EOG Resources 8K Reports Third Quarter 2020 Results; Adds Premium Natural Gas Play in South Texas; Provides Three-Year Outlook | EOG 5 Nov 20

EXHIBIT 99.1

November 5, 2020

EOG Resources Reports Third Quarter 2020 Results; Adds Premium Natural Gas Play in South Texas; Provides Three-Year Outlook

•Identified 21 Tcf Net Resource Potential and 1,250 Net Premium Locations in New South Texas Natural Gas Play

•Added a Total of 1,400 Net Premium Locations to Drilling Inventory Which Now Totals 11,500 Locations

•Generated $1.2 Billion Net Cash Provided by Operating Activities and Significant Free Cash Flow

•Capital Expenditures 23% Below Target and Crude Oil Production 2% Above Target

•Per-Unit Cash Operating Costs Below Targets

•Introduced Three-Year Outlook with 70-80% Cash Flow Reinvestment

HOUSTON – (PR Newswire) – EOG Resources, Inc. (EOG) today reported a third quarter 2020 net loss of $42 million, or $0.07 per share, compared with third quarter 2019 net income of $615 million, or $1.06 per share.

Adjusted non-GAAP net income for the third quarter 2020 was $252 million, or $0.43 per share, compared with adjusted non-GAAP net income of $654 million, or $1.13 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Third Quarter 2020 Review

EOG continued to respond aggressively to adverse market conditions by sharply lowering operating and capital costs as well as deferring production volumes to future periods. Reductions to operating costs were offset by lower commodity prices and production volumes, resulting in lower earnings in the third quarter 2020 compared with the same prior year period. Realized crude oil prices were $40.15 per barrel in the third quarter, down 29 percent from the same prior year period, while natural gas prices declined 21 percent, to $1.68 per thousand cubic feet. These declines were partially offset by an increase in natural gas liquids prices in the third quarter to $14.34 per barrel, up 13 percent compared with the same prior year period.

Compared with the third quarter 2019, total company crude oil volumes were 19 percent lower, at 377,600 barrels of oil per day (Bopd). Natural gas liquids production was one percent lower and natural gas volumes were 13 percent lower, contributing to 14 percent lower total company daily production. EOG continued to return shut-in wells to production during the third quarter, and nearly all shut-in wells were back on production by the end of September. On average, 28,000 Bopd was shut-in during the third quarter. EOG also began initial production from approximately 100 net new wells in the third quarter, after deferring such activity earlier in the year in response to lower oil prices.

Lease and well costs declined 24 percent on a per-unit basis compared with the same prior year period, driving an overall reduction in per-unit operating costs. Most of the lease and well cost savings were based on sustainable efficiency improvements in well-site maintenance, equipment repair, managing offset completions and other production operations.

Net cash provided by operating activities was $1.2 billion. Excluding changes in working capital and certain other items, EOG generated $1.3 billion of discretionary cash flow. The company incurred total expenditures of $646 million, including $499 million of capital expenditures before acquisitions, non‐cash transactions and asset retirement costs, resulting in $762 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

“Our operational execution continues to be excellent,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “I’m grateful to all EOG employees during these unusual times. We continue to exceed expectations by optimizing production volumes and reducing costs while maintaining our strong safety and environmental performance.

“Notably, we are not playing defense in the current challenging environment. In fact, the opposite is true: we are aggressively moving EOG forward, advancing new plays, identifying innovative solutions to lower costs and improve well productivity, sharpening our technological edge and further demonstrating our commitment to sustainability. All of this is driven from the bottom up by a decentralized organization and a unique culture. This year more than ever, we are focused on investing in our people and enhancing our culture to sustain our competitive advantage and enable EOG to play an increasingly vital role in meeting the long-term global energy needs.”

New South Texas Natural Gas Play and Premium Inventory Update

EOG has made a large natural gas resource play discovery on its Dorado prospect located in Webb County, Texas. A total of 21 trillion cubic feet (Tcf) of estimated net resource potential is contained in 700 feet of stacked pay in the Austin Chalk and Eagle Ford Shale formations. The company has identified an initial 1,250 net premium drilling locations across its 163,000 net acre position in the core of the play. EOG has drilled 17 wells in the Dorado play since January 2019, including five wells targeting the Austin Chalk and 12 wells targeting the Upper and Lower Eagle Ford.

The Austin Chalk formation has an estimated net resource potential of 9.5 Tcf of natural gas. EOG has identified 530 net premium drilling locations in the Austin Chalk. The prolific Austin Chalk wells generate rates of return that are competitive with EOG’s large inventory of premium oil plays. The rates of return are supported by low cash operating costs and proximity to several natural gas markets with options for LNG and pipeline export pricing. In addition, EOG plans to apply its latest water and emissions management technology to minimize the environmental footprint of its development activities.

The five initial Austin Chalk wells produced an average of 3.5 billion cubic feet (Bcf) of natural gas per well in the first year of production, with an average lateral length of 6,600 feet per well. EOG expects to complete approximately 15 wells in the Austin Chalk in 2021. A typical Austin Chalk well is expected to recover 22 Bcf of natural gas, or 18 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $7.0 million per well.

The company has identified additional net resource potential of 11.5 Tcf and 720 net premium drilling locations in the Lower and Upper Eagle Ford, which underlies the Austin Chalk in the same area. Wells targeting the Eagle Ford also generate strong premium rates of return, supported by low drilling costs and shared infrastructure with the Austin Chalk wells.

The first 12 wells targeting the Eagle Ford produced an average of 2.8 Bcf of natural gas per well in the first year of production, with an average lateral length of 7,700 feet per well. A typical Eagle Ford well is expected to recover 19 Bcf of natural gas, or 16 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $6.5 million per well.

Including the Dorado locations, EOG added 1,400 net premium drilling locations to its undrilled premium inventory in the third quarter 2020. Taking into account wells drilled over the past year and updated location counts across its portfolio, EOG’s premium inventory now totals approximately 11,500 net locations.

“Our new South Texas natural gas play is the latest example of EOG’s sustainable business model of organic exploration-driven resource expansion,” Thomas said. “The addition of Dorado to EOG’s diverse portfolio of premium plays improves the financial profile of EOG by every measure. It also allows us to diversify capital deployment throughout the organization and across our assets. We believe this prolific new discovery represents the lowest-cost natural gas play in the U.S., which will be both operationally efficient and have a small environmental footprint. With 21 Tcf of net resource potential captured by EOG in the heart of the play, it is also one of the largest. Dorado competes today with EOG’s premium oil plays, and we expect it to move rapidly into the top tier of our inventory as development unfolds. This is just the latest example of how EOG continues to organically improve.”

Capital Allocation Outlook

Over the next three years, EOG’s goal is to continue improving reinvestment returns, lowering per-unit operating costs and generating strong free cash flow to support a growing sustainable dividend while further strengthening its balance sheet. The company anticipates the current imbalance in the global crude oil market is likely to extend into 2021, and therefore expects to maintain its crude oil production at approximately the same level as the fourth quarter 2020. Assuming a balanced crude oil market after 2021, EOG expects to reinvest 70 to 80 percent of its discretionary cash flow and generate up to 10 percent compound annual crude oil production growth in 2022 and 2023 at a $50 West Texas Intermediate crude oil price and using the company’s current inventory of premium locations. At higher oil prices, EOG expects to maintain the same growth rate of up to 10 percent per year. Priorities for the allocation of additional free cash flow include sustainable dividend growth, debt reduction, the return of additional cash to shareholders and low-cost property acquisitions.

“Our new three-year outlook provides visibility into the momentum we have built the last four years since the introduction of our premium return criteria,” Thomas said. “EOG’s long-term strategy and capital allocation priorities remain consistent. We are focused on high-return reinvestment in our growing stable of premium plays, which continues to improve in quality and drives increasing capital efficiency. With our disciplined capital allocation, we expect free cash flow growth, which will support sustainable dividend growth and further strengthen the balance sheet. Returning additional cash to shareholders also becomes more likely as oil prices continue to recover. Altogether, this balanced strategy leverages the competitive strengths of EOG and maximizes total shareholder value.”

Financial Review

At September 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $3.1 billion of cash on the balance sheet at the end of the third quarter, EOG’s net debt-to-total capitalization ratio was 12 percent. EOG’s liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of September 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG divested its assets in the Marcellus Shale effective September 1, 2020 for proceeds of approximately $130 million. Current production from the divested assets is approximately 40 million cubic feet of natural gas per day and there were no premium locations associated with the assets.

Third Quarter 2020 Results Webcast

Friday, November 6, 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 EOG

EOG 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 Contacts

David Streit 713-571-4902

Neel Panchal 713-571-4884

Media and Investor Contact

Kimberly 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 any changes or other actions which may result from the recent U.S. elections 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 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.


Table of Contents


Third Quarter 2020
Supplemental Financial and Operating Data			Page

Income Statements			8
Wellhead Volumes and Prices			9
Balance Sheets			10
Cash Flows Statements			11
Non-GAAP Financial Measures			12
Adjusted Net Income (Loss)			13
Discretionary Cash Flow and Free Cash Flow			15
Total Expenditures			18
EBITDAX and Adjusted EBITDAX			19
Net Debt-to-Total Capitalization Ratio			20
Reserve Replacement Cost Data			25
Financial Commodity Derivative Contracts			26
Direct After-Tax Rate of Return			30
ROCE & ROE			31
Cost per Barrel of Oil Equivalent			36
Quarter and Full Year Guidance			41


Income Statements
In thousands of USD, except per share data (Unaudited)
	3Q 2020	3Q 2019	YTD 2020	YTD 2019
Operating Revenues and Other
Crude Oil and Condensate	1,394,622	2,418,989	4,074,747	7,148,258
Natural Gas Liquids	184,771	164,736	439,215	569,748
Natural Gas	183,790	269,625	535,250	874,489
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	(3,978)	85,902	1,075,433	242,622
Gathering, Processing and Marketing	538,955	1,334,450	1,940,387	4,121,490
Gains (Losses) on Asset Dispositions, Net	(70,976)	(523)	(41,283)	3,650
Other, Net	18,300	30,276	42,801	99,470
Total	2,245,484	4,303,455	8,066,550	13,059,727

Operating Expenses
Lease and Well	227,473	348,883	802,478	1,032,455
Transportation Costs	180,257	199,365	540,281	549,988
Gathering and Processing Costs	114,790	127,549	340,039	351,487
Exploration Costs	38,413	34,540	105,373	103,386
Dry Hole Costs	12,604	24,138	13,063	28,001
Impairments	78,990	105,275	1,957,340	289,761
Marketing Costs	521,351	1,343,293	2,074,788	4,114,265
Depreciation, Depletion and Amortization	823,050	953,597	2,529,789	2,790,496
General and Administrative	124,460	135,758	370,588	364,210
Taxes Other Than Income	126,810	203,098	364,489	600,418
Total	2,248,198	3,475,496	9,098,228	10,224,467

Operating Income (Loss)	(2,714)	827,959	(1,031,678)	2,835,260
Other Income, Net	3,401	9,118	17,009	23,233
Income (Loss) Before Interest Expense and Income Taxes	687	837,077	(1,014,669)	2,858,493
Interest Expense, Net	53,242	39,620	152,145	144,434
Income (Loss) Before Income Taxes	(52,555)	797,457	(1,166,814)	2,714,059
Income Tax Provision (Benefit)	(10,088)	182,335	(224,776)	615,670
Net Income (Loss)	(42,467)	615,122	(942,038)	2,098,389

Dividends Declared per Common Share	0.3750	0.2875	1.1250	0.7950
Net Income (Loss) Per Share
Basic	(0.07)	1.06	(1.63)	3.63
Diluted	(0.07)	1.06	(1.63)	3.61
Average Number of Common Shares
Basic	579,055	577,839	578,740	577,498
Diluted	579,055	581,271	578,740	581,190


Wellhead Volumes and Prices
(Unaudited)
	3Q 2020	3Q 2019	% Change		YTD 2020	YTD 2019	% Change

Crude Oil and Condensate Volumes (MBbld) (A)
United States	376.6	463.2	-19	%	396.6	451.2	-12	%
Trinidad	1.0	0.8	25	%	0.5	0.7	-29	%
Other International (B)	—	0.1	-100	%	0.2	0.1	100	%
Total	377.6	464.1	-19	%	397.3	452.0	-12	%

Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States	40.19	56.67	-29	%	37.45	57.95	-35	%
Trinidad	25.41	48.36	-47	%	26.35	47.26	-44	%
Other International (B)	25.29	59.87	-58	%	45.09	58.43	-23	%
Composite	40.15	56.66	-29	%	37.44	57.93	-35	%

Natural Gas Liquids Volumes (MBbld) (A)
United States	140.1	141.3	-1	%	134.2	130.8	3	%
Other International (B)	—	—			—	—
Total	140.1	141.3	-1	%	134.2	130.8	3	%

Average Natural Gas Liquids Prices ($/Bbl) (C)
United States	14.34	12.67	13	%	11.95	15.96	-25	%
Other International (B)	—	—			—	—
Composite	14.34	12.67	13	%	11.95	15.96	-25	%

Natural Gas Volumes (MMcfd) (A)
United States	1,008	1,079	-7	%	1,029	1,043	-1	%
Trinidad	151	260	-42	%	175	267	-34	%
Other International (B)	31	34	-9	%	34	36	-6	%
Total	1,190	1,373	-13	%	1,238	1,346	-8	%

Average Natural Gas Prices ($/Mcf) (C)
United States	1.49	1.97	-25	%	1.38	2.23	-38	%
Trinidad	2.35	2.52	-7	%	2.20	2.71	-19	%
Other International (B)	4.73	4.25	11	%	4.45	4.29	4	%
Composite	1.68	2.13	-21	%	1.58	2.38	-34	%

Crude Oil Equivalent Volumes (MBoed) (D)
United States	684.7	784.3	-13	%	702.3	755.8	-7	%
Trinidad	26.2	44.1	-41	%	29.8	45.1	-34	%
Other International (B)	5.1	5.8	-12	%	5.7	6.2	-8	%
Total	716.0	834.2	-14	%	737.8	807.1	-9	%

Total MMBoe (D)	65.9	76.7	-14	%	202.2	220.3	-8	%

(A) Thousand barrels per day or million cubic feet per day, as applicable.
(B) Other International includes EOG's China and Canada operations.
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2020).
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.


Balance Sheets
In thousands of USD, except share data (Unaudited)
	September 30,	December 31,
	2020	2019
Current Assets
Cash and Cash Equivalents	3,065,556	2,027,972
Accounts Receivable, Net	1,134,346	2,001,658
Inventories	668,541	767,297
Assets from Price Risk Management Activities	18,417	1,299
Income Taxes Receivable	3,182	151,665
Other	205,015	323,448
Total	5,095,057	5,273,339

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	64,020,452	62,830,415
Other Property, Plant and Equipment	4,402,091	4,472,246
Total Property, Plant and Equipment	68,422,543	67,302,661
Less: Accumulated Depreciation, Depletion and Amortization	(39,789,537)	(36,938,066)
Total Property, Plant and Equipment, Net	28,633,006	30,364,595
Deferred Income Taxes	1,916	2,363
Other Assets	1,344,039	1,484,311
Total Assets	35,074,018	37,124,608

Current Liabilities
Accounts Payable	1,245,029	2,429,127
Accrued Taxes Payable	267,245	254,850
Dividends Payable	217,334	166,273
Liabilities from Price Risk Management Activities	23,486	20,194
Current Portion of Long-Term Debt	770,831	1,014,524
Current Portion of Operating Lease Liabilities	255,357	369,365
Other	240,760	232,655
Total	3,020,042	4,486,988

Long-Term Debt	4,949,902	4,160,919
Other Liabilities	2,151,092	1,789,884
Deferred Income Taxes	4,804,656	5,046,101
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,668,294 Shares Issued at September 30, 2020 and 582,213,016 Shares Issued at December 31, 2019	205,837	205,822
Additional Paid in Capital	5,916,213	5,817,475
Accumulated Other Comprehensive Loss	(7,930)	(4,652)
Retained Earnings	14,051,197	15,648,604
Common Stock Held in Treasury, 322,591 Shares at September 30, 2020 and 298,820 Shares at December 31, 2019	(16,991)	(26,533)
Total Stockholders' Equity	20,148,326	21,640,716
Total Liabilities and Stockholders' Equity	35,074,018	37,124,608


Cash Flows Statements
In thousands of USD (Unaudited)
	3Q 2020	3Q 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)	(42,467)	615,122	(942,038)	2,098,389
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	823,050	953,597	2,529,789	2,790,496
Impairments	78,990	105,275	1,957,340	289,761
Stock-Based Compensation Expenses	33,811	54,670	113,454	132,323
Deferred Income Taxes	(33,311)	184,282	(241,003)	508,576
(Gains) Losses on Asset Dispositions, Net	70,976	523	41,283	(3,650)
Other, Net	1,465	(1,284)	1,636	4,155
Dry Hole Costs	12,604	24,138	13,063	28,001
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	3,978	(85,902)	(1,075,433)	(242,622)
Net Cash Received from Settlements of Commodity Derivative Contracts	275,133	108,418	998,894	139,708
Other, Net	(465)	(424)	(1,185)	1,215
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(260,829)	63,891	930,628	(5,855)
Inventories	7,439	66,857	92,014	55,598
Accounts Payable	(37,755)	7,400	(1,222,473)	134,253
Accrued Taxes Payable	73,482	34,767	12,395	88,047
Other Assets	161,879	(92,814)	414,857	394,573
Other Liabilities	51,664	39,791	(12,739)	(18,315)
Changes in Components of Working Capital Associated with Investing and Financing Activities	(6,091)	(16,643)	276,063	(38,677)
Net Cash Provided by Operating Activities	1,213,553	2,061,664	3,886,545	6,355,976
Investing Cash Flows
Additions to Oil and Gas Properties	(468,487)	(1,420,385)	(2,458,520)	(4,866,882)
Additions to Other Property, Plant and Equipment	(17,652)	(70,469)	(165,018)	(187,350)
Proceeds from Sales of Assets	145,575	17,767	188,943	35,409
Changes in Components of Working Capital Associated with Investing Activities	6,091	16,621	(276,063)	38,677
Net Cash Used in Investing Activities	(334,473)	(1,456,466)	(2,710,658)	(4,980,146)
Financing Cash Flows
Long-Term Debt Borrowings	—	—	1,483,852	—
Long-Term Debt Repayments	—	—	(1,000,000)	(900,000)
Dividends Paid	(217,142)	(166,170)	(601,242)	(420,851)
Treasury Stock Purchased	(9,764)	(13,835)	(14,821)	(22,238)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	—	863	8,614	9,558
Debt Issuance Costs	—	(114)	(2,635)	(5,016)
Repayment of Finance Lease Liabilities	(4,864)	(3,235)	(13,309)	(9,638)
Changes in Components of Working Capital Associated with Financing Activities	—	22	—	—
Net Cash Used in Financing Activities	(231,770)	(182,469)	(139,541)	(1,348,185)
Effect of Exchange Rate Changes on Cash	1,745	(109)	1,238	(174)
Increase in Cash and Cash Equivalents	649,055	422,620	1,037,584	27,471
Cash and Cash Equivalents at Beginning of Period	2,416,501	1,160,485	2,027,972	1,555,634
Cash and Cash Equivalents at End of Period	3,065,556	1,583,105	3,065,556	1,583,105

Non-GAAP Financial Measures

To supplement the presentation of its financial results prepared in accordance with 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 investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, 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 in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG’s performance.

EOG believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company’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 conform to peer company or industry analysts’ practices.


Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited)
	3Q 2020
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Loss (GAAP)	(52,555)	10,088	(42,467)	(0.07)
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	3,978	(873)	3,105	(0.01)
Net Cash Received from Settlements of Commodity Derivative Contracts	275,133	(60,386)	214,747	0.37
Add: Losses on Asset Dispositions, Net	70,976	(15,600)	55,376	0.10
Add: Certain Impairments	26,531	(5,636)	20,895	0.04
Adjustments to Net Income (Loss)	376,618	(82,495)	294,123	0.50

Adjusted Net Income (Non-GAAP)	324,063	(72,407)	251,656	0.43

Average Number of Common Shares (GAAP)
Basic				579,055
Diluted				579,055

Average Number of Common Shares (Non-GAAP)
Basic				579,055
Diluted				580,609


	3Q 2019
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	797,457	(182,335)	615,122	1.06
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(85,902)	18,854	(67,048)	(0.12)
Net Cash Received from Settlements of Commodity Derivative Contracts	108,418	(23,796)	84,622	0.15
Add: Losses on Asset Dispositions, Net	523	(89)	434	—
Add: Certain Impairments	27,215	(5,973)	21,242	0.04
Adjustments to Net Income (Loss)	50,254	(11,004)	39,250	0.07

Adjusted Net Income (Non-GAAP)	847,711	(193,339)	654,372	1.13

Average Number of Common Shares (GAAP)
Basic				577,839
Diluted				581,271

Average Number of Common Shares (Non-GAAP)				577,839
Basic				581,271
Diluted


Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited)
	YTD 2020
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Loss (GAAP)	(1,166,814)	224,776	(942,038)	(1.63)
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(1,075,433)	236,036	(839,397)	(1.45)
Net Cash Received from Settlements of Commodity Derivative Contracts	998,894	(219,237)	779,657	1.35
Add: Losses on Asset Dispositions, Net	41,283	(9,057)	32,226	0.06
Add: Certain Impairments	1,782,014	(373,960)	1,408,054	2.43
Adjustments to Net Income (Loss)	1,746,758	(366,218)	1,380,540	2.39

Adjusted Net Income (Non-GAAP)	579,944	(141,442)	438,502	0.76

Average Number of Common Shares (GAAP)
Basic				578,740
Diluted				578,740

Average Number of Common Shares (Non-GAAP)
Basic				578,740
Diluted				580,301


	YTD 2019
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	2,714,059	(615,670)	2,098,389	3.61
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(242,622)	53,251	(189,371)	(0.34)
Net Cash Received from Settlements of Commodity Derivative Contracts	139,708	(30,663)	109,045	0.19
Add: Gains on Asset Dispositions, Net	(3,650)	910	(2,740)	—
Add: Certain Impairments	116,249	(25,514)	90,735	0.16
Adjustments to Net Income (Loss)	9,685	(2,016)	7,669	0.01

Adjusted Net Income (Non-GAAP)	2,723,744	(617,686)	2,106,058	3.62

Average Number of Common Shares (GAAP)
Basic				577,498
Diluted				581,190

Average Number of Common Shares (Non-GAAP)
Basic				577,498
Diluted				581,190


Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited)
	3Q 2020		3Q 2019	YTD 2020		YTD 2019

Net Cash Provided by Operating Activities (GAAP)	1,213,553		2,061,664	3,886,545		6,355,976

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	37,380		29,374	90,346		85,250
Other Non-Current Income Taxes - Net Receivable	—		33,855	112,704		179,537
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	260,829		(63,891)	(930,628)		5,855
Inventories	(7,439)		(66,857)	(92,014)		(55,598)
Accounts Payable	37,755		(7,400)	1,222,473		(134,253)
Accrued Taxes Payable	(73,482)		(34,767)	(12,395)		(88,047)
Other Assets	(161,879)		92,814	(414,857)		(394,573)
Other Liabilities	(51,664)		(39,791)	12,739		18,315
Changes in Components of Working Capital Associated with Investing and Financing Activities	6,091		16,643	(276,063)		38,677
Discretionary Cash Flow (Non-GAAP)	1,261,144		2,021,644	3,598,850		6,011,139

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease	-38	%		-40	%

Discretionary Cash Flow (Non-GAAP)	1,261,144		2,021,644	3,598,850		6,011,139
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)	(499,305)		(1,518,019)	(2,661,641)		(4,846,221)
Free Cash Flow (Non-GAAP) (b)	761,839		503,625	937,209		1,164,918

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month and nine-month periods ended September 30, 2020 and 2019:

Total Expenditures (GAAP)	645,534		1,629,343	3,005,723		5,394,389
Less:
Asset Retirement Costs	(42,650)		(90,970)	(68,213)		(151,551)
Non-Cash Expenditures of Other Property, Plant and Equipment	—		—	(60)		(586)
Non-Cash Acquisition Costs of Unproved Properties	(80,757)		(10,666)	(128,488)		(64,387)
Non-Cash Finance Leases	—		—	(73,277)		—
Acquisition Costs of Proved Properties	(22,822)		(9,688)	(74,044)		(331,644)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	499,305		1,518,019	2,661,641		4,846,221

(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the three-month and nine-month periods ending September 30, 2020. The comparative prior periods shown have been revised to conform to this presentation.

Maintenance Capital Expenditures
The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to anticipated 4Q 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 Financing Activities	115,061		(301,083)		(89,992)
Discretionary Cash Flow (Non-GAAP)	8,122,150		8,271,692		4,839,532

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

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 Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 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 purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019. The comparative prior periods shown have been revised to conform to this presentation.


Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited)

	FY 2016		FY 2015		FY 2014		FY 2013		FY 2012

Net Cash Provided by Operating Activities (GAAP)	2,359,063		3,595,165		8,649,155		7,329,414		5,236,777

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	104,199		124,011		157,453		134,531		159,182
Excess Tax Benefits from Stock-Based Compensation	29,357		26,058		99,459		55,831		67,035
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	232,799		(641,412)		(84,982)		23,613		178,683
Inventories	(170,694)		(58,450)		161,958		(53,402)		156,762
Accounts Payable	74,048		1,409,197		(543,630)		(178,701)		17,150
Accrued Taxes Payable	(92,782)		(11,798)		(16,486)		(75,142)		(78,094)
Other Assets	40,636		(118,143)		14,448		109,567		118,520
Other Liabilities	16,225		66,257		(75,420)		20,382		(36,114)
Changes in Components of Working Capital Associated with Investing and Financing Activities	156,102		(499,767)		103,414		51,361		(74,158)
Discretionary Cash Flow (Non-GAAP)	2,748,953		3,891,118		8,465,369		7,417,454		5,745,743

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

Discretionary Cash Flow (Non-GAAP)	2,748,953		3,891,118		8,465,369		7,417,454		5,745,743
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)	(2,706,397)		(4,682,326)		(8,292,090)		(7,101,791)		(7,539,994)
Free Cash Flow (Non-GAAP) (b)	42,556		(791,208)		173,279		315,663		(1,794,251)

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2016, 2015, 2014, 2013 and 2012:

Total Expenditures (GAAP)	6,554,053		5,216,413		8,631,906		7,361,457		7,753,828
Less:
Asset Retirement Costs	19,865		(53,470)		(195,630)		(134,445)		(126,987)
Non-Cash Expenditures of Other Property, Plant and Equipment	(16,585)		—		—		—		(65,791)
Non-Cash Acquisition Costs of Unproved Properties	(3,101,913)		—		(5,085)		(5,007)		(20,317)
Acquisition Costs of Proved Properties	(749,023)		(480,617)		(139,101)		(120,214)		(739)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	2,706,397		4,682,326		8,292,090		7,101,791		7,539,994

(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item.


Total Expenditures
In millions of USD (Unaudited)

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

Exploration and Development Drilling	378	1,173	4,951	4,935	3,132
Facilities	38	161	629	625	575
Leasehold Acquisitions	88	56	276	488	427
Property Acquisitions	23	10	380	124	73
Capitalized Interest	7	10	38	24	27
Subtotal	534	1,410	6,274	6,196	4,234
Exploration Costs	38	34	140	149	145
Dry Hole Costs	13	24	28	5	5
Exploration and Development Expenditures	585	1,468	6,442	6,350	4,384
Asset Retirement Costs	44	91	186	70	56
Total Exploration and Development Expenditures	629	1,559	6,628	6,420	4,440
Other Property, Plant and Equipment	17	70	272	286	173
Total Expenditures	646	1,629	6,900	6,706	4,613


EBITDAX and Adjusted EBITDAX
In thousands of USD (Unaudited)
	3Q 2020		3Q 2019	YTD 2020		YTD 2019

Net Income (Loss) (GAAP)	(42,467)		615,122	(942,038)		2,098,389

Adjustments:
Interest Expense, Net	53,242		39,620	152,145		144,434
Income Tax Provision (Benefit)	(10,088)		182,335	(224,776)		615,670
Depreciation, Depletion and Amortization	823,050		953,597	2,529,789		2,790,496
Exploration Costs	38,413		34,540	105,373		103,386
Dry Hole Costs	12,604		24,138	13,063		28,001
Impairments	78,990		105,275	1,957,340		289,761
EBITDAX (Non-GAAP)	953,744		1,954,627	3,590,896		6,070,137
(Gains) Losses on MTM Commodity Derivative Contracts	3,978		(85,902)	(1,075,433)		(242,622)
Net Cash Received from Settlements of Commodity Derivative Contracts	275,133		108,418	998,894		139,708
(Gains) Losses on Asset Dispositions, Net	70,976		523	41,283		(3,650)

Adjusted EBITDAX (Non-GAAP)	1,303,831		1,977,666	3,555,640		5,963,573

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease	-34	%		-40	%

Definitions
EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); 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)
	September 30, 2020		June 30, 2020		March 31, 2020

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

Current and Long-Term Debt (GAAP) - (b)	5,721		5,724		5,222
Less: Cash	(3,066)		(2,417)		(2,907)
Net Debt (Non-GAAP) - (c)	2,655		3,307		2,315

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

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

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

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	12	%	14	%	10	%


Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited)
	December 31, 2019		September 30, 2019		June 30, 2019		March 31, 2019

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

Current and Long-Term Debt (GAAP) - (b)	5,175		5,177		5,179		6,081
Less: Cash	(2,028)		(1,583)		(1,160)		(1,136)
Net Debt (Non-GAAP) - (c)	3,147		3,594		4,019		4,945

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

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

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

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


Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited)
	December 31, 2018		September 30, 2018		June 30, 2018		March 31, 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, 2017		September 30, 2017		June 30, 2017		March 31, 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, 2016		September 30, 2016		June 30, 2016		March 31, 2016		December 31, 2015

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

Current and Long-Term Debt (GAAP) - (b)	6,986		6,986		6,986		6,986		6,660
Less: Cash	(1,600)		(1,049)		(780)		(668)		(719)
Net Debt (Non-GAAP) - (c)	5,386		5,937		6,206		6,318		5,941

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

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

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	33	%	37	%	37	%	36	%	34	%

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


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 Activities (GAAP)	6,628.2	6,419.7	4,439.4	6,445.2	4,928.3	7,904.8
Less: Asset Retirement Costs	(186.1)	(69.7)	(55.6)	19.9	(53.5)	(195.6)
Non-Cash Acquisition Costs of Unproved Properties	(97.7)	(290.5)	(255.7)	(3,101.8)	—	—
Acquisition Costs of Proved Properties	(379.9)	(123.7)	(72.6)	(749.0)	(480.6)	(139.1)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a)	5,964.5	5,935.8	4,055.5	2,614.3	4,394.2	7,570.1

Total Costs Incurred in Exploration and Development Activities (GAAP)	6,628.2	6,419.7	4,439.4	6,445.2	4,928.3	7,904.8
Less: Asset Retirement Costs	(186.1)	(69.7)	(55.6)	19.9	(53.5)	(195.6)
Non-Cash Acquisition Costs of Unproved Properties	(97.7)	(290.5)	(255.7)	(3,101.8)	—	—
Non-Cash Acquisition Costs of Proved Properties	(52.3)	(70.9)	(26.2)	(732.3)	—	—
Total Exploration and Development Expenditures (Non-GAAP) - (b)	6,292.1	5,988.6	4,101.9	2,631.0	4,874.8	7,709.2

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 - (b / ( e - c))	8.21	9.33	8.71	5.22	11.91	13.25


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 the mark-to-market accounting method.

ICE Brent Differential Basis Swap Contracts

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

2020

Volume (Bbld)

Weighted Average Price Differential
($/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 the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

2020

Volume (Bbld)

Weighted Average Price Differential
($/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 in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through October 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

2020	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)


February 1, 2020 through June 30, 2020 (CLOSED)	10,000	0.70
July 1, 2020 through September 30, 2020 (CLOSED)	88,000	(1.16)
October 1, 2020 through November 30, 2020 (CLOSED)	66,000	(1.16)
December 2020	66,000	(1.16)

In May 2020, EOG entered into crude oil Roll Differential swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $2.6 million through October 30, 2020, for the settlement of certain of these contracts and expects to pay $0.6 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.


Crude Oil NYMEX WTI Price Swap Contracts
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

2020	Volume (Bbld)	Weighted Average Price ($/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 swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $359.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $4.1 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.


Crude Oil ICE Brent Price Swap Contracts
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

2020	Volume (Bbld)	Weighted Average Price ($/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 Swap Contracts) through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

2020	Volume (Bbld)	Weighted Average Price ($/Bbl)


January 1, 2020 through February 29, 2020 (CLOSED)	4,000	21.34
March 1, 2020 through April 30, 2020 (CLOSED)	25,000	17.92

In April and May 2020, EOG entered into Mont Belvieu Propane Price Swap Contracts for the period from May 1, 2020 through December 31, 2020, with notional 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 Contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $5.7 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $3.5 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Natural Gas Price Swap Contracts

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

2021

Volume (MMBtud)

Weighted Average Price
($/MMBtu)

January 1, 2021 through December 31, 2021

500,000

2.99

Natural Gas Collar Contracts

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

2020

Volume (MMBtud)

Weighted Average
Ceiling Price
($/MMBtu)

Weighted
Average
Floor Price
($/MMBtu)

April 1, 2020 through July 31, 2020 (CLOSED)

250,000

2.50

2.00

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million through October 30, 2020, for the settlement of these contracts. The offsetting contracts were excluded from the above table.


Rockies Differential Basis Swap Contracts
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

2020	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)


January 1, 2020 through October 31, 2020 (CLOSED)	30,000	0.55
November 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 the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

2020

Volume (MMBtud)

Weighted Average Price Differential
($/MMBtu)

January 1, 2020 through December 31, 2020 (CLOSED)

60,000

0.05

Waha Differential Basis Swap Contracts

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

2020

Volume (MMBtud)

Weighted Average Price Differential
($/MMBtu)

January 1, 2020 through April 30, 2020 (CLOSED)

50,000

1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $8.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to pay net cash of $3.0 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were 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 to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG’s interest) for all wells in such 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 utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated 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 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 NPV Captured

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 Tax		Income Tax Impact		After 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	3Q 2020	YTD 2020

Cost per Barrel of Oil Equivalent (Boe) Calculation
Volume - Thousand Barrels of Oil Equivalent - (a)	79,548	56,733	65,873	202,153

Crude Oil and Condensate	2,065,498	614,627	1,394,622	4,074,747
Natural Gas Liquids	160,535	93,909	184,771	439,215
Natural Gas	209,764	141,696	183,790	535,250
Total Wellhead Revenues - (b)	2,435,797	850,232	1,763,183	5,049,212

Operating Costs
Lease and Well	329,659	245,346	227,473	802,478
Transportation Costs	208,296	151,728	180,257	540,281
Gathering and Processing Costs	128,482	96,767	114,790	340,039
General and Administrative	114,273	131,855	124,460	370,588
Taxes Other Than Income	157,360	80,319	126,810	364,489
Interest Expense, Net	44,690	54,213	53,242	152,145
Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c)	982,760	760,228	827,032	2,570,020

Depreciation, Depletion and Amortization (DD&A)	1,000,060	706,679	823,050	2,529,789
Total Operating Cost (excluding Total Exploration Costs) - (d)	1,982,820	1,466,907	1,650,082	5,099,809

Exploration Costs	39,677	27,283	38,413	105,373
Dry Hole Costs	372	87	12,604	13,063
Impairments	1,572,935	305,415	78,990	1,957,340
Total Exploration Costs	1,612,984	332,785	130,007	2,075,776
Less: Certain Impairments (Non-GAAP)	(1,516,316)	(239,167)	(26,531)	(1,782,014)
Total Exploration Costs (Non-GAAP)	96,668	93,618	103,476	293,762

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)	2,079,488	1,560,525	1,753,558	5,393,571

Composite Average Wellhead Revenue per Boe - (b) / (a)	30.62	14.99	26.77	24.98

Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / (a)	12.36	13.40	12.56	12.70

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)]	18.26	1.59	14.21	12.28

Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a)	24.93	25.86	25.05	25.21

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)]	5.69	(10.87)	1.72	(0.23)

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a)	26.15	27.51	26.62	26.66

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)]	4.47	(12.52)	0.15	(1.68)


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 Costs) - (c)	4,079,085	3,911,029	3,169,689

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 Exploration Costs) - (c) / (a)	13.66	14.90	14.25

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

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

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

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

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


Cost 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 Costs) - (c)	2,793,511	3,184,133	3,895,421

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 Exploration Costs) - (c) / (a)	13.64	15.25	17.95

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

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

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

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

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


Quarter and Full Year Guidance
(Unaudited)

(a) Fourth Quarter and Full Year 2020 Forecast
The forecast items for the fourth quarter and full year 2020 set forth below 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, to 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.

(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 excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.

(c) Benchmark Commodity Pricing
EOG bases United States and Trinidad crude oil and condensate price 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 gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.


Estimated Ranges for Fourth Quarter and Full Year 2020	4Q 2020			FY 2020
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States	435.0	-	445.0	406.3	-	408.8
Trinidad	1.6	-	2.0	0.8	-	0.9
Other International	0.0	-	0.2	0.1	-	0.1
Total	436.6	-	447.2	407.2	-	409.8
Natural Gas Liquids Volumes (MBbld)
Total	140.0	-	150.0	137.2	-	139.7
Natural Gas Volumes (MMcfd)
United States	1,040	-	1,100	1,032	-	1,047
Trinidad	170	-	190	174	-	179
Other International	20	-	30	30	-	33
Total	1,230	-	1,320	1,236	-	1,259
Crude Oil Equivalent Volumes (MBoed)
United States	748.3	-	778.3	715.4	-	722.9
Trinidad	29.9	-	33.7	29.8	-	30.8
Other International	3.3	-	5.2	5.1	-	5.6
Total	781.5	-	817.2	750.3	-	759.3

Capital Expenditures ($MM)	830	-	930	3,400		3,600


Quarter and Full Year Guidance
(Unaudited)

Estimated Ranges for Fourth Quarter and Full Year 2020	4Q 2020					FY 2020
Operating Costs
Unit Costs ($/Boe)
Lease and Well	3.80		-	4.30		3.92		-	4.05
Transportation Costs	2.55		-	2.95		2.64		-	2.74
Gathering and Processing	1.75		-	1.85		1.70		-	1.72
Depreciation, Depletion and Amortization	12.20		-	12.70		12.41		-	12.54
General and Administrative	1.80		-	1.90		1.82		-	1.85

Expenses ($MM)
Exploration and Dry Hole	45		-	55		163		-	173
Impairment	100		-	150		265		-	315
Capitalized Interest	5		-	10		29		-	34
Net Interest	51		-	56		203		-	208

Taxes Other Than Income (% of Wellhead Revenue)	6.0	%	-	8.0	%	6.7	%	-	7.8	%

Income Taxes
Effective Rate	20	%	-	25	%	16	%	-	21	%
Current Tax (Benefit) / Expense ($MM)	10		-	50		(85)		-	(45)

Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI	(1.85)		-	0.15		(1.07)		-	(0.52)
Trinidad - above (below) WTI	(14.40)		-	(12.40)		(12.52)		-	(11.40)
Other International - above (below) WTI	(8.00)		-	(2.00)		2.18		-	3.68
Natural Gas Liquids
Realizations as % of WTI	34	%	-	46	%	32	%	-	35	%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub	(0.60)		-	(0.20)		(0.54)		-	(0.43)
Realizations
Trinidad	3.15		-	3.65		2.44		-	2.59
Other International	4.35		-	4.85		4.44		-	4.54

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

EOG Resources (EOG) 8-KEOG Resources Reports Third Quarter 2020 Results; Adds Premium Natural Gas Play in South Texas; Provides Three-Year Outlook