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
08/04/2022 - 04:15 PM
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 Hedges Crude 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.
Volumes Total 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 Other Cash 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 Flow EOG 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 Acquisition EOG 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 Well Per-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 Processing Per-unit transportation and G&P costs in 2Q were in-line with 1Q and slightly below the guidance midpoints.
General and Administrative Per-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 Dividend The 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 iSense SM Continuous Leak Detection System EOG 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 2022 Guidance 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 ($MM)
745
680
65
573
393
446
313
Third Quarter and Full-Year 2022 Guidance3
(Unaudited)
See "Endnotes" below for related discussion and definitions.
3Q 2022 Guidance Range
FY 2022 Guidance Range
2021 Actual
2020 Actual
Crude Oil and Condensate Volumes (MBod)
United States
456.0
-
465.0
458.0
-
463.0
443.4
408.1
Trinidad
0.0
-
1.0
0.4
-
0.6
1.5
1.0
Other International
0.0
-
0.0
0.0
-
0.0
0.1
0.1
Total
456.0
-
466.0
458.4
-
463.6
445.0
409.2
Natural Gas Liquids Volumes (MBbld)
Total
180.0
-
210.0
185.0
-
205.0
144.5
136.0
Natural Gas Volumes (MMcfd)
United States
1,250
-
1,350
1,270
-
1,350
1,210
1,040
Trinidad
135
-
165
175
-
185
217
180
Other International
0
-
0
0
-
0
9
32
Total
1,385
-
1,515
1,445
-
1,535
1,436
1,252
Crude Oil Equivalent Volumes (MBoed)
United States
844.3
-
900.0
854.7
-
893.0
789.6
717.5
Trinidad
22.5
-
28.5
29.6
-
31.4
37.7
30.9
Other International
0.0
-
0.0
0.0
-
0.0
1.6
5.4
Total
866.8
-
928.5
884.3
-
924.4
828.9
753.8
Benchmark Price
Oil (WTI) ($/Bbl)
67.96
39.40
Natural Gas (HH) ($/Mcf)
3.85
2.08
Crude Oil and Condensate Differentials - above (below) WTI 4 ($/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 Hub 5 ($/Mcf)
United States
0.65
-
1.05
0.85
-
1.00
1.03
(0.47)
Natural Gas Realizations 6 ($/Mcf)
Trinidad
7.00
-
7.60
4.00
-
4.50
3.40
2.57
Total Expenditures (GAAP) ($MM)
4,255
4,113
Capital Expenditures 7 (non-GAAP) ($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 Webcast Friday, 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 EOG EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad . To learn more visit www.eogresources.com.
Investor Contacts David Streit 713‐571‐4902 Neel Panchal 713‐571‐4884
Media Contact Kimberly 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 586,391,670 Shares 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 257,268 Shares 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
Before Tax
Income Tax Impact
After Tax
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
Before Tax
Income Tax Impact
After Tax
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
Before Tax
Income Tax Impact
After Tax
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
Before Tax
Income Tax Impact
After Tax
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
Before Tax
Income Tax Impact
After Tax
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
4Q 2021
3Q 2021
2Q 2021
YTD 2022
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).
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SOURCE EOG Resources, Inc.