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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

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

  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)