EOG Resources Announces Outstanding Third Quarter 2018 Results

INVESTORS

News Detail |

HOUSTON, Nov. 1, 2018 /PRNewswire/ --

Exceeds High End of Oil and NGL Production Targets
Generates Significant Free Cash Flow
Achieves Improved Well Performance and Lower Costs in Delaware Basin
Secures 2019 Services at Competitive Prices and Raises 2018 Capex Guidance Range to $5.8-$6.0 Billion
Targets Further Well Cost Reductions in 2019

EOG Resources, Inc. (EOG) today reported third quarter 2018 net income of $1.2 billion, or $2.05 per share. This compares to third quarter 2017 net income of $101 million, or $0.17 per share. Net cash from operating activities in the third quarter 2018 was $2.2 billion.

Adjusted non-GAAP net income for the third quarter 2018 was $1.0 billion, or $1.75 per share, compared to adjusted non-GAAP net income of $111 million, or $0.19 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 Review
EOG set a company record and exceeded the high end of its target range for crude oil volumes in the third quarter 2018 by producing 415,000 barrels of oil per day (Bopd), an increase of 27 percent compared to the same prior year period. Natural gas liquids (NGL) production increased 46 percent while natural gas volumes grew 13 percent, contributing to total company production growth of 25 percent.

Per-unit operating expenses declined during the third quarter 2018 compared to the same prior year period. General and administrative expenses fell 20 percent, transportation costs declined 15 percent and depreciation, depletion and amortization expenses fell 13 percent, all on a per-unit basis.

EOG generated $2.3 billion of discretionary cash flow in the third quarter 2018. After considering exploration and development expenditures of $1.7 billion and dividend payments of $107 million, EOG produced free cash flow during the third quarter of $503 million. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

"EOG delivered a compelling combination of production growth, high returns and free cash flow in the third quarter 2018 due to disciplined capital allocation. These results demonstrate the value of EOG's sustainable business model," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is making significant progress lowering costs and improving well performance. Our culture of innovation, experimentation and entrepreneurship combined with our ability to capture and quickly analyze real-time data and make rapid changes in the field are resulting in significant performance improvements company-wide."

Updated 2018 Outlook
EOG has raised its target for full-year 2018 crude oil production growth to 19 percent. To maintain operational continuity into 2019, the company elected to retain high performing service providers for the remainder of 2018. Approximately 65 percent of its anticipated 2019 services have been secured at competitive pricing. As a result, EOG increased its 2018 exploration and development expenditure forecast to $5.8 to $6.0 billion, excluding acquisitions and non-cash transactions. The company is on track to reduce total well costs by five percent in 2018, and targets further well cost reductions in 2019. EOG now expects to complete approximately 720 net wells in 2018, an increase of 20 net wells from its prior forecast.

"We are positioning EOG to carry the operating efficiencies gained this year into 2019. We secured a significant proportion of our service costs, which along with disciplined execution will help further reduce well costs and improve returns," Thomas continued. "With a deep inventory of premium drilling locations across multiple plays, EOG will continue to allocate capital to the highest return areas while maintaining a disciplined operating pace. EOG is well positioned to continue delivering its unique combination of high returns, disciplined growth and strong free cash flow for years to come."

Operating Highlights
EOG's South Texas Eagle Ford remained the most active area of the company in the third quarter 2018. EOG now expects to complete 290 net wells in 2018, an addition of 20 net wells from the prior forecast. EOG also continued to delineate the South Texas Austin Chalk, completing 14 wells in the third quarter.

In the Delaware Basin, EOG made significant progress on well cost reductions and optimizing targeting and development patterns. The company increased the number of wells developed in a single package and drilled longer laterals. Packages of four wells or more accounted for 87 percent of the wells brought on line in the third quarter. EOG also made additional progress towards its cost reduction goals. Drilling speeds and the pace of completion operations increased markedly during the quarter. In addition, the company now supplies nearly all of its Delaware Basin sand from local sources and has further increased its use of low-cost recycled water.

EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window. EOG is testing spacing patterns and various targets across the play. The company completed 11 wells in the third quarter. EOG completed a package of four wells spaced 660 feet apart late in the second quarter. The Ted 2326 #1H-#4H were completed with an average treated lateral length of 10,000 feet per well and average 30-day initial production rates per well of 800 barrels of oil equivalent per day, or 660 Bopd, 90 barrels per day of NGLs and 0.3 million cubic feet per day of natural gas. These low-decline wells support our initial spacing assessment of 660 feet. EOG is also making significant progress reducing well costs in this new play. Recent wells have been brought to production at costs at or below the company's $7.8 million target.

EOG continued development of its premium plays across the Rocky Mountain region. The company brought 20 wells on line in the Powder River Basin during the third quarter 2018, including 13 wells from the Turner formation. In the Wyoming DJ Basin, EOG began production from 25 wells in the third quarter 2018. EOG completed 19 wells in the Williston Basin during the third quarter as part of its seasonal development program.

Financial Review
At September 30, 2018, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 26 percent. Considering cash on the balance sheet at the end of the third quarter, EOG's net debt was $5.2 billion for a net debt-to-total capitalization ratio of 22 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG reached an agreement to divest all of its U.K. operations. Closing is anticipated in the fourth quarter 2018.

During the third quarter ended September 30, 2018, EOG entered into additional crude oil derivative contracts. A comprehensive summary of EOG's crude oil and natural gas derivative contracts is provided in the attached tables.

Third Quarter 2018 Results Webcast
Friday, November 2, 2018, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG 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, the United Kingdom and China. To learn more visit www.eogresources.com.

Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404

Media and Investor Contact
Kimberly Ehmer 713-571-4676

This press release includes 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, 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, reduce or otherwise control operating and capital costs, generate income or cash flows, pay down 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, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These 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 the measure and estimates presented or referenced herein. 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 economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
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;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, 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; 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 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 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 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;
political conditions and developments around the world (such as 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;
physical, electronic and cyber security breaches; and
the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, 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 and 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 estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves 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, 2017, 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.

EOG RESOURCES, INC.
Financial Report
(Unaudited; in millions, except per share data)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018			2017

Operating Revenues and Other	$	4,781.6		$	2,644.8	$	12,700.9		$	7,867.9
Net Income	$	1,191.0		$	100.5	$	2,526.3		$	152.1
Net Income Per Share
Basic	$	2.06		$	0.17	$	4.38		$	0.26
Diluted	$	2.05		$	0.17	$	4.35		$	0.26
Average Number of Common Shares
Basic		577.3			574.8		576.4			574.4
Diluted		581.6			578.7		580.4			578.5


Summary Income Statements
(Unaudited; in thousands, except per share data)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018			2017
Operating Revenues and Other
Crude Oil and Condensate	$	2,655,278		$	1,451,410	$	7,134,114		$	4,326,925
Natural Gas Liquids		353,704			180,038		861,473			480,389
Natural Gas		311,713			220,402		912,324			675,012
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		(52,081)			(6,606)		(297,735)			64,860
Gathering, Processing and Marketing		1,360,992			784,368		3,899,250			2,289,702
Gains (Losses) on Asset Dispositions, Net		115,944			(8,202)		94,658			(33,876)
Other, Net		36,074			23,434		96,779			64,869
Total		4,781,624			2,644,844		12,700,863			7,867,881
Operating Expenses
Lease and Well		321,568			251,943		936,236			762,906
Transportation Costs		196,027			183,565		550,781			548,635
Gathering and Processing Costs		114,063			32,590		324,577			105,480
Exploration Costs		32,823			30,796		115,137			122,401
Dry Hole Costs		358			50		5,260			77
Impairments		44,617			53,677		160,934			325,798
Marketing Costs		1,326,974			793,536		3,853,827			2,320,671
Depreciation, Depletion and Amortization		918,180			846,222		2,515,445			2,527,642
General and Administrative		111,284			111,717		310,065			317,462
Taxes Other Than Income		209,043			125,912		582,395			386,319
Total		3,274,937			2,430,008		9,354,657			7,417,391

Operating Income		1,506,687			214,836		3,346,206			450,490

Other Income (Expense), Net		3,308			226		(4,516)			8,349

Income Before Interest Expense and Income Taxes		1,509,995			215,062		3,341,690			458,839

Interest Expense, Net		63,632			69,082		189,032			211,010

Income Before Income Taxes		1,446,363			145,980		3,152,658			247,829

Income Tax Provision		255,411			45,439		626,386			95,718

Net Income	$	1,190,952		$	100,541	$	2,526,272		$	152,111

Dividends Declared per Common Share	$	0.2200		$	0.1675	$	0.5900		$	0.5025

EOG RESOURCES, INC.
Operating Highlights
(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018			2017		2018			2017
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States		409.2			327.1		382.9			324.3
Trinidad		0.8			0.8		0.8			0.8
Other International ^(B)		5.0			-		4.1			1.0
Total		415.0			327.9		387.8			326.1

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$	69.53		$	48.06	$	67.35		$	48.61
Trinidad		61.71			39.42		58.91			40.24
Other International ^(B)		72.81			-		71.83			51.55
Composite		69.55			48.11		67.38			48.60

Natural Gas Liquids Volumes (MBbld) ^(A)
United States		127.8			87.4		113.9			84.3
Other International ^(B)		-			-		-			-
Total		127.8			87.4		113.9			84.3

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$	30.09		$	22.38	$	27.71		$	20.87
Other International ^(B)		-			-		-			-
Composite		30.09			22.38		27.71			20.87

Natural Gas Volumes (MMcfd) ^(A)
United States		948			748		905			744
Trinidad		260			323		278			317
Other International ^(B)		28			25		31			22
Total		1,236			1,096		1,214			1,083

Average Natural Gas Prices ($/Mcf) ^(C)
United States	$	2.67		$	2.20	$	2.66		$	2.22
Trinidad		2.88			2.04		2.91			2.33
Other International ^(B)		3.83			3.74		4.10			3.72
Composite		2.74	^(D)		2.19		2.75	^(D)		2.28

Crude Oil Equivalent Volumes (MBoed) ^(E)
United States		695.0			539.2		647.6			532.6
Trinidad		44.1			54.6		47.2			53.6
Other International ^(B)		9.7			4.3		9.2			4.8
Total		748.8			598.1		704.0			591.0

Total MMBoe ^(E)		68.9			55.0		192.2			161.3


(A) Thousand barrels per day or million cubic feet per day, as applicable.
(B) Other International includes EOG's United Kingdom, 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 quarterly period ended September 30, 2018).
(D) Includes positive revenue adjustments of $0.49 per Mcf and $0.43 per Mcf for the three and nine months ended September 30, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09). (see Note 1 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Revenues.
(E) 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.

EOG RESOURCES, INC.
Summary Balance Sheets
(Unaudited; in thousands, except share data)

	September 30,		December 31,
	2018		2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,274,132	$	834,228
Accounts Receivable, Net		2,151,247		1,597,494
Inventories		766,964		483,865
Assets from Price Risk Management Activities		1,569		7,699
Income Taxes Receivable		320,938		113,357
Other		302,242		242,465
Total		4,817,092		3,279,108

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		56,799,237		52,555,741
Other Property, Plant and Equipment		4,191,958		3,960,759
Total Property, Plant and Equipment		60,991,195		56,516,500
Less: Accumulated Depreciation, Depletion and Amortization		(33,043,454)		(30,851,463)
Total Property, Plant and Equipment, Net		27,947,741		25,665,037
Deferred Income Taxes		16,880		17,506
Other Assets		856,023		871,427
Total Assets	$	33,637,736	$	29,833,078

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,435,773	$	1,847,131
Accrued Taxes Payable		249,234		148,874
Dividends Payable		126,829		96,410
Liabilities from Price Risk Management Activities		132,618		50,429
Current Portion of Long-Term Debt		1,262,874		356,235
Other		217,819		226,463
Total		4,425,147		2,725,542


Long-Term Debt		5,171,949		6,030,836
Other Liabilities		1,302,249		1,275,213
Deferred Income Taxes		4,199,921		3,518,214
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 580,308,937 Shares Issued at September 30, 2018 and 578,827,768 Shares Issued at December 31, 2017		205,803		205,788
Additional Paid in Capital		5,626,259		5,536,547
Accumulated Other Comprehensive Loss		(19,458)		(19,297)
Retained Earnings		12,778,104		10,593,533
Common Stock Held in Treasury, 478,042 Shares at September 30, 2018 and 350,961 Shares at December 31, 2017		(52,238)		(33,298)
Total Stockholders' Equity		18,538,470		16,283,273
Total Liabilities and Stockholders' Equity	$	33,637,736	$	29,833,078

EOG RESOURCES, INC.
Summary Statements of Cash Flows
(Unaudited; in thousands)

	Nine Months Ended
	September 30,
	2018		2017
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	2,526,272	$	152,111
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		2,515,445		2,527,642
Impairments		160,934		325,798
Stock-Based Compensation Expenses		116,290		101,537
Deferred Income Taxes		681,702		114,850
(Gains) Losses on Asset Dispositions, Net		(94,658)		33,876
Other, Net		15,314		(4,514)
Dry Hole Costs		5,260		77
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		297,735		(64,860)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(180,228)		4,730
Other, Net		1,652		270
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(553,529)		(25,445)
Inventories		(286,817)		(17,674)
Accounts Payable		537,525		112,894
Accrued Taxes Payable		(36,891)		(49,967)
Other Assets		(103,334)		(83,940)
Other Liabilities		(14,776)		(69,224)
Changes in Components of Working Capital Associated with Investing and Financing Activities		95,484		(120,373)
Net Cash Provided by Operating Activities		5,683,380		2,937,788

Investing Cash Flows
Additions to Oil and Gas Properties		(4,571,932)		(2,927,988)
Additions to Other Property, Plant and Equipment		(202,384)		(139,558)
Proceeds from Sales of Assets		11,582		191,593
Other Investing Activities		(19,993)		-
Changes in Components of Working Capital Associated with Investing Activities		(95,541)		120,469
Net Cash Used in Investing Activities		(4,878,268)		(2,755,484)

Financing Cash Flows
Long-Term Debt Repayments		-		(600,000)
Dividends Paid		(311,075)		(289,261)
Treasury Stock Purchased		(58,558)		(50,374)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		12,098		11,174
Repayment of Capital Lease Obligation		(5,052)		(4,897)
Changes in Components of Working Capital Associated with Financing Activities		57		(96)
Net Cash Used in Financing Activities		(362,530)		(933,454)

Effect of Exchange Rate Changes on Cash		(2,678)		(2,607)

Increase (Decrease) in Cash and Cash Equivalents		439,904		(753,757)
Cash and Cash Equivalents at Beginning of Period		834,228		1,599,895
Cash and Cash Equivalents at End of Period	$	1,274,132	$	846,138

EOG RESOURCES, INC.
Third Quarter 2018 Well Results by Play
(Unaudited)

	Wells Online			Initial Gross 30-Day Average Production Rate
	Gross	Net	Lateral Length (ft)	Crude Oil and Condensate (Bbld) ^(A)	Natural Gas Liquids (Bbld) ^(A)	Natural Gas (MMcfd) ^(A)	Crude Oil Equivalent (Boed) ^(B)
Delaware Basin
Wolfcamp	61	58	7,100	1,655	505	2.9	2,640
Bone Spring	4	4	5,200	1,135	270	1.6	1,675
Leonard	6	5	4,500	995	325	1.9	1,645

South Texas Eagle Ford	90	83	7,300	1,235	155	0.9	1,540

South Texas Austin Chalk	14	10	5,000	1,815	340	2.0	2,485

Powder River Basin Turner	13	11	7,500	795	320	3.7	1,730

DJ Basin Codell	25	19	10,100	915	105	0.4	1,090

Williston Basin Bakken/Three Forks	19	12	9,400	1,135	130	0.6	1,370

Anadarko Basin Woodford Oil Window	11	9	8,500	720	120	0.4	915

(A) Barrels per day or million cubic feet per day, as applicable.

(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.

EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP)
To Net Income (GAAP)
(Unaudited; in thousands, except per share data)


The following chart adjusts the three-month and nine-month periods ended September 30, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	Three Months Ended				Three Months Ended
	September 30, 2018				September 30, 2017

		Income		Diluted		Income		Diluted
	Before	Tax	After	Earnings	Before	Tax	After	Earnings
	Tax	Impact	Tax	per Share	Tax	Impact	Tax	per Share
Reported Net Income (GAAP)	$1,446,363	$(255,411)	$1,190,952	$ 2.05	$145,980	$ (45,439)	$100,541	$ 0.17
Adjustments:
Losses on Mark-to-Market Commodity Derivative Contracts	52,081	(11,472)	40,609	0.07	6,606	(2,368)	4,238	0.01
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(91,894)	20,241	(71,653)	(0.12)	2,139	(767)	1,372	-
Add: Net (Gains) Losses on Asset Dispositions	(115,944)	28,934	(87,010)	(0.15)	8,202	(3,068)	5,134	0.01
Less: Tax Reform Impact	-	(57,127)	(57,127)	(0.10)	-	-	-	-
Adjustments to Net Income	(155,757)	(19,424)	(175,181)	(0.30)	16,947	(6,203)	10,744	0.02

Adjusted Net Income (Non-GAAP)	$1,290,606	$(274,835)	$1,015,771	$ 1.75	$162,927	$ (51,642)	$111,285	$ 0.19

Average Number of Common Shares (GAAP)
Basic				577,254				574,783
Diluted				581,559				578,736



	Nine Months Ended				Nine Months Ended
	September 30, 2018				September 30, 2017

		Income		Diluted		Income		Diluted
	Before	Tax	After	Earnings	Before	Tax	After	Earnings
	Tax	Impact	Tax	per Share	Tax	Impact	Tax	per Share
Reported Net Income (GAAP)	$3,152,658	$(626,386)	$2,526,272	$ 4.35	$247,829	$ (95,718)	$152,111	$ 0.26
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts	297,735	(65,582)	232,153	0.40	(64,860)	23,249	(41,611)	(0.07)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(180,228)	39,699	(140,529)	(0.24)	4,730	(1,695)	3,035	0.01
Add: Net (Gains) Losses on Asset Dispositions	(94,658)	24,235	(70,423)	(0.12)	33,876	(11,955)	21,921	0.04
Add: Impairments	20,876	(4,598)	16,278	0.03	161,148	(57,764)	103,384	0.18
Add: Legal Settlement - Early Lease Termination	-	-	-	-	10,202	(3,657)	6,545	0.01
Add: Joint Venture Transaction Costs	-	-	-	-	3,056	(1,095)	1,961	-
Less: Tax Reform Impact	-	(63,651)	(63,651)	(0.11)	-	-	-	-
Adjustments to Net Income	43,725	(69,897)	(26,172)	(0.04)	148,152	(52,917)	95,235	0.17

Adjusted Net Income (Non-GAAP)	$3,196,383	$(696,283)	$2,500,100	$ 4.31	$395,981	$(148,635)	$247,346	$ 0.43

Average Number of Common Shares (GAAP)
Basic				576,431				574,370
Diluted				580,442				578,453

EOG RESOURCES, INC.
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)
To Net Cash Provided By Operating Activities (GAAP)
(Unaudited; in thousands)

Calculation of Free Cash Flow (Non-GAAP)
(Unaudited; in thousands)

The following chart reconciles the three-month and nine-month periods ended September 30, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable (Payable), Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months and nine months ended September 30, 2018. EOG management uses this information for comparative purposes within the industry.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017

Net Cash Provided by Operating Activities (GAAP)	$	2,189,597	$	961,363	$	5,683,380	$	2,937,788

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		27,032		26,132		96,716		106,268
Other Non-Current Income Taxes - Net Receivable (Payable)		(129,941)		-		62,421		-
Changes in Components of Working Capital and Other Assets
and Liabilities
Accounts Receivable		243,778		129,231		553,529		25,445
Inventories		94,598		11,545		286,817		17,674
Accounts Payable		(81,548)		(36,190)		(537,525)		(112,894)
Accrued Taxes Payable		59,426		10,843		36,891		49,967
Other Assets		40,491		22,851		103,334		83,940
Other Liabilities		(38,392)		2,355		14,776		69,224
Changes in Components of Working Capital Associated with
Investing and Financing Activities		(122,763)		41,235		(95,484)		120,373

Discretionary Cash Flow (Non-GAAP)	$	2,282,278	$	1,169,365	$	6,204,855	$	3,297,785

Discretionary Cash Flow (Non-GAAP) - Percentage Increase		95%				88%


Discretionary Cash Flow (Non-GAAP)	$	2,282,278			$	6,204,855
Less:
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)^(a)		(1,671,922)				(4,869,951)
Dividends Paid (GAAP)		(107,465)				(311,075)
Free Cash Flow (Non-GAAP)	$	502,891			$	1,023,829


(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and nine months ended September 30, 2018:

Total Expenditures (GAAP)	$	1,828,348			$	5,201,921
Less:
Asset Retirement Costs		(10,834)				(41,789)
Non-Cash Expenditures of Other Property, Plant and Equipment		(1,257)				(48,937)
Non-Cash Acquisition Costs of Unproved Properties		(101,821)				(161,823)
Acquisition Costs of Proved Properties		(42,514)				(79,421)
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)	$	1,671,922			$	4,869,951

EOG RESOURCES, INC.
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net,
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs,
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX)
(Non-GAAP) to Net Income (GAAP)
(Unaudited; in thousands)

The following chart adjusts the three-month and nine-month periods ended September 30, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017

Net Income (GAAP)	$	1,190,952	$	100,541	$	2,526,272	$	152,111

Adjustments:
Interest Expense, Net		63,632		69,082		189,032		211,010
Income Tax Provision		255,411		45,439		626,386		95,718
Depreciation, Depletion and Amortization		918,180		846,222		2,515,445		2,527,642
Exploration Costs		32,823		30,796		115,137		122,401
Dry Hole Costs		358		50		5,260		77
Impairments		44,617		53,677		160,934		325,798
EBITDAX (Non-GAAP)		2,505,973		1,145,807		6,138,466		3,434,757
Total (Gains) Losses on MTM Commodity Derivative Contracts		52,081		6,606		297,735		(64,860)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(91,894)		2,139		(180,228)		4,730
(Gains) Losses on Asset Dispositions, Net		(115,944)		8,202		(94,658)		33,876

Adjusted EBITDAX (Non-GAAP)	$	2,350,216	$	1,162,754	$	6,161,315	$	3,408,503

Adjusted EBITDAX (Non-GAAP) - Percentage Increase		102%				81%

EOG RESOURCES, INC.
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total
Capitalization (Non-GAAP) as Used in the Calculation of
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
(Unaudited; in millions, except ratio data)

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

	At		At
	September 30,		December 31,
	2018		2017

Total Stockholders' Equity - (a)	$	18,538	$	16,283

Current and Long-Term Debt (GAAP) - (b)		6,435		6,387
Less: Cash		(1,274)		(834)
Net Debt (Non-GAAP) - (c)		5,161		5,553

Total Capitalization (GAAP) - (a) + (b)	$	24,973	$	22,670

Total Capitalization (Non-GAAP) - (a) + (c)	$	23,699	$	21,836

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		26%		28%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		22%		25%

EOG RESOURCES, INC.
Crude Oil and Natural Gas Financial Commodity
Derivative Contracts

EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate 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 pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through October 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.


Midland Differential Basis Swap Contracts
					Weighted
					Average Price
				Volume	Differential
				(Bbld)	($/Bbl)
2018
January 1, 2018 through November 30, 2018 (closed)				15,000	$ 1.063
December 2018				15,000	1.063

2019
January 1, 2019 through December 31, 2019				20,000	$ 1.075


EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through October 26, 2018. 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.


Gulf Coast Differential Basis Swap Contracts
					Weighted
					Average Price
				Volume	Differential
				(Bbld)	($/Bbl)
2018
January 1, 2018 through September 30, 2018 (closed)				37,000	$ 3.818
October 1, 2018 through November 30, 2018 (closed)				52,000	3.911
December 2018				52,000	3.911

2019
January 1, 2019 through December 31, 2019				13,000	$ 5.572


Presented below is a comprehensive summary of EOG's crude oil price swap contracts through October 26, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl.


Crude Oil Price Swap Contracts
					Weighted
				Volume	Average Price
				(Bbld)	($/Bbl)
2018
January 1, 2018 through September 30, 2018 (closed)				134,000	$ 60.04
October 1, 2018 through December 31, 2018				134,000	60.04


Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.


Natural Gas Price Swap Contracts
					Weighted
				Volume	Average Price
				(MMBtud)	($/MMBtu)
2018
March 1, 2018 through October 31, 2018 (closed)				35,000	$ 3.00
November 2018				35,000	3.00


EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day 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 call option strike price.

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through October 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.


Natural Gas Option Contracts
		Call Options Sold		Put Options Purchased
			Weighted		Weighted
		Volume	Average Price	Volume	Average Price
		(MMBtud)	($/MMBtu)	(MMBtud)	($/MMBtu)
2018
March 1, 2018 through October 31, 2018 (closed)		120,000	$ 3.38	96,000	$ 2.94
November 2018		120,000	3.38	96,000	2.94


Definitions
Bbld	Barrels per day
$/Bbl	Dollars per barrel
MMBtud	Million British thermal units per day
$/MMBtu	Dollars per million British thermal units
NYMEX	U.S. New York Mercantile Exchange

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

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

EOG RESOURCES, INC.
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss)
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP),
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively
(Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

		2017			2016			2015			2014			2013
Return on Capital Employed (ROCE) (Non-GAAP)

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

Net Income (Loss) (GAAP) - (b)	$	2,583		$	(1,097)		$	(4,525)		$	2,915
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules)		(1,934)	(a)		204	(b)		4,559	(c)		(199)	(d)
Adjusted Net Income (Loss) (Non-GAAP) - (c)	$	649		$	(893)		$	34		$	2,716

Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d)	$	16,283		$	13,982		$	12,943		$	17,713		$	15,418
Less: Tax Reform Impact		(2,169)			-			-			-			-
Total Stockholders' Equity (Non-GAAP) - (e)	$	14,114		$	13,982		$	12,943		$	17,713		$	15,418

Average Total Stockholders' Equity (GAAP) * - (f)	$	15,133		$	13,463		$	15,328		$	16,566

Average Total Stockholders' Equity (Non-GAAP) * - (g)	$	14,048		$	13,463		$	15,328		$	16,566

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

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

Total Capitalization (Non-GAAP) - (e) + (i)	$	19,667		$	19,368		$	18,879		$	21,532		$	20,009

Average Total Capitalization (Non-GAAP) * - (j)	$	19,518		$	19,124		$	20,206		$	20,771

ROCE (GAAP Net Income) - [(a) + (b)] / (j)		14.1%			-4.8%			-21.6%			14.7%

ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j)		4.2%			-3.7%			0.9%			13.7%

Return on Equity (ROE)

ROE (GAAP) (GAAP Net Income) - (b) / (f)		17.1%			-8.1%			-29.5%			17.6%

ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g)		4.6%			-6.6%			0.2%			16.4%

* Average for the current and immediately preceding year





Adjustments to Net Income (Loss) (GAAP)


(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017:
		Year Ended December 31, 2017
		Before			Income Tax			After
		Tax			Impact			Tax
Adjustments:
Add: Mark-to-Market Commodity Derivative Contracts Impact	$	(12)		$	4		$	(8)
Add: Impairments of Certain Assets		261			(93)			168
Add: Net Losses on Asset Dispositions		99			(35)			64
Add: Legal Settlement - Early Lease Termination		10			(4)			6
Add: Joint Venture Transaction Costs		3			(1)			2
Add: Joint Interest Billings Deemed Uncollectible		5			(2)			3
Less: Tax Reform Impact		-			(2,169)			(2,169)
Total	$	366		$	(2,300)		$	(1,934)

(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016:
		Year Ended December 31, 2016
		Before			Income Tax			After
		Tax			Impact			Tax
Adjustments:
Add: Mark-to-Market Commodity Derivative Contracts Impact	$	77		$	(28)		$	49
Add: Impairments of Certain Assets		321			(113)			208
Less: Net Gains on Asset Dispositions		(206)			62			(144)
Add: Trinidad Tax Settlement		-			43			43
Add: Voluntary Retirement Expense		42			(15)			27
Add: Acquisition - State Apportionment Change		-			16			16
Add: Acquisition Costs		5			-			5
Total	$	239		$	(35)		$	204

(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015:
		Year Ended December 31, 2015
		Before			Income Tax			After
		Tax			Impact			Tax
Adjustments:
Add: Mark-to-Market Commodity Derivative Contracts Impact	$	668		$	(238)		$	430
Add: Impairments of Certain Assets		6,308			(2,183)			4,125
Less: Texas Margin Tax Rate Reduction		-			(20)			(20)
Add: Legal Settlement - Early Leasehold Termination		19			(6)			13
Add: Severance Costs		9			(3)			6
Add: Net Losses on Asset Dispositions		9			(4)			5
Total	$	7,013		$	(2,454)		$	4,559

(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014:
		Year Ended December 31, 2014
		Before			Income Tax			After
		Tax			Impact			Tax
Adjustments:
Less: Mark-to-Market Commodity Derivative Contracts Impact	$	(800)		$	285		$	(515)
Add: Impairments of Certain Assets		824			(271)			553
Less: Net Gains on Asset Dispositions		(508)			21			(487)
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years		-			250			250
Total	$	(484)		$	285		$	(199)

EOG RESOURCES, INC.
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively
(Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

		2013		2012		2011		2010		2009		2008
Return on Capital Employed (ROCE) (Non-GAAP)
(Calculated Using GAAP Net Income)

Net Interest Expense (GAAP)	$	235	$	214	$	210	$	130	$	101	$	52
Tax Benefit Imputed (based on 35%)		(82)		(75)		(74)		(46)		(35)		(18)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	153	$	139	$	136	$	84	$	66	$	34

Net Income (Loss) (GAAP) - (b)	$	2,197	$	570	$	1,091	$	161	$	547	$	2,437

Total Stockholders' Equity (GAAP) - (d)	$	15,418	$	13,285	$	12,641	$	10,232	$	9,998	$	9,015

Average Total Stockholders' Equity (GAAP) * - (f)	$	14,352	$	12,963	$	11,437	$	10,115	$	9,507	$	8,003

Current and Long-Term Debt (GAAP) - (h)	$	5,909	$	6,312	$	5,009	$	5,223	$	2,797	$	1,897
Less: Cash		(1,318)		(876)		(616)		(789)		(686)		(331)
Net Debt (Non-GAAP) - (i)	$	4,591	$	5,436	$	4,393	$	4,434	$	2,111	$	1,566

Total Capitalization (GAAP) - (d) + (h)	$	21,327	$	19,597	$	17,650	$	15,455	$	12,795	$	10,912

Total Capitalization (Non-GAAP) - (d) + (i)	$	20,009	$	18,721	$	17,034	$	14,666	$	12,109	$	10,581

Average Total Capitalization (Non-GAAP) * - (j)	$	19,365	$	17,878	$	15,850	$	13,388	$	11,345	$	9,351

ROCE (GAAP Net Income) - [(a) + (b)] / (j)		12.1%		4.0%		7.7%		1.8%		5.4%		26.4%


Return on Equity (ROE) (GAAP)

ROE (GAAP Net Income) - (b) / (f)		15.3%		4.4%		9.5%		1.6%		5.8%		30.5%


* Average for the current and immediately preceding year


EOG RESOURCES, INC.
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively
(Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

		2007		2006		2005		2004		2003		2002
Return on Capital Employed (ROCE) (Non-GAAP)
(Calculated Using GAAP Net Income)

Net Interest Expense (GAAP)	$	47	$	43	$	63	$	63	$	59	$	60
Tax Benefit Imputed (based on 35%)		(16)		(15)		(22)		(22)		(21)		(21)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	31	$	28	$	41	$	41	$	38	$	39

Net Income (Loss) (GAAP) - (b)	$	1,090	$	1,300	$	1,260	$	625	$	430	$	87

Total Stockholders' Equity (GAAP)- (d)	$	6,990	$	5,600	$	4,316	$	2,945	$	2,223	$	1,672

Average Total Stockholders' Equity (GAAP) * - (f)	$	6,295	$	4,958	$	3,631	$	2,584	$	1,948	$	1,658

Current and Long-Term Debt (GAAP) - (h)	$	1,185	$	733	$	985	$	1,078	$	1,109	$	1,145
Less: Cash		(54)		(218)		(644)		(21)		(4)		(10)
Net Debt (Non-GAAP) - (i)	$	1,131	$	515	$	341	$	1,057	$	1,105	$	1,135

Total Capitalization (GAAP) - (d) + (h)	$	8,175	$	6,333	$	5,301	$	4,023	$	3,332	$	2,817

Total Capitalization (Non-GAAP) - (d) + (i)	$	8,121	$	6,115	$	4,657	$	4,002	$	3,328	$	2,807

Average Total Capitalization (Non-GAAP) * - (j)	$	7,118	$	5,386	$	4,330	$	3,665	$	3,068	$	2,652

ROCE (GAAP Net Income) - [(a) + (b)] / (j)		15.7%		24.7%		30.0%		18.2%		15.3%		4.8%


Return on Equity (ROE) (GAAP)

ROE (GAAP Net Income) - (b) / (f)		17.3%		26.2%		34.7%		24.2%		22.1%		5.2%


* Average for the current and immediately preceding year


EOG RESOURCES, INC.
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively
(Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

		2001		2000		1999		1998		1997
Return on Capital Employed (ROCE) (Non-GAAP)
(Calculated Using GAAP Net Income)

Net Interest Expense (GAAP)	$	45	$	61	$	62	$	49
Tax Benefit Imputed (based on 35%)		(16)		(21)		(22)		(17)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	29	$	40	$	40	$	32

Net Income (Loss) (GAAP) - (b)	$	399	$	397	$	569	$	56

Total Stockholders' Equity (GAAP)- (d)	$	1,643	$	1,381	$	1,130	$	1,280	$	1,281

Average Total Stockholders' Equity (GAAP) * - (f)	$	1,512	$	1,256	$	1,205	$	1,281

Current and Long-Term Debt (GAAP) - (h)	$	856	$	859	$	990	$	1,143	$	745
Less: Cash		(3)		(20)		(25)		(6)		(9)
Net Debt (Non-GAAP) - (i)	$	853	$	839	$	965	$	1,137	$	736

Total Capitalization (GAAP) - (d) + (h)	$	2,499	$	2,240	$	2,120	$	2,423	$	2,026

Total Capitalization (Non-GAAP) - (d) + (i)	$	2,496	$	2,220	$	2,095	$	2,417	$	2,017

Average Total Capitalization (Non-GAAP) * - (j)	$	2,358	$	2,158	$	2,256	$	2,217

ROCE (GAAP Net Income) - [(a) + (b)] / (j)		18.2%		20.2%		27.0%		4.0%


Return on Equity (ROE) (GAAP)

ROE (GAAP Net Income) - (b) / (f)		26.4%		31.6%		47.2%		4.4%


* Average for the current and immediately preceding year

EOG RESOURCES, INC.
Cash Operating Expenses per Barrel of Oil Equivalent (Boe)
(Unaudited; in thousands, except per Boe amounts)


	Year-To-Date (YTD)	Year Ended
	September 30,	December 31,
	2018	2017		2016		2015		2014

Cash Operating Expenses (GAAP)*
Lease and Well	$ 936,236	$ 1,044,847		$ 927,452		$ 1,182,282		$ 1,416,413
Transportation Costs	550,781	740,352		764,106		849,319		972,176
General and Administrative	310,065	434,467		394,815		366,594		402,010
Cash Operating Expenses	1,797,082	2,219,666		2,086,373		2,398,195		2,790,599
Less: Legal Settlement - Early Leasehold Termination	-	(10,202)		-		(19,355)		-
Less: Voluntary Retirement Expense	-	-		(42,054)		-		-
Less: Acquisition Costs - Yates Transaction	-	-		(5,100)		-		-
Less: Joint Venture Transaction Costs	-	(3,056)		-		-		-
Less: Joint Interest Billings Deemed Uncollectible	-	(4,528)		-		-		-
Adjusted Cash Operating Expenses (Non-GAAP) - (a)	$ 1,797,082	$ 2,201,880		$ 2,039,219		$ 2,378,840		$ 2,790,599

Volume - Thousand Barrels of Oil Equivalent - (b)	192,182	222,251		204,929		208,862		217,073

Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b)	$ 9.35	$ 9.91	(c)	$ 9.95	(d)	$ 11.39	(e)	$ 12.86	(f)

Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - Percentage Decrease
YTD 2017 compared to YTD 2016 - [(c) - (d)] / (d)	0%
YTD 2017 compared to YTD 2015 - [(c) - (e)] / (e)	-13%
YTD 2017 compared to YTD 2014 - [(c) - (f)] / (f)	-23%

* Includes stock compensation expense and other non-cash items.

EOG RESOURCES, INC.
Cost per Barrel of Oil Equivalent (Boe)
(Unaudited; in thousands, except per Boe amounts)


	Year Ended
	December 31,
	2014	2015	2016	2017

Volume - Thousand Barrels of Oil Equivalent	217,073	208,862	204,929	222,251

Total Wellhead Revenues	$ 12,592,917	$ 6,403,258	$ 5,496,743	$ 7,907,891

Composite Average Wellhead Revenue per Boe	$ 58.01	$ 30.66	$ 26.82	$ 35.58

Operating Costs
Lease and Well	$ 1,416,413	$ 1,182,282	$ 927,452	$ 1,044,847
Transportation Costs	972,176	849,319	764,106	740,352
Gathering and Processing Costs	145,800	146,156	122,901	148,775

General and Administrative	402,010	366,594	394,815	434,467
Less: Voluntary Retirement Expense	-	-	(42,054)	-
Less: Acquisition Costs	-	-	(5,100)	-
Less: Legal Settlement - Early Leasehold Termination	-	(19,355)	-	(10,202)
Less: Joint Venture Transaction Costs	-	-	-	(3,056)
Less: Joint Interest Billings Deemed Uncollectible	-	-	-	(4,528)
General and Administrative (Non-GAAP)	402,010	347,239	347,661	416,681

Taxes Other Than Income	757,564	421,744	349,710	544,662
Interest Expense, Net	201,458	237,393	281,681	274,372
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Exploration Costs)	$ 3,895,421	$ 3,184,133	$ 2,793,511	$ 3,169,689

Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Exploration Costs)	$ 17.95	$ 15.25	$ 13.64	$ 14.25

Composite Average Margin per Boe (Non- GAAP) (excluding DD&A and Exploration Costs)	$ 40.06	$ 15.41	$ 13.18	$ 21.33

Depreciation, Depletion and Amortization (DD&A)	3,997,041	3,313,644	3,553,417	3,409,387
Total Operating Cost (Non-GAAP) (excluding Exploration Costs)	$ 7,892,462	$ 6,497,777	$ 6,346,928	$ 6,579,076

Total Operating Cost per Boe (Non-GAAP) (excluding Exploration Costs)	$ 36.38	$ 31.11	$ 30.98	$ 29.59

Composite Average Margin per Boe (Non-GAAP) (excluding Exploration Costs)	$ 21.63	$ (0.45)	$ (4.16)	$ 5.99

Total Exploration Costs	976,453	6,777,786	755,877	629,191
Less: Impairments	(824,312)	(6,307,593)	(320,617)	(261,452)
Total Exploration Costs (Non-GAAP)	152,141	470,193	435,260	367,739

Total Operating Cost (Non-GAAP) (including Exploration Costs)	$ 8,044,603	$ 6,967,970	$ 6,782,188	$ 6,946,815

Total Operating Cost per Boe (Non-GAAP) (including Exploration Costs)	$ 37.08	$ 33.36	$ 33.10	$ 31.24

Composite Average Margin per Boe (Non-GAAP) (including Exploration Costs)	$ 20.93	$ (2.70)	$ (6.28)	$ 4.34


EOG RESOURCES, INC.
Cost per Barrel of Oil Equivalent (Boe)
(Unaudited; in thousands, except per Boe amounts)


	Three Months Ended			Year-To-Date
	March 31,	June 30,	September 30,	September 30,
	2018	2018	2018	2018

Volume - Thousand Barrels of Oil Equivalent	59,394	63,898	68,890	192,182

Total Wellhead Revenues	$ 2,622,489	$ 2,964,727	$ 3,320,695	$ 8,907,911

Composite Average Wellhead Revenue per Boe	$ 44.15	$ 46.40	$ 48.20	$ 46.35

Operating Costs
Lease and Well	$ 300,064	$ 314,604	$ 321,568	$ 936,236
Transportation Costs	176,957	177,797	196,027	550,781
Gathering and Processing Costs	101,345	109,169	114,063	324,577
General and Administrative	94,698	104,083	111,284	310,065
Taxes Other Than Income	179,084	194,268	209,043	582,395
Interest Expense, Net	61,956	63,444	63,632	189,032
Total Cash Operating Cost (excluding DD&A and Exploration Costs)	$ 914,104	$ 963,365	$ 1,015,617	$ 2,893,086

Total Cash Operating Cost per Boe (excluding DD&A and Exploration Costs)	$ 15.39	$ 15.07	$ 14.75	$ 15.05

Composite Average Margin per Boe (excluding DD&A and Exploration Costs)	$ 28.76	$ 31.33	$ 33.45	$ 31.30

Depreciation, Depletion and Amortization (DD&A)	748,591	848,674	918,180	2,515,445
Total Operating Cost (excluding Exploration Costs)	$ 1,662,695	$ 1,812,039	$ 1,933,797	$ 5,408,531

Total Operating Cost per Boe (excluding Exploration Costs)	$ 27.99	$ 28.35	$ 28.08	$ 28.14

Composite Average Margin per Boe (excluding Exploration Costs)	$ 16.16	$ 18.05	$ 20.12	$ 18.21

Total Exploration Costs	99,445	104,088	77,798	281,331
Less: Impairments	(20,876)	-	-	(20,876)
Total Exploration Costs (Non-GAAP)	78,569	104,088	77,798	260,455

Total Operating Cost (Non-GAAP) (including Exploration Costs)	$ 1,741,264	$ 1,916,127	$ 2,011,595	$ 5,668,986

Total Operating Cost per Boe (Non-GAAP) (including Exploration Costs)	$ 29.31	$ 29.98	$ 29.21	$ 29.50

Composite Average Margin per Boe (Non-GAAP) (including Exploration Costs)	$ 14.84	$ 16.42	$ 18.99	$ 16.85

EOG RESOURCES, INC.
Fourth Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing

(a) Fourth Quarter and Full Year 2018 Forecast

The forecast items for the fourth quarter and full year 2018 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) 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
						(Unaudited)
		4Q 2018						Full Year 2018
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States		425.0	-		430.0			393.5	-		394.8
Trinidad		0.5	-		0.7			0.7	-		0.9
Other International		3.0	-		5.0			3.8	-		4.3
Total		428.5	-		435.7			398.0	-		400.0

Natural Gas Liquids Volumes (MBbld)
Total		115.0	-		125.0			114.1	-		116.7

Natural Gas Volumes (MMcfd)
United States		975	-		1,025			923	-		935
Trinidad		220	-		250			264	-		271
Other International		30	-		40			30	-		33
Total		1,225	-		1,315			1,217	-		1,239

Crude Oil Equivalent Volumes (MBoed)
United States		702.5	-		725.8			661.5	-		667.3
Trinidad		37.2	-		42.4			44.6	-		46.1
Other International		8.0	-		11.7			8.8	-		9.8
Total		747.7	-		779.9			714.9	-		723.2

						Estimated Ranges
						(Unaudited)
	4Q 2018							Full Year 2018
Operating Costs
Unit Costs ($/Boe)
Lease and Well	$	4.45	-	$	4.85		$	4.80	-	$	4.90
Transportation Costs	$	2.45	-	$	2.85		$	2.75	-	$	2.85
Depreciation, Depletion and Amortization	$	13.60	-	$	13.95		$	13.23	-	$	13.32

Expenses ($MM)
Exploration, Dry Hole and Impairment	$	105	-	$	125		$	365	-	$	385
General and Administrative	$	105	-	$	115		$	415	-	$	425
Gathering and Processing	$	110	-	$	130		$	435	-	$	455
Capitalized Interest	$	5	-	$	7		$	23	-	$	25
Net Interest	$	55	-	$	58		$	244	-	$	247

Taxes Other Than Income (% of Wellhead Revenue)		6.5%	-		6.8%			6.5%	-		6.7%

Income Taxes
Effective Rate		20%	-		25%			19%	-		24%
Current Tax (Benefit) / Expense ($MM)	$	(70)	-	$	(30)		$	(190)	-	$	(150)

Capital Expenditures (Excluding Acquisitions, $MM)
Exploration and Development, Excluding Facilities							$	4,900	-	$	5,000
Exploration and Development Facilities							$	600	-	$	650
Gathering, Processing and Other							$	300	-	$	350

Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI	$	0.00	-	$	2.00		$	0.50	-	$	1.05
Trinidad - above (below) WTI	$	(11.00)	-	$	(9.00)		$	(9.00)	-	$	(8.00)
Other International - above (below) WTI	$	0.00	-	$	7.00		$	3.80	-	$	5.60

Natural Gas Liquids
Realizations as % of WTI		38%	-		46%			41%	-		43%

Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub	$	(0.40)	-	$	0.00		$	(0.25)	-	$	(0.15)

Realizations
Trinidad	$	2.40	-	$	2.80		$	2.80	-	$	2.90
Other International	$	4.15	-	$	4.65		$	4.10	-	$	4.25

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.