UBS Global

Oil and Gas Conference

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.

UBS_0517-3

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

UBS_0517-4

Exploration

Operations

Information

Technology

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

• Rate-of-Return Driven

• Decentralized / Non-Bureaucratic

• Multi-Disciplined Teamwork

• Innovative / Entrepreneurial

• Every Employee is a Business

Person

Culture

UBS_0517-5

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%

UBS_0517-6

Increased Premium Inventory by 1,200 Net Locations to ≈ 7,200 Wells

- Premium Resource Potential Increased 27% to 6.5 BnBoe*

- Increase ≈ 2.5X Forecast 2017 Well Completions

- Added 700 Locations in Delaware Basin and 500 in Eagle Ford

Exceeded High End of All U.S. Production Targets

Achieved Record Permian Basin Horizontal Well Results

- Whirling Wind 4-Well Package Average IP-30 5,060 Boed Each

- EOG Operates 14 of Top 20 Permian Basin Horizontal Wells

Reduced CWC** in Eagle Ford, Delaware Basin and Bakken

Added Three Rigs within Current Capex Forecast

- Average 26 Rigs Operating in 2017

Lowered 2017 Cash Operating Cost Forecast***

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

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

*** Based on full-year estimates as of May 8, 2017.

1Q 2017

UBS_0517-7

Deliver Double-Digit High-Return Oil Production Growth

- 18% YOY Growth at $47 Flat Oil*

Balance Capex + Dividend with Discretionary Cash Flow

- Complete ≈ 480 Net Wells

- Average 26 Rigs in 2017

Expand Premium Strategy

- Premium Wells Generate at Least 30% Direct ATROR** at $40 Oil

- Total Well Completions ≈80% Premium in 2017 vs. 50% in 2016

- Replace Premium Inventory 2X Faster Than Drilling

Capture New Premium Plays Through Organic Exploration

Reduce Costs Further

- Efficiencies and Contract Roll-Offs Offset Price Inflation

Utilize Asset Sale Proceeds to Further Strengthen Balance Sheet

* Based on midpoint of 2017 guidance, as of May 8, 2017.

** See reconciliation schedule.

Build on EOG’s Premium Foundation

UBS_0517-8

More Oil from Fewer Wells

- Higher Returns with Lower Finding and Development Costs

- Drives Lower DD&A Rate and Higher ROCE

Adding New Premium Inventory 2X Faster Than Drilling

- Convert Existing Locations to Premium

- Exploration

- Tactical Acquisitions

Robust Growth for Far Less Capital

Premium Well Definition

Minimum 30% Direct ATROR* at $40 Oil

Does Not Change with Oil Prices

* See reconciliation schedules.

UBS_0517-9

Direct ATROR*

First Year Oil per Well (Gross, Bbl)

Direct Finding Cost ($/Boe)

Capital Efficiency ($/First Year Boed)

Number of Net Wells Completed

>100%

≈ 200,000

$6.90

$7,600

220

* Calculated using futures strip prices in February 2017. See reconciliation schedule.

≈ 20%

≈ 100,000

$13.25

$17,200

225

Premium Drilling is a Game-Changer for EOG

2016 Wells Non-PremiumPremium

UBS_0517-10

$30 $40 $50 $60

* Domestic gross completed wells

14%

23%

50%

80%

2014 2015 2016 2017

Est

2018+

Est

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

100%+

10%

60%

30%

Oil:

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

* See reconciliation schedules.

Premium Drilling Direct ATROR*

(Minimum Return for Premium)

Percent EOG Wells* Meeting

Premium Standard

90+%

UBS_0517-11

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 Yates Sep 2016 May 2017

2.0 BnBoe

625 MBoe

3.5 BnBoe

815 MBoe

1.6 BnBoe

920 MBoe

5.1 BnBoe

850 MBoe

6.5 BnBoe

900 MBoe

≈3,200

≈4,300

1,740

≈6,000

≈7,200

UBS_0517-12

WTI Oil:

HHub Gas:

4%

28%

21%

19%

5%

15%

18%

30%

26%

16%

26%

5%

2%

8%

4%

12%14%

1%-4%

199

8

199

9

200

0

200

1

200

2

200

3

200

4

200

5

200

6

200

7

200

8

200

9

201

0

201

1

201

2

201

3

201

4

201

5

201

6

* 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

1998-2016Average13.1%

UBS_0517-13

0

200

400

600

800

1,000

EOG A B C D E F G H I J K L M N O P Q R S T U V W

37 7 7 19 12 14 7 15 24 4 49 18 48 119 7 15 20 22 6 11 31 34 37 24

5,000’ Lateral

Boed

Delaware Basin Oil

Average daily six-month production, normalized to 5,000’ lateral. All horizontal wells from original operator, January 2016 – April 2017.

Gas production converted at 20:1. Wolfcamp formation, Wolfcamp reservoir designation, all counties.

Delaware Basin peer companies: APA, APC, BHP, COP, CXO, JAG, MTDR, OXY, RDS, REN and XEC.

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 (2016).

Well Count

Midland Basin Oil

Solid Colors: Oil

Gray Bar: Natural Gas

UBS_0517-14

0

1,000

2,000

3,000

4,000W

hir

lin

g W

ind

14

Fe

d C

om

70

4H

Wh

irli

ng

Win

d 1

1 F

ed

Co

m 7

03

H

Wh

irli

ng

Win

d 1

1 F

ed

Co

m 7

02

H

Ra

ttle

sn

ak

e 2

1 F

ed

era

l C

om

70

2H

Ra

ttle

sn

ak

e 2

1 F

ed

era

l C

om

70

1H

Wh

irli

ng

Win

d 1

1 F

ed

Co

m 7

01

H

Ca

bra

Nin

o 1

1 B

3N

C S

tate

Co

m 1

H

Orr

tan

na

20

Fe

d 7

01

H

Ra

ttle

sn

ak

e 2

8 F

ed

era

l C

om

70

4H

Th

or

21

70

2H

Lo

ma

s R

oja

s 2

6 S

tate

Co

m 7

08

H

Dra

ina

ge

34

-13

6 1

H

Gri

dir

on

N00

1W

B

Orr

tan

na

20

Fe

d 7

02

H

Sa

le R

an

ch

23F

6H

En

du

ran

ce

36

Sta

te C

om

70

5H

Th

or

21

Fe

dera

l C

om

704

H

Bla

ck

Be

ar

36

Sta

te 7

04

H

Ma

sk H

z U

nit

100

4H

Sil

ve

r C

ity

Un

it A

1H

EOG Well

* Horizontal oil wells

Source: IHS, company reports and State of New Mexico Oil Conservation Division regulatory filings.

Industry Well

Bopd

UBS_0517-15

-

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-Month

Cumulative MBO

2016

2016

2016

2013

2015

2014

2015

20152014

2014

2013

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 (2016).

EOG Initiates:

• Precision Targeting

• Advanced Completions

UBS_0517-16

* 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

UBS_0517-17

0

50

100

150

200

250

Delaware BasinWolfcamp

Bone Spring Eagle Ford Bakken SCOOP/STACK

Midland BasinWolfcamp

Tho

usa

nd

s

EOG

Industry

5,000’ Lateral

MBoe

Cumulative nine-month production, normalized to 5,000’ lateral.

Gas production converted at 20:1.

Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2016).

UBS_0517-18

Vertical Integration

- Drilling Fluids, Chemicals and Flowback

- Self-Sourced Materials and Technology

- Sand Costs Declining

Strategic Partnerships with Vendors – EOG Preferred Customer

Large Scale Procurement

Infrastructure Investment

- Water Handling and Recycling

Roll-off of Higher-Cost Legacy Contracts and Inventory

Efficiencies

- Completion Redesigns – Enhanced Well Productivity at Less Cost

- Faster Rig Moves and Drilling Times

- Off-Line Cementing

- Faster Completion Times

Year, After Year, After Year . . .

UBS_0517-19

7.2

5.1 4.8 4.6

2015 2016 1Q17 Target

5.7

4.7 4.5 4.3

2015 2016 1Q17 Target

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

9.8

8.57.8 7.6

2015 2016 1Q17 Target

Delaware Basin

Wolfcamp Oil PlaySouth Texas Eagle Ford Bakken

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

1Q17

-8%1Q17

-4%

1Q17

-6%

UBS_0517-20

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 May 8, 2017. See reconciliation schedules.

$10.40**

UBS_0517-21

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

UBS_0517-22

UBS_0517-23

Giant Data Sets- Real-Time Data Streaming in from Every Asset- Correlate with Library of Logs, Cores, 3-D Seismic and Reservoir Models

Apply Proprietary Algorithms with In-House Software

65+ In-House Desktop and Mobile Software Applications. . . and Counting

Mobile Applications Enable Decentralized Decision Making- A Control Room in Your Pocket

Advanced Completion Designs and Implementation Techniques- Apply Data Science to Optimize Completion to Geologic Setting

Petrophysical Modeling of “Best Target” Enables Precision Lateral Targeting

In-House Geosteering Software Integrated with Petrophysical Models

Sustainable Competitive Advantage

UBS_0517-24

Frac Fleets

Rigs

Wells

Real-Time Data Streams

User and Field Data

Inputs

Other Data Sources

EOG Proprietary

Data Marts

DesktopMobile

Data Science and

Predictive Algorithms

65+ EOG Proprietary Applications

Mobile Applications - A Control Room in Your Pocket

UBS_0517-25

Lower

Eagle

Ford

1. Grade Rock Characteristics High to Low Quality

2. Overall

Grade

3. Drill

* Sample 1-foot core

extracted from

Lower Eagle Ford.

Enlarged to show

detail of the rock.

UBS_0517-26

Contain Events Closer

to WellboreEnhance Complexity to

Contact More Surface Area

Note: Microseismic dots represent well stimulation events during completions.

UBS_0517-27

Play

Net

Acres

Total

Locations*

Resource

Potential**

(MMBoe)

Premium

Locations***

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

Bakken/Three Forks

- Core

- Non-Core

120,000

110,000

975

1,125

620

400

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

81,000

400,000 _

460

315 _

210

190 _

200

120 _

≈ 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

UBS_0517-28

* Based on full-year estimates as of May 8, 2017.

Exploration and

Development

81%

Exploration and

Development Facilities

13%

Gathering,

Processing and Other

6%

Resume Double-Digit High-Return Oil Growth

Balance Capex + Dividend with Discretionary Cash Flow at $47 Oil

≈80% of Well Completions Estimated to be Premium

Diversified Investments – Oil Production Growth From All 5 Major Basins

Asset Sale Proceeds Strengthen Balance Sheet – Not Funding Operations

2017 Estimated Capex ≈ $3.7 to $4.1 Bn*

2017 Outlook

UBS_0517-29

0

10

20

30

40

50

60

70

80

EOG A B C D E F PeerAvg

G H I J K L

Source: Company Reports. Natural gas converted at 6:1.

Peer Group: APA, APC, CLR, COP, CXO, DVN, HES, MRO, NBL, NFX, PXD and XEC.

UBS_0517-30

0%

10%

20%

30%

40%

50%

60%

70%

A B C D E F G H PeerAvg

I J EOG K L M N O

* Source: Company reports as of 3/31/17 (XEC as of 12/31/16). See reconciliation schedule.

Peer Companies: APA, APC, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OXY, PXD, RRC and XEC.

UBS_0517-31

$0.03 $0.04 $0.04 $0.04 $0.05 $0.06$0.08

$0.12

$0.18

$0.26

$0.29$0.31 $0.32

$0.34

$0.38

$0.59

$0.67 $0.67

$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.

Committed to the Dividend – 16 Increases in 17 Years

UBS_0517-32

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 Conv

Oil Sands

New Marginal Cost of Oil

(≈ $65 - $75)North Sea

U.S. Tight OilFar East

Russia EOG ($30)*

EOG Competitive Globally

UBS_0517-33

21.520.4

19.4

10.5

2015 2016 1Q17 Record

Delaware Basin

Wolfcamp Oil PlaySouth Texas Eagle Ford Bakken

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

7.8

5.9 6.0

3.4

2015 2016 1Q17 Record

12.4

8.57.8

5.4

2014 2015 2016 Record

1Q17

-5%2016

-8%

UBS_0517-34

Brushy Canyon

Leonard A

Leonard B

1st Bone Spring

2nd Bone Spring

3rd Bone Spring

Upper Wolfcamp

Middle Wolfcamp

Lower Wolfcamp

4,8

00

’

One World

Trade Center

1,792’

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

Bakken

Lower

Eagle

Ford

40’150’

Battery

Park

Wall Street

City Hall

UBS_0517-35

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 Gathering and Takeaway

- Gas Processing

Test Permian Northwest Shelf in 2017

Eddy

Lea

LovingWinkler

Culberson

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.

UBS_0517-36

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- 1Q 2017 33 Gross Wells 30-Day IP 1,850 2,855 5,600’- Whirling Wind 4-Well Pattern 3,510 5,060 7,100’

* 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

NGLs

32%

Typical Wolfcamp

Combo Well

Gas

42%

Oil

26%

Gas

27%

NGLs

20%

Oil

53%

Typical Wolfcamp

Oil Well

UBS_0517-37

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

Estimated Resource Potential 1.4 BnBoe,* Net to EOG

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.

NGLs

16%

Typical Second Bone

Spring Well

Gas

22%Oil

62%

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

Estimated Resource Potential 1.7 BnBoe,* Net to EOG

Typical Well

- EUR 1,175 MBoe, Gross; 940 MBoe, NAR

- CWC** Target $6.3 MM for 6,800’ Lateral

NGLs

28%

Typical Red Hills

Leonard Shale Well

Gas

41%

Oil

31%

Second Bone Spring

Leonard Shale

UBS_0517-38

0

50

100

150

200

250

300

350

0 90 180 270 360

Thousands

Delaware Basin Second Bone Spring Wells

Average Cumulative Production*

Delaware Basin Wolfcamp Oil Wells

Average Cumulative Production*

(MBoe)

Producing Days

* Normalized to 4,500-foot lateral.

2015

0

40

80

120

160

200

240

0 90 180 270 360

Thousands

Producing Days

(MBoe)

2015

2016 2016

* Normalized to 4,500-foot lateral.

UBS_0517-39

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%

NGLs

14%

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’

Bopd Boed Lateral

1Q 2017 65 Gross Wells 30-Day IP 1,130 1,390 6,500’

Shifting to Longer Laterals in West

Completion Innovations Lower Well Costs with Same Productivity

Acreage 97% Held by Production

* 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

Crude Oil

Window

Dry Gas

Window

Wet Gas

Window

0 25 Miles

San Antonio

Corpus Christi

Laredo

EOG 590,000 Net Acres

528,000 Net Acres in Oil Window

2017 Operations

UBS_0517-40

0

25

50

75

100

125

150

175

0 90 180 270 360

Thousands

Eagle Ford East Wells

Average Cumulative Oil Production*

2012

20132014

Eagle Ford West Wells

Average Cumulative Oil Production*

(Mbo)

Producing Days

* Normalized to 6,600-foot lateral.

2015

0

25

50

75

100

125

150

175

0 90 180 270 360

Thousands

Producing Days

* Normalized to 4,600-foot lateral.

(Mbo)

2012

2013

2014

2015

2016

2016

UBS_0517-41

Successful 32-Well Pilot in 2016

- Incremental Reserves 30%-70%

- Well Spacing as Close as 200’

Test Supports Premium Economics

- Direct ATROR* >30% and PVI** >2.0

- Capital Investment ≈$1MM per Well

2016 EOR Net Oil Production 300 MBO

- 70% Increase YOY

≈ 100 Additional Wells in 2017

- Six Areas in Eastern Eagle Ford

* 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.

Cumulative Oil Production per Well

1.0x

1.3x – 1.7x

Primary

Recovery

(Net Mbo)

Enhanced Oil

Recovery

Produce 2 - 5 Years

Before EOR Injection

Production Response

≈3 Months After Injection

UBS_0517-42

* 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

3 Wells Bakken Lite 1Q 2017 Bopd Boed Lateral

- 30-Day IP 795 955 7,700’

Gas 15%

Williston Basin

Remaining Wells

Oil

70%

NGL15%

Canada

Bakken Core

Antelope

Extension

Bakken

Lite

State Line

Elm

Coulee

EOG Acreage – Bakken/Three Forks

Bakken Oil Saturated

20 Miles

Stanley, ND

Core

Non-Core

UBS_0517-43

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

Complete ≈30 Net Wells in 2017 vs. 20 in 2016

CWC* Target $5.0MM for 8,000’ Lateral

5 Gross Wells 1Q 2017 Bopd Boed Lateral

- 30-Day IP 950 1,160 4,900’

DJ Basin Codell Identified as Premium Play

Complete ≈15 Net Wells in 2017 vs. 30 in 2016

CWC* Target $4.5MM for 9,000’ Lateral

Installed Water and Gas Infrastructure to Lower Costs

Record Drilling Performance - 18,000’ Well in 3 Days

Powder River Basin

DJ Basin DJ Basin

EOG 81,000 Net Acres

Laramie

WeldCO

WY

Powder River Basin

Campbell

Crook

Weston

NiobraraConverse

Natrona

Johnson

Sheridan WY

MT

EOG 400,000 Net Acres

PRB Core

ExplorationArea

Average 2 Rigs in Rockies in 2017

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

UBS_0517-44

East Irish Sea (Conwy)

- Production Commenced March 2016

- Optimum Production Rate ≈10,000 Bopd

- Further Evaluation to Maximize Reservoir

Productivity

Sercan Joint Development Project

- Completed 5 Gross / 3 Net Well Program

Drill 4 Additional Gross Wells in 2H 2017

Active Exploration Program

- Completed New Seismic Survey

TRINIDAD

ATLANTIC

OCEAN

U(a)

VENEZUELA

4(a)

U(b)

SECC

NORTH

SEA

East

Irish

Sea

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.