PR Newswire
HOUSTON, Aug. 4, 2021 /PRNewswire/ — EOG Resources, Inc. (EOG) today reported second quarter 2021 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 |
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|
|
|
|
|||||
|
|
Total Revenue |
4,139 |
3,694 |
1,103 |
|||
|
Net Income (Loss) |
907 |
677 |
(910) |
||||
|
Net Income (Loss) Per Share |
1.55 |
1.16 |
(1.57) |
||||
|
Net Cash Provided by Operating Activities |
1,559 |
1,870 |
88 |
||||
|
Total Expenditures |
1,089 |
1,067 |
534 |
||||
|
Current and Long-Term Debt |
5,125 |
5,133 |
5,724 |
||||
|
Cash and Cash Equivalents |
3,880 |
3,388 |
2,417 |
||||
|
Debt-to-Total Capitalization |
19.7 |
% |
19.8 |
% |
21.9 |
% |
|
|
|
Adjusted Net Income (Loss) |
1,012 |
946 |
(131) |
|||
|
Adjusted Net Income (Loss) Per Share |
1.73 |
1.62 |
(0.23) |
||||
|
Discretionary Cash Flow |
2,030 |
2,010 |
672 |
||||
|
Cash Capital Expenditures before Acquisitions |
972 |
945 |
478 |
||||
|
Free Cash Flow |
1,058 |
1,065 |
194 |
||||
|
Net Debt |
1,245 |
1,745 |
3,307 |
||||
|
Net Debt-to-Total Capitalization |
5.6 |
% |
7.8 |
% |
14.0 |
% |
|
Second Quarter 2021 Highlights
- Earned adjusted net income of $1.0 billion, or $1.73 per share
- Generated over $1.0 billion of free cash flow
- Capital expenditures below low end of guidance range driven by sustainable cost reductions
- Increased full-year well cost reduction target to 7% from 5%
- Oil production above high end of guidance range
- Total per-unit cash operating costs 3% below guidance midpoint
- Achieved strong ESG performance in 2020 driven by technology and innovation, positioning EOG ahead of pace to meet near-term ESG targets
Volumes and Capital Expenditures
|
|
|
|
|
|
|
Crude Oil and Condensate (MBod) |
448.6 |
443.0 |
431.0 |
331.1 |
|
Natural Gas Liquids (MBbld) |
138.5 |
132.5 |
124.3 |
101.2 |
|
Natural Gas (MMcfd) |
1,445 |
1,386 |
1,342 |
1,147 |
|
|
|
|
|
|
|
|
|
|
|
|
From William R. “Bill” Thomas, Chairman and Chief Executive Officer
“EOG is consistently delivering strong results. Our talented employees, supported by our unique culture, have risen to meet the double-premium investment standard in every aspect of the business. Outstanding operating execution, strong well productivity and lower well costs resulted in higher production and lower capital expenditures compared with our plan. We further lowered operating costs while our differentiated marketing strategy captured premium product prices.
“As a result, we generated a second consecutive quarter of record-level free cash flow. Our longstanding free cash flow priorities remain intact. We have already committed to return $1.5 billion of cash to shareholders in 2021 through regular and special dividends, including $820 million paid on July 30. Returning cash to shareholders remains a priority as we generate additional free cash flow during the second half of the year.
“EOG’s industry-leading execution extends to our environmental performance, where we are driving meaningful reductions in GHG and methane emissions intensity. We have almost completely eliminated routine flaring and continue to increase the percentage of recycled water used in our operations. Our entrepreneurial culture fosters new technology and innovations to further enhance our performance. Our successful closed-loop gas capture pilot is being expanded to additional locations. And we recently initiated a carbon capture and storage pilot project. Our goal remains to be among the lowest cost, highest return and lowest emissions producers and to play a significant role in the long-term future of energy.
“Our outstanding second quarter results are a testament to EOG’s special culture. EOG has never been in better shape and we are getting even better. With the momentum we are building from the shift to double premium, I am confident the company will continue to make significant improvements in the years ahead.”
Second Quarter 2021 Financial Performance
Adjusted Earnings per Share 2Q 2021 vs 1Q 2021
Prices and Hedges
Overall crude oil equivalent prices increased slightly in 2Q, with higher crude oil and NGL prices partially offset by lower natural gas prices.
Cash paid for hedge settlements increased to $193 million in 2Q compared with payments of $30 million in 1Q.
Volumes
Total company crude oil production of 448,600 Bopd was above the high end of the guidance range and 4% more than 1Q, which was impacted by adverse weather. NGL production was 11% higher and natural gas production was 8% higher, contributing to an overall 6% increase in total company equivalent volumes.
Per-Unit Costs
Total per-unit cash operating costs in 2Q were 3% below the midpoint of the guidance range, and lower compared with 1Q, due to reductions in lease and well costs from compression savings and gathering and processing costs from lower fuel and power rates.
Change in Cash 2Q 2021 vs 1Q 2021
Free Cash Flow
EOG generated discretionary cash flow (net cash provided by operating activities before exploration costs and changes in working capital) of $2.03 billion in 2Q. The company incurred $972 million of cash capital expenditures before acquisitions, resulting in $1.06 billion of free cash flow.
Capital Expenditures
Cash capital expenditures before acquisitions of $972 million were below the low end of the guidance range due to lower well costs from sustainable efficiency improvements. Faster drilling times, more efficient completion operations and lower-cost sand and water sourcing contributed to lower overall well costs. As a result, EOG has increased its full-year well cost reduction target to 7% from 5%.
Second Quarter 2021 Operating Performance
Lease and Well
Per-unit LOE costs were $0.22 below the 2Q 2021 guidance midpoint, primarily due to lower costs for compression, water handling and lease upkeep.
Transportation, Gathering and Processing
Per-unit transportation costs in 2Q were similar to 1Q and within the guidance range. Gathering and processing costs on a per-unit basis declined 14% compared with 1Q, driven by declines in fuel and power prices from elevated winter levels.
General and Administrative
G&A costs on a per-unit basis were in-line with 1Q 2021 and within the guidance range.
Depreciation, Depletion and Amortization
Per-unit DD&A costs in 2Q were below the target and down 6% compared with 1Q due to the addition of reserves from new wells at lower finding costs.
Second Quarter 2021 Results vs Guidance
|
|
|
|
|
|
|
|
|
|
United States |
446.9 |
441.0 |
5.9 |
428.7 |
442.4 |
376.6 |
330.9 |
|
Trinidad |
1.7 |
1.9 |
(0.2) |
2.2 |
2.3 |
1.0 |
0.1 |
|
Other International |
0.0 |
0.1 |
(0.1) |
0.1 |
0.1 |
0.0 |
0.1 |
|
Total |
448.6 |
443.0 |
5.6 |
431.0 |
444.8 |
377.6 |
331.1 |
|
|
|||||||
|
Total |
138.5 |
132.5 |
6.0 |
124.3 |
141.4 |
140.1 |
101.2 |
|
|
|||||||
|
United States |
1,199 |
1,160 |
39 |
1,100 |
1,075 |
1,008 |
939 |
|
Trinidad |
233 |
210 |
23 |
217 |
192 |
151 |
174 |
|
Other International |
13 |
16 |
(3) |
25 |
25 |
31 |
34 |
|
Total |
1,445 |
1,386 |
59 |
1,342 |
1,292 |
1,190 |
1,147 |
|
|
828.0 |
806.6 |
21.4 |
778.9 |
801.5 |
716.0 |
623.4 |
|
Total MMBoe |
75.3 |
73.4 |
1.9 |
70.1 |
73.7 |
65.9 |
56.7 |
|
|
|||||||
|
Oil (WTI) ($/Bbl) |
66.06 |
57.80 |
42.67 |
40.94 |
27.85 |
||
|
Natural Gas (HH) ($/Mcf) |
2.83 |
2.69 |
2.65 |
1.94 |
1.73 |
||
|
|
|||||||
|
United States |
0.10 |
0.25 |
(0.15) |
0.27 |
(0.81) |
(0.75) |
(7.45) |
|
Trinidad |
(9.80) |
(11.50) |
1.70 |
(8.03) |
(9.76) |
(15.53) |
(27.25) |
|
Other International |
(10.50) |
(8.50) |
(2.00) |
(19.19) |
(6.77) |
(15.65) |
20.93 |
|
|
44.1% |
40.0% |
4.1% |
48.5% |
41.1% |
35.0% |
36.6% |
|
|
|||||||
|
United States |
0.16 |
(0.20) |
0.36 |
2.83 |
(0.36) |
(0.45) |
(0.62) |
|
|
|||||||
|
Trinidad |
3.37 |
3.35 |
0.02 |
3.38 |
3.57 |
2.35 |
2.13 |
|
Other International |
5.69 |
5.65 |
0.04 |
5.66 |
5.47 |
4.73 |
4.36 |
|
|
1,089 |
1,067 |
1,107 |
646 |
534 |
||
|
|
972 |
1,100 |
(128) |
945 |
828 |
499 |
478 |
|
|
|||||||
|
Lease and Well |
3.58 |
3.80 |
(0.22) |
3.85 |
3.54 |
3.45 |
4.32 |
|
Transportation Costs |
2.84 |
2.80 |
0.04 |
2.88 |
2.64 |
2.74 |
2.67 |
|
General and Administrative |
1.59 |
1.55 |
0.04 |
1.57 |
1.54 |
1.89 |
2.32 |
|
Gathering and Processing |
1.70 |
1.85 |
(0.15) |
1.98 |
1.62 |
1.74 |
1.71 |
|
Cash Operating Costs |
9.71 |
10.00 |
(0.29) |
10.28 |
9.34 |
9.82 |
11.02 |
|
Depreciation, Depletion and Amortization |
12.13 |
12.30 |
(0.17) |
12.84 |
11.81 |
12.49 |
12.46 |
|
|
|||||||
|
Exploration and Dry Hole |
49 |
45 |
4 |
44 |
40 |
51 |
27 |
|
Impairment (GAAP) |
44 |
44 |
143 |
79 |
305 |
||
|
Impairment (excluding certain impairments (non-GAAP)) |
43 |
70 |
(27) |
43 |
57 |
52 |
66 |
|
Capitalized Interest |
8 |
8 |
0 |
8 |
7 |
7 |
8 |
|
Net Interest |
45 |
48 |
(3) |
47 |
53 |
53 |
54 |
|
|
6.9% |
7.0% |
(0.1%) |
6.7% |
5.1% |
7.2% |
9.4% |
|
|
|||||||
|
Effective Rate |
19.3% |
22.5% |
(3.2%) |
23.2% |
21.1% |
19.2% |
20.6% |
|
Deferred Ratio |
(45%) |
8% |
(53%) |
(18%) |
60% |
330% |
107% |
Third Quarter and Full-Year 2021 Guidance1
|
(Unaudited) |
||||||||
|
|
|
|
|
|
||||
|
|
||||||||
|
United States |
440.0 |
– |
447.0 |
437.0 |
– |
445.0 |
408.1 |
455.5 |
|
Trinidad |
0.5 |
– |
1.5 |
1.0 |
– |
1.8 |
1.0 |
0.6 |
|
Other International |
0.0 |
– |
0.0 |
0.0 |
– |
0.2 |
0.1 |
0.1 |
|
Total |
440.5 |
– |
448.5 |
438.0 |
– |
447.0 |
409.2 |
456.2 |
|
|
||||||||
|
Total |
135.0 |
– |
145.0 |
130.0 |
– |
140.0 |
136.0 |
134.1 |
|
|
||||||||
|
United States |
1,150 |
– |
1,250 |
1,150 |
– |
1,250 |
1,040 |
1,069 |
|
Trinidad |
195 |
– |
225 |
200 |
– |
230 |
180 |
260 |
|
Other International |
0 |
– |
0 |
5 |
– |
15 |
32 |
37 |
|
Total |
1,345 |
– |
1,475 |
1,355 |
– |
1,495 |
1,252 |
1,366 |
|
|
||||||||
|
United States |
766.7 |
– |
800.3 |
758.7 |
– |
793.3 |
717.5 |
767.8 |
|
Trinidad |
33.0 |
– |
39.0 |
34.3 |
– |
40.1 |
30.9 |
44.0 |
|
Other International |
0.0 |
– |
0.0 |
0.8 |
– |
2.7 |
5.4 |
6.2 |
|
Total |
799.7 |
– |
839.3 |
793.8 |
– |
836.1 |
753.8 |
818.0 |
|
|
||||||||
|
Oil (WTI) ($/Bbl) |
39.40 |
57.04 |
||||||
|
Natural Gas (HH) ($/Mcf) |
2.08 |
2.62 |
||||||
|
|
||||||||
|
United States |
(0.20) |
– |
0.80 |
(0.20) |
– |
0.80 |
(0.75) |
0.70 |
|
Trinidad |
(8.50) |
– |
(6.50) |
(10.50) |
– |
(8.50) |
(9.20) |
(9.88) |
|
|
||||||||
|
Total |
45% |
– |
55% |
42% |
– |
52% |
34.0% |
28.1% |
|
|
||||||||
|
United States |
0.10 |
– |
0.50 |
0.70 |
– |
0.90 |
(0.47) |
(0.40) |
|
|
||||||||
|
Trinidad |
3.10 |
– |
3.60 |
3.10 |
– |
3.60 |
2.57 |
2.72 |
|
|
4,113 |
6,900 |
||||||
|
|
900 |
– |
1,100 |
3,700 |
– |
4,100 |
3,490 |
6,234 |
|
|
||||||||
|
Lease and Well |
3.45 |
– |
4.15 |
3.40 |
– |
4.10 |
3.85 |
4.58 |
|
Transportation Costs |
2.80 |
– |
3.20 |
2.75 |
– |
3.15 |
2.66 |
2.54 |
|
General and Administrative |
1.75 |
– |
1.85 |
1.55 |
– |
1.65 |
1.75 |
1.64 |
|
Gathering and Processing |
1.80 |
– |
2.00 |
1.75 |
– |
1.95 |
1.66 |
1.60 |
|
Cash Operating Costs |
9.80 |
– |
11.20 |
9.45 |
– |
10.85 |
9.92 |
10.36 |
|
Depreciation, Depletion and Amortization |
11.70 |
– |
12.30 |
11.70 |
– |
12.70 |
12.32 |
12.56 |
|
|
||||||||
|
Exploration and Dry Hole |
35 |
– |
45 |
160 |
– |
180 |
159 |
168 |
|
Impairment (GAAP) |
2,100 |
518 |
||||||
|
Impairment (excluding certain impairments (non-GAAP)) |
65 |
– |
105 |
255 |
– |
295 |
232 |
243 |
|
Capitalized Interest |
5 |
– |
10 |
25 |
– |
30 |
31 |
38 |
|
Net Interest |
42 |
– |
48 |
180 |
– |
185 |
205 |
185 |
|
|
6.0% |
– |
8.0% |
6.5% |
– |
7.5% |
6.6% |
6.9% |
|
|
||||||||
|
Effective Rate |
21% |
– |
26% |
20% |
– |
25% |
18.2% |
22.9% |
|
Deferred Ratio |
25% |
– |
40% |
0% |
– |
15% |
54.8% |
107.4% |
Second Quarter 2021 Results Webcast
Thursday, August 5, 2021, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG’s website for one year.
https://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 and Investor Contact
Kimberly Ehmer 713‐571‐4676
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1) |
The forecast items for the third quarter and full year 2021 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. |
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2) |
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. |
|
3) |
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. |
|
4) |
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions. |
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|
Acq |
Acquisitions |
|
ATROR |
After-tax rate of return |
|
Bbl |
Barrel |
|
Bn |
Billion |
|
Boe |
Barrels of oil equivalent |
|
Bopd |
Barrels of oil per day |
|
Capex |
Capital expenditures |
|
CO2e |
Carbon dioxide equivalent |
|
DCF |
Discretionary cash flow |
|
DD&A |
Depreciation, Depletion and Amortization |
|
Disc |
Discoveries |
|
Divest |
Divestitures |
|
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,” “goal,” “may,” “will,” “focused on,” “should” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward‐looking statements. In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet goals or ambitions with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward‐looking statements. Forward‐looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward‐looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG’s forward‐looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward‐looking, non‐GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward‐looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward‐looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward‐looking, non‐GAAP financial measures to the respective most directly comparable forward‐looking GAAP financial measures. Management believes these forward‐looking, non‐GAAP measures may be a useful tool for the investment community in comparing EOG’s forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward‐looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG’s actual results may differ materially from such measures and estimates. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward‐looking statements include, among others:
- the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
- the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
- the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
- the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, natural gas liquids, and natural gas;
- security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
- the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
- the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;
- the impact of, and changes in, government policies, laws and regulations, including any changes or other actions which may result from the recent U.S. elections and change in U.S. administration and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
- EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
- the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;
- competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
- the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
- the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
- weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
- the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
- EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and
- to otherwise satisfy its capital expenditure requirements;
- the extent to which EOG is successful in its completion of planned asset dispositions;
- the extent and effect of any hedging activities engaged in by EOG;
- the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
- the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
- geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
- the use of competing energy sources and the development of alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts; and
- the other factors described under ITEM 1A, Risk Factors, of EOG’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2020 and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10‐Q or Current Reports on Form 8‐K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG’s forward-looking statements. EOG’s forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include “potential” reserves, “resource potential” and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2020, available from EOG at P.O. Box 4362, Houston, Texas 77210‐4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov. In addition, reconciliation and calculation schedules for non‐GAAP financial measures can be found on the EOG website at www.eogresources.com.
|
|
||||||||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
|
||||||||||||||
|
Crude Oil and Condensate |
2,699 |
2,251 |
615 |
4,950 |
2,680 |
|||||||||
|
Natural Gas Liquids |
367 |
314 |
93 |
681 |
254 |
|||||||||
|
Natural Gas |
404 |
625 |
141 |
1,029 |
351 |
|||||||||
|
Gains (Losses) on Mark-to-Market |
(427) |
(367) |
(127) |
(794) |
1,079 |
|||||||||
|
Gathering, Processing and Marketing |
1,022 |
848 |
362 |
1,870 |
1,401 |
|||||||||
|
Gains (Losses) on Asset Dispositions, Net |
51 |
(6) |
14 |
45 |
30 |
|||||||||
|
Other, Net |
23 |
29 |
5 |
52 |
26 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
Lease and Well |
270 |
270 |
245 |
540 |
575 |
|||||||||
|
Transportation Costs |
214 |
202 |
152 |
416 |
360 |
|||||||||
|
Gathering and Processing Costs |
128 |
139 |
97 |
267 |
225 |
|||||||||
|
Exploration Costs |
35 |
33 |
27 |
68 |
67 |
|||||||||
|
Dry Hole Costs |
13 |
11 |
— |
24 |
— |
|||||||||
|
Impairments |
44 |
44 |
305 |
88 |
1,878 |
|||||||||
|
Marketing Costs |
991 |
838 |
444 |
1,829 |
1,554 |
|||||||||
|
Depreciation, Depletion and Amortization |
914 |
900 |
707 |
1,814 |
1,707 |
|||||||||
|
General and Administrative |
120 |
110 |
132 |
230 |
246 |
|||||||||
|
Taxes Other Than Income |
239 |
215 |
81 |
454 |
238 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Other Income (Expense), Net |
(2) |
(4) |
(4) |
(6) |
14 |
|||||||||
|
Income (Loss) Before Interest Expense |
1,169 |
928 |
(1,091) |
2,097 |
(1,015) |
|||||||||
|
Interest Expense, Net |
45 |
47 |
54 |
92 |
99 |
|||||||||
|
Income (Loss) Before Income Taxes |
1,124 |
881 |
(1,145) |
2,005 |
(1,114) |
|||||||||
|
Income Tax Provision (Benefit) |
217 |
204 |
(235) |
421 |
(214) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Dividends Declared per Common Share |
1.4125 |
0.4125 |
0.3750 |
1.8250 |
0.7500 |
|||||||||
|
Net Income (Loss) Per Share |
||||||||||||||
|
Basic |
1.56 |
1.17 |
(1.57) |
2.73 |
(1.55) |
|||||||||
|
Diluted |
1.55 |
1.16 |
(1.57) |
2.72 |
(1.55) |
|||||||||
|
Average Number of Common Shares |
||||||||||||||
|
Basic |
580 |
580 |
579 |
580 |
579 |
|||||||||
|
Diluted |
584 |
583 |
579 |
583 |
579 |
|||||||||
|
|
||||||||||||||||||||
|
(Unaudited) |
||||||||||||||||||||
|
|
|
|
|
|
|
|
||||||||||||||
|
Crude Oil and Condensate Volumes |
||||||||||||||||||||
|
United States |
446.9 |
330.9 |
35 |
% |
428.7 |
437.8 |
406.8 |
8 |
% |
|||||||||||
|
Trinidad |
1.7 |
0.1 |
1,600 |
% |
2.2 |
2.0 |
0.3 |
567 |
% |
|||||||||||
|
Other International (B) |
— |
0.1 |
-100 |
% |
0.1 |
— |
0.1 |
-100 |
% |
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Average Crude Oil and Condensate Prices |
||||||||||||||||||||
|
United States |
66.16 |
20.40 |
224 |
% |
58.07 |
62.22 |
36.17 |
72 |
% |
|||||||||||
|
Trinidad |
56.26 |
0.60 |
9,290 |
% |
49.77 |
52.57 |
27.75 |
89 |
% |
|||||||||||
|
Other International (B) |
55.56 |
48.78 |
14 |
% |
38.61 |
42.36 |
53.41 |
-21 |
% |
|||||||||||
|
Composite |
66.12 |
20.40 |
224 |
% |
58.02 |
62.18 |
36.16 |
72 |
% |
|||||||||||
|
Natural Gas Liquids Volumes (MBbld) (A) |
||||||||||||||||||||
|
United States |
138.5 |
101.2 |
37 |
% |
124.3 |
131.5 |
131.2 |
0 |
% |
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Average Natural Gas Liquids Prices |
||||||||||||||||||||
|
United States |
29.15 |
10.20 |
186 |
% |
28.03 |
28.62 |
10.65 |
169 |
% |
|||||||||||
|
Composite |
29.15 |
10.20 |
186 |
% |
28.03 |
28.62 |
10.65 |
169 |
% |
|||||||||||
|
Natural Gas Volumes (MMcfd) (A) |
||||||||||||||||||||
|
United States |
1,199 |
939 |
28 |
% |
1,100 |
1,150 |
1,039 |
11 |
% |
|||||||||||
|
Trinidad |
233 |
174 |
34 |
% |
217 |
225 |
188 |
20 |
% |
|||||||||||
|
Other International (B) |
13 |
34 |
-62 |
% |
25 |
19 |
35 |
-46 |
% |
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Average Natural Gas Prices ($/Mcf) (C) |
||||||||||||||||||||
|
United States |
2.99 |
1.11 |
170 |
% |
5.52 |
4.19 |
1.32 |
217 |
% |
|||||||||||
|
Trinidad |
3.37 |
2.13 |
58 |
% |
3.38 |
3.37 |
2.15 |
57 |
% |
|||||||||||
|
Other International (B) |
5.69 |
4.36 |
31 |
% |
5.66 |
5.67 |
4.34 |
31 |
% |
|||||||||||
|
Composite |
3.07 |
1.36 |
126 |
% |
5.17 |
4.08 |
1.53 |
167 |
% |
|||||||||||
|
Crude Oil Equivalent Volumes (MBoed) (D) |
||||||||||||||||||||
|
United States |
785.2 |
588.5 |
33 |
% |
736.4 |
761.0 |
711.1 |
7 |
% |
|||||||||||
|
Trinidad |
40.6 |
29.2 |
39 |
% |
38.5 |
39.5 |
31.6 |
25 |
% |
|||||||||||
|
Other International (B) |
2.2 |
5.7 |
-61 |
% |
4.0 |
3.1 |
6.1 |
-49 |
% |
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
(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, 2021). |
||||||||||||||||||||
|
(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. |
||||||||||||||||||||
|
|
|||||
|
In millions of USD, except share data (Unaudited) |
|||||
|
|
|
||||
|
|
|
||||
|
|
|||||
|
Cash and Cash Equivalents |
3,880 |
3,329 |
|||
|
Accounts Receivable, Net |
2,015 |
1,522 |
|||
|
Inventories |
516 |
629 |
|||
|
Assets from Price Risk Management Activities |
— |
65 |
|||
|
Income Taxes Receivable |
11 |
23 |
|||
|
Other |
513 |
294 |
|||
|
|
|
|
|||
|
|
|||||
|
Oil and Gas Properties (Successful Efforts Method) |
66,299 |
64,793 |
|||
|
Other Property, Plant and Equipment |
4,635 |
4,479 |
|||
|
Total Property, Plant and Equipment |
70,934 |
69,272 |
|||
|
Less: Accumulated Depreciation, Depletion and Amortization |
(42,275) |
(40,673) |
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
|||||
|
Accounts Payable |
2,012 |
1,681 |
|||
|
Accrued Taxes Payable |
286 |
206 |
|||
|
Dividends Payable |
820 |
217 |
|||
|
Liabilities from Price Risk Management Activities |
396 |
— |
|||
|
Current Portion of Long-Term Debt |
39 |
781 |
|||
|
Current Portion of Operating Lease Liabilities |
253 |
295 |
|||
|
Other |
196 |
280 |
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
|||||
|
|
|||||
|
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 584,102,233 |
206 |
206 |
|||
|
Additional Paid in Capital |
6,017 |
5,945 |
|||
|
Accumulated Other Comprehensive Loss |
(15) |
(12) |
|||
|
Retained Earnings |
14,689 |
14,170 |
|||
|
Common Stock Held in Treasury, 243,058 Shares at June 30, 2021 and 124,265 |
(16) |
(7) |
|||
|
|
|
|
|||
|
|
|
|
|||
|
|
||||||||||||||
|
In millions of USD (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
|
||||||||||||||
|
Reconciliation of Net Income (Loss) to Net Cash Provided |
||||||||||||||
|
Net Income (Loss) |
907 |
(910) |
677 |
1,584 |
(900) |
|||||||||
|
Items Not Requiring (Providing) Cash |
||||||||||||||
|
Depreciation, Depletion and Amortization |
914 |
707 |
900 |
1,814 |
1,707 |
|||||||||
|
Impairments |
44 |
305 |
44 |
88 |
1,878 |
|||||||||
|
Stock-Based Compensation Expenses |
31 |
40 |
35 |
66 |
80 |
|||||||||
|
Deferred Income Taxes |
(97) |
(253) |
(36) |
(133) |
(208) |
|||||||||
|
(Gains) Losses on Asset Dispositions, Net |
(51) |
(14) |
6 |
(45) |
(30) |
|||||||||
|
Other, Net |
6 |
9 |
7 |
13 |
— |
|||||||||
|
Dry Hole Costs |
13 |
— |
11 |
24 |
— |
|||||||||
|
Mark-to-Market Commodity Derivative Contracts |
||||||||||||||
|
Total (Gains) Losses |
427 |
127 |
367 |
794 |
(1,079) |
|||||||||
|
Net Cash Received from (Payments for) |
(193) |
640 |
(30) |
(223) |
724 |
|||||||||
|
Other, Net |
— |
— |
1 |
1 |
— |
|||||||||
|
Changes in Components of Working Capital and Other |
||||||||||||||
|
Accounts Receivable |
(186) |
469 |
(308) |
(494) |
1,191 |
|||||||||
|
Inventories |
37 |
(18) |
64 |
101 |
85 |
|||||||||
|
Accounts Payable |
11 |
(1,619) |
172 |
183 |
(1,185) |
|||||||||
|
Accrued Taxes Payable |
(163) |
(6) |
243 |
80 |
(61) |
|||||||||
|
Other Assets |
(119) |
195 |
(103) |
(222) |
253 |
|||||||||
|
Other Liabilities |
32 |
2 |
(89) |
(57) |
(64) |
|||||||||
|
Changes in Components of Working Capital Associated |
(54) |
414 |
(91) |
(145) |
282 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
Additions to Oil and Gas Properties |
(968) |
(424) |
(875) |
(1,843) |
(1,990) |
|||||||||
|
Additions to Other Property, Plant and Equipment |
(55) |
(24) |
(42) |
(97) |
(147) |
|||||||||
|
Proceeds from Sales of Assets |
141 |
17 |
5 |
146 |
43 |
|||||||||
|
Changes in Components of Working Capital Associated |
54 |
(414) |
91 |
145 |
(282) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
Long-Term Debt Borrowings |
— |
1,484 |
— |
— |
1,484 |
|||||||||
|
Long-Term Debt Repayments |
— |
(1,000) |
(750) |
(750) |
(1,000) |
|||||||||
|
Dividends Paid |
(239) |
(217) |
(219) |
(458) |
(384) |
|||||||||
|
Treasury Stock Purchased |
(2) |
— |
(10) |
(12) |
(5) |
|||||||||
|
Proceeds from Stock Options Exercised and Employee |
9 |
8 |
— |
9 |
8 |
|||||||||
|
Debt Issuance Costs |
— |
(3) |
— |
— |
(3) |
|||||||||
|
Repayment of Finance Lease Liabilities |
(9) |
(5) |
(9) |
(18) |
(8) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG’s quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Discretionary Cash Flow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics. |
|
A reconciliation of each of these measures to their most directly comparable GAAP financial measure 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. |
|
|
|||||||||||
|
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 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. |
|||||||||||
|
|
|||||||||||
|
|
|
|
|
||||||||
|
|
|
|
|
|
|||||||
|
Adjustments: |
|||||||||||
|
Losses on Mark-to-Market Commodity Derivative Contracts |
427 |
(93) |
334 |
0.58 |
|||||||
|
Net Cash Payments for Settlements of 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 |
|||||||
|
|
|
|
|
|
|||||||
|
Average Number of Common Shares (GAAP) |
|||||||||||
|
Basic |
580 |
||||||||||
|
Diluted |
584 |
||||||||||
|
Average Number of Common Shares (Non-GAAP) |
|||||||||||
|
Basic |
580 |
||||||||||
|
Diluted |
584 |
||||||||||
|
|
|||||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
|||||||||||
|
|
|||||||||||
|
|
|
|
|
||||||||
|
|
|
|
|
|
|||||||
|
Adjustments: |
|||||||||||
|
Losses on Mark-to-Market Commodity Derivative Contracts |
127 |
(29) |
98 |
0.17 |
|||||||
|
Net Cash Received from Settlements of Commodity Derivative Contracts |
640 |
(141) |
499 |
0.86 |
|||||||
|
Less: Gains on Asset Dispositions, Net |
(14) |
4 |
(10) |
(0.02) |
|||||||
|
Add: Certain Impairments |
239 |
(47) |
192 |
0.33 |
|||||||
|
Adjustments to Net Loss |
992 |
(213) |
779 |
1.34 |
|||||||
|
|
|
|
|
|
|||||||
|
Average Number of Common Shares (GAAP) |
|||||||||||
|
Basic |
579 |
||||||||||
|
Diluted |
579 |
||||||||||
|
Average Number of Common Shares (Non-GAAP) |
|||||||||||
|
Basic |
579 |
||||||||||
|
Diluted |
579 |
||||||||||
|
|
|||||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
|||||||||||
|
|
|||||||||||
|
|
|
|
|
||||||||
|
|
|
|
|
|
|||||||
|
Adjustments: |
|||||||||||
|
Losses on Mark-to-Market Commodity Derivative Contracts |
367 |
(81) |
286 |
0.49 |
|||||||
|
Net Cash Payments for Settlements of Commodity Derivative Contracts |
(30) |
7 |
(23) |
(0.04) |
|||||||
|
Add: Losses on Asset Dispositions, Net |
6 |
(1) |
5 |
0.01 |
|||||||
|
Add: Certain Impairments |
1 |
— |
1 |
— |
|||||||
|
Adjustments to Net Income |
344 |
(75) |
269 |
0.46 |
|||||||
|
|
|
|
|
|
|||||||
|
Average Number of Common Shares (GAAP) |
|||||||||||
|
Basic |
580 |
||||||||||
|
Diluted |
583 |
||||||||||
|
Average Number of Common Shares (Non-GAAP) |
|||||||||||
|
Basic |
580 |
||||||||||
|
Diluted |
583 |
||||||||||
|
|
|||||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
|||||||||||
|
|
|||||||||||
|
|
|
|
|
||||||||
|
|
|
|
|
|
|||||||
|
Adjustments: |
|||||||||||
|
Losses on Mark-to-Market Commodity Derivative Contracts |
794 |
(174) |
620 |
1.07 |
|||||||
|
Net Cash Payments for 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 |
|||||||
|
|
|
|
|
|
|||||||
|
Average Number of Common Shares (GAAP) |
|||||||||||
|
Basic |
580 |
||||||||||
|
Diluted |
583 |
||||||||||
|
Average Number of Common Shares (Non-GAAP) |
|||||||||||
|
Basic |
580 |
||||||||||
|
Diluted |
583 |
||||||||||
|
|
|||||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
|||||||||||
|
|
|||||||||||
|
|
|
|
|
||||||||
|
|
|
|
|
|
|||||||
|
Adjustments: |
|||||||||||
|
Gains on Mark-to-Market Commodity Derivative Contracts |
(1,079) |
236 |
(843) |
(1.47) |
|||||||
|
Net Cash Received from Settlements of Commodity Derivative Contracts |
724 |
(159) |
565 |
0.98 |
|||||||
|
Less: Gains on Asset Dispositions, Net |
(30) |
7 |
(23) |
(0.04) |
|||||||
|
Add: Certain Impairments |
1,755 |
(367) |
1,388 |
2.40 |
|||||||
|
Adjustments to Net Loss |
1,370 |
(283) |
1,087 |
1.87 |
|||||||
|
|
|
|
|
|
|||||||
|
Average Number of Common Shares (GAAP) |
|||||||||||
|
Basic |
579 |
||||||||||
|
Diluted |
579 |
||||||||||
|
Average Number of Common Shares (Non-GAAP) |
|||||||||||
|
Basic |
579 |
||||||||||
|
Diluted |
580 |
||||||||||
|
|
|||||
|
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) |
|||||
|
|
|
||||
|
|
|||||
|
2Q 2021 Composite Average Wellhead Revenue per Boe |
46.07 |
||||
|
Less: 1Q 2021 Composite Average Welhead Revenue per Boe |
(45.49) |
||||
|
Subtotal |
0.58 |
||||
|
Multiplied by: 2Q 2021 Crude Oil Equivalent Volumes (MMBoe) |
75.3 |
||||
|
Total Change in Revenue |
44 |
||||
|
Less: Income Tax Benefit (Cost) Imputed (based on 23%) |
(10) |
||||
|
Change in Net Income |
34 |
||||
|
Change in Diluted Earnings per Share |
0.06 |
||||
|
|
|||||
|
2Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative |
(193) |
||||
|
Less: Income Tax Benefit (Cost) |
42 |
||||
|
After Tax – (a) |
(151) |
||||
|
1Q 2021 Net Cash Received (Paid) from Settlement of Commodity Derivative Contracts |
(30) |
||||
|
Less: Income Tax Benefit (Cost) |
7 |
||||
|
After Tax – (b) |
(23) |
||||
|
Change in Net Income – (a) – (b) |
(128) |
||||
|
Change in Diluted Earnings per Share |
(0.22) |
||||
|
|
|||||
|
2Q 2021 Crude Oil Equivalent Volumes (MMBoe) |
75.3 |
||||
|
Less: 1Q 2021 Crude Oil Equivalent Volumes (MMBoe) |
(70.1) |
||||
|
Subtotal |
5.2 |
||||
|
Multiplied by: 2Q 2021 Composite Average Margin per Boe (Including Total |
19.25 |
||||
|
Change in Revenue |
101 |
||||
|
Less: Income Tax Benefit (Cost) Imputed (based on 23%) |
(23) |
||||
|
Change in Net Income |
78 |
||||
|
Change in Diluted Earnings per Share |
0.13 |
||||
|
|
|||||
|
1Q 2021 Total Operating Cost per Boe (including Total Exploration Costs) (Non- |
28.11 |
||||
|
Less: 2Q 2021 Total Operating Cost per Boe (including Total Exploration Costs) |
(26.82) |
||||
|
Subtotal |
1.29 |
||||
|
Multiplied by: 2Q 2021 Crude Oil Equivalent Volumes (MMBoe) |
75.3 |
||||
|
Change in Before-Tax Net Income |
97 |
||||
|
Less: Income Tax Benefit (Cost) Imputed (based on 23%) |
(22) |
||||
|
Change in Net Income |
75 |
||||
|
Change in Diluted Earnings per Share |
0.13 |
||||
|
|
0.01 |
||||
|
|
|
||||
|
2Q 2021 Average Number of Common Shares (Non-GAAP) – Diluted |
584 |
||||
|
|
||||||||||||||
|
In millions of USD (Unaudited) |
||||||||||||||
|
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (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 Exploration Costs (excluding Stock-Based Compensation Expenses), 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 Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Net Cash Provided by Operating Activities (GAAP) |
1,559 |
1,870 |
88 |
3,429 |
2,673 |
|||||||||
|
Adjustments: |
||||||||||||||
|
Exploration Costs (excluding Stock-Based |
29 |
28 |
21 |
57 |
53 |
|||||||||
|
Changes in Components of Working Capital and |
||||||||||||||
|
Accounts Receivable |
186 |
308 |
(469) |
494 |
(1,191) |
|||||||||
|
Inventories |
(37) |
(64) |
18 |
(101) |
(85) |
|||||||||
|
Accounts Payable |
(11) |
(172) |
1,619 |
(183) |
1,185 |
|||||||||
|
Accrued Taxes Payable |
163 |
(243) |
6 |
(80) |
61 |
|||||||||
|
Other Assets |
119 |
103 |
(195) |
222 |
(253) |
|||||||||
|
Other Liabilities |
(32) |
89 |
(2) |
57 |
64 |
|||||||||
|
Changes in Components of Working Capital |
54 |
91 |
(414) |
145 |
(282) |
|||||||||
|
Other Non-Current Income Taxes – Net Receivable |
— |
— |
— |
— |
113 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Discretionary Cash Flow (Non-GAAP) – Percentage Increase |
202 |
% |
73 |
% |
||||||||||
|
Discretionary Cash Flow (Non-GAAP) |
2,030 |
2,010 |
672 |
4,040 |
2,338 |
|||||||||
|
Less: |
||||||||||||||
|
Total Cash Capital Expenditures Before Acquisitions |
(972) |
(945) |
(478) |
(1,917) |
(2,163) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP): |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Total Expenditures (GAAP) |
1,089 |
1,067 |
534 |
2,156 |
2,360 |
|||||||||
|
Less: |
||||||||||||||
|
Asset Retirement Costs |
(31) |
(17) |
(5) |
(48) |
(25) |
|||||||||
|
Non-Cash Expenditures of Other Property, Plant and |
— |
— |
— |
— |
— |
|||||||||
|
Non-Cash Acquisition Costs of Unproved Properties |
— |
(22) |
(24) |
(22) |
(48) |
|||||||||
|
Non-Cash Finance Leases |
— |
(74) |
(24) |
(74) |
(73) |
|||||||||
|
Acquisition Costs of Proved Properties |
(86) |
(9) |
(3) |
(95) |
(51) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|||||||||||
|
In millions of USD (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
Net Cash Provided by Operating Activities (GAAP) |
5,008 |
8,163 |
7,769 |
4,265 |
|||||||
|
Adjustments: |
|||||||||||
|
Exploration Costs (excluding Stock-Based Compensation Expenses) |
126 |
113 |
125 |
122 |
|||||||
|
Changes in Components of Working Capital and Other Assets and |
|||||||||||
|
Accounts Receivable |
(467) |
92 |
368 |
392 |
|||||||
|
Inventories |
(123) |
(90) |
395 |
175 |
|||||||
|
Accounts Payable |
795 |
(169) |
(439) |
(324) |
|||||||
|
Accrued Taxes Payable |
49 |
(40) |
92 |
64 |
|||||||
|
Other Assets |
(325) |
(358) |
125 |
659 |
|||||||
|
Other Liabilities |
(8) |
57 |
(11) |
90 |
|||||||
|
Changes in Components of Working Capital Associated with |
(75) |
115 |
(301) |
(90) |
|||||||
|
Other Non-Current Income Taxes – Net (Payable) Receivable |
113 |
239 |
149 |
(513) |
|||||||
|
|
|
|
|
|
|||||||
|
Discretionary Cash Flow (Non-GAAP) – Percentage Increase (Decrease) |
-37 |
% |
-2 |
% |
71 |
% |
76 |
% |
|||
|
Discretionary Cash Flow (Non-GAAP) |
5,093 |
8,122 |
8,272 |
4,840 |
|||||||
|
Less: |
|||||||||||
|
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) |
(3,490) |
(6,234) |
(6,172) |
(4,228) |
|||||||
|
|
|
|
|
|
|||||||
|
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP): |
|||||||||||
|
Total Expenditures (GAAP) |
4,113 |
6,900 |
6,706 |
4,613 |
|||||||
|
Less: |
|||||||||||
|
Asset Retirement Costs |
(117) |
(186) |
(70) |
(56) |
|||||||
|
Non-Cash Expenditures of Other Property, Plant and Equipment |
— |
(2) |
(1) |
— |
|||||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(197) |
(98) |
(291) |
(256) |
|||||||
|
Non-Cash Finance Leases |
(174) |
— |
(48) |
— |
|||||||
|
Acquisition Costs of Proved Properties |
(135) |
(380) |
(124) |
(73) |
|||||||
|
|
|
|
|
|
|||||||
|
|
||||||||||||||
|
In millions of USD (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Net Cash Provided by Operating Activities (GAAP) |
2,359 |
3,595 |
8,649 |
7,329 |
5,237 |
|||||||||
|
Adjustments: |
||||||||||||||
|
Exploration Costs (excluding Stock-Based Compensation |
104 |
124 |
158 |
134 |
158 |
|||||||||
|
Changes in Components of Working Capital and Other |
||||||||||||||
|
Accounts Receivable |
233 |
(641) |
(85) |
24 |
179 |
|||||||||
|
Inventories |
(171) |
(58) |
162 |
(53) |
157 |
|||||||||
|
Accounts Payable |
74 |
1,409 |
(544) |
(179) |
17 |
|||||||||
|
Accrued Taxes Payable |
(93) |
(12) |
(16) |
(75) |
(78) |
|||||||||
|
Other Assets |
41 |
(118) |
14 |
110 |
119 |
|||||||||
|
Other Liabilities |
16 |
66 |
(75) |
20 |
(36) |
|||||||||
|
Changes in Components of Working Capital Associated |
156 |
(500) |
103 |
51 |
(74) |
|||||||||
|
Excess Tax Benefits from Stock-Based Compensation |
30 |
26 |
99 |
56 |
67 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Discretionary Cash Flow (Non-GAAP) – Percentage Increase (Decrease) |
-29 |
% |
-54 |
% |
14 |
% |
29 |
% |
||||||
|
Discretionary Cash Flow (Non-GAAP) |
2,749 |
3,891 |
8,465 |
7,417 |
5,746 |
|||||||||
|
Less: |
||||||||||||||
|
Total Cash Capital Expenditures Before Acquisitions |
(2,706) |
(4,682) |
(8,292) |
(7,102) |
(7,540) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP): |
||||||||||||||
|
Total Expenditures (GAAP) |
6,554 |
5,216 |
8,632 |
7,361 |
7,754 |
|||||||||
|
Less: |
||||||||||||||
|
Asset Retirement Costs |
20 |
(53) |
(196) |
(134) |
(127) |
|||||||||
|
Non-Cash Expenditures of Other Property, Plant and |
(17) |
— |
— |
— |
(66) |
|||||||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(3,102) |
— |
(5) |
(5) |
(20) |
|||||||||
|
Acquisition Costs of Proved Properties |
(749) |
(481) |
(139) |
(120) |
(1) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|||||||||||||||||
|
In millions of USD (Unaudited) |
|||||||||||||||||
|
|
|
|
|
|
|
||||||||||||
|
Exploration and Development Drilling |
711 |
381 |
2,664 |
4,951 |
4,935 |
3,132 |
|||||||||||
|
Facilities |
105 |
31 |
347 |
629 |
625 |
575 |
|||||||||||
|
Leasehold Acquisitions |
46 |
30 |
265 |
276 |
488 |
427 |
|||||||||||
|
Property Acquisitions |
86 |
3 |
135 |
380 |
124 |
73 |
|||||||||||
|
Capitalized Interest |
7 |
8 |
31 |
38 |
24 |
27 |
|||||||||||
|
Subtotal |
955 |
453 |
3,442 |
6,274 |
6,196 |
4,234 |
|||||||||||
|
Exploration Costs |
35 |
27 |
146 |
140 |
149 |
145 |
|||||||||||
|
Dry Hole Costs |
13 |
— |
13 |
28 |
5 |
5 |
|||||||||||
|
Exploration and Development Expenditures |
1,003 |
480 |
3,601 |
6,442 |
6,350 |
4,384 |
|||||||||||
|
Asset Retirement Costs |
31 |
5 |
117 |
186 |
70 |
56 |
|||||||||||
|
Total Exploration and Development Expenditures |
1,034 |
485 |
3,718 |
6,628 |
6,420 |
4,440 |
|||||||||||
|
Other Property, Plant and Equipment |
55 |
49 |
395 |
272 |
286 |
173 |
|||||||||||
|
|
|
|
|
|
|
|
|||||||||||
|
|
||||||||||
|
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 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. |
||||||||||
|
|
|
|
|
|||||||
|
Net Income (Loss) (GAAP) |
907 |
(910) |
1,584 |
(900) |
||||||
|
Adjustments: |
||||||||||
|
Interest Expense, Net |
45 |
54 |
92 |
99 |
||||||
|
Income Tax Provision (Benefit) |
217 |
(235) |
421 |
(214) |
||||||
|
Depreciation, Depletion and Amortization |
914 |
707 |
1,814 |
1,707 |
||||||
|
Exploration Costs |
35 |
27 |
68 |
67 |
||||||
|
Dry Hole Costs |
13 |
— |
24 |
— |
||||||
|
Impairments |
44 |
305 |
88 |
1,878 |
||||||
|
|
|
|
|
|
||||||
|
(Gains) Losses on MTM Commodity Derivative Contracts |
427 |
127 |
794 |
(1,079) |
||||||
|
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
(193) |
640 |
(223) |
724 |
||||||
|
Gains on Asset Dispositions, Net |
(51) |
(14) |
(45) |
(30) |
||||||
|
|
|
|
|
|
||||||
|
Adjusted EBITDAX (Non-GAAP) – Percentage Increase |
236 |
% |
105 |
% |
||||||
|
|
||||||||||
|
EBITDAX – Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments |
||||||||||
|
|
|||||
|
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. |
|||||
|
|
|
||||
|
Total Stockholders’ Equity – (a) |
20,881 |
20,762 |
|||
|
Current and Long-Term Debt (GAAP) – (b) |
5,125 |
5,133 |
|||
|
Less: Cash |
(3,880) |
(3,388) |
|||
|
Net Debt (Non-GAAP) – (c) |
1,245 |
1,745 |
|||
|
Total Capitalization (GAAP) – (a) + (b) |
26,006 |
25,895 |
|||
|
|
|
|
|||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
19.7 |
% |
19.8 |
% |
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
In millions of USD, except ratio data (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
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 |
|||||||
|
|
|
|
|
|
|||||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
22.3 |
% |
22.1 |
% |
21.9 |
% |
19.6 |
% |
|||
|
|
|
|
|
|
|
|
|
|
|||
|
|
|||||||||||
|
In millions of USD, except ratio data (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
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 |
|||||||
|
|
|
|
|
|
|||||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
19.3 |
% |
19.7 |
% |
20.1 |
% |
23.4 |
% |
|||
|
|
|
|
|
|
|
|
|
|
|||
|
|
|||||||||||
|
In millions of USD, except ratio data (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
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 |
|||||||
|
|
|
|
|
|
|||||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
23.9 |
% |
25.8 |
% |
26.9 |
% |
27.6 |
% |
|||
|
|
|
|
|
|
|
|
|
|
|||
|
|
|||||||||||
|
In millions of USD, except ratio data (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
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 |
|||||||
|
|
|
|
|
|
|||||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
28.2 |
% |
31.4 |
% |
33.4 |
% |
33.4 |
% |
|||
|
|
|
|
|
|
|
|
|
|
|||
|
|
||||||||||||||
|
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Total Stockholders’ Equity – (a) |
13,982 |
11,798 |
12,057 |
12,405 |
12,943 |
|||||||||
|
Current and Long-Term Debt (GAAP) – (b) |
6,986 |
6,986 |
6,986 |
6,986 |
6,660 |
|||||||||
|
Less: Cash |
(1,600) |
(1,049) |
(780) |
(668) |
(719) |
|||||||||
|
Net Debt (Non-GAAP) – (c) |
5,386 |
5,937 |
6,206 |
6,318 |
5,941 |
|||||||||
|
Total Capitalization (GAAP) – (a) + (b) |
20,968 |
18,784 |
19,043 |
19,391 |
19,603 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
33.3 |
% |
37.2 |
% |
36.7 |
% |
36.0 |
% |
34.0 |
% |
||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
||||||||||||||||||||
|
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. |
||||||||||||||||||||
|
|
|
|
|
|
|
|
||||||||||||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
3,718 |
6,628 |
6,420 |
4,440 |
6,445 |
4,928 |
7,905 |
|||||||||||||
|
Less: Asset Retirement Costs |
(117) |
(186) |
(70) |
(56) |
20 |
(53) |
(196) |
|||||||||||||
|
Non-Cash Acquisition Costs of |
(197) |
(98) |
(291) |
(256) |
(3,102) |
— |
— |
|||||||||||||
|
Acquisition Costs of Proved |
(135) |
(380) |
(124) |
(73) |
(749) |
(481) |
(139) |
|||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
3,718 |
6,628 |
6,420 |
4,440 |
6,445 |
4,928 |
7,905 |
|||||||||||||
|
Less: Asset Retirement Costs |
(117) |
(186) |
(70) |
(56) |
20 |
(53) |
(196) |
|||||||||||||
|
Non-Cash Acquisition Costs of |
(197) |
(98) |
(291) |
(256) |
(3,102) |
— |
— |
|||||||||||||
|
Non-Cash Acquisition Costs of |
(15) |
(52) |
(71) |
(26) |
(732) |
— |
— |
|||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
||||||||||||||||||||
|
Revisions Due to Price – (c) |
(278) |
(60) |
35 |
154 |
(101) |
(574) |
52 |
|||||||||||||
|
Revisions Other Than Price |
(89) |
— |
(40) |
48 |
253 |
107 |
49 |
|||||||||||||
|
Purchases in Place |
10 |
17 |
12 |
2 |
42 |
56 |
14 |
|||||||||||||
|
Extensions, Discoveries and Other Additions – (d) |
564 |
750 |
670 |
421 |
209 |
246 |
519 |
|||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Sales in Place |
(31) |
(5) |
(11) |
(21) |
(168) |
(4) |
(36) |
|||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
|
||||||||||||||
|
|
||||||||||||||||||||
|
Total Drilling, Before Revisions – (a / d) |
5.79 |
7.95 |
8.86 |
9.64 |
12.51 |
17.87 |
14.58 |
|||||||||||||
|
All-in Total, Net of Revisions – (b / e) |
16.32 |
8.90 |
8.85 |
6.56 |
6.52 |
(29.63) |
12.16 |
|||||||||||||
|
All-in Total, Excluding Revisions Due to |
6.98 |
8.21 |
9.33 |
8.71 |
5.22 |
11.91 |
13.25 |
|||||||||||||
|
|
|
|
$/Boe |
U.S. Dollars per barrel of oil equivalent |
|
MMBoe |
Million barrels of oil equivalent |
|
|
|||||||||
|
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 as of July 30, 2021. |
|||||||||
|
|
|||||||||
|
|
|||||||||
|
|
|
|
|
||||||
|
January 2021 (closed) |
NYMEX WTI |
151 |
$ |
50.06 |
|||||
|
February – March 2021 (closed) |
NYMEX WTI |
201 |
51.29 |
||||||
|
April – June 2021 (closed) |
NYMEX WTI |
150 |
51.68 |
||||||
|
July 2021 (closed) |
NYMEX WTI |
150 |
52.71 |
||||||
|
August – September 2021 |
NYMEX WTI |
150 |
52.71 |
||||||
|
January – March 2022 |
NYMEX WTI |
140 |
65.58 |
||||||
|
April – June 2022 |
NYMEX WTI |
140 |
65.62 |
||||||
|
July – September 2022 |
NYMEX WTI |
100 |
64.98 |
||||||
|
October – December 2022 |
NYMEX WTI |
40 |
63.71 |
||||||
|
|
|||||||||
|
|
|||||||||
|
|
|
|
|
||||||
|
February 2021 (closed) |
NYMEX WTI Roll Differential (1) |
30 |
$ |
0.11 |
|||||
|
March – August 2021 (closed) |
NYMEX WTI Roll Differential (1) |
125 |
0.17 |
||||||
|
September – December 2021 |
NYMEX WTI Roll Differential (1) |
125 |
0.17 |
||||||
|
January – 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. |
|||||||||
|
|
|||||||||
|
|
|||||||||
|
|
|
|
|
||||||
|
January – July 2021 (closed) |
Mont Belvieu Propane (non-Tet) |
15 |
$ |
29.44 |
|||||
|
August – December 2021 |
Mont Belvieu Propane (non-Tet) |
15 |
29.44 |
||||||
|
|
||||||||||||||||
|
|
|
|||||||||||||||
|
|
|
|
|
|
|
|||||||||||
|
January – March 2021 (closed) |
NYMEX Henry Hub |
500 |
$ |
2.99 |
500 |
$ |
2.43 |
|||||||||
|
April – August 2021 (closed) |
NYMEX Henry Hub |
500 |
2.99 |
570 |
2.81 |
|||||||||||
|
September 2021 |
NYMEX Henry Hub |
500 |
2.99 |
570 |
2.81 |
|||||||||||
|
October – December 2021 |
NYMEX Henry Hub |
500 |
2.99 |
500 |
2.83 |
|||||||||||
|
January – December 2022 (closed) (1) |
NYMEX Henry Hub |
20 |
2.75 |
— |
— |
|||||||||||
|
January – December 2022 |
NYMEX Henry Hub |
100 |
2.93 |
— |
— |
|||||||||||
|
January – December 2023 |
NYMEX Henry Hub |
100 |
2.93 |
— |
— |
|||||||||||
|
January – December 2024 |
NYMEX Henry Hub |
100 |
2.93 |
— |
— |
|||||||||||
|
January – December 2025 |
NYMEX Henry Hub |
100 |
2.93 |
— |
— |
|||||||||||
|
April – August 2021 (closed) |
JKM |
70 |
6.65 |
— |
— |
|||||||||||
|
September 2021 |
JKM |
70 |
6.65 |
— |
— |
|||||||||||
|
(1) |
In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of its 2022 natural gas price swap contracts which were open at that time. EOG received net cash of $0.6 million for the settlement of these contracts. |
|
|
|
|
$/Bbl |
Dollars per barrel |
|
$/MMBtu |
Dollars per million British Thermal Units |
|
Bbl |
Barrel |
|
EOG |
EOG Resources, Inc. |
|
JKM |
Japan Korea Marker |
|
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 |
|
|
|
|
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. |
|
|
|
|
|
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 |
|
|
|
|
|
Based on GAAP Accrual Accounting |
|
|
Includes All Indirect Capital and Growth Capital for Infrastructure |
|
|
– Eagle Ford, Bakken, Permian and Powder River Basin Facilities |
|
|
– Gathering and Processing |
|
|
Includes Legacy Gas Capital and Capital from Mature Wells |
|
|
|
|||||||||||||||||
|
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. |
|||||||||||||||||
|
|
|
|
|
|
|
||||||||||||
|
Interest Expense, Net (GAAP) |
198 |
45 |
47 |
53 |
53 |
||||||||||||
|
Tax Benefit Imputed (based on 21%) |
(41) |
(9) |
(10) |
(11) |
(11) |
||||||||||||
|
|
|
|
|
|
|
||||||||||||
|
Net Income (Loss) (GAAP) – (b) |
1,879 |
907 |
677 |
337 |
(42) |
||||||||||||
|
Adjustments to Net Income (Loss), Net of Tax (See Below Detail) (1) |
742 |
105 |
269 |
74 |
294 |
||||||||||||
|
|
|
|
|
|
|
||||||||||||
|
Total Stockholders’ Equity – (d) |
20,881 |
20,881 |
20,762 |
20,302 |
20,148 |
20,388 |
|||||||||||
|
Average Total Stockholders’ Equity * – (e) |
20,635 |
||||||||||||||||
|
Current and Long-Term Debt (GAAP) – (f) |
5,125 |
5,125 |
5,133 |
5,816 |
5,721 |
5,724 |
|||||||||||
|
Less: Cash |
(3,880) |
(3,880) |
(3,388) |
(3,329) |
(3,066) |
(2,417) |
|||||||||||
|
Net Debt (Non-GAAP) – (g) |
1,245 |
1,245 |
1,745 |
2,487 |
2,655 |
3,307 |
|||||||||||
|
Total Capitalization (GAAP) – (d) + (f) |
26,006 |
26,006 |
25,895 |
26,118 |
25,869 |
26,112 |
|||||||||||
|
Total Capitalization (Non-GAAP) – (d) + (g) |
22,126 |
22,126 |
22,507 |
22,789 |
22,803 |
23,695 |
|||||||||||
|
Average Total Capitalization (Non-GAAP) * – (h) |
22,911 |
||||||||||||||||
|
|
|||||||||||||||||
|
|
|
|
|||||||||||||||
|
|
|
|
|||||||||||||||
|
|
|||||||||||||||||
|
|
|
|
|||||||||||||||
|
|
|
|
|||||||||||||||
|
* Average for the beginning and ending trailing 12 month period. |
|||||||||||||||||
|
(1) Detail of adjustments to Net Income (Loss) (GAAP): |
|||||||||||||||||
|
|
|
|
|||||||||||||||
|
|
|||||||||||||||||
|
Adjustments: |
|||||||||||||||||
|
Add: Mark-to-Market Commodity Derivative |
234 |
(51) |
183 |
||||||||||||||
|
Add: Impairments of Certain Assets |
1 |
— |
1 |
||||||||||||||
|
Less: Net Gains on Asset Dispositions |
(51) |
17 |
(34) |
||||||||||||||
|
Less: Tax Benefits Related to Exiting Canada |
|
|
(45) |
||||||||||||||
|
|
|
|
|
||||||||||||||
|
|
|||||||||||||||||
|
Adjustments: |
|||||||||||||||||
|
Add: Mark-to-Market Commodity Derivative |
337 |
(74) |
263 |
||||||||||||||
|
Add: Impairments of Certain Assets |
1 |
— |
1 |
||||||||||||||
|
Add: Net Losses on Asset Dispositions |
6 |
(1) |
5 |
||||||||||||||
|
|
|
|
|
||||||||||||||
|
|
|||||||||||||||||
|
Adjustments: |
|||||||||||||||||
|
Add: Mark-to-Market Commodity Derivative |
2 |
(1) |
1 |
||||||||||||||
|
Add: Impairments of Certain Assets |
86 |
(18) |
68 |
||||||||||||||
|
Add: Net Losses on Asset Dispositions |
6 |
(1) |
5 |
||||||||||||||
|
|
|
|
|
||||||||||||||
|
|
|||||||||||||||||
|
Adjustments: |
|||||||||||||||||
|
Add: Mark-to-Market Commodity Derivative |
279 |
(60) |
219 |
||||||||||||||
|
Add: Impairments of Certain Assets |
27 |
(7) |
20 |
||||||||||||||
|
Add: Net Losses on Asset Dispositions |
71 |
(16) |
55 |
||||||||||||||
|
|
|
|
|
||||||||||||||
|
|
|||||||||||
|
In millions of USD, except ratio data (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
Interest Expense, Net (GAAP) |
205 |
185 |
245 |
||||||||
|
Tax Benefit Imputed (based on 21%) |
(43) |
(39) |
(51) |
||||||||
|
|
|
|
|
||||||||
|
Net Income (Loss) (GAAP) – (b) |
(605) |
2,735 |
3,419 |
||||||||
|
Adjustments to Net Income (Loss), Net of Tax (See Below Detail) (1) |
1,455 |
158 |
(201) |
||||||||
|
|
|
|
|
||||||||
|
Total Stockholders’ Equity – (d) |
20,302 |
21,641 |
19,364 |
16,283 |
|||||||
|
Average Total Stockholders’ Equity * – (e) |
20,972 |
20,503 |
17,824 |
||||||||
|
Current and Long-Term Debt (GAAP) – (f) |
5,816 |
5,175 |
6,083 |
6,387 |
|||||||
|
Less: Cash |
(3,329) |
(2,028) |
(1,556) |
(834) |
|||||||
|
Net Debt (Non-GAAP) – (g) |
2,487 |
3,147 |
4,527 |
5,553 |
|||||||
|
Total Capitalization (GAAP) – (d) + (f) |
26,118 |
26,816 |
25,447 |
22,670 |
|||||||
|
Total Capitalization (Non-GAAP) – (d) + (g) |
22,789 |
24,788 |
23,891 |
21,836 |
|||||||
|
Average Total Capitalization (Non-GAAP) * – (h) |
23,789 |
24,340 |
22,864 |
||||||||
|
|
|||||||||||
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|||||
|
|
|||||||||||
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|||||
|
* Average for the current and immediately preceding year |
|||||||||||
|
(1) Detail of adjustments to Net Income (Loss) (GAAP): |
|||||||||||
|
|
|
|
|||||||||
|
|
|||||||||||
|
Adjustments: |
|||||||||||
|
Add: Mark-to-Market Commodity Derivative Contracts Impact |
(74) |
16 |
(58) |
||||||||
|
Add: Impairments of Certain Assets |
1,868 |
(392) |
1,476 |
||||||||
|
Add: Net Losses on Asset Dispositions |
47 |
(10) |
37 |
||||||||
|
|
|
|
|
||||||||
|
|
|||||||||||
|
Adjustments: |
|||||||||||
|
Add: Mark-to-Market Commodity Derivative Contracts Impact |
51 |
(11) |
40 |
||||||||
|
Add: Impairments of Certain Assets |
275 |
(60) |
215 |
||||||||
|
Less: Net Gains on Asset Dispositions |
(124) |
27 |
(97) |
||||||||
|
|
|
|
|
||||||||
|
|
|||||||||||
|
Adjustments: |
|||||||||||
|
Add: Mark-to-Market Commodity Derivative Contracts Impact |
(93) |
20 |
(73) |
||||||||
|
Add: Impairments of Certain Assets |
153 |
(34) |
119 |
||||||||
|
Less: Net Gains on Asset Dispositions |
(175) |
38 |
(137) |
||||||||
|
Less: Tax Reform Impact |
— |
(110) |
(110) |
||||||||
|
|
|
|
|
||||||||
|
|
||||||||||||||
|
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. |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Interest Expense, Net (GAAP) |
274 |
282 |
237 |
201 |
235 |
|||||||||
|
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
(82) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Net Income (Loss) (GAAP) – (b) |
2,583 |
(1,097) |
(4,525) |
2,915 |
2,197 |
|||||||||
|
Total Stockholders’ Equity – (d) |
16,283 |
13,982 |
12,943 |
17,713 |
15,418 |
|||||||||
|
Average Total Stockholders’ Equity* – (e) |
15,133 |
13,463 |
15,328 |
16,566 |
14,352 |
|||||||||
|
Current and Long-Term Debt (GAAP) – (f) |
6,387 |
6,986 |
6,655 |
5,906 |
5,909 |
|||||||||
|
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) |
|||||||||
|
Net Debt (Non-GAAP) – (g) |
5,553 |
5,386 |
5,936 |
3,819 |
4,591 |
|||||||||
|
Total Capitalization (GAAP) – (d) + (f) |
22,670 |
20,968 |
19,598 |
23,619 |
21,327 |
|||||||||
|
Total Capitalization (Non-GAAP) – (d) + (g) |
21,836 |
19,368 |
18,879 |
21,532 |
20,009 |
|||||||||
|
Average Total Capitalization (Non-GAAP)* – (h) |
20,602 |
19,124 |
20,206 |
20,771 |
19,365 |
|||||||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
* Average for the current and immediately preceding year |
||||||||||||||
|
|
||||||||||||||
|
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Interest Expense, Net (GAAP) |
214 |
210 |
130 |
101 |
52 |
|||||||||
|
Tax Benefit Imputed (based on 35%) |
(75) |
(74) |
(46) |
(35) |
(18) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Net Income (GAAP) – (b) |
570 |
1,091 |
161 |
547 |
2,437 |
|||||||||
|
Total Stockholders’ Equity – (d) |
13,285 |
12,641 |
10,232 |
9,998 |
9,015 |
|||||||||
|
Average Total Stockholders’ Equity* – (e) |
12,963 |
11,437 |
10,115 |
9,507 |
8,003 |
|||||||||
|
Current and Long-Term Debt (GAAP) – (f) |
6,312 |
5,009 |
5,223 |
2,797 |
1,897 |
|||||||||
|
Less: Cash |
(876) |
(616) |
(789) |
(686) |
(331) |
|||||||||
|
Net Debt (Non-GAAP) – (g) |
5,436 |
4,393 |
4,434 |
2,111 |
1,566 |
|||||||||
|
Total Capitalization (GAAP) – (d) + (f) |
19,597 |
17,650 |
15,455 |
12,795 |
10,912 |
|||||||||
|
Total Capitalization (Non-GAAP) – (d) + (g) |
18,721 |
17,034 |
14,666 |
12,109 |
10,581 |
|||||||||
|
Average Total Capitalization (Non-GAAP)* – (h) |
17,878 |
15,850 |
13,388 |
11,345 |
9,351 |
|||||||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
* Average for the current and immediately preceding year |
||||||||||||||
|
|
||||||||||||||
|
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Interest Expense, Net (GAAP) |
47 |
43 |
63 |
63 |
59 |
|||||||||
|
Tax Benefit Imputed (based on 35%) |
(16) |
(15) |
(22) |
(22) |
(21) |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Net Income (GAAP) – (b) |
1,090 |
1,300 |
1,260 |
625 |
430 |
|||||||||
|
Total Stockholders’ Equity – (d) |
6,990 |
5,600 |
4,316 |
2,945 |
2,223 |
|||||||||
|
Average Total Stockholders’ Equity* – (e) |
6,295 |
4,958 |
3,631 |
2,584 |
1,948 |
|||||||||
|
Current and Long-Term Debt (GAAP) – (f) |
1,185 |
733 |
985 |
1,078 |
1,109 |
|||||||||
|
Less: Cash |
(54) |
(218) |
(644) |
(21) |
(4) |
|||||||||
|
Net Debt (Non-GAAP) – (g) |
1,131 |
515 |
341 |
1,057 |
1,105 |
|||||||||
|
Total Capitalization (GAAP) – (d) + (f) |
8,175 |
6,333 |
5,301 |
4,023 |
3,332 |
|||||||||
|
Total Capitalization (Non-GAAP) – (d) + (g) |
8,121 |
6,115 |
4,657 |
4,002 |
3,328 |
|||||||||
|
Average Total Capitalization (Non-GAAP)* – (h) |
7,118 |
5,386 |
4,330 |
3,665 |
3,068 |
|||||||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
* Average for the current and immediately preceding year |
||||||||||||||
|
|
||||||||||||||
|
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
Interest Expense, Net (GAAP) |
60 |
45 |
61 |
62 |
||||||||||
|
Tax Benefit Imputed (based on 35%) |
(21) |
(16) |
(21) |
(22) |
||||||||||
|
|
|
|
|
|
||||||||||
|
Net Income (GAAP) – (b) |
87 |
399 |
397 |
569 |
||||||||||
|
Total Stockholders’ Equity – (d) |
1,672 |
1,643 |
1,381 |
1,130 |
1,280 |
|||||||||
|
Average Total Stockholders’ Equity* – (e) |
1,658 |
1,512 |
1,256 |
1,205 |
||||||||||
|
Current and Long-Term Debt (GAAP) – (f) |
1,145 |
856 |
859 |
990 |
1,143 |
|||||||||
|
Less: Cash |
(10) |
(3) |
(20) |
(25) |
(6) |
|||||||||
|
Net Debt (Non-GAAP) – (g) |
1,135 |
853 |
839 |
965 |
1,137 |
|||||||||
|
Total Capitalization (GAAP) – (d) + (f) |
2,817 |
2,499 |
2,240 |
2,120 |
2,423 |
|||||||||
|
Total Capitalization (Non-GAAP) – (d) + (g) |
2,807 |
2,496 |
2,220 |
2,095 |
2,417 |
|||||||||
|
Average Total Capitalization (Non-GAAP)* – (h) |
2,652 |
2,358 |
2,158 |
2,256 |
||||||||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||
|
* Average for the current and immediately preceding year |
||||||||||||||
|
|
||||||||||||||
|
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. |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Total Operating Expenses (c) |
2,968 |
2,762 |
2,477 |
2,249 |
2,190 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
Crude Oil and Condensate |
2,699 |
2,251 |
1,711 |
1,395 |
615 |
|||||||||
|
Natural Gas Liquids |
367 |
314 |
229 |
185 |
93 |
|||||||||
|
Natural Gas |
404 |
625 |
302 |
184 |
141 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
Lease and Well |
270 |
270 |
261 |
227 |
245 |
|||||||||
|
Transportation Costs |
214 |
202 |
195 |
180 |
152 |
|||||||||
|
Gathering and Processing Costs |
128 |
139 |
119 |
115 |
97 |
|||||||||
|
General and Administrative |
120 |
110 |
113 |
125 |
132 |
|||||||||
|
Taxes Other Than Income |
239 |
215 |
114 |
126 |
81 |
|||||||||
|
Interest Expense, Net |
45 |
47 |
53 |
53 |
54 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Depreciation, Depletion and Amortization (DD&A) |
914 |
900 |
870 |
823 |
707 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Exploration Costs |
35 |
33 |
41 |
38 |
27 |
|||||||||
|
Dry Hole Costs |
13 |
11 |
— |
13 |
— |
|||||||||
|
Impairments |
44 |
44 |
143 |
79 |
305 |
|||||||||
|
Total Exploration Costs (GAAP) |
92 |
88 |
184 |
130 |
332 |
|||||||||
|
Less: Certain Impairments (1) |
(1) |
(1) |
(86) |
(27) |
(239) |
|||||||||
|
Total Exploration Costs (Non-GAAP) |
91 |
87 |
98 |
103 |
93 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
||||||||||||||
|
|
|
|
|
|
||||||||||
|
|
||||||||||||||
|
|
|
|
|
|
|
|||||||||
|
Composite Average Operating Expenses per Boe – (c) / (a) |
39.42 |
39.40 |
33.61 |
34.13 |
38.62 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Total Operating Cost per Boe (excluding DD&A and Total |
13.48 |
14.02 |
11.60 |
12.56 |
13.40 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (g) / (a) |
25.61 |
26.86 |
23.41 |
25.05 |
25.86 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (h) / (a) |
26.85 |
28.12 |
25.90 |
27.00 |
31.75 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
|
||||||||||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (i) / (a) |
26.82 |
28.11 |
24.72 |
26.62 |
27.51 |
|||||||||
|
|
|
|
|
|
|
|||||||||
|
(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). |
|
|
|||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
Total Operating Expenses (c) |
11,576 |
13,681 |
12,806 |
10,282 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|||||||||||
|
Crude Oil and Condensate |
5,786 |
9,613 |
9,517 |
6,256 |
|||||||
|
Natural Gas Liquids |
668 |
785 |
1,128 |
730 |
|||||||
|
Natural Gas |
837 |
1,184 |
1,302 |
922 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|||||||||||
|
Lease and Well |
1,063 |
1,367 |
1,283 |
1,045 |
|||||||
|
Transportation Costs |
735 |
758 |
747 |
740 |
|||||||
|
Gathering and Processing Costs |
459 |
479 |
437 |
149 |
|||||||
|
General and Administrative (GAAP) |
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) |
484 |
489 |
427 |
416 |
|||||||
|
Taxes Other Than Income |
478 |
800 |
772 |
545 |
|||||||
|
Interest Expense, Net |
205 |
185 |
245 |
274 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
Depreciation, Depletion and Amortization (DD&A) |
3,400 |
3,750 |
3,435 |
3,409 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
Exploration Costs |
146 |
140 |
149 |
145 |
|||||||
|
Dry Hole Costs |
13 |
28 |
5 |
5 |
|||||||
|
Impairments |
2,100 |
518 |
347 |
479 |
|||||||
|
Total Exploration Costs (GAAP) |
2,259 |
686 |
501 |
629 |
|||||||
|
Less: Certain Impairments (2) |
(1,868) |
(275) |
(153) |
(261) |
|||||||
|
Total Exploration Costs (Non-GAAP) |
391 |
411 |
348 |
368 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
|
|||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||||
|
|
|
|
|
||||||||
|
|
|||||||||||
|
|
|
|
|
|
|||||||
|
Composite Average Operating Expenses per Boe – (c) / (a) |
41.96 |
45.81 |
48.79 |
46.25 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|||||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a) |
12.39 |
13.66 |
14.90 |
14.34 |
|||||||
|
|
|
|
|
|
|||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) |
24.71 |
26.22 |
27.99 |
29.67 |
|||||||
|
|
|
|
|
|
|||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) |
32.92 |
28.51 |
29.89 |
32.50 |
|||||||
|
|
|
|
|
|
|||||||
|
|
|||||||||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (g) / (a) |
12.39 |
13.66 |
14.90 |
14.25 |
|||||||
|
|
|
|
|
|
|||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) |
24.71 |
26.22 |
27.99 |
29.59 |
|||||||
|
|
|
|
|
|
|||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) |
26.13 |
27.60 |
29.32 |
31.24 |
|||||||
|
|
|
|
|
|
|||||||
|
(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). |
|
|
|||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||
|
|
|
|
|||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
Total Operating Expenses (c) |
8,876 |
15,443 |
12,793 |
||||||
|
|
|
|
|
||||||
|
|
|||||||||
|
Crude Oil and Condensate |
4,317 |
4,935 |
9,742 |
||||||
|
Natural Gas Liquids |
437 |
408 |
934 |
||||||
|
Natural Gas |
742 |
1,061 |
1,916 |
||||||
|
|
|
|
|
||||||
|
|
|||||||||
|
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 |
||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
Depreciation, Depletion and Amortization (DD&A) |
3,553 |
3,314 |
3,997 |
||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
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 |
||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
|
|||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||
|
|
|
|
|||||||
|
|
|||||||||
|
|
|
|
|
||||||
|
Composite Average Operating Expenses per Boe – (c) / (a) |
43.30 |
73.93 |
58.92 |
||||||
|
|
|
|
|
||||||
|
|
|
|
|
||||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a) |
13.86 |
15.33 |
17.95 |
||||||
|
|
|
|
|
||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) |
31.19 |
31.20 |
36.38 |
||||||
|
|
|
|
|
||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) |
34.88 |
63.64 |
40.85 |
||||||
|
|
|
|
|
||||||
|
|
|||||||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (g) / (a) |
13.64 |
15.25 |
17.95 |
||||||
|
|
|
|
|
||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) |
30.98 |
31.11 |
36.38 |
||||||
|
|
|
|
|
||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) |
33.10 |
33.36 |
37.08 |
||||||
|
|
|
|
|
||||||
|
(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). |
View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-second-quarter-2021-results-301348730.html
SOURCE EOG Resources, Inc.
