EOG Resources Reports Excellent Fourth Quarter and Full Year 2019 Results

February 28, 2020

EOG Resources Reports Excellent Fourth Quarter and Full Year 2019 Results; Announces 2020 Capital Program; Raises Dividend by 30 Percent

Increased Common Stock Dividend by 30 Percent to $1.50 Indicated Annual Rate
Earned $2.7 Billion Net Income in 2019, or $4.71 per Share
Generated $8.2 Billion Net Cash from Operating Activities and Significant Free Cash Flow
Exceeded Fourth Quarter and Full Year 2019 Crude Oil Production Target with Capital Expenditures Below Target
Lease and Well and DD&A Expense Rates Below Target in Fourth Quarter and Full Year 2019
Increased Proved Reserves by 14% and Replaced 253% of 2019 Production at $8.21 per Boe Finding Cost
$6.3 to $6.7 Billion Capital Program Targets 10 14% Crude Oil Volume Growth in 2020
2020 Capital Program and Dividend Funded with Net Cash from Operating Activities at Oil Prices Below $50

HOUSTON EOG Resources, Inc. (EOG) today reported fourth quarter 2019 net income of $637 million, or $1.10 per share, compared with fourth quarter 2018 net income of $893 million, or

$1.54 per share. Net cash from operating activities for the fourth quarter 2019 was $1.8 billion. For the full year 2019, EOG reported net income of $2.7 billion, or $4.71 per share, compared with net income of $3.4 billion, or $5.89 per share, for the full year 2018. Net cash from operating activities for the full year 2019 was $8.2 billion.

Adjusted non GAAP net income for the fourth quarter 2019 was $787 million, or $1.35 per share, compared with adjusted non GAAP net income of $718 million, or $1.24 per share, for the same prior year period. Adjusted non GAAP net income for the full year 2019 was $2.9 billion, or $4.98 per share, compared with adjusted non GAAP net income of $3.2 billion, or

$5.54 per share, for the full year 2018.

Increased crude oil production from high return operating areas and reductions in per unit operating costs contributed to EOG’s strong fourth quarter 2019 financial results. Adjusted earnings per share, discretionary cash flow and adjusted EBITDAX increased in the fourth quarter 2019 compared with the same prior year period, demonstrating EOG’s resiliency and ability to overcome declines in commodity prices. Please refer to the attached tables for definitions and the reconciliation of non GAAP measures to GAAP measures.

Fourth Quarter and Full Year 2019 Operating Review

Capital efficiency improvements from increased well productivity and cost reductions across EOG’s premium plays supported strong operating and financial performance in 2019. United States crude oil volumes grew 15 percent to 455,500 barrels of oil per day (Bopd). Total company natural gas liquids production increased 16 percent, while total company natural gas volumes grew 12 percent.

Total crude oil volumes in the fourth quarter 2019 were 468,900 Bopd, which was above the midpoint of the target range and represents an eight percent increase compared with the same prior year period. Natural gas liquids and natural gas volumes increased by 17 percent and 15 percent, respectively, during this same period. EOG incurred total expenditures of $1.5 billion in the fourth quarter. Total cash capital expenditures before acquisitions of $1.4 billion were below the low end of the target range. Please refer to the attached tables for definitions and the reconciliation of non GAAP measures to GAAP measures.

EOG continued to lower operating costs during the fourth quarter 2019. Lease and well costs declined 13 percent, transportation costs fell five percent and depreciation, depletion and amortization (DD&A) expenses fell six percent, all on a per unit basis compared with the same prior year period. The company also continued to implement sustainable efficiency improvements to reduce well costs. The fourth quarter improvements brought full year 2019 well cost reductions to seven percent, two percentage points ahead of the target.

EOG generated $2.1 billion of discretionary cash flow in the fourth quarter 2019. After considering total cash capital expenditures before acquisitions of $1.4 billion, EOG generated free cash flow during the fourth quarter 2019 of $723 million. For the full year 2019, EOG generated $8.1 billion of discretionary cash flow and incurred total cash capital expenditures before acquisitions of $6.2 billion, resulting in free cash flow of $1.9 billion. Please refer to the attached tables for definitions and the reconciliation of non GAAP measures to GAAP measures. As is further explained in the attached reconciliation tables, EOG now defines its free cash flow for a period as its discretionary cash flow for such period less its total cash capital expenditures (before acquisitions) for such period (without regards to the dividends paid in such period).

EOG believes this definition of free cash flow is more consistent with that utilized by other companies in the industry.

“Year after year, EOG keeps getting better, delivering record operating performance in 2019. Significant capital efficiency improvements from strong well productivity and sustainable cost reductions allowed us to deliver higher production with less capital investment than we planned at the beginning of the year,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “We did this while generating substantial free cash flow, strengthening our financial position and increasing the dividend. This was the third consecutive year since our transition to premium drilling that EOG delivered double digit returns and production growth along with strong free cash flow.”

2020 Capital Plan

The purpose of EOG’s annual capital program is to generate high returns on investment and increase the company’s business value. Exploration and development expenditures for 2020 are expected to range from $6.3 billion to $6.7 billion, including facilities and gathering, processing and other expenditures, and excluding acquisitions and non cash exchanges. The disciplined capital program supports growth in crude oil production of 10 to 14 percent in 2020 and funds dividend payments with net cash from operating activities at less than $50 oil.

Due to the decline in crude oil prices, the 2020 capital plan allocates slightly less capital to growing oil production than in 2019. To continue to improve the company, the 2020 plan allocates more capital than in 2019 to fund new high quality drilling potential and high return infrastructure to further lower EOG’s cost structure and environmental footprint. With the benefit of sustainable cost reductions and operational efficiencies, EOG expects to complete approximately 800 net wells in 2020 compared with 750 net wells in 2019. Activity will remain focused in EOG’s highest rate of return oil assets in the Delaware Basin, Eagle Ford and Rocky Mountain Area.

“EOG’s 2020 capital plan reflects continued improvement in capital efficiency, highlights the resiliency of our business model, and ensures the capital program and dividend payments can be funded at a conservative oil price. Looking to the future, our 2020 plan also invests in new high return drilling potential and infrastructure development to lower costs and further improve the company,” Thomas said. “EOG’s sustainable competitive advantages already position us as one of the lowest cost oil producers in the global market and we are poised to extend our cost advantage well into the future.”

Dividend Increase

The board of directors declared a dividend of $0.375 per share on EOG’s Common Stock, an increase of 30 percent. The dividend will be payable April 30, 2020, to stockholders of record as of April 16, 2020. The indicated annual rate is $1.50 per share.

“EOG’s high return premium drilling program and our low cost structure allow us to continue upholding the commitment we have made to return more cash to shareholders. This latest dividend increase demonstrates the confidence we have in our ability to grow cash flow, generate high returns through our premium well strategy and improve our future inventory with high quality new drilling potential,” Thomas said.

Reserves

At year end 2019, total company net proved reserves were 3,329 million barrels of oil equivalent (MMBoe), a 14 percent increase compared with year end 2018. Net proved reserve additions from all sources, excluding revisions due to price, replaced 253 percent of EOG’s 2019 production at a finding and development cost of $8.21 per barrel of oil equivalent. Revisions due to price decreased net proved reserves by 60 MMBoe and asset divestitures decreased net proved reserves by five MMBoe. For more reserves detail and a reconciliation of non GAAP measures to GAAP measures please refer to the attached tables.

For the 32nd consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.

Financial Review

EOG further strengthened its financial position during the fourth quarter 2019. At December 31, 2019, EOG’s total debt outstanding was $5.2 billion for a debt to total capitalization ratio of 19 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $3.1 billion for a net debt to total capitalization ratio of 13 percent. For definitions and the reconciliation of non GAAP measures to GAAP measures, please refer to the attached tables.

Fourth Quarter 2019 Results Webcast

Friday, February 28, 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

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 fourth 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 fourth 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;
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

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.

Financial Report

(Unaudited; in millions, except per share data)

Three Months Ended Twelve Months Ended

December 31, December 31,

	2019		2018		2019		2018
Operating Revenues and Other	$ 4,320.2		$ 4,574.5		$ 17,380.0		$ 17,275.4
Net Income	$ 636.5		$ 892.8		$ 2,734.9		$ 3,419.0
Net Income Per Share Basic	$ 1.10		$ 1.55		$ 4.73		$ 5.93
Diluted	$ 1.10		$ 1.54		$ 4.71		$ 5.89
Average Number of Common Shares Basic		578.2		577.0		577.7		576.6
Diluted		580.8		580.3		580.8		580.4

Summary Income Statements (Unaudited; in thousands, except per share data)

	Three Months Ended	Twelve Months Ended
	December 31,	December 31,
	2019 2018	2019 2018
Operating Revenues and Other
Crude Oil and Condensate	$ 2,464,274 $ 2,383,326	$ 9,612,532 $ 9,517,440
Natural Gas Liquids	215,070 266,037	784,818 1,127,510
Natural Gas	309,606 389,213	1,184,095 1,301,537
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	(62,347) 132,095	180,275 (165,640)
Gathering, Processing and Marketing	1,238,792 1,331,105	5,360,282 5,230,355
Gains on Asset Dispositions, Net	119,963 79,904	123,613 174,562
Other, Net	34,888 (7,144)	134,358 89,635
Total	4,320,246 4,574,536	17,379,973 17,275,399
Operating Expenses
Lease and Well	334,538 346,442	1,366,993 1,282,678
Transportation Costs	208,312 196,095	758,300 746,876
Gathering and Processing Costs	127,615 112,396	479,102 436,973
Exploration Costs	36,495 33,862	139,881 148,999
Dry Hole Costs	– 145	28,001 5,405
Impairments	228,135 186,087	517,896 347,021
Marketing Costs	1,237,259 1,349,416	5,351,524 5,203,243
Depreciation, Depletion and Amortization	959,208 919,963	3,749,704 3,435,408
General and Administrative	125,187 116,904	489,397 426,969
Taxes Other Than Income	199,746 190,086	800,164 772,481
Total	3,456,495 3,451,396	13,680,962 12,806,053
Operating Income	863,751 1,123,140	3,699,011 4,469,346
Other Income, Net	8,152 21,220	31,385 16,704
Income Before Interest Expense and Income Taxes	871,903 1,144,360	3,730,396 4,486,050
Interest Expense, Net	40,695 56,020	185,129 245,052
Income Before Income Taxes	831,208 1,088,340	3,545,267 4,240,998
Income Tax Provision	194,687 195,572	810,357 821,958
Net Income	$ 636,521 $ 892,768	$ 2,734,910 $ 3,419,040
Dividends Declared per Common Share	$ 0.2875 $ 0.2200	$ 1.0825 $ 0.8100

EOG RESOURCES, INC.

Operating Highlights (Unaudited)

	Three Months Ended			Twelve Months Ended
	December 31,			December 31,
	2019 2018		% Change	2019 2018		% Change
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States	468.3 430.3		9%	455.5 394.8		15%
Trinidad	0.5 0.8		-38%	0.6 0.8		-25%
Other International ^(B)	0.1 4.5		-98%	0.1 4.3		-98%
Total	468.9 435.6		8%	456.2 399.9		14%
Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$ 57.14	$ 59.37	-4%	$ 57.74	$ 65.16	-11%
Trinidad	46.73	51.80	-10%	47.16	57.26	-18%
Other International ^(B)	53.76	70.44	-24%	57.40	71.45	-20%
Composite	57.13	59.47	-4%	57.72	65.21	-11%
Natural Gas Liquids Volumes (MBbld) ^(A)
United States	144.0	122.8	17%	134.1	116.1	16%
Other International ^(B)	–	–		–	–
Total	144.0	122.8	17%	134.1	116.1	16%
Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$ 16.23	$ 23.54	-31%	$ 16.03	$ 26.60	-40%
Other International ^(B)	–	–		–	–
Composite	16.23	23.54	-31%	16.03	26.60	-40%
Natural Gas Volumes (MMcfd) ^(A)
United States	1,148	974	18%	1,069	923	16%
Trinidad	242	230	5%	260	266	-2%
Other International ^(B)	35	32	9%	37	30	23%
Total	1,425	1,236	15%	1,366	1,219	12%
Average Natural Gas Prices ($/Mcf) ^(C)
United States	$ 2.20	$ 3.50	-37%	$ 2.22	$ 2.88	-23%
Trinidad	2.78	3.03	-8%	2.72	2.94	-7%
Other International ^(B)	4.88	4.02	22%	4.44	4.08	9%
Composite	2.36	3.42	-31%	2.38	2.92	-19%
Crude Oil Equivalent Volumes (MBoed) ^(D)
United States	803.6	715.5	12%	767.8	664.7	16%
Trinidad	40.9	39.0	5%	44.0	45.1	-2%
Other International ^(B)	5.8	10.0	-42%	6.2	9.4	-34%
Total	850.3	764.5	11%	818.0	719.2	14%

Total MMBoe ^(D) 78.2 70.3 11% 298.6 262.5 14%

Thousand barrels per day or million cubic feet per day, as
Other International includes EOG’s United Kingdom, China and Canada The United Kingdom operations were sold in the fourth quarter of 2018.
Dollars per barrel or per thousand cubic feet, as Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG’s Annual Report on Form 10-K for the year ended December 31, 2019).
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural 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.

Summary Balance Sheets (Unaudited; in thousands, except share data)

		December 31,	December 31,
		2019	2018
	ASSETS
Current Assets
Cash and Cash Equivalents		$ 2,027,972	$ 1,555,634
Accounts Receivable, Net		2,001,658	1,915,215
Inventories		767,297	859,359
Assets from Price Risk Management Activities		1,299	23,806
Income Taxes Receivable		151,665	427,909
Other		323,448	275,467
Total		5,273,339	5,057,390
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		62,830,415	57,330,016
Other Property, Plant and Equipment		4,472,246	4,220,665
Total Property, Plant and Equipment		67,302,661	61,550,681
Less: Accumulated Depreciation, Depletion and Amortization		(36,938,066)	(33,475,162)
Total Property, Plant and Equipment, Net		30,364,595	28,075,519
Deferred Income Taxes		2,363	777
Other Assets		1,484,311	800,788
Total Assets		$ 37,124,608	$ 33,934,474

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Accounts Payable	$ 2,429,127	$ 2,239,850
Accrued Taxes Payable	254,850	214,726
Dividends Payable	166,273	126,971
Liabilities from Price Risk Management Activities	20,194	–
Current Portion of Long-Term Debt	1,014,524	913,093
Current Portion of Operating Lease Liabilities	369,365	–
Other	232,655	233,724
Total	4,486,988	3,728,364

Long-Term Debt	4,160,919	5,170,169
Other Liabilities	1,789,884	1,258,355
Deferred Income Taxes Commitments and Contingencies	5,046,101	4,413,398
Stockholders’ Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and
582,213,016 Shares and 580,408,117 Shares Issued at December 31, 2019 and 2018, respectively	205,822	205,804
Additional Paid in Capital	5,817,475	5,658,794
Accumulated Other Comprehensive Loss	(4,652)	(1,358)
Retained Earnings	15,648,604	13,543,130
Common Stock Held in Treasury, 298,820 Shares and 385,042 Shares at December 31, 2019 and 2018, respectively	(26,533)	(42,182)
Total Stockholders’ Equity	21,640,716	19,364,188
Total Liabilities and Stockholders’ Equity	$ 37,124,608	$ 33,934,474

EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands)
Cash Flows from Operating Activities	Three Months Ended December 31, 2019 2018		Twelve Months Ended December 31, 2019 2018
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$ 636,521 $ 892,768		$ 2,734,910 $ 3,419,040
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	959,208 919,963		3,749,704 3,435,408
Impairments	228,135 186,087		517,896 347,021
Stock-Based Compensation Expenses	42,415 39,047		174,738 155,337
Deferred Income Taxes	123,082 212,454		631,658 894,156
Gains on Asset Dispositions, Net	(119,963) (79,904)		(123,613) (174,562)
Other, Net	341 (8,248)		4,496 7,066
Dry Hole Costs	– 145		28,001 5,405
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	62,347 (132,095)		(180,275) 165,640
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	91,521 (78,678)		231,229 (258,906)
Other, Net	(253) 1,456		962 3,108
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(85,937) 185,349		(91,792) (368,180)
Inventories	34,686 (108,591)		90,284 (395,408)
Accounts Payable	34,286 (98,178)		168,539 439,347
Accrued Taxes Payable	(47,925) (55,570)		40,122 (92,461)
Other Assets	(36,572) (22,101)		358,001 (125,435)
Other Liabilities	(38,304) 25,725		(56,619) 10,949
Changes in Components of Working Capital Associated with Investing and Financing
Activities	(76,384)	205,599	(115,061)	301,083
Net Cash Provided by Operating Activities	1,807,204	2,085,228	8,163,180	7,768,608
Investing Cash Flows
Additions to Oil and Gas Properties	(1,285,003)	(1,267,362)	(6,151,885)	(5,839,294)
Additions to Other Property, Plant and Equipment	(83,291)	(34,797)	(270,641)	(237,181)
Proceeds from Sales of Assets	104,883	215,864	140,292	227,446
Other Investing Activities	(10,000)	–	(10,000)	(19,993)
Changes in Components of Working Capital Associated with Investing Activities	76,384	(205,599)	115,061	(301,140)
Net Cash Used in Investing Activities	(1,197,027)	(1,291,894)	(6,177,173)	(6,170,162)
Financing Cash Flows
Long-Term Debt Repayments	–	(350,000)	(900,000)	(350,000)
Dividends Paid	(167,349)	(126,970)	(588,200)	(438,045)
Treasury Stock Purchased	(2,914)	(4,898)	(25,152)	(63,456)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	8,388	8,462	17,946	20,560
Debt Issuance Costs	–	–	(5,016)	–
Repayment of Finance Lease Obligation	(3,261)	(3,167)	(12,899)	(8,219)
Changes in Components of Working Capital Associated with Financing Activities	–	–	–	57
Net Cash Used in Financing Activities	(165,136)	(476,573)	(1,513,321)	(839,103)
Effect of Exchange Rate Changes on Cash	(174)	(35,259)	(348)	(37,937)
Increase in Cash and Cash Equivalents	444,867	281,502	472,338	721,406
Cash and Cash Equivalents at Beginning of Period	1,583,105	1,274,132	1,555,634	834,228
Cash and Cash Equivalents at End of Period	$ 2,027,972	$ 1,555,634	$ 2,027,972	$ 1,555,634

Fourth Quarter 2019 Well Results by Play (Unaudited)

Wells On Line Initial Gross 30-Day Average Production Rate

		Lateral Length	Crude Oil and Condensate	Natural Gas Liquids	Natural Gas	Crude Oil Equivalent
	Gross Net	(ft)	(Bbld) ^(A)	(Bbld) ^(A)	(MMcfd) ^(A)	(Boed) ^(B)
Delaware Basin
Wolfcamp	23 20	9,400	2,500	750	3.7	3,850
Bone Spring	17 15	8,000	1,850	450	2.3	2,700
Leonard	11 11	8,000	2,350	900	4.6	4,000
South Texas Eagle Ford	67 64	7,400	1,100	150	0.6	1,350
South Texas Austin Chalk	9 9	6,100	1,650	300	1.4	2,200
Powder River Basin
Turner / Parkman	7 6	8,900	900	150	3.5	1,650
Niobrara	1 1	8,800	950	50	0.7	1,100
DJ Basin Codell / Niobrara	12 11	11,400	850	50	0.4	950
Williston Basin Bakken/Three Forks	6 5	10,100	2,250	250	1.9	2,800

Barrels per day or million cubic feet per day, as
Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural

EOG RESOURCES, INC.

Reconciliation of Adjusted Net Income (Unaudited; in thousands, except per share data)

The following chart adjusts the three-month and twelve-month periods ended December 31, 2019 and 2018 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions in 2019 and 2018, to add back impairment charges related to certain of EOG’s assets in 2019 and 2018 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

Three Months Ended Three Months Ended

December 31, 2019 December 31, 2018

Before

Tax

Income Tax

Impact

After

Tax

Diluted Earnings

per Share

Before

Tax

Income Tax

Impact

After

Tax

Diluted Earnings

per Share

Reported Net Income (GAAP)

$ 831,208

$ (194,687)

$ 636,521

$ 1.10

$ 1,088,340

$ (195,572)

$ 892,768

$ 1.54

Adjustments:

(Gains) Losses on Mark-to-Market Commodity

Derivative Contracts 62,347 (13,684) 48,663 0.08 (132,095) 29,096 (102,999) (0.18)

Net Cash Received from (Payments for)

Settlements of Commodity Derivative
Contracts	91,521	(20,087)	71,434	0.12	(78,678)	17,330	(61,348)	(0.11)
Less: Gains on Asset Dispositions, Net	(119,963)	26,342	(93,621)	(0.16)	(79,904)	13,625	(66,279)	(0.11)
Add: Impairments	158,725	(34,837)	123,888	0.21	131,795	(29,031)	102,764	0.18
Less: Tax Reform Impact	–	–	–	–	–	(46,684)	(46,684)	(0.08)
Adjustments to Net Income	192,630	(42,266)	150,364	0.25	(158,882)	(15,664)	(174,546)	(0.30)
Adjusted Net Income (Non-GAAP)	$ 1,023,838	$ (236,953)	$ 786,885	$ 1.35	$ 929,458	$ (211,236)	$ 718,222	$ 1.24
Average Number of Common Shares (GAAP) Basic				578,219				577,035
Diluted				580,849				580,288

Twelve Months Ended Twelve Months Ended

December 31, 2019 December 31, 2018

Before

Tax

Income Tax

Impact

After

Tax

Diluted Earnings

per Share

Before

Tax

Income Tax

Impact

After

Tax

Diluted Earnings

per Share

Reported Net Income (GAAP)

$ 3,545,267

$ (810,357)

$ 2,734,910

$ 4.71

$ 4,240,998

$ (821,958)

$ 3,419,040

$ 5.89

Adjustments:

(Gains) Losses on Mark-to-Market Commodity

Derivative Contracts (180,275) 39,567 (140,708) (0.24) 165,640 (36,486) 129,154 0.22

Net Cash Received from (Payments for)

Settlements of Commodity Derivative
Contracts	231,229	(50,750)	180,479	0.31	(258,906)	57,029	(201,877)	(0.35)
Less: Gains on Asset Dispositions, Net	(123,613)	27,252	(96,361)	(0.17)	(174,562)	37,860	(136,702)	(0.24)
Add: Impairments	274,974	(60,351)	214,623	0.37	152,671	(33,629)	119,042	0.21
Less: Tax Reform Impact	–	–	–	–	–	(110,335)	(110,335)	(0.19)
Adjustments to Net Income	202,315	(44,282)	158,033	0.27	(115,157)	(85,561)	(200,718)	(0.35)
Adjusted Net Income (Non-GAAP)	$ 3,747,582	$ (854,639)	$ 2,892,943	$ 4.98	$ 4,125,841	$ (907,519)	$ 3,218,322	$ 5.54
Average Number of Common Shares (GAAP) Basic				577,670				576,578
Diluted				580,777				580,441

Reconciliation of Discretionary Cash Flow (Unaudited; in thousands)

Calculation of Free Cash Flow (Unaudited; in thousands)

The following chart reconciles the three-month periods ended December 31, 2019 and 2018 and twelve-month periods ended December 31, 2019, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes – Net (Payable) Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the three months ended December 31, 2019 and 2018 and twelve months ended December 31, 2019, 2018 and 2017. EOG management uses this information for comparative purposes within the industry.

Three Months Ended Twelve Months Ended

December 31, December 31,

2019 2018 2019 2018 2017

Net Cash Provided by Operating Activities (GAAP)	$ 1,807,204	$ 2,085,228	$ 8,163,180	$ 7,768,608	$ 4,265,336
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	28,483	27,270	113,733	123,986	122,688
Other Non-Current Income Taxes – Net (Payable) Receivable	59,174	86,572	238,711	148,993	(513,404)
Changes in Components of Working Capital and Other Assets
and Liabilities
Accounts Receivable	85,937	(185,349)	91,792	368,180	392,131
Inventories	(34,686)	108,591	(90,284)	395,408	174,548
Accounts Payable	(34,286)	98,178	(168,539)	(439,347)	(324,192)
Accrued Taxes Payable	47,925	55,570	(40,122)	92,461	63,937
Other Assets	36,572	22,101	(358,001)	125,435	658,609
Other Liabilities	38,304	(25,725)	56,619	(10,949)	89,871
Changes in Components of Working Capital Associated with
Investing and Financing Activities	76,384	(205,599)	115,061	(301,083)	(89,992)
Discretionary Cash Flow (Non-GAAP)	$ 2,111,011	$ 2,066,837	$ 8,122,150	$ 8,271,692	$ 4,839,532
Discretionary Cash Flow (Non-GAAP) – Percentage Increase/Decrease	2%		-2%	71%
Discretionary Cash Flow (Non-GAAP)	$ 2,111,011	$ 2,066,837	$ 8,122,150	$ 8,271,692	4,839,532
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a)	(1,388,233)	(1,302,999)	(6,234,454)	(6,172,950)	(4,228,859)
Free Cash Flow (Non-GAAP) ^(b)	$ 722,778	$ 763,838	$ 1,887,696	$ 2,098,742	$ 610,673

See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month periods ended December 31, 2019 and 2018 and twelve- month periods ended December 31, 2019, 2018 and 2017:

Total Expenditures (GAAP)	$ 1,506,061	$ 1,504,438	$ 6,900,450	$ 6,706,359	$ 4,612,746
Less:
Asset Retirement Costs	(34,537)	(27,910)	(186,088)	(69,699)	(55,592)
Non-Cash Expenditures of Other Property, Plant and Equipment	(1,680)	(547)	(2,266)	(49,484)	–
Non-Cash Acquisition Costs of Unproved Properties	(33,317)	(128,719)	(97,704)	(290,542)	(255,711)
Acquisition Costs of Proved Properties	(48,294)	(44,263)	(379,938)	(123,684)	(72,584)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	$ 1,388,233	$ 1,302,999	$ 6,234,454	$ 6,172,950	$ 4,228,859

To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item for the three- month and twelve-month periods ending December 31, 2019. The comparative prior periods have been revised for this change in

Maintenance Capital Expenditures

The capital expenditures required to fund drilling as well as infrastructure requirements to keep oil production flat relative to 2019 across all premium oil plays.

EOG RESOURCES, INC.

Reconciliation of Discretionary Cash Flow (Unaudited; in thousands)

Calculation of Free Cash Flow (Unaudited; in thousands)

The following chart reconciles the twelve-month periods ended December 31, 2014, 2013 and 2012 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2014, 2013 and 2012. EOG management uses this information for comparative purposes within the industry.

		Twelve Months Ended December 31,
	2014	2013		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 Financing Activities	103,414	51,361	(74,158)
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)

See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 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

To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item. The comparative prior periods presented herein have been revised for this change in

Maintenance Capital Expenditures

The capital expenditures required to fund drilling as well as infrastructure requirements to keep oil production flat relative to 2019 across all premium oil plays.

Total Expenditures (Unaudited; in millions)

Three Months Ended Twelve Months Ended

December 31, December 31,

2019 2018 2019 2018 2017

Exploration and Development Drilling	$ 1,086	$ 1,092	$ 4,951	$ 4,935	$ 3,132
Facilities	130	107	629	625	575
Leasehold Acquisitions	75	157	276	488	427
Property Acquisitions	48	45	380	124	73
Capitalized Interest	10	6	38	24	27
Subtotal	1,349	1,407	6,274	6,196	4,234
Exploration Costs	37	34	140	149	145
Dry Hole Costs	–	–	28	5	5
Exploration and Development Expenditures	1,386	1,441	6,442	6,350	4,384
Asset Retirement Costs	35	28	186	70	56
Total Exploration and Development Expenditures	1,421	1,469	6,628	6,420	4,440
Other Property, Plant and Equipment	85	35	272	286	173
Total Expenditures	$ 1,506	$ 1,504	$ 6,900	$ 6,706	$ 4,613

Reconciliation of Adjusted EBITDAX (Unaudited; in thousands)

The following chart adjusts the three-month and twelve-month periods ended December 31, 2019 and 2018 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the gains on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

Three Months Ended Twelve Months Ended

December 31, December 31,

2019 2018 2019 2018

Net Income (GAAP)	$ 636,521	$ 892,768	$ 2,734,910	$ 3,419,040
Adjustments: Interest Expense, Net	40,695	56,020	185,129	245,052
Income Tax Provision	194,687	195,572	810,357	821,958
Depreciation, Depletion and Amortization	959,208	919,963	3,749,704	3,435,408
Exploration Costs	36,495	33,862	139,881	148,999
Dry Hole Costs	–	145	28,001	5,405
Impairments	228,135	186,087	517,896	347,021
EBITDAX (Non-GAAP)	2,095,741	2,284,417	8,165,878	8,422,883
Total (Gains) Losses on MTM Commodity Derivative Contracts	62,347	(132,095)	(180,275)	165,640
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	91,521	(78,678)	231,229	(258,906)
Gains on Asset Dispositions, Net	(119,963)	(79,904)	(123,613)	(174,562)
Adjusted EBITDAX (Non-GAAP)	$ 2,129,646	$ 1,993,740	$ 8,093,219	$ 8,155,055
Adjusted EBITDAX (Non-GAAP) – Percentage Increase/Decrease	7%		-1%

Reconciliation of Net Debt and Total Capitalization Calculation of Net Debt-to-Total Capitalization Ratio (Unaudited; in millions, except ratio data)

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non- GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

At December 31,

2019		2018		2017		2016
Total Stockholders’ Equity – (a) $ 21,641		$ 19,364		$ 16,283		$ 13,982
Current and Long-Term Debt (GAAP) – (b)	5,175		6,083		6,387		6,986
Less: Cash	(2,028)		(1,556)		(834)		(1,600)
Net Debt (Non-GAAP) – (c)	3,147		4,527		5,553		5,386
Total Capitalization (GAAP) – (a) + (b)	$ 26,816		$ 25,447		$ 22,670		$ 20,968
Total Capitalization (Non-GAAP) – (a) + (c)	$ 24,788		$ 23,891		$ 21,836		$ 19,368
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)]	19%		24%		28%		33%
Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)]	13%		19%		25%		28%

Reserves Supplemental Data (Unaudited)

2019 NET PROVED RESERVES RECONCILIATION SUMMARY

United Other

States Trinidad International Total

CRUDE OIL AND CONDENSATE (MMBbl)

Beginning Reserves 1,531.7 0.4 0.2 1,532.3

Revisions (43.0) 0.1 – (42.9)

Purchases in Place 2.9 – – 2.9

Extensions, Discoveries and Other Additions 370.0 – – 370.0

Sales in Place (1.3) – – (1.3) Production (166.3) (0.2) (0.1) (166.6)

Ending Reserves 1,694.0 0.3 0.1 1,694.4

NATURAL GAS LIQUIDS (MMBbl)

Beginning Reserves 614.3 – – 614.3

Revisions 5.4 – – 5.4

Purchases in Place 2.0 – – 2.0

Extensions, Discoveries and Other Additions 167.8 – – 167.8

Sales in Place (0.9) – – (0.9) Production (48.9)———————————————- (48.9)

Ending Reserves 739.7 – – 739.7

NATURAL GAS (Bcf)

Beginning Reserves 4,390.6 237.0 59.6 4,687.2

Revisions (184.4) 47.0 2.6 (134.8)

Purchases in Place 71.7 – – 71.7

Extensions, Discoveries and Other Additions 1,175.9 87.5 9.7 1,273.1 Sales in Place (14.5) – – (14.5) Production (404.5) (95.4) (13.1) (513.0)

Ending Reserves 5,034.8 276.1 58.8 5,369.7

OIL EQUIVALENTS (MMBoe)

Beginning Reserves 2,877.8 39.9 10.1 2,927.8

Revisions (68.3) 7.9 0.4 (60.0)

Purchases in Place 16.8 – – 16.8

Extensions, Discoveries and Other Additions 733.7 14.6 1.7 750.0

Sales in Place (4.6) – – (4.6) Production (282.6) (16.1) (2.2) (300.9)

Ending Reserves 3,272.8 46.3 10.0 3,329.1

Net Proved Developed Reserves (MMBoe)

At December 31, 2018 1,503.4 37.7 7.0 1,548.1

At December 31, 2019 1,684.2 29.9 7.1 1,721.2

2019 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)

United Other

States Trinidad International Total

Acquisition Cost of Unproved Properties	$ 276.1	$ –	$ –	$ 276.1
Exploration Costs	213.5	46.6	13.2	273.3
Development Costs	5,480.7	24.0	8.1	5,512.8
Total Drilling	5,970.3	70.6	21.3	6,062.2
Acquisition Cost of Proved Properties	379.9	–	–	379.9
Asset Retirement Costs	181.1	1.0	4.0	186.1
Total Exploration and Development Expenditures	6,531.3	71.6	25.3	6,628.2
Gathering, Processing and Other	269.7	2.4	0.1	272.2
Total Expenditures	6,801.0	74.0	25.4	6,900.4
Proceeds from Sales in Place	(140.3)	–	–	(140.3)
Net Expenditures	$ 6,660.7	$ 74.0	$ 25.4	$ 6,760.1
RESERVE REPLACEMENT COSTS ($ / Boe ) *
All-in Total, Net of Revisions	$ 9.09	$ 3.14	$ 10.14	$ 8.90
All-in Total, Excluding Revisions Due to Price	$ 8.36	$ 3.14	$ 10.14	$ 8.21
RESERVE REPLACEMENT *
Drilling Only	260%	91%	77%	249%
All-in Total, Net of Revisions and Dispositions	240%	140%	95%	233%
All-in Total, Excluding Revisions Due to Price	261%	140%	95%	253%
All-in Total, Liquids	234%	50%	0%	233%

* See attached reconciliation schedule for calculation methodology

Reconciliation of Total Exploration and Development Expenditures Calculation of Reserve Replacement Costs ($ / BOE)

(Unaudited; in millions, except ratio data)

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflects total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

For the Twelve Months Ended December 31, 2019	United States	Other Trinidad International Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	$ 6,531.3	$ 71.6 $ 25.3 $ 6,628.2
Less: Asset Retirement Costs	(181.1)	(1.0) (4.0) (186.1)
Non-Cash Acquisition Costs of Unproved Properties	(97.7)	– – (97.7)
Total Acquisition Cost of Proved Properties	(379.9)	– – (379.9)
Total Exploration and Development Expenditures for Drilling Only (Non- GAAP) – (a)	$ 5,872.6	$ 70.6 $ 21.3 $ 5,964.5
Total Costs Incurred in Exploration and Development Activities (GAAP)	$ 6,531.3	$ 71.6 $ 25.3 $ 6,628.2
Less: Asset Retirement Costs	(181.1)	(1.0) (4.0) (186.1)
Non-Cash Acquisition Costs of Unproved Properties	(97.7)	– – (97.7)
Non-Cash Acquisition Costs of Proved Properties	(52.3)	– – (52.3)
Total Exploration and Development Expenditures (Non-GAAP) – (b)	$ 6,200.2	$ 70.6 $ 21.3 $ 6,292.1
Total Expenditures (GAAP)	$ 6,801.0	$ 74.0 $ 25.4 $ 6,900.4
Less: Asset Retirement Costs	(181.1)	(1.0) (4.0) (186.1)
Non-Cash Acquisition Costs of Unproved Properties	(97.7)	– – (97.7)
Non-Cash Acquisition Costs of Proved Properties	(52.3)	– – (52.3)
Non-Cash Capital – Other Miscellaneous	(1.6)	– – (1.6)
Total Cash Expenditures (Non-GAAP)	$ 6,468.3	$ 73.0 $ 21.4 $ 6,562.7
Net Proved Reserve Additions From All Sources – Oil Equivalents
Revisions Due to Price – (c)	(59.7)	– – (59.7)
Revisions Other Than Price	(8.6)	7.9 0.4 (0.3)
Purchases in Place	16.8	– – 16.8
Extensions, Discoveries and Other Additions – (d)	733.7	14.6 1.7 750.0
Total Proved Reserve Additions – (e)	682.2	22.5 2.1 706.8
Sales in Place	(4.6)	– – (4.6)
Net Proved Reserve Additions From All Sources – (f)	677.6	22.5 2.1 702.2
Production – (g)	282.6	16.1 2.2 300.9
RESERVE REPLACEMENT COSTS ($ / Boe)
Total Drilling, Before Revisions – (a / d)	$ 8.00	$ 4.84 $ 12.53 $ 7.95
All-in Total, Net of Revisions – (b / e)	$ 9.09	$ 3.14 $ 10.14 $ 8.90
All-in Total, Excluding Revisions Due to Price – (b / (e – c))	$ 8.36	$ 3.14 $ 10.14 $ 8.21
RESERVE REPLACEMENT
Drilling Only – (d / g)	260%	91% 77% 249%
All-in Total, Net of Revisions and Dispositions – (f / g)	240%	140% 95% 233%
All-in Total, Excluding Revisions Due to Price – ((f – c ) / g)	261%	140% 95% 253%
Net Proved Reserve Additions From All Sources – Liquids (MMBbl)
Revisions	(37.6)	0.1 – (37.5)
Purchases in Place	4.9	– – 4.9
Extensions, Discoveries and Other Additions – (h)	537.8	– – 537.8
Total Proved Reserve Additions	505.1	0.1 – 505.2
Sales in Place	(2.2)	– – (2.2)
Net Proved Reserve Additions From All Sources – (i)	502.9	0.1 – 503.0
Production – (j)	215.2	0.2 0.1 215.5
RESERVE REPLACEMENT – LIQUIDS
Drilling Only – (h / j)	250%	0% 0% 250%
All-in Total, Net of Revisions & Dispositions – (i / j)	234%	50% 0% 233%

Reconciliation of Drillbit Exploration and Development Expenditures Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) (Unaudited; in millions, except ratio data)

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.

For the Twelve Months Ended December 31, 2019

PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)

Total Costs Incurred in Exploration and Development Activities (GAAP)

Total

$ 6,628.2

Less: Asset Retirement Costs (186.1)

Acquisition Costs of Unproved Properties (276.1)

Acquisition Cost of Proved Properties (379.9)

Drillbit Exploration and Development Expenditures (Non-GAAP) – (k)

$ 5,786.1

Total Proved Reserves – Extensions, Discoveries and Other Additions

(MMBoe) 750.0

Add: Conversion of Proved Undeveloped Reserves to Proved Developed 302.0

Less: Proved Undeveloped Extensions and Discoveries (578.3)

Proved Developed Reserves – Extensions and Discoveries (MMBoe) 473.7

Total Proved Reserves – Revisions (MMBoe) (60.0)

Less: Proved Undeveloped Reserves – Revisions 49.8

Proved Developed – Revisions Due to Price 59.7

Proved Developed Reserves – Revisions Other Than Price (MMBoe) 49.5

Proved Developed Reserves – Extensions and discoveries plus Revisions

Other than Price (MMBoe) – (l) 523.2

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) – (k / l) $ 11.06

Reconciliation of Total Exploration and Development Expenditures For Drilling Only and Total Exploration and Development Expenditures

Calculation of Reserve Replacement Costs ($ / BOE) (Unaudited; in millions, except ratio data)

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

	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 – (f)	702.2		665.8		604.4		235.9		(168.0)		597.9
Production – (g)	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

Crude Oil, NGLs and Natural Gas Financial Commodity Derivative Contracts

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

Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate 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 pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG’s Midland Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

Midland Differential Basis Swap Contracts

Weighted Average Price

	Volume	Differential
	(Bbld)	($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	20,000	$ 1.075

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG’s Gulf Coast Differential basis swap contracts through February 19, 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.

Gulf Coast Differential Basis Swap Contracts

Weighted Average Price

	Volume	Differential
	(Bbld)	($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	13,000	$ 5.572

EOG has also entered into crude oil swaps 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 February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

Roll Differential Swap Contracts

Weighted Average Price

	Volume	Differential
	(Bbld)	($/Bbl)
2020
February 2020 (closed)	10,000	$ 0.70
March 1, 2020 through December 31, 2020	10,000	0.70

Presented below is a comprehensive summary of EOG’s crude oil price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts

Weighted

2019	Volume (Bbld)	Average Price ($/Bbl)
April 2019 (closed)	25,000	$ 60.00
May 1, 2019 through December 31, 2019 (closed)	150,000	62.50
2020 January 2020 (closed)	200,000	$ 59.33
February 1, 2020 through March 31, 2020	200,000	59.33
April 1, 2020 through June 30, 2020	200,000	59.59
July 1, 2020 through September 30, 2020	107,000	58.94

Presented below is a comprehensive summary of EOG’s Mont Belvieu propane (non-TET) price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Mont Belvieu Propane Price Swap Contracts

Weighted

	Volume	Average Price
	(Bbld)	($/Bbl)
2020
January 2020 (closed)	4,000	$ 21.34
February 2020	4,000	21.34
March 1, 2020 through December 31, 2020	25,000	17.92

Presented below is a comprehensive summary of EOG’s natural gas price swap contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

2019

Natural Gas Price Swap Contracts

Weighted

Volume Average Price

(MMBtud) ($/MMBtu)

April 1, 2019 through October 31, 2019 (closed) 250,000 $ 2.90

EOG has also 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. Presented below is a comprehensive summary of EOG’s natural gas collar contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts

Weighted Average Price ($/MMBtu)

Volume (MMBtud) Ceiling Price Floor Price

2020

April 1, 2020 through October 31, 2020 250,000 $

2.50 $

2.00

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 February 19, 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.

Rockies Differential Basis Swap Contracts

Weighted Average Price

	Volume	Differential
	(MMBtud)	($/MMBtu)
2020
January 1, 2020 through February 29, 2020 (closed)	30,000	$ 0.55
March 1, 2020 through December 31, 2020	30,000	0.55

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). Presented below is a comprehensive summary of EOG’s HSC Differential basis swap contracts through February 19, 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.

HSC Differential Basis Swap Contracts

Weighted Average Price

	Volume	Differential
	(MMBtud)	($/MMBtu)
2020
January 1, 2020 through February 29, 2020 (closed)	60,000	$ 0.05
March 1, 2020 through December 31, 2020	60,000	0.05

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 February 19, 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.

Waha Differential Basis Swap Contracts

Weighted Average Price

	Volume	Differential
	(MMBtud)	($/MMBtu)
2020
January 1, 2020 through February 29, 2020 (closed)	50,000	$ 1.40
March 1, 2020 through December 31, 2020	50,000	1.40

Definitions

Bbld Barrels per day

$/Bbl Dollars per barrel

MMBtud Million British thermal units per day

$/MMBtu Dollars per million British thermal units NYMEX U.S. New York Mercantile Exchange

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

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

Reconciliation of After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization

Calculations of Return on Capital Employed and Return on Equity (Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non- GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

Return on Capital Employed (ROCE) (Non-GAAP)	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) Adjustments to Net Income, Net of Tax (See Accompanying	$ 2,735	$ 3,419
Schedule)	158 (1)	(201) (2)
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
ROCE (GAAP Net Income) – [(a) + (b)] / (h)	11.8%	15.8%
ROCE (Non-GAAP Adjusted Net Income) – [(a) + (c)] / (h)	12.5%	14.9%
Return on Equity (ROE)
ROE (GAAP Net Income) – (b) / (e)	13.3%	19.2%
ROE (Non-GAAP Adjusted Net Income) – (c) / (e)	14.1%	18.1%
* Average for the current and immediately preceding year
Adjustments to Net Income (GAAP)

See below schedule for detail of adjustments to Net Income (GAAP) in 2019:

Year Ended December 31, 2019

	Before	Income Tax	After
	Tax	Impact	Tax
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

See below schedule for detail of adjustments to Net Income (GAAP) in 2018:

Year Ended December 31, 2018

	Before	Income Tax	After
	Tax	Impact	Tax
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)

Reconciliation of After-Tax Net Interest Expense, Net Debt and Total Capitalization

Calculation of Return on Capital Employed (Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After- Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

2017 2016 2015 2014 2013

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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

ROCE (GAAP Net Income) – [(a) + (b)] / (h)

13.4%

-4.8%

-21.6%

14.7%

12.1%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)

17.1%

-8.1%

-29.5%

17.6%

15.3%

* Average for the current and immediately preceding year

2012 2011 2010 2009 2008

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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 (Loss) (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

ROCE (GAAP Net Income) – [(a) + (b)] / (h)

4.0%

7.7%

1.8%

5.4%

26.4%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)

4.4%

9.5%

1.6%

5.8%

30.5%

* Average for the current and immediately preceding year

2007 2006 2005 2004 2003

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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 (Loss) (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

ROCE (GAAP Net Income) – [(a) + (b)] / (h)

15.7%

24.7%

30.0%

18.2%

15.3%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)

17.3%

26.2%

34.7%

24.2%

22.1%

* Average for the current and immediately preceding year

2002 2001 2000 1999 1998

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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 (Loss) (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

ROCE (GAAP Net Income) – [(a) + (b)] / (h)

4.8%

18.2%

20.2%

27.0%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)

5.2%

26.4%

31.6%

47.2%

* Average for the current and immediately preceding year

Cash Operating Expenses per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)

Year Ended December 31,

2019		2018	2017	2016	2015	2014
Cash Operating Expenses (GAAP)*
Lease and Well	$ 1,366,993	$ 1,282,678	$ 1,044,847	$ 927,452	$ 1,182,282	$ 1,416,413
Transportation Costs	758,300	746,876	740,352	764,106	849,319	972,176
General and Administrative	489,397	426,969	434,467	394,815	366,594	402,010
Cash Operating Expenses	2,614,690	2,456,523	2,219,666	2,086,373	2,398,195	2,790,599
Less: Legal Settlement – Early Leasehold Termination	–	–	(10,202)	–	(19,355)	–
Less: Voluntary Retirement Expense	–	–	–	(42,054)	–	–
Less: Acquisition Costs – Yates Transaction	–	–	–	(5,100)	–	–
Less: Joint Venture Transaction Costs	–	–	(3,056)	–	–	–
Less: Joint Interest Billings Deemed Uncollectible	–	–	(4,528)	–	–	–
Adjusted Cash Operating Expenses (Non-GAAP) – (a)	$ 2,614,690	$ 2,456,523	$ 2,201,880	$ 2,039,219	$ 2,378,840	$ 2,790,599
Volume – Thousand Barrels of Oil Equivalent – (b)	298,565	262,516	222,251	204,929	208,862	217,073

Adjusted Cash Operating Expenses Per Boe (Non-GAAP) – (a) / (b) $ 8.76 (c) $ 9.36 (d) $ 9.91 (e) $ 9.95 (f) $ 11.39 (g) $ 12.86 (h)

Adjusted Cash Operating Expenses Per Boe (Non-GAAP) – Percentage Decrease

2019 compared to 2018 – [(c) – (d)] / (d) -6%

2019 compared to 2017 – [(c) – (e)] / (e) -12%

2019 compared to 2016 – [(c) – (f)] / (f) -12%

2019 compared to 2015 – [(c) – (g)] / (g) -23%

2019 compared to 2014 – [(c) – (h)] / (h) -32%

* Includes stock compensation expense and other non-cash items.

Cost per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)

Three Months Ended

	March 31, 2019	June 30, 2019	September 30, 2019	December 31, 2019
Volume – Thousand Barrels of Oil Equivalent – (a)	69,623	73,964	76,748	78,231
Crude Oil and Condensate	$ 2,200,403	$ 2,528,866	$ 2,418,989	$ 2,464,274
Natural Gas Liquids	218,638	186,374	164,736	215,070
Natural Gas	334,972	269,892	269,625	309,606
Total Wellhead Revenues – (b)	$ 2,754,013	$ 2,985,132	$ 2,853,350	$ 2,988,950
Operating Costs Lease and Well	$ 336,291	$ 347,281	$ 348,883	$ 334,538
Transportation Costs	176,522	174,101	199,365	208,312
Gathering and Processing Costs	111,295	112,643	127,549	127,615
General and Administrative	106,672	121,780	135,758	125,187
Taxes Other Than Income	192,906	204,414	203,098	199,746
Interest Expense, Net	54,906	49,908	39,620	40,695

Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) – (c)

$ 978,592

$ 1,010,127

$ 1,054,273

$ 1,036,093

Depreciation, Depletion and Amortization (DD&A)	879,595	957,304		953,597		959,208
Total Operating Cost (excluding Total Exploration Costs) – (d)	$ 1,858,187	$ 1,967,431		$ 2,007,870		$ 1,995,301
Exploration Costs	$ 36,324	$ 32,522		$ 34,540		$ 36,495
Dry Hole Costs	94	3,769		24,138		–
Impairments	72,356	112,130		105,275		228,135
Total Exploration Costs	108,774	148,421		163,953		264,630
Less: Impairments (Non-GAAP)	(23,745)	(65,289)		(27,215)		(158,725)
Total Exploration Costs (Non-GAAP)	$ 85,029	$ 83,132		$ 136,738		$ 105,905
Total Operating Cost (Non-GAAP) (including Total
Exploration Costs) – (e)	$ 1,943,216		$ 2,050,563		$ 2,144,608		$ 2,101,206
Composite Average Wellhead Revenue per Boe – (b) / (a)	$ 39.56		$ 40.36		$ 37.18		$ 38.21
Total Cash Operating Cost per Boe (excluding DD&A
and Total Exploration Costs) – (c) / (a)	$ 14.06		$ 13.65		$ 13.75		$ 13.24

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

$ 25.50

$ 26.71

$ 23.43

$ 24.97

Total Operating Cost per Boe (excluding Total Exploration Costs) – (d) / (a)

$ 26.69

$ 26.59

$ 26.18

$ 25.50

Composite Average Margin per Boe (excluding Total Exploration Costs) – [(b) / (a) – (d) / (a)]

$ 12.87

$ 13.77

$ 11.00

$ 12.71

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

$ 27.91

$ 27.72

$ 27.97

$ 26.85

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

$ 11.65

$ 12.64

$ 9.21

$ 11.36

Year Ended

December 31,

	2019	2018		2017
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) Total Operating Cost (Non-GAAP) (excluding Total	3,749,704	3,435,408		3,409,387
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: 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
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

Year Ended

December 31,

	2016	2015		2014
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) Total Operating Cost (Non-GAAP) (excluding Total	3,553,417	3,313,644		3,997,041
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: 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
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

EOG RESOURCES, INC.

First Quarter and Full Year 2020 Forecast and Benchmark Commodity Pricing

First Quarter and Full Year 2020 Forecast

The forecast items for the first 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.

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 Exchanges.

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 (Unaudited)

1Q 2020 Full Year 2020

Daily Sales Volumes

Crude Oil and Condensate Volumes (MBbld)

United States	479.0	– 487.0	499.0	– 517.6
Trinidad	0.5	– 0.7	1.0	– 1.2
Other International	0.0	– 0.2	0.0	– 0.2
Total	479.5	– 487.9	500.0	– 519.0

Natural Gas Liquids Volumes (MBbld)

Total 150.0 – 160.0 157.0 – 177.0

Natural Gas Volumes (MMcfd)

United States	1,090	– 1,150	1,135	– 1,235
Trinidad	185	– 215	215	– 255
Other International	25	– 35	25	– 35
Total	1,300	– 1,400	1,375	– 1,525

Crude Oil Equivalent Volumes (MBoed)

United States	810.7	– 838.7	845.2	– 900.4
Trinidad	31.3	– 36.5	36.8	– 43.7
Other International	4.2	– 6.0	4.2	– 6.0
Total	846.2	– 881.2	886.2	– 950.1

Capital Expenditures ($MM) $ 1,850 – $ 2,050 $ 6,300 – $ 6,700

Estimated Ranges (Unaudited)

1Q 2020 Full Year 2020

Operating Costs
Unit Costs ($/Boe) Lease and Well	$ 4.30	– $ 4.80	$ 4.20	– $ 4.80
Transportation Costs	$ 2.40	– $ 2.80	$ 2.30	– $ 2.70
General and Administrative	$ 1.55	– $ 1.65	$ 1.55	– $ 1.65
Gathering and Processing	$ 1.70	– $ 1.80	$ 1.60	– $ 1.80
Depreciation, Depletion and Amortization	$ 13.00	– $ 13.50	$ 12.15	– $ 13.15
Expenses ($MM)
Exploration and Dry Hole	$ 40	– $ 50	$ 145	– $ 185
Impairment	$ 80	– $ 90	$ 325	– $ 365
Capitalized Interest	$ 9	– $ 11	$ 37	– $ 43
Net Interest	$ 39	– $ 41	$ 136	– $ 140
Taxes Other Than Income (% of Wellhead Revenue)	7.0%	– 8.0%	7.0%	– 8.0%
Income Taxes Effective Rate	21%	– 26%	21%	– 26%
Current Tax (Benefit) / Expense ($MM)	$ (15)	– $ 30	$ 5	– $ 50

Pricing – (Refer to Benchmark Commodity Pricing in text) Crude Oil and Condensate ($/Bbl)

Differentials

United States – above (below) WTI	$ (0.10)	– $ 0.90	$ (0.50)	– $ 1.50
Trinidad – above (below) WTI	$ (11.00)	– $ (9.00)	$ (11.50)	– $ (9.50)
Other International – above (below) WTI	$ 0.75	– $ 4.75	$ (0.65)	– $ 1.35

Natural Gas Liquids

Realizations as % of WTI 21% – 27% 21% – 27%

Natural Gas ($/Mcf) Differentials

United States – above (below) NYMEX Henry Hub $ (0.70) – $ (0.30) $ (0.90) – $ (0.30)

Realizations
Trinidad	$ 2.40	– $ 2.80	$ 2.50	– $ 3.20
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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