EOG Resources Reports Fourth Quarter and Full-Year 2020 Results; Raises Dividend by 10% and Announces 2021 Capital Program Focused on Improving Total Returns; Sets Goal to Achieve Zero Routine Flaring by 2025 and Ambition to Reach Net Zero Scope 1 and 2 GHG Emissions by 2040

Rhea-AI Summary

EOG Resources reported strong fourth quarter and full-year 2020 results, highlighting a net income of $337 million for Q4 and $850 million for the year, with adjusted earnings of $0.71 per share. The company generated $666 million in free cash flow in Q4, leading to a 10% dividend increase to an annual rate of $1.65. EOG's capital expenditures were below guidance, emphasizing operational efficiency, while maintaining a debt-to-total capitalization of 22.3%. EOG aims to achieve zero routine flaring by 2025 and net zero GHG emissions by 2040.

Positive

• Increased dividend by 10% to $1.65 annual rate.
• Generated $1.6 billion free cash flow at an average WTI oil price of $39.
• Reduced well costs by 15% and cash operating costs by 4%.

Negative

• Net income dropped from $2.735 billion in FY 2019 to a loss of $605 million in FY 2020.
• Crude oil volumes decreased by 10% compared to 2019 due to market conditions.

HOUSTON, Feb. 25, 2021 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2020 results. Supplemental financial tables, a related presentation and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions are available on EOG's website at http://investors.eogresources.com/investors. Such reconciliation schedules are also included herein.

Key Financial Results
In millions of USD, except per-share and ratio data

		4Q 2020		3Q 2020		4Q 2019		FY 2020		FY 2019
GAAP	Total Revenue	2,965		2,246		4,320		11,032		17,380
	Net Income (Loss)	337		(43)		637		(605)		2,735
	Net Income (Loss) Per Share	0.58		(0.07)		1.10		(1.04)		4.71
	Net Cash Provided by Operating Activities	1,121		1,214		1,807		5,008		8,163
	Total Expenditures	1,108		646		1,506		4,113		6,900
	Current and Long-Term Debt	5,816		5,721		5,175		5,816		5,175
	Cash and Cash Equivalents	3,329		3,066		2,028		3,329		2,028
	Debt-to-Total Capitalization	22.3	%	22.1	%	19.3	%	22.3	%	19.3	%
Non- GAAP	Adjusted Net Income	411		252		787		850		2,893
	Adjusted Net Income Per Share	0.71		0.43		1.35		1.46		4.98
	Discretionary Cash Flow	1,494		1,261		2,111		5,093		8,122
	Cash Capital Expenditures before Acquisitions	829		499		1,388		3,490		6,234
	Free Cash Flow	666		762		723		1,603		1,888
	Net Debt	2,487		2,655		3,147		2,487		3,147
	Net Debt-to-Total Capitalization	10.9	%	11.6	%	12.7	%	10.9	%	12.7	%

From William R. "Bill" Thomas, Chairman and Chief Executive Officer

"EOG made significant improvements to its operating performance during 2020, across every area of the company. The benefits of these improvements are reflected in our fourth quarter results, and have created strong momentum as we set out to drive even better performance in 2021. I want to thank our talented employees for their ongoing dedication and focus, which drove significant progress and innovation in a challenging environment.

"We implemented countless innovations across the company in 2020 that sustainably reduced well costs and operating costs. We also made progress on a number of new exploration plays with the objective of increasing capital efficiency and returns while lowering the production decline rate. And we remained focused on strong environmental and safety performance which, together with our low cost structure, position EOG to be a significant part of the long–term energy solution."

 

 

Fourth Quarter and Full-Year 2020 Highlights

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Volumes and Capital Expenditures

Wellhead Volumes	4Q 2020	4Q 2020 Guidance Midpoint	3Q 2020	4Q 2019	FY 2020	FY 2019
Crude Oil and Condensate (MBod)	444.8	441.9	377.6	468.9	409.2	456.2
Natural Gas Liquids (MBbld)	141.4	145.0	140.1	144.0	136.0	134.1
Natural Gas (MMcfd)	1,292	1,275	1,190	1,425	1,252	1,366
Total Crude Oil Equivalent (MBoed)	801.5	799.4	716.0	850.3	753.8	818.0
Cash Capital Expenditures before Acquisitions ($MM)	829	880	499	1,388	3,490	6,234

Full–Year 2020

• Generated $1.6 billion free cash flow at $39 average WTI oil price
• Earned $850 million adjusted net income in 2020, or $1.46 per share
• Reduced well costs 15% and per–unit cash operating costs 4%
• Replaced 159% of production at $6.98 per Boe finding and development cost

Fourth Quarter 2020

• Generated $666 million free cash flow
• Capital expenditures 6% below guidance midpoint with oil production 1% above guidance midpoint
• Per–unit cash operating cost 11% below guidance midpoint

2021 Plan

• Increased common stock dividend by 10% to $1.65 indicated annual rate
• Capital plan of $3.7 to $4.1 billion maintains oil production at 4Q 2020 rate and funds growing exploration program along with targeted cost and emissions reduction projects
• 2021 capital plan and dividend funded with discretionary cash flow at less than $40 WTI oil price
• Sets goal to achieve zero routine flaring by 2025 and set ambition to reach net zero scope 1 and scope 2 GHG emissions by 2040

Fourth Quarter 2020 Financial Performance

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Adjusted Earnings per Share 4Q 2020 vs 3Q 2020

Price and Hedges
Higher prices for natural gas, natural gas liquids and crude oil all contributed to higher QoQ earnings. This was partially offset by a decrease in hedge settlements, to $72 million received in 4Q 2020 from $275 million received in 3Q 2020.

Volume
Total company crude oil production of 444,800 Bopd in the fourth quarter was above the guidance midpoint and increased 18% QoQ. Production increased 1% for NGLs and increased 9% for natural gas, for a 12% increase in total company equivalent volumes.

Per-Unit Costs
EOG demonstrated significant operating discipline as most per‐unit cost categories decreased QoQ. The largest contributors to cost improvements were DD&A, taxes other than income, G&A and exploration.

Other
The effective tax rate on an adjusted basis decreased 1.1% QoQ, offset by a decrease in other income.

 

Change in Cash 4Q 2020 vs 3Q 2020

Free Cash Flow
Net cash provided by operating activities, plus exploration expense and changes in working capital, yielded discretionary cash flow of $1.5 billion in 4Q 2020. EOG incurred $829 million of cash capital expenditures before acquisitions, resulting in $666 million of free cash flow.

Capital Expenditures
Cash capital expenditures before acquisitions were below the low end of the guidance range due to lower than forecast exploration and infrastructure spending.

 

Full-Year 2020 Financial Performance

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Adjusted Earnings per Share 2020 vs 2019

Price and Hedges
Crude oil prices declined by 33% in 2020 compared with 2019, while prices for NGLs and natural gas declined by 16% and 23%, respectively. This was partially offset by an increase in hedge settlements, to $1.1 billion received in 2020 from $231 million received in 2019.

Volume
In response to low crude oil prices, EOG shut‐in certain wells during 2020 to defer production to future periods with higher prices, reducing 2020 crude oil volumes by 25,000 Bopd. Total company crude oil volumes in 2020 were 409,200 Bopd, 10% lower than 2019. For the year, NGL volumes increased 1% while natural gas volumes decreased 8%, contributing to 8% lower total company daily production.

Per-Unit Costs
EOG achieved significant per‐unit cost reductions during 2020, driven by sustainable efficiency improvements. Lease and well costs declined 16% on a per‐unit basis compared with 2019, to $3.85 per Boe. This was the largest contributor to the overall 4% reduction in per‐unit cash operating costs. A 2% decrease in per‐unit rates for DD&A and lower taxes other than income also contributed to the YoY cost improvement.

Other
Lower marketing margin (gathering, processing and marketing revenue less marketing costs), other revenue and other income contributed to lower adjusted EPS in 2020 vs. 2019. The effective tax rate on an adjusted basis in 2020 was similar compared with 2019.

Change in Cash 2020 vs 2019

Free Cash Flow
Net cash provided by operating activities, plus exploration expense and changes in working capital, yielded discretionary cash flow of $5.1 billion in 2020. EOG incurred $3.5 billion of cash capital expenditures before acquisitions, resulting in $1.6 billion of free cash flow.

Capital Expenditures
Cash capital expenditures before acquisitions of $3.5 billion decreased 44% from 2019.

 

Fourth Quarter 2020 Operating Performance

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Lease and Well
LOE costs declined 17% compared with the prior–year period and were also $0.51 below the 4Q 2020 guidance midpoint, representing the largest contribution to the per–unit total cash cost performance compared with guidance. Lower workover and water handling costs were the largest contributors to the strong LOE performance.

General and Administrative
EOG maintained its staffing and salary levels during 2020, with a focus on protecting its unique culture and organizational effectiveness. Reductions in certain employee-related costs were the primary contributors to lower per-unit G&A costs.

Transportation, Gathering and Processing
Increased production volumes from the return of shut–in wells and the startup of new wells contributed to the per–unit cost reductions in 4Q 2020 compared with 3Q 2020.

Depreciation, Depletion and Amortization
The addition of new wells with lower finding costs and positive revisions from lower production costs contributed to the overall reduction in per–unit DD&A costs.

 

2020 Reserves and Dividend Increase

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Finding and Development Cost

• Finding and development cost, excluding price revisions, declined 15% YoY in 2020 to $6.98 per Boe.
• Proved developed finding cost, excluding price revisions, declined 33% compared with 2019 to $7.41 per Boe.
• Total drilling finding and development cost, excluding revisions, fell by 27% to $5.79 per Boe.
• For the 33rd consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and McNaughton.

2020 Reserve Replacement

• Net proved reserve additions from all sources, excluding price revisions, replaced 159% of 2020 production. Extensions and discoveries were the largest contributor to the additions
• Reduction in the number of wells in our future development plan, partially offset by lower forecast production costs, drove other than price (OTP) revision.

Sustainable, Growing Dividend Since 1999

• The Board of Directors declared a dividend of $0.4125 per share on EOG's Common Stock.
• The new dividend represents a 10% increase from the prior level and a cumulative increase of 146% since 2017.
• The dividend is payable April 30, 2021 to stockholders of record as of April 16, 2021.
• The indicated annual rate is $1.65.

 

2021 Capital Plan

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Low Breakeven Unhedged Oil Price with Significant Free Cash Flow Leverage

• Capital plan of $3.7 to $4.1 billion and dividend funded at less than $40 WTI oil price, before considering cash received or paid for settlements of commodity derivative contracts
• Plan maintains 2021 crude oil volumes of 434,000 to 446,000 Bopd, approximately flat with 4Q 2020
• No plans to increase capital expenditures or grow production volumes during 2021, even in higher commodity price environment
• Focused on double–premium potential locations – minimum 60% ATROR at flat $40 WTI and $2.50 HH
• Complete approximately 500 net wells in 2021 focused on Delaware Basin, Eagle Ford and Powder River Basin
• Accelerating leasing and testing of numerous high–impact exploration projects
• Capital plan also funds international plays and environmental projects

Additional Comments from Bill Thomas
"The 2021 capital plan is consistent with the strategy we have followed over the last year of not growing production in an oversupplied market. We are focused on increasing returns, generating free cash flow and maintaining our productive capacity while the oil market rebalances. In addition, we continue to invest in infrastructure to support reliable, safe, low-cost and low-emissions operations. With the improvements we have made in our operations and the size and quality of our premium inventory, we can now focus our capital allocation on the top half of our premium inventory – wells that are double–premium or better. Using double-premium investment metrics will make a step-change improvement in EOG's future performance.

"We continue to press forward in our exploration efforts and are allocating more capital in 2021 to test high–impact oil plays and lease acreage. While much of the industry is scaling back or abandoning exploration, we are confident that our pipeline of new high–return plays can significantly increase the long–term value of EOG and we are pursuing them aggressively.

"The increase in the regular dividend reflects the significant progress EOG has made in the past 12 months. We have lowered operating costs and well costs, in turn reducing the breakeven oil price needed to maintain our production. It also demonstrates the confidence we have in the resiliency of our business. We will evaluate all options to maximize total shareholder return as cash becomes available."

 

Committed to ESG Performance

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EOG Sustainability Ambitions

• Endorsed World Bank Zero Routine Flaring by 2030 Initiative with goal to achieve that standard by 2025
• Set goal to capture 99.8% of wellhead gas in 2021 compared with 99.6% in 2020
• Expanding first–of–its–kind closed–loop gas capture project in partnership with New Mexico Oil Conservation Division to minimize flaring caused by downstream market interruptions
• Set ambition to reach net zero scope 1 and scope 2 GHG emissions3 by 2040
• EOG believes achieving our net zero ambition helps support the broader framework of the Paris Agreement

Additional Comments from Bill Thomas
"I'm very proud of our employees for their efforts to deliver significant improvements in EOG's safety and environmental results the past several years. It is a strong testament to EOG's culture and only happens when everyone is focused and working together.

"We are moving aggressively to continue to improve our strong record of environmental performance. We are aiming to capture 99.8% of wellhead gas in 2021 and our goal is to eliminate routine flaring by 2025. We also keep raising the bar on water management, procuring more of our water from reuse sources every year. These efforts both reduce our environmental footprint and lower our costs.

"In the long run, our environmental ambitions are as bold as the rest of our operations. We have made significant progress the past several years, applying innovation and technology through our decentralized culture to reduce our emissions intensity. This progress, along with our ambition to reduce scope 1 and scope 2 GHG emissions to net zero by 2040, motivates us to pursue further innovations for the future. EOG is focused on being among the lowest cost, highest return and lowest emissions producers, playing a significant role in the long–term future of energy."

 

Fourth Quarter 2020 Results vs Guidance

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Crude Oil and Condensate (MBod)	4Q 2020		4Q 2020 Guidance Midpoint		Variance		3Q 2020		2Q 2020		1Q 2020		4Q 2019
US	442.4		440.0		2.4		376.6		330.9		482.7		468.3
Trinidad	2.3		1.8		0.5		1.0		0.1		0.5		0.5
Other Intl	0.1		0.1		0.0		0.0		0.1		0.1		0.1
Total	444.8		441.9		2.9		377.6		331.1		483.3		468.9
NGLs (MBbld)
Total	141.4		145.0		(3.6)		140.1		101.2		161.3		144.0
Natural Gas (MMcfd)
US	1,075		1,070		5		1,008		939		1,139		1,148
Trinidad	192		180		12		151		174		201		242
Other Intl	25		25		0		31		34		38		35
Total	1,292		1,275		17		1,190		1,147		1,378		1,425
Total Crude Oil Equivalent Volumes (MBoed)	801.5		799.4		2.1		716.0		623.4		874.1		850.3
Total MMBoe	73.7		73.5		0.2		65.9		56.7		79.5		78.2
Capital Expenditures ($MM)	829		880		(51)		499		478		1,685		1,388
Benchmark Price
Oil (WTI) ($/Bbl)	42.67						40.94		27.85		46.08		56.96
Natural Gas (HH) ($/Mcf)	2.65						1.94		1.73		1.98		2.49
Crude Oil and Condensate ($/Bbl) - above (below) WTI
US	(0.81)		(0.85)		0.04		(0.75)		(7.45)		0.89		0.18
Trinidad	(9.76)		(13.40)		3.64		(15.53)		(27.25)		(11.15)		(10.23)
Other Intl	(6.77)		(5.00)		(1.76)		(15.65)		20.93		11.43		($3.20)
NGLs - Realizations (% of WTI)	41.1%		40.0%		1.1%		35.0%		36.6%		23.7%		28.5%
Nat Gas ($/Mcf) - above (below) HH
US	(0.36)		(0.40)		0.04		(0.45)		(0.62)		(0.48)		(0.29)
Natural Gas Realizations ($/Mcf)
Trinidad	3.57		3.40		0.17		2.35		2.13		2.17		2.78
Other Intl	5.47		4.60		0.87		4.73		4.36		4.32		4.88
Unit Costs ($/Boe)
Lease and Well	3.54		4.05		(0.51)		3.45		4.32		4.14		4.28
Transportation Costs	2.64		2.75		(0.11)		2.74		2.67		2.62		2.66
General and Administrative	1.54		1.85		(0.31)		1.89		2.32		1.44		1.60
Gathering and Processing	1.62		1.80		(0.18)		1.74		1.71		1.62		1.63
Cash Operating Costs	9.34		10.45		(1.11)		9.82		11.02		9.82		10.17
DD&A	11.81		12.45		(0.64)		12.49		12.46		12.57		12.26
Expenses ($MM)
Exploration and Dry Hole	40		50		(10)		51		27		40		36
Impairment (GAAP)	142						79		305		1,573		228
Impairment (excluding certain impairments (non-GAAP))	56		125		(69)		52		66		57		69
Capitalized Interest	7		8		(1)		7		8		9		10
Net Interest	53		54		(1)		53		54		45		41
Taxes Other Than Income (% of Wellhead Revenue)	5.1%		7.0%		-1.9%		7.2%		9.4%		6.5%		6.7%
Income Taxes
Effective Rate	21.1%		22.5%		-1.3%		19.2%		20.6%		68.4%		23.4%
Current Tax (Benefit) / Expense ($MM)	36		30		6		23		17		(136)		12

 

First Quarter and Full-Year 2021 Guidance

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	1Q 2021 Guidance Range				FY 2021 Guidance Range				2020 Act		2019 Act
Crude Oil and Condensate (MBod)
US	418.0	-	428.0		433.0	-	444.0		408.1		455.5
Trinidad	1.6	-	2.4		1.0	-	1.8		1.0		0.6
Other Intl	0.0	-	0.2		0.0	-	0.2		0.1		0.1
Total	419.6	-	430.6		434.0	-	446.0		409.2		456.2
NGLs (MBbld)
Total	125.0	-	135.0		130.0	-	170.0		136.0		134.1
Natural Gas (MMcfd)
US	1,095	-	1,155		1,100	-	1,200		1,040		1,069
Trinidad	200	-	230		180	-	220		180		260
Other Intl	15	-	25		15	-	25		32		37
Total	1,310	-	1,410		1,295	-	1,445		1,252		1,366
Total Crude Oil Equivalent Volumes (MBoed)	762.9	-	800.6		779.8	-	856.9		753.8		818.0
Total MMBoe	68.7	-	72.1		284.6	-	312.8		275.9		298.6
Benchmark Price
Oil (WTI) ($/Bbl)									39.40		57.04
Natural Gas (HH) ($/Mcf)									2.08		2.62
Crude Oil and Condensate ($/Bbl) - above (below) WTI
US	(0.80)	-	1.20		(0.55)	-	1.45		(0.75)		0.70
Trinidad	(11.50)	-	(9.50)		(12.40)	-	(10.40)		(9.20)		(9.88)
Other Intl	(21.00)	-	(15.00)		(19.20)	-	(17.20)		3.68		0.36
NGLs - Realizations (% of WTI)
Total	43%	-	55%		38%	-	50%		34.0%		28.1%
Nat Gas ($/Mcf) - above (below) HH
US	1.75	-	4.25		(0.25)	-	1.25		(0.47)		(0.40)
Natural Gas Realizations ($/Mcf)
Trinidad	3.10	-	3.60		3.10	-	3.60		2.57		2.72
Other Intl	5.45	-	5.95		5.20	-	6.20		4.66		4.44
Capital Expenditures ($MM)	900	-	1,100		3,700	-	4,100		3,490		6,234
Unit Costs ($/Boe)
Lease and Well	3.60	-	4.30		3.50	-	4.20		3.85		4.58
Transport Costs	2.60	-	3.00		2.65	-	3.05		2.66		2.54
General and Administrative	1.60	-	1.70		1.50	-	1.60		1.75		1.64
Gathering and Processing	1.75	-	1.85		1.65	-	1.85		1.66		1.60
Cash Operating Costs	9.55	-	10.85		9.30	-	10.70		9.92		10.36
Total DD&A	12.60	-	13.10		11.70	-	12.70		12.32		12.56
Expenses ($MM)
Exploration and Dry Hole	35	-	45		140	-	180		159		168
Impairment (GAAP)									2,100		518
Impairment (excluding certain impairments (non-GAAP))	45	-	95		255	-	295		232		243
Capitalized Interest	5	-	10		25	-	30		31		38
Net Interest	45	-	50		180	-	185		205		185
Taxes Other (% of Wellhead Revenue)	6.0%	-	8.0%		6.5%	-	7.5%		6.6%		6.9%
Income Taxes
Effective Rate	21%	-	26%		21%	-	26%		18.2%		22.9%
Deferred Ratio	(5%)	-	5%		0%	-	15%		54.8%		107.4%

Fourth Quarter 2020 Results Webcast
Friday, February 26, 2021, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors

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

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

Media and Investor Contact
Kimberly Ehmer 713–571–4676

Category: Earnings

Endnotes

1. Metric tons of gross operated GHG emissions (Scope 1), on a CO2e basis, per Mboe of total gross operated U.S. production.
2. Mcf of gross operated methane emissions (Scope 1) per Mcf of total gross operated U.S. natural gas production.
3. Total gross operated Scope 1 and 2 GHG emissions on a CO2e basis.

 

Glossary
Acq	Acquisitions
ATROR	After-tax rate of return
Bbl	Barrel
Bn	Billion
Boe	Barrels of oil equivalent
Bopd	Barrels of oil per day
Capex	Capital expenditures
CO2e	Carbon dioxide equivalent
DCF	Discretionary cash flow
DD&A	Depreciation, Depletion and Amortization
Disc	Discoveries
Divest	Divestitures
$MM	Million United States dollars
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
QoQ	Quarter over quarter
Trans	Transportation expense
USD	United States dollar
WTI	West Texas Intermediate
YoY	Year over year

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

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

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

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

Income Statements

In thousands of USD, except per share data (Unaudited)
	4Q 2020			3Q 2020			4Q 2019			FY 2020			FY 2019
Operating Revenues and Other
Crude Oil and Condensate	1,710,862			1,394,622			2,464,274			5,785,609			9,612,532
Natural Gas Liquids	228,299			184,771			215,070			667,514			784,818
Natural Gas	301,883			183,790			309,606			837,133			1,184,095
Gains (Losses) on Mark-to-Market        Commodity Derivative Contracts	69,304			(3,978)			(62,347)			1,144,737			180,275
Gathering, Processing and Marketing	642,597			538,955			1,238,792			2,582,984			5,360,282
Gains (Losses) on Asset Dispositions, Net	(5,600)			(70,976)			119,963			(46,883)			123,613
Other, Net	18,153			18,300			34,888			60,954			134,358
Total	2,965,498			2,245,484			4,320,246			11,032,048			17,379,973
Operating Expenses
Lease and Well	260,896			227,473			334,538			1,063,374			1,366,993
Transportation Costs	194,708			180,257			208,312			734,989			758,300
Gathering and Processing Costs	119,172			114,790			127,615			459,211			479,102
Exploration Costs	40,415			38,413			36,495			145,788			139,881
Dry Hole Costs	20			12,604			—			13,083			28,001
Impairments	142,440			78,990			228,135			2,099,780			517,896
Marketing Costs	622,941			521,351			1,237,259			2,697,729			5,351,524
Depreciation, Depletion and Amortization	870,564			823,050			959,208			3,400,353			3,749,704
General and Administrative	113,235			124,460			125,187			483,823			489,397
Taxes Other Than Income	113,445			126,810			199,746			477,934			800,164
Total	2,477,836			2,248,198			3,456,495			11,576,064			13,680,962
Operating Income (Loss)	487,662			(2,714)			863,751			(544,016)			3,699,011
Other Income (Expense), Net	(6,781)			3,401			8,152			10,228			31,385
Income (Loss) Before Interest Expense         and Income Taxes	480,881			687			871,903			(533,788)			3,730,396
Interest Expense, Net	53,121			53,242			40,695			205,266			185,129
Income (Loss) Before Income Taxes	427,760			(52,555)			831,208			(739,054)			3,545,267
Income Tax Provision (Benefit)	90,294			(10,088)			194,687			(134,482)			810,357
Net Income (Loss)	337,466			(42,467)			636,521			(604,572)			2,734,910
Dividends Declared per Common Share	0.3750			0.3750			0.2875			1.5000			1.0825
Net Income (Loss) Per Share
Basic	0.58			(0.07)			1.10			(1.04)			4.73
Diluted	0.58			(0.07)			1.10			(1.04)			4.71
Average Number of Common Shares
Basic	579,624			579,055			578,219			578,949			577,670
Diluted	580,885			579,055			580,849			578,949			580,777

 

Wellhead Volumes and Prices

(Unaudited)
	4Q 2020			4Q 2019			% Change			3Q 2020			FY 2020			FY 2019			% Change
Crude Oil and Condensate Volumes (MBbld) (A)
United States	442.4			468.3			-6	%		376.6			408.1			455.5			-10	%
Trinidad	2.3			0.5			360	%		1.0			1.0			0.6			67	%
Other International (B)	0.1			0.1			0	%		—			0.1			0.1			0	%
Total	444.8			468.9			-5	%		377.6			409.2			456.2			-10	%
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States	41.86			57.14			-27	%		40.19			38.65			57.74			-33	%
Trinidad	32.91			46.43			-30	%		25.41			30.20			47.16			-36	%
Other International (B)	35.90			53.76			-33	%		25.29			43.08			57.40			-25	%
Composite	41.81			57.13			-27	%		40.15			38.63			57.72			-33	%
Natural Gas Liquids Volumes (MBbld) (A)
United States	141.4			144.0			-2	%		140.1			136.0			134.1			1	%
Other International (B)	—			—						—			—			—
Total	141.4			144.0			-2	%		140.1			136.0			134.1			1	%
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States	17.54			16.23			8	%		14.34			13.41			16.03			-16	%
Other International (B)	—			—						—			—			—
Composite	17.54			16.23			8	%		14.34			13.41			16.03			-16	%
Natural Gas Volumes (MMcfd) (A)
United States	1,075			1,148			-6	%		1,008			1,040			1,069			-3	%
Trinidad	192			242			-21	%		151			180			260			-31	%
Other International (B)	25			35			-29	%		31			32			37			-14	%
Total	1,292			1,425			-9	%		1,190			1,252			1,366			-8	%
Average Natural Gas Prices ($/Mcf) (C)
United States	2.29			2.20			4	%		1.49			1.61			2.22			-27	%
Trinidad	3.57			2.78			28	%		2.35			2.57			2.72			-6	%
Other International (B)	5.47			4.88			12	%		4.73			4.66			4.44			5	%
Composite	2.54			2.36			8	%		1.68			1.83			2.38			-23	%
Crude Oil Equivalent Volumes (MBoed) (D)
United States	763.0			803.6			-5	%		684.7			717.5			767.8			-7	%
Trinidad	34.2			40.9			-16	%		26.2			30.9			44.0			-30	%
Other International (B)	4.3			5.8			-26	%		5.1			5.4			6.2			-13	%
Total	801.5			850.3			-6	%		716.0			753.8			818.0			-8	%
Total MMBoe (D)	73.7			78.2			-6	%		65.9			275.9			298.6			-8	%

(A)

Thousand barrels per day or million cubic feet per day, as applicable.

(B)

Other International includes EOG's China and Canada operations.

(C)

Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2020).

(D)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 

Balance Sheets

In thousands of USD, except share data (Unaudited)
	December 31,			December 31,
	2020			2019
Current Assets
Cash and Cash Equivalents	3,328,928			2,027,972
Accounts Receivable, Net	1,522,256			2,001,658
Inventories	629,401			767,297
Assets from Price Risk Management Activities	64,559			1,299
Income Taxes Receivable	23,037			151,665
Other	293,987			323,448
Total	5,862,168			5,273,339
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	64,792,798			62,830,415
Other Property, Plant and Equipment	4,478,976			4,472,246
Total Property, Plant and Equipment	69,271,774			67,302,661
Less:  Accumulated Depreciation, Depletion and Amortization	(40,673,147)			(36,938,066)
Total Property, Plant and Equipment, Net	28,598,627			30,364,595
Deferred Income Taxes	2,127			2,363
Other Assets	1,341,679			1,484,311
Total Assets	35,804,601			37,124,608
Current Liabilities
Accounts Payable	1,681,193			2,429,127
Accrued Taxes Payable	205,754			254,850
Dividends Payable	217,419			166,273
Liabilities from Price Risk Management Activities	—			20,194
Current Portion of Long-Term Debt	781,054			1,014,524
Current Portion of Operating Lease Liabilities	295,089			369,365
Other	279,595			232,655
Total	3,460,104			4,486,988
Long-Term Debt	5,035,351			4,160,919
Other Liabilities	2,147,932			1,789,884
Deferred Income Taxes	4,859,327			5,046,101
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,694,850 Shares and 582,213,016 Shares Issued at December 31, 2020 and 2019, respectively	205,837			205,822
Additional Paid in Capital	5,945,024			5,817,475
Accumulated Other Comprehensive Loss	(12,328)			(4,652)
Retained Earnings	14,169,969			15,648,604
Common Stock Held in Treasury, 124,265 Shares and 298,820 Shares at December 31, 2020 and 2019, respectively	(6,615)			(26,533)
Total Stockholders' Equity	20,301,887			21,640,716
Total Liabilities and Stockholders' Equity	35,804,601			37,124,608

 

Cash Flows Statements

In thousands of USD (Unaudited)
	4Q 2020			4Q 2019			FY 2020			FY 2019
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating    Activities:
Net Income (Loss)	337,466			636,521			(604,572)			2,734,910
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	870,564			959,208			3,400,353			3,749,704
Impairments	142,440			228,135			2,099,780			517,896
Stock-Based Compensation Expenses	32,942			42,415			146,396			174,738
Deferred Income Taxes	54,613			123,082			(186,390)			631,658
(Gains) Losses on Asset Dispositions, Net	5,600			(119,963)			46,883			(123,613)
Other, Net	11,190			341			12,826			4,496
Dry Hole Costs	20			—			13,083			28,001
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	(69,304)			62,347			(1,144,737)			(180,275)
Net Cash Received from Settlements of Commodity Derivative    Contracts	71,753			91,521			1,070,647			231,229
Other, Net	2,539			(253)			1,354			962
Changes in Components of Working Capital and Other Assets and    Liabilities
Accounts Receivable	(464,105)			(85,937)			466,523			(91,792)
Inventories	30,633			34,686			122,647			90,284
Accounts Payable	427,206			34,286			(795,267)			168,539
Accrued Taxes Payable	(61,491)			(47,925)			(49,096)			40,122
Other Assets	(90,336)			(36,572)			324,521			358,001
Other Liabilities	20,837			(38,304)			8,098			(56,619)
Changes in Components of Working Capital Associated with    Investing Activities	(201,329)			(76,384)			74,734			(115,061)
Net Cash Provided by Operating Activities	1,121,238			1,807,204			5,007,783			8,163,180
Investing Cash Flows
Additions to Oil and Gas Properties	(784,954)			(1,285,003)			(3,243,474)			(6,151,885)
Additions to Other Property, Plant and Equipment	(56,208)			(83,291)			(221,226)			(270,641)
Proceeds from Sales of Assets	2,985			104,883			191,928			140,292
Other Investing Activities	—			(10,000)			—			(10,000)
Changes in Components of Working Capital Associated with    Investing Activities	201,329			76,384			(74,734)			115,061
Net Cash Used in Investing Activities	(636,848)			(1,197,027)			(3,347,506)			(6,177,173)
Financing Cash Flows
Long-Term Debt Borrowings	—			—			1,483,852			—
Long-Term Debt Repayments	—			—			(1,000,000)			(900,000)
Dividends Paid	(219,581)			(167,349)			(820,823)			(588,200)
Treasury Stock Purchased	(1,309)			(2,914)			(16,130)			(25,152)
Proceeds from Stock Options Exercised and Employee Stock    Purchase Plan	7,555			8,388			16,169			17,946
Debt Issuance Costs	(14)			—			(2,649)			(5,016)
Repayment of Finance Lease Liabilities	(6,135)			(3,261)			(19,444)			(12,899)
Net Cash Used in Financing Activities	(219,484)			(165,136)			(359,025)			(1,513,321)
Effect of Exchange Rate Changes on Cash	(1,534)			(174)			(296)			(348)
Increase in Cash and Cash Equivalents	263,372			444,867			1,300,956			472,338
Cash and Cash Equivalents at Beginning of Period	3,065,556			1,583,105			2,027,972			1,555,634
Cash and Cash Equivalents at End of Period	3,328,928			2,027,972			3,328,928			2,027,972

 

Non-GAAP Financial Measures

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

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

EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance.

EOG believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods.

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

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

 

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)
	4Q 2020
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (GAAP)	427,760			(90,294)			337,466			0.58
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(69,304)			15,211			(54,093)			(0.10)
Net Cash Received from Settlements of Commodity Derivative Contracts	71,753			(15,749)			56,004			0.10
Add: Losses on Asset Dispositions, Net	5,600			(1,248)			4,352			0.01
Add: Certain Impairments	86,451			(18,692)			67,759			0.12
Adjustments to Net Income	94,500			(20,478)			74,022			0.13
Adjusted Net Income (Non-GAAP)	522,260			(110,772)			411,488			0.71
Average Number of Common Shares (GAAP)
Basic										579,624
Diluted										580,885
Average Number of Common Shares (Non-GAAP)
Basic										579,624
Diluted										580,885
	3Q 2020
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Loss (GAAP)	(52,555)			10,088			(42,467)			(0.07)
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	3,978			(873)			3,105			(0.01)
Net Cash Received from Settlements of Commodity Derivative Contracts	275,133			(60,386)			214,747			0.37
Add: Losses on Asset Dispositions, Net	70,976			(15,600)			55,376			0.10
Add: Certain Impairments	26,531			(5,636)			20,895			0.04
Adjustments to Net Loss	376,618			(82,495)			294,123			0.50
Adjusted Net Income (Non-GAAP)	324,063			(72,407)			251,656			0.43
Average Number of Common Shares (GAAP)
Basic										579,055
Diluted										579,055
Average Number of Common Shares (Non-GAAP)										579,055
Basic										580,609
Diluted

 

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)
	4Q 2019
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (GAAP)	831,208			(194,687)			636,521			1.10
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	62,347			(13,684)			48,663			0.08
Net Cash Received from Settlements of Commodity Derivative Contracts	91,521			(20,087)			71,434			0.12
Less: Gains on Asset Dispositions, Net	(119,963)			26,342			(93,621)			(0.16)
Add: Certain Impairments	158,725			(34,837)			123,888			0.21
Adjustments to Net Income	192,630			(42,266)			150,364			0.25
Adjusted Net Income (Non-GAAP)	1,023,838			(236,953)			786,885			1.35
Average Number of Common Shares (GAAP)
Basic										578,219
Diluted										580,849
Average Number of Common Shares (Non-GAAP)										578,219
Basic										580,849
Diluted

 

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)
	FY 2020
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Loss (GAAP)	(739,054)			134,482			(604,572)			(1.04)
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(1,144,737)			251,247			(893,490)			(1.55)
Net Cash Received from Settlements of Commodity Derivative Contracts	1,070,647			(234,986)			835,661			1.44
Add: Losses on Asset Dispositions, Net	46,883			(10,305)			36,578			0.06
Add: Certain Impairments	1,868,465			(392,652)			1,475,813			2.55
Adjustments to Net Loss	1,841,258			(386,696)			1,454,562			2.50
Adjusted Net Income (Non-GAAP)	1,102,204			(252,214)			849,990			1.46
Average Number of Common Shares (GAAP)
Basic										578,949
Diluted										578,949
Average Number of Common Shares (Non-GAAP)
Basic										578,949
Diluted										580,595
	FY 2019
	Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (GAAP)	3,545,267			(810,357)			2,734,910			4.71
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(180,275)			39,567			(140,708)			(0.24)
Net Cash Received from Settlements of Commodity Derivative Contracts	231,229			(50,750)			180,479			0.31
Less: Gains on Asset Dispositions, Net	(123,613)			27,252			(96,361)			(0.17)
Add: Certain Impairments	274,974			(60,351)			214,623			0.37
Adjustments to Net Income	202,315			(44,282)			158,033			0.27
Adjusted Net Income (Non-GAAP)	3,747,582			(854,639)			2,892,943			4.98
Average Number of Common Shares (GAAP)
Basic										577,670
Diluted										580,777
Average Number of Common Shares (Non-GAAP)
Basic										577,670
Diluted										580,777

 

Adjusted Net Income per Share

In thousands of USD, except share and per Boe data (Unaudited)
3Q 2020 Adjusted Net Income per Share (Non-GAAP)				0.43
Realized Price
4Q 2020 Composite Average Wellhead Revenue per Boe	30.39
Less:  3Q 2020 Composite Average Welhead Revenue per Boe	(26.77)
Subtotal	3.62
Multiplied by: 4Q 2020 Crude Oil Equivalent Volumes (MMBoe)	73.7
Total Change in Revenue	266,794
Less: Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%)	(17,342)
Net Change in Revenue	249,452
Less: Tax Benefit Imputed (based on 21%)	(52,385)
Change in Net Income	197,067
Change in Diluted Earnings per Share				0.34
Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts
4Q 2020 Net Cash Received from Settlement of Commodity Derivative Contracts	71,753
Less:  Income Tax Impact	(15,749)
After Tax - (a)	56,004
3Q 2020 Net Cash Received from Settlement of Commodity Derivative Contracts	275,133
Less:  Income Tax Impact	(60,386)
After Tax - (b)	214,747
Change in Net Income - (a) - (b)	(158,743)
Change in Diluted Earnings per Share				(0.27)
Wellhead Volumes
4Q 2020 Crude Oil Equivalent Volumes (MMBoe)	73.7
Less:  3Q 2020 Crude Oil Equivalent Volumes (MMBoe)	(65.9)
Subtotal	7.8
Times:  4Q 2020 Composite Average Margin per Boe (Non-GAAP)    (Including Total Exploration Costs) (refer to "Costs per Barrel of Oil Equivalent"    schedule)	5.67
Change in Revenue	44,226
Less:  Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%)	(2,875)
Net Change in Reveue	41,351
Less:  Tax Benefit Imputed (based on 21%)	(8,684)
Change in Net Income	32,668
Change in Diluted Earnings per Share				0.06
Operating Cost per Boe
3Q 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs)    (refer to "Costs per Barrel of Oil Equivalent" schedule)	26.62
Less:  4Q 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration    Costs) (refer to "Costs per Barrel of Oil Equivalent" schedule)	(24.72)
Subtotal	1.9
Times:  4Q 2020 Crude Oil Equivalent Volumes (MMBoe)	73.7
Change in Before-Tax Net Income	140,030
Less:  Tax Benefit Imputed (based on 21%)	(29,406)
Change in Net Income	110,624
Change in Diluted Earnings per Share				0.19
Other Items				(0.04)
4Q 2020 Adjusted Net Income per Share (Non-GAAP)				0.71
4Q 2020 Average Number of Common Shares (Non-GAAP) - Diluted	580,885

 

Adjusted Net Income per Share

In thousands of USD, except share and per Boe data (Unaudited)
FY 2019 Adjusted Net Income per Share (Non-GAAP)				4.98
Realized Price
FY 2020 Composite Average Wellhead Revenue per Boe	26.42
Less:  FY 2019 Composite Average Welhead Revenue per Boe	(38.79)
Subtotal	(12.37)
Multiplied by: FY 2020 Crude Oil Equivalent volumes (MMBoe)	275.9
Total Change in Revenue	(3,412,883)
Less: Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%)	221,837
Net Change in Revenue	(3,191,046)
Less: Tax Benefit Imputed (based on 21%)	670,120
Change in Net Income	(2,520,926)
Change in Diluted Earnings per Share				(4.34)
Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts
FY 2020 Net Cash Received from Settlement of Commodity Derivative Contracts	1,070,647
Less:  Income Tax Impact	(234,986)
After Tax - (a)	835,661
FY 2019 Net Cash Received from Settlement of Commodity Derivative Contracts	231,229
Less:  Income Tax Impact	(50,750)
After Tax - (b)	180,479
Change in Net Income - (a) - (b)	655,182
Change in Diluted Earnings per Share				1.13
Wellhead Volumes
FY 2020 Crude Oil Equivalent Volumes (MMBoe)	275.9
Less:  FY 2019 Crude Oil Equivalent Volumes (MMBoe)	(298.6)
Subtotal	(22.7)
Times:  FY 2020 Composite Average Margin per Boe (Non-GAAP)    (Including Total Exploration Costs) (refer to "Costs per Barrel of Oil Equivalent"    schedule)	0.29
Change in Revenue	(6,583)
Less:  Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%)	428
Net Change in Reveue	(6,155)
Less:  Tax Benefit Imputed (based on 21%)	1,293
Change in Net Income	(4,863)
Change in Diluted Earnings per Share				(0.01)
Operating Cost per Boe
FY 2019 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs)    (refer to "Costs per Barrel of Oil Equivalent" schedule)	27.6
Less:  FY 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration    Costs) (refer to "Costs per Barrel of Oil Equivalent" schedule)	(26.13)
Subtotal	1.47
Times:  FY 2020 Crude Oil Equivalent Volumes (MMBoe)	275.9
Change in Before-Tax Net Income	405,573
Less:  Tax Benefit Imputed (based on 21%)	(85,170)
Change in Net Income	320,403
Change in Diluted Earnings per Share				0.55
Other Items				(0.85)
FY 2020 Adjusted Net Income per Share (Non-GAAP)				1.46
FY 2020 Average Number of Common Shares (Non-GAAP) - Diluted	580,595

 

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)
	4Q 2020			3Q 2020			4Q 2019			FY 2020			FY 2019
Net Cash Provided by Operating Activities (GAAP)	1,121,238			1,213,553			1,807,204			5,007,783			8,163,180
Adjustments:
Exploration Costs (excluding Stock-Based Compensation    Expenses)	34,295			37,380			28,483			124,641			113,733
Other Non-Current Income Taxes - Net Receivable	—			—			59,174			112,704			238,711
Changes in Components of Working Capital and Other    Assets and Liabilities
Accounts Receivable	464,105			260,829			85,937			(466,523)			91,792
Inventories	(30,633)			(7,439)			(34,686)			(122,647)			(90,284)
Accounts Payable	(427,206)			37,755			(34,286)			795,267			(168,539)
Accrued Taxes Payable	61,491			(73,482)			47,925			49,096			(40,122)
Other Assets	90,336			(161,879)			36,572			(324,521)			(358,001)
Other Liabilities	(20,837)			(51,664)			38,304			(8,098)			56,619
Changes in Components of Working Capital Associated    with Investing and Financing Activities	201,329			6,091			76,384			(74,734)			115,061
Discretionary Cash Flow (Non-GAAP)	1,494,118			1,261,144			2,111,011			5,092,968			8,122,150
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease	-29	%								-37	%
Discretionary Cash Flow (Non-GAAP)	1,494,118			1,261,144			2,111,011			5,092,968			8,122,150
Less:
Total Cash Capital Expenditures Before Acquisitions    (Non-GAAP) (a)	(828,507)			(499,305)			(1,388,233)			(3,490,148)			(6,234,454)
Free Cash Flow (Non-GAAP) (b)	665,611			761,839			722,778			1,602,820			1,887,696
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month periods ended September 30, 2020 and December 31, 2020 and 2019 and twelve-month periods ended December 31, 2020 and 2019:
Total Expenditures (GAAP)	1,107,557			645,534			1,506,061			4,113,280			6,900,450
Less:
Asset Retirement Costs	(49,109)			(42,650)			(34,537)			(117,322)			(186,088)
Non-Cash Expenditures of Other Property, Plant and Equipment	(1)			—			(1,680)			(61)			(2,266)
Non-Cash Acquisition Costs of Unproved Properties	(68,337)			(80,757)			(33,317)			(196,825)			(97,704)
Non-Cash Finance Leases	(100,485)			—			—			(173,762)			—
Acquisition Costs of Proved Properties	(61,118)			(22,822)			(48,294)			(135,162)			(379,938)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	828,507			499,305			1,388,233			3,490,148			6,234,454
(b) To better align the  presentation of  free cash  flow for comparative purposes  within the industry, free cash flow  excludes dividends paid (GAAP) as a reconciling item for the three-month periods ending September 30, 2020 and December 31, 2020 and twelve-month periods ending December 31, 2020.  The comparative prior periods shown have been revised to conform to this presentation.
Maintenance Capital Expenditures
The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to 4Q 2020 U.S. oil production.

 

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)
	FY 2019			FY 2018			FY 2017
Net Cash Provided by Operating Activities (GAAP)	8,163,180			7,768,608			4,265,336
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	113,733			123,986			122,688
Other Non-Current Income Taxes - Net (Payable) Receivable	238,711			148,993			(513,404)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	91,792			368,180			392,131
Inventories	(90,284)			395,408			174,548
Accounts Payable	(168,539)			(439,347)			(324,192)
Accrued Taxes Payable	(40,122)			92,461			63,937
Other Assets	(358,001)			125,435			658,609
Other Liabilities	56,619			(10,949)			89,871
Changes in Components of Working Capital Associated with Investing and    Financing Activities	115,061			(301,083)			(89,992)
Discretionary Cash Flow (Non-GAAP)	8,122,150			8,271,692			4,839,532
Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease)	-2	%		71	%		76	%
Discretionary Cash Flow (Non-GAAP)	8,122,150			8,271,692			4,839,532
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)	(6,234,454)			(6,172,950)			(4,228,859)
Free Cash Flow (Non-GAAP) (b)	1,887,696			2,098,742			610,673
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017:
Total Expenditures (GAAP)	6,900,450			6,706,359			4,612,746
Less:
Asset Retirement Costs	(186,088)			(69,699)			(55,592)
Non-Cash Expenditures of Other Property, Plant and Equipment	(2,266)			(49,484)			—
Non-Cash Acquisition Costs of Unproved Properties	(97,704)			(290,542)			(255,711)
Acquisition Costs of Proved Properties	(379,938)			(123,684)			(72,584)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	6,234,454			6,172,950			4,228,859
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019.  The comparative prior periods shown have been revised to conform to this presentation.

 

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)
	FY 2016			FY 2015			FY 2014			FY 2013			FY 2012
Net Cash Provided by Operating Activities (GAAP)	2,359,063			3,595,165			8,649,155			7,329,414			5,236,777
Adjustments:
Exploration Costs (excluding Stock-Based    Compensation Expenses)	104,199			124,011			157,453			134,531			159,182
Excess Tax Benefits from Stock-Based Compensation	29,357			26,058			99,459			55,831			67,035
Changes in Components of Working Capital and    Other Assets and Liabilities
Accounts Receivable	232,799			(641,412)			(84,982)			23,613			178,683
Inventories	(170,694)			(58,450)			161,958			(53,402)			156,762
Accounts Payable	74,048			1,409,197			(543,630)			(178,701)			17,150
Accrued Taxes Payable	(92,782)			(11,798)			(16,486)			(75,142)			(78,094)
Other Assets	40,636			(118,143)			14,448			109,567			118,520
Other Liabilities	16,225			66,257			(75,420)			20,382			(36,114)
Changes in Components of Working Capital    Associated with Investing and Financing Activities	156,102			(499,767)			103,414			51,361			(74,158)
Discretionary Cash Flow (Non-GAAP)	2,748,953			3,891,118			8,465,369			7,417,454			5,745,743
Discretionary Cash Flow (Non-GAAP) - Percentage    Increase (Decrease)	-29	%		-54	%		14	%		29	%
Discretionary Cash Flow (Non-GAAP)	2,748,953			3,891,118			8,465,369			7,417,454			5,745,743
Less:
Total Cash Capital Expenditures Before Acquisitions    (Non-GAAP) (a)	(2,706,397)			(4,682,326)			(8,292,090)			(7,101,791)			(7,539,994)
Free Cash Flow (Non-GAAP) (b)	42,556			(791,208)			173,279			315,663			(1,794,251)
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2016, 2015, 2014, 2013 and 2012:
Total Expenditures (GAAP)	6,554,053			5,216,413			8,631,906			7,361,457			7,753,828
Less:
Asset Retirement Costs	19,865			(53,470)			(195,630)			(134,445)			(126,987)
Non-Cash Expenditures of Other Property, Plant    and Equipment	(16,585)			—			—			—			(65,791)
Non-Cash Acquisition Costs of Unproved Properties	(3,101,913)			—			(5,085)			(5,007)			(20,317)
Acquisition Costs of Proved Properties	(749,023)			(480,617)			(139,101)			(120,214)			(739)
Total Cash Capital Expenditures Before Acquisitions    (Non-GAAP)	2,706,397			4,682,326			8,292,090			7,101,791			7,539,994
(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item.

 

Total Expenditures

In millions of USD (Unaudited)
	4Q 2020			4Q 2019			FY 2020			FY 2019			FY 2018			FY 2017
Exploration and Development Drilling	592			1,086			2,664			4,951			4,935			3,132
Facilities	99			130			347			629			625			575
Leasehold Acquisitions	102			75			265			276			488			427
Property Acquisitions	61			48			135			380			124			73
Capitalized Interest	7			10			31			38			24			27
Subtotal	861			1,349			3,442			6,274			6,196			4,234
Exploration Costs	41			37			146			140			149			145
Dry Hole Costs	—			—			13			28			5			5
Exploration and Development Expenditures	902			1,386			3,601			6,442			6,350			4,384
Asset Retirement Costs	48			35			117			186			70			56
Total Exploration and Development Expenditures	950			1,421			3,718			6,628			6,420			4,440
Other Property, Plant and Equipment	157			85			395			272			286			173
Total Expenditures	1,107			1,506			4,113			6,900			6,706			4,613

 

EBITDAX and Adjusted EBITDAX

In thousands of USD (Unaudited)
	4Q 2020			4Q 2019			FY 2020			FY 2019
Net Income (Loss) (GAAP)	337,466			636,521			(604,572)			2,734,910
Adjustments:
Interest Expense, Net	53,121			40,695			205,266			185,129
Income Tax Provision (Benefit)	90,294			194,687			(134,482)			810,357
Depreciation, Depletion and Amortization	870,564			959,208			3,400,353			3,749,704
Exploration Costs	40,415			36,495			145,788			139,881
Dry Hole Costs	20			—			13,083			28,001
Impairments	142,440			228,135			2,099,780			517,896
EBITDAX (Non-GAAP)	1,534,320			2,095,741			5,125,216			8,165,878
(Gains) Losses on MTM Commodity Derivative Contracts	(69,304)			62,347			(1,144,737)			(180,275)
Net Cash Received from Settlements of Commodity Derivative Contracts	71,753			91,521			1,070,647			231,229
(Gains) Losses on Asset Dispositions, Net	5,600			(119,963)			46,883			(123,613)
Adjusted EBITDAX (Non-GAAP)	1,542,369			2,129,646			5,098,009			8,093,219
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease	-28	%					-37	%
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)
	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

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

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

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

In millions of USD, except ratio data (Unaudited)
	December 31, 2016			September 30, 2016			June 30, 2016			March 31, 2016			December 31, 2015
Total Stockholders' Equity - (a)	13,982			11,798			12,057			12,405			12,943
Current and Long-Term Debt (GAAP) - (b)	6,986			6,986			6,986			6,986			6,660
Less: Cash	(1,600)			(1,049)			(780)			(668)			(719)
Net Debt (Non-GAAP) - (c)	5,386			5,937			6,206			6,318			5,941
Total Capitalization (GAAP) - (a) + (b)	20,968			18,784			19,043			19,391			19,603
Total Capitalization (Non-GAAP) - (a) + (c)	19,368			17,735			18,263			18,723			18,884
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	33.3	%		37.2	%		36.7	%		36.0	%		34.0	%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]	27.8	%		33.5	%		34.0	%		33.7	%		31.5	%

 

Proved Reserves and Reserve Replacement Data

(Unaudited)
2020 Net Proved Reserves Reconciliation Summary	United States			Trinidad			Other International			Total
Crude Oil and Condensate (MMBbl)
Beginning Reserves	1,694.0			0.3			0.1			1,694.4
Revisions	(225.4)			—			—			(225.4)
Purchases in Place	2.2			—			—			2.2
Extensions, Discoveries and Other Additions	194.7			0.9			—			195.6
Sales in Place	(3.2)			—			—			(3.2)
Production	(149.4)			(0.4)			—			(149.8)
Ending Reserves	1,512.9			0.8			0.1			1,513.8
Natural Gas Liquids (MMBbl)
Beginning Reserves	739.7			—			—			739.7
Revisions	(59.8)			—			—			(59.8)
Purchases in Place	3.8			—			—			3.8
Extensions, Discoveries and Other Additions	180.2			—			—			180.2
Sales in Place	(1.4)			—			—			(1.4)
Production	(49.8)			—			—			(49.8)
Ending Reserves	812.7			—			—			812.7
Natural Gas (Bcf)
Beginning Reserves	5,034.8			276.1			58.8			5,369.7
Revisions	(497.7)			4.8			1.6			(491.3)
Purchases in Place	26.3			—			—			26.3
Extensions, Discoveries and Other Additions	1,077.9			53.9			—			1,131.8
Sales in Place	(157.3)			—			—			(157.3)
Production	(441.4)			(65.9)			(11.6)			(518.9)
Ending Reserves	5,042.6			268.9			48.8			5,360.3
Oil Equivalents (MMBoe)
Beginning Reserves	3,272.8			46.3			10.0			3,329.1
Revisions	(368.1)			0.8			0.2			(367.1)
Purchases in Place	10.4			—			—			10.4
Extensions, Discoveries and Other Additions	554.6			9.8			—			564.4
Sales in Place	(30.8)			—			—			(30.8)
Production	(272.8)			(11.3)			(2.0)			(286.1)
Ending Reserves	3,166.1			45.6			8.2			3,219.9
Net Proved Developed Reserves (MMBoe)
At December 31, 2019	1,684.2			29.9			7.1			1,721.2
At December 31, 2020	1,614.4			29.3			5.4			1,649.1
2020 Exploration and Development Expenditures ($ Millions)
Acquisition Cost of Unproved Properties	264.8			—			—			264.8
Exploration Costs	203.4			81.2			11.4			296.0
Development Costs	2,901.0			3.9			—			2,904.9
Total Drilling	3,369.2			85.1			11.4			3,465.7
Acquisition Cost of Proved Properties	97.0			—			38.2			135.2
Asset Retirement Costs	97.2			0.2			19.9			117.3
Total Exploration and Development Expenditures	3,563.4			85.3			69.5			3,718.2
Gathering, Processing and Other	394.9			0.1			0.1			395.1
Total Expenditures	3,958.3			85.4			69.6			4,113.3
Proceeds from Sales in Place	(191.9)			—			—			(191.9)
Net Expenditures	3,766.4			85.4			69.6			3,921.4
Reserve Replacement Costs ($ / Boe) *
All-in Total, Net of Revisions	16.53			8.03			248.00			16.32
All-in Total, Excluding Revisions Due to Price	6.85			8.03			248.00			6.98
Reserve Replacement *
Drilling Only	203	%		87	%		0	%		197	%
All-in Total, Net of Revisions and Dispositions	61	%		94	%		10	%		62	%
All-in Total, Excluding Revisions Due to Price	163	%		94	%		10	%		159	%
All-in Total, Liquids	46	%		225	%		0	%		46	%
*   See following reconciliation schedule for calculation methodology

 

Reserve Replacement Cost Data

(Unaudited; in millions, except ratio data)
For the Twelve Months Ended December 31, 2020	United States			Trinidad			Other International			Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	3,563.4			85.3			69.5			3,718.2
Less:   Asset Retirement Costs	(97.2)			(0.2)			(19.9)			(117.3)
Non-Cash Acquisition Costs of Unproved Properties	(196.8)			—			—			(196.8)
Total Acquisition Costs of Proved Properties	(97.0)			—			(38.2)			(135.2)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a)	3,172.4			85.1			11.4			3,268.9
Total Costs Incurred in Exploration and Development Activities (GAAP)	3,563.4			85.3			69.5			3,718.2
Less:   Asset Retirement Costs	(97.2)			(0.2)			(19.9)			(117.3)
Non-Cash Acquisition Costs of Unproved Properties	(196.8)			—			—			(196.8)
Non-Cash Acquisition Costs of Proved Properties	(14.6)			—			—			(14.6)
Total Exploration and Development Expenditures (Non-GAAP) - (b)	3,254.8			85.1			49.6			3,389.5
Total Expenditures (GAAP)	3,958.3			85.4			69.6			4,113.3
Less:   Asset Retirement Costs	(97.2)			(0.2)			(19.9)			(117.3)
Non-Cash Acquisition Costs of Unproved Properties	(196.8)			—			—			(196.8)
Non-Cash Acquisition Costs of Proved Properties	(14.6)			—			—			(14.6)
Non-Cash Capital - Other Miscellaneous	(173.9)			—			—			(173.9)
Total Cash Expenditures (Non-GAAP)	3,475.8			85.2			49.7			3,610.7
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	(278.2)			—			—			(278.2)
Revisions Other Than Price	(89.9)			0.8			0.2			(88.9)
Purchases in Place	10.4			—			—			10.4
Extensions, Discoveries and Other Additions - (d)	554.6			9.8			—			564.4
Total Proved Reserve Additions - (e)	196.9			10.6			0.2			207.7
Sales in Place	(30.8)			—			—			(30.8)
Net Proved Reserve Additions From All Sources - (f)	166.1			10.6			0.2			176.9
Production - (g)	272.8			11.3			2.0			286.1
Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	5.72			8.68			—			5.79
All-in Total, Net of Revisions - (b / e)	16.53			8.03			248.00			16.32
All-in Total, Excluding Revisions Due to Price - (b / (e - c))	6.85			8.03			248.00			6.98
Reserve Replacement
Drilling Only - (d / g)	203	%		87	%		0	%		197	%
All-in Total, Net of Revisions and Dispositions - (f / g)	61	%		94	%		10	%		62	%
All-in Total, Excluding Revisions Due to Price - ((f - c) / g)	163	%		94	%		10	%		159	%
Net Proved Reserve Additions From All Sources - Liquids (MMBbl)
Revisions	(285.2)			—			—			(285.2)
Purchases in Place	6.0			—			—			6.0
Extensions, Discoveries and Other Additions - (h)	374.9			0.9			—			375.8
Total Proved Reserve Additions	95.7			0.9			—			96.6
Sales in Place	(4.6)			—			—			(4.6)
Net Proved Reserve Additions From All Sources - (i)	91.1			0.9			—			92.0
Production - (j)	199.2			0.4			—			199.6
Reserve Replacement - Liquids
Drilling Only - (h / j)	188	%		225	%		0	%		188	%
All-in Total, Net of Revisions and Dispositions - (i / j)	46	%		225	%		0	%		46	%

 

Reserve Replacement Cost Data

(Unaudited; in millions, except ratio data)
For the Twelve Months Ended December 31, 2020
Proved Developed Reserve Replacement Costs ($ / Boe)	Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	3,718.2
Less:   Asset Retirement Costs	(117.3)
Acquisition Costs of Unproved Properties	(264.8)
Acquisition Costs of Proved Properties	(135.2)
Drillbit Exploration and Development Expenditures (Non-GAAP) - (k)	3,200.9
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe)	564.4
Add:  Conversion of Proved Undeveloped Reserves to Proved Developed	212.2
Less:  Proved Undeveloped Extensions and Discoveries	(456.1)
Proved Developed Reserves - Extensions and Discoveries (MMBoe)	320.5
Total Proved Reserves - Revisions (MMBoe)	(367.1)
Less:  Proved Undeveloped Reserves - Revisions	277.3
Proved Developed - Revisions Due to Price	201.0
Proved Developed Reserves - Revisions Other Than Price (MMBoe)	111.2
Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (l)	431.7
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) - (k / l)	7.41

 

Reserve Replacement Cost Data

In millions of USD, except reserves and ratio data (Unaudited)
	2020			2019			2018			2017			2016			2015			2014
Total Costs Incurred in Exploration and    Development Activities (GAAP)	3,718.2			6,628.2			6,419.7			4,439.4			6,445.2			4,928.3			7,904.8
Less:  Asset Retirement Costs	(117.3)			(186.1)			(69.7)			(55.6)			19.9			(53.5)			(195.6)
Non-Cash Acquisition Costs of    Unproved Properties	(196.8)			(97.7)			(290.5)			(255.7)			(3,101.8)			—			—
Acquisition Costs of Proved Properties	(135.2)			(379.9)			(123.7)			(72.6)			(749.0)			(480.6)			(139.1)
Total Exploration and Development    Expenditures for Drilling Only (Non-    GAAP) - (a)	3,268.9			5,964.5			5,935.8			4,055.5			2,614.3			4,394.2			7,570.1
Total Costs Incurred in Exploration and    Development Activities (GAAP)	3,718.2			6,628.2			6,419.7			4,439.4			6,445.2			4,928.3			7,904.8
Less:  Asset Retirement Costs	(117.3)			(186.1)			(69.7)			(55.6)			19.9			(53.5)			(195.6)
Non-Cash Acquisition Costs of    Unproved Properties	(196.8)			(97.7)			(290.5)			(255.7)			(3,101.8)			—			—
Non-Cash Acquisition Costs of    Proved Properties	(14.6)			(52.3)			(70.9)			(26.2)			(732.3)			—			—
Total Exploration and Development    Expenditures (Non-GAAP) - (b)	3,389.5			6,292.1			5,988.6			4,101.9			2,631.0			4,874.8			7,709.2
Net Proved Reserve Additions From All    Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c)	(278.2)			(59.7)			34.8			154.0			(100.7)			(573.8)			52.2
Revisions Other Than Price	(88.9)			(0.3)			(39.5)			48.0			252.9			107.2			48.4
Purchases in Place	10.4			16.8			11.6			2.3			42.3			56.2			14.4
Extensions, Discoveries and Other Additions - (d)	564.4			750.0			669.7			420.8			209.0			245.9			519.2
Total Proved Reserve Additions - (e)	207.7			706.8			676.6			625.1			403.5			(164.5)			634.2
Sales in Place	(30.8)			(4.6)			(10.8)			(20.7)			(167.6)			(3.5)			(36.3)
Net Proved Reserve Additions From All Sources	176.9			702.2			665.8			604.4			235.9			(168.0)			597.9
Production	286.1			300.9			265.0			224.4			207.1			211.2			219.1
Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d)	5.79			7.95			8.86			9.64			12.51			17.87			14.58
All-in Total, Net of Revisions - (b / e)	16.32			8.90			8.85			6.56			6.52			(29.63)			12.16
All-in Total, Excluding Revisions Due to Price -  (b / ( e - c))	6.98			8.21			9.33			8.71			5.22			11.91			13.25

 

Definitions

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

 

Financial Commodity Derivative Contracts

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

ICE Brent Differential Basis Swap Contracts
Prices received by EOG for its crude oil production generally vary from NYMEX WTI prices due to adjustments for delivery location (basis) and other factors.  EOG has entered into crude oil basis swap contracts in order to fix the differential between ICE Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.
2020		Volume (Bbld)			Weighted Average Price Differential ($/Bbl)
May 2020 (CLOSED)		10,000			4.92

Houston Differential Basis Swap Contracts
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential).  Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.
2020		Volume (Bbld)			Weighted Average Price Differential ($/Bbl)
May 2020 (CLOSED)		10,000			1.55

Roll Differential Basis Swap Contracts
EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential).  Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.
2020		Volume (Bbld)			Weighted Average Price Differential ($/Bbl)
February 1, 2020 through June 30, 2020 (CLOSED)		10,000			0.70
July 1, 2020 through September 30, 2020 (CLOSED)		88,000			(1.16)
October 1, 2020 through December 31, 2020 (CLOSED)		66,000			(1.16)
2021
February 2021 (CLOSED)		30,000			0.11
March 1, 2021 through December 31, 2021		125,000			0.17
2022
January 1, 2022 through December 31, 2022		125,000			0.15

In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Crude Oil NYMEX WTI Price Swap Contracts
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
2020		Volume (Bbld)			Weighted Average Price ($/Bbl)
January 1, 2020 through March 31, 2020 (CLOSED)		200,000			59.33
April 1, 2020 through May 31, 2020 (CLOSED)		265,000			51.36
2021
January 2021 (CLOSED)		151,000			50.06
February 1, 2021 through March 31, 2021		201,000			51.29
April 1, 2021 through June 30, 2021		150,000			51.68
July 1, 2021 through September 30, 2021		150,000			52.71
In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020.  EOG received net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Crude Oil ICE Brent Price Swap Contracts
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
2020		Volume (Bbld)			Weighted Average Price ($/Bbl)
April 2020 (CLOSED)		75,000			25.66
May 2020 (CLOSED)		35,000			26.53

Mont Belvieu Propane Price Swap Contracts
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
2020		Volume (Bbld)			Weighted Average Price ($/Bbl)
January 1, 2020 through February 29, 2020 (CLOSED)		4,000			21.34
March 1, 2020 through April 30, 2020 (CLOSED)		25,000			17.92
2021
January 2021 (CLOSED)		15,000			29.44
February 1, 2021 through December 31, 2020 (CLOSED)		15,000			29.44
In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl.  These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl.  EOG received net cash of $9.2 million for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

Natural Gas NYMEX Henry Hub Price Swap Contracts
Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts through February 18, 2021, with notional volumes sold (purchased) expressed in MMBtud and prices expressed in $/MMBtu.  In January 2021, EOG executed the early termination provision granting EOG the right to terminate certain 2022 natural gas NYMEX Henry Hub price swap contracts with notional volumes of 20,000 MMBtud at a weighted average price of $2.75 per MMBtu for the period from January 1, 2022 through December 31, 2022.  EOG received net cash of $0.6 million for the settlement of these contracts.
2021		Volume (MMBtud)			Weighted Average Price  ($/MMBtu)
April 1, 2021 through September 30, 2021		(70,000)			2.64
2022
January 1, 2022 through December 31, 2022 (CLOSED)		20,000			2.75
In December 2020 and January 2021, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu and for the period from April 1, 2021 through December 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.83 per MMBtu.  These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time periods with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu.  EOG received net cash of $16.5 million through February 18, 2021, for the settlement of certain of these contracts, and expects to receive net cash of $30.3 million during the remainder of 2021 for the settlement of the remaining contracts.  The offsetting contracts were excluded from the above table.

Natural Gas JKM Price Swap Contracts
Presented below is a comprehensive summary of EOG's natural gas JKM price swap contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
2021		Volume (MMBtud)			Weighted Average Price  ($/MMBtu)
April 1, 2021 through September 30, 2021		70,000			6.65

Natural Gas Collar Contracts
EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts.  The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price.  The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price.  In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020.  EOG received net cash of $7.8 million for the settlement of these contracts.  Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
2020		Volume (MMBtud)			Weighted Average Ceiling Price ($/MMBtu)			Weighted Average Floor Price ($/MMBtu)
April 1, 2020 through July 31, 2020 (CLOSED)		250,000			2.50			2.00
In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.  These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.  EOG received net cash of $1.1 million  for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

Rockies Differential Basis Swap Contracts
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors.  EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential).  Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
2020		Volume (MMBtud)			Weighted Average Price Differential  ($/MMBtu)
January 1, 2020 through December 31, 2020 (CLOSED)		30,000			0.55

HSC Differential Basis Swap Contracts
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential).  In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020.  EOG paid net cash of $0.4 million for the settlement of these contracts.  Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
2020		Volume (MMBtud)			Weighted Average Price Differential  ($/MMBtu)
January 1, 2020 through December 31, 2020 (CLOSED)		60,000			0.05

Waha Differential Basis Swap Contracts
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential).  Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
2020		Volume (MMBtud)			Weighted Average Price Differential  ($/MMBtu)
January 1, 2020 through April 30, 2020 (CLOSED)		50,000			1.40
In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu.  These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu.  EOG paid net cash of 11.9 million for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

 

Definitions

Bbld		Barrels per day
$/Bbl		Dollars per barrel
ICE		Intercontinental Exchange
MMBtud		Million British thermal units per day
$/MMBtu		Dollars per million British thermal units
NYMEX		U.S. New York Mercantile Exchange
WTI		West Texas Intermediate

 

Direct After-Tax Rate of Return

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).  As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.
Direct ATROR
Based on Cash Flow and Time Value of Money
- Estimated future commodity prices and operating costs
- Costs incurred to drill, complete and equip a well, including facilities
Excludes Indirect Capital
- Gathering and Processing and other Midstream
- Land, Seismic, Geological and Geophysical
Payback ~12 Months on 100% Direct ATROR Wells
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured
Return on Equity / Return on Capital Employed
Based on GAAP Accrual Accounting
Includes All Indirect Capital and Growth Capital for Infrastructure
- Eagle Ford, Bakken, Permian Facilities
- Gathering and Processing
Includes Legacy Gas Capital and Capital from Mature Wells

 

ROCE & ROE

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

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)
	2017			2016			2015			2014			2013
Net Interest Expense (GAAP)	274			282			237			201			235
Tax Benefit Imputed (based on 35%)	(96)			(99)			(83)			(70)			(82)
After-Tax Net Interest Expense (Non-GAAP) - (a)	178			183			154			131			153
Net Income (Loss) (GAAP) - (b)	2,583			(1,097)			(4,525)			2,915			2,197
Total Stockholders' Equity - (d)	16,283			13,982			12,943			17,713			15,418
Average Total Stockholders' Equity* - (e)	15,133			13,463			15,328			16,566			14,352
Current and Long-Term Debt (GAAP) - (f)	6,387			6,986			6,655			5,906			5,909
Less:  Cash	(834)			(1,600)			(719)			(2,087)			(1,318)
Net Debt (Non-GAAP) - (g)	5,553			5,386			5,936			3,819			4,591
Total Capitalization (GAAP) - (d) + (f)	22,670			20,968			19,598			23,619			21,327
Total Capitalization (Non-GAAP) - (d) + (g)	21,836			19,368			18,879			21,532			20,009
Average Total Capitalization (Non-GAAP)* - (h)	20,602			19,124			20,206			20,771			19,365
Return on Capital Employed (ROCE)
GAAP Net Income (Loss) - [(a) + (b)] / (h)	13.4	%		-4.8	%		-21.6	%		14.7	%		12.1	%
Return on Equity (ROE)
GAAP Net Income (Loss) - (b) / (e)	17.1	%		-8.1	%		-29.5	%		17.6	%		15.3	%
* Average for the current and immediately preceding year

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)
	2012			2011			2010			2009			2008
Net Interest Expense (GAAP)	214			210			130			101			52
Tax Benefit Imputed (based on 35%)	(75)			(74)			(46)			(35)			(18)
After-Tax Net Interest Expense (Non-GAAP) - (a)	139			136			84			66			34
Net Income (GAAP) - (b)	570			1,091			161			547			2,437
Total Stockholders' Equity - (d)	13,285			12,641			10,232			9,998			9,015
Average Total Stockholders' Equity* - (e)	12,963			11,437			10,115			9,507			8,003
Current and Long-Term Debt (GAAP) - (f)	6,312			5,009			5,223			2,797			1,897
Less:  Cash	(876)			(616)			(789)			(686)			(331)
Net Debt (Non-GAAP) - (g)	5,436			4,393			4,434			2,111			1,566
Total Capitalization (GAAP) - (d) + (f)	19,597			17,650			15,455			12,795			10,912
Total Capitalization (Non-GAAP) - (d) + (g)	18,721			17,034			14,666			12,109			10,581
Average Total Capitalization (Non-GAAP)* - (h)	17,878			15,850			13,388			11,345			9,351
Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)	4.0	%		7.7	%		1.8	%		5.4	%		26.4	%
Return on Equity (ROE)
GAAP Net Income - (b) / (e)	4.4	%		9.5	%		1.6	%		5.8	%		30.5	%
* Average for the current and immediately preceding year

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)
	2007			2006			2005			2004			2003
Net Interest Expense (GAAP)	47			43			63			63			59
Tax Benefit Imputed (based on 35%)	(16)			(15)			(22)			(22)			(21)
After-Tax Net Interest Expense (Non-GAAP) - (a)	31			28			41			41			38
Net Income (GAAP) - (b)	1,090			1,300			1,260			625			430
Total Stockholders' Equity - (d)	6,990			5,600			4,316			2,945			2,223
Average Total Stockholders' Equity* - (e)	6,295			4,958			3,631			2,584			1,948
Current and Long-Term Debt (GAAP) - (f)	1,185			733			985			1,078			1,109
Less:  Cash	(54)			(218)			(644)			(21)			(4)
Net Debt (Non-GAAP) - (g)	1,131			515			341			1,057			1,105
Total Capitalization (GAAP) - (d) + (f)	8,175			6,333			5,301			4,023			3,332
Total Capitalization (Non-GAAP) - (d) + (g)	8,121			6,115			4,657			4,002			3,328
Average Total Capitalization (Non-GAAP)* - (h)	7,118			5,386			4,330			3,665			3,068
Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)	15.7	%		24.7	%		30.0	%		18.2	%		15.3	%
Return on Equity (ROE)
GAAP Net Income - (b) / (e)	17.3	%		26.2	%		34.7	%		24.2	%		22.1	%
* Average for the current and immediately preceding year

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)
	2002			2001			2000			1999			1998
Net Interest Expense (GAAP)	60			45			61			62
Tax Benefit Imputed (based on 35%)	(21)			(16)			(21)			(22)
After-Tax Net Interest Expense (Non-GAAP) - (a)	39			29			40			40
Net Income (GAAP) - (b)	87			399			397			569
Total Stockholders' Equity - (d)	1,672			1,643			1,381			1,130			1,280
Average Total Stockholders' Equity* - (e)	1,658			1,512			1,256			1,205
Current and Long-Term Debt (GAAP) - (f)	1,145			856			859			990			1,143
Less:  Cash	(10)			(3)			(20)			(25)			(6)
Net Debt (Non-GAAP) - (g)	1,135			853			839			965			1,137
Total Capitalization (GAAP) - (d) + (f)	2,817			2,499			2,240			2,120			2,423
Total Capitalization (Non-GAAP) - (d) + (g)	2,807			2,496			2,220			2,095			2,417
Average Total Capitalization (Non-GAAP)* - (h)	2,652			2,358			2,158			2,256
Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)	4.8	%		18.2	%		20.2	%		27.0	%
Return on Equity (ROE)
GAAP Net Income - (b) / (e)	5.2	%		26.4	%		31.6	%		47.2	%
* Average for the current and immediately preceding year

 

Costs per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)
	1Q 2020			2Q 2020			3Q 2020			4Q 2020
Cost per Barrel of Oil Equivalent (Boe) Calculation
Volume - Thousand Barrels of Oil Equivalent - (a)	79,548			56,733			65,873			73,740
Crude Oil and Condensate	2,065,498			614,627			1,394,622			1,710,862
Natural Gas Liquids	160,535			93,909			184,771			228,299
Natural Gas	209,764			141,696			183,790			301,883
Total Wellhead Revenues - (b)	2,435,797			850,232			1,763,183			2,241,044
Operating Costs
Lease and Well	329,659			245,346			227,473			260,896
Transportation Costs	208,296			151,728			180,257			194,708
Gathering and Processing Costs	128,482			96,767			114,790			119,172
General and Administrative	114,273			131,855			124,460			113,235
Taxes Other Than Income	157,360			80,319			126,810			113,445
Interest Expense, Net	44,690			54,213			53,242			53,121
Total Cash Cost (excluding DD&A and Total Exploration Costs) - (c)	982,760			760,228			827,032			854,577
Depreciation, Depletion and Amortization (DD&A)	1,000,060			706,679			823,050			870,564
Total Operating Cost (excluding Total Exploration Costs) - (d)	1,982,820			1,466,907			1,650,082			1,725,141
Exploration Costs	39,677			27,283			38,413			40,415
Dry Hole Costs	372			87			12,604			20
Impairments	1,572,935			305,415			78,990			142,440
Total Exploration Costs	1,612,984			332,785			130,007			182,875
Less:  Certain Impairments (Non-GAAP)	(1,516,316)			(239,167)			(26,531)			(86,451)
Total Exploration Costs (Non-GAAP)	96,668			93,618			103,476			96,424
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)	2,079,488			1,560,525			1,753,558			1,821,565
Composite Average Wellhead Revenue per Boe - (b) / (a)	30.62			14.99			26.77			30.39
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -   (c) /    (a)	12.36			13.40			12.56			11.60
Composite Average Margin per Boe (excluding DD&A and Total Exploration    Costs) - [(b) / (a) - (c) / (a)]	18.26			1.59			14.21			18.79
Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a)	24.93			25.86			25.05			23.41
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a)     - (d) / (a)]	5.69			(10.87)			1.72			6.98
Total Operating Cost  per Boe (Non-GAAP) (including Total Exploration Costs) -    (e) / (a)	26.15			27.51			26.62			24.72
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration    Costs) - [(b) / (a) - (e) / (a)]	4.47			(12.52)			0.15			5.67

 

Costs per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)
	2020			2019			2018			2017
Cost per Barrel of Oil Equivalent (Boe) Calculation
Volume - Thousand Barrels of Oil Equivalent - (a)	275,893			298,565			262,516			222,251
Crude Oil and Condensate	5,785,609			9,612,532			9,517,440			6,256,396
Natural Gas Liquids	667,514			784,818			1,127,510			729,561
Natural Gas	837,133			1,184,095			1,301,537			921,934
Total Wellhead Revenues - (b)	7,290,256			11,581,445			11,946,487			7,907,891
Operating Costs
Lease and Well	1,063,374			1,366,993			1,282,678			1,044,847
Transportation Costs	734,989			758,300			746,876			740,352
Gathering and Processing Costs	459,211			479,102			436,973			148,775
General and Administrative	483,823			489,397			426,969			434,467
Less:  Legal Settlement - Early Leasehold Termination	—			—			—			(10,202)
Less:  Joint Venture Transaction Costs	—			—			—			(3,056)
Less:  Joint Interest Billings Deemed Uncollectible	—			—			—			(4,528)
General and Administrative (Non-GAAP)	483,823			489,397			426,969			416,681
Taxes Other Than Income	477,934			800,164			772,481			544,662
Interest Expense, Net	205,266			185,129			245,052			274,372
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c)	3,424,597			4,079,085			3,911,029			3,169,689
Depreciation, Depletion and Amortization (DD&A)	3,400,353			3,749,704			3,435,408			3,409,387
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d)	6,824,950			7,828,789			7,346,437			6,579,076
Exploration Costs	145,788			139,881			148,999			145,342
Dry Hole Costs	13,083			28,001			5,405			4,609
Impairments	2,099,780			517,896			347,021			479,240
Total Exploration Costs	2,258,651			685,778			501,425			629,191
Less:  Certain Impairments (Non-GAAP)	(1,868,465)			(274,974)			(152,671)			(261,452)
Total Exploration Costs (Non-GAAP)	390,186			410,804			348,754			367,739
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)	7,215,136			8,239,593			7,695,191			6,946,815
Cost per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited)
	2020			2019			2018			2017
Composite Average Wellhead Revenue per Boe - (b) / (a)	26.42			38.79			45.51			35.58
Total Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) -   (c)    / (a)	12.39			13.66			14.90			14.25
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration    Costs) - [(b) / (a) - (c) / (a)]	14.03			25.13			30.61			21.33
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) -    (d) / (a)	24.71			26.22			27.99			29.59
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) -    [(b) / (a) - (d) / (a)]	1.71			12.57			17.52			5.99
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) -     (e) / (a)	26.13			27.60			29.32			31.24
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) -    [(b) / (a) - (e) / (a)]	0.29			11.19			16.19			4.34

 

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)
	2016			2015			2014
Cost per Barrel of Oil Equivalent (Boe) Calculation
Volume - Thousand Barrels of Oil Equivalent - (a)	204,929			208,862			217,073
Crude Oil and Condensate	4,317,341			4,934,562			9,742,480
Natural Gas Liquids	437,250			407,658			934,051
Natural Gas	742,152			1,061,038			1,916,386
Total Wellhead Revenues - (b)	5,496,743			6,403,258			12,592,917
Operating Costs
Lease and Well	927,452			1,182,282			1,416,413
Transportation Costs	764,106			849,319			972,176
Gathering and Processing Costs	122,901			146,156			145,800
General and Administrative	394,815			366,594			402,010
Less:  Voluntary Retirement Expense	(42,054)			—			—
Less:  Acquisition Costs	(5,100)			—			—
Less:  Legal Settlement - Early Leasehold Termination	—			(19,355)			—
General and Administrative (Non-GAAP)	347,661			347,239			402,010
Taxes Other Than Income	349,710			421,744			757,564
Interest Expense, Net	281,681			237,393			201,458
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c)	2,793,511			3,184,133			3,895,421
Depreciation, Depletion and Amortization (DD&A)	3,553,417			3,313,644			3,997,041
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d)	6,346,928			6,497,777			7,892,462
Exploration Costs	124,953			149,494			184,388
Dry Hole Costs	10,657			14,746			48,490
Impairments	620,267			6,613,546			743,575
Total Exploration Costs	755,877			6,777,786			976,453
Less:  Certain Impairments (Non-GAAP)	(320,617)			(6,307,593)			(824,312)
Total Exploration Costs (Non-GAAP)	435,260			470,193			152,141
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)	6,782,188			6,967,970			8,044,603

 

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)
	2016			2015			2014
Composite Average Wellhead Revenue per Boe - (b) / (a)	26.82			30.66			58.01
Total Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) -    (c) / (a)	13.64			15.25			17.95
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration    Costs) - [(b) / (a) - (c) / (a)]	13.18			15.41			40.06
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) -     (d) / (a)	30.98			31.11			36.38
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) -    [(b) / (a) - (d) / (a)]	(4.16)			(0.45)			21.63
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) -     (e) / (a)	33.10			33.36			37.08
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) -    [(b) / (a) - (e) / (a)]	(6.28)			(2.70)			20.93

 

Quarter and Full Year Guidance

(Unaudited)
(a)  First Quarter and Full Year 2021 Forecast
The forecast items for the first quarter and full year 2021 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release.  EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.  This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.
(b)  Capital Expenditures
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.
(c)  Benchmark Commodity Pricing
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.
Estimated Ranges for First Quarter and Full Year 2021		1Q 2021								FY 2021
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States		418.0		-		428.0				433.0		-		444.0
Trinidad		1.6		-		2.4				1.0		-		1.8
Other International		0.0		-		0.2				0.0		-		0.2
Total		419.6		-		430.6				434.0		-		446.0
Natural Gas Liquids Volumes (MBbld)
Total		125.0		-		135.0				130.0		-		170.0
Natural Gas Volumes (MMcfd)
United States		1,095		-		1,155				1,100		-		1,200
Trinidad		200		-		230				180		-		220
Other International		15		-		25				15		-		25
Total		1,310		-		1,410				1,295		-		1,445
Crude Oil Equivalent Volumes (MBoed)
United States		725.5		-		755.5				746.3		-		814.0
Trinidad		34.9		-		40.7				31.0		-		38.5
Other International		2.5		-		4.4				2.5		-		4.4
Total		762.9		-		800.6				779.8		-		856.9
Capital Expenditures ($MM)		900		-		1,100				3,700		-		4,100

 

Quarter and Full Year Guidance

(Unaudited)
Estimated Ranges for First Quarter and Full Year 2021						1Q 2021								FY 2021
Operating Costs
Unit Costs ($/Boe)
Lease and Well						3.60		-		4.30				3.50		-		4.20
Transportation Costs						2.60		-		3.00				2.65		-		3.05
Gathering and Processing						1.75		-		1.85				1.65		-		1.85
Depreciation, Depletion and Amortization						12.60		-		13.10				11.70		-		12.70
General and Administrative						1.60		-		1.70				1.50		-		1.60
Expenses ($MM)
Exploration and Dry Hole						35		-		45				140		-		180
Impairment						45		-		95				255		-		295
Capitalized Interest						5		-		10				25		-		30
Net Interest						45		-		50				180		-		185
Taxes Other Than Income (% of Wellhead Revenue)						6.0	%	-		8.0	%			6.5	%	-		7.5	%
Income Taxes
Effective Rate						21	%	-		26	%			21	%	-		26	%
Deferred Ratio						(5)	%	-		5	%			0	%	-		15	%
Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI						(0.80)		-		1.20				(0.55)		-		1.45
Trinidad - above (below) WTI						(11.50)		-		(9.50)				(12.40)		-		(10.40)
Other International - above (below) WTI						(21.00)		-		(15.00)				(19.20)		-		(17.20)
Natural Gas Liquids
Realizations as % of WTI						43	%	-		55	%			38	%	-		50	%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub						1.75		-		4.25				(0.25)		-		1.25
Realizations
Trinidad						3.10		-		3.60				3.10		-		3.60
Other International						5.45		-		5.95				5.20		-		6.20

 

Definitions

$/Bbl

U.S. Dollars per barrel

$/Boe

U.S. Dollars per barrel of oil equivalent

$/Mcf

U.S. Dollars per thousand cubic feet

$MM

U.S. Dollars in millions

MBbld

Thousand barrels per day

MBoed

Thousand barrels of oil equivalent per day

MMcfd

Million cubic feet per day

NYMEX

U.S. New York Mercantile Exchange

WTI

West Texas Intermediate

 

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SOURCE EOG Resources, Inc.