EX-99.1 2 exh99-1110520.htm PRESS RELEASE OF EOG RESOURCES, INC.
EXHIBIT 99.1
November 5, 2020
EOG Resources Reports Third Quarter 2020 Results; Adds Premium Natural Gas Play in South Texas; Provides Three-Year Outlook
•Identified 21 Tcf Net Resource Potential and 1,250 Net Premium Locations in New South Texas Natural Gas Play
•Added a Total of 1,400 Net Premium Locations to Drilling Inventory Which Now Totals 11,500 Locations
•Generated $1.2 Billion Net Cash Provided by Operating Activities and Significant Free Cash Flow
•Capital Expenditures 23% Below Target and Crude Oil Production 2% Above Target
•Per-Unit Cash Operating Costs Below Targets
•Introduced Three-Year Outlook with 70-80% Cash Flow Reinvestment
HOUSTON – (PR Newswire) – EOG Resources, Inc. (EOG) today reported a third quarter 2020 net loss of $42 million, or $0.07 per share, compared with third quarter 2019 net income of $615 million, or $1.06 per share.
Adjusted non-GAAP net income for the third quarter 2020 was $252 million, or $0.43 per share, compared with adjusted non-GAAP net income of $654 million, or $1.13 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Third Quarter 2020 Review
EOG continued to respond aggressively to adverse market conditions by sharply lowering operating and capital costs as well as deferring production volumes to future periods. Reductions to operating costs were offset by lower commodity prices and production volumes, resulting in lower earnings in the third quarter 2020 compared with the same prior year period. Realized crude oil prices were $40.15 per barrel in the third quarter, down 29 percent from the same prior year period, while natural gas prices declined 21 percent, to $1.68 per thousand cubic feet. These declines were partially offset by an increase in natural gas liquids prices in the third quarter to $14.34 per barrel, up 13 percent compared with the same prior year period.
Compared with the third quarter 2019, total company crude oil volumes were 19 percent lower, at 377,600 barrels of oil per day (Bopd). Natural gas liquids production was one percent lower and natural gas volumes were 13 percent lower, contributing to 14 percent lower total company daily production. EOG continued to return shut-in wells to production during the third quarter, and nearly all shut-in wells were back on production by the end of September. On average, 28,000 Bopd was shut-in during the third quarter. EOG also began initial production from approximately 100 net new wells in the third quarter, after deferring such activity earlier in the year in response to lower oil prices.

Lease and well costs declined 24 percent on a per-unit basis compared with the same prior year period, driving an overall reduction in per-unit operating costs. Most of the lease and well cost savings were based on sustainable efficiency improvements in well-site maintenance, equipment repair, managing offset completions and other production operations.
Net cash provided by operating activities was $1.2 billion. Excluding changes in working capital and certain other items, EOG generated $1.3 billion of discretionary cash flow. The company incurred total expenditures of $646 million, including $499 million of capital expenditures before acquisitions, non‐cash transactions and asset retirement costs, resulting in $762 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
“Our operational execution continues to be excellent,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “I’m grateful to all EOG employees during these unusual times. We continue to exceed expectations by optimizing production volumes and reducing costs while maintaining our strong safety and environmental performance.
“Notably, we are not playing defense in the current challenging environment. In fact, the opposite is true: we are aggressively moving EOG forward, advancing new plays, identifying innovative solutions to lower costs and improve well productivity, sharpening our technological edge and further demonstrating our commitment to sustainability. All of this is driven from the bottom up by a decentralized organization and a unique culture. This year more than ever, we are focused on investing in our people and enhancing our culture to sustain our competitive advantage and enable EOG to play an increasingly vital role in meeting the long-term global energy needs.”
New South Texas Natural Gas Play and Premium Inventory Update
EOG has made a large natural gas resource play discovery on its Dorado prospect located in Webb County, Texas. A total of 21 trillion cubic feet (Tcf) of estimated net resource potential is contained in 700 feet of stacked pay in the Austin Chalk and Eagle Ford Shale formations. The company has identified an initial 1,250 net premium drilling locations across its 163,000 net acre position in the core of the play. EOG has drilled 17 wells in the Dorado play since January 2019, including five wells targeting the Austin Chalk and 12 wells targeting the Upper and Lower Eagle Ford.
The Austin Chalk formation has an estimated net resource potential of 9.5 Tcf of natural gas. EOG has identified 530 net premium drilling locations in the Austin Chalk. The prolific Austin Chalk wells generate rates of return that are competitive with EOG’s large inventory of premium oil plays. The rates of return are supported by low cash operating costs and proximity to several natural gas markets with options for LNG and pipeline export pricing. In addition, EOG plans to apply its latest water and emissions management technology to minimize the environmental footprint of its development activities.
The five initial Austin Chalk wells produced an average of 3.5 billion cubic feet (Bcf) of natural gas per well in the first year of production, with an average lateral length of 6,600 feet per well. EOG expects to complete approximately 15 wells in the Austin Chalk in 2021. A typical Austin Chalk well is expected to recover 22 Bcf of natural gas, or 18 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $7.0 million per well.
The company has identified additional net resource potential of 11.5 Tcf and 720 net premium drilling locations in the Lower and Upper Eagle Ford, which underlies the Austin Chalk in the same area. Wells targeting the Eagle Ford also generate strong premium rates of return, supported by low drilling costs and shared infrastructure with the Austin Chalk wells.

The first 12 wells targeting the Eagle Ford produced an average of 2.8 Bcf of natural gas per well in the first year of production, with an average lateral length of 7,700 feet per well. A typical Eagle Ford well is expected to recover 19 Bcf of natural gas, or 16 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $6.5 million per well.
Including the Dorado locations, EOG added 1,400 net premium drilling locations to its undrilled premium inventory in the third quarter 2020. Taking into account wells drilled over the past year and updated location counts across its portfolio, EOG’s premium inventory now totals approximately 11,500 net locations.
“Our new South Texas natural gas play is the latest example of EOG’s sustainable business model of organic exploration-driven resource expansion,” Thomas said. “The addition of Dorado to EOG’s diverse portfolio of premium plays improves the financial profile of EOG by every measure. It also allows us to diversify capital deployment throughout the organization and across our assets. We believe this prolific new discovery represents the lowest-cost natural gas play in the U.S., which will be both operationally efficient and have a small environmental footprint. With 21 Tcf of net resource potential captured by EOG in the heart of the play, it is also one of the largest. Dorado competes today with EOG’s premium oil plays, and we expect it to move rapidly into the top tier of our inventory as development unfolds. This is just the latest example of how EOG continues to organically improve.”
Capital Allocation Outlook
Over the next three years, EOG’s goal is to continue improving reinvestment returns, lowering per-unit operating costs and generating strong free cash flow to support a growing sustainable dividend while further strengthening its balance sheet. The company anticipates the current imbalance in the global crude oil market is likely to extend into 2021, and therefore expects to maintain its crude oil production at approximately the same level as the fourth quarter 2020. Assuming a balanced crude oil market after 2021, EOG expects to reinvest 70 to 80 percent of its discretionary cash flow and generate up to 10 percent compound annual crude oil production growth in 2022 and 2023 at a $50 West Texas Intermediate crude oil price and using the company’s current inventory of premium locations. At higher oil prices, EOG expects to maintain the same growth rate of up to 10 percent per year. Priorities for the allocation of additional free cash flow include sustainable dividend growth, debt reduction, the return of additional cash to shareholders and low-cost property acquisitions.
“Our new three-year outlook provides visibility into the momentum we have built the last four years since the introduction of our premium return criteria,” Thomas said. “EOG’s long-term strategy and capital allocation priorities remain consistent. We are focused on high-return reinvestment in our growing stable of premium plays, which continues to improve in quality and drives increasing capital efficiency. With our disciplined capital allocation, we expect free cash flow growth, which will support sustainable dividend growth and further strengthen the balance sheet. Returning additional cash to shareholders also becomes more likely as oil prices continue to recover. Altogether, this balanced strategy leverages the competitive strengths of EOG and maximizes total shareholder value.”
Financial Review
At September 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $3.1 billion of cash on the balance sheet at the end of the third quarter, EOG’s net debt-to-total capitalization ratio was 12 percent. EOG’s liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of September 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG divested its assets in the Marcellus Shale effective September 1, 2020 for proceeds of approximately $130 million. Current production from the divested assets is approximately 40 million cubic feet of natural gas per day and there were no premium locations associated with the assets.
Third Quarter 2020 Results Webcast
Friday, November 6, 2020, 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
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, returns, 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," "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, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG’s forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG’s actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
•the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
•the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

•the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
•the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
•the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation and refining facilities;
•the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;
•the impact of, and changes in, government policies, laws and regulations, including any changes or other actions which may result from the recent U.S. elections and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
•EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
•competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
•the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
•the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
•weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage and transportation facilities;
•the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
•EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
•the extent to which EOG is successful in its completion of planned asset dispositions;
•the extent and effect of any hedging activities engaged in by EOG;
•the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
•the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
•geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
•the use of competing energy sources and the development of alternative energy sources;
•the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
•acts of war and terrorism and responses to these acts; and

•the other factors described under ITEM 1A, Risk Factors, on pages 13 through 23 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, “resource potential” and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019, 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.

Table of Contents |
Third Quarter 2020 |
Supplemental Financial and Operating Data | Page
Income Statements | 8
Wellhead Volumes and Prices | 9
Balance Sheets | 10
Cash Flows Statements | 11
Non-GAAP Financial Measures | 12
Adjusted Net Income (Loss) | 13
Discretionary Cash Flow and Free Cash Flow | 15
Total Expenditures | 18
EBITDAX and Adjusted EBITDAX | 19
Net Debt-to-Total Capitalization Ratio | 20
Reserve Replacement Cost Data | 25
Financial Commodity Derivative Contracts | 26
Direct After-Tax Rate of Return | 30
ROCE & ROE | 31
Cost per Barrel of Oil Equivalent | 36
Quarter and Full Year Guidance | 41

Income Statements |  |  |  |  |  |  |
In thousands of USD, except per share data (Unaudited)
| 3Q 2020 |  | 3Q 2019 |  | YTD 2020 |  | YTD 2019
Operating Revenues and Other |  |  |  |
Crude Oil and Condensate | 1,394,622 |  |  | 2,418,989 |  |  | 4,074,747 |  |  | 7,148,258 |
Natural Gas Liquids | 184,771 |  |  | 164,736 |  |  | 439,215 |  |  | 569,748 |
Natural Gas | 183,790 |  |  | 269,625 |  |  | 535,250 |  |  | 874,489 |
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | (3,978) |  |  | 85,902 |  |  | 1,075,433 |  |  | 242,622 |
Gathering, Processing and Marketing | 538,955 |  |  | 1,334,450 |  |  | 1,940,387 |  |  | 4,121,490 |
Gains (Losses) on Asset Dispositions, Net | (70,976) |  |  | (523) |  |  | (41,283) |  |  | 3,650 |
Other, Net | 18,300 |  |  | 30,276 |  |  | 42,801 |  |  | 99,470 |
Total | 2,245,484 |  |  | 4,303,455 |  |  | 8,066,550 |  |  | 13,059,727 |
Operating Expenses |  |  |  |  |  |  |
Lease and Well | 227,473 |  |  | 348,883 |  |  | 802,478 |  |  | 1,032,455 |
Transportation Costs | 180,257 |  |  | 199,365 |  |  | 540,281 |  |  | 549,988 |
Gathering and Processing Costs | 114,790 |  |  | 127,549 |  |  | 340,039 |  |  | 351,487 |
Exploration Costs | 38,413 |  |  | 34,540 |  |  | 105,373 |  |  | 103,386 |
Dry Hole Costs | 12,604 |  |  | 24,138 |  |  | 13,063 |  |  | 28,001 |
Impairments | 78,990 |  |  | 105,275 |  |  | 1,957,340 |  |  | 289,761 |
Marketing Costs | 521,351 |  |  | 1,343,293 |  |  | 2,074,788 |  |  | 4,114,265 |
Depreciation, Depletion and Amortization | 823,050 |  |  | 953,597 |  |  | 2,529,789 |  |  | 2,790,496 |
General and Administrative | 124,460 |  |  | 135,758 |  |  | 370,588 |  |  | 364,210 |
Taxes Other Than Income | 126,810 |  |  | 203,098 |  |  | 364,489 |  |  | 600,418 |
Total | 2,248,198 |  |  | 3,475,496 |  |  | 9,098,228 |  |  | 10,224,467 |
Operating Income (Loss) | (2,714) |  |  | 827,959 |  |  | (1,031,678) |  |  | 2,835,260 |
Other Income, Net | 3,401 |  |  | 9,118 |  |  | 17,009 |  |  | 23,233 |
Income (Loss) Before Interest Expense and Income Taxes | 687 |  |  | 837,077 |  |  | (1,014,669) |  |  | 2,858,493 |
Interest Expense, Net | 53,242 |  |  | 39,620 |  |  | 152,145 |  |  | 144,434 |
Income (Loss) Before Income Taxes | (52,555) |  |  | 797,457 |  |  | (1,166,814) |  |  | 2,714,059 |
Income Tax Provision (Benefit) | (10,088) |  |  | 182,335 |  |  | (224,776) |  |  | 615,670 |
Net Income (Loss) | (42,467) |  |  | 615,122 |  |  | (942,038) |  |  | 2,098,389 |
Dividends Declared per Common Share | 0.3750 |  |  | 0.2875 |  |  | 1.1250 |  |  | 0.7950 |
Net Income (Loss) Per Share |  |  |  |  |  |  |
Basic | (0.07) |  |  | 1.06 |  |  | (1.63) |  |  | 3.63 |
Diluted | (0.07) |  |  | 1.06 |  |  | (1.63) |  |  | 3.61 |
Average Number of Common Shares |  |  |  |  |  |  |
Basic | 579,055 |  |  | 577,839 |  |  | 578,740 |  |  | 577,498 |
Diluted | 579,055 |  |  | 581,271 |  |  | 578,740 |  |  | 581,190 |

8

Wellhead Volumes and Prices |  |  |  |  |  |  |  |  |  |
(Unaudited) |  |
| 3Q 2020 |  | 3Q 2019 |  | % Change |  | YTD 2020 |  | YTD 2019 |  | % Change |  |  |  |  |  |
Crude Oil and Condensate Volumes (MBbld) (A) |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 376.6 |  |  | 463.2 |  |  | -19 | % |  | 396.6 |  |  | 451.2 |  |  | -12 | % |  |  |  |  |  |
Trinidad | 1.0 |  |  | 0.8 |  |  | 25 | % |  | 0.5 |  |  | 0.7 |  |  | -29 | % |  |  |  |  |  |
Other International (B) | — |  |  | 0.1 |  |  | -100 | % |  | 0.2 |  |  | 0.1 |  |  | 100 | % |  |  |  |  |  |
Total | 377.6 |  |  | 464.1 |  |  | -19 | % |  | 397.3 |  |  | 452.0 |  |  | -12 | % |  |  |  |  |  |
Average Crude Oil and Condensate Prices ($/Bbl) (C) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 40.19 |  |  | 56.67 |  |  | -29 | % |  | 37.45 |  |  | 57.95 |  |  | -35 | % |  |  |  |  |  |
Trinidad | 25.41 |  |  | 48.36 |  |  | -47 | % |  | 26.35 |  |  | 47.26 |  |  | -44 | % |  |  |  |  |  |
Other International (B) | 25.29 |  |  | 59.87 |  |  | -58 | % |  | 45.09 |  |  | 58.43 |  |  | -23 | % |  |  |  |  |  |
Composite | 40.15 |  |  | 56.66 |  |  | -29 | % |  | 37.44 |  |  | 57.93 |  |  | -35 | % |  |  |  |  |  |
Natural Gas Liquids Volumes (MBbld) (A) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 140.1 |  |  | 141.3 |  |  | -1 | % |  | 134.2 |  |  | 130.8 |  |  | 3 | % |  |  |  |  |  |
Other International (B) | — |  |  | — |  |  |  |  | — |  |  | — |  |  |  |  |  |  |  |  |
Total | 140.1 |  |  | 141.3 |  |  | -1 | % |  | 134.2 |  |  | 130.8 |  |  | 3 | % |  |  |  |  |  |
Average Natural Gas Liquids Prices ($/Bbl) (C) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 14.34 |  |  | 12.67 |  |  | 13 | % |  | 11.95 |  |  | 15.96 |  |  | -25 | % |  |  |  |  |  |
Other International (B) | — |  |  | — |  |  |  |  | — |  |  | — |  |  |  |  |  |  |  |  |
Composite | 14.34 |  |  | 12.67 |  |  | 13 | % |  | 11.95 |  |  | 15.96 |  |  | -25 | % |  |  |  |  |  |
Natural Gas Volumes (MMcfd) (A) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 1,008 |  |  | 1,079 |  |  | -7 | % |  | 1,029 |  |  | 1,043 |  |  | -1 | % |  |  |  |  |  |
Trinidad | 151 |  |  | 260 |  |  | -42 | % |  | 175 |  |  | 267 |  |  | -34 | % |  |  |  |  |  |
Other International (B) | 31 |  |  | 34 |  |  | -9 | % |  | 34 |  |  | 36 |  |  | -6 | % |  |  |  |  |  |
Total | 1,190 |  |  | 1,373 |  |  | -13 | % |  | 1,238 |  |  | 1,346 |  |  | -8 | % |  |  |  |  |  |
Average Natural Gas Prices ($/Mcf) (C) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 1.49 |  |  | 1.97 |  |  | -25 | % |  | 1.38 |  |  | 2.23 |  |  | -38 | % |  |  |  |  |  |
Trinidad | 2.35 |  |  | 2.52 |  |  | -7 | % |  | 2.20 |  |  | 2.71 |  |  | -19 | % |  |  |  |  |  |
Other International (B) | 4.73 |  |  | 4.25 |  |  | 11 | % |  | 4.45 |  |  | 4.29 |  |  | 4 | % |  |  |  |  |  |
Composite | 1.68 |  |  | 2.13 |  |  | -21 | % |  | 1.58 |  |  | 2.38 |  |  | -34 | % |  |  |  |  |  |
Crude Oil Equivalent Volumes (MBoed) (D) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States | 684.7 |  |  | 784.3 |  |  | -13 | % |  | 702.3 |  |  | 755.8 |  |  | -7 | % |  |  |  |  |  |
Trinidad | 26.2 |  |  | 44.1 |  |  | -41 | % |  | 29.8 |  |  | 45.1 |  |  | -34 | % |  |  |  |  |  |
Other International (B) | 5.1 |  |  | 5.8 |  |  | -12 | % |  | 5.7 |  |  | 6.2 |  |  | -8 | % |  |  |  |  |  |
Total | 716.0 |  |  | 834.2 |  |  | -14 | % |  | 737.8 |  |  | 807.1 |  |  | -9 | % |  |  |  |  |  |
Total MMBoe (D) | 65.9 |  |  | 76.7 |  |  | -14 | % |  | 202.2 |  |  | 220.3 |  |  | -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 Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 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. |  |  |  |  |  |

9

Balance Sheets |  |  |
In thousands of USD, except share data (Unaudited)
| September 30, |  | December 31,
| 2020 |  | 2019
Current Assets |  |  |
Cash and Cash Equivalents | 3,065,556 |  |  | 2,027,972 |
Accounts Receivable, Net | 1,134,346 |  |  | 2,001,658 |
Inventories | 668,541 |  |  | 767,297 |
Assets from Price Risk Management Activities | 18,417 |  |  | 1,299 |
Income Taxes Receivable | 3,182 |  |  | 151,665 |
Other | 205,015 |  |  | 323,448 |
Total | 5,095,057 |  |  | 5,273,339 |
Property, Plant and Equipment |  |  |
Oil and Gas Properties (Successful Efforts Method) | 64,020,452 |  |  | 62,830,415 |
Other Property, Plant and Equipment | 4,402,091 |  |  | 4,472,246 |
Total Property, Plant and Equipment | 68,422,543 |  |  | 67,302,661 |
Less: Accumulated Depreciation, Depletion and Amortization | (39,789,537) |  |  | (36,938,066) |
Total Property, Plant and Equipment, Net | 28,633,006 |  |  | 30,364,595 |
Deferred Income Taxes | 1,916 |  |  | 2,363 |
Other Assets | 1,344,039 |  |  | 1,484,311 |
Total Assets | 35,074,018 |  |  | 37,124,608 |
Current Liabilities |  |  |
Accounts Payable | 1,245,029 |  |  | 2,429,127 |
Accrued Taxes Payable | 267,245 |  |  | 254,850 |
Dividends Payable | 217,334 |  |  | 166,273 |
Liabilities from Price Risk Management Activities | 23,486 |  |  | 20,194 |
Current Portion of Long-Term Debt | 770,831 |  |  | 1,014,524 |
Current Portion of Operating Lease Liabilities | 255,357 |  |  | 369,365 |
Other | 240,760 |  |  | 232,655 |
Total | 3,020,042 |  |  | 4,486,988 |
Long-Term Debt | 4,949,902 |  |  | 4,160,919 |
Other Liabilities | 2,151,092 |  |  | 1,789,884 |
Deferred Income Taxes | 4,804,656 |  |  | 5,046,101 |
Commitments and Contingencies |  |  |
Stockholders' Equity |  |  |
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,668,294 Shares Issued at September 30, 2020 and 582,213,016 Shares Issued at December 31, 2019 | 205,837 |  |  | 205,822 |
Additional Paid in Capital | 5,916,213 |  |  | 5,817,475 |
Accumulated Other Comprehensive Loss | (7,930) |  |  | (4,652) |
Retained Earnings | 14,051,197 |  |  | 15,648,604 |
Common Stock Held in Treasury, 322,591 Shares at September 30, 2020 and 298,820 Shares at December 31, 2019 | (16,991) |  |  | (26,533) |
Total Stockholders' Equity | 20,148,326 |  |  | 21,640,716 |
Total Liabilities and Stockholders' Equity | 35,074,018 |  |  | 37,124,608 |

10

Cash Flows Statements |  |  |  |  |  |  |
In thousands of USD (Unaudited)
| 3Q 2020 |  | 3Q 2019 |  | YTD 2020 |  | YTD 2019
Cash Flows from Operating Activities |  |  |  |  |  |  |
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |  |  |  |  |  |  |
Net Income (Loss) | (42,467) |  |  | 615,122 |  |  | (942,038) |  |  | 2,098,389 |
Items Not Requiring (Providing) Cash |  |  |  |  |  |  |
Depreciation, Depletion and Amortization | 823,050 |  |  | 953,597 |  |  | 2,529,789 |  |  | 2,790,496 |
Impairments | 78,990 |  |  | 105,275 |  |  | 1,957,340 |  |  | 289,761 |
Stock-Based Compensation Expenses | 33,811 |  |  | 54,670 |  |  | 113,454 |  |  | 132,323 |
Deferred Income Taxes | (33,311) |  |  | 184,282 |  |  | (241,003) |  |  | 508,576 |
(Gains) Losses on Asset Dispositions, Net | 70,976 |  |  | 523 |  |  | 41,283 |  |  | (3,650) |
Other, Net | 1,465 |  |  | (1,284) |  |  | 1,636 |  |  | 4,155 |
Dry Hole Costs | 12,604 |  |  | 24,138 |  |  | 13,063 |  |  | 28,001 |
Mark-to-Market Commodity Derivative Contracts |  |  |  |  |  |  |
Total (Gains) Losses | 3,978 |  |  | (85,902) |  |  | (1,075,433) |  |  | (242,622) |
Net Cash Received from Settlements of Commodity Derivative Contracts | 275,133 |  |  | 108,418 |  |  | 998,894 |  |  | 139,708 |
Other, Net | (465) |  |  | (424) |  |  | (1,185) |  |  | 1,215 |
Changes in Components of Working Capital and Other Assets and Liabilities |  |  |  |  |  |  |
Accounts Receivable | (260,829) |  |  | 63,891 |  |  | 930,628 |  |  | (5,855) |
Inventories | 7,439 |  |  | 66,857 |  |  | 92,014 |  |  | 55,598 |
Accounts Payable | (37,755) |  |  | 7,400 |  |  | (1,222,473) |  |  | 134,253 |
Accrued Taxes Payable | 73,482 |  |  | 34,767 |  |  | 12,395 |  |  | 88,047 |
Other Assets | 161,879 |  |  | (92,814) |  |  | 414,857 |  |  | 394,573 |
Other Liabilities | 51,664 |  |  | 39,791 |  |  | (12,739) |  |  | (18,315) |
Changes in Components of Working Capital Associated with Investing and Financing Activities | (6,091) |  |  | (16,643) |  |  | 276,063 |  |  | (38,677) |
Net Cash Provided by Operating Activities | 1,213,553 |  |  | 2,061,664 |  |  | 3,886,545 |  |  | 6,355,976 |
Investing Cash Flows |  |  |  |  |  |  |
Additions to Oil and Gas Properties | (468,487) |  |  | (1,420,385) |  |  | (2,458,520) |  |  | (4,866,882) |
Additions to Other Property, Plant and Equipment | (17,652) |  |  | (70,469) |  |  | (165,018) |  |  | (187,350) |
Proceeds from Sales of Assets | 145,575 |  |  | 17,767 |  |  | 188,943 |  |  | 35,409 |
Changes in Components of Working Capital Associated with Investing Activities | 6,091 |  |  | 16,621 |  |  | (276,063) |  |  | 38,677 |
Net Cash Used in Investing Activities | (334,473) |  |  | (1,456,466) |  |  | (2,710,658) |  |  | (4,980,146) |
Financing Cash Flows |  |  |  |  |  |  |
Long-Term Debt Borrowings | — |  |  | — |  |  | 1,483,852 |  |  | — |
Long-Term Debt Repayments | — |  |  | — |  |  | (1,000,000) |  |  | (900,000) |
Dividends Paid | (217,142) |  |  | (166,170) |  |  | (601,242) |  |  | (420,851) |
Treasury Stock Purchased | (9,764) |  |  | (13,835) |  |  | (14,821) |  |  | (22,238) |
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | — |  |  | 863 |  |  | 8,614 |  |  | 9,558 |
Debt Issuance Costs | — |  |  | (114) |  |  | (2,635) |  |  | (5,016) |
Repayment of Finance Lease Liabilities | (4,864) |  |  | (3,235) |  |  | (13,309) |  |  | (9,638) |
Changes in Components of Working Capital Associated with Financing Activities | — |  |  | 22 |  |  | — |  |  | — |
Net Cash Used in Financing Activities | (231,770) |  |  | (182,469) |  |  | (139,541) |  |  | (1,348,185) |
Effect of Exchange Rate Changes on Cash | 1,745 |  |  | (109) |  |  | 1,238 |  |  | (174) |
Increase in Cash and Cash Equivalents | 649,055 |  |  | 422,620 |  |  | 1,037,584 |  |  | 27,471 |
Cash and Cash Equivalents at Beginning of Period | 2,416,501 |  |  | 1,160,485 |  |  | 2,027,972 |  |  | 1,555,634 |
Cash and Cash Equivalents at End of Period | 3,065,556 |  |  | 1,583,105 |  |  | 3,065,556 |  |  | 1,583,105 |

11

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.
12

Adjusted Net Income (Loss) |  |  |  |  |  |  |
In thousands of USD, except per share data (Unaudited) |  |  |  |  |  |  |
| 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 Income (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) |  |  |  |  |  |  |
Basic |  |  |  |  |  |  | 579,055 |
Diluted |  |  |  |  |  |  | 580,609 |

| 3Q 2019
| Before Tax |  | Income Tax Impact |  | After Tax |  | Diluted Earnings per Share
Reported Net Income (GAAP) | 797,457 |  |  | (182,335) |  |  | 615,122 |  |  | 1.06 |
Adjustments: |  |  |  |  |  |  |
Gains on Mark-to-Market Commodity Derivative Contracts | (85,902) |  |  | 18,854 |  |  | (67,048) |  |  | (0.12) |
Net Cash Received from Settlements of Commodity Derivative Contracts | 108,418 |  |  | (23,796) |  |  | 84,622 |  |  | 0.15 |
Add: Losses on Asset Dispositions, Net | 523 |  |  | (89) |  |  | 434 |  |  | — |
Add: Certain Impairments | 27,215 |  |  | (5,973) |  |  | 21,242 |  |  | 0.04 |
Adjustments to Net Income (Loss) | 50,254 |  |  | (11,004) |  |  | 39,250 |  |  | 0.07 |
Adjusted Net Income (Non-GAAP) | 847,711 |  |  | (193,339) |  |  | 654,372 |  |  | 1.13 |
Average Number of Common Shares (GAAP) |  |  |  |  |  |  |
Basic |  |  |  |  |  |  | 577,839 |
Diluted |  |  |  |  |  |  | 581,271 |
Average Number of Common Shares (Non-GAAP) |  |  |  |  |  |  | 577,839 |
Basic |  |  |  |  |  |  | 581,271 |
Diluted |  |  |  |  |  |  |

13

Adjusted Net Income (Loss) |  |  |  |  |  |  |
In thousands of USD, except per share data (Unaudited) |  |  |  |  |  |  |
| YTD 2020
| Before Tax |  | Income Tax Impact |  | After Tax |  | Diluted Earnings per Share
Reported Net Loss (GAAP) | (1,166,814) |  |  | 224,776 |  |  | (942,038) |  |  | (1.63) |
Adjustments: |  |  |  |  |  |  |
Gains on Mark-to-Market Commodity Derivative Contracts | (1,075,433) |  |  | 236,036 |  |  | (839,397) |  |  | (1.45) |
Net Cash Received from Settlements of Commodity Derivative Contracts | 998,894 |  |  | (219,237) |  |  | 779,657 |  |  | 1.35 |
Add: Losses on Asset Dispositions, Net | 41,283 |  |  | (9,057) |  |  | 32,226 |  |  | 0.06 |
Add: Certain Impairments | 1,782,014 |  |  | (373,960) |  |  | 1,408,054 |  |  | 2.43 |
Adjustments to Net Income (Loss) | 1,746,758 |  |  | (366,218) |  |  | 1,380,540 |  |  | 2.39 |
Adjusted Net Income (Non-GAAP) | 579,944 |  |  | (141,442) |  |  | 438,502 |  |  | 0.76 |
Average Number of Common Shares (GAAP) |  |  |  |  |  |  |
Basic |  |  |  |  |  |  | 578,740 |
Diluted |  |  |  |  |  |  | 578,740 |
Average Number of Common Shares (Non-GAAP) |  |  |  |  |  |  |
Basic |  |  |  |  |  |  | 578,740 |
Diluted |  |  |  |  |  |  | 580,301 |

| YTD 2019
| Before Tax |  | Income Tax Impact |  | After Tax |  | Diluted Earnings per Share
Reported Net Income (GAAP) | 2,714,059 |  |  | (615,670) |  |  | 2,098,389 |  |  | 3.61 |
Adjustments: |  |  |  |  |  |  |
Gains on Mark-to-Market Commodity Derivative Contracts | (242,622) |  |  | 53,251 |  |  | (189,371) |  |  | (0.34) |
Net Cash Received from Settlements of Commodity Derivative Contracts | 139,708 |  |  | (30,663) |  |  | 109,045 |  |  | 0.19 |
Add: Gains on Asset Dispositions, Net | (3,650) |  |  | 910 |  |  | (2,740) |  |  | — |
Add: Certain Impairments | 116,249 |  |  | (25,514) |  |  | 90,735 |  |  | 0.16 |
Adjustments to Net Income (Loss) | 9,685 |  |  | (2,016) |  |  | 7,669 |  |  | 0.01 |
Adjusted Net Income (Non-GAAP) | 2,723,744 |  |  | (617,686) |  |  | 2,106,058 |  |  | 3.62 |
Average Number of Common Shares (GAAP) |  |  |  |  |  |  |
Basic |  |  |  |  |  |  | 577,498 |
Diluted |  |  |  |  |  |  | 581,190 |
Average Number of Common Shares (Non-GAAP) |  |  |  |  |  |  |
Basic |  |  |  |  |  |  | 577,498 |
Diluted |  |  |  |  |  |  | 581,190 |

14

Discretionary Cash Flow and Free Cash Flow |  |  |  |  |  |  |
In thousands of USD (Unaudited) |  |  |  |  |  |  |  |  |  |  |  |
| 3Q 2020 |  | 3Q 2019 |  | YTD 2020 |  | YTD 2019 |  |  |  |  |
Net Cash Provided by Operating Activities (GAAP) | 1,213,553 |  |  | 2,061,664 |  |  | 3,886,545 |  |  | 6,355,976 |  |  |  |  |  |
Adjustments: |  |  |  |  |  |  |  |  |  |  |  |
Exploration Costs (excluding Stock-Based Compensation Expenses) | 37,380 |  |  | 29,374 |  |  | 90,346 |  |  | 85,250 |  |  |  |  |  |
Other Non-Current Income Taxes - Net Receivable | — |  |  | 33,855 |  |  | 112,704 |  |  | 179,537 |  |  |  |  |  |
Changes in Components of Working Capital and Other Assets and Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Accounts Receivable | 260,829 |  |  | (63,891) |  |  | (930,628) |  |  | 5,855 |  |  |  |  |  |
Inventories | (7,439) |  |  | (66,857) |  |  | (92,014) |  |  | (55,598) |  |  |  |  |  |
Accounts Payable | 37,755 |  |  | (7,400) |  |  | 1,222,473 |  |  | (134,253) |  |  |  |  |  |
Accrued Taxes Payable | (73,482) |  |  | (34,767) |  |  | (12,395) |  |  | (88,047) |  |  |  |  |  |
Other Assets | (161,879) |  |  | 92,814 |  |  | (414,857) |  |  | (394,573) |  |  |  |  |  |
Other Liabilities | (51,664) |  |  | (39,791) |  |  | 12,739 |  |  | 18,315 |  |  |  |  |  |
Changes in Components of Working Capital Associated with Investing and Financing Activities | 6,091 |  |  | 16,643 |  |  | (276,063) |  |  | 38,677 |  |  |  |  |  |
Discretionary Cash Flow (Non-GAAP) | 1,261,144 |  |  | 2,021,644 |  |  | 3,598,850 |  |  | 6,011,139 |  |  |  |  |  |
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease | -38 | % |  |  |  | -40 | % |  |  |  |  |  |  |
Discretionary Cash Flow (Non-GAAP) | 1,261,144 |  |  | 2,021,644 |  |  | 3,598,850 |  |  | 6,011,139 |  |  |  |  |  |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) | (499,305) |  |  | (1,518,019) |  |  | (2,661,641) |  |  | (4,846,221) |  |  |  |  |  |
Free Cash Flow (Non-GAAP) (b) | 761,839 |  |  | 503,625 |  |  | 937,209 |  |  | 1,164,918 |  |  |  |  |  |
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month and nine-month periods ended September 30, 2020 and 2019: |  |  |  |  |
Total Expenditures (GAAP) | 645,534 |  |  | 1,629,343 |  |  | 3,005,723 |  |  | 5,394,389 |  |  |  |  |  |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Asset Retirement Costs | (42,650) |  |  | (90,970) |  |  | (68,213) |  |  | (151,551) |  |  |  |  |  |
Non-Cash Expenditures of Other Property, Plant and Equipment | — |  |  | — |  |  | (60) |  |  | (586) |  |  |  |  |  |
Non-Cash Acquisition Costs of Unproved Properties | (80,757) |  |  | (10,666) |  |  | (128,488) |  |  | (64,387) |  |  |  |  |  |
Non-Cash Finance Leases | — |  |  | — |  |  | (73,277) |  |  | — |  |  |  |  |  |
Acquisition Costs of Proved Properties | (22,822) |  |  | (9,688) |  |  | (74,044) |  |  | (331,644) |  |  |  |  |  |
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | 499,305 |  |  | 1,518,019 |  |  | 2,661,641 |  |  | 4,846,221 |  |  |  |  |  |
(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 and nine-month periods ending September 30, 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 anticipated 4Q 2020 U.S. oil production.

15

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 Financing Activities | 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. |  |  |  |  |

16

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 Compensation Expenses) | 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 Other Assets and Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 Associated with Investing and Financing Activities | 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 Increase (Decrease) | -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 (Non-GAAP) (a) | (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 and Equipment | (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 (Non-GAAP) | 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. |  |  |  |  |

17

Total Expenditures |  |  |  |  |  |  |  |  |
In millions of USD (Unaudited) |  |  |  |  |  |  |  |  |
| 3Q 2020 |  | 3Q 2019 |  | FY 2019 |  | FY 2018 |  | FY 2017
Exploration and Development Drilling | 378 |  |  | 1,173 |  |  | 4,951 |  |  | 4,935 |  |  | 3,132 |
Facilities | 38 |  |  | 161 |  |  | 629 |  |  | 625 |  |  | 575 |
Leasehold Acquisitions | 88 |  |  | 56 |  |  | 276 |  |  | 488 |  |  | 427 |
Property Acquisitions | 23 |  |  | 10 |  |  | 380 |  |  | 124 |  |  | 73 |
Capitalized Interest | 7 |  |  | 10 |  |  | 38 |  |  | 24 |  |  | 27 |
Subtotal | 534 |  |  | 1,410 |  |  | 6,274 |  |  | 6,196 |  |  | 4,234 |
Exploration Costs | 38 |  |  | 34 |  |  | 140 |  |  | 149 |  |  | 145 |
Dry Hole Costs | 13 |  |  | 24 |  |  | 28 |  |  | 5 |  |  | 5 |
Exploration and Development Expenditures | 585 |  |  | 1,468 |  |  | 6,442 |  |  | 6,350 |  |  | 4,384 |
Asset Retirement Costs | 44 |  |  | 91 |  |  | 186 |  |  | 70 |  |  | 56 |
Total Exploration and Development Expenditures | 629 |  |  | 1,559 |  |  | 6,628 |  |  | 6,420 |  |  | 4,440 |
Other Property, Plant and Equipment | 17 |  |  | 70 |  |  | 272 |  |  | 286 |  |  | 173 |
Total Expenditures | 646 |  |  | 1,629 |  |  | 6,900 |  |  | 6,706 |  |  | 4,613 |

18

EBITDAX and Adjusted EBITDAX |  |  |  |  |  |  |  |  |  |
In thousands of USD (Unaudited) |  |  |  |  |  |  |  |  |  |
| 3Q 2020 |  | 3Q 2019 |  | YTD 2020 |  | YTD 2019 |  |  |
Net Income (Loss) (GAAP) | (42,467) |  |  | 615,122 |  |  | (942,038) |  |  | 2,098,389 |  |  |  |
Adjustments: |  |  |  |  |  |  |  |  |  |
Interest Expense, Net | 53,242 |  |  | 39,620 |  |  | 152,145 |  |  | 144,434 |  |  |  |
Income Tax Provision (Benefit) | (10,088) |  |  | 182,335 |  |  | (224,776) |  |  | 615,670 |  |  |  |
Depreciation, Depletion and Amortization | 823,050 |  |  | 953,597 |  |  | 2,529,789 |  |  | 2,790,496 |  |  |  |
Exploration Costs | 38,413 |  |  | 34,540 |  |  | 105,373 |  |  | 103,386 |  |  |  |
Dry Hole Costs | 12,604 |  |  | 24,138 |  |  | 13,063 |  |  | 28,001 |  |  |  |
Impairments | 78,990 |  |  | 105,275 |  |  | 1,957,340 |  |  | 289,761 |  |  |  |
EBITDAX (Non-GAAP) | 953,744 |  |  | 1,954,627 |  |  | 3,590,896 |  |  | 6,070,137 |  |  |  |
(Gains) Losses on MTM Commodity Derivative Contracts | 3,978 |  |  | (85,902) |  |  | (1,075,433) |  |  | (242,622) |  |  |  |
Net Cash Received from Settlements of Commodity Derivative Contracts | 275,133 |  |  | 108,418 |  |  | 998,894 |  |  | 139,708 |  |  |  |
(Gains) Losses on Asset Dispositions, Net | 70,976 |  |  | 523 |  |  | 41,283 |  |  | (3,650) |  |  |  |
Adjusted EBITDAX (Non-GAAP) | 1,303,831 |  |  | 1,977,666 |  |  | 3,555,640 |  |  | 5,963,573 |  |  |  |
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease | -34 | % |  |  |  | -40 | % |  |  |  |  |
Definitions |  |  |  |  |  |  |  |  |  |
EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments |  |  |

19

Net Debt-to-Total Capitalization Ratio |  |  |  |
In millions of USD, except ratio data (Unaudited) |  |  |  |  |
| September 30, 2020 |  | June 30, 2020 |  | March 31, 2020
Total Stockholders' Equity - (a) | 20,148 |  |  | 20,388 |  |  | 21,471 |
Current and Long-Term Debt (GAAP) - (b) | 5,721 |  |  | 5,724 |  |  | 5,222 |
Less: Cash | (3,066) |  |  | (2,417) |  |  | (2,907) |
Net Debt (Non-GAAP) - (c) | 2,655 |  |  | 3,307 |  |  | 2,315 |
Total Capitalization (GAAP) - (a) + (b) | 25,869 |  |  | 26,112 |  |  | 26,693 |
Total Capitalization (Non-GAAP) - (a) + (c) | 22,803 |  |  | 23,695 |  |  | 23,786 |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 22 | % |  | 22 | % |  | 20 | %
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 12 | % |  | 14 | % |  | 10 | %

20

Net Debt-to-Total Capitalization Ratio |  |  |  |
In millions of USD, except ratio data (Unaudited) |  |  |  |  |  |  |
| December 31, 2019 |  | September 30, 2019 |  | June 30, 2019 |  | March 31, 2019
Total Stockholders' Equity - (a) | 21,641 |  |  | 21,124 |  |  | 20,630 |  |  | 19,904 |
Current and Long-Term Debt (GAAP) - (b) | 5,175 |  |  | 5,177 |  |  | 5,179 |  |  | 6,081 |
Less: Cash | (2,028) |  |  | (1,583) |  |  | (1,160) |  |  | (1,136) |
Net Debt (Non-GAAP) - (c) | 3,147 |  |  | 3,594 |  |  | 4,019 |  |  | 4,945 |
Total Capitalization (GAAP) - (a) + (b) | 26,816 |  |  | 26,301 |  |  | 25,809 |  |  | 25,985 |
Total Capitalization (Non-GAAP) - (a) + (c) | 24,788 |  |  | 24,718 |  |  | 24,649 |  |  | 24,849 |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 19 | % |  | 20 | % |  | 20 | % |  | 23 | %
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 13 | % |  | 15 | % |  | 16 | % |  | 20 | %

21

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)] | 24 | % |  | 26 | % |  | 27 | % |  | 28 | % |  |
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 19 | % |  | 22 | % |  | 24 | % |  | 25 | % |  |

22

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 | % |  | 31 | % |  | 33 | % |  | 33 | % |  |
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 25 | % |  | 28 | % |  | 28 | % |  | 28 | % |  |

23

Net Debt-to-Total Capitalization Ratio |  |  |  |
In millions of USD, except ratio data (Unaudited) |  |  |  |  |  |  |  |  |  |
| December 31, 2016 |  | September 30, 2016 |  | June 30, 2016 |  | March 31, 2016 |  | December 31, 2015 |  |
Total Stockholders' Equity - (a) | 13,982 |  |  | 11,798 |  |  | 12,057 |  |  | 12,405 |  |  | 12,943 |  |  |
Current and Long-Term Debt (GAAP) - (b) | 6,986 |  |  | 6,986 |  |  | 6,986 |  |  | 6,986 |  |  | 6,660 |  |  |
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 | % |  | 37 | % |  | 37 | % |  | 36 | % |  | 34 | % |  |
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 28 | % |  | 33 | % |  | 34 | % |  | 34 | % |  | 31 | % |  |

24

Reserve Replacement Cost Data |  |
In millions of USD, except reserves and ratio data (Unaudited) |  |  |  |  |  |  |  |  |  |  |
| 2019 |  | 2018 |  | 2017 |  | 2016 |  | 2015 |  | 2014
Total Costs Incurred in Exploration and Development Activities (GAAP) | 6,628.2 |  |  | 6,419.7 |  |  | 4,439.4 |  |  | 6,445.2 |  |  | 4,928.3 |  |  | 7,904.8 |
Less: Asset Retirement Costs | (186.1) |  |  | (69.7) |  |  | (55.6) |  |  | 19.9 |  |  | (53.5) |  |  | (195.6) |
Non-Cash Acquisition Costs of Unproved Properties | (97.7) |  |  | (290.5) |  |  | (255.7) |  |  | (3,101.8) |  |  | — |  |  | — |
Acquisition Costs of Proved Properties | (379.9) |  |  | (123.7) |  |  | (72.6) |  |  | (749.0) |  |  | (480.6) |  |  | (139.1) |
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) | 5,964.5 |  |  | 5,935.8 |  |  | 4,055.5 |  |  | 2,614.3 |  |  | 4,394.2 |  |  | 7,570.1 |
Total Costs Incurred in Exploration and Development Activities (GAAP) | 6,628.2 |  |  | 6,419.7 |  |  | 4,439.4 |  |  | 6,445.2 |  |  | 4,928.3 |  |  | 7,904.8 |
Less: Asset Retirement Costs | (186.1) |  |  | (69.7) |  |  | (55.6) |  |  | 19.9 |  |  | (53.5) |  |  | (195.6) |
Non-Cash Acquisition Costs of Unproved Properties | (97.7) |  |  | (290.5) |  |  | (255.7) |  |  | (3,101.8) |  |  | — |  |  | — |
Non-Cash Acquisition Costs of Proved Properties | (52.3) |  |  | (70.9) |  |  | (26.2) |  |  | (732.3) |  |  | — |  |  | — |
Total Exploration and Development Expenditures (Non-GAAP) - (b) | 6,292.1 |  |  | 5,988.6 |  |  | 4,101.9 |  |  | 2,631.0 |  |  | 4,874.8 |  |  | 7,709.2 |
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |  |  |  |  |  |  |  |  |  |  |
Revisions Due to Price - (c) | (59.7) |  |  | 34.8 |  |  | 154.0 |  |  | (100.7) |  |  | (573.8) |  |  | 52.2 |
Revisions Other Than Price | (0.3) |  |  | (39.5) |  |  | 48.0 |  |  | 252.9 |  |  | 107.2 |  |  | 48.4 |
Purchases in Place | 16.8 |  |  | 11.6 |  |  | 2.3 |  |  | 42.3 |  |  | 56.2 |  |  | 14.4 |
Extensions, Discoveries and Other Additions - (d) | 750.0 |  |  | 669.7 |  |  | 420.8 |  |  | 209.0 |  |  | 245.9 |  |  | 519.2 |
Total Proved Reserve Additions - (e) | 706.8 |  |  | 676.6 |  |  | 625.1 |  |  | 403.5 |  |  | (164.5) |  |  | 634.2 |
Sales in Place | (4.6) |  |  | (10.8) |  |  | (20.7) |  |  | (167.6) |  |  | (3.5) |  |  | (36.3) |
Net Proved Reserve Additions From All Sources | 702.2 |  |  | 665.8 |  |  | 604.4 |  |  | 235.9 |  |  | (168.0) |  |  | 597.9 |
Production | 300.9 |  |  | 265.0 |  |  | 224.4 |  |  | 207.1 |  |  | 211.2 |  |  | 219.1 |
Reserve Replacement Costs ($ / Boe) |  |  |  |  |  |  |  |  |  |  |
Total Drilling, Before Revisions - (a / d) | 7.95 |  |  | 8.86 |  |  | 9.64 |  |  | 12.51 |  |  | 17.87 |  |  | 14.58 |
All-in Total, Net of Revisions - (b / e) | 8.90 |  |  | 8.85 |  |  | 6.56 |  |  | 6.52 |  |  | (29.63) |  |  | 12.16 |
All-in Total, Excluding Revisions Due to Price - (b / ( e - c)) | 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

25

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 October 30, 2020. 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 October 30, 2020. 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 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 swap contracts through October 30, 2020. 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 November 30, 2020 (CLOSED) |  | 66,000 |  |  | (1.16) |
December 2020 |  | 66,000 |  |  | (1.16) |

26

In May 2020, EOG entered into crude oil Roll Differential 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 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 $2.6 million through October 30, 2020, for the settlement of certain of these contracts and expects to pay $0.6 million during the remainder of 2020 for the settlement of the remaining 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 October 30, 2020, 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 |
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 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 $359.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $4.1 million during the remainder of 2020 for the settlement of the remaining 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 October 30, 2020, 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 October 30, 2020, 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 |
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 $5.7 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $3.5 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

27

Natural Gas Price Swap Contracts
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
2021 |  | Volume (MMBtud) |  | Weighted Average Price ($/MMBtu)
January 1, 2021 through December 31, 2021 |  | 500,000 |  |  | 2.99 |

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 NYMEX Henry Hub natural gas price for the contract month (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 October 30, 2020, 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 through October 30, 2020, 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 October 30, 2020. 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 October 31, 2020 (CLOSED) |  | 30,000 |  |  | 0.55 |
November 1, 2020 through December 31, 2020 |  | 30,000 |  |  | 0.55 |

28

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 October 30, 2020. 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 October 30, 2020. 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 $8.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to pay net cash of $3.0 million during the remainder of 2020 for the settlement of the remaining 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 |

29

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 |

30

ROCE & ROE |  |  |  |  |
In millions of USD, except ratio data (Unaudited) |  |  |  |  |
| 2019 |  | 2018 |  | 2017
Net Interest Expense (GAAP) | 185 |  |  | 245 |  |  |
Tax Benefit Imputed (based on 21%) | (39) |  |  | (51) |  |  |
After-Tax Net Interest Expense (Non-GAAP) - (a) | 146 |  |  | 194 |  |  |
Net Income (GAAP) - (b) | 2,735 |  |  | 3,419 |  |  |
Adjustments to Net Income, Net of Tax (See Below Detail) (1) | 158 |  |  | (201) |  |  |
Adjusted Net Income (Non-GAAP) - (c) | 2,893 |  |  | 3,218 |  |  |
Total Stockholders' Equity - (d) | 21,641 |  |  | 19,364 |  |  | 16,283 |
Average Total Stockholders' Equity * - (e) | 20,503 |  |  | 17,824 |  |  |
Current and Long-Term Debt (GAAP) - (f) | 5,175 |  |  | 6,083 |  |  | 6,387 |
Less: Cash | (2,028) |  |  | (1,556) |  |  | (834) |
Net Debt (Non-GAAP) - (g) | 3,147 |  |  | 4,527 |  |  | 5,553 |
Total Capitalization (GAAP) - (d) + (f) | 26,816 |  |  | 25,447 |  |  | 22,670 |
Total Capitalization (Non-GAAP) - (d) + (g) | 24,788 |  |  | 23,891 |  |  | 21,836 |
Average Total Capitalization (Non-GAAP) * - (h) | 24,340 |  |  | 22,864 |  |  |
Return on Capital Employed (ROCE) |  |  |  |  |
GAAP Net Income - [(a) + (b)] / (h) | 11.8 | % |  | 15.8 | % |  |
Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) | 12.5 | % |  | 14.9 | % |  |
Return on Equity (ROE) |  |  |  |  |
GAAP Net Income - (b) / (e) | 13.3 | % |  | 19.2 | % |  |
Non-GAAP Adjusted Net Income - (c) / (e) | 14.1 | % |  | 18.1 | % |  |
* Average for the current and immediately preceding year |  |  |  |  |
(1) Detail of adjustments to Net Income (GAAP): |  |  |  |  |
| Before Tax |  | Income Tax Impact |  | After Tax
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) |

31

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 |  |  |  |  |  |  |  |  |

32

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 |  |  |  |  |  |  |  |  |

33

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 |  |  |  |  |  |  |  |  |

34

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 |  |  |  |  |  |  |  |  |

35

Costs per Barrel of Oil Equivalent |
In thousands of USD, except Boe and per Boe amounts (Unaudited) |  |  |  |  |  |  |
| 1Q 2020 |  | 2Q 2020 |  | 3Q 2020 |  | YTD 2020
Cost per Barrel of Oil Equivalent (Boe) Calculation |  |  |  |  |  |  |
Volume - Thousand Barrels of Oil Equivalent - (a) | 79,548 |  |  | 56,733 |  |  | 65,873 |  |  | 202,153 |
Crude Oil and Condensate | 2,065,498 |  |  | 614,627 |  |  | 1,394,622 |  |  | 4,074,747 |
Natural Gas Liquids | 160,535 |  |  | 93,909 |  |  | 184,771 |  |  | 439,215 |
Natural Gas | 209,764 |  |  | 141,696 |  |  | 183,790 |  |  | 535,250 |
Total Wellhead Revenues - (b) | 2,435,797 |  |  | 850,232 |  |  | 1,763,183 |  |  | 5,049,212 |
Operating Costs |  |  |  |  |  |  |
Lease and Well | 329,659 |  |  | 245,346 |  |  | 227,473 |  |  | 802,478 |
Transportation Costs | 208,296 |  |  | 151,728 |  |  | 180,257 |  |  | 540,281 |
Gathering and Processing Costs | 128,482 |  |  | 96,767 |  |  | 114,790 |  |  | 340,039 |
General and Administrative | 114,273 |  |  | 131,855 |  |  | 124,460 |  |  | 370,588 |
Taxes Other Than Income | 157,360 |  |  | 80,319 |  |  | 126,810 |  |  | 364,489 |
Interest Expense, Net | 44,690 |  |  | 54,213 |  |  | 53,242 |  |  | 152,145 |
Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c) | 982,760 |  |  | 760,228 |  |  | 827,032 |  |  | 2,570,020 |
Depreciation, Depletion and Amortization (DD&A) | 1,000,060 |  |  | 706,679 |  |  | 823,050 |  |  | 2,529,789 |
Total Operating Cost (excluding Total Exploration Costs) - (d) | 1,982,820 |  |  | 1,466,907 |  |  | 1,650,082 |  |  | 5,099,809 |
Exploration Costs | 39,677 |  |  | 27,283 |  |  | 38,413 |  |  | 105,373 |
Dry Hole Costs | 372 |  |  | 87 |  |  | 12,604 |  |  | 13,063 |
Impairments | 1,572,935 |  |  | 305,415 |  |  | 78,990 |  |  | 1,957,340 |
Total Exploration Costs | 1,612,984 |  |  | 332,785 |  |  | 130,007 |  |  | 2,075,776 |
Less: Certain Impairments (Non-GAAP) | (1,516,316) |  |  | (239,167) |  |  | (26,531) |  |  | (1,782,014) |
Total Exploration Costs (Non-GAAP) | 96,668 |  |  | 93,618 |  |  | 103,476 |  |  | 293,762 |
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 2,079,488 |  |  | 1,560,525 |  |  | 1,753,558 |  |  | 5,393,571 |
Composite Average Wellhead Revenue per Boe - (b) / (a) | 30.62 |  |  | 14.99 |  |  | 26.77 |  |  | 24.98 |
Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / (a) | 12.36 |  |  | 13.40 |  |  | 12.56 |  |  | 12.70 |
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | 18.26 |  |  | 1.59 |  |  | 14.21 |  |  | 12.28 |
Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) | 24.93 |  |  | 25.86 |  |  | 25.05 |  |  | 25.21 |
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | 5.69 |  |  | (10.87) |  |  | 1.72 |  |  | (0.23) |
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | 26.15 |  |  | 27.51 |  |  | 26.62 |  |  | 26.66 |
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | 4.47 |  |  | (12.52) |  |  | 0.15 |  |  | (1.68) |

36

Costs per Barrel of Oil Equivalent |  |  |  |  |
In thousands of USD, except Boe and per Boe amounts (Unaudited)
| 2019 |  | 2018 |  | 2017
Cost per Barrel of Oil Equivalent (Boe) Calculation |  |  |  |  |
Volume - Thousand Barrels of Oil Equivalent - (a) | 298,565 |  |  | 262,516 |  |  | 222,251 |
Crude Oil and Condensate | 9,612,532 |  |  | 9,517,440 |  |  | 6,256,396 |
Natural Gas Liquids | 784,818 |  |  | 1,127,510 |  |  | 729,561 |
Natural Gas | 1,184,095 |  |  | 1,301,537 |  |  | 921,934 |
Total Wellhead Revenues - (b) | 11,581,445 |  |  | 11,946,487 |  |  | 7,907,891 |
Operating Costs |  |  |  |  |
Lease and Well | 1,366,993 |  |  | 1,282,678 |  |  | 1,044,847 |
Transportation Costs | 758,300 |  |  | 746,876 |  |  | 740,352 |
Gathering and Processing Costs | 479,102 |  |  | 436,973 |  |  | 148,775 |
General and Administrative | 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) | 489,397 |  |  | 426,969 |  |  | 416,681 |
Taxes Other Than Income | 800,164 |  |  | 772,481 |  |  | 544,662 |
Interest Expense, Net | 185,129 |  |  | 245,052 |  |  | 274,372 |
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) | 4,079,085 |  |  | 3,911,029 |  |  | 3,169,689 |
Depreciation, Depletion and Amortization (DD&A) | 3,749,704 |  |  | 3,435,408 |  |  | 3,409,387 |
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) | 7,828,789 |  |  | 7,346,437 |  |  | 6,579,076 |
Exploration Costs | 139,881 |  |  | 148,999 |  |  | 145,342 |
Dry Hole Costs | 28,001 |  |  | 5,405 |  |  | 4,609 |
Impairments | 517,896 |  |  | 347,021 |  |  | 479,240 |
Total Exploration Costs | 685,778 |  |  | 501,425 |  |  | 629,191 |
Less: Certain Impairments (Non-GAAP) | (274,974) |  |  | (152,671) |  |  | (261,452) |
Total Exploration Costs (Non-GAAP) | 410,804 |  |  | 348,754 |  |  | 367,739 |
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 8,239,593 |  |  | 7,695,191 |  |  | 6,946,815 |

37

Cost per Barrel of Oil Equivalent |  |  |  |  |
In thousands of USD, except Boe and per Boe amounts (Unaudited) |  |  |  |  |
| 2019 |  | 2018 |  | 2017
Composite Average Wellhead Revenue per Boe - (b) / (a) | 38.79 |  |  | 45.51 |  |  | 35.58 |
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) / (a) | 13.66 |  |  | 14.90 |  |  | 14.25 |
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | 25.13 |  |  | 30.61 |  |  | 21.33 |
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - (d) / (a) | 26.22 |  |  | 27.99 |  |  | 29.59 |
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | 12.57 |  |  | 17.52 |  |  | 5.99 |
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | 27.60 |  |  | 29.32 |  |  | 31.24 |
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | 11.19 |  |  | 16.19 |  |  | 4.34 |

38

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 Cash 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 |

39

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 Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) / (a) | 13.64 |  |  | 15.25 |  |  | 17.95 |
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | 13.18 |  |  | 15.41 |  |  | 40.06 |
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - (d) / (a) | 30.98 |  |  | 31.11 |  |  | 36.38 |
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | (4.16) |  |  | (0.45) |  |  | 21.63 |
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | 33.10 |  |  | 33.36 |  |  | 37.08 |
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | (6.28) |  |  | (2.70) |  |  | 20.93 |

40

Quarter and Full Year Guidance |  |  |
(Unaudited)
(a) Fourth Quarter and Full Year 2020 Forecast
The forecast items for the fourth quarter and full year 2020 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 Fourth Quarter and Full Year 2020 |  | 4Q 2020 |  |  | FY 2020
Daily Sales Volumes |  |  |  |  |  |  |  |  |  |  |
Crude Oil and Condensate Volumes (MBbld) |  |  |  |  |  |  |  |  |  |  |
United States |  | 435.0 |  | - |  | 445.0 |  |  |  | 406.3 |  | - |  | 408.8 |
Trinidad |  | 1.6 |  | - |  | 2.0 |  |  |  | 0.8 |  | - |  | 0.9 |
Other International |  | 0.0 |  | - |  | 0.2 |  |  |  | 0.1 |  | - |  | 0.1 |
Total |  | 436.6 |  | - |  | 447.2 |  |  |  | 407.2 |  | - |  | 409.8 |
Natural Gas Liquids Volumes (MBbld) |  |  |  |  |  |  |  |  |  |  |
Total |  | 140.0 |  | - |  | 150.0 |  |  |  | 137.2 |  | - |  | 139.7 |
Natural Gas Volumes (MMcfd) |  |  |  |  |  |  |  |  |  |  |
United States |  | 1,040 |  | - |  | 1,100 |  |  |  | 1,032 |  | - |  | 1,047 |
Trinidad |  | 170 |  | - |  | 190 |  |  |  | 174 |  | - |  | 179 |
Other International |  | 20 |  | - |  | 30 |  |  |  | 30 |  | - |  | 33 |
Total |  | 1,230 |  | - |  | 1,320 |  |  |  | 1,236 |  | - |  | 1,259 |
Crude Oil Equivalent Volumes (MBoed) |  |  |  |  |  |  |  |  |  |  |
United States |  | 748.3 |  | - |  | 778.3 |  |  |  | 715.4 |  | - |  | 722.9 |
Trinidad |  | 29.9 |  | - |  | 33.7 |  |  |  | 29.8 |  | - |  | 30.8 |
Other International |  | 3.3 |  | - |  | 5.2 |  |  |  | 5.1 |  | - |  | 5.6 |
Total |  | 781.5 |  | - |  | 817.2 |  |  |  | 750.3 |  | - |  | 759.3 |
Capital Expenditures ($MM) |  | 830 |  | - |  | 930 |  |  |  | 3,400 |  |  |  | 3,600 |

41

Quarter and Full Year Guidance |  |  |  |
(Unaudited)
Estimated Ranges for Fourth Quarter and Full Year 2020 |  | 4Q 2020 |  |  | FY 2020
Operating Costs |  |  |  |  |  |  |  |  |  |  |
Unit Costs ($/Boe) |  |  |  |  |  |  |  |  |  |  |
Lease and Well |  | 3.80 |  | - |  | 4.30 |  |  |  | 3.92 |  | - |  | 4.05 |
Transportation Costs |  | 2.55 |  | - |  | 2.95 |  |  |  | 2.64 |  | - |  | 2.74 |
Gathering and Processing |  | 1.75 |  | - |  | 1.85 |  |  |  | 1.70 |  | - |  | 1.72 |
Depreciation, Depletion and Amortization |  | 12.20 |  | - |  | 12.70 |  |  |  | 12.41 |  | - |  | 12.54 |
General and Administrative |  | 1.80 |  | - |  | 1.90 |  |  |  | 1.82 |  | - |  | 1.85 |
Expenses ($MM) |  |  |  |  |  |  |  |  |  |  |
Exploration and Dry Hole |  | 45 |  | - |  | 55 |  |  |  | 163 |  | - |  | 173 |
Impairment |  | 100 |  | - |  | 150 |  |  |  | 265 |  | - |  | 315 |
Capitalized Interest |  | 5 |  | - |  | 10 |  |  |  | 29 |  | - |  | 34 |
Net Interest |  | 51 |  | - |  | 56 |  |  |  | 203 |  | - |  | 208 |
Taxes Other Than Income (% of Wellhead Revenue) |  | 6.0 | % | - |  | 8.0 | % |  |  | 6.7 | % | - |  | 7.8 | %
Income Taxes |  |  |  |  |  |  |  |  |  |  |
Effective Rate |  | 20 | % | - |  | 25 | % |  |  | 16 | % | - |  | 21 | %
Current Tax (Benefit) / Expense ($MM) |  | 10 |  | - |  | 50 |  |  |  | (85) |  | - |  | (45) |
Pricing - (Refer to Benchmark Commodity Pricing in text) |  |  |  |  |  |  |  |  |  |  |
Crude Oil and Condensate ($/Bbl) |  |  |  |  |  |  |  |  |  |  |
Differentials |  |  |  |  |  |  |  |  |  |  |
United States - above (below) WTI |  | (1.85) |  | - |  | 0.15 |  |  |  | (1.07) |  | - |  | (0.52) |
Trinidad - above (below) WTI |  | (14.40) |  | - |  | (12.40) |  |  |  | (12.52) |  | - |  | (11.40) |
Other International - above (below) WTI |  | (8.00) |  | - |  | (2.00) |  |  |  | 2.18 |  | - |  | 3.68 |
Natural Gas Liquids |  |  |  |  |  |  |  |  |  |  |
Realizations as % of WTI |  | 34 | % | - |  | 46 | % |  |  | 32 | % | - |  | 35 | %
Natural Gas ($/Mcf) |  |  |  |  |  |  |  |  |  |  |
Differentials |  |  |  |  |  |  |  |  |  |  |
United States - above (below) NYMEX Henry Hub |  | (0.60) |  | - |  | (0.20) |  |  |  | (0.54) |  | - |  | (0.43) |
Realizations |  |  |  |  |  |  |  |  |  |  |
Trinidad |  | 3.15 |  | - |  | 3.65 |  |  |  | 2.44 |  | - |  | 2.59 |
Other International |  | 4.35 |  | - |  | 4.85 |  |  |  | 4.44 |  | - |  | 4.54 |

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 |  |  |  |  |  |  |  |  |  |  |

42