Eog 0216

NYSE Stock Symbol: EOG
Common Dividend: $0.67
Basic Shares Outstanding: 550 Million
Internet Address:
http://www.eogresources.com
Investor Relations Contacts
Cedric W. Burgher, SVP Investor and Public Relations
(713) 571-4658, cburgher@eogresources.com
David J. Streit, Director IR
(713) 571-4902, dstreit@eogresources.com
Kimberly M. Ehmer, Manager IR
(713) 571-4676, kehmer@eogresources.com

Copyright; Assumption of Risk: Copyright 2016. 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 and costs, 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 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 21 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 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, 2015, 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_0216-1
Shifting to Premium Locations
- Generate at Least 30% Direct ATROR* at $40 Oil
- Sustainable Improvement >10 Years of Inventory and Growing
Grow Premium Inventory At Rapid Pace
- Improve Existing Plays With Technology and Innovation
Precision Lateral Targeting & Advanced Completions
- Organic Exploration and Tactical Acquisitions
Increase Capital Productivity
- Oil Production Declines Just 5% YOY With 47% Less Capital
- Drill ≈200 Net Wells and Complete ≈270 Net Wells
- 300 Drilled Uncompleted Net Wells At YE 2015
- Average 11 Rigs in 2016; 9 Rigs on Contract At YE 2016
Maintain Strong Balance Sheet
Focus on Returns
* See reconciliation schedules.
Low-Cost Global Oil Producer

EOG_0216-2
A Record Year For Improvements
Identified 2 BnBoe* and >3,200 Premium Net Well Locations
Increased Capital Efficiency
- Reduced Capital Spending 44% YOY and Maintained Flat U.S. Oil Production
Identified >6x New Net Well Locations as Drilled in 2015
- ≈2,200 in Delaware Basin and ≈960 in Bakken/Three Forks
- Added 1.6 BnBoe Net Resource Potential*
Generated Sustainable Efficiency Improvements
- Reduced 2015 Cash Operating Costs** by 17%
- Lowered Well Costs In Top Plays
2015 Results
Achieved 192% Proved Reserve Replacement*** at $11.91/BOE All-In Finding Cost***
Exceeded Oil Production Forecast
Delivered Capital Spending Below Forecast
Acquired 34,000 Net Acres In Sweet Spot of Delaware Basin
* Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells.
** LOE, transportation, G&A, Taxes other than income and gathering and processing, on a per-unit basis. Exclude one-time expense of $18.7 million
related to early leasehold termination. Includes stock compensation and other non-cash expense. See reconciliation schedules.
*** Reserve replacement ratio and finding costs before revisions due to price. See reconciliation schedules.

EOG_0216-3
High-Quality Assets With Scale
- Large Eagle Ford, Bakken and Delaware Basin Footprints
- Scale Drives Cost Savings and Leverages Technology Gains
Innovation and Technology Focus
- In-House Completion Design
- Merging Data Science and Geoscience
Low-Cost Operator
- Highest Production Per Employee in Peer Group
- Vertically Integrated: Self-Sourced Sand, Chemicals and Drilling Fluids
Organic Exploration Growth
- Internal Prospect Generation First-Mover Advantage
- Replacing Inventory At 2x Drilling Pace
Organization and Culture
- Decentralized Structure Bottom-Up Value Creation
- Returns-Driven Culture – Significant Employee Compensation Criteria
Sustainable Competitive Advantage

EOG_0216-4
$30 $40 $50 $60
>3,200 Premium Net Well Locations With 2 BnBoe*
>10 Years of High Rate-of-Return Drilling
* Estimated potential reserves net to EOG, not proved reserves. See reconciliation schedules.
100%+
10%
60%
30%

EOG_0216-5
Eagle Ford
Delaware Basin Wolfcamp - Oil and Combo
Delaware Basin 2nd Bone Spring Sand
Delaware Basin Leonard
Bakken/Three Forks – Core
Bakken/Three Forks – Non-Core
* Direct ATROR at Flat Oil Prices. See reconciliation schedules. Oil price at the wellhead, natural gas price $2.50 per MMBtu.
40%15%
Powder River Basin
Wyoming DJ Basin
5% 10%
$50Oil
Excludes Indirect Capital:
- Gathering, Processing and Other Midstream
- Land, Seismic, Geological and Geophysical
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
$40Oil
60%30%
Premium Inventory

EOG_0216-6
Eagle Ford
Bakken/Three Forks – Core
Bakken/Three Forks – Non-Core
Delaware Basin Wolfcamp
Delaware Basin 2nd Bone Spring Sand
Delaware Basin Leonard
DJ Basin
Powder River Basin
Inventory Growing in Quality and Size
5,200
590
950
2,130
1,250
1,600
460
275
≈ 12,500
* Number of remaining net wells as of January 1, 2016. Assumes no further downspacing, acreage additions or enhanced recovery.
** Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells.
Remaining Locations*
Total Premium
549,000
120,000
110,000
168,000
111,000
93,000
85,000
63,000
≈ 1,300,000
Net
Acres
Resource
Potential
(MMBoe)**Play
3,200
620
400
1,300
500
550
210
190
≈ 7,000
1,535
330
695
255
280
80
≈ 3,200

EOG_0216-7
Shift to Premium Locations
Higher Well Productivity
Lower Costs
* Domestic completions, gross oil production.
10.7
13.6
20.9
2014 2015 2016 Est
120-Day Cumulative
Oil Production*
(Bbl per Foot Treated Lateral)

EOG_0216-8
* Based on full-year estimates as of February 25, 2016, excluding acquisitions.
$6.2
$3.6
$2.0
$1.4
$0.8
$0.4
$0.7
$0.3
$0.1
288.9
284.4
270.0
0.00
50.00
100.00
150.00
200.00
250.00
300.00
0
1
2
3
4
5
6
7
8
9
10
2014 2015 2016*
$8.3 Bn
$4.7 Bn
$2.4 - $2.6 Bn
- 44%
- 47%
Oil Production (MBopd)
Gathering, Processing and Other
Exploration and Development Facilities
Exploration and Development

EOG_0216-9
0
5
10
15
20
25
30
35
40
0
100
200
300
400
500
600
700
800
900
EOG A B C D E F G H I J K
Number
of Wells
1st 3 Months
Bopd/Boed 113
Wolfcamp Delaware
Wolfcamp Midland
Natural Gas
Well Count
Average three-month production, normalized to 5,000’ lateral. All horizontal wells from original operator January – October 2015. Gas production converted at 20:1.
Delaware Basin: Culberson, Eddy, Lea, Loving, Reeves and Ward counties. Peer Companies: APA, APC, CXO, XEC.
Midland Basin: Martin, Midland and Upton counties. Peer Companies: APA, CXO, FANG, PE, PXD, RSPP, QEP.
Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2016).

EOG_0216-10
0
20
40
60
80
100
120
140
0 30 60 90 120 150 180 210
Eagle Ford East Wells
Average Cumulative Oil Production*
2012
2013
2014
Eagle Ford West Wells
Average Cumulative Crude Oil Production*
(Mbo)
Producing Days
* Normalized to 6,600-foot lateral.
2015
0
20
40
60
80
100
120
140
0 30 60 90 120 150 180 210
Producing Days
* Normalized to 4,600-foot lateral.
(Mbo)
2012
2013
2014
2015

EOG_0216-11
2015 Completions
4,030 Events /1,000 ft
540 Events /1,000 ft
2010 Completions
Contain Events Closer
to Wellbore
Enhance Complexity to
Contact More Surface Area
Note: Microseismic dots represent well stimulation events during completions.

EOG_0216-12
Lower
Eagle Ford
1. Measure Rock Characteristics and Grade High to Low Quality
2. Overall
Grade
3. Drill

EOG_0216-13
* CWC = Drilling, Completion, Well-Site Facilities and Flowback.
11.5
7.5
6.8
2014 2015 Target
Delaware Basin
Wolfcamp Oil Play
South Texas Eagle Ford Bakken
* Normalized to 5,300’ lateral. * Normalized to 8,400’ lateral.* Normalized to 4,500’ lateral.
6.1
5.7
5.3
2014 2015 Target
8.8
7.2
6.5
2014 2015 Target

EOG_0216-14
2014 1Q15 2Q15 3Q15 4Q15
G&P G&A Taxes Other Than Income Transportation LOE
$12.84*
$13.72
$14.49
$15.39
$17.02
* Excludes one-time expense of $18.7 million related to early leasehold termination. Includes stock compensation
expense and other non-cash items. See reconciliation schedules.

EOG_0216-15
Middle East
Venezuela
Brazil
Russia
Nigeria
Angola
US L48 Conv
Mexico
GOM
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Middle
East/Russia
Medium Cost
Conventional
US
Tight Oil
Deep
Water
High Cost
Non-OPEC
Arctic / Russian
Unconventional
* Price required to achieve 10% Direct ATROR (see reconciliation schedules).
Source: PIRA.
Brent ($/BBL)
50% 22% 5% 16% 7% -% World Supply
Oil Sands
New Marginal Cost of Oil
(≈ $65 - $75)
North Sea
U.S. Tight OilFar East
Russia EOG ($30)
*
EOG Competitive Globally

EOG_0216-16
* Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves booked at December 31, 2015
and prior production from existing wells.
500 MMBoe Net to EOG*
Over-Pressured Oil Play
- Testing 550’ Spacing
Brushy Canyon
Leonard A
Leonard B
1st Bone Spring
2nd Bone Spring
3rd Bone Spring
Upper Wolfcamp
Middle Wolfcamp
Lower Wolfcamp
4,800’
550 MMBoe Net to EOG*
Oil and Combo Play
- 300’- 500’ Spacing
1,300 MMBoe Net to EOG*
Over-Pressured Oil and
Combo Play
- Testing 500’ Spacing
4 Rigs 2016
NewMexico
Texas
Red Hills

EOG_0216-17
168,000 Net Acres Prospective with Multiple Target Zones
- 4,500’ Average Lateral; ≈700’ Spacing
- 2,130 Net Drilling Locations
- Complete ≈60 Net Wells in 2016 vs. 28 in 2015
Estimated Resource Potential 1.3 BnBoe,* Net to EOG
Oil Play
- 110,000 Net Acres, 1,375 Locations
- EUR 750 MBoe, Gross; 600 MBoe, NAR
- CWC** $7.5MM in 2015; Target $6.8MM
Combo Play
- 58,000 Net Acres, 755 Locations
- CWC** $6.6MM in 2015
- Acquired ≈8,000 Net Acres in 4Q 2015
Testing 500’ Spacing and Additional Targets
- First High-Density Completion in 3Q 2015
Average 30-Day IP in 4Q 2015: 1,495 Bopd and 2,215 Boed
- 12 Wells in Wolfcamp Oil and Combo Windows
* Estimated potential reserves net to EOG, not proved reserves. Includes 211 MMBoe of proved reserves booked at December 31, 2015
** CWC = Drilling, Completion, Well-Site Facilities and Flowback.
NGLs
33%
Typical Reeves County
Wolfcamp Combo Well
Gas
36%
Oil
31%
Gas
26%
NGLs
24%
Oil
50%
Typical Northern
Wolfcamp Oil Well

EOG_0216-18
111,000 Net Acres Prospective in Northern Delaware Basin
- 1,250 Net Drilling Locations; ≈ 850’ Spacing
Estimated Resource Potential 500 MMBoe,* Net to EOG
Typical Well
- 4,500’ Lateral
- $6.6 MM CWC** in 2015
- API 43°- 48°
93,000 Net Acres Prospective
- >1,600 Net Drilling Locations; 12 Net Wells Completed in 2015
Estimated Resource Potential 550 MMBoe,* Net to EOG
- Evaluating Oil Mix; Highly Variable Across the Play
Typical Well
- 4,500’ Lateral
- $5.8 MM CWC** in 2015
* Estimated potential reserves net to EOG, not proved reserves. Includes 64 MMBoe of proved reserves in Second Bone Spring Sand and
72 MMBoe in Leonard Shale booked at December 31, 2015 and prior production from existing wells.
NGLs
17%
Typical 2nd Bone
Spring Sand Well
Gas
23%
Oil
60%
Leonard Shale
Second Bone Spring Sand

EOG_0216-19
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
76%
Gas
13%
NGLs
11%
Current Production Mix
2016 Operations
Largest Oil Producer and Acreage Holder in the Eagle Ford
- Average 5 Rigs Operating in 2016
Estimated Resource Potential 3.2 BnBoe;* 7,200 Net Wells
- EUR 450 MBoe/Well, NAR at ≈ 40-Acre Spacing
Precision Targeting
- Lateral Drilling Window 20’ vs. Prior 150’
Acreage 91% Held by Production at YE 2015
30-Day IP (Bopd)
Lepori Unit 4H 2,915
Lightfoot Unit 5H-8H 2,425
Naylor Jones Unit 31 1H 1,780
Focused on Premium Locations
Few Lease Retention Obligations
Testing Stacked-Staggered “W” Patterns 200’ to 250’ Apart
Reducing Operating Costs Through Sustainable Efficiencies
* Estimated potential reserves net to EOG, not proved reserves. Includes 1,032 MMBoe proved reserves booked at December 31, 2015
Crude Oil
Window
Dry Gas
Window
Wet Gas
Window
0 25 Miles
San Antonio
Corpus Christi
Laredo
EOG 608,000 Net Acres
549,000 Net Acres in Oil Window

EOG_0216-20
* Estimated potential reserves net to EOG, not proved reserves. Includes 165 MMBoe proved reserves in Bakken/Three Forks
booked at December 31, 2015. Includes prior production from existing wells.
Focus on Premium Locations in Bakken Core
Complete ≈10 Net Wells in 2016 vs. 25 in 2015
Estimated Resource Potential 1.0 BnBoe*
- 1,540 Net Remaining Locations
- 8,400’ Lateral
- $7.2 MM CWC** in 2015
- 650’ Spacing
Core – Highest Rate-of-Return Drilling
- 120,000 Net Acres
- Bakken Core and Antelope Extension
Non-Core – Future Upside
- 110,000 Net Acres
- Bakken Lite, State Line and Elm Coulee
Canada
Bakken Core
Bakken
Subcrop
Antelope
Extension
Bakken Lite
State Line
Elm
Coulee
EOG Acreage – Bakken/Three Forks
Bakken Oil Saturated
20 Miles
Gas
15%
Remaining Wells
Oil
70%
NGL
15%
Reserve Potential* Gross/Net Net
Area MMBoe, Net EUR (MBoe/Well) Locations
Core 360 745/610 590
Non-Core 400 510/420 950
Existing Wells 260 580/470 560
Total 1,020 2,100
Stanley, ND
Core
Non-Core

EOG_0216-21
Improve Well Productivity with Technology and Innovation
- Precision Lateral Targeting
- High-Density Completions
Lower Costs
- Identify Further Efficiency Improvements
- Enhance Infrastructure
Extend Our Lead
- Add Premium-Quality Drilling Potential Thru Organic Exploration
- Develop Only Premium Locations Going Forward
Maintain a Strong Balance Sheet
- Balance Capex to Cash Flow
- Recycle Inventory Through Asset Sales
Reset Company to Be Successful At Low Prices
Resume High-Return Growth When Prices Improve

EOG_0216-23
(MBod)
8,087
8,244
8,568
8,577 8,678
8,754
8,835
8,959
9,129
9,201
9,428
9,345
9,456
9,653
9,694
9,479
9,315
9,433
9,407
9,449
9,370
9,318
9,197 9,125
9,041
8,987 8,926
8,815
8,687
8,611
8,404
8,309
8,414
8,498
8,509
8,504
8,492
8,476
8,425
8,310
8,247
8,420
8,568
8,603
Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov
* EIA STEO Model Released 2/9/2016.
2014
+1,252
2015
+721
2016
-732
2017
-233
7,998

EOG_0216-24
What Are The Drivers?
Production Increased 2 MMBod January 2013 to May 2015
- 11% Longer Laterals
- 14% Enhanced Completion Technology
- 75% Number of Wells Put to Sales Each Month
Conclusion
- Number of New Wells Put to Sales Most Significant Driver
- Completion Technology Continues to Improve
- Lateral Length Plateauing
Production Will Decline When Operators
Stop Outspending Cash Flow

EOG_0216-25
Asset Quality
- Highly Variable
- Small Sweet Spots
Sustainable Productivity Improvements
- Driven by Operators with the Best Technology
Cost Reductions
- Cyclical for Many Operators – Not Sustainable
Very Few Operators Earn a 10% ATROR at $40 Oil
Only Operators With the Best Assets and Technology
Will Be Successful At Lower Oil Prices
All Operators Are Not Equal

EOG_0216-26
EOG > 2X Industry Average
758
368
0
100
200
300
400
500
600
700
800
EOG Industry
* Eagle Ford, Bakken, Permian, DJ and PRB.
1/1/13 through 6/30/15.
Bopd

EOG_0216-27
* Source: Sanford C. Bernstein & Co. Thousand Club includes wells with 30-day rate over 1,000 Boed in 2015.
Represents 3,600 wells out of 40,000 drilled.
Companies: BHP, CHK, CLR, COG, COP, CXO, DVN, EPE, EQT, HES, MRO, NBL, PXD, RRC, RICE, SM, SWN, TOU, XEC.
0%
20%
40%
60%
80%
100%
0
50
100
150
200
250
300
EOG A B C D E F G H I J K L M N O P Q R S
Well Count
Percent Oil
Well Count Percent Oil

EOG_0216-28
Data as of Sept. 2015.
Peer companies: APC, CHK, CLR, COP, CXO, DVN, MRO, PXD and WLL.
359
250
214 213 212
188
158 155 153
137
EOG A B C D E F G H I
EOG is Industry Leader

EOG_0216-29
9.0%
7.6%
7.3%
6.5%
4.9%
4.3% 4.2% 4.2%
2.8%
2.5%
EOG A B C Peer
Avg
D E F G H
* Source: FactSet, adjusted earnings. Peer companies: APC, APA, CHK, DVN, HES, MRO, NBL and PXD.

EOG_0216-30
$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.
* Indicated annual rate.
Committed to the Dividend
16 Dividend Increases in 17 Years

EOG_0216-31
United Kingdom
East Irish Sea (Conwy)
- First Production March 2016
- Estimated Peak Production – 20 MBopd, Net
Complete One Net Well Late 2016
Limited Capital Spending in 2016
Active Exploration Program
Trinidad
TRINIDAD
ATLANTIC
OCEAN
U(a)
VENEZUELA
4(a)
U(b)
SECC
NORTH
SEA
East
Irish
Sea
Trinidad and Tobago
United Kingdom

EOG_0216-32
Maintain Strong Balance Sheet
- Investment Grade Credit Ratings
Successful Efforts Accounting
Zero Goodwill
$2.7 Billion in Available Liquidity
- $0.7 Billion Cash at December 31, 2015
- $2.0 Billion Credit Facility – Undrawn at December 31, 2015
Increased Dividend 16 Times in 17 Years
- Current Indicated Annual Rate $0.67 per Share
EOG Reserves Within 5% of Independent Engineering Analysis
- Prepared by DeGolyer and MacNaughton
- 28 Consecutive Years
- Reviewed 86% of 2015 Proved Reserves

EOG_0216-33
0
1
2
3
4
5
6
7
8
9
A B C D E F G Peer
Avg
H I J K L M EOG N O
Source: UBS Investment Research. Net debt as of 9/30/15 and 2016E EBITDAX as of January 22, 2016.
Based on $40/Bbl WTI and $2.45/MMBtu.
Peer Group: APA, APC, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OXY, PXD, RRC and SWN.

Eog 0216

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