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

Feb 25 2021 21:15 GMT

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

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

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

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

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

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

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

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

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


	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

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