FORWARD-LOOKING STATEMENTS

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2 FORWARD-LOOKING STATEMENTS Certain statements in this presentation contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934 including, without limitation, expectations, beliefs, plans and objectives regarding anticipated financial and operating results, asset divestitures, estimated reserves, drilling locations, capital expenditures, price estimates, typical well results and well profiles, type curve, and production and operating expense guidance included in this presentation. 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 filed Annual Report on Form 10-K, recent Quarterly Reports on Form 10-Q, recent filed Current Reports on Form 8-K available on our website, and in our other public filings and press releases. These forward-looking statements are based on Apache Corporation s (Apache) current expectations, estimates and projections about the company, its industry, its management s beliefs and certain assumptions made by management. No assurance can be given that such expectations, estimates or projections will prove to have been correct. A number of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this presentation, including, Apache s ability to meet its production targets, successfully manage its capital expenditures and to complete, test and produce the wells and prospects identified in this presentation; to successfully plan, secure necessary government approvals, finance, build and operate the necessary infrastructure; 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,, guidance and similar phrases. Because such statements involve risks and uncertainties, Apache s actual results and performance may differ materially from the results expressed or implied by such forward-looking statements. Given these risks and uncertainties, you are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date hereof. Unless legally required, we assume no duty to update these statements as of any future date. However, you should review carefully reports and documents that Apache files periodically with the Securities and Exchange Commission. Cautionary Note to Investors: The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable, and possible reserves that meet the SEC's definitions for such terms. Apache may use certain terms in this presentation, such as resource, resource potential, net resource potential, potential resource, resource base, identified resources, potential net recoverable, potential reserves, unbooked resources, economic resources, net resources, undeveloped resource, net risked resources, inventory and other similar terms that the SEC guidelines strictly prohibit Apache from including in filings with the SEC. Such terms do not take into account the certainty of 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 carefully the disclosure in Apache s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, available from Apache at or by writing Apache at: 2000 Post Oak Blvd., Suite 100, Houston, Texas (Attn: Corporate Secretary). You can also obtain this report from the SEC by calling SEC-0330 or from the SEC's website at 1

3 AGENDA I. Overview: John Christmann, CEO & President II. III. IV. North Sea Asset Review: Cory Loegering, Region VP and Managing Director North Sea Financial Considerations: Gary Clark, VP Investor Relations Key Takeaways: John Christmann, CEO & President V. Q&A 2

4 OVERVIEW JOHN CHRISTMANN, CHIEF EXECUTIVE OFFICER & PRESIDENT 3

5 APACHE TODAY Realigned the organization and streamlined the portfolio Significantly strengthened the balance sheet Aligned activity and capital spend for current price environment Aggressively reducing all facets of the cost structure North America to provide long-term growth International will deliver free cash flow with upside potential 4

6 NORTH SEA IS IMPORTANT TO APACHE Theme Contribution North Sea provides balance to our portfolio Diversification: short, medium and long-cycle projects Competitive, high rates of return North Sea generates significant operating and free cash flow High netbacks per Boe Supplements long-term North American investment North Sea inventory has the quality and depth to sustain production for more than a decade Significant recent success Unrisked net resource inventory of 4x - 7x net proved reserve upside Apache will only invest in projects that compete on a fully burdened ROR and NPV basis. 5

7 APACHE NORTH SEA IS HIGHLY DIFFERENTIATED Two of the most prolific North Sea hydrocarbon accumulations at Forties and Beryl Significant prior infrastructure investment Best-in-class production efficiency Advantaged pipeline and platform locations Industry-leading operating costs in North Sea 6

8 INDUSTRY LEADER IN PRODUCTION EFFICIENCY 95% 90% 85% APA Operating Efficiency UKCS Avg. Operating Efficiency APACHE >90% PRODUCTION EFFICIENCY VS. OPERATOR AVERAGE OF 65% 80% 75% Apache Enters U.K. North Sea 70% 65% 60% UKCS Avg. Efficiency 55% 50% Source: Production efficiency data was provided by the Production Efficiency Task Force, a task force of the U.K. government policy advisory group PILOT. 7

9 ADVANTAGED INFRASTRUCTURE LOCATION Apache North Sea not dependent on third-party facilities Direct to Tanker 91% Uptime Direct to Terminal 93% Uptime 8

10 ~50% OPERATING COST ADVANTAGE Unit Operating Cost ($/Boe) $35 $30 Apache UK North Sea Avg $27.07 $30.49 $25 $22.19 $20 $15 $13.46 $13.76 $17.64 $14.74 $16.66 $13.62 $10 $7.02 $8.03 $10.37 $11.49 $5 $ Source: Oil and Gas UK 2015 Activity Survey 9

11 BENEFIT OF HIGHER PRODUCTION EFFICIENCY AND LOWER OPERATING COSTS Boe/d 1,400 Example U.K. North Sea Well Apache NPV10: $7.6 MM, ROR: 48% 92% Efficiency $14/Boe Operating Costs Month UK North Sea Avg. NPV10: $0.3 MM, ROR: 11% 65% Efficiency $29/Boe Operating Costs (1) Calculated based on consensus prices as of Nov. 9, Apache economics do not include the benefits of our investment allowances. 10

12 MORE DOLLARS WILL GO TOWARD DRILLING Capital (1) Capital (1,2) Infrastructure 44% Drilling and Completion 51% Seismic and Exploration 10% Infrastructure Dummy Data 12% Drilling and Completion 78% Seismic and Exploration 5% (1) Excludes acquisitions. (2) Based on Apache mean-risked reserve and capital spending case. 11

13 NORTH SEA OUTLOOK: NEXT 5 YEARS $ in millions $900 Brent Prices: Historical average: $ Consensus 5-year average: $67 MBoe/d 80 $ in millions $ $400 $600 $ $300 $ $100 $0 0 Avg. Annual Capital Avg. Daily Production (1) (1,2) (1) Capital excludes acquisitions. (2) Based on Apache mean-risked reserve and capital spending case. $0 Avg. Annual ATax Free Cash Flow 12

14 NORTH SEA ASSET REVIEW CORY LOEGERING, REGION VP AND MANAGING DIRECTOR NORTH SEA 13

15 NORTH SEA HIGHLIGHTS Apache has a very advantaged position Top-tier assets Most efficient operator High rates of return Strong free cash flow generation 14 Significant upside ahead Unrisked drilling inventory with 4x to 7x net proved reserve upside Proven ability to extend field asset life Additional upside exploration potential Improving U.K. tax regime and incentives 14

16 SECOND-LARGEST U.K. NORTH SEA OIL PRODUCER MBBLS/D 100 Top U.K. North Sea Oil Producers Source: WoodMac UK Net entitlement production UK 15

17 FORTIES Largest oil field in the U.K. North Sea 15 miles Acquired in April 2003 from BP for $630 million Field is one large 4-way structural closure Apache has invested $2.3 billion in infrastructure and $2.3 billion on drilling and workovers Forties Field Overlaid On Map of Houston Apache 3Q 15 Net Production 20 miles Estimated OOIP Total Cumulative Gross Production 41,000 Boe/d 5 Billion Boe 2.6 Billion Boe 16

18 FORTIES Most resilient field in the North Sea 2003: Apache acquired Forties field, the 10th largest oil producer in the U.K. North Sea Mbo/d : 2nd largest oil producer in the U.K. North Sea, still producing ~40 MBoe/d Mbo/d

19 FORTIES Exceptional field revival Apache invested ~$1 billion in infrastructure during the first 5 years Increased efficiency and stabilized production with the drill bit Drilled an average of 14 development wells per year Gross Mboe/d Satellite Fields Forties Field - Apache Forties Field - BP Gross Wells Drilled Apache acquires Forties from BP

20 FORTIES Exceptional field revival Net Production Net Proved Reserves Years Until Decommission Date Mboe/d MMBoe Years MBoe/d Added MMBoe Produced Extended Decommission Date 18+ Years At Acquisition (2003) 2014 At Acquisition (2003) 2014 At Acquisition (2003)

21 FORTIES Acquired inventory targets identified at time of acquisition Bravo Charlie Delta Alpha FASP Echo Identified targets 20

22 FORTIES Wells drilled since acquisition 32 initial targets drilled - 74% success rate 134 Apache identified targets drilled - 75% success rate Bravo Charlie Alpha FASP Delta Echo Identified targets at acquisition Additional identified targets by Apache 21

23 FORTIES Substantial low-risk inventory remaining 84 targets currently identified 2016 seismic will increase the count Bravo Charlie Alpha FASP Delta Echo All targets drilled by Apache Remaining targets 22

24 FORTIES Significant reserves remain Giant field: 5 billion barrels of original oil in place ~2.6 billion barrels recovered to date (52% Rf) Each 1% additional recovery is ~50 million barrels 4D seismic shoots and increased water injection continuously expands the potential location count 23

25 FORTIES Development location type curve Boe/d 5-Year Production Curve (PMean) 1,400 1,200 1, >100% rate of return Month Current Locations 30-Day Average Production Rate EUR % Oil % WI Completed Well Cost Facilities Cost ATAX ROR NPV (ATax) 84 1,297 Boe/d 535 MBoe 100% 97% $13 MM $1 MM >100% $7 MM 24

26 FORTIES An Apache success story Since 2003, Apache has: Generated $18.4 billion in revenue Invested $10.2 billion (capital and operating costs) Delivered $1.5 billion of cumulative free cash flow Realized an estimated 27% rate of return to date New projects will allow us drive additional recoveries and value Leveraging previous infrastructure spend will drive free cash flow potential higher 25

27 BERYL AREA Significant growth potential Acquired in January 2012 from ExxonMobil for $1.44 billion APA has invested ~$300 million in infrastructure Exceptional exploration and development success in Q 2015 production of ~26,000 Boe/d L4S: 30-Day IP 9679 Boe/d Beryl Area Recent Well Results Beryl Nevis Ness Buckland Corona discovery BCE: 30-Day IP 6916 Boe/d BDE: 30-Day IP 1071 Boe/d BLA: 30-Day IP 1670 Boe/d ACN: 30-Day IP 9496 Boe/d K discovery Skene 26

28 BERYL AREA Resource-rich embayment P A L A E O C E N E EOCENE Traps formed by complex faulting Nevis Ness Beryl Multiple reservoirs and seals provide multiple stacked pay opportunities WEST OLIGOCENE Lark EAST Horda Buckland Frigg Sele Skene Sele Claystone Heimdal Maureen CRETACEOUS JURASSIC Beryl Raude Upper Cretaceous Shetland Group TRIASSIC Lewis Fm Cormorant Beryl 27

29 BERYL AREA Seismic driving Apache s success Greatly improved imaging has helped to identify and de-risk a large portfolio of exploration and development prospects Legacy 1990 s 3D D seismic 28

30 BERYL AREA Ready for take-off Net Production Net Proved Reserves Years Until Decommission Date MBoe/d MMBoe Years MMBoe Produced Extended Decommission Date 9+ Years At Acquisition (2012) 2014 At Acquisition (2012) 2014 At Acquisition (2012)

31 BERYL AREA Acquired targets targets at time of acquisition Targets at acquisition Platforms 30

32 BERYL AREA Wells drilled since acquisition 21 targets drilled to date Apache drilled targets Targets at Acquisition Platforms 31

33 BERYL AREA New 3D seismic generated 8x inventory increase 81 targets remaining Apache drilled targets Remaining targets Platforms 32

34 BERYL AREA Substantial reserve upside Net Mean Unrisked Reserve (MMBoe) Net MMBoe Unrisked net reserve potential Development Exploration

35 BERYL AREA K discovery (Callater) Jurassic 9/ /19-18Z 9/19-18X Empire State Building 1 km Net Reserves (1) Net Unrisked Capital Working Interest 55% Oil % / Gas % ROR (1) NPV10 (1) MMBoe $318 million 40% / 60% >100% $340 - $680 million Pay proven in 3 fault blocks One remaining undrilled block to southeast Over 1,500 feet TVD net pay logged Initial production in 2017 (1) Calculated based on consensus prices as of Nov. 9, 2015, after tax and represents Pmean to P10 estimates. 34

36 BERYL AREA Storr prospect Jurassic Storr SHL 1 km Net Reserves (1) Net Unrisked Capital Working Interest 55% Oil % / Gas % 8 21 MMBoe $172 million 49% / 51% Highly faulted relay ramp Stacked objectives On trend with Skene Field Mid 2016 test ROR (1) NPV10 (1) >100% $67 - $196 million (1) Calculated based on consensus prices as of Nov. 9, 2015, after tax and represents Pmean to P10 estimates. 35

37 BERYL AREA Kinord prospect Jurassic EAST SHETLAND PLATFORM KINORD WEST Stacked objectives, Jurassic and Triassic, in each of the two identified fault blocks KINORD EAST BERYL BRAVO High-risk, high-reward target Mid 2016 test NEVIS CENTRAL NESS 2000 ft 5 km 1 km Net Reserves (1) Net Unrisked Capital MMBoe $235 million Working Interest 55% Oil % / Gas % 81% / 19% ROR (1) NPV10 (1) >100% $134 - $508 million (1) Calculated based on consensus prices as of Nov. 9, 2015, after tax and represents Pmean to P10 estimates. 36

38 BERYL AREA Tertiary injectite portfolio Corona discovery Titan Prospect ~100,000 acres covering the Tertiary play Apache has high working interest across the play Identified multiple drillable prospects in Beryl Area with MMBoe net unrisked reserves Corona is Apache s first injectite discovery Next prospect, Titan, is scheduled for 2016 Tertiary Injectite Area 37

39 BERYL AREA Tertiary play concept Eocene aged sedimentary injectites forming complex stratigraphic traps Injectite Geometries Parent sands Remobilization of sands form complex reservoir geometries PGS 2013 MC3D GeoStreamer Source: Schlumberger Publication (Figure adapted from Hurst and Cartwright); Hurst A and Cartwright J: Relevance of Sand Injectites to Hydrocarbon Exploration and Production, in Hurst A and Cartwright J (eds): Sand Injectites: Implications for Hydrocarbon Exploration and Production, AAPG Memoir 87. Tulsa: AAPG (2007):

40 100 feet BERYL AREA Corona discovery tertiary injectite Beryl Discovery Appraisal Buckland gas-oil contact Skene Corona oil-water contact development acreage exploration acreage Net Reserves (1) Net Unrisked Capital Working Interest 100% Oil % / Gas % ROR (1) NPV10 (1) 9-19 MMBoe $308 million 98% / 2% >100% $51 - $111 million 225 feet net pay 252 feet net pay Identified on new Beryl 3D APA s first tertiary well in the Beryl Area 362 foot column height Excellent reservoir quality High permeability and porosity (1) Calculated based on consensus prices as of Nov. 9, 2015, after tax and represents Pmean to P10 estimates. 39

41 BERYL AREA Titan prospect, next tertiary injectite test 1000 feet Titan Supported by seismic DHI amplitudes Water Bottom Titan Corona discovery reduces risk profile Multiple follow-on exploration opportunities Horda 500 m Net Reserves (1) Net Unrisked Capital MMBoe $632 million Injectite Working Interest 77% Oil % / Gas % 100% / 0% Heimdal ROR (1) NPV10 (1) >100% $497 million (1) Calculated based on consensus prices as of Nov. 9, 2015, after tax and represents Pmean to P10 estimates. 40

42 BERYL AREA Existing infrastructure to accommodate future growth Beryl Alpha Current 100% Capacity Oil (Mb/d) Gas Compression (MMscf/d) Water Injection (Mb/d) Power (MW) Beryl Bravo Current 100% Capacity Oil (Mb/d) 5 60 Gas Compression (MMscf/d) Water Injected (Mb/d) Power (MW) Significant capacity to support future growth. 41

43 BERYL AREA SUMMARY Exceptional success in 2015: 89% success rate on 9 wells Plan 3 significant explorations tests in 2016 Relatively quick tieback with high ROR projects Unrisked net reserve potential of MMBoe 42

44 OTHER HIGH IMPACT EXPLORATION Val D Sere Vail Albion Forties Seagull Komodo Isabella Net unrisked MMBoe Net MMBoe Unrisked net reserve potential A B C D E F Pmean values Prospects Additional P10 value 43

45 SEAGULL DISCOVERY 9.3 km 2 Closure 672 feet of oil over a 1,092-foot column Facility constrained flow of 8,700 Bo/d and 16 MMcfp/d 22/29-2Z Seagull 22/ /29-8y Chrysler Building 22/29-8Y Net Reserves (1) Net Unrisked Capital MMBoe $360 million 1,092 ft oil column Working Interest 35% Oil % / Gas % 79% / 21% ROR (1) NPV10 (1) >100% $238 - $393 million Oil Saturation (1) Calculated based on consensus prices as of Nov. 9, 2015, after tax and represents Pmean to P10 estimates. 44

46 FINANCIAL CONSIDERATIONS GARY CLARK, VICE PRESIDENT INVESTOR RELATIONS 45

47 NORTH SEA RESOURCE POTENTIAL Forties Development : 84 current locations, 44 MMBoe Beryl Area Development and Exploration: 350 to 600 MMBoe Other High Impact Exploration: 180 to 410 MMBoe Total unrisked net resource potential: 574 to 1,054 MMBoe 46

48 U.K. TAX OVERVIEW 2016 applicable tax rates Tax Rate (1) Old Tax Regime New Tax Regime Petroleum Revenue Tax (PRT) 50% 35% Currently expensed under Taxes other than income line Corporate Tax (CT) 30% 30% Income tax expense line Supplementary Charge (SCT) 32% 20% Income tax expense line Investment Allowance Geared to incent companies to drill and develop fields in the North Sea Allows 62.5% of qualifying field expenditures to reduce taxable income when calculating the SCT Most capital expenditures, on or after April 1, 2015, and some operational expenditures, on or after Oct. 8, 2015, are available for investment allowance (1) PRT rate change effective Jan. 1, Supplementary charge rate effective Jan. 1,

49 EXAMPLE OF U.K. TAX CALCULATION Old Tax Regime New Tax Regime Lifting Revenue (1) $1,000 $1,000 OPEX (200) (200) CAPEX (300) (300) Taxable Income for PRT PRT Rate 50% 35% PRT (250) (175) Operating Income Corporate Tax Rate 30% 30% Corporate Tax (75) (98) Supplementary Charge Rate 32% 20% Supplementary Charge (80) (65) Total Corporate Tax and Supplementary Charge (155) (163) Investment Allowance Benefit (2) Net Corporate Tax and Supplementary Charge (95) (125) Net Income $155 $200 Investment Allowance Calculation Old Tax Regime New Tax Regime Assumes a single field calculation (3) CAPEX $300 $300 Investment Allowance Rate 62.5% 62.5% Investment Allowance (CAPEX) x (Investment Allowance Rate) Revenues 1,000 1,000 Operating Income Activated Allowance (Minimum of Investment Allowance or Revenues) Applicable SCT Income (Operating income) - (Activated Investment Allowance) SCT Rate 32% 20% SCT (20) (28) (SCT Rate) x (Applicable SCT Income) Supplemental Charge Tax (80) (65) Investment Allowance Benefit $60 $38 (1) Lifting revenue is dependent on scheduled tanker offloads, off take capacity, etc. (2) Investment allowance supersedes previous field allowances and currently shown on a comparable basis and in this example showing the aggregate effects of the rate changes and not the change in the field allowance methodology. (3) Investment allowances are calculated on a field level basis, which are aggregated to arrive at the net benefit reducing the supplementary charge. 48

50 ASSET RETIREMENT OBLIGATION (ARO) REVIEW Present value of Apache North Sea ARO is approximately $1.3 billion at Sept. 30, 2015 Tax relief from the U.K. government offsets the financial burden of this obligation Total net present value benefit of ~$870 million Present value of ARO liability net of deferred tax benefit ~$430 million at Sept. 30, 2015 All PVs and 10k assume 1.5% inflation and 6% discount rate as used by corporate accounting 10k $values are BTAX 49

51 ASSET RETIREMENT OBLIGATION REVIEW No significant ARO expenditures expected for the next 10 years In millions $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 Years 0-5 Years 6-10 Years

52 COMMON MODELING MISCONCEPTIONS Future Development Modeling Issue Apache North Sea fields are near-term reserve blow-down assets Reality As demonstrated, Apache fields can sustain production and potentially proved reserves for at least 5 years Unit Operating Cost Industry average of $29 per Boe Apache operating cost of $14 per Boe Asset Retirement Obligation Exploration Opportunity F&D Cost Large asset retirement obligation within 5 to 10 years, generally not accounting for deferred tax benefits No value for future exploration potential Relatively high historical F&D costs U.K. tax relief significantly reduces ARO cost to Apache. Abandonment dates are deferred as field lives are extended Recent proven exploration successes, and additional reserve potential of 4x-7x total proved reserves Significant infrastructure spending behind us and we will leverage the investment moving forward 51

53 KEY TAKEAWAYS JOHN CHRISTMANN CHIEF EXECUTIVE OFFICER & PRESIDENT 52

54 APACHE NORTH SEA IS HIGHLY DIFFERENTIATED Forties and Beryl two of the biggest and best hydrocarbon accumulations in the North Sea Extensive inventory of locations is still growing Infrastructure in excellent shape, higher percentage of capital dollars going toward drilling APA s low cost structure and high production efficiency turn marginal economics into high ROR s 53

55 KEY TAKEAWAYS Apache s North Sea production and reserves can economically sustain or grow over the next five years Returns in the North Sea are highly competitive with returns in Egypt and the Permian Basin Over the next five years in the North Sea anticipates: Direct over 75% of our capital to drilling and completion activities, versus less than 50% over the last five years Investing approximately $3 billion in capital, generating $1.75 billion in free cash flow, sustaining production and having similar or greater proved reserves than today Improving reserve additions, F&D costs, free cash flow and ROCE 54

56 QUESTIONS AND ANSWERS 55

57 APPENDIX 56

58 ECONOMIC ASSUMPTIONS Brent oil ($/Bbl): all economics assume the following Bloomberg consensus pricing as of November 9, 2015 of $58, $65, and $70 for years 2016, 2017 and respectively. Natural gas ($/MMbtu): all economics assume flat natural gas prices of $7.75 for Project and prospect capital estimates include spending for: drilling, completion, plugging and abandonment, infrastructure and G&A costs Rate of return and NPV calculations are after-tax 57