What were EOG Resources' Q4 2021 financial results?

EOG Resources reported a record adjusted net income of $1.8 billion in Q4 2021, with free cash flow of $2.0 billion.

What is EOG's dividend for 2022?

EOG declared a regular dividend of $0.75 per share and a special dividend of $1.00 per share, payable in April and March 2022, respectively.

How much free cash flow did EOG generate in 2021?

EOG generated a record $5.5 billion in free cash flow for the full year 2021.

What is EOG's capital expenditure plan for 2022?

EOG's capital expenditure plan for 2022 ranges from $4.3 billion to $4.7 billion.

How did EOG's financial performance change from 2020 to 2021?

EOG increased its full-year adjusted net income to $5.0 billion in 2021, a significant improvement from a net loss in 2020.

EOG Resources Reports Fourth Quarter and Full-Year 2021 Results; Announces 2022 Capital Program; Declares $1.00 per Share Special Dividend

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EOG Resources reported strong financial results for the fourth quarter and full-year 2021, achieving a record adjusted net income of $1.8 billion ($3.09 per share) in Q4, up from $1.3 billion in Q3. For FY 2021, adjusted net income reached $5.0 billion ($8.61 per share). The company generated $2.0 billion in free cash flow in Q4 and $5.5 billion for the year. EOG declared a regular dividend of $0.75 and a special dividend of $1.00 per share, payable in April and March 2022, respectively. The capital plan for 2022 is set between $4.3 to $4.7 billion.

Positive

Record Q4 adjusted net income of $1.8 billion, up from $1.3 billion in Q3.
Full-year adjusted net income of $5.0 billion, a significant increase from a loss in 2020.
Generated $5.5 billion of free cash flow for 2021.
Declared a total dividend of $1.75 per share, boosting shareholder returns.

Negative

Increased per-unit costs mainly due to higher lease, maintenance, and remediation costs.
Free cash flow was impacted by capital expenditures of $1.1 billion in Q4.

02/24/2022 - 04:15 PM

HOUSTON, Feb. 24, 2022 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 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
		4Q 2021	3Q 2021	4Q 2020	FY 2021	FY 2020
GAAP	Total Revenue	6,044	4,765	2,965	18,642	11,032
	Net Income (Loss)	1,985	1,095	337	4,664	(605)
	Net Income (Loss) Per Share	3.39	1.88	0.58	7.99	(1.04)
	Net Cash Provided by Operating Activities	3,166	2,196	1,121	8,791	5,008
	Total Expenditures	1,137	962	1,107	4,255	4,113
	Current and Long-Term Debt	5,109	5,117	5,816	5,109	5,816
	Cash and Cash Equivalents	5,209	4,293	3,329	5,209	3,329
	Debt-to-Total Capitalization	18.7%	19.0%	22.3%	18.7%	22.3%

Non-GAAP	Adjusted Net Income	1,806	1,264	411	5,028	850
	Adjusted Net Income Per Share	3.09	2.16	0.71	8.61	1.46
	Discretionary Cash Flow	3,106	2,296	1,494	9,442	5,093
	Cash Capital Expenditures before Acquisitions	1,057	935	828	3,909	3,490
	Free Cash Flow	2,049	1,361	666	5,533	1,603
	Net Debt	(100)	824	2,487	(100)	2,487
	Net Debt-to-Total Capitalization	(0.5)%	3.6%	10.9%	(0.5)%	10.9%

Fourth Quarter Highlights

Record quarterly adjusted net income of $1.8 billion, or $3.09 per share, and $2.0 billion of free cash flow
Capital expenditures in-line with guidance while oil production above guidance mid-point
Declared regular dividend of $0.75 per share and special dividend of $1.00 per share

Full Year 2021 Highlights

Record annual adjusted net income of $5.0 billion, or $8.61 per share
Generated record $5.5 billion of free cash flow
Reduced well costs 7%
Identified 700 new net double premium locations, replacing 170% of double premium wells drilled in 2021
Replaced more than two times 2021 production at $5.81 per Boe finding and development cost
Achieved significant improvements in methane emissions, water and safety performance

2022 Capital Plan

Capital plan of $4.3 to $4.7 billion returns oil production to pre-pandemic levels, maintains flat well costs, lowers per-unit cash costs and funds investments to further improve the business
Cash from operations before working capital funds capital plan at $32 WTI

Fourth Quarter and Full-Year 2021 Highlights

Volumes and Capital Expenditures

Wellhead Volumes	4Q 2021	4Q 2021 Guidance Midpoint	3Q 2021	4Q 2020	FY 2021	FY 2020
Crude Oil and Condensate (MBod)	450.6	447.0	449.5	444.8	445.0	409.2
Natural Gas Liquids (MBbld)	156.9	153.0	157.9	141.4	144.5	136.0
Natural Gas (MMcfd)	1,534	1,535	1,422	1,292	1,436	1,252
Total Crude Oil Equivalent (MBoed)	863.1	855.8	844.4	801.5	828.9	753.8

Cash Capital Expenditures before Acquisitions ($MM)	1,057	1,050	935	828	3,909	3,490

From Ezra Yacob, Chief Executive Officer

"The outstanding fourth quarter results cap off a tremendous year for EOG – record earnings, record free cash flow, and return of cash that places EOG among the leaders in our industry and across the broader market. Reflecting these results, we are continuing to deliver on our long-standing free cash flow priorities with another $1.00 per share special dividend while further strengthening the balance sheet. Strong returns due to our premium investment standard and levered by our high-performance culture drove the results.
Double-premium, the latest increase to our investment standard that we formalized at the start of 2021, is just beginning to flow through to our bottom-line financial performance. The best is yet to come.

"The strong fourth quarter performance was also a hallmark of our consistent operational execution, as we once again delivered on our production and capital targets. Exploration efforts continued to move forward, as we progressed multiple domestic oil prospects that stand to further improve the quality of our large inventory of future drilling locations. We applied technology and innovation towards continuing improvements in our ESG performance during 2021, including methane emissions, water and safety. We are aiming to do even better this year.

"Looking to 2022, our disciplined capital plan reflects an oil market that is in position to rebalance during the year. It is focused on investments in high-return double premium wells along with exploration and infrastructure projects to further improve the business. Combined with our low cost structure and an improved commodity price environment, EOG is positioned to once again generate significant free cash flow. We remain firmly committed to our long-standing free cash flow and cash return priorities. EOG has never been better positioned to generate significant long-term shareholder value."

Fourth Quarter 2021 Financial Performance

Adjusted Earnings per Share 4Q 2021 vs 3Q 2021

Prices and Hedges
Natural gas, crude oil and NGL prices increased in 4Q compared with 3Q. In addition, cash paid for hedge settlements declined by $171 million in 4Q compared with 3Q.

Production Volumes
Total company equivalent volumes increased 2% compared with 3Q. Crude oil production of 450,600 Bopd was above the mid-point of the guidance range due to better well productivity. NGL production declined slightly compared with 3Q due to decreased extraction of ethane. Natural gas production increased 8% compared with 3Q, primarily due to EOG's Dorado dry gas play in south Texas.

Per-Unit Costs
Increased impairment and dry hole costs primarily related to drilling in Oman were the largest contributors to the per-unit cost increase in 4Q. Lease and well costs also contributed to the overall cost increase. These were partially offset by reductions in DD&A and G&A costs.

Other
A lower effective income tax rate was the primary contributor to the increase in earnings from this category.

Change in Cash 4Q 2021 vs 3Q 2021

Free Cash Flow
EOG generated discretionary cash flow (net cash provided by operating activities before exploration costs and changes in working capital) of $3.1 billion in 4Q. The company incurred $1.1 billion of capital expenditures, resulting in $2.0 billion of free cash flow.

Capital Expenditures
Capital expenditures of $1.1 billion were in-line with the mid-point of the guidance range. EOG has continued to be successful offsetting inflationary price pressures with additional efficiencies and other operating improvements.

Dividends
EOG paid $0.2 billion of regular dividends and $1.2 billion of special dividends in 4Q

Full-Year 2021 Financial Performance

Adjusted Earnings per Share 2021 vs 2020

Prices and Hedges
Crude oil prices increased by 77% in 2021 compared with 2020, while prices for NGLs and natural gas more than doubled. Higher prices along with increased production volumes generated a wellhead revenue increase of $8.1 billion, or 111%, in 2021 compared with 2020. This was partially offset by an increase in cash paid for hedge settlements of $1.7 billion from 2020 to 2021.

Production Volumes
Total company equivalent production increased 10% in 2021 compared with 2020, when EOG shut in certain wells in response to low crude oil prices. Crude oil volumes in 2021 were 445,000 Bopd, 9% higher than 2020 and consistent with EOG's plan to maintain production at 4Q 2020 levels. NGL volumes increased 6% while natural gas volumes increased 15%.

Per-Unit Costs
Impairments, transportation and G&P costs increased in 2021 compared with 2020, mostly offset by reductions in DD&A, LOE and G&A costs.

Other
Per-unit taxes other than income increased by $1.73 per Boe in 2021 compared with 2020, due to increased product prices, and was the largest contributor to the reduction in earnings from this category.

Change in Cash 2021 vs 2020

Free Cash Flow
EOG generated discretionary cash flow (net cash provided by operating activities before exploration costs and changes in working capital) of $9.4 billion in 2021. The company incurred $3.9 billion of capital expenditures, resulting in $5.5 billion of free cash flow.

Dividend and Debt
EOG doubled its regular dividend rate during 2021, from $1.50 per share at year-end 2020 to $3.00 per share by year-end 2021. In addition, EOG paid $3.00 per share in special dividends during 2021. Altogether, EOG returned $2.7 billion to shareholders in 2021. Also, EOG repaid with cash on hand the $750 million principal amount of notes that matured in February 2021.

Fourth Quarter 2021 Operating Performance

Lease and Well
Per-unit LOE costs were above the guidance mid- point and prior periods due to higher costs for fuel, lease maintenance and remediation.

Transportation, Gathering and Processing
Per-unit transportation and G&P costs in 4Q were slightly below the guidance midpoints and in-line with 3Q. Costs increased compared with the prior year period primarily due to higher fuel costs.

Depreciation, Depletion and Amortization
The addition of reserves from new wells at lower finding costs, driven by EOG's double-premium drilling program, continues to lower DD&A costs. Per-unit DD&A costs were below the guidance midpoint and declined 4% and 3% compared with 3Q 2021 and 4Q 2020, respectively.

General and Administrative
Per-unit G&A costs in 4Q were above the guidance midpoint and the prior year due to higher employee related costs.

2021 Reserves and Premium Location Additions; Special Dividend

Finding and Development Cost
Finding and development cost, excluding price revisions, declined 17% YoY in 2021 to $5.81 per Boe. Proved developed finding cost, excluding price revisions, was $7.98 per Boe in 2021. For the 34th consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and McNaughton.

Reserve Replacement
Extensions and discoveries, net of revisions other than price, added 644 MMBoe of proved reserves in 2021. Revisions other than price reduced proved reserves primarily due to the high-grading of our future drilling plan. Proved undeveloped locations that did not meet EOG's double premium standard were replaced with fewer, more productive double-premium locations. Reserves from these high-graded proved undeveloped locations are included as part of reserve additions from extensions and discoveries. Net proved reserve additions from all sources, excluding price revisions, replaced 208% of 2021 production.

2021 Premium Location Additions
EOG identified 700 new net double-premium locations in 2021, replacing 170% of the approximately 410 net double-premium wells drilled in 2021. The new double-premium locations are spread across EOG's portfolio of high-return plays. The double-premium inventory increased to 6,000 net locations from 5,700 previously and represents more than 11 years of drilling at EOG's current pace. EOG's total premium inventory of 11,500 net undrilled locations remained unchanged in 2021.

Regular Dividend and Special Dividend
The Board of Directors today declared a dividend of $0.75 per share on EOG's common stock. The dividend will be payable April 29, 2022, to stockholders of record as of April 15, 2022. The indicated annual rate is $3.00 per share. The Board of Directors today also declared a special dividend of $1.00 per share on EOG's Common Stock. The special dividend will be payable March 29, 2022, to stockholders of record as of March 15, 2022

2021 ESG Performance and 2022 Capital Program

Further Improvements to Strong ESG Track Record

~25% Reduction in Methane Emissions Percentage
99.8% Wellhead Gas Capture
55% of Water Sourced from Reuse
10% Reduction in Total Recordable Incident Rate

2021 ESG Performance – Preliminary Results
EOG reduced its methane emissions percentage by approximately 25% during 2021. Reduced emissions associated with pneumatic controllers and lower fugitive emissions contributed to the reduction. Wellhead gas capture increased to 99.8% from 99.6% in 2020. Water sourced from reuse increased to 55% from 46% in 2020. Finally, EOG improved its safety performance in 2021, with a reduction of 10% in the total recordable incident rate compared with 2020. The company's GHG intensity rate increased slightly in 2021 due to increased compression for gas gathering. EOG remains confident in achieving its 2025 emissions goals and its ambition to reach net zero scope 1 and scope 2 emissions by 2040.

2022 Capital Program²Total expenditures for 2022 are expected to range from $4.3 to $4.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, other property, plant and equipment, and excluding property acquisitions, asset retirement costs and non-cash exchanges. The capital program also excludes certain exploration costs incurred as operating expenses. The disciplined capital program is focused on high-return investment in EOG's double-premium drilling inventory and returns oil production back to pre-pandemic levels of 455,000 to 467,000 Bopd.

Approximately $3 billion of the capital program is allocated to investment in EOG's existing premium areas. The capital program also funds investment in international plays, high-potential exploration drilling across multiple prospects and investment in various cost-reduction, infrastructure and environmental projects. The total capital program can be funded from cash flow provided by operating activities before changes in working capital at a $32 WTI oil price. EOG plans to complete 570 net wells in 2022 compared with 519 net wells in 2021, including an additional 20 net wells in the Dorado natural gas play and 10 additional net wells in new high potential exploration prospects.

Fourth Quarter 2021 Results vs Guidance


(Unaudited)
Crude Oil and Condensate Volumes (MBod)	4Q 2021	4Q 2021 Guidance Midpoint	Variance	3Q 2021	2Q 2021	1Q 2021	4Q 2020
United States	449.7	446.0	3.7	448.3	446.9	428.7	442.4
Trinidad	0.9	1.0	(0.1)	1.2	1.7	2.2	2.3
Other International	0.0	0.0	0.0	0.0	0.0	0.1	0.1
Total	450.6	447.0	3.6	449.5	448.6	431.0	444.8
Natural Gas Liquids Volumes (MBbld)
Total	156.9	153.0	3.9	157.9	138.5	124.3	141.4
Natural Gas Volumes (MMcfd)
United States	1,328	1,335	(7)	1,210	1,199	1,100	1,075
Trinidad	206	200	6	212	233	217	192
Other International	0	0	0	0	13	25	25
Total	1,534	1,535	(1)	1,422	1,445	1,342	1,292

Total Crude Oil Equivalent Volumes (MBoed)	863.1	855.8	7.3	844.4	828.0	778.9	801.5
Total MMBoe	79.4	78.7	0.7	77.7	75.3	70.1	73.7

Benchmark Price
Oil (WTI) ($/Bbl)	77.17			70.55	66.06	57.80	42.67
Natural Gas (HH) ($/Mcf)	5.83			4.01	2.83	2.69	2.65

Crude Oil and Condensate - above (below) WTI ($/Bbl)
United States	1.14	0.70	0.44	0.33	0.10	0.27	(0.81)
Trinidad	(10.31)	(11.00)	0.69	(10.36)	(9.80)	(8.03)	(9.76)

Natural Gas Liquids - Realizations as % of WTI	52.4%	55.0%	(2.6%)	53.5%	44.1%	48.5%	41.1%

Natural Gas - above (below) NYMEX Henry Hub ($/Mcf)
United States	0.57	1.10	(0.53)	0.49	0.16	2.83	(0.36)
Natural Gas Realizations ($/Mcf)
Trinidad	3.48	3.45	0.03	3.39	3.37	3.38	3.57

Total Expenditures (GAAP) ($MM)	1,137			962	1,089	1,067	1,107
Capital Expenditures (non-GAAP) ($MM)	1,057	1,050	7	935	972	945	828

Operating Unit Costs ($/Boe)
Lease and Well	4.09	3.75	0.34	3.48	3.58	3.85	3.54
Transportation Costs	2.87	2.95	(0.08)	2.82	2.84	2.88	2.64
Gathering and Processing	1.85	1.90	(0.05)	1.87	1.70	1.98	1.62
General and Administrative	1.75	1.55	0.20	1.83	1.59	1.57	1.54
Cash Operating Costs	10.56	10.15	0.41	10.00	9.71	10.28	9.34
Depreciation, Depletion and Amortization	11.46	11.70	(0.24)	11.93	12.13	12.84	11.81

Expenses ($MM)
Exploration and Dry Hole	85	43	42	48	49	44	40
Impairment (GAAP)	206			82	44	44	143
Impairment (excluding certain impairments (non-GAAP))	206	120	86	69	43	43	57
Capitalized Interest	9	8	1	8	8	8	7
Net Interest	38	45	(7)	48	45	47	53

Taxes Other Than Income (% of Wellhead Revenue)	6.8%	7.0%	(0.2%)	6.8%	6.9%	6.7%	5.1%
Income Taxes
Effective Rate	20.5%	23.5%	(3.0%)	23.4%	19.3%	23.2%	21.1%
Deferred Ratio	23%	13%	11%	(33%)	(45%)	(18%)	60%

First Quarter and Full-Year 2022 Guidance²


(Unaudited)
See "Endnotes" below for related discussion and definitions.	1Q 2022 Guidance Range			FY 2022 Guidance Range			2021 Actual	2020 Actual
Crude Oil and Condensate Volumes (MBod)
United States	442.0	-	452.0	454.5	-	466.5	443.4	408.1
Trinidad	0.7	-	0.9	0.4	-	0.6	1.5	1.0
Other International	0.0	-	0.0	0.0	-	0.0	0.1	0.1
Total	442.7	-	452.9	454.9	-	467.1	445.0	409.2
Natural Gas Liquids Volumes (MBbld)
Total	182.0	-	192.0	170.0	-	210.0	144.5	136.0
Natural Gas Volumes (MMcfd)
United States	1,200	-	1,270	1,240	-	1,340	1,210	1,040
Trinidad	185	-	215	160	-	200	217	180
Other International	0	-	0	0	-	0	9	32
Total	1,385	-	1,485	1,400	-	1,540	1,436	1,252
Crude Oil Equivalent Volumes (MBoed)
United States	824.0	-	855.7	831.2	-	899.8	789.6	717.5
Trinidad	31.5	-	36.7	27.1	-	33.9	37.7	30.9
Other International	0.0	-	0.0	0.0	-	0.0	1.6	5.4
Total	855.5	-	892.4	858.3	-	933.7	828.9	753.8

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

Crude Oil and Condensate Differentials - above (below) WTI³ ($/Bbl)
United States	0.50	-	2.50	0.50	-	2.50	0.58	(0.75)
Trinidad	(12.00)	-	(10.00)	(11.00)	-	(9.00)	(11.70)	(9.20)
Natural Gas Liquids - Realizations as % of WTI
Total	37%	-	47%	34%	-	49%	50.5%	34.0%
Natural Gas Differentials - above (below) NYMEX Henry Hub⁴ ($/Mcf)
United States	0.15	-	1.65	(0.30)	-	1.70	1.03	(0.47)
Natural Gas Realizations ($/Mcf)
Trinidad	3.10	-	3.60	2.90	-	3.90	3.40	2.57

Total Expenditures (GAAP) ($MM)							4,255	4,113
Capital Expenditures⁵ (non-GAAP) ($MM)	1,000	-	1,200	4,300	-	4,700	3,909	3,490

Operating Unit Costs ($/Boe)
Lease and Well	3.60	-	4.20	3.45	-	4.05	3.75	3.85
Transportation Costs	2.65	-	3.05	2.60	-	3.10	2.85	2.66
Gathering and Processing	1.75	-	1.95	1.65	-	1.95	1.85	1.66
General and Administrative	1.60	-	1.70	1.65	-	1.75	1.69	1.75
Cash Operating Costs	9.60	-	10.90	9.35	-	10.85	10.14	9.92
Depreciation, Depletion and Amortization	10.50	-	11.00	10.15	-	11.15	12.07	12.32

Expenses ($MM)
Exploration and Dry Hole	40	-	50	150	-	190	225	159
Impairment (GAAP)							376	2,100
Impairment (excluding certain impairments (non-GAAP))	60	-	100	300	-	340	361	232
Capitalized Interest	5	-	10	30	-	40	33	31
Net Interest	40	-	45	165	-	175	178	205

Taxes Other Than Income (% of Wellhead Revenue)	6.5%	-	8.5%	7.0%	-	8.0%	6.8%	6.6%
Income Taxes
Effective Rate	20%	-	25%	20%	-	25%	21.4%	18.2%
Current Tax (Benefit) / Expense ($MM)	440	-	540	1,700	-	2,100	1,393	(61)

Fourth Quarter and Full-Year 2021 Results Webcast
Friday, February 25, 2022, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. http://investors.eogresources.com/Investors

About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com.

Investor Contacts
David Streit 713–571–4902
Neel Panchal 713–571–4884

Media and Investor Contact
Kimberly Ehmer 713–571–4676

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

2)	The forecast items for the first quarter and full year 2022 set forth above for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

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, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and certain exploration costs incurred as operating expenses.

Glossary
Acq	Acquisitions
ATROR	After-tax rate of return
Bbl	Barrel
Bn	Billion
Boe	Barrels of oil equivalent
Bopd	Barrels of oil per day
CAGR	Compound annual growth rate
Capex	Capital expenditures
CFO	Cash flow provided by operating activities before changes in working capital
CO2e	Carbon dioxide equivalent
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," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward looking statements.
Forward–looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward–looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward–looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward–looking, non–GAAP financial measures, such as free cash flow 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 (NGLs), 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, NGLs and natural gas;
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with
applicable laws and regulations;
competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
the availability and cost of, and competition in the oil and gas exploration and production industry for, employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent to which EOG is successful in its completion of planned asset dispositions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
acts of war and terrorism and responses to these acts; and
the other factors described under ITEM 1A, Risk Factors of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10–K for the fiscal year ended December 31, 2021, available from EOG at P.O. Box 4362, Houston, Texas 77210–4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1–800–SEC–0330 or from the SEC's website at www.sec.gov. In addition, reconciliation 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)
	4Q 2021	3Q 2021	4Q 2020	FY 2021	FY 2020
Operating Revenues and Other
Crude Oil and Condensate	3,246	2,929	1,711	11,125	5,786
Natural Gas Liquids	583	548	229	1,812	668
Natural Gas	847	568	302	2,444	837
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	136	(494)	70	(1,152)	1,145
Gathering, Processing and Marketing	1,232	1,186	643	4,288	2,583
Gains (Losses) on Asset Dispositions, Net	(29)	1	(6)	17	(47)
Other, Net	29	27	16	108	60
Total	6,044	4,765	2,965	18,642	11,032

Operating Expenses
Lease and Well	325	270	261	1,135	1,063
Transportation Costs	228	219	195	863	735
Gathering and Processing Costs	147	145	119	559	459
Exploration Costs	42	44	41	154	146
Dry Hole Costs	43	4	—	71	13
Impairments	206	82	143	376	2,100
Marketing Costs	1,160	1,184	621	4,173	2,698
Depreciation, Depletion and Amortization	910	927	870	3,651	3,400
General and Administrative	139	142	113	511	484
Taxes Other Than Income	316	277	114	1,047	478
Total	3,516	3,294	2,477	12,540	11,576

Operating Income (Loss)	2,528	1,471	488	6,102	(544)
Other Income (Expense), Net	9	6	(7)	9	10
Income (Loss) Before Interest Expense and Income Taxes	2,537	1,477	481	6,111	(534)
Interest Expense, Net	38	48	53	178	205
Income (Loss) Before Income Taxes	2,499	1,429	428	5,933	(739)
Income Tax Provision (Benefit)	514	334	91	1,269	(134)
Net Income (Loss)	1,985	1,095	337	4,664	(605)

Dividends Declared per Common Share	2.7500	0.4125	0.3750	4.9875	1.5000
Net Income (Loss) Per Share
Basic	3.42	1.88	0.58	8.03	(1.04)
Diluted	3.39	1.88	0.58	7.99	(1.04)
Average Number of Common Shares
Basic	581	581	580	581	579
Diluted	585	584	581	584	579

Wellhead Volumes and Prices


(Unaudited)
	4Q 2021	4Q 2020	% Change	3Q 2021	FY 2021	FY 2020	% Change

Crude Oil and Condensate Volumes (MBbld) ^(A)
United States	449.7	442.4	2 %	448.3	443.4	408.1	9 %
Trinidad	0.9	2.3	-61 %	1.2	1.5	1.0	50 %
Other International ^(B)	—	0.1	-100 %	—	0.1	0.1	0 %
Total	450.6	444.8	1 %	449.5	445.0	409.2	9 %

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	78.31	41.86	87 %	70.88	68.54	38.65	77 %
Trinidad	66.86	32.91	103 %	60.19	56.26	30.20	86 %
Other International ^(B)	—	35.90	-100 %	—	42.36	43.08	-2 %
Composite	78.29	41.81	87 %	70.85	68.50	38.63	77 %

Natural Gas Liquids Volumes (MBbld) ^(A)
United States	156.9	141.4	11 %	157.9	144.5	136.0	6 %
Total	156.9	141.4	11 %	157.9	144.5	136.0	6 %

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	40.40	17.54	130 %	37.72	34.35	13.41	156 %
Composite	40.40	17.54	130 %	37.72	34.35	13.41	156 %

Natural Gas Volumes (MMcfd) ^(A)
United States	1,328	1,075	24 %	1,210	1,210	1,040	16 %
Trinidad	206	192	7 %	212	217	180	21 %
Other International ^(B)	—	25	-100 %	—	9	32	-72 %
Total	1,534	1,292	19 %	1,422	1,436	1,252	15 %

Average Natural Gas Prices ($/Mcf) ^(C)
United States	6.40	2.29	180 %	4.50	4.88	1.61	203 %
Trinidad	3.48	3.57	-3 %	3.39	3.40	2.57	32 %
Other International ^(B)	—	5.47	-100 %	—	5.67	4.66	22 %
Composite	6.00	2.54	136 %	4.34	4.66	1.83	155 %

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States	827.8	763.0	8 %	807.9	789.6	717.5	10 %
Trinidad	35.3	34.2	3 %	36.5	37.7	30.9	22 %
Other International ^(B)	—	4.3	-100 %	—	1.6	5.4	-70 %
Total	863.1	801.5	8 %	844.4	828.9	753.8	10 %

Total MMBoe ^(D)	79.4	73.7	8 %	77.7	302.5	275.9	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 Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 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)
	December 31,	December 31,
	2021	2020
Current Assets
Cash and Cash Equivalents	5,209	3,329
Accounts Receivable, Net	2,335	1,522
Inventories	584	629
Assets from Price Risk Management Activities	—	65
Income Taxes Receivable	—	23
Other	456	294
Total	8,584	5,862

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	67,644	64,793
Other Property, Plant and Equipment	4,753	4,479
Total Property, Plant and Equipment	72,397	69,272
Less: Accumulated Depreciation, Depletion and Amortization	(43,971)	(40,673)
Total Property, Plant and Equipment, Net	28,426	28,599
Deferred Income Taxes	11	2
Other Assets	1,215	1,342
Total Assets	38,236	35,805

Current Liabilities
Accounts Payable	2,242	1,681
Accrued Taxes Payable	518	206
Dividends Payable	436	217
Liabilities from Price Risk Management Activities	269	—
Current Portion of Long-Term Debt	37	781
Current Portion of Operating Lease Liabilities	240	295
Other	300	280
Total	4,042	3,460

Long-Term Debt	5,072	5,035
Other Liabilities	2,193	2,149
Deferred Income Taxes	4,749	4,859
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 585,521,512 Shares and 583,694,850 Shares Issued at December 31, 2021 and 2020, respectively	206	206
Additional Paid in Capital	6,087	5,945
Accumulated Other Comprehensive Loss	(12)	(12)
Retained Earnings	15,919	14,170
Common Stock Held in Treasury, 257,268 Shares and 124,265 Shares at December 31, 2021 and 2020, respectively	(20)	(7)
Total Stockholders' Equity	22,180	20,302
Total Liabilities and Stockholders' Equity	38,236	35,805

Cash Flow Statements


In millions of USD (Unaudited)
	4Q 2021	4Q 2020	3Q 2021	FY 2021	FY 2020
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Income (Loss)	1,985	337	1,095	4,664	(605)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	910	870	927	3,651	3,400
Impairments	206	143	82	376	2,100
Stock-Based Compensation Expenses	35	33	51	152	146
Deferred Income Taxes	122	55	(111)	(122)	(186)
(Gains) Losses on Asset Dispositions, Net	29	6	(1)	(17)	47
Other, Net	(2)	10	2	13	12
Dry Hole Costs	43	—	4	71	13
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	(136)	(70)	494	1,152	(1,145)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(122)	72	(293)	(638)	1,071
Other, Net	(1)	2	7	7	1
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(182)	(464)	(145)	(821)	467
Inventories	(108)	31	(6)	(13)	123
Accounts Payable	341	427	(68)	456	(795)
Accrued Taxes Payable	26	(61)	206	312	(49)
Other Assets	(81)	(90)	167	(136)	325
Other Liabilities	201	21	(260)	(116)	8
Changes in Components of Working Capital Associated with Investing Activities	(100)	(201)	45	(200)	75
Net Cash Provided by Operating Activities	3,166	1,121	2,196	8,791	5,008
Investing Cash Flows
Additions to Oil and Gas Properties	(949)	(785)	(846)	(3,638)	(3,244)
Additions to Other Property, Plant and Equipment	(65)	(56)	(50)	(212)	(221)
Proceeds from Sales of Assets	77	3	8	231	192
Changes in Components of Working Capital Associated with Investing Activities	100	201	(45)	200	(75)
Net Cash Used in Investing Activities	(837)	(637)	(933)	(3,419)	(3,348)
Financing Cash Flows
Long-Term Debt Borrowings	—	—	—	—	1,484
Long-Term Debt Repayments	—	—	—	(750)	(1,000)
Dividends Paid	(1,406)	(220)	(820)	(2,684)	(821)
Treasury Stock Purchased	(8)	(1)	(21)	(41)	(16)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	10	8	—	19	16
Debt Issuance Costs	—	—	—	—	(3)
Repayment of Finance Lease Liabilities	(10)	(6)	(9)	(37)	(19)
Net Cash Used in Financing Activities	(1,414)	(219)	(850)	(3,493)	(359)
Effect of Exchange Rate Changes on Cash	1	(2)	—	1	—
Increase in Cash and Cash Equivalents	916	263	413	1,880	1,301
Cash and Cash Equivalents at Beginning of Period	4,293	3,066	3,880	3,329	2,028
Cash and Cash Equivalents at End of Period	5,209	3,329	4,293	5,209	3,329

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.

	4Q 2021
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

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

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

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

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


Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	4Q 2020
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	428	(91)	337	0.58
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(70)	15	(55)	(0.10)
Net Cash Received from Settlements of Commodity Derivative Contracts	72	(16)	56	0.10
Add: Losses on Asset Dispositions, Net	6	(1)	5	0.01
Add: Certain Impairments	86	(18)	68	0.12
Adjustments to Net Income	94	(20)	74	0.13

Adjusted Net Income (Non-GAAP)	522	(111)	411	0.71

Average Number of Common Shares (GAAP)
Basic				580
Diluted				581

Average Number of Common Shares (Non-GAAP)
Basic				580
Diluted				581

	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)
	FY 2021
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	5,933	(1,269)	4,664	7.99
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	1,152	(250)	902	1.54
Net Cash Payments for Settlements of Commodity Derivative Contracts	(638)	138	(500)	(0.86)
Less: Gains on Asset Dispositions, Net	(17)	9	(8)	(0.01)
Add: Certain Impairments	15	—	15	0.03
Less: Tax Benefits Related to Exiting Canada Operations	—	(45)	(45)	(0.08)
Adjustments to Net Income	512	(148)	364	0.62

Adjusted Net Income (Non-GAAP)	6,445	(1,417)	5,028	8.61

Average Number of Common Shares (GAAP)
Basic				581
Diluted				584

Average Number of Common Shares (Non-GAAP)
Basic				581
Diluted				584

	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)

3Q 2021 Adjusted Net Income per Share (Non-GAAP)		2.16

Realized Price
4Q 2021 Composite Average Wellhead Revenue per Boe	58.88
Less: 3Q 2021 Composite Average Welhead Revenue per Boe	(52.07)
Subtotal	6.81
Multiplied by: 4Q 2021 Crude Oil Equivalent Volumes (MMBoe)	79.4
Total Change in Revenue	541
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	(124)
Change in Net Income	416
Change in Diluted Earnings per Share		0.71

Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts
4Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative Contracts	(122)
Less: Income Tax Benefit (Cost)	25
After Tax - (a)	(97)
3Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative Contracts	(293)
Less: Income Tax Benefit (Cost)	64
After Tax - (b)	(229)
Change in Net Income - (a) - (b)	132
Change in Diluted Earnings per Share		0.23

Wellhead Volumes
4Q 2021 Crude Oil Equivalent Volumes (MMBoe)	79.4
Less: 3Q 2021 Crude Oil Equivalent Volumes (MMBoe)	(77.7)
Subtotal	1.7
Multiplied by: 4Q 2021 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	28.74
Change in Revenue	49
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	(11)
Change in Net Income	38
Change in Diluted Earnings per Share		0.07


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

Operating Cost per Boe
3Q 2021 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	27.62
Less: 3Q 2021 Taxes Other Than Income	(3.57)
Less: 4Q 2021 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	(30.14)
Add: 4Q 2021 Taxes Other Than Income	3.98
Subtotal	(2.11)
Multiplied by: 4Q 2021 Crude Oil Equivalent Volumes (MMBoe)	79.4
Change in Before-Tax Net Income	(168)
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	39
Change in Net Income	(129)
Change in Diluted Earnings per Share		(0.22)

Other ⁽¹⁾		0.14

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

4Q 2021 Average Number of Common Shares (Non-GAAP) - Diluted	585

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

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)

FY 2020 Adjusted Net Income per Share (Non-GAAP)		1.46

Realized Price
FY 2021 Composite Average Wellhead Revenue per Boe	50.84
Less: FY 2020 Composite Average Wellhead Revenue per Boe	(26.42)
Subtotal	24.42
Multiplied by: FY 2021 Crude Oil Equivalent Volumes (MMBoe)	302.5
Total Change in Revenue	7,388
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	(1,699)
Change in Net Income	5,689
Change in Diluted Earnings per Share		9.74

Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts
FY 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative Contracts	(638)
Less: Income Tax Benefit (Cost)	138
After Tax - (a)	(500)
FY 2020 Net Cash Received (Paid) from Settlement of Commodity Derivative Contracts	1,071
Less: Income Tax Benefit (Cost)	(235)
After Tax - (b)	836
Change in Net Income - (a) - (b)	(1,336)
Change in Diluted Earnings per Share		(2.29)

Wellhead Volumes
FY 2021 Crude Oil Equivalent Volumes (MMBoe)	302.5
Less: FY 2020 Crude Oil Equivalent Volumes (MMBoe)	(275.9)
Subtotal	26.7
Multiplied by: FY 2021 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	22.64
Change in Revenue	604
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	(139)
Change in Net Income	465
Change in Diluted Earnings per Share		0.80


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

Operating Cost per Boe
FY 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	26.13
Less: 3Q 2021 Taxes Other Than Income	(1.73)
Less: FY 2021 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) (refer to "Costs per Barrel of Oil Equivalent" schedule)	(28.20)
Add: 4Q 2021 Taxes Other Than Income	3.46
Subtotal	(0.34)
Multiplied by: FY 2021 Crude Oil Equivalent Volumes (MMBoe)	302.5
Change in Before-Tax Net Income	(103)
Less: Income Tax Benefit (Cost) Imputed (based on 23%)	24
Change in Net Income	(79)
Change in Diluted Earnings per Share		(0.14)
Other ⁽¹⁾		(0.96)

FY 2021 Adjusted Net Income per Share (Non-GAAP)		8.61

FY 2021 Average Number of Common Shares (Non-GAAP) - Diluted	584

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

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.

	4Q 2021	3Q 2021	4Q 2020	FY 2021	FY 2020

Net Cash Provided by Operating Activities (GAAP)	3,166	2,196	1,121	8,791	5,008

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	37	39	36	133	126
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	182	145	464	821	(467)
Inventories	108	6	(31)	13	(123)
Accounts Payable	(341)	68	(427)	(456)	795
Accrued Taxes Payable	(26)	(206)	61	(312)	49
Other Assets	81	(167)	90	136	(325)
Other Liabilities	(201)	260	(21)	116	(8)
Changes in Components of Working Capital Associated with Investing Activities	100	(45)	201	200	(75)
Other Non-Current Income Taxes - Net Receivable	—	—	—	—	113
Discretionary Cash Flow (Non-GAAP)	3,106	2,296	1,494	9,442	5,093

Discretionary Cash Flow (Non-GAAP) - Percentage Increase	108 %			85 %

Discretionary Cash Flow (Non-GAAP)	3,106	2,296	1,494	9,442	5,093
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a)	(1,057)	(935)	(828)	(3,909)	(3,490)
Free Cash Flow (Non-GAAP)	2,049	1,361	666	5,533	1,603


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

	4Q 2021	3Q 2021	4Q 2020	FY 2021	FY 2020

Total Expenditures (GAAP)	1,137	962	1,107	4,255	4,113
Less:
Asset Retirement Costs	(71)	(8)	(48)	(127)	(117)
Non-Cash Acquisition Costs of Unproved Properties	(8)	(15)	(69)	(45)	(197)
Non-Cash Finance Leases	—	—	(101)	(74)	(174)
Acquisition Costs of Proved Properties	(1)	(4)	(61)	(100)	(135)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	1,057	935	828	3,909	3,490

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

	FY 2019	FY 2018	FY 2017

Net Cash Provided by Operating Activities (GAAP)	8,163	7,769	4,265

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	113	125	122
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	92	368	392
Inventories	(90)	395	175
Accounts Payable	(169)	(439)	(324)
Accrued Taxes Payable	(40)	92	64
Other Assets	(358)	125	659
Other Liabilities	57	(11)	90
Changes in Components of Working Capital Associated with Investing and Financing Activities	115	(301)	(90)
Other Non-Current Income Taxes - Net (Payable) Receivable	239	149	(513)
Discretionary Cash Flow (Non-GAAP)	8,122	8,272	4,840

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

Discretionary Cash Flow (Non-GAAP)	8,122	8,272	4,840
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a)	(6,234)	(6,172)	(4,228)
Free Cash Flow (Non-GAAP)	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)	6,900	6,706	4,613
Less:
Asset Retirement Costs	(186)	(70)	(56)
Non-Cash Expenditures of Other Property, Plant and Equipment	(2)	(1)	—
Non-Cash Acquisition Costs of Unproved Properties	(98)	(291)	(256)
Non-Cash Finance Leases	—	(48)	—
Acquisition Costs of Proved Properties	(380)	(124)	(73)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	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)

	4Q 2021	4Q 2020	FY 2021	FY 2020	FY 2019	FY 2018	FY 2017

Exploration and Development Drilling	767	592	2,864	2,664	4,951	4,935	3,132
Facilities	118	99	405	347	629	625	575
Leasehold Acquisitions	21	102	215	265	276	488	427
Property Acquisitions	1	61	100	135	380	124	73
Capitalized Interest	9	7	33	31	38	24	27
Subtotal	916	861	3,617	3,442	6,274	6,196	4,234
Exploration Costs	42	41	154	146	140	149	145
Dry Hole Costs	43	—	71	13	28	5	5
Exploration and Development Expenditures	1,001	902	3,842	3,601	6,442	6,350	4,384
Asset Retirement Costs	71	48	127	117	186	70	56
Total Exploration and Development Expenditures	1,072	950	3,969	3,718	6,628	6,420	4,440
Other Property, Plant and Equipment	65	157	286	395	272	286	173
Total Expenditures	1,137	1,107	4,255	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.

	4Q 2021	4Q 2020	FY 2021	FY 2020

Net Income (Loss) (GAAP)	1,985	337	4,664	(605)

Adjustments:
Interest Expense, Net	38	53	178	205
Income Tax Provision (Benefit)	514	91	1,269	(134)
Depreciation, Depletion and Amortization	910	870	3,651	3,400
Exploration Costs	42	41	154	146
Dry Hole Costs	43	—	71	13
Impairments	206	143	376	2,100
EBITDAX (Non-GAAP)	3,738	1,535	10,363	5,125
(Gains) Losses on MTM Commodity Derivative Contracts	(136)	(70)	1,152	(1,145)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(122)	72	(638)	1,071
(Gains) Losses on Asset Dispositions, Net	29	6	(17)	47

Adjusted EBITDAX (Non-GAAP)	3,509	1,543	10,860	5,098

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	19.3%	19.7%	20.1%	23.4%

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


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

Total Stockholders' Equity - (a)	19,364	18,538	17,452	16,841

Current and Long-Term Debt (GAAP) - (b)	6,083	6,435	6,435	6,435
Less: Cash	(1,556)	(1,274)	(1,008)	(816)
Net Debt (Non-GAAP) - (c)	4,527	5,161	5,427	5,619

Total Capitalization (GAAP) - (a) + (b)	25,447	24,973	23,887	23,276

Total Capitalization (Non-GAAP) - (a) + (c)	23,891	23,699	22,879	22,460

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	23.9%	25.8%	26.9%	27.6%

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


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

Total Stockholders' Equity - (a)	16,283	13,922	13,902	13,928

Current and Long-Term Debt (GAAP) - (b)	6,387	6,387	6,987	6,987
Less: Cash	(834)	(846)	(1,649)	(1,547)
Net Debt (Non-GAAP) - (c)	5,553	5,541	5,338	5,440

Total Capitalization (GAAP) - (a) + (b)	22,670	20,309	20,889	20,915

Total Capitalization (Non-GAAP) - (a) + (c)	21,836	19,463	19,240	19,368

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	28.2%	31.4%	33.4%	33.4%

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

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

Total Stockholders' Equity - (a)	13,982	11,798	12,057	12,405	12,956

Current and Long-Term Debt (GAAP) - (b)	6,986	6,986	6,986	6,986	6,656
Less: Cash	(1,600)	(1,049)	(780)	(668)	(719)
Net Debt (Non-GAAP) - (c)	5,386	5,937	6,206	6,318	5,937

Total Capitalization (GAAP) - (a) + (b)	20,968	18,784	19,043	19,391	19,612

Total Capitalization (Non-GAAP) - (a) + (c)	19,368	17,735	18,263	18,723	18,893

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	33.3%	37.2%	36.7%	36.0%	33.9%

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

Proved Reserves and Reserve Replacement Data


(Unaudited)

2021 Net Proved Reserves Reconciliation Summary	United States	Trinidad	Other International	Total
Crude Oil and Condensate (MMBbl)
Beginning Reserves	1,513	1	—	1,514
Revisions	(116)	—	—	(116)
Purchases in Place	2	—	—	2
Extensions, Discoveries and Other Additions	311	1	—	312
Sales in Place	(2)	—	—	(2)
Production	(162)	—	—	(162)
Ending Reserves	1,546	2	—	1,548

Natural Gas Liquids (MMBbl)
Beginning Reserves	813	—	—	813
Revisions	(128)	—	—	(128)
Purchases in Place	3	—	—	3
Extensions, Discoveries and Other Additions	194	—	—	194
Sales in Place	—	—	—	—
Production	(53)	—	—	(53)
Ending Reserves	829	—	—	829

Natural Gas (Bcf)
Beginning Reserves	5,043	269	48	5,360
Revisions	754	26	3	783
Purchases in Place	23	—	—	23
Extensions, Discoveries and Other Additions	2,574	100	—	2,674
Sales in Place	(4)	—	(48)	(52)
Production	(483)	(80)	(3)	(566)
Ending Reserves	7,907	315	—	8,222

Oil Equivalents (MMBoe)
Beginning Reserves	3,166	46	8	3,220
Revisions	(118)	4	—	(114)
Purchases in Place	9	—	—	9
Extensions, Discoveries and Other Additions	934	18	—	952
Sales in Place	(3)	—	(8)	(11)
Production	(295)	(14)	—	(309)
Ending Reserves	3,693	54	—	3,747

Net Proved Developed Reserves (MMBoe)
At December 31, 2020	1,614	30	5	1,649
At December 31, 2021	1,926	22	—	1,948

2021 Exploration and Development Expenditures ($ Millions)

Acquisition Cost of Unproved Properties	207	—	8	215
Exploration Costs	296	7	51	354
Development Costs	3,120	53	—	3,173
Total Drilling	3,623	60	59	3,742
Acquisition Cost of Proved Properties	100	—	—	100
Asset Retirement Costs	86	24	17	127
Total Exploration and Development Expenditures	3,809	84	76	3,969
Gathering, Processing and Other	283	—	3	286
Total Expenditures	4,092	84	79	4,255
Proceeds from Sales in Place	(102)	—	(129)	(231)
Net Expenditures	3,990	84	(50)	4,024

Reserve Replacement Costs ($ / Boe) *
All-in Total, Net of Revisions	4.45	2.73	—	4.48
All-in Total, Excluding Revisions Due to Price	5.82	2.73	—	5.81

Reserve Replacement *
Drilling Only	317 %	129 %	0 %	308 %
All-in Total, Net of Revisions and Dispositions	279 %	157 %	0 %	271 %
All-in Total, Excluding Revisions Due to Price	213 %	157 %	0 %	208 %
All-in Total, Liquids	123 %	0 %	0 %	123 %

* See following reconciliation schedule for calculation methodology

Reserve Replacement Cost Data


(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2021	United States	Trinidad	Other International	Total

Total Costs Incurred in Exploration and Development Activities (GAAP)	3,809	84	76	3,969
Less: Asset Retirement Costs	(86)	(24)	(17)	(127)
Non-Cash Acquisition Costs of Unproved Properties	(45)	—	—	(45)
Total Acquisition Costs of Proved Properties	(100)	—	—	(100)
Total Exploration and Development Expenditures for Drilling Only (Non- GAAP) - (a)	3,578	60	59	3,697

Total Costs Incurred in Exploration and Development Activities (GAAP)	3,809	84	76	3,969
Less: Asset Retirement Costs	(86)	(24)	(17)	(127)
Non-Cash Acquisition Costs of Unproved Properties	(45)	—	—	(45)
Non-Cash Acquisition Costs of Proved Properties	(5)	—	—	(5)
Total Exploration and Development Expenditures (Non-GAAP) - (b)	3,673	60	59	3,792

Total Expenditures (GAAP)	4,092	84	79	4,255
Less: Asset Retirement Costs	(86)	(24)	(17)	(127)
Non-Cash Acquisition Costs of Unproved Properties	(45)	—	—	(45)
Non-Cash Acquisition Costs of Proved Properties	(5)	—	—	(5)
Non-Cash Capital - Other Miscellaneous	(74)	—	—	(74)
Total Cash Expenditures (Non-GAAP)	3,882	60	62	4,004

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	194	—	—	194
Revisions Other Than Price	(312)	4	—	(308)
Purchases in Place	9	—	—	9
Extensions, Discoveries and Other Additions - (d)	934	18	—	952
Total Proved Reserve Additions - (e)	825	22	—	847
Sales in Place	(3)	—	(8)	(11)
Net Proved Reserve Additions From All Sources - (f)	822	22	(8)	836

Production - (g)	295	14	—	309

Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	3.83	3.33	—	3.88
All-in Total, Net of Revisions - (b / e)	4.45	2.73	—	4.48
All-in Total, Excluding Revisions Due to Price - (b / (e - c))	5.82	2.73	—	5.81

Reserve Replacement
Drilling Only - (d / g)	317 %	129 %	0 %	308 %
All-in Total, Net of Revisions and Dispositions - (f / g)	279 %	157 %	0 %	271 %
All-in Total, Excluding Revisions Due to Price - ((f - c) / g)	213 %	157 %	0 %	208 %

Net Proved Reserve Additions From All Sources - Liquids (MMBbl)
Revisions	(244)	—	—	(244)
Purchases in Place	5	—	—	5
Extensions, Discoveries and Other Additions - (h)	505	1	—	506
Total Proved Reserve Additions	266	1	—	267
Sales in Place	(2)	—	—	(2)
Net Proved Reserve Additions From All Sources - (i)	264	1	—	265

Production - (j)	215	—	—	215

Reserve Replacement - Liquids
Drilling Only - (h / j)	235 %	0 %	0 %	235 %
All-in Total, Net of Revisions and Dispositions - (i / j)	123 %	0 %	0 %	123 %

Reserve Replacement Cost Data


(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2021

Proved Developed Reserve Replacement Costs ($ / Boe)	Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	3,969
Less: Asset Retirement Costs	(127)
Acquisition Costs of Unproved Properties	(215)
Acquisition Costs of Proved Properties	(100)
Drillbit Exploration and Development Expenditures (Non-GAAP) - (k)	3,527

Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe)	952
Add: Conversion of Proved Undeveloped Reserves to Proved Developed	243
Less: Proved Undeveloped Extensions and Discoveries	(779)
Proved Developed Reserves - Extensions and Discoveries (MMBoe)	416

Total Proved Reserves - Revisions (MMBoe)	(114)
Less: Proved Undeveloped Reserves - Revisions	305
Proved Developed - Revisions Due to Price	(165)
Proved Developed Reserves - Revisions Other Than Price (MMBoe)	26

Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (l)	442

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) - (k / l)	7.98

Reserve Replacement Cost Data


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

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

	2021	2020	2019	2018

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

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

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

Production	309	285	301	265

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

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

	2017	2016	2015	2014

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

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

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

Production	224	206	210	220

Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	9.64	12.51	17.87	14.58
All-in Total, Net of Revisions - (b / e)	6.56	6.52	(29.63)	12.16
All-in Total, Excluding Revisions Due to Price - (b / ( e - c))	8.71	5.22	11.91	13.25

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

Financial Commodity Derivative Contracts


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

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2021, (closed) and remaining for 2022 and thereafter as of February 18, 2022.

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 2022 (closed)	NYMEX WTI	140	65.58
February - 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	100	70.15
October - December 2023	NYMEX WTI	69	69.41

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 - December 2021 (closed)	NYMEX WTI Roll Differential⁽¹⁾	125	0.17
January - February 2022 (closed)	NYMEX WTI Roll Differential⁽¹⁾	125	0.15
March - 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 - December 2021 (closed)	Mont Belvieu Propane (non-Tet)	15	$ 29.44

Financial Commodity Derivative Contracts (Continued)

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 - December 2021 (closed)	NYMEX Henry Hub	500	2.99	500	2.83
January - December 2022 (closed)⁽¹⁾	NYMEX Henry Hub	20	2.75	—	—
January - February 2022 (closed)	NYMEX Henry Hub	725	3.57	—	—
March - 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 - February 2022 (closed)	NYMEX Henry Hub HSC Differential⁽¹⁾	210	$ (0.01)
March - December 2022	NYMEX Henry Hub HSC Differential⁽¹⁾	210	(0.01)
January - December 2023	NYMEX Henry Hub HSC Differential⁽¹⁾	135	(0.01)
January - December 2024	NYMEX Henry Hub HSC Differential⁽¹⁾	10	0.00
January - December 2025	NYMEX Henry Hub HSC Differential⁽¹⁾	10	0.00


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

Financial Commodity Derivative Contracts (Continued)

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.

	2021	2020	2019	2018	2017

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

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

Total Stockholders' Equity - (d)	22,180	20,302	21,641	19,364	16,283

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

Current and Long-Term Debt (GAAP) - (f)	5,109	5,816	5,175	6,083	6,387
Less: Cash	(5,209)	(3,329)	(2,028)	(1,556)	(834)
Net Debt (Non-GAAP) - (g)	(100)	2,487	3,147	4,527	5,553

Total Capitalization (GAAP) - (d) + (f)	27,289	26,118	26,816	25,447	22,670

Total Capitalization (Non-GAAP) - (d) + (g)	22,080	22,789	24,788	23,891	21,836

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

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

Return on Equity (ROE)
GAAP Net Income (Loss) - (b) / (e)	22.0%	-2.9%	13.3%	19.2%
Non-GAAP Adjusted Net Income - (c) / (e)	23.7%	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, 2021
Adjustments:
Add: Mark-to-Market Commodity Derivative Contracts Impact	514	(112)	402
Add: Certain Impairments	15	—	15
Less: Gains on Asset Dispositions, Net	(17)	9	(8)
Less: Tax Benefits Related to Exiting Canada Operations	—	(45)	(45)
Total	512	(148)	364

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

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

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

ROCE & ROE


In millions of USD, except ratio data (Unaudited)

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

	2017	2016	2015

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

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

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

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

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

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

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

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

Return on Capital Employed (ROCE)
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.

	4Q 2021	3Q 2021	2Q 2021	1Q 2021	4Q 2020

Volume - Million Barrels of Oil Equivalent - (a)	79.4	77.7	75.3	70.1	73.7

Total Operating Revenues and Other (b)	6,044	4,765	4,139	3,694	2,965
Total Operating Expenses (c)	3,516	3,294	2,968	2,762	2,477
Operating Income (Loss) (d)	2,528	1,471	1,171	932	488

Wellhead Revenues
Crude Oil and Condensate	3,246	2,929	2,699	2,251	1,711
Natural Gas Liquids	583	548	367	314	229
Natural Gas	847	568	404	625	302
Total Wellhead Revenues - (e)	4,676	4,045	3,470	3,190	2,242

Operating Costs
Lease and Well	325	270	270	270	261
Transportation Costs	228	219	214	202	195
Gathering and Processing Costs	147	145	128	139	119
General and Administrative	139	142	120	110	113
Taxes Other Than Income	316	277	239	215	114
Interest Expense, Net	38	48	45	47	53
Total Operating Cost (excluding DD&A and Total Exploration Costs) (f)	1,193	1,101	1,016	983	855

Depreciation, Depletion and Amortization (DD&A)	910	927	914	900	870

Total Operating Cost (excluding Total Exploration Costs) - (g)	2,103	2,028	1,930	1,883	1,725

Exploration Costs	42	44	35	33	41
Dry Hole Costs	43	4	13	11	—
Impairments	206	82	44	44	143
Total Exploration Costs (GAAP)	291	130	92	88	184
Less: Certain Impairments ⁽¹⁾	—	(13)	(1)	(1)	(86)
Total Exploration Costs (Non-GAAP)	291	117	91	87	98

Total Operating Cost (including Total Exploration Costs (GAAP)) - (h)	2,394	2,158	2,022	1,971	1,909
Total Operating Cost (including Total Exploration Costs (Non-GAAP)) - (i)	2,394	2,145	2,021	1,970	1,823

Total Wellhead Revenues less Total Operating Cost (including Total Exploration Costs (GAAP))	2,282	1,887	1,448	1,219	333
Total Wellhead Revenues less Total Operating Cost (including Total Exploration Costs (Non-GAAP))	2,282	1,900	1,449	1,220	419

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

	4Q 2021	3Q 2021	2Q 2021	1Q 2021	4Q 2020

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

Composite Average Operating Revenues and Other per Boe - (b) / (a)	76.12	61.33	54.97	52.70	40.23
Composite Average Operating Expenses per Boe - (c) / (a)	44.28	42.40	39.42	39.40	33.61
Composite Average Operating Income (Loss) per Boe - (d) / (a)	31.84	18.93	15.55	13.30	6.62

Composite Average Wellhead Revenue per Boe - (e) / (a)	58.88	52.07	46.07	45.49	30.39

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)	15.02	14.19	13.48	14.02	11.60

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]	43.86	37.88	32.59	31.47	18.79

Total Operating Cost per Boe (excluding Total Exploration Costs) - (g) / (a)	26.48	26.12	25.61	26.86	23.41

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (g) / (a)]	32.40	25.95	20.46	18.63	6.98

Total Operating Cost per Boe (including Total Exploration Costs) - (h) / (a)	30.15	27.79	26.85	28.12	25.90

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (h) / (a)]	28.73	24.28	19.22	17.37	4.49

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

Total Operating Cost per Boe (including Total Exploration Costs) - (i) / (a)	30.14	27.62	26.85	28.11	24.72

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (i) / (a)]	28.74	24.45	19.25	17.38	5.67

(1)

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

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

	2021		2020	2019	2018	2017

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

	2016	2015	2014

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

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SOURCE EOG Resources, Inc.

EOG Resources Reports Fourth Quarter and Full-Year 2021 Results; Announces 2022 Capital Program; Declares $1.00 per Share Special Dividend

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EOG Resources Reports Fourth Quarter and Full-Year 2021 Results; Announces 2022 Capital Program; Declares $1.00 per Share Special Dividend

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