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NYSE Stock Symbol:
Common Dividend:
Basic Shares Outstanding:
Internet Address:
http://www.eogresources.com
EOG
$0.67
547.5 Million
Investor Relations Contacts
Maire A. Baldwin, Vice President IR
(713) 651-6364, Fax (713) 651-6473
mbaldwin@eogresources.com
David J. Streit, Director IR
(713) 571-4902, dstreit@eogresources.com
Kimberly A. Matthews, Manager IR
(713) 571-4676, kmatthews@eogresources.com
Copyright; Assumption of Risk: Copyright 2014. 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, 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:
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the timing and extent of changes in prices for, 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 optimize 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, 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 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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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 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). As noted above, 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, 2013, 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.
2Q 2014
Delivered 33% YOY U.S. Crude Oil Growth and 17% Total Production Growth
Raised Common Stock Dividend 34%; Second Increase in 2014
Added Delaware Basin Oil Play, 2nd Bone Spring Sand to Drilling Inventory
Strong Spacing and Productivity Results from Leonard Shale
Grew Non-GAAP EPS 38%, EBITDAX 19% and Discretionary Cash Flow 18%*
Net Debt-to-Total Cap Ratio 22% at June 30, 2014*
YTD 2014
Added ≈ 10 Years of High-Return Drilling Inventory in DJ and Powder River Basins
Increased Eagle Ford Reserves** by 45% - 2.2 BnBoe
- Added ≈ 1,600 High ROR Net Drilling Locations
- Expect Continued Production Growth Next 10+ Years
3.2 BnBoe, Net to EOG
* Certain financial metrics reflected are ‘as Adjusted.’ See reconciliation schedules.
** Estimated potential reserves, not proved reserves.
EOG_0914 v3-1
Best Horizontal Crude Oil Assets in North America
Peer-Leading Organic Crude Oil Production Growth
- 2011
+52%
- 2012
+39%
40% 4-Year CAGR
- 2013
+40%
- 2014E*
+29%
2014E ROE/ROCE > Average of Majors, Integrateds and Independent E&Ps
Exploration and Technology Focus Increases Drilling Inventory
- Identify New Plays
- Expand and Improve Existing Plays
- Completion Technology Leader
Efficient and Innovative Operator
- EOG Self-Sourced Sand Reduces Completion Costs
- EOG Crude-by-Rail Infrastructure Provides Market Flexibility
Disciplined, Return-Focused Capital Allocation
Rate-of-Return Focus Drives Shareholder Value and Growth
* Based on mid-point of full-year 2014 production estimates as of August 5, 2014.
EOG_0914 v3-2
Exploration and Technology Focus
Exploration
- Identify Additional Targets in Existing Plays
- Generate New Plays Internally
- Capture Premier Acreage
- Early-Mover Strategy Drives Low Leasing Costs
Technology Application
- EOG Completion Innovation
- Increase Drilling Density/Down-Spacing to Maximize NPV
- Reduce Per-Unit Operating Costs
Inventory Growing in Both Size and Quality
- Added 2,300 Net Drilling Locations 1H 2014
2x 2014 Drilling Program
- New Inventory Return >60% Direct ATROR*
- New Resource Plays Still Growing in North America
Core Competency and Sustainable Competitive Advantage
* See reconciliation schedules.
EOG_0914 v3-3
Direct After-Tax Rate of Return*
100%
Eagle Ford
Bakken/Three Forks
Delaware Basin Leonard
Powder River Basin Parkman
Wyoming DJ Basin Codell
Powder River Basin Turner
Delaware Basin 2nd Bone Spring Sand
Delaware Basin Wolfcamp
60%
30%
Wyoming DJ Basin Niobrara
Midland Basin Wolfcamp
Barnett Combo
Dry Gas
* See reconciliation schedules.
EOG_0914 v3-4
2014*
Gathering,
Processing
and Other
10%
Majority of Capex Increase Going to Top Plays:
Eagle Ford, Bakken, Permian and Rockies
10
Exploration and
Development
Facilities
11%
9
8
$8.1 to $8.3 Bn
$7.1 Bn
7
6
5
Exploration &
Development
E&P
Facilities
Exploration &
Development
Gathering,
Processing
and Other
4
3
Exploration and
Development
79%
2
1
0
2013
2013
Exploration and
Development
E&D Facilities
Gathering,
Processing &
Other
2014E*
2014E*
2014E Capex ≈ $8.1 to $8.3 Bn* Including Facilities and Midstream
* Based on full-year estimates as of August 5, 2014, excluding acquisitions.
EOG_0914 v3-5
Tactical - 2014
High Return Oil Growth
Increased Dividend Twice
- February +33%
- August
+34%
Strategic - 2015+
High Rate-of-Return Capital Expansion
- Increase E&P Activity in Highest ATROR Plays
- Increase High-Return Drilling Inventory through Exploration
Consider Further Dividend Increases
Maintain Strong Balance Sheet
EOG_0914 v3-6
Extending Our Lead
400
350
EOG
300
OXY
250
CVX
200
150
100
50
0
Jan
May
2010
Sep
Jan
May
Sep
Jan
2011
May
Sep
2012
Jan
May
Sep
2013
Jan
2014
* Source: IHS data through April 2014. Gross operated oil production.
EOG_0914 v3-7
70
60
50
40
30
20
10
Co. 12 Co. 13
Chesapeake Energy
Marathon Oil
Average
Co. 8 Co. 9 Co. 10 Co. 11
Denbury Resources
Apache Corp
Co. 7
Cimarex Energy
Peer
Avg.
Noble Energy
Co. 6
Newfield Exploration
Co. 5
Concho Resources
Co. 4
Pioneer Resources
Co. 3
Continental Resources
Co. 2
Devon Energy
Co. 1
Anadarko Petroleum
-10
EOG Resources
EOG
Hess Corporation
0
Sources: Company filings, First Call. Production adjusted for Acquisitions/Dispositions to reflect ‘Organic’ production only.
Peers include: APA, APC, CHK, CLR, CXO, DNR, DVN, HES, MRO, NBL, NFX, PXD, XEC.
EOG_0914 v3-8
300
≈ 285
250
65
Actual
220
200
62
158
150
113
100
75
50
55
20
2009
2010
45
38
0
2011
2012
2013
2014E*
* Based on mid-point of full-year 2014 production estimates as of August 5, 2014.
EOG_0914 v3-9
2014
Net Wells
520
Oil
Eagle Ford
Drilling
Years*
12
Bakken/Three Forks
80
8
Delaware Basin Leonard/Bone Spring
40
40+
DJ Basin
39
12
Powder River Basin
34
8
Delaware Basin Wolfcamp
14
75+
Midland Basin Wolfcamp
10
50+
Combo
>15 Years of Drilling
* Based on current technology and 2014 drilling program. Assumes no further downspacing or enhanced recovery.
EOG_0914 v3-10
2011
2012
2013
2014E*
2015E - 2017E
Crude Oil and Condensate
52%
39%
40%
29%
NGLs
39%
32%
17%
18%
48%
37%
34%
27%
Continued
Best-in-Class
Double-Digit
Growth
North American Gas
-7%
-9%
-13%
-3%
Flat
Other Gas**
--%
9%
-6%
3%
Flat
9.4%
10.3%
9.4%
14%
Total Company Liquids
Total Company
Highest Annual Organic Crude Oil Growth of
Large Cap E&P Peer Group Over Last Four Years
* Based on the mid-point of full-year 2014 production estimates as of August 5, 2014. Liquids converted at 6:1 ratio.
** Contingent on Trinidad market conditions.
EOG_0914 v3-11
79%
76%
≈ 89%
88%
86%
NGLs
72%
71%
59%
53%
Oil
47%
41%
29%
21%
28%
24%
14%
2006
2007
2008
2009
2010
2011
Liquids (Crude Oil and NGLs)
2012
12%
2013
≈ 11%
2014E*
Natural Gas
* Based on NYMEX 2014 Current Oil to Gas Prices as of July 11, 2014 and mid-point of full-year 2014 production estimates as of August 5, 2014.
EOG_0914 v3-12
$43.31
$40.14
$34.11
$29.29
$20.04
2010
2011
2012
2013
2Q YTD
* Wellhead Revenues for Crude Oil and Condensate, Natural Gas Liquids and Natural Gas less Lease and Well Costs, Transportation Costs, Exploration Costs, Dry Hole Costs, General and
Administrative, Taxes Other than Income and Net Interest Expense plus any Net Cash Receipts from (Payments on) Settlement of Commodity Derivative Contracts, calculated on a per unit basis.
EOG_0914 v3-13
ROCE
ROE
18.1%
14.5%
15.6%
12.4%
11.8%
9.4%
2012*
2013*
2014E**
2012*
2013*
2014E**
* See reconciliation schedule.
** Goldman Sachs estimates July 25, 2014, $96.50 WTI and $4.25 Henry Hub in 2014.
EOG_0914 v3-14
ROCE*
ROE*
18.1%
15.6%
14.5%
13.7%
14.1%
12.7%
12.4%
10.0%
13.6%
11.7%
11.2%
9.5%
8.9%
1
2013
2
2014E
1
2013
E&P
Integrateds
Majors
EOG
3.7%
E&P
Integrateds
Majors
EOG
E&P
Integrateds
Majors
EOG
3.4%
E&P
Integrateds
Majors
EOG
6.6%
2
2014E
* Source: Goldman Sachs, May/July 2014 estimates. Majors: BP, CVX, RDS, TOT, XOM.
Integrateds: COP, HES, MRO, MUR, OXY. E&Ps: APC, APA, CHK, DVN, NBL, NFX, PXD. Also see EOG reconciliation schedules.
EOG_0914 v3-15
Committed to the Dividend
$0.70
$0.67
Increased Dividend Twice in 2014
16 Dividend Increases in 15 Years
$0.60
$0.50
$0.50
$0.40
$0.375
$0.29
$0.30
$0.31
$0.32
2010
2011
$0.34
$0.255
$0.18
$0.20
$0.12
$0.10
$0.03 $0.035 $0.04
$0.04
$0.05
$0.06
1999
2002
2003
2004
$0.08
$0.00
2000
2001
2005
2006
2007
2008
2009
2012
2013
2014*
2014**
Note: Dividends adjusted for 2-for-1 stock split effective March 1, 2005 and March 31, 2014.
* Indicated annual rate effective April 2014.
** Indicated annual rate effective October 2014.
EOG_0914 v3-16
140
API Gravity
120
50 to 100
48° to 50°
100
45° to 48°
35° to 45°
80
0 to 35°
60
40
20
0
EOG
EOG
1
Conoco Phillips
2
3
Devon
4
5
Anadarko
6
7
EP Energy
8
9
BHP
10
* IHS data January 2011 through April 2014. Cumulative gross crude oil and condensate production for producers with
≥20 MMbo. Producers 1 -10 include: APC, BHP, CHK, COP, DVN, EPE, FCX (ECA), MRO, MUR, PXD.
EOG_0914 v3-17
Largest Oil Producer and Acreage Holder in the
Eagle Ford
- 2Q 2014 Oil Production Up 46% YOY
Continued Outstanding Well Results Across Acreage
IP Rate
County
Well
Bopd
Gonzales
Boothe Unit 11H
4,570
DeWitt
Justiss Unit 13H
4,130
Karnes
McCoy Unit 2H
5,415
Atascosa
Pacheco Unit 1H
1,840
McMullen
Naylor Jones Unit 43 W2H
2,030
La Salle
Naylor Jones Unit 127 2H
2,500
Window
Crude Oil
Wet Gas
Dry Gas
Total
Net Acres
564,000
22,000
46,000
632,000
San Antonio
Crude Oil
Window
Wet Gas
Window
Dry Gas
Window
Corpus Christi
Laredo
0
25 Miles
EOG 632,000 Net Acres
Gas
12%
NGLs
10%
Oil
78%
Current Production Mix
EOG_0914 v3-18
Big Fields Get Bigger
Increased Estimated Potential Reserves* by 45%
Increased Total Well Count to 7,200, Net Locations
- ≈ 12-Year Inventory of >60% ATROR** Drilling Locations
- Average 40-Acre Spacing Across Acreage
Reserve Potential* Since Discovery
(BnBoe)
3.2
Increased EUR to 450 MBoe/Well, NAR
2.2
Third Reserve Increase in Four Years
1.6
2014 Operations
0.9
Well Economics >100% Direct ATROR**
Continue to Improve Wells with Completion Techniques
Plan to Drill ≈ 520 Net Wells, 26-Rig Program
Apr 2010
Feb 2012
Feb 2013
Feb 2014
EOG Self-Sourced Sand Continues to Increase Efficiencies
and Lower Well Costs
Targeting $5.7 MM CWC with Larger Fracs and Longer Laterals
* Estimated potential reserves, not proved reserves. Includes 765 MMBoe proved reserves booked at December 31, 2013.
** See reconciliation schedule.
EOG_0914 v3-19
April 2010
Wells/Section (Unit)
5
Feb 2012
10
Feb 2013
Feb 2014
10 - 16
16
Per Well
Spacing (Acres)
130 Acres
65 Acres
40-65 Acres
≈40 Acres
Est. Reserves, NAR
320 MBoe
450 MBoe
400 MBoe
450 MBoe
$5.25 MM
$6 MM
$6 MM
$5.7 MM
80%
130%
100%
100%+
CWC
Direct ATROR*
Per Section (640 Acres)
Est. Reserves
NPV10
1.6 MMBoe
$23 MM
Total Net Potential Reserves
0.9 BnBoe
4.5 MMBoe
$69 MM
1.6 BnBoe
6.4 MMBoe
$98 MM
2.2 BnBoe
7.2 MMBoe
$114 MM
3.2 BnBoe**
* See reconciliation schedule.
** Estimated potential reserves, not proved reserves. Includes 765 MMBoe proved reserves booked at December 31, 2013.
EOG_0914 v3-20
Average Cumulative Crude Oil Production*
for Eagle Ford West Wells
(Mbo)
45
2014 YTD
40
2013
35
30
2012
2011
25
20
15
10
5
0
0
10
20
30
40
50
60
Producing Days
* Normalized to 5,300’-foot lateral.
EOG_0914 v3-21
Atascosa County
Pacheco Unit 1H
1,840 Bopd
Dicke A Unit 4H
1,810 Bopd
Gonzales County
Zimmerman Unit 14H
3,800 Bopd
Boothe Unit 11H, 16H
4,570 and 3,245 Bopd
San Antonio
DeWitt County
Justiss Unit 11H – 13H
3,900 – 4,130 Bopd
Karnes County
Wolf Unit 6H - 9H
3,160 - 3,600 Bopd
McCoy Unit 2H, 1H
5,415 and 5,290 Bopd
La Salle County
Laurette Unit 1H
2,040 Bopd
Naylor Jones Unit 127 1H – 3H
2,200 – 2,500 Bopd
McMullen County
Naylor Jones Unit 43 West 2H
2,030 Bopd
0
25 Miles
EOG 564,000 Net Acres in Crude Oil Window
EOG_0914 v3-22
Transformed into High ROR Crude Oil Growth Play
Canada
New Frac Technology Improves Recovery and Returns
Stanley, ND
State Line
Delivering 100% Direct ATROR* from Core and Antelope
Bakken
Lite
- Bakken Core ≈ 90,000 Net Acres
- Antelope Extension ≈ 20,000 Net Acres
Elm
Coulee
86 MBoed Gross Production YE 2013, 38% Increase YOY
Bakken
Subcrop
Strong Core Wells
- Wayzetta 43-0311H
- Wayzetta 44-0311H
- Wayzetta 45-0311H
Bakken Core
Parshall 1-36H
Discovery Well
1,505 Bopd
2,410 Bopd
2,690 Bopd
20 Miles
EOG Acreage – Bakken/Three Forks
Bakken Oil Saturated
Operations
2014 Focus on Core and Antelope; 6 Rigs
80 Net Wells Planned for 2014, Target $9.0 MM CWC
Continued Success with 1,300’ Spacing
- Testing Further Downspacing to Maximize NPV
EOG Self-Sourced Sand Now Fully Integrated
Testing Three Forks Intervals in 2H 2014
* See reconciliation schedules.
Note: 221 MMBoe proved reserves in Bakken/Three Forks booked at December 31, 2013.
Antelope
Extension
Gas
2%
NGLs
6%
Gas
11%
Oil
92%
Core Well
NGLs
11%
Oil
78%
Antelope Well
EOG_0914 v3-23
Leonard A
Texas
New Mexico
Brushy Canyon
Leonard B
Net to EOG*
MMboe
High ROR Oil Play
- Spacing Tests Underway
550 MMboe
Over Pressured Oil Play
- Strong Initial Tests
Evaluating
High ROR Combo Play
- Spacing Tests Underway
800 MMboe
4,800’
1st Bone Spring
Leonard/
Bone Spring
2nd Bone Spring
3rd Bone Spring
Wolfcamp
Upper Wolfcamp
Middle Wolfcamp
Lower Wolfcamp
* Estimated potential reserves, not proved reserves.
EOG_0914 v3-24
Drilled and Participated in 16 Wells Since 2013
- Wells Producing from 500 - 1,400 Bopd
- API = 45°
Target Well Economics for 4,500’ Lateral
- EUR ≈ 500 MBoe/Well, Gross
- $6 MM CWC and 100% Direct ATROR*
- Plan to Drill 9 Wells in 2014
Beneath 73,000 Net-Acre Leonard Position
- Evaluating and Delineating Acreage
NGLs
14%
Gas
16%
Oil
70%
Typical Red Hills
2nd Bone Spring Sand Well
Integrating Self-Sourced Sand
Applying EOG Advanced Completion Technology
First EOG Wells Delivering Very Good Results and Economics
IP Rates Lea County
Bopd + NGLs Bpd + MMcfd
Mars 3 State #1H
1,270
150
1.1
Jolly Roger 16 State #1H
1,450
210
1.5
Lateral
3,300’
4,500’
* See reconciliation schedule
EOG_0914 v3-25
73,000 Net Acres
EOG’s 3rd Best ROR Play
NGLs
26%
Both a Development and Exploration Area
Estimated Reserve Potential* 550 MMBoe, Net to EOG
Gas
24%
Target Well Economics for 4,400’ Lateral
- 500 MBoe EUR/Well, Gross; 400 MBoe, NAR
Oil
50%
Typical Leonard
Well
- $5.0 MM CWC and ≈ 100% Direct ATROR**
1,600+ Net Drilling Locations
- 2-Rig Drilling Program
- Testing Multiple Zones and Spacing Patterns
Recent ‘A’ Zone Downspacing and ‘B’ Zone Well Results – Peak Rates
Dragon 36 State (4 Wells)
Gemini (3 Wells)
Mercury State #1H
Mercury State #2H
Falcon 25 Fed #2H
Zone
A
A
A
B
B
Bopd
+
1,100 - 1,500
1,120 - 1,530
1,700
1,630
920
NGLs Bpd
195 - 235
185 - 220
360
230
120
+
MMcfd
1.1 - 1.3
1.0 - 1.2
2.0
1.3
0.7
* Estimated potential reserves, not proved reserves. Includes 63 MMBoe of proved reserves booked at December 31, 2013.
** See reconciliation schedule.
EOG_0914 v3-26
Completed Well Costs*
($MM)
Average Oil IP Rates*
(Bopd)
$6.9
$6.4
1,263
$5.3
$5.0
691
2011
2012
2013
2014
YTD
2011
737
2012
783
2013
2014
YTD
* Normalized to ≈ 4,400-foot lateral.
EOG_0914 v3-27
Better Wells on Tighter Spacing
(Mbo)
(Feet)
45
40
1,200
1,032’
15%
911’
35
1,000
17%
14%
30
800
836’
25
600
20
554’
400
15
10
200
5
0
0
2011
2012
2013
Average 80-Day Cumulative Oil*
2014 YTD
Well-Spacing
* Normalized to 4,400-foot lateral.
EOG_0914 v3-28
134,000 Net Acres
Multiple Pay Targets
Estimated Reserve Potential* 800 MMBoe, Net to EOG
Target Well Economics for 4,500’ Lateral, Reeves County
- 900 Mboe EUR/Well, Gross; 700 MBoe, NAR
- $6.5 MM CWC and 70% Direct ATROR**
1,100+ Net Drilling Locations
- Plan to Drill 14 Net Wells in 2014
- 1 Rig
Testing 750’ Spacing Pattern in Same Zone
- Good Initial Results
Recent Well Results – Peak Rates (Reeves County)
State Apache 57 (3 Wells)
State Harrison Ranch 56 (2 Wells)
State Apache 57 #1107H
Zone
Upper
Upper
Upper
Oil
31%
NGLs
33%
Gas
36%
Typical Delaware
Wolfcamp Well
Bopd
+ NGLs Bpd + MMcfd
590 - 865
200 - 265
1.3 - 1.7
660, 665
275, 450
1.8, 2.9
1,600
460
3.0
* Estimated potential reserves, not proved reserves. Assumes estimated 2% - 3% recovery factor and includes 21 MMBoe of proved reserves booked
at December 31, 2013.
** See reconciliation schedules.
EOG_0914 v3-29
10 Years of High-Return Drilling Inventory in the Rockies
Basin
DJ
Powder River
Play
Net
Acres
Net
Locations
Net to EOG*
MMboe
%
Crude Oil
API
Direct
ATROR**
Codell
85,000
225
125
78%
36
>100%
Niobrara
50,000
235
85
71%
35
≈45%
Parkman
30,000
115
75
69%
41
>100%
Turner
63,000
160
115
34%
44- 56
≈100%
735
400
Total
* Estimated potential reserves, not proved reserves.
** See reconciliation schedules.
EOG_0914 v3-30
Targeting Codell and Niobrara, 39 Net Wells
Target Economics for 9,000 Foot Laterals
Codell
Niobrara
EUR/Well (Mboe)
Gross
695
430
NAR
560
355
CWC ($MM)
$7.3
$8.0
Direct ATROR*
>100%
≈45%
Spacing (Feet)
Current
1,300’
880’
Testing
710’
710’
Codell – Recent Well IPs (9,000’ Laterals)
Bopd
Jubilee 103-0433H
1,400
Windy 504-1806H
1,400
Jubilee 513-0820H
1,325
Jubilee 584-1705H
1,180
Pole Creek 525-2413H
1,165
Jubilee 586-1705H
1,145
Niobrara – Initial Well IPs (3,600’ Laterals)
Bopd
Windy 01-18H
700
Jubilee 30-07H
670
Jubilee 69-04H
700
Jubilee
513-0820H
Pole Creek
525-2413H
Jubilee
69-04H
Jubilee
30-07H
Jubilee
103-0433H
Jubilee
584-1705H
586-1705H
Windy
01-18H
Windy
504-1806H
Gas
7%
NGLs
15%
Oil
78%
Codell Well
NGLs
19%
Gas
10%
Oil
71%
Niobrara Well
* See reconciliation schedules.
EOG_0914 v3-31
Wyoming
Targeting Parkman and Turner, 34 Net Wells
Lateral Length
EUR/Well (Mboe)
Gross
NAR
CWC ($MM)
Direct ATROR*
Spacing (Feet)
Current
Parkman
7,300’
Turner
8,200’
850
680
$5.0
>100%
860
705
$7.5
≈100%
Mary’s Draw
419-16H
1,300’
1,655’
Mary’s Draw
404-21H
Bolt
404-05H
Bolt
429-05H
Bolt
22-05H
Blade
01-2116H
Mary’s Draw
468-34H
Parkman – Recent Well IPs (4,000’ Laterals)
Mary’s Draw 404-21H
Mary’s Draw 468-34H
Bopd + Rich Gas
1,045
305 Mcfd
980
330 Mcfd
NGLs
11%
Turner – Recent Well IPs
Blade 01-2116H
Bolt 22-05H
Bopd
746
686
NGLs
+ Bpd +
112
132
GasGas
43%43%
Gas
20%
Mcfd
1,046
1,230
Lateral
6,500’
4,200’
Oil
69%
Parkman Well
Oil
Oil
34%
34%
NGLs
23%
NGLs
23%
Turner Well
* See reconciliation schedules.
EOG_0914 v3-32
Play
Haynesville
Marcellus, Bradford County
S. Texas Frio/Vicksburg
Eagle Ford
Barnett
Uinta
Horn River
Net
Acres
Type
143,000
Gas and Combo
46,000
195,000
68,000
Gas
Gas and Combo
Gas
298,000
Gas and Combo
94,000
Gas and Combo
127,000
Gas
Acreage Holds Option Value for Natural Gas Price Recovery
EOG_0914 v3-33
Trinidad
Trinidad and Tobago
ATLANTIC
OCEAN
Expect Full Contract Deliverability in 2014
TRINIDAD
2H 2014 Drilling Program to Maintain Future
Deliverability
- Plan to Drill 3 Net Wells
4(a)
U(a)
U(b)
SECC
VENEZUELA
United Kingdom
United Kingdom
Central
Graben
East Irish Sea (Conwy)
- First Production Early 2015
- Estimated Peak Production – 20 MBopd, Net
East
Irish
Sea
NORTH
SEA
Southern
Gas Basin
EOG_0914 v3-34
Maintain Low Net Debt-to-Total Cap Ratio
- Credit Ratings – Moody’s A3 / S&P ASuccessful Efforts Accounting
Zero Goodwill
Two Dividend Increases in 2014
- 16 Increases in 15 Years
EOG Reserves Within 5% of Independent Engineering Analysis
Prepared by DeGolyer and MacNaughton
- 26 Straight Years
- Reviewed 82% of Proved Reserves for 2013
EOG_0914 v3-35
Crude Oil*
2014
August 1 to December 31
Bbld
$/Bbl
194,000
$96.19
MMBtud
$/MMBtu
330,000
$4.55
175,000
$4.51
Natural Gas*
2014
September 1 to December 31
2015
January 1 to December 31
* As of August 5, 2014. Does not reflect options held by certain counterparties to extend current crude oil derivative contracts or to enter into
additional natural gas derivative contracts. See reconciliation schedules for details.
EOG_0914 v3-36
Rate-of-Return Focused Investments Drive Shareholder Value and Growth
Peer-Leading Organic Crude Oil Production Growth
2014E ROE/ROCE > Average of Majors, Integrateds and Independent E&Ps
Exploration Focus
- Premier Acreage Positions
- Early-Mover Strategy Drives Low Leasing Costs
Completions Designed In-House Using Self-Sourced Materials
- Highest Productivity Wells in Industry
- Lowest Completed Well Costs
- Still Making Advancements
Peer-Leading Discretionary Cash Flow Growth
- 15 Years of Dividend Growth
- Strengthening Balance Sheet
EOG_0914 v3-37
Copyright; Assumption of Risk: Copyright 2014. 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, 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:
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the timing and extent of changes in prices for, 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 optimize 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, 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 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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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 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). As noted above, 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, 2013, 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.