EOG Resources Reports Excellent Third Quarter 2021 Results; Raises Regular Dividend 82% and Declares $2.00 per Share Special Dividend

Rhea-AI Summary

EOG Resources reported strong financial results for Q3 2021, including total revenue of $4.77 billion and net income of $1.1 billion, representing an increase from $907 million in Q2 2021. Adjusted net income was $1.26 billion, or $2.16 per share, up from $1.01 billion in Q2. EOG raised its regular dividend by 82% to an annual rate of $3.00 per share and declared a special dividend of $2.00 per share. The company generated impressive free cash flow of $1.36 billion while keeping capital expenditures low at $935 million, benefiting from cost efficiencies.

Positive

• Total revenue increased to $4.77 billion in Q3 2021 from $4.14 billion in Q2 2021.
• Net income rose to $1.1 billion, or $1.88 per share, compared to $907 million in Q2.
• Adjusted net income was $1.26 billion, or $2.16 per share, a significant increase from $1.01 billion.
• $1.36 billion free cash flow generated in Q3.
• Regular dividend increased by 82% to $3.00 per share annually, reflecting strong financial health.
• Declared a special dividend of $2.00 per share, highlighting commitment to returning capital to shareholders.

Negative

• None.

HOUSTON, Nov. 4, 2021 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported third quarter 2021 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

Key Financial Results

In millions of USD, except per-share and ratio data
		3Q 2021		2Q 2021		3Q 2020
GAAP	Total Revenue	4,765		4,139		2,246
	Net Income (Loss)	1,095		907		(42)
	Net Income (Loss) Per Share	1.88		1.55		(0.07)
	Net Cash Provided by Operating Activities	2,196		1,559		1,214
	Total Expenditures	962		1,089		646
	Current and Long-Term Debt	5,117		5,125		5,721
	Cash and Cash Equivalents	4,293		3,880		3,066
	Debt-to-Total Capitalization	19.0	%	19.7	%	22.1	%
Non-GAAP	Adjusted Net Income	1,264		1,012		252
	Adjusted Net Income Per Share	2.16		1.73		0.43
	Discretionary Cash Flow	2,296		2,030		1,261
	Cash Capital Expenditures before Acquisitions	935		972		499
	Free Cash Flow	1,361		1,058		762
	Net Debt	824		1,245		2,655
	Net Debt-to-Total Capitalization	3.6	%	5.6	%	11.6	%

Third Quarter 2021 Highlights

• Increased regular dividend 82% to an indicated annual rate of $3.00 per share
• Declared special dividend of $2.00 per share
• Updated share repurchase authorization
• Earned adjusted net income of $1.3 billion, or $2.16 per share
• Generated $1.4 billion of free cash flow
• Capital expenditures near low end of guidance range driven by sustainable cost reductions
• Oil and NGL production above high end of guidance ranges
• Total per-unit cash operating costs below guidance midpoint

Volumes and Capital Expenditures

Wellhead Volumes	3Q 2021	3Q 2021 Guidance Midpoint	2Q 2021	3Q 2020
Crude Oil and Condensate (MBod)	449.5	444.5	448.6	377.6
Natural Gas Liquids (MBbld)	157.9	140.0	138.5	140.1
Natural Gas (MMcfd)	1,422	1,410	1,445	1,190
Total Crude Oil Equivalent (MBoed)	844.4	819.5	828.0	716.0
Cash Capital Expenditures before Acquisitions ($MM)	935	1,000	972	499

From Ezra Yacob, Chief Executive Officer
"EOG delivered exceptionally strong earnings and free cash flow in the third quarter driven by our double premium investment program. We extended our track record of reliable execution with better than expected production, capital expenditures, operating costs and product prices.

"For the second time this year, we've increased our dividend rate. This quarter's 82 percent raise brings our indicated annual rate to $3.00 per share, doubling the dividend compared to last year. Our high-return investment program, first spurred by our shift to a premium investment standard in 2016 and followed by the double premium standard instituted last year, has positioned the company to step up our cash return to shareholders. The sizable increase in the regular dividend closes the gap between the prior dividend level and the significant improvement in EOG's profitability since 2016. It should also be taken as a signal of our confidence that we can continue improving in the future.

"We also continue to deliver on our other cash return priorities, with a second special dividend to be paid this year and an update to our share repurchase authorization. Share repurchases provide the opportunity to create additional value for stockholders when executed prudently and at the right time. We remain firmly committed to our long-term free cash flow priorities.

"EOG has never been in better shape. Our high-return business model is sustainable for the long term, underpinned by a deep inventory of double premium drilling locations. We also remain optimistic about the potential of new exploration plays to improve the overall quality of our inventory. Our financial and operational results, our world-class assets as well as our continued progress on exploration are a testament to the strength of EOG's underlying business, all driven by our talented employees and unique culture. We are well positioned to be one of the lowest cost and lowest emissions producers and generate superior cash returns, free cash flow growth and long-term shareholder value."

Third Quarter 2021 Financial Performance

Adjusted Earnings per Share 3Q 2021 vs 2Q 2021

Prices and Hedges
Natural gas, crude oil and NGL prices increased significantly in 3Q compared with 2Q, partially offset by an increase in cash paid for hedge settlements in 3Q of $100 million compared with 2Q.

Volumes
Total company crude oil production of 449,500 Bopd was above the high end of the guidance range due to better well productivity. Increased extraction of ethane boosted NGL production 14% higher than 2Q while contributing to slightly lower natural gas production, along with declines related to plant downtime in Trinidad. Total company equivalent volumes increased 2% compared with 2Q.

Per-Unit Costs
Per-unit cash operating costs in 3Q were 5% below the midpoint of the guidance range, primarily due to lower than forecasted lease and well and transportation costs. Compared with 2Q, per-unit cash operating costs increased 3% due to higher gathering and processing and general and administrative costs. In addition, per-unit taxes other than income increased compared with 2Q due to higher product prices.

Change in Cash 3Q 2021 vs 2Q 2021

Free Cash Flow
EOG generated discretionary cash flow (net cash provided by operating activities before exploration costs and changes in working capital) of $2.3 billion in 3Q. The company incurred $935 million of cash capital expenditures before acquisitions, resulting in $1.4 billion of free cash flow.

Capital Expenditures
Cash capital expenditures before acquisitions of $935 million were near the low end of the guidance range due to lower well costs from sustainable efficiency improvements. EOG was able to offset inflationary pressures with efficiency improvements in many areas. In particular, the application of "super-zipper" completion techniques, faster drilling times, lower-cost sand sourcing and the addition of infrastructure to procure lower-cost water all contributed to the overall cost reductions.

Third Quarter 2021 Operating Performance

Lease and Well
Per-unit LOE costs were $0.32 below the guidance mid-point due to lower water handling and compression costs. Per-unit LOE costs were $0.10 below 2Q due to overall efficiency improvements. Per- unit costs were in-line with 3Q 2020.

Transportation, Gathering and Processing
Per-unit transportation costs were below the guidance mid- point due to lower than expected NGL and oil transportation fees. Per-unit G&P costs increased from 2Q due to higher fuel prices while transportation costs were in-line with 2Q. Per-unit transportation and G&P costs increased 3% and 7%, respectively, compared with 3Q 2020 due to increased fuel prices and higher storage and terminal fees.

General and Administrative
Per-unit G&A costs were in line with the guidance midpoint. Per-unit G&A costs were above 2Q due to seasonally higher employee related costs. Per-unit G&A costs decreased from 3Q 2020 as increased production volumes more than offset increased employee related costs.

Depreciation, Depletion and Amortization
Per-unit DD&A costs were slightly below the guidance midpoint and declined 2% and 4% compared with 2Q 2021 and 3Q 2020, respectively, due to the addition of reserves from new wells at lower finding costs.

Free Cash Flow Allocation Actions

Declared $0.75 per Share Regular Dividend – 82% Increase to $3.00 per Share Indicated Annual Rate

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The Board of Directors today declared a regular dividend of $0.75 per share on EOG's Common Stock. The dividend is payable January 28, 2022 to stockholders of record as of January 14, 2022. The new dividend represents a $3.00 per share indicated annual rate, an 82% increase from the previous level. The annual cash commitment towards the dividend is $785 million higher and reflects EOG's low cost of supply, robust cash flow generation and strong balance sheet. A growing, sustainable dividend is the company's primary mode of returning cash to shareholders. EOG has a long track record of delivering against this objective as the company has never suspended or reduced its regular dividend.

$2.00 per Share Special Dividend
The Board of Directors today also declared a special dividend of $2.00 per share on EOG's Common Stock. The dividend is payable December 30, 2021 to stockholders of record as of December 15, 2021. EOG has now committed to return $2.7 billion of cash to stockholders in 2021, representing approximately 30 percent of expected 2021 discretionary cash flow.

Share Repurchase Authorization
In addition, the Board of Directors today updated EOG's share repurchase authorization to $5 billion. The updated authorization is consistent with EOG's long-standing cash flow priorities and complements existing avenues to return cash to shareholders through regular and special dividends. The repurchase authorization enables EOG to opportunistically increase per-share value for stockholders.

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Third Quarter 2021 Results vs Guidance

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(Unaudited)
Crude Oil and Condensate Volumes (MBod)	3Q 2021	3Q 2021 Guidance Midpoint	Variance	2Q 2021	1Q 2021	4Q 2020	3Q 2020
United States	448.3	443.5	4.8	446.9	428.7	442.4	376.6
Trinidad	1.2	1.0	0.2	1.7	2.2	2.3	1.0
Other International	0.0	0.0	0.0	0.0	0.1	0.1	0.0
Total	449.5	444.5	5.0	448.6	431.0	444.8	377.6
Natural Gas Liquids Volumes (MBbld)
Total	157.9	140.0	17.9	138.5	124.3	141.4	140.1
Natural Gas Volumes (MMcfd)
United States	1,210	1,200	10	1,199	1,100	1,075	1,008
Trinidad	212	210	2	233	217	192	151
Other International	0	0	0	13	25	25	31
Total	1,422	1,410	12	1,445	1,342	1,292	1,190
Total Crude Oil Equivalent Volumes (MBoed)	844.4	819.5	24.9	828.0	778.9	801.5	716.0
Total MMBoe	77.7	75.4	2.3	75.3	70.1	73.7	65.9
Benchmark Price
Oil (WTI) ($/Bbl)	70.55			66.06	57.80	42.67	40.94
Natural Gas (HH) ($/Mcf)	4.01			2.83	2.69	2.65	1.94
Crude Oil and Condensate - above (below) WTI ($/Bbl)
United States	0.33	0.30	0.03	0.10	0.27	(0.81)	(0.75)
Trinidad	(10.36)	(7.50)	(2.86)	(9.80)	(8.03)	(9.76)	(15.53)
Natural Gas Liquids - Realizations as % of WTI	53.5%	50.0%	3.5%	44.1%	48.5%	41.1%	35.0%
Natural Gas - above (below) NYMEX Henry Hub ($/Mcf)
United States	0.49	0.30	0.19	0.16	2.83	(0.36)	(0.45)
Natural Gas Realizations ($/Mcf)
Trinidad	3.39	3.35	0.04	3.37	3.38	3.57	2.35
Total Expenditures (GAAP) ($MM)	962			1,089	1,067	1,107	646
Capital Expenditures (non-GAAP) ($MM)	935	1,000	(65)	972	945	828	499
Operating Unit Costs ($/Boe)
Lease and Well	3.48	3.80	(0.32)	3.58	3.85	3.54	3.45
Transportation Costs	2.82	3.00	(0.18)	2.84	2.88	2.64	2.74
Gathering and Processing	1.87	1.90	(0.03)	1.70	1.98	1.62	1.74
General and Administrative	1.83	1.80	0.03	1.59	1.57	1.54	1.89
Cash Operating Costs	10.00	10.50	(0.50)	9.71	10.28	9.34	9.82
Depreciation, Depletion and Amortization	11.93	12.00	(0.07)	12.13	12.84	11.81	12.49
Expenses ($MM)
Exploration and Dry Hole	48	40	8	49	44	40	51
Impairment (GAAP)	82			44	44	143	79
Impairment (excluding certain impairments (non-GAAP))	69	85	(16)	43	43	57	52
Capitalized Interest	8	8	0	8	8	7	7
Net Interest	48	45	3	45	47	53	53
Taxes Other Than Income (% of Wellhead Revenue)	6.8%	7.0%	(0.2%)	6.9%	6.7%	5.1%	7.2%
Income Taxes
Effective Rate	23.4%	23.5%	(0.1%)	19.3%	23.2%	21.1%	19.2%
Deferred Ratio	(33%)	33%	(66%)	(45%)	(18%)	60%	330%

 

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Fourth Quarter and Full-Year 2021 Guidance²

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(Unaudited)
See "Endnotes" below for related discussion and definitions.	4Q 2021 Guidance Range			FY 2021 Guidance Range			2020 Actual	2019 Actual
Crude Oil and Condensate Volumes (MBod)
United States	442.0	-	450.0	441.5	-	443.5	408.1	455.5
Trinidad	0.5	-	1.5	1.4	-	1.6	1.0	0.6
Other International	0.0	-	0.0	0.0	-	0.0	0.1	0.1
Total	442.5	-	451.5	442.9	-	445.1	409.2	456.2
Natural Gas Liquids Volumes (MBbld)
Total	148.0	-	158.0	142.3	-	144.8	136.0	134.1
Natural Gas Volumes (MMcfd)
United States	1,285	-	1,385	1,199	-	1,225	1,040	1,069
Trinidad	185	-	215	212	-	219	180	260
Other International	0	-	0	9	-	10	32	37
Total	1,470	-	1,600	1,420	-	1,454	1,252	1,366
Crude Oil Equivalent Volumes (MBoed)
United States	804.2	-	838.8	783.6	-	792.5	717.5	767.8
Trinidad	31.3	-	37.3	36.7	-	38.1	30.9	44.0
Other International	0.0	-	0.0	1.5	-	1.7	5.4	6.2
Total	835.5	-	876.1	821.8	-	832.3	753.8	818.0
Benchmark Price
Oil (WTI) ($/Bbl)							39.40	57.04
Natural Gas (HH) ($/Mcf)							2.08	2.62
Crude Oil and Condensate Differentials - above (below) WTI3 ($/Bbl)
United States	0.20	-	1.20	0.30	-	0.60	(0.75)	0.70
Trinidad	(12.00)	-	(10.00)	(12.79)	-	(10.64)	(9.20)	(9.88)
Natural Gas Liquids - Realizations as % of WTI
Total	50%	-	60%	50%	-	53%	34.0%	28.1%
Natural Gas Differentials - above (below) NYMEX Henry Hub4 ($/Mcf)
United States	0.60	-	1.60	0.95	-	1.30	(0.47)	(0.40)
Natural Gas Realizations ($/Mcf)
Trinidad	3.20	-	3.70	3.34	-	3.46	2.57	2.72
Total Expenditures (GAAP) ($MM)							4,113	6,900
Capital Expenditures5 (non-GAAP) ($MM)	950	-	1,150	3,800	-	4,000	3,490	6,234
Operating Unit Costs ($/Boe)
Lease and Well	3.40	-	4.10	3.57	-	3.76	3.85	4.58
Transportation Costs	2.75	-	3.15	2.82	-	2.93	2.66	2.54
Gathering and Processing	1.80	-	2.00	1.83	-	1.89	1.66	1.60
General and Administrative	1.50	-	1.60	1.62	-	1.65	1.75	1.64
Cash Operating Costs	9.45	-	10.85	9.84	-	10.23	9.92	10.36
Depreciation, Depletion and Amortization	11.40	-	12.00	12.06	-	12.21	12.32	12.56
Expenses ($MM)
Exploration and Dry Hole	40	-	45	180	-	185	159	168
Impairment (GAAP)							2,100	518
Impairment (excluding certain impairments (non-GAAP))	100	-	140	257	-	297	232	243
Capitalized Interest	5	-	10	29	-	34	31	38
Net Interest	42	-	48	182	-	188	205	185
Taxes Other Than Income (% of Wellhead Revenue)	6.0%	-	8.0%	6.5%	-	7.5%	6.6%	6.9%
Income Taxes
Effective Rate	21%	-	26%	20%	-	25%	18.2%	22.9%
Deferred Ratio	5%	-	20%	(20%)	-	(5%)	54.8%	107.4%

 

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Third Quarter 2021 Results Webcast
Friday, November 5, 2021, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year.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)	The 2022 dividend amount reflects the indicated annual rate of the quarterly dividend declared on November 4, 2021.
2)	The forecast items for the fourth quarter and full year 2021 set forth above for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, 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.
3)	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.
4)	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.
5)	The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.

 

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

This press release may include forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward‐looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward‐looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet goals or ambitions with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward‐looking statements. Forward‐looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward‐looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward‐looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward‐looking, non‐GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward‐looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward‐looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward‐looking, non‐GAAP financial measures to the respective most directly comparable forward‐looking GAAP financial measures. Management believes these forward‐looking, non‐GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward‐looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward‐looking statements include, among others:

• the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
• the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
• the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
• the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, natural gas liquids, and natural gas;
• security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
• the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
• the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
• the impact of, and changes in, government policies, laws and regulations, including any changes or other actions which may result from the recent U.S. elections and change in U.S. administration and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and  access to and use of water;  laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and  gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
• EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
• the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
• competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
• the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
• weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
• the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
• EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
• the extent to which EOG is successful in its completion of planned asset dispositions;
• the extent and effect of any hedging activities engaged in by EOG;
• the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
• the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
• geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
• the use of competing energy sources and the development of alternative energy sources;
• the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
• acts of war and terrorism and responses to these acts; and
• the other factors described under ITEM 1A, Risk Factors, of EOG's Annual Report on Form 10‐K for the fiscal year ended December 31, 2020 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10‐Q or Current Reports on Form 8‐K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on  Form 10‐K for the fiscal year ended December 31, 2020, available from EOG at P.O. Box 4362, Houston, Texas 77210‐4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non‐GAAP financial measures can be found on the EOG website at www.eogresources.com.

Income Statements

In millions of USD, except share data (in millions) and per share data (Unaudited)
	3Q 2021			2Q 2021			3Q 2020			YTD 2021			YTD 2020
Operating Revenues and Other
Crude Oil and Condensate	2,929			2,699			1,395			7,879			4,075
Natural Gas Liquids	548			367			185			1,229			439
Natural Gas	568			404			184			1,597			535
Gains (Losses) on Mark-to-Market      Commodity Derivative Contracts	(494)			(427)			(4)			(1,288)			1,075
Gathering, Processing and Marketing	1,186			1,022			539			3,056			1,940
Gains (Losses) on Asset Dispositions, Net	1			51			(71)			46			(41)
Other, Net	27			23			18			79			44
Total	4,765			4,139			2,246			12,598			8,067
Operating Expenses
Lease and Well	270			270			227			810			802
Transportation Costs	219			214			180			635			540
Gathering and Processing Costs	145			128			115			412			340
Exploration Costs	44			35			38			112			105
Dry Hole Costs	4			13			13			28			13
Impairments	82			44			79			170			1,957
Marketing Costs	1,184			991			523			3,013			2,077
Depreciation, Depletion and Amortization	927			914			823			2,741			2,530
General and Administrative	142			120			125			372			371
Taxes Other Than Income	277			239			126			731			364
Total	3,294			2,968			2,249			9,024			9,099
Operating Income (Loss)	1,471			1,171			(3)			3,574			(1,032)
Other Income (Expense), Net	6			(2)			3			—			17
Income (Loss) Before Interest Expense      and Income Taxes	1,477			1,169			—			3,574			(1,015)
Interest Expense, Net	48			45			53			140			152
Income (Loss) Before Income Taxes	1,429			1,124			(53)			3,434			(1,167)
Income Tax Provision (Benefit)	334			217			(11)			755			(225)
Net Income (Loss)	1,095			907			(42)			2,679			(942)
Dividends Declared per Common Share	0.4125			1.4125			0.3750			2.2375			1.1250
Net Income (Loss) Per Share
Basic	1.88			1.56			(0.07)			4.62			(1.63)
Diluted	1.88			1.55			(0.07)			4.59			(1.63)
Average Number of Common Shares
Basic	581			580			579			580			579
Diluted	584			584			579			584			579

 

Wellhead Volumes and Prices

(Unaudited)
	3Q 2021			3Q2020			% Change			2Q 2021			YTD 2021			YTD 2020			% Change
Crude Oil and Condensate Volumes      (MBbld) (A)
United States	448.3			376.6			19	%		446.9			441.3			396.6			11	%
Trinidad	1.2			1.0			20	%		1.7			1.7			0.5			240	%
Other International (B)	—			—						—			0.1			0.2			-50	%
Total	449.5			377.6			19	%		448.6			443.1			397.3			12	%
Average Crude Oil and Condensate Prices      ($/Bbl) (C)
United States	70.88			40.19			76	%		66.16			65.18			37.45			74	%
Trinidad	60.19			25.41			137	%		56.26			54.33			26.35			106	%
Other International (B)	—			25.29			-100	%		55.56			42.36			45.09			-6	%
Composite	70.85			40.15			76	%		66.12			65.14			37.44			74	%
Natural Gas Liquids Volumes (MBbld) (A)
United States	157.9			140.1			13	%		138.5			140.4			134.2			5	%
Total	157.9			140.1			13	%		138.5			140.4			134.2			5	%
Average Natural Gas Liquids Prices       ($/Bbl) (C)
United States	37.72			14.34			163	%		29.15			32.07			11.95			168	%
Composite	37.72			14.34			163	%		29.15			32.07			11.95			168	%
Natural Gas Volumes (MMcfd) (A)
United States	1,210			1,008			20	%		1,199			1,170			1,029			14	%
Trinidad	212			151			40	%		233			221			175			26	%
Other International (B)	—			31			-100	%		13			12			34			-65	%
Total	1,422			1,190			19	%		1,445			1,403			1,238			13	%
Average Natural Gas Prices ($/Mcf) (C)
United States	4.50			1.49			203	%		2.99			4.30			1.38			213	%
Trinidad	3.39			2.35			44	%		3.37			3.38			2.20			53	%
Other International (B)	—			4.73			-100	%		5.69			5.67			4.45			27	%
Composite	4.34			1.68			158	%		3.07			4.17			1.58			164	%
Crude Oil Equivalent Volumes (MBoed) (D)
United States	807.9			684.7			18	%		785.2			776.8			702.3			11	%
Trinidad	36.5			26.2			39	%		40.6			38.5			29.8			29	%
Other International (B)	—			5.1			-100	%		2.2			2.0			5.7			-65	%
Total	844.4			716.0			18	%		828.0			817.3			737.8			11	%
Total MMBoe (D)	77.7			65.9			18	%		75.3			223.1			202.2			10	%

(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 September 30, 2021).

(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)
	September 30,			December 31,
	2021			2020
Current Assets
Cash and Cash Equivalents	4,293			3,329
Accounts Receivable, Net	2,154			1,522
Inventories	521			629
Assets from Price Risk Management Activities	18			65
Income Taxes Receivable	—			23
Other	363			294
Total	7,349			5,862
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	67,024			64,793
Other Property, Plant and Equipment	4,694			4,479
Total Property, Plant and Equipment	71,718			69,272
Less:  Accumulated Depreciation, Depletion and Amortization	(43,173)			(40,673)
Total Property, Plant and Equipment, Net	28,545			28,599
Deferred Income Taxes	14			2
Other Assets	1,264			1,342
Total Assets	37,172			35,805
Current Liabilities
Accounts Payable	1,972			1,681
Accrued Taxes Payable	492			206
Dividends Payable	240			217
Liabilities from Price Risk Management Activities	238			—
Current Portion of Long-Term Debt	38			781
Current Portion of Operating Lease Liabilities	250			295
Other	254			280
Total	3,484			3,460
Long-Term Debt	5,079			5,035
Other Liabilities	2,214			2,149
Deferred Income Taxes	4,630			4,859
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 585,361,866      Shares Issued at September 30, 2021 and 583,694,850 Shares Issued at       December 31, 2020	206			206
Additional Paid in Capital	6,058			5,945
Accumulated Other Comprehensive Loss	(13)			(12)
Retained Earnings	15,542			14,170
Common Stock Held in Treasury, 371,249 Shares at September 30, 2021 and       124,265 Shares at December 31, 2020	(28)			(7)
Total Stockholders' Equity	21,765			20,302
Total Liabilities and Stockholders' Equity	37,172			35,805

 

Cash Flows Statements

In millions of USD (Unaudited)
	3Q 2021			3Q 2020			2Q 2021			YTD 2021			YTD 2020
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided      by Operating Activities:
Net Income (Loss)	1,095			(42)			907			2,679			(942)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	927			823			914			2,741			2,530
Impairments	82			79			44			170			1,957
Stock-Based Compensation Expenses	51			33			31			117			113
Deferred Income Taxes	(111)			(33)			(97)			(244)			(241)
(Gains) Losses on Asset Dispositions, Net	(1)			71			(51)			(46)			41
Other, Net	2			2			6			15			2
Dry Hole Costs	4			13			13			28			13
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	494			4			427			1,288			(1,075)
Net Cash Received from (Payments for) Settlements       of Commodity Derivative Contracts	(293)			275			(193)			(516)			999
Other, Net	7			(1)			—			8			(1)
Changes in Components of Working Capital and Other      Assets and Liabilities
Accounts Receivable	(145)			(260)			(186)			(639)			931
Inventories	(6)			7			37			95			92
Accounts Payable	(68)			(37)			11			115			(1,222)
Accrued Taxes Payable	206			73			(163)			286			12
Other Assets	167			162			(119)			(55)			415
Other Liabilities	(260)			51			32			(317)			(13)
Changes in Components of Working Capital Associated      with Investing Activities	45			(6)			(54)			(100)			276
Net Cash Provided by Operating Activities	2,196			1,214			1,559			5,625			3,887
Investing Cash Flows
Additions to Oil and Gas Properties	(846)			(469)			(968)			(2,689)			(2,459)
Additions to Other Property, Plant and Equipment	(50)			(18)			(55)			(147)			(165)
Proceeds from Sales of Assets	8			146			141			154			189
Changes in Components of Working Capital Associated       with Investing Activities	(45)			6			54			100			(276)
Net Cash Used in Investing Activities	(933)			(335)			(828)			(2,582)			(2,711)
Financing Cash Flows
Long-Term Debt Borrowings	—			—			—			—			1,484
Long-Term Debt Repayments	—			—			—			(750)			(1,000)
Dividends Paid	(820)			(217)			(239)			(1,278)			(601)
Treasury Stock Purchased	(21)			(10)			(2)			(33)			(15)
Proceeds from Stock Options Exercised and Employee       Stock Purchase Plan	—			—			9			9			8
Debt Issuance Costs	—			—			—			—			(3)
Repayment of Finance Lease Liabilities	(9)			(5)			(9)			(27)			(13)
Net Cash Used in Financing Activities	(850)			(232)			(241)			(2,079)			(140)
Effect of Exchange Rate Changes on Cash	—			2			2			—			2
Increase in Cash and Cash Equivalents	413			649			492			964			1,038
Cash and Cash Equivalents at Beginning of Period	3,880			2,417			3,388			3,329			2,028
Cash and Cash Equivalents at End of Period	4,293			3,066			3,880			4,293			3,066

 

Non-GAAP Financial Measures

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

A reconciliation of each of these measures to their most directly comparable GAAP financial measure 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 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.
	3Q 2021
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (GAAP)	1,429			(334)			1,095			1.88
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	494			(108)			386			0.65
Net Cash Payments for Settlements of Commodity Derivative Contracts	(293)			64			(229)			(0.39)
Less: Gains on Asset Dispositions, Net	(1)			—			(1)			—
Add: Certain Impairments	13			—			13			0.02
Adjustments to Net Income	213			(44)			169			0.28
Adjusted Net Income (Non-GAAP)	1,642			(378)			1,264			2.16
Average Number of Common Shares (GAAP)
Basic										581
Diluted										584
Average Number of Common Shares (Non-GAAP)
Basic										581
Diluted										584
Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	3Q 2020
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Loss (GAAP)	(53)			11			(42)			(0.07)
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	4			—			4			0.01
Net Cash Received from Settlements of Commodity Derivative Contracts	275			(60)			215			0.37
Add: Losses on Asset Dispositions, Net	71			(16)			55			0.09
Add: Certain Impairments	27			(7)			20			0.03
Adjustments to Net Loss	377			(83)			294			0.50
Adjusted Net Income (Non-GAAP)	324			(72)			252			0.43
Average Number of Common Shares (GAAP)
Basic										579
Diluted										579
Average Number of Common Shares (Non-GAAP)
Basic										579
Diluted										581
Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	2Q 2021
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (GAAP)	1,124			(217)			907			1.55
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	427			(93)			334			0.58
Net Cash Payments for Settlements of Commodity Derivative Contracts	(193)			42			(151)			(0.26)
Less: Gains on Asset Dispositions, Net	(51)			17			(34)			(0.06)
Add: Certain Impairments	1			—			1			—
Less: Tax Benefits Related to Exiting Canada Operations	—			(45)			(45)			(0.08)
Adjustments to Net Income	184			(79)			105			0.18
Adjusted Net Income (Non-GAAP)	1,308			(296)			1,012			1.73
Average Number of Common Shares (GAAP)
Basic										580
Diluted										584
Average Number of Common Shares (Non-GAAP)
Basic										580
Diluted										584
Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	YTD 2021
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (GAAP)	3,434			(755)			2,679			4.59
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	1,288			(282)			1,006			1.72
Net Cash Payments for Settlements of Commodity Derivative Contracts	(516)			113			(403)			(0.69)
Less: Gains on Asset Dispositions, Net	(46)			16			(30)			(0.05)
Add: Certain Impairments	15			—			15			0.03
Less: Tax Benefits Related to Exiting Canada Operations	—			(45)			(45)			(0.08)
Adjustments to Net Income	741			(198)			543			0.93
Adjusted Net Income (Non-GAAP)	4,175			(953)			3,222			5.52
Average Number of Common Shares (GAAP)
Basic										580
Diluted										584
Average Number of Common Shares (Non-GAAP)
Basic										580
Diluted										584
Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	YTD 2020
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Loss (GAAP)	(1,167)			225			(942)			(1.63)
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(1,075)			236			(839)			(1.45)
Net Cash Received from Settlements of Commodity Derivative Contracts	999			(219)			780			1.35
Add: Losses on Asset Dispositions, Net	41			(9)			32			0.06
Add: Certain Impairments	1,782			(374)			1,408			2.43
Adjustments to Net Loss	1,747			(366)			1,381			2.39
Adjusted Net Income (Non-GAAP)	580			(141)			439			0.76
Average Number of Common Shares (GAAP)
Basic										579
Diluted										579
Average Number of Common Shares (Non-GAAP)
Basic										579
Diluted										580
Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	FY 2020
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Loss (GAAP)	(739)			134			(605)			(1.04)
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(1,145)			251			(894)			(1.55)
Net Cash Received from Settlements of Commodity Derivative Contracts	1,071			(235)			836			1.44
Add: Losses on Asset Dispositions, Net	47			(10)			37			0.06
Add: Certain Impairments	1,868			(392)			1,476			2.55
Adjustments to Net Loss	1,841			(386)			1,455			2.50
Adjusted Net Income (Non-GAAP)	1,102			(252)			850			1.46
Average Number of Common Shares (GAAP)
Basic										579
Diluted										579
Average Number of Common Shares (Non-GAAP)
Basic										579
Diluted										581

 

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)
2Q 2021 Adjusted Net Income per Share (Non-GAAP)				1.73
Realized Price
3Q 2021 Composite Average Wellhead Revenue per Boe	52.07
Less:  2Q 2021 Composite Average Welhead Revenue per Boe	(46.07)
Subtotal	6.00
Multiplied by: 3Q 2021 Crude Oil Equivalent Volumes (MMBoe)	77.7
Total Change in Revenue	466
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	(107)
Change in Net Income	359
Change in Diluted Earnings per Share				0.61
Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts
3Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative       Contracts	(293)
Less:  Income Tax Benefit (Cost)	64
After Tax - (a)	(229)
2Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative        Contracts	(193)
Less:  Income Tax Benefit (Cost)	42
After Tax - (b)	(151)
Change in Net Income - (a) - (b)	(78)
Change in Diluted Earnings per Share				(0.13)
Wellhead Volumes
3Q 2021 Crude Oil Equivalent Volumes (MMBoe)	77.7
Less:  2Q 2021 Crude Oil Equivalent Volumes (MMBoe)	(75.3)
Subtotal	2.3
Multiplied by:  3Q 2021 Composite Average Margin per Boe (Including Total      Exploration Costs) (Non-GAAP) (refer to "Revenues, Costs and Margins Per Barrel of       Oil Equivalent" schedule)	24.45
Change in Revenue	57
Less:  Income Tax Benefit (Cost) Imputed (based on 23%)	(13)
Change in Net Income	44
Change in Diluted Earnings per Share				0.08
Operating Cost per Boe
2Q 2021 Total Operating Cost per Boe (including Total Exploration Costs) (Non-GAAP)      (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	26.82
Less:  3Q 2021 Total Operating Cost per Boe (including Total Exploration Costs) (Non-      GAAP) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"       schedule)	(27.62)
Subtotal	(0.8)
Multiplied by:  3Q 2021 Crude Oil Equivalent Volumes (MMBoe)	77.7
Change in Before-Tax Net Income	(62)
Less:  Income Tax Benefit (Cost) Imputed (based on 23%)	14
Change in Net Income	(48)
Change in Diluted Earnings per Share				(0.08)
Other Items				(0.05)
3Q 2021 Adjusted Net Income per Share (Non-GAAP)				2.16
3Q 2021 Average Number of Common Shares (Non-GAAP) - Diluted	584

 

Discretionary Cash Flow and Free Cash Flow

In millions of USD (Unaudited)
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), 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 Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below.  EOG management uses this information for comparative purposes within the industry.
	3Q 2021			2Q 2021			3Q 2020			YTD 2021			YTD 2020
Net Cash Provided by Operating Activities (GAAP)	2,196			1,559			1,214			5,625			3,887
Adjustments:
Exploration Costs (excluding Stock-Based      Compensation Expenses)	39			29			37			96			90
Changes in Components of Working Capital and      Other Assets and Liabilities
Accounts Receivable	145			186			260			639			(931)
Inventories	6			(37)			(7)			(95)			(92)
Accounts Payable	68			(11)			37			(115)			1,222
Accrued Taxes Payable	(206)			163			(73)			(286)			(12)
Other Assets	(167)			119			(162)			55			(415)
Other Liabilities	260			(32)			(51)			317			13
Changes in Components of Working Capital      Associated with Investing Activities	(45)			54			6			100			(276)
Other Non-Current Income Taxes - Net Receivable	—			—			—			—			113
Discretionary Cash Flow (Non-GAAP)	2,296			2,030			1,261			6,336			3,599
Discretionary Cash Flow (Non-GAAP) – Percentage      Increase	82	%								76	%
Discretionary Cash Flow (Non-GAAP)	2,296			2,030			1,261			6,336			3,599
Less:
Total Cash Capital Expenditures Before Acquisitions       (Non-GAAP) (a)	(935)			(972)			(499)			(2,852)			(2,662)
Free Cash Flow (Non-GAAP)	1,361			1,058			762			3,484			937
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP):
	3Q 2021			2Q 2021			3Q 2020			YTD 2021			YTD 2020
Total Expenditures (GAAP)	962			1,089			646			3,118			3,006
Less:
Asset Retirement Costs	(8)			(31)			(44)			(56)			(69)
Non-Cash Expenditures of Other Property, Plant and      Equipment	—			—			—			—			—
Non-Cash Acquisition Costs of Unproved Properties	(15)			—			(80)			(37)			(128)
Non-Cash Finance Leases	—			—			—			(74)			(73)
Acquisition Costs of Proved Properties	(4)			(86)			(23)			(99)			(74)
Total Cash Capital Expenditures Before Acquisitions      (Non-GAAP)	935			972			499			2,852			2,662

 

Discretionary Cash Flow and Free Cash Flow (Continued)
In millions of USD (Unaudited)
	FY 2020			FY 2019			FY 2018			FY 2017
Net Cash Provided by Operating Activities (GAAP)	5,008			8,163			7,769			4,265
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	126			113			125			122
Changes in Components of Working Capital and Other Assets and       Liabilities
Accounts Receivable	(467)			92			368			392
Inventories	(123)			(90)			395			175
Accounts Payable	795			(169)			(439)			(324)
Accrued Taxes Payable	49			(40)			92			64
Other Assets	(325)			(358)			125			659
Other Liabilities	(8)			57			(11)			90
Changes in Components of Working Capital Associated with      Investing and Financing Activities	(75)			115			(301)			(90)
Other Non-Current Income Taxes - Net (Payable) Receivable	113			239			149			(513)
Discretionary Cash Flow (Non-GAAP)	5,093			8,122			8,272			4,840
Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease)	-37	%		-2	%		71	%		76	%
Discretionary Cash Flow (Non-GAAP)	5,093			8,122			8,272			4,840
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)	(3,490)			(6,234)			(6,172)			(4,228)
Free Cash Flow (Non-GAAP)	1,603			1,888			2,100			612
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP):
Total Expenditures (GAAP)	4,113			6,900			6,706			4,613
Less:
Asset Retirement Costs	(117)			(186)			(70)			(56)
Non-Cash Expenditures of Other Property, Plant and Equipment	—			(2)			(1)			—
Non-Cash Acquisition Costs of Unproved Properties	(197)			(98)			(291)			(256)
Non-Cash Finance Leases	(174)			—			(48)			—
Acquisition Costs of Proved Properties	(135)			(380)			(124)			(73)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	3,490			6,234			6,172			4,228

 

Discretionary Cash Flow and Free Cash Flow (Continued)
In millions of USD (Unaudited)
	FY 2016			FY 2015			FY 2014			FY 2013			FY 2012
Net Cash Provided by Operating Activities (GAAP)	2,359			3,595			8,649			7,329			5,237
Adjustments:
Exploration Costs (excluding Stock-Based Compensation      Expenses)	104			124			158			134			158
Changes in Components of Working Capital and Other       Assets and Liabilities
Accounts Receivable	233			(641)			(85)			24			179
Inventories	(171)			(58)			162			(53)			157
Accounts Payable	74			1,409			(544)			(179)			17
Accrued Taxes Payable	(93)			(12)			(16)			(75)			(78)
Other Assets	41			(118)			14			110			119
Other Liabilities	16			66			(75)			20			(36)
Changes in Components of Working Capital Associated        with Investing and Financing Activities	156			(500)			103			51			(74)
Excess Tax Benefits from Stock-Based Compensation	30			26			99			56			67
Discretionary Cash Flow (Non-GAAP)	2,749			3,891			8,465			7,417			5,746
Discretionary Cash Flow (Non-GAAP) - Percentage Increase      (Decrease)	-29	%		-54	%		14	%		29	%
Discretionary Cash Flow (Non-GAAP)	2,749			3,891			8,465			7,417			5,746
Less:
Total Cash Capital Expenditures Before Acquisitions       (Non-GAAP) (a)	(2,706)			(4,682)			(8,292)			(7,102)			(7,540)
Free Cash Flow (Non-GAAP)	43			(791)			173			315			(1,794)
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP):
Total Expenditures (GAAP)	6,554			5,216			8,632			7,361			7,754
Less:
Asset Retirement Costs	20			(53)			(196)			(134)			(127)
Non-Cash Expenditures of Other Property, Plant and       Equipment	(17)			—			—			—			(66)
Non-Cash Acquisition Costs of Unproved Properties	(3,102)			—			(5)			(5)			(20)
Acquisition Costs of Proved Properties	(749)			(481)			(139)			(120)			(1)
Total Cash Capital Expenditures Before Acquisitions (Non-      GAAP)	2,706			4,682			8,292			7,102			7,540

 

Total Expenditures

In millions of USD (Unaudited)
	3Q 2021			3Q 2020			FY 2020			FY 2019			FY 2018			FY 2017
Exploration and Development Drilling	653			378			2,664			4,951			4,935			3,132
Facilities	100			38			347			629			625			575
Leasehold Acquisitions	90			88			265			276			488			427
Property Acquisitions	4			23			135			380			124			73
Capitalized Interest	9			7			31			38			24			27
Subtotal	856			534			3,442			6,274			6,196			4,234
Exploration Costs	44			38			146			140			149			145
Dry Hole Costs	4			13			13			28			5			5
Exploration and Development Expenditures	904			585			3,601			6,442			6,350			4,384
Asset Retirement Costs	8			44			117			186			70			56
Total Exploration and Development Expenditures	912			629			3,718			6,628			6,420			4,440
Other Property, Plant and Equipment	50			17			395			272			286			173
Total Expenditures	962			646			4,113			6,900			6,706			4,613

 

EBITDAX and Adjusted EBITDAX

In millions of USD (Unaudited)
The following table adjusts the reported Net Income (Loss) (GAAP) to 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 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.
	3Q 2021		3Q 2020			YTD 2021			YTD 2020
Net Income (Loss) (GAAP)	1,095		(42)			2,679			(942)
Adjustments:
Interest Expense, Net	48		53			140			152
Income Tax Provision (Benefit)	334		(11)			755			(225)
Depreciation, Depletion and Amortization	927		823			2,741			2,530
Exploration Costs	44		38			112			105
Dry Hole Costs	4		13			28			13
Impairments	82		79			170			1,957
EBITDAX (Non-GAAP)	2,534		953			6,625			3,590
(Gains) Losses on MTM Commodity Derivative Contracts	494		4			1,288			(1,075)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(293)		275			(516)			999
(Gains) Losses on Asset Dispositions, Net	(1)		71			(46)			41
Adjusted EBITDAX (Non-GAAP)	2,734		1,303			7,351			3,555
Adjusted EBITDAX (Non-GAAP) - Percentage Increase	110	%				107	%
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.
	September 30, 2021			June 30, 2021			March 31, 2021
Total Stockholders' Equity - (a)	21,765			20,881			20,762
Current and Long-Term Debt (GAAP) - (b)	5,117			5,125			5,133
Less: Cash	(4,293)			(3,880)			(3,388)
Net Debt (Non-GAAP) - (c)	824			1,245			1,745
Total Capitalization (GAAP) - (a) + (b)	26,882			26,006			25,895
Total Capitalization (Non-GAAP) - (a) + (c)	22,589			22,126			22,507
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	19.0	%		19.7	%		19.8	%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	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			6,660
Less: Cash	(1,600)			(1,049)			(780)			(668)			(719)
Net Debt (Non-GAAP) - (c)	5,386			5,937			6,206			6,318			5,941
Total Capitalization (GAAP) - (a) + (b)	20,968			18,784			19,043			19,391			19,603
Total Capitalization (Non-GAAP) - (a) + (c)	19,368			17,735			18,263			18,723			18,884
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	33.3	%		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	%		31.5	%

 

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.
	2020			2019			2018			2017			2016			2015			2014
Total Costs Incurred in Exploration and      Development Activities (GAAP)	3,718			6,628			6,420			4,440			6,445			4,928			7,905
Less:  Asset Retirement Costs	(117)			(186)			(70)			(56)			20			(53)			(196)
Non-Cash Acquisition Costs of      Unproved Properties	(197)			(98)			(291)			(256)			(3,102)			—			—
Acquisition Costs of Proved Properties	(135)			(380)			(124)			(73)			(749)			(481)			(139)
Total Exploration and Development     Expenditures for Drilling Only (Non-     GAAP) - (a)	3,269			5,964			5,935			4,055			2,614			4,394			7,570
Total Costs Incurred in Exploration and      Development Activities (GAAP)	3,718			6,628			6,420			4,440			6,445			4,928			7,905
Less:  Asset Retirement Costs	(117)			(186)			(70)			(56)			20			(53)			(196)
Non-Cash Acquisition Costs of      Unproved Properties	(197)			(98)			(291)			(256)			(3,102)			—			—
Non-Cash Acquisition Costs of      Proved Properties	(15)			(52)			(71)			(26)			(732)			—			—
Total Exploration and Development      Expenditures (Non-GAAP) - (b)	3,389			6,292			5,988			4,102			2,631			4,875			7,709
Net Proved Reserve Additions From All      Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	(278)			(60)			35			154			(101)			(574)			52
Revisions Other Than Price	(89)			—			(40)			48			253			107			49
Purchases in Place	10			17			12			2			42			56			14
Extensions, Discoveries and Other Additions - (d)	564			750			670			421			209			246			519
Total Proved Reserve Additions - (e)	207			707			677			625			403			(165)			634
Sales in Place	(31)			(5)			(11)			(21)			(168)			(4)			(36)
Net Proved Reserve Additions From All Sources	176			702			666			604			235			(169)			598
Production	285			301			265			224			206			210			220
	2020			2019			2018			2017			2016			2015			2014
Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	5.79			7.95			8.86			9.64			12.51			17.87			14.58
All-in Total, Net of Revisions - (b / e)	16.32			8.90			8.85			6.56			6.52			(29.63)			12.16
All-in Total, Excluding Revisions Due to Price -  (b / ( e - c))	6.98			8.21			9.33			8.71			5.22			11.91			13.25

 

Definitions
$/Boe	U.S. Dollars per barrel of oil equivalent
MMBoe	Million barrels of oil equivalent

 

Financial Commodity Derivative Contracts

EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.
Presented below is a comprehensive summary of EOG's financial commodity derivative contracts as of October 29, 2021.
Crude Oil Financial Price Swap Contracts
				Contracts Sold
Period		Settlement Index		Volume (MBbld)			Weighted Average Price ($/Bbl)
January 2021 (closed)		NYMEX WTI		151			$	50.06
February - March 2021 (closed)		NYMEX WTI		201			51.29
April - June 2021 (closed)		NYMEX WTI		150			51.68
July - September 2021 (closed)		NYMEX WTI		150			52.71
January - March 2022		NYMEX WTI		140			65.58
April - June 2022		NYMEX WTI		140			65.62
July - September 2022		NYMEX WTI		140			65.59
October - December 2022		NYMEX WTI		140			65.68
January - March 2023		NYMEX WTI		150			67.92
April - June 2023		NYMEX WTI		120			67.79
July - September 2023		NYMEX WTI		9			68.00

 

Crude Oil Basis Swap Contracts
				Contracts Sold
Period		Settlement Index		Volume (MBbld)			Weighted Average Price Differential ($/Bbl)
February 2021 (closed)		NYMEX WTI Roll Differential (1)		30			$	0.11
March - November 2021 (closed)		NYMEX WTI Roll Differential (1)		125			0.17
December 2021		NYMEX WTI Roll Differential (1)		125			0.17
January - 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.

 

NGL Financial Price Swap Contracts
				Contracts Sold
Period		Settlement Index		Volume (MBbld)			Weighted Average Price ($/Bbl)
January - October 2021 (closed)		Mont Belvieu Propane (non-Tet)		15			$	29.44
November - December 2021		Mont Belvieu Propane (non-Tet)		15			29.44

 

Natural Gas Financial Price Swap Contracts
				Contracts Sold							Contracts Purchased
Period		Settlement Index		Volume (MMBtud in thousands)			Weighted Average Price ($/MMBtu)				Volume (MMBtud in thousands)			Weighted Average Price ($/MMBtu)
January - March 2021 (closed)		NYMEX Henry Hub		500			$	2.99			500			$	2.43
April - September 2021      (closed)		NYMEX Henry Hub		500			2.99				570			2.81
October - November 2021      (closed)		NYMEX Henry Hub		500			2.99				500			2.83
December 2021		NYMEX Henry Hub		500			2.99				500			2.83
January - December 2022      (closed) (1)		NYMEX Henry Hub		20			2.75				—			—
January - 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				—			—
April - September 2021      (closed)		JKM		70			6.65				—			—

(1)	In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of its 2022 natural gas price swap contracts which were open at that time.  EOG received net cash of $0.6 million for the settlement of these contracts.

 

Natural Gas Basis Swap Contracts
				Contracts Sold
Period		Settlement Index		Volume (MMBtud in thousands)			Weighted Average Price ($/MMBtu)
January - December 2022		NYMEX Henry Hub HSC Differential (1)		140			$	0.01
January - December 2023		NYMEX Henry Hub HSC Differential (1)		65			0.00
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
JKM	Japan Korea Marker
MBbld	Thousand barrels per day
MMBtu	Million British Thermal Units
MMBtud	Million British Thermal Units per day
NGL	Natural Gas Liquids
NYMEX	New York Mercantile Exchange
WTI	West Texas Intermediate

 

Direct After-Tax Rate of Return

The calculation of EOG's direct after-tax rate of return (ATROR) with 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.
	2020			2019			2018			2017
Interest Expense, Net (GAAP)	205			185			245
Tax Benefit Imputed (based on 21%)	(43)			(39)			(51)
After-Tax Net Interest Expense (Non-GAAP) - (a)	162			146			194
Net Income (Loss) (GAAP) - (b)	(605)			2,735			3,419
Adjustments to Net Income (Loss), Net of Tax (See Below Detail) (1)	1,455			158			(201)
Adjusted Net Income (Non-GAAP) - (c)	850			2,893			3,218
Total Stockholders' Equity - (d)	20,302			21,641			19,364			16,283
Average Total Stockholders' Equity * - (e)	20,972			20,503			17,824
Current and Long-Term Debt (GAAP) - (f)	5,816			5,175			6,083			6,387
Less:  Cash	(3,329)			(2,028)			(1,556)			(834)
Net Debt (Non-GAAP) - (g)	2,487			3,147			4,527			5,553
Total Capitalization (GAAP) - (d) + (f)	26,118			26,816			25,447			22,670
Total Capitalization (Non-GAAP) - (d) + (g)	22,789			24,788			23,891			21,836
Average Total Capitalization (Non-GAAP) * - (h)	23,789			24,340			22,864
Return on Capital Employed (ROCE)
GAAP Net Income (Loss) - [(a) + (b)] / (h)	(1.9)	%		11.8	%		15.8	%
Non-GAAP Adjusted Net Income - [(a) + (c)] / (h)	4.3	%		12.5	%		14.9	%
Return on Equity (ROE)
GAAP Net Income (Loss) - (b) / (e)	(2.9)	%		13.3	%		19.2	%
Non-GAAP Adjusted Net Income - (c) / (e)	4.1	%		14.1	%		18.1	%
* Average for the current and immediately preceding year
(1) Detail of adjustments to Net Income (Loss) (GAAP):
				Before Tax			Income Tax Impact			After Tax
Year Ended December 31, 2020
Adjustments:
Add:  Mark-to-Market Commodity Derivative Contracts Impact				(74)			16			(58)
Add:  Impairments of Certain Assets				1,868			(392)			1,476
Add:  Net Losses on Asset Dispositions				47			(10)			37
Total				1,841			(386)			1,455
Year Ended December 31, 2019
Adjustments:
Add:  Mark-to-Market Commodity Derivative Contracts Impact				51			(11)			40
Add:  Impairments of Certain Assets				275			(60)			215
Less:  Net Gains on Asset Dispositions				(124)			27			(97)
Total				202			(44)			158
Year Ended December 31, 2018
Adjustments:
Add:  Mark-to-Market Commodity Derivative Contracts Impact				(93)			20			(73)
Add:  Impairments of Certain Assets				153			(34)			119
Less:  Net Gains on Asset Dispositions				(175)			38			(137)
Less:  Tax Reform Impact				—			(110)			(110)
Total				(115)			(86)			(201)

 

ROCE & ROE
In millions of USD, except ratio data (Unaudited)
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)
GAAP Net Income (Loss) - [(a) + (b)] / (h)					13.4	%		-4.8	%		-21.6	%
Return on Equity (ROE)
GAAP Net Income (Loss) - (b) / (e)					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
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
Average Total Stockholders' Equity* - (e)					16,566			14,352			12,963
Current and Long-Term Debt (GAAP) - (f)					5,906			5,909			6,312
Less:  Cash					(2,087)			(1,318)			(876)
Net Debt (Non-GAAP) - (g)					3,819			4,591			5,436
Total Capitalization (GAAP) - (d) + (f)					23,619			21,327			19,597
Total Capitalization (Non-GAAP) - (d) + (g)					21,532			20,009			18,721
Average Total Capitalization (Non-GAAP)* - (h)					20,771			19,365			17,878
Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)					14.7	%		12.1	%		4.0	%
Return on Equity (ROE)
GAAP Net Income - (b) / (e)					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.
	3Q 2021			2Q 2021			1Q 2021			4Q 2020			3Q 2020
Volume - Million Barrels of Oil Equivalent - (a)	77.7			75.3			70.1			73.7			65.9
Total Operating Revenues and Other (b)	4,765			4,139			3,694			2,965			2,246
Total Operating Expenses (c)	3,294			2,968			2,762			2,477			2,249
Operating Income (Loss) (d)	1,471			1,171			932			488			(3)
Wellhead Revenues
Crude Oil and Condensate	2,929			2,699			2,251			1,711			1,395
Natural Gas Liquids	548			367			314			229			185
Natural Gas	568			404			625			302			184
Total Wellhead Revenues - (e)	4,045			3,470			3,190			2,242			1,764
Operating Costs
Lease and Well	270			270			270			261			227
Transportation Costs	219			214			202			195			180
Gathering and Processing Costs	145			128			139			119			115
General and Administrative	142			120			110			113			125
Taxes Other Than Income	277			239			215			114			126
Interest Expense, Net	48			45			47			53			53
Total Operating Cost (excluding DD&A and Total Exploration      Costs) (f)	1,101			1,016			983			855			826
Depreciation, Depletion and Amortization (DD&A)	927			914			900			870			823
Total Operating Cost (excluding Total Exploration Costs) - (g)	2,028			1,930			1,883			1,725			1,649
Exploration Costs	44			35			33			41			38
Dry Hole Costs	4			13			11			—			13
Impairments	82			44			44			143			79
Total Exploration Costs (GAAP)	130			92			88			184			130
Less:  Certain Impairments (1)	(13)			(1)			(1)			(86)			(27)
Total Exploration Costs (Non-GAAP)	117			91			87			98			103
Total Operating Cost (including Total Exploration Costs      (GAAP)) - (h)	2,158			2,022			1,971			1,909			1,779
Total Operating Cost (including Total Exploration Costs      (Non-GAAP)) - (i)	2,145			2,021			1,970			1,823			1,752
Total Wellhead Revenues less Total Operating Cost      (including Total Exploration Costs (GAAP))	1,887			1,448			1,219			333			(15)
Total Wellhead Revenues less Total Operating Cost      (including Total Exploration Costs (Non-GAAP))	1,900			1,449			1,220			419			12
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
	3Q 2021			2Q 2021			1Q 2021			4Q 2020			3Q 2020
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)
Composite Average Operating Revenues and Other per Boe     - (b) / (a)	61.33			54.97			52.70			40.23			34.08
Composite Average Operating Expenses per Boe - (c) / (a)	42.40			39.42			39.40			33.61			34.13
Composite Average Operating Income (Loss) per Boe     - (d) / (a)	18.93			15.55			13.30			6.62			(0.05)
Composite Average Wellhead Revenue per Boe - (e) / (a)	52.07			46.07			45.49			30.39			26.77
Total Operating Cost per Boe (excluding DD&A and Total     Exploration Costs) -   (f) / (a)	14.19			13.48			14.02			11.60			12.56
Composite Average Margin per Boe (excluding DD&A and     Total Exploration Costs) - [(e) / (a) - (f) / (a)]	37.88			32.59			31.47			18.79			14.21
Total Operating Cost per Boe (excluding Total Exploration      Costs) - (g) / (a)	26.12			25.61			26.86			23.41			25.05
Composite Average Margin per Boe (excluding Total     Exploration Costs) - [(e) / (a) - (g) / (a)]	25.95			20.46			18.63			6.98			1.72
Total Operating Cost per Boe (including Total Exploration     Costs) - (h) / (a)	27.79			26.85			28.12			25.90			27.00
Composite Average Margin per Boe (including Total     Exploration Costs) - [(e) / (a) - (h) / (a)]	24.28			19.22			17.37			4.49			(0.23)
Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)
Total Operating Cost per Boe (including Total Exploration      Costs) - (i) / (a)	27.62			26.85			28.11			24.72			26.62
Composite Average Margin per Boe (including Total      Exploration Costs) - [(e) / (a) - (i) / (a)]	24.45			19.25			17.38			5.67			0.15

(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)
	2020			2019			2018			2017
Volume - Million Barrels of Oil Equivalent - (a)	275.9			298.6			262.5			222.3
Total Operating Revenues and Other (b)	11,032			17,380			17,275			11,208
Total Operating Expenses (c)	11,576			13,681			12,806			10,282
Operating Income (Loss) (d)	(544)			3,699			4,469			926
Wellhead Revenues
Crude Oil and Condensate	5,786			9,613			9,517			6,256
Natural Gas Liquids	668			785			1,128			730
Natural Gas	837			1,184			1,302			922
Total Wellhead Revenues - (e)	7,291			11,582			11,947			7,908
Operating Costs
Lease and Well	1,063			1,367			1,283			1,045
Transportation Costs	735			758			747			740
Gathering and Processing Costs	459			479			437			149
General and Administrative (GAAP)	484			489			427			434
Less:  Legal Settlement - Early Leasehold Termination	—			—			—			(10)
Less:  Joint Venture Transaction Costs	—			—			—			(3)
Less:  Joint Interest Billings Deemed Uncollectible	—			—			—			(5)
General and Administrative (Non-GAAP) (1)	484			489			427			416
Taxes Other Than Income	478			800			772			545
Interest Expense, Net	205			185			245			274
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)	3,424			4,078			3,911			3,187
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)	3,424			4,078			3,911			3,169
Depreciation, Depletion and Amortization (DD&A)	3,400			3,750			3,435			3,409
Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)	6,824			7,828			7,346			6,596
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)	6,824			7,828			7,346			6,578
Exploration Costs	146			140			149			145
Dry Hole Costs	13			28			5			5
Impairments	2,100			518			347			479
Total Exploration Costs (GAAP)	2,259			686			501			629
Less:  Certain Impairments (2)	(1,868)			(275)			(153)			(261)
Total Exploration Costs (Non-GAAP)	391			411			348			368
Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)	9,083			8,514			7,847			7,225
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) - (k)	7,215			8,239			7,694			6,946
Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total     Exploration Costs (GAAP))	(1,792)			3,068			4,100			683
Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total        Exploration Costs (Non-GAAP))	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)
	2020			2019			2018			2017
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)
Composite Average Operating Revenues and Other per Boe - (b) / (a)	39.99			58.20			65.81			50.42
Composite Average Operating Expenses per Boe - (c) / (a)	41.96			45.81			48.79			46.25
Composite Average Operating Income (Loss) per Boe - (d) / (a)	(1.97)			12.39			17.02			4.17
Composite Average Wellhead Revenue per Boe - (e) / (a)	26.42			38.79			45.51			35.58
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -   (f) / (a)	12.39			13.66			14.90			14.34
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) -   (f) / (a)]	14.03			25.13			30.61			21.24
Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)	24.71			26.22			27.99			29.67
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]	1.71			12.57			17.52			5.91
Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)	32.92			28.51			29.89			32.50
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]	(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)	12.39			13.66			14.90			14.25
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) -   (g) / (a)]	14.03			25.13			30.61			21.33
Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)	24.71			26.22			27.99			29.59
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]	1.71			12.57			17.52			5.99
Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)	26.13			27.60			29.32			31.24
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]	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).

 

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SOURCE EOG Resources, Inc.

FAQ

What were EOG's financial results for Q3 2021?

EOG reported total revenue of $4.77 billion and net income of $1.1 billion for Q3 2021.

What is the new dividend amount announced by EOG?

EOG increased its regular dividend by 82% to an annual rate of $3.00 per share.

When will EOG's special dividend be paid?

The special dividend of $2.00 per share will be paid on December 30, 2021.

How much free cash flow did EOG generate in Q3 2021?

EOG generated $1.36 billion in free cash flow during Q3 2021.

What was EOG's plan for share repurchases?

EOG updated its share repurchase authorization to $5 billion, aligning with its cash flow priorities.