PR Newswire | Aug 4, 2021 04:25PM EDT

08/04 15:24 CDT

EOG Resources Reports Second Quarter 2021 Results HOUSTON, Aug. 4, 2021

HOUSTON, Aug. 4, 2021 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second 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

2Q 1Q 2Q 2021 2021 2020

Total Revenue 4,139 3,694 1,103

Net Income (Loss) 907 677 (910)

Net Income (Loss) Per Share 1.55 1.16 (1.57)

Net Cash Provided by Operating Activities 1,559 1,870 88GAAP Total Expenditures 1,089 1,067 534

Current and Long-Term Debt 5,125 5,133 5,724

Cash and Cash Equivalents 3,880 3,388 2,417

Debt-to-Total Capitalization 19.7 % 19.8 % 21.9 %

Adjusted Net Income (Loss) 1,012 946 (131)

Adjusted Net Income (Loss) Per Share 1.73 1.62 (0.23)

Discretionary Cash Flow 2,030 2,010 672

Non- Cash Capital Expenditures before 972 945 478GAAP Acquisitions

Free Cash Flow 1,058 1,065 194

Net Debt 1,245 1,745 3,307

Net Debt-to-Total Capitalization 5.6 % 7.8 % 14.0 %

Second Quarter 2021 Highlights

* Earned adjusted net income of $1.0 billion, or $1.73 per share * Generated over $1.0 billion of free cash flow * Capital expenditures below low end of guidance range driven by sustainable cost reductions * Increased full-year well cost reduction target to 7% from 5% * Oil production above high end of guidance range * Total per-unit cash operating costs 3% below guidance midpoint * Achieved strong ESG performance in 2020 driven by technology and innovation, positioning EOG ahead of pace to meet near-term ESG targets

Volumes and Capital Expenditures

2Q 2021Wellhead Volumes 2Q 2021 Guidance 1Q 2021 2Q 2020 Midpoint

Crude Oil and Condensate (MBod) 448.6 443.0 431.0 331.1

Natural Gas Liquids (MBbld) 138.5 132.5 124.3 101.2

Natural Gas (MMcfd) 1,445 1,386 1,342 1,147

Total Crude Oil Equivalent (MBoed) 828.0 806.5 778.9 623.4

Cash Capital Expenditures before Acquisitions 972 1,100 945 478($MM)

From William R. "Bill" Thomas, Chairman and Chief Executive Officer"EOG is consistently delivering strong results. Our talented employees, supported by our unique culture, have risen to meet the double-premium investment standard in every aspect of the business. Outstanding operating execution, strong well productivity and lower well costs resulted in higher production and lower capital expenditures compared with our plan. We further lowered operating costs while our differentiated marketing strategy captured premium product prices.

"As a result, we generated a second consecutive quarter of record-level free cash flow. Our longstanding free cash flow priorities remain intact. We have already committed to return $1.5 billion of cash to shareholders in 2021 through regular and special dividends, including $820 million paid on July 30. Returning cash to shareholders remains a priority as we generate additional free cash flow during the second half of the year.

"EOG's industry-leading execution extends to our environmental performance, where we are driving meaningful reductions in GHG and methane emissions intensity. We have almost completely eliminated routine flaring and continue to increase the percentage of recycled water used in our operations. Our entrepreneurial culture fosters new technology and innovations to further enhance our performance. Our successful closed-loop gas capture pilot is being expanded to additional locations. And we recently initiated a carbon capture and storage pilot project. Our goal remains to be among the lowest cost, highest return and lowest emissions producers and to play a significant role in the long-term future of energy.

"Our outstanding second quarter results are a testament to EOG's special culture. EOG has never been in better shape and we are getting even better. With the momentum we are building from the shift to double premium, I am confident the company will continue to make significant improvements in the years ahead."

Second Quarter 2021 Financial Performance

Adjusted Earnings per Share 2Q 2021 vs 1Q 2021

Prices and HedgesOverall crude oil equivalent prices increased slightly in 2Q, with higher crude oil and NGL prices partially offset by lower natural gas prices.

Cash paid for hedge settlements increased to $193 million in 2Q compared with payments of $30 million in 1Q.

VolumesTotal company crude oil production of 448,600 Bopd was above the high end of the guidance range and 4% more than 1Q, which was impacted by adverse weather. NGL production was 11% higher and natural gas production was 8% higher, contributing to an overall 6% increase in total company equivalent volumes.

Per-Unit CostsTotal per-unit cash operating costs in 2Q were 3% below the midpoint of the guidance range, and lower compared with 1Q, due to reductions in lease and well costs from compression savings and gathering and processing costs from lower fuel and power rates.

Change in Cash 2Q 2021 vs 1Q 2021

Free Cash FlowEOG generated discretionary cash flow (net cash provided by operating activities before exploration costs and changes in working capital) of $2.03 billion in 2Q. The company incurred $972 million of cash capital expenditures before acquisitions, resulting in $1.06 billion of free cash flow.

Capital ExpendituresCash capital expenditures before acquisitions of $972 million were below the low end of the guidance range due to lower well costs from sustainable efficiency improvements. Faster drilling times, more efficient completion operations and lower-cost sand and water sourcing contributed to lower overall well costs. As a result, EOG has increased its full-year well cost reduction target to 7% from 5%.

Second Quarter 2021 Operating Performance

Lease and WellPer-unit LOE costs were $0.22 below the 2Q 2021 guidance midpoint, primarily due to lower costs for compression, water handling and lease upkeep.

Transportation, Gathering and ProcessingPer-unit transportation costs in 2Q were similar to 1Q and within the guidance range. Gathering and processing costs on a per-unit basis declined 14% compared with 1Q, driven by declines in fuel and power prices from elevated winter levels.

General and AdministrativeG&A costs on a per-unit basis were in-line with 1Q 2021 and within the guidance range.Depreciation, Depletion and AmortizationPer-unit DD&A costs in 2Q were below the target and down 6% compared with 1Q due to the addition of reserves from new wells at lower finding costs.

Second Quarter 2021 Results vs Guidance

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

United States 446.9 441.0 5.9 428.7 442.4 376.6 330.9

Trinidad 1.7 1.9 (0.2) 2.2 2.3 1.0 0.1

Other International 0.0 0.1 (0.1) 0.1 0.1 0.0 0.1

Total 448.6 443.0 5.6 431.0 444.8 377.6 331.1

Natural Gas Liquids Volumes (MBbld)

Total 138.5 132.5 6.0 124.3 141.4 140.1 101.2

Natural Gas Volumes (MMcfd)

United States 1,199 1,160 39 1,100 1,075 1,008 939

Trinidad 233 210 23 217 192 151 174

Other International 13 16 (3) 25 25 31 34

Total 1,445 1,386 59 1,342 1,292 1,190 1,147

Total Crude OilEquivalent Volumes 828.0 806.6 21.4 778.9 801.5 716.0 623.4(MBoed)

Total MMBoe 75.3 73.4 1.9 70.1 73.7 65.9 56.7

Benchmark Price

Oil (WTI) ($/Bbl) 66.06 57.80 42.67 40.94 27.85

Natural Gas (HH) ($/ 2.83 2.69 2.65 1.94 1.73Mcf)

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

United States 0.10 0.25 (0.15) 0.27 (0.81) (0.75) (7.45)

Trinidad (9.80) (11.50) 1.70 (8.03) (9.76) (15.53) (27.25)

Other International (10.50) (8.50) (2.00) (19.19) (6.77) (15.65) 20.93

Natural Gas Liquids -Realizations as % of 44.1% 40.0% 4.1% 48.5% 41.1% 35.0% 36.6%WTI

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

United States 0.16 (0.20) 0.36 2.83 (0.36) (0.45) (0.62)

Natural Gas Realizations ($/Mcf)

Trinidad 3.37 3.35 0.02 3.38 3.57 2.35 2.13

Other International 5.69 5.65 0.04 5.66 5.47 4.73 4.36

Total Expenditures 1,089 1,067 1,107 646 534(GAAP) ($MM)

Capital Expenditures 972 1,100 (128) 945 828 499 478(non-GAAP) ($MM)

Operating Unit Costs ($/Boe)

Lease and Well 3.58 3.80 (0.22) 3.85 3.54 3.45 4.32

Transportation Costs 2.84 2.80 0.04 2.88 2.64 2.74 2.67

General and 1.59 1.55 0.04 1.57 1.54 1.89 2.32Administrative

Gathering and 1.70 1.85 (0.15) 1.98 1.62 1.74 1.71Processing

Cash Operating Costs 9.71 10.00 (0.29) 10.28 9.34 9.82 11.02

Depreciation,Depletion and 12.13 12.30 (0.17) 12.84 11.81 12.49 12.46Amortization

Expenses ($MM)

Exploration and Dry 49 45 4 44 40 51 27Hole

Impairment (GAAP) 44 44 143 79 305

Impairment (excludingcertain impairments 43 70 (27) 43 57 52 66(non-GAAP))

Capitalized Interest 8 8 0 8 7 7 8

Net Interest 45 48 (3) 47 53 53 54

Taxes Other ThanIncome (% of Wellhead 6.9% 7.0% (0.1%) 6.7% 5.1% 7.2% 9.4%Revenue)

Income Taxes

Effective Rate 19.3% 22.5% (3.2%) 23.2% 21.1% 19.2% 20.6%

Deferred Ratio (45%) 8% (53%) (18%) 60% 330% 107%

Third Quarter and Full-Year 2021 Guidance1

(Unaudited)

See "Endnotes" below for related 3Q 2021 FY 2021 2020 2019discussion and definitions. Guidance Range Guidance Range Actual Actual

Crude Oil and Condensate Volumes(MBod)

United States 440.0 - 447.0 437.0 - 445.0 408.1 455.5

Trinidad 0.5 - 1.5 1.0 - 1.8 1.0 0.6

Other International 0.0 - 0.0 0.0 - 0.2 0.1 0.1

Total 440.5 - 448.5 438.0 - 447.0 409.2 456.2

Natural Gas Liquids Volumes(MBbld)

Total 135.0 - 145.0 130.0 - 140.0 136.0 134.1

Natural Gas Volumes (MMcfd)

United States 1,150 - 1,250 1,150 - 1,250 1,040 1,069

Trinidad 195 - 225 200 - 230 180 260

Other International 0 - 0 5 - 15 32 37

Total 1,345 - 1,475 1,355 - 1,495 1,252 1,366

Crude Oil Equivalent Volumes(MBoed)

United States 766.7 - 800.3 758.7 - 793.3 717.5 767.8

Trinidad 33.0 - 39.0 34.3 - 40.1 30.9 44.0

Other International 0.0 - 0.0 0.8 - 2.7 5.4 6.2

Total 799.7 - 839.3 793.8 - 836.1 753.8 818.0

Benchmark Price

Oil (WTI) ($/Bbl) 39.40 57.04

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

Crude Oil and Condensate Differentials - above (below) WTI2 ($/Bbl)

United States (0.20) - 0.80 (0.20) - 0.80 (0.75) 0.70

Trinidad (8.50) - (6.50) (10.50) - (8.50) (9.20) (9.88)

Natural Gas Liquids -Realizations as % of WTI

Total 45% - 55% 42% - 52% 34.0% 28.1%

Natural Gas Differentials - above (below) NYMEX Henry Hub3 ($/Mcf)

United States 0.10 - 0.50 0.70 - 0.90 (0.47) (0.40)

Natural Gas Realizations ($/Mcf)

Trinidad 3.10 - 3.60 3.10 - 3.60 2.57 2.72

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

Capital Expenditures4 (non-GAAP) 900 - 1,100 3,700 - 4,100 3,490 6,234($MM)

Operating Unit Costs ($/Boe)

Lease and Well 3.45 - 4.15 3.40 - 4.10 3.85 4.58

Transportation Costs 2.80 - 3.20 2.75 - 3.15 2.66 2.54

General and Administrative 1.75 - 1.85 1.55 - 1.65 1.75 1.64

Gathering and Processing 1.80 - 2.00 1.75 - 1.95 1.66 1.60

Cash Operating Costs 9.80 - 11.20 9.45 - 10.85 9.92 10.36

Depreciation, Depletion and 11.70 - 12.30 11.70 - 12.70 12.32 12.56Amortization

Expenses ($MM)

Exploration and Dry Hole 35 - 45 160 - 180 159 168

Impairment (GAAP) 2,100 518

Impairment (excluding certain 65 - 105 255 - 295 232 243impairments (non-GAAP))

Capitalized Interest 5 - 10 25 - 30 31 38

Net Interest 42 - 48 180 - 185 205 185

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

Income Taxes

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

Deferred Ratio 25% - 40% 0% - 15% 54.8% 107.4%

Second Quarter 2021 Results WebcastThursday, August 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. https://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

The forecast items for the third 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, to1) 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 price2) 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 gas3) 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,4) 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 day

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)

2Q 2021 1Q 2021 2Q 2020 YTD YTD 2020 2021

Operating Revenues and Other

Crude Oil and Condensate 2,699 2,251 615 4,950 2,680

Natural Gas Liquids 367 314 93 681 254

Natural Gas 404 625 141 1,029 351

Gains (Losses) on Mark-to-Market (427) (367) (127) (794) 1,079 Commodity Derivative Contracts

Gathering, Processing and 1,022 848 362 1,870 1,401Marketing

Gains (Losses) on Asset 51 (6) 14 45 30Dispositions, Net

Other, Net 23 29 5 52 26

Total 4,139 3,694 1,103 7,833 5,821

Operating Expenses

Lease and Well 270 270 245 540 575

Transportation Costs 214 202 152 416 360

Gathering and Processing Costs 128 139 97 267 225

Exploration Costs 35 33 27 68 67

Dry Hole Costs 13 11 - 24 -

Impairments 44 44 305 88 1,878

Marketing Costs 991 838 444 1,829 1,554

Depreciation, Depletion and 914 900 707 1,814 1,707Amortization

General and Administrative 120 110 132 230 246

Taxes Other Than Income 239 215 81 454 238

Total 2,968 2,762 2,190 5,730 6,850

Operating Income (Loss) 1,171 932 (1,087) 2,103 (1,029)

Other Income (Expense), Net (2) (4) (4) (6) 14

Income (Loss) Before InterestExpense 1,169 928 (1,091) 2,097 (1,015) and Income Taxes

Interest Expense, Net 45 47 54 92 99

Income (Loss) Before Income Taxes 1,124 881 (1,145) 2,005 (1,114)

Income Tax Provision (Benefit) 217 204 (235) 421 (214)

Net Income (Loss) 907 677 (910) 1,584 (900)

Dividends Declared per Common 1.4125 0.4125 0.3750 1.8250 0.7500Share

Net Income (Loss) Per Share

Basic 1.56 1.17 (1.57) 2.73 (1.55)

Diluted 1.55 1.16 (1.57) 2.72 (1.55)

Average Number of Common Shares

Basic 580 580 579 580 579

Diluted 584 583 579 583 579

Wellhead Volumes and Prices

(Unaudited)

2Q 2Q2020 % 1Q YTD YTD % 2021 Change 2021 2021 2020 Change

Crude Oil andCondensate Volumes (MBbld) ^(A)

United States 446.9 330.9 35 % 428.7 437.8 406.8 8 %

Trinidad 1.7 0.1 1,600 % 2.2 2.0 0.3 567 %

Other International ^ - 0.1 -100 % 0.1 - 0.1 -100 %(B)

Total 448.6 331.1 35 % 431.0 439.8 407.2 8 %

Average Crude Oil andCondensate Prices ($/Bbl) ^(C)

United States 66.16 20.40 224 % 58.07 62.22 36.17 72 %

Trinidad 56.26 0.60 9,290 % 49.77 52.57 27.75 89 %

Other International ^ 55.56 48.78 14 % 38.61 42.36 53.41 -21 %(B)

Composite 66.12 20.40 224 % 58.02 62.18 36.16 72 %

Natural Gas LiquidsVolumes (MBbld) ^(A)

United States 138.5 101.2 37 % 124.3 131.5 131.2 0 %

Total 138.5 101.2 37 % 124.3 131.5 131.2 0 %

Average Natural GasLiquids Prices ($/Bbl) ^(C)

United States 29.15 10.20 186 % 28.03 28.62 10.65 169 %

Composite 29.15 10.20 186 % 28.03 28.62 10.65 169 %

Natural Gas Volumes(MMcfd) ^(A)

United States 1,199 939 28 % 1,100 1,150 1,039 11 %

Trinidad 233 174 34 % 217 225 188 20 %

Other International ^ 13 34 -62 % 25 19 35 -46 %(B)

Total 1,445 1,147 26 % 1,342 1,394 1,262 10 %

Average Natural GasPrices ($/Mcf) ^(C)

United States 2.99 1.11 170 % 5.52 4.19 1.32 217 %

Trinidad 3.37 2.13 58 % 3.38 3.37 2.15 57 %

Other International ^ 5.69 4.36 31 % 5.66 5.67 4.34 31 %(B)

Composite 3.07 1.36 126 % 5.17 4.08 1.53 167 %

Crude Oil EquivalentVolumes (MBoed) ^(D)

United States 785.2 588.5 33 % 736.4 761.0 711.1 7 %

Trinidad 40.6 29.2 39 % 38.5 39.5 31.6 25 %

Other International ^ 2.2 5.7 -61 % 4.0 3.1 6.1 -49 %(B)

Total 828.0 623.4 33 % 778.9 803.6 748.8 7 %

Total MMBoe ^(D) 75.3 56.7 33 % 70.1 145.4 136.3 7 %

(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 June 30, 2021).

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

Balance Sheets

In millions of USD, except share data (Unaudited)

June 30, December 31,

2021 2020

Current Assets

Cash and Cash Equivalents 3,880 3,329

Accounts Receivable, Net 2,015 1,522

Inventories 516 629

Assets from Price Risk Management Activities - 65

Income Taxes Receivable 11 23

Other 513 294

Total 6,935 5,862

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method) 66,299 64,793

Other Property, Plant and Equipment 4,635 4,479

Total Property, Plant and Equipment 70,934 69,272

Less: Accumulated Depreciation, Depletion and (42,275) (40,673)Amortization

Total Property, Plant and Equipment, Net 28,659 28,599

Deferred Income Taxes 3 2

Other Assets 1,288 1,342

Total Assets 36,885 35,805

Current Liabilities

Accounts Payable 2,012 1,681

Accrued Taxes Payable 286 206

Dividends Payable 820 217

Liabilities from Price Risk Management Activities 396 -

Current Portion of Long-Term Debt 39 781

Current Portion of Operating Lease Liabilities 253 295

Other 196 280

Total 4,002 3,460

Long-Term Debt 5,086 5,035

Other Liabilities 2,186 2,149

Deferred Income Taxes 4,730 4,859

Commitments and Contingencies

Stockholders' Equity

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorizedand 584,102,233 Shares Issued at June 30, 2021 and 583,694,850 Shares 206 206Issued at December 31, 2020

Additional Paid in Capital 6,017 5,945

Accumulated Other Comprehensive Loss (15) (12)

Retained Earnings 14,689 14,170

Common Stock Held in Treasury, 243,058 Shares at June 30,2021 and 124,265 (16) (7) Shares at December 31, 2020

Total Stockholders' Equity 20,881 20,302

Total Liabilities and Stockholders' Equity 36,885 35,805

Cash Flows Statements

In millions of USD (Unaudited)

2Q 2Q 2020 1Q YTD 2021 YTD 2020 2021 2021

Cash Flows from Operating Activities

Reconciliation of Net Income (Loss)to Net Cash Provided by Operating Activities:

Net Income (Loss) 907 (910) 677 1,584 (900)

Items Not Requiring (Providing) Cash

Depreciation, Depletion and 914 707 900 1,814 1,707Amortization

Impairments 44 305 44 88 1,878

Stock-Based Compensation Expenses 31 40 35 66 80

Deferred Income Taxes (97) (253) (36) (133) (208)

(Gains) Losses on Asset (51) (14) 6 (45) (30)Dispositions, Net

Other, Net 6 9 7 13 -

Dry Hole Costs 13 - 11 24 -

Mark-to-Market Commodity DerivativeContracts

Total (Gains) Losses 427 127 367 794 (1,079)

Net Cash Received from (Paymentsfor) (193) 640 (30) (223) 724 Settlements of CommodityDerivative Contracts

Other, Net - - 1 1 -

Changes in Components of WorkingCapital and Other Assets and Liabilities

Accounts Receivable (186) 469 (308) (494) 1,191

Inventories 37 (18) 64 101 85

Accounts Payable 11 (1,619) 172 183 (1,185)

Accrued Taxes Payable (163) (6) 243 80 (61)

Other Assets (119) 195 (103) (222) 253

Other Liabilities 32 2 (89) (57) (64)

Changes in Components of WorkingCapital Associated (54) 414 (91) (145) 282 with Investing Activities

Net Cash Provided by Operating 1,559 88 1,870 3,429 2,673Activities

Investing Cash Flows

Additions to Oil and Gas Properties (968) (424) (875) (1,843) (1,990)

Additions to Other Property, Plant (55) (24) (42) (97) (147)and Equipment

Proceeds from Sales of Assets 141 17 5 146 43

Changes in Components of WorkingCapital Associated 54 (414) 91 145 (282) with Investing Activities

Net Cash Used in Investing (828) (845) (821) (1,649) (2,376)Activities

Financing Cash Flows

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

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

Dividends Paid (239) (217) (219) (458) (384)

Treasury Stock Purchased (2) - (10) (12) (5)

Proceeds from Stock OptionsExercised and Employee 9 8 - 9 8 Stock Purchase Plan

Debt Issuance Costs - (3) - - (3)

Repayment of Finance Lease (9) (5) (9) (18) (8)Liabilities

Net Cash Provided by (Used in) (241) 267 (988) (1,229) 92Financing Activities

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

Increase (Decrease) in Cash and 492 (490) 59 551 389Cash Equivalents

Cash and Cash Equivalents at 3,388 2,907 3,329 3,329 2,028Beginning of Period

Cash and Cash Equivalents at End of 3,880 2,417 3,388 3,880 2,417Period

Non-GAAP Financial Measures

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

A reconciliation of each of these measures to their most directly comparableGAAP financial measure and related discussion is included in the tables on thefollowing 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 industryanalysts who make certain adjustments to GAAP measures (for example, to excludenon-recurring items) to facilitate comparisons to others in EOG's industry, andwho utilize non-GAAP measures in their calculations of certain statistics (forexample, return on capital employed and return on equity) used to evaluateEOG'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 financialand operating performance with the financial and operating performance of othercompanies in the industry and (ii) analyzing EOG's financial and operatingperformance across periods.

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

In addition, because not all companies use identical calculations, EOG'spresentation of non-GAAP measures may not be comparable to, and may becalculated differently from, similarly titled measures disclosed by othercompanies, including its peer companies. EOG may also change the calculation ofone or more of its non-GAAP measures from time to time - for example, toaccount 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.

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 427 (93) 334 0.58Derivative Contracts

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

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

Add: Certain Impairments 1 - 1 -

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

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)

2Q 2020

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Loss (GAAP) (1,145) 235 (910) (1.57)

Adjustments:

Losses on Mark-to-Market Commodity 127 (29) 98 0.17Derivative Contracts

Net Cash Received from Settlements 640 (141) 499 0.86of Commodity Derivative Contracts

Less: Gains on Asset Dispositions, (14) 4 (10) (0.02)Net

Add: Certain Impairments 239 (47) 192 0.33

Adjustments to Net Loss 992 (213) 779 1.34

Adjusted Net Loss (Non-GAAP) (153) 22 (131) (0.23)

Average Number of Common Shares(GAAP)

Basic 579

Diluted 579

Average Number of Common Shares(Non-GAAP)

Basic 579

Diluted 579

Adjusted Net Income (Loss)

(Continued)

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

1Q 2021

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Income (GAAP) 881 (204) 677 1.16

Adjustments:

Losses on Mark-to-Market Commodity 367 (81) 286 0.49Derivative Contracts

Net Cash Payments for Settlements (30) 7 (23) (0.04)of Commodity Derivative Contracts

Add: Losses on Asset Dispositions, 6 (1) 5 0.01Net

Add: Certain Impairments 1 - 1 -

Adjustments to Net Income 344 (75) 269 0.46

Adjusted Net Income (Non-GAAP) 1,225 (279) 946 1.62

Average Number of Common Shares(GAAP)

Basic 580

Diluted 583

Average Number of Common Shares(Non-GAAP)

Basic 580

Diluted 583

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) 2,005 (421) 1,584 2.72

Adjustments:

Losses on Mark-to-Market Commodity 794 (174) 620 1.07Derivative Contracts

Net Cash Payments for Settlements (223) 49 (174) (0.30)of Commodity Derivative Contracts

Less: Gains on Asset Dispositions, (45) 16 (29) (0.05)Net

Add: Certain Impairments 2 - 2 -

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

Adjustments to Net Income 528 (154) 374 0.64

Adjusted Net Income (Non-GAAP) 2,533 (575) 1,958 3.36

Average Number of Common Shares(GAAP)

Basic 580

Diluted 583

Average Number of Common Shares(Non-GAAP)

Basic 580

Diluted 583

Adjusted Net Income (Loss)

(Continued)

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

YTD 2020

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Loss (GAAP) (1,114) 214 (900) (1.55)

Adjustments:

Gains on Mark-to-Market Commodity (1,079) 236 (843) (1.47)Derivative Contracts

Net Cash Received from Settlements 724 (159) 565 0.98of Commodity Derivative Contracts

Less: Gains on Asset Dispositions, (30) 7 (23) (0.04)Net

Add: Certain Impairments 1,755 (367) 1,388 2.40

Adjustments to Net Loss 1,370 (283) 1,087 1.87

Adjusted Net Income (Non-GAAP) 256 (69) 187 0.32

Average Number of Common Shares(GAAP)

Basic 579

Diluted 579

Average Number of Common Shares(Non-GAAP)

Basic 579

Diluted 580

Adjusted Net Income Per Share

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

1Q 2021 Adjusted Net Income per Share (Non-GAAP) 1.62

Realized Price

2Q 2021 Composite Average Wellhead Revenue per Boe 46.07

Less: 1Q 2021 Composite Average Welhead Revenue per Boe (45.49)

Subtotal 0.58

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

Total Change in Revenue 44

Less: Income Tax Benefit (Cost) Imputed (based on 23%) (10)

Change in Net Income 34

Change in Diluted Earnings per Share 0.06

Net Cash Received (Paid) from Settlements of CommodityDerivative Contracts

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

Less: Income Tax Benefit (Cost) 42

After Tax - (a) (151)

1Q 2021 Net Cash Received (Paid) from Settlement of Commodity (30)Derivative Contracts

Less: Income Tax Benefit (Cost) 7

After Tax - (b) (23)

Change in Net Income - (a) - (b) (128)

Change in Diluted Earnings per Share (0.22)

Wellhead Volumes

2Q 2021 Crude Oil Equivalent Volumes (MMBoe) 75.3

Less: 1Q 2021 Crude Oil Equivalent Volumes (MMBoe) (70.1)

Subtotal 5.2

Multiplied by: 2Q 2021 Composite Average Margin per Boe(Including Total Exploration Costs) (Non-GAAP) (refer to "Revenues, Costs 19.25and Margins Per Barrel of Oil Equivalent" schedule)

Change in Revenue 101

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

Change in Net Income 78

Change in Diluted Earnings per Share 0.13

Operating Cost per Boe

1Q 2021 Total Operating Cost per Boe (including TotalExploration Costs) (Non- GAAP) (refer to "Revenues, Costs and Margins Per Barrel 28.11of Oil Equivalent" schedule)

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

Subtotal 1.29

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

Change in Before-Tax Net Income 97

Less: Income Tax Benefit (Cost) Imputed (based on 23%) (22)

Change in Net Income 75

Change in Diluted Earnings per Share 0.13

Other Items 0.01

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

2Q 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.

2Q 2021 1Q 2021 2Q 2020 YTD 2021 YTD 2020

Net Cash Provided by 1,559 1,870 88 3,429 2,673Operating Activities (GAAP)

Adjustments:

Exploration Costs (excludingStock-Based 29 28 21 57 53 Compensation Expenses)

Changes in Components ofWorking Capital and Other Assets andLiabilities

Accounts Receivable 186 308 (469) 494 (1,191)

Inventories (37) (64) 18 (101) (85)

Accounts Payable (11) (172) 1,619 (183) 1,185

Accrued Taxes Payable 163 (243) 6 (80) 61

Other Assets 119 103 (195) 222 (253)

Other Liabilities (32) 89 (2) 57 64

Changes in Components ofWorking Capital 54 91 (414) 145 (282) Associated withInvesting Activities

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

Discretionary Cash Flow 2,030 2,010 672 4,040 2,338(Non-GAAP)

Discretionary Cash Flow(Non-GAAP) - Percentage 202 % 73 %Increase

Discretionary Cash Flow 2,030 2,010 672 4,040 2,338(Non-GAAP)

Less:

Total Cash CapitalExpenditures Before (972) (945) (478) (1,917) (2,163)Acquisitions (Non-GAAP) ^(a)

Free Cash Flow (Non-GAAP) 1,058 1,065 194 2,123 175

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

2Q 2021 1Q 2021 2Q 2020 YTD 2021 YTD 2020

Total Expenditures (GAAP) 1,089 1,067 534 2,156 2,360

Less:

Asset Retirement Costs (31) (17) (5) (48) (25)

Non-Cash Expenditures ofOther Property, Plant and - - - - - Equipment

Non-Cash Acquisition Costs - (22) (24) (22) (48)of Unproved Properties

Non-Cash Finance Leases - (74) (24) (74) (73)

Acquisition Costs of Proved (86) (9) (3) (95) (51)Properties

Total Cash CapitalExpenditures BeforeAcquisitions 972 945 478 1,917 2,163

(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 5,008 8,163 7,769 4,265Activities (GAAP)

Adjustments:

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

Changes in Components of WorkingCapital 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 WorkingCapital Associated with (75) 115 (301) (90) Investing and FinancingActivities

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

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

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

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

Less:

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

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 - (2) (1) -Property, Plant and Equipment

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

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

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

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

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 byOperating Activities 2,359 3,595 8,649 7,329 5,237(GAAP)

Adjustments:

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

Changes in Components ofWorking 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 ofWorking Capital Associated 156 (500) 103 51 (74) with Investing andFinancing Activities

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

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

Discretionary Cash Flow(Non-GAAP) - PercentageIncrease -29 % -54 % 14 % 29 %

(Decrease)

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

Less:

Total Cash CapitalExpenditures Before (2,706) (4,682) (8,292) (7,102) (7,540)Acquisitions (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 ofOther Property, Plant and (17) - - - (66) Equipment

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

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

Total Cash CapitalExpenditures BeforeAcquisitions (Non- 2,706 4,682 8,292 7,102 7,540

GAAP)

Total Expenditures

In millions of USD (Unaudited)

2Q 2Q FY FY FY FY 2021 2020 2020 2019 2018 2017

Exploration and Development 711 381 2,664 4,951 4,935 3,132Drilling

Facilities 105 31 347 629 625 575

Leasehold Acquisitions 46 30 265 276 488 427

Property Acquisitions 86 3 135 380 124 73

Capitalized Interest 7 8 31 38 24 27

Subtotal 955 453 3,442 6,274 6,196 4,234

Exploration Costs 35 27 146 140 149 145

Dry Hole Costs 13 - 13 28 5 5

Exploration and Development 1,003 480 3,601 6,442 6,350 4,384Expenditures

Asset Retirement Costs 31 5 117 186 70 56

Total Exploration and Development 1,034 485 3,718 6,628 6,420 4,440Expenditures

Other Property, Plant and 55 49 395 272 286 173Equipment

Total Expenditures 1,089 534 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.

2Q 2021 2Q 2020 YTD 2021 YTD 2020

Net Income (Loss) (GAAP) 907 (910) 1,584 (900)

Adjustments:

Interest Expense, Net 45 54 92 99

Income Tax Provision (Benefit) 217 (235) 421 (214)

Depreciation, Depletion and 914 707 1,814 1,707Amortization

Exploration Costs 35 27 68 67

Dry Hole Costs 13 - 24 -

Impairments 44 305 88 1,878

EBITDAX (Non-GAAP) 2,175 (52) 4,091 2,637

(Gains) Losses on MTM Commodity 427 127 794 (1,079)Derivative Contracts

Net Cash Received from (Paymentsfor) Settlements of Commodity (193) 640 (223) 724

Derivative Contracts

Gains on Asset Dispositions, Net (51) (14) (45) (30)

Adjusted EBITDAX (Non-GAAP) 2,358 701 4,617 2,252

Adjusted EBITDAX (Non-GAAP) - 236 % 105 %Percentage Increase

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.

June 30, March 31,

2021 2021

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

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

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

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

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

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

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

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

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratiodata (Unaudited)

December September June 30, March 31, 31, 30, 2020 2020 2020 2020

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

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

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) + 26,118 25,869 26,112 26,693(b)

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

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

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

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratiodata (Unaudited)

December September June 30, March 31, 31, 30, 2019 2019 2019 2019

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

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

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) + 26,816 26,301 25,809 25,985(b)

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

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

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

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data(Unaudited)

December September June 30, March 31, 31, 30, 2018 2018 2018 2018

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

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

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) + 25,447 24,973 23,887 23,276(b)

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

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

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

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data(Unaudited)

December September June 30, March 31, 31, 30, 2017 2017 2017 2017

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

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

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) + 22,670 20,309 20,889 20,915(b)

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

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

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

Net Debt-to-Total Capitalization Ratio

(Continued)

In millions of USD, except ratio data(Unaudited)

December September June 30, March December 31, 30, 31, 31, 2016 2016 2016 2016 2015

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

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

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

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

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

Net Debt-to-TotalCapitalization (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 CostsIncurred inExploration and 3,718 6,628 6,420 4,440 6,445 4,928 7,905 DevelopmentActivities(GAAP)

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

Non-CashAcquisitionCosts of (197) (98) (291) (256) (3,102) - - UnprovedProperties

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

TotalExploration andDevelopment

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

GAAP) - (a)

Total CostsIncurred inExploration and 3,718 6,628 6,420 4,440 6,445 4,928 7,905 DevelopmentActivities(GAAP)

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

Non-CashAcquisitionCosts of (197) (98) (291) (256) (3,102) - - UnprovedProperties

Non-CashAcquisitionCosts of (15) (52) (71) (26) (732) - - ProvedProperties

TotalExploration andDevelopment 3,389 6,292 5,988 4,102 2,631 4,875 7,709

Expenditures(Non-GAAP) - (b)

Net ProvedReserveAdditions FromAll

Sources -Oil Equivalents(MMBoe)

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

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

Purchases in 10 17 12 2 42 56 14Place

Extensions,Discoveries andOther 564 750 670 421 209 246 519

Additions -(d)

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

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

Net ProvedReserveAdditions From 176 702 666 604 235 (169) 598All

Sources

Production 285 301 265 224 206 210 220

2020 2019 2018 2017 2016 2015 2014

ReserveReplacementCosts ($ / Boe)

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

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

All-in Total,ExcludingRevisions Due to 6.98 8.21 9.33 8.71 5.22 11.91 13.25 Price - (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 July 30, 2021.

Crude Oil Financial Price Swap Contracts

Contracts Sold

Weighted Volume AveragePeriod Settlement Index Price (MBbld) ($/Bbl)

January 2021 (closed) NYMEX WTI 151 $ 50.06

February - March 2021 NYMEX WTI 201 51.29(closed)

April - June 2021 (closed) NYMEX WTI 150 51.68

July 2021 (closed) NYMEX WTI 150 52.71

August - September 2021 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 100 64.98

October - December 2022 NYMEX WTI 40 63.71

Crude Oil Basis Swap Contracts

Contracts Sold

Weighted Average Volume PricePeriod Settlement Index (MBbld) Differential

($/Bbl)

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

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

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

January - December 2022 NYMEX WTI Roll Differential^ 125 0.15 (1)

(1) This settlement index is used to fix the differential in pricing betweenthe NYMEX calendar month average and the physical crude oil delivery month.

NGL Financial Price Swap Contracts

Contracts Sold

Weighted Volume AveragePeriod Settlement Index Price (MBbld) ($/Bbl)

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

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

Natural Gas Financial Price Swap Contracts

Contracts Sold Contracts Purchased

Weighted Weighted Volume Volume Settlement Average AveragePeriod Index (MMBtud in Price (MMBtud in Price

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

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

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

September 2021 NYMEX Henry 500 2.99 570 2.81 Hub

October - December NYMEX Henry 500 2.99 500 2.832021 Hub

January - December2022 NYMEX Henry 20 2.75 - - Hub (closed)^ (1)

January - December NYMEX Henry 100 2.93 - -2022 Hub

January - December NYMEX Henry 100 2.93 - -2023 Hub

January - December NYMEX Henry 100 2.93 - -2024 Hub

January - December NYMEX Henry 100 2.93 - -2025 Hub

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

September 2021 JKM 70 6.65 - -

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.

Glossary:

$/Bbl Dollars per barrel

$/MMBtu Dollars per million British Thermal Units

Bbl Barrel

EOG EOG Resources, Inc.

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, exceptratio 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.

Trailing 12 2Q 2021 1Q 2021 4Q 2020 3Q 2020 2Q 2020 Months

2Q 2021

Interest Expense, Net 198 45 47 53 53(GAAP)

Tax Benefit Imputed (based (41) (9) (10) (11) (11)on 21%)

After-Tax Net Interest 157 36 37 42 42Expense (Non-GAAP) - (a)

Net Income (Loss) (GAAP) - 1,879 907 677 337 (42)(b)

Adjustments to Net Income(Loss), Net of Tax (See 742 105 269 74 294

Below Detail) ^(1)

Adjusted Net Income 2,621 1,012 946 411 252(Non-GAAP) - (c)

Total Stockholders' Equity 20,881 20,881 20,762 20,302 20,148 20,388- (d)

Average TotalStockholders' Equity * - 20,635(e)

Current and Long-Term Debt 5,125 5,125 5,133 5,816 5,721 5,724(GAAP) - (f)

Less: Cash (3,880) (3,880) (3,388) (3,329) (3,066) (2,417)

Net Debt (Non-GAAP) - (g) 1,245 1,245 1,745 2,487 2,655 3,307

Total Capitalization 26,006 26,006 25,895 26,118 25,869 26,112(GAAP) - (d) + (f)

Total Capitalization 22,126 22,126 22,507 22,789 22,803 23,695(Non-GAAP) - (d) + (g)

Average TotalCapitalization (Non-GAAP) 22,911* - (h)

Return on Capital Employed(ROCE)

GAAP Net Income (Loss) - 8.9 %[(a) + (b)] / (h)

Non-GAAP Adjusted Net 12.1 %Income - [(a) + (c)] / (h)

Return on Equity (ROE)

GAAP Net Income (Loss) - 9.1 %(b) / (e)

Non-GAAP Adjusted Net 12.7 %Income - (c) / (e)

* Average for the beginning and endingtrailing 12 month period.

(1) Detail of adjustments to NetIncome (Loss) (GAAP):

Before Income After

Tax Tax Tax Impact

Q2 2021

Adjustments:

Add: Mark-to-MarketCommodity Derivative 234 (51) 183 Contracts Impact

Add: Impairments of 1 - 1Certain Assets

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

Less: Tax Benefits Relatedto Exiting Canada - (45) (45) Operations

Total 184 (79) 105

Q1 2021

Adjustments:

Add: Mark-to-MarketCommodity Derivative 337 (74) 263 Contracts Impact

Add: Impairments of 1 - 1Certain Assets

Add: Net Losses on Asset 6 (1) 5Dispositions

Total 344 (75) 269

Q4 2020

Adjustments:

Add: Mark-to-MarketCommodity Derivative 2 (1) 1 Contracts Impact

Add: Impairments of 86 (18) 68Certain Assets

Add: Net Losses on Asset 6 (1) 5Dispositions

Total 94 (20) 74

Q3 2020

Adjustments:

Add: Mark-to-MarketCommodity 279 (60) 219Derivative ContractsImpact

Add: Impairments of 27 (7) 20Certain Assets

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

Total 377 (83) 294

ROCE & ROE

(Continued)

In millions of USD, except ratio data(Unaudited)

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 162 146 194(Non-GAAP) - (a)

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

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

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 * - 20,972 20,503 17,824(e)

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) + 22,789 24,788 23,891 21,836(g)

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

Return on Capital Employed (ROCE)

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

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

Return on Equity (ROE)

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

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

* Average for the current andimmediately preceding year

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

Before Income After Tax Tax Tax Impact

Year Ended December 31, 2020

Adjustments:

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

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 51 (11) 40Derivative Contracts Impact

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 (93) 20 (73)Derivative Contracts Impact

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, exceptratio 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 2014 2013

Interest Expense, Net 274 282 237 201 235(GAAP)

Tax Benefit Imputed (based (96) (99) (83) (70) (82)on 35%)

After-Tax Net Interest 178 183 154 131 153Expense (Non-GAAP) - (a)

Net Income (Loss) (GAAP) - 2,583 (1,097) (4,525) 2,915 2,197(b)

Total Stockholders' Equity 16,283 13,982 12,943 17,713 15,418- (d)

Average Total Stockholders' 15,133 13,463 15,328 16,566 14,352Equity* - (e)

Current and Long-Term Debt 6,387 6,986 6,655 5,906 5,909(GAAP) - (f)

Less: Cash (834) (1,600) (719) (2,087) (1,318)

Net Debt (Non-GAAP) - (g) 5,553 5,386 5,936 3,819 4,591

Total Capitalization (GAAP) 22,670 20,968 19,598 23,619 21,327- (d) + (f)

Total Capitalization 21,836 19,368 18,879 21,532 20,009(Non-GAAP) - (d) + (g)

Average TotalCapitalization (Non-GAAP)* 20,602 19,124 20,206 20,771 19,365- (h)

Return on Capital Employed(ROCE)

GAAP Net Income (Loss) - 13.4 % -4.8 % -21.6 % 14.7 % 12.1 %[(a) + (b)] / (h)

Return on Equity (ROE)

GAAP Net Income (Loss) - 17.1 % -8.1 % -29.5 % 17.6 % 15.3 %(b) / (e)

* Average for the currentand immediately precedingyear

ROCE & ROE

(Continued)

In millions of USD, exceptratio data (Unaudited)

2012 2011 2010 2009 2008

Interest Expense, Net 214 210 130 101 52(GAAP)

Tax Benefit Imputed (based (75) (74) (46) (35) (18)on 35%)

After-Tax Net Interest 139 136 84 66 34Expense (Non-GAAP) - (a)

Net Income (GAAP) - (b) 570 1,091 161 547 2,437

Total Stockholders' Equity 13,285 12,641 10,232 9,998 9,015- (d)

Average Total Stockholders' 12,963 11,437 10,115 9,507 8,003Equity* - (e)

Current and Long-Term Debt 6,312 5,009 5,223 2,797 1,897(GAAP) - (f)

Less: Cash (876) (616) (789) (686) (331)

Net Debt (Non-GAAP) - (g) 5,436 4,393 4,434 2,111 1,566

Total Capitalization (GAAP) 19,597 17,650 15,455 12,795 10,912- (d) + (f)

Total Capitalization 18,721 17,034 14,666 12,109 10,581(Non-GAAP) - (d) + (g)

Average TotalCapitalization (Non-GAAP)* 17,878 15,850 13,388 11,345 9,351- (h)

Return on Capital Employed(ROCE)

GAAP Net Income - [(a) + 4.0 % 7.7 % 1.8 % 5.4 % 26.4 %(b)] / (h)

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 4.4 % 9.5 % 1.6 % 5.8 % 30.5 %

* Average for the currentand immediately precedingyear

ROCE & ROE

(Continued)

In millions of USD, exceptratio data (Unaudited)

2007 2006 2005 2004 2003

Interest Expense, Net 47 43 63 63 59(GAAP)

Tax Benefit Imputed (based (16) (15) (22) (22) (21)on 35%)

After-Tax Net Interest 31 28 41 41 38Expense (Non-GAAP) - (a)

Net Income (GAAP) - (b) 1,090 1,300 1,260 625 430

Total Stockholders' Equity 6,990 5,600 4,316 2,945 2,223- (d)

Average Total Stockholders' 6,295 4,958 3,631 2,584 1,948Equity* - (e)

Current and Long-Term Debt 1,185 733 985 1,078 1,109(GAAP) - (f)

Less: Cash (54) (218) (644) (21) (4)

Net Debt (Non-GAAP) - (g) 1,131 515 341 1,057 1,105

Total Capitalization (GAAP) 8,175 6,333 5,301 4,023 3,332- (d) + (f)

Total Capitalization 8,121 6,115 4,657 4,002 3,328(Non-GAAP) - (d) + (g)

Average TotalCapitalization (Non-GAAP)* 7,118 5,386 4,330 3,665 3,068- (h)

Return on Capital Employed(ROCE)

GAAP Net Income - [(a) + 15.7 % 24.7 % 30.0 % 18.2 % 15.3 %(b)] / (h)

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 17.3 % 26.2 % 34.7 % 24.2 % 22.1 %

* Average for the currentand immediately precedingyear

ROCE & ROE

(Continued)

In millions of USD, exceptratio data (Unaudited)

2002 2001 2000 1999 1998

Interest Expense, Net 60 45 61 62(GAAP)

Tax Benefit Imputed (based (21) (16) (21) (22)on 35%)

After-Tax Net Interest 39 29 40 40Expense (Non-GAAP) - (a)

Net Income (GAAP) - (b) 87 399 397 569

Total Stockholders' Equity 1,672 1,643 1,381 1,130 1,280- (d)

Average Total Stockholders' 1,658 1,512 1,256 1,205Equity* - (e)

Current and Long-Term Debt 1,145 856 859 990 1,143(GAAP) - (f)

Less: Cash (10) (3) (20) (25) (6)

Net Debt (Non-GAAP) - (g) 1,135 853 839 965 1,137

Total Capitalization (GAAP) 2,817 2,499 2,240 2,120 2,423- (d) + (f)

Total Capitalization 2,807 2,496 2,220 2,095 2,417(Non-GAAP) - (d) + (g)

Average TotalCapitalization (Non-GAAP)* 2,652 2,358 2,158 2,256- (h)

Return on Capital Employed(ROCE)

GAAP Net Income - [(a) + 4.8 % 18.2 % 20.2 % 27.0 %(b)] / (h)

Return on Equity (ROE)

GAAP Net Income - (b) / (e) 5.2 % 26.4 % 31.6 % 47.2 %

* Average for the currentand immediately precedingyear

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.

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

Volume - Million Barrels of Oil 75.3 70.1 73.7 65.9 56.7Equivalent - (a)

Total Operating Revenues and Other (b) 4,139 3,694 2,965 2,246 1,103

Total Operating Expenses (c) 2,968 2,762 2,477 2,249 2,190

Operating Income (Loss) (d) 1,171 932 488 (3) (1,087)

Wellhead Revenues

Crude Oil and Condensate 2,699 2,251 1,711 1,395 615

Natural Gas Liquids 367 314 229 185 93

Natural Gas 404 625 302 184 141

Total Wellhead Revenues - (e) 3,470 3,190 2,242 1,764 849

Operating Costs

Lease and Well 270 270 261 227 245

Transportation Costs 214 202 195 180 152

Gathering and Processing Costs 128 139 119 115 97

General and Administrative 120 110 113 125 132

Taxes Other Than Income 239 215 114 126 81

Interest Expense, Net 45 47 53 53 54

Total Operating Cost (excluding DD&Aand Total Exploration 1,016 983 855 826 761

Costs) (f)

Depreciation, Depletion and 914 900 870 823 707Amortization (DD&A)

Total Operating Cost (excluding Total 1,930 1,883 1,725 1,649 1,468Exploration Costs) - (g)

Exploration Costs 35 33 41 38 27

Dry Hole Costs 13 11 - 13 -

Impairments 44 44 143 79 305

Total Exploration Costs (GAAP) 92 88 184 130 332

Less: Certain Impairments ^(1) (1) (1) (86) (27) (239)

Total Exploration Costs (Non-GAAP) 91 87 98 103 93

Total Operating Cost (including TotalExploration Costs 2,022 1,971 1,909 1,779 1,800

(GAAP)) - (h)

Total Operating Cost (including TotalExploration Costs 2,021 1,970 1,823 1,752 1,561

(Non-GAAP)) - (i)

Total Wellhead Revenues less TotalOperating Cost 1,448 1,219 333 (15) (951) (including Total Exploration Costs(GAAP))

Total Wellhead Revenues less TotalOperating Cost 1,449 1,220 419 12 (712) (including Total Exploration Costs(Non-GAAP))

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

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

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

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

Composite Average Operating Revenuesand Other per Boe 54.97 52.70 40.23 34.08 19.45

- (b) / (a)

Composite Average Operating Expenses 39.42 39.40 33.61 34.13 38.62per Boe - (c) / (a)

Composite Average Operating Income(Loss) per Boe 15.55 13.30 6.62 (0.05) (19.17)

- (d) / (a)

Composite Average Wellhead Revenue per 46.07 45.49 30.39 26.77 14.99Boe - (e) / (a)

Total Operating Cost per Boe (excludingDD&A and Total 13.48 14.02 11.60 12.56 13.40 Exploration Costs) - (f) / (a)

Composite Average Margin per Boe(excluding DD&A and 32.59 31.47 18.79 14.21 1.59 Total Exploration Costs) - [(e) /(a) - (f) / (a)]

Total Operating Cost per Boe (excludingTotal Exploration 25.61 26.86 23.41 25.05 25.86

Costs) - (g) / (a)

Composite Average Margin per Boe(excluding Total 20.46 18.63 6.98 1.72 (10.87) Exploration Costs) - [(e) / (a) -(g) / (a)]

Total Operating Cost per Boe (includingTotal Exploration 26.85 28.12 25.90 27.00 31.75

Costs) - (h) / (a)

Composite Average Margin per Boe(including Total 19.22 17.37 4.49 (0.23) (16.76) Exploration Costs) - [(e) / (a) -(h) / (a)]

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

Total Operating Cost per Boe (includingTotal Exploration 26.82 28.11 24.72 26.62 27.51

Costs) - (i) / (a)

Composite Average Margin per Boe(including Total 19.25 17.38 5.67 0.15 (12.52) 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 of EOG's oil and gas properties or other assets). EOG(1) 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 - 275.9 298.6 262.5 222.3(a)

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 - - - (10)Termination

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

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

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 3,424 4,078 3,911 3,187and Total Exploration Costs) - (f)

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

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

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

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

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 9,083 8,514 7,847 7,225Exploration Costs (GAAP)) - (j)

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

Total Wellhead Revenues less Total OperatingCost (GAAP) (including Total (1,792) 3,068 4,100 683

Exploration Costs (GAAP))

Total Wellhead Revenues less Total OperatingCost (Non-GAAP) (including Total 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 Boeamounts (Unaudited)

2020 2019 2018 2017

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Composite Average Margin per Boe (includingTotal Exploration Costs) - [(e) / (a) - (k) / 0.29 11.19 16.19 4.34 (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(2) 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 - (19) -Termination

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 2,841 3,203 3,895Total Exploration Costs) - (f)

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

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

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

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

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 7,150 13,295 8,868Exploration Costs (GAAP)) - (j)

Total Operating Cost (Non-GAAP) (including Total 6,782 6,968 8,044Exploration Costs (Non-GAAP)) - (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) (including Total (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 37.32 41.92 83.07Boe - (b) / (a)

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

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

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

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

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

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

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

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

(a)]

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

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

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

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

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

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

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

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

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

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

(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(2) 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).

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SOURCE EOG Resources, Inc.