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EOG Resources Reports Fourth Quarter and Full-Year 2024 Results; Announces 2025 Capital Plan

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EOG Resources reported strong Q4 and full-year 2024 results, with Q4 adjusted net income of $1.5 billion ($2.74 per share) and $1.3 billion in free cash flow. The company generated $5.4 billion in free cash flow for full-year 2024, returning $5.3 billion to shareholders.

Q4 oil production reached 494,600 Bopd, while full-year production increased 3% to 491,400 Bopd. The company achieved a 6% reduction in average well costs across its multi-basin portfolio and replaced 201% of 2024 production at a finding and development cost of $7.03 per Boe (GAAP).

For 2025, EOG announced a $6.2 billion capital plan targeting 3% oil production growth and 6% total production growth. The company declared a quarterly dividend of $0.975 per share, representing a 7% increase, and repurchased $981 million of shares in Q4 2024.

EOG Resources ha riportato risultati solidi per il quarto trimestre e per l'intero anno 2024, con un reddito netto rettificato di 1,5 miliardi di dollari (2,74 dollari per azione) e 1,3 miliardi di dollari di flusso di cassa libero nel quarto trimestre. L'azienda ha generato 5,4 miliardi di dollari di flusso di cassa libero per l'intero anno 2024, restituendo 5,3 miliardi di dollari agli azionisti.

La produzione di petrolio nel quarto trimestre ha raggiunto 494.600 Bopd, mentre la produzione annuale è aumentata del 3% a 491.400 Bopd. L'azienda ha ottenuto una riduzione del 6% nei costi medi dei pozzi nel suo portafoglio multi-bacino e ha sostituito il 201% della produzione del 2024 a un costo di scoperta e sviluppo di 7,03 dollari per Boe (GAAP).

Per il 2025, EOG ha annunciato un piano di capitali di 6,2 miliardi di dollari mirato a una crescita della produzione di petrolio del 3% e a una crescita totale della produzione del 6%. L'azienda ha dichiarato un dividendo trimestrale di 0,975 dollari per azione, rappresentando un aumento del 7%, e ha riacquistato azioni per 981 milioni di dollari nel quarto trimestre del 2024.

EOG Resources reportó resultados sólidos para el cuarto trimestre y para el año completo 2024, con un ingreso neto ajustado de 1.5 mil millones de dólares (2.74 dólares por acción) y 1.3 mil millones de dólares en flujo de caja libre. La compañía generó 5.4 mil millones de dólares en flujo de caja libre para el año completo 2024, devolviendo 5.3 mil millones de dólares a los accionistas.

La producción de petróleo en el cuarto trimestre alcanzó 494,600 Bopd, mientras que la producción anual aumentó un 3% a 491,400 Bopd. La empresa logró una reducción del 6% en los costos promedio de los pozos en su cartera de múltiples cuencas y reemplazó el 201% de la producción de 2024 a un costo de descubrimiento y desarrollo de 7.03 dólares por Boe (GAAP).

Para 2025, EOG anunció un plan de capital de 6.2 mil millones de dólares con el objetivo de un crecimiento del 3% en la producción de petróleo y un crecimiento total del 6% en la producción. La compañía declaró un dividendo trimestral de 0.975 dólares por acción, lo que representa un aumento del 7%, y recompró acciones por 981 millones de dólares en el cuarto trimestre de 2024.

EOG Resources는 2024년 4분기 및 연간 실적을 발표했으며, 4분기 조정 순이익은 15억 달러(주당 2.74달러)와 13억 달러의 자유 현금 흐름을 기록했습니다. 이 회사는 2024년 전체에 걸쳐 54억 달러의 자유 현금 흐름을 창출했으며, 53억 달러를 주주에게 환원했습니다.

4분기 석유 생산량은 494,600 Bopd에 도달했으며, 연간 생산량은 3% 증가하여 491,400 Bopd에 이르렀습니다. 이 회사는 다수의 분지 포트폴리오에서 평균 우물 비용을 6% 절감했으며, 2024년 생산의 201%를 1 Boe당 7.03달러의 탐사 및 개발 비용으로 대체했습니다 (GAAP).

2025년을 위해 EOG는 62억 달러의 자본 계획을 발표하며, 석유 생산량 3% 성장과 총 생산량 6% 성장을 목표로 하고 있습니다. 이 회사는 주당 0.975달러의 분기 배당금을 선언했으며, 이는 7% 증가한 수치이며, 2024년 4분기에 9억 8100만 달러의 주식을 재매입했습니다.

EOG Resources a annoncé des résultats solides pour le quatrième trimestre et pour l'année entière 2024, avec un revenu net ajusté de 1,5 milliard de dollars (2,74 dollars par action) et 1,3 milliard de dollars de flux de trésorerie disponible. L'entreprise a généré 5,4 milliards de dollars de flux de trésorerie disponible pour l'année entière 2024, restituant 5,3 milliards de dollars aux actionnaires.

La production de pétrole pour le quatrième trimestre a atteint 494 600 Bopd, tandis que la production annuelle a augmenté de 3 % pour atteindre 491 400 Bopd. L'entreprise a réalisé une réduction de 6 % des coûts moyens des puits dans son portefeuille multi-bassins et a remplacé 201 % de la production de 2024 à un coût de découverte et de développement de 7,03 dollars par Boe (GAAP).

Pour 2025, EOG a annoncé un plan d'investissement de 6,2 milliards de dollars visant une croissance de 3 % de la production pétrolière et une croissance totale de 6 % de la production. L'entreprise a déclaré un dividende trimestriel de 0,975 dollar par action, représentant une augmentation de 7 %, et a racheté pour 981 millions de dollars d'actions au quatrième trimestre 2024.

EOG Resources hat starke Ergebnisse für das vierte Quartal und das gesamte Jahr 2024 gemeldet, mit einem bereinigten Nettogewinn von 1,5 Milliarden Dollar (2,74 Dollar pro Aktie) und 1,3 Milliarden Dollar an freiem Cashflow. Das Unternehmen erzielte 5,4 Milliarden Dollar an freiem Cashflow für das gesamte Jahr 2024 und gab 5,3 Milliarden Dollar an die Aktionäre zurück.

Die Ölproduktion im vierten Quartal erreichte 494.600 Bopd, während die Jahresproduktion um 3% auf 491.400 Bopd stieg. Das Unternehmen erreichte eine Reduzierung der durchschnittlichen Bohrkosten um 6% in seinem Multi-Basin-Portfolio und ersetzte 201% der Produktion von 2024 zu einem Erschließungs- und Entwicklungskosten von 7,03 Dollar pro Boe (GAAP).

Für 2025 kündigte EOG einen Investitionsplan von 6,2 Milliarden Dollar an, der ein Produktionswachstum von 3% bei Öl und ein Gesamtproduktionswachstum von 6% zum Ziel hat. Das Unternehmen erklärte eine vierteljährliche Dividende von 0,975 Dollar pro Aktie, was einem Anstieg von 7% entspricht, und kaufte im vierten Quartal 2024 Aktien im Wert von 981 Millionen Dollar zurück.

Positive
  • Generated $5.4B free cash flow in 2024
  • Returned 98% of free cash flow ($5.3B) to shareholders
  • Reduced well costs by 6%
  • 201% reserve replacement ratio
  • 7% dividend increase
  • 3% oil production growth and 6% total production growth planned for 2025
Negative
  • Q4 crude oil prices decreased vs Q3
  • Q4 NGL production below guidance midpoint
  • Natural gas prices decreased 22% in 2024
  • Higher G&A costs in Q4 due to increased employee expenses

Insights

EOG Resources delivered impressive Q4 and full-year 2024 results that demonstrate its resilience in a challenging commodity price environment. The company generated $1.3 billion in Q4 free cash flow and $5.4 billion for the full year, returning an exceptional 98% to shareholders through dividends and share repurchases.

The company's operational excellence is evident in its 6% reduction in average well costs across its multi-basin portfolio - a significant achievement when many peers are struggling with cost inflation. EOG's 201% reserve replacement ratio at a finding and development cost of $6.68 per Boe (non-GAAP) demonstrates superior capital efficiency and extends the company's runway of high-return inventory.

EOG's strategic focus on portfolio diversification is paying dividends, with increased activity planned in the emerging Utica and Dorado plays complementing its Delaware Basin operations. This multi-basin approach provides natural hedging against regional disruptions and allows the company to allocate capital to the highest-return opportunities across market cycles.

The $6.2 billion 2025 capital plan targeting 3% oil growth and 6% total production growth reflects disciplined expansion while maintaining capital efficiency. The 7% dividend increase to an annual rate of $3.90 per share, combined with ongoing share repurchases that have already reduced the share count by 5% since 2023, underscores management's commitment to returning capital while maintaining one of the industry's strongest balance sheets.

EOG's strategic participation agreement with Bapco Energies in Bahrain represents an important international diversification move that could provide meaningful growth opportunities beyond its core U.S. operations, potentially unlocking new resource plays with favorable economics.

EOG Resources' 2024 results demonstrate why it's considered one of the premier operators in the U.S. shale sector. The company's exceptional 201% reserve replacement ratio at a finding and development cost of $6.68 per Boe (non-GAAP) significantly extends its high-quality inventory runway - a important competitive advantage in an industry where tier-one drilling locations are becoming increasingly scarce.

The 6% reduction in average well costs is particularly impressive considering the inflationary environment affecting the broader industry. EOG's integrated approach - combining extended laterals, proprietary drilling motor technology, and innovations in completion design - has created sustainable efficiency improvements rather than temporary cost reductions. This technical leadership translates directly to superior capital efficiency metrics and enhanced returns.

EOG's multi-basin development strategy provides important operational flexibility that single-basin operators lack. By maintaining a disciplined presence across the Delaware Basin, Eagle Ford, Powder River Basin, DJ Basin, and now expanding in the Utica and Dorado plays, EOG can optimize its rig allocation to focus on the highest-return opportunities regardless of regional constraints or commodity price differentials.

The company's marketing strategy continues to deliver superior price realizations - a often overlooked competitive advantage that meaningfully enhances margins. By securing advantageous transportation contracts and market access, EOG effectively captures premium pricing relative to benchmark indices.

The strategic participation agreement in Bahrain represents an important diversification move that could provide meaningful growth opportunities beyond U.S. borders. Combined with existing operations in Trinidad, this international footprint gives EOG exposure to potentially higher-margin international gas markets while reducing dependence on domestic price dynamics.

The $6.2 billion capital plan for 2025 strikes a prudent balance between modest growth (3% oil, 6% total) and continued robust free cash flow generation, positioning EOG to maintain its industry-leading capital return program through market cycles.

HOUSTON, Feb. 27, 2025 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2024 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 2024


3Q 2024


2Q 2024


1Q 2024


4Q 2023


FY 2024


FY 2023


Total Revenue

5,585


5,965


6,025


6,123


6,357


23,698


24,186


Net Income

1,251


1,673


1,690


1,789


1,988


6,403


7,594


Net Income Per Share

2.23


2.95


2.95


3.10


3.42


11.25


13.00


Net Cash Provided by Operating Activities

2,763


3,588


2,889


2,903


3,104


12,143


11,340


Total Expenditures

1,446


1,573


1,682


1,952


1,634


6,653


6,818


Current and Long-Term Debt

4,752


3,776


3,784


3,791


3,799


4,752


3,799


Cash and Cash Equivalents

7,092


6,122


5,431


5,292


5,278


7,092


5,278


Debt-to-Total Capitalization

13.9 %


11.3 %


11.5 %


11.7 %


11.9 %


13.9 %


11.9 %


Cash Operating Costs ($/Boe)

10.15


10.15


10.11


10.37


10.52


10.19


10.33











Non - GAAP









Adjusted Net Income

1,535


1,644


1,807


1,626


1,783


6,612


6,825


Adjusted Net Income Per Share

2.74


2.89


3.16


2.82


3.07


11.62


11.69


CFO before Changes in Working Capital

2,635


2,988


3,042


2,928


2,989


11,593


11,149


Capital Expenditures

1,358


1,497


1,668


1,703


1,512


6,226


6,041


Free Cash Flow

1,277


1,491


1,374


1,225


1,477


5,367


5,108


Net Debt

(2,340)


(2,346)


(1,647)


(1,501)


(1,479)


(2,340)


(1,479)


Net Debt-to-Total Capitalization

(8.7 %)


(8.6 %)


(6.0 %)


(5.5 %)


(5.6 %)


(8.7 %)


(5.6 %)


Cash Operating Costs ($/Boe)1

10.15


10.05


10.11


10.37


10.52


10.17


10.33


Fourth Quarter Highlights

 - Earned adjusted net income of $1.5 billion, or $2.74 per share
 - Generated $1.3 billion of free cash flow
 - Declared regular quarterly dividend of $0.975 per share and repurchased $981 million of shares
 - Oil and gas volumes, and total per-unit operating costs better than guidance midpoints

Full-Year 2024 Highlights and 2025 Capital Plan

 - Generated $5.4 billion of free cash flow and returned $5.3 billion to shareholders
 - Replaced 201% of 2024 production at a finding and development cost, excluding price revisions, of
   $7.03 per Boe (GAAP) and $6.68 per Boe (Non-GAAP)
 - Reduced average well costs 6% across multi-basin portfolio
 - Announced $6.2 billion 2025 capital plan to grow oil production 3% and total production 6%
 - EOG and Bapco Energies entered into a strategic participation agreement in Bahrain

Volumes and Capital Expenditures




 

 

Volumes

 

4Q 2024


4Q 2024
Guidance
Midpoint


3Q 2024


2Q 2024


1Q 2024


4Q 2023


FY 2024


FY 2023


Crude Oil and Condensate (MBod)

494.6


493.0


493.0


490.7


487.4


485.2


491.4


475.8


Natural Gas Liquids (MBbld)

252.5


260.0


254.3


244.8


231.7


235.8


245.9


223.8


Natural Gas (MMcfd)

2,092


2,075


1,970


1,872


1,858


1,831


1,948


1,711


Total Crude Oil Equivalent (MBoed)

1,095.7


1,098.9


1,075.7


1,047.5


1,028.8


1,026.2


1,062.1


984.8



















Capital Expenditures ($MM)

1,358


1,330


1,497


1,668


1,703


1,512


6,226


6,041


From Ezra Yacob, Chairman and Chief Executive Officer
"2024 was another year of strong execution for EOG. Oil and total volumes were higher than our original plan, capital expenditures were on target, and we continued to lower cash operating costs. We improved productivity and base production performance through innovations in completion design and artificial lift automation. Along with better productivity, sustainable efficiency improvements from extended laterals and EOG's in-house drilling motor program helped lower well costs 6%. Our comprehensive marketing strategy continued to deliver peer-leading U.S. price realizations, further maximizing margins across our portfolio. 2024 also marked another year of progress in the Utica and Dorado plays that resulted in consistent, strong results helping to support higher activity going forward.

"EOG's operational execution supported the company's exceptional financial performance and record cash return to shareholders in 2024. We generated $5.4 billion in free cash flow and returned $5.3 billion, or 98%, to shareholders. This robust cash return was anchored by our sustainable, growing regular dividend, which we increased by 7%, and included $3.2 billion in share repurchases. Since we initiated share repurchases in 2023, we have reduced our share count by approximately 5%. As we continue to optimize our capital structure, our strong cash flow generation and industry-leading balance sheet better position us to deliver shareholder value through the cycles.

"We are excited about 2025 where we have detailed a disciplined plan that builds on last year's success and lays a foundation for the future. Our comprehensive investment approach, focused on returns and optimizing value from our diverse portfolio of multi-basin assets, coupled with our industry-leading exploration expertise, provide long-term visibility for high returns and strong free cash flow generation. EOG has never been better positioned to deliver long-term shareholder value and we remain focused on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy."

Fourth Quarter 2024 Financial Performance

Prices

 - Crude oil prices decreased in 4Q compared with 3Q, partially offset by an increase in NGL and natural gas prices from 3Q

Volumes

 - Oil production of 494,600 Bopd was above the midpoint of the guidance range and up from 3Q
 - NGL production was below the midpoint of the guidance range and down from 3Q
 - Natural gas production was above the midpoint of the guidance range and up 6% from 3Q
 - Total company equivalent production was below the midpoint of the guidance range but increased 2% from 3Q

Per-Unit Costs

 - LOE, GP&T, and DD&A expenses decreased in 4Q compared with 3Q, while G&A costs increased

Hedges

 - Mark-to-market hedge losses decreased 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 $2.64 billion
 - Incurred $1.36 billion of capital expenditures
 - This resulted in $1.28 billion of free cash flow

Cash Return and Working Capital

 - Paid $509 million in regular dividends
 - Repurchased $981 million of stock
 - Completed a $1.0 billion bond offering

Full-Year 2024 Financial Performance

Prices

 - Crude oil prices decreased 2%
 - NGL prices increased 1%
 - Natural gas prices decreased 22%

Volumes

- Oil production increased 3% to 491,400 Bopd
- NGL production increased 10%
- Natural gas production increased 14%
- Total company equivalent production increased 8%

Per-Unit Costs

 - Lower LOE, GP&T, and G&A costs were offset by higher DD&A expenses in 2024

Hedges

 - Lower mark-to-market hedge gains contributed to lower GAAP earnings per share in 2024 compared with 2023
 - Higher net cash received to settle hedges partially offset lower commodity prices in 2024

Free Cash Flow

 - Cash flow from operations before changes in working capital was $11.6 billion
 - Incurred $6.2 billion of capital expenditures
 - This resulted in $5.4 billion of free cash flow

Cash Return and Working Capital

 - Paid $2.1 billion in regular dividends
 - Repurchased $3.2 billion of stock
 - Completed a $1.0 billion bond offering
 - Postponement of tax payments associated with severe weather tax relief accounted for approximately
   $700 million of the increase from working capital and other items

Fourth Quarter 2024 Operating Performance and Cash Return

Lease and Well

 - QoQ: Decreased primarily due to lower well service and labor costs

 - Guidance Midpoint: Lower primarily due to lower workover expenses, labor and fuel costs

Gathering, Processing and Transportation Costs

 - QoQ: Decreased primarily due to lower oil transportation expenses

 - Guidance Midpoint: Lower primarily due to lower compression-related fuel cost

General and Administrative

 - QoQ: Higher due to higher employee-related expenses and professional fees

 - Guidance Midpoint: Lower due to lower employee-related expenses

Depreciation, Depletion and Amortization

 - QoQ: Lower primarily due to the addition of lower cost reserves and positive reserve revisions

 - Guidance Midpoint: Lower primarily due to the addition of lower cost reserves and positive reserve revisions

Regular Dividend and Fourth Quarter Share Repurchases

The Board of Directors today declared a dividend of $0.975 per share on EOG's common stock. The dividend will be payable April 30, 2025, to stockholders of record as of April 16, 2025. The indicated annual rate is $3.90 per share, reflecting a 7% increase compared with 2024.

During the fourth quarter, the company repurchased 7.8 million shares for $981 million under its share repurchase authorization, at an average purchase price of $126 per share.

For full-year 2024, the company repurchased 25.8 million shares for $3.2 billion under its share repurchase authorization, at an average purchase price of $123 per share. EOG has $5.8 billion remaining on its current repurchase authorization.

2024 Reserves

Finding and Development Cost

Finding and development cost, excluding price revisions, decreased in 2024 to $6.68 per Boe, due to higher year-over-year well performance and cost reductions. Proved developed finding cost, excluding price revisions, was $8.71 per Boe (GAAP) and $8.04 per Boe (Non-GAAP) in 2024.

Reserve Replacement

Total proved reserves increased 6% in 2024. Extensions and discoveries added 580 MMBoe of proved reserves in 2024. Revisions other than price increased proved reserves by 215 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 201% of 2024 total production.

2025 Capital Program

Total expenditures for 2025 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 is anchored by steady year-over-year activity levels in the Delaware Basin, with a step up in activity in the Utica and Dorado plays. The plan delivers 3% oil volume growth and 6% total volume growth through the drilling and completion of 605 net wells across EOG's multi-basin portfolio of high return inventory.

The capital program also funds the completion of strategic infrastructure projects and international investment opportunities, including exploration projects in Trinidad and Bahrain.

EOG and Bapco Energies Entered Into a Strategic Participation Agreement in Bahrain

The companies will evaluate a natural gas exploration prospect with planned drilling activity in 2025. The transaction is subject to further government approvals.

Fourth Quarter 2024 Results vs Guidance

(Unaudited)


See "Endnotes" below for related discussion and definitions.


4Q 2024


4Q 2024

Guidance
Midpoint


 

Variance


 

3Q 2024


 

2Q 2024


1Q 2024


 

4Q 2023


Crude Oil and Condensate Volumes (MBod)















United States

493.5


491.9


1.6


491.8


490.1


486.8


484.6


Trinidad

1.1


1.1


0.0


1.2


0.6


0.6


0.6


Total

494.6


493.0


1.6


493.0


490.7


487.4


485.2


Natural Gas Liquids Volumes (MBbld)

Total

252.5


260.0


(7.5)


254.3


244.8


231.7


235.8


Natural Gas Volumes (MMcfd)

United States

1,840


1,825


15


1,745


1,668


1,658


1,653


Trinidad

252


250


2


225


204


200


178


Total

2,092


2,075


17


1,970


1,872


1,858


1,831



Total Crude Oil Equivalent Volumes (MBoed)

1,095.7


1,098.9


(3.2)


1,075.7


1,047.5


1,028.8


1,026.2


Total MMBoe

100.8


101.1


(0.3)


99.0


95.3


93.6


94.4







Benchmark Price





Oil (WTI) ($/Bbl)

70.28






75.16


80.55


76.97


78.33


Natural Gas (HH) ($/Mcf)

2.79






2.16


1.89


2.24


2.87



Crude Oil and Condensate - above (below) WTI4 ($/Bbl)















United States

1.40


1.75


(0.35)


1.79


2.16


1.49


2.28


Trinidad

(9.81)


(10.35)


0.54


(12.01)


(9.80)


(9.47)


(9.12)


Natural Gas Liquids - Realizations as % of WTI

Total

33.9 %


32.0 %


1.9 %


29.8 %


28.7 %


31.6 %


28.5 %


Natural Gas - above (below) NYMEX Henry Hub5 ($/Mcf)















United States

(0.40)


(0.35)


(0.05)


(0.32)


(0.32)


(0.14)


(0.15)


Natural Gas Realizations ($/Mcf)

Trinidad

3.86


3.65


0.21


3.68


3.48


3.54


3.81







Total Expenditures (GAAP) ($MM)

1,446






1,573


1,682


1,952


1,634


Capital Expenditures (non-GAAP) ($MM)

1,358


1,330


28


1,497


1,668


1,703


1,512







Operating Unit Costs ($/Boe)

Lease and Well

3.91


4.20


(0.29)


3.96


4.09


4.23


4.00


Gathering, Processing and Transportation Costs3

4.37


4.45


(0.08)


4.50


4.44


4.41


4.49


General and Administrative (GAAP)

1.87






1.69


1.58


1.73


2.03


General and Administrative (non-GAAP)1

1.87


1.90


(0.03)


1.59


1.58


1.73


2.03


Cash Operating Costs (GAAP)

10.15






10.15


10.11


10.37


10.52


Cash Operating Costs (non-GAAP)1

10.15


10.55


(0.40)


10.05


10.11


10.37


10.52


Depreciation, Depletion and Amortization

10.11


10.35


(0.24)


10.42


10.32


11.47


9.85







Expenses ($MM)

Exploration and Dry Hole

60


60


0


43


39


46


41


Impairment (GAAP)

276






15


81


19


79


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

23


120


(97)


15


46


17


60


Capitalized Interest

13


11


2


12


10


10


9


Net Interest

38


33


5


31


36


33


35







TOTI (% of Wellhead Revenue) (GAAP)

6.8 %






6.5 %


7.5 %


7.7 %


6.6 %


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

6.8 %


7.5 %


(0.7 %)


7.2 %


7.5 %


7.7 %


6.6 %


Income Taxes





Effective Rate

23.0 %


21.5 %


1.5 %


21.6 %


21.7 %


22.2 %


21.6 %


Current Tax Expense ($MM)

454


495


(41)


240


341


312


352


 

First Quarter and Full-Year 2025 Guidance7

(Unaudited)


See "Endnotes" below for related discussion and definitions


1Q 2025
Guidance Range


1Q 2025 Midpoint


FY 2025
Guidance Range


FY 2025 Midpoint


2024 Actual


2023 Actual


2022

Actual



















Crude Oil and Condensate Volumes (MBod)

















 United States

495.0 -

503.0


499.0


499.5 -

507.5


503.5


490.6


475.2


460.7


 Trinidad

0.8 -

1.2


1.0


0.9 -

1.3


1.1


0.8


0.6


0.6


 Total

495.8 -

504.2


500.0


500.4 -

508.8


504.6


491.4


475.8


461.3


Natural Gas Liquids Volumes (MBbld)

















 Total

233.0 -

245.0


239.0


249.0 -

261.0


255.0


245.9


223.8


197.7


Natural Gas Volumes (MMcfd)

















 United States

1,740 -

1,840


1,790


1,900 -

2,000


1,950


1,728


1,551


1,315


 Trinidad

225 -

245


235


215 -

235


225


220


160


180


 Total

1,965 -

2,085


2,025


2,115 -

2,235


2,175


1,948


1,711


1,495


Crude Oil Equivalent Volumes (MBoed)

















 United States

1,018.0 -

1,054.7


1,036.4


1,065.2 -

1,101.8


1,083.5


1,024.5


957.5


877.5


 Trinidad

38.3 -

42.0


40.2


36.7 -

40.5


38.6


37.6


27.3


30.7


 Total

1,056.3 -

1,096.7


1,076.5


1,101.9 -

1,142.3


1,122.1


1,062.1


984.8


908.2



















Benchmark Price

















Oil (WTI) ($/Bbl)











75.72


77.61


94.23


Natural Gas (HH) ($/Mcf)











2.27


2.74


6.64



















Crude Oil and Condensate - above (below) WTI4 ($/Bbl)

















United States

0.65 -

2.15


1.40


0.20 -

2.20


1.20


1.70


1.57


2.99


Trinidad

(12.95) -

(11.45)


(12.20)


(8.10) -

(6.10)


(7.10)


(11.29)


(9.03)


(8.07)


Natural Gas Liquids - Realizations as % of WTI


Total

30.0% -

40.0 %


35.0 %


29.0% -

39.0 %


34.0 %


30.9 %


29.7 %


39.0 %


Natural Gas - above (below) NYMEX Henry Hub5 ($/Mcf)

















United States

(0.70) -

0.00


(0.35)


(1.35) -

0.65


(0.35)


(0.28)


(0.04)


0.63


Natural Gas Realizations8 ($/Mcf)

















Trinidad

3.25 -

3.95


3.60


3.00 -

4.00


3.50


3.65


3.65


4.43



















Total Expenditures (GAAP) ($MM)











6,653


6,818


5,610


Capital Expenditures9 (non-GAAP) ($MM)

1,475 -

1,575


1,525


6,000 -

6,400


6,200


6,226


6,041


4,607



















Operating Unit Costs ($/Boe)

















Lease and Well

4.00 -

4.50


4.25


3.90 -

4.40


4.15


4.04


4.05


4.02


Gathering, Processing and Transportation Costs3

4.30 -

4.80


4.55


4.30 -

4.80


4.55


4.43


4.50


4.78


General and Administrative (GAAP)

1.75 -

2.05


1.90


1.65 -

1.95


1.80


1.72


1.78


1.72


General and Administrative (non-GAAP)1











1.70


1.78


1.67


Cash Operating Costs (GAAP)

10.05 -

11.35


10.70


9.85 -

11.15


10.50


10.19


10.33


10.52


Cash Operating Costs (non-GAAP)1











10.17


10.33


10.47


Depreciation, Depletion and Amortization

10.00 -

11.00


10.50


9.90 -

10.90


10.40


10.57


9.72


10.69


 Expenses ($MM)

















Exploration and Dry Hole

40 -

80


60


210 -

250


230


188


182


204


Impairment (GAAP)











391


202


382


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

30 -

110


70


240 -

320


280


100


160


269


Capitalized Interest

10 -

14


12


46 -

50


48


45


33


36


Net Interest

46 -

50


48


173 -

177


175


138


148


179



















TOTI (% of Wellhead Revenue) (GAAP)

7.0% -

9.0 %


8.0 %


7.0% -

9.0 %


8.0 %


7.1 %


7.4 %


7.0 %


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











7.3 %


7.4 %


7.5 %


Income Taxes

















Effective Rate

20.0% -

25.0 %


22.5 %


20.0% -

25.0 %


22.5 %


22.1 %


21.6 %


21.7 %


Current Tax Expense ($MM)

340 -

440


390


1,350 -

1,750


1,550


1,348


1,415


2,208


Fourth Quarter and Full-Year 2024 Results Webcast

Friday, February 28, 2025, 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 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)

Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of Wellhead Revenue) (non-GAAP) and G&A (non-GAAP) for each of 3Q 2024, fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024, fiscal year 2024 and fiscal year 2022 was $(0.10), $(0.02) and $(0.05), respectively, as set forth in "Fourth Quarter 2024 Results vs Guidance" and "First Quarter and Full-Year 2025 Guidance" above.

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, interest expense and the impact of changes in the effective income tax rate.

3)

Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

4)

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.

5)

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.

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 2025 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 full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited.

9)

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

GAAP

Generally accepted accounting principles

G&A

General and administrative expense

G&P

Gathering and processing

GHG

Greenhouse gas

GP&T

Gathering, processing & transportation expense

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

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 and any accompanying disclosures 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 or safety 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, magnitude 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 recoveries 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 any inflationary or other 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 the prevention of, 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 and equipment;
  • the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions 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 or other 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 and other 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 legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;
  • the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, 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, concessions, 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 and natural disasters, including its impact on crude oil and natural gas demand, and 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 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; 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, 2024 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. The unavailable information could have a significant impact on our ultimate results. However, 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 or any accompanying disclosures 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, 2024 (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.

Table of Contents




Fourth Quarter 2024


Supplemental Financial and Operating Data

Page



Income Statements

15

Volumes and Prices

17

Balance Sheets

18

Cash Flow Statements

19

Non-GAAP Financial Measures

20

Adjusted Net Income

21

Net Income Per Share

28

Adjusted Net Income Per Share

32

Cash Flow from Operations and Free Cash Flow

36

Net Debt-to-Total Capitalization Ratio

37

Proved Reserves and Reserve Replacement Data

38

Reserve Replacement Cost Data

39

Revenues, Costs and Margins Per Barrel of Oil Equivalent

44

 

Income Statements


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





2023


2024



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

3,182

3,252

3,717

3,597

13,748


3,480

3,692

3,488

3,261

13,921


Natural Gas Liquids

490

409

501

484

1,884


513

515

524

554

2,106


Natural Gas

517

334

417

476

1,744


382

303

372

494

1,551


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

376

101

43

298

818


237

(47)

79

(65)

204


Gathering, Processing and Marketing

1,390

1,465

1,478

1,473

5,806


1,459

1,519

1,481

1,341

5,800


Gains (Losses) on Asset Dispositions,
   Net

69

(9)

35

—

95


26

20

(7)

(23)

16


Other, Net

20

21

21

29

91


26

23

28

23

100


Total

6,044

5,573

6,212

6,357

24,186


6,123

6,025

5,965

5,585

23,698















Operating Expenses













Lease and Well

359

348

369

378

1,454


396

390

392

394

1,572


Gathering, Processing and
   Transportation Costs (A)

395

396

406

423

1,620


413

423

445

441

1,722


Exploration Costs

50

47

43

41

181


45

34

43

52

174


Dry Hole Costs

1

—

—

—

1


1

5

—

8

14


Impairments

34

35

54

79

202


19

81

15

276

391


Marketing Costs

1,361

1,456

1,383

1,509

5,709


1,404

1,490

1,500

1,323

5,717


Depreciation, Depletion and
   Amortization

798

866

898

930

3,492


1,074

984

1,031

1,019

4,108


General and Administrative

145

142

161

192

640


162

151

167

189

669


Taxes Other Than Income

329

313

341

301

1,284


338

337

283

291

1,249


Total

3,472

3,603

3,655

3,853

14,583


3,852

3,895

3,876

3,993

15,616















Operating Income

2,572

1,970

2,557

2,504

9,603


2,271

2,130

2,089

1,592

8,082


Other Income, Net

65

51

52

66

234


62

66

76

70

274


Income Before Interest Expense and
   Income Taxes

2,637

2,021

2,609

2,570

9,837


2,333

2,196

2,165

1,662

8,356


Interest Expense, Net

42

35

36

35

148


33

36

31

38

138


Income Before Income Taxes

2,595

1,986

2,573

2,535

9,689


2,300

2,160

2,134

1,624

8,218


Income Tax Provision

572

433

543

547

2,095


511

470

461

373

1,815


Net Income

2,023

1,553

2,030

1,988

7,594


1,789

1,690

1,673

1,251

6,403















Dividends Declared per Common Share

1.8250

0.8250

0.8250

2.4100

5.8850


0.9100

0.9100

0.9100

0.9750

3.7050


Net Income Per Share













Basic

3.46

2.68

3.51

3.43

13.07


3.11

2.97

2.97

2.25

11.31


Diluted

3.45

2.66

3.48

3.42

13.00


3.10

2.95

2.95

2.23

11.25


Average Number of Common Shares













Basic

584

580

579

579

581


575

569

564

557

566


Diluted

587

584

583

581

584


577

572

568

561

569




(A)

Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs.  This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

 

Volumes and Prices

(Unaudited)





2023


2024



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

457.1

476.0

482.8

484.6

475.2


486.8

490.1

491.8

493.5

490.6


Trinidad

0.6

0.6

0.5

0.6

0.6


0.6

0.6

1.2

1.1

0.8


Total

457.7

476.6

483.3

485.2

475.8


487.4

490.7

493.0

494.6

491.4















Average Crude Oil and Condensate Prices

($/Bbl) (B)













United States

$   77.27

$   74.98

$   83.61

$   80.61

$   79.18


$   78.46

$   82.71

$   76.95

$   71.68

$   77.42


Trinidad

68.98

64.88

71.38

69.21

65.58


67.50

70.75

63.15

60.47

64.43


Composite

77.26

74.97

83.60

80.60

79.17


78.45

82.69

76.92

71.66

77.40















Natural Gas Liquids Volumes (MBbld) (A)













United States

212.2

215.7

231.1

235.8

223.8


231.7

244.8

254.3

252.5

245.9


Total

212.2

215.7

231.1

235.8

223.8


231.7

244.8

254.3

252.5

245.9















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













United States

$   25.67

$   20.85

$   23.56

$   22.29

$   23.07


$   24.32

$   23.11

$   22.42

$   23.85

$   23.40


Composite

25.67

20.85

23.56

22.29

23.07


24.32

23.11

22.42

23.85

23.40















Natural Gas Volumes (MMcfd) (A)













United States

1,475

1,513

1,562

1,653

1,551


1,658

1,668

1,745

1,840

1,728


Trinidad

164

155

142

178

160


200

204

225

252

220


Total

1,639

1,668

1,704

1,831

1,711


1,858

1,872

1,970

2,092

1,948















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













United States

$     3.47

$     2.07

$     2.59

$     2.72

$     2.70


$     2.10

$     1.57

$     1.84

$     2.39

$     1.99


Trinidad

3.87

3.45

3.41

3.81

3.65


3.54

3.48

3.68

3.86

3.65


Composite

3.51

2.20

2.66

2.82

2.79


2.26

1.78

2.05

2.57

2.17















Crude Oil Equivalent Volumes (MBoed) (C)













United States

915.0

943.8

974.2

995.8

957.5


994.7

1,013.0

1,037.1

1,052.7

1,024.5


Trinidad

28.0

26.5

24.3

30.4

27.3


34.1

34.5

38.6

43.0

37.6


Total

943.0

970.3

998.5

1,026.2

984.8


1,028.8

1,047.5

1,075.7

1,095.7

1,062.1















Total MMBoe (C)

84.9

88.3

91.9

94.4

359.4


93.6

95.3

99.0

100.8

388.7

















(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 and other 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, 2024).

(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.

 

Balance Sheets

In millions of USD (Unaudited)



2023


2024



MAR

JUN

SEP

DEC


MAR

JUN

SEP

DEC


Current Assets











Cash and Cash Equivalents

5,018

4,764

5,326

5,278


5,292

5,431

6,122

7,092


Accounts Receivable, Net

2,455

2,263

2,927

2,716


2,688

2,657

2,545

2,650


Inventories

1,131

1,355

1,379

1,275


1,154

1,069

1,038

985


Assets from Price Risk Management Activities

—

—

—

106


110

4

—

—


Other (A)

580

524

626

560


684

642

460

503


Total

9,184

8,906

10,258

9,935


9,928

9,803

10,165

11,230













Property, Plant and Equipment











Oil and Gas Properties (Successful Efforts Method)

67,907

69,178

70,730

72,090


73,356

74,615

75,887

77,091


Other Property, Plant and Equipment

5,101

5,282

5,355

5,497


5,768

6,078

6,314

6,418


Total Property, Plant and Equipment

73,008

74,460

76,085

77,587


79,124

80,693

82,201

83,509


Less:  Accumulated Depreciation, Depletion and
   Amortization

(42,785)

(43,550)

(44,362)

(45,290)


(46,047)

(47,049)

(48,075)

(49,297)


Total Property, Plant and Equipment, Net

30,223

30,910

31,723

32,297


33,077

33,644

34,126

34,212


Deferred Income Taxes

31

33

33

42


38

44

42

39


Other Assets

1,587

1,638

1,633

1,583


1,753

1,733

1,818

1,705


Total Assets

41,025

41,487

43,647

43,857


44,796

45,224

46,151

47,186













Current Liabilities











Accounts Payable

2,438

2,205

2,464

2,437


2,389

2,436

2,290

2,464


Accrued Taxes Payable

637

425

605

466


786

600

855

1,007


Dividends Payable

482

478

478

526


523

516

513

539


Liabilities from Price Risk Management Activities

31

22

22

—


—

8

32

116


Current Portion of Long-Term Debt

33

34

34

34


34

534

34

532


Current Portion of Operating Lease Liabilities

354

335

337

325


318

303

338

315


Other

253

232

285

286


223

231

344

381


Total

4,228

3,731

4,225

4,074


4,273

4,628

4,406

5,354













Long-Term Debt

3,787

3,780

3,772

3,765


3,757

3,250

3,742

4,220


Other Liabilities

2,620

2,581

2,698

2,526


2,533

2,456

2,480

2,395


Deferred Income Taxes

4,943

5,138

5,194

5,402


5,597

5,731

5,949

5,866


Commitments and Contingencies






















Stockholders' Equity











Common Stock, $0.01 Par

206

206

206

206


206

206

206

206


Additional Paid in Capital

6,219

6,257

6,133

6,166


6,188

6,219

6,058

6,090


Accumulated Other Comprehensive Loss

(8)

(9)

(7)

(9)


(8)

(8)

(9)

(4)


Retained Earnings

19,423

20,497

22,047

22,634


23,897

25,071

26,231

26,941


Common Stock Held in Treasury

(393)

(694)

(621)

(907)


(1,647)

(2,329)

(2,912)

(3,882)


Total Stockholders' Equity

25,447

26,257

27,758

28,090


28,636

29,159

29,574

29,351


Total Liabilities and Stockholders' Equity

41,025

41,487

43,647

43,857


44,796

45,224

46,151

47,186




(A)

Effective October 1, 2024, EOG combined Income Taxes Receivable into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets.

 

Cash Flow Statements

In millions of USD (Unaudited)














2023


2024



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

2,023

1,553

2,030

1,988

7,594


1,789

1,690

1,673

1,251

6,403


Items Not Requiring (Providing) Cash













Depreciation, Depletion and Amortization

798

866

898

930

3,492


1,074

984

1,031

1,019

4,108


Impairments

34

35

54

79

202


19

81

15

276

391


Stock-Based Compensation Expenses

34

35

57

51

177


45

45

58

51

199


Deferred Income Taxes

234

194

56

199

683


199

128

220

(80)

467


(Gains) Losses on Asset Dispositions, Net

(69)

9

(35)

—

(95)


(26)

(20)

7

23

(16)


Other, Net

4

2

(1)

22

27


9

3

2

3

17


Dry Hole Costs

1

—

—

—

1


1

5

—

8

14


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

(376)

(101)

(43)

(298)

(818)


(237)

47

(79)

65

(204)


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

(123)

(30)

23

18

(112)


55

79

61

19

214


Other, Net

(1)

—

(1)

—

(2)


—

—

—

—

—


Changes in Components of Working Capital and
   Other Assets and Liabilities













Accounts Receivable

338

137

(714)

201

(38)


58

33

109

(99)

101


Inventories

(77)

(226)

(28)

100

(231)


117

75

30

37

259


Accounts Payable

(77)

(231)

238

(49)

(119)


(58)

29

(159)

152

(36)


Accrued Taxes Payable

232

(212)

180

(139)

61


319

(185)

256

151

541


Other Assets

52

43

(92)

36

39


(161)

42

197

(34)

44


Other Liabilities

193

(47)

54

(16)

184


(71)

(20)

108

6

23


Changes in Components of Working Capital
   Associated with Investing Activities

35

250

28

(18)

295


(229)

(127)

59

(85)

(382)


Net Cash Provided by Operating Activities

3,255

2,277

2,704

3,104

11,340


2,903

2,889

3,588

2,763

12,143


Investing Cash Flows













Additions to Oil and Gas Properties

(1,305)

(1,341)

(1,379)

(1,360)

(5,385)


(1,485)

(1,357)

(1,263)

(1,248)

(5,353)


Additions to Other Property, Plant and Equipment

(319)

(180)

(139)

(162)

(800)


(350)

(313)

(239)

(117)

(1,019)


Proceeds from Sales of Assets

92

29

14

5

140


9

10

—

4

23


Changes in Components of Working Capital
   Associated with Investing Activities

(35)

(250)

(28)

18

(295)


229

127

(59)

85

382


Net Cash Used in Investing Activities

(1,567)

(1,742)

(1,532)

(1,499)

(6,340)


(1,597)

(1,533)

(1,561)

(1,276)

(5,967)


Financing Cash Flows













Long-Term Debt Borrowings

—

—

—

—

—


—

—

—

985

985


Long-Term Debt Repayments

(1,250)

—

—

—

(1,250)


—

—

—

—

—


Dividends Paid

(1,067)

(480)

(494)

(1,345)

(3,386)


(525)

(520)

(533)

(509)

(2,087)


Treasury Stock Purchased

(317)

(302)

(109)

(310)

(1,038)


(759)

(699)

(795)

(993)

(3,246)


Proceeds from Stock Options Exercised and
   Employee Stock Purchase Plan

—

9

1

10

20


—

11

—

11

22


Debt Issuance Costs

—

(8)

—

—

(8)


—

—

—

(2)

(2)


Repayment of Finance Lease Liabilities

(8)

(8)

(8)

(8)

(32)


(8)

(9)

(8)

(8)

(33)


Net Cash Used in Financing Activities

(2,642)

(789)

(610)

(1,653)

(5,694)


(1,292)

(1,217)

(1,336)

(516)

(4,361)


Effect of Exchange Rate Changes on Cash

—

—

—

—

—


—

–

–

(1)

(1)


Increase (Decrease) in Cash and Cash Equivalents

(954)

(254)

562

(48)

(694)


14

139

691

970

1,814


Cash and Cash Equivalents at Beginning of Period

5,972

5,018

4,764

5,326

5,972


5,278

5,292

5,431

6,122

5,278


Cash and Cash Equivalents at End of Period

5,018

4,764

5,326

5,278

5,278


5,292

5,431

6,122

7,092

7,092


 


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

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 net unrealized mark-to-market (gains) losses from these and other derivative 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 2024



Before
Tax


Income Tax
Impact


After
Tax


Diluted
Earnings
per Share











Reported Net Income (GAAP)

1,624


(373)


1,251


2.23


Adjustments:









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

65


(14)


51


0.10


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

19


(4)


15


0.03


Add: Losses on Asset Dispositions, Net

23


(4)


19


0.03


Add: Certain Impairments

254


(55)


199


0.35


Adjustments to Net Income

361


(77)


284


0.51











Adjusted Net Income (Non-GAAP)

1,985


(450)


1,535


2.74











Average Number of Common Shares









Basic







557


Diluted







561




(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period.  For the three months ended December 31, 2024, such amount was $19 million. 

 

Adjusted Net Income

(Continued)


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



















3Q 2024



Before
Tax


Income Tax
Impact


After
Tax


Diluted
Earnings
per Share











Reported Net Income (GAAP)

2,134


(461)


1,673


2.95


Adjustments:









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

(79)


17


(62)


(0.11)


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

61


(13)


48


0.08


Add: Losses on Asset Dispositions, Net

7


(2)


5


0.01


Less: Severance Tax Refund

(31)


7


(24)


(0.04)


Add: Severance Tax Consulting Fees

10


(2)


8


0.01


Less: Interest on Severance Tax Refund

(5)


1


(4)


(0.01)


Adjustments to Net Income

(37)


8


(29)


(0.06)











Adjusted Net Income (Non-GAAP)

2,097


(453)


1,644


2.89











Average Number of Common Shares









Basic







564


Diluted







568




(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period.  For the three months ended September 30, 2024, such amount was $61 million.

 

Adjusted Net Income

(Continued)

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











2Q 2024



Before
Tax


Income Tax
Impact


After
Tax


Diluted 
Earnings
per Share











Reported Net Income (GAAP)

2,160


(470)


1,690


2.95


Adjustments:









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

47


(10)


37


0.07


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

79


(17)


62


0.11


Less: Gains on Asset Dispositions, Net

(20)


5


(15)


(0.03)


Add: Certain Impairments

35


(2)


33


0.06


Adjustments to Net Income

141


(24)


117


0.21











Adjusted Net Income (Non-GAAP)

2,301


(494)


1,807


3.16











Average Number of Common Shares









Basic







569


Diluted







572




(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2024, such amount was $79 million.

 

Adjusted Net Income

(Continued)


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





1Q 2024



Before
Tax


Income Tax
Impact


After
Tax


Diluted
Earnings
per Share











Reported Net Income (GAAP)

2,300


(511)


1,789


3.10


Adjustments:









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

(237)


51


(186)


(0.31)


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

55


(12)


43


0.07


Less: Gains on Asset Dispositions, Net

(26)


4


(22)


(0.04)


Add: Certain Impairments

2


—


2


—


Adjustments to Net Income

(206)


43


(163)


(0.28)











Adjusted Net Income (Non-GAAP)

2,094


(468)


1,626


2.82











Average Number of Common Shares









Basic







575


Diluted







577




(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2024, such amount was $55 million.

 

Adjusted Net Income

(Continued)


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



















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


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









Basic







579


Diluted







581




(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (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

(Continued)


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










FY 2024



Before
Tax


Income Tax
Impact


After
Tax


Diluted
Earnings
per Share











Reported Net Income (GAAP)

8,218


(1,815)


6,403


11.25


Adjustments:









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

(204)


44


(160)


(0.28)


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

214


(46)


168


0.30


Less: Gains on Asset Dispositions, Net

(16)


3


(13)


(0.02)


Add: Certain Impairments

291


(57)


234


0.41


Less: Severance Tax Refund

(31)


7


(24)


(0.04)


Add: Severance Tax Consulting Fees

10


(2)


8


0.01


Less: Interest on Severance Tax Refund

(5)


1


(4)


(0.01)


Adjustments to Net Income

259


(50)


209


0.37











Adjusted Net Income (Non-GAAP)

8,477


(1,865)


6,612


11.62











Average Number of Common Shares









Basic







566


Diluted







569













(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was $214 million.

 

Adjusted Net Income

(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









Basic







581


Diluted







584




(1)

Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (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.

 

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 2024 Net Income per Share (GAAP) - Diluted



2.95







Realized Price





4Q 2024 Composite Average Wellhead Revenue per Boe

42.74




Less:  3Q 2024 Composite Average Wellhead Revenue per Boe

(44.31)




Subtotal

(1.57)




Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe)

100.8




Total Change in Revenue

(158)




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

35




Change in Net Income

(123)




Change in Diluted Earnings per Share



(0.22)







Volumes





4Q 2024 Crude Oil Equivalent Volumes (MMBoe)

100.8




Less:  3Q 2024 Crude Oil Equivalent Volumes (MMBoe)

(99.0)




Subtotal

1.8




Multiplied by:  4Q 2024 Composite Average Margin per Boe (GAAP) (Including Total
   Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
   schedule below)

15.88




Change in Margin

29




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

(6)




Change in Net Income

23




Change in Diluted Earnings per Share



0.04







Certain Operating Costs per Boe





3Q 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

20.57




Less:  4Q 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.26)




Subtotal

0.31




Multiplied by:  4Q 2024 Crude Oil Equivalent Volumes (MMBoe)

100.8




Change in Before-Tax Net Income

31




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

(7)




Change in Net Income

24




Change in Diluted Earnings per Share



0.04


 

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 and Other Derivative Contracts, Net




4Q 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

(65)




Less:  Income Tax Benefit (Provision)

14




After Tax - (a)

(51)




Less: 3Q 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

79




Less:  Income Tax Benefit (Provision)

(17)




After Tax - (b)

62




Change in Net Income - (a) - (b)

(113)




Change in Diluted Earnings per Share



(0.20)







Other (1)



(0.38)







4Q 2024 Net Income per Share (GAAP) - Diluted



2.23







4Q 2024 Average Number of Common Shares - Diluted

561






(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 2023 Net Income per Share (GAAP)



13.00







Realized Price





FY 2024 Composite Average Wellhead Revenue per Boe

45.22




Less:  FY 2023 Composite Average Wellhead Revenue per Boe

(48.34)




Subtotal

(3.12)




Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe)

388.7




Total Change in Revenue

(1,213)




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

267




Change in Net Income

(946)




Change in Diluted Earnings per Share



(1.66)







Volumes





FY 2024 Crude Oil Equivalent Volumes (MMBoe)

388.7




Less:  FY 2023 Crude Oil Equivalent Volumes (MMBoe)

(359.4)




Subtotal

29.3




Multiplied by:  FY 2024 Composite Average Margin per Boe (GAAP) (Including Total
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule below)

19.40




Change in Margin

568




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

(125)




Change in Net Income

443




Change in Diluted Earnings per Share



0.78







Certain Operating Costs per Boe





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

20.05




Less:  FY 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.76)




Subtotal

(0.71)




Multiplied by:  FY 2024 Crude Oil Equivalent Volumes (MMBoe)

388.7




Change in Before-Tax Net Income

(276)




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

61




Change in Net Income

(215)




Change in Diluted Earnings per Share



(0.38)


 

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 and Other Derivative Contracts, Net




FY 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative
   Contracts

204




Less:  Income Tax Benefit (Provision)

(44)




After Tax - (a)

160




Less:  FY 2023 Net Gains (Losses) on Mark-to-Market Commodity and Other Derivative Contracts

818




Less:  Income Tax Benefit (Provision)

(176)




After Tax - (b)

642




Change in Net Income - (a) - (b)

(482)




Change in Diluted Earnings per Share



(0.85)







Other (1)



0.36







FY 2024 Net Income per Share (GAAP) - Diluted



11.25







FY 2024 Average Number of Common Shares - Diluted

569






(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 2024 Adjusted Net Income per Share (Non-GAAP) - Diluted



2.89







Realized Price





4Q 2024 Composite Average Wellhead Revenue per Boe

42.74




Less:  3Q 2024 Composite Average Wellhead Revenue per Boe

(44.31)




Subtotal

(1.57)




Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe)

100.8




Total Change in Revenue

(158)




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

35




Change in Net Income

(123)




Change in Diluted Earnings per Share



(0.22)







Volumes





4Q 2024 Crude Oil Equivalent Volumes (MMBoe)

100.8




Less:  3Q 2024 Crude Oil Equivalent Volumes (MMBoe)

(99.0)




Subtotal

1.8




Multiplied by:  4Q 2024 Composite Average Margin per Boe (Non-GAAP) (Including Total
   Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
   schedule below)

18.40




Change in Margin

33




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

(7)




Change in Net Income

26




Change in Diluted Earnings per Share



0.05







Certain Operating Costs per Boe





3Q 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

20.47




Less:  4Q 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.26)




Subtotal

0.21




Multiplied by:  4Q 2024 Crude Oil Equivalent Volumes (MMBoe)

100.8




Change in Before-Tax Net Income

21




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

(5)




Change in Net Income

16




Change in Diluted Earnings per Share



0.03


 

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 2024 Net Cash Received from (Payments for)  Settlements of Financial Commodity Derivative
   Contracts

19




Less:  Income Tax Benefit (Provision)

(4)




After Tax - (a)

15




3Q 2024 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative
   Contracts

61




Less:  Income Tax Benefit (Provision)

(13)




After Tax - (b)

48




Change in Net Income - (a) - (b)

(33)




Change in Diluted Earnings per Share



(0.06)







Other (1)



0.05







4Q 2024 Adjusted Net Income per Share (Non-GAAP)



2.74







4Q 2024 Average Number of Common Shares - Diluted

561






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



11.69





Realized Price




FY 2024 Composite Average Wellhead Revenue per Boe

45.22



Less:  FY 2023 Composite Average Wellhead Revenue per Boe

(48.34)



Subtotal

(3.12)



Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe)

388.7



Total Change in Revenue

(1,213)



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

267



Change in Net Income

(946)



Change in Diluted Earnings per Share



(1.66)





Volumes




FY 2024 Crude Oil Equivalent Volumes (MMBoe)

388.7



Less:  FY 2023 Crude Oil Equivalent Volumes (MMBoe)

(359.4)



Subtotal

29.3



Multiplied by:  FY 2024 Composite Average Margin per Boe (Non-GAAP)
(Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule below)

20.09



Change in Margin

589



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

(130)



Change in Net Income

459



Change in Diluted Earnings per Share



0.81





Certain Operating Costs per Boe




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

20.05



Less:  FY 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.74)



Subtotal

(0.69)



Multiplied by:  FY 2024 Crude Oil Equivalent Volumes (MMBoe)

388.7



Change in Before-Tax Net Income

(268)



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

59



Change in Net Income

(209)



Change in Diluted Earnings per Share



(0.37)

 

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 2024 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

214



Less:  Income Tax Benefit (Provision)

(46)



After Tax - (a)

168



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

(112)



Less:  Income Tax Benefit (Provision)

24



After Tax - (b)

(88)



Change in Net Income - (a) - (b)

256



Change in Diluted Earnings per Share



0.45





Other (1)



0.70





FY 2024 Adjusted Net Income per Share (Non-GAAP)



11.62





FY 2024 Average Number of Common Shares (Non-GAAP) - Diluted

569









(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. 



2023


2024



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)

3,255

2,277

2,704

3,104

11,340


2,903

2,889

3,588

2,763

12,143















Adjustments:













Changes in Components of Working Capital and Other Assets and Liabilities













Accounts Receivable

(338)

(137)

714

(201)

38


(58)

(33)

(109)

99

(101)


Inventories

77

226

28

(100)

231


(117)

(75)

(30)

(37)

(259)


Accounts Payable

77

231

(238)

49

119


58

(29)

159

(152)

36


Accrued Taxes Payable

(232)

212

(180)

139

(61)


(319)

185

(256)

(151)

(541)


Other Assets

(52)

(43)

92

(36)

(39)


161

(42)

(197)

34

(44)


Other Liabilities

(193)

47

(54)

16

(184)


71

20

(108)

(6)

(23)


Changes in Components of Working Capital Associated with Investing Activities

(35)

(250)

(28)

18

(295)


229

127

(59)

85

382


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

2,559

2,563

3,038

2,989

11,149


2,928

3,042

2,988

2,635

11,593


Less:













Total Capital Expenditures (Non-GAAP) (a)

(1,489)

(1,521)

(1,519)

(1,512)

(6,041)


(1,703)

(1,668)

(1,497)

(1,358)

(6,226)


Free Cash Flow (Non-GAAP)

1,070

1,042

1,519

1,477

5,108


1,225

1,374

1,491

1,277

5,367


 

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
















2023


2024



1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year


1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year















Total Expenditures (GAAP)

1,717

1,664

1,803

1,634

6,818


1,952

1,682

1,573

1,446

6,653


Less:













Asset Retirement Costs

(10)

(26)

(191)

(30)

(257)


(21)

60

(11)

(26)

2


Non-Cash Development Drilling

—

(35)

(50)

(5)

(90)


—

—

—

—

—


Non-Cash Acquisition Costs of
   Unproved Properties

(31)

(28)

(1)

(39)

(99)


(31)

(34)

(17)

(3)

(85)


Acquisition Costs of Proved Properties

(4)

(6)

1

(7)

(16)


(21)

(5)

—

(7)

(33)


Acquisition Costs of Other Property,
   Plant and Equipment

(133)

(1)

—

—

(134)


(131)

(1)

(5)

—

(137)


Exploration Costs

(50)

(47)

(43)

(41)

(181)


(45)

(34)

(43)

(52)

(174)


Total Capital Expenditures (Non-GAAP)

1,489

1,521

1,519

1,512

6,041


1,703

1,668

1,497

1,358

6,226


 

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,
2024


September 30,
2024


June 30,
2024


March 31,
2024


December 31,
2023













Total Stockholders' Equity - (a)

29,351


29,574


29,159


28,636


28,090













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

4,752


3,776


3,784


3,791


3,799


Less: Cash

(7,092)


(6,122)


(5,431)


(5,292)


(5,278)


Net Debt (Non-GAAP) - (c)

(2,340)


(2,346)


(1,647)


(1,501)


(1,479)













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

34,103


33,350


32,943


32,427


31,889













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

27,011


27,228


27,512


27,135


26,611













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

13.9 %


11.3 %


11.5 %


11.7 %


11.9 %













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

-8.7 %


-8.6 %


-6.0 %


-5.5 %


-5.6 %


 

Proved Reserves and Reserve Replacement Data


(Unaudited)











2024 Net Proved Reserves Reconciliation Summary

United

States


Trinidad


Other

International


Total


Crude Oil and Condensate (MMBbl)









Beginning Reserves

1,754


2


—


1,756


Revisions

71


—


—


71


Purchases in Place

3


—


—


3


Extensions, Discoveries and Other Additions

228


—


—


228


Sales in Place

(8)


—


—


(8)


Production

(180)


—


—


(180)


Ending Reserves

1,868


2


—


1,870











Natural Gas Liquids (MMBbl)









Beginning Reserves

1,254


—


—


1,254


Revisions

31


—


—


31


Purchases in Place

2


—


—


2


Extensions, Discoveries and Other Additions

164


—


—


164


Sales in Place

(3)


—


—


(3)


Production

(90)


—


—


(90)


Ending Reserves

1,358


—


—


1,358











Natural Gas (Bcf)









Beginning Reserves

8,630


300


—


8,930


Revisions

(202)


2


—


(200)


Purchases in Place

10


—


—


10


Extensions, Discoveries and Other Additions

1,098


23


—


1,121


Sales in Place

(14)


—


—


(14)


Production

(644)


(81)


—


(725)


Ending Reserves

8,878


244


—


9,122











Oil Equivalents (MMBoe)









Beginning Reserves

4,447


51


—


4,498


Revisions

68


1


—


69


Purchases in Place

6


—


—


6


Extensions, Discoveries and Other Additions

576


4


—


580


Sales in Place

(14)


—


—


(14)


Production

(377)


(14)


—


(391)


Ending Reserves

4,706


42


—


4,748











Net Proved Developed Reserves (MMBoe)









At December 31, 2023

2,322


27


—


2,349


At December 31, 2024

2,542


24


—


2,566











2024 Exploration and Development Expenditures ($ Millions)











Acquisition Cost of Unproved Properties

229


—


1


230


Exploration Costs

286


115


28


429


Development Costs

4,820


124


—


4,944


Total Drilling

5,335


239


29


5,603


Acquisition Cost of Proved Properties

33


—


—


33


Asset Retirement Costs

(37)


8


27


(2)


Total Exploration and Development Expenditures

5,331


247


56


5,634


Gathering, Processing and Other

1,017


2


—


1,019


Total Expenditures

6,348


249


56


6,653


Proceeds from Sales in Place

(23)


—


—


(23)


Net Expenditures

6,325


249


56


6,630











Reserve Replacement Costs ($ / Boe) *









All-in Total, Net of Revisions

7.85


47.00


—


8.17


All-in Total, Excluding Revisions Due to Price

6.41


47.00


—


6.68











Reserve Replacement *









Drilling Only

153 %


29 %


0 %


148 %


All-in Total, Net of Revisions and Dispositions 

169 %


36 %


0 %


164 %


All-in Total, Excluding Revisions Due to Price

207 %


36 %


0 %


201 %


All-in Total, Liquids

181 %


0 %


0 %


181 %











*   See following reconciliation schedule for calculation methodology


 

Reserve Replacement Cost Data


(Unaudited; in millions, except ratio data)











For the Twelve Months Ended December 31, 2024

United

States


Trinidad


Other

International


Total











Total Costs Incurred in Exploration and Development Activities (GAAP)

5,331


247


56


5,634


Less: Asset Retirement Costs

37


(8)


(27)


2


Non-Cash Acquisition Costs of Unproved Properties

(85)


—


—


(85)


Total Acquisition Costs of Proved Properties

(33)


—


—


(33)


Exploration Expenses

(154)


(4)


(16)


(174)


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

5,096


235


13


5,344











Total Costs Incurred in Exploration and Development Activities (GAAP)

5,331


247


56


5,634


Less: Asset Retirement Costs

37


(8)


(27)


2


Non-Cash Acquisition Costs of Unproved Properties

(85)


—


—


(85)


Non-Cash Acquisition Costs of Proved Properties

(24)


—


—


(24)


Exploration Expenses

(154)


(4)


(16)


(174)


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

5,105


235


13


5,353











Total Expenditures (GAAP)

6,348


249


56


6,653


Less: Asset Retirement Costs

37


(8)


(27)


2


Non-Cash Acquisition Costs of Unproved Properties

(85)


—


—


(85)


Non-Cash Acquisition Costs of Proved Properties

(24)


—


—


(24)


Exploration Expenses

(154)


(4)


(16)


(174)


Total Cash Expenditures (Non-GAAP)

6,122


237


13


6,372











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









Revisions Due to Price - (c)

(146)


—


—


(146)


Revisions Other Than Price

214


1


—


215


Purchases in Place

6


—


—


6


Extensions, Discoveries and Other Additions - (d)

576


4


—


580


Total Proved Reserve Additions - (e)

650


5


—


655


Sales in Place

(14)


—


—


(14)


Net Proved Reserve Additions From All Sources - (f)

636


5


—


641











Production - (g)

377


14


—


391











Reserve Replacement Costs ($ / Boe)









Total Drilling, Before Revisions - (a / d)

8.85


58.75


—


9.21


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

7.85


47.00


—


8.17


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

6.41


47.00


—


6.68











Reserve Replacement









Drilling Only - (d / g)

153 %


29 %


0 %


148 %


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

169 %


36 %


0 %


164 %


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

207 %


36 %


0 %


201 %











 

Reserve Replacement Cost Data

(Continued)


(Unaudited; in millions, except ratio data)


















For the Twelve Months Ended December 31, 2024

United

States


Trinidad


Other

International


Total











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









Revisions

102


—


—


102


Purchases in Place

5


—


—


5


Extensions, Discoveries and Other Additions - (h)

392


—


—


392


Total Proved Reserve Additions

499


—


—


499


Sales in Place

(11)


—


—


(11)


Net Proved Reserve Additions From All Sources - (i)

488


—


—


488











Production - (j)

270


—


—


270











Reserve Replacement - Liquids









Drilling Only - (h / j)

145 %


0 %


0 %


145 %


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

181 %


0 %


0 %


181 %


 

Reserve Replacement Cost Data

(Continued)



(Unaudited; in millions, except ratio data)






For the Twelve Months Ended December 31, 2024






Proved Developed Reserve Replacement Costs ($ / Boe)

Total


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

5,634


Less:  Asset Retirement Costs

2


Acquisition Costs of Unproved Properties

(230)


Acquisition Costs of Proved Properties

(33)


Exploration Expenses

(174)


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

5,199





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

580


Add:  Conversion of Proved Undeveloped Reserves to Proved Developed

370


Less: Proved Undeveloped Extensions and Discoveries

(479)


Proved Developed Reserves - Extensions and Discoveries (MMBoe)

471





Total Proved Reserves - Revisions (MMBoe)

69


Less: Proved Undeveloped Reserves - Revisions

66


          Proved Developed - Revisions Due to Price

41


Proved Developed Reserves - Revisions Other Than Price (MMBoe)

176





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

647





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

8.71





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

8.04


 

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.












2024


2023


2022


2021











Total Costs Incurred in Exploration and Development Activities (GAAP)

5,634


6,018


5,229


3,969


Less:  Asset Retirement Costs

2


(257)


(298)


(127)


Non-Cash Acquisition Costs of Unproved Properties

(85)


(99)


(127)


(45)


Total Acquisition Costs of Proved Properties

(33)


(16)


(419)


(100)


Non-Cash Development Drilling

—


(90)


—


—


Exploration Expenses

(174)


(181)


(159)


(154)


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

5,344


5,375


4,226


3,543











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

5,634


6,018


5,229


3,969


Less:  Asset Retirement Costs

2


(257)


(298)


(127)


Non-Cash Acquisition Costs of Unproved Properties

(85)


(99)


(127)


(45)


Non-Cash Acquisition Costs of Proved Properties

(24)


(6)


(26)


(5)


Non-Cash Development Drilling

—


(90)


—


—


Exploration Expenses

(174)


(181)


(159)


(154)


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

5,353


5,385


4,619


3,638











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









Revisions Due to Price - (d)

(146)


(110)


11


194


Revisions Other Than Price

215


139


325


(308)


Purchases in Place

6


2


16


9


Extensions, Discoveries and Other Additions - (e)

580


607


560


952


Total Proved Reserve Additions - (f)

655


638


912


847


Sales in Place

(14)


(17)


(88)


(11)


Net Proved Reserve Additions From All Sources

641


621


824


836











Production

391


361


333


309











Reserve Replacement Costs ($ / Boe)









Total Drilling, Before Revisions - (a / e)

9.21


8.86


7.55


3.72


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

8.17


8.44


5.06


4.30


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

7.03


8.05


5.80


6.08


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

6.68


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

 

Revenues, Costs and Margins Per Barrel of Oil Equivalent


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













EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.














4Q 2024


3Q 2024


2Q 2024


1Q 2024


4Q 2023













Volume - Million Barrels of Oil Equivalent - (a)

100.8


99.0


95.3


93.6


94.4













Total Operating Revenues and Other (b)

5,585


5,965


6,025


6,123


6,357


Total Operating Expenses (c)

3,993


3,876


3,895


3,852


3,853


Operating Income (d)

1,592


2,089


2,130


2,271


2,504













Wellhead Revenues











Crude Oil and Condensate

3,261


3,488


3,692


3,480


3,597


Natural Gas Liquids

554


524


515


513


484


Natural Gas

494


372


303


382


476


Total Wellhead Revenues - (e)

4,309


4,384


4,510


4,375


4,557













Operating Costs











Lease and Well

394


392


390


396


378


Gathering, Processing and Transportation Costs (1)

441


445


423


413


423


General and Administrative (GAAP)

189


167


151


162


192


Less:  Severance Tax Consulting Fees

—


(10)


—


—


—


General and Administrative (Non-GAAP) (3)

189


157


151


162


192


Taxes Other Than Income (GAAP)

291


283


337


338


301


Add:  Severance Tax Refund

—


31


—


—


—


Taxes Other Than Income (Non-GAAP) (4)

291


314


337


338


301


Interest Expense, Net

38


31


36


33


35


Total Operating Cost (GAAP)  (excluding DD&A and Total Exploration
   Costs) (f)

1,353


1,318


1,337


1,342


1,329


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

1,353


1,339


1,337


1,342


1,329













Depreciation, Depletion and Amortization (DD&A)

1,019


1,031


984


1,074


930













Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)

2,372


2,349


2,321


2,416


2,259


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

2,372


2,370


2,321


2,416


2,259













Exploration Costs

52


43


34


45


41


Dry Hole Costs

8


—


5


1


—


Impairments

276


15


81


19


79


Total Exploration Costs (GAAP)

336


58


120


65


120


Less:  Certain Impairments (2)

(254)


—


(35)


(2)


(19)


Total Exploration Costs (Non-GAAP)

82


58


85


63


101













Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) -
   (j)

2,708


2,407


2,441


2,481


2,379


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

2,454


2,428


2,406


2,479


2,360













Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total
   Exploration Costs (GAAP))

1,601


1,977


2,069


1,894


2,178


Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total
   Exploration Costs (Non-GAAP))

1,855


1,956


2,104


1,896


2,197


 

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)


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























4Q 2024


3Q 2024


2Q 2024


1Q 2024


4Q 2023


Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)






















Composite Average Operating Revenues and Other per Boe - (b) / (a)

55.41


60.25


63.22


65.42


67.34


Composite Average Operating Expenses per Boe - (c) / (a)

39.62


39.15


40.87


41.16


40.81


Composite Average Operating Income per Boe  - (d) / (a)

15.79


21.10


22.35


24.26


26.53













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

42.74


44.31


47.31


46.73


48.27













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

13.42


13.32


14.03


14.33


14.08













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

29.32


30.99


33.28


32.40


34.19













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

23.53


23.74


24.35


25.80


23.93













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

19.21


20.57


22.96


20.93


24.34













Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)

26.86


24.33


25.61


26.49


25.20













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

15.88


19.98


21.70


20.24


23.07













Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)






















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

13.42


13.53


14.03


14.33


14.08













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

29.32


30.78


33.28


32.40


34.19













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

23.53


23.95


24.35


25.80


23.93













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

19.21


20.36


22.96


20.93


24.34













Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)

24.34


24.54


25.24


26.47


25.00













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

18.40


19.77


22.07


20.26


23.27













 

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)

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
















2024


2023


2022


2021













Volume - Million Barrels of Oil Equivalent - (a)



388.7


359.4


331.5


302.5













Total Operating Revenues and Other (b)



23,698


24,186


25,702


18,642


Total Operating Expenses (c)



15,616


14,583


15,736


12,540


Operating Income (Loss) (d)



8,082


9,603


9,966


6,102













Wellhead Revenues











Crude Oil and Condensate



13,921


13,748


16,367


11,125


Natural Gas Liquids



2,106


1,884


2,648


1,812


Natural Gas



1,551


1,744


3,781


2,444


Total Wellhead Revenues - (e)



17,578


17,376


22,796


15,381













Operating Costs











Lease and Well



1,572


1,454


1,331


1,135


Gathering, Processing and Transportation Costs (1)



1,722


1,620


1,587


1,422


General and Administrative (GAAP)



669


640


570


511


Less:  Severance Tax Consulting Fees



(10)


—


(16)


—


General and Administrative (Non-GAAP) (3)



659


640


554


511


Taxes Other Than Income (GAAP)



1,249


1,284


1,585


1,047


Add:  Severance Tax Refund



31


—


115


—


Taxes Other Than Income (Non-GAAP) (4)



1,280


1,284


1,700


1,047


Interest Expense, Net



138


148


179


178


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



5,350


5,146


5,252


4,293


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



5,371


5,146


5,351


4,293













Depreciation, Depletion and Amortization (DD&A)



4,108


3,492


3,542


3,651













Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)



9,458


8,638


8,794


7,944


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



9,479


8,638


8,893


7,944













Exploration Costs



174


181


159


154


Dry Hole Costs



14


1


45


71


Impairments



391


202


382


376


Total Exploration Costs (GAAP)



579


384


586


601


Less:  Certain Impairments (2)



(291)


(42)


(113)


(15)


Total Exploration Costs (Non-GAAP)



288


342


473


586













Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)



10,037


9,022


9,380


8,545


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



9,767


8,980


9,366


8,530













Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total  Exploration Costs (GAAP))



7,541


8,354


13,416


6,836


Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))



7,811


8,396


13,430


6,851


 

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)

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














2024


2023


2022


2021













Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)






















Composite Average Operating Revenues and Other per Boe - (b) / (a)



60.97


67.30


77.53


61.63


Composite Average Operating Expenses per Boe - (c) / (a)



40.18


40.58


47.47


41.46


Composite Average Operating Income (Loss) per Boe - (d) / (a)



20.79


26.72


30.06


20.17













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



45.22


48.34


68.77


50.84













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



13.76


14.31


15.84


14.19













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



31.46


34.03


52.93


36.65













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



24.33


24.03


26.53


26.26













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



20.89


24.31


42.24


24.58













Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)



25.82


25.10


28.30


28.25













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



19.40


23.24


40.47


22.59













Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)






















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



13.82


14.31


16.14


14.19













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



31.40


34.03


52.63


36.65













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



24.39


24.03


26.83


26.26













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



20.83


24.31


41.94


24.58













Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)



25.13


24.98


28.26


28.20













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



20.09


23.36


40.51


22.64




(1)

Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs.  This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

(2)

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 exploration 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).

(3)

EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring. 

(4)

EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring. 

 

Cision View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2024-results-announces-2025-capital-plan-302387958.html

SOURCE EOG Resources, Inc.

FAQ

What were EOG Resources' Q4 2024 earnings per share and free cash flow?

EOG reported Q4 2024 adjusted earnings of $2.74 per share and generated $1.3 billion in free cash flow.

How much did EOG return to shareholders in 2024?

EOG returned $5.3 billion to shareholders in 2024, including $2.1 billion in regular dividends and $3.2 billion in share repurchases.

What is EOG's production growth target for 2025?

EOG's 2025 capital plan targets 3% oil production growth and 6% total production growth.

How much did EOG reduce well costs in 2024?

EOG achieved a 6% reduction in average well costs across its multi-basin portfolio in 2024.

What is EOG's new quarterly dividend for 2025?

EOG declared a quarterly dividend of $0.975 per share, reflecting a 7% increase from 2024.

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Eog Res Inc

NYSE:EOG

EOG Rankings

#175 Ranked by Market Cap
#1016 Ranked by Dividends

EOG Latest News

Feb 11, 2025
Donald F. Textor to Retire from EOG Resources Board of Directors
Jan 16, 2025
EOG Resources Schedules Conference Call and Webcast of Fourth Quarter and Full Year 2024 Results for February 28, 2025
Dec 18, 2024
EOG Resources to Present at Upcoming Conference
Nov 7, 2024
EOG Resources Reports Third Quarter 2024 Results and Raises Regular Dividend 7%
Oct 29, 2024
EOG Resources to Present at Upcoming Conference

EOG Stock Data

69.47B
560.50M
0.31%
92.84%
2.39%
Oil & Gas E&P
Crude Petroleum & Natural Gas
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United States
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