EOG Resources Reports First Quarter 2022 Results; Adds Quantitative Guidance to Cash Return Framework and Declares $1.80 per Share Special Dividend

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EOG Resources reported first-quarter 2022 results with total revenue of $3.983 billion and net income of $390 million. The company declared a special dividend of $1.80 per share and a regular dividend of $0.75 per share, emphasizing a commitment to return at least 60% of free cash flow to shareholders. EOG generated $2.4 billion in free cash flow and achieved an adjusted net income of $2.346 billion or $4.00 per share. Production volumes exceeded guidance, showcasing the company's operational efficiency amidst inflation and supply chain challenges.

Positive

Declared a special dividend of $1.80 per share and regular dividend of $0.75 per share.
Generated $2.4 billion in free cash flow, demonstrating strong operational performance.
Achieved adjusted net income of $2.346 billion or $4.00 per share, reflecting robust earnings.

Negative

Net income decreased significantly from $1.985 billion in 4Q 2021 to $390 million in 1Q 2022.
Cash flow from operating activities declined from $3.166 billion in 4Q 2021 to $828 million in 1Q 2022.
Working capital changes represented a cash use of $2.6 billion, impacting liquidity.

05/05/2022 - 04:15 PM

HOUSTON, May 5, 2022 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported first quarter 2022 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

Key Financial Results

In millions of USD, except per-share and ratio data
		1Q 2022	4Q 2021	1Q 2021
GAAP	Total Revenue	3,983	6,044	3,694
	Net Income	390	1,985	677
	Net Income Per Share	0.67	3.39	1.16
	Net Cash Provided by Operating Activities	828	3,166	1,870
	Total Expenditures	1,144	1,137	1,067
	Current and Long-Term Debt	5,099	5,109	5,133
	Cash and Cash Equivalents	4,009	5,209	3,388
	Debt-to-Total Capitalization	19.1%	18.7%	19.8%

Non- GAAP	Adjusted Net Income	2,346	1,806	946
	Adjusted Net Income Per Share	4.00	3.09	1.62
	CFO before Changes in Working Capital	3,372	3,069	1,982
	Capital Expenditures	1,009	1,015	912
	Free Cash Flow	2,363	2,054	1,070
	Net Debt	1,090	(100)	1,745
	Net Debt-to-Total Capitalization	4.8%	(0.5)%	7.8%

First Quarter 2022 Highlights

Announced guidance to return minimum 60% of free cash flow to shareholders each year
Declared special dividend of $1.80 per share and regular dividend of $0.75 per share
Earned adjusted net income of $2.3 billion, or $4.00 per share
Generated $2.4 billion of free cash flow
Oil, NGL and natural gas production above guidance midpoints
Capital expenditures near low end of guidance range
Total per-unit cash operating costs below guidance midpoint

First Quarter 2022 Highlights

Volumes and Capital Expenditures

Wellhead Volumes	1Q 2022	1Q 2022 Guidance Midpoint	4Q 2021	1Q 2021
Crude Oil and Condensate (MBod)	450.1	447.8	450.6	431.0
Natural Gas Liquids (MBbld)	190.3	187.0	156.9	124.3
Natural Gas (MMcfd)	1,458	1,435	1,534	1,342
Total Crude Oil Equivalent (MBoed)	883.3	874.0	863.1	778.9

Capital Expenditures ($MM)	1,009	1,100	1,015	912

From Ezra Yacob, Chief Executive Officer

"EOG is off to a great start in 2022. We extended our track record of reliable execution with strong first quarter results. Production volumes, capital expenditures and overall operating costs were each better than expected. Despite challenges from rising inflation and supply chain constraints since we announced our 2022 plan at the start of the year, we remain well positioned to deliver within our production and capital expenditure targets. Consistent with the EOG culture, our employees continue to find new innovations and efficiencies to meet our goals for the year.

"Along with strong operating execution, EOG continues to deliver on our long-term free cash flow priorities. In addition to the $0.75 per share regular dividend, we declared a $1.80 per share special dividend. We also initiated new cash return guidance to provide greater transparency to capital allocation, committing to return at least 60 percent of free cash flow to shareholders each year. Our financial strategy aims to create long-term shareholder value and our free cash flow priorities and cash return guidance remain consistent with this goal.

"Our 2022 game plan is on track, guided by our long-term strategy focused on returns. EOG's competitive advantage includes a diverse portfolio of plays across multiple basins, powered by our high-performing people and unique culture. Our pristine balance sheet and commitment to low-cost exploration continue to serve us well. We are well positioned to be among the lowest cost, highest return, lowest emissions producers, playing a significant role in the long-term future of energy."

First Quarter 2022 Financial Performance

Adjusted Earnings per Share 1Q 2022 vs 4Q 2021

Prices and Hedges
Crude oil prices increased significantly in 1Q compared with 4Q, partially offset by declines in natural gas and NGL prices. In addition, cash paid for hedge settlements in 1Q increased by $174 million compared with 4Q.

Volumes
Total company crude oil production in 1Q of 450,100 Bopd was above the midpoint of the guidance range and in-line with 4Q. NGL production was above the midpoint of the guidance range and increased 21% compared with 4Q due to increased extraction of ethane. Natural gas production declined 5% compared with 4Q, also related to extraction of ethane. Total company equivalent daily volumes increased 2% compared with 4Q.

Per-Unit Costs
Lower impairment and DD&A costs were the largest contributors to the overall reduction in per-unit costs in 1Q compared with 4Q. Compared with 4Q, per-unit cash operating costs decreased $0.32 per BOE due to lower G&A, G&P and LOE costs.

Change in Cash 1Q 2022 vs 4Q 2021

Free Cash Flow
EOG generated cash flow from operations before changes in working capital of $3.4 billion in 1Q. The company incurred $1.0 billion of cash capital expenditures, resulting in $2.4 billion of free cash flow.

Working Capital
Changes in working capital in 1Q represented a use of cash of $2.6 billion. Most of the change is due to an increase in collateral EOG has posted with counterparties to financial commodity derivative contracts that are in a net liability position.

First Quarter 2022 Operating Performance

Lease and Well
Per-unit LOE costs declined $0.09 in 1Q compared with 4Q but were $0.10 above the 1Q guidance midpoint. Fuel and power costs increased more than forecast during 1Q. Workover and labor costs declined in 1Q compared with 4Q, but the reduction was less than forecast.

Depreciation, Depletion and Amortization
Per-unit DD&A costs in 1Q were lower than the guidance midpoint and declined 7% compared with 4Q due to positive price-related reserve revisions and the addition of new reserves at lower finding costs.

Transportation, Gathering and Processing
Per-unit transportation and G&P costs in 1Q were in-line with 4Q and the guidance midpoints.

General and Administrative
Per-unit G&A costs declined 11% compared with 4Q and were below the guidance midpoint due to lower employee-related costs.

Free Cash Flow Allocation Actions

Regular Dividend and Special Dividend
The Board of Directors today declared a regular dividend of $0.75 per share on EOG's common stock. The regular dividend will be payable July 29, 2022, to stockholders of record as of July 15, 2022. The indicated annual rate is $3.00 per share. The Board of Directors today also declared a special dividend of $1.80 per share on EOG's common stock. The special dividend will be payable June 30, 2022, to stockholders of record as of June 15, 2022.

Cash Return Guidance
EOG announced its commitment to return a minimum of 60% of free cash flow to shareholders each year. This additional transparency complements the company's long-standing free cash flow priorities. It also reflects EOG's determination to continue to deliver on all its priorities, including returning additional cash to shareholders through special dividends or opportunistic share repurchases. The highest priority remains paying a sustainable and growing regular dividend. The $0.75 per share regular dividend declared today represents a $3.00 per share indicated annual rate. This is an 86% increase from the $1.61 per share regular dividends paid in 2021. EOG today also declared a special dividend of $1.80 per share. Combined with the $1.00 per share special dividend declared in February, EOG has committed to return $1.6 billion to shareholders through special dividends to-date in 2022.

First Quarter 2022 Results vs Guidance

(Unaudited)

Crude Oil and Condensate Volumes (MBod)	1Q 2022	1Q 2022 Guidance Midpoint	Variance	4Q 2021	3Q 2021	2Q 2021	1Q 2021
United States	449.4	447.0	2.4	449.7	448.3	446.9	428.7
Trinidad	0.7	0.8	(0.1)	0.9	1.2	1.7	2.2
Other International	0.0	0.0	0.0	0.0	0.0	0.0	0.1
Total	450.1	447.8	2.3	450.6	449.5	448.6	431.0
Natural Gas Liquids Volumes (MBbld)
Total	190.3	187.0	3.3	156.9	157.9	138.5	124.3
Natural Gas Volumes (MMcfd)
United States	1,249	1,235	14	1,328	1,210	1,199	1,100
Trinidad	209	200	9	206	212	233	217
Other International	0	0	0	0	0	13	25
Total	1,458	1,435	23	1,534	1,422	1,445	1,342

Total Crude Oil Equivalent Volumes (MBoed)	883.3	874.0	9.3	863.1	844.4	828.0	778.9
Total MMBoe	79.5	78.7	0.8	79.4	77.7	75.3	70.1

Benchmark Price
Oil (WTI) ($/Bbl)	94.38			77.17	70.55	66.06	57.80
Natural Gas (HH) ($/Mcf)	4.91			5.83	4.01	2.83	2.69

Crude Oil and Condensate - above (below) WTI ($/Bbl)
United States	1.64	1.50	0.14	1.14	0.33	0.10	0.27
Trinidad	(10.56)	(11.00)	0.44	(10.31)	(10.36)	(9.80)	(8.03)

Natural Gas Liquids - Realizations as % of WTI	42.1%	42.0%	0.1%	52.4%	53.5%	44.1%	48.5%

Natural Gas - above (below) NYMEX Henry Hub ($/Mcf)
United States	0.90	0.90	0.00	0.57	0.49	0.16	2.83
Natural Gas Realizations ($/Mcf)
Trinidad	3.36	3.35	0.01	3.48	3.39	3.37	3.38

Total Expenditures (GAAP) ($MM)	1,144			1,137	962	1,089	1,067
Capital Expenditures (non-GAAP) ($MM)	1,009	1,100	(91)	1,015	891	937	912

Operating Unit Costs ($/Boe)
Lease and Well	4.00	3.90	0.10	4.09	3.48	3.58	3.85
Transportation Costs	2.87	2.85	0.02	2.87	2.82	2.84	2.88
Gathering and Processing	1.81	1.85	(0.04)	1.85	1.87	1.70	1.98
General and Administrative	1.56	1.65	(0.09)	1.75	1.83	1.59	1.57
Cash Operating Costs	10.24	10.25	(0.01)	10.56	10.00	9.71	10.28
Depreciation, Depletion and Amortization	10.65	10.75	(0.10)	11.46	11.93	12.13	12.84

Expenses ($MM)
Exploration and Dry Hole	48	45	3	85	48	49	44
Impairment (GAAP)	55			206	82	44	44
Impairment (excluding certain impairments (non-GAAP))³	55	80	(25)	206	69	43	43
Capitalized Interest	8	8	0	9	8	8	8
Net Interest	48	43	5	38	48	45	47

Taxes Other Than Income (% of Wellhead Revenue)	7.4%	7.5%	(0.1%)	6.8%	6.8%	6.9%	6.7%
Income Taxes
Effective Rate	21.7%	22.5%	(0.8%)	20.5%	23.4%	19.3%	23.2%
Current Tax (Benefit) / Expense ($MM)	573	490	83	393	446	313	240

Second Quarter and Full-Year 2022 Guidance⁴

(Unaudited)

See "Endnotes" below for related discussion and definitions.	2Q 2022 Guidance Range			FY 2022 Guidance Range			2021 Actual	2020 Actual
Crude Oil and Condensate Volumes (MBod)
United States	453.0	-	463.0	454.5	-	466.5	443.4	408.1
Trinidad	0.0	-	1.0	0.4	-	0.6	1.5	1.0
Other International	0.0	-	0.0	0.0	-	0.0	0.1	0.1
Total	453.0	-	464.0	454.9	-	467.1	445.0	409.2
Natural Gas Liquids Volumes (MBbld)
Total	178.0	-	208.0	170.0	-	210.0	144.5	136.0
Natural Gas Volumes (MMcfd)
United States	1,230	-	1,330	1,240	-	1,340	1,210	1,040
Trinidad	170	-	200	160	-	200	217	180
Other International	0	-	0	0	-	0	9	32
Total	1,400	-	1,530	1,400	-	1,540	1,436	1,252
Crude Oil Equivalent Volumes (MBoed)
United States	836.0	-	892.7	831.2	-	899.8	789.6	717.5
Trinidad	28.3	-	34.3	27.1	-	33.9	37.7	30.9
Other International	0.0	-	0.0	0.0	-	0.0	1.6	5.4
Total	864.3	-	927.0	858.3	-	933.7	828.9	753.8

Benchmark Price
Oil (WTI) ($/Bbl)							67.96	39.40
Natural Gas (HH) ($/Mcf)							3.85	2.08

Crude Oil and Condensate Differentials - above (below) WTI5 ($/Bbl)
United States	2.30	-	3.30	1.00	-	3.00	0.58	(0.75)
Trinidad	(9.50)	-	(7.50)	(11.00)	-	(9.00)	(11.70)	(9.20)
Natural Gas Liquids - Realizations as % of WTI
Total	35.0%	-	45.0%	34.0%	-	49.0%	50.5%	34.0%
Natural Gas Differentials - above (below) NYMEX Henry Hub6 ($/Mcf)
United States	0.25	-	1.25	(0.35)	-	1.65	1.03	(0.47)
Natural Gas Realizations ($/Mcf)
Trinidad	3.15	-	3.65	2.90	-	3.90	3.40	2.57

Total Expenditures (GAAP) ($MM)							4,255	4,113
Capital Expenditures7 (non-GAAP) ($MM)	1,100	-	1,300	4,300	-	4,700	3,755	3,344

Operating Unit Costs ($/Boe)
Lease and Well	3.45	-	4.15	3.55	-	4.15	3.75	3.85
Transportation Costs	2.75	-	3.15	2.65	-	3.15	2.85	2.66
Gathering and Processing	1.80	-	2.00	1.70	-	2.00	1.85	1.66
General and Administrative	1.70	-	2.00	1.70	-	1.80	1.69	1.75
Cash Operating Costs	9.70	-	11.30	9.60	-	11.10	10.14	9.92
Depreciation, Depletion and Amortization	10.50	-	11.10	10.15	-	11.15	12.07	12.32

Expenses ($MM)
Exploration and Dry Hole	35	-	45	150	-	190	225	159
Impairment (GAAP)							376	2,100
Impairment (excluding certain impairments (non-GAAP))²	60	-	110	300	-	340	361	232
Capitalized Interest	5	-	10	25	-	35	33	31
Net Interest	45	-	50	180	-	190	178	205

Taxes Other Than Income (% of Wellhead Revenue)	6.0%	-	8.0%	7.0%	-	8.0%	6.8%	6.6%
Income Taxes
Effective Rate	20.0%	-	25.0%	20.0%	-	25.0%	21.4%	18.2%
Current Tax (Benefit) / Expense ($MM)	630	-	730	2,350	-	2,650	1,393	(61)

First Quarter 2022 Results Webcast

Friday, May 6, 2022, 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 and Trinidad. 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

Endnotes
1)	Includes gathering, processing and marketing revenue, other revenue, marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.

2)	Based on full-year 2022 guidance, as of May 5, 2022. Assumes $3.25 Henry Hub natural gas price for 2022. Includes ~$1.3 Bn cash paid for settlement of derivative contracts.

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

4)	The forecast items for the second quarter and full year 2022 set forth above for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, 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.

5)	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.

6)	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.

7)	The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

Glossary
Acq	Acquisitions
ATROR	After-tax rate of return
Bbl	Barrel
Bn	Billion
Boe	Barrels of oil equivalent
Bopd	Barrels of oil per day
CAGR	Compound annual growth rate
Capex	Capital expenditures
CFO	Cash flow provided by operating activities before changes in working capital
CO2e	Carbon dioxide equivalent
DD&A	Depreciation, Depletion and Amortization
Disc	Discoveries
Divest	Divestitures
EPS	Earnings per share
Ext	Extensions
G&A	General and administrative expense
G&P	Gathering and processing expense
GHG	Greenhouse gas
HH	Henry Hub
LOE	Lease operating expense, or lease and well expense
MBbld	Thousand barrels of liquids per day
MBod	Thousand barrels of oil per day
MBoe	Thousand barrels of oil equivalent
MBoed	Thousand barrels of oil equivalent per day
Mcf	Thousand cubic feet of natural gas
MMBoe	Million barrels of oil equivalent
MMcfd	Million cubic feet of natural gas per day
NGLs	Natural gas liquids
OTP	Other than price
NYMEX	U.S. New York Mercantile Exchange
QoQ	Quarter over quarter
Trans	Transportation expense
USD	United States dollar
WTI	West Texas Intermediate
YoY	Year over year
$MM	Million United States dollars
$/Bbl	U.S. Dollars per barrel
$/Boe	U.S. Dollars per barrel of oil equivalent
$/Mcf	U.S. Dollars per thousand cubic feet

This press release may include forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward-looking statements.
Forward‐looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward‐looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward‐looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward‐looking, non‐GAAP financial measures, such as free cash flow and cash flow from operations before changes in working capital, 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 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 (NGLs), natural gasand related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
the availability, cost, terms and timing of issuance or execution of 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 climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax legislation); environmental, health and safety laws and regulations relating to 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;
the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
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, economically and in compliance withapplicable laws and regulations;
competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
the availability and cost of, and competition in the oil and gas exploration and production industry for, employees and other personnel, facilities, equipment, materials (such as water, sand and tubulars) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent to which EOG is successful in its completion of planned asset dispositions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
acts of war and terrorism and responses to these acts; and
the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2021 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, 2021, 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 schedules and definitions for non‐GAAP financial measures can be found on the EOG website at www.eogresources.com.

Income Statements

In millions of USD, except share data (in millions) and per share data (Unaudited)
	1Q 2022	4Q 2021	1Q 2021
Operating Revenues and Other
Crude Oil and Condensate	3,889	3,246	2,251
Natural Gas Liquids	681	583	314
Natural Gas	716	847	625
Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts	(2,820)	136	(367)
Gathering, Processing and Marketing	1,469	1,232	848
Gains (Losses) on Asset Dispositions, Net	25	(29)	(6)
Other, Net	23	29	29
Total	3,983	6,044	3,694

Operating Expenses
Lease and Well	318	325	270
Transportation Costs	228	228	202
Gathering and Processing Costs	144	147	139
Exploration Costs	45	42	33
Dry Hole Costs	3	43	11
Impairments	55	206	44
Marketing Costs	1,283	1,160	838
Depreciation, Depletion and Amortization	847	910	900
General and Administrative	124	139	110
Taxes Other Than Income	390	316	215
Total	3,437	3,516	2,762

Operating Income	546	2,528	932
Other Income (Expense), Net	(1)	9	(4)
Income Before Interest Expense and Income Taxes	545	2,537	928
Interest Expense, Net	48	38	47
Income Before Income Taxes	497	2,499	881
Income Tax Provision	107	514	204
Net Income	390	1,985	677

Dividends Declared per Common Share	1.7500	2.7500	0.4125
Net Income Per Share
Basic	0.67	3.42	1.17
Diluted	0.67	3.39	1.16
Average Number of Common Shares
Basic	582	581	580
Diluted	586	585	583

Wellhead Volumes and Prices

(Unaudited)
	1Q 2022	1Q 2021	% Change	4Q 2021

Crude Oil and Condensate Volumes (MBbld) ^(A)
United States	449.4	428.7	5 %	449.7
Trinidad	0.7	2.2	-68 %	0.9
Other International ^(B)	—	0.1	-100 %	—
Total	450.1	431.0	4 %	450.6

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	96.02	58.07	65 %	78.31
Trinidad	83.82	49.77	68 %	66.86
Other International ^(B)	—	38.61	-100 %	—
Composite	96.00	58.02	65 %	78.29
		58.02
Natural Gas Liquids Volumes (MBbld) ^(A)
United States	190.3	124.3	53 %	156.9
Total	190.3	124.3	53 %	156.9

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	39.77	28.03	42 %	40.40
Composite	39.77	28.03	42 %	40.40

Natural Gas Volumes (MMcfd) ^(A)
United States	1,249	1,100	14 %	1,328
Trinidad	209	217	-4 %	206
Other International ^(B)	—	25	-100 %	—
Total	1,458	1,342	9 %	1,534

Average Natural Gas Prices ($/Mcf) ^(C)
United States	5.81	5.52	5 %	6.40
Trinidad	3.36	3.38	-1 %	3.48
Other International ^(B)	—	5.66	-100 %	—
Composite	5.46	5.17	6 %	6.00

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States	847.8	736.4	15 %	827.8
Trinidad	35.5	38.5	-8 %	35.3
Other International ^(B)	—	4.0	-100 %	—
Total	883.3	778.9	13 %	863.1

Total MMBoe ^(D)	79.5	70.1	13 %	79.4


(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
(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 quarterly period ended March 31, 2022).
(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 millions of USD, except share data (Unaudited)
	March 31,	December 31,
	2022	2021
Current Assets
Cash and Cash Equivalents	4,009	5,209
Accounts Receivable, Net	3,213	2,335
Inventories	586	584
Other	671	456
Total	8,479	8,584

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	65,408	67,644
Other Property, Plant and Equipment	4,801	4,753
Total Property, Plant and Equipment	70,209	72,397
Less: Accumulated Depreciation, Depletion and Amortization	(41,747)	(43,971)
Total Property, Plant and Equipment, Net	28,462	28,426
Deferred Income Taxes	13	11
Other Assets	1,143	1,215
Total Assets	38,097	38,236

Current Liabilities
Accounts Payable	2,660	2,242
Accrued Taxes Payable	1,130	518
Dividends Payable	436	436
Liabilities from Price Risk Management Activities	260	269
Current Portion of Long-Term Debt	1,283	37
Current Portion of Operating Lease Liabilities	223	240
Other	272	300
Total	6,264	4,042

Long-Term Debt	3,816	5,072
Other Liabilities	2,191	2,193
Deferred Income Taxes	4,286	4,749
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 585,944,344 Shares Issued at March 31, 2022 and 585,521,512 Shares Issued at December 31, 2021	206	206
Additional Paid in Capital	6,095	6,087
Accumulated Other Comprehensive Loss	(13)	(12)
Retained Earnings	15,283	15,919
Common Stock Held in Treasury, 290,472 Shares at March 31, 2022 and 257,268 Shares at December 31, 2021	(31)	(20)
Total Stockholders' Equity	21,540	22,180
Total Liabilities and Stockholders' Equity	38,097	38,236

Cash Flows Statements

In millions of USD (Unaudited)
	1Q 2022	4Q 2021	1Q 2021
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	390	1,985	677
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	847	910	900
Impairments	55	206	44
Stock-Based Compensation Expenses	35	35	35
Deferred Income Taxes	(465)	122	(36)
(Gains) Losses on Asset Dispositions, Net	(25)	29	6
Other, Net	6	(2)	7
Dry Hole Costs	3	43	11
Mark-to-Market Financial Commodity Derivative Contracts Total (Gains) Losses	2,820	(136)	367
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts	(296)	(122)	(30)
Other, Net	2	(1)	1
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(878)	(182)	(308)
Inventories	(14)	(108)	64
Accounts Payable	130	341	172
Accrued Taxes Payable	613	26	243
Other Assets	(213)	(81)	(103)
Other Liabilities	(2,250)	201	(89)
Changes in Components of Working Capital Associated with Investing Activities	68	(100)	(91)
Net Cash Provided by Operating Activities	828	3,166	1,870
Investing Cash Flows
Additions to Oil and Gas Properties	(939)	(949)	(875)
Additions to Other Property, Plant and Equipment	(70)	(65)	(42)
Proceeds from Sales of Assets	121	77	5
Changes in Components of Working Capital Associated with Investing Activities	(68)	100	91
Net Cash Used in Investing Activities	(956)	(837)	(821)
Financing Cash Flows
Long-Term Debt Repayments	—	—	(750)
Dividends Paid	(1,023)	(1,406)	(219)
Treasury Stock Purchased	(43)	(8)	(10)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	4	10	—
Repayment of Finance Lease Liabilities	(10)	(10)	(9)
Net Cash Used in Financing Activities	(1,072)	(1,414)	(988)
Effect of Exchange Rate Changes on Cash	—	1	(2)
Increase (Decrease) in Cash and Cash Equivalents	(1,200)	916	59
Cash and Cash Equivalents at Beginning of Period	5,209	4,293	3,329
Cash and Cash Equivalents at End of Period	4,009	5,209	3,388

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), Cash Flow from Operations Before Working Capital, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics.

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

As further discussed in the tables on the following pages, EOG believes 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. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods.

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

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

Adjusted Net Income (Loss)

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

The following tables adjust the reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets) - see "Revenues, Costs and Margins Per Barrel of Oil Equivalent" below for additional related discussion) and to make certain other adjustments to exclude non-recurring and certain other items as further described below. 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.

	1Q 2022
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	497	(107)	390	0.67
Adjustments:
Losses on Mark-to-Market Financial Commodity Derivative Contracts	2,820	(612)	2,208	3.76
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts	(296)	64	(232)	(0.40)
Add: Gains on Asset Dispositions, Net	(25)	5	(20)	(0.03)
Adjustments to Net Income	2,499	(543)	1,956	3.33

Adjusted Net Income (Non-GAAP)	2,996	(650)	2,346	4.00

Average Number of Common Shares (Non-GAAP)
Basic				582
Diluted				586

Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	4Q 2021
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	2,499	(514)	1,985	3.39
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts	(136)	32	(104)	(0.17)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts	(122)	25	(97)	(0.17)
Add: Losses on Asset Dispositions, Net	29	(7)	22	0.04
Adjustments to Net Income	(229)	50	(179)	(0.30)

Adjusted Net Income (Non-GAAP)	2,270	(464)	1,806	3.09

Average Number of Common Shares (Non-GAAP)
Basic				581
Diluted				585

	1Q 2021
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	881	(204)	677	1.16
Adjustments:
Losses on Mark-to-Market Financial Commodity Derivative Contracts	367	(81)	286	0.49
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts	(30)	7	(23)	(0.04)
Add: Losses on Asset Dispositions, Net	6	(1)	5	0.01
Add: Certain Impairments	1	—	1	—
Adjustments to Net Income	344	(75)	269	0.46

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

Average Number of Common Shares (Non-GAAP)
Basic				580
Diluted				583

Adjusted Net Income Per Share
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

4Q 2021 Adjusted Net Income per Share (Non-GAAP)		3.09

Realized Price
1Q 2022 Composite Average Wellhead Revenue per Boe	66.50
Less: 4Q 2021 Composite Average Welhead Revenue per Boe	(58.88)
Subtotal	7.62
Multiplied by: 1Q 2022 Crude Oil Equivalent Volumes (MMBoe)	79.5
Total Change in Revenue	606
Less: Income Tax Benefit (Provision) Imputed (based on 23%)	(139)
Change in Net Income	467
Change in Diluted Earnings per Share		0.80

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
1Q 2022 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts	(296)
Less: Income Tax Benefit (Provision)	64
After Tax - (a)	(232)
4Q 2021 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts	(122)
Less: Income Tax Benefit (Provision)	25
After Tax - (b)	(97)
Change in Net Income - (a) - (b)	(135)
Change in Diluted Earnings per Share		(0.23)

Wellhead Volumes
1Q 2022 Crude Oil Equivalent Volumes (MMBoe)	79.5
Less: 4Q 2021 Crude Oil Equivalent Volumes (MMBoe)	(79.4)
Subtotal	0.1
Multiplied by: 1Q 2022 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	38.80
Change in Revenue	4
Less: Income Tax Benefit (Provision) Imputed (based on 23%)	(1)
Change in Net Income	3
Change in Diluted Earnings per Share		—

Adjusted Net Income Per Share (Continued)
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Operating Cost per Boe
4Q 2021 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	30.14
Less: 4Q 2021 Taxes Other Than Income	(3.98)
Less: 1Q 2022 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	(27.70)
Add: 1Q 2022 Taxes Other Than Income	4.91
Subtotal	3.37
Multiplied by: 1Q 2022 Crude Oil Equivalent Volumes (MMBoe)	79.5
Change in Before-Tax Net Income	268
Less: Income Tax Benefit (Provision) Imputed (based on 23%)	(62)
Change in Net Income	206
Change in Diluted Earnings per Share		0.35

Other ⁽¹⁾		(0.01)

1Q 2022 Adjusted Net Income per Share (Non-GAAP)		4.00

1Q 2022 Average Number of Common Shares (Non-GAAP) - Diluted	586


(1)	Includes gathering, processing and marketing revenue, other revenue, marketing costs, taxes other than income, other income (expense), interest expense and the effect of changes in the effective income tax rate.

Cash Flow from Operations and Free Cash Flow

In millions of USD (Unaudited)

The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Cash Flow from Operations Before Working Capital (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 Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing and Financing Activities and certain other adjustments to exclude non-recurring and certain other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Cash Flow from Operations Before Working Capital (Non-GAAP) (see below reconciliation) for such period less the total capital expenditures (Non-GAAP) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. To further the comparability of EOG's financial results with those of EOG's peer companies and other companies in the industry, EOG now utilizes Cash Flow from Operations Before Working Capital (Non-GAAP), instead of Discretionary Cash Flow (Non-GAAP), in calculating its Free Cash Flow (Non-GAAP). Accordingly, Free Cash Flow (Non-GAAP) for the three-month period ended March 31, 2022 has been calculated on such basis, and the calculations of Free Cash Flow (Non-GAAP) for each of the prior periods shown have been revised and conformed.

	1Q 2022	4Q 2021	3Q 2021	2Q 2021	1Q 2021

Net Cash Provided by Operating Activities (GAAP)	828	3,166	2,196	1,559	1,870

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	878	182	145	186	308
Inventories	14	108	6	(37)	(64)
Accounts Payable	(130)	(341)	68	(11)	(172)
Accrued Taxes Payable	(613)	(26)	(206)	163	(243)
Other Assets	213	81	(167)	119	103
Other Liabilities	2,250	(201)	260	(32)	89
Changes in Components of Working Capital Associated with Investing Activities	(68)	100	(45)	54	91
Cash Flow from Operations Before Working Capital (Non-GAAP)	3,372	3,069	2,257	2,001	1,982

Cash Flow from Operations Before Working Capital (Non-GAAP)	3,372	3,069	2,257	2,001	1,982
Less:
Total Capital Expenditures (Non-GAAP) ^(a)	(1,009)	(1,015)	(891)	(937)	(912)
Free Cash Flow (Non-GAAP)	2,363	2,054	1,366	1,064	1,070

(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

	1Q 2022	4Q 2021	3Q 2021	2Q 2021	1Q 2021

Total Expenditures (GAAP)	1,144	1,137	962	1,089	1,067
Less:
Asset Retirement Costs	(27)	(71)	(8)	(31)	(17)
Non-Cash Acquisition Costs of Unproved Properties	(58)	(8)	(15)	—	(22)
Non-Cash Finance Leases	—	—	—	—	(74)
Acquisition Costs of Proved Properties	(5)	(1)	(4)	(86)	(9)
Exploration Costs	(45)	(42)	(44)	(35)	(33)
Total Capital Expenditures (Non-GAAP)	1,009	1,015	891	937	912

Cash Flow from Operations and Free Cash Flow (Continued)
In millions of USD (Unaudited)

	FY 2021	FY 2020	FY 2019

Net Cash Provided by Operating Activities (GAAP)	8,791	5,008	8,163

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	821	(467)	92
Inventories	13	(123)	(90)
Accounts Payable	(456)	795	(169)
Accrued Taxes Payable	(312)	49	(40)
Other Assets	136	(325)	(358)
Other Liabilities	116	(8)	57
Changes in Components of Working Capital Associated with Investing and Financing Activities	200	(75)	115
Other Non-Current Income Taxes - Net Receivable	—	113	239
Cash Flow from Operations Before Working Capital (Non-GAAP)	9,309	4,967	8,009

Cash Flow from Operations Before Working Capital (Non-GAAP)	9,309	4,967	8,009
Less:
Total Capital Expenditures (Non-GAAP) ^(a)	(3,755)	(3,344)	(6,094)
Free Cash Flow (Non-GAAP)	5,554	1,623	1,915

(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

Total Expenditures (GAAP)	4,255	4,113	6,900
Less:
Asset Retirement Costs	(127)	(117)	(186)
Non-Cash Expenditures of Other Property, Plant and Equipment	—	—	(2)
Non-Cash Acquisition Costs of Unproved Properties	(45)	(197)	(98)
Non-Cash Finance Leases	(74)	(174)	—
Acquisition Costs of Proved Properties	(100)	(135)	(380)
Exploration Costs	(154)	(146)	(140)
Total Capital Expenditures (Non-GAAP)	3,755	3,344	6,094

Cash Flow from Operations and Free Cash Flow (Continued)
In millions of USD (Unaudited)

	FY 2018	FY 2017	FY 2016

Net Cash Provided by Operating Activities (GAAP)	7,769	4,265	2,359

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	368	392	233
Inventories	395	175	(171)
Accounts Payable	(439)	(324)	74
Accrued Taxes Payable	92	64	(93)
Other Assets	125	659	41
Other Liabilities	(11)	90	16
Changes in Components of Working Capital Associated with Investing and Financing Activities	(301)	(90)	156
Other Non-Current Income Taxes - Net (Payable) Receivable	149	(513)	—
Excess Tax Benefits from Stock-Based Compensation	—	—	30
Cash Flow from Operations Before Working Capital (Non-GAAP)	8,147	4,718	2,645

Cash Flow from Operations Before Working Capital (Non-GAAP)	8,147	4,718	2,645
Less:
Total Capital Expenditures (Non-GAAP) ^(a)	(6,023)	(4,083)	(2,581)
Free Cash Flow (Non-GAAP)	2,124	635	64

(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

Total Expenditures (GAAP)	6,706	4,613	6,554
Less:
Asset Retirement Costs	(70)	(56)	20
Non-Cash Expenditures of Other Property, Plant and Equipment	(1)	—	(17)
Non-Cash Acquisition Costs of Unproved Properties	(291)	(256)	(3,102)
Non-Cash Finance Leases	(48)	—	—
Acquisition Costs of Proved Properties	(124)	(73)	(749)
Exploration Costs	(149)	(145)	(125)
Total Capital Expenditures (Non-GAAP)	6,023	4,083	2,581

Total Expenditures

In millions of USD (Unaudited)

	1Q 2022	4Q 2021	3Q 2021	2Q 2021	1Q 2021

Exploration and Development Drilling	813	767	653	711	733
Facilities	109	118	100	105	82
Leasehold Acquisitions	64	21	90	46	58
Property Acquisitions	5	1	4	86	9
Capitalized Interest	8	9	9	7	8
Subtotal	999	916	856	955	890
Exploration Costs	45	42	44	35	33
Dry Hole Costs	3	43	4	13	11
Exploration and Development Expenditures	1,047	1,001	904	1,003	934
Asset Retirement Costs	27	71	8	31	17
Total Exploration and Development Expenditures	1,074	1,072	912	1,034	951
Other Property, Plant and Equipment	70	65	50	55	116
Total Expenditures	1,144	1,137	962	1,089	1,067

Total Expenditures (Continued)
In millions of USD (Unaudited)

	FY 2021	FY 2020	FY 2019	FY 2018	FY 2017	FY 2016

Exploration and Development Drilling	2,864	2,664	4,951	4,935	3,132	1,957
Facilities	405	347	629	625	575	375
Leasehold Acquisitions	215	265	276	488	427	3,217
Property Acquisitions	100	135	380	124	73	749
Capitalized Interest	33	31	38	24	27	31
Subtotal	3,617	3,442	6,274	6,196	4,234	6,329
Exploration Costs	154	146	140	149	145	125
Dry Hole Costs	71	13	28	5	5	11
Exploration and Development Expenditures	3,842	3,601	6,442	6,350	4,384	6,465
Asset Retirement Costs	127	117	186	70	56	(20)
Total Exploration and Development Expenditures	3,969	3,718	6,628	6,420	4,440	6,445
Other Property, Plant and Equipment	286	395	272	286	173	109
Total Expenditures	4,255	4,113	6,900	6,706	4,613	6,554

EBITDAX and Adjusted EBITDAX

In millions of USD (Unaudited)

The following table adjusts the reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)), 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 Financial Commodity Derivative Contracts by eliminating the unrealized Mark-to-Market (MTM) (Gains) Losses from these transactions and to eliminate the (Gains) Losses 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 (Loss) (GAAP) to add back Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)), 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.

	1Q 2022	1Q 2021

Net Income (GAAP)	390	677

Adjustments:
Interest Expense, Net	48	47
Income Tax Provision	107	204
Depreciation, Depletion and Amortization	847	900
Exploration Costs	45	33
Dry Hole Costs	3	11
Impairments	55	44
EBITDAX (Non-GAAP)	1,495	1,916
Losses on MTM Financial Commodity Derivative Contracts	2,820	367
Net Cash Payments for Settlements of Commodity Derivative Contracts	(296)	(30)
(Gains) Losses on Asset Dispositions, Net	(25)	6

Adjusted EBITDAX (Non-GAAP)	3,994	2,259

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)

The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A 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.

	March 31, 2022	December 31, 2021	September 30, 2021	June 30, 2021	March 31, 2021

Total Stockholders' Equity - (a)	21,540	22,180	21,765	20,881	20,762

Current and Long-Term Debt (GAAP) - (b)	5,099	5,109	5,117	5,125	5,133
Less: Cash	(4,009)	(5,209)	(4,293)	(3,880)	(3,388)
Net Debt (Non-GAAP) - (c)	1,090	(100)	824	1,245	1,745

Total Capitalization (GAAP) - (a) + (b)	26,639	27,289	26,882	26,006	25,895

Total Capitalization (Non-GAAP) - (a) + (c)	22,630	22,080	22,589	22,126	22,507

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	19.1%	18.7%	19.0%	19.7%	19.8%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	4.8%	-0.5%	3.6%	5.6%	7.8%

Net Debt-to-Total Capitalization Ratio (Continued)
In millions of USD, except ratio data (Unaudited)

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

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

Current and Long-Term Debt (GAAP) - (b)	5,816	5,721	5,724	5,222
Less: Cash	(3,329)	(3,066)	(2,417)	(2,907)
Net Debt (Non-GAAP) - (c)	2,487	2,655	3,307	2,315

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

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

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

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

Net Debt-to-Total Capitalization Ratio (Continued)
In millions of USD, except ratio data (Unaudited)
	December 31, 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)]	19.3%	19.7%	20.1%	23.4%

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

Net Debt-to-Total Capitalization Ratio (Continued)
In millions of USD, except ratio data (Unaudited)
	December 31, 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)]	23.9%	25.8%	26.9%	27.6%

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

Net Debt-to-Total Capitalization Ratio (Continued)
In millions of USD, except ratio data (Unaudited)
	December 31, 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)]	28.2%	31.4%	33.4%	33.4%

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

Net Debt-to-Total Capitalization Ratio (Continued)
In millions of USD, except ratio data (Unaudited)
	December 31, 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	6,656
Less: Cash	(1,600)	(1,049)	(780)	(668)	(719)
Net Debt (Non-GAAP) - (c)	5,386	5,937	6,206	6,318	5,937

Total Capitalization (GAAP) - (a) + (b)	20,968	18,784	19,043	19,391	19,599

Total Capitalization (Non-GAAP) - (a) + (c)	19,368	17,735	18,263	18,723	18,880

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

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	27.8%	33.5%	34.0%	33.7%	31.4%

Reserve Replacement Cost Data

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

The following table 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 (and the non-GAAP measures used in calculating such statistics) provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics (and the non-GAAP measures used in calculating such 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.

	2021	2020	2019	2018

Total Costs Incurred in Exploration and Development Activities (GAAP)	3,969	3,718	6,628	6,420
Less: Asset Retirement Costs	(127)	(117)	(186)	(70)
Non-Cash Acquisition Costs of Unproved Properties	(45)	(197)	(98)	(291)
Acquisition Costs of Proved Properties	(100)	(135)	(380)	(124)
Total Exploration and Development Expenditures for Drilling Only (Non- GAAP) - (a)	3,697	3,269	5,964	5,935

Total Costs Incurred in Exploration and Development Activities (GAAP)	3,969	3,718	6,628	6,420
Less: Asset Retirement Costs	(127)	(117)	(186)	(70)
Non-Cash Acquisition Costs of Unproved Properties	(45)	(197)	(98)	(291)
Non-Cash Acquisition Costs of Proved Properties	(5)	(15)	(52)	(71)
Total Exploration and Development Expenditures (Non-GAAP) - (b)	3,792	3,389	6,292	5,988

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	194	(278)	(60)	35
Revisions Other Than Price	(308)	(89)	—	(40)
Purchases in Place	9	10	17	12
Extensions, Discoveries and Other Additions - (d)	952	564	750	670
Total Proved Reserve Additions - (e)	847	207	707	677
Sales in Place	(11)	(31)	(5)	(11)
Net Proved Reserve Additions From All Sources	836	176	702	666

Production	309	285	301	265

Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	3.88	5.79	7.95	8.86
All-in Total, Net of Revisions - (b / e)	4.48	16.32	8.90	8.85
All-in Total, Excluding Revisions Due to Price - (b / ( e - c))	5.81	6.98	8.21	9.33

Reserve Replacement Cost Data (Continued)
In millions of USD, except reserves and ratio data (Unaudited)

	2017	2016	2015	2014

Total Costs Incurred in Exploration and Development Activities (GAAP)	4,440	6,445	4,928	7,905
Less: Asset Retirement Costs	(56)	20	(53)	(196)
Non-Cash Acquisition Costs of Unproved Properties	(256)	(3,102)	—	—
Acquisition Costs of Proved Properties	(73)	(749)	(481)	(139)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a)	4,055	2,614	4,394	7,570

Total Costs Incurred in Exploration and Development Activities (GAAP)	4,440	6,445	4,928	7,905
Less: Asset Retirement Costs	(56)	20	(53)	(196)
Non-Cash Acquisition Costs of Unproved Properties	(256)	(3,102)	—	—
Non-Cash Acquisition Costs of Proved Properties	(26)	(732)	—	—
Total Exploration and Development Expenditures (Non-GAAP) - (b)	4,102	2,631	4,875	7,709

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	154	(101)	(574)	52
Revisions Other Than Price	48	253	107	49
Purchases in Place	2	42	56	14
Extensions, Discoveries and Other Additions - (d)	421	209	246	519
Total Proved Reserve Additions - (e)	625	403	(165)	634
Sales in Place	(21)	(168)	(4)	(36)
Net Proved Reserve Additions From All Sources	604	235	(169)	598

Production	224	206	210	220

Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	9.64	12.51	17.87	14.58
All-in Total, Net of Revisions - (b / e)	6.56	6.52	(29.63)	12.16
All-in Total, Excluding Revisions Due to Price - (b / ( e - c))	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.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2022 to May 4, 2022 (closed) and outstanding as of May 4, 2022.

Crude Oil Financial Price Swap Contracts
		Contracts Sold		Contracts Purchased
Period	Settlement Index	Volume (MBbld)	Weighted Average Price ($/Bbl)	Volume (MBbld)	Weighted Average Price ($/Bbl)
January - March 2022 (closed)	NYMEX WTI	140	$ 65.58	—	$ —
April 2022 (closed)	NYMEX WTI	140	65.62	—	—
May - June 2022	NYMEX WTI	140	65.62	—	—
July - September 2022	NYMEX WTI	140	65.59	—	—
October - December 2022 (closed) ⁽¹⁾	NYMEX WTI	53	66.11	—	—
October - December 2022	NYMEX WTI	87	65.41	87	88.85
January - March 2023	NYMEX WTI	150	67.92	—	—
April - June 2023	NYMEX WTI	120	67.79	—	—
July - September 2023	NYMEX WTI	100	70.15	—	—
October - December 2023	NYMEX WTI	69	69.41	—	—


(1)	In April 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October - December 2022 crude oil financial price swap contracts which were open at that time. EOG paid net cash of $114 million for the settlement of these contracts.

Crude Oil Basis Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MBbld)	Weighted Average Price Differential ($/Bbl)
January - May 2022 (closed)	NYMEX WTI Roll Differential⁽¹⁾	125	$ 0.15
June - December 2022	NYMEX WTI Roll Differential⁽¹⁾	125	0.15


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

Financial Commodity Derivative Contracts (Continued)

Natural Gas Financial Price Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price ($/MMBtu)
January - May 2022 (closed)	NYMEX Henry Hub	725	$ 3.57
June - December 2022	NYMEX Henry Hub	725	3.57
January - December 2023	NYMEX Henry Hub	725	3.18
January - December 2024	NYMEX Henry Hub	725	3.07
January - December 2025	NYMEX Henry Hub	725	3.07

Natural Gas Basis Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price Differential ($/MMBtu)
January - May 2022 (closed)	NYMEX Henry Hub HSC Differential⁽¹⁾	210	$ (0.01)
June - December 2022	NYMEX Henry Hub HSC Differential⁽¹⁾	210	(0.01)
January - December 2023	NYMEX Henry Hub HSC Differential⁽¹⁾	135	(0.01)
January - December 2024	NYMEX Henry Hub HSC Differential⁽¹⁾	10	0.00
January - December 2025	NYMEX Henry Hub HSC Differential⁽¹⁾	10	0.00


(1)	This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

Glossary:
$/Bbl	Dollars per barrel
$/MMBtu	Dollars per million British Thermal Units
Bbl	Barrel
EOG	EOG Resources, Inc.
HSC	Houston Ship Channel
MBbld	Thousand barrels per day
MMBtu	Million British Thermal Units
MMBtud	Million British Thermal Units per day
NGL	Natural Gas Liquids
NYMEX	New York Mercantile Exchange
WTI	West Texas Intermediate

Direct After-Tax Rate of Return


The calculation of EOG's direct after-tax rate of return (ATROR) with respect to EOG's 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 EOG's direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, EOG's direct ATROR 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 wellsite facilities and flowback
Excludes Indirect Capital
- Gathering and Processing and other Midstream
- Land, Seismic, Geological and Geophysical
- Offsite Production Facilities

Payback ~12 Months on 100% Direct ATROR Wells
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of 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 and Powder River Basin Facilities
- Gathering and Processing
Includes Legacy Gas Capital and Capital from Mature Wells

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Interest Expense, Net (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) 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.

	2021	2020	2019	2018

Interest Expense, Net (GAAP)	178	205	185	245
Tax Benefit Imputed (based on 21%)	(37)	(43)	(39)	(51)
After-Tax Net Interest Expense (Non-GAAP) - (a)	141	162	146	194

Net Income (Loss) (GAAP) - (b)	4,664	(605)	2,735	3,419
Adjustments to Net Income (Loss), Net of Tax (See Below Detail) ⁽¹⁾	364	1,455	158	(201)
Adjusted Net Income (Non-GAAP) - (c)	5,028	850	2,893	3,218

Total Stockholders' Equity - (d)	22,180	20,302	21,641	19,364

Average Total Stockholders' Equity * - (e)	21,241	20,972	20,503	17,824

Current and Long-Term Debt (GAAP) - (f)	5,109	5,816	5,175	6,083
Less: Cash	(5,209)	(3,329)	(2,028)	(1,556)
Net Debt (Non-GAAP) - (g)	(100)	2,487	3,147	4,527

Total Capitalization (GAAP) - (d) + (f)	27,289	26,118	26,816	25,447

Total Capitalization (Non-GAAP) - (d) + (g)	22,080	22,789	24,788	23,891

Average Total Capitalization (Non-GAAP) * - (h)	22,435	23,789	24,340	22,864

Return on Capital Employed (ROCE)
Calculated Using GAAP Net Income (Loss) - [(a) + (b)] / (h) (Non- GAAP)	21.4%	-1.9%	11.8%	15.8%
Calculated Using Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) (Non-GAAP)	23.0%	4.3%	12.5%	14.9%

Return on Equity (ROE)
Calculated Using GAAP Net Income (Loss) - (b) / (e) (GAAP)	22.0%	-2.9%	13.3%	19.2%
Calculated Using Non-GAAP Adjusted Net Income - (c) / (e) (Non- GAAP)	23.7%	4.1%	14.1%	18.1%

* Average for the current and immediately preceding year

ROCE & ROE (Continued)

(1) Detail of adjustments to Net Income (Loss) (GAAP):
	Before Tax	Income Tax Impact	After Tax
Year Ended December 31, 2021
Adjustments:
Add: Mark-to-Market Financial Commodity Derivative Contracts Impact	514	(112)	402
Add: Certain Impairments	15	—	15
Less: Gains on Asset Dispositions, Net	(17)	9	(8)
Less: Tax Benefits Related to Exiting Canada Operations	—	(45)	(45)
Total	512	(148)	364

Year Ended December 31, 2020
Adjustments:
Add: Mark-to-Market Financial Commodity Derivative Contracts Impact	(74)	16	(58)
Add: Certain Impairments	1,868	(392)	1,476
Add: Losses on Asset Dispositions, Net	47	(10)	37
Total	1,841	(386)	1,455

Year Ended December 31, 2019
Adjustments:
Add: Mark-to-Market Financial Commodity Derivative Contracts Impact	51	(11)	40
Add: Certain Impairments	275	(60)	215
Less: Gains on Asset Dispositions, Net	(124)	27	(97)
Total	202	(44)	158

Year Ended December 31, 2018
Adjustments:
Add: Mark-to-Market Financial Commodity Derivative Contracts Impact	(93)	20	(73)
Add: Certain Impairments	153	(34)	119
Less: Gains on Asset Dispositions, Net	(175)	38	(137)
Less: Tax Reform Impact	—	(110)	(110)
Total	(115)	(86)	(201)

ROCE & ROE
In millions of USD, except ratio data (Unaudited)

The following tables reconcile Interest Expense, Net (GAAP), Current 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) 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, 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

Interest Expense, Net (GAAP)	274	282	237
Tax Benefit Imputed (based on 35%)	(96)	(99)	(83)
After-Tax Net Interest Expense (Non-GAAP) - (a)	178	183	154

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

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

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

Current and Long-Term Debt (GAAP) - (f)	6,387	6,986	6,655
Less: Cash	(834)	(1,600)	(719)
Net Debt (Non-GAAP) - (g)	5,553	5,386	5,936

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

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

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

Return on Capital Employed (ROCE)
Calculated Using GAAP Net Income (Loss) - [(a) + (b)] / (h) (Non-GAAP)	13.4 %	-4.8 %	-21.6 %

Return on Equity (ROE)
Calculated Using GAAP Net Income (Loss) - (b) / (e) (GAAP)	17.1 %	-8.1 %	-29.5 %


* Average for the current and immediately preceding year

ROCE & ROE (Continued)
In millions of USD, except ratio data (Unaudited)

	2014	2013	2012	2011

Interest Expense, Net (GAAP)	201	235	214
Tax Benefit Imputed (based on 35%)	(70)	(82)	(75)
After-Tax Net Interest Expense (Non-GAAP) - (a)	131	153	139

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

Total Stockholders' Equity - (d)	17,713	15,418	13,285	12,641

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

Current and Long-Term Debt (GAAP) - (f)	5,906	5,909	6,312	5,009
Less: Cash	(2,087)	(1,318)	(876)	(616)
Net Debt (Non-GAAP) - (g)	3,819	4,591	5,436	4,393

Total Capitalization (GAAP) - (d) + (f)	23,619	21,327	19,597	17,650

Total Capitalization (Non-GAAP) - (d) + (g)	21,532	20,009	18,721	17,034

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

Return on Capital Employed (ROCE)
Calculated Using GAAP Net Income - [(a) + (b)] / (h) (Non- GAAP)	14.7 %	12.1 %	4.0 %

Return on Equity (ROE)
Calculated Using GAAP Net Income - (b) / (e) (GAAP)	17.6 %	15.3 %	4.4 %


* Average for the current and immediately preceding year

Revenues, Costs and Margins Per Barrel of Oil Equivalent

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

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margin per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	1Q 2022	4Q 2021	3Q 2021	2Q 2021	1Q 2021

Volume - Million Barrels of Oil Equivalent - (a)	79.5	79.4	77.7	75.3	70.1

Total Operating Revenues and Other (b)	3,983	6,044	4,765	4,139	3,694
Total Operating Expenses (c)	3,437	3,516	3,294	2,968	2,762
Operating Income (d)	546	2,528	1,471	1,171	932

Wellhead Revenues
Crude Oil and Condensate	3,889	3,246	2,929	2,699	2,251
Natural Gas Liquids	681	583	548	367	314
Natural Gas	716	847	568	404	625
Total Wellhead Revenues - (e)	5,286	4,676	4,045	3,470	3,190

Operating Costs
Lease and Well	318	325	270	270	270
Transportation Costs	228	228	219	214	202
Gathering and Processing Costs	144	147	145	128	139
General and Administrative	124	139	142	120	110
Taxes Other Than Income	390	316	277	239	215
Interest Expense, Net	48	38	48	45	47
Total Operating Cost (excluding DD&A and Total Exploration Costs) (f)	1,252	1,193	1,101	1,016	983

Depreciation, Depletion and Amortization (DD&A)	847	910	927	914	900

Total Operating Cost (excluding Total Exploration Costs) - (g)	2,099	2,103	2,028	1,930	1,883

Exploration Costs	45	42	44	35	33
Dry Hole Costs	3	43	4	13	11
Impairments	55	206	82	44	44
Total Exploration Costs (GAAP)	103	291	130	92	88
Less: Certain Impairments ⁽¹⁾	—	—	(13)	(1)	(1)
Total Exploration Costs (Non-GAAP)	103	291	117	91	87

Total Operating Cost (including Total Exploration Costs (GAAP)) - (h)	2,202	2,394	2,158	2,022	1,971
Total Operating Cost (including Total Exploration Costs (Non-GAAP)) - (i)	2,202	2,394	2,145	2,021	1,970

Total Wellhead Revenues less Total Operating Cost (including Total Exploration Costs (GAAP))	3,084	2,282	1,887	1,448	1,219
Total Wellhead Revenues less Total Operating Cost (including Total Exploration Costs (Non-GAAP))	3,084	2,282	1,900	1,449	1,220

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	1Q 2022	4Q 2021	3Q 2021	2Q 2021	1Q 2021

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

Composite Average Operating Revenues and Other per Boe - (b) / (a)	50.10	76.12	61.33	54.97	52.70
Composite Average Operating Expenses per Boe - (c) / (a)	43.23	44.28	42.40	39.42	39.40
Composite Average Operating Income per Boe - (d) / (a)	6.87	31.84	18.93	15.55	13.30

Composite Average Wellhead Revenue per Boe - (e) / (a)	66.50	58.88	52.07	46.07	45.49

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	15.75	15.02	14.19	13.48	14.02

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	50.75	43.86	37.88	32.59	31.47

Total Operating Cost per Boe (excluding Total Exploration Costs) - (g) / (a)	26.40	26.48	26.12	25.61	26.86

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (g) / (a)]	40.10	32.40	25.95	20.46	18.63

Total Operating Cost per Boe (including Total Exploration Costs) - (h) / (a)	27.70	30.15	27.79	26.85	28.12

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (h) / (a)]	38.80	28.73	24.28	19.22	17.37

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

Total Operating Cost per Boe (including Total Exploration Costs) - (i) / (a)	27.70	30.14	27.62	26.82	28.11

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (i) / (a)]	38.80	28.74	24.45	19.25	17.38


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

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	2021		2020	2019	2018	2017

Volume - Million Barrels of Oil Equivalent - (a)	302.5		275.9	298.6	262.5	222.3

Total Operating Revenues and Other (b)	18,642		11,032	17,380	17,275	11,208
Total Operating Expenses (c)	12,540		11,576	13,681	12,806	10,282
Operating Income (Loss) (d)	6,102		(544)	3,699	4,469	926

Wellhead Revenues
Crude Oil and Condensate	11,125		5,786	9,613	9,517	6,256
Natural Gas Liquids	1,812		668	785	1,128	730
Natural Gas	2,444		837	1,184	1,302	922
Total Wellhead Revenues - (e)	15,381		7,291	11,582	11,947	7,908

Operating Costs
Lease and Well	1,135		1,063	1,367	1,283	1,045
Transportation Costs	863		735	758	747	740
Gathering and Processing Costs	559		459	479	437	149
General and Administrative (GAAP)	511		484	489	427	434
Less: Legal Settlement - Early Leasehold Termination	—		—	—	—	(10)
Less: Joint Venture Transaction Costs	—		—	—	—	(3)
Less: Joint Interest Billings Deemed Uncollectible	—		—	—	—	(5)
General and Administrative (Non-GAAP)⁽¹⁾	511		484	489	427	416
Taxes Other Than Income	1,047		478	800	772	545
Interest Expense, Net	178		205	185	245	274
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	4,293		3,424	4,078	3,911	3,187
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	4,293		3,424	4,078	3,911	3,169

Depreciation, Depletion and Amortization (DD&A)	3,651		3,400	3,750	3,435	3,409

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	7,944		6,824	7,828	7,346	6,596
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	7,944		6,824	7,828	7,346	6,578

Exploration Costs	154		146	140	149	145
Dry Hole Costs	71		13	28	5	5
Impairments	376		2,100	518	347	479
Total Exploration Costs (GAAP)	601	601	2,259	686	501	629
Less: Certain Impairments ⁽²⁾	(15)		(1,868)	(275)	(153)	(261)
Total Exploration Costs (Non-GAAP)	586		391	411	348	368

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	8,545		9,083	8,514	7,847	7,225
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k)	8,530		7,215	8,239	7,694	6,946

Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	6,836		(1,792)	3,068	4,100	683
Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))	6,851		76	3,343	4,253	962

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
	2021	2020	2019	2018	2017

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

Composite Average Operating Revenues and Other per Boe - (b) / (a)	61.63	39.99	58.20	65.81	50.42
Composite Average Operating Expenses per Boe - (c) / (a)	41.46	41.96	45.81	48.79	46.25
Composite Average Operating Income (Loss) per Boe - (d) / (a)	20.17	(1.97)	12.39	17.02	4.17

Composite Average Wellhead Revenue per Boe - (e) / (a)	50.84	26.42	38.79	45.51	35.58

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	14.19	12.39	13.66	14.90	14.34

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	36.65	14.03	25.13	30.61	21.24

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)	26.26	24.71	26.22	27.99	29.67

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]	24.58	1.71	12.57	17.52	5.91

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)	28.25	32.92	28.51	29.89	32.50

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]	22.59	(6.50)	10.28	15.62	3.08

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

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)	14.19	12.39	13.66	14.90	14.25

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]	36.65	14.03	25.13	30.61	21.33

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)	26.26	24.71	26.22	27.99	29.59

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]	24.58	1.71	12.57	17.52	5.99

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)	28.20	26.13	27.60	29.32	31.24

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]	22.64	0.29	11.19	16.19	4.34


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

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

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	2016	2015	2014

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

Total Operating Revenues and Other (b)	7,651	8,757	18,035
Total Operating Expenses (c)	8,876	15,443	12,793
Operating Income (Loss) (d)	(1,225)	(6,686)	5,242

Wellhead Revenues
Crude Oil and Condensate	4,317	4,935	9,742
Natural Gas Liquids	437	408	934
Natural Gas	742	1,061	1,916
Total Wellhead Revenues - (e)	5,496	6,404	12,592

Operating Costs
Lease and Well	927	1,182	1,416
Transportation Costs	764	849	972
Gathering and Processing Costs	123	146	146
General and Administrative (GAAP)	395	367	402
Less: Voluntary Retirement Expense	(42)	—	—
Less: Acquisition Costs	(5)	—	—
Less: Legal Settlement - Early Leasehold Termination	—	(19)	—
General and Administrative (Non-GAAP)⁽¹⁾	348	348	402
Taxes Other Than Income	350	422	758
Interest Expense, Net	282	237	201
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	2,841	3,203	3,895
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	2,794	3,184	3,895

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

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	6,394	6,517	7,892
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	6,347	6,498	7,892

Exploration Costs	125	149	184
Dry Hole Costs	11	15	48
Impairments	620	6,614	744
Total Exploration Costs (GAAP)	756	6,778	976
Less: Certain Impairments ⁽²⁾	(321)	(6,308)	(824)
Total Exploration Costs (Non-GAAP)	435	470	152

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	7,150	13,295	8,868
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) - (k)	6,782	6,968	8,044

Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	(1,654)	(6,891)	3,724
Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))	(1,286)	(564)	4,548

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
	2016	2015	2014

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

Composite Average Operating Revenues and Other per Boe - (b) / (a)	37.32	41.92	83.07
Composite Average Operating Expenses per Boe - (c) / (a)	43.30	73.93	58.92
Composite Average Operating Income (Loss) per Boe - (d) / (a)	(5.98)	(32.01)	24.15

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

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

View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-first-quarter-2022-results-adds-quantitative-guidance-to-cash-return-framework-and-declares-1-80-per-share-special-dividend-301541238.html

SOURCE EOG Resources, Inc.

FAQ

What are EOG's dividends for 2022?

EOG declared a regular dividend of $0.75 per share and a special dividend of $1.80 per share.

When will EOG's dividends be paid?

The regular dividend will be payable on July 29, 2022, and the special dividend on June 30, 2022.

What percentage of free cash flow does EOG return to shareholders?

EOG commits to returning a minimum of 60% of free cash flow to shareholders each year.

How much free cash flow did EOG generate in Q1 2022?

EOG generated $2.4 billion in free cash flow in the first quarter of 2022.

EOG Resources Reports First Quarter 2022 Results; Adds Quantitative Guidance to Cash Return Framework and Declares $1.80 per Share Special Dividend

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EOG Resources Reports First Quarter 2022 Results; Adds Quantitative Guidance to Cash Return Framework and Declares $1.80 per Share Special Dividend

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