EOG Resources Reports Second Quarter 2020 Results

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EOG Resources reported a second quarter 2020 net loss of $909 million, or $1.57 per share, compared to a net income of $848 million, or $1.46 per share in Q2 2019. Adjusted non-GAAP net loss was $131 million, reflecting the impact of lower commodity prices and production volumes due to COVID-19. Despite these challenges, EOG generated positive free cash flow of $194 million by significantly reducing operating costs and capital expenditures. Additionally, EOG discovered 500 Bcf of net natural gas resources in Trinidad, enhancing its future production potential.

Positive

Generated positive free cash flow of $194 million in Q2 2020.
Reduced capital expenditures by 26%, exceeding initial forecasts.
Discovered 500 Bcf net natural gas resource potential in Trinidad.
Increased 2020 well cost savings target to 12% from 8%.

Negative

Reported a net loss of $909 million in Q2 2020.
Total crude oil volumes were down 27% year-over-year.
Average daily production decreased by 23% compared to Q2 2019.

08/06/2020 - 04:14 PM

HOUSTON, Aug. 6, 2020 /PRNewswire/ --

Generated Positive Net Cash Provided by Operating Activities and Free Cash Flow
Produced 7% More Crude Oil for 26% Less Capital Expenditures than Forecast
Per-Unit Cash Operating Costs Below Targets
Discovered 500 Bcf Net Natural Gas Resource Potential in Trinidad
Increased 2020 Well Cost Savings Target to 12% from 8%, Supporting Improved Outlook for Capital Efficiency

EOG Resources, Inc. (EOG) today reported a second quarter 2020 net loss of $909 million, or $1.57 per share, compared with second quarter 2019 net income of $848 million, or $1.46 per share.

Adjusted non-GAAP net loss for the second quarter 2020 was $131 million, or $0.23 per share, compared with adjusted non-GAAP net income of $762 million, or $1.31 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Second Quarter 2020 Review

Earnings in the second quarter 2020 were lower than the same prior year period due to lower commodity prices and production volumes, partially offset by reduced operating costs. EOG adjusted quickly to the decline in commodity prices – a result of COVID-19's impact on demand – by slowing drilling activity and lowering both capital expenditures and operating costs. EOG also deferred production by delaying initial production from most new wells and shutting in production from lower-margin, existing wells across multiple basins. Deferring production volumes into higher-priced time periods is a return-based decision designed to maximize net present value.

As a result of EOG's actions to address the rapid change in market conditions, total company crude oil volumes were 331,100 barrels of oil per day (Bopd), 27 percent below the second quarter 2019. Natural gas liquids production was 23 percent lower and natural gas volumes were 15 percent lower, contributing to 23 percent lower total company daily production.

Net crude oil volumes associated with the shut-in of existing wells peaked at approximately 107,000 Bopd in May, with an average of approximately 73,000 Bopd shut in during the second quarter. The company estimates that approximately 25,000 Bopd will remain shut-in on average during the third quarter 2020. EOG began to return shut-in volumes to production in June, and expects nearly all shut-in wells to begin production before the end of the third quarter. EOG also deferred initial production from most new wells until late June, with ten net new wells contributing less than 1,000 Bopd of production in the second quarter. EOG continues to closely monitor market conditions and retains flexibility to adjust its plans in response to changes in commodity prices.

Lease and well, transportation, and gathering and processing costs each declined in the second quarter compared with the prior year period. Lease and well costs were the largest contributor to the overall cost reduction and were down eight percent on a per-unit basis. Sustainable efficiency improvements and service cost reductions contributed to the savings. These factors also contributed to an improved well cost reduction target of 12 percent for 2020, an increase from the forecast at the start of the year of eight percent.

During the second quarter, EOG received net cash from settlements of financial commodity derivative contracts of $639 million. The company also elected to sell a portion of its crude oil production in May and June under fixed-price agreements to further limit its exposure to commodity price volatility. This contributed to lower average crude oil prices compared with the prior year period and reduced revenues from gathering, processing and marketing relative to marketing costs.

Net cash provided by operating activities was $88 million. Changes in working capital and other assets and liabilities generated a net cash outflow of $1.0 billion in the second quarter 2020 and a net cash inflow of $0.2 billion in the first six months of 2020. Excluding changes in working capital and certain other items, EOG generated $672 million of discretionary cash flow in the second quarter 2020. The company incurred total expenditures of $534 million, including $478 million of capital expenditures before acquisitions, non–cash transactions and asset retirement costs, resulting in $194 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

"EOG generated positive free cash flow in the second quarter, made possible by our ability to quickly reduce activity and cut operating costs in all of our operating areas in response to historically low oil prices," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "This is a testament to EOG's unique culture and the flexibility provided by a decentralized organizational structure. In addition, our focus on safety, innovation, technical advancements and continuous improvement has not wavered. Our talented employees quickly and safely adapted to these volatile conditions, and I want to thank them for their dedication and commitment to EOG.

"Going forward, we will remain flexible and ready to respond to changes in market conditions with the goal of maximizing long-term shareholder value. Our priorities are unchanged: generate high returns on any capital invested and generate free cash flow to fund the dividend and protect our strong balance sheet. The sustainable improvements we are making across the company will support improved capital efficiency in the future, enabling EOG to maintain production at lower oil prices. We are confident EOG will emerge from the downturn an even better company."

Trinidad Exploration Success

EOG announced significant discoveries from its drilling campaign in Trinidad that have estimated gross resource potential of up to 1.0 trillion cubic feet of natural gas, or 500 billion cubic feet, net to EOG. The discoveries are based on results from four wells drilled in the past year located on three different blocks in shallow water off the southeast coast of Trinidad. The discoveries will support the installation of two new production platforms and development programs for the next three to five years. EOG plans to drill two additional wells over the remainder of 2020. Additional resource potential could be confirmed through further evaluation of the discovery wells and subsequent development. The exploration success supports EOG's long-term strategy in Trinidad of generating high returns and strong free cash flow through low-cost operations and targeted exploration.

Financial Review

EOG retains exceptional financial flexibility, with strong investment-grade credit ratings, low leverage ratios and ample liquidity. At June 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $2.4 billion of cash on the balance sheet at the end of the second quarter, EOG's net debt was $3.3 billion for a net debt-to-total capitalization ratio of 14 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of June 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

On April 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 that matured on that date. In addition, on April 14, 2020, EOG closed its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050. EOG received aggregate net proceeds from the sale, after deducting underwriting discounts and offering expenses, of approximately $1.48 billion. On June 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020 that matured on that date.

During the second quarter, EOG entered into offsetting contracts to lock-in the value of outstanding crude oil NYMEX WTI price swap contracts and other financial commodity derivative contracts effective from June through December 2020. As of June 30, EOG expects to receive net cash payments of $360 million from the settlement of these contracts over the remainder of 2020.

Second Quarter 2020 Results Webcast
Friday, August 7, 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 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 imposing 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.

Income Statements

In thousands of USD, except per share data (Unaudited)
	2Q 2020	2Q 2019	YTD 2020	YTD 2019
Operating Revenues and Other
Crude Oil and Condensate	614,627	2,528,866	2,680,125	4,729,269
Natural Gas Liquids	93,909	186,374	254,444	405,012
Natural Gas	141,696	269,892	351,460	604,864
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	(126,362)	177,300	1,079,411	156,720
Gathering, Processing and Marketing	362,786	1,501,386	1,401,432	2,787,040
Gains on Asset Dispositions, Net	13,233	8,009	29,693	4,173
Other, Net	3,485	25,803	24,501	69,194
Total	1,103,374	4,697,630	5,821,066	8,756,272

Operating Expenses
Lease and Well	245,346	347,281	575,005	683,572
Transportation Costs	151,728	174,101	360,024	350,623
Gathering and Processing Costs	96,767	112,643	225,249	223,938
Exploration Costs	27,283	32,522	66,960	68,846
Dry Hole Costs	87	3,769	459	3,863
Impairments	305,415	112,130	1,878,350	184,486
Marketing Costs	444,444	1,500,915	1,553,437	2,770,972
Depreciation, Depletion and Amortization	706,679	957,304	1,706,739	1,836,899
General and Administrative	131,855	121,780	246,128	228,452
Taxes Other Than Income	80,319	204,414	237,679	397,320
Total	2,189,923	3,566,859	6,850,030	6,748,971

Operating Income (Loss)	(1,086,549)	1,130,771	(1,028,964)	2,007,301
Other Income (Expense), Net	(4,500)	8,503	13,608	14,115
Income (Loss) Before Interest Expense and Income Taxes	(1,091,049)	1,139,274	(1,015,356)	2,021,416
Interest Expense, Net	54,213	49,908	98,903	104,814
Income (Loss) Before Income Taxes	(1,145,262)	1,089,366	(1,114,259)	1,916,602
Income Tax Provision (Benefit)	(235,878)	241,525	(214,688)	433,335
Net Income (Loss)	(909,384)	847,841	(899,571)	1,483,267

Dividends Declared per Common Share	0.3750	0.2875	0.7500	0.5075
Net Income (Loss) Per Share
Basic	(1.57)	1.47	(1.55)	2.57
Diluted	(1.57)	1.46	(1.55)	2.56
Average Number of Common Shares
Basic	578,719	577,460	578,581	577,333
Diluted	578,719	580,247	578,581	580,204

Wellhead Volumes and Prices

(Unaudited)
	2Q 2020	2Q 2019	% Change		YTD 2020	YTD 2019	% Change

Crude Oil and Condensate Volumes (MBbld) ^(A)
United States	330.9	454.9	-27	%	406.8	445.1	-9	%
Trinidad	0.1	0.6	-83	%	0.3	0.7	-57	%
Other International ^(B)	0.1	0.2	-50	%	0.1	—
Total	331.1	455.7	-27	%	407.2	445.8	-9	%

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	20.40	61.01	-67	%	36.17	58.63	-38	%
Trinidad	0.60	49.56	-99	%	27.75	46.62	-40	%
Other International ^(B)	48.78	55.07	-11	%	53.41	57.78	-8	%
Composite	20.40	60.99	-67	%	36.16	58.61	-38	%

Natural Gas Liquids Volumes (MBbld) ^(A)
United States	101.2	131.1	-23	%	131.2	125.4	5	%
Other International ^(B)	—	—			—	—
Total	101.2	131.1	-23	%	131.2	125.4	5	%

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	10.20	15.63	-35	%	10.65	17.84	-40	%
Other International ^(B)	—	—			—	—
Composite	10.20	15.63	-35	%	10.65	17.84	-40	%

Natural Gas Volumes (MMcfd) ^(A)
United States	939	1,047	-10	%	1,039	1,025	1	%
Trinidad	174	273	-36	%	188	270	-30	%
Other International ^(B)	34	36	-6	%	35	37	-5	%
Total	1,147	1,356	-15	%	1,262	1,332	-5	%

Average Natural Gas Prices ($/Mcf) ^(C)
United States	1.11	1.98	-44	%	1.32	2.37	-44	%
Trinidad	2.13	2.69	-21	%	2.15	2.80	-23	%
Other International ^(B)	4.36	4.25	2	%	4.34	4.31	1	%
Composite	1.36	2.19	-38	%	1.53	2.51	-39	%

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States	588.5	760.4	-23	%	711.1	741.3	-4	%
Trinidad	29.2	46.1	-37	%	31.6	45.6	-31	%
Other International ^(B)	5.7	6.3	-10	%	6.1	6.4	-5	%
Total	623.4	812.8	-23	%	748.8	793.3	-6	%

Total MMBoe ^(D)	56.7	74.0	-23	%	136.3	143.6	-5	%

(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 June 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.

Balance Sheets

In thousands of USD, except per share data (Unaudited)
	June 30,	December 31,
	2020	2019
Current Assets
Cash and Cash Equivalents	2,416,501	2,027,972
Accounts Receivable, Net	943,354	2,001,658
Inventories	676,580	767,297
Assets from Price Risk Management Activities	207,019	1,299
Income Taxes Receivable	196,958	151,665
Other	156,979	323,448
Total	4,597,391	5,273,339

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	64,406,245	62,830,415
Other Property, Plant and Equipment	4,665,815	4,472,246
Total Property, Plant and Equipment	69,072,060	67,302,661
Less: Accumulated Depreciation, Depletion and Amortization	(39,838,595)	(36,938,066)
Total Property, Plant and Equipment, Net	29,233,465	30,364,595
Deferred Income Taxes	1,846	2,363
Other Assets	1,388,969	1,484,311
Total Assets	35,221,671	37,124,608

Current Liabilities
Accounts Payable	1,281,166	2,429,127
Accrued Taxes Payable	193,763	254,850
Dividends Payable	217,004	166,273
Liabilities from Price Risk Management Activities	—	20,194
Current Portion of Long-Term Debt	21,121	1,014,524
Current Portion of Operating Lease Liabilities	252,642	369,365
Other	188,685	232,655
Total	2,154,381	4,486,988

Long-Term Debt	5,703,141	4,160,919
Other Liabilities	2,138,696	1,789,884
Deferred Income Taxes	4,837,896	5,046,101
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,386,649 Shares Issued at June 30, 2020 and 582,213,016 Shares Issued at December 31, 2019	205,824	205,822
Additional Paid in Capital	5,886,298	5,817,475
Accumulated Other Comprehensive Loss	(6,130)	(4,652)
Retained Earnings	14,312,493	15,648,604
Common Stock Held in Treasury, 142,025 Shares at June 30, 2020 and 298,820 Shares at December 31, 2019	(10,928)	(26,533)
Total Stockholders' Equity	20,387,557	21,640,716
Total Liabilities and Stockholders' Equity	35,221,671	37,124,608

Cash Flows Statements

In thousands of USD (Unaudited)
	2Q 2020	2Q 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)	(909,384)	847,841	(899,571)	1,483,267
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	706,679	957,304	1,706,739	1,836,899
Impairments	305,415	112,130	1,878,350	184,486
Stock-Based Compensation Expenses	39,571	38,566	79,643	77,653
Deferred Income Taxes	(252,466)	217,970	(207,692)	324,294
Gains on Asset Dispositions, Net	(13,233)	(8,009)	(29,693)	(4,173)
Other, Net	8,986	2,487	171	5,439
Dry Hole Costs	87	3,769	459	3,863
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	126,362	(177,300)	(1,079,411)	(156,720)
Net Cash Received from Settlements of Commodity Derivative Contracts	639,388	10,444	723,761	31,290
Other, Net	(365)	663	(720)	1,639
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	469,294	239,250	1,191,457	(69,746)
Inventories	(18,095)	7,720	84,575	(11,259)
Accounts Payable	(1,618,276)	(67,229)	(1,184,718)	126,853
Accrued Taxes Payable	(6,482)	(61,718)	(61,087)	53,280
Other Assets	194,682	494,322	252,978	487,387
Other Liabilities	1,675	(4,014)	(64,403)	(58,106)
Changes in Components of Working Capital Associated with Investing and Financing Activities	414,236	72,347	282,154	(22,034)
Net Cash Provided by Operating Activities	88,074	2,686,543	2,672,992	4,294,312
Investing Cash Flows
Additions to Oil and Gas Properties	(423,982)	(1,507,024)	(1,990,033)	(3,446,497)
Additions to Other Property, Plant and Equipment	(24,591)	(55,918)	(147,366)	(116,881)
Proceeds from Sales of Assets	17,567	2,593	43,368	17,642
Changes in Components of Working Capital Associated with Investing Activities	(414,236)	(72,325)	(282,154)	22,056
Net Cash Used in Investing Activities	(845,242)	(1,632,674)	(2,376,185)	(3,523,680)
Financing Cash Flows
Long-Term Debt Borrowings	1,483,852	—	1,483,852	—
Long-Term Debt Repayments	(1,000,000)	(900,000)	(1,000,000)	(900,000)
Dividends Paid	(217,042)	(127,135)	(384,100)	(254,681)
Treasury Stock Purchased	(402)	(2,155)	(5,057)	(8,403)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	8,548	8,292	8,614	8,695
Debt Issuance Costs	(2,635)	(4,902)	(2,635)	(4,902)
Repayment of Finance Lease Liabilities	(4,824)	(3,213)	(8,445)	(6,403)
Changes in Components of Working Capital Associated with Financing Activities	—	(22)	—	(22)
Net Cash Provided by (Used in) Financing Activities	267,497	(1,029,135)	92,229	(1,165,716)
Effect of Exchange Rate Changes on Cash	(680)	(59)	(507)	(65)
Increase (Decrease) in Cash and Cash Equivalents	(490,351)	24,675	388,529	(395,149)
Cash and Cash Equivalents at Beginning of Period	2,906,852	1,135,810	2,027,972	1,555,634
Cash and Cash Equivalents at End of Period	2,416,501	1,160,485	2,416,501	1,160,485

Non-GAAP Financial Measures

To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Discretionary Cash Flow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics.

A reconciliation of each of these measures to their most directly comparable GAAP financial measure is included in the tables below and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com.

EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance.

EOG believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods.

The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Total Debt, Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP.

In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices.

Adjusted Net Income (Loss)

In thousands of USD, except per share data (Unaudited)
	2Q 2020
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Loss (GAAP)	(1,145,262)	235,878	(909,384)	(1.57)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts	126,362	(27,734)	98,628	0.17
Net Cash Received from Settlements of Commodity Derivative Contracts	639,388	(140,333)	499,055	0.86
Less: Gains on Asset Dispositions, Net	(13,233)	2,930	(10,303)	(0.02)
Add: Certain Impairments	239,167	(48,351)	190,816	0.33
Adjustments to Net Loss	991,684	(213,488)	778,196	1.34

Adjusted Net Loss (Non-GAAP)	(153,578)	22,390	(131,188)	(0.23)

Average Number of Common Shares (GAAP)
Basic				578,719
Diluted				578,719

Average Number of Common Shares (Non-GAAP)
Basic				578,719
Diluted				578,719

	2Q 2019
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,089,366	(241,525)	847,841	1.46
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts	(177,300)	38,930	(138,370)	(0.24)
Net Cash Received from Settlements of Commodity Derivative Contracts	10,444	(2,276)	8,168	0.01
Less: Gains on Asset Dispositions, Net	(8,009)	1,734	(6,275)	(0.01)
Add: Certain Impairments	65,289	(14,311)	50,978	0.09
Adjustments to Net Income	(109,576)	24,077	(85,499)	(0.15)

Adjusted Net Income (Non-GAAP)	979,790	(217,448)	762,342	1.31

Average Number of Common Shares (GAAP)
Basic				577,460
Diluted				580,247

Average Number of Common Shares (Non-GAAP)				577,460
Basic				580,247
Diluted

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)	(1,114,259)	214,688	(899,571)	(1.55)
Adjustments:
Gains Mark-to-Market Commodity Derivative Contracts	(1,079,411)	236,909	(842,502)	(1.47)
Net Cash Received from Settlements of Commodity Derivative Contracts	723,761	(158,851)	564,910	0.98
Less: Gains on Asset Dispositions, Net	(29,693)	6,543	(23,150)	(0.04)
Add: Certain Impairments	1,755,483	(368,324)	1,387,159	2.40
Adjustments to Net Loss	1,370,140	(283,723)	1,086,417	1.87

Adjusted Net Income (Non-GAAP)	255,881	(69,035)	186,846	0.32

Average Number of Common Shares (GAAP)
Basic				578,581
Diluted				578,581

Average Number of Common Shares (Non-GAAP)
Basic				578,581
Diluted				580,179

	YTD 2019
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,916,602	(433,335)	1,483,267	2.56
Adjustments:
Gains on Mark-to-Market Commodity Derivative Contracts	(156,720)	34,397	(122,323)	(0.21)
Net Cash Received from Settlements of Commodity Derivative Contracts	31,290	(6,868)	24,422	0.04
Less: Gains on Asset Dispositions, Net	(4,173)	998	(3,175)	(0.01)
Add: Certain Impairments	89,034	(19,541)	69,493	0.12
Adjustments to Net Income	(40,569)	8,986	(31,583)	(0.06)

Adjusted Net Income (Non-GAAP)	1,876,033	(424,349)	1,451,684	2.50

Average Number of Common Shares (GAAP)
Basic				577,333
Diluted				580,204

Average Number of Common Shares (Non-GAAP)
Basic				577,333
Diluted				580,204

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)
	2Q 2020		2Q 2019	YTD 2020		YTD 2019

Net Cash Provided by Operating Activities (GAAP)	88,074		2,686,543	2,672,992		4,294,312

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	20,484		26,089	52,966		55,876
Other Non-Current Income Taxes - Net Receivable	—		42,764	112,704		145,682
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(469,294)		(239,250)	(1,191,457)		69,746
Inventories	18,095		(7,720)	(84,575)		11,259
Accounts Payable	1,618,276		67,229	1,184,718		(126,853)
Accrued Taxes Payable	6,482		61,718	61,087		(53,280)
Other Assets	(194,682)		(494,322)	(252,978)		(487,387)
Other Liabilities	(1,675)		4,014	64,403		58,106
Changes in Components of Working Capital Associated with Investing and Financing Activities	(414,236)		(72,347)	(282,154)		22,034
Discretionary Cash Flow (Non-GAAP)	671,524		2,074,718	2,337,706		3,989,495

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease	-68	%		-41	%

Discretionary Cash Flow (Non-GAAP)	671,524		2,074,718	2,337,706		3,989,495
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a)	(477,616)		(1,595,726)	(2,162,336)		(3,328,202)
Free Cash Flow (Non-GAAP) ^(b)	193,908		478,992	175,370		661,293

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month and six-month periods ended June 30, 2020 and 2019:

Total Expenditures (GAAP)	534,411		1,663,127	2,360,189		3,765,046
Less:
Asset Retirement Costs	(5,955)		(55,425)	(25,563)		(60,581)
Non-Cash Expenditures of Other Property, Plant and Equipment	(60)		(586)	(60)		(586)
Non-Cash Acquisition Costs of Unproved Properties	(23,243)		(10,240)	(47,731)		(53,721)
Non-Cash Finance Leases	(24,319)		—	(73,277)		—
Acquisition Costs of Proved Properties	(3,218)		(1,150)	(51,222)		(321,956)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	477,616		1,595,726	2,162,336		3,328,202

(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 six-month periods ending June 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.

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	%

Discretionary Cash Flow (Non-GAAP)	8,122,150		8,271,692		4,839,532
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a)	(6,234,454)		(6,172,950)		(4,228,859)
Free Cash Flow (Non-GAAP) ^(b)	1,887,696		2,098,742		610,673

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017:

Total Expenditures (GAAP)	6,900,450		6,706,359		4,612,746
Less:
Asset Retirement Costs	(186,088)		(69,699)		(55,592)
Non-Cash Expenditures of Other Property, Plant and Equipment	(2,266)		(49,484)		—
Non-Cash Acquisition Costs of Unproved Properties	(97,704)		(290,542)		(255,711)
Acquisition Costs of Proved Properties	(379,938)		(123,684)		(72,584)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	6,234,454		6,172,950		4,228,859

(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019. The comparative prior periods shown have been revised to conform to this presentation.

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)

	FY 2014		FY 2013		FY 2012

Net Cash Provided by Operating Activities (GAAP)	8,649,155		7,329,414		5,236,777

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)	157,453		134,531		159,182
Excess Tax Benefits from Stock-Based Compensation	99,459		55,831		67,035
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(84,982)		23,613		178,683
Inventories	161,958		(53,402)		156,762
Accounts Payable	(543,630)		(178,701)		17,150
Accrued Taxes Payable	(16,486)		(75,142)		(78,094)
Other Assets	14,448		109,567		118,520
Other Liabilities	(75,420)		20,382		(36,114)
Changes in Components of Working Capital Associated with Investing and Financing Activities	103,414		51,361		(74,158)
Discretionary Cash Flow (Non-GAAP)	8,465,369		7,417,454		5,745,743

Discretionary Cash Flow (Non-GAAP) - Percentage Increase	14	%	29	%

Discretionary Cash Flow (Non-GAAP)	8,465,369		7,417,454		5,745,743
Less:
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) ^(a)	(8,292,090)		(7,101,791)		(7,539,994)
Free Cash Flow (Non-GAAP) ^(b)	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, 2014, 2013 and 2012:

Total Expenditures (GAAP)	8,631,906		7,361,457		7,753,828
Less:
Asset Retirement Costs	(195,630)		(134,445)		(126,987)
Non-Cash Expenditures of Other Property, Plant and Equipment	—		—		(65,791)
Non-Cash Acquisition Costs of Unproved Properties	(5,085)		(5,007)		(20,317)
Acquisition Costs of Proved Properties	(139,101)		(120,214)		(739)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)	8,292,090		7,101,791		7,539,994

(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item.

Total Expenditures

In millions of USD (Unaudited)

	2Q 2020	2Q 2019	FY 2019	FY 2018	FY 2017

Exploration and Development Drilling	381	1,290	4,951	4,935	3,132
Facilities	31	174	629	625	575
Leasehold Acquisitions	30	38	276	488	427
Property Acquisitions	3	1	380	124	73
Capitalized Interest	8	11	38	24	27
Subtotal	453	1,514	6,274	6,196	4,234
Exploration Costs	27	33	140	149	145
Dry Hole Costs	—	4	28	5	5
Exploration and Development Expenditures	480	1,551	6,442	6,350	4,384
Asset Retirement Costs	5	56	186	70	56
Total Exploration and Development Expenditures	485	1,607	6,628	6,420	4,440
Other Property, Plant and Equipment	49	56	272	286	173
Total Expenditures	534	1,663	6,900	6,706	4,613

EBITDAX and Adjusted EBITDAX

In thousands of USD (Unaudited)
	2Q 2020		2Q 2019	YTD 2020		YTD 2019

Net Income (Loss) (GAAP)	(909,384)		847,841	(899,571)		1,483,267

Adjustments:
Interest Expense, Net	54,213		49,908	98,903		104,814
Income Tax Provision (Benefit)	(235,878)		241,525	(214,688)		433,335
Depreciation, Depletion and Amortization	706,679		957,304	1,706,739		1,836,899
Exploration Costs	27,283		32,522	66,960		68,846
Dry Hole Costs	87		3,769	459		3,863
Impairments	305,415		112,130	1,878,350		184,486
EBITDAX (Non-GAAP)	(51,585)		2,244,999	2,637,152		4,115,510
(Gains) Losses on MTM Commodity Derivative Contracts	126,362		(177,300)	(1,079,411)		(156,720)
Net Cash Received from Settlements of Commodity Derivative Contracts	639,388		10,444	723,761		31,290
Less: Gains on Asset Dispositions, Net	(13,233)		(8,009)	(29,693)		(4,173)

Adjusted EBITDAX (Non-GAAP)	700,932		2,070,134	2,251,809		3,985,907

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease	-66	%		-44	%

Definitions
EBITDAX - Earnings Before Interest Expense; Income Taxes; Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments

Net Debt-to-Total Capitalization Ratio

In millions of USD, except ratio data (Unaudited)
	June 30, 2020		March 31, 2020		December 31, 2019		September 30, 2019		June 30, 2019		March 31, 2019

Total Stockholders' Equity - (a)	20,388		21,471		21,641		21,124		20,630		19,904

Current and Long-Term Debt (GAAP) - (b)	5,724		5,222		5,175		5,177		5,179		6,081
Less: Cash	(2,417)		(2,907)		(2,028)		(1,583)		(1,160)		(1,136)
Net Debt (Non-GAAP) - (c)	3,307		2,315		3,147		3,594		4,019		4,945

Total Capitalization (GAAP) - (a) + (b)	26,112		26,693		26,816		26,301		25,809		25,985

Total Capitalization (Non-GAAP) - (a) + (c)	23,695		23,786		24,788		24,718		24,649		24,849

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	22	%	20	%	19	%	20	%	20	%	23	%

Net Debt-to-Total Capitalization (Non- GAAP) - (c) / [(a) + (c)]	14	%	10	%	13	%	15	%	16	%	20	%

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	%

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	%

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	%

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

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 July 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 July 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 July 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	0.7
July 1, 2020 through August 31, 2020 (CLOSED)	88,000	(1.16)
Sep-20	88,000	(1.16)
October 1, 2020 through December 31, 2020	66,000	(1.16)

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 expects to pay net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Crude Oil NYMEX WTI Price Swap Contracts
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through July 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 expects to receive net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Crude Oil ICE Brent Price Swap Contracts
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through July 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 July 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 expects to receive net cash of $9.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Natural Gas Price Swap Contracts
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through July 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	50,000	2.75

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. The net cash EOG received for settling these contracts was $7.8 million. Presented below is a comprehensive summary of EOG's natural gas collar contracts through July 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	2.5	2

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 expects to receive net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Rockies Differential Basis Swap Contracts
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through July 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	Weighted Average Price Differential
	(MMBtud)	($/MMBtu)
January 1, 2020 through July 31, 2020 (CLOSED)	30,000	0.55
August 1, 2020 through December 31, 2020	30,000	0.55

HSC Differential Basis Swap Contracts
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. The net cash EOG paid for settling these contracts was $0.4 million. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through July 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 July 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	Weighted Average Price Differential
	(MMBtud)	($/MMBtu)
January 1, 2020 through April 30, 2020 (CLOSED)	50,000	1.4

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 expects to pay net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Definitions

Bbld		Barrels per day
$/Bbl		Dollars per barrel
ICE		Intercontinental Exchange
MMBtud		Million British thermal units per day
$/MMBtu		Dollars per million British thermal units
NYMEX		U.S. New York Mercantile Exchange
WTI		West Texas Intermediate

Direct After-Tax Rate of Return


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

Direct ATROR
Based on Cash Flow and Time Value of Money
- Estimated future commodity prices and operating costs
- Costs incurred to drill, complete and equip a well, including facilities
Excludes Indirect Capital
- Gathering and Processing and other Midstream
- Land, Seismic, Geological and Geophysical

Payback ~12 Months on 100% Direct ATROR Wells
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

Return on Equity / Return on Capital Employed
Based on GAAP Accrual Accounting
Includes All Indirect Capital and Growth Capital for Infrastructure
- Eagle Ford, Bakken, Permian Facilities
- Gathering and Processing
Includes Legacy Gas Capital and Capital from Mature Wells

ROCE & ROE

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

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

	2017		2016		2015		2014		2013

Net Interest Expense (GAAP)	274		282		237		201		235
Tax Benefit Imputed (based on 35%)	(96)		(99)		(83)		(70)		(82)
After-Tax Net Interest Expense (Non-GAAP) - (a)	178		183		154		131		153

Net Income (Loss) (GAAP) - (b)	2,583		(1,097)		(4,525)		2,915		2,197

Total Stockholders' Equity - (d)	16,283		13,982		12,943		17,713		15,418

Average Total Stockholders' Equity* - (e)	15,133		13,463		15,328		16,566		14,352

Current and Long-Term Debt (GAAP) - (f)	6,387		6,986		6,655		5,906		5,909
Less: Cash	(834)		(1,600)		(719)		(2,087)		(1,318)
Net Debt (Non-GAAP) - (g)	5,553		5,386		5,936		3,819		4,591

Total Capitalization (GAAP) - (d) + (f)	22,670		20,968		19,598		23,619		21,327

Total Capitalization (Non-GAAP) - (d) + (g)	21,836		19,368		18,879		21,532		20,009

Average Total Capitalization (Non-GAAP)* - (h)	20,602		19,124		20,206		20,771		19,365

Return on Capital Employed (ROCE)
GAAP Net Income (Loss) - [(a) + (b)] / (h)	13.4	%	-4.8	%	-21.6	%	14.7	%	12.1	%

Return on Equity (ROE)
GAAP Net Income (Loss) - (b) / (e)	17.1	%	-8.1	%	-29.5	%	17.6	%	15.3	%

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

	2012		2011		2010		2009		2008

Net Interest Expense (GAAP)	214		210		130		101		52
Tax Benefit Imputed (based on 35%)	(75)		(74)		(46)		(35)		(18)
After-Tax Net Interest Expense (Non-GAAP) - (a)	139		136		84		66		34

Net Income (GAAP) - (b)	570		1,091		161		547		2,437

Total Stockholders' Equity - (d)	13,285		12,641		10,232		9,998		9,015

Average Total Stockholders' Equity* - (e)	12,963		11,437		10,115		9,507		8,003

Current and Long-Term Debt (GAAP) - (f)	6,312		5,009		5,223		2,797		1,897
Less: Cash	(876)		(616)		(789)		(686)		(331)
Net Debt (Non-GAAP) - (g)	5,436		4,393		4,434		2,111		1,566

Total Capitalization (GAAP) - (d) + (f)	19,597		17,650		15,455		12,795		10,912

Total Capitalization (Non-GAAP) - (d) + (g)	18,721		17,034		14,666		12,109		10,581

Average Total Capitalization (Non-GAAP)* - (h)	17,878		15,850		13,388		11,345		9,351

Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)	4.0	%	7.7	%	1.8	%	5.4	%	26.4	%

Return on Equity (ROE)
GAAP Net Income - (b) / (e)	4.4	%	9.5	%	1.6	%	5.8	%	30.5	%

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

	2007		2006		2005		2004		2003

Net Interest Expense (GAAP)	47		43		63		63		59
Tax Benefit Imputed (based on 35%)	(16)		(15)		(22)		(22)		(21)
After-Tax Net Interest Expense (Non-GAAP) - (a)	31		28		41		41		38

Net Income (GAAP) - (b)	1,090		1,300		1,260		625		430

Total Stockholders' Equity - (d)	6,990		5,600		4,316		2,945		2,223

Average Total Stockholders' Equity* - (e)	6,295		4,958		3,631		2,584		1,948

Current and Long-Term Debt (GAAP) - (f)	1,185		733		985		1,078		1,109
Less: Cash	(54)		(218)		(644)		(21)		(4)
Net Debt (Non-GAAP) - (g)	1,131		515		341		1,057		1,105

Total Capitalization (GAAP) - (d) + (f)	8,175		6,333		5,301		4,023		3,332

Total Capitalization (Non-GAAP) - (d) + (g)	8,121		6,115		4,657		4,002		3,328

Average Total Capitalization (Non-GAAP)* - (h)	7,118		5,386		4,330		3,665		3,068

Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)	15.7	%	24.7	%	30.0	%	18.2	%	15.3	%

Return on Equity (ROE)
GAAP Net Income - (b) / (e)	17.3	%	26.2	%	34.7	%	24.2	%	22.1	%

* Average for the current and immediately preceding year

ROCE & ROE

In millions of USD, except ratio data (Unaudited)

	2002		2001		2000		1999		1998

Net Interest Expense (GAAP)	60		45		61		62
Tax Benefit Imputed (based on 35%)	(21)		(16)		(21)		(22)
After-Tax Net Interest Expense (Non-GAAP) - (a)	39		29		40		40

Net Income (GAAP) - (b)	87		399		397		569

Total Stockholders' Equity - (d)	1,672		1,643		1,381		1,130		1,280

Average Total Stockholders' Equity* - (e)	1,658		1,512		1,256		1,205

Current and Long-Term Debt (GAAP) - (f)	1,145		856		859		990		1,143
Less: Cash	(10)		(3)		(20)		(25)		(6)
Net Debt (Non-GAAP) - (g)	1,135		853		839		965		1,137

Total Capitalization (GAAP) - (d) + (f)	2,817		2,499		2,240		2,120		2,423

Total Capitalization (Non-GAAP) - (d) + (g)	2,807		2,496		2,220		2,095		2,417

Average Total Capitalization (Non-GAAP)* - (h)	2,652		2,358		2,158		2,256

Return on Capital Employed (ROCE)
GAAP Net Income - [(a) + (b)] / (h)	4.8	%	18.2	%	20.2	%	27.0	%

Return on Equity (ROE)
GAAP Net Income - (b) / (e)	5.2	%	26.4	%	31.6	%	47.2	%

* Average for the current and immediately preceding year

Costs per Barrel of Oil Equivalent

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

	1Q 2020	2Q 2020	YTD 2020

Cost per Barrel of Oil Equivalent (Boe) Calculation
Volume - Thousand Barrels of Oil Equivalent - (a)	79,548	56,733	136,281

Crude Oil and Condensate	2,065,498	614,627	2,680,125
Natural Gas Liquids	160,535	93,909	254,444
Natural Gas	209,764	141,696	351,460
Total Wellhead Revenues - (b)	2,435,797	850,232	3,286,029

Operating Costs
Lease and Well	329,659	245,346	575,005
Transportation Costs	208,296	151,728	360,024
Gathering and Processing Costs	128,482	96,767	225,249
General and Administrative	114,273	131,855	246,128
Taxes Other Than Income	157,360	80,319	237,679
Interest Expense, Net	44,690	54,213	98,903
Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c)	982,760	760,228	1,742,988

Depreciation, Depletion and Amortization (DD&A)	1,000,060	706,679	1,706,739
Total Operating Cost (excluding Total Exploration Costs) - (d)	1,982,820	1,466,907	3,449,727

Exploration Costs	39,677	27,283	66,960
Dry Hole Costs	372	87	459
Impairments	1,572,935	305,415	1,878,350
Total Exploration Costs	1,612,984	332,785	1,945,769
Less: Certain Impairments (Non-GAAP)	(1,516,316)	(239,167)	(1,755,483)
Total Exploration Costs (Non-GAAP)	96,668	93,618	190,286

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)	2,079,488	1,560,525	3,640,013

Composite Average Wellhead Revenue per Boe - (b) / (a)	30.62	14.99	24.11

Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / (a)	12.36	13.40	12.79

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)]	18.26	1.59	11.32

Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a)	24.93	25.86	25.31

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)]	5.69	(10.87)	(1.20)

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a)	26.15	27.51	26.71

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)]	4.47	(12.52)	(2.60)

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

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

Costs 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

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

Quarter and Full Year Guidance

(Unaudited)

(a) Third Quarter and Full Year 2020 Forecast
The forecast items for the third 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 Third Quarter and Full Year 2020	3Q 2020			FY 2020

Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States	363.0	-	373.0	402.0	-	408.0
Trinidad	0.6	-	1.0	0.6	-	1.0
Other International	—	-	0.2	—	-	0.2
Total	363.6	-	374.2	402.6	-	409.2
Natural Gas Liquids Volumes (MBbld)
Total	125.0	-	135.0	130.0	-	140.0
Natural Gas Volumes (MMcfd)
United States	940	-	1,000	985	-	1,075
Trinidad	165	-	185	180	-	195
Other International	20	-	30	20	-	30
Total	1,125	-	1,215	1,185	-	1,300
Crude Oil Equivalent Volumes (MBoed)
United States	644.7	-	674.7	696.2	-	727.2
Trinidad	28.1	-	31.8	30.6	-	33.5
Other International	3.3	-	5.2	3.3	-	5.2
Total	676.1	-	711.7	730.1	-	765.9

Quarter and Full Year Guidance

(Unaudited)

Estimated Ranges for Third Quarter and Full Year 2020	3Q 2020					FY 2020

Capital Expenditures ($MM)	600		-	700		3,400		-	3,600

Operating Costs
Unit Costs ($/Boe)
Lease and Well	4.20		-	4.70		4.10		-	4.50
Transportation Costs	2.70		-	3.10		2.50		-	2.90
Gathering and Processing	1.70			1.90		1.65			1.85
Depreciation, Depletion and Amortization	12.10			12.60		11.85			12.85
General and Administrative	2.25		-	2.35		1.85		-	1.95

Expenses ($MM)
Exploration and Dry Hole	35		-	45		130		-	170
Impairment	80			90		290			330
Capitalized Interest	5		-	9		27		-	33
Net Interest	50		-	54		200		-	205

Taxes Other Than Income (% of Wellhead Revenue)	7.0	%	-	9.0	%	7.0	%	-	8.0	%

Income Taxes
Effective Rate	15	%	-	20	%	16	%	-	21	%
Current Tax (Benefit) / Expense ($MM)	(15)		-	25		(120)		-	(80)

*Pricing - (Refer to Benchmark Commodity Pricing* in text)**
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI	(2.30)		-	(0.30)		(2.05)		-	(0.05)
Trinidad - above (below) WTI	(11.00)		-	(9.00)		(9.50)		-	(7.50)
Other International - above (below) WTI	(18.75)		-	(12.75)		2.00		-	7.00
Natural Gas Liquids
Realizations as % of WTI	29	%	-	41	%	30	%	-	36	%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub	(0.70)		-	(0.30)		(0.80)		-	(0.20)
Realizations
Trinidad	2.10		-	2.70		2.30		-	3.00
Other International	4.00		-	4.50		3.85		-	4.85

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

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SOURCE EOG Resources, Inc.

FAQ

What was EOG Resources' net loss for the second quarter of 2020?

EOG Resources reported a net loss of $909 million, or $1.57 per share, for the second quarter of 2020.

How much free cash flow did EOG Resources generate in Q2 2020?

EOG Resources generated positive free cash flow of $194 million in the second quarter of 2020.

What were the production volume changes for EOG Resources in Q2 2020?

EOG's total crude oil volumes were 331,100 barrels per day, 27% lower than in Q2 2019.

What significant discovery did EOG Resources announce in Trinidad?

EOG announced a significant discovery of 500 billion cubic feet of net natural gas resource potential in Trinidad.

EOG Resources Reports Second Quarter 2020 Results

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EOG Resources Reports Second Quarter 2020 Results

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What was EOG Resources' net loss for the second quarter of 2020?

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