interest 48 45 3 45 47 53 53

Taxes Other Than Income (% of Wellhead Revenue) 6.8% 7.0% (0.2%) 6.9% 6.7% 5.1% 7.2%

Income Taxes

Effective Rate 23.4% 23.5% (0.1%) 19.3% 23.2% 21.1% 19.2%

Deferred Ratio (33%) 33% (66%) (45%) (18%) 60% 330%

Fourth Quarter and Full-Year 2021 Guidance2

(Unaudited)

See "Endnotes" below for 4Q 2021 FY 2021 2020 2019related discussion and Guidance Range Guidance Range Actual Actualdefinitions.

Crude Oil and CondensateVolumes (MBod)

United States 442.0 - 450.0 441.5 - 443.5 408.1 455.5

Trinidad 0.5 - 1.5 1.4 - 1.6 1.0 0.6

Other International 0.0 - 0.0 0.0 - 0.0 0.1 0.1

Total 442.5 - 451.5 442.9 - 445.1 409.2 456.2

Natural Gas Liquids Volumes(MBbld)

Total 148.0 - 158.0 142.3 - 144.8 136.0 134.1

Natural Gas Volumes (MMcfd)

United States 1,285 - 1,385 1,199 - 1,225 1,040 1,069

Trinidad 185 - 215 212 - 219 180 260

Other International 0 - 0 9 - 10 32 37

Total 1,470 - 1,600 1,420 - 1,454 1,252 1,366

Crude Oil Equivalent Volumes(MBoed)

United States 804.2 - 838.8 783.6 - 792.5 717.5 767.8

Trinidad 31.3 - 37.3 36.7 - 38.1 30.9 44.0

Other International 0.0 - 0.0 1.5 - 1.7 5.4 6.2

Total 835.5 - 876.1 821.8 - 832.3 753.8 818.0

Benchmark Price

Oil (WTI) ($/Bbl) 39.40 57.04

Natural Gas (HH) ($/Mcf) 2.08 2.62

Crude Oil and Condensate Differentials - above (below) WTI^3 ($/Bbl)

United States 0.20 - 1.20 0.30 - 0.60 (0.75) 0.70

Trinidad (12.00) - (10.00) (12.79) - (10.64) (9.20) (9.88)

Natural Gas Liquids -Realizations as % of WTI

Total 50% - 60% 50% - 53% 34.0% 28.1%

Natural Gas Differentials - above (below) NYMEX Henry Hub^4 ($/Mcf)

United States 0.60 - 1.60 0.95 - 1.30 (0.47) (0.40)

Natural Gas Realizations ($/Mcf)

Trinidad 3.20 - 3.70 3.34 - 3.46 2.57 2.72

Total Expenditures (GAAP) 4,113 6,900($MM)

Capital Expenditures5 950 - 1,150 3,800 - 4,000 3,490 6,234(non-GAAP) ($MM)

Operating Unit Costs ($/Boe)

Lease and Well 3.40 - 4.10 3.57 - 3.76 3.85 4.58

Transportation Costs 2.75 - 3.15 2.82 - 2.93 2.66 2.54

Gathering and Processing 1.80 - 2.00 1.83 - 1.89 1.66 1.60

General and Administrative 1.50 - 1.60 1.62 - 1.65 1.75 1.64

Cash Operating Costs 9.45 - 10.85 9.84 - 10.23 9.92 10.36

Depreciation, Depletion and 11.40 - 12.00 12.06 - 12.21 12.32 12.56Amortization

Expenses ($MM)

Exploration and Dry Hole 40 - 45 180 - 185 159 168

Impairment (GAAP) 2,100 518

Impairment (excludingcertain impairments 100 - 140 257 - 297 232 243(non-GAAP))

Capitalized Interest 5 - 10 29 - 34 31 38

Net Interest 42 - 48 182 - 188 205 185

Taxes Other Than Income (% 6.0% - 8.0% 6.5% - 7.5% 6.6% 6.9%of Wellhead Revenue)

Income Taxes

Effective Rate 21% - 26% 20% - 25% 18.2% 22.9%

Deferred Ratio 5% - 20% (20%) - (5%) 54.8% 107.4%

Third Quarter 2021 Results WebcastFriday, November 5, 2021, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. http://investors.eogresources.com/Investors

About EOGEOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com.

Investor ContactsDavid Streit 713?571?4902 Neel Panchal 713?571?4884

Media and Investor ContactKimberly Ehmer 713?571?4676

Endnotes

1) The 2022 dividend amount reflects the indicated annual rate of the quarterly dividend declared on November 4, 2021.

The forecast items for the fourth quarter and full year 2021 set forth above for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to2) update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

EOG bases United States and Trinidad crude oil and condensate price3) differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

EOG bases United States natural gas price differentials upon the natural gas4) price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs,5) Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.

Glossary

Acq Acquisitions

ATROR After-tax rate of return

Bbl Barrel

Bn Billion

Boe Barrels of oil equivalent

Bopd Barrels of oil per dayCAGR Compound annual growth rate

Capex Capital expenditures

CO2e Carbon dioxide equivalent

DCF Discretionary cash flow

DD&A Depreciation, Depletion and Amortization

Disc Discoveries

Divest Divestitures

EPS Earnings per share

Ext Extensions

G&A General and administrative expense

G&P Gathering and processing expense

GHG Greenhouse gas

HH Henry Hub

LOE Lease operating expense, or lease and well expense

MBbld Thousand barrels of liquids per day

MBod Thousand barrels of oil per day

MBoe Thousand barrels of oil equivalent

MBoed Thousand barrels of oil equivalent per day

Mcf Thousand cubic feet of natural gas

MMBoe Million barrels of oil equivalent

MMcfd Million cubic feet of natural gas per day

NGLs Natural gas liquids

OTP Other than price

NYMEX U.S. New York Mercantile Exchange

QoQ Quarter over quarter

Trans Transportation expense

USD United States dollar

WTI West Texas Intermediate

YoY Year over year

$MM Million United States dollars

$/Bbl U.S. Dollars per barrel

$/Boe U.S. Dollars per barrel of oil equivalent

$/Mcf U.S. Dollars per thousand cubic feet

This press release may include 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," "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 goals or ambitions 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. Furthermore, this press release and any accompanying disclosures may include or reference certain forward?looking, non?GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward?looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward?looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward?looking, non?GAAP financial measures to the respective most directly comparable forward?looking GAAP financial measures. Management believes these forward?looking, non?GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward?looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. 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, 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, natural gas liquids, 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, and competition for, 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 any changes or other actions which may result from the recent U.S. elections and change in U.S. administration and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, 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; * 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 and economically; * competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services; * the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services; * the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; * weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities; * the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; * EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; * the extent to which EOG is successful in its completion of planned asset dispositions; * the extent and effect of any hedging activities engaged in by EOG; * the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; * the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic; * geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates; * the use of competing energy sources and the development of alternative energy sources; * 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, 2020 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.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10?K for the fiscal year ended December 31, 2020, available from EOG at P.O. Box 4362, Houston, Texas 77210?4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1?800?SEC?0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non?GAAP financial measures can be found on the EOG website at www.eogresources.com.

Income Statements

In millions of USD, except share data (in millions) and per share data(Unaudited)

3Q 2021 2Q 2021 3Q 2020 YTD 2021 YTD 2020

Operating Revenues and Other

Crude Oil and Condensate 2,929 2,699 1,395 7,879 4,075

Natural Gas Liquids 548 367 185 1,229 439

Natural Gas 568 404 184 1,597 535

Gains (Losses) on Mark-to-Market (494) (427) (4) (1,288) 1,075 Commodity Derivative Contracts

Gathering, Processing and Marketing 1,186 1,022 539 3,056 1,940

Gains (Losses) on Asset Dispositions, Net 1 51 (71) 46 (41)

Other, Net 27 23 18 79 44

Total 4,765 4,139 2,246 12,598 8,067

Operating Expenses

Lease and Well 270 270 227 810 802

Transportation Costs 219 214 180 635 540

Gathering and Processing Costs 145 128 115 412 340

Exploration Costs 44 35 38 112 105

Dry Hole Costs 4 13 13 28 13

Impairments 82 44 79 170 1,957

Marketing Costs 1,184 991 523 3,013 2,077

Depreciation, Depletion and Amortization 927 914 823 2,741 2,530

General and Administrative 142 120 125 372 371

Taxes Other Than Income 277 239 126 731 364

Total 3,294 2,968 2,249 9,024 9,099

Operating Income (Loss) 1,471 1,171 (3) 3,574 (1,032)

Other Income (Expense), Net 6 (2) 3 - 17

Income (Loss) Before Interest Expense 1,477 1,169 - 3,574 (1,015) and Income Taxes

Interest Expense, Net 48 45 53 140 152

Income (Loss) Before Income Taxes 1,429 1,124 (53) 3,434 (1,167)

Income Tax Provision (Benefit) 334 217 (11) 755 (225)

Net Income (Loss) 1,095 907 (42) 2,679 (942)

Dividends Declared per Common Share 0.4125 1.4125 0.3750 2.2375 1.1250

Net Income (Loss) Per Share

Basic 1.88 1.56 (0.07) 4.62 (1.63)

Diluted 1.88 1.55 (0.07) 4.59 (1.63)

Average Number of Common Shares

Basic 581 580 579 580 579

Diluted 584 584 579 584 579

Wellhead Volumes and Prices

(Unaudited)

3Q 2021 3Q2020 % Change 2Q 2021 YTD 2021 YTD 2020 % Change

Crude Oil and Condensate Volumes

(MBbld) ^(A)

United States 448.3 376.6 19 % 446.9 441.3 396.6 11 %

Trinidad 1.2 1.0 20 % 1.7 1.7 0.5 240 %

Other International ^(B) - - - 0.1 0.2 -50 %

Total 449.5 377.6 19 % 448.6 443.1 397.3 12 %

Average Crude Oil and Condensate Prices

($/Bbl) ^(C)

United States 70.88 40.19 76 % 66.16 65.18 37.45 74 %

Trinidad 60.19 25.41 137 % 56.26 54.33 26.35 106 %

Other International ^(B) - 25.29 -100 % 55.56 42.36 45.09 -6 %

Composite 70.85 40.15 76 % 66.12 65.14 37.44 74 %

Natural Gas Liquids Volumes (MBbld) ^(A)

United States 157.9 140.1 13 % 138.5 140.4 134.2 5 %

Total 157.9 140.1 13 % 138.5 140.4 134.2 5 %

Average Natural Gas Liquids Prices

($/Bbl) ^(C)

United States 37.72 14.34 163 % 29.15 32.07 11.95 168 %

Composite 37.72 14.34 163 % 29.15 32.07 11.95 168 %

Natural Gas Volumes (MMcfd) ^(A)

United States 1,210 1,008 20 % 1,199 1,170 1,029 14 %

Trinidad 212 151 40 % 233 221 175 26 %

Other International ^(B) - 31 -100 % 13 12 34 -65 %

Total 1,422 1,190 19 % 1,445 1,403 1,238 13 %

Average Natural Gas Prices ($/Mcf) ^(C)

United States 4.50 1.49 203 % 2.99 4.30 1.38 213 %

Trinidad 3.39 2.35 44 % 3.37 3.38 2.20 53 %

Other International ^(B) - 4.73 -100 % 5.69 5.67 4.45 27 %

Composite 4.34 1.68 158 % 3.07 4.17 1.58 164 %

Crude Oil Equivalent Volumes (MBoed) ^(D)

United States 807.9 684.7 18 % 785.2 776.8 702.3 11 %

Trinidad 36.5 26.2 39 % 40.6 38.5 29.8 29 %

Other International ^(B) - 5.1 -100 % 2.2 2.0 5.7 -65 %

Total 844.4 716.0 18 % 828.0 817.3 737.8 11 %

Total MMBoe ^(D) 77.7 65.9 18 % 75.3 223.1 202.2 10 %

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

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

Dollars per barrel or per thousand cubic feet, as applicable. Excludes the(C) impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2021).

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural(D) 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.

Balance Sheets

In millions of USD, except share data (Unaudited)

September 30, December 31,

2021 2020

Current Assets

Cash and Cash Equivalents 4,293 3,329

Accounts Receivable, Net 2,154 1,522

Inventories 521 629

Assets from Price Risk Management Activities 18 65

Income Taxes Receivable - 23

Other 363 294

Total 7,349 5,862

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method) 67,024 64,793

Other Property, Plant and Equipment 4,694 4,479

Total Property, Plant and Equipment 71,718 69,272

Less: Accumulated Depreciation, Depletion and Amortization (43,173) (40,673)

Total Property, Plant and Equipment, Net 28,545 28,599

Deferred Income Taxes 14 2

Other Assets 1,264 1,342

Total Assets 37,172 35,805

Current Liabilities

Accounts Payable 1,972 1,681

Accrued Taxes Payable 492 206

Dividends Payable 240 217

Liabilities from Price Risk Management Activities 238 -

Current Portion of Long-Term Debt 38 781

Current Portion of Operating Lease Liabilities 250 295

Other 254 280

Total 3,484 3,460

Long-Term Debt 5,079 5,035

Other Liabilities 2,214 2,149

Deferred Income Taxes 4,630 4,859

Commitments and Contingencies

Stockholders' Equity

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 585,361,866 Shares Issued at September 30, 2021 and 583,694,850 Shares Issued at 206 206 December 31, 2020

Additional Paid in Capital 6,058 5,945

Accumulated Other Comprehensive Loss (13) (12)

Retained Earnings 15,542 14,170

Common Stock Held in Treasury, 371,249 Shares at September 30, 2021 and (28) (7) 124,265 Shares at December 31, 2020

Total Stockholders' Equity 21,765 20,302

Total Liabilities and Stockholders' Equity 37,172 35,805

Cash Flows Statements

In millions of USD (Unaudited)

3Q 2021 3Q 2020 2Q 2021 YTD 2021 YTD 2020

Cash Flows from Operating Activities

Reconciliation of Net Income (Loss) to Net Cash Provided

by Operating Activities:

Net Income (Loss) 1,095 (42) 907 2,679 (942)

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization 927 823 914 2,741 2,530

Impairments 82 79 44 170 1,957

Stock-Based Compensation Expenses 51 33 31 117 113

Deferred Income Taxes (111) (33) (97) (244) (241)

(Gains) Losses on Asset Dispositions, Net (1) 71 (51) (46) 41

Other, Net 2 2 6 15 2

Dry Hole Costs 4 13 13 28 13

Mark-to-Market Commodity Derivative Contracts

Total (Gains) Losses 494 4 427 1,288 (1,075)

Net Cash Received from (Payments for) Settlements (293) 275 (193) (516) 999 of Commodity Derivative Contracts

Other, Net 7 (1) - 8 (1)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable (145) (260) (186) (639) 931

Inventories (6) 7 37 95 92

Accounts Payable (68) (37) 11 115 (1,222)

Accrued Taxes Payable 206 73 (163) 286 12

Other Assets 167 162 (119) (55) 415

Other Liabilities (260) 51 32 (317) (13)

Changes in Components of Working Capital Associated 45 (6) (54) (100) 276 with Investing Activities

Net Cash Provided by Operating Activities 2,196 1,214 1,559 5,625 3,887

Investing Cash Flows

Additions to Oil and Gas Properties (846) (469) (968) (2,689) (2,459)

Additions to Other Property, Plant and Equipment (50) (18) (55) (147) (165)

Proceeds from Sales of Assets 8 146 141 154 189

Changes in Components of Working Capital Associated (45) 6 54 100 (276) with Investing Activities

Net Cash Used in Investing Activities (933) (335) (828) (2,582) (2,711)

Financing Cash Flows

Long-Term Debt Borrowings - - - - 1,484

Long-Term Debt Repayments - - - (750) (1,000)

Dividends Paid (820) (217) (239) (1,278) (601)

Treasury Stock Purchased (21) (10) (2) (33) (15)

Proceeds from Stock Options Exercised and Employee - - 9 9 8 Stock Purchase Plan

Debt Issuance Costs - - - - (3)

Repayment of Finance Lease Liabilities (9) (5) (9) (27) (13)

Net Cash Used in Financing Activities (850) (232) (241) (2,079) (140)

Effect of Exchange Rate Changes on Cash - 2 2 - 2

Increase in Cash and Cash Equivalents 413 649 492 964 1,038

Cash and Cash Equivalents at Beginning of Period 3,880 2,417 3,388 3,329 2,028

Cash and Cash Equivalents at End of Period 4,293 3,066 3,880 4,293 3,066

Non-GAAP Financial Measures



To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United Statesof America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not preparedor presented in accordance with GAAP. These non-GAAP financial measures mayinclude, but are not limited to, Adjusted Net Income (Loss), Discretionary Cash Flow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics.



A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the "Reconciliations & Guidance"section of the "Investors" page of the EOG website at www.eogresources.com.



As further discussed in the tables on the following pages, EOG believes thesemeasures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance.



EOG believes that the non-GAAP measures presented, when viewed in combinationwith its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting thecompany's performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods.



The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP.



In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time - for example, to account for changes in its business and operations or to more closely conformto peer company or industry analysts' practices.

Adjusted Net Income (Loss)

In millions of USD, except share data (in millions) and per share data(Unaudited)

The following tables adjust the reported Net Income (Loss) (GAAP) to reflectactual net cash received from (payments for) settlements of commodityderivative contracts by eliminating the unrealized mark-to-market (gains)losses from these transactions, to eliminate the net (gains) losses on assetdispositions, to add back impairment charges related to certain of EOG's assets(which are generally (i) attributable to declines in commodity prices, (ii)related to sales of certain oil and gas properties or (iii) the result ofcertain other events or decisions (e.g., a periodic review of EOG's oil and gasproperties or other assets) - see "Revenues, Costs and Margins Per Barrel ofOil Equivalent" below for additional related discussion) and to make certainother adjustments to exclude non-recurring and certain other items as furtherdescribed below. EOG believes this presentation may be useful to investors whofollow the practice of some industry analysts who adjust reported companyearnings to match hedge realizations to production settlement months and makecertain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financialperformance with the financial performance of other companies in the industry.

3Q 2021

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Income (GAAP) 1,429 (334) 1,095 1.88

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts 494 (108) 386 0.65

Net Cash Payments for Settlements of Commodity Derivative Contracts (293) 64 (229) (0.39)

Less: Gains on Asset Dispositions, Net (1) - (1) -

Add: Certain Impairments 13 - 13 0.02

Adjustments to Net Income 213 (44) 169 0.28

Adjusted Net Income (Non-GAAP) 1,642 (378) 1,264 2.16

Average Number of Common Shares (GAAP)

Basic 581

Diluted 584

Average Number of Common Shares (Non-GAAP)

Basic 581

Diluted 584

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data(Unaudited)

3Q 2020

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Loss (GAAP) (53) 11 (42) (0.07)

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts 4 - 4 0.01

Net Cash Received from Settlements of Commodity Derivative Contracts 275 (60) 215 0.37

Add: Losses on Asset Dispositions, Net 71 (16) 55 0.09

Add: Certain Impairments 27 (7) 20 0.03

Adjustments to Net Loss 377 (83) 294 0.50

Adjusted Net Income (Non-GAAP) 324 (72) 252 0.43

Average Number of Common Shares (GAAP)

Basic 579

Diluted 579

Average Number of Common Shares (Non-GAAP)

Basic 579

Diluted 581

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data(Unaudited)

2Q 2021

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Income (GAAP) 1,124 (217) 907 1.55

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts 427 (93) 334 0.58

Net Cash Payments for Settlements of Commodity Derivative Contracts (193) 42 (151) (0.26)

Less: Gains on Asset Dispositions, Net (51) 17 (34) (0.06)

Add: Certain Impairments 1 - 1 -

Less: Tax Benefits Related to Exiting Canada Operations - (45) (45) (0.08)

Adjustments to Net Income 184 (79) 105 0.18

Adjusted Net Income (Non-GAAP) 1,308 (296) 1,012 1.73

Average Number of Common Shares (GAAP)

Basic 580

Diluted 584

Average Number of Common Shares (Non-GAAP)

Basic 580

Diluted 584

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data(Unaudited)

YTD 2021

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Income (GAAP) 3,434 (755) 2,679 4.59

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts 1,288 (282) 1,006 1.72

Net Cash Payments for Settlements of Commodity Derivative Contracts (516) 113 (403) (0.69)

Less: Gains on Asset Dispositions, Net (46) 16 (30) (0.05)

Add: Certain Impairments 15 - 15 0.03

Less: Tax Benefits Related to Exiting Canada Operations - (45) (45) (0.08)

Adjustments to Net Income 741 (198) 543 0.93

Adjusted Net Income (Non-GAAP) 4,175 (953) 3,222 5.52

Average Number of Common Shares (GAAP)

Basic 580

Diluted 584

Average Number of Common Shares (Non-GAAP)

Basic 580

Diluted 584

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data(Unaudited)

YTD 2020

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Loss (GAAP) (1,167) 225 (942) (1.63)

Adjustments:

Gains on Mark-to-Market Commodity Derivative Contracts (1,075) 236 (839) (1.45)

Net Cash Received from Settlements of Commodity Derivative Contracts 999 (219) 780 1.35

Add: Losses on Asset Dispositions, Net 41 (9) 32 0.06

Add: Certain Impairments 1,782 (374) 1,408 2.43

Adjustments to Net Loss 1,747 (366) 1,381 2.39

Adjusted Net Income (Non-GAAP) 580 (141) 439 0.76

Average Number of Common Shares (GAAP)

Basic 579

Diluted 579

Average Number of Common Shares (Non-GAAP)

Basic 579

Diluted 580

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data(Unaudited)

FY 2020

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Loss (GAAP) (739) 134 (605) (1.04)

Adjustments:

Gains on Mark-to-Market Commodity Derivative Contracts (1,145) 251 (894) (1.55)

Net Cash Received from Settlements of Commodity Derivative Contracts 1,071 (235) 836 1.44

Add: Losses on Asset Dispositions, Net 47 (10) 37 0.06

Add: Certain Impairments 1,868 (392) 1,476 2.55

Adjustments to Net Loss 1,841 (386) 1,455 2.50

Adjusted Net Income (Non-GAAP) 1,102 (252) 850 1.46

Average Number of Common Shares (GAAP)

Basic 579

Diluted 579

Average Number of Common Shares (Non-GAAP)

Basic 579

Diluted 581

Adjusted Net Income Per Share

In millions of USD, except share data (in millions), per share data, productionvolume data and per Boe data (Unaudited)

2Q 2021 Adjusted Net Income per Share (Non-GAAP) 1.73

Realized Price

3Q 2021 Composite Average Wellhead Revenue per Boe 52.07

Less: 2Q 2021 Composite Average Welhead Revenue per Boe (46.07)

Subtotal 6.00

Multiplied by: 3Q 2021 Crude Oil Equivalent Volumes (MMBoe) 77.7

Total Change in Revenue 466

Less: Income Tax Benefit (Cost) Imputed (based on 23%) (107)

Change in Net Income 359

Change in Diluted Earnings per Share 0.61

Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts

3Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative (293) Contracts

Less: Income Tax Benefit (Cost) 64

After Tax - (a) (229)

2Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative (193) Contracts

Less: Income Tax Benefit (Cost) 42

After Tax - (b) (151)

Change in Net Income - (a) - (b) (78)

Change in Diluted Earnings per Share (0.13)

Wellhead Volumes

3Q 2021 Crude Oil Equivalent Volumes (MMBoe) 77.7

Less: 2Q 2021 Crude Oil Equivalent Volumes (MMBoe) (75.3)

Subtotal 2.3

Multiplied by: 3Q 2021 Composite Average Margin per Boe (Including Total Exploration Costs) (Non-GAAP) (refer to "Revenues, Costs and Margins Per 24.45Barrel of Oil Equivalent" schedule)

Change in Revenue 57

Less: Income Tax Benefit (Cost) Imputed (based on 23%) (13)

Change in Net Income 44

Change in Diluted Earnings per Share 0.08

Operating Cost per Boe

2Q 2021 Total Operating Cost per Boe (including Total Exploration Costs)(Non-GAAP) 26.82 (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"schedule)

Less: 3Q 2021 Total Operating Cost per Boe (including Total Exploration Costs)(Non- GAAP) (refer to "Revenues, Costs and Margins Per Barrel of Oil (27.62)Equivalent" schedule)

Subtotal (0.8)

Multiplied by: 3Q 2021 Crude Oil Equivalent Volumes (MMBoe) 77.7

Change in Before-Tax Net Income (62)

Less: Income Tax Benefit (Cost) Imputed (based on 23%) 14

Change in Net Income (48)

Change in Diluted Earnings per Share (0.08)

Other Items (0.05)

3Q 2021 Adjusted Net Income per Share (Non-GAAP) 2.16

3Q 2021 Average Number of Common Shares (Non-GAAP) - Diluted 584

Discretionary Cash Flow and Free Cash Flow

In millions of USD (Unaudited)

The following tables reconcile Net Cash Provided by Operating Activities (GAAP)to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may beuseful to investors who follow the practice of some industry analysts whoadjust Net Cash Provided by Operating Activities for Exploration Costs(excluding Stock-Based Compensation Expenses), Changes in Components of WorkingCapital and Other Assets and Liabilities, Changes in Components of WorkingCapital Associated with Investing and Financing Activities and certain otheradjustments to exclude non-recurring and certain other items as furtherdescribed below. EOG defines Free Cash Flow (Non-GAAP) for a given period asDiscretionary Cash Flow (Non-GAAP) (see below reconciliation) for such periodless the total cash capital expenditures (before acquisitions) incurred(Non-GAAP) during such period, as is illustrated below. EOG management usesthis information for comparative purposes within the industry.

3Q 2021 2Q 2021 3Q 2020 YTD 2021 YTD 2020

Net Cash Provided by Operating Activities (GAAP) 2,196 1,559 1,214 5,625 3,887

Adjustments:

Exploration Costs (excluding Stock-Based 39 29 37 96 90 Compensation Expenses)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 145 186 260 639 (931)

Inventories 6 (37) (7) (95) (92)

Accounts Payable 68 (11) 37 (115) 1,222

Accrued Taxes Payable (206) 163 (73) (286) (12)

Other Assets (167) 119 (162) 55 (415)

Other Liabilities 260 (32) (51) 317 13

Changes in Components of Working Capital (45) 54 6 100 (276) Associated with Investing Activities

Other Non-Current Income Taxes - Net Receivable - - - - 113

Discretionary Cash Flow (Non-GAAP) 2,296 2,030 1,261 6,336 3,599

Discretionary Cash Flow (Non-GAAP) - Percentage 82 % 76 % Increase

Discretionary Cash Flow (Non-GAAP) 2,296 2,030 1,261 6,336 3,599

Less:

Total Cash Capital Expenditures Before Acquisitions (935) (972) (499) (2,852) (2,662) (Non-GAAP) ^(a)

Free Cash Flow (Non-GAAP) 1,361 1,058 762 3,484 937

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP):

3Q 2021 2Q 2021 3Q 2020 YTD 2021 YTD 2020

Total Expenditures (GAAP) 962 1,089 646 3,118 3,006

Less:

Asset Retirement Costs (8) (31) (44) (56) (69)

Non-Cash Expenditures of Other Property, Plant and - - - - - Equipment

Non-Cash Acquisition Costs of Unproved Properties (15) - (80) (37) (128)

Non-Cash Finance Leases - - - (74) (73)

Acquisition Costs of Proved Properties (4) (86) (23) (99) (74)

Total Cash Capital Expenditures Before Acquisitions 935 972 499 2,852 2,662 (Non-GAAP)

Discretionary Cash Flow and Free Cash Flow

(Continued)

In millions of USD (Unaudited)

FY 2020 FY 2019 FY 2018 FY 2017

Net Cash Provided by Operating Activities (GAAP) 5,008 8,163 7,769 4,265

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 126 113 125 122

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable (467) 92 368 392

Inventories (123) (90) 395 175

Accounts Payable 795 (169) (439) (324)

Accrued Taxes Payable 49 (40) 92 64

Other Assets (325) (358) 125 659

Other Liabilities (8) 57 (11) 90

Changes in Components of Working Capital Associated with (75) 115 (301) (90) Investing and Financing Activities

Other Non-Current Income Taxes - Net (Payable) Receivable 113 239 149 (513)

Discretionary Cash Flow (Non-GAAP) 5,093 8,122 8,272 4,840

Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease) -37 % -2 % 71 % 76 %

Discretionary Cash Flow (Non-GAAP) 5,093 8,122 8,272 4,840

Less:

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a) (3,490) (6,234) (6,172) (4,228)

Free Cash Flow (Non-GAAP) 1,603 1,888 2,100 612

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP):

Total Expenditures (GAAP) 4,113 6,900 6,706 4,613

Less:

Asset Retirement Costs (117) (186) (70) (56)

Non-Cash Expenditures of Other Property, Plant and Equipment - (2) (1) -

Non-Cash Acquisition Costs of Unproved Properties (197) (98) (291) (256)

Non-Cash Finance Leases (174) - (48) -

Acquisition Costs of Proved Properties (135) (380) (124) (73)

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) 3,490 6,234 6,172 4,228

Discretionary Cash Flow and Free Cash Flow

(Continued)

In millions of USD (Unaudited)

FY 2016 FY 2015 FY 2014 FY 2013 FY 2012

Net Cash Provided by Operating Activities (GAAP) 2,359 3,595 8,649 7,329 5,237

Adjustments:

Exploration Costs (excluding Stock-Based Compensation 104 124 158 134 158 Expenses)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 233 (641) (85) 24 179

Inventories (171) (58) 162 (53) 157

Accounts Payable 74 1,409 (544) (179) 17

Accrued Taxes Payable (93) (12) (16) (75) (78)

Other Assets 41 (118) 14 110 119

Other Liabilities 16 66 (75) 20 (36)

Changes in Components of Working Capital Associated 156 (500) 103 51 (74) with Investing and Financing Activities

Excess Tax Benefits from Stock-Based Compensation 30 26 99 56 67

Discretionary Cash Flow (Non-GAAP) 2,749 3,891 8,465 7,417 5,746

Discretionary Cash Flow (Non-GAAP) - Percentage Increase -29 % -54 % 14 % 29 % (Decrease)

Discretionary Cash Flow (Non-GAAP) 2,749 3,891 8,465 7,417 5,746

Less:

Total Cash Capital Expenditures Before Acquisitions (2,706) (4,682) (8,292) (7,102) (7,540) (Non-GAAP) ^(a)

Free Cash Flow (Non-GAAP) 43 (791) 173 315 (1,794)

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP):

Total Expenditures (GAAP) 6,554 5,216 8,632 7,361 7,754

Less:

Asset Retirement Costs 20 (53) (196) (134) (127)

Non-Cash Expenditures of Other Property, Plant and (17) - - - (66) Equipment

Non-Cash Acquisition Costs of Unproved Properties (3,102) - (5) (5) (20)

Acquisition Costs of Proved Properties (749) (481) (139) (120) (1)

Total Cash Capital Expenditures Before Acquisitions (Non- 2,706 4,682 8,292 7,102 7,540 GAAP)

Total Expenditures

In millions of USD (Unaudited)

3Q 2021 3Q 2020 FY 2020 FY 2019 FY 2018 FY 2017

Exploration and Development Drilling 653 378 2,664 4,951 4,935 3,132

Facilities 100 38 347 629 625 575

Leasehold Acquisitions 90 88 265 276 488 427

Property Acquisitions 4 23 135 380 124 73

Capitalized Interest 9 7 31 38 24 27

Subtotal 856 534 3,442 6,274 6,196 4,234

Exploration Costs 44 38 146 140 149 145

Dry Hole Costs 4 13 13 28 5 5

Exploration and Development Expenditures 904 585 3,601 6,442 6,350 4,384

Asset Retirement Costs 8 44 117 186 70 56

Total Exploration and Development Expenditures 912 629 3,718 6,628 6,420 4,440

Other Property, Plant and Equipment 50 17 395 272 286 173

Total Expenditures 962 646 4,113 6,900 6,706 4,613

EBITDAX and Adjusted EBITDAX

In millions of USD (Unaudited)

The following table adjusts the reported Net Income (Loss) (GAAP) to EarningsBefore Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)),Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs andImpairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflectactual Net Cash Received from (Payments for) Settlements of CommodityDerivative Contracts by eliminating the unrealized Mark-to-Market (MTM) (Gains)Losses from these transactions and to eliminate the (Gains) Losses on AssetDispositions (Net). EOG believes this presentation may be useful to investorswho follow the practice of some industry analysts who adjust reported NetIncome (Loss) (GAAP) to add back Interest Expense, Net, Income Taxes (IncomeTax Provision (Benefit)), Depreciation, Depletion and Amortization, ExplorationCosts, Dry Hole Costs and Impairments and further adjust such amount to matchrealizations to production settlement months and make certain other adjustmentsto exclude non-recurring and certain other items. EOG management uses thisinformation for purposes of comparing its financial performance with thefinancial performance of other companies in the industry.

3Q 2021 3Q 2020 YTD 2021 YTD 2020

Net Income (Loss) (GAAP) 1,095 (42) 2,679 (942)

Adjustments:

Interest Expense, Net 48 53 140 152

Income Tax Provision (Benefit) 334 (11) 755 (225)

Depreciation, Depletion and Amortization 927 823 2,741 2,530

Exploration Costs 44 38 112 105

Dry Hole Costs 4 13 28 13

Impairments 82 79 170 1,957

EBITDAX (Non-GAAP) 2,534 953 6,625 3,590

(Gains) Losses on MTM Commodity Derivative Contracts 494 4 1,288 (1,075)

Net Cash Received from (Payments for) Settlements of Commodity Derivative (293) 275 (516) 999Contracts

(Gains) Losses on Asset Dispositions, Net (1) 71 (46) 41

Adjusted EBITDAX (Non-GAAP) 2,734 1,303 7,351 3,555

Adjusted EBITDAX (Non-GAAP) - Percentage Increase 110 % 107 %

Definitions

EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision(Benefit); Depreciation, Depletion and Amortization; Exploration Costs; DryHole Costs; and Impairments

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt(Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),as used in the Net Debt-to-Total Capitalization ratio calculation. A portionof the cash is associated with international subsidiaries; tax considerationsmay impact debt paydown. EOG believes this presentation may be useful toinvestors who follow the practice of some industry analysts who utilize NetDebt and Total Capitalization (Non-GAAP) in their Net Debt-to-TotalCapitalization ratio calculation. EOG management uses this information forcomparative purposes within the industry.

September 30, June 30, March 31,

2021 2021 2021

Total Stockholders' Equity - (a) 21,765 20,881 20,762

Current and Long-Term Debt (GAAP) - (b) 5,117 5,125 5,133

Less: Cash (4,293) (3,880) (3,388)

Net Debt (Non-GAAP) - (c) 824 1,245 1,745

Total Capitalization (GAAP) - (a) + (b) 26,882 26,006 25,895

Total Capitalization (Non-GAAP) - (a) + (c) 22,589 22,126 22,507

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 19.0 % 19.7 % 19.8 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 3.6 % 5.6 % 7.8 %

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31,

2020 2020 2020 2020

Total Stockholders' Equity - (a) 20,302 20,148 20,388 21,471

Current and Long-Term Debt (GAAP) - (b) 5,816 5,721 5,724 5,222

Less: Cash (3,329) (3,066) (2,417) (2,907)

Net Debt (Non-GAAP) - (c) 2,487 2,655 3,307 2,315

Total Capitalization (GAAP) - (a) + (b) 26,118 25,869 26,112 26,693

Total Capitalization (Non-GAAP) - (a) + (c) 22,789 22,803 23,695 23,786

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 22.3 % 22.1 % 21.9 % 19.6 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 10.9 % 11.6 % 14.0 % 9.7 %

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31,

2019 2019 2019 2019

Total Stockholders' Equity - (a) 21,641 21,124 20,630 19,904

Current and Long-Term Debt (GAAP) - (b) 5,175 5,177 5,179 6,081

Less: Cash (2,028) (1,583) (1,160) (1,136)

Net Debt (Non-GAAP) - (c) 3,147 3,594 4,019 4,945

Total Capitalization (GAAP) - (a) + (b) 26,816 26,301 25,809 25,985

Total Capitalization (Non-GAAP) - (a) + (c) 24,788 24,718 24,649 24,849

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 19.3 % 19.7 % 20.1 % 23.4 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 12.7 % 14.5 % 16.3 % 19.9 %

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31,

2018 2018 2018 2018

Total Stockholders' Equity - (a) 19,364 18,538 17,452 16,841

Current and Long-Term Debt (GAAP) - (b) 6,083 6,435 6,435 6,435

Less: Cash (1,556) (1,274) (1,008) (816)

Net Debt (Non-GAAP) - (c) 4,527 5,161 5,427 5,619

Total Capitalization (GAAP) - (a) + (b) 25,447 24,973 23,887 23,276

Total Capitalization (Non-GAAP) - (a) + (c) 23,891 23,699 22,879 22,460

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 23.9 % 25.8 % 26.9 % 27.6 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 18.9 % 21.8 % 23.7 % 25.0 %

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31,

2017 2017 2017 2017

Total Stockholders' Equity - (a) 16,283 13,922 13,902 13,928

Current and Long-Term Debt (GAAP) - (b) 6,387 6,387 6,987 6,987

Less: Cash (834) (846) (1,649) (1,547)

Net Debt (Non-GAAP) - (c) 5,553 5,541 5,338 5,440

Total Capitalization (GAAP) - (a) + (b) 22,670 20,309 20,889 20,915

Total Capitalization (Non-GAAP) - (a) + (c) 21,836 19,463 19,240 19,368

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 28.2 % 31.4 % 33.4 % 33.4 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 25.4 % 28.5 % 27.7 % 28.1 %

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, September 30, June 30, March 31, December 31,

2016 2016 2016 2016 2015

Total Stockholders' Equity - (a) 13,982 11,798 12,057 12,405 12,943

Current and Long-Term Debt (GAAP) - (b) 6,986 6,986 6,986 6,986 6,660

Less: Cash (1,600) (1,049) (780) (668) (719)

Net Debt (Non-GAAP) - (c) 5,386 5,937 6,206 6,318 5,941

Total Capitalization (GAAP) - (a) + (b) 20,968 18,784 19,043 19,391 19,603

Total Capitalization (Non-GAAP) - (a) + (c) 19,368 17,735 18,263 18,723 18,884

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 33.3 % 37.2 % 36.7 % 36.0 % 34.0 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / 27.8 % 33.5 % 34.0 % 33.7 % 31.5 % [(a) + (c)]

Reserve Replacement Cost Data

In millions of USD, except reserves and ratio data (Unaudited)

The following table reconciles Total Costs Incurred in Exploration andDevelopment Activities (GAAP) to Total Exploration and Development Expendituresfor Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures(Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve ReplacementCosts, including "Drilling Only" and "All-In", which reflect total explorationand development expenditures divided by total net proved reserve additions fromextensions and discoveries only, or from all sources. Combined with ReserveReplacement, these statistics (and the non-GAAP measures used in calculatingsuch statistics) provide management and investors with an indication of theresults of the current year capital investment program. Reserve ReplacementCost statistics (and the non-GAAP measures used in calculating such statistics)are widely recognized and reported by industry participants and are used by EOGmanagement and other third parties for comparative purposes within theindustry. Please note that the actual cost of adding reserves will vary fromthe reported statistics due to timing differences in reserve bookings andcapital expenditures. Accordingly, some analysts use three or five yearaverages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undevelopedreserves in exploration and development expenditures.

2020 2019 2018 2017 2016 2015 2014

Total Costs Incurred in Exploration and 3,718 6,628 6,420 4,440 6,445 4,928 7,905 Development Activities (GAAP)

Less: Asset Retirement Costs (117) (186) (70) (56) 20 (53) (196)

Non-Cash Acquisition Costs of (197) (98) (291) (256) (3,102) - - Unproved Properties

Acquisition Costs of Proved (135) (380) (124) (73) (749) (481) (139)Properties

Total Exploration and Development

Expenditures for Drilling Only (Non- 3,269 5,964 5,935 4,055 2,614 4,394 7,570

GAAP) - (a)

Total Costs Incurred in Exploration and 3,718 6,628 6,420 4,440 6,445 4,928 7,905 Development Activities (GAAP)

Less: Asset Retirement Costs (117) (186) (70) (56) 20 (53) (196)

Non-Cash Acquisition Costs of (197) (98) (291) (256) (3,102) - - Unproved Properties

Non-Cash Acquisition Costs of (15) (52) (71) (26) (732) - - Proved Properties

Total Exploration and Development 3,389 6,292 5,988 4,102 2,631 4,875 7,709 Expenditures (Non-GAAP) - (b)

Net Proved Reserve Additions From All

Sources - Oil Equivalents (MMBoe)

Revisions Due to Price - (c) (278) (60) 35 154 (101) (574) 52

Revisions Other Than Price (89) - (40) 48 253 107 49

Purchases in Place 10 17 12 2 42 56 14

Extensions, Discoveries and Other 564 750 670 421 209 246 519Additions - (d)

Total Proved Reserve Additions - (e) 207 707 677 625 403 (165) 634

Sales in Place (31) (5) (11) (21) (168) (4) (36)

Net Proved Reserve Additions From All 176 702 666 604 235 (169) 598Sources

Production 285 301 265 224 206 210 220

2020 2019 2018 2017 2016 2015 2014

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions - (a / d) 5.79 7.95 8.86 9.64 12.51 17.87 14.58

All-in Total, Net of Revisions - (b / e) 16.32 8.90 8.85 6.56 6.52 (29.63) 12.16

All-in Total, Excluding Revisions Due to 6.98 8.21 9.33 8.71 5.22 11.91 13.25Price - (b / ( e - c))

Definitions

$/Boe U.S. Dollars per barrel of oil equivalent

MMBoe Million barrels of oil equivalent

Financial Commodity Derivative Contracts

EOG accounts for financial commodity derivative contracts using themark-to-market accounting method.

Presented below is a comprehensive summary of EOG's financial commodityderivative contracts as of October 29, 2021.

Crude Oil Financial Price Swap Contracts

Contracts Sold

Volume Weighted Average PricePeriod Settlement Index (MBbld) ($/Bbl)

January 2021 (closed) NYMEX WTI 151 $ 50.06

February - March 2021 (closed) NYMEX WTI 201 51.29

April - June 2021 (closed) NYMEX WTI 150 51.68

July - September 2021 (closed) NYMEX WTI 150 52.71

January - March 2022 NYMEX WTI 140 65.58

April - June 2022 NYMEX WTI 140 65.62

July - September 2022 NYMEX WTI 140 65.59

October - December 2022 NYMEX WTI 140 65.68

January - March 2023 NYMEX WTI 150 67.92

April - June 2023 NYMEX WTI 120 67.79

July - September 2023 NYMEX WTI 9 68.00

Crude Oil Basis Swap Contracts

Contracts Sold

Weighted Average Price VolumePeriod Settlement Index Differential (MBbld) ($/Bbl)

February 2021 (closed) NYMEX WTI Roll Differential^ (1) 30 $ 0.11

March - November 2021 (closed) NYMEX WTI Roll Differential^ (1) 125 0.17

December 2021 NYMEX WTI Roll Differential^ (1) 125 0.17

January - 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.

NGL Financial Price Swap Contracts

Contracts Sold

Volume Weighted Average PricePeriod Settlement Index (MBbld) ($/Bbl)

January - October 2021 (closed) Mont Belvieu Propane (non-Tet) 15 $ 29.44

November - December 2021 Mont Belvieu Propane (non-Tet) 15 29.44

Natural Gas Financial Price Swap Contracts

Contracts Sold Contracts Purchased

Volume Weighted Volume Weighted

Period Settlement Index (MMBtud in Average Price (MMBtud in Average Price

thousands) ($/MMBtu) thousands) ($/MMBtu)

January - March 2021 (closed) NYMEX Henry Hub 500 $ 2.99 500 $ 2.43

April - September 2021 NYMEX Henry Hub 500 2.99 570 2.81 (closed)

October - November 2021 NYMEX Henry Hub 500 2.99 500 2.83 (closed)

December 2021 NYMEX Henry Hub 500 2.99 500 2.83

January - December 2022 NYMEX Henry Hub 20 2.75 - - (closed)^ (1)

January - December 2022 NYMEX Henry Hub 725 3.57 - -

January - December 2023 NYMEX Henry Hub 725 3.18 - -

January - December 2024 NYMEX Henry Hub 725 3.07 - -

January - December 2025 NYMEX Henry Hub 725 3.07 - -

April - September 2021 JKM 70 6.65 - - (closed)

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

Natural Gas Basis Swap Contracts

Contracts Sold

Volume Weighted Average PricePeriod Settlement Index (MMBtud in ($/MMBtu) thousands)

January - December 2022 NYMEX Henry Hub HSC Differential^ (1) 140 $ 0.01

January - December 2023 NYMEX Henry Hub HSC Differential^ (1) 65 0.00

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.

Glossary:

$/Bbl Dollars per barrel

$/MMBtu Dollars per million British Thermal Units

Bbl Barrel

EOG EOG Resources, Inc.

HSC Houston Ship Channel

JKM Japan Korea Marker

MBbld Thousand barrels per day

MMBtu Million British Thermal Units

MMBtud Million British Thermal Units per day

NGL Natural Gas Liquids

NYMEX New York Mercantile Exchange

WTI West Texas Intermediate

Direct After-Tax Rate of Return

The calculation of EOG's direct after-tax rate of return (ATROR) with respectto EOG's capital expenditure program for a particular play or well is based onthe estimated recoverable reserves ("net" to EOG's interest) for all wells insuch play or such well (as the case may be), the estimated net present value(NPV) of the future net cash flows from such reserves (for which we utilizecertain assumptions regarding future commodity prices and operating costs) andEOG's direct net costs incurred in drilling or acquiring (as the case may be)such wells or well (as the case may be). As such, EOG's direct ATROR withrespect to our capital expenditures for a particular play or well cannot becalculated from our consolidated financial statements.

Direct ATROR

Based on Cash Flow and Time Value of Money

- Estimated future commodity prices and operating costs

- Costs incurred to drill, complete and equip a well, including wellsite facilities and flowback

Excludes Indirect Capital

- Gathering and Processing and other Midstream

- Land, Seismic, Geological and Geophysical

- Offsite Production Facilities

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPVCaptured

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

- Eagle Ford, Bakken, Permian and Powder River Basin Facilities

- Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Interest Expense, Net (GAAP), Net Income (Loss)(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) toAfter-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), NetDebt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used inthe Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow thepractice of some industry analysts who utilize After-Tax Net Interest Expense,Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCEand ROE calculations. EOG management uses this information for purposes ofcomparing its financial performance with the financial performance of othercompanies in the industry.

2020 2019 2018 2017

Interest Expense, Net (GAAP) 205 185 245

Tax Benefit Imputed (based on 21%) (43) (39) (51)

After-Tax Net Interest Expense (Non-GAAP) - (a) 162 146 194

Net Income (Loss) (GAAP) - (b) (605) 2,735 3,419

Adjustments to Net Income (Loss), Net of Tax (See Below Detail) ^(1) 1,455 158 (201)

Adjusted Net Income (Non-GAAP) - (c) 850 2,893 3,218

Total Stockholders' Equity - (d) 20,302 21,641 19,364 16,283

Average Total Stockholders' Equity * - (e) 20,972 20,503 17,824

Current and Long-Term Debt (GAAP) - (f) 5,816 5,175 6,083 6,387

Less: Cash (3,329) (2,028) (1,556) (834)

Net Debt (Non-GAAP) - (g) 2,487 3,147 4,527 5,553

Total Capitalization (GAAP) - (d) + (f) 26,118 26,816 25,447 22,670

Total Capitalization (Non-GAAP) - (d) + (g) 22,789 24,788 23,891 21,836

Average Total Capitalization (Non-GAAP) * - (h) 23,789 24,340 22,864

Return on Capital Employed (ROCE)

GAAP Net Income (Loss) - [(a) + (b)] / (h) (1.9) % 11.8 % 15.8 %

Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) 4.3 % 12.5 % 14.9 %

Return on Equity (ROE)

GAAP Net Income (Loss) - (b) / (e) (2.9) % 13.3 % 19.2 %

Non-GAAP Adjusted Net Income - (c) / (e) 4.1 % 14.1 % 18.1 %

* Average for the current and immediately preceding year

(1) Detail of adjustments to Net Income (Loss) (GAAP):

Before Income Tax After

Tax Impact Tax

Year Ended December 31, 2020

Adjustments:

Add: Mark-to-Market Commodity Derivative Contracts Impact (74) 16 (58)

Add: Impairments of Certain Assets 1,868 (392) 1,476

Add: Net Losses on Asset Dispositions 47 (10) 37

Total 1,841 (386) 1,455

Year Ended December 31, 2019

Adjustments:

Add: Mark-to-Market Commodity Derivative Contracts Impact 51 (11) 40

Add: Impairments of Certain Assets 275 (60) 215

Less: Net Gains on Asset Dispositions (124) 27 (97)

Total 202 (44) 158

Year Ended December 31, 2018

Adjustments:

Add: Mark-to-Market Commodity Derivative Contracts Impact (93) 20 (73)

Add: Impairments of Certain Assets 153 (34) 119

Less: Net Gains on Asset Dispositions (175) 38 (137)

Less: Tax Reform Impact - (110) (110)

Total (115) (86) (201)

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Interest Expense, Net (GAAP), Current andLong-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net InterestExpense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP),respectively, as used in the Return on Capital Employed (ROCE) and Return onEquity (ROE) calculations. EOG believes this presentation may be useful toinvestors who follow the practice of some industry analysts who utilizeAfter-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) intheir ROCE calculation. EOG management uses this information for purposes ofcomparing its financial performance with the financial performance of othercompanies in the industry.

2017 2016 2015

Interest Expense, Net (GAAP) 274 282 237

Tax Benefit Imputed (based on 35%) (96) (99) (83)

After-Tax Net Interest Expense (Non-GAAP) - (a) 178 183 154

Net Income (Loss) (GAAP) - (b) 2,583 (1,097) (4,525)

Total Stockholders' Equity - (d) 16,283 13,982 12,943

Average Total Stockholders' Equity* - (e) 15,133 13,463 15,328

Current and Long-Term Debt (GAAP) - (f) 6,387 6,986 6,655

Less: Cash (834) (1,600) (719)

Net Debt (Non-GAAP) - (g) 5,553 5,386 5,936

Total Capitalization (GAAP) - (d) + (f) 22,670 20,968 19,598

Total Capitalization (Non-GAAP) - (d) + (g) 21,836 19,368 18,879

Average Total Capitalization (Non-GAAP)* - (h) 20,602 19,124 20,206

Return on Capital Employed (ROCE)

GAAP Net Income (Loss) - [(a) + (b)] / (h) 13.4 % -4.8 % -21.6 %

Return on Equity (ROE)

GAAP Net Income (Loss) - (b) / (e) 17.1 % -8.1 % -29.5 %

* Average for the current and immediately preceding year

ROCE & ROE

(Continued)

In millions of USD, except ratio data (Unaudited)

2014 2013 2012

Interest Expense, Net (GAAP) 201 235 214

Tax Benefit Imputed (based on 35%) (70) (82) (75)

After-Tax Net Interest Expense (Non-GAAP) - (a) 131 153 139

Net Income (GAAP) - (b) 2,915 2,197 570

Total Stockholders' Equity - (d) 17,713 15,418 13,285

Average Total Stockholders' Equity* - (e) 16,566 14,352 12,963

Current and Long-Term Debt (GAAP) - (f) 5,906 5,909 6,312

Less: Cash (2,087) (1,318) (876)

Net Debt (Non-GAAP) - (g) 3,819 4,591 5,436

Total Capitalization (GAAP) - (d) + (f) 23,619 21,327 19,597

Total Capitalization (Non-GAAP) - (d) + (g) 21,532 20,009 18,721

Average Total Capitalization (Non-GAAP)* - (h) 20,771 19,365 17,878

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h) 14.7 % 12.1 % 4.0 %

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 17.6 % 15.3 % 4.4 %

* Average for the current and immediately preceding year

Revenues, Costs and Margins Per Barrel of Oil Equivalent

In millions of USD, except Boe and per Boe amounts (Unaudited)

EOG believes this presentation may be useful to investors who follow thepractice of some industry analysts who review certain components and/or groupsof components of revenues, costs and/or margin per barrel of oil equivalent(Boe). Certain of these components are adjusted for non-recurring and certainother items, as further discussed below.



EOG management uses this information for purposes of comparing its financialperformance with the financial performance of other companies in the industry.

3Q 2021 2Q 2021 1Q 2021 4Q 2020 3Q 2020

Volume - Million Barrels of Oil Equivalent - (a) 77.7 75.3 70.1 73.7 65.9

Total Operating Revenues and Other (b) 4,765 4,139 3,694 2,965 2,246

Total Operating Expenses (c) 3,294 2,968 2,762 2,477 2,249

Operating Income (Loss) (d) 1,471 1,171 932 488 (3)

Wellhead Revenues

Crude Oil and Condensate 2,929 2,699 2,251 1,711 1,395

Natural Gas Liquids 548 367 314 229 185

Natural Gas 568 404 625 302 184

Total Wellhead Revenues - (e) 4,045 3,470 3,190 2,242 1,764

Operating Costs

Lease and Well 270 270 270 261 227

Transportation Costs 219 214 202 195 180

Gathering and Processing Costs 145 128 139 119 115

General and Administrative 142 120 110 113 125

Taxes Other Than Income 277 239 215 114 126

Interest Expense, Net 48 45 47 53 53

Total Operating Cost (excluding DD&A and Total Exploration 1,101 1,016 983 855 826 Costs) (f)

Depreciation, Depletion and Amortization (DD&A) 927 914 900 870 823

Total Operating Cost (excluding Total Exploration Costs) - (g) 2,028 1,930 1,883 1,725 1,649

Exploration Costs 44 35 33 41 38

Dry Hole Costs 4 13 11 - 13

Impairments 82 44 44 143 79

Total Exploration Costs (GAAP) 130 92 88 184 130

Less: Certain Impairments ^(1) (13) (1) (1) (86) (27)

Total Exploration Costs (Non-GAAP) 117 91 87 98 103

Total Operating Cost (including Total Exploration Costs 2,158 2,022 1,971 1,909 1,779 (GAAP)) - (h)

Total Operating Cost (including Total Exploration Costs 2,145 2,021 1,970 1,823 1,752 (Non-GAAP)) - (i)

Total Wellhead Revenues less Total Operating Cost 1,887 1,448 1,219 333 (15) (including Total Exploration Costs (GAAP))

Total Wellhead Revenues less Total Operating Cost 1,900 1,449 1,220 419 12 (including Total Exploration Costs (Non-GAAP))

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

3Q 2021 2Q 2021 1Q 2021 4Q 2020 3Q 2020

Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe 61.33 54.97 52.70 40.23 34.08 - (b) / (a)

Composite Average Operating Expenses per Boe - (c) / (a) 42.40 39.42 39.40 33.61 34.13

Composite Average Operating Income (Loss) per Boe 18.93 15.55 13.30 6.62 (0.05) - (d) / (a)

Composite Average Wellhead Revenue per Boe - (e) / (a) 52.07 46.07 45.49 30.39 26.77

Total Operating Cost per Boe (excluding DD&A and Total 14.19 13.48 14.02 11.60 12.56 Exploration Costs) - (f) / (a)

Composite Average Margin per Boe (excluding DD&A and 37.88 32.59 31.47 18.79 14.21 Total Exploration Costs) - [(e) / (a) - (f) / (a)]

Total Operating Cost per Boe (excluding Total Exploration 26.12 25.61 26.86 23.41 25.05 Costs) - (g) / (a)

Composite Average Margin per Boe (excluding Total 25.95 20.46 18.63 6.98 1.72 Exploration Costs) - [(e) / (a) - (g) / (a)]

Total Operating Cost per Boe (including Total Exploration 27.79 26.85 28.12 25.90 27.00 Costs) - (h) / (a)

Composite Average Margin per Boe (including Total 24.28 19.22 17.37 4.49 (0.23) Exploration Costs) - [(e) / (a) - (h) / (a)]

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (including Total Exploration 27.62 26.85 28.11 24.72 26.62 Costs) - (i) / (a)

Composite Average Margin per Boe (including Total 24.45 19.25 17.38 5.67 0.15 Exploration Costs) - [(e) / (a) - (i) / (a)]

In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review(1) of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2020 2019 2018 2017

Volume - Million Barrels of Oil Equivalent - (a) 275.9 298.6 262.5 222.3

Total Operating Revenues and Other (b) 11,032 17,380 17,275 11,208

Total Operating Expenses (c) 11,576 13,681 12,806 10,282

Operating Income (Loss) (d) (544) 3,699 4,469 926

Wellhead Revenues

Crude Oil and Condensate 5,786 9,613 9,517 6,256

Natural Gas Liquids 668 785 1,128 730

Natural Gas 837 1,184 1,302 922

Total Wellhead Revenues - (e) 7,291 11,582 11,947 7,908

Operating Costs

Lease and Well 1,063 1,367 1,283 1,045

Transportation Costs 735 758 747 740

Gathering and Processing Costs 459 479 437 149

General and Administrative (GAAP) 484 489 427 434

Less: Legal Settlement - Early Leasehold Termination - - - (10)

Less: Joint Venture Transaction Costs - - - (3)

Less: Joint Interest Billings Deemed Uncollectible - - - (5)

General and Administrative (Non-GAAP)^ (1) 484 489 427 416

Taxes Other Than Income 478 800 772 545

Interest Expense, Net 205 185 245 274

Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f) 3,424 4,078 3,911 3,187

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - 3,424 4,078 3,911 3,169(g)

Depreciation, Depletion and Amortization (DD&A) 3,400 3,750 3,435 3,409

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 6,824 7,828 7,346 6,596

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 6,824 7,828 7,346 6,578

Exploration Costs 146 140 149 145

Dry Hole Costs 13 28 5 5

Impairments 2,100 518 347 479

Total Exploration Costs (GAAP) 2,259 686 501 629

Less: Certain Impairments ^(2) (1,868) (275) (153) (261)

Total Exploration Costs (Non-GAAP) 391 411 348 368

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 9,083 8,514 7,847 7,225

Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) 7,215 8,239 7,694 6,946- (k)

Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total (1,792) 3,068 4,100 683 Exploration Costs (GAAP))

Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (includingTotal 76 3,343 4,253 962

Exploration Costs (Non-GAAP))

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2020 2019 2018 2017

Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe - (b) / (a) 39.99 58.20 65.81 50.42

Composite Average Operating Expenses per Boe - (c) / (a) 41.96 45.81 48.79 46.25

Composite Average Operating Income (Loss) per Boe - (d) / (a) (1.97) 12.39 17.02 4.17

Composite Average Wellhead Revenue per Boe - (e) / (a) 26.42 38.79 45.51 35.58

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 12.39 13.66 14.90 14.34(f) / (a)

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) -[(e) / (a) 14.03 25.13 30.61 21.24

- (f) / (a)]

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 24.71 26.22 27.99 29.67

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / 1.71 12.57 17.52 5.91(a) - (h) / (a)]

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 32.92 28.51 29.89 32.50

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (6.50) 10.28 15.62 3.08(a) - (j) / (a)]

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 12.39 13.66 14.90 14.25(g) / (a)

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) -[(e) / (a) 14.03 25.13 30.61 21.33

- (g) / (a)]

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 24.71 26.22 27.99 29.59

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / 1.71 12.57 17.52 5.99(a) - (i) / (a)]

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 26.13 27.60 29.32 31.24

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / 0.29 11.19 16.19 4.34(a) - (k) / (a)]

EOG believes excluding the above-referenced items from general and(1) administrative expense is appropriate and provides useful information to investors, as EOG views such items as non-recurring.

In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review(2) of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2016 2015 2014

Volume - Million Barrels of Oil Equivalent - (a) 205.0 208.9 217.1

Total Operating Revenues and Other (b) 7,651 8,757 18,035

Total Operating Expenses (c) 8,876 15,443 12,793

Operating Income (Loss) (d) (1,225) (6,686) 5,242

Wellhead Revenues

Crude Oil and Condensate 4,317 4,935 9,742

Natural Gas Liquids 437 408 934

Natural Gas 742 1,061 1,916

Total Wellhead Revenues - (e) 5,496 6,404 12,592

Operating Costs

Lease and Well 927 1,182 1,416

Transportation Costs 764 849 972

Gathering and Processing Costs 123 146 146

General and Administrative (GAAP) 395 367 402

Less: Voluntary Retirement Expense (42) - -

Less: Acquisition Costs (5) - -

Less: Legal Settlement - Early Leasehold Termination - (19) -

General and Administrative (Non-GAAP)^ (1) 348 348 402

Taxes Other Than Income 350 422 758

Interest Expense, Net 282 237 201

Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f) 2,841 3,203 3,895

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - 2,794 3,184 3,895(g)

Depreciation, Depletion and Amortization (DD&A) 3,553 3,314 3,997

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 6,394 6,517 7,892

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 6,347 6,498 7,892

Exploration Costs 125 149 184

Dry Hole Costs 11 15 48

Impairments 620 6,614 744

Total Exploration Costs (GAAP) 756 6,778 976

Less: Certain Impairments ^(2) (321) (6,308) (824)

Total Exploration Costs (Non-GAAP) 435 470 152

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 7,150 13,295 8,868

Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) 6,782 6,968 8,044- (k)

Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total (1,654) (6,891) 3,724 Exploration Costs (GAAP))

Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (includingTotal (1,286) (564) 4,548

Exploration Costs (Non-GAAP))

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2016 2015 2014

Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe - (b) / (a) 37.32 41.92 83.07

Composite Average Operating Expenses per Boe - (c) / (a) 43.30 73.93 58.92

Composite Average Operating Income (Loss) per Boe - (d) / (a) (5.98) (32.01) 24.15

Composite Average Wellhead Revenue per Boe - (e) / (a) 26.82 30.66 58.01

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 13.86 15.33 17.95(f) / (a)

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) -[(e) / 12.96 15.33 40.06

(a) - (f) / (a)]

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 31.19 31.20 36.38

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) /(a) - (h) / (4.37) (0.54) 21.63

(a)]

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 34.88 63.64 40.85

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (8.06) (32.98) 17.16(a) - (j) / (a)]

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 13.64 15.25 17.95(g) / (a)

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) -[(e) / 13.18 15.41 40.06

(a) - (g) / (a)]

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 30.98 31.11 36.38

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (4.16) (0.45) 21.63(a) - (i) / (a)]

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 33.10 33.36 37.08

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (6.28) (2.70) 20.93(a) - (k) / (a)]

EOG believes excluding the above-referenced items from general and(1) administrative expense is appropriate and provides useful information to investors, as EOG views such items as non-recurring.

In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes(2) excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).

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SOURCE EOG Resources, Inc.