EOG Resources Reports Fourth Quarter and Full-Year 2023 Results; Announces 2024 Capital Plan

EOG Resources

HOUSTONFeb. 22, 2024 /PRNewswire/ — EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2023 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG’s website at http://investors.eogresources.com/investors.

Key Financial Results

In millions of USD, except per-share, per-Boe and ratio data

GAAP

4Q 2023

3Q 2023

2Q 2023

1Q 2023

4Q 2022

FY 2023

FY 2022

Total Revenue

6,357

6,212

5,573

6,044

6,719

24,186

25,702

Net Income

1,988

2,030

1,553

2,023

2,277

7,594

7,759

Net Income Per Share

3.42

3.48

2.66

3.45

3.87

13.00

13.22

Net Cash Provided by Operating Activities

3,104

2,704

2,277

3,255

3,444

11,340

11,093

Total Expenditures

1,634

1,803

1,664

1,717

1,535

6,818

5,610

Current and Long-Term Debt

3,799

3,806

3,814

3,820

5,078

3,799

5,078

Cash and Cash Equivalents

5,278

5,326

4,764

5,018

5,972

5,278

5,972

Debt-to-Total Capitalization

11.9 %

12.1 %

12.7 %

13.1 %

17.0 %

11.9 %

17.0 %

Cash Operating Costs ($/Boe)

10.52

10.19

10.03

10.59

10.82

10.33

10.52

General and Administrative Costs ($/Boe)

2.03

1.75

1.61

1.71

1.87

1.78

1.72

Non – GAAP

Adjusted Net Income

1,783

2,007

1,457

1,578

1,941

6,825

8,080

Adjusted Net Income Per Share

3.07

3.44

2.49

2.69

3.30

11.69

13.76

CFO before Changes in Working Capital

2,989

3,038

2,563

2,559

3,091

11,149

12,252

Capital Expenditures

1,512

1,519

1,521

1,489

1,361

6,041

4,607

Free Cash Flow

1,477

1,519

1,042

1,070

1,730

5,108

7,645

Net Debt

(1,479)

(1,520)

(950)

(1,198)

(894)

(1,479)

(894)

Net Debt-to-Total Capitalization

(5.6 %)

(5.8 %)

(3.8 %)

(4.9 %)

(3.7 %)

(5.6 %)

(3.7 %)

Cash Operating Costs ($/Boe)1

10.52

10.19

10.03

10.59

10.82

10.33

10.47

General and Administrative Costs ($/Boe)1

2.03

1.75

1.61

1.71

1.87

1.78

1.67

 

Fourth Quarter Highlights

  • Earned adjusted net income of $1.8 billion, or $3.07 per share
  • Generated $1.5 billion of free cash flow
  • Declared regular quarterly dividend of $0.91 per share and repurchased $300 million of shares
  • Volumes and per-unit operating costs beat guidance midpoints
  • Entered into a 10-year Brent-linked gas sales agreement starting in January 2027

Full-Year 2023 Highlights and 2024 Capital Plan

  • Generated $5.1 billion of free cash flow and returned $4.4 billion to shareholders
  • Delivered oil and total volumes on target and reduced per-unit cash operating costs and DD&A
  • Announced $6.2 billion capital plan to grow oil production 3% and total production 7%

 

Volumes and Capital Expenditures

4Q 2023

4Q 2023

Guidance
Midpoint

3Q 2023

2Q 2023

1Q 2023

4Q 2022

FY 2023

FY 2022

Wellhead Volumes

Crude Oil and Condensate (MBod)

485.2

483.5

483.3

476.6

457.7

465.6

475.8

461.3

Natural Gas Liquids (MBbld)

235.8

234.0

231.1

215.7

212.2

189.0

223.8

197.7

Natural Gas (MMcfd)

1,831

1,785

1,704

1,668

1,639

1,527

1,711

1,495

Total Crude Oil Equivalent (MBoed)

1,026.2

1,015.0

998.5

970.3

943.0

909.1

984.8

908.2

Capital Expenditures ($MM)

1,512

1,500

1,519

1,521

1,489

1,361

6,041

4,607

 

From Ezra Yacob, Chairman and Chief Executive Officer
“EOG continues to deliver on its value proposition as demonstrated by our strong execution in 2023. Oil and total volumes were on target, capital expenditures on budget, and we further lowered operating costs. Each of the teams working across our multi-basin portfolio championed the EOG culture and played an important role in delivering another successful year.

“The ability to manage investment and pace of activity at the appropriate level for each of our plays was critical to our success in 2023. We lowered the overall cost basis of the company by balancing activity between foundational assets and emerging plays. Progress across our portfolio, including continued improvement in Delaware Basin productivity, successful delineation results in the Utica play, and advancements across several exploration areas, provides opportunity for further improvement going forward.

“EOG’s operating results drove our financial performance. EOG earned strong return on capital, while generating $5.1 billion of free cash flow. Cash return to shareholders of $4.4 billion was well above our prior minimum 60% commitment and continues to be anchored by our sustainable, growing regular dividend. The financial strength of the company, including our cash flow generation capacity and our industry-leading balance sheet, allowed us to increase our regular dividend 10% and go-forward cash return commitment to a minimum 70% of annual free cash flow.

“EOG’s business has never been better, and our financial position has never been stronger. Our 2024 plan demonstrates our consistent focus on improving the cost structure of our company. The depth of resource across our multi-basin portfolio of premium assets provides long-term visibility for high returns and strong free cash flow generation. Our confidence in EOG’s ability to compete across sectors, create value for our shareholders, and be part of the long-term energy solution has never been higher.”

 

Fourth Quarter 2023 Financial Performance

Prices

  • Crude oil and NGL prices decreased, partially offset by an increase in natural gas prices from 3Q

Volumes

  • Oil production of 485,200 Bopd was above the guidance midpoint and up from 3Q
  • NGL production was above the guidance midpoint and up 2% from 3Q
  • Natural gas production was above the high end of the guidance range and up 7% from 3Q
  • Total company equivalent production increased 3% from 3Q

Per-Unit Costs

  • Gathering & processing, G&A, and DD&A expenses increased in 4Q compared with 3Q, while LOE and transportation costs decreased

Hedges

  • Mark-to-market hedge gains increased GAAP earnings per share in 4Q compared with 3Q
  • Cash received to settle hedges decreased from 3Q, lowering adjusted non-GAAP earnings per share

Free Cash Flow

  • Cash flow from operations before changes in working capital was $3.0 billion
  • EOG incurred $1.5 billion of capital expenditures
  • This resulted in $1.5 billion of free cash flow

Cash Return and Working Capital

  • Paid $479 million in regular dividends
  • Paid $866 million in special dividends
  • Repurchased $300 million of stock
  • Changes in working capital and other items accounted for approximately $100 million of the increase in cash

 

Full-Year 2023 Financial Performance

Prices

  • Crude oil prices decreased 19%
  • NGL prices decreased 37%
  • Natural gas prices decreased 60%

Volumes

  • Crude oil production increased 3% to 475,800 Bopd
  • NGL production increased 13%
  • Natural gas production increased 14%
  • Total company equivalent production increased 8%

Per-Unit Costs

  • DD&A, transportation costs, and gathering & processing costs decreased in 2023, partially offset by higher LOE and G&A

Hedges

  • Lower commodity prices in 2023 were partially offset by net mark-to-market hedge gains and lower net cash payments to settle hedges than 2022

Free Cash Flow

  • Cash flow from operations before changes in working capital was $11.1 billion
  • EOG incurred $6.0 billion of capital expenditures
  • This resulted in $5.1 billion of free cash flow

Cash Return and Working Capital

  • Paid $1.9 billion in regular dividends
  • Paid $1.5 billion in special dividends
  • Repurchased $971 million of stock
  • Repaid $1.25 billion of debt upon maturity

 

Fourth Quarter 2023 Operating Performance; Cash Return

Lease and Well

  • QoQ: Generally flat
  • Guidance Midpoint: Lower primarily due to water handling costs and workovers

Transportation

  • QoQ: Generally flat
  • Guidance Midpoint: Lower primarily due to natural gas transportation

Gathering and Processing

  • QoQ: Increased primarily due to fuel costs
  • Guidance Midpoint: Generally flat

General and Administrative

  • QoQ: Increased primarily due to professional fees and employee-related expenses
  • Guidance Midpoint: Higher primarily due to professional fees and employee- related expenses

Depreciation, Depletion and Amortization

  • QoQ: Increased primarily due to well mix
  • Guidance Midpoint: Lower primarily due to the addition of lower cost reserves

 

Regular Dividend and Fourth Quarter Share Repurchases
The Board of Directors today declared a dividend of $0.91 per share on EOG’s common stock. The dividend will be payable April 30, 2024, to stockholders of record as of April 16, 2024. The indicated annual rate is $3.64 per share.

During the fourth quarter, the company repurchased 2.4 million shares for $300 million under its share repurchase authorization, at an average purchase price of $123 per share.

For full-year 2023, the company repurchased 8.6 million shares for $971 million under its share repurchase authorization, at an average purchase price of $112 per share. EOG has $4.0 billion remaining on its current repurchase authorization.

 

2023 Reserves

Finding and Development Cost
Finding and development cost, excluding price revisions, increased in 2023 to $7.20 per Boe, due to lower year-over-year revisions other than price and cost inflation. Proved developed finding cost, excluding price revisions, was $10.50 per Boe (GAAP) and $9.35 per Boe (Non-GAAP) in 2023.

For the 36th consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.

Reserve Replacement
Total proved reserves increased 6% in 2023. Extensions and discoveries added 607 MMBoe of proved reserves in 2023. Revisions other than price increased proved reserves by 139 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 202% of 2023 total production.

 

2024 Capital Program and Brent-Linked Gas Sales Agreement

2024 Capital Program
Total expenditures for 2024 are expected to range from $6.0 to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs, and other property, plant and equipment, and excluding property acquisitions, asset retirement costs and non-cash exchanges and transactions. The capital program also excludes certain exploration costs incurred as operating expenses.

The disciplined capital program allocates approximately $4.3 billion to drill and complete 600 net wells in EOG’s domestic premium areas. Strong capital efficiency delivers 3% oil volume growth and 7% total volume growth, for ~$100 million lower year-over-year total direct investment in drilling and completion activity. The plan is anchored by steady year-over-year activity levels across most of EOG’s premium plays, with a step up in activity in the Ohio Utica play.

The capital program also funds investment in environmental and infrastructure projects, including approximately $400 million in strategic infrastructure projects associated with EOG’s Delaware Basin and Dorado assets. These projects are expected to provide several long-term benefits to the company, including margin improvement through higher price realizations and lower operating costs.

Brent-Linked Gas Sales Agreement
EOG entered into a 10-year Brent-linked gas sales agreement. Starting in January 2027, the company will have sales volumes of 140K MMBtu per day linked to Brent crude oil prices with an additional 40K MMBtu per day linked to Brent crude oil prices or a US Gulf Coast gas index. This latest agreement complements existing agreements in providing additional pricing diversification for gas volumes sourced across several basins within EOG’s multi-basin portfolio.

 

Fourth Quarter 2023 Results vs Guidance

(Unaudited)

See “Endnotes” below for related discussion and definitions.

4Q 2023

4Q 2023

Guidance

Midpoint

Variance

3Q 2023

2Q 2023

1Q 2023

4Q 2022

Crude Oil and Condensate Volumes (MBod)

United States

484.6

483.1

1.5

482.8

476.0

457.1

465.1

Trinidad

0.6

0.4

0.2

0.5

0.6

0.6

0.5

Other International

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Total

485.2

483.5

1.7

483.3

476.6

457.7

465.6

Natural Gas Liquids Volumes (MBbld)

Total

235.8

234.0

1.8

231.1

215.7

212.2

189.0

Natural Gas Volumes (MMcfd)

United States

1,653

1,615

38

1,562

1,513

1,475

1,378

Trinidad

178

170

8

142

155

164

149

Other International

0

0

0

0

0

0

0

Total

1,831

1,785

46

1,704

1,668

1,639

1,527

Total Crude Oil Equivalent Volumes (MBoed)

1,026.2

1,015.0

11.2

998.5

970.3

943.0

909.1

Total MMBoe

94.4

93.4

1.0

91.9

88.3

84.9

83.6

Benchmark Price

Oil (WTI) ($/Bbl)

78.33

82.18

73.75

76.11

82.63

Natural Gas (HH) ($/Mcf)

2.87

2.55

2.09

3.43

6.27

Crude Oil and Condensate – above (below) WTI3 ($/Bbl)

United States

2.28

2.00

0.28

1.43

1.23

1.16

3.05

Trinidad

(9.12)

(11.25)

2.13

(10.80)

(8.87)

(7.13)

(7.42)

Natural Gas Liquids – Realizations as % of WTI

Total

28.5 %

27.0 %

1.5 %

28.7 %

28.3 %

33.7 %

34.6 %

Natural Gas – above (below) NYMEX Henry Hub4 ($/Mcf)

United States

(0.15)

0.15

(0.30)

0.04

(0.02)

0.04

(0.15)

Natural Gas Realizations5 ($/Mcf)

Trinidad

3.81

3.48

0.33

3.41

3.45

3.87

3.97

Total Expenditures (GAAP) ($MM)

1,634

1,803

1,664

1,717

1,535

Capital Expenditures (non-GAAP) ($MM)

1,512

1,500

12

1,519

1,521

1,489

1,361

Operating Unit Costs ($/Boe)

Lease and Well

4.00

4.20

(0.20)

4.02

3.94

4.23

4.23

Transportation Costs

2.60

2.65

(0.05)

2.61

2.67

2.78

2.83

Gathering and Processing

1.89

1.90

(0.01)

1.81

1.81

1.87

1.89

General and Administrative (GAAP)

2.03

1.90

0.13

1.75

1.61

1.71

1.87

General and Administrative (non-GAAP)1

2.03

1.90

0.13

1.75

1.61

1.71

1.87

Cash Operating Costs (GAAP)

10.52

10.65

(0.13)

10.19

10.03

10.59

10.82

Cash Operating Costs (non-GAAP)

10.52

10.65

(0.13)

10.19

10.03

10.59

10.82

Depreciation, Depletion and Amortization

9.85

10.00

(0.15)

9.78

9.81

9.40

10.50

Expenses ($MM)

Exploration and Dry Hole

41

45

(4)

43

47

51

48

Impairment (GAAP)

79

54

35

34

142

Impairment (excluding certain impairments (non-GAAP))6

60

100

(40)

31

35

34

111

Capitalized Interest

9

10

(1)

8

8

8

11

Net Interest

35

34

1

36

35

42

42

TOTI (% of Wellhead Revenue) (GAAP)

6.6 %

7.5 %

(0.9 %)

7.4 %

7.8 %

7.8 %

7.8 %

TOTI (% of Wellhead Revenue) (non-GAAP)1

6.6 %

7.5 %

(0.9 %)

7.4 %

7.8 %

7.8 %

7.8 %

Income Taxes

Effective Rate

21.6 %

21.5 %

0.1 %

21.1 %

21.9 %

22.0 %

20.4 %

Current Tax Expense ($MM)

352

330

22

486

241

338

409

 

First Quarter and Full-Year 2024 Guidance7

(Unaudited)
See “Endnotes” below for related discussion and definitions.

1Q 2024

Guidance Range

1Q 2024

Midpoint

FY 2024

Guidance Range

FY 2024

Midpoint

2023

Actual

2022

Actual

2021

Actual

Crude Oil and Condensate Volumes (MBod)

United States

483.0

489.0

486.0

485.0

490.0

487.5

475.2

460.7

443.4

Trinidad

0.1

0.5

0.3

0.5

1.5

1.0

0.6

0.6

1.5

Other International

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.1

Total

483.1

489.5

486.3

485.5

491.5

488.5

475.8

461.3

445.0

Natural Gas Liquids Volumes (MBbld)

Total

223.0

233.0

228.0

220.0

250.0

235.0

223.8

197.7

144.5

Natural Gas Volumes (MMcfd)

United States

1,625

1,675

1,650

1,630

1,830

1,730

1,551

1,315

1,210

Trinidad

170

200

185

210

240

225

160

180

217

Other International

0

0

0

0

0

0

0

0

9

Total

1,795

1,875

1,835

1,840

2,070

1,955

1,711

1,495

1,436

Crude Oil Equivalent Volumes (MBoed)

United States

976.8

1,001.2

989.0

976.7

1,045.0

1,010.9

957.5

877.5

789.6

Trinidad

28.4

33.8

31.1

35.5

41.5

38.5

27.3

30.7

37.7

Other International

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

1.6

Total

1,005.2

1,035.0

1,020.1

1,012.2

1,086.5

1,049.4

984.8

908.2

828.9

Benchmark Price

Oil (WTI) ($/Bbl)

77.61

94.23

67.96

Natural Gas (HH) ($/Mcf)

2.74

6.64

3.85

Crude Oil and Condensate – above (below) WTI3 ($/Bbl)

United States

0.75

2.25

1.50

0.40

2.40

1.40

1.57

2.99

0.58

Trinidad

(10.10)

(8.60)

(9.35)

(11.40)

(9.40)

(10.40)

(9.03)

(8.07)

(11.70)

Natural Gas Liquids – Realizations as % of WTI

Total

27.0 %

37.0 %

32.0 %

26.0 %

36.0 %

31.0 %

29.7 %

39.0 %

50.5 %

Natural Gas – above (below) NYMEX Henry Hub4 ($/Mcf)

United States

(0.45)

0.25

(0.10)

(1.30)

0.80

(0.25)

(0.04)

0.63

1.03

Natural Gas Realizations5 ($/Mcf)

Trinidad

3.10

3.80

3.45

3.00

4.00

3.50

3.65

4.43

3.40

Total Expenditures (GAAP) ($MM)

6,818

5,610

4,255

Capital Expenditures8 (non-GAAP) ($MM)

1,650

1,750

1,700

6,000

6,400

6,200

6,041

4,607

3,755

Operating Unit Costs ($/Boe)

Lease and Well

3.95

4.45

4.20

3.80

4.50

4.15

4.05

4.02

3.75

Transportation Costs

2.50

2.80

2.65

2.45

2.85

2.65

2.66

2.91

2.85

Gathering and Processing

1.85

2.05

1.95

1.85

2.15

2.00

1.84

1.87

1.85

General and Administrative (GAAP)

1.70

2.00

1.85

1.70

1.95

1.83

1.78

1.72

1.69

General and Administrative (non-GAAP)1

1.78

1.67

1.69

Cash Operating Costs (GAAP)

10.00

11.30

10.65

9.80

11.45

10.63

10.33

10.52

10.14

Cash Operating Costs (non-GAAP)

10.33

10.47

10.14

Depreciation, Depletion and Amortization

10.90

11.90

11.40

10.00

11.00

10.50

9.72

10.69

12.07

Expenses ($MM)

Exploration and Dry Hole

30

70

50

175

225

200

182

204

225

Impairment (GAAP)

202

382

376

Impairment (excluding certain impairments (non-GAAP))6

30

110

70

160

240

200

160

269

361

Capitalized Interest

7

11

9

39

43

41

33

36

33

Net Interest

33

37

35

131

135

133

148

179

178

TOTI (% of Wellhead Revenue) (GAAP)

7.0 %

9.0 %

8.0 %

7.0 %

9.0 %

8.0 %

7.4 %

7.0 %

6.8 %

TOTI (% of Wellhead Revenue) (non-GAAP)1

7.4 %

7.5 %

6.8 %

Income Taxes

Effective Rate

20.0 %

25.0 %

22.5 %

20.0 %

25.0 %

22.5 %

21.6 %

21.7 %

21.4 %

Current Tax Expense ($MM)

270

370

320

1,060

1,460

1,260

1,415

2,208

1,393

 

Fourth Quarter and Full-Year 2023 Results Webcast
Friday, February 23, 20249:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG’s website for one year. http://investors.eogresources.com/Investors

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

Investor Contacts
Pearce Hammond 713-571-4684
Neel Panchal 713-571-4884
Shelby O’Connor 713-571-4560

Media Contact
Kimberly Ehmer 713-571-4676

 

Endnotes

1)

Third quarter 2022 TOTI (% of Wellhead Revenue) (non-GAAP) and General and Administrative Costs (non-GAAP) exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying Adjusted Net Income (Loss) reconciliation schedule.

2)

Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.

3)

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

4)

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.

5)

The third quarter and full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $3.37/Mcf and $0.76/Mcf, respectively, for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited (NGC).

6)

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

7)

The forecast items for the first quarter and full year 2024 set forth above for EOG are based on currently available information and expectations as of the date of this 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 this press release and EOG’s related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

8)

The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

 

Glossary

Acq

Acquisitions

ATROR

After-tax rate of return

Bbl

Barrel

Bn

Billion

Boe

Barrels of oil equivalent

Bopd

Barrels of oil per day

CAGR

Compound annual growth rate

Capex

Capital expenditures

CFO

Cash flow provided by operating activities before changes in working capital

CO2e

Carbon dioxide equivalent

DD&A

Depreciation, Depletion and Amortization

Disc

Discoveries

Divest

Divestitures

EPS

Earnings per share

Ext

Extensions

G&A

General and administrative expense

G&P

Gathering and processing expense

GHG

Greenhouse gas

HH

Henry Hub

LOE

Lease operating expense, or lease and well expense

MBbld

Thousand barrels of liquids per day

MBod

Thousand barrels of oil per day

MBoe

Thousand barrels of oil equivalent

MBoed

Thousand barrels of oil equivalent per day

Mcf

Thousand cubic feet of natural gas

MMBoe

Million barrels of oil equivalent

MMcfd

Million cubic feet of natural gas per day

NGLs

Natural gas liquids

NYMEX

U.S. New York Mercantile Exchange

OTP

Other than price

QoQ

Quarter over quarter

TOTI

Taxes other than income

Trans

Transportation expense

USD

United States dollar

WTI

West Texas Intermediate

YoY

Year over year

$MM

Million United States dollars

$/Bbl

U.S. Dollars per barrel

$/Boe

U.S. Dollars per barrel of oil equivalent

$/Mcf

U.S. Dollars per thousand cubic feet

 

This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements. EOG typically uses words such as “expect,” “anticipate,” “estimate,” “project,” “strategy,” “intend,” “plan,” “target,” “aims,” “ambition,” “initiative,” “goal,” “may,” “will,” “focused on,” “should” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG’s future financial or 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 drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, pay and/or increase regular and/or special dividends or repurchase shares 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 such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. 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. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:

  • the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;
  • the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
  • the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures 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 success of EOG’s cost-mitigation initiatives and actions in offsetting the impact of inflationary pressures on EOG’s operating costs and capital expenditures;
  • the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
  • security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on prevention and disclosure requirements relating to cyber incidents;
  • the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities;
  • the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of- way, and EOG’s ability to retain mineral licenses and leases;
  • the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax and emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
  • continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG’s day-to-day operations;
  • the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets, ambitions and initiatives;
  • EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
  • the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
  • competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
  • the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel 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, liquefaction, 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;
  • 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 conflicts), including in the areas in which EOG operates;
  • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
  • acts of war and terrorism and responses to these acts; and
  • the other factors described under ITEM 1A, Risk Factors of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 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.

Historical Non-GAAP Financial Measures:
Reconciliation schedules and definitions for the historical non-GAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com.

Cautionary Notice Regarding Forward-Looking Non-GAAP Financial Measures:
In addition, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow, cash flow provided by operating activities before changes in working capital and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. 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 changes in working capital and future impairments. 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 without unreasonable efforts. 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.

Oil and Gas Reserves:
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, 2023 (and any updates to such disclosure set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), 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.

 

Income Statements

In millions of USD, except share data (in millions) and per share data (Unaudited)

2022

2023

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Operating Revenues and Other

Crude Oil and Condensate

3,889

4,699

4,109

3,670

16,367

3,182

3,252

3,717

3,597

13,748

Natural Gas Liquids

681

777

693

497

2,648

490

409

501

484

1,884

Natural Gas

716

1,000

1,235

830

3,781

517

334

417

476

1,744

Gains (Losses) on Mark-to-Market Financial Commodity Derivative
Contracts, Net

(2,820)

(1,377)

(18)

233

(3,982)

376

101

43

298

818

Gathering, Processing and Marketing

1,469

2,169

1,561

1,497

6,696

1,390

1,465

1,478

1,473

5,806

Gains (Losses) on Asset Dispositions, Net

25

97

(21)

(27)

74

69

(9)

35

95

Other, Net

23

42

34

19

118

20

21

21

29

91

Total

3,983

7,407

7,593

6,719

25,702

6,044

5,573

6,212

6,357

24,186

Operating Expenses

Lease and Well

318

324

335

354

1,331

359

348

369

378

1,454

Transportation Costs

228

244

257

237

966

236

236

240

245

957

Gathering and Processing Costs

144

152

167

158

621

159

160

166

178

663

Exploration Costs

45

35

35

44

159

50

47

43

41

181

Dry Hole Costs

3

20

18

4

45

1

1

Impairments

55

91

94

142

382

34

35

54

79

202

Marketing Costs

1,283

2,127

1,621

1,504

6,535

1,361

1,456

1,383

1,509

5,709

Depreciation, Depletion and Amortization

847

911

906

878

3,542

798

866

898

930

3,492

General and Administrative

124

128

162

156

570

145

142

161

192

640

Taxes Other Than Income

390

472

334

389

1,585

329

313

341

301

1,284

Total

3,437

4,504

3,929

3,866

15,736

3,472

3,603

3,655

3,853

14,583

Operating Income

546

2,903

3,664

2,853

9,966

2,572

1,970

2,557

2,504

9,603

Other Income (Expense), Net

(1)

27

40

48

114

65

51

52

66

234

Income Before Interest Expense and Income Taxes

545

2,930

3,704

2,901

10,080

2,637

2,021

2,609

2,570

9,837

Interest Expense, Net

48

48

41

42

179

42

35

36

35

148

Income Before Income Taxes

497

2,882

3,663

2,859

9,901

2,595

1,986

2,573

2,535

9,689

Income Tax Provision

107

644

809

582

2,142

572

433

543

547

2,095

Net Income

390

2,238

2,854

2,277

7,759

2,023

1,553

2,030

1,988

7,594

Dividends Declared per Common Share

1.7500

2.5500

2.2500

2.3250

8.8750

1.8250

0.8250

0.8250

2.4100

5.8850

Net Income Per Share

Basic

0.67

3.84

4.90

3.90

13.31

3.46

2.68

3.51

3.43

13.07

Diluted

0.67

3.81

4.86

3.87

13.22

3.45

2.66

3.48

3.42

13.00

Average Number of Common Shares

Basic

582

583

583

584

583

584

580

579

579

581

Diluted

586

588

587

588

587

587

584

583

581

584

 

Wellhead Volumes and Prices

(Unaudited)

2022

2023

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Crude Oil and Condensate Volumes (MBbld) (A)

United States

449.4

463.5

464.6

465.1

460.7

457.1

476.0

482.8

484.6

475.2

Trinidad

0.7

0.6

0.5

0.5

0.6

0.6

0.6

0.5

0.6

0.6

Total

450.1

464.1

465.1

465.6

461.3

457.7

476.6

483.3

485.2

475.8

Average Crude Oil and Condensate Prices ($/Bbl) (B)

United States

$ 96.02

$ 111.26

$ 96.05

$ 85.68

$ 97.22

$ 77.27

$ 74.98

$ 83.61

80.61

$ 79.18

Trinidad

83.82

98.29

84.98

75.21

86.16

68.98

64.88

71.38

69.21

68.58

Composite

96.00

111.25

96.04

85.67

97.21

77.26

74.97

83.60

80.60

79.17

Natural Gas Liquids Volumes (MBbld) (A)

United States

190.3

201.9

209.3

189.0

197.7

212.2

215.7

231.1

235.8

223.8

Total

190.3

201.9

209.3

189.0

197.7

212.2

215.7

231.1

235.8

223.8

Average Natural Gas Liquids Prices ($/Bbl) (B)

United States

$ 39.77

$ 42.28

$ 36.02

$ 28.55

$ 36.70

$ 25.67

$ 20.85

$ 23.56

22.29

$ 23.07

Composite

39.77

42.28

36.02

28.55

36.70

25.67

20.85

23.56

22.29

23.07

Natural Gas Volumes (MMcfd) (A)

United States

1,249

1,324

1,306

1,378

1,315

1,475

1,513

1,562

1,653

1,551

Trinidad

209

204

163

149

180

164

155

142

178

160

Total

1,458

1,528

1,469

1,527

1,495

1,639

1,668

1,704

1,831

1,711

Average Natural Gas Prices ($/Mcf) (B)

United States

$ 5.81

$ 7.77

$ 9.35

$ 6.12

$ 7.27

$ 3.47

$ 2.07

$ 2.59

2.72

$ 2.70

Trinidad (D)

3.36

3.42

7.45

3.97

4.43

3.87

3.45

3.41

3.81

3.65

Composite

5.46

7.19

9.14

5.91

6.93

3.51

2.20

2.66

2.82

2.79

Crude Oil Equivalent Volumes (MBoed) (C)

United States

847.8

886.1

891.6

883.8

877.5

915.0

943.8

974.2

995.8

957.5

Trinidad

35.5

34.6

27.6

25.3

30.7

28.0

26.5

24.3

30.4

27.3

Total

883.3

920.7

919.2

909.1

908.2

943.0

970.3

998.5

1,026.2

984.8

Total MMBoe (C)

79.5

83.8

84.6

83.6

331.5

84.9

88.3

91.9

94.4

359.4

(A)

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

(B)

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, 2023).

(C)

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.

(D)

Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG’s composite wellhead natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with the National Gas Company of Trinidad and Tobago Limited and its subsidiary amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

 

Balance Sheets

In millions of USD (Unaudited)

2022

2023

MAR

JUN

SEP

DEC

MAR

JUN

SEP

DEC

Current Assets

Cash and Cash Equivalents

4,009

3,073

5,272

5,972

5,018

4,764

5,326

5,278

Accounts Receivable, Net

3,213

3,735

3,343

2,774

2,455

2,263

2,927

2,716

Inventories

586

739

872

1,058

1,131

1,355

1,379

1,275

Assets from Price Risk Management Activities

1

106

Income Taxes Receivable

93

97

1

Other

671

605

621

574

580

523

626

560

Total

8,479

8,153

10,201

10,475

9,184

8,906

10,258

9,935

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method)

65,408

66,098

67,065

67,322

67,907

69,178

70,730

72,090

Other Property, Plant and Equipment

4,801

4,862

4,659

4,786

5,101

5,282

5,355

5,497

Total Property, Plant and Equipment

70,209

70,960

71,724

72,108

73,008

74,460

76,085

77,587

Less: Accumulated Depreciation, Depletion and Amortization

(41,747)

(42,113)

(42,623)

(42,679)

(42,785)

(43,550)

(44,362)

(45,290)

Total Property, Plant and Equipment, Net

28,462

28,847

29,101

29,429

30,223

30,910

31,723

32,297

Deferred Income Taxes

13

12

18

33

31

33

33

42

Other Assets

1,143

1,127

1,167

1,434

1,587

1,638

1,633

1,583

Total Assets

38,097

38,139

40,487

41,371

41,025

41,487

43,647

43,857

Current Liabilities

Accounts Payable

2,660

2,896

2,718

2,532

2,438

2,205

2,464

2,437

Accrued Taxes Payable

1,130

594

542

405

637

425

605

466

Dividends Payable

436

437

437

482

482

478

478

526

Liabilities from Price Risk Management Activities

260

79

243

169

31

22

22

Current Portion of Long-Term Debt

1,283

1,282

1,282

1,283

33

34

34

34

Current Portion of Operating Lease Liabilities

223

216

235

296

354

335

337

325

Other

272

264

289

346

253

232

285

286

Total

6,264

5,768

5,746

5,513

4,228

3,731

4,225

4,074

Long-Term Debt

3,816

3,809

3,802

3,795

3,787

3,780

3,772

3,765

Other Liabilities

2,191

2,067

2,573

2,574

2,620

2,581

2,698

2,526

Deferred Income Taxes

4,286

4,183

4,517

4,710

4,943

5,138

5,194

5,402

Commitments and Contingencies

Stockholders’ Equity

Common Stock, $0.01 Par

206

206

206

206

206

206

206

206

Additional Paid in Capital

6,095

6,128

6,155

6,187

6,219

6,257

6,133

6,166

Accumulated Other Comprehensive Loss

(13)

(12)

(6)

(8)

(8)

(9)

(7)

(9)

Retained Earnings

15,283

16,028

17,563

18,472

19,423

20,497

22,047

22,634

Common Stock Held in Treasury

(31)

(38)

(69)

(78)

(393)

(694)

(621)

(907)

Total Stockholders’ Equity

21,540

22,312

23,849

24,779

25,447

26,257

27,758

28,090

Total Liabilities and Stockholders’ Equity

38,097

38,139

40,487

41,371

41,025

41,487

43,647

43,857

 

Cash Flow Statements

In millions of USD (Unaudited)

2022

2023

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Cash Flows from Operating Activities

Reconciliation of Net Income to Net Cash Provided by Operating Activities:

Net Income

390

2,238

2,854

2,277

7,759

2,023

1,553

2,030

1,988

7,594

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization

847

911

906

878

3,542

798

866

898

930

3,492

Impairments

55

91

94

142

382

34

35

54

79

202

Stock-Based Compensation Expenses

35

30

34

34

133

34

35

57

51

177

Deferred Income Taxes

(465)

(102)

327

179

(61)

234

194

56

199

683

(Gains) Losses on Asset Dispositions, Net

(25)

(97)

21

27

(74)

(69)

9

(35)

(95)

Other, Net

6

(16)

(5)

15

4

2

(1)

22

27

Dry Hole Costs

3

20

18

4

45

1

1

Mark-to-Market Financial Commodity Derivative Contracts (Gains) Losses, Net

2,820

1,377

18

(233)

3,982

(376)

(101)

(43)

(298)

(818)

Net Cash Received from (Payments for) Settlements of Financial
Commodity Derivative Contracts

(296)

(2,114)

(847)

(244)

(3,501)

(123)

(30)

23

18

(112)

Other, Net

2

19

12

12

45

(1)

(1)

(2)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

(878)

(522)

392

661

(347)

338

137

(714)

201

(38)

Inventories

(14)

(157)

(140)

(223)

(534)

(77)

(226)

(28)

100

(231)

Accounts Payable

130

259

(88)

(211)

90

(77)

(231)

238

(49)

(119)

Accrued Taxes Payable

613

(536)

(53)

(137)

(113)

232

(212)

180

(139)

61

Other Assets

(213)

71

(129)

(93)

(364)

52

43

(92)

36

39

Other Liabilities

(2,250)

433

1,269

282

(266)

193

(47)

54

(16)

184

Changes in Components of Working Capital Associated with Investing Activities

68

143

90

74

375

35

250

28

(18)

295

Net Cash Provided by Operating Activities

828

2,048

4,773

3,444

11,093

3,255

2,277

2,704

3,104

11,340

Investing Cash Flows

Additions to Oil and Gas Properties

(939)

(1,349)

(1,102)

(1,229)

(4,619)

(1,305)

(1,341)

(1,379)

(1,360)

(5,385)

Additions to Other Property, Plant and Equipment

(70)

(75)

(103)

(133)

(381)

(319)

(180)

(139)

(162)

(800)

Proceeds from Sales of Assets

121

110

79

39

349

92

29

14

5

140

Other Investing Activities

(30)

(30)

Changes in Components of Working Capital Associated with Investing Activities

(68)

(143)

(90)

(74)

(375)

(35)

(250)

(28)

18

(295)

Net Cash Used in Investing Activities

(956)

(1,487)

(1,216)

(1,397)

(5,056)

(1,567)

(1,742)

(1,532)

(1,499)

(6,340)

Financing Cash Flows

Long-Term Debt Repayments

(1,250)

(1,250)

Dividends Paid

(1,023)

(1,486)

(1,312)

(1,327)

(5,148)

(1,067)

(480)

(494)

(1,345)

(3,386)

Treasury Stock Purchased

(43)

(15)

(37)

(23)

(118)

(317)

(302)

(109)

(310)

(1,038)

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

4

13

11

28

9

1

10

20

Debt Issuance Costs

(8)

(8)

Repayment of Finance Lease Liabilities

(10)

(9)

(8)

(8)

(35)

(8)

(8)

(8)

(8)

(32)

Net Cash Used in Financing Activities

(1,072)

(1,497)

(1,357)

(1,347)

(5,273)

(2,642)

(789)

(610)

(1,653)

(5,694)

Effect of Exchange Rate Changes on Cash

(1)

(1)

Increase (Decrease) in Cash and Cash Equivalents

(1,200)

(936)

2,199

700

763

(954)

(254)

562

(48)

(694)

Cash and Cash Equivalents at Beginning of Period

5,209

4,009

3,073

5,272

5,209

5,972

5,018

4,764

5,326

5,972

Cash and Cash Equivalents at End of Period

4,009

3,073

5,272

5,972

5,972

5,018

4,764

5,326

5,278

5,278

 

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), Cash Flow from Operations Before Changes in Working Capital, Free Cash Flow, Net Debt and related statistics.

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

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

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

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

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

Direct ATROR

The calculation of EOG’s direct after-tax rate of return (ATROR) is based on EOG’s net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG’s direct net costs incurred in drilling or acquiring such well(s). As such, EOG’s direct ATROR for a particular well(s) or play cannot be calculated from EOG’s consolidated financial statements.

 

Adjusted Net Income (Loss)

In millions of USD, except share data (in millions) and per share data (Unaudited)

The following tables adjust reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG’s assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG’s oil and gas properties or other assets)), and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

4Q 2023

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

2,535

(547)

1,988

3.42

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net

(298)

64

(234)

(0.40)

Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1)

18

(4)

14

0.02

Less: Losses on Asset Dispositions, Net

Add: Certain Impairments

19

(4)

15

0.03

Adjustments to Net Income

(261)

56

(205)

(0.35)

Adjusted Net Income (Non-GAAP)

2,274

(491)

1,783

3.07

Average Number of Common Shares (Non-GAAP)

Basic

579

Diluted

581

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG adds to reported Net Income (Loss) (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2023, such amount was $18 million.

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

3Q 2023

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

2,573

(543)

2,030

3.48

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net

(43)

9

(34)

(0.06)

Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1)

23

(5)

18

0.03

Less: Gains on Asset Dispositions, Net

(35)

7

(28)

(0.05)

Add: Certain Impairments

23

(2)

21

0.04

Adjustments to Net Income

(32)

9

(23)

(0.04)

Adjusted Net Income (Non-GAAP)

2,541

(534)

2,007

3.44

Average Number of Common Shares (Non-GAAP)

Basic

579

Diluted

583

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG adds to reported Net Income (Loss) (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2023, such amount was $23 million.

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

2Q 2023

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

1,986

(433)

1,553

2.66

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net

(101)

22

(79)

(0.14)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(30)

6

(24)

(0.04)

Add: Losses on Asset Dispositions, Net

9

(2)

7

0.01

Adjustments to Net Income

(122)

26

(96)

(0.17)

Adjusted Net Income (Non-GAAP)

1,864

(407)

1,457

2.49

Average Number of Common Shares (Non-GAAP)

Basic

580

Diluted

584

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2023, such amount was $30 million.

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

1Q 2023

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

2,595

(572)

2,023

3.45

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net

(376)

81

(295)

(0.51)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(123)

27

(96)

(0.16)

Less: Gains on Asset Dispositions, Net

(69)

15

(54)

(0.09)

Adjustments to Net Income

(568)

123

(445)

(0.76)

Adjusted Net Income (Non-GAAP)

2,027

(449)

1,578

2.69

Average Number of Common Shares (Non-GAAP)

Basic

584

Diluted

587

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2023, such amount was $123 million.

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

4Q 2022

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

2,859

(582)

2,277

3.87

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net

(233)

57

(176)

(0.31)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(244)

48

(196)

(0.33)

Add: Losses on Asset Dispositions, Net

27

(6)

21

0.04

Add: Certain Impairments

31

(16)

15

0.03

Adjustments to Net Income

(419)

83

(336)

(0.57)

Adjusted Net Income (Non-GAAP)

2,440

(499)

1,941

3.30

Average Number of Common Shares (Non-GAAP)

Basic

584

Diluted

588

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2022, such amount was $244 million.

 

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

FY 2023

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

9,689

(2,095)

7,594

13.00

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net

(818)

176

(642)

(1.09)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(112)

24

(88)

(0.15)

Less: Gains on Asset Dispositions, Net

(95)

20

(75)

(0.13)

Add: Certain Impairments

42

(6)

36

0.06

Adjustments to Net Income

(983)

214

(769)

(1.31)

Adjusted Net Income (Non-GAAP)

8,706

(1,881)

6,825

11.69

Average Number of Common Shares (Non-GAAP)

Basic

581

Diluted

584

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2023, such amount was $112 million.

 

Adjusted Net Income (Loss)

(Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

FY 2022

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)

9,901

(2,142)

7,759

13.22

Adjustments:

Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net

3,982

(858)

3,124

5.32

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(3,501)

755

(2,746)

(4.68)

Less: Gains on Asset Dispositions, Net

(74)

17

(57)

(0.10)

Add: Certain Impairments

113

(31)

82

0.14

Less: Severance Tax Refund

(115)

25

(90)

(0.15)

Add: Severance Tax Consulting Fees

16

(3)

13

0.02

Less: Interest on Severance Tax Refund

(7)

2

(5)

(0.01)

Adjustments to Net Income

414

(93)

321

0.54

Adjusted Net Income (Non-GAAP)

10,315

(2,235)

8,080

13.76

Average Number of Common Shares (Non-GAAP)

Basic

583

Diluted

587

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2022, such amount was $3,501 million, of which $1,391 million was related to the early termination of certain contracts.

 

Net Income per Share

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

3Q 2023 Net Income per Share (GAAP)

3.48

Realized Price

4Q 2023 Composite Average Wellhead Revenue per Boe

48.27

Less: 3Q 2023 Composite Average Wellhead Revenue per Boe

(50.46)

Subtotal

(2.19)

Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe)

94.4

Total Change in Revenue

(207)

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

46

Change in Net Income

(161)

Change in Diluted Earnings per Share

(0.28)

Wellhead Volumes

4Q 2023 Crude Oil Equivalent Volumes (MMBoe)

94.4

Less: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe)

(91.9)

Subtotal

2.5

Multiplied by: 4Q 2023 Composite Average Margin per Boe (GAAP) (Including Total
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule)

23.07

Change in Margin

58

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(13)

Change in Net Income

45

Change in Diluted Earnings per Share

0.08

Certain Operating Costs per Boe

3Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

19.97

Less: 4Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.37)

Subtotal

(0.40)

Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe)

94.4

Change in Before-Tax Net Income

(38)

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

8

Change in Net Income

(30)

Change in Diluted Earnings per Share

(0.05)

 

Net Income Per Share

(Continued)

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net

4Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts

298

Less: Income Tax Benefit (Provision)

(64)

After Tax – (a)

234

Less: 3Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts

43

Less: Income Tax Benefit (Provision)

(9)

After Tax – (b)

34

Change in Net Income – (a) – (b)

200

Change in Diluted Earnings per Share

0.34

Other (1)

(0.15)

4Q 2023 Net Income per Share (GAAP)

3.42

4Q 2023 Average Number of Common Shares (GAAP) – Diluted

581

(1)

Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.

 

Net Income per Share

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

FY 2022 Net Income per Share (GAAP)

13.22

Realized Price

FY 2023 Composite Average Wellhead Revenue per Boe

48.34

Less: FY 2022 Composite Average Wellhead Revenue per Boe

(68.77)

Subtotal

(20.43)

Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe)

359.4

Total Change in Revenue

(7,343)

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

1,615

Change in Net Income

(5,728)

Change in Diluted Earnings per Share

(9.81)

Wellhead Volumes

FY 2023 Crude Oil Equivalent Volumes (MMBoe)

359.4

Less: FY 2022 Crude Oil Equivalent Volumes (MMBoe)

(331.5)

Subtotal

27.9

Multiplied by: FY 2023 Composite Average Margin per Boe (GAAP) (Including Total
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”
schedule)

23.24

Change in Margin

648

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(143)

Change in Net Income

505

Change in Diluted Earnings per Share

0.86

Certain Operating Costs per Boe

FY 2022 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

21.21

Less: FY 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.05)

Subtotal

1.16

Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe)

359.4

Change in Before-Tax Net Income

417

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(92)

Change in Net Income

325

Change in Diluted Earnings per Share

0.56

 

Net Income Per Share

(Continued)

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net

FY 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts

818

Less: Income Tax Benefit (Provision)

(176)

After Tax – (a)

642

Less: FY 2022 Net Gains (Losses) on Mark-to-Market Commodity Derivative Contracts

(3,982)

Less: Income Tax Benefit (Provision)

858

After Tax – (b)

(3,124)

Change in Net Income – (a) – (b)

3,766

Change in Diluted Earnings per Share

6.45

Other (1)

1.72

FY 2023 Net Income per Share (GAAP)

13.00

FY 2023 Average Number of Common Shares (GAAP) – Diluted

584

(1)

Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.

 

Adjusted Net Income Per Share

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

3Q 2023 Adjusted Net Income per Share (Non-GAAP)

3.44

Realized Price

4Q 2023 Composite Average Wellhead Revenue per Boe

48.27

Less: 3Q 2023 Composite Average Wellhead Revenue per Boe

(50.46)

Subtotal

(2.19)

Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe)

94.4

Total Change in Revenue

(207)

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

46

Change in Net Income

(161)

Change in Diluted Earnings per Share

(0.28)

Wellhead Volumes

4Q 2023 Crude Oil Equivalent Volumes (MMBoe)

94.4

Less: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe)

(91.9)

Subtotal

2.5

Multiplied by: 4Q 2023 Composite Average Margin per Boe (Non-GAAP) (Including Total
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”
schedule)

23.27

Change in Margin

58

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(13)

Change in Net Income

45

Change in Diluted Earnings per Share

0.08

Certain Operating Costs per Boe

3Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

19.97

Less: 4Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.37)

Subtotal

(0.40)

Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe)

94.4

Change in Before-Tax Net Income

(38)

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

8

Change in Net Income

(30)

Change in Diluted Earnings per Share

(0.05)

 

Adjusted Net Income Per Share

(Continued)

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

4Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

18

Less: Income Tax Benefit (Provision)

(4)

After Tax – (a)

14

3Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

23

Less: Income Tax Benefit (Provision)

(5)

After Tax – (b)

18

Change in Net Income – (a) – (b)

(4)

Change in Diluted Earnings per Share

(0.01)

Other (1)

(0.11)

4Q 2023 Adjusted Net Income per Share (Non-GAAP)

3.07

4Q 2023 Average Number of Common Shares (Non-GAAP) – Diluted

581

(1)

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

 

Adjusted Net Income per Share

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

FY 2022 Adjusted Net Income per Share (Non-GAAP)

13.76

Realized Price

FY 2023 Composite Average Wellhead Revenue per Boe

48.34

Less: FY 2022 Composite Average Wellhead Revenue per Boe

(68.77)

Subtotal

(20.43)

Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe)

359.4

Total Change in Revenue

(7,343)

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

1,615

Change in Net Income

(5,728)

Change in Diluted Earnings per Share

(9.81)

Wellhead Volumes

FY 2023 Crude Oil Equivalent Volumes (MMBoe)

359.4

Less: FY 2022 Crude Oil Equivalent Volumes (MMBoe)

(331.5)

Subtotal

27.9

Multiplied by: FY 2023 Composite Average Margin per Boe (Non-GAAP)
(Including Total Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil
Equivalent” schedule)

23.36

Change in Margin

652

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(143)

Change in Net Income

509

Change in Diluted Earnings per Share

0.87

Certain Operating Costs per Boe

FY 2022 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

21.16

Less: FY 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.05)

Subtotal

1.11

Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe)

359.4

Change in Before-Tax Net Income

399

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(88)

Change in Net Income

311

Change in Diluted Earnings per Share

0.53

 

Adjusted Net Income Per Share

(Continued)

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

FY 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

(112)

Less: Income Tax Benefit (Provision)

24

After Tax – (a)

(88)

FY 2022 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

(3,501)

Less: Income Tax Benefit (Provision)

755

After Tax – (b)

(2,746)

Change in Net Income – (a) – (b)

2,658

Change in Diluted Earnings per Share

4.55

Other (1)

1.79

FY 2023 Adjusted Net Income per Share (Non-GAAP)

11.69

FY 2023 Average Number of Common Shares (Non-GAAP) – Diluted

584

(1)

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

 

Cash Flow from Operations and Free Cash Flow

In millions of USD (Unaudited)

The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Cash Flow from Operations Before Changes in Working Capital (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing Activities and certain other adjustments to exclude non-recurring and certain other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Cash Flow from Operations Before Changes in Working Capital (Non-GAAP) (see below reconciliation) for such period less the total capital expenditures (Non-GAAP) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry.

2022

2023

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Net Cash Provided by Operating Activities (GAAP)

828

2,048

4,773

3,444

11,093

3,255

2,277

2,704

3,104

11,340

Adjustments:

Changes in Components of Working Capital
and Other Assets and Liabilities

Accounts Receivable

878

522

(392)

(661)

347

(338)

(137)

714

(201)

38

Inventories

14

157

140

223

534

77

226

28

(100)

231

Accounts Payable

(130)

(259)

88

211

(90)

77

231

(238)

49

119

Accrued Taxes Payable

(613)

536

53

137

113

(232)

212

(180)

139

(61)

Other Assets

213

(71)

129

93

364

(52)

(43)

92

(36)

(39)

Other Liabilities

2,250

(433)

(1,269)

(282)

266

(193)

47

(54)

16

(184)

Changes in Components of Working Capital
Associated with Investing Activities

(68)

(143)

(90)

(74)

(375)

(35)

(250)

(28)

18

(295)

Cash Flow from Operations Before Changes in
Working Capital (Non-GAAP)

3,372

2,357

3,432

3,091

12,252

2,559

2,563

3,038

2,989

11,149

Cash Flow from Operations Before Changes in
Working Capital (Non-GAAP)

3,372

2,357

3,432

3,091

12,252

2,559

2,563

3,038

2,989

11,149

Less:

Total Capital Expenditures (Non-GAAP) (a)

(1,009)

(1,071)

(1,166)

(1,361)

(4,607)

(1,489)

(1,521)

(1,519)

(1,512)

(6,041)

Free Cash Flow (Non-GAAP)

2,363

1,286

2,266

1,730

7,645

1,070

1,042

1,519

1,477

5,108

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

2022

2023

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Total Expenditures (GAAP)

1,144

1,521

1,410

1,535

5,610

1,717

1,664

1,803

1,634

6,818

Less:

Asset Retirement Costs

(27)

(43)

(139)

(89)

(298)

(10)

(26)

(191)

(30)

(257)

Non-Cash Acquisition Costs of
Unproved Properties

(58)

(21)

(28)

(20)

(127)

(31)

(28)

(1)

(39)

(99)

Non-Cash Development Drilling

(35)

(50)

(5)

(90)

Acquisition Costs of Proved Properties

(5)

(351)

(42)

(21)

(419)

(4)

(6)

1

(7)

(16)

Acquisition Costs of Other Property,
Plant and Equipment

(133)

(1)

(134)

Exploration Costs

(45)

(35)

(35)

(44)

(159)

(50)

(47)

(43)

(41)

(181)

Total Capital Expenditures (Non-GAAP)

1,009

1,071

1,166

1,361

4,607

1,489

1,521

1,519

1,512

6,041

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

December 31,
2023

September 30,
2023

June 30,
2023

March 31,
2023

December 31,
2022

Total Stockholders’ Equity – (a)

28,090

27,758

26,257

25,447

24,779

Current and Long-Term Debt (GAAP) – (b)

3,799

3,806

3,814

3,820

5,078

Less: Cash

(5,278)

(5,326)

(4,764)

(5,018)

(5,972)

Net Debt (Non-GAAP) – (c)

(1,479)

(1,520)

(950)

(1,198)

(894)

Total Capitalization (GAAP) – (a) + (b)

31,889

31,564

30,071

29,267

29,857

Total Capitalization (Non-GAAP) – (a) + (c)

26,611

26,238

25,307

24,249

23,885

Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)]

11.9 %

12.1 %

12.7 %

13.1 %

17.0 %

Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)]

-5.6 %

-5.8 %

-3.8 %

-4.9 %

-3.7 %

 

Proved Reserves and Reserve Replacement Data

(Unaudited)

2023 Net Proved Reserves Reconciliation Summary

United

States

Trinidad

Other

International

Total

Crude Oil and Condensate (MMBbl)

Beginning Reserves

1,659

2

1,661

Revisions

56

56

Purchases in Place

1

1

Extensions, Discoveries and Other Additions

219

219

Sales in Place

(7)

(7)

Production

(174)

(174)

Ending Reserves

1,754

2

1,756

Natural Gas Liquids (MMBbl)

Beginning Reserves

1,145

1,145

Revisions

26

26

Purchases in Place

1

1

Extensions, Discoveries and Other Additions

169

169

Sales in Place

(5)

(5)

Production

(82)

(82)

Ending Reserves

1,254

1,254

Natural Gas (Bcf)

Beginning Reserves

8,273

318

8,591

Revisions

(327)

12

(315)

Purchases in Place

3

3

Extensions, Discoveries and Other Additions

1,287

29

1,316

Sales in Place

(28)

(28)

Production

(578)

(59)

(637)

Ending Reserves

8,630

300

8,930

Oil Equivalents (MMBoe)

Beginning Reserves

4,183

55

4,238

Revisions

28

1

29

Purchases in Place

2

2

Extensions, Discoveries and Other Additions

602

5

607

Sales in Place

(17)

(17)

Production

(351)

(10)

(361)

Ending Reserves

4,447

51

4,498

Net Proved Developed Reserves (MMBoe)

At December 31, 2022

2,162

23

2,185

At December 31, 2023

2,322

27

2,349

2023 Exploration and Development Expenditures ($ Millions)

Acquisition Cost of Unproved Properties

207

207

Exploration Costs

370

53

14

437

Development Costs

4,987

114

5,101

Total Drilling

5,564

167

14

5,745

Acquisition Cost of Proved Properties

16

16

Asset Retirement Costs

241

3

13

257

Total Exploration and Development Expenditures

5,821

170

27

6,018

Gathering, Processing and Other

799

1

800

Total Expenditures

6,620

171

27

6,818

Proceeds from Sales in Place

(70)

(70)

(140)

Net Expenditures

6,550

101

27

6,678

Reserve Replacement Costs ($ / Boe) *

All-in Total, Net of Revisions

8.26

27.17

8.44

All-in Total, Excluding Revisions Due to Price

7.03

27.17

7.20

Reserve Replacement *

Drilling Only

172 %

50 %

0 %

168 %

All-in Total, Net of Revisions and Dispositions

175 %

60 %

0 %

172 %

All-in Total, Excluding Revisions Due to Price

207 %

60 %

0 %

202 %

All-in Total, Liquids

180 %

0 %

0 %

180 %

* See following reconciliation schedule for calculation methodology

Reserve Replacement Cost Data

(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2023

United

States

Trinidad

Other

International

Total

Total Costs Incurred in Exploration and Development Activities (GAAP)

5,821

170

27

6,018

Less: Asset Retirement Costs

(241)

(3)

(13)

(257)

Non-Cash Acquisition Costs of Unproved Properties

(99)

(99)

Total Acquisition Costs of Proved Properties

(16)

(16)

Non-Cash Development Drilling

(90)

(90)

Exploration Expenses

(166)

(4)

(11)

(181)

Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) – (a)

5,209

163

3

5,375

Total Costs Incurred in Exploration and Development Activities (GAAP)

5,821

170

27

6,018

Less: Asset Retirement Costs

(241)

(3)

(13)

(257)

Non-Cash Acquisition Costs of Unproved Properties

(99)

(99)

Non-Cash Acquisition Costs of Proved Properties

(6)

(6)

Non-Cash Development Drilling

(90)

(90)

Exploration Expenses

(166)

(4)

(11)

(181)

Total Exploration and Development Expenditures (Non-GAAP) – (b)

5,219

163

3

5,385

Total Expenditures (GAAP)

6,620

171

27

6,818

Less: Asset Retirement Costs

(241)

(3)

(13)

(257)

Non-Cash Acquisition Costs of Unproved Properties

(99)

(99)

Non-Cash Acquisition Costs of Proved Properties

(6)

(6)

Non-Cash Development Drilling

(90)

(90)

Exploration Expenses

(166)

(4)

(11)

(181)

Total Cash Expenditures (Non-GAAP)

6,018

164

3

6,185

Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe)

Revisions Due to Price – (c)

(110)

(110)

Revisions Other Than Price

138

1

139

Purchases in Place

2

2

Extensions, Discoveries and Other Additions – (d)

602

5

607

Total Proved Reserve Additions – (e)

632

6

638

Sales in Place

(17)

(17)

Net Proved Reserve Additions From All Sources – (f)

615

6

621

Production – (g)

351

10

361

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions – (a / d)

8.65

32.60

8.86

All-in Total, Net of Revisions – (b / e)

8.26

27.17

8.44

All-in Total, Excluding Revisions Due to Price – (b / (e – c))

7.03

27.17

7.20

Reserve Replacement

Drilling Only – (d / g)

172 %

50 %

0 %

168 %

All-in Total, Net of Revisions and Dispositions – (f / g)

175 %

60 %

0 %

172 %

All-in Total, Excluding Revisions Due to Price – ((f – c) / g)

207 %

60 %

0 %

202 %

Reserve Replacement Cost Data

(Continued)

(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2023

United

States

Trinidad

Other

International

Total

Net Proved Reserve Additions From All Sources – Liquids (MMBbl)

Revisions

82

82

Purchases in Place

2

2

Extensions, Discoveries and Other Additions – (h)

388

388

Total Proved Reserve Additions

472

472

Sales in Place

(12)

(12)

Net Proved Reserve Additions From All Sources – (i)

460

460

Production – (j)

256

256

Reserve Replacement – Liquids

Drilling Only – (h / j)

152 %

0 %

0 %

152 %

All-in Total, Net of Revisions and Dispositions – (i / j)

180 %

0 %

0 %

180 %

 

Reserve Replacement Cost Data

(Continued)

(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2023

Proved Developed Reserve Replacement Costs ($ / Boe)

Total

Total Costs Incurred in Exploration and Development Activities (GAAP) – (k)

6,018

Less: Asset Retirement Costs

(257)

Acquisition Costs of Unproved Properties

(207)

Acquisition Costs of Proved Properties

(16)

Exploration Expenses

(181)

Drillbit Exploration and Development Expenditures (Non-GAAP) – (l)

5,357

Total Proved Reserves – Extensions, Discoveries and Other Additions (MMBoe)

607

Add: Conversion of Proved Undeveloped Reserves to Proved Developed

360

Less: Proved Undeveloped Extensions and Discoveries

(516)

Proved Developed Reserves – Extensions and Discoveries (MMBoe)

451

Total Proved Reserves – Revisions (MMBoe)

29

Less: Proved Undeveloped Reserves – Revisions

51

Proved Developed – Revisions Due to Price

42

Proved Developed Reserves – Revisions Other Than Price (MMBoe)

122

Proved Developed Reserves – Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) – (m)

573

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) – (k / m)

10.50

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) – (l / m)

9.35

 

Reserve Replacement Cost Data

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

The following table reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics (and the non-GAAP measures used in calculating such statistics) provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics (and the non-GAAP measures used in calculating such statistics) are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. In addition, to further the comparability of the results of EOG’s current-year capital investment program with those of EOG’s peer companies and other companies in the industry, EOG now deducts Exploration Expenses, as illustrated below, in calculating Total Exploration and Development Expenditures for Drilling Only (Non-GAAP), Total Exploration and Development Expenditures (Non-GAAP), Total Cash Expenditures (Non-GAAP), Drillbit Exploration and Development Expenditures (Non-GAAP) and the related Reserve Replacement Costs metrics. Accordingly, Total Exploration and Development Expenditures for Drilling Only (Non-GAAP), Total Exploration and Development Expenditures (Non-GAAP), Total Cash Expenditures (Non-GAAP), Drillbit Exploration and Development Expenditures (Non-GAAP) and the related Reserve Replacement Costs metrics, in each case for fiscal year 2023 and 2022, have been calculated on such basis, and the calculations for each of the prior periods shown have been revised and conformed.

2023

2022

2021

Total Costs Incurred in Exploration and Development Activities (GAAP)

6,018

5,229

3,969

Less: Asset Retirement Costs

(257)

(298)

(127)

Non-Cash Acquisition Costs of Unproved Properties

(99)

(127)

(45)

Total Acquisition Costs of Proved Properties

(16)

(419)

(100)

Non-Cash Development Drilling

(90)

Exploration Expenses

(181)

(159)

(154)

Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) – (a)

5,375

4,226

3,543

Total Costs Incurred in Exploration and Development Activities (GAAP) – (b)

6,018

5,229

3,969

Less: Asset Retirement Costs

(257)

(298)

(127)

Non-Cash Acquisition Costs of Unproved Properties

(99)

(127)

(45)

Non-Cash Acquisition Costs of Proved Properties

(6)

(26)

(5)

Non-Cash Development Drilling

(90)

Exploration Expenses

(181)

(159)

(154)

Total Exploration and Development Expenditures (Non-GAAP) – (c)

5,385

4,619

3,638

Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe)

Revisions Due to Price – (d)

(110)

11

194

Revisions Other Than Price

139

325

(308)

Purchases in Place

2

16

9

Extensions, Discoveries and Other Additions – (e)

607

560

952

Total Proved Reserve Additions – (f)

638

912

847

Sales in Place

(17)

(88)

(11)

Net Proved Reserve Additions From All Sources

621

824

836

Production

361

333

309

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions – (a / e)

8.86

7.55

3.72

All-in Total, Net of Revisions – (c / f)

8.44

5.06

4.30

All-in Total, Excluding Revisions Due to Price (GAAP) – (b / ( f – d))

8.05

5.80

6.08

All-in Total, Excluding Revisions Due to Price (Non-GAAP) – (c / ( f – d))

7.20

5.13

5.57

 

Reserve Replacement Cost Data

(Continued)

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

2020

2019

2018

Total Costs Incurred in Exploration and Development Activities (GAAP)

3,718

6,628

6,420

Less: Asset Retirement Costs

(117)

(186)

(70)

Non-Cash Acquisition Costs of Unproved Properties

(197)

(98)

(291)

Total Acquisition Costs of Proved Properties

(135)

(380)

(124)

Exploration Expenses

(146)

(140)

(149)

Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) – (a)

3,123

5,824

5,786

Total Costs Incurred in Exploration and Development Activities (GAAP) – (b)

3,718

6,628

6,420

Less: Asset Retirement Costs

(117)

(186)

(70)

Non-Cash Acquisition Costs of Unproved Properties

(197)

(98)

(291)

Non-Cash Acquisition Costs of Proved Properties

(15)

(52)

(71)

Exploration Expenses

(146)

(140)

(149)

Total Exploration and Development Expenditures (Non-GAAP) – (c)

3,243

6,152

5,839

Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe)

Revisions Due to Price – (d)

(278)

(60)

35

Revisions Other Than Price

(89)

(40)

Purchases in Place

10

17

12

Extensions, Discoveries and Other Additions – (e)

564

750

670

Total Proved Reserve Additions – (f)

207

707

677

Sales in Place

(31)

(5)

(11)

Net Proved Reserve Additions From All Sources

176

702

666

Production

285

301

265

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions – (a / e)

5.54

7.77

8.64

All-in Total, Net of Revisions – (c / f)

15.67

8.70

8.62

All-in Total, Excluding Revisions Due to Price (GAAP) – (b / ( f – d))

7.67

8.64

10.00

All-in Total, Excluding Revisions Due to Price (Non-GAAP) – (c / ( f – d))

6.69

8.02

9.10

 

Definitions

$/Boe

U.S. Dollars per barrel of oil equivalent

MMBoe

Million barrels of oil equivalent

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SOURCE EOG Resources, Inc.

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About Stu Turley 3277 Articles
Stuart Turley is President and CEO of Sandstone Group, a top energy data, and finance consultancy working with companies all throughout the energy value chain. Sandstone helps both small and large-cap energy companies to develop customized applications and manage data workflows/integration throughout the entire business. With experience implementing enterprise networks, supercomputers, and cellular tower solutions, Sandstone has become a trusted source and advisor.   He is also the Executive Publisher of www.energynewsbeat.com, the best source for 24/7 energy news coverage, and is the Co-Host of the energy news video and Podcast Energy News Beat. Energy should be used to elevate humanity out of poverty. Let's use all forms of energy with the least impact on the environment while being sustainable without printing money. Stu is also a co-host on the 3 Podcasters Walk into A Bar podcast with David Blackmon, and Rey Trevino. Stuart is guided by over 30 years of business management experience, having successfully built and help sell multiple small and medium businesses while consulting for numerous Fortune 500 companies. He holds a B.A in Business Administration from Oklahoma State and an MBA from Oklahoma City University.