PR Newswire | Aug 6, 2020 04:15PM EDT

08/06 15:14 CDT

EOG Resources Reports Second Quarter 2020 Results HOUSTON, Aug. 6, 2020

HOUSTON, Aug. 6, 2020 /PRNewswire/ --

* Generated Positive Net Cash Provided by Operating Activities and Free Cash Flow * Produced 7% More Crude Oil for 26% Less Capital Expenditures than Forecast * Per-Unit Cash Operating Costs Below Targets * Discovered 500 Bcf Net Natural Gas Resource Potential in Trinidad * Increased 2020 Well Cost Savings Target to 12% from 8%, Supporting Improved Outlook for Capital Efficiency

EOG Resources, Inc. (EOG) today reported a second quarter 2020 net loss of $909 million, or $1.57 per share, compared with second quarter 2019 net income of $848 million, or $1.46 per share.

Adjusted non-GAAP net loss for the second quarter 2020 was $131 million, or $0.23 per share, compared with adjusted non-GAAP net income of $762 million, or $1.31 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Second Quarter 2020 Review

Earnings in the second quarter 2020 were lower than the same prior year period due to lower commodity prices and production volumes, partially offset by reduced operating costs. EOG adjusted quickly to the decline in commodity prices - a result of COVID-19's impact on demand - by slowing drilling activity and lowering both capital expenditures and operating costs. EOG also deferred production by delaying initial production from most new wells and shutting in production from lower-margin, existing wells across multiple basins. Deferring production volumes into higher-priced time periods is a return-based decision designed to maximize net present value.

As a result of EOG's actions to address the rapid change in market conditions, total company crude oil volumes were 331,100 barrels of oil per day (Bopd), 27 percent below the second quarter 2019. Natural gas liquids production was 23 percent lower and natural gas volumes were 15 percent lower, contributing to 23 percent lower total company daily production.

Net crude oil volumes associated with the shut-in of existing wells peaked at approximately 107,000 Bopd in May, with an average of approximately 73,000 Bopd shut in during the second quarter. The company estimates that approximately 25,000 Bopd will remain shut-in on average during the third quarter 2020. EOG began to return shut-in volumes to production in June, and expects nearly all shut-in wells to begin production before the end of the third quarter. EOG also deferred initial production from most new wells until late June, with ten net new wells contributing less than 1,000 Bopd of production in the second quarter. EOG continues to closely monitor market conditions and retains flexibility to adjust its plans in response to changes in commodity prices.

Lease and well, transportation, and gathering and processing costs each declined in the second quarter compared with the prior year period. Lease and well costs were the largest contributor to the overall cost reduction and were down eight percent on a per-unit basis. Sustainable efficiency improvements and service cost reductions contributed to the savings. These factors also contributed to an improved well cost reduction target of 12 percent for 2020, an increase from the forecast at the start of the year of eight percent.

During the second quarter, EOG received net cash from settlements of financial commodity derivative contracts of $639 million. The company also elected to sell a portion of its crude oil production in May and June under fixed-price agreements to further limit its exposure to commodity price volatility. This contributed to lower average crude oil prices compared with the prior year period and reduced revenues from gathering, processing and marketing relative to marketing costs.

Net cash provided by operating activities was $88 million. Changes in working capital and other assets and liabilities generated a net cash outflow of $1.0 billion in the second quarter 2020 and a net cash inflow of $0.2 billion in the first six months of 2020. Excluding changes in working capital and certain other items, EOG generated $672 million of discretionary cash flow in the second quarter 2020. The company incurred total expenditures of $534 million, including $478 million of capital expenditures before acquisitions, non-cash transactions and asset retirement costs, resulting in $194 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

"EOG generated positive free cash flow in the second quarter, made possible by our ability to quickly reduce activity and cut operating costs in all of our operating areas in response to historically low oil prices," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "This is a testament to EOG's unique culture and the flexibility provided by a decentralized organizational structure. In addition, our focus on safety, innovation, technical advancements and continuous improvement has not wavered. Our talented employees quickly and safely adapted to these volatile conditions, and I want to thank them for their dedication and commitment to EOG.

"Going forward, we will remain flexible and ready to respond to changes in market conditions with the goal of maximizing long-term shareholder value. Our priorities are unchanged: generate high returns on any capital invested and generate free cash flow to fund the dividend and protect our strong balance sheet. The sustainable improvements we are making across the company will support improved capital efficiency in the future, enabling EOG to maintain production at lower oil prices. We are confident EOG will emerge from the downturn an even better company."

Trinidad Exploration Success

EOG announced significant discoveries from its drilling campaign in Trinidad that have estimated gross resource potential of up to 1.0 trillion cubic feet of natural gas, or 500 billion cubic feet, net to EOG. The discoveries are based on results from four wells drilled in the past year located on three different blocks in shallow water off the southeast coast of Trinidad. The discoveries will support the installation of two new production platforms and development programs for the next three to five years. EOG plans to drill two additional wells over the remainder of 2020. Additional resource potential could be confirmed through further evaluation of the discovery wells and subsequent development. The exploration success supports EOG's long-term strategy in Trinidad of generating high returns and strong free cash flow through low-cost operations and targeted exploration.

Financial Review

EOG retains exceptional financial flexibility, with strong investment-grade credit ratings, low leverage ratios and ample liquidity. At June 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $2.4 billion of cash on the balance sheet at the end of the second quarter, EOG's net debt was $3.3 billion for a net debt-to-total capitalization ratio of 14 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of June 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

On April 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 that matured on that date. In addition, on April 14, 2020, EOG closed its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050. EOG received aggregate net proceeds from the sale, after deducting underwriting discounts and offering expenses, of approximately $1.48 billion. On June 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020 that matured on that date.

During the second quarter, EOG entered into offsetting contracts to lock-in the value of outstanding crude oil NYMEX WTI price swap contracts and other financial commodity derivative contracts effective from June through December 2020. As of June 30, EOG expects to receive net cash payments of $360 million from the settlement of these contracts over the remainder of 2020.

Second Quarter 2020 Results WebcastFriday, August 7, 2020, 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, Trinidad, and China. To learn more visit www.eogresources.com.

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

Media and Investor ContactKimberly Ehmer 713-571-4676

Category: Earnings

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, returns, 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," "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, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness 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 crude oil and condensate, natural gas liquids, natural gas and related commodity production; * 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 and refining 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 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 imposing 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 and transportation 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, on pages 13 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 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, 2019, 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 thousands of USD, except per share data (Unaudited)

2Q 2020 2Q 2019 YTD 2020 YTD 2019

Operating Revenues and Other

Crude Oil and Condensate 614,627 2,528,866 2,680,125 4,729,269

Natural Gas Liquids 93,909 186,374 254,444 405,012

Natural Gas 141,696 269,892 351,460 604,864

Gains (Losses) on Mark-to-Market Commodity Derivative (126,362) 177,300 1,079,411 156,720 Contracts

Gathering, Processing and Marketing 362,786 1,501,386 1,401,432 2,787,040

Gains on Asset Dispositions, Net 13,233 8,009 29,693 4,173

Other, Net 3,485 25,803 24,501 69,194

Total 1,103,374 4,697,630 5,821,066 8,756,272

Operating Expenses

Lease and Well 245,346 347,281 575,005 683,572

Transportation Costs 151,728 174,101 360,024 350,623

Gathering and Processing Costs 96,767 112,643 225,249 223,938

Exploration Costs 27,283 32,522 66,960 68,846

Dry Hole Costs 87 3,769 459 3,863

Impairments 305,415 112,130 1,878,350 184,486

Marketing Costs 444,444 1,500,915 1,553,437 2,770,972

Depreciation, Depletion and Amortization 706,679 957,304 1,706,739 1,836,899

General and Administrative 131,855 121,780 246,128 228,452

Taxes Other Than Income 80,319 204,414 237,679 397,320

Total 2,189,923 3,566,859 6,850,030 6,748,971

Operating Income (Loss) (1,086,549) 1,130,771 (1,028,964) 2,007,301

Other Income (Expense), Net (4,500) 8,503 13,608 14,115

Income (Loss) Before Interest Expense and Income Taxes (1,091,049) 1,139,274 (1,015,356) 2,021,416

Interest Expense, Net 54,213 49,908 98,903 104,814

Income (Loss) Before Income Taxes (1,145,262) 1,089,366 (1,114,259) 1,916,602

Income Tax Provision (Benefit) (235,878) 241,525 (214,688) 433,335

Net Income (Loss) (909,384) 847,841 (899,571) 1,483,267

Dividends Declared per Common Share 0.3750 0.2875 0.7500 0.5075

Net Income (Loss) Per Share

Basic (1.57) 1.47 (1.55) 2.57

Diluted (1.57) 1.46 (1.55) 2.56

Average Number of Common Shares

Basic 578,719 577,460 578,581 577,333

Diluted 578,719 580,247 578,581 580,204

Wellhead Volumes and Prices

(Unaudited)

2Q 2020 2Q 2019 % Change YTD 2020 YTD 2019 % Change

Crude Oil and Condensate Volumes (MBbld) ^(A)

United States 330.9 454.9 -27 % 406.8 445.1 -9 %

Trinidad 0.1 0.6 -83 % 0.3 0.7 -57 %

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

Total 331.1 455.7 -27 % 407.2 445.8 -9 %

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)

United States 20.40 61.01 -67 % 36.17 58.63 -38 %

Trinidad 0.60 49.56 -99 % 27.75 46.62 -40 %

Other International ^(B) 48.78 55.07 -11 % 53.41 57.78 -8 %

Composite 20.40 60.99 -67 % 36.16 58.61 -38 %

Natural Gas Liquids Volumes (MBbld) ^(A)

United States 101.2 131.1 -23 % 131.2 125.4 5 %

Other International ^(B) - - - -

Total 101.2 131.1 -23 % 131.2 125.4 5 %

Average Natural Gas Liquids Prices ($/Bbl) ^(C)

United States 10.20 15.63 -35 % 10.65 17.84 -40 %

Other International ^(B) - - - -

Composite 10.20 15.63 -35 % 10.65 17.84 -40 %

Natural Gas Volumes (MMcfd) ^(A)

United States 939 1,047 -10 % 1,039 1,025 1 %

Trinidad 174 273 -36 % 188 270 -30 %

Other International ^(B) 34 36 -6 % 35 37 -5 %

Total 1,147 1,356 -15 % 1,262 1,332 -5 %

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

United States 1.11 1.98 -44 % 1.32 2.37 -44 %

Trinidad 2.13 2.69 -21 % 2.15 2.80 -23 %

Other International ^(B) 4.36 4.25 2 % 4.34 4.31 1 %

Composite 1.36 2.19 -38 % 1.53 2.51 -39 %

Crude Oil Equivalent Volumes (MBoed) ^(D)

United States 588.5 760.4 -23 % 711.1 741.3 -4 %

Trinidad 29.2 46.1 -37 % 31.6 45.6 -31 %

Other International ^(B) 5.7 6.3 -10 % 6.1 6.4 -5 %

Total 623.4 812.8 -23 % 748.8 793.3 -6 %

Total MMBoe ^(D) 56.7 74.0 -23 % 136.3 143.6 -5 %

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

(B)Other International includes EOG's China and Canada operations.

Dollars per barrel or per thousand cubic feet, as applicable. Excludes (C)the 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 fiscal quarter ended June 30, 2020).

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio (D)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 thousands of USD, except per share data (Unaudited)

June 30, December 31,

2020 2019

Current Assets

Cash and Cash Equivalents 2,416,501 2,027,972

Accounts Receivable, Net 943,354 2,001,658

Inventories 676,580 767,297

Assets from Price Risk Management Activities 207,019 1,299

Income Taxes Receivable 196,958 151,665

Other 156,979 323,448

Total 4,597,391 5,273,339

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method) 64,406,245 62,830,415

Other Property, Plant and Equipment 4,665,815 4,472,246

Total Property, Plant and Equipment 69,072,060 67,302,661

Less: Accumulated Depreciation, Depletion and Amortization (39,838,595) (36,938,066)

Total Property, Plant and Equipment, Net 29,233,465 30,364,595

Deferred Income Taxes 1,846 2,363

Other Assets 1,388,969 1,484,311

Total Assets 35,221,671 37,124,608

Current Liabilities

Accounts Payable 1,281,166 2,429,127

Accrued Taxes Payable 193,763 254,850

Dividends Payable 217,004 166,273

Liabilities from Price Risk Management Activities - 20,194

Current Portion of Long-Term Debt 21,121 1,014,524

Current Portion of Operating Lease Liabilities 252,642 369,365

Other 188,685 232,655

Total 2,154,381 4,486,988

Long-Term Debt 5,703,141 4,160,919

Other Liabilities 2,138,696 1,789,884

Deferred Income Taxes 4,837,896 5,046,101

Commitments and Contingencies

Stockholders' Equity

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,386,649 Shares Issued at June 30, 2020 and 582,213,016 Shares Issued at December 205,824 205,822 31, 2019

Additional Paid in Capital 5,886,298 5,817,475

Accumulated Other Comprehensive Loss (6,130) (4,652)

Retained Earnings 14,312,493 15,648,604

Common Stock Held in Treasury, 142,025 Shares at June 30, 2020 and 298,820 (10,928) (26,533) Shares at December 31, 2019

Total Stockholders' Equity 20,387,557 21,640,716

Total Liabilities and Stockholders' Equity 35,221,671 37,124,608

Cash Flows Statements

In thousands of USD (Unaudited)

2Q 2020 2Q 2019 YTD 2020 YTD 2019

Cash Flows from Operating Activities

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

Net Income (Loss) (909,384) 847,841 (899,571) 1,483,267

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization 706,679 957,304 1,706,739 1,836,899

Impairments 305,415 112,130 1,878,350 184,486

Stock-Based Compensation Expenses 39,571 38,566 79,643 77,653

Deferred Income Taxes (252,466) 217,970 (207,692) 324,294

Gains on Asset Dispositions, Net (13,233) (8,009) (29,693) (4,173)

Other, Net 8,986 2,487 171 5,439

Dry Hole Costs 87 3,769 459 3,863

Mark-to-Market Commodity Derivative Contracts

Total (Gains) Losses 126,362 (177,300) (1,079,411) (156,720)

Net Cash Received from Settlements of Commodity 639,388 10,444 723,761 31,290 Derivative Contracts

Other, Net (365) 663 (720) 1,639

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 469,294 239,250 1,191,457 (69,746)

Inventories (18,095) 7,720 84,575 (11,259)

Accounts Payable (1,618,276) (67,229) (1,184,718) 126,853

Accrued Taxes Payable (6,482) (61,718) (61,087) 53,280

Other Assets 194,682 494,322 252,978 487,387

Other Liabilities 1,675 (4,014) (64,403) (58,106)

Changes in Components of Working Capital Associated with 414,236 72,347 282,154 (22,034) Investing and Financing Activities

Net Cash Provided by Operating Activities 88,074 2,686,543 2,672,992 4,294,312

Investing Cash Flows

Additions to Oil and Gas Properties (423,982) (1,507,024) (1,990,033) (3,446,497)

Additions to Other Property, Plant and Equipment (24,591) (55,918) (147,366) (116,881)

Proceeds from Sales of Assets 17,567 2,593 43,368 17,642

Changes in Components of Working Capital Associated with (414,236) (72,325) (282,154) 22,056 Investing Activities

Net Cash Used in Investing Activities (845,242) (1,632,674) (2,376,185) (3,523,680)

Financing Cash Flows

Long-Term Debt Borrowings 1,483,852 - 1,483,852 -

Long-Term Debt Repayments (1,000,000) (900,000) (1,000,000) (900,000)

Dividends Paid (217,042) (127,135) (384,100) (254,681)

Treasury Stock Purchased (402) (2,155) (5,057) (8,403)

Proceeds from Stock Options Exercised and Employee Stock 8,548 8,292 8,614 8,695 Purchase Plan

Debt Issuance Costs (2,635) (4,902) (2,635) (4,902)

Repayment of Finance Lease Liabilities (4,824) (3,213) (8,445) (6,403)

Changes in Components of Working Capital Associated with - (22) - (22) Financing Activities

Net Cash Provided by (Used in) Financing Activities 267,497 (1,029,135) 92,229 (1,165,716)

Effect of Exchange Rate Changes on Cash (680) (59) (507) (65)

Increase (Decrease) in Cash and Cash Equivalents (490,351) 24,675 388,529 (395,149)

Cash and Cash Equivalents at Beginning of Period 2,906,852 1,135,810 2,027,972 1,555,634

Cash and Cash Equivalents at End of Period 2,416,501 1,160,485 2,416,501 1,160,485

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 is included in the tables below and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com.



EOG believes these measures 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 intheir 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. 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), Total 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 thousands of USD, except per share data (Unaudited)

2Q 2020

Before Income Tax After Diluted

Tax Impact Tax Earnings per Share

Reported Net Loss (GAAP) (1,145,262) 235,878 (909,384) (1.57)

Adjustments:

(Gains) Losses on Mark-to-Market Commodity Derivative Contracts 126,362 (27,734) 98,628 0.17

Net Cash Received from Settlements of Commodity Derivative Contracts 639,388 (140,333) 499,055 0.86

Less: Gains on Asset Dispositions, Net (13,233) 2,930 (10,303) (0.02)

Add: Certain Impairments 239,167 (48,351) 190,816 0.33

Adjustments to Net Loss 991,684 (213,488) 778,196 1.34

Adjusted Net Loss (Non-GAAP) (153,578) 22,390 (131,188) (0.23)

Average Number of Common Shares (GAAP)

Basic 578,719

Diluted 578,719

Average Number of Common Shares (Non-GAAP)

Basic 578,719

Diluted 578,719

2Q 2019

Before After Diluted Income Tax Tax Impact Tax Earnings per Share

Reported Net Income (GAAP) 1,089,366 (241,525) 847,841 1.46

Adjustments:

(Gains) Losses on Mark-to-Market Commodity Derivative Contracts (177,300) 38,930 (138,370) (0.24)

Net Cash Received from Settlements of Commodity Derivative Contracts 10,444 (2,276) 8,168 0.01

Less: Gains on Asset Dispositions, Net (8,009) 1,734 (6,275) (0.01)

Add: Certain Impairments 65,289 (14,311) 50,978 0.09

Adjustments to Net Income (109,576) 24,077 (85,499) (0.15)

Adjusted Net Income (Non-GAAP) 979,790 (217,448) 762,342 1.31

Average Number of Common Shares (GAAP)

Basic 577,460

Diluted 580,247

Average Number of Common Shares (Non-GAAP) 577,460

Basic 580,247

Diluted

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)

YTD 2020

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Loss (GAAP) (1,114,259) 214,688 (899,571) (1.55)

Adjustments:

Gains Mark-to-Market Commodity Derivative Contracts (1,079,411) 236,909 (842,502) (1.47)

Net Cash Received from Settlements of Commodity Derivative Contracts 723,761 (158,851) 564,910 0.98

Less: Gains on Asset Dispositions, Net (29,693) 6,543 (23,150) (0.04)

Add: Certain Impairments 1,755,483 (368,324) 1,387,159 2.40

Adjustments to Net Loss 1,370,140 (283,723) 1,086,417 1.87

Adjusted Net Income (Non-GAAP) 255,881 (69,035) 186,846 0.32

Average Number of Common Shares (GAAP)

Basic 578,581

Diluted 578,581

Average Number of Common Shares (Non-GAAP)

Basic 578,581

Diluted 580,179

YTD 2019

Diluted Before Income Tax After Earnings Tax Impact Tax per Share

Reported Net Income (GAAP) 1,916,602 (433,335) 1,483,267 2.56

Adjustments:

Gains on Mark-to-Market Commodity Derivative Contracts (156,720) 34,397 (122,323) (0.21)

Net Cash Received from Settlements of Commodity Derivative Contracts 31,290 (6,868) 24,422 0.04

Less: Gains on Asset Dispositions, Net (4,173) 998 (3,175) (0.01)

Add: Certain Impairments 89,034 (19,541) 69,493 0.12

Adjustments to Net Income (40,569) 8,986 (31,583) (0.06)

Adjusted Net Income (Non-GAAP) 1,876,033 (424,349) 1,451,684 2.50

Average Number of Common Shares (GAAP)

Basic 577,333

Diluted 580,204

Average Number of Common Shares (Non-GAAP)

Basic 577,333

Diluted 580,204

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

2Q 2020 2Q 2019 YTD 2020 YTD 2019

Net Cash Provided by Operating Activities (GAAP) 88,074 2,686,543 2,672,992 4,294,312

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 20,484 26,089 52,966 55,876

Other Non-Current Income Taxes - Net Receivable - 42,764 112,704 145,682

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable (469,294) (239,250) (1,191,457) 69,746

Inventories 18,095 (7,720) (84,575) 11,259

Accounts Payable 1,618,276 67,229 1,184,718 (126,853)

Accrued Taxes Payable 6,482 61,718 61,087 (53,280)

Other Assets (194,682) (494,322) (252,978) (487,387)

Other Liabilities (1,675) 4,014 64,403 58,106

Changes in Components of Working Capital Associated with Investing and (414,236) (72,347) (282,154) 22,034 Financing Activities

Discretionary Cash Flow (Non-GAAP) 671,524 2,074,718 2,337,706 3,989,495

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease -68 % -41 %

Discretionary Cash Flow (Non-GAAP) 671,524 2,074,718 2,337,706 3,989,495

Less:

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a) (477,616) (1,595,726) (2,162,336) (3,328,202)

Free Cash Flow (Non-GAAP) ^(b) 193,908 478,992 175,370 661,293

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP) for the three-month and six-monthperiods ended June 30, 2020 and 2019:

Total Expenditures (GAAP) 534,411 1,663,127 2,360,189 3,765,046

Less:

Asset Retirement Costs (5,955) (55,425) (25,563) (60,581)

Non-Cash Expenditures of Other Property, Plant and Equipment (60) (586) (60) (586)

Non-Cash Acquisition Costs of Unproved Properties (23,243) (10,240) (47,731) (53,721)

Non-Cash Finance Leases (24,319) - (73,277) -

Acquisition Costs of Proved Properties (3,218) (1,150) (51,222) (321,956)

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) 477,616 1,595,726 2,162,336 3,328,202

(b) To better align the presentation of free cash flow for comparative purposeswithin the industry, free cash flow excludes dividends paid (GAAP) as areconciling item for the three-month and six-month periods ending June 30,2020. The comparative prior periods shown have been revised to conform to thispresentation.

Maintenance Capital Expenditures

The capital expenditures required to fund drilling and infrastructurerequirements to keep U.S. oil production in 2021 flat relative to anticipated4Q 2020 U.S. oil production.

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

FY 2019 FY 2018 FY 2017

Net Cash Provided by Operating Activities (GAAP) 8,163,180 7,768,608 4,265,336

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 113,733 123,986 122,688

Other Non-Current Income Taxes - Net (Payable) Receivable 238,711 148,993 (513,404)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable 91,792 368,180 392,131

Inventories (90,284) 395,408 174,548

Accounts Payable (168,539) (439,347) (324,192)

Accrued Taxes Payable (40,122) 92,461 63,937

Other Assets (358,001) 125,435 658,609

Other Liabilities 56,619 (10,949) 89,871

Changes in Components of Working Capital Associated with Investing and 115,061 (301,083) (89,992) Financing Activities

Discretionary Cash Flow (Non-GAAP) 8,122,150 8,271,692 4,839,532

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

Discretionary Cash Flow (Non-GAAP) 8,122,150 8,271,692 4,839,532

Less:

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a) (6,234,454) (6,172,950) (4,228,859)

Free Cash Flow (Non-GAAP) ^(b) 1,887,696 2,098,742 610,673

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP) for the twelve-month periods endedDecember 31, 2019, 2018 and 2017:

Total Expenditures (GAAP) 6,900,450 6,706,359 4,612,746

Less:

Asset Retirement Costs (186,088) (69,699) (55,592)

Non-Cash Expenditures of Other Property, Plant and Equipment (2,266) (49,484) -

Non-Cash Acquisition Costs of Unproved Properties (97,704) (290,542) (255,711)

Acquisition Costs of Proved Properties (379,938) (123,684) (72,584)

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) 6,234,454 6,172,950 4,228,859

(b) To better align the presentation of free cash flow for comparative purposeswithin the industry, free cash flow excludes dividends paid (GAAP) as areconciling item for the twelve-month period ending December 31, 2019. Thecomparative prior periods shown have been revised to conform to thispresentation.

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

FY 2014 FY 2013 FY 2012

Net Cash Provided by Operating Activities (GAAP) 8,649,155 7,329,414 5,236,777

Adjustments:

Exploration Costs (excluding Stock-Based Compensation Expenses) 157,453 134,531 159,182

Excess Tax Benefits from Stock-Based Compensation 99,459 55,831 67,035

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable (84,982) 23,613 178,683

Inventories 161,958 (53,402) 156,762

Accounts Payable (543,630) (178,701) 17,150

Accrued Taxes Payable (16,486) (75,142) (78,094)

Other Assets 14,448 109,567 118,520

Other Liabilities (75,420) 20,382 (36,114)

Changes in Components of Working Capital Associated with Investing and 103,414 51,361 (74,158)Financing Activities

Discretionary Cash Flow (Non-GAAP) 8,465,369 7,417,454 5,745,743

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

Discretionary Cash Flow (Non-GAAP) 8,465,369 7,417,454 5,745,743

Less:

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a) (8,292,090) (7,101,791) (7,539,994)

Free Cash Flow (Non-GAAP) ^(b) 173,279 315,663 (1,794,251)

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash CapitalExpenditures Before Acquisitions (Non-GAAP) for the twelve-month periods endedDecember 31, 2014, 2013 and 2012:

Total Expenditures (GAAP) 8,631,906 7,361,457 7,753,828

Less:

Asset Retirement Costs (195,630) (134,445) (126,987)

Non-Cash Expenditures of Other Property, Plant and Equipment - - (65,791)

Non-Cash Acquisition Costs of Unproved Properties (5,085) (5,007) (20,317)

Acquisition Costs of Proved Properties (139,101) (120,214) (739)

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) 8,292,090 7,101,791 7,539,994

(b) To better align the presentation of free cash flow for comparative purposeswithin the industry, the presentation of free cash flow for the comparativeprior periods shown has been revised to exclude dividends paid (GAAP) as areconciling item.

Total Expenditures

In millions of USD (Unaudited)

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

Exploration and Development Drilling 381 1,290 4,951 4,935 3,132

Facilities 31 174 629 625 575

Leasehold Acquisitions 30 38 276 488 427

Property Acquisitions 3 1 380 124 73

Capitalized Interest 8 11 38 24 27

Subtotal 453 1,514 6,274 6,196 4,234

Exploration Costs 27 33 140 149 145

Dry Hole Costs - 4 28 5 5

Exploration and Development Expenditures 480 1,551 6,442 6,350 4,384

Asset Retirement Costs 5 56 186 70 56

Total Exploration and Development Expenditures 485 1,607 6,628 6,420 4,440

Other Property, Plant and Equipment 49 56 272 286 173

Total Expenditures 534 1,663 6,900 6,706 4,613

EBITDAX and Adjusted EBITDAX

In thousands of USD (Unaudited)

2Q 2020 2Q 2019 YTD 2020 YTD 2019

Net Income (Loss) (GAAP) (909,384) 847,841 (899,571) 1,483,267

Adjustments:

Interest Expense, Net 54,213 49,908 98,903 104,814

Income Tax Provision (Benefit) (235,878) 241,525 (214,688) 433,335

Depreciation, Depletion and Amortization 706,679 957,304 1,706,739 1,836,899

Exploration Costs 27,283 32,522 66,960 68,846

Dry Hole Costs 87 3,769 459 3,863

Impairments 305,415 112,130 1,878,350 184,486

EBITDAX (Non-GAAP) (51,585) 2,244,999 2,637,152 4,115,510

(Gains) Losses on MTM Commodity Derivative Contracts 126,362 (177,300) (1,079,411) (156,720)

Net Cash Received from Settlements of Commodity Derivative Contracts 639,388 10,444 723,761 31,290

Less: Gains on Asset Dispositions, Net (13,233) (8,009) (29,693) (4,173)

Adjusted EBITDAX (Non-GAAP) 700,932 2,070,134 2,251,809 3,985,907

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease -66 % -44 %

Definitions

EBITDAX - Earnings Before Interest Expense; Income Taxes; Depreciation,Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

June 30, March 31, December 31, September 30, June 30, March 31, 2020 2020 2019 2019 2019 2019

Total Stockholders' Equity - (a) 20,388 21,471 21,641 21,124 20,630 19,904

Current and Long-Term Debt (GAAP) - (b) 5,724 5,222 5,175 5,177 5,179 6,081

Less: Cash (2,417) (2,907) (2,028) (1,583) (1,160) (1,136)

Net Debt (Non-GAAP) - (c) 3,307 2,315 3,147 3,594 4,019 4,945

Total Capitalization (GAAP) - (a) + (b) 26,112 26,693 26,816 26,301 25,809 25,985

Total Capitalization (Non-GAAP) - (a) + (c) 23,695 23,786 24,788 24,718 24,649 24,849

Debt-to-Total Capitalization (GAAP) - (b) / 22 % 20 % 19 % 20 % 20 % 23 % [(a) + (b)]

Net Debt-to-Total Capitalization (Non- 14 % 10 % 13 % 15 % 16 % 20 % GAAP) - (c) / [(a) + (c)]

Net Debt-to-Total Capitalization Ratio

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)] 24 % 26 % 27 % 28 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 19 % 22 % 24 % 25 %

Net Debt-to-Total Capitalization Ratio

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 % 31 % 33 % 33 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 25 % 28 % 28 % 28 %

Net Debt-to-Total Capitalization Ratio

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) + 33 % 37 % 37 % 36 % 34 % (b)]

Net Debt-to-Total Capitalization (Non-GAAP) - 28 % 33 % 34 % 34 % 31 % (c) / [(a) + (c)]

Reserve Replacement Cost Data

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

2019 2018 2017 2016 2015 2014

Total Costs Incurred in Exploration and Development 6,628.2 6,419.7 4,439.4 6,445.2 4,928.3 7,904.8Activities (GAAP)

Less: Asset Retirement Costs (186.1) (69.7) (55.6) 19.9 (53.5) (195.6)

Non-Cash Acquisition Costs of Unproved (97.7) (290.5) (255.7) (3,101.8) - - Properties

Acquisition Costs of Proved Properties (379.9) (123.7) (72.6) (749.0) (480.6) (139.1)

Total Exploration and Development Expenditures for 5,964.5 5,935.8 4,055.5 2,614.3 4,394.2 7,570.1 Drilling Only (Non-GAAP) - (a)

Total Costs Incurred in Exploration and Development 6,628.2 6,419.7 4,439.4 6,445.2 4,928.3 7,904.8 Activities (GAAP)

Less: Asset Retirement Costs (186.1) (69.7) (55.6) 19.9 (53.5) (195.6)

Non-Cash Acquisition Costs of Unproved (97.7) (290.5) (255.7) (3,101.8) - - Properties

Non-Cash Acquisition Costs of Proved Properties (52.3) (70.9) (26.2) (732.3) - -

Total Exploration and Development Expenditures 6,292.1 5,988.6 4,101.9 2,631.0 4,874.8 7,709.2 (Non-GAAP) - (b)

Net Proved Reserve Additions From All Sources - Oil

Equivalents (MMBoe)

Revisions Due to Price - (c) (59.7) 34.8 154.0 (100.7) (573.8) 52.2

Revisions Other Than Price (0.3) (39.5) 48.0 252.9 107.2 48.4

Purchases in Place 16.8 11.6 2.3 42.3 56.2 14.4

Extensions, Discoveries and Other Additions - (d) 750.0 669.7 420.8 209.0 245.9 519.2

Total Proved Reserve Additions - (e) 706.8 676.6 625.1 403.5 (164.5) 634.2

Sales in Place (4.6) (10.8) (20.7) (167.6) (3.5) (36.3)

Net Proved Reserve Additions From All Sources 702.2 665.8 604.4 235.9 (168.0) 597.9

Production 300.9 265.0 224.4 207.1 211.2 219.1

Reserve Replacement Costs ($ / Boe)

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

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

All-in Total, Excluding Revisions Due to Price - 8.21 9.33 8.71 5.22 11.91 13.25 (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.

ICE Brent Differential Basis Swap Contracts

Prices received by EOG for its crude oil production generally vary from NYMEXWTI prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix thedifferential between ICE Brent pricing and pricing in Cushing, Oklahoma (ICEBrent Differential). Presented below is a comprehensive summary of EOG's ICEBrent Differential basis swap contracts through July 30, 2020. The weightedaverage price differential expressed in $/Bbl represents the amount of additionto Cushing, Oklahoma, prices for the notional volumes expressed in Bbld coveredby the basis swap contracts.

Weighted Average Price Volume2020 Differential (Bbld) ($/Bbl)

May 2020 (CLOSED) 10,000 4.92

Houston Differential Basis Swap Contracts

EOG has also entered into crude oil basis swap contracts in order to fix thedifferential between pricing in Houston, Texas, and Cushing, Oklahoma (HoustonDifferential). Presented below is a comprehensive summary of EOG's HoustonDifferential basis swap contracts through July 30, 2020. The weighted averageprice differential expressed in $/Bbl represents the amount of addition toCushing, Oklahoma, prices for the notional volumes expressed in Bbld covered bythe basis swap contracts.

Weighted Average Price Volume2020 Differential (Bbld) ($/Bbl)

May 2020 (CLOSED) 10,000 1.55

Roll Differential Swap Contracts

EOG has also entered into crude oil swaps in order to fix the differential inpricing between the NYMEX calendar month average and the physical crude oildelivery month (Roll Differential). Presented below is a comprehensive summaryof EOG's Roll Differential swap contracts through July 30, 2020. The weightedaverage price differential expressed in $/Bbl represents the amount of netaddition (reduction) to delivery month prices for the notional volumesexpressed in Bbld covered by the swap contracts.

Weighted Average Price Volume2020 Differential (Bbld) ($/Bbl)

February 1, 2020 through June 30, 2020 (CLOSED) 10,000 0.7

July 1, 2020 through August 31, 2020 (CLOSED) 88,000 (1.16)

Sep-20 88,000 (1.16)

October 1, 2020 through December 31, 2020 66,000 (1.16)

In May 2020, EOG entered into crude oil Roll Differential swap contracts forthe period from July 1, 2020 through September 30, 2020, with notional volumesof 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, andfor the period from October 1, 2020 through December 31, 2020, with notionalvolumes of 44,000 Bbld at a weighted average price differential of $(0.73) perBbl. These contracts partially offset certain outstanding Roll Differentialswap contracts for the same time periods and volumes at a weighted averageprice differential of $(1.16) per Bbl. EOG expects to pay net cash of $3.2million for the settlement of these contracts. The offsetting contracts wereexcluded from the above table.

Crude Oil NYMEX WTI Price Swap Contracts

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI priceswap contracts through July 30, 2020, with notional volumes expressed in Bbldand prices expressed in $/Bbl.

Weighted Volume2020 Average Price (Bbld) ($/Bbl)

January 1, 2020 through March 31, 2020 (CLOSED) 200,000 59.33

April 1, 2020 through May 31, 2020 (CLOSED) 265,000 51.36

In April and May 2020, EOG entered into crude oil NYMEX WTI price swapcontracts for the period from June 1, 2020 through June 30, 2020, with notionalvolumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for theperiod from July 1, 2020 through July 31, 2020, with notional volumes of254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period fromAugust 1, 2020 through September 30, 2020, with notional volumes of 154,000Bbld at a weighted average price of $34.18 per Bbl and for the period fromOctober 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbldat a weighted average price of $30.04 per Bbl. These contracts offset theremaining NYMEX WTI price swap contracts for the same time periods and volumesat a weighted average price of $51.36 per Bbl for the period from June 1, 2020through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 throughJuly 31, 2020, $50.42 per Bbl for the period from August 1, 2020 throughSeptember 30, 2020 and $31.00 per Bbl for the period from October 1, 2020through December 31, 2020. EOG expects to receive net cash of $364.0 millionfor the settlement of these contracts. The offsetting contracts were excludedfrom the above table.

Crude Oil ICE Brent Price Swap Contracts

Presented below is a comprehensive summary of EOG's crude oil ICE Brent priceswap contracts through July 30, 2020, with notional volumes expressed in Bbldand prices expressed in $/Bbl.

Weighted Volume2020 Average Price (Bbld) ($/Bbl)

April 2020 (CLOSED) 75,000 25.66

May 2020 (CLOSED) 35,000 26.53

Mont Belvieu Propane Price Swap Contracts

Presented below is a comprehensive summary of EOG's Mont Belvieu propane(non-TET) financial price swap contracts (Mont Belvieu Propane Price SwapContracts) through July 30, 2020, with notional volumes expressed in Bbld andprices expressed in $/Bbl.

Weighted Volume2020 Average Price (Bbld) ($/Bbl)

January 1, 2020 through February 29, 2020 4,000 21.34(CLOSED)

March 1, 2020 through April 30, 2020 (CLOSED) 25,000 17.92

In April and May 2020, EOG entered into Mont Belvieu propane price swapcontracts for the period from May 1, 2020 through December 31, 2020, withnotional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contractsfor the same time period with notional volumes of 25,000 Bbld at a weightedaverage price of $17.92 per Bbl. EOG expects to receive net cash of $9.2million for the settlement of these contracts. The offsetting contracts wereexcluded from the above table.

Natural Gas Price Swap Contracts

Presented below is a comprehensive summary of EOG's natural gas price swapcontracts through July 30, 2020, with notional volumes expressed in MMBtud andprices expressed in $/MMBtu.

Weighted Volume2021 Average Price (MMBtud) ($/MMBtu)

January 1, 2021 through December 31, 2021 50,000 2.75

Natural Gas Collar Contracts

EOG has entered into natural gas collar contracts, which establish ceiling andfloor prices for the sale of notional volumes of natural gas as specified inthe collar contracts. The collars require that EOG pay the difference betweenthe ceiling price and the NYMEX Henry Hub natural gas price for the contractmonth (Henry Hub Index Price) in the event the Henry Hub Index Price is abovethe ceiling price. The collars grant EOG the right to receive the differencebetween the floor price and the Henry Hub Index Price in the event the HenryHub Index Price is below the floor price. In March 2020, EOG executed theearly termination provision granting EOG the right to terminate certain 2020natural gas collar contracts with notional volumes of 250,000 MMBtud at aweighted average ceiling price of $2.50 per MMBtu and a weighted average floorprice of $2.00 per MMBtu for the period from April 1, 2020 through July 31,2020. The net cash EOG received for settling these contracts was $7.8million. Presented below is a comprehensive summary of EOG's natural gascollar contracts through July 30, 2020, with notional volumes expressed inMMBtud and prices expressed in $/MMBtu.

Weighted Weighted Average Volume Average 2020 Floor (MMBtud) Ceiling Price Price

($/MMBtu) ($/ MMBtu)

April 1, 2020 through July 31, 2020 (CLOSED) 250,000 2.5 2

In April 2020, EOG entered into natural gas collar contracts for the periodfrom August 1, 2020 through October 31, 2020, with notional volumes of 250,000MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 perMMBtu. These contracts offset the remaining natural gas collar contracts forthe same time period with notional volumes of 250,000 MMBtud at a ceiling priceof $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG expects toreceive net cash of $1.1 million for the settlement of these contracts. Theoffsetting contracts were excluded from the above table.

Rockies Differential Basis Swap Contracts

Prices received by EOG for its natural gas production generally vary from NYMEXHenry Hub prices due to adjustments for delivery location (basis) and otherfactors. EOG has entered into natural gas basis swap contracts in order to fixthe differential between pricing in the Rocky Mountain area and NYMEX Henry Hubprices (Rockies Differential). Presented below is a comprehensive summary ofEOG's Rockies Differential basis swap contracts through July 30, 2020. Theweighted average price differential expressed in $/MMBtu represents the amountof reduction to NYMEX Henry Hub prices for the notional volumes expressed inMMBtud covered by the basis swap contracts.

Volume Weighted Average2020 Price Differential

(MMBtud) ($/MMBtu)

January 1, 2020 through July 31, 2020 (CLOSED) 30,000 0.55

August 1, 2020 through December 31, 2020 30,000 0.55

HSC Differential Basis Swap Contracts

EOG has also entered into natural gas basis swap contracts in order to fix thedifferential between pricing at the Houston Ship Channel (HSC) and NYMEX HenryHub prices (HSC Differential). In March 2020, EOG executed the earlytermination provision granting EOG the right to terminate certain 2020 HSCDifferential basis swaps with notional volumes of 60,000 MMBtud at a weightedaverage price differential of $0.05 per MMBtu for the period from April 1, 2020through December 31, 2020. The net cash EOG paid for settling these contractswas $0.4 million. Presented below is a comprehensive summary of EOG's HSCDifferential basis swap contracts through July 30, 2020. The weighted averageprice differential expressed in $/MMBtu represents the amount of reduction toNYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered bythe basis swap contracts.

Volume Weighted Average2020 Price Differential (MMBtud) ($/MMBtu)

January 1, 2020 through December 31, 2020 60,000 0.05(CLOSED)

Waha Differential Basis Swap Contracts

EOG has also entered into natural gas basis swap contracts in order to fix thedifferential between pricing at the Waha Hub in West Texas and NYMEX Henry Hubprices (Waha Differential). Presented below is a comprehensive summary ofEOG's Waha Differential basis swap contracts through July 30, 2020. Theweighted average price differential expressed in $/MMBtu represents the amountof reduction to NYMEX Henry Hub prices for the notional volumes expressed inMMBtud covered by the basis swap contracts.

Volume Weighted Average2020 Price Differential

(MMBtud) ($/MMBtu)

January 1, 2020 through April 30, 2020 (CLOSED) 50,000 1.4

In April 2020, EOG entered into Waha Differential basis swap contracts for theperiod from May 1, 2020 through December 31, 2020, with notional volumes of50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts forthe same time period with notional volumes of 50,000 MMBtud at a weightedaverage price differential of $1.40 per MMBtu. EOG expects to pay net cash of$11.9 million for the settlement of these contracts. The offsetting contractswere excluded from the above table.

Definitions

Bbld Barrels per day

$/Bbl Dollars per barrel

ICE Intercontinental Exchange

MMBtud Million British thermal units per day

$/MMBtu Dollars per million British thermal units

NYMEX U.S. New York Mercantile Exchange

WTI West Texas Intermediate

Direct After-Tax Rate of Return

The calculation of our direct after-tax rate of return (ATROR) with respect toour capital expenditure program for a particular play or well is based on theestimated recoverable reserves ("net" to EOG's interest) for all wells in suchplay 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 utilize certainassumptions regarding future commodity prices and operating costs) and ourdirect net costs incurred in drilling or acquiring (as the case may be) suchwells or well (as the case may be). As such, our direct ATROR with respect toour capital expenditures for a particular play or well cannot be calculatedfrom 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 facilities

Excludes Indirect Capital

- Gathering and Processing and other Midstream

- Land, Seismic, Geological and Geophysical

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 Facilities

- Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2019 2018 2017

Net Interest Expense (GAAP) 185 245

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

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

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

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

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

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

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

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

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

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

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

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

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

Return on Capital Employed (ROCE)

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

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

Return on Equity (ROE)

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

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

* Average for the current and immediately preceding year

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

Before Income Tax After Tax Impact Tax

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)

2017 2016 2015 2014 2013

Net Interest Expense (GAAP) 274 282 237 201 235

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

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

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

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

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

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

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

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

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

Return on Capital Employed (ROCE)

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

Return on Equity (ROE)

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

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2012 2011 2010 2009 2008

Net Interest Expense (GAAP) 214 210 130 101 52

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

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

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

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

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

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

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

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

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

Return on Capital Employed (ROCE)

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

Return on Equity (ROE)

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

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2007 2006 2005 2004 2003

Net Interest Expense (GAAP) 47 43 63 63 59

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

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

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

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

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

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

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

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

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

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

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

Return on Capital Employed (ROCE)

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

Return on Equity (ROE)

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

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2002 2001 2000 1999 1998

Net Interest Expense (GAAP) 60 45 61 62

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

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

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

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

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

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

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

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

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

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

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

Return on Capital Employed (ROCE)

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

Return on Equity (ROE)

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

* Average for the current and immediately preceding year

Costs per Barrel of Oil Equivalent

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

1Q 2020 2Q 2020 YTD 2020

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a) 79,548 56,733 136,281

Crude Oil and Condensate 2,065,498 614,627 2,680,125

Natural Gas Liquids 160,535 93,909 254,444

Natural Gas 209,764 141,696 351,460

Total Wellhead Revenues - (b) 2,435,797 850,232 3,286,029

Operating Costs

Lease and Well 329,659 245,346 575,005

Transportation Costs 208,296 151,728 360,024

Gathering and Processing Costs 128,482 96,767 225,249

General and Administrative 114,273 131,855 246,128

Taxes Other Than Income 157,360 80,319 237,679

Interest Expense, Net 44,690 54,213 98,903

Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c) 982,760 760,228 1,742,988

Depreciation, Depletion and Amortization (DD&A) 1,000,060 706,679 1,706,739

Total Operating Cost (excluding Total Exploration Costs) - (d) 1,982,820 1,466,907 3,449,727

Exploration Costs 39,677 27,283 66,960

Dry Hole Costs 372 87 459

Impairments 1,572,935 305,415 1,878,350

Total Exploration Costs 1,612,984 332,785 1,945,769

Less: Certain Impairments (Non-GAAP) (1,516,316) (239,167) (1,755,483)

Total Exploration Costs (Non-GAAP) 96,668 93,618 190,286

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) 2,079,488 1,560,525 3,640,013

Composite Average Wellhead Revenue per Boe - (b) / (a) 30.62 14.99 24.11

Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) 12.36 13.40 12.79- (c) / (a)

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - 18.26 1.59 11.32[(b) / (a) - (c) / (a)]

Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) 24.93 25.86 25.31

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / 5.69 (10.87) (1.20)(a) - (d) / (a)]

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - 26.15 27.51 26.71(e) / (a)

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) 4.47 (12.52) (2.60)- [(b) / (a) - (e) / (a)]

Costs per Barrel of Oil Equivalent

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

2019 2018 2017

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a) 298,565 262,516 222,251

Crude Oil and Condensate 9,612,532 9,517,440 6,256,396

Natural Gas Liquids 784,818 1,127,510 729,561

Natural Gas 1,184,095 1,301,537 921,934

Total Wellhead Revenues - (b) 11,581,445 11,946,487 7,907,891

Operating Costs

Lease and Well 1,366,993 1,282,678 1,044,847

Transportation Costs 758,300 746,876 740,352

Gathering and Processing Costs 479,102 436,973 148,775

General and Administrative 489,397 426,969 434,467

Less: Legal Settlement - Early Leasehold Termination - - (10,202)

Less: Joint Venture Transaction Costs - - (3,056)

Less: Joint Interest Billings Deemed Uncollectible - - (4,528)

General and Administrative (Non-GAAP) 489,397 426,969 416,681

Taxes Other Than Income 800,164 772,481 544,662

Interest Expense, Net 185,129 245,052 274,372

Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 4,079,085 3,911,029 3,169,689Costs) - (c)

Depreciation, Depletion and Amortization (DD&A) 3,749,704 3,435,408 3,409,387

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) 7,828,789 7,346,437 6,579,076

Exploration Costs 139,881 148,999 145,342

Dry Hole Costs 28,001 5,405 4,609

Impairments 517,896 347,021 479,240

Total Exploration Costs 685,778 501,425 629,191

Less: Certain Impairments (Non-GAAP) (274,974) (152,671) (261,452)

Total Exploration Costs (Non-GAAP) 410,804 348,754 367,739

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) 8,239,593 7,695,191 6,946,815

Cost per Barrel of Oil Equivalent

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

2019 2018 2017

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

Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total 13.66 14.90 14.25Exploration Costs) - (c) / (a)

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total 25.13 30.61 21.33Exploration Costs) - [(b) / (a) - (c) / (a)]

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - 26.22 27.99 29.59(d) / (a)

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) 12.57 17.52 5.99- [(b) / (a) - (d) / (a)]

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - 27.60 29.32 31.24(e) / (a)

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

Costs per Barrel of Oil Equivalent

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

2016 2015 2014

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a) 204,929 208,862 217,073

Crude Oil and Condensate 4,317,341 4,934,562 9,742,480

Natural Gas Liquids 437,250 407,658 934,051

Natural Gas 742,152 1,061,038 1,916,386

Total Wellhead Revenues - (b) 5,496,743 6,403,258 12,592,917

Operating Costs

Lease and Well 927,452 1,182,282 1,416,413

Transportation Costs 764,106 849,319 972,176

Gathering and Processing Costs 122,901 146,156 145,800

General and Administrative 394,815 366,594 402,010

Less: Voluntary Retirement Expense (42,054) - -

Less: Acquisition Costs (5,100) - -

Less: Legal Settlement - Early Leasehold Termination - (19,355) -

General and Administrative (Non-GAAP) 347,661 347,239 402,010

Taxes Other Than Income 349,710 421,744 757,564

Interest Expense, Net 281,681 237,393 201,458

Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 2,793,511 3,184,133 3,895,421Costs) - (c)

Depreciation, Depletion and Amortization (DD&A) 3,553,417 3,313,644 3,997,041

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) 6,346,928 6,497,777 7,892,462

Exploration Costs 124,953 149,494 184,388

Dry Hole Costs 10,657 14,746 48,490

Impairments 620,267 6,613,546 743,575

Total Exploration Costs 755,877 6,777,786 976,453

Less: Certain Impairments (Non-GAAP) (320,617) (6,307,593) (824,312)

Total Exploration Costs (Non-GAAP) 435,260 470,193 152,141

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) 6,782,188 6,967,970 8,044,603

Cost per Barrel of Oil Equivalent

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

2016 2015 2014

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

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

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total 13.18 15.41 40.06Exploration Costs) - [(b) / (a) - (c) / (a)]

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

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) (4.16) (0.45) 21.63- [(b) / (a) - (d) / (a)]

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

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

Quarter and Full Year Guidance

(Unaudited)

(a) Third Quarter and Full Year 2020 Forecast

The forecast items for the third quarter and full year 2020 set forth below forEOG Resources, Inc. (EOG) are based on current available information andexpectations as of the date of the accompanying press release. EOG undertakesno obligation, other than as required by applicable law, to update or revisethis forecast, whether as a result of new information, subsequent events,anticipated or unanticipated circumstances or otherwise. This forecast, whichshould be read in conjunction with the accompanying press release and EOG'srelated Current Report on Form 8-K filing, replaces and supersedes anypreviously issued guidance or forecast.

(b) Capital Expenditures

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

(c) Benchmark Commodity Pricing

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

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

Estimated Ranges for Third Quarter and Full Year 2020 3Q 2020 FY 2020

Daily Sales Volumes

Crude Oil and Condensate Volumes (MBbld)

United States 363.0 - 373.0 402.0 - 408.0

Trinidad 0.6 - 1.0 0.6 - 1.0

Other International - - 0.2 - - 0.2

Total 363.6 - 374.2 402.6 - 409.2

Natural Gas Liquids Volumes (MBbld)

Total 125.0 - 135.0 130.0 - 140.0

Natural Gas Volumes (MMcfd)

United States 940 - 1,000 985 - 1,075

Trinidad 165 - 185 180 - 195

Other International 20 - 30 20 - 30

Total 1,125 - 1,215 1,185 - 1,300

Crude Oil Equivalent Volumes (MBoed)

United States 644.7 - 674.7 696.2 - 727.2

Trinidad 28.1 - 31.8 30.6 - 33.5

Other International 3.3 - 5.2 3.3 - 5.2

Total 676.1 - 711.7 730.1 - 765.9

Quarter and Full Year Guidance

(Unaudited)

Estimated Ranges for Third Quarter and Full Year 2020 3Q 2020 FY 2020

Capital Expenditures ($MM) 600 - 700 3,400 - 3,600

Operating Costs

Unit Costs ($/Boe)

Lease and Well 4.20 - 4.70 4.10 - 4.50

Transportation Costs 2.70 - 3.10 2.50 - 2.90

Gathering and Processing 1.70 1.90 1.65 1.85

Depreciation, Depletion and Amortization 12.10 12.60 11.85 12.85

General and Administrative 2.25 - 2.35 1.85 - 1.95

Expenses ($MM)

Exploration and Dry Hole 35 - 45 130 - 170

Impairment 80 90 290 330

Capitalized Interest 5 - 9 27 - 33

Net Interest 50 - 54 200 - 205

Taxes Other Than Income (% of Wellhead Revenue) 7.0 % - 9.0 % 7.0 % - 8.0 %

Income Taxes

Effective Rate 15 % - 20 % 16 % - 21 %

Current Tax (Benefit) / Expense ($MM) (15) - 25 (120) - (80)

Pricing - (Refer to Benchmark Commodity Pricing intext)

Crude Oil and Condensate ($/Bbl)

Differentials

United States - above (below) WTI (2.30) - (0.30) (2.05) - (0.05)

Trinidad - above (below) WTI (11.00) - (9.00) (9.50) - (7.50)

Other International - above (below) WTI (18.75) - (12.75) 2.00 - 7.00

Natural Gas Liquids

Realizations as % of WTI 29 % - 41 % 30 % - 36 %

Natural Gas ($/Mcf)

Differentials

United States - above (below) NYMEX Henry Hub (0.70) - (0.30) (0.80) - (0.20)

Realizations

Trinidad 2.10 - 2.70 2.30 - 3.00

Other International 4.00 - 4.50 3.85 - 4.85

Definitions

$/Bbl U.S. Dollars per barrel

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

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

$MM U.S. Dollars in millions

MBbld Thousand barrels per day

MBoed Thousand barrels of oil equivalent per day

MMcfd Million cubic feet per day

NYMEX U.S. New York Mercantile Exchange

WTI West Texas Intermediate

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SOURCE EOG Resources, Inc.