apache investor day 20140226

7/23/2019 Apache Investor Day 20140226

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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



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



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



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.



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%



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



10

#1 GROWTH GENERATOR IN THE PERMIAN BASIN

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12

14

16

18

20

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



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

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90

100

2011 2012 2013

MBOE/D, Net

% Liquids 20% 34% 50%

APA acreage

15 mi



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



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



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



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



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



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.



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%



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



RETURNING CAPITAL TO SHAREHOLDERS

20

Dividend

13% per share growth in 2012



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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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





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



NORTH AMERICAONSHORE

John Christmann

February 26, 2014



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.



0

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60,000

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120,000

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160,000

2009 2010 2011 2012 2013 Q4'13

Permian Central

0

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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



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



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



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



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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450

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



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



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


Expanding Horizontal Activities

Central



Emerging Canyon Lime Play

Gulf Coast


Emerging Eagle Ford Shale Play

Note 1. Pro forma for divested volumes from Canada sales, including 2014 planned divestitures.



VIDEO

33



PERMIAN

John Christmann

February 26, 2014



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



-

20

40

60

80

100

120

140

160

-

5

10

15

20

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



-

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



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



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




40

2013 Net MBOE/D

211

12792 79 78

55 53

0

100

200

300

A APA B C D E F


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



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




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%



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



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



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



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


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

/



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’



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



49

MIDLAND BASIN HORIZONTALTREMENDOUS UNCONVENTIONAL POTENTIAL

Note: Logs above hung on Clearfork.



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



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



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




53

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: 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




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



Acres1 (000) 292 (232 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 Basin1



% Oil / Gas / NGL 61% / 19% / 20%

WI / NRI 94% / 72%

ROR 48%

Total Inventory 1,152


57

WOLFCAMP SHALE: SOUTHERN MIDLAND BASINDRILLING INVENTORY ECONOMICS


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 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



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)



APA acreage

25 mi

Deadwood Field

CLINE SHALEEXPANDING HORIZONTAL PROGRAM

Cline Shale

CLINE SHALE



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



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



Cline1



% Oil / Gas / NGL 67% / 14 % / 19%

WI / NRI 78% / 60%

ROR 23%



62

CLINE SHALEDRILLING INVENTORY ECONOMICS


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



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



Other Midland Vertical

D+C Cost $MM 2.2

EUR MBOE 136


% Oil / Gas / NGL 56% / 22% / 22%WI / NRI 87% / 69%

ROR 27%


PUD + Probable Inventory 2,139

Spraberry Vertical



% 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



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



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)


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



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



Strawn

D+C Cost $MM 7.5

EUR MBOE 354


% Oil / Gas / NGL 73% / 10% / 17%

WI / NRI 100% / 81%

ROR 43%

Total Inventory 61


Wichita Albany



% 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



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


-

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



Wolfcamp/Penn

D+C Cost $MM 2.1

EUR MBOE 122


% Oil / Gas / NGL 63% / 16% / 21%WI / NRI 93% / 80%

ROR 30%

Total Inventory 164


Clearfork/Tubb



% 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



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



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



Delaware Horizontal



% Oil / Gas / NGL 45% / 28% / 27%

WI / NRI 94% / 72%

ROR 22%


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



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



BREAK

75



CENTRAL

John Christmann

February 26, 2014

APACHE CENTRAL



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


CENTRAL REGION: CONSISTENT, PROFITABLE GROWTH



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


Prod. Replacement1 195%


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



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



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



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



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



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



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


Acres (000) 855 (435 net)

2014 New Wells 62


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



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%


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


EUR MBOE 1,272

Bartz 19 #20-19H

Granite Wash A


EUR MBOE 1,140

Stiles 3 #27-3H

Caldwell30-day IP BOE/D 1,872

EUR MBOE 1,251

Stiles 4 #21-4H

Caldwell


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



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



Acres (000) 758 (429 net)

2014 New Wells 100


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


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


Wolfcampian

Desmoinesian


Target Formation


15 mi

CLEVELAND



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



Cleveland1

D+C Cost $MM 3.6

EUR MBOE 275


% Oil / Gas / NGL 16% / 51%/ 33%WI / NRI 52% / 41%

ROR 22%



Drilling Inventory Economics

Month

BOE/D


89


2 mi

APA acreage

APA 2013 Wells

Knox Pipkin 28-4H


EUR MBOE 360

Leland Mekeel 226-4H

30-day IP BOE/D 494

EUR MBOE 352

Mekeel 303 3H


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%


CLEVELAND RESULTS VS. TYPE CURVE



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



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


PROLIFIC OIL PLAY MOVING TO PAD DEVELOPMENT

91

Hugoton

Brown Dolomite


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


Wolfcampian

Desmoinesian

P e n

n s y l v a n i a n

Target Formation


15 mi

OPERATIONAL EXCELLENCE



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



Tonkawa1

D+C Cost $MM 4.5

EUR MBOE 245


% Oil / Gas / NGL 53% / 28%/ 19%

WI / NRI 36% / 29%

ROR 25%



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



Month

BOE/D

93


APA acreage

APA 2013 Wells

Chenette 2-9H

30-day IP BOE/D 632

EUR MBOE 415

Denney 2-19H


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%


TONKAWA RESULTS VS. TYPE CURVE



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



Hugoton

Brown Dolomite


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


Acres (000) 609 (295 net)

2014 New WellsMarmaton Shelf

Lower Marmaton

6436

28


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



Marmaton Shelf 1

D+C Cost $MM 4.1

EUR MBOE 246


% Oil / Gas / NGL 39% / 35%/ 27%WI / NRI 42% / 34%

ROR 22%



Carolea 594 1H


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


96


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%


MARMATON SHELF RESULTS VS. TYPE CURVE



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



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


Month



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


3 mi

APA acreage

APA 2013 Wells

Bombay 2-32H


EUR MBOE 1,188

Mamie 5-4H


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%


LOWER MARMATON RESULTS VS. TYPE CURVE



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



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


Hugoton

Brown Dolomite


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


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



Cottage Grove1

D+C Cost $MM 7.3

EUR MBOE 318


% Oil / Gas / NGL 69% / 14%/ 17%

WI / NRI 68% / 54%

ROR 50%

Total Inventory 54




101

0

100

200

300

400

500

600

700

800

0 6 12 18 24 30 36 42 48 54 60


1 mi

APA acreage

APA 2013 Wells

Stiles 4 #17-4H30-day IP BOE/D 1,495

EUR MBOE 636

Stiles 16 #15-16H


Stiles 18 #18-18H30-day IP BOE/D 662

EUR MBOE 438

Bartz 19 #21-19H


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%


COTTAGE GROVE RESULTS VS. TYPE CURVE



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



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


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



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



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



CANADA

John Christmann

February 26, 2014

CANADA’S ASSET BASETRANSFORMATION UNDERWAY



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



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



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



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



Dunvegan

Gross Acreage: 350,928

Net MMBOE: 174

Duvernay


Net MMBOE: 461

Bluesky / Glauconite


Net MMBOE: 808

Viking

Gross Acreage: 1,359,129

Net MMBOE: 337

Montney


Net MMBOE: 254

Cardium


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



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



113

HORIZONTAL REDEVELOMENT

Acres (000) 561 (378 Net)

2014P New Wells 44

Drilling Inventory 3,041


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



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


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



115

Drilling Economics

D+C Cost $MM 5.5

EUR MBOE 585

% Oil / Gas / Liquids 10% / 72% / 18%


ROR 36%

WI/NRI 66% / 55%

Current Inventory 1,944


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



116

KAYBOB DEVELOPMENT AREA

Note: Type curve assumes lateral length of 4,200’.

DUVERNAY FORMATIONDEVONIAN SHALE – ALBERTA DEEP BASIN



117

DEVONIAN SHALE ALBERTA DEEP BASIN

Acres (000) 239 Gross (176 net)

2014P New Wells 6

Drilling Inventory 1,656


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



KAYBOB AND SIMONETTE

Drilling Economics

D+C Cost $MM 13

EUR MBOE 684

% Oil / Gas / Liquids 40% / 45% / 15%


ROR 37%

WI/NRI 71% / 68%

Current Inventory 574


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



119

HIGH RATE / HIGH MMBOE RESERVOIR

Acres (000) 158 Gross (124 Net)

2014P New Wells 2

Drilling Inventory 837


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


SINOPEC 15-29 Hz


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



120

LIQUIDS RICH FAIRWAY

Drilling Economics

D+C Cost $MM 7.3

EUR MBOE 877

% Oil / Gas / Liquids 14% / 78% / 8%


ROR 25%

WI/NRI 73% / 66%


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’.



GULF COAST ONSHORE

John Christmann

February 26, 2014

GULF COAST REGIONDELIVERING GROWTH



122

2014 Plan

Capital $550 MM

2014 Avg. Rigs 6

Gross Wells1 85

2013 Results

Average Production

30.8 MBOE/D

+11.5% YoY


Prod. Replacement 81%


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


Note 1. Represents operated and non-operated wells Apache participates in.

APA Hz rigs

(3)

APA Vt rigs

(3)


EAGLE FORD SHALE PLAYTARGETING OIL IN NORTHERN WINDOW



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



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



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



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



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



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


Stasny - Porterfield EF #2H


Leone #2HLateral Length: 4,747’ Note: Geosteering issue, 2/3 of

lateral below pay.

NORTH AMERICAN POWERHOUSE



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



BREAK

130



INTERNATIONAL& GOM

Tom Voytovich

February 26, 2014

INTERNATIONAL AND GOM SUMMARY



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



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



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)



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



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



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)



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



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



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



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



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



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



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



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



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



ReservoirObjectives

147

INTRODUCING HORIZONTALS TO THE WDUNCONVENTIONAL TECHNOLOGY TRANSFERRED TO EGYPT



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



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



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



151

2014 Plans

E&P Capital1 $0.8 Bn

2014 Avg. Rigs 2

Gross Wells 18

2013 Highlights


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



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

152

BALNAVES OIL DEVELOPMENT GRASSROOTS OIL DEVELOPMENT: CONVERTING RESOURCES TO RESERVES



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



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



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



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

http://localhost/var/www/apps/conversion/tmp/scratch_5/AEN-Julimar_Development_Project_576.wmv



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



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



159

2014 Plans2

Capital $450 MM

2014 Avg. Rigs 1.8

Gross Wells 7

2013 Highlights1


Capital $397 MM

Average Rigs 1

Gross Wells 4

Success Rate 66%


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



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



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



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

162



2014 EXPECTATIONS

Brady Parish

February 26, 2014

2013 PRO FORMA PRODUCTION BRIDGE

MBOE/D



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



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



166

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



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.



CLOSING REMARKS

Steve Farris

February 26, 2014



APACHE TODAY




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



INVESTOR DAY Q&A

170



APPENDIX

P d ti fil G l l ll l t d th i

ECONOMICS ASSUMPTIONS



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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