Elk #1 Gas DiscoveryMid-October Test Results

Elk #1 Discovery Status Summary(Gas and Condensate Confirmed)

– InterOil announces a gas and gas liquids discovery at the Elk #1 well, Papua New Guinea, in June 2006 with a flow test confirming gas and condensate to surface.

– On October 16, 2006 after additional drilling a second drill stem test, DST #2, was performed over the open hole interval from 5,381 to 6,090 feet.

– The well flowed 21.7 MMcfd through 2 ½ inch ID drill string at 1,200 psi of pressure through a 60/64th inch choke.

– The well produced high quality stabilized condensate with a gravity of 49 to 46 API.

– Shut-in surface gas pressures have remained consistent in the range 3,150 psi to 3,165 psi throughout testing since June.

– The drilling has indicated approximately 709 feet of gross limestone reservoir, with the top of the Puri Limestone at 5,471 feet (1,668 meters).

– Down hole tools recorded detailed bottom hole pressure and temperature data which are currently being retrieved.

– The Australian Government research agency, CSIRO, analysis indicates the Elk condensate originated in the peak to late oil generation window of the source rock, materially increasing the possibility of an oil leg deeper in the Elk structure and/or the adjacent Antelope structure

– InterOil plans to run a preliminary test string of 5 inch production tubing to enable a larger condensate and gas flow test on the Elk well, as the current 2 ½ inch ID drill pipe test string restricted the flow of gas and condensate production.

Information from the Elk well to date is very encouraging. The test reports are only partially complete at this date. Additional data will be obtained and continued interpretation will be done. Logging and more testing through a larger production string will be done over the coming weeks.

Elk #1 Test – June 2006

Elk #1 Discovery (Fractured Reservoir Summary)

• Elk #1 was drilled to a total measured depth of 6,506 feet (1,983 meters), with the top of the Puri limestone being encountered at 5,473 ft (1,668m) based on mud log data.

• The total reservoir thickness drilled at the current location was limited to an estimated 709 feet (216 meters), as result of down hole instability.

• The reservoir is a heavily fractured system with high permeability which enhances the capacity of the well to flow.

• Seismic information from the Elk survey and nearby outcrop data indicate the limestone thicknesses may be 1,500 to 2,000 feet thick.

• Prior to the first Drill Stem Test, DST #1, the well had experienced 4 gas kicks. The first DST recorded a shut-in surface pressure of 3,150 psi.

• The estimated potential hydrocarbon column height is calculated at up to 4,000 feet based on recorded surface pressures.

• Drilling and testing has been completed only in the top section of the hydrocarbon column as calculated from the recorded gas pressures.

Further drilling will be done to confirm the total column height and potential for oil

Aquifer Gradient – Elk #1 Theoretical Gas Column ~ 4,000 feet

The separation between aquifer pressure and formation pressure at Elk is second to Hides –(largest in PNG).

• Hides reservoir ~ net 116 feet (35m) of sandstone Column est. @ 5,600 feet, est. GIP 9.7 TCF• Elk reservoir est. ~ 2,000 feet (~ 600-650m) of Tertiary Limestone, Current thickness ~ 700 feet;• Est. Elk Column at ~ 4,000 feet

5,910 ft

4,000 ft

Top of Puri Limestone

Elk #1 Formation confirmed at a depth 1,668m. Chart shows the transition from basal Orbulina Marl to Puri Limestone with calcimetry at 57% below the empirical limestone cut off of 55% to 70% established from offset wells.

Elk #1 Discovery (Condensate and Gas DST Summary)

• On the basis of DST #1, the Elk #1 well has been classified as a gas and condensate discovery, with potential for oil at deeper intervals confirmed by data from DST #1 - June 2006 and DST #2 - October 2006.

• High quality stabilized condensate has been produced with a 46 to 49 API gravity. The gas oil ratio (GOR) will be evaluated with an additional test once a 5 inch production test string is installed in the Elk #1 well.

• Well Test Data: 7” Flow 1st DST 2nd DST

• Estimated bottom hole pressure 3,700 psi 3,700 psi 3,750 psi• Wellhead surface pressure 3,150 psi 3,150 psi 3,165 psi• Calculated AOF 150 MMcfd 150 MMcfd To be determined• Sample test – Flow 50MMcfd 7.1MMcfd 21.7MMcfd • Pipe size 7 inch 2 ½ inch ID 2 ½ inch ID• Pressure 2,000psi 500 psi 1,200 psi• Choke size 1 ¾ inch 48/64 inch 60/64 inch

Well cleaned up and flowing gas with some condensate

Gas and Condensate

Potential for Oil at Elk• Offset wells established an oil system in the Puri limestone

• Puri flowed oil at a peak rate of 1,610 bopd (10 miles west)• Moose #1 and #2 had live oil shows (5 miles north)

• Heavy condensate was recovered high in the potential 4,000 feet hydrocarbon column

• API Gravity of the condensate is at the lower range at 46 to 49 and below the condensate gravity of 51.7 at the Puri oil discovery

• Condensate from the Elk well was sent to the independent labs of CSIRO for detailed study. CSIRO has initially determined that liquids produced from the Elk reservoir originated in the peak to late oil generation window.

• The vast majority of the producing oil fields in PNG have a gas cap.

This information gives InterOil encouragement to pursue an oil leg in the Elk and Antelope structures

Condensate samples at the refinery labImproved quality as well cleans up

Elk - Forward Program• The well will be logged to confirm the following:

– Net reservoir column thickness– Dip of reservoir, image logs - fracture sizes – Conventional reservoir parameters (porosity, saturation, formation water resistivity)– Obtain down hole reservoir pressure and temperature for Calculated Absolute Open

Flow (CAOF)

• Production testing will be performed– Complete Elk #1 with 5 inch tubing– Establish higher gas flow rates– Evaluate condensate yield,GOR, for possible increases in liquids at higher flow rates– Hydrocarbon composition (condensate quality)– Additional pressure and reservoir studies

• InterOil’s appraisal plan will be initiated – Appraise Elk structure with additional wells to locate possible oil leg, increases in

condensate with depth, and determine the total thickness of the hydrocarbon column and resource size for LNG facility

– Drill Antelope structure to add gas volume, confirm condensate economics, potential oil, and scope for an increased LNG facility

Elk #1 Conclusions(Mid-October)

Milestone event for InterOil

“ A new gas and condensate discovery for InterOil and PNG”

• Shallow high pressure gas• High quality condensate • High permeability fractured reservoir • Demonstrated high flow rates• Potential 4,000 feet hydrocarbon column• Potential for oil

Elk #1 Test - October 2006

Detailed Test Data(Appendix)

Current and past test data:

• DST 2: The following are the results of DST #2 conducted to 16th October 2006

– Surface pressure 3,190 psi through a 3 1/2 inch drill pipe test string (2 1/2” ID), stable at 3,165 psi– Gas and gas liquids to surface with a stable flow rate of ~21.7 MMSCFGPD@ 1,200 psi with a 60/64th inch choke,

tested through 2 1/2 inch drill string, stabilized condensate gravity 46 API – Gas and gas liquids to surface with a stable flow rate of ~15 MMSCFGPD@ 2,440 psi with a 34/64th inch choke,

tested through 2 1/2 inch drill string, stabilized condensate gravity 47 API– Gas and gas liquids to surface with a stable flow rate of ~10 MMSCFGPD@ 2,830 psi with a 26/64th inch choke,

tested through a 2 1/2 inch drill string, stabilized condensate gravity 50 API– No pressure depletion was observed from surface pressures throughout the test and subsequent build up.– Stabilized condensate liquids of 49 to 46 API were recovered during the test and are undergoing further lab

evaluation.

• DST 1: The following are the results of DST #1 conducted between June 22 and 24, 2006– Surface pressure at 3,150 psi recorded on 7 inch casing– Estimated bottom hole pressure of 3,700 psi– Gas and gas liquids to surface with an estimated flow rate of ~ 7.1MMSCFGPD @ 500 psi, through a 48/64th inch

choke, through 2 1/2 inch ID drill pipe, with a further downhole restriction of a stuck tool to limit the flow rates.– Estimated Calculated Absolute Open Flow (CAOF) for gas was calculated at 150 MMSCFGPD– No pressure depletion was observed from surface pressures throughout the test and subsequent build up.– Hydrocarbon liquids were recovered during the test and confirmed origination from a source in the peak to late oil

generation window.

• JUNE 11th 2006 flow through 7” casing– Gas and gas liquids to surface with an estimated flow rate of ~ 50 MMSCFGPD @ 2,000 psi, through a 1 3/4 inch

choke.

• This press release contains forward-looking statements as defined in U.S. federal and Canadian securities laws. All statements, other than statements of historical facts, included in this release are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our drilling plans, plans for expanding our business segments, business strategy, plans and objectives for future operations, future capital and other expenditures, and those statements preceded by, followed by or that otherwise include the words “may,” “plans’” “believe,” “expects," “anticipates,”“intends,” “estimates” or similar expressions or variations on such expressions. Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors that could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties include, but are not limited to, the ability of our refinery to operate at full capacity and to operate profitability; uncertainty involving the geology of oil and gas deposits and reserve estimates; delays and changes in plans with respect to exploration or development projects or capital expenditures; political, legal and economic risks related to Papua New Guinea; the impact of competition; the volatility of prices for crude oil and the volatility of the difference between our purchase price of crude oil feedstocks and the sales price of our refined products; the uncertainty of our ability to attract capital; and the risks described under the heading “Risk Factors” in our 2005 Annual Information Form dated March 31, 2006 and our Management’s Discussion and Analysis for the Second Quarter of 2006.

• Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this MD&A will prove to be accurate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should notbe regarded as a representation by us or any other person that our objectives and plans will be achieved. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise. Our forward-looking statements are expressly qualified in their entirety 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. All information contained herein regarding resources are references to undiscovered resources under Canadian National Instrument 51-101, whether stated or not.

Cautionary &Forward Looking Statements