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EOG Resources Reports Second Quarter 2022 Results, Declares $1.50 per Share Special Dividend and Reiterates Unchanged Full-Year 2022 Capital and Oil Volume Plan

August 4, 2022 4:15 PM EDT

HOUSTON, Aug. 4, 2022 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second quarter 2022 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 and ratio data

2Q 2022

1Q 2022

2Q 2021

GAAP

Total Revenue

7,407

3,983

4,139

Net Income

2,238

390

907

Net Income Per Share

3.81

0.67

1.55

Net Cash Provided by Operating Activities

2,048

828

1,559

Total Expenditures

1,521

1,144

1,089

Current and Long-Term Debt

5,091

5,099

5,125

Cash and Cash Equivalents

3,073

4,009

3,880

Debt-to-Total Capitalization

18.6 %

19.1 %

19.7 %

Non-GAAP

Adjusted Net Income

1,614

2,346

1,012

Adjusted Net Income Per Share

2.74

4.00

1.73

CFO before Changes in Working Capital

2,357

3,372

2,001

Capital Expenditures

1,071

1,009

937

Free Cash Flow

1,286

2,363

1,064

Net Debt

2,018

1,090

1,245

Net Debt-to-Total Capitalization

8.3 %

4.8 %

5.6 %

Second Quarter 2022 Highlights

  • Declared special dividend of $1.50 per share
  • Earned adjusted net income of $1.6 billion, or $2.74 per share
  • Generated $1.3 billion of free cash flow
  • Oil, NGL and natural gas production above guidance midpoints
  • Capital expenditures below low end of guidance range
  • Total per-unit cash operating costs below guidance midpoint
  • Deployed in-house developed continuous leak detection system
Second Quarter 2022 Highlights

Volumes and Capital Expenditures

Wellhead Volumes

2Q 2022

2Q 2022

Guidance

Midpoint

1Q 2022

2Q 2021

Crude Oil and Condensate (MBod)

464.1

458.5

450.1

448.6

Natural Gas Liquids (MBbld)

201.9

193.0

190.3

138.5

Natural Gas (MMcfd)

1,528

1,465

1,458

1,445

Total Crude Oil Equivalent (MBoed)

920.7

895.7

883.3

828.0

Capital Expenditures ($MM)

1,071

1,200

1,009

937

From Ezra Yacob, Chief Executive Officer

"EOG delivered another quarter of outstanding operating execution. Our second quarter performance is attributable to the dedication and persistence of our employees and the power of our high-quality inventory across our multi-basin portfolio.

"We are adding reserves at lower finding costs and in turn lowering the overall cost base of the company. The Delaware Basin remains the largest area of activity in the company and is delivering exceptional returns. The Eagle Ford also continues to deliver top-tier results while operating at a steady pace. Our emerging South Texas Dorado dry gas play and Powder River Basin Mowry and Niobrara combo plays are contributing to EOG's success today while laying the groundwork for years of future high-return investment. And our robust exploration pipeline of potential new plays promises to further raise the bar on our performance.

"Our performance this year proves that we have emerged from the downturn better than ever. The company is positioned to deliver significant value to shareholders with our low cost structure and increased exposure to oil and natural gas prices with the recent reductions in our hedge position. This is supported by an industry-leading balance sheet and a regular dividend that allow EOG to deliver significant value through the cycle.

"We are well positioned to carry this momentum into 2023. We have offset a significant portion of inflation this year and are working on plans to identify further cost savings next year. We continue to advance new technology and innovative projects to further lower our environmental footprint, such as an EOG-developed continuous leak detection system that is being deployed at our Delaware Basin facilities. Throughout the year and as we begin to plan for 2023 we remain focused on disciplined capital allocation. Our long-term vision is to be among the lowest cost, highest return and lowest emissions producers, playing a significant role in the long-term future of energy."

Second Quarter 2022 Financial Performance

Adjusted Earnings per Share 2Q 2022 vs 1Q 2022

Prices and HedgesCrude oil, NGL and natural gas prices increased significantly in 2Q compared with 1Q. Cash paid for hedge settlements in 2Q increased by $1.8 billion compared with 1Q, of which $1.3 billion related to the early termination of certain contracts.

VolumesTotal company crude oil production in 2Q of 464,100 Bopd was above the high end of the guidance range and 3% more than 1Q. NGL and natural gas production were each above the midpoint of the guidance ranges and increased 6% and 5%, respectively, compared with 1Q. Total company equivalent production increased 4% compared with 1Q.

Per-Unit Costs and OtherCash operating costs declined to $10.12 per BOE in 2Q compared with $10.24 per BOE in 1Q. Lower lease and well cost was the most significant contributor to the reduction. A higher DD&A rate offset the reduction in cash operating costs. Lower marketing margin (gathering, processing and marketing revenue less marketing costs) and higher taxes other than income reduced earnings from other sources in 2Q compared with 1Q.

Change in Cash 2Q 2022 vs 1Q 2022

Free Cash FlowEOG generated cash flow from operations before changes in working capital of $2.4 billion in 2Q. The company incurred $1.1 billion of cash capital expenditures, resulting in $1.3 billion of free cash flow.

Dividends and Bolt-on AcquisitionEOG paid $1.5 billion in dividends in 2Q, including $1.1 billion of special dividends. Acquisitions and divestitures in 2Q reduced cash by $0.2 billion, primarily related to a bolt-on acquisition in an exploration area and partially offset by sales of non-core assets.

Second Quarter 2022 Operating Performance

Lease and WellPer-unit LOE costs declined $0.13 in 2Q compared with 1Q and were within the guidance range. The divestiture of legacy gas assets in the Rocky Mountain area and overall efficiency improvements in the Delaware Basin were the largest contributors to the cost reduction.

Transportation, Gathering and ProcessingPer-unit transportation and G&P costs in 2Q were in-line with 1Q and slightly below the guidance midpoints.

General and AdministrativePer-unit G&A costs in 2Q were in-line with 1Q but significantly below the guidance midpoint. A transaction expected to occur in 2Q was not executed.

Depreciation, Depletion and Amortization Per-unit DD&A costs in 2Q were slightly above the guidance midpoint and increased 2% compared with 1Q. Facility additions and the divestiture of legacy gas assets contributed to the increase.

Special Dividend and Continuous Methane Monitoring

Special DividendThe Board of Directors today declared a special dividend of $1.50 per share on EOG's common stock. The special dividend will be payable September 29, 2022, to stockholders of record as of September 15, 2022. Consistent with its past practice for the third quarter regular dividend, the Board will consider the quarterly regular dividend in September.

EOG's iSenseSM Continuous Leak Detection SystemEOG has been evaluating continuous methane monitoring technology for several years and initiated a pilot project using an EOG-developed system about 18 months ago, named iSenseSM. The company tested iSenseSM against other monitoring solutions in use and available in the market. The testing confirmed that iSenseSM detects methane release events consistent with other commercial systems. iSenseSM is currently deployed in the Delaware Basin covering about 60% of production. The system will be deployed across additional sites in the Delaware Basin and other operating areas over the remainder of 2022 and in 2023.

As an in-house developed system, iSenseSM enables EOG to integrate the data it collects with existing operational data from EOG's other proprietary systems. This allows for the unique ability to analyze production and facility data to conduct root cause analysis, prioritize resources and dispatch repair measures. EOG expects to learn through analysis of the growing data set collected by iSenseSM how to design and build better facilities and continuously improve its infrastructure.

Second Quarter 2022 Results vs Guidance

(Unaudited) 

Crude Oil and Condensate Volumes (MBod)

2Q 2022

2Q 2022Guidance Midpoint

Variance

1Q 2022

4Q 2021

3Q 2021

2Q 2021

United States

463.5

458.0

5.5

449.4

449.7

448.3

446.9

Trinidad

0.6

0.5

0.1

0.7

0.9

1.2

1.7

Other International

0.0

0.0

0.0

0.0

0.0

0.0

0.0

Total

464.1

458.5

5.6

450.1

450.6

449.5

448.6

Natural Gas Liquids Volumes (MBbld)

Total

201.9

193.0

8.9

190.3

156.9

157.9

138.5

Natural Gas Volumes (MMcfd)

United States

1,324

1,280

44

1,249

1,328

1,210

1,199

Trinidad

204

185

19

209

206

212

233

Other International

0

0

0

0

0

0

13

Total

1,528

1,465

63

1,458

1,534

1,422

1,445

Total Crude Oil Equivalent Volumes (MBoed)

920.7

895.7

25.0

883.3

863.1

844.4

828.0

Total MMBoe

83.8

81.5

2.3

79.5

79.4

77.7

75.3

Benchmark Price

Oil (WTI) ($/Bbl)

108.42

94.38

77.17

70.55

66.06

Natural Gas (HH) ($/Mcf)

7.17

4.91

5.83

4.01

2.83

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

United States

2.84

2.80

0.04

1.64

1.14

0.33

0.10

Trinidad

(10.13)

(8.50)

(1.63)

(10.56)

(10.31)

(10.36)

(9.80)

Natural Gas Liquids - Realizations as % of WTI

39.0 %

40.0 %

(1.0 %)

42.1 %

52.4 %

53.5 %

44.1 %

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

United States

0.60

0.75

(0.15)

0.90

0.57

0.49

0.16

Natural Gas Realizations ($/Mcf)

Trinidad

3.42

3.40

0.02

3.36

3.48

3.39

3.37

Total Expenditures (GAAP) ($MM)

1,521

1,144

1,137

962

1,089

Capital Expenditures (non-GAAP) ($MM)

1,071

1,200

(129)

1,009

1,015

891

937

Operating Unit Costs ($/Boe)

Lease and Well

3.87

3.80

0.07

4.00

4.09

3.48

3.58

Transportation Costs

2.91

2.95

(0.04)

2.87

2.87

2.82

2.84

Gathering and Processing

1.81

1.90

(0.09)

1.81

1.85

1.87

1.70

General and Administrative

1.53

1.85

(0.32)

1.56

1.75

1.83

1.59

Cash Operating Costs

10.12

10.50

(0.38)

10.24

10.56

10.00

9.71

Depreciation, Depletion and Amortization

10.87

10.80

0.07

10.65

11.46

11.93

12.13

Expenses ($MM)

Exploration and Dry Hole

55

40

15

48

85

48

49

Impairment (GAAP)

91

55

206

82

44

Impairment (excluding certain impairments (non-GAAP))2

55

85

(30)

55

206

69

43

Capitalized Interest

7

8

(1)

8

9

8

8

Net Interest

48

48

0

48

38

48

45

Taxes Other Than Income (% of Wellhead Revenue)

7.3 %

7.0 %

0.3 %

7.4 %

6.8 %

6.8 %

6.9 %

Income Taxes

Effective Rate

22.3 %

22.5 %

(0.2 %)

21.7 %

20.5 %

23.4 %

19.3 %

Current Tax (Benefit) / Expense ($MM)

745

680

65

573

393

446

313

Third Quarter and Full-Year 2022 Guidance3

(Unaudited)

See "Endnotes" below for related discussion and definitions.

3Q 2022Guidance Range

FY 2022Guidance Range

2021 Actual

2020 Actual

Crude Oil and Condensate Volumes (MBod)

United States

456.0

-

465.0

458.0

-

463.0

443.4

408.1

Trinidad

0.0

-

1.0

0.4

-

0.6

1.5

1.0

Other International

0.0

-

0.0

0.0

-

0.0

0.1

0.1

Total

456.0

-

466.0

458.4

-

463.6

445.0

409.2

Natural Gas Liquids Volumes (MBbld)

Total

180.0

-

210.0

185.0

-

205.0

144.5

136.0

Natural Gas Volumes (MMcfd)

United States

1,250

-

1,350

1,270

-

1,350

1,210

1,040

Trinidad

135

-

165

175

-

185

217

180

Other International

0

-

0

0

-

0

9

32

Total

1,385

-

1,515

1,445

-

1,535

1,436

1,252

Crude Oil Equivalent Volumes (MBoed)

United States

844.3

-

900.0

854.7

-

893.0

789.6

717.5

Trinidad

22.5

-

28.5

29.6

-

31.4

37.7

30.9

Other International

0.0

-

0.0

0.0

-

0.0

1.6

5.4

Total

866.8

-

928.5

884.3

-

924.4

828.9

753.8

Benchmark Price

Oil (WTI) ($/Bbl)

67.96

39.40

Natural Gas (HH) ($/Mcf)

3.85

2.08

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

United States

3.00

-

4.00

2.40

-

2.80

0.58

(0.75)

Trinidad

(10.00)

-

(8.00)

(11.00)

-

(9.00)

(11.70)

(9.20)

Natural Gas Liquids - Realizations as % of WTI

Total

33.0 %

-

43.0 %

36.0 %

-

42.0 %

50.5 %

34.0 %

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

United States

0.65

-

1.05

0.85

-

1.00

1.03

(0.47)

Natural Gas Realizations6 ($/Mcf)

Trinidad

7.00

-

7.60

4.00

-

4.50

3.40

2.57

Total Expenditures (GAAP) ($MM)

4,255

4,113

Capital Expenditures7 (non-GAAP) ($MM)

1,150

-

1,350

4,300

-

4,700

3,755

3,344

Operating Unit Costs ($/Boe)

Lease and Well

3.50

-

4.20

3.70

-

4.00

3.75

3.85

Transportation Costs

2.70

-

3.10

2.80

-

3.00

2.85

2.66

Gathering and Processing

1.75

-

1.95

1.80

-

1.90

1.85

1.66

General and Administrative

1.90

-

2.20

1.60

-

1.80

1.69

1.75

Cash Operating Costs

9.85

-

11.45

9.90

-

10.70

10.14

9.92

Depreciation, Depletion and Amortization

10.55

-

11.15

10.65

-

10.95

12.07

12.32

Expenses ($MM)

Exploration and Dry Hole

45

-

55

170

-

210

225

159

Impairment (GAAP)

376

2,100

Impairment (excluding certain impairments (non-GAAP))2

50

-

90

210

-

290

361

232

Capitalized Interest

5

-

10

25

-

35

33

31

Net Interest

42

-

47

180

-

190

178

205

Taxes Other Than Income (% of Wellhead Revenue)

6.0 %

-

8.0 %

7.0 %

-

8.0 %

6.8 %

6.6 %

Income Taxes

Effective Rate

20.0 %

-

25.0 %

20.0 %

-

25.0 %

21.4 %

18.2 %

Current Tax (Benefit) / Expense ($MM)

410

-

510

2,300

-

2,500

1,393

(61)

 

Second Quarter 2022 Results WebcastFriday, August 5, 2022, 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 EOGEOG 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 ContactsDavid Streit 713‐571‐4902 Neel Panchal 713‐571‐4884

Media ContactKimberly Ehmer 713‐571‐4676

Endnotes

1)

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

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 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).

3)

The forecast items for the third quarter and full year 2022 set forth above for EOG Resources, Inc. (EOG) are  based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

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 simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

6)

The third quarter 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of approximately $3.50/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited (NGC).

7)

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

 

Glossary

Acq

Acquisitions

ATROR

After-tax rate of return

Bbl

Barrel

Bn

Billion

Boe

Barrels of oil equivalent

Bopd

Barrels of oil per day

CAGR

Compound annual growth rate

Capex

Capital expenditures

CFO

Cash flow provided by operating activities before changes in working capital

CO2e

Carbon dioxide equivalent

DD&A

Depreciation, Depletion and Amortization

Disc

Discoveries

Divest

Divestitures

EPS

Earnings per share

Ext

Extensions

G&A

General and administrative expense

G&P

Gathering and processing expense

GHG

Greenhouse gas

HH

Henry Hub

LOE

Lease operating expense, or lease and well expense

MBbld

Thousand barrels of liquids per day

MBod

Thousand barrels of oil per day

MBoe

Thousand barrels of oil equivalent

MBoed

Thousand barrels of oil equivalent per day

Mcf

Thousand cubic feet of natural gas

MMBoe

Million barrels of oil equivalent

MMcfd

Million cubic feet of natural gas per day

NGLs

Natural gas liquids

OTP

Other than price

NYMEX

U.S. New York Mercantile Exchange

QoQ

Quarter over quarter

Trans

Transportation expense

USD

United States dollar

WTI

West Texas Intermediate

YoY

Year over year

$MM

Million United States dollars

$/Bbl

U.S. Dollars per barrel

$/Boe

U.S. Dollars per barrel of oil equivalent

$/Mcf

U.S. Dollars per thousand cubic feet

This press release may include forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, 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 operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward-looking statements.Forward‐looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward‐looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward‐looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward‐looking, non‐GAAP financial measures, such as free cash flow and cash flow from operations before changes in working capital, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward‐looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward‐looking    GAAP measures, such as future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward‐looking, non‐GAAP financial measures to the respective most directly comparable forward‐looking GAAP financial measures. Management believes these forward‐looking, non‐GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward‐looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates.  Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's  forward‐looking statements include, among others:

  • the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (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, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
  • the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, 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;
  • the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
  • the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
  • the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax 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 and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
  • EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
  • the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
  • competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
  • the availability and cost of, and competition in the oil and gas exploration and production industry for, employees and other personnel, facilities, equipment, materials (such as water, sand and tubulars) and services;
  • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
  • weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
  • the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
  • EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
  • the extent to which EOG is successful in its completion of planned asset dispositions;
  • the extent and effect of any hedging activities engaged in by EOG;
  • the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
  • the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
  • geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
  • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
  • acts of war and terrorism and responses to these acts; and
  • the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2021 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on  Form 10‐K for the fiscal year ended December 31, 2021, available from EOG at P.O. Box 4362, Houston, Texas 77210‐4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC's website at www.sec.gov. In addition, reconciliation schedules and definitions for non‐GAAP financial measures can be found on the EOG website at www.eogresources.com.

Income Statements

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

2Q 2022

1Q 2022

2Q 2021

YTD 2022

YTD 2021

Operating Revenues and Other

Crude Oil and Condensate

4,699

3,889

2,699

8,588

4,950

Natural Gas Liquids

777

681

367

1,458

681

Natural Gas

1,000

716

404

1,716

1,029

Losses on Mark-to-Market Financial      Commodity Derivative Contracts

(1,377)

(2,820)

(427)

(4,197)

(794)

Gathering, Processing and Marketing

2,169

1,469

1,022

3,638

1,870

Gains on Asset Dispositions, Net

97

25

51

122

45

Other, Net

42

23

23

65

52

Total

7,407

3,983

4,139

11,390

7,833

Operating Expenses

Lease and Well

324

318

270

642

540

Transportation Costs

244

228

214

472

416

Gathering and Processing Costs

152

144

128

296

267

Exploration Costs

35

45

35

80

68

Dry Hole Costs

20

3

13

23

24

Impairments

91

55

44

146

88

Marketing Costs

2,127

1,283

991

3,410

1,829

Depreciation, Depletion and Amortization

911

847

914

1,758

1,814

General and Administrative

128

124

120

252

230

Taxes Other Than Income

472

390

239

862

454

Total

4,504

3,437

2,968

7,941

5,730

Operating Income

2,903

546

1,171

3,449

2,103

Other Income (Expense), Net

27

(1)

(2)

26

(6)

Income Before Interest Expense and Income      Taxes

2,930

545

1,169

3,475

2,097

Interest Expense, Net

48

48

45

96

92

Income Before Income Taxes

2,882

497

1,124

3,379

2,005

Income Tax Provision

644

107

217

751

421

Net Income

2,238

390

907

2,628

1,584

Dividends Declared per Common Share

2.5500

1.7500

1.4125

4.3000

1.8250

Net Income Per Share

Basic

3.84

0.67

1.56

4.52

2.73

Diluted

3.81

0.67

1.55

4.48

2.72

Average Number of Common Shares

Basic

583

582

580

582

580

Diluted

588

586

584

587

583

Wellhead Volumes and Prices

(Unaudited)

2Q 2022

2Q 2021

% Change

1Q 2022

YTD 2022

YTD 2021

% Change

Crude Oil and Condensate Volumes      (MBbld) (A)

United States

463.5

446.9

4 %

449.4

456.5

437.8

4 %

Trinidad

0.6

1.7

-65 %

0.7

0.7

2.0

-65 %

Other International (B)

Total

464.1

448.6

3 %

450.1

457.2

439.8

4 %

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

United States

$ 111.26

66.16

68 %

$    96.02

$   103.80

$      62.22

67 %

Trinidad

98.29

56.26

75 %

83.82

90.33

52.57

72 %

Other International (B)

55.56

-100 %

42.36

-100 %

Composite

111.25

66.12

68 %

96.00

103.78

62.18

67 %

58.02

Natural Gas Liquids Volumes (MBbld) (A)

United States

201.9

138.5

46 %

190.3

196.1

131.5

49 %

Total

201.9

138.5

46 %

190.3

196.1

131.5

49 %

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

United States

$  42.28

$  29.15

45 %

$    39.77

$      41.07

$      28.62

43 %

Composite

42.28

29.15

45 %

39.77

41.07

28.62

43 %

Natural Gas Volumes (MMcfd) (A)

United States

1,324

1,199

10 %

1,249

1,287

1,150

12 %

Trinidad

204

233

-12 %

209

206

225

-8 %

Other International (B)

13

-100 %

19

-100 %

Total

1,528

1,445

6 %

1,458

1,493

1,394

7 %

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

United States

$     7.77

$     2.99

160 %

$       5.81

$        6.83

$        4.19

63 %

Trinidad

3.42

3.37

2 %

3.36

3.39

3.37

0 %

Other International (B)

5.69

-100 %

5.67

-100 %

Composite

7.19

3.07

134 %

5.46

6.35

4.08

56 %

Crude Oil Equivalent Volumes (MBoed) (D)

United States

886.1

785.2

13 %

847.8

867.1

761.0

14 %

Trinidad

34.6

40.6

-15 %

35.5

35.0

39.5

-11 %

Other International (B)

2.2

-100 %

3.1

-100 %

Total

920.7

828.0

11 %

883.3

902.1

803.6

12 %

Total MMBoe (D)

83.8

75.3

11 %

79.5

163.3

145.4

12 %

(A)

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

(B) 

Other International includes EOG's China and Canada operations.  The China operations were sold in the second quarter of 2021.

(C)

Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022).

(D)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

Balance Sheets

In millions of USD, except share data (Unaudited)

June 30,

December 31,

2022

2021

Current Assets

Cash and Cash Equivalents

3,073

5,209

Accounts Receivable, Net

3,735

2,335

Inventories

739

584

Assets from Price Risk Management Activities

1

Other

605

456

Total

8,153

8,584

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method)

66,098

67,644

Other Property, Plant and Equipment

4,862

4,753

Total Property, Plant and Equipment

70,960

72,397

Less:  Accumulated Depreciation, Depletion and Amortization

(42,113)

(43,971)

Total Property, Plant and Equipment, Net

28,847

28,426

Deferred Income Taxes

12

11

Other Assets

1,127

1,215

Total Assets

38,139

38,236

Current Liabilities

Accounts Payable

2,896

2,242

Accrued Taxes Payable

594

518

Dividends Payable

437

436

Liabilities from Price Risk Management Activities

79

269

Current Portion of Long-Term Debt

1,282

37

Current Portion of Operating Lease Liabilities

216

240

Other

264

300

Total

5,768

4,042

Long-Term Debt

3,809

5,072

Other Liabilities

2,067

2,193

Deferred Income Taxes

4,183

4,749

Commitments and Contingencies

Stockholders' Equity

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 586,391,670Shares Issued at June 30, 2022 and 585,521,512 Shares Issued at December 31, 2021

206

206

Additional Paid in Capital

6,128

6,087

Accumulated Other Comprehensive Loss

(12)

(12)

Retained Earnings

16,028

15,919

Common Stock Held in Treasury, 344,705 Shares at June 30, 2022 and 257,268Shares at December 31, 2021

(38)

(20)

Total Stockholders' Equity

22,312

22,180

Total Liabilities and Stockholders' Equity

38,139

38,236

 

Cash Flows Statements

In millions of USD (Unaudited)

2Q 2022

2Q 2021

1Q 2022

YTD 2022

YTD 2021

Cash Flows from Operating Activities

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

Net Income

2,238

907

390

2,628

1,584

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization

911

914

847

1,758

1,814

Impairments

91

44

55

146

88

Stock-Based Compensation Expenses

30

31

35

65

66

Deferred Income Taxes

(102)

(97)

(465)

(567)

(133)

Gains on Asset Dispositions, Net

(97)

(51)

(25)

(122)

(45)

Other, Net

(16)

6

6

(10)

13

Dry Hole Costs

20

13

3

23

24

Mark-to-Market Financial Commodity Derivative Contracts Total Losses

1,377

427

2,820

4,197

794

Net Cash Payments for Settlements of Financial      Commodity Derivative Contracts

(2,114)

(193)

(296)

(2,410)

(223)

Other, Net

19

2

21

1

Changes in Components of Working Capital and Other      Assets and Liabilities

Accounts Receivable

(522)

(186)

(878)

(1,400)

(494)

Inventories

(157)

37

(14)

(171)

101

Accounts Payable

259

11

130

389

183

Accrued Taxes Payable

(536)

(163)

613

77

80

Other Assets

71

(119)

(213)

(142)

(222)

Other Liabilities

433

32

(2,250)

(1,817)

(57)

Changes in Components of Working Capital Associated      with Investing Activities

143

(54)

68

211

(145)

Net Cash Provided by Operating Activities

2,048

1,559

828

2,876

3,429

Investing Cash Flows

Additions to Oil and Gas Properties

(1,349)

(968)

(939)

(2,288)

(1,843)

Additions to Other Property, Plant and Equipment

(75)

(55)

(70)

(145)

(97)

Proceeds from Sales of Assets

110

141

121

231

146

Other Investing Activities

(30)

(30)

Changes in Components of Working Capital Associated      with Investing Activities

(143)

54

(68)

(211)

145

Net Cash Used in Investing Activities

(1,487)

(828)

(956)

(2,443)

(1,649)

Financing Cash Flows

Long-Term Debt Repayments

(750)

Dividends Paid

(1,486)

(239)

(1,023)

(2,509)

(458)

Treasury Stock Purchased

(15)

(2)

(43)

(58)

(12)

Proceeds from Stock Options Exercised and Employee      Stock Purchase Plan

13

9

4

17

9

Repayment of Finance Lease Liabilities

(9)

(9)

(10)

(19)

(18)

Net Cash Used in Financing Activities

(1,497)

(241)

(1,072)

(2,569)

(1,229)

Effect of Exchange Rate Changes on Cash

2

Increase (Decrease)  in Cash and Cash Equivalents

(936)

492

(1,200)

(2,136)

551

Cash and Cash Equivalents at Beginning of Period

4,009

3,388

5,209

5,209

3,329

Cash and Cash Equivalents at End of Period

3,073

3,880

4,009

3,073

3,880

  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 Working Capital, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics.

A reconciliation of each of these measures to their most directly comparable GAAP financial measure 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 and operating 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 and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods.

The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), 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. 

Adjusted Net Income (Loss)

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

The following tables adjust the reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets) - see "Revenues, Costs and Margins Per Barrel of Oil Equivalent" below for additional related discussion) 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.

2Q 2022

BeforeTax

Income Tax Impact

AfterTax

Diluted Earnings per Share

Reported Net Income (GAAP)

2,882

(644)

2,238

3.81

Adjustments:

Losses on Mark-to-Market Financial Commodity Derivative Contracts

1,377

(299)

1,078

1.82

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

(2,114)

459

(1,655)

(2.81)

Less: Gains on Asset Dispositions, Net

(97)

21

(76)

(0.13)

Add: Certain Impairments

36

(7)

29

0.05

Adjustments to Net Income

(798)

174

(624)

(1.07)

Adjusted Net Income (Non-GAAP)

2,084

(470)

1,614

2.74

Average Number of Common Shares (Non-GAAP)

Basic

583

Diluted

588

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss)  (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period.  For the second quarter of 2022, such amount was $2,114 million, of which $1,328 million was related to the early termination of certain contracts.  See "Financial Commodity Derivative Contracts" below for further discussion.

Adjusted Net Income (Loss)(Continued)

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

1Q 2022

BeforeTax

Income TaxImpact

AfterTax

Diluted Earnings per Share

Reported Net Income (GAAP)

497

(107)

390

0.67

Adjustments:

Losses on Mark-to-Market Financial Commodity Derivative Contracts

2,820

(612)

2,208

3.76

Net Cash Payments for Settlements of Financial Commodity Derivative      Contracts

(296)

64

(232)

(0.40)

Less: Gains on Asset Dispositions, Net

(25)

5

(20)

(0.03)

Adjustments to Net Income

2,499

(543)

1,956

3.33

Adjusted Net Income (Non-GAAP)

2,996

(650)

2,346

4.00

Average Number of Common Shares (Non-GAAP)

Basic

582

Diluted

586

 

2Q 2021

BeforeTax

Income Tax Impact

AfterTax

Diluted Earnings per Share

Reported Net Income (GAAP)

1,124

(217)

907

1.55

Adjustments:

Losses on Mark-to-Market Financial Commodity Derivative Contracts

427

(93)

334

0.58

Net Cash Payments for Settlements of Financial Commodity Derivative      Contracts

(193)

42

(151)

(0.26)

Less: Gains on Asset Dispositions, Net

(51)

17

(34)

(0.06)

Add: Certain Impairments

1

1

Less: Tax Benefits Related to Exiting Canada Operations

(45)

(45)

(0.08)

Adjustments to Net Income

184

(79)

105

0.18

Adjusted Net Income (Non-GAAP)

1,308

(296)

1,012

1.73

Average Number of Common Shares (Non-GAAP)

Basic

580

Diluted

584

 

 

YTD 2022

BeforeTax

Income Tax Impact

AfterTax

Diluted Earnings per Share

Reported Net Income (GAAP)

3,379

(751)

2,628

4.48

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts

4,197

(911)

3,286

5.59

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

(2,410)

523

(1,887)

(3.21)

Less: Gains on Asset Dispositions, Net

(122)

26

(96)

(0.16)

Add: Certain Impairments

36

(7)

29

0.05

Adjustments to Net Income

1,701

(369)

1,332

2.27

Adjusted Net Income (Non-GAAP)

5,080

(1,120)

3,960

6.75

Average Number of Common Shares (Non-GAAP)

Basic

582

Diluted

587

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period.  For the first six months of 2022, such amount was $2,410 million, of which $1,328 million was related to the early termination of certain contracts.  See "Financial Commodity Derivative Contracts" below for further discussion.

 

YTD 2021

BeforeTax

Income Tax Impact

AfterTax

Diluted Earnings per Share

Reported Net Income (GAAP)

2,005

(421)

1,584

2.72

Adjustments:

Losses on Mark-to-Market Commodity Derivative Contracts

794

(174)

620

1.07

Net Cash Payments from Settlements of Commodity Derivative Contracts

(223)

49

(174)

(0.30)

Less: Gains on Asset Dispositions, Net

(45)

16

(29)

(0.05)

Add: Certain Impairments

2

2

Less: Tax Benefits Related to Exiting Canada Operations

(45)

(45)

(0.08)

Adjustments to Net Income

528

(154)

374

0.64

Adjusted Net Income (Non-GAAP)

2,533

(575)

1,958

3.36

Average Number of Common Shares (Non-GAAP)

Basic

580

Diluted

583

 

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)

1Q 2022 Adjusted Net Income per Share (Non-GAAP)

4.00

Realized Price

2Q 2022 Composite Average Wellhead Revenue per Boe

77.29

Less:  1Q 2022 Composite Average Welhead Revenue per Boe

(66.50)

Subtotal

10.79

Multiplied by: 2Q 2022 Crude Oil Equivalent Volumes (MMBoe)

83.8

Total Change in Revenue

904

Less: Income Tax Benefit (Provision) Imputed (based on 23%)

(208)

Change in Net Income

696

Change in Diluted Earnings per Share

1.18

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

2Q 2022 Net Cash Received from (Payments for) Settlement of Financial      Commodity Derivative Contracts

(2,114)

Less:  Income Tax Benefit (Provision)

459

After Tax - (a)

(1,655)

1Q 2022 Net Cash Received from (Payments for) Settlement of Financial      Commodity Derivative Contracts

(296)

Less:  Income Tax Benefit (Provision)

64

After Tax - (b)

(232)

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

(1,423)

Change in Diluted Earnings per Share

(2.42)

Wellhead Volumes

2Q 2022 Crude Oil Equivalent Volumes (MMBoe)

83.8

Less:  1Q 2022 Crude Oil Equivalent Volumes (MMBoe)

(79.5)

Subtotal

4.3

Multiplied by:  2Q 2022 Composite Average Margin per Boe (Non-GAAP) (Including      Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil      Equivalent" schedule)

48.79

Change in Revenue

209

Less:  Income Tax Benefit (Provision) Imputed (based on 23%)

(48)

Change in Net Income

161

Change in Diluted Earnings per Share

0.27

Operating Cost per Boe

1Q 2022 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration      Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"      schedule)

27.70

Less:  1Q 2022 Taxes Other Than Income

(4.91)

Less:  2Q 2022 Total Operating Cost per Boe (Non-GAAP) (including Total      Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil      Equivalent" schedule)

(28.50)

Add: 2Q 2022 Taxes Other Than Income

5.63

Subtotal

(0.08)

Multiplied by:  2Q 2022 Crude Oil Equivalent Volumes (MMBoe)

83.8

Change in Before-Tax Net Income

(7)

Less:  Income Tax Benefit (Provision) Imputed (based on 23%)

2

Change in Net Income

(5)

Change in Diluted Earnings per Share

(0.01)

Other (1)

(0.28)

2Q 2022 Adjusted Net Income per Share (Non-GAAP)

2.74

2Q 2022 Average Number of Common Shares (Non-GAAP) - Diluted

588

(1)

Includes gathering, processing and marketing revenue, other revenue, marketing costs, taxes other than income, other income (expense), interest expense and the effect 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 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 and Financing 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 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.  To further the comparability of EOG's financial results with those of EOG's peer companies and other companies in the industry, EOG now utilizes Cash Flow from Operations Before Working Capital (Non-GAAP), instead of Discretionary Cash Flow (Non-GAAP), in calculating its Free Cash Flow (Non-GAAP).  Accordingly, Free Cash Flow (Non-GAAP) for the three-month and six-month periods ended June 30, 2022 have been calculated on such basis, and the calculations of Free Cash Flow (Non-GAAP) for each of the prior periods shown have been revised and conformed.

2Q 2022

1Q 2022

4Q 2021

3Q 2021

2Q 2021

Net Cash Provided by Operating Activities (GAAP)

2,048

828

3,166

2,196

1,559

Adjustments:

Changes in Components of Working Capital and      Other Assets and Liabilities

Accounts Receivable

522

878

182

145

186

Inventories

157

14

108

6

(37)

Accounts Payable

(259)

(130)

(341)

68

(11)

Accrued Taxes Payable

536

(613)

(26)

(206)

163

Other Assets

(71)

213

81

(167)

119

Other Liabilities

(433)

2,250

(201)

260

(32)

Changes in Components of Working Capital      Associated with Investing Activities

(143)

(68)

100

(45)

54

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

2,357

3,372

3,069

2,257

2,001

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

2,357

3,372

3,069

2,257

2,001

Less:

Total Capital Expenditures (Non-GAAP) (a)

(1,071)

(1,009)

(1,015)

(891)

(937)

Free Cash Flow (Non-GAAP)

1,286

2,363

2,054

1,366

1,064

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

2Q 2022

1Q 2022

4Q 2021

3Q 2021

2Q 2021

Total Expenditures (GAAP)

1,521

1,144

1,137

962

1,089

Less:

Asset Retirement Costs

(43)

(27)

(71)

(8)

(31)

Non-Cash Acquisition Costs of Unproved      Properties

(21)

(58)

(8)

(15)

Non-Cash Finance Leases

Acquisition Costs of Proved Properties

(351)

(5)

(1)

(4)

(86)

Exploration Costs

(35)

(45)

(42)

(44)

(35)

Total Capital Expenditures (Non-GAAP)

1,071

1,009

1,015

891

937

Cash Flow from Operations and Free Cash Flow(Continued)

In millions of USD (Unaudited)

YTD 2022

YTD 2021

Net Cash Provided by Operating Activities (GAAP)

2,876

3,429

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

1,400

494

Inventories

171

(101)

Accounts Payable

(389)

(183)

Accrued Taxes Payable

(77)

(80)

Other Assets

142

222

Other Liabilities

1,817

57

Changes in Components of Working Capital Associated with Investing Activities

(211)

145

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

5,729

3,983

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

5,729

3,983

Less:

Total Capital Expenditures (Non-GAAP) (a)

(2,080)

(1,849)

Free Cash Flow (Non-GAAP)

3,649

2,134

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

YTD 2022

YTD 2021

Total Expenditures (GAAP)

2,665

2,156

Less:

Asset Retirement Costs

(70)

(48)

Non-Cash Acquisition Costs of Unproved Properties

(79)

(22)

Non-Cash Finance Leases

(74)

Acquisition Costs of Proved Properties

(356)

(95)

Exploration Costs

(80)

(68)

Total Capital Expenditures (Non-GAAP)

2,080

1,849

Cash Flow from Operations and Free Cash Flow(Continued)

In millions of USD (Unaudited)

FY 2021

FY 2020

FY 2019

Net Cash Provided by Operating Activities (GAAP)

8,791

5,008

8,163

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

821

(467)

92

Inventories

13

(123)

(90)

Accounts Payable

(456)

795

(169)

Accrued Taxes Payable

(312)

49

(40)

Other Assets

136

(325)

(358)

Other Liabilities

116

(8)

57

Changes in Components of Working Capital Associated with Investing and Financing      Activities

200

(75)

115

Other Non-Current Income Taxes - Net Receivable

113

239

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

9,309

4,967

8,009

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

9,309

4,967

8,009

Less:

Total Capital Expenditures (Non-GAAP) (a)

(3,755)

(3,344)

(6,094)

Free Cash Flow (Non-GAAP)

5,554

1,623

1,915

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

Total Expenditures (GAAP)

4,255

4,113

6,900

Less:

Asset Retirement Costs

(127)

(117)

(186)

Non-Cash Expenditures of Other Property, Plant and Equipment

(2)

Non-Cash Acquisition Costs of Unproved Properties

(45)

(197)

(98)

Non-Cash Finance Leases

(74)

(174)

Acquisition Costs of Proved Properties

(100)

(135)

(380)

Exploration Costs

(154)

(146)

(140)

Total Capital Expenditures (Non-GAAP)

3,755

3,344

6,094

Cash Flow from Operations and Free Cash Flow(Continued)

In millions of USD (Unaudited)

FY 2018

FY 2017

FY 2016

Net Cash Provided by Operating Activities (GAAP)

7,769

4,265

2,359

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

368

392

233

Inventories

395

175

(171)

Accounts Payable

(439)

(324)

74

Accrued Taxes Payable

92

64

(93)

Other Assets

125

659

41

Other Liabilities

(11)

90

16

Changes in Components of Working Capital Associated with Investing and Financing      Activities

(301)

(90)

156

Other Non-Current Income Taxes - Net (Payable) Receivable

149

(513)

Excess Tax Benefits from Stock-Based Compensation

30

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

8,147

4,718

2,645

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

8,147

4,718

2,645

Less:

Total Capital Expenditures (Non-GAAP) (a)

(6,023)

(4,083)

(2,581)

Free Cash Flow (Non-GAAP)

2,124

635

64

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

Total Expenditures (GAAP)

6,706

4,613

6,554

Less:

Asset Retirement Costs

(70)

(56)

20

Non-Cash Expenditures of Other Property, Plant and Equipment

(1)

(17)

Non-Cash Acquisition Costs of Unproved Properties

(291)

(256)

(3,102)

Non-Cash Finance Leases

(48)

Acquisition Costs of Proved Properties

(124)

(73)

(749)

Exploration Costs

(149)

(145)

(125)

Total Capital Expenditures (Non-GAAP)

6,023

4,083

2,581

Total Expenditures

In millions of USD (Unaudited)

2Q 2022

1Q 2022

4Q2021

3Q 2021

2Q 2021

YTD2022

YTD 2021

Exploration and Development Drilling

866

813

767

653

711

1,679

1,444

Facilities

90

109

118

100

105

199

187

Leasehold Acquisitions

34

64

21

90

46

98

104

Property Acquisitions

351

5

1

4

86

356

95

Capitalized Interest

7

8

9

9

7

15

15

Subtotal

1,348

999

916

856

955

2,347

1,845

Exploration Costs

35

45

42

44

35

80

68

Dry Hole Costs

20

3

43

4

13

23

24

Exploration and Development      Expenditures

1,403

1,047

1,001

904

1,003

2,450

1,937

Asset Retirement Costs

43

27

71

8

31

70

48

Total Exploration and Development      Expenditures

1,446

1,074

1,072

912

1,034

2,520

1,985

Other Property, Plant and Equipment

75

70

65

50

55

145

171

Total Expenditures

1,521

1,144

1,137

962

1,089

2,665

2,156

Total Expenditures(Continued)

In millions of USD (Unaudited)

FY 2021

FY 2020

FY 2019

FY 2018

FY 2017

FY 2016

Exploration and Development Drilling

2,864

2,664

4,951

4,935

3,132

1,957

Facilities

405

347

629

625

575

375

Leasehold Acquisitions

215

265

276

488

427

3,217

Property Acquisitions

100

135

380

124

73

749

Capitalized Interest

33

31

38

24

27

31

Subtotal

3,617

3,442

6,274

6,196

4,234

6,329

Exploration Costs

154

146

140

149

145

125

Dry Hole Costs

71

13

28

5

5

11

Exploration and Development Expenditures

3,842

3,601

6,442

6,350

4,384

6,465

Asset Retirement Costs

127

117

186

70

56

(20)

Total Exploration and Development Expenditures

3,969

3,718

6,628

6,420

4,440

6,445

Other Property, Plant and Equipment

286

395

272

286

173

109

Total Expenditures

4,255

4,113

6,900

6,706

4,613

6,554

 

EBITDAX and Adjusted EBITDAX

In millions of USD (Unaudited)

The following table adjusts the reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts by eliminating the unrealized Mark-to-Market (MTM) (Gains) Losses from these transactions and to eliminate the (Gains) Losses on Asset Dispositions (Net).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match 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.

2Q 2022

2Q 2021

YTD 2022

YTD 2021

Net Income (GAAP)

2,238

907

2,628

1,584

Adjustments:

Interest Expense, Net

48

45

96

92

Income Tax Provision

644

217

751

421

Depreciation, Depletion and Amortization

911

914

1,758

1,814

Exploration Costs

35

35

80

68

Dry Hole Costs

20

13

23

24

Impairments

91

44

146

88

EBITDAX (Non-GAAP)

3,987

2,175

5,482

4,091

Losses on MTM Financial Commodity Derivative Contracts

1,377

427

4,197

794

Net Cash Payments for Settlements of Commodity Derivative Contracts

(2,114)

(193)

(2,410)

(223)

Gains on Asset Dispositions, Net

(97)

(51)

(122)

(45)

Adjusted EBITDAX (Non-GAAP)

3,153

2,358

7,147

4,617

Definitions

EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments

 Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)

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.

June 30,

2022

March 31,

2022

Total Stockholders' Equity - (a)

22,312

21,540

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

5,091

5,099

Less: Cash

(3,073)

(4,009)

Net Debt (Non-GAAP) - (c)

2,018

1,090

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

27,403

26,639

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

24,330

22,630

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

18.6 %

19.1 %

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

8.3 %

4.8 %

Net Debt-to-Total Capitalization Ratio(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, 2021

September 30,

2021

June 30,

2021

March 31,

2021

Total Stockholders' Equity - (a)

22,180

21,765

20,881

20,762

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

5,109

5,117

5,125

5,133

Less: Cash

(5,209)

(4,293)

(3,880)

(3,388)

Net Debt (Non-GAAP) - (c)

(100)

824

1,245

1,745

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

27,289

26,882

26,006

25,895

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

22,080

22,589

22,126

22,507

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

18.7 %

19.0 %

19.7 %

19.8 %

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

-0.5 %

3.6 %

5.6 %

7.8 %

Net Debt-to-Total Capitalization Ratio(Continued)

In millions of USD, except ratio data (Unaudited)

December 31,

2020

September 30,

2020

June 30,

2020

March 31,

2020

Total Stockholders' Equity - (a)

20,302

20,148

20,388

21,471

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

5,816

5,721

5,724

5,222

Less: Cash

(3,329)

(3,066)

(2,417)

(2,907)

Net Debt (Non-GAAP) - (c)

2,487

2,655

3,307

2,315

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

26,118

25,869

26,112

26,693

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

22,789

22,803

23,695

23,786

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

22.3 %

22.1 %

21.9 %

19.6 %

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

10.9 %

11.6 %

14.0 %

9.7 %

Net Debt-to-Total Capitalization Ratio(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, 2019

September 30, 2019

June 30,

2019

March 31,

2019

Total Stockholders' Equity - (a)

21,641

21,124

20,630

19,904

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

5,175

5,177

5,179

6,081

Less: Cash

(2,028)

(1,583)

(1,160)

(1,136)

Net Debt (Non-GAAP) - (c)

3,147

3,594

4,019

4,945

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

26,816

26,301

25,809

25,985

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

24,788

24,718

24,649

24,849

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

19.3 %

19.7 %

20.1 %

23.4 %

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

12.7 %

14.5 %

16.3 %

19.9 %

Net Debt-to-Total Capitalization Ratio(Continued)

In millions of USD, except ratio data (Unaudited)

December 31,

2018

September 30,

2018

June 30,

2018

March 31,

2018

Total Stockholders' Equity - (a)

19,364

18,538

17,452

16,841

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

6,083

6,435

6,435

6,435

Less: Cash

(1,556)

(1,274)

(1,008)

(816)

Net Debt (Non-GAAP) - (c)

4,527

5,161

5,427

5,619

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

25,447

24,973

23,887

23,276

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

23,891

23,699

22,879

22,460

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

23.9 %

25.8 %

26.9 %

27.6 %

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

18.9 %

21.8 %

23.7 %

25.0 %

Net Debt-to-Total Capitalization Ratio(Continued)

In millions of USD, except ratio data (Unaudited)

December 31,

2017

September 30,

2017

June 30,

2017

March 31,

2017

Total Stockholders' Equity - (a)

16,283

13,922

13,902

13,928

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

6,387

6,387

6,987

6,987

Less: Cash

(834)

(846)

(1,649)

(1,547)

Net Debt (Non-GAAP) - (c)

5,553

5,541

5,338

5,440

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

22,670

20,309

20,889

20,915

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

21,836

19,463

19,240

19,368

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

28.2 %

31.4 %

33.4 %

33.4 %

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

25.4 %

28.5 %

27.7 %

28.1 %

Net Debt-to-Total Capitalization Ratio(Continued)

In millions of USD, except ratio data (Unaudited)

December 31, 2016

September 30, 2016

June 30,

2016

March 31,

2016

December 31,

2015

Total Stockholders' Equity - (a)

13,982

11,798

12,057

12,405

12,943

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

6,986

6,986

6,986

6,986

6,656

Less: Cash

(1,600)

(1,049)

(780)

(668)

(719)

Net Debt (Non-GAAP) - (c)

5,386

5,937

6,206

6,318

5,937

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

20,968

18,784

19,043

19,391

19,599

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

19,368

17,735

18,263

18,723

18,880

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

33.3 %

37.2 %

36.7 %

36.0 %

34.0 %

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

27.8 %

33.5 %

34.0 %

33.7 %

31.4 %

 

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.

2021

2020

2019

2018

Total Costs Incurred in Exploration and Development Activities (GAAP)

3,969

3,718

6,628

6,420

Less:  Asset Retirement Costs

(127)

(117)

(186)

(70)

Non-Cash Acquisition Costs of Unproved Properties

(45)

(197)

(98)

(291)

Acquisition Costs of Proved Properties

(100)

(135)

(380)

(124)

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

3,697

3,269

5,964

5,935

Total Costs Incurred in Exploration and Development Activities (GAAP)

3,969

3,718

6,628

6,420

Less:  Asset Retirement Costs

(127)

(117)

(186)

(70)

Non-Cash Acquisition Costs of Unproved Properties

(45)

(197)

(98)

(291)

Non-Cash Acquisition Costs of Proved Properties

(5)

(15)

(52)

(71)

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

3,792

3,389

6,292

5,988

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

Revisions Due to Price - (c)

194

(278)

(60)

35

Revisions Other Than Price

(308)

(89)

(40)

Purchases in Place

9

10

17

12

Extensions, Discoveries and Other Additions - (d)

952

564

750

670

Total Proved Reserve Additions - (e)

847

207

707

677

Sales in Place

(11)

(31)

(5)

(11)

Net Proved Reserve Additions From All Sources

836

176

702

666

Production

309

285

301

265

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions - (a / d)

3.88

5.79

7.95

8.86

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

4.48

16.32

8.90

8.85

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

5.81

6.98

8.21

9.33

Reserve Replacement Cost Data(Continued)

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

2017

2016

2015

2014

Total Costs Incurred in Exploration and Development Activities (GAAP)

4,440

6,445

4,928

7,905

Less:  Asset Retirement Costs

(56)

20

(53)

(196)

Non-Cash Acquisition Costs of Unproved Properties

(256)

(3,102)

Acquisition Costs of Proved Properties

(73)

(749)

(481)

(139)

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

4,055

2,614

4,394

7,570

Total Costs Incurred in Exploration and Development Activities (GAAP)

4,440

6,445

4,928

7,905

Less:  Asset Retirement Costs

(56)

20

(53)

(196)

Non-Cash Acquisition Costs of Unproved Properties

(256)

(3,102)

Non-Cash Acquisition Costs of Proved Properties

(26)

(732)

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

4,102

2,631

4,875

7,709

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

Revisions Due to Price - (c)

154

(101)

(574)

52

Revisions Other Than Price

48

253

107

49

Purchases in Place

2

42

56

14

Extensions, Discoveries and Other Additions - (d)

421

209

246

519

Total Proved Reserve Additions - (e)

625

403

(165)

634

Sales in Place

(21)

(168)

(4)

(36)

Net Proved Reserve Additions From All Sources

604

235

(169)

598

Production

224

206

210

220

Reserve Replacement Costs ($ / Boe)

Total Drilling, Before Revisions - (a / d)

9.64

12.51

17.87

14.58

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

6.56

6.52

(29.63)

12.16

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

8.71

5.22

11.91

13.25

Definitions

$/Boe

U.S. Dollars per barrel of oil equivalent

MMBoe

Million barrels of oil equivalent

 

Financial Commodity Derivative Contracts

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

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2022 to July 29, 2022 (closed) and outstanding as of July 29, 2022. 

Crude Oil Financial Price Swap Contracts

Contracts Sold

Contracts Purchased

Period

Settlement Index

Volume

(MBbld)

Weighted Average Price

($/Bbl)

Volume(MBbld)

Weighted Average Price ($/Bbl)

January  - March 2022 (closed)

NYMEX WTI

140

$             65.58

$                   —

April  - June 2022 (closed)

NYMEX WTI

140

65.62

July 2022 (closed)

NYMEX WTI

140

65.59

August - September 2022

NYMEX WTI

140

65.59

October - December 2022 (closed) (1)

NYMEX WTI

53

66.11

October - December 2022

NYMEX WTI

87

65.41

87

88.85

January - February 2023 (closed) (1)

NYMEX WTI

7

69.51

January - February 2023

NYMEX WTI

143

67.84

6

102.26

March 2023 (closed) (1)

NYMEX WTI

37

67.35

March 2023

NYMEX WTI

113

68.11

6

102.26

April - May 2023 (closed) (1)

NYMEX WTI

29

68.28

April - May 2023

NYMEX WTI

91

67.63

2

98.15

June 2023 (closed) (1)

NYMEX WTI

118

67.77

June 2023

NYMEX WTI

2

69.10

2

98.15

July - September 2023 (closed) (1)

NYMEX WTI

100

70.15

October - December 2023 (closed) (1)

NYMEX WTI

69

69.41

(1)

In the second quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October 2022 - December 2023 crude oil financial price swap contracts which were open at that time.  EOG paid net cash of $593 million for the settlement of these contracts.

Financial Commodity Derivative Contracts(Continued)

Crude Oil Basis Swap Contracts

Contracts Sold

Period

Settlement Index

Volume (MBbld)

Weighted Average Price Differential  ($/Bbl)

January - August 2022 (closed)

NYMEX WTI Roll Differential (1)

125

$                          0.15

September - December 2022

NYMEX WTI Roll Differential (1)

125

0.15

(1)

This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.

 Natural Gas Financial Price Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MMBtud in thousands)

Weighted Average Price ($/MMBtu)

January - August 2022 (closed)

NYMEX Henry Hub

725

$                                    3.57

September 2022

NYMEX Henry Hub

725

3.57

October - December 2022 (closed) (1)

NYMEX Henry Hub

425

3.05

October - December 2022

NYMEX Henry Hub

300

4.32

January - December 2023 (closed) (1)

NYMEX Henry Hub

425

3.05

January - December 2023

NYMEX Henry Hub

300

3.36

January - December 2024

NYMEX Henry Hub

725

3.07

January - December 2025

NYMEX Henry Hub

725

3.07

(1)

In the second quarter of 2022, EOG executed the early termination provision granting EOG the right to terminate certain of its October 2022 - December 2023 natural gas  financial price swap contracts which were open at that time.  EOG paid net cash of $735 million for the settlement of these contracts.

 Natural Gas Basis Swap Contracts

Contracts Sold

Period

Settlement Index

Volume

(MMBtud in thousands)

Weighted Average Price Differential

($/MMBtu)

January - July 2022 (closed)

NYMEX Henry Hub HSC Differential (1)

210

$                                   (0.01)

August - December 2022

NYMEX Henry Hub HSC Differential (1)

210

(0.01)

January - December 2023

NYMEX Henry Hub HSC Differential (1)

135

(0.01)

January - December 2024

NYMEX Henry Hub HSC Differential (1)

10

0.00

January - December 2025

NYMEX Henry Hub HSC Differential (1)

10

0.00

(1)

This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

 

Glossary:

$/Bbl

Dollars per barrel

$/MMBtu

Dollars per million British Thermal Units

Bbl

Barrel

EOG

EOG Resources, Inc.

HSC

Houston Ship Channel

MBbld

Thousand barrels per day

MMBtu

Million British Thermal Units

MMBtud

Million British Thermal Units per day

NGL

Natural Gas Liquids

NYMEX

New York Mercantile Exchange

WTI

West Texas Intermediate

Direct After-Tax Rate of Return

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

Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

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

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical

  - Offsite Production Facilities

Payback ~12 Months on 100% Direct ATROR Wells

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

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian, Powder River Basin and Dorado Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Interest Expense, Net (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

2021

2020

2019

2018

Interest Expense, Net (GAAP)

178

205

185

245

Tax Benefit Imputed (based on 21%)

(37)

(43)

(39)

(51)

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

141

162

146

194

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

4,664

(605)

2,735

3,419

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

364

1,455

158

(201)

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

5,028

850

2,893

3,218

Total Stockholders' Equity - (d)

22,180

20,302

21,641

19,364

Average Total Stockholders' Equity * - (e)

21,241

20,972

20,503

17,824

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

5,109

5,816

5,175

6,083

Less:  Cash

(5,209)

(3,329)

(2,028)

(1,556)

Net Debt (Non-GAAP) - (g)

(100)

2,487

3,147

4,527

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

27,289

26,118

26,816

25,447

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

22,080

22,789

24,788

23,891

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

22,435

23,789

24,340

22,864

Return on Capital Employed (ROCE)

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

21.4 %

-1.9 %

11.8 %

15.8 %

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

23.0 %

4.3 %

12.5 %

14.9 %

Return on Equity (ROE)

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

22.0 %

-2.9 %

13.3 %

19.2 %

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

23.7 %

4.1 %

14.1 %

18.1 %

* Average for the current and immediately preceding year

ROCE & ROE(Continued)

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

Before

Tax

Income Tax Impact

After

Tax

Year Ended December 31, 2021

Adjustments:

Add:  Mark-to-Market Financial Commodity Derivative Contracts Impact

514

(112)

402

Add:  Certain Impairments

15

15

Less:  Gains on Asset Dispositions, Net

(17)

9

(8)

Less:  Tax Benefits Related to Exiting Canada Operations

(45)

(45)

Total

512

(148)

364

Year Ended December 31, 2020

Adjustments:

Add:  Mark-to-Market Financial Commodity Derivative Contracts Impact

(74)

16

(58)

Add:  Certain Impairments

1,868

(392)

1,476

Add:  Losses on Asset Dispositions, Net

47

(10)

37

Total

1,841

(386)

1,455

Year Ended December 31, 2019

Adjustments:

Add:  Mark-to-Market Financial Commodity Derivative Contracts Impact

51

(11)

40

Add:  Certain Impairments

275

(60)

215

Less:  Gains on Asset Dispositions, Net

(124)

27

(97)

Total

202

(44)

158

Year Ended December 31, 2018

Adjustments:

Add:  Mark-to-Market Financial Commodity Derivative Contracts Impact

(93)

20

(73)

Add:  Certain Impairments

153

(34)

119

Less:  Gains on Asset Dispositions, Net

(175)

38

(137)

Less:  Tax Reform Impact

(110)

(110)

Total

(115)

(86)

(201)

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

The following tables reconcile Interest Expense, Net (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

2017

2016

2015

Interest Expense, Net (GAAP)

274

282

237

Tax Benefit Imputed (based on 35%)

(96)

(99)

(83)

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

178

183

154

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

2,583

(1,097)

(4,525)

Total Stockholders' Equity - (d)

16,283

13,982

12,943

Average Total Stockholders' Equity* - (e)

15,133

13,463

15,328

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

6,387

6,986

6,655

Less:  Cash

(834)

(1,600)

(719)

Net Debt (Non-GAAP) - (g)

5,553

5,386

5,936

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

22,670

20,968

19,598

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

21,836

19,368

18,879

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

20,602

19,124

20,206

Return on Capital Employed (ROCE)

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

13.4 %

-4.8 %

-21.6 %

Return on Equity (ROE)

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

17.1 %

-8.1 %

-29.5 %

* Average for the current and immediately preceding year

ROCE & ROE(Continued)

In millions of USD, except ratio data (Unaudited)

2014

2013

2012

2011

Interest Expense, Net (GAAP)

201

235

214

Tax Benefit Imputed (based on 35%)

(70)

(82)

(75)

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

131

153

139

Net Income (GAAP) - (b)

2,915

2,197

570

Total Stockholders' Equity - (d)

17,713

15,418

13,285

12,641

Average Total Stockholders' Equity* - (e)

16,566

14,352

12,963

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

5,906

5,909

6,312

5,009

Less:  Cash

(2,087)

(1,318)

(876)

(616)

Net Debt (Non-GAAP) - (g)

3,819

4,591

5,436

4,393

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

23,619

21,327

19,597

17,650

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

21,532

20,009

18,721

17,034

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

20,771

19,365

17,878

Return on Capital Employed (ROCE)

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

14.7 %

12.1 %

4.0 %

Return on Equity (ROE)

Calculated Using GAAP Net Income - (b) / (e) (GAAP)

17.6 %

15.3 %

4.4 %

* Average for the current and immediately preceding year

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 margin 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.

2Q 2022

1Q 2022

4Q 2021

3Q 2021

2Q 2021

Volume - Million Barrels of Oil Equivalent - (a)

83.8

79.5

79.4

77.7

75.3

Total Operating Revenues and Other (b)

7,407

3,983

6,044

4,765

4,139

Total Operating Expenses (c)

4,504

3,437

3,516

3,294

2,968

Operating Income (d)

2,903

546

2,528

1,471

1,171

Wellhead Revenues

Crude Oil and Condensate

4,699

3,889

3,246

2,929

2,699

Natural Gas Liquids

777

681

583

548

367

Natural Gas

1,000

716

847

568

404

Total Wellhead Revenues - (e)

6,476

5,286

4,676

4,045

3,470

Operating Costs

Lease and Well

324

318

325

270

270

Transportation Costs

244

228

228

219

214

Gathering and Processing Costs

152

144

147

145

128

General and Administrative

128

124

139

142

120

Taxes Other Than Income

472

390

316

277

239

Interest Expense, Net

48

48

38

48

45

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

1,368

1,252

1,193

1,101

1,016

Depreciation, Depletion and Amortization (DD&A)

911

847

910

927

914

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

2,279

2,099

2,103

2,028

1,930

Exploration Costs

35

45

42

44

35

Dry Hole Costs

20

3

43

4

13

Impairments

91

55

206

82

44

Total Exploration Costs (GAAP)

146

103

291

130

92

Less:  Certain Impairments (1)

(36)

(13)

(1)

Total Exploration Costs (Non-GAAP)

110

103

291

117

91

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

2,425

2,202

2,394

2,158

2,022

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

2,389

2,202

2,394

2,145

2,021

Total Wellhead Revenues less Total Operating Cost

     (including Total Exploration Costs (GAAP))

4,051

3,084

2,282

1,887

1,448

Total Wellhead Revenues less Total Operating Cost

     (including Total Exploration Costs (Non-GAAP))

4,087

3,084

2,282

1,900

1,449

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

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

88.39

50.10

76.12

61.33

54.97

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

53.75

43.23

44.28

42.40

39.42

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

34.64

6.87

31.84

18.93

15.55

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

77.29

66.50

58.88

52.07

46.07

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

16.32

15.75

15.02

14.19

13.48

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

60.97

50.75

43.86

37.88

32.59

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

27.19

26.40

26.48

26.12

25.61

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

50.10

40.10

32.40

25.95

20.46

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

28.94

27.70

30.15

27.79

26.85

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

48.35

38.80

28.73

24.28

19.22

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

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

28.50

27.70

30.14

27.62

26.82

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

48.79

38.80

28.74

24.45

19.25

(1) 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).

Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)

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

2021

2020

2019

2018

2017

Volume - Million Barrels of Oil Equivalent - (a)

302.5

275.9

298.6

262.5

222.3

Total Operating Revenues and Other (b)

18,642

11,032

17,380

17,275

11,208

Total Operating Expenses (c)

12,540

11,576

13,681

12,806

10,282

Operating Income (Loss) (d)

6,102

(544)

3,699

4,469

926

Wellhead Revenues

Crude Oil and Condensate

11,125

5,786

9,613

9,517

6,256

Natural Gas Liquids

1,812

668

785

1,128

730

Natural Gas

2,444

837

1,184

1,302

922

Total Wellhead Revenues - (e)

15,381

7,291

11,582

11,947

7,908

Operating Costs

Lease and Well

1,135

1,063

1,367

1,283

1,045

Transportation Costs

863

735

758

747

740

Gathering and Processing Costs

559

459

479

437

149

General and Administrative (GAAP)

511

484

489

427

434

Less:  Legal Settlement - Early Leasehold Termination

(10)

Less:  Joint Venture Transaction Costs

(3)

Less:  Joint Interest Billings Deemed Uncollectible

(5)

General and Administrative (Non-GAAP) (1)

511

484

489

427

416

Taxes Other Than Income

1,047

478

800

772

545

Interest Expense, Net

178

205

185

245

274

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

4,293

3,424

4,078

3,911

3,187

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

4,293

3,424

4,078

3,911

3,169

Depreciation, Depletion and Amortization (DD&A)

3,651

3,400

3,750

3,435

3,409

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

7,944

6,824

7,828

7,346

6,596

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

7,944

6,824

7,828

7,346

6,578

Exploration Costs

154

146

140

149

145

Dry Hole Costs

71

13

28

5

5

Impairments

376

2,100

518

347

479

Total Exploration Costs (GAAP)

601

601

2,259

686

501

629

Less:  Certain Impairments (2)

(15)

(1,868)

(275)

(153)

(261)

Total Exploration Costs (Non-GAAP)

586

391

411

348

368

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

8,545

9,083

8,514

7,847

7,225

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

8,530

7,215

8,239

7,694

6,946

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

6,836

(1,792)

3,068

4,100

683

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

6,851

76

3,343

4,253

962

Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)

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

2021

2020

2019

2018

2017

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

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

61.63

39.99

58.20

65.81

50.42

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

41.46

41.96

45.81

48.79

46.25

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

20.17

(1.97)

12.39

17.02

4.17

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

50.84

26.42

38.79

45.51

35.58

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

14.19

12.39

13.66

14.90

14.34

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

36.65

14.03

25.13

30.61

21.24

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

26.26

24.71

26.22

27.99

29.67

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

24.58

1.71

12.57

17.52

5.91

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

28.25

32.92

28.51

29.89

32.50

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

22.59

(6.50)

10.28

15.62

3.08

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

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

14.19

12.39

13.66

14.90

14.25

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

36.65

14.03

25.13

30.61

21.33

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

26.26

24.71

26.22

27.99

29.59

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

24.58

1.71

12.57

17.52

5.99

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

28.20

26.13

27.60

29.32

31.24

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

22.64

0.29

11.19

16.19

4.34

(1)  EOG believes excluding the above-referenced items from general and administrative expense is appropriate and provides useful information to investors, as EOG views such items as non-recurring.  

(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).

Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)

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

2016

2015

2014

Volume - Million Barrels of Oil Equivalent - (a)

205.0

208.9

217.1

Total Operating Revenues and Other (b)

7,651

8,757

18,035

Total Operating Expenses (c)

8,876

15,443

12,793

Operating Income (Loss) (d)

(1,225)

(6,686)

5,242

Wellhead Revenues

Crude Oil and Condensate

4,317

4,935

9,742

Natural Gas Liquids

437

408

934

Natural Gas

742

1,061

1,916

Total Wellhead Revenues - (e)

5,496

6,404

12,592

Operating Costs

Lease and Well

927

1,182

1,416

Transportation Costs

764

849

972

Gathering and Processing Costs

123

146

146

General and Administrative (GAAP)

395

367

402

Less:  Voluntary Retirement Expense

(42)

Less: Acquisition Costs

(5)

Less:  Legal Settlement - Early Leasehold Termination

(19)

General and Administrative (Non-GAAP) (1)

348

348

402

Taxes Other Than Income

350

422

758

Interest Expense, Net

282

237

201

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

2,841

3,203

3,895

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

2,794

3,184

3,895

Depreciation, Depletion and Amortization (DD&A)

3,553

3,314

3,997

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

6,394

6,517

7,892

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

6,347

6,498

7,892

Exploration Costs

125

149

184

Dry Hole Costs

11

15

48

Impairments

620

6,614

744

Total Exploration Costs (GAAP)

756

6,778

976

Less:  Certain Impairments (2)

(321)

(6,308)

(824)

Total Exploration Costs (Non-GAAP)

435

470

152

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

7,150

13,295

8,868

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

6,782

6,968

8,044

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

(1,654)

(6,891)

3,724

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

(1,286)

(564)

4,548

Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)

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

2016

2015

2014

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

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

37.32

41.92

83.07

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

43.30

73.93

58.92

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

(5.98)

(32.01)

24.15

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

26.82

30.66

58.01

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

13.86

15.33

17.95

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

12.96

15.33

40.06

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

31.19

31.20

36.38

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

(4.37)

(0.54)

21.63

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

34.88

63.64

40.85

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

(8.06)

(32.98)

17.16

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

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

13.64

15.25

17.95

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

13.18

15.41

40.06

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

30.98

31.11

36.38

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

(4.16)

(0.45)

21.63

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

33.10

33.36

37.08

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

(6.28)

(2.70)

20.93

(1) EOG believes excluding the above-referenced items from general and administrative expense is appropriate and provides useful information to investors, as EOG views such items as non-recurring.  

(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).

 

Cision View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-second-quarter-2022-results-declares-1-50-per-share-special-dividend-and-reiterates-unchanged-full-year-2022-capital-and-oil-volume-plan-301600408.html

SOURCE EOG Resources, Inc.



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