Company Update March 2017

Company Update March 2017 Oil Search Limited ARBN 055 079 868 ASX: OSH POMSoX: OSH US ADR: OISHY www.oilsearch.com

DISCLAIMER While every effort is made to provide accurate and complete information, Oil Search Limited does not warrant that the information in this presentation is free from errors or omissions or is suitable for its intended use. Subject to any terms implied by law which cannot be excluded, Oil Search Limited accepts no responsibility for any loss, damage, cost or expense (whether direct or indirect) incurred by you as a result of any error, omission or misrepresentation in information in this presentation. All information in this presentation is subject to change without notice. This presentation also contains forward-looking statements which are subject to particular risks associated with the oil and gas industry. Oil Search Limited believes there are reasonable grounds for the expectations on which the statements are based. However actual outcomes could differ materially due to a range of factors including oil and gas prices, demand for oil, currency fluctuations, drilling results, field performance, the timing of well work-overs and field development, reserves depletion, progress on gas commercialisation and fiscal and other government issues and approvals. Company Update March 2017 2

Oil Search overview» Established in Papua New Guinea (PNG) in 1929» 29% interest in world-class PNG LNG Project, operated by ExxonMobil, and ~60% interest in all PNG s producing oil fields, operated by Oil Search (OSH)» Pursuing major LNG growth opportunities: P nyang Juha North Juha Hides Gas Conditioning Plant Muruk Kutubu Hides Angore Agogo Moran Gobe Main Elk/Antelope PNG LNG Project Gas Fields PNG LNG Project Facilities Non PNG LNG Gas/Oil Fields Papua New Guinea Strong resource base bolstered by reserves upgrades at PNG LNG, with 10+ tcf 2C undeveloped gas resource available to support expansion» Opportunity for project cooperation/ integration increased by recent ExxonMobil acquisition of InterOil (IOC)» Material gas exploration upside in PNG» Market capitalisation ~A$11bn (~US$8bn)» Listed on ASX (Share Code: OSH) and POMSOX, plus US ADR programme (Share Code: OISHY) Kimu SE Gobe Barikewa OSH Operated OSH Interest Oil Pipeline Oil Facility Oil Field Gas Pipeline Gas Facility Gas Field Condensate Pipeline Uramu Hagana Flinders LNG Plant Hides Kutubu Port Moresby Licence blocks PPL 374 & PPL 375 subject to regulatory approvals Company Update March 2017 3

Recent key milestones achieved» Several key milestones achieved over past few months: PNG LNG producing consistently at ~8 MTPA, compared to 6.9 MTPA nameplate capacity: OSH believes further optimisation possible Major increase in PNG LNG Project reserves: Supports increased production rates and leaves discovered undeveloped resources at P nyang and Elk-Antelope unencumbered to support expansion Increase in Elk-Antelope resource: 21% increase in 2C, to 6.45 tcf Discovery of gas at Muruk: Increases optionality for sourcing of gas for expansion Reduces uncertainty of several leads and prospects on-trend, with material prospectivity Successful completion of ExxonMobil acquisition of InterOil: Opens way for formal discussions to commence on cooperative development between Elk-Antelope and PNG LNG» Set against backdrop of a tightening long term LNG market, with demand stimulated by lower LNG pricing and new technology Company Update March 2017 4

2016 operational highlights» Strong operating result delivered: Record oil and gas production: 30.24 mmboe 3% higher than 2015: Underpinned by excellent production performance from PNG LNG Project and solid oil production Continuation of unit production cost reductions, down 16% from US$10.08 boe in 2015 to US$8.50 boe. 30% drop since 2014 Strong platform of reserves and resources for growth and sustainability: 49% increase in 1P reserves 11% increase in 2P reserves Reserves cover on 1P basis of 16 years, 18 years for 2P 2P reserves and 2C contingent resources cover of 44 years Successful Antelope appraisal programme and resource certification Definition of development options for PNG LNG, P nyang and Elk- Antelope expected to be discussed in 1Q17 following recent completion of ExxonMobil acquisition of IOC Company Update March 2017 5

Highest ever full year production» FY16 production of 30.24 mmboe, an all-time record for OSH: Outstanding performance by PNG LNG Project: 23.4 mmboe (101.8 bcf LNG plus 3.45 mmboe liquids). Annualised production rate of ~7.9 MTPA, peak rate of ~8.4 MTPA in November & December High uptime (>96%), operating >15% above design capacity 108 LNG cargoes sold, 89 under long term contract and 19 spot cargoes 6.8 mmboe contributed from operated oil fields and Hides GTE, well above budget for mature fields: Oil 5.0 mmboe Hides GTE 1.21 mmboe SE Gobe third party gas sales to PNG LNG 3.1 bcf Facilities uptime >94%, excellent performance 32 cargoes of Kutubu Blend and 10 naphtha cargoes sold Net Production (mmboe) 35 30 25 20 15 10 5 0 PNG LNG OSH-operated +186% 6.74 19.27 12.20 29.25 +3% 30.24 22.22 23.42 6.74 7.08 7.03 6.83 2013 2014 2015 2016 1 Includes SE Gobe gas sales +52% 1 1 Company Update March 2017 6

Reserves and resources at 31 December 2016» Major increase in PNG LNG Project reserves: Technically recoverable gas recertified for all Project fields by NSAI. Reserves assessed using OSH corporate economic assumptions 1P category: 50% increase in PNG LNG gas reserves (+815 bcf), with ~26% coming from OSH-operated oil fields, and 30% increase in condensate (+13 mmbbl) 2P category: 12% increase in PNG LNG gas reserves (+353 bcf), minor reduction in condensate (-3 mmbbl)» Increases after record production volumes for 2016 of 8.5 mmbbl oil and condensate and 105.8 bcf gas*» Key changes to resources: Addition of 254 bcf of 2C gas and 13 mmbbl of 2C condensate, equivalent to 6.53 tcf of raw gas gross, from Elk-Antelope (PRL 15): Gross figures consistent with average 2016 certification by NSAI and GCA, average 1C and 2C resource of 5.2 tcf and 6.4 tcf of raw gas respectively Removal of 21.9 mmbbl oil and 6.3 bcf gas relating to Taza and Block 7, Yemen * Production volumes include Oil Search s entitlement of PDL 1 (16.67%) for Hides GTE Project At end Dec 2016 Oil and condensate (mmbbl) % Change Gas (bscf) % change 1P Reserves 62.3 8% 2,151 49% 2P Reserves 75.7 13% 2,425 11% 2C Resources 48.3 15% 3,709 3% Total 2P & 2C 124.0 14% 6,134 6%» On 2016 production of 30.24 mmboe:» 1P reserves life - 16 years» 2P reserves life - 18 years» 2P reserves and 2C resources life - 44 years» Substantial 2C gas which is likely to be commercialised by LNG expansion Company Update March 2017 7

Fourth consecutive year of improved safety performance Per million Hours worked 5 4 3 2 1 4.7 3.9 2.7 3.1 Total Recordable Incident Rate 2.9 2.7 2.6 2.5 2.1 2.0 2.3 1.9 2.1 1.8 2.0 1.7 1.8 1.7 1.6 1.2 OSH 2.0 1.9 1.5 1.2 IOGP 1.53 Per million hours worked 0.75 0.50 0.25 0.00 Lost Time Injury Frequency 0.59 0.49 0.00 2013 2014 2015 2016» Safety improvement plan introduced following increase in TRIR in 1H16 0.26» Significantly better performance in 2H16, leading to 20% improvement in TRIR for FY16 relative to FY15, from 1.9 to 1.53 per million hours worked» Process safety performance a key focus for production and drilling operations 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016» Strong environmental performance in 2016, continuation of ISO 14001 certification Company Update March 2017 8

2016 financial highlights» Core profit of US$106.7m: Achieved despite 33% lower realised LNG and gas prices and 12% drop in realised oil and condensate price» Statutory NPAT US$89.8m, including profit from IOC break-fee, offset by deferred tax restatement» Final dividend for 2016 of 2.5 US cents, 3.5 US cents total for year» Strong performance during lower oil price environment: Cash flow positive at ~US$17/bbl, with break-even cash flow after interest, principal repayments and sustaining capex ~US$28/bbl US$1.61bn liquidity available to support growth programmes Company Update March 2017 9

Financial metrics are robust Cash flow break-even analysis (US$/boe) 50 40 30 20 10 0 11.2 Operating costs* 5.9 Interest expense** 1.3 Sustaining capex Cash and Corporate Facilities available Average realised oil price 9.5 Principal repayments*** 27.9 Total * Excludes inventory movements, donations, IOC acquisition costs, power expense, business development costs, other expenses and rig operating costs ** Includes interest from finance leases *** Includes payments for finance leases Cash flow Chart 1500 1000 500 0 Non Escrow Escrow Opening Cash Operating Investing Financing Closing Cash Operating cash flow of US$18.15/boe Indicative annual repayment profile Non Escrow Escrow 1000 750 500 250 0 2012 2013 2014 2015 2016 Cash (US$M) Corporate Facilities Available (US$M) Balance sheet solid, liquidity US$1.61bn US$m 600 400 200 - Principal Repayment Total Principal & Interest Company Update March 2017 10

Sources of gas for LNG expansion P nyang (~3.5tcf, 2C,~1.1 tcf 1C ) Juha Muruk (TBC) Hides Angore Moran PNG LNG Project Gas Fields PNG LNG Project Facilities Hides Gas Conditioning Plant Agogo Gas available for expansion Papua New Guinea Kutubu Gobe Main Elk/Antelope (~6.5tcf 2C, ~5.3tcf 1C) Hides Kutubu Port Moresby Oil Pipeline Oil Facility Oil Field Gas Pipeline Gas Pipeline Gas Facility Gas Field Condensate Pipeline LNG Plant Company Update March 2017 11

Material increase in PNG LNG reserves» NSAI recertification of PNG LNG fields has resulted in gross increase of ~2.8 tcf 1P (~815 bcf OSH net) in future sales gas. Provides flexibility and ability to: 8 7 PNG LNG 1P Reserves* Sustain higher rates of production (~8 MTPA) from PNG LNG and potentially provide early 1P coverage for LNG expansion Optimally place volumes in either term contracts (for uncommitted production above 6.6 MTPA) and / or spot market» Further bolsters strongly performing world class project and increases likelihood of high value integrated LNG expansion Gas Reserves (1P, 100% basis) (tcf) 6 5 4 3 2 1 - YE2015 Reserves Production YE2016 2016 Recertification YE2016 Reserves * After historical production, F&F and shrinkage, adjusted for economic limit using OSH s corporate assumptions Company Update March 2017 12

Material increase in PRL 15 resources» Increase in OSH 2C contingent resource at Elk- Antelope following 2017 drilling and evaluation: Gas increased by 21% to 1,473 bcf (6.45 tcf gross) Condensate increased to 13 mmbbl (57 mmbbl gross)» Final appraisal well - Antelope 7/7ST1 - underway: Objective to provide structural control and test for reservoir in poorly defined western flank No carbonate reservoir encountered to date, consistent with OSH and certification interpretation Drilling ahead to Antelope Deep secondary target No volumes carried for Antelope 7 Poorer quality seismic imaging Antelope Deep Antelope PRL 15» Five-year extension of PRL 15 licence granted in December: Licence conditions stipulate completion of pre-feed and FEED in first two years» Project milestones will lead to timely LNG development ELK ANTELOPE 0 10 Km Company Update March 2017 13

Muruk gas discovery adds to existing undeveloped resources» OSH-operated Muruk discovery located ~21km from nearest producing PNG LNG infrastructure: Due to proximity to Hides, could result in competitive development costs (subject to appraisal results) PPL 402 Muruk 1 PPL 402 WI % Oil Search 37.5 Esso PNG Wren Ltd (ExxonMobil affiliate) 42.5 Santos 20 Provides optionality of field phasing for LNG expansion to deliver maximum value to all parties» Muruk, and de-risked exploration prospects along trend, add to 2C resources in Elk-Antelope and P nyang of 10 tcf» P nyang South 2 well to be drilled in 2H17, contracting for well pad construction underway: Recertification to take place after well completion Resources* (tcf) 14 12 10 8 2C 6 4 1C 2 0 Expansion Project * Upstream dry gas Muruk Subject to additional appraisal Additional Volume Company Update March 2017 14

Cooperative LNG expansion» Elk-Antelope and P nyang can supply two additional 4+ MTPA trains constructed together at existing PNG LNG site» Formal discussions on LNG expansion to commence shortly post completion of ExxonMobil acquisition of InterOil» OSH, partners and Government have confirmed intent to pursue coordinated development» Targeting alignment on field phasing and commercial model in 2H17 LNG Export (MTPA) 18 16 14 12 Elk-Antelope + P nyang + Muruk 10 8 6 4 PNG LNG Foundation 2 0» Various commercial models can deliver brownfield expansion: US$2-3+ bn of downstream cost synergy US$125+ million annual opex savings Optimised field phasing and schedule acceleration Company Update March 2017 15

Cost benefits for LNG expansion integration, with material opex and capex savings Sharing of utilities, power generation, metering, controls US$/mmbtu 20 15 10 5 - Reduction of overall tank storage requirements Construction of spur instead of new jetty & sharing of shipping channel Infrastructure (laydown, roads, camps, buildings) Sharing of flare LNG Project Breakeven Price Source: Wood Mackenzie 3Q16 LNG Tool, full-life breakeven, 10% discount rate, FOB» PNG Government a major beneficiary of cost-effective and timely development» Even without cooperation, PNG expansion projects consistently rated lowest quartile costs by industry analysts» Potential downstream capex savings of US$2-3bn and opex savings of US$125m pa improve economics further» Potential additional savings in: PMT/Owner s costs Upstream synergies Schedule acceleration» Maintains two major operators in PNG Company Update March 2017 16

LNG market currently oversupplied, but tightening 600 500 Global LNG Supply-Demand Balance mtpa 400 300 200 100 0 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Operating Under Construction Global LNG Demand Source: FACTS Global Energy Sep 2016 North East Asia expiring LNG contracts 2017 2026 (MTPA) Japan >45 Korea >20 Others ~7» View in Sep 16 that additional supply was required from ~2024 to meet global demand» Several LNG buyers and sellers have indicated market is now expected to rebalance in early 2020s, with new supply required to meet both market growth and expiring contracts» FID for new supply required this decade» North East Asia remains key growth region Company Update March 2017 17

Long term LNG market demand expanding» Long term global LNG demand expected to continue to grow strongly, absorbing new supply» LNG usage expanding (including for use in merchant shipping)» Strong demand growth in traditional markets such as China and India» Number of LNG importing countries / LNG buyers continues to grow: Traditional exporters eg Indonesia now also in market as buyers for domestic requirements LNG buyers have emerged in new markets such as Thailand, Singapore, Bangladesh, Vietnam, Pakistan, Philippines, Egypt, Jordan» FSRUs and other technology have supported demand growth and have facilitated faster delivery to markets Company Update March 2017 18

Short term oversupply but long term LNG outlook remains strong» LNG spot price rose from ~US$4/mmbtu in 1H16 to >US$9/mmBtu in Dec 2016, driven by seasonal and supply issues. Now back to ~US$6.50/mmBtu» Long term LNG market fundamentals remain strong: Buyers continuing to enter into long term SPAs Consistent with recent oil price appreciation, LNG short and long term pricing strengthening Oil linked pricing prevalence continues to be default in new long term contracts» PNG expansion well positioned to capture market opportunities: Continued exceptional performance of PNG LNG Additional PNG LNG volumes available for short/mid/long term LNG marketing following recertification 10+ tcf resources with overlapping ownership interests Cost-competitive brownfield integrated development Company Update March 2017 19

Gas commercialisation activities in 2017 2017 work streams to progress timely co-operative development Elk-Antelope Completion of Antelope 7ST1 ExxonMobil entry to PRL 15 P nyang P nyang South 2 pad construction to commence in April 2017 Target P nyang South 2 in 2H17 (after wet season) and recertification Muruk Completion of Muruk 1 and sidetracks, certification Site prep for additional appraisal well(s) Integration technical study and commercial discussions between JVs and PNG LNG to deliver binding agreements Concept Select and commencement of upstream and downstream pre-feed before YE 2017 Gas Agreement discussions to commence before YE 2017 FEED 2018 Company Update March 2017 20

2016 exploration strategy and outcome» PNG-wide prospectivity review completed focusing on long term strategy: 60% of PNG s resource yet to find (ie >7bn boe) >90% of yet to find expected to be gas» Materially expanding PNG acreage: Focus on gas expansion and delineating remaining oil Strong portfolio including several game changers» Significant Muruk gas discovery end 2016: ~350m gas column to date (no GWC yet defined) 21 km NE of Hides infrastructure Results upgrade on-trend prospectivity» 2017 programme targeting 4-6 tcf unrisked: Active appraisal drilling in 2017 Seismic to firm up material new prospects to drill in 2018, targeting key LNG hubs» Industry cost rebasing has resulted in significant cost savings and ability to attract world class personnel Company Update March 2017 1. NW Highlands Hub Near field exploration activities targeting 2-3 tcf mean gross prospective resources (unrisked) 3. Papuan Deep water Hub New frontier Seismic & studies to mature candidates for drilling 2018/19 2. Gulf / Forelands Hub Targeting 1-2 tcf mean gross prospective resources (unrisked) Appraisal existing resources targeting up to 1.3 tcf gross 2C resources (unrisked) 21

Muruk gas discovery (OSH 37.5% and operator)» Early results from Muruk very encouraging, strong JV alignment for early appraisal» Muruk 1 & sidetracks in 2017: Muruk 1 Muruk tested large structure 21km NW of Hides. Penetrated gas saturated Toro sand with gross thickness of 106 metres Muruk 1ST1 targeted Toro reservoir 1km to NE. Has more than doubled proven gas column to 350 metres Muruk mapped closure Sidetrack being deepened and reorientated to target Toro deeper and gain additional structural information Active forward appraisal programme being proposed: Muruk Lowest Known Gas Deepening Muruk 1ST1 plus additional side tracks likely Site prep in 2017 for appraisal drilling in 2018 Seismic on Karoma prospect, to mature for drilling in 2018» Muruk result has derisked major play trend: Three prospects along trend with similar attributes to Muruk. Combined unrisked mean resource potential of 4 6 tcf Targets to be confirmed by 2017 seismic SW NE Company Update March 2017 22

Appraisal of material upside in existing Foreland fields» Appraisal to define 2C resource and near field exploration opportunities (Kimu North): PRL 8 PRL 9 2016 seismic acquisition upgraded resource potential 2017/18 wells targeting ~1 tcf mean unrisked prospective resources» Kimu (PRL 8, OSH 60.7%): Kimu Barikewa Cluster of prospects adjacent to Kimu gas field with recently identified upside» Barikewa (PRL 9, OSH 45.1%): PRL10 Uramu Kimu road network Confirm 1C and 2C resource, Field located adjacent to existing infrastructure» Uramu (PRL 10, OSH 100%): Kimu North Uramu 1A Well will test updip potential High-quality reef, shallow water, well to define 2C» Results will drive final commercialisation options: Tier 1: Existing LNG project integration Kimu West Tier 2: Small-scale LNG Tier 3: Power generation / petrochemicals 0 4 Km TWT Seismic 0 2 Km Company Update March 2017 23

Small scale LNG (sslng)» Opportunity exists to commercialise smaller undeveloped gas resources from Gulf, Western and Highlands Provinces through smaller scale LNG development (0.5 1.5MTPA)» Likely to require combination of in-country and regional end users: Potential for supply to capture fuel requirements for mines and east coast of PNG Regional LNG supply prospects for power generation» Oil Search to appraise Barikewa and Kimu fields in 2017 and Uramu in 2018 to confirm the resource base for potential sslng: Partnering strategy to facilitate development 24

Three year exploration focus in PNG» Optimal combination of appraisal and high quality exploration, supporting gas expansion and material new growth opportunities» Coordinated programmes to prioritise capital, optimise rig activity and drive lower costs» Appraisal drilling to focus commercialisation efforts» Partnering to balance portfolio risk, manage capital and secure commercialisation path Region / Hub 2016 2017 2017 2017 2017 2018 2018 2018 2018 2019 2019 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q NW Highlands Onshore Gulf 2D Seismic* 2D Seismic* Muruk Muruk 1 sidetracks P'nyang SE 2* Well 3* Well 4* Well 5* Well 6* Well 7 Ant 7 / Deep 2D Seismic* Barikewa 3 Kimu West* 2D Seis* Well 1* Well 2* Well 3* Well 4 Offshore Shallow water Grav - Mag* Well 1 Well 2 Offshore Deep water 3D Seismic* Seismic Expl'n Well Appraisal Well * Subject to JV and/or government approval, timing dependent on rig availability Schedule subject to change Company Update March 2017 25

Key events expected in 2017» Comprehensive discussions on cooperation and project development scope, following recent completion of ExxonMobil entry to PRL 15 (Elk-Antelope) : Licence commitments on PRL 15 and PRL 3 a factor in driving timely entry into FEED and FID» Further appraisal of Muruk in 1H17 and drilling on P nyang in 2H17» Completion of Elk-Antelope appraisal (and Antelope Deep exploration) followed by reserve/resource review» Continued optimisation of PNG LNG production» PNG election June/July. New Government formed August 2017 Company Update March 2017 26

PNG election timeframe 'Your Choice, Protect the Democracy - Election 2017'» Timing Last sitting of Parliament PNG Major Political Party's as at Nov 2016* Seats held % of seats Friday, 5 February 2017 Issue of Writs & Nominations Voting: Open: Thursday 20 April 2017 Close: Thursday 27 April 2017 Start: Saturday 24 June 2017 End: Saturday 8 July 2017 Return of Writs By Monday 24 July 2017 Government is formed (with contingency timing) : August People's National Congress Party 27 24.3% Triumph Heritage Empowerment Rural Party 12 10.8% Papua New Guinea Party 8 7.2% National Alliance Party 7 6.3% United Resources Party 7 6.3% People's Party 6 5.4% People's Progress Party 6 5.4% Social Democratic Party 3 2.7% Coalition for Reform Party 2 2.7% Melanesian Liberal Party 2 2.7% New Generation Party 2 2.7% People's Movement for Change Party 2 2.7% People's United Assembly Party 2 2.7% People's Democratic Movement 2 2.7% Independent 16 14.4% *Parties with one seat not shown Company Update March 2017 27

2017 production outlook» 2017 production forecast: 28.5 30.5 mmboe» OSH-operated: 5.5 6.5 mmboe Includes 2.8 3.1 bcf (net) of SE Gobe gas sales (OSH 22.34%) exported to PNG LNG Specific focus on production optimisation and efficiency through integrated Life of Asset Planning» PNG LNG: 23 24 mmboe 101-104 bcf LNG, 600-650 mmscf power, 3.0 3.5 mmbbl liquids PNG LNG routine compressor maintenance planned for May and September 2017 Planning for Angore tie-in and HGCP slugcatcher modifications in 2018 LNG (MTPA) 10 8 6 4 2 0 Actual Quarterly Rates 2014 initial ramp-up PNG LNG Production Oil Search Projected OSH Net Production (mmboe) 1,2 35 30 25 20 15 10 5 0 PNG LNG (T1 + T2) Hides GTE SE Mananda Gobe Moran Kutubu Operated Fields 19.32 29.25 6.38* 6.47* 7.08* 7.03* 30.24 6.83* 28.5-30.5 5.5-6.5* 2012 2013 2014 2015 2016 2017F 1. LNG sales products at outlet of plant, post fuel, flare and shrinkage 2. Gas:oil conversion rate from 2014 onwards: 5,100 scf = 1 barrel of oil equivalent (prior 6,000 scf/boe) * Oil Search operated production, including SE Gobe gas sales to PNG LNG Project Company Update March 2017 28

2017 Guidance 2017 Capital Cost Guidance (US$360 460 million) US$m 2000 1750 1500 1250 1000 750 500 250 0 2013 2014 2015 2016 2017 Guidance Other PP&E Production Development US$918m PRL 15 acquisition costs Exploration & Evaluation» Exploration & Evaluation: US$250 300 million» Development: US$35 45 million» Production: US$45 65 million» Other PP&E: US$30 50 million Production 2017 Guidance 1 Oil Search operated 5.5 6.5 mmboe 2,3 PNG LNG Project: LNG Power Liquids 101 104 bcf 600 650 mmscf 3.0 3.5 mmbbl Total PNG LNG Project 23 24 mmboe 2 Total Production Operating Costs Production costs Other operating costs 4 Depreciation and amortisation 28.5 30.5 mmboe US$8.50 10.50 / boe US$135 145 million US$12 13 / boe 1 Numbers may not add due to rounding. 2 Gas volumes have been converted to barrels of oil equivalent using an Oil Search specific conversion factor of 5,100 scf = 1 boe, which represents a weighted average, based on Oil Search s reserves portfolio, using the actual calorific value of each gas volume at its point of sale. 3 Includes 2.8 3.0 bcf (net) of SE Gobe gas sales exported to the PNG LNG Project (OSH 22.34%). 4 Includes Hides GTE gas purchase costs, royalties and levies, selling and distribution costs, rig operating costs, corporate administration costs (including business development) Company Update March 2017 29

Summary - unprecedented platform for growth» 2016 Strategy Refresh highlighted potential to deliver top quartile returns for next 5 7 years» Delivery of PNG LNG expansion and development of Elk-Antelope core to high-returning growth» Recent milestones establish strong platform to deliver: Upgrade in PNG LNG Project reserves support expanded capacity. Existing world class project and infrastructure Strong resource base with 10 tcf + available for expansion: Elk-Antelope appraisal nearly complete, P nyang drilling in 2H17 Muruk a potential significant resource Multiple train potential Entry of ExxonMobil into PRL 15 triggers cooperation discussions, starting 1Q17: Already strong support from all stakeholders» Building excellent exploration portfolio, complementary to gas commercialisation» Ancillary field development review sslng» Comprehensive in-country community-based programmes underwriting stable operations» Further organisational optimisation with succession planning Company Update March 2017 30

Oil Search Limited ARBN 055 079 868

Appendix 1: Strong long term TSR performance 120 80 Total Shareholder Returns to 31 December 2016 Median TSR ASX200 Median TSR ASX200 Energy OSH TSR 112.0 % TSR 40 0 6.3 0.4 0.4 20.8-12.3-40 -50.0-45.7-80 -70.7 Company Update March 2017 1 YEAR 5 YEAR 10 YEAR Source: Orientcap 32

Appendix 2: 2016 highlights and financial Performance Highlights 2016 2015 Sales volume (mmboe) 30.59 28.76 Operating cash flow (US$m) 555.1 952.7 Total dividend (US cents) 3.5 10.0 Net debt (US$m) 3,076.6 3,318.2 Liquidity (US$m) 1,612.7 1,658.5 Full Year P&L (US$m) 2016 2015 Revenue 1,235.9 1,585.7 Costs of production (296.0) (324.4) Other costs (87.7) (110.1) EBITDAX 1 852.2 1,151.3 Depreciation and amortisation (436.7) (407.8) Exploration costs expensed (53.2) (50.9) Impairment - (399.3) InterOil break fee (net) 18.7 - Net finance costs (196.0) (185.1) Profit before tax 185.0 108.3 Tax (95.2) (147.6) Net profit/(loss) after tax 89.8 (39.4) Impairment (net of tax) - 399.3 InterOil break fee (net) PNG tax law changes Core profit 1 (18.7) 35.6 106.7 - - 359.9» 6% increase in sales volume offset by lower average realised prices, reducing revenue by 22%» Operating cash flow and earnings solid despite soft oil and LNG market conditions liquids price 12% down on prior year and LNG price down 33% due to pricing lag» Operating costs lowered, despite higher sales volumes, due to efficiency savings and reduced discretionary work programmes» Core profit of US$106.7 million excludes: InterOil bid related income of US$48.0 million, partially offset by associated costs of US$29.3 million One-off, non-cash restatement of deferred tax balances of US$35.6 million, resulting in effective tax rate of 51%» Final ordinary dividend of 2.5 US cents per share 1 EBITDAX (earnings before interest, tax, depreciation/amortisation, non-core activities, impairment and exploration) and Core profit (net profit after tax before significant items) are non-ifrs measures that are presented to provide a more meaningful understanding of the performance of Oil Search s operations. The non-ifrs financial information is derived from the financial statements which have been subject to review by the Group s auditor. Company Update March 2017 33

Appendix 3: Unit production costs reduced to US$8.50/boe US$m 2016 2015 Production costs: - PNG LNG - PNG Oil and Gas 150.6 106.5 149.9 144.9 257.1 294.8 US$/boe 8.50 10.08 Royalties and levies 5.4 12.4» Production costs on a per barrel of oil equivalent (boe) basis declined 16%» PNG LNG production unit costs on a per boe basis were 5% lower than 2015 unit costs, with PNG LNG Project producing well above nameplate capacity» PNG oil and gas unit production costs per boe for 2016 were 24% lower than in prior year, primarily due to cost reduction initiatives, one-off restructuring costs in 2015 and no well workover activity in 2016 Unit production costs PNG Oil & Gas PNG LNG Gas purchases 14.7 20.9 Inventory movements 18.9 (3.7) Total costs of production 296.0 324.4 US$ / boe 25 20 15 10 5 15.60 6.43 20.62 (~US$18.50 excl one-offs) 6.75 0 2016 2015 Company Update March 2017 34

Appendix 4: Operating margins EBITDAX Margin % 100 95 90 85 80 75 70 65 114 72 111 72 98 78 2012 2013 2014 2015 2016 EBITDAX Margin 51 73 Oil & Condensate Price 45 69 120 100 80 60 40 20 0 US$/boe» Average realised oil and condensate price of US$45.04/bbl, reflecting the continual deterioration in global oil prices in early 2016» EBITDAX margin down due to lower oil and condensate, LNG and gas prices, partially offset by increase in sales volumes Company Update March 2017 Cash Margin by Asset US$/boe 50 45 40 35 30 25 20 15 10 5 0 5.50 15.60 23.67 PNG Oil & Gas 1.68 6.43 30.02 PNG LNG Cash Margin Production costs Other costs» PNG Oil and Gas and PNG LNG cash margins remain healthy but impacted by downturn in oil prices» Other costs include shipping and inventory movements and, for Oil and Gas, gas purchases for Hides GTE project 35

Appendix 5: Cash flows» Healthy operating cash flows despite weak oil price environment: US$m 1,500 555 Operating cash flow of US$18.15/boe 1,250 Includes borrowing costs of US$194.0 million (232)» Investment spend driven by US$142.9 million spent on exploration and evaluation expenditure, mainly relating to Antelope wells including related pre-feed activities and other exploration drilling (Muruk 1 well, Strickland 1 and 2 wells) 1,000 750 500 910 Non Escrow (371) 863 Non Escrow» Financing includes payment of 2015 final 2016 interim dividends totalling US$76.1m» Repayment of US$289.3m under PNG LNG Project finance facility 250 0 Escrow Opening Cash Jan 2016 Escrow Operating Investing Financing Closing Cash Dec 2016 Company Update March 2017 36