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2
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Certain statements in this presentation contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933and Section 21E of the Securities and Exchange Act of 1934 including, without limitation, expectations, beliefs, plans and objectives regardingproduction and exploration activities. Any matters that are not historical facts are forward-looking and, accordingly, involve estimates,assumptions, risks and uncertainties, including, without limitation, risks, uncertainties and other factors discussed in our most recently filedAnnual Report on Form 10-K, recent Quarterly Reports on Form 10-Q, recent filed Current Reports on Form 8-K available on our website,http://www.apachecorp.com/, and in our other public filings and press releases. These forward-looking statements are based on ApacheCorporation’s (Apache) current expectations, estimates and projections about the company, its industry, its management’s beliefs and certainassumptions made by management. No assurance can be given that such expectations, estimates or projections will prove to have beencorrect. A number of factors could cause actual results to differ materially from the projections, anticipated results or other expectationsexpressed in this presentation, including, Apache’s ability to meet its production targets, successfully manage its capital expenditures and tocomplete, test and produce the wells and prospects identified in this presentation; to successfully plan, secure necessary governmentapprovals, finance, build and operate the necessary infrastructure and LNG plants; and to achieve its production and budget expectations on its
projects.
Whenever possible, these “forward-looking statements” are identified by words such as “expects,” “believes,” “anticipates,” “projects,” andsimilar phrases. Because such statements involve risks and uncertainties, Apache’s actual results and performance may differ materially fromthe results expressed or implied by such forward-looking statements. Given these risks and uncertainties, you are cautioned not to place unduereliance on such forward-looking statements, which speak only as of the date hereof. Unless legally required, we assume no duty to updatethese statements as of any future date. However, you should review carefully reports and documents that Apache files periodically with theSecurities and Exchange Commission.
Cautionary Note to Investors: The United States Securities and Exchange Commission ("SEC") permits oil and gas companies, in their filings withthe SEC, to disclose only proved, probable, and possible reserves that meet the SEC's definitions for such terms. Apache may use certain termsin this presentation, such as “resource,” “resource potential,” “net resource potential,” “potential resource,” “resource base,” “identifiedresources,” “potential net recoverable,” “potential reserves,” “unbooked resources,” “economic resources,” “net resources” and other similarterms that the SEC guidelines strictly prohibit Apache from including in filings with the SEC. Such terms do not take into account the certaintyof resource recovery, which is contingent on exploration success, technical improvements in drilling access, commerciality and other factors,and are therefore not indicative of expected future resource recovery and should not be relied upon. Investors are urged to consider carefullythe disclosure in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, available from Apache atwww.apachecorp.com or by writing Apache at: 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056 (Attn: Corporate Secretary). You can alsoobtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.
FORWARD-LOOKING STATEMENTS
3
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STRATEGIC OVERVIEW
Steve Farris
February 26, 2014
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MBOE/D, Net
STRATEGIC REPOSITIONING FOR NEXT GROWTH PHASE
5
GOM
International
North America
Onshore
N.A. Onshore
Liquids
Expansion
International
Expansion
International
Entry
Note: 2013 Pro forma: after GOM Shelf sale, Egypt JV, expected Argentina sale and Canada property sales 2013 + 2014 targeted.
537
Repositioned for
Next Growth Phase
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Focused portfolio: growth assets, free cash flow assets
Powered by North America onshore
Play to our core strength in operational execution
Production growth: visible, predictable, repeatable
Rate of return: liquids focus, relentless execution
Internally funded capital program ex LNG
Return capital to shareholders
REPOSITIONING OBJECTIVES
6
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DECISIVE STEPS TAKEN IN 2013-14
7
Delivered portfolio repositioning
GOM Shelf sale (retaining 50% of exploration portfolio)
Egypt JV with Sinopec
Argentina sale1
Canada transitioning
Accelerated North America liquids growth: +34% in 2013
Returned capital to shareholders
Dividend increase: 18% in ‘13, 25% in ’14
Repurchased $1.2 BN of stock thus far
Strengthened balance sheet
$2.6 BN debt reduction, entered 2014 with $1.9BN of cash
Note 1. Argentina sale expected to close 1Q 2014.
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7%
10%
3%
13%
18%
20%
11%
8% 8%
8
GOM Shelf
50% Liquids 58% Liquids
20091
Note 1. 2009 production has been reduced by Egypt tax barrels of 47 MBOE/D for comparability.Note 2. Pro forma is 2013 less divested volumes from GOM Shelf, Canada, including 2014 proposed sales, Egypt w/o tax barrels excluding noncontrolling interest and expected
Argentina sale.
537 MBOE/D 537 MBOE/D
60% North
America
Onshore
North America Onshore
GOM
International
REPOSITIONED PORTFOLIO
GOM
17%
24%
6%
14%
2%
13%
14%
11%
2013 Pro Forma2
34% North
America
Onshore
14%
19%
23%
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9
APACHE TODAY
Proven leader in oil-levered North America growth:
#1 growth generator in Permian + Anadarko basins
Strongly positioned to drive the company’s growth
Major free cash flow assets:
Egypt, North Sea, Australia: #1 positions
LNG: incremental, company-driving free cash flow
Industry shift to execution:
APA’s core strength and track record
Built to last: Rate of return focus
Internally funded capital program ex LNG
Sustainable growth: resource depth, repeatable running room
Financial strength to execute our strategy
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10
#1 GROWTH GENERATOR IN THE PERMIAN BASIN
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APA A B C D E F
Average MBOE/D Added in 2013
Note: Peers include COP, CXO, DVN, OXY, PXD, and XEC; data sourced from company investor presentations and Wall Street research.
3.3MM acres (1.7MM net)
127 MBOE/D in 2013
22% liquids growth, 17% BOE growth
4.8BN BOE APA net evaluated
resource (26% increase from 2012)
Midland
BasinDelaware
Basin
Central
Basin
Platform
MBOE/D, Net
19
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1.8MM acres (1MM net)
91 MBOE/D in 2013
122% liquids growth, 49% BOE growth
#1 driller in deep portion of basin
Multi-play portfolio: Granite Wash,
Tonkawa, Cleveland, Marmaton
5.2BN BOE APA net evaluated resource
11
MULTI-PLAY ANADARKO BASIN GROWTH ENGINE58 YEAR TRACK RECORD
Horizontal Well Liquids Drive APA’s Growth
45
61
91
0
10
20
30
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50
60
70
80
90
100
2011 2012 2013
MBOE/D, Net
% Liquids 20% 34% 50%
APA acreage
15 mi
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0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
2009 2010 2011 2012 2013 Q4'13
Permian Central
0
50,000
100,000
150,000
200,000
250,000
2009 2010 2011 2012 2013 Q4'13
Permian Central
12
Liquids Track Record (B/D) BOE/D Track Record
MULTI-YEAR TRACK RECORD: PROVEN DRIVERS
89
227
39
151
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13 Note: Peers include: Anadarko, Chesapeake, Devon, EOG, and Occidental. Latest 2013 company guidance used for companies who have not yet reported full 2013 results.
34% 34%
26%
21%
15%
5%
APA A B C D E
LEADER IN NORTH AMERICA LIQUIDS GROWTH
2013 % Growth
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14
Australia
Sustainable free cash flow generation
>$1 BN in 2014
Large, stable oil production
Brent pricing advantage
Exploration, Egypt horizontals
Visible growth project pipeline
2014 Avg.: 18-25 MBOED
Premium domestic gas market
Wheatstone LNG
Exploration with infrastructure
North Sea
Apache
AcreageOil FieldGas Field
Egypt, North Sea Australia
BERYL
FORTIES
INTERNATIONAL:
SUSTAINABLE FREE CASH FLOW WITH UPSIDE
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15
WHEATSTONE LNG
First production in 2016
85% contracted (oil-based pricing)
8.9 MMTPA LNG
APA = 13% LNG operated by Chevron, Apache
operates its upstream
Illustrative Free Cash Flow Profile
Note 1. Pre-tax, based on $100/BBL Brent oil price. Assumes capital costs and timing of project start-up are as currently planned.
-1,500
-1,300
-1,100
-900
-700
-500
-300
-100
100
300
500
700
900
1,100
2014 2015 2016 2017 2018 2019 2020 2021
Pre-Tax Cash Flow
Capital Investment
Pre-Tax Cash Flow at $100 Brent1
$MM 20-YearContracts
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16
A
KITIMAT LNG
Commercialize 50 TCF gross discoveries in Liard, Horn River Basins
Most advanced LNG project in Canada
10 MMTPA LNG, APA currently 50%
Apache operates upstream 2013: Chevron became operator of downstream
2014: Apache to right-size Kitimat LNG participation
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15-18% North America onshore liquids growth
Driven by oil
Double-digit global liquids growth
5-8% global BOE production growth
Capex ex LNG = within cash flow
17
2014 EXPECTATIONS
Note: All growth rates based on 2013 pro forma production. Excluding Egypt tax barrels and noncontrolling interest.
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18 Note 1. Includes E&D and GTP capital. Excludes non oil and gas capital of $0.2 billion and LNG projects. Egypt excludes noncontrolling interest.Note 2. Kitimat LNG investment = up to $1.0 billion in 2014 based on current 50% participation. APA to right-size Kitimat LNG participation in 2014.
Canada
$0.6 Bn
Central
$1.7 BN
GC Onshore
$0.5 Bn
2014 CAPITAL PLAN North America Onshore
GOM
International
Additional Investment in LNG: Wheatstone $1.4 Bn
Kitimat2 TBD
Permian
$2.6 Bn
64% North
America
Onshore
E&P Capital = $8.5 Bn1
Australia
$0.8 BnNorth Sea
$0.9 Bn
Egypt
$0.9 Bn
GOM
$0.5 Bn
20%
31%6%
7%
6%
11%
11%9%
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WE ARE ALREADY DELIVERING IT
19
2013 Production Growth
Note 1. All growth rates exclude Egypt tax barrels and noncontrolling interest. 2013 continuing operations.Note 2. 2014 Plan: after GOM Shelf sale, Egypt JV, expected Argentina sale and Canada property sales (2013 + 2014 targeted).
6.4%
-1.3%
8%
5%
2014 Plan2
Reported1 Retained
Assets
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RETURNING CAPITAL TO SHAREHOLDERS
20
Dividend
13% per share growth in 2012
18% per share growth in 2013
25% per share growth in 2014
Strategy: consistently grow our dividend at attractive rates
Buyback
$1.2 BN 2013 + 2014 YTD
Our shares remain a compelling value opportunity at
current price levels
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700
2013PF 2014E 2015E 2016E
MBOE/D, Net
HIGH-GRADED PORTFOLIO:
ENHANCED PREDICTABILITY
21
North America Onshore
GOM
International
Note: Pro forma for divested volumes from GOM Shelf, Canada, Egypt and expected Argentina sale. Egypt excludes tax barrels and after noncontrolling interest.Note 1. Wheatstone free cash flow before tax.
2017: Wheatstone LNG1
At full ramp-up:
>$1 BN annual free cash flow 30 MBOE/D, net
No decline for decades
Enhanced predictability with
high-graded portfolio
Liquids growth driven by oil
No exploration contribution
Strong international FCF generation
Capex ex LNG = cash flow
Midpoint of expectation range displayed
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Proven leader in oil-levered North America growth:
#1 growth generator in Permian + Anadarko basins
60% of company production in NA onshore (and rising)
Major free cash flow assets:
>$1 BN/year FCF from Egypt, North Sea, Australia (#1 positions)
Incremental $1 BN/year free cash flow from Wheatstone LNG
Industry shift to execution:
Proven track record: APA core strength
Built to last:
Rate of return discipline: focus on repeatable liquids plays
Self-funded capital program ex LNG. Financial strength to deliver our strategy
Sustainable: NA onshore resource alone 4x APA proved reserves
22
APACHE TODAY
Repositioned, focused: ready for next phase of value growth
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NORTH AMERICAONSHORE
John Christmann
February 26, 2014
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24
N.A. ONSHORE 2013 HIGHLIGHTS
North America onshore liquids growth 34%
Most active N.A. onshore driller in 2013 Averaged 79 rigs and drilled ~1,300 wells
Outstanding organic production replacement and reserve
growth Overall production replacement of 230% at $17 per BOE Permian = 323%; Central = 195%; Canada = 189%
Permian and Central reserve growth of 14% each
Substantially reduced costs in resource plays1
20+ days reduced drilling 25%+ reduction in completion costs
Overall resource increase to 14.0 BBOE Expanded Permian resource base by 1.0 BBOE to 4.8 BBOE
Note 1. Based upon Barnhart area Wolfcamp Shale improvements from 2012 through current.
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0
20,000
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120,000
140,000
160,000
2009 2010 2011 2012 2013 Q4'13
Permian Central
0
50,000
100,000
150,000
200,000
250,000
2009 2010 2011 2012 2013 Q4'13
Permian Central
25
Liquids Track Record (B/D) BOE/D Track Record
PROVEN NORTH AMERICA GROWTH DRIVERS
89
227
39
151
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38%
40%
21%
18%
54%
4%
24%
N.A. ONSHORE RESOURCE BASE:VISIBLE, PREDICTABLE UPSIDE
Pro Forma Proved Reserves1 Total Resources2
CanadaCentral
Permian
GC
Onshore
Canada
Central
Permian
1.7 BBOE 14.0 BBOE
Note 1. Proved reserves as of 12/31/2013 and pro forma for 2014 Canada divestures.Note 2. Resource estimates as of February 2014. Still evaluating Gulf Coast Onshore resources.26
Eagle Ford Resources
Under Assessment
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HZ WELL MANUFACTURING - LEVERAGING EXPERIENCE DRIVING EFFICIENCY ACROSS ALL DISCIPLINES
Frac-Water RecyclingSelf-Sourcing Frac ChemicalsSweet Spot IdentificationFrac Costs - Granite Wash
$/Lateral foot
Horizontal Rig Count
Hz Drilling Operations Excellence
Increasing pad drilling
Sharing hz drilling best practices
Frac Stimulation Optimization
Aggressive frac staging methods
Operations efficiency
Focus on Recovery Efficiency
Sweet Spot Identification
Well spacing field trials
Supply Chain Efficiency
Self-sourcing sand and frac chemicals
Bidding in size
Water Management Innovation
Industry leading frac-water recycling
27
Central Permian Canada Gulf Coast Egypt
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28
N.A. ONSHORE 2014 PLAN
2014 E&D capital of $5.4Bn
47% Permian; 32% Central
Avg. Rigs 85; gross wells ~1,400
~875 horizontal gross wells
2014: 15% to 18% North America onshore liquids growth
Driven by oil
Continue delineation of liquids plays
Gulf Coast: Eagle Ford oil
Central: Canyon Lime oil
Canada: Duvernay and Montney liquids-rich gas
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32%
47%
10%
11%
Total N.A. 2014 E&D Capital = $5.4 Bn
2014 PLAN FOCUSED ON ONSHORE LIQUIDS GROWTH
29
2014 Project Capital*
$775 MM
Canada
$0.6 Bn
Central
$1.7 BN
Permian$2.6 Bn
GC Onshore
$0.5 Bn
2014 Plan
Avg. Rigs Total Wells
Permian 39 (23 Hz) 768 (297 Hz)
Central 32 (31 Hz) 418 (412 Hz)
Gulf Coast
Onshore6 (3 Hz) 85 (49 Hz)
Canada 8 (7 Hz) 121 (117 Hz)
Total 85 (64 Hz) ~1,400 (~875 Hz)
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2013PF 2014E 2015E 2016E
N.A. ONSHORE LONG-TERM GROWTHPREDICTABLE, REPEATABLE, PROFITABLE
30 Note: Pro forma for divested volumes from Canada sales, including 2014 planned divestitures. Canada includes Kitimat volumes.
MBOE/D, Net
Midpoint of expectation range displayed
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31
NORTH AMERICAN POWERHOUSE
Most active driller
Track record of delivering consistent, repeatable growth
Organic production replacement of 230% at $17 per BOE
Substantial reduction of costs in resource plays
Massive resource base
Almost 14 BBOE
Including 4.8 BBOE in the Permian
Emerging resource plays under assessment
12% to 16% liquids growth over the next three years
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32
NORTH AMERICA ONSHORE POSITION
Canada2013PF Avg. Production1: 74.6 MBOE/D
Undeveloped Resources: 2.8 BBOE
Emerging Montney / Duvernay Shale Plays
Permian
2013 Avg. Production: 127.1 MBOE/D
Undeveloped Resources: 4.8 BBOE
Expanding Horizontal Activities
Central
2013 Avg. Production: 91.3 MBOE/D
Undeveloped Resources: 5.2 BBOE
Emerging Canyon Lime Play
Gulf Coast
2013 Avg. Production: 30.8 MBOE/D
Emerging Eagle Ford Shale Play
Note 1. Pro forma for divested volumes from Canada sales, including 2014 planned divestitures.
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VIDEO
33
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PERMIAN
John Christmann
February 26, 2014
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35
APACHE PERMIANA MAJOR GROWTH BUSINESS
New Mexico Texas
APA acreage
Midland
#1 driller in the Permian Basin
3.3 million acres (1.7 million net)
4Q 13: 134 MBOE/D net (76% Liquids)
15 mi
APA Hz rigs
(22)
APA Vt rigs
(16)
3 Hz/3 Vt
5 Hz
4 Hz
1 Hz/2 Vt
3 Vt
Currently running 38 rigs
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-
20
40
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160
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5
10
15
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25
30
35
40
45
50
2013 Results
Average Production127.1 MBOE/D
+17.3% YoY
Liquids Growth +22.1% YoY
Prod. Replacement1 323%
Proved Reserves 910 MMBOE
Capital $2.6B
Average Rigs 42 (19 Hz)
Gross Wells2 785 Total / 186 Hz
Note 1. ‘Prod. Replacement’ represents organic replacement (ie, excluding the effects of A&D and revisions).
Note 2. ‘Gross Wells’ reflect wells drilled or participated in during 2013; excludes salt water disposal and water injection wells .
Production & Operated Rig Count Growth
2013 HIGHLIGHTS AVERAGED 42 RIGS AND COMPLETED 785 WELLS
2010 2011 2012 2013
Rigs
(line)
Mboe/d
(bars)
APA Permian
Region
Established
36
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5
10
15
20
25
30
35
40
45Hz Vt
Apache Operated Rig Count
CHARGING AHEAD WITH HORIZONTAL RIGS UP TO 23 HORIZONTAL RIGS BY YEAR END 2013
2010 2011 2012 2013
37
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38 Note: Peers include COP, CXO, DVN, OXY, PXD, and XEC; data sourced from company investor presentations and Wall Street research.
#1 PERMIAN DRILLER IN 2013
Operated
Rigs
0
5
10
15
20
25
30
35
40
45
APA A B C D E F
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39
2ND LARGEST FOOTPRINT: 1.7 MM NET ACRES
Net Acres
(000’s)
0
500
1,000
1,500
2,000
2,500
3,000
A APA B C D E F
Note: Peers include COP, CXO, DVN, OXY, PXD, and XEC; data sourced from company investor presentations and Wall Street research.
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40
2013 Net MBOE/D
211
12792 79 78
55 53
0
100
200
300
A APA B C D E F
Note: Peers include COP, CXO, DVN, OXY, PXD, and XEC; data sourced from company investor presentations and Wall Street research.
17% GROWTH ON 2ND LARGEST BASE
% Growth 2013 vs 2012
2%
17%13%
20% 18%
8%
21%
0%
10%20%
30%
40%
A APA B C D E F
6692
108 201220112010
APA Hist
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41
#1 GROWTH BY VOLUME ACROSS PEERS
MBOE/D
Added in 2013
0
2
4
6
8
10
12
14
16
18
20
APA A B C D E F
Note: Peers include COP, CXO, DVN, OXY, PXD, and XEC; data sourced from company investor presentations and Wall Street research.
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2010 2011 2012 2013
2014
Plan
Employees 345 662 792 914 ~970
Investment $0.4B $1.2B $2.3B $2.6B $2.6B
Production(MBOE/D)1 66.5 91.7 108.3 127.1 12-15%
growth
Rigs 6 25 32 42 39
New Hz
Wells2 17 39 104 186 297
Total New
Wells2 263 507 781 785 768
42
REGION GROWTHSECOND TO NONE
Note 1. ‘Production’ in the table above reflects the annual average. Note 2. ‘Wells’ reflect wells drilled or participated in; excludes salt water disposal and water injection wells.
+60%
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51.060.2
72.1
11.8
18.0
23.4
28.9
30.1
31.6
-
20
40
60
80
100
120
140
2011 2012 2013
Oil NGL Gas
M B O E / D
Liquids % of Mix
2011 Actual 69%2012 Actual 72%
2013 Actual 75%
REGION GROWTHTRACK RECORD OF ORGANIC GROWTH
43
2014P
12-15%
Growth
91.7
108.3
127.1
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44
GROWING TOTAL RESOURCE1 BILLION BOE NET INCREASE IN TOTAL RESOURCE SINCE 2012
Understanding of new areas now sufficient for inclusion(i.e., Augusta Barrow, Fasken/Circle Bar, Southern Crane)
Understanding of new landing zones now sufficient for
inclusion (i.e., Lower Wolfcamp and Spraberry)
Higher EUR’s across most of our key plays supported by
completion optimization and well performance
Vertical to horizontal reclassification (i.e., larger volumes/acre)
Reduced location counts in some areas due to improved
understanding of vertical down spacing potential
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45
Net Resources Gross / Net Acreage
4.8 BBOE 3.3MM/ 1.7MM
Midland
Basin
Delaware
Basin
APA acreage
CentralBasin
Platform
TOTAL RESOURCE
Note: Acreage numbers shown in call-outs are stated in thousands of acres; resource numbers represent total net unrisked undeveloped resource, inclusive of proved.
Midland Basin
Gross Acreage 950
Net Acreage 635
Net MMBOE 2,961
CBP + N/NW Shelf
Gross Acreage 1,800
Net Acreage 850
Net MMBOE 1,275
Delaware Basin
Gross Acreage 550
Net Acreage 215
Net MMBOE 599
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Delaware Basin
Bell Canyon
Cherry Canyon
Bushy Canyon
Bone Spring
Lime
Leonard Shale
Avalon Shale
1st Bone Spring
2nd Bone Spring
3rd Bone Spring
Upper Wolfcamp
Middle Wolfcamp
Lower Wol fcamp
Cisco
Canyon
Strawn
Atoka
Bend
Morrow
D e l a w a r e
M o u n t a i n G r o
u p
B o n e S p r i n g
P e n n s y l v a n i a n
W o l f b o n e
W o l f c a m p
Midland BasinLeonard Lime
Leonard
Upper Spraberry
Lower Spraberry
Dean
Upper Wolfcamp
Middle Wolfcamp
Lower Wol fcamp
Cline Shale
Strawn
Atoka
Barnett
Mississippian Lime
Fusselman
Sylvan
EllenburgerOrd.
Woodford
Devonian
L e o n a r d
W o l f c a m p
P e n n s y l v
a n i a n
Miss.
Dev.
Sil.
CBP/NW Shelf
TansilYates
Seven Rivers
Queen
Grayburg
Judkins
McNight
Glorieta
Upper Clearfork
Tubb
Lower Clearfork
Wichita Albany
Wolf. Wolfcamp Lime
Cisco
Canyon
Strawn
AtokaBarnett
Mississippian
Devonian
Sil. Silurian
Montoya
Simpson
Ellenburger
G u a d a l u p e
L e o n a r d
P e n n s y l v a n i a n
O r d o v i c i a n
San Andres
Woodford
Dev.
Miss.
Future potential landing zone
Currently being developed
INCREASING HORIZONTAL ACTIVITY APACHE HORIZONTAL TARGETS
20 mi
Midland
BasinDelaware
Basin
Permian Basin
APA acreage
Central
BasinPlatform
Stratigraphy Columns:
46
/
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Lea
Eddy
Reeves
Loving Winkler
Andrews
Gaines
Ector Midland Glasscock
Ward CraneUpton Reagan Irion
Martin
Dawson Borden
Howard
GarzaLynnTerryYoakum
Pecos Crockett
Sterling
Mitchell
Scurry
Kent
Lubbock Crosby Dickens
47
SRH
Rocker B 1106 HC
Cline Hz (Lower)
763 BOEPDDec 21, 2013
4,437’
THREE BAR
TBSU #119H
Wichita Albany Hz818 BOEPD
Oct 13, 2013
7,467’
AUGUSTA BARROW
Augusta Barrow #1417H
Barnett Shale Hz
852 BOEPDNov 16, 2013
4,400’
PECOS BEND
Chaparral 89 #102H
Bone Spring Hz (3rd)
1,130 BOEPD
Jan 19, 20144,400’
CRANE
University Lands 36 #6H
Grayburg Hz
961 BOEPD
Dec 24, 2013
3,050’
YESO
Crow Fed #11H
Yeso Hz286 BOEPD
Nov 8, 2013
3,880’
DEADWOOD
Greatwhite 44 #3H
Cline Hz (Lower)
956 BOEPD
Dec 10, 2013
4,270’
VEALMOOR
Thompson 12#2 H
Spraberry Hz (Lower)
261 BOEPDOct 25, 2013
4,907’
RECENT HORIZONTAL RESULTS MANY WAYS TO WIN
POWELL / MILLER
Miller 36 #2 HU
Wolfcamp Hz
756 BOEPD
Oct 12, 2013
4,877’
POWELL / MILLER
CC 3626 HM
Wolfcamp Hz
909 BOEPD
Sep 27, 20135,835’
SRH
Rocker B 1105 HL
Wolfcamp Hz
843 BOEPD
Dec 22, 2013
4,459’
BARNHART
Scott Sugg 5051 H33M
Wolfcamp Hz
798 BOEPD
Nov 29, 2013
7,532’
FIELD/AREA
APA Well Name
Landing Zone
Peak IP rate
1st Flow Date
Lateral Length
DEADWOOD
Ballenger 3142 #5H
Cline Hz (Lower)
827 BOEPDOct 6, 2013
5,150’
NORTH MONAHANS
Sealy & Smith B #95H
Strawn/Penn Hz
1,054 BOEPD
Dec 17, 2013
6,300’
PECOS BEND
Chaparral 89 #101H
Bone Spring Hz (3rd)
1,375 BOEPD
Dec 19, 2013
3,700’
YESO
Crow Fed #10H
Yeso Hz
244 BOEPDNov 14, 2013
3,935’
THREE BAR
Carmichael #1501H
Wichita Albany Hz
614 BOEPDNov 27, 2013
4,650’ DEADWOOD
Lee59 #8H
Cline Hz (Lower)
466 BOEPD
Dec 9, 2013
4,020’
DEADWOOD
Lee59 #10H
Cline Hz (Lower)
529 BOEPD
Dec 9, 2013
4,400’
BARNHART
Sugg 4948 H53M
Wolfcamp Hz
876 BOEPD
Nov 16, 2013
7,185’
BARNHART
Scott Sugg 5051 E H61U
Wolfcamp Hz
1,152 BOEPD
Oct 27, 2013
7,455’
BARNHART
Scott Sugg 5554 H43M
Wolfcamp Hz
1,111 BOEPD
Dec 22, 2013
7,628’
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APA acreage
25 mi
Midland Basin
Cline Shale
Wolfcamp Shale
48
APA owns ~950,000 gross acres across Midland Basin
Abundant opportunities accessing over 5,000’ of section
Significant drilling across multiple plays, from vertical Wolfberry to Cline & Wolfcamp
shales
MIDLAND BASINMULTI-PLAY GROWTH ENGINE
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49
MIDLAND BASIN HORIZONTALTREMENDOUS UNCONVENTIONAL POTENTIAL
Note: Logs above hung on Clearfork.
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50
World class oil shale
Multiple operated areas
Focused on spacing and completion optimization
12 horizontal rigs planned in 2014
Acres (000) 502 (401 net)
Planned 2014 Wells 131 (All Hz)
Resources 846 MMBOE net
APA acreage
25 mi
Wolfcamp Shale
WOLFCAMP SHALEGROWING OUR RESOURCE
-
200
400
600
800
1,000
2012 Current
Midland Basin Wolfcamp Shale
MMBOE
Midland Basin
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51
Proved concept and moved to full pad development mode
109 wells drilled1 since 2012 (15 currently completing)
WOLFCAMP SHALEPROVEN MODEL: APACHE’S BARNHART AREA (IRION CO.)
APA acreage
25 mi
Wolfcamp Shale
-
2,000
4,000
6,000
8,000
10,000
12,000
-
10,000
20,000
30,000
40,000
50,000
60,000
MCFD BOPD
Barnhart Wolfcamp Gross ProductionMcf/d Bo/d
Barnhart Field
Midland Basin
Note 1. ‘109 wells drilled’ includes 104 wells drilled to total depth and 5 wells currently drilling.
WOLFCAMP SHALE BARNHART
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Well Highlights IP (24 hr Pk) IP (30-Day Avg) Lateral (ft) EUR (MBOE)
Scott Sugg 5554 H31U 918 Pending 7,697 685
Scott Sugg 5554 H43M 1,111 882 7,628 631
Scott Sugg 5554 H33M 1,079 795 7,581 627
Clinch 4238 H53LU 1,055 720 8,589 744
Scott Sugg 5051 E H61U 1,152 682 7,455 620
Began pad drilling in Q3 2012
5 rigs planned in 2014
Multiple field trials Industry leading water recycling
Upside in completion optimization
WOLFCAMP SHALE: BARNHARTCONSISTENT FAST-PACED EXECUTION WITH STRONG RESULTS
Scott Sugg Lease
Bennie Lease
Clinch Lease
Irion
52
APA acreage
Note: Rates shown in the table above are shown on a 3-stream basis
WOLFCAMP SHALE BARNHART
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WOLFCAMP SHALE: BARNHARTDRILLING FASTER AND LOWERING COSTS
Move to pad drilling
Reduced geo-steering
Optimal casing points
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0 5 10 15 20 25 30 35
Transition to oil based mud
Advanced hz drilling practices
Drilling cost reduced 26%
2012-2013 YoY $/ft
Depth (ft)
Days
Avg 2012
(21 wells)
Avg 2013
(78 wells)2013 Pace Setter
WOLFCAMP SHALE BARNHART
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Wolfcamp Shale: Barnhart1
D+C Cost $MM 6.3EUR MBOE 600
30-Day IP Rate Boed 515
% Oil / Gas / NGL 55% / 21% /24%
WI / NRI 85% / 64%
ROR2
41%
Total Inventory 644
PUD + Probable Inventory 172
54
WOLFCAMP SHALE: BARNHARTDRILLING INVENTORY ECONOMICS
Note 1. Type curve assumes 1.5 mile lateral.
Note 2. All well economics assume $90.00/Bbl WTI, $4.50/MMBTU NYMEX, and $27.00/Bbl NGL prices.
0
100
200
300
400
500
600
0 6 12 18 24 30 36 42 48 54 60Month
BOE/D
WOLFCAMP SHALE BARNHART
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55
4Q 13/1Q 14 Results:
Step change in completion productivity;Optimizing stage and frac designs;
Current Barnhart Wolfcamp type
curve used to calculate resource
WOLFCAMP SHALE: BARNHARTRECENT COMPLETION TRIALS
Conducting field trials
More potential improvement in
productivity and costs
Self-sourcing frac chemicals & sand
Improved wireline & drill-out efficiency
Applying learnings in all areas
WOLFCAMP SHALE SOUTHERN MIDLAND BASIN
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Acres1 (000) 292 (232 net)
Planned 2014 Wells 53 (All Hz)
Resources 549 MMBOE net
10 mi
Upton Reagan
Midland
56
Spraberry Aldwell Unit
Scottish Rite Hospital
Barnhart Field
Lone Roger Grierson Springs
Big Lake
University/Weatherby
Powell
Wildfire
v
WOLFCAMP SHALE: SOUTHERN MIDLAND BASINAPPLYING LEARNINGS
Select Apache fields in the Southern Midland Basin
v
Drilling focused on Midland, Reagan,and Upton Counties
Upper, Middle, Lower Wolfcamp and
Cline shale targets
23 wells drilled
7 horizontal rigs running (2 verticals)
New 3D seismic being progressed
Note 1. Acreage number presented reflects Apache’s acreage in Midland, Upton, and Reagan counties.
APA acreage
WOLFCAMP SHALE SOUTHERN MIDLAND BASIN
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Wolfcamp Shale: Southern Midland Basin1
D+C Cost $MM 7.8EUR MBOE 662
30-Day IP Rate Boed 590
% Oil / Gas / NGL 61% / 19% / 20%
WI / NRI 94% / 72%
ROR 48%
Total Inventory 1,152
PUD + Probable Inventory 385
57
WOLFCAMP SHALE: SOUTHERN MIDLAND BASINDRILLING INVENTORY ECONOMICS
Note 1. Type curve assumes 1.5 mile lateral.
0
100
200
300
400
500
600
700
0 6 12 18 24 30 36 42 48 54 60Month
BOE/D
WOLFCAMP SHALE SOUTHERN MIDLAND BASIN
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WOLFCAMP SHALE: SOUTHERN MIDLAND BASINRECENT COMPLETION TRIALS
58
100
1,000
10,000
0 30 60 90 120 150 180
B O E P D
Days
Miller #3601HM – M. Wolfcamp (Upton Co); 1 mi. lateral
24-hour Peak IP rate of 1,391 BOEPD (82% oil)
CC #3626HM – M. Wolfcamp (Upton Co); 1 mi. lateral
24-hour Peak IP rate of 909 BOEPD (86% oil)
SRH North #1624HM – M. Wolfcamp (Reagan Co); 1.5 mi. lateral
24-hour Peak IP rate of 854 BOEPD (82% oil)
662 MBOE Type Curve
(1.5 mile lateral)
CLINE SHALE
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59
Expanding resource play with focus on Glasscock
County Drilled 51 wells to date across three fields
Increased our resource by over 20 MMBOE since 2012
Drilling inventory identified across multiple APA fields
3 horizontal rigs planned for 2014
Acres (000) 640 (510 net)
Planned 2014 Wells 35 (All Hz)
Resources 665 MMBOE net
APA acreage
25 mi
Deadwood Field
CLINE SHALEEXPANDING HORIZONTAL PROGRAM
Cline Shale
CLINE SHALE
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0
100
200
300
400
500
600
700
800
900
0 30 60 90 120 150 180 210 240 270 300
B O E P D
Days On
Barracuda 45 #2H
Marlin 47 #2H
Lee 59 #10H
Hammerhead 33 #8H
1 Mile Type Curve
1.5 mile Type Curve
15 Lower Cline (2014 Plan)
Completed Lower Cline
Barnett/Atoka & Wolfcamp horizontals to
be drilled and evaluated
2014 horizontal plan: 35 wells, 3 rigs
CLINE SHALELEADING GLASSCOCK CLINE PLAYER
Barracuda 45 #2H
30d IP 713 BOEPD
Hammerhead 33 #8H
30d IP 566 BOEPD
Marlin 47 #2H
30d IP 286 BOEPD
Lee 59 #10H
30d IP 371 BOEPD
Deadwood Cline Avg Daily Production Curves1
60 Note 1. All wells plotted in the chart above were drilled with 1 mile laterals; both 1 and 1.5 miles type curves are shown for reference.
APA acreage 1.75 mi
526 MBOE
424 MBOE
CLINE SHALE
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61
CLINE SHALESTEP CHANGE IN COMPLETIONS
EUR
(MBOE)
0
100
200
300
400
500
600
2013 2013 2014
Early development
1-mi. lateral
Optimized 1-mi. lateral 1.5-mi. lateral
2013 Early
development
1-mi. lateral
2013 Optimized
1-mile lateral
+40%
CLINE SHALE
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Cline1
D+C Cost $MM 8.5EUR MBOE 536
30-Day IP Rate Boed 420
% Oil / Gas / NGL 67% / 14 % / 19%
WI / NRI 78% / 60%
ROR 23%
Total Inventory 2,068
PUD + Probable Inventory 190
62
CLINE SHALEDRILLING INVENTORY ECONOMICS
Note 1. Type curve assumes 1.5 mile lateral.
Month
BOE/D
0
50
100
150
200
250
300
350
400
450
0 6 12 18 24 30 36 42 48 54 60
MIDLAND BASIN VERTICAL
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63
Attractive rates of return and predictable drilling
results
Spraberry through Fusselman pay zones
Upsides being pursued:
Improving completions, drilling efficiencies
Increased location density
Acres (000) 950 (635 net)
Planned 2014 Wells 170
Resources 1,390 MMBOE net
APA acreage
25 mi
Midland Basin
Squire 9007(Fusselman)
30-day IP BOE/D 577
EUR MBOE 813
SRH #1619(Fusselman)
30-day IP BOE/D 187
EUR MBOE 360
SAU 2 #2(Spraberry/Dean)
30-day IP BOE/D 109
EUR MBOE 310
Frances Gunn A33(Clearfork - Wolfcamp)
30-day IP BOE/D 130
EUR MBOE 134
Condor 48 #1(Wolfwood)
30-day IP BOE/D 391
EUR MBOE 567
MIDLAND BASIN VERTICALMULTI-ZONE STACKED PAY
MIDLAND BASIN VERTICAL
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Other Midland Vertical
D+C Cost $MM 2.2
EUR MBOE 136
30-Day IP Rate Boed 94
% Oil / Gas / NGL 56% / 22% / 22%WI / NRI 87% / 69%
ROR 27%
Total Inventory 10,539
PUD + Probable Inventory 2,139
Spraberry Vertical
D+C Cost $MM 2.0EUR MBOE 148
30-Day IP Rate Boed 73
% Oil / Gas / NGL 49% / 26% / 25%
WI / NRI 89% / 72%
ROR 23%
Total Inventory 3,762PUD + Probable Inventory 951
64
0
10
20
30
40
50
60
70
80
0 6 12 18 24 30 36 42 48 54 60Month
BOE/D
0
10
20
30
40
50
60
70
80
90
100
0 6 12 18 24 30 36 42 48 54 60
BOE/D
Month
MIDLAND BASIN VERTICALDRILLING INVENTORY ECONOMICS
MIDLAND BASIN TRACK RECORD
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Increased production 8x to 25 MBOE/D in 26
months of APA as operator
678 wells drilled
65
Hardy 18 #13
(Wolfwood)
30d IP 192 BOEPD
Squire 9007
(Fusselman)
30d IP 577 BOEPD
Maui 5# 1
(Wolfwood)
30d IP 386 BOEPD
Kestrel 38 #3
(Wolfwood)
30d IP 194 BOEPD
Hartley #20
(Fusselman)
30d IP 173 BOEPD
Barracuda 45 #8
(Fusselman)
30d IP 362 BOEPD
Condor 48 #1
(Wolfwood)
30d IP 391 BOEPD
2.5 mi
MIDLAND BASIN TRACK RECORDDEADWOOD: EXECUTION & IMPACTIVE GROWTH
-
2,000
4,000
6,000 8,000
10,000
12,000
14,000
16,000
18,000
-
10,000
20,000
30,000 40,000
50,000
60,000
70,000
80,000
90,000
1
2 - 2 0 1 0
0
3 - 2 0 1 1
0
6 - 2 0 1 1
0
9 - 2 0 1 1
1
2 - 2 0 1 1
0
3 - 2 0 1 2
0
6 - 2 0 1 2
0
9 - 2 0 1 2
1
2 - 2 0 1 2
0
3 - 2 0 1 3
0
6 - 2 0 1 3
0
9 - 2 0 1 3
1
2 - 2 0 1 3
MCFD BOPD
Deadwood Gross ProductionMcf/d Bo/d
APA takes
over as
operator
Analyst Day
June 2012
APA acreage
Program shiftto horizontals
CENTRAL BASIN PLATFORM & N/NW SHELF
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66
New horizontal opportunities
Three Bar, Monahans, Augusta Barrow
Currently running 3 hz and 7 vt rigs
Acres (000) 1,800 (850 net)
Planned 2014 Wells 328 (105 Hz)
Resources 1,275 MMBOE net
20 mi APA acreage
Northwest Shelf
North Shelf
Central Basin
Platform
CENTRAL BASIN PLATFORM & N/NW SHELFPRODUCTION LEGACY OF THE BASIN, WITH UPSIDE
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000MCFD BOPD
Three Bar Area
Gross ProductionMcf/d Bo/d
Three Bar
Area
Monahans Augusta
Barrow
CENTRAL BASIN PLATFORM HORIZONTALS
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67
Carmichael #1501H30-day IP BOE/D 507
EUR MBOE 321
Wichita Albany
CENTRAL BASIN PLATFORM HORIZONTALSCONVENTIONAL OIL PLAYS
10 mi
Strawn
Sealy & Smith
Foundation B #95H30-day IP BOE/D 900
EUR MBOE 507
Apache remains a leader in the horizontal
exploitation of these formations
Drilled 22 hz Wichita Albany wells (conventionaldolomite) & 2 hz Strawn wells (fractured
carbonate) in 2013
Plan to drill 21 hz wells in 2014
APA acreage
TBSU #119H30-day IP BOE/D 769
EUR MBOE 552
CENTRAL BASIN PLATFORM HORIZONTALS
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Strawn
D+C Cost $MM 7.5
EUR MBOE 354
30-Day IP Rate Boed 609
% Oil / Gas / NGL 73% / 10% / 17%
WI / NRI 100% / 81%
ROR 43%
Total Inventory 61
PUD + Probable Inventory 14
Wichita Albany
D+C Cost $MM 5.6EUR MBOE 367
30-Day IP Rate Boed 477
% Oil / Gas / NGL 60% / 21% / 19%
WI / NRI 78% / 62%
ROR 65%
Total Inventory 274PUD + Probable Inventory 94
68
CENTRAL BASIN PLATFORM HORIZONTALSDRILLING INVENTORY ECONOMICS
BOE/D
Month
0
100
200
300
400
500
600
700
0 6 12 18 24 30 36 42 48 54 60
BOE/D
Month
050
100
150
200
250
300
350
400
450
500
0 6 12 18 24 30 36 42 48 54 60
CENTRAL BASIN PLATFORM VERTICALS
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Plays benefit from large-scale established
infrastructure network
Predictable drilling results
Plan is to drill 60 Clearfork and 12 Wolfcamp
wells in 2014 Increased density drilling
Waterflood support, low decline rates
69
Clearfork/Tubb
CENTRAL BASIN PLATFORM VERTICALSCONVENTIONAL OIL PLAYS
10 mi
Wolfcamp/Penn
APA acreage
Seth Campbell #8230-day IP BOE/D 1,091
EUR MBOE 714 Bakke Unit #16930-day IP BOE/D 382
EUR MBOE 489
TXLSU #6005
30-day IP BOE/D 188EUR MBOE 152
Andrews Unit #54930-day IP BOE/D 188EUR MBOE 273
Lockhart B-12 #13
30-day IP BOE/D 120EUR MBOE 151
-
200
400
600 800
1,000
1,200
1,400
1,600
1,800
2,000
0
2,000
4,000
6,000
8,000
10,000
12,000
J a n - 1 1
A p r - 1 1
J u l - 1 1
O c t - 1 1
J a n - 1 2
A p r - 1 2
J u l - 1 2
O c t - 1 2
J a n - 1 3
A p r - 1 3
J u l - 1 3
O c t - 1 3
J a n - 1 4
Keystone (Seth Campbell) Field
Gross ProductionMcf/d Bo/d
CENTRAL BASIN PLATFORM VERTICALS
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Wolfcamp/Penn
D+C Cost $MM 2.1
EUR MBOE 122
30-Day IP Rate Boed 94
% Oil / Gas / NGL 63% / 16% / 21%WI / NRI 93% / 80%
ROR 30%
Total Inventory 164
PUD + Probable Inventory 63
Clearfork/Tubb
D+C Cost $MM 1.7EUR MBOE 112
30-Day IP Rate Boed 90
% Oil / Gas / NGL 61% / 24% / 16%
WI / NRI 78% / 69%
ROR 35%
Total Inventory 3,067PUD + Probable Inventory 1,065
70
CENTRAL BASIN PLATFORM VERTICALSDRILLING INVENTORY ECONOMICS
BOE/D
Month
010
20
30
40
50
60
70
8090
100
0 6 12 18 24 30 36 42 48 54 60
BOE/D
Month
0
10
20
30
40
50
60
70
80
90
100
0 6 12 18 24 30 36 42 48 54 60
DELAWARE BASIN
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71
10 mi
APA acreage
Pecos Bend- Under development
- 2 rigs active, 3 landing zones
WAHA- Commercializing
- 1 rig active, 2 landing zones
Dixieland- Planning stage
Lobo Hueso
- Commercializing
- 1st well completing
Seven Mile Mesa
- Planning stage
DELAWARE BASINOPENING UP MULTIPLE NEW AREAS
South Pecos
- Planning stage
Acres (000)
550 (215 net)
Planned 2014 Wells 28 (21 Hz)
Drilling Inventory 599 MMBOE net
Full Development Mode
Pecos Bend Field
Commercialized 3 landing zones 4-6 wells per section spacing
Testing 5 new landing zones
Horizontal Commercialization
WAHA Prospect
Currently drilling 2 hz landing zones
Lobo Hueso
Testing Wolfcamp and 3rd Bone Spring
New 3D seismic delivered
Planning phase underway in Seven Mile
Mesa, Dixieland, and South Pecos
DELAWARE BASIN
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72
Emerging Apache opportunity
Full scale horizontal development underway at Pecos Bend Prospect
3 commercialized landing zones in the 2nd Bone Spring, 3rd Bone Spring, & Wolfcamp
2 rigs currently active planning to ramp up to 3 rigs in March
DELAWARE BASINPECOS BEND: WOLFCAMP & BONE SPRING DEVELOPMENT
Chaparral 89 #101H
3rd Bone Spring30-day IP BOE/D 1,226
EUR MBOE 763
Boe/d
20 mi APA acreage
Delaware
Basin
Chaparral 89 #1H
2nd Bone Spring30-day IP BOE/D 724
EUR MBOE 511
Robin 8 #1H
Upper Wolfcamp30-day IP BOE/D 697
EUR MBOE 693
0
300
600
900
1,200
1,500
0 100 200 300 400 500
Chaparral 89 #1H
Robin 8 #1H
Chaparral 89 #101H
Type Curve
Days
552 MBOE
DELAWARE BASIN
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Delaware Horizontal
D+C Cost $MM 7.9EUR MBOE 552
30-Day IP Rate Boed 786
% Oil / Gas / NGL 45% / 28% / 27%
WI / NRI 94% / 72%
ROR 22%
Total Inventory 1,507
PUD + Probable Inventory 754Month
BOE/D
0 100
200
300
400
500
600
700
800
5 11 17 23 29 35 41 47 53 59
73
DELAWARE BASINDRILLING INVENTORY ECONOMICS
LONG TERM PERFORMANCE
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74
105
125
92
108
127
0
20
40
60
80
100
120
140
2011 2012 2013
2012 Projections Actual / Projections
M B O E / D
LONG TERM PERFORMANCEDELIVERING AND EXCEEDING EXPECTATIONS
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BREAK
75
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CENTRAL
John Christmann
February 26, 2014
APACHE CENTRAL
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77
DELIVERING HORIZONTAL LIQUIDS GROWTH
APA Acreage
#1 driller in the deep portion of the Anadarko
1.8 million acres (1.0 million net)
58 year track record in the Anadarko Basin
Multiple productive formations
APA Hz rigs
(28)
APA Vt rigs
(1)
Texas
Oklahoma
50 miles
Currently running 29 rigs
CENTRAL REGION: CONSISTENT, PROFITABLE GROWTH
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78
0
5
10
15
20
25
30
35
-
10
20
30
40
50 60
70
80
90
100
2010 2011 2012
Cordillera
Closing
LIQUIDS GROWTH UP 122% YEAR OVER YEAR
2013
2013 Results
Average Production91.3 MBOE/D
+49.2% YoY
Liquids Growth +121.7% YoY
Prod. Replacement1 195%
Proved Reserves 304 MMBOE
Capital $1.7 B
Average Rigs 27
Gross Wells2 322 Total/299 Hz
Mboe/d
(bars)
Rigs
(line)Production & Operated Rig Count Growth
Note 1. ‘Prod. Replacement’ represents organic replacement (ie, excluding the effects of A&D and revisions).
Note 2. ‘Gross Wells’ reflect wells drilled or participated in during 2013; excludes salt water disposal and water injection wells .
REGION GROWTH
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79
REGION GROWTHSUBSTANTIALLY INCREASING ACTIVITY
2010 2011 2012 20132014
Plan
Employees 236 227 384 474 ~530
Investment $0.5B $0.5B $1.1B $1.7B $1.7B
Production(MBOE/D)1 39.1 44.6 61.2 91.3 12%-15%
growth
Rigs 9 9 18 27 32
New Hz
Wells2 59 90 178 299 412
Total New Wells2
84 108 192 322 418
Note 1. ‘Production’ in the table above reflects the annual average.
Note 2. ‘Wells’ reflect wells drilled or participated in; excludes salt water disposal and water injection wells.
+38%
HISTORY OF GROWTH
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2 4 714
232
7
23
34 35
36
40
45
3639
45
61
91
-
10
20
30
40
50
60
70
80
90
100
2009 2010 2011 2012 2013
Oil NGL Gas
M B O E / D
Liquids % of Mix
2009 Actual 7%
2010 Actual 11%2011 Actual 20%
2012 Actual 34%
2013 Actual 50%
80
CONSISTENT LIQUIDS-DRIVEN GROWTH 2014P
12-15%
Growth
TOTAL RESOURCE
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81
Tonkawa
Gross Acreage 822
Net Acreage 407
Net MMBOE 242
Cleveland
Gross Acreage 758
Net Acreage 429
Net MMBOE 397
Granite Wash
Gross Acreage 855
Net Acreage 435
Net MMBOE 3,849
Marmaton
Gross Acreage 609
Net Acreage 295
Net MMBOE 271
Canyon Wash/Lime
Gross Acreage 150
Net Acreage 100
Net MMBOE 107
Other2
Gross Acreage 435
Net Acreage 205
Net MMBOE 318APA acreage
15 mi
TOTAL RESOURCE
Cottage Grove
Gross Acreage 222
Net Acreage 93
Net MMBOE 9
Net Resources1 Gross / Net Acreage1
5.2 BBOE 1.8MM/ 1.0MM
Note 1. Acreage numbers shown in call-outs are stated in thousands of acres; resource numbers represent total net
unrisked undeveloped resource, inclusive of proved.
Note 2. ‘Other’ includes resources attributable to the Bakken, Cherokee, Thirteen Fingers, Skinner, Woodford, and
Sweetwater formations.
CENTRAL REGION 2013 DRILLING HIGHLIGHTS
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82
10 Miles
CANYON WASH
Boys Ranch 116 #5
2,784 BOE/D
Aug 4, 2013
Vertical
CLEVELAND
Knox Pipkin 28 #4
1,284 BOE/D
Sep 8, 2013
3,676’
GRANITE WASH
Stiles 3 #20-3H
2,142 BOE/D
Jan 29, 2013
5,245’
COTTAGE GROVE
Bartz 19 #21-19H1,318 BOE/D
Nov 25,2013
4,083’
GRANITE WASHJill 54 #4-54H
2,785 BOE/D
Mar 26, 2013
4,618’ COTTAGE GROVE
Stiles 1 #18-1H
1,318 BOE/D
Mar 22, 2013
3,388
COTTAGE GROVE
Simmons 3-30H
2,135 BOE/D
Apr 7, 2013
4,550’
LOWER MARMATON
Burns Family Trust 1-3H
1,657 BOE/D
Jun 16, 2013
4,158’
TONKAWA
Inselman 3-10H
841 BOE/D
Mar 22, 2013
3,998’
MARMATON
Webb Trust #1-1H2,150 BOE/D
Jun 20, 2013
4,550’
TONKAWA
Hagerman #1-25H
1,307 BOE/D
Aug 10, 2013
4,208’
APA acreage
Oil
Liquids Rich
Gas
CENTRAL REGION 2013 DRILLING HIGHLIGHTSEXCELLENT RESULTS IN EVERY PLAY
CLEVELAND
Flathers 232 #1H888 BOE/D
May 17, 2013
4,295’
LANDING ZONE
APA Well Name
Peak IP rate
Completion Date
Lateral length
CANYON WASH
Bivins-LIT 115 R1,890 BOE/D
Jun 14, 2013
Vertical
CENTRAL REGION
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83
Multiple stacked objectives is why we like the basin
Generalized Cross-Section of Anadarko Basin
Texas Panhandle Deep Basin Northern Oklahoma
CENTRAL REGIONFIVE MILES OF PROVEN PRODUCTION
GRANITE WASH
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Hugoton
Brown Dolomite
Chase / Council Grove
Admire
Upper Virgil
Douglas 9,400'
Tonkawa
Cottage Grove
Hogshooter 11,000'
Checkerboard
Cleveland
Marmaton 13,000'
Oswego
Cherokee
Skinner
Red Fork 15,000'
Witchita Orgeny
Morrow SH
Morrow SD P e n n .
Atoka
13 Finger Lime
D e e s e
Atokan
D o r n
H i l l s
G
R A N I T E W A S H
D o r n
H i l l s
Morrowan
C i s c o
Virgilian
H o x b a r
Missourian
L o w e r P e r m i a n
Wolfcampian
Desmoinesian
P e n n s y l v a n i a n
Acres (000) 855 (435 net)
2014 New Wells 62
Resources 3,849 MMBOE net
CONSISTENCY, ATTRACTIVE ECONOMICS, RUNNING ROOM
The term Granite Wash is textural
(maturity, grain size, minerals) rather
than depositional or digenetic
Apache has drilled 164 Granite Wash
horizontals in the last 5 years with
consistently strong results across 12
recognized zones
11 rigs running as of Q4 201384
Target Formation
Potential Apache TargetAPA acreage
15 mi
GRANITE WASH
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Granite Wash1
D+C Cost $MM 8.8
EUR MBOE 763
30-Day IP Rate Boed 1,404
% Oil / Gas / NGL 13% / 52%/ 35%WI / NRI 31% / 25%
ROR2 42%
Total Inventory 21,019
PUD + Probable Inventory 1,158
ECONOMICS, RECENT WELLS
Month
BOE/DDrilling Inventory Economics
85
Recent Well Highlights
APA acreage
APA 2013 Wells
Stiles 18 #25-18H
Caldwell
30-day IP BOE/D 1,585
EUR MBOE 1,324
Jill 54 #4H
Upper Granite Wash B
30-day IP BOE/D 2,697
EUR MBOE 1,272
Bartz 19 #20-19H
Granite Wash A
30-day IP BOE/D 1,466
EUR MBOE 1,140
Stiles 3 #27-3H
Caldwell30-day IP BOE/D 1,872
EUR MBOE 1,251
Stiles 4 #21-4H
Caldwell
30-day IP BOE/D 2,074
EUR MBOE 1,2960
200
400
600
800
1,000
1,200
1,400
1,600
0 6 12 18 24 30 36 42 48 54 60
2 mi
NYMEX
$/MMBTU ROR%$4.00 36%
$4.50 42%
$5.00 49%
$5.50 56%
Note 1. Type curve assumes 1 mile lateral.
Note 2. All well economics assume $90.00/Bbl WTI, $4.50/MMBTU NYMEX, and $27.00/Bbl NGL prices.
GRANITE WASH RESULTS VS. TYPE CURVE
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1
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
B O
E P D
Days On
Type Curve
Bartz 19 #15-19H
Bartz 19 SL #25-19H
Weatherly SL #6-1H
Tyler #4-55H
Stiles #10-16H
86
CLEVELAND
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Acres (000) 758 (429 net)
2014 New Wells 100
Resources 397 MMBOE net
ACCELERATED ACTIVITY IN 2014
Increased near term focus on
Cleveland oil targets Double the activity in 2014 with 4 rigs
running as of Q1 2014
Significantly reduced D+C cost to
$3.6MM
87
Hugoton
Brown Dolomite
Chase / Council Grove
Admire
Upper Virgil
Douglas 9,400'
Tonkawa
Cottage Grove
Hogshooter 11,000'
Checkerboard
Cleveland
Marmaton 13,000'
Oswego
Cherokee
Skinner
Red Fork 15,000'
Witchita Orgeny
Morrow SH
Morrow SD P e n n .
Atoka
13 Finger Lime
D e e s e
Atokan
D o r n
H i l l s
G
R A N I T E W A S H
D o r n
H i l l s
Morrowan
C i s c o
Virgilian
H o x b a r
Missourian
L o w e r P e r m i a n
Wolfcampian
Desmoinesian
P e n n s y l v a n i a n
Target Formation
Potential Apache TargetAPA acreage
15 mi
CLEVELAND
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TRACK RECORD OF STRONG PRODUCTION GROWTH
Strong history of liquids driven growth, with 60 horizontals drilled by
Apache in the last 5 years
Near term focus on oil targets, with ample liquids rich opportunity on the
horizon
88
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Liquids BOE
APA acreage
15 mi
CLEVELAND
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Cleveland1
D+C Cost $MM 3.6
EUR MBOE 275
30-Day IP Rate Boed 404
% Oil / Gas / NGL 16% / 51%/ 33%WI / NRI 52% / 41%
ROR 22%
Total Inventory 3,479
PUD + Probable Inventory 175
Drilling Inventory Economics
Month
BOE/D
ECONOMICS, RECENT WELLS
89
Recent Well Highlights
2 mi
APA acreage
APA 2013 Wells
Knox Pipkin 28-4H
30-day IP BOE/D 1,051
EUR MBOE 360
Leland Mekeel 226-4H
30-day IP BOE/D 494
EUR MBOE 352
Mekeel 303 3H
30-day IP BOE/D 592EUR MBOE 330
Flathers 232-1H
30-day IP BOE/D 702
EUR MBOE 260
Hoover 216-4H30-day IP BOE/D 715
EUR MBOE 4430
50
100
150
200
250
300
350
400
450
0 6 12 18 24 30 36 42 48 54 60
NYMEX
$/MMBTU ROR%
$4.00 19%
$4.50 22%$5.00 25%
$5.50 29%
Note 1. Type curve assumes 1 mile lateral.
CLEVELAND RESULTS VS. TYPE CURVE
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90
1
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
B O
E P D
Days On
Type Curve
Hoover 216-4H
Knox Pipkin 28-4H
Flathers 232-1H
Leland Meekel 226-4H
Meekel 303-3H
TONKAWA
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Apache is a proven leader in horizontal
Tonkawa drilling
91 wells drilled in 2012 and 2013 alone
7 rigs running as of Q1 2014
Successfully reduced D+C cost to
$4.5MM
Acres (000) 822 (407 net)
2014 New Wells 93
Resources 242 MMBOE net
PROLIFIC OIL PLAY MOVING TO PAD DEVELOPMENT
91
Hugoton
Brown Dolomite
Chase / Council Grove
AdmireUpper Virgil
Douglas 9,400'
Tonkawa
Cottage Grove
Hogshooter 11,000'
Checkerboard
Cleveland
Marmaton 13,000'
Oswego
Cherokee
Skinner
Red Fork 15,000'
Witchita Orgeny
Morrow SH
Morrow SD P e
n n .
Atoka
13 Finger Lime
D e e s e
Atokan
D o r n
H i l l s
G R A N I T E W A S H
D o r n
H i l l s
Morrowan
C i s c o
Virgilian
H o x b a r
Missourian
L o w e r P e r m i a n
Wolfcampian
Desmoinesian
P e n
n s y l v a n i a n
Target Formation
Potential Apache TargetAPA acreage
15 mi
OPERATIONAL EXCELLENCE
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4134 30
23 22 24
0
25
50
2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3 2013 Q4
Drilling Days
3.10 2.75 2.50 2.35 2.05 1.90
0.0
2.5
5.0
2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3 2013 Q4
Completion Costs39% Cost
Reduction
Completed cost for 13,000’ 10 stage well
reduced from $6.4 MM to $4.5 MM92
INCREASING EFFICIENCIES IN TONKAWA
TONKAWA
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Tonkawa1
D+C Cost $MM 4.5
EUR MBOE 245
30-Day IP Rate Boed 335
% Oil / Gas / NGL 53% / 28%/ 19%
WI / NRI 36% / 29%
ROR 25%
Total Inventory 3,419
PUD + Probable Inventory 518
Oak 2-16H
30-day IP BOE/D 956
EUR MBOE 394
0
50
100
150
200
250
300
350
0 6 12 18 24 30 36 42 48 54 60
Drilling Inventory Economics
ECONOMICS, RECENT WELLS
Month
BOE/D
93
Recent Well Highlights
APA acreage
APA 2013 Wells
Chenette 2-9H
30-day IP BOE/D 632
EUR MBOE 415
Denney 2-19H
30-day IP BOE/D 571EUR MBOE 511
Beavin 24-17-25 2H
30-day IP BOE/D 682
EUR MBOE 319
3 mi
NYMEX$/MMBTU ROR%
$4.00 24%
$4.50 25%
$5.00 26%
$5.50 27%
Note 1. Type curve assumes 1 mile lateral.
TONKAWA RESULTS VS. TYPE CURVE
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94
1
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
B O E P D
Days On
Type Curve
Beavin 24-17-25 #2H
Denney 2-19H
Chenette 2-9H
Oak 2-16HAllen 2-15H
McCracken 2-16H
Teague 1-23H
MARMATONACTIVITY IN PLAY EXPANDING TO DEEP BASIN
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Hugoton
Brown Dolomite
Chase / Council Grove
Admire
Upper Virgil
Douglas 9,400'
Tonkawa
Cottage Grove
Hogshooter 11,000'
Checkerboard
Cleveland
Marmaton 13,000'
Oswego
Cherokee
Skinner
Red Fork 15,000'
Witchita Orgeny
Morrow SH
Morrow SD P e n n .
Atoka
13 Finger Lime
D e e s e
Atokan
D o r n
H i l l s
G R A
N I T E W A S H
D o r n
H i l l s
Morrowan
C i s c o
Virgilian
H o x b a r
Missourian
L o w e r P e
r m i a n
Wolfcampian
Desmoinesian
P e n n s y l v a n i a n
Acres (000) 609 (295 net)
2014 New WellsMarmaton Shelf
Lower Marmaton
6436
28
Resources 271 MMBOE net
ACTIVITY IN PLAY EXPANDING TO DEEP BASIN
Increased focus on deep basin
opportunity Double the activity in Lower Marmaton
in 2014
APA acreage provides exposure to a very
significant portion of the play area
95
Target Formation
Potential Apache Target
SHELF
DEEP
BASIN
APA acreage
15 mi
MARMATON SHELFECONOMICS RECENT WELLS
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Marmaton Shelf 1
D+C Cost $MM 4.1
EUR MBOE 246
30-Day IP Rate Boed 254
% Oil / Gas / NGL 39% / 35%/ 27%WI / NRI 42% / 34%
ROR 22%
Total Inventory 2,684
PUD + Probable Inventory 88
Carolea 594 1H
30-day IP BOE/D 239EUR MBOE 240
Wheat 678 4H (2012)
30-day IP BOE/D 484
EUR MBOE 350
Wheat 678 3H (2012)
30-day IP BOE/D 280
EUR MBOE 365
0
50
100
150
200
250
300
0 6 12 18 24 30 36 42 48 54 60
Month
BOE/DDrilling Inventory Economics
ECONOMICS, RECENT WELLS
96
Recent Well Highlights
2 mi
APA acreage
APA 2013 Wells
Beavin 1-24H
30-day IP BOE/D 336
EUR MBOE 260
NYMEX
$/MMBTU ROR%
$4.00 20%
$4.50 22%
$5.00 23%
$5.50 24%
Note 1. Type curve assumes 1 mile lateral.
MARMATON SHELF RESULTS VS. TYPE CURVE
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1
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
B O
E P D
Days On
Type Curve
Randall 640-1H
Wheat 678-4H
Wheat 678-3H
97
LOWER MARMATON: AN EMERGING DEEP PLAYECONOMICS RECENT WELLS
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Lower Marmaton1
D+C Cost $MM 10.0
EUR MBOE 1,207
30-Day IP Rate Boed 1,716
% Oil / Gas / NGL 14% / 52%/ 35%WI / NRI 32% / 25%
ROR 37%
Current Inventory 170
PUD + Probable Inventory 49
Month
Drilling Inventory Economics
ECONOMICS, RECENT WELLS
98
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
0 6 12 18 24 30 36 42 48 54 60
Recent Well Highlights
3 mi
APA acreage
APA 2013 Wells
Bombay 2-32H
30-day IP BOE/D 2,204
EUR MBOE 1,188
Mamie 5-4H
30-day IP BOE/D 1,767
EUR MBOE 1,293
Merritt 1-29H30-day IP BOE/D 1,054
EUR MBOE 985
Merritt 1-28H30-day IP BOE/D 2,522
EUR MBOE 1,096
BOE/D
NYMEX
$/MMBTU ROR%
$4.00 33%
$4.50 37%
$5.00 42%
$5.50 47%
Note 1. Type curve assumes 1 mile lateral.
LOWER MARMATON RESULTS VS. TYPE CURVE
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100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
B O E P D
Days On
Type Curve
Mamie 5-4HC
Bombay 2-32H
Merritt 1-28H
Skyy 2-32H
Frank 1-34H
99
COTTAGE GROVEHIGH ROR HORIZONTAL OIL PLAY
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Apache drilled first horizontal in OK
34 wells drilled by Apache since 2012 Continue to evaluate acreage for aerial
extent and additional opportunity
100
Acres (000) 222 (93 net)
2014 New Wells 28
Resources 9 MMBOE net
Hugoton
Brown Dolomite
Chase / Council Grove
AdmireUpper Virgil
Douglas 9,400'
Tonkawa
Cottage Grove
Hogshooter 11,000'
Checkerboard
Cleveland
Marmaton 13,000'
Oswego
Cherokee
Skinner
Red Fork 15,000'
Witchita Orgeny
Morrow SH
Morrow SD P e
n n .
Atoka
13 Finger Lime
D e e s e
Atokan
D o r n
H i l l s
G R A N I T E W A S H
D o r n
H i l l s
Morrowan
C i s c o
Virgilian
H o x b a r
Missourian
L o w e r P e r m i a n
Wolfcampian
Desmoinesian
P e n
n s y l v a n i a n
Target Formation
Potential Apache Target
HIGH ROR HORIZONTAL OIL PLAY
APA acreage
15 mi
COTTAGE GROVEECONOMICS RECENT WELLS
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Cottage Grove1
D+C Cost $MM 7.3
EUR MBOE 318
30-Day IP Rate Boed 752
% Oil / Gas / NGL 69% / 14%/ 17%
WI / NRI 68% / 54%
ROR 50%
Total Inventory 54
PUD + Probable Inventory 27
Drilling Inventory Economics
ECONOMICS, RECENT WELLS
101
0
100
200
300
400
500
600
700
800
0 6 12 18 24 30 36 42 48 54 60
Recent Well Highlights
1 mi
APA acreage
APA 2013 Wells
Stiles 4 #17-4H30-day IP BOE/D 1,495
EUR MBOE 636
Stiles 16 #15-16H
30-day IP BOE/D 455EUR MBOE 435
Stiles 18 #18-18H30-day IP BOE/D 662
EUR MBOE 438
Bartz 19 #21-19H
30-day IP BOE/D 1,314
EUR MBOE 573
Stiles 1 #18-1H
30-day IP BOE/D 616
EUR MBOE 531
Month
BOE/D
NYMEX
$/MMBTU ROR%
$4.00 49%
$4.50 50%
$5.00 51%
$5.50 52%
Note 1. Type curve assumes 1 mile lateral.
COTTAGE GROVE RESULTS VS. TYPE CURVE
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1
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
B O
E P D
Days On
Type Curve
Stiles 68 #27-68H
Stiles 4 #18-4H
Stiles 3 #24-3H
Bartz 19 #21-19H
102
CANYON WASHBIVINS RANCH ACHIEVED 10 000 BOPD IN 23 MONTHS
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BIVINS RANCH ACHIEVED 10,000 BOPD IN 23 MONTHS
103
200 square mile contiguous position with less than one well per 20 miles
2 rigs deployed for past two years
Paint Ridge has 10 MMBO EUR with additional 16 MMBO secondary potential
Greatest opportunity may yet be the horizontal in Canyon Limestone
Apache drilling its first Canyon Lime horizontal in 2014
Acres (000) 150 (100 net)
2014 New Wells 10
Resources 107 MMBOE net
Quaternay
Tertiary
Triassic Dockum
Ochoa
Artesia
Pease River
Clear ForkWichita
Wolfcamp
Virgil Cisco
Des Moines Canyon
Atoka Strawn
Morrow Bend
Mississippian Chester
Maramec
Osage
Permian
Pennsylvanian
Guadalupe
Leonard
2013 Wells
Apache Acreage
Canyon Lime location
Canyon Wash location
61 sqmi 3D
Apache 244sq mile 3D
Continental Resources
LS Ranch 642-1HAPA 10% WI
Bivins-LIT 115 RCanyon Wash
30 Day IP – 1,674 BOE/D
Boys Ranch 116 #5Canyon Wash
30 Day IP – 2,246 BOE/D
Bivins LIT 110#1Canyon Lime Vertical test
30 Day IP – 20 BO/D
Bivins East 41-1HCanyon Lime Horizontal
Drilling
2 mi
Paint Ridge
Field
CENTRAL REGIONBIVINS RANCH HORIZONTAL CANYON LIMESTONE EXPLORATION
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Canyon Lime is a continuous reservoir overlying sandstone
One horizontal well drilling & 4 more planned for 2014
Canyon Wash Canyon Lime
4,200 BO Cum (Lime) 1,000,000 BOE EUR (Wash) 9,222 BO Cum (Lime)
CIG Ware #1 Celeron Bivins 1-39PApache Bivins 115 #1
Canyon LimeCanyon Lime
A A’
160 Acre Spacing
Celeron
Bivins #1-39PAccumulated 9 MBO from
perforations in vertical section
Continental Resources
LS Ranch 642-1HAPA 10% WI
A
A’
CIG
Ware #1Accumulated 4 MBO from
perforation in vertical section
ApacheBivins East 41-1HCurrently drilling first Apache
Canyon Lime test
Paint Ridge
Field
Apache
Bivins LIT 110#1Canyon LM successful vertical test
Stratigraphic Cross-Section through Canyon Limestone
104
BIVINS RANCH HORIZONTAL CANYON LIMESTONE EXPLORATION
Apache Acreage2 mi
CENTRAL REGION – EXCEEDING EXPECTATIONS
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56
82
45
61
91
0
10
20
30
40
50
60
70
80
90
100
2011 2012 2013
2012 Base Projections Actual
M B O E
/ D
2011
105
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CANADA
John Christmann
February 26, 2014
CANADA’S ASSET BASETRANSFORMATION UNDERWAY
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TRANSFORMATION UNDERWAY
107
Recently Divested Acreage
Alberta
Repositioning Canada1
Before After2
Gross Acres 6.2 MM 4.1 MM
Net Acres 4.9 MM 3.2 MM
Active Well Count 9,613 3,535
British
Columbia
Kitimat
Upstream
Note 1. Amounts exclude wells and acres attributable to Kitimat Upstream.
Note 2. Also excludes acreage and wells attributable 2013 and 2014 divestitures.
2014 Divestment Acreage
Current Apache Acreage
Divested nearly two-thirds ofApache’s well count and one-
third of production in Canada.
APACHE CANADALIQUIDS RICH OPPORTUNITIES
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LIQUIDS-RICH OPPORTUNITIES
108
Apache AcreageKaybob
West 5
Provost
House
Mountain
Kitimat
Upstream
APA Hz rigs (8)
Note 1. Excludes 2013 divestitures as of their closing date and 2014 potential divestitures as of January 2013.
Note 2. Excludes capital associated with Kitimat project of $204 million.
Note 3. Land retention wells excluded
Note 4: Excludes amounts attributable to 2013 divestitures, 2014 divestitures and Kitimat Upstream.
2013 RESULTS
Pro forma AverageProduction (Includes legacy
Horn River Production)1
74,582 BOE/D
Pro forma % Liquids
(Includes Legacy Horn River
Production)1
30%
Prod. Replacement 189%
Pro Forma Proved Reserves1 410 MMBOE
Capital2 $705 MM
Average Rigs 7 (6 Hz)
Gross Wells3
143 (129 Hz)
4.1 million gross acres (3.2 million net)4
3,535 active wells4
8 rigs running
Current Rigs
TRANSFORMING THE REGIONRE POSITIONING THE BASE FOR GROWTH
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RE-POSITIONING THE BASE FOR GROWTH
Note 1. Figures exclude Horn River / NEBC and Divest Properties.109
2014 PLAN1
Capital $600 MM
2014 Avg. Rigs 8 (7 Hz)
Gross Wells 121 (117 Hz)
Liquids Focused Drilling
Evaluated the resource base
Divested non-core gas properties in 2013
Additional 2014 divestitures
Noel, Wapiti, Ojay
Core plays Bluesky - 32 wells
Swan Hills - 12 wells
Provost Viking - 24 wells
Set in motion plans for additional growth
in new liquids-rich areas Duvernay - 6 wells
Montney - 2 wells
Ellerslie - 4 wells
MULTIPLE STACKED PLAYS
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ELLERSLIE
CARDIUM
VIKING
DUNVEGAN
DUVERNAY
BEAVERHILL
LAKE
MONTNEY
BLUESKY /
GLAUCONITE
Black Oil Plays
Repeatable low cost /high ROR drilling
inventory
Liquids Rich Gas Plays
Deep basin gas plays
provide high rates and
significant volumes
Secondary Recovery High ROR development
projects
110
CURRENT RESOURCE INVENTORY
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Dunvegan
Gross Acreage: 350,928
Net MMBOE: 174
Duvernay
Gross Acreage: 265,204
Net MMBOE: 461
Bluesky / Glauconite
Gross Acreage: 561,110
Net MMBOE: 808
Viking
Gross Acreage: 1,359,129
Net MMBOE: 337
Montney
Gross Acreage: 157,874
Net MMBOE: 254
Cardium
Gross Acreage: 558,476
Net MMBOE: 341
Net Resources Gross / Net Acreage1
2.8 BBOE 4.1 MM/ 3.2 MM
Ellerslie
Gross Acreage: 260,720Net MMBOE : 252
111 Note 1. Excludes acreage attributable to 2014 divestitures and Kitimat Upstream..
CANADA REGION – RECENT WELL HIGHLIGHTSBluesky
Dunvegan
Swan Hills
Well Name
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Bluesky
9-20-58-18W5
6,500 MCF/D; 400 BO/D
4,203’
Dunvegan
9-35-60-20W5
508 BO/D
4835’
Dina
11-26-34-9W4
198 BO/D
Vertical Drill
PROVOSTWEST 5
KAYBOB
WAPITI
Noel
Bluesky
13-30-58-19W5
4,500 MCF/D; 280 BO/D
4,157’
Bluesky
4-28-58-19W5
4,600 MCF/D; 393 BO/D
4,147’
2013 drilled 143 wells in 12 different formations
Excellent well results throughout the Canadian Region
Glauconite
13-19-41-5W5
3,900 MCF/D; 135 BO/D4,931’
Glauconite
16-18-40-6W5
4,500 MCF/D; 243 BO/D
7,047’
Swan Hills
8-26-70-11W5
214 BO/D
2,614’
Swan Hills
6-24-69-10W5266 BO/D
2,720’
Swan Hills
14-1-69-11W5
320 BO/D
3,186’
Viking
7-29-35-4W4
144 BO/D
3,280’
Montney
1-13-59-21W5
5,635 MCF/D; 40 BO/D
4,058’
112
Play/Formation
30-Day IP Rate
Lateral Length
Sparky
11-32-36-4W4166 BO/D
3,526’
LOWER CRETACEOUS BLUESKY / GLAUCONITEHORIZONTAL REDEVELOMENT
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113
HORIZONTAL REDEVELOMENT
Acres (000) 561 (378 Net)
2014P New Wells 44
Drilling Inventory 3,041
Resources 808 MMBOE net
Established Bluesky liquids-rich
horizontal play
Play fairway defined by verticalproducers
41 APA horizontal wells drilled to
date
4 rigs running
Kaybob
(Current focusarea)
BC
AB
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
B O E P D
Date
2012 / 2013 DRILLING PROGRAM
Production decrease
attributed to third-party
plant downtime
BLUESKY PLAY OVERVIEW - KAYBOB
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Cretaceous sandstone play
Horizontal development program
Liquids rich gas (55 BBLS/ MMSCF)
Doubling activity level in 2014
Testing upside potential
Edges of Sand Lobes
Well Density / Spacing
Increased focus on pad drilling
APA 16-27 HZ
30-day IP BOE/D 620
EUR MBOE 573
APA 12-21 HZTest BOE/D 1,199
EUR MBOE 1,070
APA 4-21 HZ
30-day IP BOE/D 1,390
EUR MBOE 1,020
5 mi
APA 9-20 HZ
IP BOE/D 1,093
EUR MBOE 677
APA 9-7 HZ
30-day IP BOE/D 700
EUR MBOE 630
Apache acreage
Proposed Apache wells
Apache drilled wells
114
BLUESKY FORMATIONKAYBOB DEVELOPMENT AREA
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115
Drilling Economics
D+C Cost $MM 5.5
EUR MBOE 585
% Oil / Gas / Liquids 10% / 72% / 18%
30-Day IP Rate Boed 971
ROR 36%
WI/NRI 66% / 55%
Current Inventory 1,944
PUD + Probable Inventory 168
KAYBOB DEVELOPMENT AREA
0
200
400
600
800
1,000
1,200
0 6 12 18 24 30 36 42 48 54 60
BOE/D Production Type Curve
Month
Note: Well economics assume a $90.00/Bbl WTI, $4.50/MMBTU NYMEX gas and lateral length of 4,200’.
NYMEX
$/MMBTU ROR%
$4.00 30%
$4.50 36%
$5.00 43%
$5.50 50%
BLUESKY FORMATIONKAYBOB DEVELOPMENT AREA
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116
KAYBOB DEVELOPMENT AREA
Note: Type curve assumes lateral length of 4,200’.
DUVERNAY FORMATIONDEVONIAN SHALE – ALBERTA DEEP BASIN
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117
DEVONIAN SHALE ALBERTA DEEP BASIN
Acres (000) 239 Gross (176 net)
2014P New Wells 6
Drilling Inventory 1,656
Resources 461 MMBOE net
Six wells planned in 2014
2-8 flowing back – no test rate yet
2-28 completing
4 wells remaining to be drilled
Competitor wells have de-risked
Apache acreage in the Kaybob LRG
fairway
Condensate yield on Apache acreage
100-250 BBLS/MMSCF
APA acreage
Key industry wells
APA Proposed wells
APA drilled wells
Map focus area depicts only ~137,000 gross
acres of total 239,000 prospective for Duvernay
DUVERNAY LIQUIDS FAIRWAYKAYBOB AND SIMONETTE
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KAYBOB AND SIMONETTE
Drilling Economics
D+C Cost $MM 13
EUR MBOE 684
% Oil / Gas / Liquids 40% / 45% / 15%
30-Day IP Rate Boed 995
ROR 37%
WI/NRI 71% / 68%
Current Inventory 574
PUD + Probable Inventory 11
Production Type Curve
NYMEX
$/MMBTU ROR%
$4.00 35%
$4.50 37%
$5.00 39%
$5.50 41%
118Note: Well economics assume a $90.00/Bbl WTI, $4.50/MMBTU NYMEX gas and lateral length of 4,200’.
MONTNEY FORMATIONHIGH RATE / HIGH MMBOE RESERVOIR
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119
HIGH RATE / HIGH MMBOE RESERVOIR
Acres (000) 158 Gross (124 Net)
2014P New Wells 2
Drilling Inventory 837
Resources 254 MMBOE net
Proven opportunity in stacked zones inliquids rich fairway
Two locations planned for 2014
13-18 completing
Well-positioned acreage base withsignificant upside
M o n t n e y
NUVISTA 16-21-Hz
30-day IP BOE/D 1031
SINOPEC 14-36 Hz
30-day IP BOE/D 1054
SINOPEC 15-29 Hz
30-day IP BOE/D 1610
5 miAPACHE 13-18-Hz
APA acreageKey industry wells
APA drilled wells
Map depicts only 9,600
acres of total 158,000
prospective for Montney
BC
AB
MONTNEY FORMATIONLIQUIDS RICH FAIRWAY
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120
LIQUIDS RICH FAIRWAY
Drilling Economics
D+C Cost $MM 7.3
EUR MBOE 877
% Oil / Gas / Liquids 14% / 78% / 8%
30-Day IP Rate Boed 892
ROR 25%
WI/NRI 73% / 66%
PUD + Probable Inventory 1610
100
200
300
400
500
600
700
800
900
0 6 12 18 24 30 36 42 48 54 60
BOE/D Production Type Curve
Month
NYMEX
$/MMBTU ROR%
$4.00 20%
$4.50 25%
$5.00 29%
$5.50 33%
Note: Well economics assume a $90.00/Bbl WTI, $4.50/MMBTU NYMEX gas and lateral length of 4,000’.
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GULF COAST ONSHORE
John Christmann
February 26, 2014
GULF COAST REGIONDELIVERING GROWTH
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122
2014 Plan
Capital $550 MM
2014 Avg. Rigs 6
Gross Wells1 85
2013 Results
Average Production
30.8 MBOE/D
+11.5% YoY
Liquids Growth +6.5% YoY
Prod. Replacement 81%
Proved Reserves 70 MMBOE
Capital $319 MMAverage Rigs 2
Gross Wells 43
Eagle Ford
South LA
Miocene
Apache Acreage
40 Miles
1.3 million acres (894,100 net)
1,285 active wells
Currently running 6 rigs
Note 1. Represents operated and non-operated wells Apache participates in.
APA Hz rigs
(3)
APA Vt rigs
(3)
Currently running 6 rigs
EAGLE FORD SHALE PLAYTARGETING OIL IN NORTHERN WINDOW
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Maverick Basin and
San Marcos ArchEast Texas Basin
U p p e r C r e t a c e o
u s
C o n i a c i a n ,
S a n t o n i a n ,
C a m p a n i a n
Austin Chalk Austin Group
T u
r o n i a n
Eagle Ford Shale
Eagle Ford Group
C e n
o m a n i a n
Buda Limestone Buda Limestone
Del Rio (Grayson)
Shale
Del Rio (Grayson)
Shale
Georgetown
Limestone
Georgetown
Limestone
Woodbine
GroupPepper
Shale
Maness Shale
Note: Map courtesy of Texas Railroad Commission.
Apache Acreage:
488,000 gross acres182,000 net acres
123
CENTRAL TEXAS EAGLE FORD2014 PROGRAM
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Testing play and evaluating resourcepotential
3 rigs running, ramp up to 4 in Q2
3D seismic - over 1,000 square miles of
new data acquisition in progress
Location advantages:
Large leasehold (181,669 net acres)
Infrastructure in place
Existing water source
Chalk / Buda potential
2014 Eagle Ford Plans
Acres (000) 488 (182 net)
2014 Capital ($MM) $300
2014 Avg. Rigs 4
2014 Gross Wells 40+
124
150 – 250
Locations
APACHE AND PEER WELL RESULTSRESULTS TO DATE IN BURLESON AND BRAZOS COUNTIES
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389
282
331
304
696
380
APA Stasny - Porterfield EF #1H & #2H
Peak Rate #1 H: 728 BOE/D
Peak Rate #2 H: 597 BOE/D
APA Reveille #8H, #9H, #11H(3 rigs drilling)
APA McCullough-Wineman #2H
(Completing)
Leone #2H
Peak Rate: 611 BOE/D
30 day IP: 257 BOE/D
Lateral: 4,747’
APA Reveille #7H
Peak Rate: 892 BOE/D
30 day IP: 535 BOE/D
Lateral: 4,909’Apache Acreage
Apache Operated Eagle Ford Wells (30 day IP-BOE/D)
Industry Eagle Ford Wells (30 day IP-BOE/D)
12 wells with
Average 30-day rates of ~590
BOE/D
Company A
30 day IP: 719 BO/D
Company B
30 day IP: 626 BO/D
125
695 619
512
530
636551
605
585
726
586
696 379
CENTRAL TEXAS EAGLE FORD DEVELOPMENT BASED ON 1 000’ WELL SPACING
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DEVELOPMENT BASED ON 1,000 WELL SPACING
126
South Texas Central Texas Net pay thins NE of San Marcos Arch ~45 ft net pay in Apache acreage
Well spacing 1,000 ft
Drainage area 160 acres for 7,000 ft lateral
CITY OF
BRYAN
CITY OF
COLLEGESTATION
Well Spacing 1,000 ft
1,000’
45’ 115’+
EAGLE FORDECONOMICS
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0
100
200
300
400
500
600
0 6 12 18 24 30 36 42 48 54 60
Production Type Curve BOE/D
Month
127 Note: Well economics assume $90/Bbl WTI, $4.00 MMBTU NYMEX,$27.00/Bbl NGL prices and 7,000’ lateral length.
Drilling EconomicsD+C Cost $MM 8.3
EUR MBOE 330
30-Day IP (BOE/D) 572
% Oil / Gas / NGL 56% / 13% / 31%
WI / NRI 100% / 80%ROR 25%
EAGLE FORD PRODUCTION APACHE WELLS IN BURLESON AND BRAZOS COUNTIES
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0
200
400
600
800
1,000
1,200
0 30 60 90 120
BOE/D
Days
Apache Type Curve
Lateral Length: 7,000’
EUR = 330MBOE
128
Reveille #7HDowntime removed and type curve
assumes 7,000’ lateral length
Stasny - Porterfield EF #1H
Lateral Length: 5,515’
Stasny - Porterfield EF #2H
Lateral Length: 5,303’
Leone #2HLateral Length: 4,747’ Note: Geosteering issue, 2/3 of
lateral below pay.
NORTH AMERICAN POWERHOUSE
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129
Most active driller
Track record of delivering consistent, repeatable growth
Organic production replacement of 230% at $17 per BOE
Substantial reduction of costs in resource plays
Massive resource base
Almost 14 BBOE
Including 4.8 BBOE in the Permian
Emerging resource plays under assessment
12% to 16% liquids growth over the next three years
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BREAK
130
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INTERNATIONAL& GOM
Tom Voytovich
February 26, 2014
INTERNATIONAL AND GOM SUMMARY
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International generates > $1 billion free cash per year
High rate of return oil drilling opportunities
North Sea: 7+ years currently identified
Egypt: 20+ years of resource inventory
Australia delivers near and long-term oil production growth
25+ MBOED peak production from 2014 projects
LNG delivers 30+ MBOED and $1 billion of free cash per year for 20 years
International provides upside oil growth potential
North Sea exploration
Egypt horizontal drilling
GOM provides production growth and exploration upside Lucius/Heidelberg: combined ~20 MBOED peak production
Deep Shelf exploration
132
NORTH SEA EXCEPTIONAL RETURNS AND FREE CASH FLOW
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EXCEPTIONAL RETURNS AND FREE CASH FLOW
133
2014 Plans
Capital $900 MM
2014 Avg. Rigs 5
Gross Wells1 31
2013 Highlights
Production 73,487 BOED
Cash Flow $1.4 Bn
Capital $875 MM
Average Rigs 4
Gross Wells1 19
Success Rate 93%Proved Reserves 150 MMBOE
Note 1. Gross wells include water injectors.
Brent-linked oil portfolio (86%)
continues to deliver significant cash flow
2013 free cash flow of ~ $500MM
Significant inventory identified following
recent seismic at Forties and Beryl
FASP in place (18 drilling slots)
North Sea
Apache Acreage
Oil Field
Gas Field
Buckland
BERYL
Skene
Maclure
Nevis South
Nevis & Ness
Complexes
Scott & Telford
Bacchus
Aviat
Nelson
Sage Gas PlantFORTIES
APACHE NORTH SEA PERFORMANCE #1 IN UK NORTH SEA PRODUCTION EFFICIENCY
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Apache at ~90% efficiency vs.operator average of ~60%
Continuous improvement
since 2003 acquisition
#1 IN UK NORTH SEA PRODUCTION EFFICIENCY
134
2012 Production Efficiency Ranking 1
Note 1. Production Efficiency Data was provided by the Production Efficiency Task Force, a task force of the UK government policy advisory group PILOT.
2013 FORTIES AREA RESULTS 9 WELLS DRILLED IN 2013 (6 FORTIES 2 TONTO 1 BACCHUS)
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Tonto
Maule
Forties
Bacchus
Note: IPs are 30 day average rates. EURs reported are gross.
9 WELLS DRILLED IN 2013 (6 FORTIES, 2 TONTO, 1 BACCHUS)
135
2013 Program
RoR: 100%EUR: 14 MMBOE
T225
IP: 974 BO/D
EUR: 123 MBOE
RoR: 13%
T257
IP: 4,291 BO/D
EUR: 1,400 MBOE
RoR: 100%
Tonto (BB5)
IP: 4,422 BO/D
EUR: 732MBOE
RoR: 100%
Bacchus B1
IP: 8,485 BO/D
EUR: 7,439 MBOE
RoR: 100%
T260
IP: 3,512 BO/D
EUR: 1,200 MBOE
RoR: 100%
T1-RD
IP: 3,140 BO/D
EUR: 740 MBOE
RoR: 100%
Tonto (BB1)
IP: 4,517 BO/D
EUR: 721RoR: 100%
T159
IP: 2,700 BO/D
EUR: 800 MBOE
RoR: 100%
T247
IP: 2,230 BO/D
EUR: 820 MBOE
RoR: 100%
FORTIES ALPHA SATELLITE PLATFORMINCREASED ACCESS TO UNDEVELOPED RESERVES
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INCREASED ACCESS TO UNDEVELOPED RESERVES
136
18 new well slots allow access to additional targets sooner
Increases available field slots by 138%, total field slots by 14% Drilling start up 2Q 2014
2014 FASP locations
2014 Forties locations
Prospects/Leads
2014 FORTIES FIELD DEVELOPMENTBUILDING ON PAST SUCCESS
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Strong target inventory derived
from 2013 4D seismic
Plan average of 3 rigs in 2014
15 total wells in 2014,
up from 9 in 2013
Nearly 6 years of inventory based
on current inventory
BUILDING ON PAST SUCCESS
137
2014 Planned Locations
Current Drilling Inventory
2014P Locations 15
Prospects + Leads 72
Total 87Tonto
MauleForties
Bacchus
2013 BERYL RESULTS 4 WELLS DRILLED (2 ALPHA, 2 BRAVO)
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Beryl Bravo
Buckland
Skene
Beryl Alpha
XSP HztlIP: 13,201 BOE/D
EUR: 840 MBOE
RoR: 100%
BWKIP: 16.5 MMCF/D
EUR: 354 MBOE
RoR: 58%
ASCIP: 2,805 BOE/D
EUR: 410 MBOE
RoR: 100%
5 km
BDDIP: 8,097 BOE/D
EUR: 1,226 MBOE
RoR: 100%
Nevis
4 WELLS DRILLED (2 ALPHA, 2 BRAVO)
138
Ness
2013 Program
RoR: 100%EUR: 2.8 MMBOE
Note: IPs are 30 day average rates. EURs reported are gross.
2014 BERYL AREA EXPLOITATIONCONTINUING TO BUILD AND DRILL EXPANDING INVENTORY
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2013 seismic delivering new
inventory in 2014
Plan average of 2 rigs in 2014
2014 plan includes 6 wells, up from
4 in 2013
Many years of drilling opportunities
CONTINUING TO BUILD AND DRILL EXPANDING INVENTORY
139
Current Drilling Inventory
2014P Locations 6
Prospects + Leads 117
Total 123
5 km
Producer
Water injector
Beryl Bravo
BucklandSkene
Beryl AlphaNess
Nevis
HIGH POTENTIAL EXPLORATION INVENTORYTOTAL ASSESSED GROSS RESOURCE OF 220-545 MMBOE
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TOTAL ASSESSED GROSS RESOURCE OF 220 545 MMBOE
140
Les Arcs (2014 drill)
Isabella
Val D’Sere
Komodo
Wyvern
A-Basin
Vail
Jessica
Forties
Val D’Sere Les Arcs
A-Basin
Komodo
Isabella
Jessica
Beryl
Vail
Skiddaw
Albion
P50 to P10
50 to 130
MMboe
P50 to P10
100 to 245
MMboe
P50 to P10
70 to 170
MMboe
Note: Resource estimates are gross.
EXPLORATION PROSPECT INVENTORY
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0
50
100
150
200
250
A B C D E F G H I J K L M N O P
Prospects
Gross P-10 Reserves
Gross Mean ReservesNet Mean Reserves
2013 Proved Reserves: 150 MMBOE
141
Unrisked Reserves
(MMBOE)
EGYPTSTRONG RETURNS AND FREE CASH FLOW FROM CONSISTENT E&D PROGRAM
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142
2014 Plans
Capital3
$1.37 Bn
($0.91 Bn APA)
2014 Avg. Rigs 27
Gross Wells4 265
Drilling TargetsBahariya, Abu Roash, AEB,
Jurassic and Paleozoic
2013 Highlights
Gross Production 350 MBOE/D
Net Production2 With Tax: 149 MBOE/D
w/o Tax: 108 MBOE/D
PF w/o Tax: 72 MBOE/D
Cash Flow2 $2.4 Bn
(PF $1.6 Bn APA)
Capital3 $1.25 Bn
(PF $0.8 Bn APA)
Average Rigs 26
Gross Wells4 235
Success Rate 86%
Note 1. As of February 2014.
Note 2. Pro Forma (PF) excludes full year amounts attributable to noncontrolling interest.
Note 3. Capital includes E&D + GTP. Pro Forma (PF) excludes full year amounts attributable to noncontrolling interest.
Note 4. Includes water injector wells.
AbuGharadiq
Alamein
MatruhShushan-Khalda
Ridge
Faghur
Gulf of
Suez
Gindi / Beni
Suef
E. Abu
GharadiqMajor Basins
Apache Acreage
CURRENT LEASEHOLD1:
6.8 MM gross acres
24 Concessions
EGYPT PRO FORMAOUTSTANDING FREE CASH FLOW GENERATION
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143
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2008 2009 2010 2011 2012 2013 2013PF
$Bn
Notes: Cash flow from operations before changes in working capital items. 2013 actual number include s noncontrolling interest. 2013PF excludes noncontrolling interest.
CAPEX includes E&D + GTP but excludes A&D.
CAPEX Cash Flow
DEVELOPMENT LEASE HISTORY RECORD APPROVALS IN LAST TWO YEARS
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144
15
1 10
2
0 0
8
3
5 5
10
54 4
7
4
7
20 20
0
5
10
15
20
25
Development Lease Approvals by YearTotal Development Leases = 119
Must have a commercial discovery to request a development lease!
4Q 2013 WELL HIGHLIGHTS CONTINUING TO DELIVER ACROSS THE PORTFOLIO
EXPLORATION DEVELOPMENT AND HORIZONTAL SUCCESS
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EXPLORATION, DEVELOPMENT AND HORIZONTAL SUCCESS
145
Apache Acreage
SWAG-8
IP : 756 BO/D, 15.3 MMCF/D
RoR: 44%
Apries-1X
IP : 4,389 BO/D, 14.2 MMCF/D
RoR: 100%
Tayim W-3
IP : 2,412 BO/D, 5.0 MMCF/D
RoR: 22%
SIWA 2-L2IP: 3,047 BO/D
RoR: 42%
NTRK-H-1X
IP: 250 BO/D, 20 MMCF/D
RoR: 88%
NRQ-8X
98 feet of net pay
Tested in Q1 2014
Meghar Field3 new wells which increased
rate from 13 to 29 MMcf/d
Note: IPs represent tested rate.
Recent Wells
AG-115H
IP: 1,681 BO/D, 3.1 MMCF/D
RoR: 39%
WESTERN DESERT STACKED PAY POTENTIAL MANY YEARS OF DRILLING TO COME
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TertiaryGross Unrisked MMBOE
43
Abu RoashGross Unrisked MMBOE
372
PaleozoicGross Unrisked MMBOE
835
Alamein/AEBGross Unrisked MMBOE
557
Gross Resources Resource Life1
Unrisked: 3.4 BBOE > 20 years
Bahariya/KharitaGross Unrisked MMBOE
588
146
JurassicGross Unrisked MMBOE
1,006
Note 1. Resource life = unrisked gross resources divided by 2013 gross production of 128 MMBOE.
WESTERN DESERT STACKED PAY POTENTIAL LOTS OF WAYS TO WIN
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ReservoirObjectives
147
INTRODUCING HORIZONTALS TO THE WDUNCONVENTIONAL TECHNOLOGY TRANSFERRED TO EGYPT
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148
323
2
6
activeplanned
Early tests have provided positive results
8 active wells with 8 more planned for 2014
Proof of concept attained in 3 of 4 zones tested
Note: IPs represents tested rate.
Apache Acreage
AG-115HIP : 1,681 BO/D, 3.1 MMCF/D
Khalda 97HIP : 814 BO/D
MRZK-102HIP : 1,200 BO/D
Apollonia
Abu Roash D & G
Upper Bahariya
Bahariya Sandstone (5)
AR-G Sandstone (3)
AR-G Dolomite (2)
AR-D Limestone (4)
Apollonia Limestone (2)
AG-115H RESULTSEARLY HORIZONTAL SUCCESS TARGETING AR-D LIMESTONE
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S N
1,970’ lateral/1,550’ net pay
Peak IP: 3,402 BOPD and 5.5MMCFD
Avg 30 day rate : 1,681 BOPD,
3.1 MMCFD
After 72 days: 1,047 BOPD, 3.3
MMCFD produced 83 MBBL and0.19 BCF
149
AG-115H
L a t e r
a l S e c t i o n
HEEL
TOE
AG-115H
IP: 1,681 BO/D, 3.1 MMCF/D
UPPER BAHARIYA HORIZONTAL PROGRAMMULTIPLE, REPEATABLE HORIZONTAL PROGRAMS PLANNED FOR
2014 IN SHUSHAN BASIN
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2014 IN SHUSHAN BASIN
150
Umbarka 227H• TD’d in 1st qtr 2014
• 2610’ lateral
• Waiting on 7 stage completion
Khalda 97H• First WD Hz well drilled in 2012
• Cumulative production of 97 MBO
• Currently producing at 225+ BOPD
Pinot 3HX• Multi-thousand acre field,
uneconomic with verticals
• 2014 Hz spud
Cygnus Field• Multi-thousand acre field of
marginal vertical wells
• Repeatable horizontal program
AUSTRALIA PROJECT EXECUTION DELIVERING PRODUCTION GROWTH
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2014 Plans
E&P Capital1 $0.8 Bn
2014 Avg. Rigs 2
Gross Wells 18
2013 Highlights
Production 56,568 BOED
Cash Flow $843 MM
E&P Capital1 $1.0 Bn
Average Rigs 2
Gross Wells 12
Success Rate 92%Proved Reserves 326 MMBOE
Note 1. 2013 and 2014 capital do not include any costs associated with Wheatstone.
Project-driven program with multiple
discoveries scheduled to come on line
over next 3 years 2014: year of execution
BrunelloBalnaves
Julimar
Zola
Varanus
Island Hub
Reindeer
Devil Creek
Gas Plant
Wheatstone
LNG & DomGas
PlantMacedon Gas
Plant
Coniston
Van Gogh
Pyrenees
Macedon
Phoenix South
AUSTRALIA PROJECT PIPELINE
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Project2014E Avg.
(Net MBOE/D)First
Production2014P Capital
($ MM)
Macedon 4-6 Q3 2013 ---
2014
Upper Pyrenees 2-3 Q1 2014 ---
Moondyne 2-3 Q2 2014 $25
Balnaves4-6 Q3 2014 190
Coniston 6-7 Q3 2014 60
Total 18-25 MBOED $275MM
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BALNAVES OIL DEVELOPMENT GRASSROOTS OIL DEVELOPMENT: CONVERTING RESOURCES TO RESERVES
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153
Subsea development through the
FPSO Armada Claire
Gas to be re-injected for later
supply to Wheatstone LNG
Drilling complete: 4 wells Subsea installation complete
FPSO upgrade ongoing,
sail away Q1 2014
Project Details
Apache WI 65% (Operator)
Partner Kufpec
First Production 3Q 2014
Initial Production (Net) 12 MBOD (Peak)
Net EUR 11-17 MMBOE
NINGALOO VISION FPSO UPGRADES IN 2014
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Ningaloo Vision FPSO taken offline at Van Gogh in Jan 2014 for upgrade toaccommodate additional Coniston volumes
Estimate reconnecting Van Gogh and Coniston in 3Q 2014
Van Gogh downtime impact of net 5-7 MBOED while off station
154
CONISTON OIL DEVELOPMENTLEVERAGING EXISTING APA INFRASTRUCTURE FOR GROWTH
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Tie-back development leveraging Van Gogh subsea infrastructure and Apache’s
Ningaloo Vision FPSO
4 multi-lateral producers completed before first production; 3 more by yearend First phase of subsea installation complete, second phase will be carried out while
the Ningaloo Vision FPSO is off station in 1H 2014
155
Project Details
Apache WI 52.50% (Operator)
Partner Inpex
First Production Q3 2014
Initial Production (Net) 14 MBOD (Peak)
Net EUR 8-11 MMBO
JULIMAR GAS DEVELOPMENT SIGNIFICANT GAS DISCOVERY – FEED GAS FOR WHEATSTONE
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Julimar Phase 1 field development is 45% complete with Brunello topholes drilled Subsea pipeline campaign underway
Drilling and subsea tree installation is scheduled for 2Q 2014
Target for first gas available: 2H 2015
156
Project Details
Apache WI 65% (Operator)
Partner Kufpec 35%
First Production Dec 2016
Net EUR 1.3 TCF gas
28 MMB condensate
(250 MMBOE)
WHEATSTONE LNG FACILITY BUILDING FOR THE FUTURE
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Overall Wheatstone project progress at 27% First compressor foundations have been installed at site
Platform deck is structurally complete
Platform substructure has left the dock for quayside works
157
Project Details
Apache WI 13% (Non Operator)
Partner Chevron 64.14%
KUFPEC 13.40%
TEPCO 8.00%
Kyushu 1.46%
First Production Dec 2016
Production (Net) 30 MBOED
2014 Capex: $1.4 Bn
WHEATSTONE LNG
Pre Tax Cash Flow at $100 Brent1
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158
First production in 2016 85% contracted (oil-based pricing)
8.9 MMTPA LNG
APA = 13%
LNG operated by Chevron, Apache
operates its upstream
Illustrative Free Cash Flow Profile
Note 1. Pre-tax, based on $100/BBL Brent oil price. Assumes capital costs and timing of project start-up are as currently planned.
-1,500
-1,300
-1,100
-900
-700
-500
-300
-100
100
300
500
700
900
1,100
2014 2015 2016 2017 2018 2019 2020 2021
Pre-Tax Cash Flow
Capital Investment
Pre-Tax Cash Flow at $100 Brent1
$MM 20-Year
Contracts
GULF OF MEXICO: SUBSALT TECH APPLIED TO SHELFNEW EYES, NEW SEISMIC, NEW OPPORTUNITIES
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159
2014 Plans2
Capital $450 MM
2014 Avg. Rigs 1.8
Gross Wells 7
2013 Highlights1
Production 11,515 BOED
Capital $397 MM
Average Rigs 1
Gross Wells 4
Success Rate 66%
Proved Reserves 63 MMBOE
Note 1. FY 2013 data represents GOM DW only with the exception of reserves (GOM DW + Shelf as of Dec. 31, 2013).
Note 2. 2014 Plan includes former DW and Shelf region plans, going forward to be known as Gulf of Mexico Region .
Development
Properties
Active Rigs
In 2013 GOM Shelf transaction, Apache
retained 50% in exploration blocks and in
horizons below production in developed
blocks
All prospecting efforts have been shifted
to more accessible, more competitive
shelf targets
ALABAMAMISSISSIPPI
ALABAMA
Bimini
GB213
Lucius
Heidelberg
ST 311
MP 302
MP 295
Bushwood
EI 136
BLOCKS Gross (000) Net (000)
Shelf 515 2,519 807
Deepwater 681 916 490
TOTAL 1,196 3,435 1,297
ACRES
LUCIUS (KC 874/875/918/919)AT THE CUSP, UNLEASHING THE POTENTIAL
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160
Proven Pliocene & Miocene subsalt oil development in 7,000’ WD Six producers drilled, four in 2013
Two completions to date with four remaining
Truss spar hull is on location
Process facilities installed 1st half 2014
Rig returns Q2 2014
Project Details
Apache WI 11.7%
Operator Anadarko
First Production 2H 2014
Initial Production (Net) 10 MBOED (Peak)
Net EUR 31.1 MMBOE
resource
2014 Net Capital $96 MM
HEIDELBERG (GC 859/860/903/904/948)OIL DEVELOPMENT UNDERWAY
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161
Five block unit in 5,300’ water depth
Two appraisal wells and one sidetrack drilled
Two wells with over 200’ net pay Rig returns late Q1 2014
Spar and topsides facilities in construction
Project Details
Apache WI 12.5%
Operator Anadarko
First Production 2016
Initial Production (Net) 9 MBOED (Peak)
Net EUR 25 MMBOE
resource
2014 Net Capital $145 MM
INTERNATIONAL AND GOM SUMMARY
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International regions deliver > $1 Billion free cash flow
annually to drive North America onshore growth
International regions have robust inventories and resources to
ensure continued free cash flow generation
Considerable upside in oil focused North Sea exploration and
successful implementation of horizontal drilling in Egypt
Australia delivers near-term production growth and adds a
visible project pipeline including the Wheatstone LNG project
GOM projects offer oil production growth through 2016 alongwith an opportunity for organic growth on over 500 blocks on
the Shelf
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2014 EXPECTATIONS
Brady Parish
February 26, 2014
2013 PRO FORMA PRODUCTION BRIDGE
MBOE/D
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164
761 71
4341
33537
0
100
200
300
400
500
600
700
800
2013 As
Reported
GOM Shelf Argentina Egypt Tax
Barrels
Noncontrolling
Interest
Canada Sales¹ Pro Forma 2013
MBOE/D
Note: Pro forma represents 2013 volumes less divested volumes from GOM Shelf, Canada, including 2014 proposed sales, Egypt and expected Argentina sale.
Note 1. Canada Sales represents 14.7 MBOE/D in 2013 and 18.4 MBOE/D in 2014.
36
2013 PRO FORMA PRODUCTION DETAIL
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165
2013 Pro Forma Production
Oil NGLs Natural GasRegion (MBBLS/D) (MBBLS/D) (MMCF/D) MBOE/D
Central 23 23 273 91
Permian 72 23 189 127
Gulf Coast 11 2 107 31
Canada 17 5 315 75NA Onshore 122 54 884 324
Egypt w/o Tax 43 0 175 72
Australia 19 0 223 57
North Sea 64 1 51 74
International 126 1 449 202
GOM 7 1 20 11
Total 256 56 1,353 537
Note: Pro forma represents 2013 volumes less divested volumes from GOM Shelf, Canada, including 2014 proposed sales, Egypt and expected Argentina sale.
2014 EXPECTATIONS
15 18% North America onshore liquids growth
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15-18% North America onshore liquids growth
Driven by oil
Double-digit global liquids growth
Global gas production approximately flat
5-8% BOE production growth
Capex ex LNG = within cash flow
Note: All growth rates based on 2013 pro forma production. Excluding Egypt tax barrels and noncontrolling interest.
2014 PRODUCTION OBSERVATIONS
Growth driven by Permian, Central and Australia
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167
Permian and Central:
+ 15-20% liquids + 12-15% BOE
Australia:
+ 8-10% BOE
2H ramp-up due to project start-up timing
Gas 5-10% lower subject to contract timing
Gulf Coast Onshore: 3-5% BOE growth (with gas decline)
Driven by Eagle Ford ramp-up in 2H
GOM: 15-20% BOE decline awaiting Lucius ramp up
Other regions: stable annual average production 1Q observations:
Scheduled: Australia FPSO downtime: -10% BOE in 1Q then flat in 2Q
Unscheduled: North Sea storm downtime: to be quantified
Note: All growth rates based on 2013 pro forma production.
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CLOSING REMARKS
Steve Farris
February 26, 2014
Proven leader in oil-levered North America growth:
#1 growth generator in Permian + Anadarko basins
APACHE TODAY
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#1 growth generator in Permian + Anadarko basins
60% of company production in NA onshore (and rising) Major free cash flow assets:
>$1 BN/year FCF from Egypt, North Sea, Australia (#1 positions)
Incremental $1 BN/year free cash flow from Wheatstone LNG
Industry shift to execution: Proven track record: APA core strength
Built to last:
Rate of return discipline: focus on repeatable liquids plays
Self-funded capital program ex LNG. Financial strength to deliver our strategy
Sustainable: NA onshore resource alone 4x APA proved reserves
169
Repositioned, focused: ready for next phase of value growth
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INVESTOR DAY Q&A
170
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APPENDIX
P d ti fil G l l ll l t d th i
ECONOMICS ASSUMPTIONS
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Production profiles: Gross sales volumes per well unless noted otherwise
“D+C Cost”: Gross drill and complete cost per well
Prices: All well economics assume $90.00/Bbl WTI, $4.50/MMBTU NYMEX, and
$27.00/Bbl NGL prices
“EUR”: Sales hydrocarbons
Single well “EUR MBOE”: Gross before royalties
Development Play or Project “Net MMBOE”: Net to Apache after royalties
“ROR”: cash internal rate of return, after royalties and before income tax
“Locations” (also “Current Inventory”): Gross drilling locations
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