AntelopeAntelope-1 Technical Summary, Current Activities and Forward Plan July 20091

Forward Looking StatementsThis presentation includes forward-looking statements as defined in United States federal and Canadian securities laws. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. In particular, this presentation contains forward-looking statements pertaining to business plans and strategies; testing at the Antelope-1 well; the Elk/Antelope seismic program; the proposed farm-out or sale of interest in the Elk/Antelope and exploration assets; the proposed condensate stripping project and expected benefits therefrom (based in part on the EDG Consulting condensate feasibility study); proposed development of a liquified natural gas processing facility; proposed exploration and development activities, including drilling, seismic programs and commitments; and the BWATA field delineation and regional exploration program; These statements are based on certain assumptions made by InterOil based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. No assurances can be given however, that these events will occur. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of InterOil, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. Some of these factors include the inherent uncertainty of oil and gas exploration activities; the availability and cost of drilling rigs, oilfield equipment, and other oilfield exploration services; InterOil's ability to finance the development of its LNG facility; InterOil's ability to timely construct and commission the LNG facility; turmoil in the financial and capital markets; political, legal and economic risks in Papua New Guinea; landowner claims; weather conditions and unforeseen operating hazards; the impact of legislation regulating emissions of greenhouse gases; and the risk factors discussed in InterOil's filings with the Securities and Exchange Commission and Canadian securities commissions, including but not limited to those in InterOil's Annual Information Form in the year ended December 31, 2008 and its annual MD&A for the year ended December 31, 2008. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. The forward-looking statements contained in this presentation are made as of the date hereof and InterOil does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable securities laws. The forward-looking statements contained herein are expressly qualified by this cautionary statement. We currently have no reserves as defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. InterOil includes in this presentation information that the SEC's guidelines strictly prohibit InterOil from including in filings with the SEC. Investors are urged to consider closely the disclosure in InterOil's Form 40-F, available from us at www.interoil.com or from the SEC at www.sec.com and Annual Information Form in the year ended December 31, 2008 on SEDAR at www.sedar.ca InterOil has commenced a process to enter into an agreement with suitable industry farm-in partner(s) to acquire interests in the Elk/Antelope structure and the proposed LNG plant. There is no assurance that any suitable farm-in partner will be identified or that any agreement will be completed as proposed or at all.

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Agenda Antelope-1 Well Technical Summary Well Review Drill Stem Test Update Elk/Antelope Field Resource Estimate

Current Activities Antelope-2 Rig Move and Spud Antelope-1 Long Term Well Test Elk/Antelope Seismic Program Phase 1 Update on Farm-out/Sale to Strategic Partner(s) Antelope-2 Well Objectives Elk/Antelope Appraisal Strategy Condensate Stripping Project Feasibility Study Exploration Program and Commitments Bwata Gas Field Delineation and Regional Exploration Seismic Program

Forward Plans

Summary

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Antelope-1 Well Technical Summary

WELL REVIEW

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Elk/Antelope Well Location Map

PPL238 PPL237

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Antelope-1 Key Dates

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Antelope-1 Objectives and ResultsAntelope-1 was spudded with the following objectives:Drill a structural attic ~2,269ft above the Elk-4 Lowest Gas Complete a second gas well in the Antelope block and extend the field by 2.6 miles south of Elk-4 Quantify Increases in condensate with depth Test for Shallow marine reefal limestone With the following results: Achieved - Top of reservoir within 2 metres of prognosis and the largest known vertical column in any well in PNG Achieved - Antelope-1 successful as a gas discovery well and completed as a future producer Achieved - Condensate yields range from 13 to 22 Bbl per MMcf with indications of oil in tests Achieved the well penetrated highly productive dolomite and limestone reef/platform reservoir as predicted Achieved - validated the reef porosity to be significantly higher than the previous Elk wells7

Quantify the porosity in the reef/platform facies

Results Surpass Expectations Hydrocarbons from 5,732 ftMD (1,747m) to 8,156 ftMD (2,486 m) indicate atotal column of 2,425 ft (739 m)

Antelope-1

Highly Productive Reservoir Record flows of 382 MMcfd and 5,000 BCPD and Calculated Absolute OpenFlow of over 17 BCF per day From 5,840 ftMD (1,780 m) to setting of the 7 casing, all drilling/testing operations conducted with no-returns to surface indicating significant permeability and porosity Over 500,000 Bbls of drilling fluid (mostly freshwater) lost to the formation Dolomite Zone: Net reservoir 746 ft (227 m) Av. Porosity 13% up to 30% Limestone Zone: Net reservoir 1,345 ft (410 m) Av. Porosity 7% Upper Transition Zone: Net reservoir 108 ft (33 m) Av. Porosity 5% Lower Transition Zone: Net reservoir 217 ft (66 m) Av. Porosity 4% Excellent hydrocarbon saturation characteristics confirmed by wireline logs and capillary height data

Deepened lowest known, or moved hydrocarbons in the field (from testdata) from 7,182 ftTVDss (2,189 m) in Elk-4 to 7,395 ftTVDss (2,254 m) in Antelope-1, an increase of 213 ft (65 m)8

Antelope-1 Well Technical Summary

ANTELOPE-1 DRILL STEM TEST UPDATE

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Lower DST Intervals and Antelope-1 LogDST intervals over tighter reservoir sections

DST #12 (2,347-2,402 mMD) DST #13 (2,375-2,402 mMD)

Lowest hydrocarbons recovered 2,452 mMD

DST #14 (2,420-2,452 mMD)

DST #15 (2,462-2,486 mMD)Test mechanically unsuccessful

DST #12, #13 and #14 were successful tests that recovered gas, condensate, oil and valid pressure data in each

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Test Update - DST #12-15 Conclusions Testing indicates gas and condensate down to 7,769 ftMD (2,368 m) / 7,133ftTVDss (2,174 m) Condensate yields at these lower intervals range from 15-22 Bbl per MMcf in field testing Condensate yields in the upper section of the dolomite were approximately 13 Bbl per MMcf in field testing PVT analysis and process simulation indicate condensate yields will be approximately45% higher through a processing plant than what is measured in the DSTs

33o-35o API oil has flowed from below 7,769 ftMD (2,368 m) / 7,133 ftTVDss(2,174 m) Due to the tight reservoir in these lower intervals, analysis indicates two possible base case outcomes i. A gas/oil contact at approximately 7,769 ftMD (2,368 m) and an oil/water contact at8,156 ftMD (2,486 m) with possible transitions between these contacts ii. A gas/water contact at approximately 8,156 ftMD (2,486 m)/ 7,520 ftTVDss (2,292 m)

These results confirm the basis for a long term well test across the deeperintervals for further oil and condensate characterization11

Antelope-1 DST SamplesThe variations observed are indicative of the oil recovered from below 7,769 ftMD (2,368 m) with 33-35 API along with a possible mixture of oil and condensate (44-49 API) and 100% condensate (52 API) DST #11 DST #12 DST #12 DST #13 DST #14

Condensate o (52 API)

Light Oil Condensate / Light Oil (44-45 API) (47-49 API) Possible Condensate Oil Mixing

Oil (33 API)

Oil (33-35 API)

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Antelope-1 Well Technical Summary

ELK/ANTELOPE FIELD RESOURCE ESTIMATE

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GLJ Petroleum Consultants Resource EstimateElk/Antelope as of December 31, 2008Case* Best 3.43 59.3 631.0 Gross Resource Estimate for Gas and Condensate As At December, 31, 2008 Contingent Gas Resources (Tcf) Contingent Condensate Resources (MMBbls) Contingent Resources MMBOE Low 2.32 36.7 423.4

High 4.73 87.9 876.2

Resource Estimate for Gas and Condensate Net to InterOil* As At December, 31, 2008 Contingent Gas Resources (Tcf) Contingent Condensate Resources (MMBbls) Contingent Resources MMBOE Low 1.3 20.4 235.7 Case* Best 1.9 33.0 351.3 High 2.6 48.9 487.8

An evaluation of the potential resources of gas and condensate for the Elk/Antelope field has been completed by GLJ Petroleum Consultants Ltd., an independent qualified reserves evaluator, as of December 31, 2008 The estimates presented are in accordance with the definitions and guidelines in the COGE Handbook and Canadian NI 51101 standards Best Case estimate of 3.43 Tcf gross (1.9 Tcf net) and High Case estimate of 4.73 Tcf gross (2.6 Tcf net).

*55.67% Participating Interest assumes all IPWI Investors and the PNG Government elect to fully participate after a Production Development License has been granted.

Please refer to the statement of resources in the Companys 2008 Annual Information Form filed on www.sedar.com for additional disclosure.

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development. There is no certainty that it will be commercially viable to produce any portion of the resources. These resource estimates are not classified as reserves primarily due to lack of marketing infrastructure, further project application, facility and reservoir design work. There is no guarantee that all or any part of the estimated resources will be recovered. Although a final project has not yet been sanctioned, pre - Front End Engineering and Design (FEED) studies are ongoing for LNG and condensate stripping operations as options for monetization of the gas and condensate.

* See definitions in commonly used terms

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Impact of the GLJ Petroleum Consultants Results Based on InterOils LNG development plan the Best Case certified recoverable resource* of 3.43 Tcf and the High Case certified recoverable resource of 4.73 Tcf by GLJ exceeds the minimum threshold for the first train of LNG It is InterOils view, based on additional information from Antelope-1 after December 31, 2008, that there is potential to increase the resource volumes and intends to have GLJ conduct a further independent resource report after the completion of Antelope-2 Encouraged by this result InterOil has accelerated planning and studies for an early monetization gas cycling and condensate stripping project which is expected to consist of: Knowledge Reservoir for detailed subsurface modelling, reservoir engineering and flow assurance EDG Consulting Engineers for surface facilities Other specialist third party studies e.g. geomechanics/fracture studies/seismic inversion etc* See definitions in commonly used terms

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Current Activities

ANTELOPE-2 RIG MOVE AND SPUD

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Antelope-2 Well Site Preparations Antelope-2 is located 2.3 milessouth of Antelope-1Antelope-1 location

A road/track has been establishedto transport heavy loads via a Morooka tracked vehicle

Significant time and cost savingswill be gained with this added functionality

This track is expected to be usedfor future well locations in the field

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Rig Move in ProgressAntelope-2 location is complete Rig move is utilising bothhelicopter and land transport

Antelope-2 spud expected in July

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Rig Move in Progress

Most of the rig is at Antelope-2 site

Ground Transport Morooka in Service

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Antelope-1 Long Term Well TestANTELOPE 1-ST2 WELLBORE SCHEMATIC WITH 2-7/8" COMPLETION TUBING

The Antelope-1 well has been prepared fora long-term test of 6 months duration in order to gather reservoir data with the following objectives:

18 5/8" casing at 239m 2-7/8" TRSV @ 85m

9 5/8" DDVs at 929.72m and 949.57m

Determine the fluid content and properties13 3/8" casing at 1002.3m

7" x 9-5/8" liner hanger at 1697m 7" x 9-5/8" ACP at 1736m 9 5/8" casing at 1747m

TOC @ 2143m

7" x 8-1/2" ACP at 2310m 2-7/8" x 7" Completion Packer @ 2300m 7" Liner at 2347m X landing nipple Perforated Joint 6" open hole XN Landing nipple

near the hydrocarbon water contact Determine connected gas in-place to the well and evaluate the potential for reservoir boundaries Determine the possible reservoir connectivity between the Elk-4 and Antelope-1 wells Evaluate reservoir transmissibility(permeability-thickness) and natural fracture conductivity

Obtain data for reservoir characterizationPBTD at 2456m

and field development planning20

Current Activities

ELK/ANTELOPE SEISMIC PROGRAM

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Elk/Antelope Appraisal Seismic - Phase 1 Antelope Seismic Acquisition Program A 100 km program of 2D seismic acquisition has been approved and is expected tocommence early third quarter 2009

Current Activities

The Aims of the Program will be to: Further delineate Elk/Antelope structure In fill seismic to reduce the interline spacing with specific focus on the Antelope reef Coordination of the seismic acquisition with drilling to allow acquisition of offset and walkaway vertical well seismic profiles Survey Planning and design of acquisition lines and parameters for : Increased data density and resolution for reservoir geophysics - Inversion and AVO analysis Image the top dolomite and top limestone Image the Antelope and Elk faults Optimize seismic-well ties (Elk-4, Antelope-1 & 2) Better constrain lateral extents of the Elk/Antelope Field Understand fractures and stress fields (anisotropy) via possible WAVSP recording during surface acquisition (Antlope-1/Antelope-2)

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Phase 1 of New Seismic Program Proposed 100km Phase 1 seismic data acquisition program

Current Activities

Further definethe Antelope reef

Image majorfaults

Increaseseismic data density

Performhigher end reservoir geophysics

Optimizeseismic-well ties

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Update on Farmout/Sale to Strategic Partner(s) In March, 2009 InterOil Corporation announced it had retainedBNP Paribas Capital (Singapore) Ltd. (BNP) and ABN AMRO Corporate Finance Australia Ltd. (ABN AMRO) as joint financial advisors for the sale of interests in the Elk/Antelope field, the Liquid Niugini Gas Ltd LNG Project and associated liquid natural gas off-take agreements with potential strategic partners

InterOil is currently qualifying bidders

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Proposed Elk/Antelope Participating InterestsParticipating Interests Pre-Transaction* Petromin/PNG State IPWI Partners InterOil* Total Participating Interests Post-Transaction* Petromin IPWI Partners Farm-In Partners InterOil* Total 22.5% 10.9% 35.0% 31.6% 100% IPWI Partners (50%) InterOil Total 10.9% 24.1% 35.0% 22.5% 21.83% 55.67% 100% Farm-In Interests Strategic Partner Strategic Partner Strategic Partner Strategic Partner Industry Partner Total Farm-Out Interests 2.5% 2.5% 2.5% 2.5% 25.0% 35.0%

*55.67% Participating Interest assumes all IPWI Investors and the PNG Government elect to fully participate after a Production Development License has been granted.

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Forward Plans

ELK/ANTELOPE APPRAISAL STRATEGY

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Antelope-2 Well Objectives The Antelope-2 location is located south of Antelope-1 inInterOils PPL237 Exploration Licence. The objectives of the well are: Penetrate the southern margin of the Antelope Reef and determinethe extent of the dolomite cap or higher porosity limestone reservoir predicted from seismic character and analogy to offset reef/platforms in the Gulf of Papua Investigate the lower transition zone to further quantify the nature and elevation of the fluid contacts in the southern extent of the field in particular providing more confidence in the vertical extent and commercial potential of the oil leg Through testing and the acquisition and analysis of whole cores, rotary side wall cores and wireline logs provide valuable data to further understand the resource This will satisfy the PPL237 licence commitment, potentially expand the known extent of the field an additional 2.3 miles (3.7 km) south and confirm its extension into PPL237

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Elk/Antelope Cross Section SchematicElk-2 Elk-1 Elk-4 Antelope-1 Antelope-2

Reef Antelope Platform Antelope Fault

Pictorial Only: Graphic Not to Scale

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Elk/Antelope Appraisal StrategyFocus on Efficiency Engagement of Knowledge Reservoir to lead the effort of sub-surfacereservoir and engineering studies to progress a detailed development and depletion plan

Acquire a second drilling rig to boost drilling capacity A two rig operation will speed up appraisal drilling, allow sharing of supportservices and add significant efficiencies to reduce over all costs

Improving infrastructure and reducing reliance on helicopter transport Acquisition of additional construction equipment to establish and maintain a road network between rig operations Acquisition of transport equipment suited to jungle conditions and additional equipment for more efficient rig site preparation

Acquire additional in-field seismic to improve data coverage Fast track selection of two new well locations These will be infill locations within the Antelope structure

In summary, by combining a second rig with improvement of infrastructure and equipment, significant synergies and savings are expected to be achieved as the reliance on helicopters is reduced29

Forward Plans

CONDENSATE STRIPPING PROJECT FEASIBILITY STUDY

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Condensate Feasibility Study Report SummaryJuly 2009

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Early Condensate Recovery This study was performed to evaluate the benefits of producing gas and stripping condensate prior to the start up of LNG processing

Condensate stripping is envisioned to be online 3-4 years priorto LNG start up

A majority of all the wells, pipelines, equipment and facilitiesthat will be used for the stripping operation will also be used once LNG is on line, enhancing overall economics

Liquids monetization and early cash flow are expected toprovide greater value to InterOil and our shareholders

Assuming the stripping project is sanctioned, project specificresources would be converted to reserves pursuant to the definitions in the COGE Handbook32

EDG Report Summary EDG Consulting Engineers were commissioned to evaluate the opportunity to facilitate early monetization of condensate from the Elk/Antelope field Perform feasibility study with defined product slate, a costestimate and schedule

EDG is an international company with over 25 yearsof consulting experience in the oil and gas industry

Specialized in cost-effective, innovative andcomplete solutions for upstream oil and gas applications

Specific experience in condensate projects ininternational environments33

Elk/Antelope Field & Plant Locations

Hides Field

Condensate Stripping Facility

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Early Design Conclusions 400MMcfd is the best initial rate for early condensatemonetization (yielding approximately 9,000 bbls per day) We believe that the stripping facility and compression station is best located at the Purari River rather than in the Elk/Antelope field Our preferred processing case has an effective condensate recovery of approximately 9,000 bpd, which is a yield of 22.4 barrels of condensate per MMcf, based on the Elk-4 PVT analysis Oil recovery and increased condensate yield with depth would result in significantly enhanced economics35

Field Development Plan Plant at River

Schematic Not to Scale

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Economics of Early CondensateInitial Final Production Production Condensate Rate Rate Price MMcfd MMcfd $/Bbl 400 400 400 400 90 PM*

Project CAPEX Million$ 320 320

Drilling CAPEX Million$ 120 120

OPEX Million$/yr 29.6 29.6

IRR % 33 38

NPV 10% Million$ 713 1,078

Payout years 1.8 2.0

* Project Mustang Price Escalation ($54 esc. to $130)as outlined in the Information Memorandum) CAPEX includes cost for roads which were not included in the EDG scope OPEX includes $3/bbl condensate transportation fee to the refinery Drilling CAPEX includes 4 additional wells First Production Jan 2011 First Production in 2012

Condensate to gas ratio = 22.4 Bbl/MMcf

The economics have been calculated on a stand alone basis as this provides the most rigorous test of the project economics returns as an acceleration project are significantly better as most of the CAPEX is absorbed by the LNG Project 37

Economic Sensitivity to Oil Price and Yield1800 1600 1400 1200 1000 800 600 400 200 0 12 15 18

NPV 10% in US$mil

US$125/bbl US$100/bbl US$90/bbl US$75/bbl US$50/bbl

22.4

21

24

27

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Yield in bbl / MMscf

NPV is for the Stand Alone condensate case38

Early Condensate Project Summary 400 MMcfd is the initial production volume foroptimum CAPEX and recovery (approx. 9,000 bpd condensate) The project has a payout of 2 years from start of production and a net present value (10%) of over $700 million Potential oil recovery and increased condensate yield with depth would result in significantly enhanced economics The EDG feasibility study and associated economics indicate a robust project; significant added value can be achieved39

Forward Plans

EXPLORATION PROGRAM AND COMMITMENTS

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Exploration Program and Commitments Following the discovery of the Elk/Antelope field InterOil hasproved its PPL licenses in the Eastern Papuan Basin to be highly prospective for hydrocarbons

InterOils future focus for its licences is to accelerate itsexploration activities and discover and commercialise oil and gas outside the Elk/Antelope field

InterOil is currently undertaking a detailed prospectivity reviewto prioritize exploration activity

Seismic acquisition, gravity and magnetics data acquisition, fieldmapping and sub-surface studies are being planned

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Exploration and Program Commitments Exploration Program and Commitments: Exploration Licences PPL236, PPL237 and PPL238 successfullyextended for additional 5 year terms (2009 2014) Recommitted to Exploration with the following Licence commitments LicencePPL236

Sq km4,502

Acre1,112,464

CommitmentsAcquire Seismic data Drill 2 Wells Acquire Seismic data Drill 3 Wells (includes Antelope-2) Acquire Seismic data (Antelope Appraisal Seismic Survey 2009) Acquire Airborne Geophysical data Drill 1 Well Summary: Appraisal and Exploration Seismic and Airborne Geophysical Programs. Minimum of 6 Wells 42

PPL237

3,238

800,124

PPL238

8,433

2,083,831

Total

16,173

4,671,756

Forward Plans

BWATA GAS FIELD DELINEATION AND REGIONAL EXPLORATION SEISMIC PROGRAM

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Proposed Bwata Gas Field Delineation and Regional Exploration Seismic Program Exploration Seismic - Phase 2 Delineate the Bwata Gas Field Delineate near field opportunities Mule Deer White Tail Big Horn Wolverine Raptor Duck Bill

Exploration Seismic - Phase 3 Investigate and delineate regional leads and Prospects including Pale Sandstone Leads and Prospects in PPL238 Additional Fold Belt Reef leads identified on Airborne Gravity in PPL236 andPPL238 Foreland reef and Mendi Limestone Leads and Prospects in PPL237

This program will meet our licence obligations and our objective of accelerating our exploration program44

Summary Antelope-1 has been drilled, tested and completed as one of the largest known onshore vertical wells in terms of both column height and flow capacity GLJ Petroleum Consultants has completed an independent assessment for the Elk/Antelope field and provided a certified recoverable resource estimate of 631 million BOE for the best case effective 31 December 2008 An early condensate stripping project is being evaluated and based on the current feasibility study the economics appear very robust The drilling of the Antelope-2 well along with the new seismic program and the planned long term well test at Antelope-1 will solidify the understanding of the Elk/Antelope reservoir An updated resource estimate is planned to be completed by GLJ Petroleum Consultants after the drilling of the Antelope-2 well45

Commonly Used Terms API AVO Bblsmeans API gravity or American Petroleum Institute gravity, and is a measure of the relative density of a petroleum liquid and the density of water, it is used to compare the relative densities of petroleum liquids means Amplitude Variation with Offset which is the variation in seismic reflection amplitude as a function of source-geophone distance or angle of incidence. This effect is often a hydrocarbon indicator, especially for gas reservoirs. means the Petroleum industry uses a 42-gallon barrel, which was 2 gallons larger than the barrels used by many other industries. Historically Standard Oil began manufacturing such barrels and painting them blue so that purchasers could be sure they were getting a 42-gallon barrel. "Bbl" is an abbreviation of "blue barrel". means billion cubic feet (a cubic foot x 109) means barrels of condensate per day

BCF BCPD Certified recoverable resource The estimates presented are in accordance with the definitions and guidelines in the COGE Handbook and Canadian NI 51-101 standards in relation to the estimates provided here in:-

The low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. The best estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. The high estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Marketable gas estimates exclude CO2, shrinkage and gas used for fuel.

DST ftMD ftTVDss Inversion

means Drill Stem Test means a measured depth in feet in the well from the drilling rig datum used to discuss depth within a single well means a depth in feet corrected for well geometry to a true vertical depth from a sea level datum used to compare between wells means a process of deriving from observed field data a subsurface model that is consistent with that data (Sheriff, 2002). Seismic inversion is the process of quantitatively transforming seismic reflection data into a rock property description of a reservoir, achieved via the integration of surface seismic data, well logs, vertical seismic profiles, and geological knowledge. LNG means Liquefied Natural Gas MMcf/MMcfd means a measure of gas volume in Millions of cubic feet or a rate of gas flow in Millions of cubic feet per day PPL means Petroleum Prospecting Licence as defined in the PNG Oil and Gas Act PVT Analysis means a series of detailed analyses of a hydrocarbon sample conducted under different conditions of volume and temperature Tcf means trillion cubic feet (a cubic foot x 1012) WAVSP means Walk Away Vertical Seismic Profile in which seismic data is recorded in the subsurface in a well, using energy sources arranged in everincreasing linear offsets from the well on the surface, and provides the most robust tie of time, depth and seismic character to the well.

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