eog 2q 2017

NYSE Stock Symbol: EOGCommon Dividend: $0.67Common Shares Outstanding: 577 Million

Internet Address:http://www.eogresources.com

2Q 2017Investor Relations Contacts

David J. Streit, Vice President IR/PR(713) 571-4902, [email protected]

Kimberly M. Ehmer, Director IR/PR(713) 571-4676, [email protected]

W. John Wagner, Engineer IR (713) 571-4404, [email protected]

Copyright; Assumption of Risk: Copyright 2017. This presentation and the contents of this presentation have been copyrighted by EOG Resources, Inc. (EOG). All rights reserved. Copying of the presentation is forbidden without the prior written consent of EOG. Information in this presentation is provided “as is” without warranty of any kind, either express or implied, including but not limited to the implied warranties of merchantability, fitness for a particular purpose and the timeliness of the information. You assume all risk in using the information. In no event shall EOG or its representatives be liable for any special, indirect or consequential damages resulting from the use of the information.

Cautionary Notice Regarding Forward-Looking Statements: This presentation 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," "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 or pay 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. 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 13 through 22 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 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.

Oil and Gas Reserves; Non-GAAP Financial Measures: 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 presentation 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, 2016, 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 _0817-3

Exceeded High End of All U.S. Production Targets

Delivered Per Unit LOE, Transportation and DD&A Rates Below Target

Reduced CWC* in Delaware, Powder River and DJ Basins

Achieved YTD Asset Sale Proceeds of $175 Million

Increased U.S. Crude Oil Growth Forecast to 20% from 18%**

Maintained Capex Guidance of $3.7-$4.1 Billion***

Balance Capex + Dividend with Discretionary Cash Flow- Complete ≈ 480 Net Wells- Average 26 Rigs in 2017

* CWC = Drilling, Completion, Well-Site Facilities and Flowback.** Based on midpoint of 2017 guidance, as of August 1, 2017.*** Based on full-year estimates, as of August 1, 2017.

2Q 2017

FY 2017

EOG _0817-4

U.S. Leader in Return on Capital Employed

U.S. Oil Growth Leader

Among Lowest Cost Producers in Global Oil Market

Commitment to Safety and the Environment

Create Significant Long-Term Shareholder Value

EOG _0817-5

High Return Oil Growth

• Fastest U.S. Horizontal Driller• Industry Leading Completion Technology• Self-Sourcing Materials / Services• Low Infrastructure & Production Cost • Proven Track Record of Execution

• Internal Prospect Generation• First Mover Advantage• Best Rock / Best Plays• Low Cost Acreage• Most Prolific U.S. Horizontal Wells

• Large Proprietary Data Marts• Real-Time Data Capture• Predictive Algorithms• 65+ In-House Desktop / Mobile Apps• Fast / Continuous Tech Advancement

Exploration

Operations

Information Technology

• Rate-of-Return Driven• Decentralized / Non-Bureaucratic• Multi-Disciplined Teamwork• Innovative / Entrepreneurial• Every Employee is a Business

Person

Culture

EOG _0817-6

WTI Oil:HHub Gas:

4%

28%

22%19%

5%

15%

18%

30%

26%

16%

26%

5%

2%

8%

4%

12%14%

1%-4%

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

* ROCE in 2013 and prior years calculated using reported net income (GAAP) and 2014 – 2016 using adjusted net income (Non-GAAP).See Reconciliation Schedules.

$17$2.20

$28$4.10

$61$7.20

$71$4.20

$95$3.70

$46$2.50

$26$3.40

1998-2016Average13.2%

EOG _0817-7

278.3

335.0

2016 2017E**

* Data from 2016 completed wells. Calculated using futures strip prices in February 2017. See reconciliation schedule.** Based on midpoint of 2017 guidance, as of August 1, 2017.

17.3415.75

2016 2017E**

Non-PremiumPremium

DD&A$/BOE

U.S. ProductionMBOD

Direct ATROR*

First Year Gross Oil(Bbl/ well)

Direct Finding Cost ($/BOE)

> 100%

≈ 200,000

≈ $7

≈ 20%

≈ 100,000

≈ $13

Drives Higher ROCE

EOG _0817-8

$30 $40 $50 $60

* Percent of domestic gross completed wells which are premium.

14%23%

50%

80%

2014 2015 2016 2017Est

2018+Est

100%+

10%

60%

30%

Oil:

* See reconciliation schedules.

Premium Drilling Direct ATROR*(Minimum Return for Premium)

Shifting to Premium Locations(% Completed Premium Wells*)

90+%

* Estimated potential reserves net to EOG, not proved reserves.

6.5 BnBoe* ≈7,200 Net Undrilled Locations >10 Years of Drilling

EOG _0817-9

Resource Potential**

* Premium locations are shown on a net basis and are all undrilled.** Estimated potential reserves net to EOG, not proved reserves.

Per Well

Feb 2016 Aug 2016 Sep 2016 May 2017

2.0 BnBoe

625 MBoe

3.5 BnBoe

815 MBoe

5.1 BnBoe

850 MBoe

6.5 BnBoe

900 MBoe

≈3,200

≈4,300

≈6,000

≈7,200

EOG _0817-10

0

200

400

600

800

1,000

1,200

1,400

EOGA B C D E F G H I J K L M N O P Q R S T U V W X Y Z AA

52 9 24 4 18 13 22 20 9 3 24 61 5 3 3 23 61 20 163 8 18 26 34 28 26 49 17 51

7,000’ LateralBoed

Delaware Basin Oil

Average daily six-month production, normalized to 7,000’ lateral. All horizontal wells from original operator, January 2016 – June 2017.Gas production converted at 20:1. Wolfcamp formation, Wolfcamp reservoir designation, all counties.Delaware Basin peer companies: APA, APC, BHP, CDEV, COP, CXO, EGN, JAG, MTDR, OXY, PE, RDS, REN, XEC and XOM.Midland Basin peer companies: APA, CVX, CXO, ECA, EGN, FANG, OXY, PE, PXD, RSPP, SM and XOM.Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2017).

Well Count

Midland Basin Oil

Solid Colors: OilGray Bar: Natural Gas

EOG _0817-11

0

1,000

2,000

3,000

4,000W

hirli

ng W

ind

11 F

eder

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04H

Whi

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Win

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Com

703

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Whi

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Win

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702

H

Nep

tune

10

Stat

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om 5

03H

Nep

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10

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02H

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H

Rat

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21 F

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om 7

01H

Orio

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701

H

Whi

rling

Win

d 14

Fed

eral

Com

701

H

Car

pent

er U

nive

rsity

Lan

ds 7

-20

Uni

t 4LS

Cab

ra N

ino

11 B

3NC

Sta

te C

om 1

H

Orr

tann

a 20

Fed

701

H

Rat

tlesn

ake

28 F

eder

al C

om 7

04H

Endu

ranc

e 36

Sta

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om 7

01H

Skul

l Cap

Fed

eral

Com

022

H

Stat

e G

alile

o 7

15H

Thor

21

702H

Lom

as R

ojas

26

Stat

e C

om 7

08H

Dra

inag

e 34

-136

1H

EOG Well

* Horizontal oil wells.Source: IHS, company reports and state regulatory filings.

Industry Well

Bopd

EOG _0817-12

-

50,000

100,000

150,000

200,000

250,000

300,000

3,500 4,500 5,500 6,500 7,500 8,500

EOG Delaware Basin

Delaware Basin Peers

Midland Basin Peers

Lateral Length (Feet)

12-MonthCumulative MBO

2016

20162016

2013

20152014

2015

20152014

20142013

2013

250

200

150

100

50

300

Longer Laterals are Driving Industry Well Productivity

Improvements

Bubble Area Denotes 30-Day IP

Cumulative 12-month oil production. All horizontal wells from original operator. Wolfcamp formation, Wolfcamp reservoir, all counties.Delaware Basin peer companies: APA, APC, BHP, COP, CXO, MTDR, OXY, RDS, REN and XEC.Midland Basin peer companies: APA, CVX, CXO, ECA, EGN, FANG, OXY, PE, PXD, RSPP and XOM.Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2017).

EOG Initiates:• Precision Targeting• Advanced Completions

EOG _0817-13

* ATROR and NPV calculated using $50 WTI and $3.00 NYMEX fixed for life of well. Assumes industry capital and operating costs equal to EOG. See reconciliation schedules.All horizontal wells from original operator. Wolfcamp formation, Wolfcamp reservoir, all counties.Delaware Basin peer companies: APA, APC, BHP, COP, CXO, MTDR, OXY, RDS, REN and XEC.Midland Basin peer companies: APA, CVX, CXO, ECA, EGN, FANG, OXY, PE, PXD, RSPP and XOM.Source: IHS

Direct ATROR* Net Present Value per Well*($MM)

151%

104%

29%15%

EOGPremium

Wells

EOGAll

Wells

IndustryDelaware

Basin

IndustryMidlandBasin

$5.9

$4.8

$1.8

$0.5

EOGPremium

Wells

EOG AllWells

IndustryDelaware

Basin

IndustryMidlandBasin

EOG _0817-14

7.2

5.1 4.8 4.6

2015 2016 1H17 Target

5.7

4.7 4.5 4.3

2015 2016 1H17 Target

* CWC = Drilling, Completion, Well-Site Facilities and Flowback.

9.88.5

7.6 7.6

2015 2016 1H17 Target

Delaware Basin Wolfcamp Oil Play South Texas Eagle Ford Bakken

* Normalized to 5,300’ lateral. * Normalized to 8,400’ lateral.* Normalized to 7,000’ lateral.

1H17-11%

1H17-4%

1H17-6%

EOG _0817-15

2014 2015 2016 2017E

$13.53$12.09*

$10.55*

G&P

G&A

Transportation

LOE

* Excludes one-time expenses of $19.4 million in 2015 related to early leasehold termination and $47.0 million in 2016 related to voluntary retirements and acquisition costs. Includes stock compensation expense and other non-cash items.

** Based on midpoint of 2017 guidance, as of August 1, 2017. Excludes one-time expenses of $13.3 million for early leasetermination and joint venture transaction costs. See reconciliation schedules.

$10.46**

EOG _0817-16

$0

$2

$4

$6

$8

$10

$12

$14

0% 10% 20% 30% 40% 50% 60% 70%

LOE/Boe

2015

Source: Company filings.Peers: APA, APC, CHK, CLR, COG, CXO, DVN, ECA, MRO, MUR, NBL, NFX, PXD, RRC, SWN and XEC.

Oil Production Mix

EOG LOE Peers’ 2016 LOE

20162017E

Low-Cost Oil Producer

EOG _0817-17

$MM

Source: FactSet consensus, U.S E&P Companies >$500MM market cap, as of 7/24/17. Consensus 2017 WTI oil price ≈ $50. * Discretionary cash flow less capex and dividends.

EOG

(1,000)

(750)

(500)

(250)

0

250

500

750

1,0001,948

2017 Consensus Cash Flow After Capex & Dividend

Based on ≈ $50 WTI

EOG _0817-18

0

100

200

300

400

500

600

700

800

2016* 2017 2018 2019 2020

$60

* Pro forma for full year of production from Yates in 2016.** Discretionary Cash Flow Capex + Current Dividend.

$50

MBopd

15%-25% CAGR

EOG _0817-19

EOG _0817-20

Real-Time Data Streams from Every Asset

EOG ProprietaryData Marts

Desktop Mobile

In-House Developed:• Algorithms• Data Science• Software

Predictive Analytics

“A Control Room in Your Pocket”

Frac Fleets

Rigs

Wells on Production

EOG Proprietary Data

• Logs• Cores• 3-D Seismic• Micro Seismic• Reservoir Models

Optimized for Big Data Processing

Comprehensive: Covers All Aspects of EOG BusinessCompletions: Optimize Advanced Designs to Geologic SettingPrecision Lateral Targeting: Petrophysical Modeling of “Best Target”Geosteering: Integrated with Petrophysical Models

Decentralized Decision Making:

65+ EOG Proprietary Applications

EOG _0817-21

LowerEagleFord

1. Grade Rock Characteristics High to Low Quality2. Overall

Grade

3. Drill

* Sample 1-foot core extracted from

Lower Eagle Ford. Enlarged to show detail of the rock.

EOG _0817-22

Contain Events Closerto Wellbore

Enhance Complexity to Contact More Surface Area

Note: Microseismic dots represent well stimulation events during completions.

EOG _0817-23

PlayNet

Acres Total

Locations*

ResourcePotential**(MMBoe)

Premium Locations***

Eagle Ford 528,000 7,200 3,200 2,425

Bakken/Three Forks - Core- Non-Core

120,000110,000

9751,125

620400

330-

Delaware Basin - Wolfcamp 346,000 2,660 2,900 1,700- Second Bone Spring 289,000 1,870 1,400 1,350- Leonard 160,000 1,800 1,700 1,100

Rockies- DJ Basin- Powder River Basin

81,000400,000 _

460315 _

210190 _

200120 _

≈ 2,100,000 ≈ 16,000 ≈ 10,600 ≈ 7,200

* Number of producing and undrilled remaining net wells as of January 1, 2017. Assumes no further downspacing, acreage additions or enhanced recovery.** Estimated potential reserves (MMBoe) net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells.

*** Premium locations are shown on a net basis and are all undrilled.

Inventory Growing in Quality and Size

EOG _0817-24

Production and Reserve Growth/

ReplacementReturns

A 20%

B 40%

C 10%

D

F 25%

10%

EOG 6%30%

E

G 10%

H 30%

Source: Company Reports. Percentages represent approximate weightings applied in determining 2016 executive officer short-term incentive compensation.Peer companies: APA, APC, COP, DVN, HES, MRO, NBL and PXD.

EOG Employees Are Incentivized to Deliver Returns

20%

25%

10% 30%

EOG _0817-25

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

Note: Dividends adjusted for 2-for-1 stock splits effective March 1, 2005 and March 31, 2014.* Source: Company reports as of 3/31/17. See reconciliation schedule. Peer Companies: APA, APC, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OXY, PXD, RRC and XEC.

Committed to the Dividend 16 Increases in 17 Years

0%

10%

20%

30%

40%

50%

60%

70%

Low Financial LeverageNet Debt to Total Capitalization*

PeerAverage

Peers

EOG

EOG _0817-26

Middle East

Venezuela

Brazil

Russia

Nigeria

Angola

US L48 Conv

Mexico

GOM

$0$10$20$30$40$50$60$70$80$90

$100

MiddleEast/Russia

Medium CostConventional

USTight Oil

DeepWater

High CostNon-OPEC

Arctic / RussianUnconventional

* Brent equivalent price required to achieve 10% Direct ATROR (see reconciliation schedules).Source: PIRA.

Brent ($/BBL)

49% 28% 5% 13% 5% -% World Supply

US L48 ConvOil Sands

New Marginal Cost of Oil

(≈ $65 - $75)North Sea

U.S. Tight OilFar East

Russia EOG ($30)*

EOG Competitive Globally

EOG _0817-27

Brushy Canyon

Leonard A

Leonard B

1st Bone Spring

2nd Bone Spring

3rd Bone Spring

Upper Wolfcamp

Middle Wolfcamp

Lower Wolfcamp

4,80

0’

One WorldTrade Center

1,792’

Battery Park to Wall Street to City Hall 4,800’ Middle Bakken

Lower EagleFord

40’ 150’

Battery Park

Wall Street

City Hall

EOG _0817-28

Net Resource Potential 6.0 BnBoe*

6,330 Net Locations; 7,200’ Laterals

Average 13 Rigs Operating in 2017

Significant Infrastructure Installed- Water Sourcing, Gathering and

Recycling- Sand Rail-Car Unloading Facilities- Oil and Gas Gathering and Takeaway

Low LOE Per-Unit Rate

Test Permian Northwest Shelf in 2017

Eddy

Lea

Loving WinklerCulberson

Ward

Reeves

Chaves

Roosevelt

NorthwestShelf

143,000 Net Acres

DelawareBasin

416,000 Net Acres

EOG 559,000 Net Acres

* Estimated potential reserves net to EOG, not proved reserves. Includes 462 MMBoe of proved reserves booked at December 31, 2016 and prior production from existing wells.

EOG _0817-29

346,000 Net Acres Prospective with Multiple Target Zones- 2,660 Net Wells- Complete ≈110 Net Wells in 2017 vs. 71 in 2016

Estimated Resource Potential 2.9 BnBoe,* Net to EOG

Oil Play- 226,000 Net Acres, 1,585 Net Wells; 660’ Spacing- Upper and Middle Zones- EUR 1,330 MBoe, Gross; 1,050 MBoe, NAR - CWC** Target $7.6 MM for 7,000’ Lateral

Combo Play- 120,000 Net Acres, 1,075 Net Wells; 880’ Spacing- Upper and Middle Zones- EUR 1,550 MBoe, Gross; 1,200 MBoe, NAR- CWC** Target $7.5 MM for 8,300’ Lateral

Testing 500’ Spacing and Additional Targets

Wolfcamp Oil and Combo Plays Bopd Boed Lateral- 2Q 2017 25 Gross Wells 30-Day IP 1,945 3,010 6,500’

* Estimated potential reserves net to EOG, not proved reserves. Includes 330 MMBoe of proved reserves booked at December 31, 2016 and prior production from existing wells.

** CWC = Drilling, Completion, Well-Site Facilities and Flowback

NGLs32%

Typical WolfcampCombo Well

Gas42%

Oil26%

Gas27%

NGLs20%

Oil53%

Typical WolfcampOil Well

EOG _0817-30

289,000 Net Acres Prospective in Northern Delaware Basin- 1,870 Net Wells; ≈ 850’ Spacing- Complete ≈25 Net Wells in 2017 vs. 13 in 2016


Typical Well- EUR 950 MBoe, Gross; 780 MBoe, NAR- CWC** Target $7.3 MM for 7,000’ Lateral

* Estimated potential reserves net to EOG, not proved reserves. Includes 67 MMBoe of proved reserves in Second Bone Spring and 66 MMBoe in Leonard Shale booked at December 31, 2016 and prior production from existing wells.

** CWC = Drilling, Completion, Well-Site Facilities and Flowback.

NGLs16%

Typical Second Bone Spring Well

Gas22%

Oil62%

160,000 Net Acres Prospective; 1,800 Net Wells- 660’ Spacing in A and B Zones- Complete ≈5 Net Wells in 2017 vs. 8 in 2016


Typical Well- EUR 1,175 MBoe, Gross; 940 MBoe, NAR- CWC** Target $6.3 MM for 6,800’ Lateral

NGLs28%

Typical Red HillsLeonard Shale Well

Gas41%

Oil31%

Second Bone Spring

Leonard Shale

EOG _0817-31

-10

40

90

140

190

240

0 90 180 270 3600

50

100

150

200

250

300

350

0 90 180 270 360

Delaware Basin Second Bone Spring WellsAverage Cumulative Production*

Delaware Basin Wolfcamp Oil Wells Average Cumulative Production*

(MBoe)

Producing Days

* Normalized to 4,500-foot lateral.

2015

Producing Days

(MBoe)

2015

2016 2016


EOG _0817-32

WEBB

FRIO

BEE

UVALDE

DIMMIT

BEXAR

KINNEY

ZAVALA

MEDINA

LA SALLE

LAVACA

MAVERICK

LIVE OAK

ATASCOSA

DE WITT

FAYETTE

MCMULLEN

WILSON

GONZALES

KARNES

GUADALUPE

Oil 71%

Gas 15%

NGLs14%

Typical Eagle Ford Well

Largest Oil Producer and Acreage Holder in the Eagle Ford- Average 8 Rigs Operating in 2017- Complete ≈195 Net Wells in 2017 vs. 236 in 2016

Estimated Resource Potential 3.2 BnBoe;* 7,200 Net Wells

Typical Well- 5,300’ Lateral; ≈40-Acre Spacing- EUR 580 MBoe, Gross; 450 MBoe, NAR- CWC** $4.7MM in 2016; Target $4.3MM

Precision Targeting- Lateral Drilling Window 20’ vs. Prior 150’

Implementing Enhanced Oil Recovery Program- Incremental Reserves 30%-70%- Direct ATROR*** >30% and PVI**** >2.0

Bopd Boed Lateral2Q 2017 51 Gross Wells 30-Day IP 1,520 1,960 6,500’- Lynch Unit 2H-4H 2,555 3,245 5,800’- Olympic A 1H-D 4H 2,160 2,910 6,600’- Dio Unit 11H-15H 2,135 2,840 5,100’

* Estimated potential reserves net to EOG, not proved reserves. Includes 1,003 MMBoe proved reserves booked at December 31, 2016 and prior production from existing wells.

** CWC = Drilling, Completion, Well-Site Facilities and Flowback*** See reconciliation schedules. Assumes oil price $40 per barrel WTI and natural gas price $2.50 per MMBtu Henry Hub.**** Net present value divided by capital investment.

Crude OilWindow

Dry GasWindow

Wet GasWindow

0 25 Miles

San Antonio

Corpus Christi

Laredo

EOG 590,000 Net Acres528,000 Net Acres in Oil Window

EOG _0817-33

0

25

50

75

100

125

150

175

0 90 180 270 360

Eagle Ford East WellsAverage Cumulative Oil Production*

2012

20132014

Eagle Ford West Wells Average Cumulative Oil Production*

(Mbo)

Producing Days


2015

0

25

50

75

100

125

150

175

0 90 180 270 360

Producing Days


(Mbo)

2012

201320142015

2016

2016

EOG _0817-34

* Estimated potential reserves net to EOG, not proved reserves. Includes 208 MMBoe proved reserves in Bakken/Three Forks booked at December 31, 2016. Includes prior production from existing wells.

** CWC = Drilling, Completion, Well-Site Facilities and Flowback.

Complete ≈35 Net Wells in 2017 vs. 48 in 2016

Estimated Resource Potential 1.0 BnBoe*- 8,400’ Lateral- $5.1 MM CWC** in 2016; Target $4.6 MM- 650’ Spacing

Focus on Premium Locations- Bakken Core and Antelope Extension Areas- 120,000 Net Acres

LOE per BOE Reduced 43% Last Two Years- Installed Water Handling and Other Infrastructure

Bopd Boed Lateral2Q 2017 22 Gross Wells 30-Day IP 1,175 1,450 8,400’- Clarks Creek 73-75, 110-0719H 2,075 2,965 9,800’

Gas 15%

Williston BasinRemaining Wells

Oil70%

NGL15%

Canada

Bakken Core

AntelopeExtension

BakkenLite

State Line

Elm Coulee

EOG Acreage – Bakken/Three ForksBakken Oil Saturated

20 Miles

Stanley, ND

CoreNon-Core

EOG _0817-35

PRB Turner Sand Identified as Premium Play- Testing 4,800’ Column of Stacked Pay


CWC* Target $5.0MM for 8,000’ Lateral- 2Q Wells at Target

8 Gross Turner Wells 2Q 2017 Bopd Boed Lateral- 30-Day IP 910 1,745 8,700’

DJ Basin Codell Identified as Premium Play


CWC* Target $4.5MM for 9,000’ Lateral- 2Q Wells at Target

10 Gross Codell Wells 2Q 2017 Bopd Boed Lateral770 885 9,000’

Powder River Basin

DJ BasinDJ Basin


Laramie

WeldCO

WY

Powder River Basin

Campbell

Crook

Weston

NiobraraConverseNatrona

Johnson

Sheridan WY

MT


PRB CoreExploration

Area

Average 2 Rigs in Rockies in 2017

* CWC = Drilling, Completion, Well-Site Facilities and Flowback.

EOG _0817-36

East Irish Sea (Conwy)- Production Commenced March 2016- Optimum Production Rate ≈10,000 Bopd- Undergoing Facility Improvements

Sercan Joint Development Project- Completed 5 Gross / 3 Net Well ProgramCompleted One Additional Net Well in July- Drill and Complete Three Additional Net Wells

in 2H 2017Entered Into New Gas Supply Contract- Enables Additional Premium Drilling

TRINIDAD

ATLANTIC OCEAN

U(a)

VENEZUELA

4(a)

U(b)

SECC

NORTH SEA

EastIrishSea

Trinidad and Tobago

United Kingdom

Trinidad

United Kingdom

Copyright; Assumption of Risk: Copyright 2017. This presentation and the contents of this presentation have been copyrighted by EOG Resources, Inc. (EOG). All rights reserved. Copying of the presentation is forbidden without the prior written consent of EOG. Information in this presentation is provided “as is” without warranty of any kind, either express or implied, including but not limited to the implied warranties of merchantability, fitness for a particular purpose and the timeliness of the information. You assume all risk in using the information. In no event shall EOG or its representatives be liable for any special, indirect or consequential damages resulting from the use of the information.

Cautionary Notice Regarding Forward-Looking Statements: This presentation 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," "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 or pay 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. 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 13 through 22 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 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.

Oil and Gas Reserves; Non-GAAP Financial Measures: 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 presentation 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, 2016, 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.