HOUSTON, Feb. 25, 2021 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2020 results. Supplemental financial tables, a related presentation and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions are available on EOG's website at http://investors.eogresources.com/investors . Such reconciliation schedules are also included herein.
Key Financial Results
In millions of USD, except per-share and ratio data
4Q 2020 |
3Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
|||||||
GAAP |
Total Revenue |
2,965 |
2,246 |
4,320 |
11,032 |
17,380 |
|||||
Net Income (Loss) |
337 |
(43) |
637 |
(605) |
2,735 |
||||||
Net Income (Loss) Per Share |
0.58 |
(0.07) |
1.10 |
(1.04) |
4.71 |
||||||
Net Cash Provided by Operating Activities |
1,121 |
1,214 |
1,807 |
5,008 |
8,163 |
||||||
Total Expenditures |
1,108 |
646 |
1,506 |
4,113 |
6,900 |
||||||
Current and Long-Term Debt |
5,816 |
5,721 |
5,175 |
5,816 |
5,175 |
||||||
Cash and Cash Equivalents |
3,329 |
3,066 |
2,028 |
3,329 |
2,028 |
||||||
Debt-to-Total Capitalization |
22.3 |
% |
22.1 |
% |
19.3 |
% |
22.3 |
% |
19.3 |
% |
|
Non- GAAP |
Adjusted Net Income |
411 |
252 |
787 |
850 |
2,893 |
|||||
Adjusted Net Income Per Share |
0.71 |
0.43 |
1.35 |
1.46 |
4.98 |
||||||
Discretionary Cash Flow |
1,494 |
1,261 |
2,111 |
5,093 |
8,122 |
||||||
Cash Capital Expenditures before Acquisitions |
829 |
499 |
1,388 |
3,490 |
6,234 |
||||||
Free Cash Flow |
666 |
762 |
723 |
1,603 |
1,888 |
||||||
Net Debt |
2,487 |
2,655 |
3,147 |
2,487 |
3,147 |
||||||
Net Debt-to-Total Capitalization |
10.9 |
% |
11.6 |
% |
12.7 |
% |
10.9 |
% |
12.7 |
% |
From William R. "Bill" Thomas, Chairman and Chief Executive Officer
"EOG made significant improvements to its operating performance during 2020, across every area of the company. The benefits of these improvements are reflected in our fourth quarter results, and have created strong momentum as we set out to drive even better performance in 2021. I want to thank our talented employees for their ongoing dedication and focus, which drove significant progress and innovation in a challenging environment.
"We implemented countless innovations across the company in 2020 that sustainably reduced well costs and operating costs. We also made progress on a number of new exploration plays with the objective of increasing capital efficiency and returns while lowering the production decline rate. And we remained focused on strong environmental and safety performance which, together with our low cost structure, position EOG to be a significant part of the long–term energy solution."
Fourth Quarter and Full-Year 2020 Highlights
Volumes and Capital Expenditures
Wellhead Volumes |
4Q 2020 |
4Q 2020 |
3Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
Crude Oil and Condensate (MBod) |
444.8 |
441.9 |
377.6 |
468.9 |
409.2 |
456.2 |
Natural Gas Liquids (MBbld) |
141.4 |
145.0 |
140.1 |
144.0 |
136.0 |
134.1 |
Natural Gas (MMcfd) |
1,292 |
1,275 |
1,190 |
1,425 |
1,252 |
1,366 |
Total Crude Oil Equivalent (MBoed) |
801.5 |
799.4 |
716.0 |
850.3 |
753.8 |
818.0 |
Cash Capital Expenditures before Acquisitions ($MM) |
829 |
880 |
499 |
1,388 |
3,490 |
6,234 |
Full–Year 2020
Fourth Quarter 2020
2021 Plan
Fourth Quarter 2020 Financial Performance
Adjusted Earnings per Share 4Q 2020 vs 3Q 2020
Price and Hedges
Higher prices for natural gas, natural gas liquids and crude oil all contributed to higher QoQ earnings. This was partially offset by a decrease in hedge settlements, to $72 million received in 4Q 2020 from $275 million received in 3Q 2020.
Volume
Total company crude oil production of 444,800 Bopd in the fourth quarter was above the guidance midpoint and increased 18% QoQ. Production increased 1% for NGLs and increased 9% for natural gas, for a 12% increase in total company equivalent volumes.
Per-Unit Costs
EOG demonstrated significant operating discipline as most per‐unit cost categories decreased QoQ. The largest contributors to cost improvements were DD&A, taxes other than income, G&A and exploration.
Other
The effective tax rate on an adjusted basis decreased 1.1% QoQ, offset by a decrease in other income.
Change in Cash 4Q 2020 vs 3Q 2020
Free Cash Flow
Net cash provided by operating activities, plus exploration expense and changes in working capital, yielded discretionary cash flow of $1.5 billion in 4Q 2020. EOG incurred $829 million of cash capital expenditures before acquisitions, resulting in $666 million of free cash flow.
Capital Expenditures
Cash capital expenditures before acquisitions were below the low end of the guidance range due to lower than forecast exploration and infrastructure spending.
Full-Year 2020 Financial Performance
Adjusted Earnings per Share 2020 vs 2019
Price and Hedges
Crude oil prices declined by 33% in 2020 compared with 2019, while prices for NGLs and natural gas declined by 16% and 23%, respectively. This was partially offset by an increase in hedge settlements, to $1.1 billion received in 2020 from $231 million received in 2019.
Volume
In response to low crude oil prices, EOG shut‐in certain wells during 2020 to defer production to future periods with higher prices, reducing 2020 crude oil volumes by 25,000 Bopd. Total company crude oil volumes in 2020 were 409,200 Bopd, 10% lower than 2019. For the year, NGL volumes increased 1% while natural gas volumes decreased 8%, contributing to 8% lower total company daily production.
Per-Unit Costs
EOG achieved significant per‐unit cost reductions during 2020, driven by sustainable efficiency improvements. Lease and well costs declined 16% on a per‐unit basis compared with 2019, to $3.85 per Boe. This was the largest contributor to the overall 4% reduction in per‐unit cash operating costs. A 2% decrease in per‐unit rates for DD&A and lower taxes other than income also contributed to the YoY cost improvement.
Other
Lower marketing margin (gathering, processing and marketing revenue less marketing costs), other revenue and other income contributed to lower adjusted EPS in 2020 vs. 2019. The effective tax rate on an adjusted basis in 2020 was similar compared with 2019.
Change in Cash 2020 vs 2019
Free Cash Flow
Net cash provided by operating activities, plus exploration expense and changes in working capital, yielded discretionary cash flow of $5.1 billion in 2020. EOG incurred $3.5 billion of cash capital expenditures before acquisitions, resulting in $1.6 billion of free cash flow.
Capital Expenditures
Cash capital expenditures before acquisitions of $3.5 billion decreased 44% from 2019.
Fourth Quarter 2020 Operating Performance
Lease and Well
LOE costs declined 17% compared with the prior–year period and were also $0.51 below the 4Q 2020 guidance midpoint, representing the largest contribution to the per–unit total cash cost performance compared with guidance. Lower workover and water handling costs were the largest contributors to the strong LOE performance.
General and Administrative
EOG maintained its staffing and salary levels during 2020, with a focus on protecting its unique culture and organizational effectiveness. Reductions in certain employee-related costs were the primary contributors to lower per-unit G&A costs.
Transportation, Gathering and Processing
Increased production volumes from the return of shut–in wells and the startup of new wells contributed to the per–unit cost reductions in 4Q 2020 compared with 3Q 2020.
Depreciation, Depletion and Amortization
The addition of new wells with lower finding costs and positive revisions from lower production costs contributed to the overall reduction in per–unit DD&A costs.
2020 Reserves and Dividend Increase
Finding and Development Cost
2020 Reserve Replacement
Sustainable, Growing Dividend Since 1999
2021 Capital Plan
Low Breakeven Unhedged Oil Price with Significant Free Cash Flow Leverage
Additional Comments from Bill Thomas
"The 2021 capital plan is consistent with the strategy we have followed over the last year of not growing production in an oversupplied market. We are focused on increasing returns, generating free cash flow and maintaining our productive capacity while the oil market rebalances. In addition, we continue to invest in infrastructure to support reliable, safe, low-cost and low-emissions operations. With the improvements we have made in our operations and the size and quality of our premium inventory, we can now focus our capital allocation on the top half of our premium inventory – wells that are double–premium or better. Using double-premium investment metrics will make a step-change improvement in EOG's future performance.
"We continue to press forward in our exploration efforts and are allocating more capital in 2021 to test high–impact oil plays and lease acreage. While much of the industry is scaling back or abandoning exploration, we are confident that our pipeline of new high–return plays can significantly increase the long–term value of EOG and we are pursuing them aggressively.
"The increase in the regular dividend reflects the significant progress EOG has made in the past 12 months. We have lowered operating costs and well costs, in turn reducing the breakeven oil price needed to maintain our production. It also demonstrates the confidence we have in the resiliency of our business. We will evaluate all options to maximize total shareholder return as cash becomes available."
Committed to ESG Performance
EOG Sustainability Ambitions
Additional Comments from Bill Thomas
"I'm very proud of our employees for their efforts to deliver significant improvements in EOG's safety and environmental results the past several years. It is a strong testament to EOG's culture and only happens when everyone is focused and working together.
"We are moving aggressively to continue to improve our strong record of environmental performance. We are aiming to capture 99.8% of wellhead gas in 2021 and our goal is to eliminate routine flaring by 2025. We also keep raising the bar on water management, procuring more of our water from reuse sources every year. These efforts both reduce our environmental footprint and lower our costs.
"In the long run, our environmental ambitions are as bold as the rest of our operations. We have made significant progress the past several years, applying innovation and technology through our decentralized culture to reduce our emissions intensity. This progress, along with our ambition to reduce scope 1 and scope 2 GHG emissions to net zero by 2040, motivates us to pursue further innovations for the future. EOG is focused on being among the lowest cost, highest return and lowest emissions producers, playing a significant role in the long–term future of energy."
Fourth Quarter 2020 Results vs Guidance
Crude Oil and Condensate (MBod) |
4Q 2020 |
4Q 2020 |
Variance |
3Q 2020 |
2Q 2020 |
1Q 2020 |
4Q 2019 |
||||||
US |
442.4 |
440.0 |
2.4 |
376.6 |
330.9 |
482.7 |
468.3 |
||||||
Trinidad |
2.3 |
1.8 |
0.5 |
1.0 |
0.1 |
0.5 |
0.5 |
||||||
Other Intl |
0.1 |
0.1 |
0.0 |
0.0 |
0.1 |
0.1 |
0.1 |
||||||
Total |
444.8 |
441.9 |
2.9 |
377.6 |
331.1 |
483.3 |
468.9 |
||||||
NGLs (MBbld) |
|||||||||||||
Total |
141.4 |
145.0 |
(3.6) |
140.1 |
101.2 |
161.3 |
144.0 |
||||||
Natural Gas (MMcfd) |
|||||||||||||
US |
1,075 |
1,070 |
5 |
1,008 |
939 |
1,139 |
1,148 |
||||||
Trinidad |
192 |
180 |
12 |
151 |
174 |
201 |
242 |
||||||
Other Intl |
25 |
25 |
0 |
31 |
34 |
38 |
35 |
||||||
Total |
1,292 |
1,275 |
17 |
1,190 |
1,147 |
1,378 |
1,425 |
||||||
Total Crude Oil Equivalent Volumes (MBoed) |
801.5 |
799.4 |
2.1 |
716.0 |
623.4 |
874.1 |
850.3 |
||||||
Total MMBoe |
73.7 |
73.5 |
0.2 |
65.9 |
56.7 |
79.5 |
78.2 |
||||||
Capital Expenditures ($MM) |
829 |
880 |
(51) |
499 |
478 |
1,685 |
1,388 |
||||||
Benchmark Price |
|||||||||||||
Oil (WTI) ($/Bbl) |
42.67 |
40.94 |
27.85 |
46.08 |
56.96 |
||||||||
Natural Gas (HH) ($/Mcf) |
2.65 |
1.94 |
1.73 |
1.98 |
2.49 |
||||||||
Crude Oil and Condensate ($/Bbl) - above (below) WTI |
|||||||||||||
US |
(0.81) |
(0.85) |
0.04 |
(0.75) |
(7.45) |
0.89 |
0.18 |
||||||
Trinidad |
(9.76) |
(13.40) |
3.64 |
(15.53) |
(27.25) |
(11.15) |
(10.23) |
||||||
Other Intl |
(6.77) |
(5.00) |
(1.76) |
(15.65) |
20.93 |
11.43 |
($3.20) |
||||||
NGLs - Realizations (% of WTI) |
41.1% |
40.0% |
1.1% |
35.0% |
36.6% |
23.7% |
28.5% |
||||||
Nat Gas ($/Mcf) - above (below) HH |
|||||||||||||
US |
(0.36) |
(0.40) |
0.04 |
(0.45) |
(0.62) |
(0.48) |
(0.29) |
||||||
Natural Gas Realizations ($/Mcf) |
|||||||||||||
Trinidad |
3.57 |
3.40 |
0.17 |
2.35 |
2.13 |
2.17 |
2.78 |
||||||
Other Intl |
5.47 |
4.60 |
0.87 |
4.73 |
4.36 |
4.32 |
4.88 |
||||||
Unit Costs ($/Boe) |
|||||||||||||
Lease and Well |
3.54 |
4.05 |
(0.51) |
3.45 |
4.32 |
4.14 |
4.28 |
||||||
Transportation Costs |
2.64 |
2.75 |
(0.11) |
2.74 |
2.67 |
2.62 |
2.66 |
||||||
General and Administrative |
1.54 |
1.85 |
(0.31) |
1.89 |
2.32 |
1.44 |
1.60 |
||||||
Gathering and Processing |
1.62 |
1.80 |
(0.18) |
1.74 |
1.71 |
1.62 |
1.63 |
||||||
Cash Operating Costs |
9.34 |
10.45 |
(1.11) |
9.82 |
11.02 |
9.82 |
10.17 |
||||||
DD&A |
11.81 |
12.45 |
(0.64) |
12.49 |
12.46 |
12.57 |
12.26 |
||||||
Expenses ($MM) |
|||||||||||||
Exploration and Dry Hole |
40 |
50 |
(10) |
51 |
27 |
40 |
36 |
||||||
Impairment (GAAP) |
142 |
79 |
305 |
1,573 |
228 |
||||||||
Impairment (excluding certain impairments (non-GAAP)) |
56 |
125 |
(69) |
52 |
66 |
57 |
69 |
||||||
Capitalized Interest |
7 |
8 |
(1) |
7 |
8 |
9 |
10 |
||||||
Net Interest |
53 |
54 |
(1) |
53 |
54 |
45 |
41 |
||||||
Taxes Other Than Income (% of Wellhead Revenue) |
5.1% |
7.0% |
-1.9% |
7.2% |
9.4% |
6.5% |
6.7% |
||||||
Income Taxes |
|||||||||||||
Effective Rate |
21.1% |
22.5% |
-1.3% |
19.2% |
20.6% |
68.4% |
23.4% |
||||||
Current Tax (Benefit) / Expense ($MM) |
36 |
30 |
6 |
23 |
17 |
(136) |
12 |
First Quarter and Full-Year 2021 Guidance
1Q 2021 Guidance Range |
FY 2021 Guidance Range |
2020 Act |
2019 Act |
||||||||
Crude Oil and Condensate (MBod) |
|||||||||||
US |
418.0 |
- |
428.0 |
433.0 |
- |
444.0 |
408.1 |
455.5 |
|||
Trinidad |
1.6 |
- |
2.4 |
1.0 |
- |
1.8 |
1.0 |
0.6 |
|||
Other Intl |
0.0 |
- |
0.2 |
0.0 |
- |
0.2 |
0.1 |
0.1 |
|||
Total |
419.6 |
- |
430.6 |
434.0 |
- |
446.0 |
409.2 |
456.2 |
|||
NGLs (MBbld) |
|||||||||||
Total |
125.0 |
- |
135.0 |
130.0 |
- |
170.0 |
136.0 |
134.1 |
|||
Natural Gas (MMcfd) |
|||||||||||
US |
1,095 |
- |
1,155 |
1,100 |
- |
1,200 |
1,040 |
1,069 |
|||
Trinidad |
200 |
- |
230 |
180 |
- |
220 |
180 |
260 |
|||
Other Intl |
15 |
- |
25 |
15 |
- |
25 |
32 |
37 |
|||
Total |
1,310 |
- |
1,410 |
1,295 |
- |
1,445 |
1,252 |
1,366 |
|||
Total Crude Oil Equivalent Volumes (MBoed) |
762.9 |
- |
800.6 |
779.8 |
- |
856.9 |
753.8 |
818.0 |
|||
Total MMBoe |
68.7 |
- |
72.1 |
284.6 |
- |
312.8 |
275.9 |
298.6 |
|||
Benchmark Price |
|||||||||||
Oil (WTI) ($/Bbl) |
39.40 |
57.04 |
|||||||||
Natural Gas (HH) ($/Mcf) |
2.08 |
2.62 |
|||||||||
Crude Oil and Condensate ($/Bbl) - above (below) WTI |
|||||||||||
US |
(0.80) |
- |
1.20 |
(0.55) |
- |
1.45 |
(0.75) |
0.70 |
|||
Trinidad |
(11.50) |
- |
(9.50) |
(12.40) |
- |
(10.40) |
(9.20) |
(9.88) |
|||
Other Intl |
(21.00) |
- |
(15.00) |
(19.20) |
- |
(17.20) |
3.68 |
0.36 |
|||
NGLs - Realizations (% of WTI) |
|||||||||||
Total |
43% |
- |
55% |
38% |
- |
50% |
34.0% |
28.1% |
|||
Nat Gas ($/Mcf) - above (below) HH |
|||||||||||
US |
1.75 |
- |
4.25 |
(0.25) |
- |
1.25 |
(0.47) |
(0.40) |
|||
Natural Gas Realizations ($/Mcf) |
|||||||||||
Trinidad |
3.10 |
- |
3.60 |
3.10 |
- |
3.60 |
2.57 |
2.72 |
|||
Other Intl |
5.45 |
- |
5.95 |
5.20 |
- |
6.20 |
4.66 |
4.44 |
|||
Capital Expenditures ($MM) |
900 |
- |
1,100 |
3,700 |
- |
4,100 |
3,490 |
6,234 |
|||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
3.60 |
- |
4.30 |
3.50 |
- |
4.20 |
3.85 |
4.58 |
|||
Transport Costs |
2.60 |
- |
3.00 |
2.65 |
- |
3.05 |
2.66 |
2.54 |
|||
General and Administrative |
1.60 |
- |
1.70 |
1.50 |
- |
1.60 |
1.75 |
1.64 |
|||
Gathering and Processing |
1.75 |
- |
1.85 |
1.65 |
- |
1.85 |
1.66 |
1.60 |
|||
Cash Operating Costs |
9.55 |
- |
10.85 |
9.30 |
- |
10.70 |
9.92 |
10.36 |
|||
Total DD&A |
12.60 |
- |
13.10 |
11.70 |
- |
12.70 |
12.32 |
12.56 |
|||
Expenses ($MM) |
|||||||||||
Exploration and Dry Hole |
35 |
- |
45 |
140 |
- |
180 |
159 |
168 |
|||
Impairment (GAAP) |
2,100 |
518 |
|||||||||
Impairment (excluding certain impairments (non-GAAP)) |
45 |
- |
95 |
255 |
- |
295 |
232 |
243 |
|||
Capitalized Interest |
5 |
- |
10 |
25 |
- |
30 |
31 |
38 |
|||
Net Interest |
45 |
- |
50 |
180 |
- |
185 |
205 |
185 |
|||
Taxes Other (% of Wellhead Revenue) |
6.0% |
- |
8.0% |
6.5% |
- |
7.5% |
6.6% |
6.9% |
|||
Income Taxes |
|||||||||||
Effective Rate |
21% |
- |
26% |
21% |
- |
26% |
18.2% |
22.9% |
|||
Deferred Ratio |
(5%) |
- |
5% |
0% |
- |
15% |
54.8% |
107.4% |
Fourth Quarter 2020 Results Webcast
Friday, February 26, 2021, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. 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
Category: Earnings
Endnotes
Glossary |
|
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 |
$MM |
Million United States dollars |
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 |
QoQ |
Quarter over quarter |
Trans |
Transportation expense |
USD |
United States dollar |
WTI |
West Texas Intermediate |
YoY |
Year over year |
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:
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.
Income Statements
In thousands of USD, except per share data (Unaudited) |
||||||||||||||
4Q 2020 |
3Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
||||||||||
Operating Revenues and Other |
||||||||||||||
Crude Oil and Condensate |
1,710,862 |
1,394,622 |
2,464,274 |
5,785,609 |
9,612,532 |
|||||||||
Natural Gas Liquids |
228,299 |
184,771 |
215,070 |
667,514 |
784,818 |
|||||||||
Natural Gas |
301,883 |
183,790 |
309,606 |
837,133 |
1,184,095 |
|||||||||
Gains (Losses) on Mark-to-Market |
69,304 |
(3,978) |
(62,347) |
1,144,737 |
180,275 |
|||||||||
Gathering, Processing and Marketing |
642,597 |
538,955 |
1,238,792 |
2,582,984 |
5,360,282 |
|||||||||
Gains (Losses) on Asset Dispositions, Net |
(5,600) |
(70,976) |
119,963 |
(46,883) |
123,613 |
|||||||||
Other, Net |
18,153 |
18,300 |
34,888 |
60,954 |
134,358 |
|||||||||
Total |
2,965,498 |
2,245,484 |
4,320,246 |
11,032,048 |
17,379,973 |
|||||||||
Operating Expenses |
||||||||||||||
Lease and Well |
260,896 |
227,473 |
334,538 |
1,063,374 |
1,366,993 |
|||||||||
Transportation Costs |
194,708 |
180,257 |
208,312 |
734,989 |
758,300 |
|||||||||
Gathering and Processing Costs |
119,172 |
114,790 |
127,615 |
459,211 |
479,102 |
|||||||||
Exploration Costs |
40,415 |
38,413 |
36,495 |
145,788 |
139,881 |
|||||||||
Dry Hole Costs |
20 |
12,604 |
— |
13,083 |
28,001 |
|||||||||
Impairments |
142,440 |
78,990 |
228,135 |
2,099,780 |
517,896 |
|||||||||
Marketing Costs |
622,941 |
521,351 |
1,237,259 |
2,697,729 |
5,351,524 |
|||||||||
Depreciation, Depletion and Amortization |
870,564 |
823,050 |
959,208 |
3,400,353 |
3,749,704 |
|||||||||
General and Administrative |
113,235 |
124,460 |
125,187 |
483,823 |
489,397 |
|||||||||
Taxes Other Than Income |
113,445 |
126,810 |
199,746 |
477,934 |
800,164 |
|||||||||
Total |
2,477,836 |
2,248,198 |
3,456,495 |
11,576,064 |
13,680,962 |
|||||||||
Operating Income (Loss) |
487,662 |
(2,714) |
863,751 |
(544,016) |
3,699,011 |
|||||||||
Other Income (Expense), Net |
(6,781) |
3,401 |
8,152 |
10,228 |
31,385 |
|||||||||
Income (Loss) Before Interest Expense |
480,881 |
687 |
871,903 |
(533,788) |
3,730,396 |
|||||||||
Interest Expense, Net |
53,121 |
53,242 |
40,695 |
205,266 |
185,129 |
|||||||||
Income (Loss) Before Income Taxes |
427,760 |
(52,555) |
831,208 |
(739,054) |
3,545,267 |
|||||||||
Income Tax Provision (Benefit) |
90,294 |
(10,088) |
194,687 |
(134,482) |
810,357 |
|||||||||
Net Income (Loss) |
337,466 |
(42,467) |
636,521 |
(604,572) |
2,734,910 |
|||||||||
Dividends Declared per Common Share |
0.3750 |
0.3750 |
0.2875 |
1.5000 |
1.0825 |
|||||||||
Net Income (Loss) Per Share |
||||||||||||||
Basic |
0.58 |
(0.07) |
1.10 |
(1.04) |
4.73 |
|||||||||
Diluted |
0.58 |
(0.07) |
1.10 |
(1.04) |
4.71 |
|||||||||
Average Number of Common Shares |
||||||||||||||
Basic |
579,624 |
579,055 |
578,219 |
578,949 |
577,670 |
|||||||||
Diluted |
580,885 |
579,055 |
580,849 |
578,949 |
580,777 |
Wellhead Volumes and Prices
(Unaudited) |
||||||||||||||||||||
4Q 2020 |
4Q 2019 |
% Change |
3Q 2020 |
FY 2020 |
FY 2019 |
% Change |
||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
||||||||||||||||||||
United States |
442.4 |
468.3 |
-6 |
% |
376.6 |
408.1 |
455.5 |
-10 |
% |
|||||||||||
Trinidad |
2.3 |
0.5 |
360 |
% |
1.0 |
1.0 |
0.6 |
67 |
% |
|||||||||||
Other International (B) |
0.1 |
0.1 |
0 |
% |
— |
0.1 |
0.1 |
0 |
% |
|||||||||||
Total |
444.8 |
468.9 |
-5 |
% |
377.6 |
409.2 |
456.2 |
-10 |
% |
|||||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
||||||||||||||||||||
United States |
41.86 |
57.14 |
-27 |
% |
40.19 |
38.65 |
57.74 |
-33 |
% |
|||||||||||
Trinidad |
32.91 |
46.43 |
-30 |
% |
25.41 |
30.20 |
47.16 |
-36 |
% |
|||||||||||
Other International (B) |
35.90 |
53.76 |
-33 |
% |
25.29 |
43.08 |
57.40 |
-25 |
% |
|||||||||||
Composite |
41.81 |
57.13 |
-27 |
% |
40.15 |
38.63 |
57.72 |
-33 |
% |
|||||||||||
Natural Gas Liquids Volumes (MBbld) (A) |
||||||||||||||||||||
United States |
141.4 |
144.0 |
-2 |
% |
140.1 |
136.0 |
134.1 |
1 |
% |
|||||||||||
Other International (B) |
— |
— |
— |
— |
— |
|||||||||||||||
Total |
141.4 |
144.0 |
-2 |
% |
140.1 |
136.0 |
134.1 |
1 |
% |
|||||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
||||||||||||||||||||
United States |
17.54 |
16.23 |
8 |
% |
14.34 |
13.41 |
16.03 |
-16 |
% |
|||||||||||
Other International (B) |
— |
— |
— |
— |
— |
|||||||||||||||
Composite |
17.54 |
16.23 |
8 |
% |
14.34 |
13.41 |
16.03 |
-16 |
% |
|||||||||||
Natural Gas Volumes (MMcfd) (A) |
||||||||||||||||||||
United States |
1,075 |
1,148 |
-6 |
% |
1,008 |
1,040 |
1,069 |
-3 |
% |
|||||||||||
Trinidad |
192 |
242 |
-21 |
% |
151 |
180 |
260 |
-31 |
% |
|||||||||||
Other International (B) |
25 |
35 |
-29 |
% |
31 |
32 |
37 |
-14 |
% |
|||||||||||
Total |
1,292 |
1,425 |
-9 |
% |
1,190 |
1,252 |
1,366 |
-8 |
% |
|||||||||||
Average Natural Gas Prices ($/Mcf) (C) |
||||||||||||||||||||
United States |
2.29 |
2.20 |
4 |
% |
1.49 |
1.61 |
2.22 |
-27 |
% |
|||||||||||
Trinidad |
3.57 |
2.78 |
28 |
% |
2.35 |
2.57 |
2.72 |
-6 |
% |
|||||||||||
Other International (B) |
5.47 |
4.88 |
12 |
% |
4.73 |
4.66 |
4.44 |
5 |
% |
|||||||||||
Composite |
2.54 |
2.36 |
8 |
% |
1.68 |
1.83 |
2.38 |
-23 |
% |
|||||||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
||||||||||||||||||||
United States |
763.0 |
803.6 |
-5 |
% |
684.7 |
717.5 |
767.8 |
-7 |
% |
|||||||||||
Trinidad |
34.2 |
40.9 |
-16 |
% |
26.2 |
30.9 |
44.0 |
-30 |
% |
|||||||||||
Other International (B) |
4.3 |
5.8 |
-26 |
% |
5.1 |
5.4 |
6.2 |
-13 |
% |
|||||||||||
Total |
801.5 |
850.3 |
-6 |
% |
716.0 |
753.8 |
818.0 |
-8 |
% |
|||||||||||
Total MMBoe (D) |
73.7 |
78.2 |
-6 |
% |
65.9 |
275.9 |
298.6 |
-8 |
% |
(A) |
Thousand barrels per day or million cubic feet per day, as applicable. |
||||||||||||||||||||
(B) |
Other International includes EOG's China and Canada operations. |
||||||||||||||||||||
(C) |
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2020). |
||||||||||||||||||||
(D) |
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
Balance Sheets
In thousands of USD, except share data (Unaudited) |
|||||
December 31, |
December 31, |
||||
2020 |
2019 |
||||
Current Assets |
|||||
Cash and Cash Equivalents |
3,328,928 |
2,027,972 |
|||
Accounts Receivable, Net |
1,522,256 |
2,001,658 |
|||
Inventories |
629,401 |
767,297 |
|||
Assets from Price Risk Management Activities |
64,559 |
1,299 |
|||
Income Taxes Receivable |
23,037 |
151,665 |
|||
Other |
293,987 |
323,448 |
|||
Total |
5,862,168 |
5,273,339 |
|||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
64,792,798 |
62,830,415 |
|||
Other Property, Plant and Equipment |
4,478,976 |
4,472,246 |
|||
Total Property, Plant and Equipment |
69,271,774 |
67,302,661 |
|||
Less: Accumulated Depreciation, Depletion and Amortization |
(40,673,147) |
(36,938,066) |
|||
Total Property, Plant and Equipment, Net |
28,598,627 |
30,364,595 |
|||
Deferred Income Taxes |
2,127 |
2,363 |
|||
Other Assets |
1,341,679 |
1,484,311 |
|||
Total Assets |
35,804,601 |
37,124,608 |
|||
Current Liabilities |
|||||
Accounts Payable |
1,681,193 |
2,429,127 |
|||
Accrued Taxes Payable |
205,754 |
254,850 |
|||
Dividends Payable |
217,419 |
166,273 |
|||
Liabilities from Price Risk Management Activities |
— |
20,194 |
|||
Current Portion of Long-Term Debt |
781,054 |
1,014,524 |
|||
Current Portion of Operating Lease Liabilities |
295,089 |
369,365 |
|||
Other |
279,595 |
232,655 |
|||
Total |
3,460,104 |
4,486,988 |
|||
Long-Term Debt |
5,035,351 |
4,160,919 |
|||
Other Liabilities |
2,147,932 |
1,789,884 |
|||
Deferred Income Taxes |
4,859,327 |
5,046,101 |
|||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,694,850 |
205,837 |
205,822 |
|||
Additional Paid in Capital |
5,945,024 |
5,817,475 |
|||
Accumulated Other Comprehensive Loss |
(12,328) |
(4,652) |
|||
Retained Earnings |
14,169,969 |
15,648,604 |
|||
Common Stock Held in Treasury, 124,265 Shares and 298,820 Shares |
(6,615) |
(26,533) |
|||
Total Stockholders' Equity |
20,301,887 |
21,640,716 |
|||
Total Liabilities and Stockholders' Equity |
35,804,601 |
37,124,608 |
Cash Flows Statements
In thousands of USD (Unaudited) |
|||||||||||
4Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
||||||||
Cash Flows from Operating Activities |
|||||||||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating |
|||||||||||
Net Income (Loss) |
337,466 |
636,521 |
(604,572) |
2,734,910 |
|||||||
Items Not Requiring (Providing) Cash |
|||||||||||
Depreciation, Depletion and Amortization |
870,564 |
959,208 |
3,400,353 |
3,749,704 |
|||||||
Impairments |
142,440 |
228,135 |
2,099,780 |
517,896 |
|||||||
Stock-Based Compensation Expenses |
32,942 |
42,415 |
146,396 |
174,738 |
|||||||
Deferred Income Taxes |
54,613 |
123,082 |
(186,390) |
631,658 |
|||||||
(Gains) Losses on Asset Dispositions, Net |
5,600 |
(119,963) |
46,883 |
(123,613) |
|||||||
Other, Net |
11,190 |
341 |
12,826 |
4,496 |
|||||||
Dry Hole Costs |
20 |
— |
13,083 |
28,001 |
|||||||
Mark-to-Market Commodity Derivative Contracts |
|||||||||||
Total (Gains) Losses |
(69,304) |
62,347 |
(1,144,737) |
(180,275) |
|||||||
Net Cash Received from Settlements of Commodity Derivative |
71,753 |
91,521 |
1,070,647 |
231,229 |
|||||||
Other, Net |
2,539 |
(253) |
1,354 |
962 |
|||||||
Changes in Components of Working Capital and Other Assets and |
|||||||||||
Accounts Receivable |
(464,105) |
(85,937) |
466,523 |
(91,792) |
|||||||
Inventories |
30,633 |
34,686 |
122,647 |
90,284 |
|||||||
Accounts Payable |
427,206 |
34,286 |
(795,267) |
168,539 |
|||||||
Accrued Taxes Payable |
(61,491) |
(47,925) |
(49,096) |
40,122 |
|||||||
Other Assets |
(90,336) |
(36,572) |
324,521 |
358,001 |
|||||||
Other Liabilities |
20,837 |
(38,304) |
8,098 |
(56,619) |
|||||||
Changes in Components of Working Capital Associated with |
(201,329) |
(76,384) |
74,734 |
(115,061) |
|||||||
Net Cash Provided by Operating Activities |
1,121,238 |
1,807,204 |
5,007,783 |
8,163,180 |
|||||||
Investing Cash Flows |
|||||||||||
Additions to Oil and Gas Properties |
(784,954) |
(1,285,003) |
(3,243,474) |
(6,151,885) |
|||||||
Additions to Other Property, Plant and Equipment |
(56,208) |
(83,291) |
(221,226) |
(270,641) |
|||||||
Proceeds from Sales of Assets |
2,985 |
104,883 |
191,928 |
140,292 |
|||||||
Other Investing Activities |
— |
(10,000) |
— |
(10,000) |
|||||||
Changes in Components of Working Capital Associated with |
201,329 |
76,384 |
(74,734) |
115,061 |
|||||||
Net Cash Used in Investing Activities |
(636,848) |
(1,197,027) |
(3,347,506) |
(6,177,173) |
|||||||
Financing Cash Flows |
|||||||||||
Long-Term Debt Borrowings |
— |
— |
1,483,852 |
— |
|||||||
Long-Term Debt Repayments |
— |
— |
(1,000,000) |
(900,000) |
|||||||
Dividends Paid |
(219,581) |
(167,349) |
(820,823) |
(588,200) |
|||||||
Treasury Stock Purchased |
(1,309) |
(2,914) |
(16,130) |
(25,152) |
|||||||
Proceeds from Stock Options Exercised and Employee Stock |
7,555 |
8,388 |
16,169 |
17,946 |
|||||||
Debt Issuance Costs |
(14) |
— |
(2,649) |
(5,016) |
|||||||
Repayment of Finance Lease Liabilities |
(6,135) |
(3,261) |
(19,444) |
(12,899) |
|||||||
Net Cash Used in Financing Activities |
(219,484) |
(165,136) |
(359,025) |
(1,513,321) |
|||||||
Effect of Exchange Rate Changes on Cash |
(1,534) |
(174) |
(296) |
(348) |
|||||||
Increase in Cash and Cash Equivalents |
263,372 |
444,867 |
1,300,956 |
472,338 |
|||||||
Cash and Cash Equivalents at Beginning of Period |
3,065,556 |
1,583,105 |
2,027,972 |
1,555,634 |
|||||||
Cash and Cash Equivalents at End of Period |
3,328,928 |
2,027,972 |
3,328,928 |
2,027,972 |
Non-GAAP Financial Measures
To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), 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 is included in the tables below and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com. |
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. 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), Total Debt, Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP. |
In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) |
|||||||||||
4Q 2020 |
|||||||||||
Before Tax |
Income Tax Impact |
After Tax |
Diluted Earnings per Share |
||||||||
Reported Net Income (GAAP) |
427,760 |
(90,294) |
337,466 |
0.58 |
|||||||
Adjustments: |
|||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts |
(69,304) |
15,211 |
(54,093) |
(0.10) |
|||||||
Net Cash Received from Settlements of Commodity Derivative Contracts |
71,753 |
(15,749) |
56,004 |
0.10 |
|||||||
Add: Losses on Asset Dispositions, Net |
5,600 |
(1,248) |
4,352 |
0.01 |
|||||||
Add: Certain Impairments |
86,451 |
(18,692) |
67,759 |
0.12 |
|||||||
Adjustments to Net Income |
94,500 |
(20,478) |
74,022 |
0.13 |
|||||||
Adjusted Net Income (Non-GAAP) |
522,260 |
(110,772) |
411,488 |
0.71 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
579,624 |
||||||||||
Diluted |
580,885 |
||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||
Basic |
579,624 |
||||||||||
Diluted |
580,885 |
||||||||||
3Q 2020 |
|||||||||||
Before Tax |
Income Tax Impact |
After Tax |
Diluted Earnings per Share |
||||||||
Reported Net Loss (GAAP) |
(52,555) |
10,088 |
(42,467) |
(0.07) |
|||||||
Adjustments: |
|||||||||||
Losses on Mark-to-Market Commodity Derivative Contracts |
3,978 |
(873) |
3,105 |
(0.01) |
|||||||
Net Cash Received from Settlements of Commodity Derivative Contracts |
275,133 |
(60,386) |
214,747 |
0.37 |
|||||||
Add: Losses on Asset Dispositions, Net |
70,976 |
(15,600) |
55,376 |
0.10 |
|||||||
Add: Certain Impairments |
26,531 |
(5,636) |
20,895 |
0.04 |
|||||||
Adjustments to Net Loss |
376,618 |
(82,495) |
294,123 |
0.50 |
|||||||
Adjusted Net Income (Non-GAAP) |
324,063 |
(72,407) |
251,656 |
0.43 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
579,055 |
||||||||||
Diluted |
579,055 |
||||||||||
Average Number of Common Shares (Non-GAAP) |
579,055 |
||||||||||
Basic |
580,609 |
||||||||||
Diluted |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) |
|||||||||||
4Q 2019 |
|||||||||||
Before Tax |
Income Tax Impact |
After Tax |
Diluted Earnings per Share |
||||||||
Reported Net Income (GAAP) |
831,208 |
(194,687) |
636,521 |
1.10 |
|||||||
Adjustments: |
|||||||||||
Losses on Mark-to-Market Commodity Derivative Contracts |
62,347 |
(13,684) |
48,663 |
0.08 |
|||||||
Net Cash Received from Settlements of Commodity Derivative Contracts |
91,521 |
(20,087) |
71,434 |
0.12 |
|||||||
Less: Gains on Asset Dispositions, Net |
(119,963) |
26,342 |
(93,621) |
(0.16) |
|||||||
Add: Certain Impairments |
158,725 |
(34,837) |
123,888 |
0.21 |
|||||||
Adjustments to Net Income |
192,630 |
(42,266) |
150,364 |
0.25 |
|||||||
Adjusted Net Income (Non-GAAP) |
1,023,838 |
(236,953) |
786,885 |
1.35 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
578,219 |
||||||||||
Diluted |
580,849 |
||||||||||
Average Number of Common Shares (Non-GAAP) |
578,219 |
||||||||||
Basic |
580,849 |
||||||||||
Diluted |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) |
|||||||||||
FY 2020 |
|||||||||||
Before Tax |
Income Tax Impact |
After Tax |
Diluted Earnings per Share |
||||||||
Reported Net Loss (GAAP) |
(739,054) |
134,482 |
(604,572) |
(1.04) |
|||||||
Adjustments: |
|||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts |
(1,144,737) |
251,247 |
(893,490) |
(1.55) |
|||||||
Net Cash Received from Settlements of Commodity Derivative Contracts |
1,070,647 |
(234,986) |
835,661 |
1.44 |
|||||||
Add: Losses on Asset Dispositions, Net |
46,883 |
(10,305) |
36,578 |
0.06 |
|||||||
Add: Certain Impairments |
1,868,465 |
(392,652) |
1,475,813 |
2.55 |
|||||||
Adjustments to Net Loss |
1,841,258 |
(386,696) |
1,454,562 |
2.50 |
|||||||
Adjusted Net Income (Non-GAAP) |
1,102,204 |
(252,214) |
849,990 |
1.46 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
578,949 |
||||||||||
Diluted |
578,949 |
||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||
Basic |
578,949 |
||||||||||
Diluted |
580,595 |
||||||||||
FY 2019 |
|||||||||||
Before Tax |
Income Tax Impact |
After Tax |
Diluted Earnings per Share |
||||||||
Reported Net Income (GAAP) |
3,545,267 |
(810,357) |
2,734,910 |
4.71 |
|||||||
Adjustments: |
|||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts |
(180,275) |
39,567 |
(140,708) |
(0.24) |
|||||||
Net Cash Received from Settlements of Commodity Derivative Contracts |
231,229 |
(50,750) |
180,479 |
0.31 |
|||||||
Less: Gains on Asset Dispositions, Net |
(123,613) |
27,252 |
(96,361) |
(0.17) |
|||||||
Add: Certain Impairments |
274,974 |
(60,351) |
214,623 |
0.37 |
|||||||
Adjustments to Net Income |
202,315 |
(44,282) |
158,033 |
0.27 |
|||||||
Adjusted Net Income (Non-GAAP) |
3,747,582 |
(854,639) |
2,892,943 |
4.98 |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
577,670 |
||||||||||
Diluted |
580,777 |
||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||
Basic |
577,670 |
||||||||||
Diluted |
580,777 |
Adjusted Net Income per Share
In thousands of USD, except share and per Boe data (Unaudited) |
|||||
3Q 2020 Adjusted Net Income per Share (Non-GAAP) |
0.43 |
||||
Realized Price |
|||||
4Q 2020 Composite Average Wellhead Revenue per Boe |
30.39 |
||||
Less: 3Q 2020 Composite Average Welhead Revenue per Boe |
(26.77) |
||||
Subtotal |
3.62 |
||||
Multiplied by: 4Q 2020 Crude Oil Equivalent Volumes (MMBoe) |
73.7 |
||||
Total Change in Revenue |
266,794 |
||||
Less: Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%) |
(17,342) |
||||
Net Change in Revenue |
249,452 |
||||
Less: Tax Benefit Imputed (based on 21%) |
(52,385) |
||||
Change in Net Income |
197,067 |
||||
Change in Diluted Earnings per Share |
0.34 |
||||
Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts |
|||||
4Q 2020 Net Cash Received from Settlement of Commodity Derivative Contracts |
71,753 |
||||
Less: Income Tax Impact |
(15,749) |
||||
After Tax - (a) |
56,004 |
||||
3Q 2020 Net Cash Received from Settlement of Commodity Derivative Contracts |
275,133 |
||||
Less: Income Tax Impact |
(60,386) |
||||
After Tax - (b) |
214,747 |
||||
Change in Net Income - (a) - (b) |
(158,743) |
||||
Change in Diluted Earnings per Share |
(0.27) |
||||
Wellhead Volumes |
|||||
4Q 2020 Crude Oil Equivalent Volumes (MMBoe) |
73.7 |
||||
Less: 3Q 2020 Crude Oil Equivalent Volumes (MMBoe) |
(65.9) |
||||
Subtotal |
7.8 |
||||
Times: 4Q 2020 Composite Average Margin per Boe (Non-GAAP) |
5.67 |
||||
Change in Revenue |
44,226 |
||||
Less: Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%) |
(2,875) |
||||
Net Change in Reveue |
41,351 |
||||
Less: Tax Benefit Imputed (based on 21%) |
(8,684) |
||||
Change in Net Income |
32,668 |
||||
Change in Diluted Earnings per Share |
0.06 |
||||
Operating Cost per Boe |
|||||
3Q 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) |
26.62 |
||||
Less: 4Q 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration |
(24.72) |
||||
Subtotal |
1.9 |
||||
Times: 4Q 2020 Crude Oil Equivalent Volumes (MMBoe) |
73.7 |
||||
Change in Before-Tax Net Income |
140,030 |
||||
Less: Tax Benefit Imputed (based on 21%) |
(29,406) |
||||
Change in Net Income |
110,624 |
||||
Change in Diluted Earnings per Share |
0.19 |
||||
Other Items |
(0.04) |
||||
4Q 2020 Adjusted Net Income per Share (Non-GAAP) |
0.71 |
||||
4Q 2020 Average Number of Common Shares (Non-GAAP) - Diluted |
580,885 |
Adjusted Net Income per Share
In thousands of USD, except share and per Boe data (Unaudited) |
|||||
FY 2019 Adjusted Net Income per Share (Non-GAAP) |
4.98 |
||||
Realized Price |
|||||
FY 2020 Composite Average Wellhead Revenue per Boe |
26.42 |
||||
Less: FY 2019 Composite Average Welhead Revenue per Boe |
(38.79) |
||||
Subtotal |
(12.37) |
||||
Multiplied by: FY 2020 Crude Oil Equivalent volumes (MMBoe) |
275.9 |
||||
Total Change in Revenue |
(3,412,883) |
||||
Less: Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%) |
221,837 |
||||
Net Change in Revenue |
(3,191,046) |
||||
Less: Tax Benefit Imputed (based on 21%) |
670,120 |
||||
Change in Net Income |
(2,520,926) |
||||
Change in Diluted Earnings per Share |
(4.34) |
||||
Net Cash Received (Paid) from Settlements of Commodity Derivative Contracts |
|||||
FY 2020 Net Cash Received from Settlement of Commodity Derivative Contracts |
1,070,647 |
||||
Less: Income Tax Impact |
(234,986) |
||||
After Tax - (a) |
835,661 |
||||
FY 2019 Net Cash Received from Settlement of Commodity Derivative Contracts |
231,229 |
||||
Less: Income Tax Impact |
(50,750) |
||||
After Tax - (b) |
180,479 |
||||
Change in Net Income - (a) - (b) |
655,182 |
||||
Change in Diluted Earnings per Share |
1.13 |
||||
Wellhead Volumes |
|||||
FY 2020 Crude Oil Equivalent Volumes (MMBoe) |
275.9 |
||||
Less: FY 2019 Crude Oil Equivalent Volumes (MMBoe) |
(298.6) |
||||
Subtotal |
(22.7) |
||||
Times: FY 2020 Composite Average Margin per Boe (Non-GAAP) |
0.29 |
||||
Change in Revenue |
(6,583) |
||||
Less: Taxes Other Than Income Benefit (Cost) Imputed (based on 6.5%) |
428 |
||||
Net Change in Reveue |
(6,155) |
||||
Less: Tax Benefit Imputed (based on 21%) |
1,293 |
||||
Change in Net Income |
(4,863) |
||||
Change in Diluted Earnings per Share |
(0.01) |
||||
Operating Cost per Boe |
|||||
FY 2019 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) |
27.6 |
||||
Less: FY 2020 Total Operating Cost per Boe (Non-GAAP) (including Total Exploration |
(26.13) |
||||
Subtotal |
1.47 |
||||
Times: FY 2020 Crude Oil Equivalent Volumes (MMBoe) |
275.9 |
||||
Change in Before-Tax Net Income |
405,573 |
||||
Less: Tax Benefit Imputed (based on 21%) |
(85,170) |
||||
Change in Net Income |
320,403 |
||||
Change in Diluted Earnings per Share |
0.55 |
||||
Other Items |
(0.85) |
||||
FY 2020 Adjusted Net Income per Share (Non-GAAP) |
1.46 |
||||
FY 2020 Average Number of Common Shares (Non-GAAP) - Diluted |
580,595 |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) |
||||||||||||||
4Q 2020 |
3Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
||||||||||
Net Cash Provided by Operating Activities (GAAP) |
1,121,238 |
1,213,553 |
1,807,204 |
5,007,783 |
8,163,180 |
|||||||||
Adjustments: |
||||||||||||||
Exploration Costs (excluding Stock-Based Compensation |
34,295 |
37,380 |
28,483 |
124,641 |
113,733 |
|||||||||
Other Non-Current Income Taxes - Net Receivable |
— |
— |
59,174 |
112,704 |
238,711 |
|||||||||
Changes in Components of Working Capital and Other |
||||||||||||||
Accounts Receivable |
464,105 |
260,829 |
85,937 |
(466,523) |
91,792 |
|||||||||
Inventories |
(30,633) |
(7,439) |
(34,686) |
(122,647) |
(90,284) |
|||||||||
Accounts Payable |
(427,206) |
37,755 |
(34,286) |
795,267 |
(168,539) |
|||||||||
Accrued Taxes Payable |
61,491 |
(73,482) |
47,925 |
49,096 |
(40,122) |
|||||||||
Other Assets |
90,336 |
(161,879) |
36,572 |
(324,521) |
(358,001) |
|||||||||
Other Liabilities |
(20,837) |
(51,664) |
38,304 |
(8,098) |
56,619 |
|||||||||
Changes in Components of Working Capital Associated |
201,329 |
6,091 |
76,384 |
(74,734) |
115,061 |
|||||||||
Discretionary Cash Flow (Non-GAAP) |
1,494,118 |
1,261,144 |
2,111,011 |
5,092,968 |
8,122,150 |
|||||||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-29 |
% |
-37 |
% |
||||||||||
Discretionary Cash Flow (Non-GAAP) |
1,494,118 |
1,261,144 |
2,111,011 |
5,092,968 |
8,122,150 |
|||||||||
Less: |
||||||||||||||
Total Cash Capital Expenditures Before Acquisitions |
(828,507) |
(499,305) |
(1,388,233) |
(3,490,148) |
(6,234,454) |
|||||||||
Free Cash Flow (Non-GAAP) (b) |
665,611 |
761,839 |
722,778 |
1,602,820 |
1,887,696 |
|||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month periods ended September 30, 2020 and December 31, 2020 and 2019 and twelve-month periods ended December 31, 2020 and 2019: |
||||||||||||||
Total Expenditures (GAAP) |
1,107,557 |
645,534 |
1,506,061 |
4,113,280 |
6,900,450 |
|||||||||
Less: |
||||||||||||||
Asset Retirement Costs |
(49,109) |
(42,650) |
(34,537) |
(117,322) |
(186,088) |
|||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment |
(1) |
— |
(1,680) |
(61) |
(2,266) |
|||||||||
Non-Cash Acquisition Costs of Unproved Properties |
(68,337) |
(80,757) |
(33,317) |
(196,825) |
(97,704) |
|||||||||
Non-Cash Finance Leases |
(100,485) |
— |
— |
(173,762) |
— |
|||||||||
Acquisition Costs of Proved Properties |
(61,118) |
(22,822) |
(48,294) |
(135,162) |
(379,938) |
|||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
828,507 |
499,305 |
1,388,233 |
3,490,148 |
6,234,454 |
|||||||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the three-month periods ending September 30, 2020 and December 31, 2020 and twelve-month periods ending December 31, 2020. The comparative prior periods shown have been revised to conform to this presentation. |
||||||||||||||
Maintenance Capital Expenditures |
||||||||||||||
The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to 4Q 2020 U.S. oil production. |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) |
||||||||
FY 2019 |
FY 2018 |
FY 2017 |
||||||
Net Cash Provided by Operating Activities (GAAP) |
8,163,180 |
7,768,608 |
4,265,336 |
|||||
Adjustments: |
||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
113,733 |
123,986 |
122,688 |
|||||
Other Non-Current Income Taxes - Net (Payable) Receivable |
238,711 |
148,993 |
(513,404) |
|||||
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||
Accounts Receivable |
91,792 |
368,180 |
392,131 |
|||||
Inventories |
(90,284) |
395,408 |
174,548 |
|||||
Accounts Payable |
(168,539) |
(439,347) |
(324,192) |
|||||
Accrued Taxes Payable |
(40,122) |
92,461 |
63,937 |
|||||
Other Assets |
(358,001) |
125,435 |
658,609 |
|||||
Other Liabilities |
56,619 |
(10,949) |
89,871 |
|||||
Changes in Components of Working Capital Associated with Investing and |
115,061 |
(301,083) |
(89,992) |
|||||
Discretionary Cash Flow (Non-GAAP) |
8,122,150 |
8,271,692 |
4,839,532 |
|||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease) |
-2 |
% |
71 |
% |
76 |
% |
||
Discretionary Cash Flow (Non-GAAP) |
8,122,150 |
8,271,692 |
4,839,532 |
|||||
Less: |
||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) |
(6,234,454) |
(6,172,950) |
(4,228,859) |
|||||
Free Cash Flow (Non-GAAP) (b) |
1,887,696 |
2,098,742 |
610,673 |
|||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017: |
||||||||
Total Expenditures (GAAP) |
6,900,450 |
6,706,359 |
4,612,746 |
|||||
Less: |
||||||||
Asset Retirement Costs |
(186,088) |
(69,699) |
(55,592) |
|||||
Non-Cash Expenditures of Other Property, Plant and Equipment |
(2,266) |
(49,484) |
— |
|||||
Non-Cash Acquisition Costs of Unproved Properties |
(97,704) |
(290,542) |
(255,711) |
|||||
Acquisition Costs of Proved Properties |
(379,938) |
(123,684) |
(72,584) |
|||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
6,234,454 |
6,172,950 |
4,228,859 |
|||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019. The comparative prior periods shown have been revised to conform to this presentation. |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) |
||||||||||||||
FY 2016 |
FY 2015 |
FY 2014 |
FY 2013 |
FY 2012 |
||||||||||
Net Cash Provided by Operating Activities (GAAP) |
2,359,063 |
3,595,165 |
8,649,155 |
7,329,414 |
5,236,777 |
|||||||||
Adjustments: |
||||||||||||||
Exploration Costs (excluding Stock-Based |
104,199 |
124,011 |
157,453 |
134,531 |
159,182 |
|||||||||
Excess Tax Benefits from Stock-Based Compensation |
29,357 |
26,058 |
99,459 |
55,831 |
67,035 |
|||||||||
Changes in Components of Working Capital and |
||||||||||||||
Accounts Receivable |
232,799 |
(641,412) |
(84,982) |
23,613 |
178,683 |
|||||||||
Inventories |
(170,694) |
(58,450) |
161,958 |
(53,402) |
156,762 |
|||||||||
Accounts Payable |
74,048 |
1,409,197 |
(543,630) |
(178,701) |
17,150 |
|||||||||
Accrued Taxes Payable |
(92,782) |
(11,798) |
(16,486) |
(75,142) |
(78,094) |
|||||||||
Other Assets |
40,636 |
(118,143) |
14,448 |
109,567 |
118,520 |
|||||||||
Other Liabilities |
16,225 |
66,257 |
(75,420) |
20,382 |
(36,114) |
|||||||||
Changes in Components of Working Capital |
156,102 |
(499,767) |
103,414 |
51,361 |
(74,158) |
|||||||||
Discretionary Cash Flow (Non-GAAP) |
2,748,953 |
3,891,118 |
8,465,369 |
7,417,454 |
5,745,743 |
|||||||||
Discretionary Cash Flow (Non-GAAP) - Percentage |
-29 |
% |
-54 |
% |
14 |
% |
29 |
% |
||||||
Discretionary Cash Flow (Non-GAAP) |
2,748,953 |
3,891,118 |
8,465,369 |
7,417,454 |
5,745,743 |
|||||||||
Less: |
||||||||||||||
Total Cash Capital Expenditures Before Acquisitions |
(2,706,397) |
(4,682,326) |
(8,292,090) |
(7,101,791) |
(7,539,994) |
|||||||||
Free Cash Flow (Non-GAAP) (b) |
42,556 |
(791,208) |
173,279 |
315,663 |
(1,794,251) |
|||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2016, 2015, 2014, 2013 and 2012: |
||||||||||||||
Total Expenditures (GAAP) |
6,554,053 |
5,216,413 |
8,631,906 |
7,361,457 |
7,753,828 |
|||||||||
Less: |
||||||||||||||
Asset Retirement Costs |
19,865 |
(53,470) |
(195,630) |
(134,445) |
(126,987) |
|||||||||
Non-Cash Expenditures of Other Property, Plant |
(16,585) |
— |
— |
— |
(65,791) |
|||||||||
Non-Cash Acquisition Costs of Unproved Properties |
(3,101,913) |
— |
(5,085) |
(5,007) |
(20,317) |
|||||||||
Acquisition Costs of Proved Properties |
(749,023) |
(480,617) |
(139,101) |
(120,214) |
(739) |
|||||||||
Total Cash Capital Expenditures Before Acquisitions |
2,706,397 |
4,682,326 |
8,292,090 |
7,101,791 |
7,539,994 |
|||||||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item. |
Total Expenditures
In millions of USD (Unaudited) |
|||||||||||||||||
4Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
FY 2018 |
FY 2017 |
||||||||||||
Exploration and Development Drilling |
592 |
1,086 |
2,664 |
4,951 |
4,935 |
3,132 |
|||||||||||
Facilities |
99 |
130 |
347 |
629 |
625 |
575 |
|||||||||||
Leasehold Acquisitions |
102 |
75 |
265 |
276 |
488 |
427 |
|||||||||||
Property Acquisitions |
61 |
48 |
135 |
380 |
124 |
73 |
|||||||||||
Capitalized Interest |
7 |
10 |
31 |
38 |
24 |
27 |
|||||||||||
Subtotal |
861 |
1,349 |
3,442 |
6,274 |
6,196 |
4,234 |
|||||||||||
Exploration Costs |
41 |
37 |
146 |
140 |
149 |
145 |
|||||||||||
Dry Hole Costs |
— |
— |
13 |
28 |
5 |
5 |
|||||||||||
Exploration and Development Expenditures |
902 |
1,386 |
3,601 |
6,442 |
6,350 |
4,384 |
|||||||||||
Asset Retirement Costs |
48 |
35 |
117 |
186 |
70 |
56 |
|||||||||||
Total Exploration and Development Expenditures |
950 |
1,421 |
3,718 |
6,628 |
6,420 |
4,440 |
|||||||||||
Other Property, Plant and Equipment |
157 |
85 |
395 |
272 |
286 |
173 |
|||||||||||
Total Expenditures |
1,107 |
1,506 |
4,113 |
6,900 |
6,706 |
4,613 |
EBITDAX and Adjusted EBITDAX
In thousands of USD (Unaudited) |
|||||||||||
4Q 2020 |
4Q 2019 |
FY 2020 |
FY 2019 |
||||||||
Net Income (Loss) (GAAP) |
337,466 |
636,521 |
(604,572) |
2,734,910 |
|||||||
Adjustments: |
|||||||||||
Interest Expense, Net |
53,121 |
40,695 |
205,266 |
185,129 |
|||||||
Income Tax Provision (Benefit) |
90,294 |
194,687 |
(134,482) |
810,357 |
|||||||
Depreciation, Depletion and Amortization |
870,564 |
959,208 |
3,400,353 |
3,749,704 |
|||||||
Exploration Costs |
40,415 |
36,495 |
145,788 |
139,881 |
|||||||
Dry Hole Costs |
20 |
— |
13,083 |
28,001 |
|||||||
Impairments |
142,440 |
228,135 |
2,099,780 |
517,896 |
|||||||
EBITDAX (Non-GAAP) |
1,534,320 |
2,095,741 |
5,125,216 |
8,165,878 |
|||||||
(Gains) Losses on MTM Commodity Derivative Contracts |
(69,304) |
62,347 |
(1,144,737) |
(180,275) |
|||||||
Net Cash Received from Settlements of Commodity Derivative Contracts |
71,753 |
91,521 |
1,070,647 |
231,229 |
|||||||
(Gains) Losses on Asset Dispositions, Net |
5,600 |
(119,963) |
46,883 |
(123,613) |
|||||||
Adjusted EBITDAX (Non-GAAP) |
1,542,369 |
2,129,646 |
5,098,009 |
8,093,219 |
|||||||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-28 |
% |
-37 |
% |
|||||||
Definitions |
|||||||||||
EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) |
|||||||||||
December 31, 2020 |
September 30, 2020 |
June 30, 2020 |
March 31, 2020 |
||||||||
Total Stockholders' Equity - (a) |
20,302 |
20,148 |
20,388 |
21,471 |
|||||||
Current and Long-Term Debt (GAAP) - (b) |
5,816 |
5,721 |
5,724 |
5,222 |
|||||||
Less: Cash |
(3,329) |
(3,066) |
(2,417) |
(2,907) |
|||||||
Net Debt (Non-GAAP) - (c) |
2,487 |
2,655 |
3,307 |
2,315 |
|||||||
Total Capitalization (GAAP) - (a) + (b) |
26,118 |
25,869 |
26,112 |
26,693 |
|||||||
Total Capitalization (Non-GAAP) - (a) + (c) |
22,789 |
22,803 |
23,695 |
23,786 |
|||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
22.3 |
% |
22.1 |
% |
21.9 |
% |
19.6 |
% |
|||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
10.9 |
% |
11.6 |
% |
14.0 |
% |
9.7 |
% |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) |
|||||||||||
December 31, |
September 30, |
June 30, 2019 |
March 31, 2019 |
||||||||
Total Stockholders' Equity - (a) |
21,641 |
21,124 |
20,630 |
19,904 |
|||||||
Current and Long-Term Debt (GAAP) - (b) |
5,175 |
5,177 |
5,179 |
6,081 |
|||||||
Less: Cash |
(2,028) |
(1,583) |
(1,160) |
(1,136) |
|||||||
Net Debt (Non-GAAP) - (c) |
3,147 |
3,594 |
4,019 |
4,945 |
|||||||
Total Capitalization (GAAP) - (a) + (b) |
26,816 |
26,301 |
25,809 |
25,985 |
|||||||
Total Capitalization (Non-GAAP) - (a) + (c) |
24,788 |
24,718 |
24,649 |
24,849 |
|||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
19.3 |
% |
19.7 |
% |
20.1 |
% |
23.4 |
% |
|||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
12.7 |
% |
14.5 |
% |
16.3 |
% |
19.9 |
% |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) |
|||||||||||
December 31, 2018 |
September 30, 2018 |
June 30, 2018 |
March 31, 2018 |
||||||||
Total Stockholders' Equity - (a) |
19,364 |
18,538 |
17,452 |
16,841 |
|||||||
Current and Long-Term Debt (GAAP) - (b) |
6,083 |
6,435 |
6,435 |
6,435 |
|||||||
Less: Cash |
(1,556) |
(1,274) |
(1,008) |
(816) |
|||||||
Net Debt (Non-GAAP) - (c) |
4,527 |
5,161 |
5,427 |
5,619 |
|||||||
Total Capitalization (GAAP) - (a) + (b) |
25,447 |
24,973 |
23,887 |
23,276 |
|||||||
Total Capitalization (Non-GAAP) - (a) + (c) |
23,891 |
23,699 |
22,879 |
22,460 |
|||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
23.9 |
% |
25.8 |
% |
26.9 |
% |
27.6 |
% |
|||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
18.9 |
% |
21.8 |
% |
23.7 |
% |
25.0 |
% |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) |
|||||||||||
December 31, 2017 |
September 30, 2017 |
June 30, 2017 |
March 31, 2017 |
||||||||
Total Stockholders' Equity - (a) |
16,283 |
13,922 |
13,902 |
13,928 |
|||||||
Current and Long-Term Debt (GAAP) - (b) |
6,387 |
6,387 |
6,987 |
6,987 |
|||||||
Less: Cash |
(834) |
(846) |
(1,649) |
(1,547) |
|||||||
Net Debt (Non-GAAP) - (c) |
5,553 |
5,541 |
5,338 |
5,440 |
|||||||
Total Capitalization (GAAP) - (a) + (b) |
22,670 |
20,309 |
20,889 |
20,915 |
|||||||
Total Capitalization (Non-GAAP) - (a) + (c) |
21,836 |
19,463 |
19,240 |
19,368 |
|||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
28.2 |
% |
31.4 |
% |
33.4 |
% |
33.4 |
% |
|||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
25.4 |
% |
28.5 |
% |
27.7 |
% |
28.1 |
% |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
December 31, |
September 30, |
June 30, 2016 |
March 31, 2016 |
December 31, 2015 |
||||||||||
Total Stockholders' Equity - (a) |
13,982 |
11,798 |
12,057 |
12,405 |
12,943 |
|||||||||
Current and Long-Term Debt (GAAP) - (b) |
6,986 |
6,986 |
6,986 |
6,986 |
6,660 |
|||||||||
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 |
|||||||||
Total Capitalization (Non-GAAP) - (a) + (c) |
19,368 |
17,735 |
18,263 |
18,723 |
18,884 |
|||||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
33.3 |
% |
37.2 |
% |
36.7 |
% |
36.0 |
% |
34.0 |
% |
||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
27.8 |
% |
33.5 |
% |
34.0 |
% |
33.7 |
% |
31.5 |
% |
Proved Reserves and Reserve Replacement Data
(Unaudited) |
|||||||||||
2020 Net Proved Reserves Reconciliation Summary |
United States |
Trinidad |
Other International |
Total |
|||||||
Crude Oil and Condensate (MMBbl) |
|||||||||||
Beginning Reserves |
1,694.0 |
0.3 |
0.1 |
1,694.4 |
|||||||
Revisions |
(225.4) |
— |
— |
(225.4) |
|||||||
Purchases in Place |
2.2 |
— |
— |
2.2 |
|||||||
Extensions, Discoveries and Other Additions |
194.7 |
0.9 |
— |
195.6 |
|||||||
Sales in Place |
(3.2) |
— |
— |
(3.2) |
|||||||
Production |
(149.4) |
(0.4) |
— |
(149.8) |
|||||||
Ending Reserves |
1,512.9 |
0.8 |
0.1 |
1,513.8 |
|||||||
Natural Gas Liquids (MMBbl) |
|||||||||||
Beginning Reserves |
739.7 |
— |
— |
739.7 |
|||||||
Revisions |
(59.8) |
— |
— |
(59.8) |
|||||||
Purchases in Place |
3.8 |
— |
— |
3.8 |
|||||||
Extensions, Discoveries and Other Additions |
180.2 |
— |
— |
180.2 |
|||||||
Sales in Place |
(1.4) |
— |
— |
(1.4) |
|||||||
Production |
(49.8) |
— |
— |
(49.8) |
|||||||
Ending Reserves |
812.7 |
— |
— |
812.7 |
|||||||
Natural Gas (Bcf) |
|||||||||||
Beginning Reserves |
5,034.8 |
276.1 |
58.8 |
5,369.7 |
|||||||
Revisions |
(497.7) |
4.8 |
1.6 |
(491.3) |
|||||||
Purchases in Place |
26.3 |
— |
— |
26.3 |
|||||||
Extensions, Discoveries and Other Additions |
1,077.9 |
53.9 |
— |
1,131.8 |
|||||||
Sales in Place |
(157.3) |
— |
— |
(157.3) |
|||||||
Production |
(441.4) |
(65.9) |
(11.6) |
(518.9) |
|||||||
Ending Reserves |
5,042.6 |
268.9 |
48.8 |
5,360.3 |
|||||||
Oil Equivalents (MMBoe) |
|||||||||||
Beginning Reserves |
3,272.8 |
46.3 |
10.0 |
3,329.1 |
|||||||
Revisions |
(368.1) |
0.8 |
0.2 |
(367.1) |
|||||||
Purchases in Place |
10.4 |
— |
— |
10.4 |
|||||||
Extensions, Discoveries and Other Additions |
554.6 |
9.8 |
— |
564.4 |
|||||||
Sales in Place |
(30.8) |
— |
— |
(30.8) |
|||||||
Production |
(272.8) |
(11.3) |
(2.0) |
(286.1) |
|||||||
Ending Reserves |
3,166.1 |
45.6 |
8.2 |
3,219.9 |
|||||||
Net Proved Developed Reserves (MMBoe) |
|||||||||||
At December 31, 2019 |
1,684.2 |
29.9 |
7.1 |
1,721.2 |
|||||||
At December 31, 2020 |
1,614.4 |
29.3 |
5.4 |
1,649.1 |
|||||||
2020 Exploration and Development Expenditures ($ Millions) |
|||||||||||
Acquisition Cost of Unproved Properties |
264.8 |
— |
— |
264.8 |
|||||||
Exploration Costs |
203.4 |
81.2 |
11.4 |
296.0 |
|||||||
Development Costs |
2,901.0 |
3.9 |
— |
2,904.9 |
|||||||
Total Drilling |
3,369.2 |
85.1 |
11.4 |
3,465.7 |
|||||||
Acquisition Cost of Proved Properties |
97.0 |
— |
38.2 |
135.2 |
|||||||
Asset Retirement Costs |
97.2 |
0.2 |
19.9 |
117.3 |
|||||||
Total Exploration and Development Expenditures |
3,563.4 |
85.3 |
69.5 |
3,718.2 |
|||||||
Gathering, Processing and Other |
394.9 |
0.1 |
0.1 |
395.1 |
|||||||
Total Expenditures |
3,958.3 |
85.4 |
69.6 |
4,113.3 |
|||||||
Proceeds from Sales in Place |
(191.9) |
— |
— |
(191.9) |
|||||||
Net Expenditures |
3,766.4 |
85.4 |
69.6 |
3,921.4 |
|||||||
Reserve Replacement Costs ($ / Boe) * |
|||||||||||
All-in Total, Net of Revisions |
16.53 |
8.03 |
248.00 |
16.32 |
|||||||
All-in Total, Excluding Revisions Due to Price |
6.85 |
8.03 |
248.00 |
6.98 |
|||||||
Reserve Replacement * |
|||||||||||
Drilling Only |
203 |
% |
87 |
% |
0 |
% |
197 |
% |
|||
All-in Total, Net of Revisions and Dispositions |
61 |
% |
94 |
% |
10 |
% |
62 |
% |
|||
All-in Total, Excluding Revisions Due to Price |
163 |
% |
94 |
% |
10 |
% |
159 |
% |
|||
All-in Total, Liquids |
46 |
% |
225 |
% |
0 |
% |
46 |
% |
|||
* See following reconciliation schedule for calculation methodology |
Reserve Replacement Cost Data
(Unaudited; in millions, except ratio data) |
|||||||||||
For the Twelve Months Ended December 31, 2020 |
United States |
Trinidad |
Other International |
Total |
|||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
3,563.4 |
85.3 |
69.5 |
3,718.2 |
|||||||
Less: Asset Retirement Costs |
(97.2) |
(0.2) |
(19.9) |
(117.3) |
|||||||
Non-Cash Acquisition Costs of Unproved Properties |
(196.8) |
— |
— |
(196.8) |
|||||||
Total Acquisition Costs of Proved Properties |
(97.0) |
— |
(38.2) |
(135.2) |
|||||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) |
3,172.4 |
85.1 |
11.4 |
3,268.9 |
|||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
3,563.4 |
85.3 |
69.5 |
3,718.2 |
|||||||
Less: Asset Retirement Costs |
(97.2) |
(0.2) |
(19.9) |
(117.3) |
|||||||
Non-Cash Acquisition Costs of Unproved Properties |
(196.8) |
— |
— |
(196.8) |
|||||||
Non-Cash Acquisition Costs of Proved Properties |
(14.6) |
— |
— |
(14.6) |
|||||||
Total Exploration and Development Expenditures (Non-GAAP) - (b) |
3,254.8 |
85.1 |
49.6 |
3,389.5 |
|||||||
Total Expenditures (GAAP) |
3,958.3 |
85.4 |
69.6 |
4,113.3 |
|||||||
Less: Asset Retirement Costs |
(97.2) |
(0.2) |
(19.9) |
(117.3) |
|||||||
Non-Cash Acquisition Costs of Unproved Properties |
(196.8) |
— |
— |
(196.8) |
|||||||
Non-Cash Acquisition Costs of Proved Properties |
(14.6) |
— |
— |
(14.6) |
|||||||
Non-Cash Capital - Other Miscellaneous |
(173.9) |
— |
— |
(173.9) |
|||||||
Total Cash Expenditures (Non-GAAP) |
3,475.8 |
85.2 |
49.7 |
3,610.7 |
|||||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
|||||||||||
Revisions Due to Price - (c) |
(278.2) |
— |
— |
(278.2) |
|||||||
Revisions Other Than Price |
(89.9) |
0.8 |
0.2 |
(88.9) |
|||||||
Purchases in Place |
10.4 |
— |
— |
10.4 |
|||||||
Extensions, Discoveries and Other Additions - (d) |
554.6 |
9.8 |
— |
564.4 |
|||||||
Total Proved Reserve Additions - (e) |
196.9 |
10.6 |
0.2 |
207.7 |
|||||||
Sales in Place |
(30.8) |
— |
— |
(30.8) |
|||||||
Net Proved Reserve Additions From All Sources - (f) |
166.1 |
10.6 |
0.2 |
176.9 |
|||||||
Production - (g) |
272.8 |
11.3 |
2.0 |
286.1 |
|||||||
Reserve Replacement Costs ($ / Boe) |
|||||||||||
Total Drilling, Before Revisions - (a / d) |
5.72 |
8.68 |
— |
5.79 |
|||||||
All-in Total, Net of Revisions - (b / e) |
16.53 |
8.03 |
248.00 |
16.32 |
|||||||
All-in Total, Excluding Revisions Due to Price - (b / (e - c)) |
6.85 |
8.03 |
248.00 |
6.98 |
|||||||
Reserve Replacement |
|||||||||||
Drilling Only - (d / g) |
203 |
% |
87 |
% |
0 |
% |
197 |
% |
|||
All-in Total, Net of Revisions and Dispositions - (f / g) |
61 |
% |
94 |
% |
10 |
% |
62 |
% |
|||
All-in Total, Excluding Revisions Due to Price - ((f - c) / g) |
163 |
% |
94 |
% |
10 |
% |
159 |
% |
|||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) |
|||||||||||
Revisions |
(285.2) |
— |
— |
(285.2) |
|||||||
Purchases in Place |
6.0 |
— |
— |
6.0 |
|||||||
Extensions, Discoveries and Other Additions - (h) |
374.9 |
0.9 |
— |
375.8 |
|||||||
Total Proved Reserve Additions |
95.7 |
0.9 |
— |
96.6 |
|||||||
Sales in Place |
(4.6) |
— |
— |
(4.6) |
|||||||
Net Proved Reserve Additions From All Sources - (i) |
91.1 |
0.9 |
— |
92.0 |
|||||||
Production - (j) |
199.2 |
0.4 |
— |
199.6 |
|||||||
Reserve Replacement - Liquids |
|||||||||||
Drilling Only - (h / j) |
188 |
% |
225 |
% |
0 |
% |
188 |
% |
|||
All-in Total, Net of Revisions and Dispositions - (i / j) |
46 |
% |
225 |
% |
0 |
% |
46 |
% |
Reserve Replacement Cost Data
(Unaudited; in millions, except ratio data) |
||
For the Twelve Months Ended December 31, 2020 |
||
Proved Developed Reserve Replacement Costs ($ / Boe) |
Total |
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
3,718.2 |
|
Less: Asset Retirement Costs |
(117.3) |
|
Acquisition Costs of Unproved Properties |
(264.8) |
|
Acquisition Costs of Proved Properties |
(135.2) |
|
Drillbit Exploration and Development Expenditures (Non-GAAP) - (k) |
3,200.9 |
|
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe) |
564.4 |
|
Add: Conversion of Proved Undeveloped Reserves to Proved Developed |
212.2 |
|
Less: Proved Undeveloped Extensions and Discoveries |
(456.1) |
|
Proved Developed Reserves - Extensions and Discoveries (MMBoe) |
320.5 |
|
Total Proved Reserves - Revisions (MMBoe) |
(367.1) |
|
Less: Proved Undeveloped Reserves - Revisions |
277.3 |
|
Proved Developed - Revisions Due to Price |
201.0 |
|
Proved Developed Reserves - Revisions Other Than Price (MMBoe) |
111.2 |
|
Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (l) |
431.7 |
|
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) - (k / l) |
7.41 |
Reserve Replacement Cost Data
In millions of USD, except reserves and ratio data (Unaudited) |
||||||||||||||||||||
2020 |
2019 |
2018 |
2017 |
2016 |
2015 |
2014 |
||||||||||||||
Total Costs Incurred in Exploration and |
3,718.2 |
6,628.2 |
6,419.7 |
4,439.4 |
6,445.2 |
4,928.3 |
7,904.8 |
|||||||||||||
Less: Asset Retirement Costs |
(117.3) |
(186.1) |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) |
|||||||||||||
Non-Cash Acquisition Costs of |
(196.8) |
(97.7) |
(290.5) |
(255.7) |
(3,101.8) |
— |
— |
|||||||||||||
Acquisition Costs of Proved |
(135.2) |
(379.9) |
(123.7) |
(72.6) |
(749.0) |
(480.6) |
(139.1) |
|||||||||||||
Total Exploration and Development |
3,268.9 |
5,964.5 |
5,935.8 |
4,055.5 |
2,614.3 |
4,394.2 |
7,570.1 |
|||||||||||||
Total Costs Incurred in Exploration and |
3,718.2 |
6,628.2 |
6,419.7 |
4,439.4 |
6,445.2 |
4,928.3 |
7,904.8 |
|||||||||||||
Less: Asset Retirement Costs |
(117.3) |
(186.1) |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) |
|||||||||||||
Non-Cash Acquisition Costs of |
(196.8) |
(97.7) |
(290.5) |
(255.7) |
(3,101.8) |
— |
— |
|||||||||||||
Non-Cash Acquisition Costs of |
(14.6) |
(52.3) |
(70.9) |
(26.2) |
(732.3) |
— |
— |
|||||||||||||
Total Exploration and Development Expenditures (Non-GAAP) - (b) |
3,389.5 |
6,292.1 |
5,988.6 |
4,101.9 |
2,631.0 |
4,874.8 |
7,709.2 |
|||||||||||||
Net Proved Reserve Additions From All |
||||||||||||||||||||
Revisions Due to Price - (c) |
(278.2) |
(59.7) |
34.8 |
154.0 |
(100.7) |
(573.8) |
52.2 |
|||||||||||||
Revisions Other Than Price |
(88.9) |
(0.3) |
(39.5) |
48.0 |
252.9 |
107.2 |
48.4 |
|||||||||||||
Purchases in Place |
10.4 |
16.8 |
11.6 |
2.3 |
42.3 |
56.2 |
14.4 |
|||||||||||||
Extensions, Discoveries and Other Additions - (d) |
564.4 |
750.0 |
669.7 |
420.8 |
209.0 |
245.9 |
519.2 |
|||||||||||||
Total Proved Reserve Additions - (e) |
207.7 |
706.8 |
676.6 |
625.1 |
403.5 |
(164.5) |
634.2 |
|||||||||||||
Sales in Place |
(30.8) |
(4.6) |
(10.8) |
(20.7) |
(167.6) |
(3.5) |
(36.3) |
|||||||||||||
Net Proved Reserve Additions From All Sources |
176.9 |
702.2 |
665.8 |
604.4 |
235.9 |
(168.0) |
597.9 |
|||||||||||||
Production |
286.1 |
300.9 |
265.0 |
224.4 |
207.1 |
211.2 |
219.1 |
|||||||||||||
Reserve Replacement Costs ($ / Boe) |
||||||||||||||||||||
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 |
Definitions
$/Boe |
U.S. Dollars per barrel of oil equivalent |
MMBoe |
Million barrels of oil equivalent |
Financial Commodity Derivative Contracts
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. |
||||
ICE Brent Differential Basis Swap Contracts |
|||||||
Prices received by EOG for its crude oil production generally vary from NYMEX WTI prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between ICE Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. |
|||||||
2020 |
Volume (Bbld) |
Weighted Average Price Differential ($/Bbl) |
|||||
May 2020 (CLOSED) |
10,000 |
4.92 |
|||||
Houston Differential Basis Swap Contracts |
|||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. |
|||||||
2020 |
Volume (Bbld) |
Weighted Average Price Differential ($/Bbl) |
|||||
May 2020 (CLOSED) |
10,000 |
1.55 |
|||||
Roll Differential Basis Swap Contracts |
|||||||
EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts. |
|||||||
2020 |
Volume (Bbld) |
Weighted Average Price Differential ($/Bbl) |
|||||
February 1, 2020 through June 30, 2020 (CLOSED) |
10,000 |
0.70 |
|||||
July 1, 2020 through September 30, 2020 (CLOSED) |
88,000 |
(1.16) |
|||||
October 1, 2020 through December 31, 2020 (CLOSED) |
66,000 |
(1.16) |
|||||
2021 |
|||||||
February 2021 (CLOSED) |
30,000 |
0.11 |
|||||
March 1, 2021 through December 31, 2021 |
125,000 |
0.17 |
|||||
2022 |
|||||||
January 1, 2022 through December 31, 2022 |
125,000 |
0.15 |
In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
||||
Crude Oil NYMEX WTI Price Swap Contracts |
|||||||
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl. |
|||||||
2020 |
Volume (Bbld) |
Weighted Average Price ($/Bbl) |
|||||
January 1, 2020 through March 31, 2020 (CLOSED) |
200,000 |
59.33 |
|||||
April 1, 2020 through May 31, 2020 (CLOSED) |
265,000 |
51.36 |
|||||
2021 |
|||||||
January 2021 (CLOSED) |
151,000 |
50.06 |
|||||
February 1, 2021 through March 31, 2021 |
201,000 |
51.29 |
|||||
April 1, 2021 through June 30, 2021 |
150,000 |
51.68 |
|||||
July 1, 2021 through September 30, 2021 |
150,000 |
52.71 |
|||||
In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
Crude Oil ICE Brent Price Swap Contracts |
|||||||
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl. |
|||||||
2020 |
Volume (Bbld) |
Weighted Average Price ($/Bbl) |
|||||
April 2020 (CLOSED) |
75,000 |
25.66 |
|||||
May 2020 (CLOSED) |
35,000 |
26.53 |
Mont Belvieu Propane Price Swap Contracts |
|||||||
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl. |
|||||||
2020 |
Volume (Bbld) |
Weighted Average Price ($/Bbl) |
|||||
January 1, 2020 through February 29, 2020 (CLOSED) |
4,000 |
21.34 |
|||||
March 1, 2020 through April 30, 2020 (CLOSED) |
25,000 |
17.92 |
|||||
2021 |
|||||||
January 2021 (CLOSED) |
15,000 |
29.44 |
|||||
February 1, 2021 through December 31, 2020 (CLOSED) |
15,000 |
29.44 |
|||||
In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $9.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
Natural Gas NYMEX Henry Hub Price Swap Contracts |
|||||||
Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts through February 18, 2021, with notional volumes sold (purchased) expressed in MMBtud and prices expressed in $/MMBtu. In January 2021, EOG executed the early termination provision granting EOG the right to terminate certain 2022 natural gas NYMEX Henry Hub price swap contracts with notional volumes of 20,000 MMBtud at a weighted average price of $2.75 per MMBtu for the period from January 1, 2022 through December 31, 2022. EOG received net cash of $0.6 million for the settlement of these contracts. |
|||||||
2021 |
Volume (MMBtud) |
Weighted Average Price ($/MMBtu) |
|||||
April 1, 2021 through September 30, 2021 |
(70,000) |
2.64 |
|||||
2022 |
|||||||
January 1, 2022 through December 31, 2022 (CLOSED) |
20,000 |
2.75 |
|||||
In December 2020 and January 2021, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu and for the period from April 1, 2021 through December 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.83 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time periods with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu. EOG received net cash of $16.5 million through February 18, 2021, for the settlement of certain of these contracts, and expects to receive net cash of $30.3 million during the remainder of 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table. |
|||||||
Natural Gas JKM Price Swap Contracts |
|||||||
Presented below is a comprehensive summary of EOG's natural gas JKM price swap contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. |
|||||||
2021 |
Volume (MMBtud) |
Weighted Average Price ($/MMBtu) |
|||||
April 1, 2021 through September 30, 2021 |
70,000 |
6.65 |
|||||
Natural Gas Collar Contracts |
||||||||||
EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. |
||||||||||
2020 |
Volume (MMBtud) |
Weighted Average Ceiling Price ($/MMBtu) |
Weighted Average Floor Price ($/MMBtu) |
|||||||
April 1, 2020 through July 31, 2020 (CLOSED) |
250,000 |
2.50 |
2.00 |
|||||||
In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
||||||||||
Rockies Differential Basis Swap Contracts |
|||||||
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. |
|||||||
2020 |
Volume (MMBtud) |
Weighted Average Price Differential ($/MMBtu) |
|||||
January 1, 2020 through December 31, 2020 (CLOSED) |
30,000 |
0.55 |
|||||
HSC Differential Basis Swap Contracts |
|||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. |
|||||||
2020 |
Volume (MMBtud) |
Weighted Average Price Differential ($/MMBtu) |
|||||
January 1, 2020 through December 31, 2020 (CLOSED) |
60,000 |
0.05 |
|||||
Waha Differential Basis Swap Contracts |
|||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. |
|||||||
2020 |
Volume (MMBtud) |
Weighted Average Price Differential ($/MMBtu) |
|||||
January 1, 2020 through April 30, 2020 (CLOSED) |
50,000 |
1.40 |
|||||
In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of 11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
|||||||
Definitions
Bbld |
Barrels per day |
||
$/Bbl |
Dollars per barrel |
||
ICE |
Intercontinental Exchange |
||
MMBtud |
Million British thermal units per day |
||
$/MMBtu |
Dollars per million British thermal units |
||
NYMEX |
U.S. New York Mercantile Exchange |
||
WTI |
West Texas Intermediate |
Direct After-Tax Rate of Return
The calculation of our direct after-tax rate of return (ATROR) with respect to our 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 our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
|
Direct ATROR |
|
Based on Cash Flow and Time Value of Money |
|
- Estimated future commodity prices and operating costs |
|
- Costs incurred to drill, complete and equip a well, including facilities |
|
Excludes Indirect Capital |
|
- Gathering and Processing and other Midstream |
|
- Land, Seismic, Geological and Geophysical |
|
Payback ~12 Months on 100% Direct ATROR Wells |
|
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
|
Return on Equity / Return on Capital Employed |
|
Based on GAAP Accrual Accounting |
|
Includes All Indirect Capital and Growth Capital for Infrastructure |
|
- Eagle Ford, Bakken, Permian Facilities |
|
- Gathering and Processing |
|
Includes Legacy Gas Capital and Capital from Mature Wells |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) |
|||||||||||
2020 |
2019 |
2018 |
2017 |
||||||||
Net Interest Expense (GAAP) |
205 |
185 |
245 |
||||||||
Tax Benefit Imputed (based on 21%) |
(43) |
(39) |
(51) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
162 |
146 |
194 |
||||||||
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) |
||||||||
Adjusted Net Income (Non-GAAP) - (c) |
850 |
2,893 |
3,218 |
||||||||
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 |
||||||||
Return on Capital Employed (ROCE) |
|||||||||||
GAAP Net Income (Loss) - [(a) + (b)] / (h) |
(1.9) |
% |
11.8 |
% |
15.8 |
% |
|||||
Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) |
4.3 |
% |
12.5 |
% |
14.9 |
% |
|||||
Return on Equity (ROE) |
|||||||||||
GAAP Net Income (Loss) - (b) / (e) |
(2.9) |
% |
13.3 |
% |
19.2 |
% |
|||||
Non-GAAP Adjusted Net Income - (c) / (e) |
4.1 |
% |
14.1 |
% |
18.1 |
% |
|||||
* Average for the current and immediately preceding year |
|||||||||||
(1) Detail of adjustments to Net Income (Loss) (GAAP): |
|||||||||||
Before Tax |
Income Tax Impact |
After Tax |
|||||||||
Year Ended December 31, 2020 |
|||||||||||
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 |
||||||||
Total |
1,841 |
(386) |
1,455 |
||||||||
Year Ended December 31, 2019 |
|||||||||||
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) |
||||||||
Total |
202 |
(44) |
158 |
||||||||
Year Ended December 31, 2018 |
|||||||||||
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) |
||||||||
Total |
(115) |
(86) |
(201) |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
2017 |
2016 |
2015 |
2014 |
2013 |
||||||||||
Net Interest Expense (GAAP) |
274 |
282 |
237 |
201 |
235 |
|||||||||
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
(82) |
|||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
178 |
183 |
154 |
131 |
153 |
|||||||||
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 |
|||||||||
Return on Capital Employed (ROCE) |
||||||||||||||
GAAP Net Income (Loss) - [(a) + (b)] / (h) |
13.4 |
% |
-4.8 |
% |
-21.6 |
% |
14.7 |
% |
12.1 |
% |
||||
Return on Equity (ROE) |
||||||||||||||
GAAP Net Income (Loss) - (b) / (e) |
17.1 |
% |
-8.1 |
% |
-29.5 |
% |
17.6 |
% |
15.3 |
% |
||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
2012 |
2011 |
2010 |
2009 |
2008 |
||||||||||
Net Interest Expense (GAAP) |
214 |
210 |
130 |
101 |
52 |
|||||||||
Tax Benefit Imputed (based on 35%) |
(75) |
(74) |
(46) |
(35) |
(18) |
|||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
139 |
136 |
84 |
66 |
34 |
|||||||||
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 |
|||||||||
Return on Capital Employed (ROCE) |
||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) |
4.0 |
% |
7.7 |
% |
1.8 |
% |
5.4 |
% |
26.4 |
% |
||||
Return on Equity (ROE) |
||||||||||||||
GAAP Net Income - (b) / (e) |
4.4 |
% |
9.5 |
% |
1.6 |
% |
5.8 |
% |
30.5 |
% |
||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
2007 |
2006 |
2005 |
2004 |
2003 |
||||||||||
Net Interest Expense (GAAP) |
47 |
43 |
63 |
63 |
59 |
|||||||||
Tax Benefit Imputed (based on 35%) |
(16) |
(15) |
(22) |
(22) |
(21) |
|||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
31 |
28 |
41 |
41 |
38 |
|||||||||
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 |
|||||||||
Return on Capital Employed (ROCE) |
||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) |
15.7 |
% |
24.7 |
% |
30.0 |
% |
18.2 |
% |
15.3 |
% |
||||
Return on Equity (ROE) |
||||||||||||||
GAAP Net Income - (b) / (e) |
17.3 |
% |
26.2 |
% |
34.7 |
% |
24.2 |
% |
22.1 |
% |
||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) |
||||||||||||||
2002 |
2001 |
2000 |
1999 |
1998 |
||||||||||
Net Interest Expense (GAAP) |
60 |
45 |
61 |
62 |
||||||||||
Tax Benefit Imputed (based on 35%) |
(21) |
(16) |
(21) |
(22) |
||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
39 |
29 |
40 |
40 |
||||||||||
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 |
||||||||||
Return on Capital Employed (ROCE) |
||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) |
4.8 |
% |
18.2 |
% |
20.2 |
% |
27.0 |
% |
||||||
Return on Equity (ROE) |
||||||||||||||
GAAP Net Income - (b) / (e) |
5.2 |
% |
26.4 |
% |
31.6 |
% |
47.2 |
% |
||||||
* Average for the current and immediately preceding year |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||||
1Q 2020 |
2Q 2020 |
3Q 2020 |
4Q 2020 |
||||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation |
|||||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
79,548 |
56,733 |
65,873 |
73,740 |
|||||||
Crude Oil and Condensate |
2,065,498 |
614,627 |
1,394,622 |
1,710,862 |
|||||||
Natural Gas Liquids |
160,535 |
93,909 |
184,771 |
228,299 |
|||||||
Natural Gas |
209,764 |
141,696 |
183,790 |
301,883 |
|||||||
Total Wellhead Revenues - (b) |
2,435,797 |
850,232 |
1,763,183 |
2,241,044 |
|||||||
Operating Costs |
|||||||||||
Lease and Well |
329,659 |
245,346 |
227,473 |
260,896 |
|||||||
Transportation Costs |
208,296 |
151,728 |
180,257 |
194,708 |
|||||||
Gathering and Processing Costs |
128,482 |
96,767 |
114,790 |
119,172 |
|||||||
General and Administrative |
114,273 |
131,855 |
124,460 |
113,235 |
|||||||
Taxes Other Than Income |
157,360 |
80,319 |
126,810 |
113,445 |
|||||||
Interest Expense, Net |
44,690 |
54,213 |
53,242 |
53,121 |
|||||||
Total Cash Cost (excluding DD&A and Total Exploration Costs) - (c) |
982,760 |
760,228 |
827,032 |
854,577 |
|||||||
Depreciation, Depletion and Amortization (DD&A) |
1,000,060 |
706,679 |
823,050 |
870,564 |
|||||||
Total Operating Cost (excluding Total Exploration Costs) - (d) |
1,982,820 |
1,466,907 |
1,650,082 |
1,725,141 |
|||||||
Exploration Costs |
39,677 |
27,283 |
38,413 |
40,415 |
|||||||
Dry Hole Costs |
372 |
87 |
12,604 |
20 |
|||||||
Impairments |
1,572,935 |
305,415 |
78,990 |
142,440 |
|||||||
Total Exploration Costs |
1,612,984 |
332,785 |
130,007 |
182,875 |
|||||||
Less: Certain Impairments (Non-GAAP) |
(1,516,316) |
(239,167) |
(26,531) |
(86,451) |
|||||||
Total Exploration Costs (Non-GAAP) |
96,668 |
93,618 |
103,476 |
96,424 |
|||||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) |
2,079,488 |
1,560,525 |
1,753,558 |
1,821,565 |
|||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
30.62 |
14.99 |
26.77 |
30.39 |
|||||||
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / |
12.36 |
13.40 |
12.56 |
11.60 |
|||||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration |
18.26 |
1.59 |
14.21 |
18.79 |
|||||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) |
24.93 |
25.86 |
25.05 |
23.41 |
|||||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a) |
5.69 |
(10.87) |
1.72 |
6.98 |
|||||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - |
26.15 |
27.51 |
26.62 |
24.72 |
|||||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration |
4.47 |
(12.52) |
0.15 |
5.67 |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||||
2020 |
2019 |
2018 |
2017 |
||||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation |
|||||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
275,893 |
298,565 |
262,516 |
222,251 |
|||||||
Crude Oil and Condensate |
5,785,609 |
9,612,532 |
9,517,440 |
6,256,396 |
|||||||
Natural Gas Liquids |
667,514 |
784,818 |
1,127,510 |
729,561 |
|||||||
Natural Gas |
837,133 |
1,184,095 |
1,301,537 |
921,934 |
|||||||
Total Wellhead Revenues - (b) |
7,290,256 |
11,581,445 |
11,946,487 |
7,907,891 |
|||||||
Operating Costs |
|||||||||||
Lease and Well |
1,063,374 |
1,366,993 |
1,282,678 |
1,044,847 |
|||||||
Transportation Costs |
734,989 |
758,300 |
746,876 |
740,352 |
|||||||
Gathering and Processing Costs |
459,211 |
479,102 |
436,973 |
148,775 |
|||||||
General and Administrative |
483,823 |
489,397 |
426,969 |
434,467 |
|||||||
Less: Legal Settlement - Early Leasehold Termination |
— |
— |
— |
(10,202) |
|||||||
Less: Joint Venture Transaction Costs |
— |
— |
— |
(3,056) |
|||||||
Less: Joint Interest Billings Deemed Uncollectible |
— |
— |
— |
(4,528) |
|||||||
General and Administrative (Non-GAAP) |
483,823 |
489,397 |
426,969 |
416,681 |
|||||||
Taxes Other Than Income |
477,934 |
800,164 |
772,481 |
544,662 |
|||||||
Interest Expense, Net |
205,266 |
185,129 |
245,052 |
274,372 |
|||||||
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) |
3,424,597 |
4,079,085 |
3,911,029 |
3,169,689 |
|||||||
Depreciation, Depletion and Amortization (DD&A) |
3,400,353 |
3,749,704 |
3,435,408 |
3,409,387 |
|||||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) |
6,824,950 |
7,828,789 |
7,346,437 |
6,579,076 |
|||||||
Exploration Costs |
145,788 |
139,881 |
148,999 |
145,342 |
|||||||
Dry Hole Costs |
13,083 |
28,001 |
5,405 |
4,609 |
|||||||
Impairments |
2,099,780 |
517,896 |
347,021 |
479,240 |
|||||||
Total Exploration Costs |
2,258,651 |
685,778 |
501,425 |
629,191 |
|||||||
Less: Certain Impairments (Non-GAAP) |
(1,868,465) |
(274,974) |
(152,671) |
(261,452) |
|||||||
Total Exploration Costs (Non-GAAP) |
390,186 |
410,804 |
348,754 |
367,739 |
|||||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) |
7,215,136 |
8,239,593 |
7,695,191 |
6,946,815 |
|||||||
Cost per Barrel of Oil Equivalent |
|||||||||||
In thousands of USD, except Boe and per Boe amounts (Unaudited) |
|||||||||||
2020 |
2019 |
2018 |
2017 |
||||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
26.42 |
38.79 |
45.51 |
35.58 |
|||||||
Total Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) |
12.39 |
13.66 |
14.90 |
14.25 |
|||||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration |
14.03 |
25.13 |
30.61 |
21.33 |
|||||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - |
24.71 |
26.22 |
27.99 |
29.59 |
|||||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - |
1.71 |
12.57 |
17.52 |
5.99 |
|||||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - |
26.13 |
27.60 |
29.32 |
31.24 |
|||||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - |
0.29 |
11.19 |
16.19 |
4.34 |
Cost per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) |
||||||||
2016 |
2015 |
2014 |
||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation |
||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
204,929 |
208,862 |
217,073 |
|||||
Crude Oil and Condensate |
4,317,341 |
4,934,562 |
9,742,480 |
|||||
Natural Gas Liquids |
437,250 |
407,658 |
934,051 |
|||||
Natural Gas |
742,152 |
1,061,038 |
1,916,386 |
|||||
Total Wellhead Revenues - (b) |
5,496,743 |
6,403,258 |
12,592,917 |
|||||
Operating Costs |
||||||||
Lease and Well |
927,452 |
1,182,282 |
1,416,413 |
|||||
Transportation Costs |
764,106 |
849,319 |
972,176 |
|||||
Gathering and Processing Costs |
122,901 |
146,156 |
145,800 |
|||||
General and Administrative |
394,815 |
366,594 |
402,010 |
|||||
Less: Voluntary Retirement Expense |
(42,054) |
— |
— |
|||||
Less: Acquisition Costs |
(5,100) |
— |
— |
|||||
Less: Legal Settlement - Early Leasehold Termination |
— |
(19,355) |
— |
|||||
General and Administrative (Non-GAAP) |
347,661 |
347,239 |
402,010 |
|||||
Taxes Other Than Income |
349,710 |
421,744 |
757,564 |
|||||
Interest Expense, Net |
281,681 |
237,393 |
201,458 |
|||||
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) |
2,793,511 |
3,184,133 |
3,895,421 |
|||||
Depreciation, Depletion and Amortization (DD&A) |
3,553,417 |
3,313,644 |
3,997,041 |
|||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) |
6,346,928 |
6,497,777 |
7,892,462 |
|||||
Exploration Costs |
124,953 |
149,494 |
184,388 |
|||||
Dry Hole Costs |
10,657 |
14,746 |
48,490 |
|||||
Impairments |
620,267 |
6,613,546 |
743,575 |
|||||
Total Exploration Costs |
755,877 |
6,777,786 |
976,453 |
|||||
Less: Certain Impairments (Non-GAAP) |
(320,617) |
(6,307,593) |
(824,312) |
|||||
Total Exploration Costs (Non-GAAP) |
435,260 |
470,193 |
152,141 |
|||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) |
6,782,188 |
6,967,970 |
8,044,603 |
|||||
Cost per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) |
||||||||
2016 |
2015 |
2014 |
||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
26.82 |
30.66 |
58.01 |
|||||
Total Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - |
13.64 |
15.25 |
17.95 |
|||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration |
13.18 |
15.41 |
40.06 |
|||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - |
30.98 |
31.11 |
36.38 |
|||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - |
(4.16) |
(0.45) |
21.63 |
|||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - |
33.10 |
33.36 |
37.08 |
|||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - |
(6.28) |
(2.70) |
20.93 |
Quarter and Full Year Guidance
(Unaudited) |
|||||||||||||||
(a) First Quarter and Full Year 2021 Forecast |
|||||||||||||||
The forecast items for the first quarter and full year 2021 set forth below 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. |
|||||||||||||||
(b) Capital Expenditures |
|||||||||||||||
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. |
|||||||||||||||
(c) Benchmark Commodity Pricing |
|||||||||||||||
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. |
|||||||||||||||
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. |
|||||||||||||||
Estimated Ranges for First Quarter and Full Year 2021 |
1Q 2021 |
FY 2021 |
|||||||||||||
Daily Sales Volumes |
|||||||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||||||
United States |
418.0 |
- |
428.0 |
433.0 |
- |
444.0 |
|||||||||
Trinidad |
1.6 |
- |
2.4 |
1.0 |
- |
1.8 |
|||||||||
Other International |
0.0 |
- |
0.2 |
0.0 |
- |
0.2 |
|||||||||
Total |
419.6 |
- |
430.6 |
434.0 |
- |
446.0 |
|||||||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||||||
Total |
125.0 |
- |
135.0 |
130.0 |
- |
170.0 |
|||||||||
Natural Gas Volumes (MMcfd) |
|||||||||||||||
United States |
1,095 |
- |
1,155 |
1,100 |
- |
1,200 |
|||||||||
Trinidad |
200 |
- |
230 |
180 |
- |
220 |
|||||||||
Other International |
15 |
- |
25 |
15 |
- |
25 |
|||||||||
Total |
1,310 |
- |
1,410 |
1,295 |
- |
1,445 |
|||||||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||||||
United States |
725.5 |
- |
755.5 |
746.3 |
- |
814.0 |
|||||||||
Trinidad |
34.9 |
- |
40.7 |
31.0 |
- |
38.5 |
|||||||||
Other International |
2.5 |
- |
4.4 |
2.5 |
- |
4.4 |
|||||||||
Total |
762.9 |
- |
800.6 |
779.8 |
- |
856.9 |
|||||||||
Capital Expenditures ($MM) |
900 |
- |
1,100 |
3,700 |
- |
4,100 |
Quarter and Full Year Guidance
(Unaudited) |
|||||||||||||||||||
Estimated Ranges for First Quarter and Full Year 2021 |
1Q 2021 |
FY 2021 |
|||||||||||||||||
Operating Costs |
|||||||||||||||||||
Unit Costs ($/Boe) |
|||||||||||||||||||
Lease and Well |
3.60 |
- |
4.30 |
3.50 |
- |
4.20 |
|||||||||||||
Transportation Costs |
2.60 |
- |
3.00 |
2.65 |
- |
3.05 |
|||||||||||||
Gathering and Processing |
1.75 |
- |
1.85 |
1.65 |
- |
1.85 |
|||||||||||||
Depreciation, Depletion and Amortization |
12.60 |
- |
13.10 |
11.70 |
- |
12.70 |
|||||||||||||
General and Administrative |
1.60 |
- |
1.70 |
1.50 |
- |
1.60 |
|||||||||||||
Expenses ($MM) |
|||||||||||||||||||
Exploration and Dry Hole |
35 |
- |
45 |
140 |
- |
180 |
|||||||||||||
Impairment |
45 |
- |
95 |
255 |
- |
295 |
|||||||||||||
Capitalized Interest |
5 |
- |
10 |
25 |
- |
30 |
|||||||||||||
Net Interest |
45 |
- |
50 |
180 |
- |
185 |
|||||||||||||
Taxes Other Than Income (% of Wellhead Revenue) |
6.0 |
% |
- |
8.0 |
% |
6.5 |
% |
- |
7.5 |
% |
|||||||||
Income Taxes |
|||||||||||||||||||
Effective Rate |
21 |
% |
- |
26 |
% |
21 |
% |
- |
26 |
% |
|||||||||
Deferred Ratio |
(5) |
% |
- |
5 |
% |
0 |
% |
- |
15 |
% |
|||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||||||||||
Differentials |
|||||||||||||||||||
United States - above (below) WTI |
(0.80) |
- |
1.20 |
(0.55) |
- |
1.45 |
|||||||||||||
Trinidad - above (below) WTI |
(11.50) |
- |
(9.50) |
(12.40) |
- |
(10.40) |
|||||||||||||
Other International - above (below) WTI |
(21.00) |
- |
(15.00) |
(19.20) |
- |
(17.20) |
|||||||||||||
Natural Gas Liquids |
|||||||||||||||||||
Realizations as % of WTI |
43 |
% |
- |
55 |
% |
38 |
% |
- |
50 |
% |
|||||||||
Natural Gas ($/Mcf) |
|||||||||||||||||||
Differentials |
|||||||||||||||||||
United States - above (below) NYMEX Henry Hub |
1.75 |
- |
4.25 |
(0.25) |
- |
1.25 |
|||||||||||||
Realizations |
|||||||||||||||||||
Trinidad |
3.10 |
- |
3.60 |
3.10 |
- |
3.60 |
|||||||||||||
Other International |
5.45 |
- |
5.95 |
5.20 |
- |
6.20 |
Definitions
$/Bbl |
U.S. Dollars per barrel |
||||||||||||
$/Boe |
U.S. Dollars per barrel of oil equivalent |
||||||||||||
$/Mcf |
U.S. Dollars per thousand cubic feet |
||||||||||||
$MM |
U.S. Dollars in millions |
||||||||||||
MBbld |
Thousand barrels per day |
||||||||||||
MBoed |
Thousand barrels of oil equivalent per day |
||||||||||||
MMcfd |
Million cubic feet per day |
||||||||||||
NYMEX |
U.S. New York Mercantile Exchange |
||||||||||||
WTI |
West Texas Intermediate |
SOURCE EOG Resources, Inc.