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

February 25, 2021 4:15 PM EST

Get inside Wall Street with StreetInsider Premium. Claim your 1-week free trial here.

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 2020GuidanceMidpoint

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 HedgesHigher 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.

VolumeTotal 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 CostsEOG 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.

OtherThe 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 FlowNet 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 ExpendituresCash 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 2020GuidanceMidpoint

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 713–571–4902Neel 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 583,694,850Shares 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 Sharesat 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 ProvedProperties

(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 toPrice -  (b / ( e - c))

6.98

8.21

9.33

8.71

5.22

11.91

13.25

 

Definitions

$/Boe

U.S. Dollars per barrel of oil equivalent

MMBoe

Million barrels of oil equivalent

 

Financial Commodity Derivative Contracts

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

ICE Brent Differential Basis Swap Contracts

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

2020

Volume

(Bbld)

Weighted

Average Price

Differential

($/Bbl)

May 2020 (CLOSED)

10,000

4.92

Houston Differential Basis Swap Contracts

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

2020

Volume

(Bbld)

Weighted

Average Price

Differential

($/Bbl)

May 2020 (CLOSED)

10,000

1.55

Roll Differential Basis Swap Contracts

EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential).  Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

2020

Volume

(Bbld)

Weighted

Average Price

Differential

($/Bbl)

February 1, 2020 through June 30, 2020 (CLOSED)

10,000

0.70

July 1, 2020 through September 30, 2020 (CLOSED)

88,000

(1.16)

October 1, 2020 through December 31, 2020 (CLOSED)

66,000

(1.16)

2021

February 2021 (CLOSED)

30,000

0.11

March 1, 2021 through December 31, 2021

125,000

0.17

2022

January 1, 2022 through December 31, 2022

125,000

0.15

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

Crude Oil NYMEX WTI Price Swap Contracts

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

2020

Volume

(Bbld)

Weighted

Average Price

($/Bbl)

January 1, 2020 through March 31, 2020 (CLOSED)

200,000

59.33

April 1, 2020 through May 31, 2020 (CLOSED)

265,000

51.36

2021

January 2021 (CLOSED)

151,000

50.06

February 1, 2021 through March 31, 2021

201,000

51.29

April 1, 2021 through June 30, 2021

150,000

51.68

July 1, 2021 through September 30, 2021

150,000

52.71

In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020.  EOG received net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Crude Oil ICE Brent Price Swap Contracts

Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

2020

Volume

(Bbld)

Weighted

Average Price

($/Bbl)

April 2020 (CLOSED)

75,000

25.66

May 2020 (CLOSED)

35,000

26.53

Mont Belvieu Propane Price Swap Contracts

Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

2020

Volume

(Bbld)

Weighted

Average Price

($/Bbl)

January 1, 2020 through February 29, 2020 (CLOSED)

4,000

21.34

March 1, 2020 through April 30, 2020 (CLOSED)

25,000

17.92

2021

January 2021 (CLOSED)

15,000

29.44

February 1, 2021 through December 31, 2020 (CLOSED)

15,000

29.44

In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl.  These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl.  EOG received net cash of $9.2 million for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

Natural Gas NYMEX Henry Hub Price Swap Contracts

Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts through February 18, 2021, with notional volumes sold (purchased) expressed in MMBtud and prices expressed in $/MMBtu.  In January 2021, EOG executed the early termination provision granting EOG the right to terminate certain 2022 natural gas NYMEX Henry Hub price swap contracts with notional volumes of 20,000 MMBtud at a weighted average price of $2.75 per MMBtu for the period from January 1, 2022 through December 31, 2022.  EOG received net cash of $0.6 million for the settlement of these contracts.

2021

Volume

(MMBtud)

Weighted

Average Price

 ($/MMBtu)

April 1, 2021 through September 30, 2021

(70,000)

2.64

2022

January 1, 2022 through December 31, 2022 (CLOSED)

20,000

2.75

In December 2020 and January 2021, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu and for the period from April 1, 2021 through December 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.83 per MMBtu.  These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time periods with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu.  EOG received net cash of $16.5 million through February 18, 2021, for the settlement of certain of these contracts, and expects to receive net cash of $30.3 million during the remainder of 2021 for the settlement of the remaining contracts.  The offsetting contracts were excluded from the above table.

Natural Gas JKM Price Swap Contracts

Presented below is a comprehensive summary of EOG's natural gas JKM price swap contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

2021

Volume

(MMBtud)

Weighted

Average Price

 ($/MMBtu)

April 1, 2021 through September 30, 2021

70,000

6.65

Natural Gas Collar Contracts

EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts.  The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price.  The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price.  In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020.  EOG received net cash of $7.8 million for the settlement of these contracts.  Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

2020

Volume (MMBtud)

Weighted

Average

Ceiling Price

($/MMBtu)

Weighted

Average

Floor Price

($/MMBtu)

April 1, 2020 through July 31, 2020 (CLOSED)

250,000

2.50

2.00

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.  These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.  EOG received net cash of $1.1 million  for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

Rockies Differential Basis Swap Contracts

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

2020

Volume

(MMBtud)

Weighted

Average Price

Differential

 ($/MMBtu)

January 1, 2020 through December 31, 2020 (CLOSED)

30,000

0.55

HSC Differential Basis Swap Contracts

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

2020

Volume

(MMBtud)

Weighted

Average Price

Differential

 ($/MMBtu)

January 1, 2020 through December 31, 2020 (CLOSED)

60,000

0.05

Waha Differential Basis Swap Contracts

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential).  Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 18, 2021.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

2020

Volume

(MMBtud)

Weighted

Average Price

Differential

 ($/MMBtu)

January 1, 2020 through April 30, 2020 (CLOSED)

50,000

1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu.  These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu.  EOG paid net cash of 11.9 million for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

 

Definitions

Bbld

Barrels per day

$/Bbl

Dollars per barrel

ICE

Intercontinental Exchange

MMBtud

Million British thermal units per day

$/MMBtu

Dollars per million British thermal units

NYMEX

U.S. New York Mercantile Exchange

WTI

West Texas Intermediate

 

Direct After-Tax Rate of Return

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).  As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.

Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

  - Costs incurred to drill, complete and equip a well, including facilities

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2020

2019

2018

2017

Net Interest Expense (GAAP)

205

185

245

Tax Benefit Imputed (based on 21%)

(43)

(39)

(51)

After-Tax Net Interest Expense (Non-GAAP) - (a)

162

146

194

Net Income (Loss) (GAAP) - (b)

(605)

2,735

3,419

Adjustments to Net Income (Loss), Net of Tax (See Below Detail) (1)

1,455

158

(201)

Adjusted Net Income (Non-GAAP) - (c)

850

2,893

3,218

Total Stockholders' Equity - (d)

20,302

21,641

19,364

16,283

Average Total Stockholders' Equity * - (e)

20,972

20,503

17,824

Current and Long-Term Debt (GAAP) - (f)

5,816

5,175

6,083

6,387

Less:  Cash

(3,329)

(2,028)

(1,556)

(834)

Net Debt (Non-GAAP) - (g)

2,487

3,147

4,527

5,553

Total Capitalization (GAAP) - (d) + (f)

26,118

26,816

25,447

22,670

Total Capitalization (Non-GAAP) - (d) + (g)

22,789

24,788

23,891

21,836

Average Total Capitalization (Non-GAAP) * - (h)

23,789

24,340

22,864

Return on Capital Employed (ROCE)

GAAP Net Income (Loss) - [(a) + (b)] / (h)

(1.9)

%

11.8

%

15.8

%

Non-GAAP Adjusted Net Income - [(a) + (c)] / (h)

4.3

%

12.5

%

14.9

%

Return on Equity (ROE)

GAAP Net Income (Loss) - (b) / (e)

(2.9)

%

13.3

%

19.2

%

Non-GAAP Adjusted Net Income - (c) / (e)

4.1

%

14.1

%

18.1

%

* Average for the current and immediately preceding year

(1) Detail of adjustments to Net Income (Loss) (GAAP):

Before

Tax

Income Tax

Impact

After

Tax

Year Ended December 31, 2020

Adjustments:

Add:  Mark-to-Market Commodity Derivative Contracts Impact

(74)

16

(58)

Add:  Impairments of Certain Assets

1,868

(392)

1,476

Add:  Net Losses on Asset Dispositions

47

(10)

37

Total

1,841

(386)

1,455

Year Ended December 31, 2019

Adjustments:

Add:  Mark-to-Market Commodity Derivative Contracts Impact

51

(11)

40

Add:  Impairments of Certain Assets

275

(60)

215

Less:  Net Gains on Asset Dispositions

(124)

27

(97)

Total

202

(44)

158

Year Ended December 31, 2018

Adjustments:

Add:  Mark-to-Market Commodity Derivative Contracts Impact

(93)

20

(73)

Add:  Impairments of Certain Assets

153

(34)

119

Less:  Net Gains on Asset Dispositions

(175)

38

(137)

Less:  Tax Reform Impact

(110)

(110)

Total

(115)

(86)

(201)

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2017

2016

2015

2014

2013

Net Interest Expense (GAAP)

274

282

237

201

235

Tax Benefit Imputed (based on 35%)

(96)

(99)

(83)

(70)

(82)

After-Tax Net Interest Expense (Non-GAAP) - (a)

178

183

154

131

153

Net Income (Loss) (GAAP) - (b)

2,583

(1,097)

(4,525)

2,915

2,197

Total Stockholders' Equity - (d)

16,283

13,982

12,943

17,713

15,418

Average Total Stockholders' Equity* - (e)

15,133

13,463

15,328

16,566

14,352

Current and Long-Term Debt (GAAP) - (f)

6,387

6,986

6,655

5,906

5,909

Less:  Cash

(834)

(1,600)

(719)

(2,087)

(1,318)

Net Debt (Non-GAAP) - (g)

5,553

5,386

5,936

3,819

4,591

Total Capitalization (GAAP) - (d) + (f)

22,670

20,968

19,598

23,619

21,327

Total Capitalization (Non-GAAP) - (d) + (g)

21,836

19,368

18,879

21,532

20,009

Average Total Capitalization (Non-GAAP)* - (h)

20,602

19,124

20,206

20,771

19,365

Return on Capital Employed (ROCE)

GAAP Net Income (Loss) - [(a) + (b)] / (h)

13.4

%

-4.8

%

-21.6

%

14.7

%

12.1

%

Return on Equity (ROE)

GAAP Net Income (Loss) - (b) / (e)

17.1

%

-8.1

%

-29.5

%

17.6

%

15.3

%

* Average for the current and immediately preceding year

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2012

2011

2010

2009

2008

Net Interest Expense (GAAP)

214

210

130

101

52

Tax Benefit Imputed (based on 35%)

(75)

(74)

(46)

(35)

(18)

After-Tax Net Interest Expense (Non-GAAP) - (a)

139

136

84

66

34

Net Income (GAAP) - (b)

570

1,091

161

547

2,437

Total Stockholders' Equity - (d)

13,285

12,641

10,232

9,998

9,015

Average Total Stockholders' Equity* - (e)

12,963

11,437

10,115

9,507

8,003

Current and Long-Term Debt (GAAP) - (f)

6,312

5,009

5,223

2,797

1,897

Less:  Cash

(876)

(616)

(789)

(686)

(331)

Net Debt (Non-GAAP) - (g)

5,436

4,393

4,434

2,111

1,566

Total Capitalization (GAAP) - (d) + (f)

19,597

17,650

15,455

12,795

10,912

Total Capitalization (Non-GAAP) - (d) + (g)

18,721

17,034

14,666

12,109

10,581

Average Total Capitalization (Non-GAAP)* - (h)

17,878

15,850

13,388

11,345

9,351

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h)

4.0

%

7.7

%

1.8

%

5.4

%

26.4

%

Return on Equity (ROE)

GAAP Net Income - (b) / (e)

4.4

%

9.5

%

1.6

%

5.8

%

30.5

%

* Average for the current and immediately preceding year

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2007

2006

2005

2004

2003

Net Interest Expense (GAAP)

47

43

63

63

59

Tax Benefit Imputed (based on 35%)

(16)

(15)

(22)

(22)

(21)

After-Tax Net Interest Expense (Non-GAAP) - (a)

31

28

41

41

38

Net Income (GAAP) - (b)

1,090

1,300

1,260

625

430

Total Stockholders' Equity - (d)

6,990

5,600

4,316

2,945

2,223

Average Total Stockholders' Equity* - (e)

6,295

4,958

3,631

2,584

1,948

Current and Long-Term Debt (GAAP) - (f)

1,185

733

985

1,078

1,109

Less:  Cash

(54)

(218)

(644)

(21)

(4)

Net Debt (Non-GAAP) - (g)

1,131

515

341

1,057

1,105

Total Capitalization (GAAP) - (d) + (f)

8,175

6,333

5,301

4,023

3,332

Total Capitalization (Non-GAAP) - (d) + (g)

8,121

6,115

4,657

4,002

3,328

Average Total Capitalization (Non-GAAP)* - (h)

7,118

5,386

4,330

3,665

3,068

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h)

15.7

%

24.7

%

30.0

%

18.2

%

15.3

%

Return on Equity (ROE)

GAAP Net Income - (b) / (e)

17.3

%

26.2

%

34.7

%

24.2

%

22.1

%

* Average for the current and immediately preceding year

 

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

2002

2001

2000

1999

1998

Net Interest Expense (GAAP)

60

45

61

62

Tax Benefit Imputed (based on 35%)

(21)

(16)

(21)

(22)

After-Tax Net Interest Expense (Non-GAAP) - (a)

39

29

40

40

Net Income (GAAP) - (b)

87

399

397

569

Total Stockholders' Equity - (d)

1,672

1,643

1,381

1,130

1,280

Average Total Stockholders' Equity* - (e)

1,658

1,512

1,256

1,205

Current and Long-Term Debt (GAAP) - (f)

1,145

856

859

990

1,143

Less:  Cash

(10)

(3)

(20)

(25)

(6)

Net Debt (Non-GAAP) - (g)

1,135

853

839

965

1,137

Total Capitalization (GAAP) - (d) + (f)

2,817

2,499

2,240

2,120

2,423

Total Capitalization (Non-GAAP) - (d) + (g)

2,807

2,496

2,220

2,095

2,417

Average Total Capitalization (Non-GAAP)* - (h)

2,652

2,358

2,158

2,256

Return on Capital Employed (ROCE)

GAAP Net Income - [(a) + (b)] / (h)

4.8

%

18.2

%

20.2

%

27.0

%

Return on Equity (ROE)

GAAP Net Income - (b) / (e)

5.2

%

26.4

%

31.6

%

47.2

%

* Average for the current and immediately preceding year

 

Costs per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

1Q 2020

2Q 2020

3Q 2020

4Q 2020

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a)

79,548

56,733

65,873

73,740

Crude Oil and Condensate

2,065,498

614,627

1,394,622

1,710,862

Natural Gas Liquids

160,535

93,909

184,771

228,299

Natural Gas

209,764

141,696

183,790

301,883

Total Wellhead Revenues - (b)

2,435,797

850,232

1,763,183

2,241,044

Operating Costs

Lease and Well

329,659

245,346

227,473

260,896

Transportation Costs

208,296

151,728

180,257

194,708

Gathering and Processing Costs

128,482

96,767

114,790

119,172

General and Administrative

114,273

131,855

124,460

113,235

Taxes Other Than Income

157,360

80,319

126,810

113,445

Interest Expense, Net

44,690

54,213

53,242

53,121

Total Cash Cost (excluding DD&A and Total Exploration Costs) - (c)

982,760

760,228

827,032

854,577

Depreciation, Depletion and Amortization (DD&A)

1,000,060

706,679

823,050

870,564

Total Operating Cost (excluding Total Exploration Costs) - (d)

1,982,820

1,466,907

1,650,082

1,725,141

Exploration Costs

39,677

27,283

38,413

40,415

Dry Hole Costs

372

87

12,604

20

Impairments

1,572,935

305,415

78,990

142,440

Total Exploration Costs

1,612,984

332,785

130,007

182,875

Less:  Certain Impairments (Non-GAAP)

(1,516,316)

(239,167)

(26,531)

(86,451)

Total Exploration Costs (Non-GAAP)

96,668

93,618

103,476

96,424

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)

2,079,488

1,560,525

1,753,558

1,821,565

Composite Average Wellhead Revenue per Boe - (b) / (a)

30.62

14.99

26.77

30.39

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -   (c) /   (a)

12.36

13.40

12.56

11.60

Composite Average Margin per Boe (excluding DD&A and Total Exploration   Costs) - [(b) / (a) - (c) / (a)]

18.26

1.59

14.21

18.79

Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a)

24.93

25.86

25.05

23.41

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a)    - (d) / (a)]

5.69

(10.87)

1.72

6.98

Total Operating Cost  per Boe (Non-GAAP) (including Total Exploration Costs) -   (e) / (a)

26.15

27.51

26.62

24.72

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration   Costs) - [(b) / (a) - (e) / (a)]

4.47

(12.52)

0.15

5.67

 

Costs per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2020

2019

2018

2017

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a)

275,893

298,565

262,516

222,251

Crude Oil and Condensate

5,785,609

9,612,532

9,517,440

6,256,396

Natural Gas Liquids

667,514

784,818

1,127,510

729,561

Natural Gas

837,133

1,184,095

1,301,537

921,934

Total Wellhead Revenues - (b)

7,290,256

11,581,445

11,946,487

7,907,891

Operating Costs

Lease and Well

1,063,374

1,366,993

1,282,678

1,044,847

Transportation Costs

734,989

758,300

746,876

740,352

Gathering and Processing Costs

459,211

479,102

436,973

148,775

General and Administrative

483,823

489,397

426,969

434,467

Less:  Legal Settlement - Early Leasehold Termination

(10,202)

Less:  Joint Venture Transaction Costs

(3,056)

Less:  Joint Interest Billings Deemed Uncollectible

(4,528)

General and Administrative (Non-GAAP)

483,823

489,397

426,969

416,681

Taxes Other Than Income

477,934

800,164

772,481

544,662

Interest Expense, Net

205,266

185,129

245,052

274,372

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c)

3,424,597

4,079,085

3,911,029

3,169,689

Depreciation, Depletion and Amortization (DD&A)

3,400,353

3,749,704

3,435,408

3,409,387

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d)

6,824,950

7,828,789

7,346,437

6,579,076

Exploration Costs

145,788

139,881

148,999

145,342

Dry Hole Costs

13,083

28,001

5,405

4,609

Impairments

2,099,780

517,896

347,021

479,240

Total Exploration Costs

2,258,651

685,778

501,425

629,191

Less:  Certain Impairments (Non-GAAP)

(1,868,465)

(274,974)

(152,671)

(261,452)

Total Exploration Costs (Non-GAAP)

390,186

410,804

348,754

367,739

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)

7,215,136

8,239,593

7,695,191

6,946,815

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2020

2019

2018

2017

Composite Average Wellhead Revenue per Boe - (b) / (a)

26.42

38.79

45.51

35.58

Total Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) -   (c)   / (a)

12.39

13.66

14.90

14.25

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration   Costs) - [(b) / (a) - (c) / (a)]

14.03

25.13

30.61

21.33

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) -    (d) / (a)

24.71

26.22

27.99

29.59

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) -   [(b) / (a) - (d) / (a)]

1.71

12.57

17.52

5.99

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) -    (e) / (a)

26.13

27.60

29.32

31.24

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) -   [(b) / (a) - (e) / (a)]

0.29

11.19

16.19

4.34

 

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2016

2015

2014

Cost per Barrel of Oil Equivalent (Boe) Calculation

Volume - Thousand Barrels of Oil Equivalent - (a)

204,929

208,862

217,073

Crude Oil and Condensate

4,317,341

4,934,562

9,742,480

Natural Gas Liquids

437,250

407,658

934,051

Natural Gas

742,152

1,061,038

1,916,386

Total Wellhead Revenues - (b)

5,496,743

6,403,258

12,592,917

Operating Costs

Lease and Well

927,452

1,182,282

1,416,413

Transportation Costs

764,106

849,319

972,176

Gathering and Processing Costs

122,901

146,156

145,800

General and Administrative

394,815

366,594

402,010

Less:  Voluntary Retirement Expense

(42,054)

Less:  Acquisition Costs

(5,100)

Less:  Legal Settlement - Early Leasehold Termination

(19,355)

General and Administrative (Non-GAAP)

347,661

347,239

402,010

Taxes Other Than Income

349,710

421,744

757,564

Interest Expense, Net

281,681

237,393

201,458

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c)

2,793,511

3,184,133

3,895,421

Depreciation, Depletion and Amortization (DD&A)

3,553,417

3,313,644

3,997,041

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d)

6,346,928

6,497,777

7,892,462

Exploration Costs

124,953

149,494

184,388

Dry Hole Costs

10,657

14,746

48,490

Impairments

620,267

6,613,546

743,575

Total Exploration Costs

755,877

6,777,786

976,453

Less:  Certain Impairments (Non-GAAP)

(320,617)

(6,307,593)

(824,312)

Total Exploration Costs (Non-GAAP)

435,260

470,193

152,141

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)

6,782,188

6,967,970

8,044,603

 

Cost per Barrel of Oil Equivalent

In thousands of USD, except Boe and per Boe amounts (Unaudited)

2016

2015

2014

Composite Average Wellhead Revenue per Boe - (b) / (a)

26.82

30.66

58.01

Total Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) -   (c) / (a)

13.64

15.25

17.95

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration   Costs) - [(b) / (a) - (c) / (a)]

13.18

15.41

40.06

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) -    (d) / (a)

30.98

31.11

36.38

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) -   [(b) / (a) - (d) / (a)]

(4.16)

(0.45)

21.63

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) -    (e) / (a)

33.10

33.36

37.08

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) -   [(b) / (a) - (e) / (a)]

(6.28)

(2.70)

20.93

 

Quarter and Full Year Guidance

(Unaudited)

(a)  First Quarter and Full Year 2021 Forecast

The forecast items for the first quarter and full year 2021 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release.  EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.  This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

(b)  Capital Expenditures

The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.

(c)  Benchmark Commodity Pricing

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

Estimated Ranges for First Quarter and Full Year 2021

1Q 2021

FY 2021

Daily Sales Volumes

Crude Oil and Condensate Volumes (MBbld)

United States

418.0

-

428.0

433.0

-

444.0

Trinidad

1.6

-

2.4

1.0

-

1.8

Other International

0.0

-

0.2

0.0

-

0.2

Total

419.6

-

430.6

434.0

-

446.0

Natural Gas Liquids Volumes (MBbld)

Total

125.0

-

135.0

130.0

-

170.0

Natural Gas Volumes (MMcfd)

United States

1,095

-

1,155

1,100

-

1,200

Trinidad

200

-

230

180

-

220

Other International

15

-

25

15

-

25

Total

1,310

-

1,410

1,295

-

1,445

Crude Oil Equivalent Volumes (MBoed)

United States

725.5

-

755.5

746.3

-

814.0

Trinidad

34.9

-

40.7

31.0

-

38.5

Other International

2.5

-

4.4

2.5

-

4.4

Total

762.9

-

800.6

779.8

-

856.9

Capital Expenditures ($MM)

900

-

1,100

3,700

-

4,100

 

Quarter and Full Year Guidance

(Unaudited)

Estimated Ranges for First Quarter and Full Year 2021

1Q 2021

FY 2021

Operating Costs

Unit Costs ($/Boe)

Lease and Well

3.60

-

4.30

3.50

-

4.20

Transportation Costs

2.60

-

3.00

2.65

-

3.05

Gathering and Processing

1.75

-

1.85

1.65

-

1.85

Depreciation, Depletion and Amortization

12.60

-

13.10

11.70

-

12.70

General and Administrative

1.60

-

1.70

1.50

-

1.60

Expenses ($MM)

Exploration and Dry Hole

35

-

45

140

-

180

Impairment

45

-

95

255

-

295

Capitalized Interest

5

-

10

25

-

30

Net Interest

45

-

50

180

-

185

Taxes Other Than Income (% of Wellhead Revenue)

6.0

%

-

8.0

%

6.5

%

-

7.5

%

Income Taxes

Effective Rate

21

%

-

26

%

21

%

-

26

%

Deferred Ratio

(5)

%

-

5

%

0

%

-

15

%

Pricing - (Refer to Benchmark Commodity Pricing in text)

Crude Oil and Condensate ($/Bbl)

Differentials

United States - above (below) WTI

(0.80)

-

1.20

(0.55)

-

1.45

Trinidad - above (below) WTI

(11.50)

-

(9.50)

(12.40)

-

(10.40)

Other International - above (below) WTI

(21.00)

-

(15.00)

(19.20)

-

(17.20)

Natural Gas Liquids

Realizations as % of WTI

43

%

-

55

%

38

%

-

50

%

Natural Gas ($/Mcf)

Differentials

United States - above (below) NYMEX Henry Hub

1.75

-

4.25

(0.25)

-

1.25

Realizations

Trinidad

3.10

-

3.60

3.10

-

3.60

Other International

5.45

-

5.95

5.20

-

6.20

 

Definitions

$/Bbl

U.S. Dollars per barrel

$/Boe

U.S. Dollars per barrel of oil equivalent

$/Mcf

U.S. Dollars per thousand cubic feet

$MM

U.S. Dollars in millions

MBbld

Thousand barrels per day

MBoed

Thousand barrels of oil equivalent per day

MMcfd

Million cubic feet per day

NYMEX

U.S. New York Mercantile Exchange

WTI

West Texas Intermediate

 

Cision View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-fullyear-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-301236027.html

SOURCE EOG Resources, Inc.



Serious News for Serious Traders! Try StreetInsider.com Premium Free!

You May Also Be Interested In





Related Categories

PRNewswire, Press Releases

Related Entities

Bakken Formation, Dividend, Crude Oil, Earnings, Definitive Agreement