InterOil Corporation   Annual Information Form   For the Year Ended December 31, 2012 February 27, 2013  

TABLE OF CONTENTS

TABLE OF CONTENTS	1
PRELIMINARY NOTES	2
GENERAL	2
LEGAL NOTICE – FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	4
CONVERSION	4
GLOSSARY OF TERMS	5
CORPORATE STRUCTURE	9
GENERAL DEVELOPMENT OF THE BUSINESS	10
BUSINESS STRATEGY	17
DESCRIPTION OF OUR BUSINESS	18
UPSTREAM - EXPLORATION AND PRODUCTION	19
MIDSTREAM - REFINING	30
MIDSTREAM - LIQUEFACTION	32
DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION	33
THE ENVIRONMENT AND COMMUNITY RELATIONS	35
RISK FACTORS	36
DIVIDENDS	47
DESCRIPTION OF CAPITAL STRUCTURE	47
MARKET FOR OUR SECURITIES	49
DIRECTORS AND EXECUTIVE OFFICERS	50
AUDIT COMMITTEE	53
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	54
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	54
MATERIAL CONTRACTS	55
TRANSFER AGENT AND REGISTRAR	56
INTERESTS OF EXPERTS	57
ADDITIONAL INFORMATION	57
Schedule A – Report of Management and Directors on Oil and Gas Disclosure	58
Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator	59
Schedule C – Audit Committee Charter	61

Annual Information Form   INTEROIL CORPORATION   1

PRELIMINARY NOTES

GENERAL

This Annual Information Form (“AIF”) has been prepared by InterOil Corporation for the year ended December 31, 2012. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2012 and Management’s Discussion and Analysis for the year ended December 31, 2012 (“2012 MD&A”), copies of which may be obtained online from SEDAR at www.sedar.com.

In this AIF, references to “we”, “us”, “our”, “the Company”, “the Corporation” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires.

All dollar amounts are stated in United States dollars unless otherwise specified.

Information presented in this AIF is as of December 31, 2012 unless otherwise specified.

Certain information, not being within our knowledge, has been furnished by our directors and executive officers. Such information includes information as to common shares in the Company beneficially owned, controlled or directed, directly or indirectly by them, their places of residence and principal occupations, both present and historical, interests in material transactions and potential conflicts of interest.

LEGAL NOTICE – FORWARD-LOOKING STATEMENTS

This AIF contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements are generally identifiable by the terminology used such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “forecasts,” “budgets,” “targets” or other similar wording suggesting future outcomes or statements regarding an outlook. We have based these forward-looking statements on our current expectations and projections about future events. All statements, other than statements of historical fact, included in or incorporated by reference in this AIF are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our business strategies and plans; plans for our exploration (including drilling plans) and other business activities and results therefrom; characteristics of our properties; entering into definitive agreements with our joint venture partners entering into an agreement with a strategic partner in respect of the LNG Project and the Elk and Antelope fields (and the timing of any such agreement); the construction of the LNG Project and the Condensate Stripping Project in Papua New Guinea; the development of the LNG Project and the Condensate Stripping Project; the timing and cost of such development; the commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; re-commissioning of our CRU; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; the timing, maturity and amount of future capital and other expenditures.

Many risks and uncertainties may affect the matters addressed in these forward-looking statements, including but not limited to:

· our ability to finance the construction and development of the LNG Project and the Condensate Stripping Project; 

· our ability to negotiate definitive agreements following conditional agreements or heads of agreement relating to the development of the LNG Project and the Condensate Stripping Project, or to otherwise negotiate and secure arrangements with other entities for such development and the associated financing thereof;

· the uncertainty associated with the availability, terms and deployment of capital; 

· our ability to construct and commission the LNG Project and the Condensate Stripping Project together with the construction of the common facilities and pipelines, on time and within budget;

· our ability to obtain and maintain necessary permits, concessions, licenses and approvals from relevant State authorities to develop our gas and condensate resources and to develop the LNG Project and the Condensate Stripping Project within reasonable time periods and upon reasonable terms;

Annual Information Form   INTEROIL CORPORATION   2

· the inherent uncertainty of oil and gas exploration activities;

· the availability of crude feedstock at economic rates;

· the uncertainty associated with the regulated prices at which our products may be sold;  

· difficulties with the recruitment and retention of qualified personnel; 

· losses from our hedging activities;

· fluctuations in currency exchange rates;

· political, legal and economic risks in Papua New Guinea; 

· landowner claims and disruption; 

· compliance with and changes in Papua New Guinean laws and regulations, including environmental laws;

· the inability of our refinery to operate at full capacity;

· the impact of competition;

· the adverse effects from importation of competing products contrary to our legal rights;

· the margins for our products and adverse effects on the value of our refinery;

· inherent limitations in all control systems, and misstatements due to errors that may occur and not be detected;

· exposure to certain uninsured risks stemming from our operations;

· contractual defaults;

· interest rate risk;

· weather conditions and unforeseen operating hazards;

· general economic conditions, including any further economic downturn, the availability of credit the European sovereign debt credit crisis and the downgrading of United States government debt;

· the impact of our current debt on our ability to obtain further financing;

· risk of legal action against us; and

· law enforcement difficulties.

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial conditions and performance, business prospects, strategies, regulatory developments, the ability to attract joint venture partners, future hydrocarbon commodity prices, the ability to secure adequate capital funding, the ability to obtain equipment in a timely manner to carry out development activities, the ability to market products successfully to current and new customers, the effects from increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop reserves and production through development and exploration activities. Although we consider these assumptions to be reasonable based on information currently available to us, they may prove to be incorrect.

Annual Information Form   INTEROIL CORPORATION   3

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 will eventuate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in this AIF.

Furthermore, the forward-looking information contained in this AIF is made as of the date hereof and, except as required by applicable law, we will not update publicly or revise any of this forward-looking information. The forward-looking information contained in this AIF is expressly qualified by this cautionary statement.

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

Crude Oil and Natural Gas Liquids		Natural Gas
bbl	one barrel equalling 34.972 Imperial gallons or 42 U.S. gallons	btu	British Thermal Units
bblspd	barrels per day	mcf	thousand standard cubic feet
boe(1)	barrels of oil equivalent	mcfpd	thousand standard cubic feet per day
boepd	barrels of oil equivalent per day	mmbtu	million British Thermal Units
bpsd	barrels per stream day	mmbtupd	million British Thermal Units per day
mboe	thousand barrels of oil equivalent	mm	million standard cubic feet
mbbl	thousand barrels	mmcfpd	million standard cubic feet per day
MMbbls	million barrels	mtpa	million tonnes per annum
MMboe	million barrels of oil equivalent	scfpd	standard cubic feet per day
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma	Tcf	trillion standard cubic feet
bscf	billion standard cubic feet	psi	pounds per square inch

Note:

(1) All calculations converting natural gas to crude oil equivalent have been made using a ratio of six mcf of natural gas to one barrel of crude equivalent. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CONVERSION

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (metric units).

To Convert From	To	Multiply By
mcf	cubic meters	28.317
cubic meters	cubic feet	35.315
bbls	cubic meters	0.159
cubic meters	bbls	6.289
feet	meters	0.305
meters	feet	3.281
miles	kilometers	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

Annual Information Form   INTEROIL CORPORATION   4

GLOSSARY OF TERMS

“2012 MD&A” means the Management’s Discussion and Analysis for the year ended December 31, 2012.

“AIF” means this Annual Information Form for the year ended December 31, 2012.

“API” means the American Petroleum Institute.

“Barrel, Bbl” (petroleum) is a unit volume measurement used for petroleum and its products.

“BNP Paribas” means BNP Paribas Capital (Singapore) Limited.

“Board” means the board of directors of InterOil.

“BP” means BP (formerly known as British Petroleum) or a subsidiary or affiliate of that company.

“BSP” means Bank of South Pacific Limited.

“CDU” means crude distillation unit.

“CGR” means condensate to gas ratio.

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook.

“Condensate” is a component of natural gas which is a liquid at surface conditions.

"Contingent resources" are those quantities of natural gas and condensate estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.  The economic status of the resources is undetermined and there is no certainty that it will be commercially viable to produce any portion of the resources. 

“Convertible notes” means the 2.75% convertible senior notes of InterOil due November 15, 2015.

“Crack spread” means the simultaneous purchase or sale of crude against the sale or purchase of refined petroleum products. These spread differentials which represent refining margins are normally quoted in dollars per barrel by converting the product prices into dollars per barrel and subtracting the crude price.

“CRU” means catalytic reformer unit.

"Crude oil" is a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

“CSP Joint Venture” or “CSP JV” means the JVOA entered into for the proposed condensate stripping facilities with Mitsui or the joint venture formed to develop and operate the proposed condensate stripping facilities as the context requires.

“Condensate Stripping Project” means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and associated facilities being progressed in joint venture with Mitsui.

“DST” means a Drill Stem Test and is a procedure for isolating and testing the surrounding geological formation through the drill pipe.

"DPE" means the Department of Petroleum and Energy, a PNG Government department responsible for regulating oil and gas activities in Papua New Guinea.

“EPC Contractor” means an engineering, procurement and construction contractor.

“EWC” means Energy World Corporation Limited, a company organized under the laws of Australia.

Annual Information Form   INTEROIL CORPORATION   5

“Farm out” is a contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for the other party’s fulfillment of contractually specified conditions. Farm out agreements often stipulate that a party must drill a well to a certain depth, at a specified location, within a certain time frame; furthermore, typically, the well must be completed as a commercial producer to earn an assignment of the working interest. The assignor of the interest usually reserves a specified overriding royalty interest, with the option to convert the overriding royalty interest to a specified working interest upon payout of drilling and production expenses.

“FEED” means front end engineering and design.

“Feedstock” means raw material used in a refinery or other processing plant.

“FID” means final investment decision. Such a decision is ordinarily the point at which a decision is made to proceed with a project and it becomes unconditional. However, in some instances the decision may be qualified by certain conditions, including being subject to necessary approvals by the State.

“FLEX LNG” means FLEX LNG Limited, a British Virgin Islands company listed on the Oslo Stock Exchange.

“Gas” means a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulfur or other non-hydrocarbon compounds.

“GLJ” means GLJ Petroleum Consultants Limited, an independent qualified reserves evaluator.

"GLJ 2012 Report" means the report dated February 27, 2013 with an effective date of December 31, 2012 setting forth certain information regarding contingent resources of our interests in the Elk and Antelope fields in PNG.

“Gross wells” means the total number of wells in which we have an interest.

“HOA” means Heads of Agreement.

“ICCC” means Papua New Guinea’s competition authority, the Independent Consumer and Competition Commission.

“IFRS” means International Financial Reporting Standards as issued by the International Accounting Standards Board.

“IPI Agreement” means any of (a) the Indirect Participation Interest Agreement between us and PNGEI originally executed April 3, 2003 and amended April 12, 2003 and further amended (and restated) May 12, 2004; (b) the Indirect Participation Interest Agreement between us and PNGDV, dated July 21, 2003 and amended (and restated) May 1, 2006; and (b) Indirect Participation Agreement, dated February 25, 2005 between us and the Investors.

“IPI holders” means investors holding IPWIs in certain exploration wells required to be drilled pursuant to the IPI Agreement.

“IPF” means InterOil power fuel, our marketing name for LSWR.

“IPP” means import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated under agreement with the State by adding the costs that would typically be incurred to import such product to an average posted price for such product in Singapore as reported by Platts. The costs added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.

“IPWI” means indirect participation working interest.

“JVOA” means joint venture operating agreement.

“LNG” means liquefied natural gas. Natural gas may be converted to a liquid state by pressure and severe cooling for transportation purposes, and then returned to a gaseous state to be used as fuel. LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas liquids, which are heavier fractions that occur naturally as liquids.

Annual Information Form   INTEROIL CORPORATION   6

“LNGL” means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG formed in Papua New Guinea to contract with the State and pursue the LNG Project, including construction of the LNG Project.

“LNG Project” means the proposed development by us of liquefaction facilities in the Gulf Province of Papua New Guinea described as our Midstream Liquefaction business segment and being undertaken as a joint venture with Pac LNG and with other potential partners, including the State.

“LNG Project Agreement” means the LNG Project Agreement between the State and LNGL dated December 23, 2009.

“LPG” means liquefied petroleum gas, typically ethane, propane, butane and isobutane. Usually produced at refineries or natural gas processing plants, including plants that fractionate raw natural gas plant liquids. LPG can also occur naturally as a condensate.

“LSWR” means low sulfur waxy residue.

“Mark-to-market” means the accounting standards of assigning a value to a position held in a financial instrument based on the current fair market price for the instrument or similar instruments.

“Mitsui” means Mitsui & Co., Ltd., a company organized under the laws of Japan and/or certain of its wholly-owned subsidiaries (as the context requires).

“MOPS” means Mean of Platts Singapore.

“Naphtha” is that portion of the distillate obtained from the refinement of petroleum which is an intermediate between the lighter gasoline and the heavier benzene. It is a feedstock destined either for the petrochemical industry or for gasoline production by reforming or isomerisation within a refinery.

"Natural gas" is a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

“NGL” means natural gas liquids, consisting of any one or more of propane, butane and condensate.

"Net wells" is the number of wells obtained by aggregating our working interest in each of our gross wells.

“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities adopted by the Canadian Securities Administrators.

“NI 52-110” means National Instrument 52-110 - Audit Committees adopted by the Canadian Securities Administrators.

“OPIC” means Overseas Private Investment Corporation, an agency of the United States Government.

“Pac LNG” means Pacific LNG Operations Ltd., a company incorporated in the Bahamas and affiliated with Clarion Finanz A.G. This company is our joint venture partner in the LNG Project (holding equal voting shares in PNG LNG), holds a 2.5% direct interest in the Elk and Antelope fields, is an IPI holder and a shareholder in PNGDV.

“PDL” means Petroleum Development License. The right granted by the State to develop a field for commercial production.

“Petromin” means Petromin PNG Holdings Limited, a company incorporated in Papua New Guinea by the State.

“PGK” means the Kina, currency of Papua New Guinea.

“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered into an IPI Agreement. (See “Description of our Business – Upstream - Exploration and Production – Participation Agreements”, “Material Contracts – Drilling Participation Agreement dated July 21, 2003”).

“PNGEI” means PNG Energy Investors LLC, an entity with which we entered into an IPI Agreement on May 12, 2004.

Annual Information Form   INTEROIL CORPORATION   7

"PNG LNG" means PNG LNG, Inc., a joint venture company established in 2007 to hold the interests of certain joint venturers in the venture to construct the proposed liquefaction facilities. Shareholders are InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and Pac LNG. (See “Material Contracts – LNG Project Shareholders Agreement dated July 30, 2007)

“PPL” means Petroleum Prospecting License. The tenement given by the State to explore for oil and gas.

"PRE" means Pacific Rubiales Energy Corp., a company incorporated in British Columbia, Canada.

“PRL” means Petroleum Retention License. The tenement given by the State to allow the license holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.

“Prospective Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub classified based on project maturity. 

“Shell” means Royal Dutch Shell plc, or a subsidiary or affiliate of that company.

“Shut-in” means wells that are capable of producing oil or natural gas which are not producing due to lack of available transportation facilities, available markets or other reasons.

“State” or “PNG” means the Independent State of Papua New Guinea.

“Sweet/sour crude” describes the degree of a given crude's sulfur content. Sour crudes are high in sulfur, sweet crudes are low.

“Working interest” means the percentage of undivided interest held by us in an oil and natural gas property, well or resources, as applicable.

“YBCA” means the Business Corporations Act (Yukon Territory).

Annual Information Form   INTEROIL CORPORATION   8

CORPORATE STRUCTURE

Name, Address and Incorporation

InterOil Corporation is a Yukon Territory corporation, continued under the YBCA on August 24, 2007.

Our registered office	Our corporate office	Our corporate office
in Canada is located at:	in Australia is located at:	in Papua New Guinea is
		located at:
Suite 300,204 Black Street	Level 3, Cairns Square,	Level 2, Ravalien Haus,
Whitehorse, Yukon	42 – 52 Abbott Street, Cairns,	Harbour City Port Moresby
Y1A 2M9	Queensland 4870	NCD,
Our corporate office in Singapore is	Our corporate office in the United
located at:	States is located at:
Triple One Somerset 111	25025 I-45 North
Somerset Road #06-05	Suite 420,
Singapore 238164	The Woodlands, Texas 77380

Copies of the Company’s articles and by-laws are available on SEDAR at www.sedar.com.

Inter-corporate Relationships

Inter-corporate relationships with and among all of our subsidiaries as at the date of this AIF are set out in the diagram below.

Annual Information Form   INTEROIL CORPORATION   9

GENERAL DEVELOPMENT OF THE BUSINESS

Three-Year History

We are developing a vertically integrated energy company operating in Papua New Guinea and the surrounding Southwest Pacific region. The following is a summary of significant events in the development of our businesses and corporate activities over the past three years.

Upstream – Exploration and Production

Our upstream business segment has focused on the drilling program in the Elk, Antelope and Triceratops fields. This has led to natural gas and natural gas liquids discoveries in those fields beginning in 2006. We continue to evaluate the size and structure of the Elk, Antelope and Triceratops fields by drilling additional appraisal wells. Our ability to commercialize these discoveries will depend, in part, on the results of these appraisals. In addition, as there is no market for natural gas within Papua New Guinea, our ability to sell natural gas production from our discoveries will depend upon the development of the LNG Project. This project will require substantial amounts of capital and will take a number of years to complete. As discussed below, we are evaluating the construction of the LNG Project on the coast of the Gulf Province and the Condensate Stripping Project within the boundaries of PRL 15. We are also exploring the sale of a portion of the ownership in the LNG Project and the Elk and Antelope fields to industry investors in order to finance and develop the LNG Project.

Set forth below is the history of the upstream activities we have conducted over the past few years:

Elk Field

The Elk-1 well in the Eastern Papua Basin, on PPL 238, was an exploration well that spudded on February 19, 2006 to test a fractured limestone target on the Elk structure. It encountered highly pressured gas from a fracture system around 1,694 meters and was completed as a potential producer on November 23, 2006 at a total depth of 1,983 meters.

We spudded the Elk-2 well on February 9, 2007. The Elk-2 well is located approximately 4.7 kilometers north of the Elk-1 location. The Elk-2 well was the first appraisal well we drilled to help us delineate the extent of the Elk structure. Elk-2 was drilled to a depth of 3,329 meters. Eight drill stem tests were performed, but none resulted in commercial flows of oil or gas.

We spudded the Elk-4 well on November 15, 2007. This well tested the Elk and Antelope structures and is located 0.9 miles (1.5 kilometers) south of Elk-1. Although this was our third Elk well, it was named Elk-4, as the Elk-3 designation had been reserved for the planned side track of Elk-2, which had been deferred. The Elk-4/4A well was spudded in November 2007. On May 1, 2008, while drilling at 7,402 feet (2,256 meters) the well experienced a gas kick, which resulted in a flow of natural gas and natural gas liquids to the surface and a discovery in the Antelope structure. The well was completed with 4 1/2 inch tubing as a potential producer and completion work ended on August 31, 2008. On September 4, 2008, the well recorded a short-term gas flow rate of 105 mmcfpd.

In August 2012, Rig 3 was mobilized to the Elk-3 drilling location. With access roads from both the north and the south and a central upstream development camp in place, we are set to begin drilling the second of two obligation wells in PRL 15. The objective of the Elk-3 delineation well is to test the Early Miocene to Late Oligocene limestone section above the gas water contact in the Elk fault block.

Antelope Field

The Antelope-1 well was spudded on October 15, 2008. On December 31, 2008 gas was encountered at 1,748 meters in a limestone/dolomite reservoir which was flowed to surface. The well was drilled to 2,710 meters, was logged and subsequent drill stem tests were performed. The well was then completed as a potential producer with 7- inch tubing and flow tested at 382 mmcfpd.

Annual Information Form   INTEROIL CORPORATION   10

In October 2008, Petromin, a government entity mandated to invest in resource projects on behalf of the State, entered into an agreement with us to take a direct interest in the Elk and Antelope fields and fund 20.5% of the costs of its development, subject to a PDL being granted within a certain timeframe. At the end of 2011, we agreed with Petromin that the agreement we entered into in 2008 was no longer valid or intended to operate and should terminate. Petromin remains the State’s nominee to acquire this interest under relevant Papua New Guinean’s legislation, once a PDL is granted. We have proposed to Petromin that cash contributions made by Petromin under the agreement to fund development, amounting to approximately $15.4 million, be held and credited against the State’s obligation to refund its portion of such costs upon grant of the PDL. We have not yet finalized an agreement with Petromin on these points.

On July 27, 2009 the Antelope-2 well, located approximately 4 kilometers south of the Antelope-1 well and within the boundaries of PPL 237, was spudded. After drilling to 1,832 meters, a 9 5/8-inch liner was set at the top of the limestone section. The well was drilled to 2,260 meters, temporarily completed with 7-inch tubing and a high-rate flow test to confirm deliverability was performed in early December 2009. This flow test recorded a maximum flow rate of 705 mmcfpd, including 11,200 bbls of condensate per day. Subsequent to this flow test, the 7-inch tubing was removed and a 7-inch liner was run. A 6 ¼-inch hole was then drilled to 2,325 meters and DST #2 was performed. This DST confirmed gas and condensate with a stabilized GCR of over 20 bbl/mmcf. The well was then drilled to 2,365 meters and DST #3 was carried out over the interval 2,320 meters to 2,365 meters. The result of DST #3, along with the data acquired during the logging operations, helped us to establish the hydrocarbon water contact in the reservoir at approximately 2,224 meters.

In September 2009, a 100 kilometer 2-D seismic program to appraise the Antelope field was commenced and recording of seismic data was completed. This data has been processed and interpreted.

During the third quarter of 2009, Pac LNG acquired a 2.5% direct working interest in gas and condensate in the Elk and Antelope fields for $25.0 million, pursuant to an option granted to it in 2007. As part of the transaction, Pac LNG was required to pay us its 2.5% share of certain historical exploration costs and transfer to us 2.5% of its ultimate economic interest in PNG LNG, the joint venture company with which we are pursuing the LNG Project with Pac LNG. Subsequent to the grant of PRL 15 over the Elk and Antelope fields, an application for the transfer of a 2.5% interest in that license to Pac LNG was submitted to the DPE, and was approved in December 2011.

To further enhance our ability to explore on our licenses a second drilling rig was acquired on February 9, 2010, for approximately $4.5 million, with additional costs incurred for the inspection, packaging and transport of the rig to Papua New Guinea.

During 2010, we completed drilling and logging activities on the Antelope-2 well, having drilled a further horizontal section in order to test the CGR in the deeper section of the reservoir. Various DSTs were performed DST #7 producing a stabilized CGR of 24.0 to 27.7 barrels of condensate per million cubic feet of natural gas. A total of 1,596 meters of horizontal drilling was performed from the original vertical well and these two sections improved our knowledge of the deeper portion of the Antelope reservoir. Subsequently, this well was completed as a potential producer.

On November 30, 2010, we were granted PRL 15, covering blocks within and surrounding the Elk and Antelope fields, unifying these fields into a single license separate from our exploration acreage and specifying minimum work commitment activities over the next five years.

Rig release from the Triceratops-2 well was received from the State on August 13, 2012. Demobilization of Rig 2 began immediately for its relocation to the Antelope-3 well location. The Antelope-3 well was spudded on September 30, 2012. In November 2011, the Antelope-3 appraisal well in PRL 15 penetrated the top of the reservoir. DST #1 in the Antelope-3 well evidenced natural gas and condensate with a maximum gas flow rate of 44.8 million cubic feet of natural gas per day, 10.4 to 14.9 barrels of condensate per million cubic feet, and a flowing tubing pressure of 2,331 psi. The Antelope-3 well was drilled to 5,905.8 feet (1,800 meters). The analyzed gas composition was similar to the Antleope-1 and Antelope-2 wells. We believe that the Antelope-3 well drilling analysis confirms the continuity of a highly productive reservoir into which the Antelope-1 and Antelope-2 wells had already been drilled.

Triceratops Field

After the interpretation of the Triceratops field seismic data, a review of the field was completed. Following that, the conclusion was reached that the Triceratops-1 well lies in the same zone, the same pool and the same field as the Bwata -1 well, which was drilled by another company over 40 years ago. To commemorate these three aspects, the field was named the Triceratops field.

Annual Information Form   INTEROIL CORPORATION   11

The Triceratops-2 appraisal well was spudded on January 15, 2012. Following successful flow from a DST of 27 mmcfd on June 6, 2012, the Triceratops-2 well was declared a discovery by the State. Between June 14, 2012 and August 13, 2012, the well was cased, and cased-hole logging and testing was completed. A number of rotary side wall cores were also taken, which were still undergoing petrophysical analysis, routine core analysis and special core analysis subsequent to year end to help determine the hydrocarbon saturation in the reservoir, which is an important input into resource estimates. In August 2012, we suspended the Triceratops-2 well as a discovery, for recompletion at a later date as a future production well, and began the process of moving the drilling rig to the Antelope-3 well location.

Completion of vertical seismic profile processing of the Triceratops field provided a confident well to-seismic tie, and remapping of this seismic data has commenced. Triceratops seismic data indicates that there is a large “attic” in terms of height and areal extent to the south, west and northwest of the Triceratops-2 well, which will be our focus during forward seismic acquisition and well programs on this field. Planning of new seismic studies and drilling locations are in progress, and will be finalized once the remapping is complete.

On April 18, 2012, we signed a binding HOA with PRE which allows PRE to earn a 10.0% net (12.9% gross) participating interest in PPL 237, including the Triceratops field located within that license. On July 27, 2012, we executed a farm-in agreement with PRE relating to the Triceratops field and the participating interest in the PPL 237 license, which was materially in line with the HOA. Pac LNG is also participating on a 25% beneficial equity basis in the portion of the farm-in transaction relating to the Triceratops field (2.5% net and 3.2% gross participating interest).

Other Fields and Facilities, Exploration Activities

The divestment of a 15% non-operated interest in PPL 244 to Oil Search (PNG) Ltd was approved by the State and finalized in October 2010.

The PPL 236 phase 1 exploratory seismic data acquisition program, which included 70 kilometers with six dip lines transecting the Whale, Tuna, Barracuda, Wahoo, Mako and Shark prospects, was completed during the first quarter of 2011. Based upon our processing and interpretation of seismic data, the Wahoo/Mako leads (PPL 236) and the Tuna lead (PPLs 236 and 238) have been selected as prospects for future exploratory drilling.

Wells in both PPL 236 and PPL 238 are required to be drilled by March 2013 in order to meet our license commitments. During November 2012, we lodged an application for variation to extend the term of our Licenses and to defer our drilling commitments with the DPE. As at February 27, 2013 no decision had been advised with respect to our applications for variation.

Seismic data acquisition and interpretation programs have been designed with a view to determining, amongst other things, the proposed location of these wells. Our Tuna and Wahoo/Mako prospects, targeting seismically defined reefal indications in PPLs 236 and 238, have matured to the drill-ready stage, and preparations to access to the proposed drilling locations are underway.

Our Hou Creek northern wharf and field access roadway are progressing to completion, and a permanent camp location is under construction. The Hou Creek wharf and crane are functioning and ready to accept materials and equipment. We have also completed the upstream field development camp near the Antelope-3 well site and drilling crews are utilizing those accommodations.

PPL236 seismic comprised an initial regional survey over a number of potential leads including Whale, Shark, Mako, Wahoo, Tuna and Barracuda. The following two phases of seismic, the Kwalaha program, focused on the high graded Wahoo/Mako and Tuna Prospects selected due to the recognition of potential reefal facies on the seismic.

Survey Name	Start	Total (km)	No. of lines	Primary License
Wolverine Seismic Survey Phase 1	18-Feb-10	20.0	2	PPL238
Poroman Seismic Survey	23-Mar-10	27.0	1
Wolverine Seismic Survey Phase 2	27-Sep-10	45.4	4	PPL238
Whale Seismic Survey (Phase 1)	07-Dec-10	70.0	6	PPL236
Kwalaha Seismic Survey (Phase 2)	14-Aug-11	56.0	7	PPL236
Tuna Seismic Survey (Phase 3)	01-Dec-11	21.1	2	PPL236
TU & KW Strike Lines (Phase 4)	08-Mar-12	36.1	2	PPL236
TOTAL		275.5	24

Annual Information Form   INTEROIL CORPORATION   12

In 2011, we acquired an airborne magnetic, gravity and gamma ray survey over PPL 236, PPL 237 and PPL 238. A total of five acquisition blocks were acquired with a combined a total of 1,428,876 line kilometers of airborne data. Data processing of this airborne data was completed and the data received in early 2012.

Condensate Stripping Project

In the first quarter of 2010, the pre-FEED phase for the development of Condensate Stripping Project was completed, and on April 15, 2010 we entered into a preliminary works joint venture and a preliminary works financing agreement with Mitsui to commence FEED work.

On August 4, 2010, we entered into a definitive CSP JV (see “Material Contracts”) for the Condensate Stripping Project with Mitsui. Under the CSP JV, Mitsui is responsible for arranging or providing financing for the capital costs of the Condensate Stripping Project in the event that a positive FID is made in respect of the Condensate Stripping Project. An option deed was also executed with Mitsui, under which Mitsui was granted an option to acquire up to 5% of the Elk and Antelope fields, and in the LNG Project. Mitsui paid $6.3 million in exchange for this option, with such amount to be refunded in the event that positive FID is not reached by the agreed upon date and the option is not exercised. An adjustment is to be made against the final acquisition price in the event the option is exercised.

During 2011, the FEED work was carried out. The FEED phase generated deliverables to technically and commercially define the project and prepare it for execution (detailed engineering, procurement, construction, fabrication, commissioning, and hand-over to operations) and proposals were solicited from potential EPC contractors. We are continuing the planning and preparation efforts for execution of the Condensate Stripping Project, which efforts include detailed project execution plan, execution schedule and risk assessment work.

At the end of 2012, we reached an agreement with Mitsui to provide for flexibility in nominating a date for FID. We can provide no assurance that we will reach FID or at all, that there will be further extensions or that we will enter into unconditional or definitive agreements with Mitsui.

Midstream – Refining segment

Over the three year period ended December 2012, our refining business unit has continued to process low sulphur crudes through the CDU at a rate sufficient to meet domestic PNG demand for middle distillate products (diesel & jet fuel) supplied from the refinery, with occasional exports of ships bunkers. The Naphtha and LSWR that is consequentially produced has been exported into the regional market via spot and term contracts, although small amounts of LSWR are sold domestically in PNG.

For operational reasons, the CRU was only in service for a four-month period of April through July of 2012. Prior to this, it had operated generally on a batch processing basis to meet domestic PNG demand for gasoline. It is anticipated that the CRU will be re-commissioned returned to service during the second quarter of 2013, following the successful installation of the new catalyst.

If, for operational reasons, we are unable to satisfy demand from refinery production we import finished products. Due to the continued shutdown of the CRU during most of 2012, the majority of gasoline we have sold during the period has been imported. Other than imports resulting from these scheduled events, our imports of middle distillates have been minimal and have not significantly affected our crude throughput.

We continue to source our crude through a supply agreement with BP. Under this agreement, we negotiate directly with crude producers and sellers for the purchase of crude. However, the purchases are completed under our arrangements with BP and the subsequent shipments employ BP’s shipping infrastructure. There has been a natural decline in production of some of our preferred crude feedstock over the past three years and diversification of our crude feedstock has been an important part of our crude acquisition strategy. We have introduced several new feedstocks to the refinery over the past three years, including our first West African crude and other Malaysian crudes. During 2011, we also concluded certain term purchase agreements for some of our preferred crudes for the 2012 year. In 2013, we will retain only one term agreement for crude. All other crudes will be purchased on a spot basis for the year.

Annual Information Form   INTEROIL CORPORATION   13

While regional hydro skimming margins have suffered, particularly in 2011, our IPP for products sold domestically affords us some protection from the low industry margins. Conversely, the IPP serves to restrict increases to our margin when margins are otherwise subject to upwards pressure. The IPP price formula has remained unchanged throughout the three year period, however, the changes agreed in late 2007 and early 2008 still remain to be formalized in our Refinery Project Agreement. (See “Material Contracts – Refinery Project Agreement”, and see “Risk Factors – There is uncertainty associated with the regulated prices of which our products are sold by our refinery”).

In 2010, our sales of middle distillates increased by 7% over 2009, then again in 2011 by a further 8% over 2010 volumes. In 2012, the trend has continued with an increase in sales of middle distillates of 12%. These increases are primarily due to increased demand driven by resources projects in PNG. These increases have occurred in an environment where there has been continued importation of refined products by certain industry participants which we believe is contrary to our agreement with the State (see “Material Contracts – Refinery Project Agreement”, and see “Risk factors – Our downstream competitors have progressively increased their direct importation of refined petroleum products rather than sourcing from the refinery”).

During 2012, we exported nine cargoes of Naphtha averaging approximately 29,806 metric tons each for a total of approximately 268,000 tonnes or 2.4 million bbls. The production of Naphtha at the refinery is variable and depends on the composition of the crude feedstock used, the relative economics for gasoline and Naphtha, and our ability (hampered during 2011 and 2012 by our inability to operate the CRU for extended periods) to utilise Naphtha in the production of gasoline. Also during 2012, we exported five cargoes of LSWR totaling approximately 810,142 bbls under a combination of both spot and term arrangements that will continue into 2013. We made three export sales of diesel and gasoline to Nauru in 2010 and no export sales of diesel or gasoline in 2011 or 2012 except for small bunker sales.

During 2012, our total throughput per day (excluding shut down days) was 24,483 bblspd versus 24,856 bblspd in 2011 and 24,682 bblspd in 2010. The total number of barrels processed into product at our refinery for 2012 was 7.426 million compared with 6.73 million for 2011, and 6.71 million in 2010. During 2012, our refinery was shut down for a total of 51 days, versus 82 days in 2011 and 81 days in 2010.

During 2011, management received results of an independent assessment of the potential asset retirement obligations of the refinery at the time of decommissioning and a provision for $4,100,735 was initially recognized for this. The provision as at December 31, 2012 was $4,978,334. This decommissioning provision represents the net present value of the estimated costs of future dismantlement, site restoration and abandonment of properties based upon current regulations and economic circumstances as at December 31, 2012.

Midstream – Liquefaction segment

On September 28, 2010, we, together with LNGL, signed a heads of agreement with EWC in relation to a proposal to construct a modular land-based LNG plant in the Gulf Province of Papua New Guinea. On February 2, 2011, the parties signed certain initial and conditional agreements (a project funding and construction agreement and a shareholders agreement) governing the parameters in respect of the aforementioned proposed development. The agreements with EWC contemplate the negotiation of further definitive agreements and are conditional on, amongst other things, reaching FID to proceed with the LNG Project by March 31, 2012, which date was subsequently revised to June 30, 2013. We can provide no assurances that we will reach FID by this date or at all, that this date will not be further extended or that we will enter into unconditional or other definitive agreements with EWC.

On April 11, 2011, we and Pac LNG entered into certain conditional framework agreements with FLEX LNG and Samsung Heavy Industries for the proposed construction of a 1.8 mtpa or 2 mtpa fixed-floating liquefied natural gas vessel. Such a vessel was expected to integrate with and augment the land-based modules to be developed with EWC. The framework agreements provided that the parties were to undertake project specific FEED work and negotiate final binding agreements in time for a FID decision in mid-December 2011. Project specific FEED work was carried out. However, as FID was not reached by mid-December 2011, these framework agreements with FLEX LNG and Samsung lapsed and were not extended.

Additionally, under the framework agreement we entered into with FLEX LNG, an equity purchase option was granted to us to acquire common shares in FLEX LNG at an average strike price of 4.5909 Norwegian Kroner. On May 16, 2011, this option was exercised, and we acquired 8,938,913 common shares of FLEX LNG at a cost of $7.5 million.

Annual Information Form   INTEROIL CORPORATION   14

During 2011, site-specific engineering for the proposed land based modular LNG plant and the fixed-floating LNG facility were undertaken along with other pre-investment in the LNG Project with the goal of lowering bidder risks and securing our LNG Project timeline and costs.

In September 2011, we retained Morgan Stanley & Co.LLC, Macquarie Capital (USA) Inc. and UBS AG as joint financial advisors to assist us with soliciting and evaluating proposals from potential strategic partners. Proposals are being solicited to obtain an internationally recognized LNG operating and equity partner for development of the LNG Project’s gas liquefaction and associated facilities in the Gulf Province of Papua New Guinea, which may include a sale of an interest in the Elk and Antelope fields, and in our other exploration tenements in Papua New Guinea. We have made significant progress with pre-FEED and FEED engineering studies, construction of roads and camps, social mapping and genealogical studies, which will assist in the final partnering and project execution.

Subsequent to year end, on January 24, 2013, we announced that we have advised bidders with whom we have been in discussions that the final binding bid solicitation period for the partnering process currently being undertaken will close on February 28, 2013. Our Board of Directors intends to meet our advisors during March 2013 for the purpose of evaluating bids received and selecting our partner(s) for the development of the LNG Project utilizing gas from the Elk and Antelope fields. We can provide no assurance that we will enter into an agreement with a strategic partner or the timing of any such agreement.

On August 3, 2011, we signed a HOA with Noble Clean Fuels Limited, a wholly owned subsidiary of Noble Group Limited, for the supply of one mtpa of LNG per annum from the LNG Project for a ten year period beginning in 2014. Definitive, binding agreements are currently being negotiated. We can provide no assurances that we will finalize and enter into such agreements.

In addition, on November 25, 2011, a HOA was signed with Gunvor Singapore Pte. Ltd for the sale of an additional one mtpa of LNG from the LNG Project. On December 2, 2011, a further HOA was signed with ENN Energy Trading Company Ltd of China, for the sale of one to one and one half mtpa of LNG from the LNG Project. The HOA, while not binding, provides exclusivity on the LNG volumes, during negotiation of the definitive agreement, and sets out the basis upon which the parties intend to negotiate and document terms for the purchase and sale of LNG, for a period of 15 years, commencing in 2015. We can provide no assurances that we will finalize and enter into such agreements.

During 2012, we continued to progress the development of our LNG Project by completing FEED for our proposed field gathering system, CSP and pipeline to the LNG Project site on the coast.

On November 16, 2012, we were notified by the Prime Minister of Papua New Guinea Hon. Peter O’Neill that the NEC had conditionally approved our LNG development project in the Gulf Province. This decision clears the way to proceed with our plans for the development of an LNG plant in the Gulf Province with initial planned output of a minimum of 3.8 million tonnes per annum. The decision also approves an option for the State to acquire an additional 27.5% interest in the Elk and Antelope gas fields, over and above the 22.5% interest to which it is entitled under the Oil & Gas Act, on terms to be negotiated with us. The NEC further approved the establishment of a State negotiating team to discuss and agree to the necessary amendments to the 2009 LNG Project Agreement between the State and Liquid Niugini Gas Limited, to give effect to the NEC decision, and to agree on the terms on which the State could acquire the additional interest. The NEC decision confirms that the basis of the acquisition will be on commercial market terms. The NEC decision also includes as a condition of its approval that the LNG plant operator must be an internationally recognized operator of the planned LNG facilities.

Downstream – Wholesale and Retail Distribution

As of December 31, 2012, we provided petroleum products to 53 retail service stations with 43 operating under the InterOil brand name and the remaining 10 operating under their own independent brand. Of the 53 service stations that we supply, 16 are either owned by or head leased to us, which we then sublease to company-approved operators. The remaining 37 service stations are independently owned and operated. In the last quarter of 2012, we took over a company owned site and commenced operating this service station. Three new retail sites have been identified and we expect to develop these sites during 2013 and 2014. We supply products to each of these service stations pursuant to distribution supply agreements. We also provide fuel pumps and related infrastructure to the operators of the majority of these retail service stations that are not owned or leased by us under cover of equipment loan agreement.

Annual Information Form   INTEROIL CORPORATION   15

During 2010, a second vessel was directly chartered and we now directly manage all our sea freight movements of fuel within Papua New Guinea. In 2011, shipping was centralized under a corporate shipping entity and this is now managed separately from the Downstream operations. In 2012, corporate shipping chartered a replacement larger vessel due to increased demand and we are again contemplating chartering a larger vessel in 2013.

In November 2010, the ICCC completed its review of the pricing arrangements for petroleum products in PNG. The purpose of the review was to consider the extent to which the existing regulation of price setting arrangements at both wholesale and retail levels should continue, or be revised for the five year period ending at the end of 2014. The report recommended an increase in margins for wholesaling and certain other activities while the retail margin is to remain the same as well as some increases in monitoring industry activity in PNG. All recommendations were implemented in 2011.

During 2012 fiscal year, we renewed our supply agreements with several key customers in the aviation industry for further three year periods.

Our retail business accounted for approximately 15% of our total downstream sales volumes in 2012, as compared to 13% over the same period in 2011. Investments were made in the last three years in new electronic systems for both pumps and the forecourt control units to support the further development of this business.

Financing

In 2010, we undertook the following financing transactions:

· In August 2010, we entered into a $25.0 million secured term loan bearing a 10% interest rate with Clarion Finanz.  The amount was made available in two instalments of $12.5 million and each instalment was drawn down during August 2010. The term loan facility matured on January 31, 2011 and was used for upstream development and general corporate purposes. The loan was repaid out of our proceeds from $280.0 million concurrent debt and equity offerings that closed in November 2010.

· In October 2010, we renewed our revolving working capital facility with BSP for the existing limit of 50.0 million Kina (approximately $18.9 million).

· On November 10, 2010, we closed concurrent public offerings of (i) 2,800,000 common shares at $75.00 per share for $210.0 million and (ii) $70.0 million aggregate principal amount of 2.75% convertible senior notes due 2015, raising gross proceeds of $280.0 million.  The net proceeds after deducting the underwriting discounts, commissions and estimated offering expenses were approximately $266.0 million. 

· Our working capital facility with BNP Paribas was renewed for $220.0 million until January 31, 2012.  This represented a $30.0 million increase to the facility limit to allow for rising crude prices and volumes.

In 2011, we undertook the following financing transactions:

· On May 23, 2011, the BNP Paribas working capital facility agreement was amended to allow a $10.0 million increase in the facility limit to $230.0 million. The facility was subsequently extended and further amended in February 2012 to increase in the facility limit to $240.0 million. In October 2012, this working capital facility agreement was amended so that the facility was made evergreen and the annual renewal requirement removed.

· In August 2011, we renewed our revolving working capital facility with BSP for the existing limit of 50.0 million Kina (approximately $23.3 million at the time of renewal) for another year. The facility had a maturity date of August 15, 2012.

Annual Information Form   INTEROIL CORPORATION   16

In 2012, we undertook the following financing transactions:

· In February 2012, we obtained a secured loan of $15.0 million from Westpac which is repayable in equal installments over 3.5 years with an interest rate of LIBOR plus 4.4% per annum. The loan agreement stipulates semi-annual principal payments of $2.1 million, with the final repayment to be made in August 2015. The loan is secured by a fixed and floating charge over the assets of our downstream operations.

· On October 16, 2012, we entered into a five year amortizing $100 million secured term loan facility with BNP Paribas Singapore, BSP and the Australia and New Zealand Banking Group (PNG) Limited. On November 9, 2012, borrowings under the facility were used to repay all outstanding amounts under the term loan granted by OPIC, and the remaining funds will be used for general corporate purposes. The loan is secured over the assets of the refinery and bears interest at LIBOR plus 6.5%. All available funds under this facility were drawn down on November 9, 2012.

· In February 2012, the Westpac working capital facility was renewed for a total amount of PGK 90.0 million (approximately $42.0 million). This facility is now set to expire in November 2014.

· The BSP facility limit is PGK 50.0 million (approximately $24.2 million), and was renewed in November 2012 for another year ending in August 2013.

Management Team

During the years 2010 to 2012, our Board and senior management changed as follows:

· On June 22, 2010, Mr. Edward Speal resigned as a director and Mr. Ford Nicholson was appointed as a director. Mr. Nicholson was also appointed to the Board’s Audit and Reserves Committees.

· In August 2011, the Right Honourable Sir Rabbie Namaliu, the former Prime Minister and former Petroleum and Energy Minister of Papua New Guinea, joined us as chair of our PNG Advisory Board, a body formed to provide advice and assist in discussions with PNG government and departments, particularly associated with the development of our LNG Project. Also in August, our General Manger Exploration & Production, Mr. Wayne Hamal, left our employ and was replaced by Mr. David Holland, formerly our Chief Geologist. Mr. Holland assumed responsibility of our upstream business segment’s exploration and field development activities. Mr. Allan Zirgulis also joined us during that month as PNG Country Manager for our LNG Project and Condensate Stripping Project.

· In July 2012, Sir Rabbie Namaliu and Mr. Samuel Delcamp were appointed as directors. The Board also separated the roles of Chairman and Chief Executive Officer. Dr. Gaylen Byker assumed the role of Chairman while Mr. Mulacek continued as Chief Executive Officer. In June, our General Counsel, Mr. Mark Laurie, left our employ and was replaced by Mr. Geoffrey Applegate, who formally joined us in December 2012. Mr. Sean Walls also joined us during that month as Deputy Chief Financial Officer.

BUSINESS STRATEGY

Our strategy is to develop a vertically integrated energy company in Papua New Guinea and the surrounding region, focusing on niche market opportunities that provide financial rewards for our shareholders, while being environmentally responsible, providing a quality working environment and contributing positively to the communities in which we operate. A significant current element of that strategy is to develop the LNG Project and the Condensate Stripping Project in Papua New Guinea and to establish gas and gas condensate reserves. We are aiming to pursue this strategy by:

Developing our position as a prudent and responsible business operator

· Building on 17 years of engagement in Papua New Guinea;

· Maintaining a sound health and safety record;

· Continuing developing sound relationships with government, partners and stakeholders; and

· Remaining a significant employer in Papua New Guinea.

Maximizing the value of our exploration assets

· Managing our exploration program to minimize relinquishment at license renewal;

Annual Information Form   INTEROIL CORPORATION   17

· Using our experience in Papua New Guinea to successfully target seismic and drilling activities; and

· Employing our second drilling rig to develop existing discoveries.

Monetizing our discovered resources

· Introducing strategic investors through the sale of interests in the Elk, Antelope and Triceratops fields, the Condensate Stripping Project, the LNG Project and associated LNG off-take to support our exploration and development activities;

· Progressing the LNG Project and the Condensate Stripping Project with a focus on accelerating cash flows; and

· Seeking licenses, enabling legislation and approvals required for our planned developments from the State.

Enhancing the existing refining and distribution business

· Continuing growth in profitable market share in the region;

· Looking for added value in refining production, and improved economies of scale; and

· Exploring improved transport efficiencies and economics.

DESCRIPTION OF OUR BUSINESS

Overview

Our operations are organized into four major business segments:

Segments	Operations
Upstream	Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua New Guinea. Developing infrastructure for the Elk and Antelope fields which includes wells, gas gathering pipelines, condensate stripping facilities and pipelines for the proposed delivery of natural gas to the Midstream Liquefaction segment and condensate to the Midstream Refining segment. This segment also conducts appraisal drilling of the Triceratops field and manages our construction business which services our development projects underway in Papua New Guinea.
Midstream	Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export.
	Liquefaction – Developing liquefaction and associated facilities in Papua New Guinea for the export of LNG.
Downstream	Wholesale and Retail Distribution – Markets and distributes refined products domestically in Papua New Guinea on a wholesale and retail basis.
Corporate	Corporate – Provides support to our other business segments by engaging in business development and improvement activities and providing general and administrative services and management, undertakes financing and treasury activities, and is responsible for government and investor relations. General and administrative and integrated costs are recovered from business segments on an equitable basis. This segment also manages our shipping business which currently operates two vessels transporting petroleum products for our Downstream segment and external customers, both within PNG and for export in the South Pacific region. Our Corporate segment results also include consolidation adjustments.

As of December 31, 2012, we had 1,093 full-time employees in all segments, with 205 in upstream, 127 in midstream refining, 543 in downstream and 218 in corporate. 

Annual Information Form   INTEROIL CORPORATION   18

UPSTREAM - EXPLORATION AND PRODUCTION

As at December 31, 2012, we had gross interests in three PPLs and one PRL in Papua New Guinea covering 3,996,453 gross acres (3,030,720 net acres), all of which were operated by us. PPLs 236, 237 and 238 and PRL 15 are located onshore in the Eastern Papuan Basin, northwest of Port Moresby.

On November 30, 2010, we were granted PRL 15, covering a total of nine graticular blocks including and surrounding the Elk and Antelope fields and extracted from PPLs 237 and 238. This PRL unifies the Elk and Antelope fields into a single license and separates the fields from our exploration acreage. The PRL has a separate minimum work program and expenditure commitment and is valid for five years to November 30, 2015.

In order to develop and commercialize the Elk and Antelope fields in PRL 15, we are obligated to apply for and obtain a Petroleum Development License covering the acreage surrounding the fields and on which to locate facilities and pipeline rights of way. PRL 15 allows us to evaluate the technical and commercial feasibility of condensate and/or gas production from the Elk and Antelope fields, pending development and submission of an application for a Petroleum Development License in respect of those fields.

The following table summarizes our interests and on acreage currently held by us as at December 31, 2012:

License Numbers	Discovery	Location	Operator	InterOil Registered License Interest			InterOil Net Beneficial Interest Owned			Blocks Covered		Acreage Gross		Acreage Net
PPL 236	None	Onshore	InterOil		100.00	%		78.1114	%		53		1,112,464		868,961
PPL 237	None	Onshore	InterOil		100.00	%		65.2081	%		25		525,872		342,911
PPL 237	Triceratops	Onshore	InterOil		100.00	%		68.4339	%		9		189,776		129,871
PPL 238		Onshore	InterOil		100.00	%		78.1114	%		94		1,978,565		1,545,485
PRL 151		Onshore	InterOil		75.6114	%		75.6114	%		9		189,776		143,492
								Total			190		3,996,453		3,030,720

¹See Petroleum License Details – Net Working Interest on PPL 236, PPL 237 and PPL 238.

Resources

We currently have no production or reserves as defined in NI 51-101 or under the definitions established by the United States Securities and Exchange Commission.

The GLJ Report is an evaluation of the resources of gas and condensate for the Elk and Antelope fields and the Triceratops field, all of which are located onshore in Papua New Guinea. The GLJ Report was prepared by GLJ, an independent qualified reserves evaluator, effective as of December 31, 2012, and was prepared in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101.

All resources estimated for the Elk and Antelope fields are classified as contingent resources – economic status undetermined. At this early stage of appraisal, the resources estimates for the Triceratops field are classified separately in the GLJ Report as either contingent resources – economic status undetermined or prospective resources. Consistent with our treatment with Elk and Antelope fields, the Triceratops prospective resources are not included.

Contingent resources are those quantities of natural gas and condensate estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The economic status of the resources is undetermined and there is no certainty that it will be commercially viable to produce any portion of the resources.

Annual Information Form   INTEROIL CORPORATION   19

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub classified based on project maturity.  Prospective resources differ from contingent resources in that they are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added.

Elk and Antelope Fields

The Elk and Antelope fields located in Papua New Guinea and contained within PRL 15 are gas fields reservoired in a composite trap comprising structural and stratigraphic elements consisting of a Late Oligocene to Late Miocene limestone and carbonate. The Elk field overlies the northern end of the Antelope field and comprises a tectonic wedge, or over thrust, of highly fractured deep water limestone and has been penetrated by the Elk-1 and Elk-2 wells. The Antelope field has been penetrated by the Elk-4, Antelope-1, Antelope-2 and Antelope-3 wells and the reservoir consists of a dominantly shallow water reef/platform complex with a dolomite cap with well-developed secondary porosity and permeability.

The following tables set forth GLJ's estimates of total contingent resources estimate for gas and condensate at the Elk and Antelope Fields and our the net contingent resources estimate for gas and condensate at the Elk and Antelope Fields as set forth in the GLJ Report:

Total Contingent Resources Estimate for Gas and Condensate
for the Elk and Antelope Fields ^{1, 2}

As at December 31, 2012	Case
Elk/Antelope Contingent		Low	Best	High
Initial Recoverable Sales Gas (Tcf)		6.83	9.07	10.85
Initial Recoverable Condensate (MMbbls)		111.5	135.4	156.3
Initial Recoverable (MMboe)		1,250.1	1,646.3	1,965.4

Contingent Resource Estimate for Gas and Condensate
at the Elk and Antelope Fields – Net to InterOil ^{2, 3}

As at December 31, 2012	Case
Elk/Antelope Contingent		Low	Best	High
Initial Recoverable Sales Gas (Tcf)		4.00	5.31	6.36
Initial Recoverable Condensate (MMbbls)		65.34	79.34	91.59
Initial Recoverable (MMboe)		732.5	964.7	1,151.7

Notes:

1. These estimates represent 100% of the Elk and Antelope fields

2. 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. With the probabilistic methods 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. With the probabilistic methods 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. With the probabilistic methods used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate

3. These estimates are based upon our holding a 58.5988% working interest in the Elk and Antelope fields, which assumes that: (i) the State and landowners elect to participate in the Elk and Antelope fields to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Elk/Antelope field and (ii) all elections are made to participate in the Field by all investors pursuant to relevant indirect participation interest agreements with us, including to participate fully and directly in the PDL.

Annual Information Form   INTEROIL CORPORATION   20

Although a final project has not yet been sanctioned, pre-FEED studies are ongoing for the LNG Project and FEED studies conducted for the Condensate Stripping Project as options for potential monetization of the gas and condensate.

Triceratops Field

The Triceratops gas and gas condensate field (see “Description of Our Business”), located in Papua New Guinea and contained within PPL 237 is reservoired in a composite trap comprising structural and stratigraphic elements consisting of a Late Oligocene to Late Miocene limestone and carbonate. The Triceratops field has been renamed from the old Bwata gas field and has been penetrated by the Bwata-1 (1959), Triceratops-1 (2005) and the Triceratops-2 wells 2012. The Triceratops-2 well was declared a discovery well by the DPE in June of 2012. The Triceratops gas field has been delineated by 140 kilometers of 2-D seismic and currently the western closure of the field remains outside the acquired seismic coverage.

The following tables present only the portion of the reservoir classified as contingent resources in the GLT Report;

Total Contingent Resources Estimate for Gas and Condensate for the Triceratops Field ^{1, 2}

As at December 31, 2012	Case
Triceratops Contingent		Low	Best	High
Initial Recoverable Sales Gas (Tcf)		0.12	0.38	0.90
Initial Recoverable Condensate (MMbbls)		2.69	8.16	19.45
Initial Recoverable (MMboe)		23.2	71.9	168.8

Contingent Resource Estimate for Gas and Condensate – Net to InterOil ^{2, 3}

As at December 31, 2012	Case
Triceratops Contingent		Low	Best	High
Initial Recoverable Sales Gas (Tcf)		0.07	0.20	0.48
Initial Recoverable Condensate (MMbbls)		1.43	4.33	10.32
Initial Recoverable (MMboe)		12.3	38.1	89.5

Notes:

1. These estimates represent 100% of the Triceratops field.

2. 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. With the probabilistic methods 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. With the probabilistic methods 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. With the probabilistic methods used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate

3. These estimates are based upon InterOil holding a 53.0364% working interest in the PPL-237, which assumes that: (i) the State and landowners elect to participate in the Triceratops field to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Triceratops field and (ii) all elections are made to participate in the Field by all investors pursuant to relevant indirect participation interest agreements with InterOil, including to participate fully and directly in the PDL.

The following contingencies must be met before the Elk and Antelope (or Triceratops) contingent resources can be classified as reserves:

· Sanctioning and financing for the facilities required to process and transport marketable natural gas to market.

· Confirmation of a market for the marketable natural gas and condensate.

· Approval from regulatory authorities to develop the resources.

· Determination of economic viability.

Annual Information Form   INTEROIL CORPORATION   21

Accuracy of Resource Estimates

The accuracy of resource estimates is in part a function of the quality and quantity of the available data and of engineering and geological interpretation and judgment. Other factors in the classification as a resource include a requirement for more delineation wells, detailed design estimates and near term development plans. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of the seismic and well data. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional delineation wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well data.

Costs incurred in relation to Exploration and Development activities

The following table outlines costs incurred by us during the year ended December 31, 2012 for property, acquisitions, exploration and development activities.

Nature of Cost	Amount (US $ million)
Property acquisition costs		-
Exploration costs	$	13.9
Development costs	$	152.2
Total	$	166.1

Additionally the following table summarizes the results of exploration and development activities on a gross and net basis (with net costs reflecting the cost to us, not including the portion of costs met by our partners), as further broken down by well type, during the year ended December 31, 2012.

Wells	Development				Exploration				Total
	Gross (US $ million)		Net (US $ million)		Gross (US $ million)		Net (US $ million)		Gross (US $ million)		Net (US $ million)
Gas	$	184.2	$	152.2	$	13.9	$	13.9	$	198.1	$	166.1
Oil		-		-		-		-		-		-
Service		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total	$	184.2	$	152.2	$	13.9	$	13.9	$	198.1	$	166.1

Operated License Commitments, Terms, Expiry and Re-Application

In March 2009, PPLs 236, 237 and 238 were extended for 5 years, with an initial term of 2 years followed by an intermediate term of 2 years and a final term of 1 year. The PPL license renewals require that we meet our work program and expenditure commitments for each term. The first 2 year term of the license anniversaries occurred in March 2011. On May 17, 2011, the State approved our work program and expenditure proposals for all three licenses.

Annual Information Form   INTEROIL CORPORATION   22

In January 2011, we applied for a variation of license conditions on PPL 238 to defer the commitment to drill a well from first two year term to the second term which ends in March 2013. The State approved this request on May 17, 2011.

We have met all other commitments under our licenses as of December 31, 2012.

Following are our applicable expenditure commitments for each PPL and PRL.

License		License Issue/Extension	Term	Commitment Years 1 to 2 ( $ Millions)			Commitment Years 3 to 5 ( $ Millions)		Total License Commitment ( $ Millions)			License Expiry
	PPL 236	March 27, 2009	5 years	$	5.0		$	10.0	$	15.0		March 27, 2014
	PPL 237	March 27, 2009	5 years	$	14.0		$	34.0	$	48.0		March 27, 2014
	PPL 238	March 6, 2009	5 years	$	2.0	(3)	$	30.0	$	32.0		March 6, 2014
	PRL15	November 30, 2010	5 years	$	53.0	(2)	$	20.0	$	73.0	(1)	November 29, 2015
			Totals	$	74.0		$	94.0	$	168.0

Notes:

⁽¹⁾Commitment total is for the first 5 years only

⁽²⁾ The application for variation of PRL15 was granted on November 28, 2012. The variation allowed us to defer the drilling of an obligation well into the second term of the license

⁽³⁾ The application for variation of 236 and 238 were submitted on December 5, 2012. The applications are still pending approval.

Petroleum License Details

The table below sets forth the working interests in our licenses in the event that the State and all other possible holders, exercise their rights to acquire their beneficial interests. All of such other parties are obligated to make payments to us to cover continuing field development costs and, if they do not make the required payments, their interests in the fields may be reduced accordingly.

Working interests in licenses

Petroleum Prospecting License 236

Participant	Working Interests (before State Participation)			Working Interests (after State Participation)
InterOil		78.1114	%		60.5363	%
IPI Holders(6)		15.1386	%		11.7324	%
PNGDV(2)		6.7500	%		5.2313	%
State(5)		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form   INTEROIL CORPORATION   23

Petroleum Prospecting License 237 - (Excluding Triceratops Gas Condensate Field)

Participant	Working Interests (before State Participation)			Working Interests (after State Participation)
InterOil(7)		65.2081	%		50.5363	%
IPI Holders(6)		15.1386	%		11.7324	%
PNGDV(2)		6.7500	%		5.2313	%
PRE(7)		12.9033	%		10.0000	%
State(5)		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 237- Triceratops Gas Condensate Field

Participant	Working Interests (before State Participation)			Working Interests (after State Participation)
InterOil(7)		68.4339	%		53.0364	%
IPI Holders(6)		13.1108	%		10.1608	%
PNGDV(2)		5.5520	%		4.3028	%
PRE(7)		12.9033	%		10.0000	%
State(5)		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form   INTEROIL CORPORATION   24

Petroleum Prospecting License 238

Participant	Working Interests (before State Participation)			Net Working Interests (after State Participation)
InterOil		78.1114	%		60.5363	%
IPI Holders(6)		15.1386	%		11.7324	%
PNGDV(2)		6.7500	%		5.2313	%
State(5)		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Retention License 15

Participant	Working Interests (before State Participation)			Working Interests (after State Participation)
InterOil		75.6114	%		58.5988	%
IPI Holders(1)		15.1386	%		11.7324	%
Pac LNG Assets Limited(2)		6.7500	%		5.2313	%
Pac LNG Investment Limited(3)		2.5000	%		1.9375	%
State(5)		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Notes:

⁽¹⁾ In February 2005, we entered into an agreement with the IPI Holders pursuant to which the IPI Holders paid us an aggregate of US$125.0 million and we agreed to drill eight exploration wells in Papua New Guinea on PPLs 236, 237 and 238. We have drilled four of these eight wells to date. Following various buybacks and conversions, IPI Holders currently hold interests totaling 15.1386% of each of these existing and future wells. Each IPI Holder has the right to acquire an interest in field development operations following the drilling of an exploration well in which the holder owns an IPI. So, if an exploration well is successful, by paying their share of field development costs, the IPI Holders will have the right to participate in the development of the fields discovered by that well.

⁽²⁾ In July 2003, we entered into a Drilling Participation agreement with PNGDV, whereby PNGDV has a 6.75% interest in eight exploration wells. We have drilled six of these exploration wells to date. PNGDV also has the right to participate in the next 16 wells that follow the first eight mentioned above up to an interest of 5.75% at a cost of US$112,500 for each 1% per well (with higher amounts to be paid if the depth exceeds 3,500 meters and the cost exceeds US$8,500,000). In June 2012, PNGDV transferred its interest in PRL15 to Pac LNG Assets Limited.

⁽³⁾ In August 2009, we entered into a Sale and Purchase Agreement with Pacific LNG Operations, Limited (PLOL) whereby PLOL acquired a 2.5% direct working interest in gas and condensate in the Elk and Antelope fields. In June 2012, PLOL transferred its interest in PRL15 to Pac LNG Investments Limited.

⁽⁴⁾ PNGEI has the right to participate up to a 4.25% interest in 16 wells commencing from exploration wells numbered 9 to 24. As of March 31, 2013, we have drilled six exploration wells since the inception of our exploration program within PPL 236, 237 and 238. In order to participate, PNGEI would be required to contribute, for each exploration well, US$112,500 per 1% plus actual costs over US$1.0 million charged pro rata for each 1%.

⁽⁵⁾ Following statements from the State questioning the continuing validly of our 2009 LNG Project Agreement, in November 2012 the State made clear that it continues to approve of the LNG Project, with modifications to be agreed upon. The State also indicated that it was interested in acquiring an additional 27.5% equity interest in the Elk and Antelope fields, over and above the 22.5% interest to which it (and the affected landowners) is entitled under the Oil and Gas Act, on terms to be negotiated with us. We are currently negotiating with the State regarding this additional 27.5% interest.

Annual Information Form   INTEROIL CORPORATION   25

⁽⁶⁾ IPI's do not have a direct interest in any PPL but they are entitled to convert their interest following grant of a PRL.

⁽⁷⁾ In July 2012, we entered into a Farm-in Agreement with PRE and in November 2012 we executed JVOAs with PRE and related documents associated with our Farm-In Agreement, pursuant to which PRE will acquire a 10.0% Net Revenue Interest after State participation (12.9% before State participation) in PPL 237. The JVOA’s cover the Triceratops Gas Condensate field and the remainder of PPL237, excluding the Triceratops Gas Condensate field (PPL 237XT). The Triceratops Gas Condensate Field is currently part of License PPL 237. We will apply for a separate PRL covering this discovery and it is expected that this PRL will cover an area of nine graticular blocks, approximately 189,000 acres. This is coincidentally the same size as PRL15. Pac LNG and its affiliates are participating on a 25% beneficial equity basis in the portion of the PRE farm-in transaction relating to the Triceratops Gas Condensate field on PPL 237, by selling PRE a 3.2258% participating interest before State participation, (2.500% after State participation), thereby reducing the Pac LNG Group’s indirect participating interest in the Triceratops structure by 3.2258%. Pac LNG Group did not participate in the sale of its Indirect interest in PPL 237XT. In PPL 237XT, PRE acquired its 10.0000% Net Revenue Interest after State participation (12.9033% before State participation) directly from InterOil. As such, we now have 3.2258% lower interest in PPL237XT than our interest in the Triceratops Gas Condensate field.

⁽⁸⁾ If a PDL is granted over the Elk Antelope Gas condensate field (currently owned under PRL15), investors in our IPI programs set out above will have the right to become registered direct working interest owners by having their interests registered on the PDL. In order to maintain their right to earn revenues from the field, the investors are required to continue to fund their share of ongoing appraisal drilling and all subsequent work that may be required to bring the field into production.

Petroleum Prospecting License 236

PPL 236 consists of 53 graticular blocks covering an area of 4,502 square kilometers or 1,112,464 acres.

The following are the work commitments for PPL 236 for the remaining two-year term of the PPL, ending in March 2013:

· A minimum expenditure of $ 9.85 million;

· Drill an exploration well at a location acceptable to the State; and

· Complete a thorough petroleum system and basin study in PPL 236.

As at February 27, 2013, we have submitted to the DPE a request for a variation of the drilling commitment under PPL 236 by deferring it into year five of the second term. As required under the Oil & Gas Act, we submitted a work program and expenditure proposal for year five. We are still awaiting confirmation of the approval of the variations from the DPE.

Petroleum Prospecting License 237

PPL 237 consists of 34 graticular blocks covering an area of 3,238 square kilometers or 715,648 acres. On November 30, 2010, a total of four graticular blocks were excised from PPL 237 and incorporated into PRL 15.

The following are the work commitments for PPL 237 for the remaining two-year term of the PPL ending in March 2013:

· Minimum expenditure of $10.0 million;

· Acquire, process and interpret new seismic data focused on selecting a drilling location; and

· Complete a thorough petroleum system and basin study in PPL 237.

We intend to apply for a PRL over an area of PPL 237 surrounding the Triceratops gas and condensate discovery totaling 9 graticular blocks.

As at February 272013, we have submitted a work program and expenditure proposal for year five of PPL237. We are still awaiting confirmation of the approval of the variations from the DPE.

Petroleum Prospecting License 238

PPL 238 consists of 94 graticular blocks covering an area of 7,922 square kilometers or 1,978,565 acres. On November 30, 2010, a total of five graticular blocks, including the blocks in which the Elk-1, Elk-4 and Elk-4A gas /condensate discovery wells were drilled, were excised from PPL 238 and incorporated into PRL 15.

Annual Information Form   INTEROIL CORPORATION   26

The following are the work commitments for PPL 238 for the remaining two-year term of the PPL ending in March 2013:

· Minimum expenditure of $ 10.0 million

· Acquire, process and interpret new seismic data focused on selecting a drilling location;

· Complete a thorough petroleum system and basin study in PPL 238 and

· Drill a well at a location acceptable to the State.

On December 5, 2012, we submitted a request for a variation of the drilling commitment to be replaced by the Airborne Gravity and Magnetics and Seismic that had been acquired in 2011 and 2012. We also submitted a work program and expenditure proposal for year five.

Petroleum Retention License 15

Petroleum retention licenses may be granted to licensees of PPLs in which petroleum fields or parts of petroleum fields have been discovered to permit time for the licensee to develop the means for commercialization of the gas discoveries. In August 2009, we applied for a PRL over the declared location and on November 30, 2010, PRL 15 was granted by the State and was excised from of PPL 237 and PPL 238.

The initial period of a petroleum retention license is for five years and further extensions of two 5-year terms may be granted at the discretion of the State.

The total financial commitment over the first five year term of PRL 15 amounts to $73.0 million. Following are the work commitments for PRL15 for the first two years of this term, ending in November 2012.

· Drill 2 wells in the Elk and Antelope fields;

· Acquire, process and interpret 100 kilometers of two dimensional seismic acquisition and complete geoscience studies;

· Conduct social mapping and social and economic impact studies;

· Conduct commercial and marketing studies; and

· Conduct surface and subsurface engineering studies

- Static and dynamic reservoir modeling

- Base case depletion plan

- Surface facilities

On June 27, 2012, we submitted an application for a variation of the PRL15 License commitment to extend the well commitments into years three and four of the License. After the successful mobilization and spudding of the Antelope-3 on September 8, 2012 we submitted a request to modify this variation to the extension of 1 well obligation into Years 3 and 4. The variation was granted by the DPE on November 27, 2012.

Petroleum Development License (“PDL”)

In order to progress the proposed development and commercialization of the Elk, Antelope and Triceratops fields, we will need to apply for and obtain a PDL from the State. Assuming that a PDL is issued, it will replace PRL 15 and include the Elk and Antelope fields and additional acreage required for in-field facilities and gathering systems. We will also need to apply for and be granted a Petroleum Processing Facilities License (“PPFL”) for the LNG Project and Pipeline Licenses (“PLs”) for the dry gas and condensate pipelines. We have commenced preparation of an application for a PDL.

The application for a PDL is made to the DPE and must be accompanied by detailed proposals for the financing, construction, establishment and operation of all facilities and services for and incidental to the recovery, processing, storage and transportation of gas from the PDL area. Collectively these will constitute the Development Plan. In addition, certain agreements and approvals from the State will need to be in place prior to the grant of the PDL including a gas agreement defining the fiscal regime applicable to the development and providing for the State’s equity participation in the fields. Environmental approvals will be necessary and we will also be obliged to submit comprehensive social mapping and landowner identifications studies of those customary landowners within the PDL area. Ministerial recognition of landowner groups is customarily based on such reports.

Annual Information Form   INTEROIL CORPORATION   27

Upon application, the State will undertake a comprehensive review of the Development Plan and any other incidental agreement or approval required before granting the PDL application. Following its review, the State shall take steps to conduct a ‘forum’ as set out under the Oil & Gas Act. The forum requires that the State co-ordinate a meeting for all affected stakeholders including the provincial, local level governments and customary landowners with a view towards establishing a regime for the distribution of royalties and other benefits that will arise from the commercialization of the fields.

Once all formalities are completed and the State is satisfied, the State may grant the PDL, the PPFL and the PLs. Should the licenses be issued, the acreage would be held subject to; (i) periodic review provided for in PNG’s Oil & Gas Act, and (ii) the license holders continuing to meet commitments associated with the license grant.

Set forth below is the current development status of each of our licenses:

License	Current Development Status
PPL 236	Our Wahoo prospect, targeting seismically defined indications in PPL 236, has matured to the drill-ready stage and preparations to facilitate access to the proposed drilling location are underway.
PPL 237	The Triceratops field is located on PPL 237. Following successful flow from a drill stem test, the Triceratops-2 well was declared a discovery by the State on June 14, 2012. The Triceratops-2 well has been suspended as a discovery for recompletion at a later date as a future production well. We have begun the process of farming out portions of our interest in PPL 237 to industry partners in order to reduce our costs of delineating the bounds of the Triceratops field.
PPL 238	Our Tuna prospect, targeting seismically defined indications in PPL 238, have matured to the drill-ready stage and preparations to facilitate access to the proposed drilling location are underway.
PRL 15	In November 2012, the Antelope-3 appraisal well in PRL 15 penetrated the top of the reservoir. We believe that the Antelope-3 well further confirms the continuity of a highly productive reservoir into which the Antelope-1 and Antelope-2 wells were drilled. We had previously drilled the Elk-1, Elk-2 and Elk-4 wells on PRL 15. We are now planning the development of infrastructure for the Elk and Antelope fields, which is expected to include gas gathering pipelines, the Condensate Stripping Project and pipelines to deliver natural gas to the LNG Project and condensate to the Midstream Refining segment.

JVOA and Farm-In Agreement with PRE

On April 18, 2012, we signed a binding HOA with PRE for PRE to be able to earn a 10.0% net (12.9% gross) participating interest in the PPL 237, including the Triceratops structure located within that license. The transaction contemplates staged initial cash payments totaling $116.0 million, an additional carry of 25% of the costs of an agreed exploration work program, and a final resource payment. On July 27, 2012, we executed Farm-In Agreement with PRE relating to the Triceratops structure and the participating interest in the PPL 237 license materially in line with the HOA signed on April 18, 2012. Completion of the farm-in transaction remains subject to satisfaction of additional conditions within 18 months, including execution of a JVOA, and State approval. PRE’s gross participating interest will be subject to the State’s back-in rights provided for in relevant legislation. Additionally, PRE has the option to terminate the Farm-In Agreement at various stages of the work program and to be reimbursed up to $96.0 million of the $116.0 million initial cash payment (which does not include carried costs) out of future upstream production proceeds. As at December 31, 2012, PRE has paid $40million of the staged cash payments.

Annual Information Form   INTEROIL CORPORATION   28

Pac LNG and its affiliates are participating on a 25% beneficial equity basis in the portion of the farm-in transaction relating to the Triceratops structure (2.5% net and 3.2% gross participating interest), by reducing Pac LNG’s IPI interest in the Triceratops structure. As a result, Pac LNG and its affiliates will receive credits (to be offset against cash call receivable from Pac LNG and its affiliates for their IPI interest) for 25% of the payments PRE makes under the farm-in transaction relating to the Triceratops structure. Pac LNG and its affiliates will also receive credits for a commission fee of 2.5% of cash payments made by PRI (other than carried costs). Certain other indirect participating interest holders may also participate in the farm-in transaction.

Upstream – Condensate Stripping Project

The Condensate Stripping Project will be designed to work in tandem with the LNG Project and will be located on the Elk and Antelope fields. A condensate-stripping plant is used to process well-stream production fluids (which generally include natural gas, gas condensate and water) by separating the condensate and water from the gas so that each can be most efficiently utilized or disposed of. During this process, the recovered water is re-injected into the field, the dry gas is treated and cooled, and the condensates are stabilized and cooled, before both the gas and condensates are pumped to the LNG facility through separate pipelines. This process is generally undertaken close to the fields producing the gas/condensate/water stream, because water left in solution is corrosive to pipelines and leaving condensate in with gas impedes the flow of both.

On August 4, 2010, we entered into a joint venture agreement (the CSP JV) with Mitsui in connection with the Condensate Stripping Project to develop a condensate stripping facility to extract condensate from the raw gas produced by the Elk and Antelope fields. Following the completion of engineering design work, financing agreements and further regulatory approvals, Mitsui will make a final investment decision (FID) and elect whether to continue with the development of the Condensate Stripping Project and take a 50% share in the facility. In the event Mitsui elects to continue with the development of the facility, it will be responsible for funding all of the capital cost to build the facility and will have the option to acquire up to a 5% interest in the Elk and Antelope fields. If Mitsui elects not to continue with the development of the facility, we will be required to refund their capital expenditures.

The capital cost for the Condensate Stripping Project was initially estimated at $550.0 million, with approximately $32.0 million of this to be expended for FEED. During 2011, the FEED work was carried out. The FEED phase generated deliverables to technically and commercially define the project and prepare it for execution (detailed engineering, procurement, construction, fabrication, commissioning, and hand-over to operations), and proposals were solicited from potential EPC contractors. We are continuing the planning and preparation efforts for the execution of the Condensate Stripping Project, which efforts include detailed project execution planning, execution scheduling and risk assessment work.

At the end of 2012, agreement was reached with Mitsui to extend the dates in the CSP agreements to provide flexibility for FID. We can provide no assurance we will reach FID by the target date or at all, that this date will be further extended or that we will enter into unconditional or definitive agreements with Mitsui.

We have selected the site for the condensate stripping plant, finalized plot dimensions and layout for the facility and conducted geotechnical site selection investigations. We have also brought in a soils specialist to assist in optimizing the site location and prepared a report recommending that condensate stripping plant be built on the site. We are currently developing site logistics plans.

Negotiations for pipeline material procurement and pipeline installation contracts have been put on hold pending finalization of agreements with the State. A geo-hazard seismological survey of the pipeline route has been completed. Pipeline route center line surveying has been completed. Gas gathering system design has been initiated. All social and economic impact statements for the pipeline license areas and social mapping and land investigation studies for the pipeline route are complete. Condensate Stripping Project base, Herd Base, Hepea and the Bluff have been established as operational bases for pipeline contractor activities.

Annual Information Form   INTEROIL CORPORATION   29

Completion of the required LNG Project by us and our joint venture partners and related construction will take a number of years to complete. No assurances can be given that we will be able to construct the proposed LNG facilities or as to the timing of such construction.

MIDSTREAM - REFINING

In the 1990s we identified the fact that, since becoming a major oil producer in 1992, Papua New Guinea was one of the few oil producing countries in the world with no domestic oil refinery. The potential to replace imports and avoid transportation costs provided an opportunity for a “niche” refinery sized to supply Papua New Guinea and nearby markets. We believed that an installation whose capacity matched that “niche” market would be economically attractive. We began implementing a business plan to capture that opportunity by sourcing an existing refinery and by working with the State to further enhance the project economics.

On January 31, 2005, our refinery achieved practical completion. Practical completion means construction of the refinery has been completed and that the refinery has satisfactorily completed the reliability and performance tests which were conducted as part of the acceptance and handover process.

We are currently the sole refiner of hydrocarbons in Papua New Guinea. Our refinery is located across the harbor from Port Moresby, the capital city of Papua New Guinea. We import crude oil for processing at our refinery and resell the refined products primarily within Papua New Guinea at IPP, which is basically the price that would be paid in Papua New Guinea for a refined product that had been imported. We also distribute a large portion of the production from our refinery through our retail distribution network.

Jet fuel, diesel and gasoline are the primary products that we produce for the domestic market. The refining process also results in the production of two Naphtha grades and low sulfur waxy residue. To the extent that we do not convert the Naphtha to gasoline, we export it to the local and Asian markets in two grades, light Naphtha and mixed Naphtha, which are predominately used as petrochemical feedstock. LSWR can be and is being sold as fuel for power generation domestically, local bunker fuel sales with the majority exported for use in other complex refineries as cracker feedstock or supply to other end users, including power generators.

Facilities and Major Subcontractors

Our refinery includes a jetty with two berths for loading and discharging vessels and a road tanker loading system (gantry). Our larger berth has deep water access of 56 feet (17 meters) and has been designed to accommodate crude and product tankers with capacity up to 130,000 dwt. Our smaller berth can accommodate ships with a capacity of up to 22,000 dwt. Our tank farm has the ability to store approximately 750,000 barrels of crude feedstock and approximately 1.1 million barrels of refined products. We have a reverse osmosis desalination unit that produces all of the water used by our refinery, camp and office facilities, power generation facilities that meet all of our electricity needs, and other site infrastructure and support facilities, including a laboratory, a waste water treatment plant, staff accommodation and a fire station.

Our refinery’s on-site laboratory is accredited by National Association of Testing Authorities, Australia. The lab is staffed and operated by an internationally recognized independent inspection and testing company. All crude imports and finished products are tested and certified on-site to contractual specifications, while independent certification of quantities loaded and discharged at the refinery are also provided by the laboratory.

Crude Supply

In December 2001, we entered into an agreement with BP Singapore for the supply of crude feedstock to our refinery. Supply under the agreement commenced when our refinery began operations in June 2004 and continued for 5 years until June 2009. Since this time the agreement has been renewed annually. BP Singapore is one of the largest marketers and shippers of crude oil in the Asia Pacific region. This contract provides us with a reliable mechanism to access and ship the majority of the regional crudes suitable for our refinery. We will continue to review this arrangement and other options for sources of feedstock supply for our refinery and have been successful in securing other crude supply agreements for specific regional crudes.

Annual Information Form   INTEROIL CORPORATION   30

Sales

Papua New Guinea is our principal market for the products our refinery produces, other than Naphtha and LSWR. Under our 30 year agreement with the State, the State has agreed to ensure that all domestic distributors purchase their refined petroleum product needs from our refinery, (and from any other refinery which may be constructed in Papua New Guinea), at IPP. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product that is being imported. In late 2007, the IPP was modified, most significantly by changing the Singapore benchmark price from the ”Singapore Posted Prices” which was no longer being updated, to MOPS which is the current benchmark price for refined products in the region in which we operate. The Project Agreement governing our relationship with the State is yet to be formally amended to reflect the revised formula which has been in use for the last four years. (See “Material Contracts – Refinery Project Agreement”). We also distribute a large portion of the production from our refinery through our retail distribution network.

The major export product from our refinery is the two grades of Naphtha. On January 1, 2010 a 12 month term agreement with Dalian Fujia Dahua Petrochemicals (“Dalian”), which operates a petrochemical plant in China, was entered into providing for export sales of Naphtha. This contract ran for an 18 month period from January 1, 2011 until June 30, 2012. Following this, we entered into a 12 month term contract with Glencore Singapore for the sale of export Naphtha which expires in June 2013.

Our refinery is fully certified to manufacture and market Jet A-1 fuel to international specifications and markets this product to both domestic Papua New Guinea and overseas airlines.

We were a net consumer of LPG until the conversion of the main process furnaces and commissioning of the Hyundai generators which burn LSWR in 2006. With the installation of the LSWR firing generators, heaters and boilers, plus improved facilities for recovering LPG from the reformer off-gas and increased percentages of sweet crudes containing LPG, we are now a net producer of LPG.

Competition

Due to their favorable properties, light sweet crudes from the Southeast Asian and Northwest Australian region are highly sought after by refiners for use as feedstock. Therefore, there is significant competition to secure cargoes of these crude types. Due to the limited supply of light sweet crudes and the strong competition, we are not always able to secure our first choice crudes for our refinery and are required to obtain alternate crudes that are available.

We own the only refinery in Papua New Guinea. While not restricted under any agreement we have with the State, we do not envision any new entrants into the refining business within Papua New Guinea under the current market conditions. However, domestic distributors have not sourced all of their requirements from the refinery since 2009. Excess diesel, gasoline, Naphtha and LSWR that are exported are sold subject to prevailing commodity market conditions. Our geographical position and limited storage capacity inhibits our ability to compete with the regional refining center in Singapore for sales of large cargo sizes. However, these same factors may also provide competitive advantages if we expand our exports of refined products to the small and fragmented South Pacific markets.

Customers

Domestically in Papua New Guinea we sell Jet A-1 fuel, diesel, gasoline and small parcels of LSWR to domestic distributors. Our main domestic customer is our downstream distribution business segment, however we also distribute fuel products to Niugini Oil Company, Islands Petroleum and Exxon Mobil.

Trading and Risk Management

Our revenues are derived from the sale of refined petroleum products. Prices for refined products and crude feedstock are volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is always a time difference between the purchase of a crude feedstock and its arrival at the refinery and the supply of finished products to customers.

Our refinery faces mainly two types of market risks:

1) Flat price (or timing) risk, which results from the time lag between crude purchases and product sales. Generally, we are required to purchase crude feedstock approximately one to two months in advance of processing, whereas the domestic supply or export of finished products takes place after the crude feedstock is discharged and processed.  This timing difference can lead to differences between the cost of our crude feedstock and the revenue from the proceeds of the sale of products, due to the fluctuation in prices during the time period. 

Annual Information Form   INTEROIL CORPORATION   31

2) Crack spread (or margin) risk. Month to month changes of crack spreads, even when pricing of crude purchases and that of product sales fall into the same month, can affect the profitability of our refinery.

However, we can use various derivative instruments to assist us to reduce or hedge away the risks of changes in the relative prices of our crude feedstock and refined products.  These derivatives, which can be used to manage our price risk, can effectively enable us to manage the refinery margin.  At the same time, this means that if the difference between our sales price of the refined products and our acquisition price of crude feedstock expands or increases, then the benefits are limited to the margin range we have established. 

The derivative instruments which we generally use are over-the-counter swaps. Swap transactions are executed between the counterparties in the derivatives swaps market. It is commonplace among major refiners and trading companies in Asia Pacific to use derivative swaps as a tool to hedge their price exposures and margins. Due to the wide usage of such derivative tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for our hedging and risk management activities. The derivative swap instrument covers commodities or products such as jet, kerosene, diesel, Naphtha, and also crudes such as Dated Brent and Dubai. By using these tools, we actively engage in hedging activities to manage margins.

During the past 3 years, we participated in a number of hedges to reduce our risks. To manage the flat price risks, we transferred crude purchases to the months of product sales by utilizing Dated Brent time spread; we also directly sold product swaps for the months of product sales, such as selling MOPS naphtha swaps. To manage the crack spread risk, we sold crack spread swaps, such as MOPS naphtha vs. Dated Brent swaps and MOPS Gasoil 0.5% vs. Dated Brent swaps.

MIDSTREAM - LIQUEFACTION

Liquefaction is the process by which gas is cooled and compressed so that it can be easily transported from its source to another location. A pipeline can be used to transport natural gas from where it has been extracted to another location where it is used. As there is essentially no domestic market for gas in Papua New Guinea, the only practical solution for the monetization of our gas resource is to transport it using specially configured ships after it has been processed into the form of LNG. LNG is a term that describes the result of a process of cooling natural gas to a temperature of -162°C and compressing it into a volume approximately 1/600^th of its original volume.

Before gas can be processed into LNG, it must be gathered from the source wells using a piping system, water and condensates must be “stripped”, or separated, from the “dry” gas and it must be transported through a pipeline to a liquefaction facility (which is usually located adjacent to a shipping terminal).

We, together with our partners, are planning the development of an LNG Project involving the construction of liquefaction facilities to be built on the coast in the Gulf Province of PNG. As presently planned the LNG Project is a staged project currently planned to be built in three stages (subject to PNG approvals) namely:

Stage 1 - Start up production: an initial capacity of 3.8mtpa of LNG with a condensate stripping unit with a capacity of 600 to 900 mmcf/d.

Stage 2 –Build Additional Production Capacity: target ramp-up of capacity up to 8 mtpa LNG production, with a condensate stripping facility capacity of 1,350 mmcf/d capacity; and

Stage 3 – Potential Expansion of Production: The potential final ramp up will be to 11 mtpa with condensate stripping facilities reaching 1,800 mmcf/d capacity.

We can provide no assurances that we will obtain the financing and approvals necessary to proceed with the LNG Project in this manner, or that we will have sufficient gas resources to support the potential expansion stage.

Initial engineering design was undertaken in relation to the LNG Project. The regulatory and taxation regime with the State was established with the execution on December 23, 2009 of the LNG Project Agreement. This agreement also provides for the participation by the State in the LNG Project, allowing it to take up to a 20.5% ownership stake. Affected landowners are able to take an additional 2% stake bringing the total to 22.5%.

Annual Information Form   INTEROIL CORPORATION   32

On November 16, 2012, we were notified by the Prime Minister of Papua New Guinea Hon. Peter O’Neill that the NEC had conditionally approved our LNG development project in the Gulf Province. This decision clears the way to proceed with our plans for the development of an LNG plant in the Gulf Province with initial planned output of a minimum of 3.8 million tonnes per annum. The decision also approves an option for the State to acquire an additional 27.5% interest in the Elk and Antelope gas fields, over and above the 22.5% interest to which it is entitled under the Oil & Gas Act, on terms to be negotiated with us. The NEC further approved the establishment of a State negotiating team to discuss and agree to the necessary amendments to the 2009 LNG Project Agreement between the State and Liquid Niugini Gas Limited, to give effect to the NEC decision, and to agree on the terms on which the State could acquire the additional interest. The NEC decision confirms that the basis of the acquisition will be on commercial market terms. The NEC decision also includes as a condition of its approval that the LNG plant operator must be an internationally recognized operator of the planned LNG facilities.

During 2010, we and Pac LNG pursuing the development of the LNG Project by exploring the use of a modular plant able to be expanded incrementally from an initial position of 2 mtpa, and to explore locating this plant in the Gulf Province rather than near our existing refinery outside of Port Moresby. Advantages perceived with this approach included the potential acceleration of first production and reduced operational risks. In line with this revised approach, certain initial conditional agreements were entered into with EWC for development of the LNG Project. The agreements remain conditional and the parties may elect not to proceed with the LNG Project on the terms specified in those agreements or at all.

The infrastructure required for the LNG Project as currently envisaged includes a jetty and breakwater for an onshore LNG loading facility with expansion potential and approximately 70 miles (115 kilometers) of pipeline from the Elk and Antelope fields to the coast. The wells and the processed gas pipeline running from the Condensate Stripping Project to the coast in the Gulf Province will be the responsibility of the owners of the Elk and Antelope fields, including us and our upstream partners.

Construction of the proposed LNG Project and related infrastructure by us and our joint venture partners would take a number of years to complete. No assurances can be given that we will be able to construct the proposed LNG facilities or as to the timing of such construction.

At present, the LNG Project is being pursued by us in joint venture with Pac LNG. Our interests in the project are held through an incorporated joint venture entity, PNG LNG which in turn wholly owns those entities formed in Papua New Guinea to pursue the LNG Project (see “Material Contracts – LNG Project Shareholders Agreement dated July 30, 2007”).

We are currently seeking an internationally recognized LNG operating and equity partner for the co-development of the LNG Project, which may include the acquisition of an interest in the Elk and Antelope fields. In the event that this search is successful it is likely that our interests in the LNG Project, and those of our partners, will be reduced.

DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION

We have the largest wholesale and retail petroleum product distribution base in Papua New Guinea, after acquiring the fuel distribution assets of BP and Shell several years ago. This business includes bulk storage, transportation distribution and aviation, wholesale and retail facilities for refined petroleum products. Our downstream business supplies petroleum products nationally in Papua New Guinea through a portfolio of retail service stations and commercial customers.

Sales

The ICCC regulates the maximum prices and margins that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea. Margins were last reviewed by the ICCC in 2010 and will be further reviewed in 2014. We and our competitors may charge less than the maximum margin set by the ICCC in order to maintain competitiveness.

Annual Information Form   INTEROIL CORPORATION   33

Supply of Products

Our retail and wholesale distribution business distributes diesel, jet fuel, avgas, gasoline, kerosene and fuel oil as well as branded commercial and industrial lubricants, such as engine and hydraulic oils. In general, all of the refined products sold pursuant to our wholesale and retail distribution business are purchased from our refinery. We import the commercial and industrial lubricants, avgas and fuel oil, which constitute a small percentage of our volumes.

We deliver refined products from our refinery to two tanker vessels we charter, which are operated by a separate corporate division. We do not own these vessels but rather lease them on a full time charter basis. We schedule all of our own movements and deliveries on our chartered vessels. Our inland depots are supplied by road tankers which are owned and operated by third party independent transport contractors.

Our terminal and depot network distributes refined petroleum products to retail service stations, aviation facilities and commercial customers. We supply retail service stations and commercial customers with petroleum products using trucks or, in the case of some commercial customers, coastal ships. We do not own any of these shipping or trucking distribution assets. We pass transportation costs through to our customers.

Retail Distribution

As of December 31, 2012, we provided petroleum products to 53 retail service stations with 43 operating under the InterOil brand name and the remaining ten operating under their own independent brands. Of the 53 service stations that we supply, 16 are either owned by or head-leased to us with a sublease to company-approved operators. We currently operate one InterOil branded service station in Port Moresby directly, with a view to capturing the additional margin available on the retail sale of petroleum products. If this venture proves successful, we may consider operating more of our own retail service stations in the future. The remaining 37 service stations we supply are independently owned and operated. We supply products to each of these service stations pursuant to distribution supply agreements. We also provide fuel pumps and related infrastructure to the operators of the majority of these retail service stations that are not owned or leased by us.

One of our major strengths is our spread of storage and distribution facilities throughout Papua New Guinea. We have terminal facilities in POM (2), Alotau, Lae (2), Madang, Wewak, Goroka, Mt Hagen (2), Rabaul, Kimbe (2) and Kavieng. The only area we are not represented in is Oro Province (Popondetta). This enables us to offer national deals to customers spread over various geographical locations. We also service eleven airfields throughout the country although we are not represented at the main international airfield at Jacksons. While we supply the only provider at this airfield with Jet A1, we have to date not been represented on the field.

Wholesale Distribution

We supply petroleum products as a wholesaler to commercial clients and operate aviation refueling facilities throughout Papua New Guinea. We own and operate six large terminals and five smaller terminals and two inland bulk fuel depots that we use to supply product throughout Papua New Guinea. We enter into commercial supply agreements with mining, agricultural, fishing, logging and similar commercial clients to supply their petroleum product needs. Pursuant to many of these agreements, we supply and maintain company-owned above-ground storage tanks and pumps that are used by these customers. More than two-thirds of the volume of petroleum products that we sold during 2011 was supplied to commercial customers. Although the volume of sales to commercial customers is far larger than through our retail distribution network, these product sales are at a lower margin due to the volume rebates offered to our larger customers as a direct result of competition in this sector. Aviation customers represented a significant proportion of our total business by volume.

Competition

Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete with smaller local distributors of petroleum products. With the decision of our competitors early in 2010 to partly import directly from overseas refineries and the consequent cessation of the joint industry shipping arrangements, it is difficult to accurately gauge our market share. Our competitors source small quantities from our refinery from both the refinery gantry for the Port Moresby market and by tanker vessel for the markets outside Port Moresby. Our major competitive advantage is the large widespread distribution network we maintain with largely adequate storage capacity that services most areas of PNG. We also believe that our commitment to the distribution business in Papua New Guinea at a time when major-integrated oil and gas companies exited the Papua New Guinea fuel distribution market provides us with a competitive advantage. However, major-integrated oil and gas companies such as ExxonMobil have greater resources than we do and could if they decided to do so, expand much more rapidly in this market than we can.

Annual Information Form   INTEROIL CORPORATION   34

Major Customers

In 2012, we sold approximately 13% of our refined petroleum products to a major mining project in Papua New Guinea pursuant to a wholesale distribution contract. These volumes were contracted with narrow margins in order to provide volumes for the Midstream Refinery operations and as such, the loss of this customer, at least in the short term, would not adversely affect the profitability of our retail and wholesale distribution business. We entered into an additional supply agreement with a major mine in January 2010 for a two plus two year period.

During 2012, we sold approximately 10% of our refined petroleum products to Pacific Energy Aviation (PNG) Ltd for aviation refueling at Papua New Guinea’s international airport in Port Moresby.

THE ENVIRONMENT AND COMMUNITY RELATIONS

Environmental Protection

Our operations in Papua New Guinea are subject to an environmental law regime which includes laws concerning emissions of substances into, and pollution and contamination of, the atmosphere, waters and land, production, use, handling, storage, transportation and disposal of waste, hazardous substances and dangerous goods, conservation of natural resources, the protection of threatened and endangered flora and fauna and the health and safety of people.

These environmental laws require that our sites be operated, maintained, abandoned and reclaimed to standards set out in the relevant legislation. The significant Papua New Guinea laws applicable to our operations include the Environment Act 2000; the Oil & Gas Act 1998; the Dumping of Wastes at Sea Act (Ch. 369); the Conservation Areas Act (Ch.362); and the International Trade (Flora and Fauna) Act (Ch.391).

The Environment Act 2000 is the single most significant legislation affecting our operations. This regulates the environmental impact of development activities in order to promote sustainable development of the environment and the economic, social and physical well-being of people and imposes a duty to take all reasonable and practicable measures to prevent or minimize environmental harm. A breach of this Act can result in significant fines or penalties. Under the Compensation (Prohibition of Foreign Legal Proceedings) Act 1995, no legal proceedings for compensation claims arising from petroleum projects in Papua New Guinea may be taken up or pursued in any foreign courtunless proceedings were first brought in a Papua New Guinea court for or in pursuance of the same or substantially the same compensation claim and;

(a)          having been served, the defendant to such proceedings has not, within the time permitted, submitted to the jurisdiction of the Papua New Guinea court; or

(b)          a final judgement has been given or a final determination has been made in relation to those proceedings in a Papua New Guinea court or a Papua New Guinea tribunal and the judgement or determination remains unsettled.

Compliance with Papua New Guinea’s environmental legislation can require significant expenditures. The environmental legislation regime is complex and subject to different interpretations. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, continued compliance with existing Papua New Guinea laws regulating the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations, as has been the case during 2012. Future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.

Up until November 2012 we had outstanding loans with OPIC, an agency of the United States Government supporting the development of our refinery. OPIC is required by statute to conduct an environmental assessment of every project proposed for financing and to decline support for projects that, in OPIC’s judgment, would have an unreasonable or major adverse impact on the environment, or on the health or safety of workers in the host country. For most industrial sectors, OPIC expects projects to meet the more stringent of the World Bank or host-country environmental, health and safety standards. OPIC systematically monitors compliance with environmental representations and non-compliance may constitute a default under loan agreements.

Annual Information Form   INTEROIL CORPORATION   35

More stringent laws and regulations relating to climate change and greenhouse gases may be adopted in the future and could cause us to incur material expenses in complying with them. Regulatory initiatives could adversely affect the marketability of the refined products we produce and any oil and natural gas we may produce in the future. The impact of such future programs cannot be predicted.

Environmental and Social Policies

We have implemented an environmental policy which acknowledges that the principles of sustainable development are integral to responsible resource management. Under the policy, we will strive to minimize impacts on the physical environment, minimize negative social impacts and we accept the community desire to protect the natural environment from the material adverse effects of resource development. We routinely conduct “Environmental Risk Analysis” for major projects in which hazards to the environment are identified, with mitigating controls implemented and a “Hazard Register” developed to monitor any residual risks. We also develop project specific “Environmental Management, Monitoring & Reporting Plans”, in compliance with the PNG environmental protection legislation in order to monitor our ongoing compliance and performance. We have established corporate level controls in which all “near miss and real incidents” are reported, and investigated.

We have not adopted any specific social policies that are fundamental to our operations. However, we are committed to working closely with the communities we operate in and to complying with all laws and governmental regulations applicable to our activities, including maintaining a safe and healthy work environment and conducting our activities in full compliance with all applicable environmental laws.

Our Community Relations department oversees the management of community assistance programs and manages land acquisition related compensation claims and payments. Our development philosophy is based on “bottom-up planning” thus ensuring that all planning and development takes the local community into account. In relation to our midstream refining business, the department has developed a long-term community development assistance program that benefits the villages in the vicinity of the refinery. In addition, we have a team of officers associated with our upstream business who operate in the field and perform a wide variety of tasks. These include land owner identification studies, social mapping management, local recruitment, liaising with landowners, recording compensation payments to land owners and assisting in the provision of health and medical services in the areas in which our exploration activities are conducted. Generally, the department works closely with government, landowners and the community in order to ensure that all our activities have a minimum environmental impact and to at least maintain, and generally improve, the quality of life of the people inhabiting the areas in which we work.

We are currently undertaking the work required under PNG’s Oil & Gas Act and Environment Act to support an application for a PDL for the Elk and Antelope fields and other related licenses which will be required for pipelines and processing facilities associated with our LNG Project. These studies cover social mapping and landowner identification studies, socio economic impact statements, land investigations, benefit sharing models and other related base line studies. We have engaged expert consultants to assist us with the preparation of a detailed environmental impact statement and other baseline environmental and health studies. These studies are a pre-requisite to the grant of a PDL and will allow us to advance the necessary planning to formulate our proposals as to the nature and distribution of project benefits, and will assist the State in convening a forum of all interested stakeholders at landowner, local and provincial government level for the purpose of procuring a development agreement on benefit sharing.

RISK FACTORS

Our business is subject to numerous risks and uncertainties, some of which are described below. The risks and uncertainties described below are not the only risks facing us. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. If any of the following risks or uncertainties actually occurs, our business, financial condition and results of operations could be materially adversely affected.

Annual Information Form   INTEROIL CORPORATION   36

Our ability to develop our resources, including developing the Condensate Stripping Project and the LNG Project, together with associated pipelines and common facilities, is contingent on our ability to obtain significant funding.

We make, and will continue to make, substantial capital expenditures for exploration, development, acquisition and production of oil and gas reserves, the LNG Project and other infrastructure associated with that proposed LNG Project, the Condensate Stripping Project, refinery expansions and improvements, acquisitions of distribution assets, and for further capital acquisitions and expenses. Our share of the cost for the construction of these projects will be significant, both to maintain our existing ownership and to meet the requirements of any reduced interest in the event we sell a portion of it, and may amount to hundreds of millions of dollars. Our existing cost estimates, which in some cases are in early stages of development, are subject to change, due to such items as scope changes, revisions resulting from more detailed estimation work, cost overruns, change orders, delays in construction, increased material costs, escalation of labor costs, and increased spending to maintain the construction schedule.

To fund these development projects, we will need to pursue a variety of sources of funding besides those that we currently have planned. Our ability to obtain such significant funding will depend, in part, on factors beyond our control, such as the status of capital and industry markets at the time financing is sought and such markets’ view of our industry and of the prospects of us and our partners at the relevant time. We may not be able to reduce our funding obligations by selling a portion of our interest in the project on terms acceptable to us. We may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development project is otherwise proceeding on schedule. In addition, our ability to obtain some types of financing may be dependent upon our ability to obtain other types of financing. For example, project-level debt financing is typically contingent upon a significant equity capital contribution from the project sponsor. As a result, even if we are able to identify potential project-level lenders, we may have to obtain another form of external financing for us to fund an equity capital contribution to the project subsidiary. A failure to obtain financing at any point in the development process could cause us to delay or fail to complete our business plan for the Condensate Stripping Project or the LNG Project.

Our business relies in part on our ability to negotiate definitive agreements following conditional framework agreements and heads of agreement relating to the development of the LNG Project and the Condensate Stripping Project, or to otherwise negotiate and secure arrangements with other entities for such development and the associated financing thereof.

In order to operate our business, we will need to negotiate and enter into definitive agreements with our joint venture partners under existing and future conditional framework agreements and heads of agreement relating to the development of the LNG Project and the Condensate Stripping Project. We have limited experience negotiating these types of agreements. Each of these agreements is important to our business, and we cannot be certain of entering into definitive agreements with any of these parties. If we lose our business relationships with any of our potential collaborators for any reason, and are unable to otherwise negotiate and secure similar arrangements with other potential collaborators, our business and prospects could be adversely affected.

We depend upon access to the capital markets to fund our growth strategy.

As a result of the weakened global economic situation, including the European sovereign debt crisis, the downgrading of United States government debt and United States fiscal policy issues, we, along with all other energy companies, may have restricted access to capital, bank debt and equity, and may also face increased borrowing costs. Although our business and asset base have not declined, the lending capacity of many financial institutions has diminished and risk premiums have increased. As future capital expenditures will be financed out of funds generated from operations, funds raised in the equity and debt markets, borrowings and possible future asset sales, our ability to do so is dependent on, among other factors, the overall state of the capital markets and investor appetite for investments in the energy industry and our assets and securities in particular.

To the extent that external sources of capital are limited or unavailable or available only on onerous terms, our ability to make capital investments and maintain existing assets may be restricted, and our assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result.

Annual Information Form   INTEROIL CORPORATION   37

Based on current funds available and expected funds generated from operations, we believe we have sufficient funds available to fund our refining and distribution business operations in the normal course, but not the full development of our exploration assets, the LNG Project and the Condensate Stripping Project, each of which would require significant capital. Significant capital will also be required in order to fund additional exploration and development of the Elk, Antelope and Triceratops fields and meet our exploration license commitments. Failure to obtain any financing necessary for our capital expenditure plans, including through transactions with joint venture parties or otherwise, will likely result in delays in these activities.

Even with the agreements we have signed to date for development of the LNG Project and the Condensate Stripping Project, we may not be able to timely construct and commission them.

We may not complete construction of the LNG Project and the Condensate Stripping Project in a timely manner within budget, or at all, due to numerous factors, some of which are beyond our control. Factors that could adversely affect our planned construction include, but are not limited to, the following:

· our inability to finalize agreements with Mitsui and other potential joint venture partners or proceed with them on satisfactory terms;

· our inability to attract a suitable partner for the development of these facilities on acceptable terms;

· uncertainties in Papua New Guinea’s existing political environment;

· failure to obtain all required governmental and third-party permits, licenses and approvals for construction and operation;

· our failure to enter into satisfactory agreements with contractors for construction of the facilities;

· failure by contractors to fulfill their obligations under construction contracts, or disagreements with them over contractual obligations;

· our inability to obtain sufficient funding for construction of associated pipelines and common facilities, or to develop the Elk, Antelope and Triceratops fields;

· shortages of materials or delays in delivery of materials;

· cost overruns and difficulty in obtaining sufficient financing to pay for such additional costs;

· difficulties or delays in obtaining gas for commissioning activities necessary to achieve commercial operability of the LNG Project and the Condensate Stripping Project;

· our inability to finalize binding off-take agreements;

· weather conditions and other catastrophes;

· difficulties in obtaining a proper workforce for construction purposes, increased labor costs and potential labor disputes;

· resistance in the local and global community to the developments due to safety, environmental or security concerns; and

· local economic and infrastructure conditions.

Our inability to timely complete (or complete at all) the LNG Project and the Condensate Stripping Project may prevent us in part or in whole from commencing operations with respect to those projects. Thus, as a result, we may not receive any cash revenues from these facilities on time or at all.

We must obtain and maintain necessary permits, licenses and approvals from relevant Papua New Guinea government authorities to develop our gas and condensate resources and to develop the LNG Project and the Condensate Stripping Project within reasonable time periods and upon reasonable terms, which can be a costly and time consuming process.

We do not hold title to our properties in Papua New Guinea, but hold licenses granted by the Papua New Guinea government. There can be no assurance that we will be able to renew any of our licenses when they expire, or obtain additional licenses necessary to develop our properties in the future. If we do not satisfy the Papua New Guinea government that we have the financial and technical capacities necessary to operate under such licenses, or to develop and operate the LNG Project and the Condensate Stripping Project such licenses may be withdrawn, or not obtained or renewed. Additionally, our ability to renew our licenses, develop our resources and develop the LNG Project and the Condensate Stripping Project may be dependent on our ability to secure a strategic partner acceptable to the State for the development of our resources and/or our proposed LNG Project and the Condensate Stripping Project. There are no assurances that we will be able to obtain such a strategic partner on terms acceptable to us, or that the Papua New Guinea government will grant us the necessary permits and approvals to develop our gas and condensate resources or to develop the LNG Project and the Condensate Stripping Project even if such a partner is obtained. Any such negative developments with respect to our permits, licenses or other approvals from the Papua New Guinea government would have a material adverse effect on our ability to conduct our business.

Annual Information Form   INTEROIL CORPORATION   38

We may not be successful in our exploration for oil and gas.

As of December 31, 2012, we had drilled a total of eight exploration wells and a number of appraisal wells in our license areas since the inception of our exploration program. Of the exploration wells, we consider two to have been successful. We are drilling and plan to drill additional wells in Papua New Guinea during the coming years in line with our commitments under our PPLs and PRLs. We cannot be certain that the wells we drill will be productive or that we will recover all or any portion of the costs to drill these wells. Because of the high cost, topography and subsurface characteristics of the areas we are exploring, we have limited seismic or other geosciences data to assist us in identifying drilling objectives. The lack of this data makes our exploration activities more risky than would be the case if such information were readily available.

Our exploration and development plans may be curtailed, delayed or cancelled as a result of a lack of adequate capital funding and other factors, such as weather, compliance with governmental regulations, price controls, landowner interference, mechanical difficulties, shortages of materials, delays in the delivery of equipment, success or failure of activities in similar areas, current and forecasted prices for oil and natural gas and changes in the estimates of costs to complete the plans. We will continue to gather information about our exploration acreage and discoveries, and it is possible that additional information may cause us to alter our schedule or determine that an exploration program or development project should not be pursued at all. You should understand that our plans regarding our exploration programs are subject to change. We cannot assure you that our exploration activities have or will result in the discovery of any additional resources. In addition, the costs of exploration and development may materially exceed our initial estimates.

Our refinery’s financial condition may be materially adversely affected if we are unable to obtain crude feedstocks at economic rates, or if we are unable to secure sufficient working capital.

While we have a number of possible sources we employ for crude supply, and our agreement with BP currently provides for the delivery of sufficient crude feedstock, we cannot assure you that we will continue to be able to source adequate feedstock for our refinery.

Some types of crude oil that are suitable for use as refinery feedstock are available in the nearby region. However, the majority of our feedstock comes from sources outside of Papua New Guinea and our access to these crudes and to oil sourced from farther outside Papua New Guinea may be more limited as there are a limited number of crude oil sources currently available that are compatible with our refinery and economic for us to refine. The number of these alternative sources is also declining. In addition, the increased cost of oil from outside Papua New Guinea may reduce our gross profit margins and negate the operational benefits of using such oil. We can provide no assurances that we will be able to obtain all of the oil needed to operate our refinery or that we will be able to obtain the crude feedstocks that allow us to operate our refinery at profitable levels.

In addition, these same factors, as well as other factors outside our control, may affect our ability to maintain our working capital or to continue to secure adequate working capital to fund our refinery’s operations.

There is uncertainty associated with the regulated prices at which our products are sold by our refinery.

Under our Refinery Project Agreement with the State (See “Material Contracts – Refinery Project Agreement”), refined products produced by our refinery are required to be sold at a defined import parity price in order for domestic distributors in Papua New Guinea to be required to source their fuel needs from our refinery. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product that is being imported, which price is set monthly. A revised formula was established with the State during 2008 and has been in operation since such time. Our agreement with the State has not been amended formally to capture that revised formula and the formula we have been operating under may be subject to attempted change. It is possible that the State will refuse to maintain the project formula and that it may seek to reduce our refining margins.

Annual Information Form   INTEROIL CORPORATION   39

We purchase our crude at a fluctuating spot market price. A primary reason for our renegotiation of the IPP pricing formula with the State was to establish a new pricing mechanism that would correlate more closely with the movements in the price of refined products and therefore the price of crude. In the event that such pricing mechanism is not maintained there is a possibility that such misalignment between the IPP for our products and the fluctuating market price of our supply may reduce our profit or cause us to cease operating the refinery.

Our ability to recruit and retain qualified personnel may have a material adverse effect on our operating results and stock price.

Our success depends in large part on the continued services of our directors, executive officers, senior managers and other key personnel. The loss of these people, especially without sufficient advance notice, could have a material adverse impact on our business. It is also very important that we attract and retain highly skilled personnel, including technical personnel, to manage the LNG Project and associated development plans, to operate our refinery, execute our exploration plans and replace personnel who leave. Competition for qualified personnel can be intense, and there are a limited number of people with the requisite knowledge and experience, particularly in Papua New Guinea where a substantial number of our skilled personnel are required to work. Under these conditions, we could be unable to recruit, train, and retain employees. If we cannot attract and retain qualified personnel, it could have a material adverse effect on our business, operating results and stock price.

Our hedging activities may result in losses.

To reduce the risks of changes in the relative prices of our crude feedstocks and refined products, we may enter into hedging arrangements. Hedging arrangements would expose us to risk of financial loss in some circumstances, including the following:

· if the amount of refined products produced is less than expected or is not produced or sold during the planned time period;

· if the other party to the hedging contract defaults on its contract obligations; or

· if there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these hedging arrangements may limit the benefit we would receive from increases in the price of our refined products relative to the prices for our crude feedstocks.

While we believe our hedge counterparties to be strong and creditworthy, disruptions occurring in the financial markets, the European sovereign debt crisis and the downgrading of United States government debt could lead to sudden changes in a counterparty’s liquidity, which could restrict their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Our results of operations and financial condition may be adversely affected by changes in currency exchange rates.

Our results of operations and financial condition may be affected by currency exchange rates. Exchange rates may fluctuate widely in response to international political conditions, general economic conditions and other factors beyond our control. While our domestic product sales are denominated in the Papua New Guinean currency, Kina, portions of our operating costs, with respect to the purchase of crude and other imported products, and our indebtedness are denominated in US dollars. A strengthening of the US dollar versus the PGK may have the effect of increasing operating costs while a weakening of the US dollar versus the PGK may reduce operating costs. Additionally, a significant portion of our operating costs are denominated in Australian currency. Strengthening of this currency against the US dollar has the effect of increasing our operating costs. In addition, since our indebtedness needs to be paid in US dollars, a strengthening of the US dollar versus the PGK may negatively impact our ability to service our US-dollar denominated debt. Moreover, we may have additional exposure to currency exchange risk since we may not be able to convert our PGK-based revenue cash flow in a timely manner in order to meet our US-dollar denominated debt obligations.

Annual Information Form   INTEROIL CORPORATION   40

Our investments in Papua New Guinea are subject to political, legal and economic risks that could materially adversely affect their value.

Our investments in Papua New Guinea involve risks typically associated with investments in developing countries, such as uncertain political, economic, legal and tax environments; corruption; expropriation and nationalization of assets; war; renegotiation or nullification of existing contracts; taxation policies; foreign exchange restrictions; international monetary fluctuations; currency controls; and foreign governmental regulations that favor or require the awarding of service contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction.

Political conditions have at times been unstable in Papua New Guinea. We attempt to conduct our business pursuant to various agreements with the State, and pursuant to its laws, in such a manner that political and economic events of this nature will have minimal effects on our operations. We believe that hydrocarbon exploration and development, development of LNG Project and the Condensate Stripping Project and our refinery operations are in the long term best interests of Papua New Guinea. Notwithstanding current conditions, our ability to conduct operations or exploration and development activities is subject to changes in government regulations or shifts in political attitudes over which we have no control. We cannot assure you that we have adequate protection against any or all of the risks described above or that present or future administrations or government regulations in Papua New Guinea will not materially adversely affect our operations.

In addition, if a dispute arises with respect to our Papua New Guinea operations or proposed development projects, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of Canada or the United States.

Title to certain of our properties, or to properties we require for the development of the LNG Project, pipelines, common facilities and the Condensate Stripping Project, may be defective or challenged by third party landowner claims, and landowner action may impede access to or activity on those properties.

Some risk exists that title to certain of our properties may be defective or subject to challenge. In particular, our properties or properties we require in Papua New Guinea could be subject to native title or traditional landowner claims, which may deprive us of some of our property rights that consequently may have a material adverse effect on our exploration and drilling operations and our development projects. In particular, certain Special Purpose Leases have been granted in Papua New Guinea in past years which have created uncertainty for landowners and other leaseholders such as us. A Commission of Inquiry has been conducted into the grants of these Special Purpose Leases. There is no guarantee that the inquiry will be finalized by this time, that its findings will be implemented, or that it will provide certainty to us in respect of our leased and licensed rights over certain lands upon which we operate.

In addition, landowner disturbances may occur on our properties which disrupt our business in Papua New Guinea.

The implementation of new Papua New Guinean laws or the failure for permits and approvals under existing Papua New Guinean laws to be granted in a timely fashion, may have a material adverse effect on our operations, developments, and financial condition.

Our operations require licenses and permits from various governmental authorities to drill wells, develop the LNG Project, pipelines and Condensate Stripping Project, operate the refinery and market our refined products. We believe that we hold all necessary licenses and permits required under applicable laws and regulations for our existing operations in Papua New Guinea and believe we will be able to comply in all material respects with the terms of such licenses and permits based upon our current plans. However, such licenses and permits are subject to change and there can be no guarantee that we will be able to obtain or maintain all necessary licenses and permits that may be required to maintain our continued operations. Moreover, it is possible that new laws may be enacted in Papua New Guinea (such as a limitation on foreign ownership of local assets) that may have a material adverse effect on our operations and financial condition.

Annual Information Form   INTEROIL CORPORATION   41

Additional licenses and permits will be required to allow us to develop our Elk, Antelope and Triceratops discoveries, the LNG Project, pipelines and the Condensate Stripping Project. There can be no guarantee that we will be able to obtain such licenses and permits in a timely fashion or at all.

We are subject to extensive laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures and the characteristics and composition of gasoline and diesel fuels. If we violate or fail to comply with these laws and regulations, we could be fined or otherwise sanctioned. Because environmental laws or regulations are increasingly becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, environmental [emissions] laws and permits may be an obstacle to the development of the LNG Project and the Condensate Stripping Project, while any major upgrades to our refinery could require material additional expenditures to comply with environmental laws and regulations.

Our refinery has not operated at full capacity since commencing operations and our profitability may be materially negatively affected if it continues not to do so.

Our refinery has never operated at full capacity for a full fiscal year, as our supplying all of Papua New Guinea’s domestic needs does not require us to operate at such capacity. In addition, our ability to operate our refinery at its rated capacity must be considered in light of the risks inherent in the operation of, and the difficulties, costs, complications and delays we face as the operator of, a relatively small refinery. These risks include, without limitation, shortages and delays in the delivery of crude feedstocks or equipment; contractual disagreements; labor shortages or disruptions; difficulties marketing our refined products; parallel importation of refined products, political events; accidents; and unforeseen engineering, design or environmental problems. We have been periodically unable to operate the catalytic reformer unit contained in our refinery which is necessary for us to produce gasoline. If we cannot produce gasoline we must import it for our downstream operations. If these risks prevent us from operating at full capacity in the future, our profitability may be negatively affected.

The Refinery Project Agreement gives us certain rights to supply refined products to the domestic market in Papua New Guinea. Although we operate the only domestic petroleum refinery in Papua New Guinea, not all domestic demand was sourced from our refinery during 2012, and we believe some competing product has been imported and sold in Papua New Guinea, which we believe, is in contravention of our rights.

Our refinery is rated to process up to 36,500 barrels of oil per day. We are able to fulfill the domestic market in Papua New Guinea’s demand for our products by refining approximately 24,000 barrels of crude oil per day. We are currently operating the refinery at less than full capacity due to an inability to profitably export our refined products and as a result of competing imports of finished products. Therefore, in order to process these additional barrels of crude feedstock, we must identify markets into which we can sell our products profitably. The operating margins currently needed for our refinery to sell refined products profitably and the cost and availability of obtaining tankers to export our refined products limit our ability to export our refined products from Papua New Guinea. In addition, under our current refinery configuration we are unable to export diesel and gasoline to Australia due to Australian regulations regarding permitted sulfur and benzene content that our refined products currently do not meet.

In addition, the Refinery Project Agreement does not provide us with an exclusive right to supply the domestic market in Papua New Guinea. Therefore, if one or more additional refineries are built in Papua New Guinea, our share of the domestic market will be diminished.

The exploration and production, refining and distribution businesses are competitive.

We operate in the highly competitive areas of hydrocarbon exploration and production, refining and distribution of refined products. A number of our competitors have materially greater financial and other resources than we possess. Such competitors have a greater ability to bear the economic risks inherent in all phases of the industry.

In our exploration and production business, we compete for the purchase of licenses from the State and the purchase of leases from other oil and gas companies. Factors that affect our ability to compete in the marketplace include:

· Our access to the capital necessary to drill wells and undertake other exploration activities necessary to retain our exploration licenses or PPLs, PRLs and to acquire additional properties;

Annual Information Form   INTEROIL CORPORATION   42

· Our ability to acquire and analyze seismic, geological and other information relating to a property;

· Our ability to retain and hire the personnel necessary to properly evaluate seismic and other information relating to a property;

· Our ability to contract for or otherwise obtain drilling equipment;

· The development of, and our ability to access, transportation systems to bring future production to the market, and the costs of such transportation systems; and

· The standards we establish for the minimum projected return on an investment of our capital.

We also compete with other oil and gas companies in Papua New Guinea for the labor and equipment needed to carry out our exploration operations and assist us with development projects. Many of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for oil and gas prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties, and to consummate transactions in this highly competitive environment. In addition, most of our competitors have been operating in the oil and gas business for a much longer time than us and have demonstrated the ability to operate through industry cycles.

In our refining business, we compete with several companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. Many of our competitors obtain a significant portion of their feedstocks from company-owned production, which may enable them to obtain feedstocks at a lower cost. In periods of constrained supply, we will have to compete on the open market for supply which may not be readily available. The high cost of transporting goods to and from Papua New Guinea reduces the availability of alternate fuel sources and retail outlets for our refined products. Competitors that have their own production or extensive distribution networks are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, new technology is making refining more efficient, which could lead to lower prices and reduced margins. We cannot be certain that we will be able to implement new technologies in a timely basis or at a cost that is acceptable to us.

The LNG Project faces competition, including competing liquefaction facilities and related infrastructure, from competitors with far greater resources, including major international energy companies. Many competing companies have secured access to, or are pursuing development or acquisition of, liquefaction facilities to serve the same markets we intend to target. In addition, competitors have developed or reopened additional liquefaction facilities in other international markets, which may also compete with the LNG Project. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to natural gas and LNG supplies than we do. The superior resources that these competitors have available for deployment could allow them to compete successfully against our LNG businesses, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Our downstream competitors have progressively increased their direct importation of refined petroleum products rather than sourcing such products from our refinery.

During 2012, our competitors have imported refined petroleum products directly rather than sourcing such products from our refinery. We believe that at least some of this competing product has been imported and distributed in Papua New Guinea in contravention of our legal rights. Our competitors’ importation has had a negative effect on our business, if it continues or increases, could materially affect our results from operations.

If our refining margins do not meet our expectations, we may be required to write down the value of our refinery.

The determination of our refinery’s fair market value is highly dependent upon the difference between the sale price we receive for refined products that we produce and the cost of the crude feedstocks used to produce those refined products. This difference is commonly referred to as refining margin. Volatile market conditions beyond our control could cause our refining margins and resulting cash flows to fall below expectations for extended periods. Should this occur, the refinery will become impaired and we will be required to write down the carrying value of our refinery on our balance sheet. Any significant write down of the value of our refinery could result in our failure to meet the financial covenants under our outstanding loan agreements.

Annual Information Form   INTEROIL CORPORATION   43

The prices we receive for the refined products we produce and sell are likely to continue to be subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and a variety of additional factors beyond our control. These factors include, but are not limited to, the condition of the worldwide economy, including the European sovereign debt crisis and the downgrading of United States government debt, and the demand for and supply of oil, the actions of the Organization of Petroleum Exporting Countries, governmental regulations, political stability in the Middle East and elsewhere, and the availability of alternate fuel sources. Oil and gas markets are both seasonal and cyclical. The prices for oil will affect:

· Our revenues, cash flows and earnings;

· Our ability to attract capital to finance our operations, and the cost of such capital;

· The value of our oil and gas properties;

· The profit or loss we incur in refining petroleum products; and

· The profit or loss we incur in exploring for and developing reserves.

There are inherent limitations in all control systems, and misstatements due to error that could seriously harm our business may occur and not be detected.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of its financial reporting and the preparation of financial statements for external purposes. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with required regulations and guidelines, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

A control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Changes to our internal controls, such as our implementation of a new enterprise resource and planning system in 2010 and 2011, may enhance the likelihood of the occurrence of these events. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our operations expose us to risks, not all of which are insured.

Our operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards and uncontrollable flows of hydrocarbons and refined products. In addition, these operations are subject to hazards of loss from earthquakes, tsunamis and severe weather conditions. As protection against operating hazards, we maintain insurance coverage against some, but not all of such potential losses. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, losses may exceed coverage limits. As a result of market conditions, premiums and deductibles for certain types of insurance policies for refiners have increased substantially and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers now require broad exclusions for losses due to risk of war and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Annual Information Form   INTEROIL CORPORATION   44

Third parties may default on their contractual obligations.

In the normal course of our business, we have entered into contractual arrangements with third parties which subject us to the risk that such parties may default on their obligations. We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, lenders, customers and other parties. In the event such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on us and our cash flow from operations.

Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.

Certain of our borrowings are at variable rates of interest and expose us to interest rate risk and we may in the future borrow additional money at variable rates. This exposes us to interest rate risk if interest rates increase, as our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed would remain the same, and our net income would decrease. A 1% change in interest rates in 2013 would have resulted in a $821,268 reduction in profit.

Weather and unforeseen operating hazards may adversely impact our operating activities.

Our operations are subject to risks inherent in the oil and gas industry, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, equipment failures including damages to our wharf facilities, pollution, and other environmental risks. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. Our Papua New Guinea operations are subject to a variety of additional operating risks such as earthquakes, mudslides, tsunamis, cyclones and other effects associated with active volcanoes, extensive rainfall or other adverse weather conditions. Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on our financial condition and results of operations.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations have the potential to be adversely affected. Potential adverse effects could include (i) damages to our facilities from powerful winds or rising waters in low-lying areas, (ii) disruption of our production activities either because of climate-related damage to our facilities [or because of increases in in our costs of operation potentially arising from such climatic effects due to less efficient or non-routine operating practices necessitated by climate effects or (iii) increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Compliance with environmental and other government regulations could be costly and could negatively impact our business.

The laws and regulations of Papua New Guinea regulate our current business.  Our operations could result in liability for personal injuries, property damage, natural resource damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages.  Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and the issuance of orders enjoining operations.  In addition, we could be liable for environmental damage caused by, among others things, previous property owners or operators.  We could also be affected by more stringent laws and regulations adopted in the future, including those related to climate change and greenhouse gases, resulting in increased operating costs.  As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could have a material adverse effect on our financial condition, results of operations and liquidity. Additionally, more stringent greenhouse gas regulation could diminish demand for oil and gas.

Annual Information Form   INTEROIL CORPORATION   45

These laws and governmental regulations, which cover matters including drilling, refining, liquefaction and gas stripping operations, and environmental protection, may be changed from time to time in response to economic or political conditions and could have a significant negative effect on our operating costs.  While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations, we cannot assure you that we will be able to continue to comply with such environmental laws and regulations without incurring substantial costs.

Our debt levels and debt covenants and other factors may limit our future flexibility in obtaining additional financing.

As at December 31, 2012, we had a total of $112.857 million in long-term debt with $100 million from the Syndicated Term Loan Facility which matures in 2017 and $12.857 million from Westpac Bank PNG which matures in 2015, together with principal repayments due during 2013 totaling $20.286 million. We also operate significant working capital facilities with BNP Paribas, Bank of South Pacific Limited and Westpac Banking PNG Limited, in the amounts of $240.0 million, $23.0 million and $42.0 million, respectively, for our midstream and downstream refining businesses, and have $70.0 million principal amount of 2.75% senior convertible notes due 2015 on issue. The level of our indebtedness will have important effects on our future operations, including:

· A portion of our cash flow will be used to pay interest and principal on our debt and will not be available for other purposes;

· Our loan agreements and facilities contain financial tests which we must satisfy in order to avoid a default under such credit facilities; and

· Our ability to obtain additional financing for capital expenditures and other purposes may be limited.

Substantial capital, which may not be available to us in the future, is required for us to complete our business plans.

We make, and will continue to make, substantial capital expenditures for exploration, development, acquisition and production of oil and gas reserves, our proposed liquefaction facilities and other infrastructure associated with that proposed LNG Project, our Condensate Stripping Project, refinery expansions and improvements, acquisitions of distribution assets, and for further capital acquisitions and expenses. We will need additional financing to complete our business plans. If we are unable to obtain debt or equity financing because of lower operating returns, lower oil or gas prices, delays, operating difficulties, construction costs, lack of drilling success, the status of global financial and credit markets, or other reasons, we may not have the ability to expend the capital necessary to undertake or complete future drilling programs, fund development activities and to make other needed capital expenditures. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

We may be party to lawsuits and other proceedings which may adversely affect our financial position or ability to pursue our business.

We may be party to lawsuits and other proceedings that arise in the future. There is a risk that we will not be successful with respect to the legal actions to which we are a party, which could have a material adverse effect on our consolidated financial position, results of operations or cash flows, or in our ability to pursue our business strategy.

You may be unable to enforce your legal rights against us.

We are a Yukon Territory, Canada Corporation. Substantially all of our assets are located outside of Canada and the United States. It may be difficult for investors to enforce, outside of Canada and the United States, judgments against us that are obtained in Canada or the United States in any such actions, including actions predicated upon the civil liability provisions of the securities laws of Canada and the United States. In addition, many of our directors and officers are nationals or residents of countries outside of Canada and the United States, and all, or a substantial portion of, the assets of such persons are located outside of Canada and the United States. As a result, it may be difficult for investors to affect service of process within Canada or the United States upon such persons or to enforce judgments against them obtained in Canadian or United States courts, including judgments predicated upon the civil liability provisions of the securities laws of Canada or the United States.

Annual Information Form   INTEROIL CORPORATION   46

Future sales of our common shares may adversely affect the price of our Shares.

We believe that substantially all of our common shares currently outstanding, and common shares issued in the future upon the exercise of outstanding options, vesting of restricted stock units and upon conversion of the IPI percentage interest, will be freely tradable under the US federal securities laws, subject to certain limitations. These limitations include vesting provisions in option and restricted stock unit agreements and volume and manner-of-sale restrictions under Rule 144 of the US Securities Act. Any sale of a substantial number of our common shares into the public market, or the perception that such sales could occur, could adversely affect the prevailing market price of our common shares.

We have never declared or paid dividends on our common shares and we do not anticipate paying dividends in the foreseeable future.

We have never paid cash dividends on our common shares, and we do not anticipate paying any cash dividends on our common shares in the foreseeable future. We currently plan to invest all available funds and future earnings into the operation and growth of our business. Our ability to make dividend payments in the future will depend on our future performance and liquidity.

DIVIDENDS

To date we have not paid dividends on our common shares and currently reinvest all cash flows from operations for the future operation and development of our business. No change to this policy or approach is intended or under consideration at the present date. There are no restrictions which prevent us from paying dividends on our common shares. Any decision to pay dividends on our common shares in the future depend upon our earnings and financial position (including the effect on financial ratios and covenants with our lenders) and such other factors as the Board may consider appropriate in the circumstances.

DESCRIPTION OF CAPITAL STRUCTURE

InterOil is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, issuable in series, of which 1,035,554 series A preferred shares are authorized. As at December 31, 2012, 48,607,398 common shares were issued and outstanding. All of the series A preferred shares that had been issued were converted into common shares during 2008 and none remain outstanding as at December 31, 2012. We also have outstanding $70.0 million principal amount of 2.75% convertible senior notes due 2015.

Common Shares

Holders of common shares are entitled to one vote per share held at any meeting of our shareholders, to receive, out of all profits or surplus available for dividends, any dividends declared by us on the common shares, and to receive our remaining property in the event of our liquidation, dissolution or winding up, whether voluntary or involuntary.

Preferred Shares

Preferred shares may at any time and from time to time be issued in one or more series, each series to consist of such number of shares as may, before the issue thereof, be determined by unanimous resolution of our directors. Subject to the provisions of the YBCA, the Board may by unanimous resolution fix from time to time, before the issue thereof, the designation, rights, privileges, restrictions and conditions attaching to each series of the preferred shares.

2.75% Convertible Senior Notes

We currently have outstanding $70.0 million principal amount of 2.75% convertible senior notes due November 2015. The convertible notes are unsecured and unsubordinated obligations of InterOil Corporation. The convertible notes rank junior to any secured indebtedness and to all existing and future liabilities of our subsidiaries, including the BNP Paribas working capital facility, the Syndicated Term Loan facility, the Mitsui preliminary financing agreement, trade payables and lease obligations.

Annual Information Form   INTEROIL CORPORATION   47

We pay interest semi-annually on May 15 and November 15. The notes are convertible into cash or common shares, based on an initial conversion rate of 10.4575 common shares per $1,000 principal amount, which represents an initial conversion price of approximately $95.625 per common share. The initial conversion price is subject to standard anti-dilution provisions designed to maintain the value of the conversion option in the event we take certain actions with respect to our common shares, such as stock splits, reverse stock splits, stock dividends and cash dividends, that affect all of the holders of our common shares equally and that could have a dilutive effect on the value of the conversion rights of the holders of the notes or that confer a benefit upon our current shareholders not otherwise available to the convertible notes. Upon conversion, holders will receive cash, common shares or a combination thereof, at our option. The convertible notes are redeemable at our option if our share price has been at least 125% ($119.53 per share) of the conversion price for at least 15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change of control, holders may require us to repurchase their convertible notes for cash at a purchase price equal to the principal amount of the notes to be repurchased, plus accrued and unpaid interest.

Shareholder Rights Plan

On May 27, 2007, we adopted a rights plan which was approved by our shareholders at the June 25, 2007 annual and special meeting of shareholders. The rights plan was re-confirmed with certain minor amendments by our shareholders at the June 22, 2010 annual and special meeting of shareholders. The rights plan was adopted to ensure, to the extent possible, that all shareholders of the Company are treated fairly in connection with any take-over bid for us. As long as a bid meets certain requirements intended to protect the interests of all shareholders, the provisions of the rights plan will not be invoked. Under the provisions of the rights plan, one right has been issued for each common share of InterOil outstanding. The rights will trade together with the common shares and will not be separable from the common shares or exercisable unless a take-over bid is made which is not a permitted bid. The rights entitle shareholders, other than shareholders making the take-over bid, to purchase additional common shares at a substantial discount to the market price at the time. Phil Mulacek, our Chief Executive Officer, holds a large proportion of our common shares of InterOil and, subject to certain grandfather provisions in the rights plan, his shareholdings will not trigger its operation.

The rights plan is similar to those adopted by other Canadian listed companies. A copy of the rights plan is available under the Company's SEDAR profile at www.sedar.com.

Options

Our 2009 Stock Incentive Plan, authorised by our shareholders at the annual and special meeting held on June 19, 2009, that allows employees to acquire our common shares. Option exercise prices are governed by the plan rules and equal the market price for the common shares on the date the options were granted. Options granted under the plan are generally fully exercisable after one year or more and expire five years after the grant date, although some have shorter vesting periods. Default provisions in the plan rules provide for immediate vesting of granted options and expiry ten years after the grant date. Some options granted under a predecessor plan approved in 2006 also remain in effect. No further grants may now be made under this superseded 2006 plan.

As of December 31, 2012, there were options outstanding to purchase 1,066,067 common shares pursuant to our stock incentive plans.

Restricted Stock Units

In addition to the options noted above, our 2009 Stock Incentive Plan also allows employees to acquire our common shares pursuant to restricted stock unit grants. As of December 31, 2012, restricted stock units entitling employees rights to 153,484 common shares were outstanding pursuant to our stock incentive plans. The restricted stock units provided those employees with the right to receive common shares on a one-for-one basis on certain vesting dates. Vesting dates generally occur one, two and/or more years after grant.

Annual Information Form   INTEROIL CORPORATION   48

Other instruments Convertible into or Exchangeable for Common Shares

We have granted IPI holders (see “Material Contracts – Amended and Restated Indirect Participation Interest Agreement dated February 25, 2005”) the right to convert their interests under the IPI Agreement into a certain number of our common shares. Certain investors under that agreement have waived their conversion right. At December 31, 2012, IPI holders held rights to convert up to 140,480 common shares remained.

MARKET FOR OUR SECURITIES

Our common shares are listed and posted for trading on the New York Stock Exchange under the symbol IOC. We are also listed on the Port Moresby Stock Exchange under the symbol IOC in Papua New Guinea. The following table discloses the monthly high and low trading prices and volumes of our common shares as traded on the New York Stock Exchange during 2012:

New York Stock Exchange (NYSE:IOC) in United States Dollars
Month	High		Low		Volume		Close
January		70.00		51.55		13,208,234		67.10
February		75.87		58.84		15,212,172		60.10
March		62.75		47.02		17,949,188		51.41
April		61.98		49.01		17,564,908		60.44
May		67.24		47.33		14,766,262		66.41
June		74.70		57.58		13,502,935		69.70
July		88.58		68.18		11,357,271		85.64
August		91.88		75.37		16,821,888		79.54
September		99.05		73.12		17,461,682		77.26
October		79.88		63.15		13,731,078		64.48
November		67.95		53.65		16,616,498		55.66
December		61.38		50.90		14,180,155		55.53
Total		75.11		57.98		182,372,271		66.11

Prior sales

· 411,760 common shares were issued during 2012 upon the exercise of stock options by employees, officers or directors at various prices defined by the option grant terms in accordance with our stock incentive plans.

· 74,567 common shares were issued during 2012 upon the vesting of restricted stock units granted to employees, officers or directors defined by the restricted stock unit grant terms in accordance with our stock incentive plans.

Annual Information Form   INTEROIL CORPORATION   49

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides information with respect to all of our directors and executive officers:

Directors and Executive Officers
Name, Address	Position with InterOil	Date of Appointment
Gaylen Byker Michigan, USA	Chairman (1)	May 29, 1997
Phil E. Mulacek Texas, USA	Director and Chief Executive Officer(2)	May 29, 1997
Christian Vinson Port Moresby, Papua New Guinea	Vice President Corporate Development and Government Affairs, Director	May 29, 1997
Roger Grundy Derbyshire, UK	Director(3)	May 29, 1997
Roger F. Lewis Western Australia, Australia	Director(4)	November 26, 2008
Ford Nicholson British Columbia, Canada	Director(5)	June 22, 2010
Sir Rabbie Namaliu Port Moresby, Papua New Guinea	Director(6)	July 2, 2012
Samuel L. Delcamp California, USA	Director(7)	July 2, 2012
William J. Jasper III Texas, USA	President and Chief Operating Officer	September 18, 2006
Collin Visaggio Western Australia, Australia	Chief Financial Officer	October 26, 2006
Geoff Applegate Singapore	General Counsel and Corporate Secretary	December 1, 2012

Annual Information Form   INTEROIL CORPORATION   50

Notes:

(1) Gaylen Byker assumed the role of Chairman of the Board in July, 2012. Gaylen acts as Chairman of each of the Board’s Nominating and Governance Committee and Compensation Committee and has held such positions throughout 2012. He is a member of the Audit Committee and of the Reserves Committee.

(2) Phil Mulacek continues as Chief Executive Officer.

(3) Roger Grundy was Chairman of the Reserves Committee throughout 2012 and as of the date of this AIF.

(4) Roger Lewis was Chairman of the Audit Committee, and a member of the Nominating and Governance Committee and Compensation Committee throughout 2012.

(5) Ford Nicholson was a member of the Audit Committee until August 13, 2012 and was then replaced by Mr. Samuel L. Delcamp, and of the Reserves Committee throughout 2012 and as of the date of this AIF.

(6) Sir Rabbie was appointed on July 2, 2012 and remains as a director as of the date of this AIF.

(7) Samuel Delcamp was appointed as a Director on July 2, 2012 and remains as a director as of the date of this AIF. He was appointed to the Audit Committee on August 13, 2012.

Certain information has been furnished by our directors and executive officers. Such information includes information as to our common shares in the Company beneficially owned, controlled or directed, directly or indirectly, by them, their places of residence and principal occupations, both present and historical, interests in material transactions and potential conflicts of interest.

The term of office of each of our directors will expire at the next annual meeting of our shareholders. All executive officers generally hold office at the pleasure of the Board.

As of February 27, 2013, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly 5,030,873 common shares, representing 10.35% of our outstanding issued common shares. In addition to the common shares beneficially owned or controlled or directed, directly or indirectly, by our directors and executive officers, 654,784 shares are issuable upon exercise of outstanding options and restricted stock units, resulting in directors and executive officers holding 11.70% of our issued common shares on a diluted basis.

Our Board has established an Audit Committee, a Compensation Committee, and a Nominating and Governance Committee. Dr. Byker and Mr. Lewis are members of each of these committees while Mr. Delcamp is an additional member of the Audit Committee. Mr. Lewis chairs the Audit Committee while Dr. Byker is the Chairman of each of the other two committees. In addition, the Board has established a Reserves Committee. Mr. Grundy is Chairman of this committee and Mr. Nicholson and Dr. Byker are additional members.

The following is a brief description of the background and principal occupations of each director and executive officer at present and during the preceding five years:

Phil E. Mulacek is our Chief Executive Officer and until July, 2, 2012 also held the position of Chairman of the Board of Directors, which he had held since our inception. Mr. Mulacek is the founder and President of Petroleum Independent & Exploration Corporation based in Houston, Texas. Petroleum Independent & Exploration Corporation was established in 1981 for the purposes of oil and gas exploration, drilling and production, and operated across the southwest portion of the United States. Petroleum Independent & Exploration Corporation led the development of our refinery and the commercial activities that were necessary to secure the refinery's economic viability. Mr. Mulacek has over 25 years experience in oil and gas exploration and production and holds a Bachelor of Science degree in petroleum engineering from Texas Tech University.

Christian M. Vinson is our Executive Vice President responsible for Corporate Development & Government Affairs. From 1995 to August 2006, he was our Chief Operating Officer. Mr. Vinson joined us from Petroleum Independent Exploration Corporation, a Houston, Texas based oil and gas exploration and production company. Before joining us, Mr. Vinson was a manager with NUM Corporation, a Schneider company involved in mechanical and electrical engineering automation, in Naperville, Illinois where he established of the company’s first office in the United States. Mr. Vinson earned an Electrical and Mechanical Engineering degree from Ecole d’Electricité et Mécanique Industrielles, Paris, France.

Gaylen J. Byker is the Chairman of our Board of Directors. He was formerly President of Calvin College, a liberal arts institution of higher learning, located in Grand Rapids, Michigan. He is also a director and chairman of the Finance and Audit Committee of Priority Health, Inc, an entity regulated by the State of Michigan Office of Financial and Insurance Services. Dr. Byker has obtained four university degrees including a PhD in international relations from the University of Pennsylvania and a Doctorate of Jurisprudence from the University of Michigan. Dr. Byker is a former partner of Offshore Energy Development Corporation (“OEDC”) where he was head of development, hedging and project finance for gas exploration and transportation projects offshore. Prior to joining OEDC, he was co-head of commodity derivatives at Phibro Energy, Inc., a subsidiary of Salomon, Inc. and head of the commodity-indexed transactions group at Banque Paribas, New York, with worldwide responsibility for hedging and financing transactions utilizing long-term commodity price risk management. Dr. Byker was manager of commodity-indexed swaps and financings for Chase Manhattan Investment Bank, New York, and was also a lawyer at Morgan, Lewis & Bockius in Philadelphia, Pennsylvania, U.S.

Annual Information Form   INTEROIL CORPORATION   51

Roger N. Grundy is the Managing Director of Breckland Ltd, a UK-based engineering consulting firm, and is an internationally recognized expert in the area of refinery efficiency. Mr. Grundy has acted as a consultant to more than 200 existing refineries on six continents for major oil companies, independents and various banks. Mr. Grundy has 40 years experience in all areas of oil refinery and petrochemical operations and construction and holds an Honors Degree in Mechanical Engineering from University College, London. He is also a Fellow of the UK Institute of Mechanical Engineers, a member of the American Institute of Chemical Engineers and a member of the Energy Institute.

Roger F. Lewis is an Australian and a former senior finance executive, having spent 22 years with Woodside Energy Ltd in Western Australia, finishing as Group Financial Controller. Prior to that he worked in commercial and finance roles for over 15 years in the heavy manufacturing industry both in Australia and overseas. He is a Fellow Certified Practicing Accountant (FCPA) with the Australian Society of Certified Practicing Accountants. Mr Lewis was a Commissioner of the Lottery Commission of Western Australia until his retirement in 2011, with particular responsibility for finance and accounting matters and as a member of the Commission’s Audit and Major Projects committees.

Ford Nicholson is the President of Kepis & Pobe Financial Group which specializes in developing international energy and other natural resource assets. Over the past 25 years Mr. Nicholson has provided executive management to several international projects. He was a co-founder and Director of Nations Energy Ltd. producing heavy oil in Kazakhstan and a founding shareholder and former board member of Bankers Petroleum Ltd. producing heavy oil in Albania. Mr. Nicholson was also a board member of Tartan Energy Inc, a heavy oil company based in California. Mr. Nicholson is currently the chairman of TSX listed BNK Petroleum Inc. producing and exploring for unconventional natural gas in Europe and the USA. Ford is also on the President's council of the International Crisis Group. Mr. Nicholson resides in British Columbia, Canada.

Sir Rabbie Namaliu is a Papua New Guinean citizen and served as Prime Minister of Papua New Guinea from 1988 until 1992. Sir Rabbie served as Speaker of the National Parliament between 1994 and 1997. Prior to this, Sir Rabbie was Minister for Foreign Affairs and Trade from 1982 until 1984 and has held several other senior government posts since his first election to parliament in 1982. An independent Non-Executive Director of Perth-based Marengo Mining Limited, Sir Rabbie has also been Chairman of the Board of Directors of the publicly listed investment firm Kina Asset Management Ltd since 2008. He is also a member of the PNG Institute of Directors. Sir Rabbie chaired our PNG Advisory Committee from August 2011 until June 30, 2012 and was appointed to the Board on July 2, 2012.

Samuel L. Delcamp is an American Citizen and has more than 40 years of investment experience. He served as Executive Director and Chief Investment Officer of The Fuller Foundation, a public charity, for 24 years. Mr. Delcamp was instrumental in founding the organization and overseeing the growth in its assets under management from $4 million to more than $600 million. Mr. Delcamp has additionally served as Director and President of MBM Partners, Inc., an unregistered investment advisor. Mr. Delcamp was appointed to the Board on July 2, 2012.

William J. Jasper III is our President and Chief Operating Officer. Mr. Jasper joined us on September 18, 2006 and leads the refining and downstream businesses. Prior to joining us, Mr. Jasper had worked for Chevron Pipe Line Company since 1974, serving in leadership and management capacities over facilities, pipelines and terminals. Mr. Jasper has an extensive background in operations and maintenance. Prior to this role Mr. Jasper had served four years as Chairman of the West Texas LPG Partnership Board of Directors. Mr. Jasper also held positions as President and General Manager of Kenai Pipe Line Company in Alaska, and of West Texas Gulf Pipeline in Texas.

Collin F. Visaggio is our Chief Financial Officer. Mr. Visaggio joined us in a consulting capacity on July 17, 2006 and was appointed as Chief Financial Officer on October 26, 2006. He is a Certified Practicing Accountant with a Master’s Degree in Business. He has also attended the Stanford Senior Executive Program in management. Mr. Visaggio has 24 years of experience in senior financial and business positions within Woodside Petroleum and BP Australia. His career has given him a broad spectrum of financial and business experience in Exploration, Offshore Oil and Gas Development and Production, Oil Refining, LNG and Domestic Gas. Mr. Visaggio was at Woodside Petroleum from March 1988 until July 2005, with his final position being Manager, Compliance and Business for the Africa Business Unit, and prior position as Manager, Commercial and Planning for the Gas Business Unit. His responsibilities included the administration and management of the business unit, financial and business processes, and governance. Prior to this and during his 17 years with Woodside, he was Deputy Chief Financial Officer, Financial Analyst and Planning Manager within the corporate finance group. Prior to joining us, Mr. Visaggio was Chief Financial Officer for Alocit Group Ltd from July 2005 until March 2006. He also served on the board of Santa Maria Ladies College from 2004 to March 2010, including as chairman for four of those years.

Annual Information Form   INTEROIL CORPORATION   52

Geoff Applegate was appointed as General Counsel and Corporate Secretary in December 1, 2012. Prior to joining us, Geoff was a Special Counsel and Partner with Gadens Lawyers of Sydney and Port Moresby for 17 years. He has been a corporate and commercial lawyer in private practice for more than 40 years, with extensive experience in resource development and oil and gas law. Geoff practiced law in Papua New Guinea for over 13 years and holds a B.A. / L.L.B. Degree from Sydney University. 

Conflicts of Interest

There are potential conflicts of interest to which some of our directors and officers will be subject in connection with our operations.  Situations may arise where some of the business activities of the directors and officers will be in direct competition with us. In particular, certain of our directors and officers will be in managerial or director positions with other oil and gas companies, whose operations may, from time to time, be in direct competition with us or entities which may, from time to time, provide financing to us, or make equity investments in our competitors.  In addition, certain of the directors have on-going relationships with other entities in respect of which we have entered or may enter into material agreements or have a business relationship. These relationships may create a real or perceived conflict of interest.

Conflicts, if any, will be subject to the procedures and remedies in the YBCA.  The YBCA provides that a director or officer shall disclose the nature and extent of any interest that he or she has in a material contract or material transaction, whether made or proposed, if the director or officer: is a party to the contract or transaction,  is a director or an officer, or an individual acting in a similar capacity, of a party to the contract or transaction, or has a material interest in a party to the contract or transaction, and shall refrain from voting on any matter in respect of such contract or transaction unless otherwise provided under the YBCA. We intend to resolve all conflicts of interest in accordance with the provisions of the YBCA.

Relationships and interests which have been disclosed as potentially giving rise to conflicts of interest include:

· Mr. Grundy is a principal of Breckland Limited, which has provided technical engineering advisory services to us on customary commercial terms.

See also under the heading “Interests of Management and Others in Material Transactions”.

AUDIT COMMITTEE

Charter of the Audit Committee

The full text of the Charter of the Audit Committee is attached as Schedule C to this Annual Information Form. The Charter was reviewed and revised during 2012.

Composition of the Audit Committee

The current members of the Audit Committee are Mr. Roger Lewis, Dr. Gaylen Byker and Mr. Samuel Delcamp. Mr. Lewis and Dr. Byker held their positions throughout 2012. Mr. Ford Nicholson was rotated out of his role as an Audit Committee member and replaced by Mr. Samuel Delcamp on August 13, 2012. All Audit Committee members are independent and financially literate within the meaning of NI 52-110.

Relevant Education and Experience

The relevant education and experience of the current members of the Audit Committee is set out in detail under the heading “Directors and Executive Officers”:

Annual Information Form   INTEROIL CORPORATION   53

This education and experience is such that each member has an understanding of the accounting principles used by us to prepare our financial statements; the ability to assess the general application of such accounting principles in connection with the accounting for estimates, accruals and reserves; experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues raised by our financial statements, or experience actively supervising one or more individuals engaged in such activities; and an understanding of internal controls and procedures for financial reporting.

Pre-Approval Policies and Procedures

The Audit Committee is authorized and required by the Board to review, discuss and pre-approve non-audit services to be performed by the external auditors, save where such services are subject to the de-minimis exceptions described in the U.S. Securities Exchange Act of 1934. In the event that non-audited services are required, a documented scope and estimate are submitted by the Company’s auditors to the Chairman of the Audit Committee who will consult with other committee members, as necessary, before providing any approval on the Audit Committee’s behalf.

External Auditor Service Fees

PricewaterhouseCoopers, Chartered Accountants, have served as our auditors since June 6, 2005. The following table sets forth the Audit Fees, Audit – Related Fees, Tax Fees and All Other Fees billed by PricewaterhouseCoopers in each of the last two financial years.

PricewaterhouseCoopers
	2012		2011
Audit Fees1	$	1,479,850	$	1,576,187
Tax Fees2	$	453,838	$	542,904
All Other Fees3	$	86,584	$	53,936
Total	$	2,020,272	$	2,173,027

Notes:

1. "Audit Fees" means the aggregate fees billed by the issuer's external auditor in each of the last two fiscal years for audit fees

2. "Tax Fees" means the aggregate fees billed in each of the last two fiscal years for professional services rendered by the issuer's external auditor for tax compliance, tax advice, and tax planning.

3. "All Other Fees" means the aggregate fees billed in each of the last two fiscal years for products and services provided by the issuer's external auditor, other than the services reported as Audit Fees, Audit-Related Fees and Tax Fees above and principally relate to the unaudited quarterly reporting of our subsidiaries.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

From time to time we are involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in our favor, we do not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on our financial position, results of operations or liquidity.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Breckland Limited has provided technical and advisory services to us on customary commercial terms. Roger Grundy, one of our directors, is a director and principal of Breckland and he has provided consulting services to us. Breckland was paid $21,293 in respect of consulting fees and expenses during 2010. No payments for consulting services were made to Breckland Limited in 2009, 2011 or 2012.

See also under the heading “Directors and Executive Officers – Conflicts of Interest”.

Annual Information Form   INTEROIL CORPORATION   54

Other than as discussed above, there are no material interests, direct or indirect, of directors, executive officers of the Company or any person or company that beneficially owns or controls or directs, directly or indirectly, more than 10% of the outstanding common shares, or any known associate or affiliate of any such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect the Company.

MATERIAL CONTRACTS

The following represent material contracts entered into or still in effect during 2012:

Condensate Stripping Plant JVOA dated August 4, 2010

The CSP JV between Mitsui and certain of our subsidiaries sets out their rights and obligations as participants in the joint venture to develop a proposed condensate stripping plant at our Elk and Antelope field site in Gulf Province, Papua New Guinea. Under the CSP JV, we and Mitsui will each have a 50% ownership interest in the proposed plant, before the State of Papua New Guinea’s statutory right to acquire up to 22.5%. The CSP JV provides for the ownership in and management of, the joint venture for the development and operation of the condensate stripping facility, both before and after a FID is taken.

Indenture Governing the 2.75% Convertible Senior Notes Due 2015 dated November 10, 2010

The $70.0 million principal amount of 2.75% convertible senior notes due 2015 were issued on November 10, 2010 pursuant to an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee, dated as of August 6, 2008, as supplemented by the first supplemental indenture, dated as of November 10, 2010. We refer to the indenture as so supplemented as the “Note Indenture”.

For a summary of the material terms of the convertible senior notes due 2015, see “Description of Capital Structure – Convertible Senior Notes Due 2015”.

LNG Project Shareholders Agreement dated July 30, 2007

The shareholders’ agreement dated July 30, 2007 by and between InterOil LNG Holdings Inc., Merrill Lynch PNG LNG Corporation (“Merrill Lynch”) and Pac LNG (the “Shareholders”) provided for the establishment and governance of PNG LNG with respect to the LNG Project described in more detail under the heading “Description of the Business – Midstream - Liquefaction”. The agreement sets out the rights and obligations of the Shareholders and the terms governing their relationship and provides that the authorized share capital structure of PNG LNG is to be made up of Class A Shares and Class B Shares. No other classes of shares may be issued. Only holders of Class A Shares have voting rights and the right to appoint directors to the board of PNG LNG. Class B shares recognize the holders’ economic interests in the PNG LNG and in the LNG Project. This agreement allows for the admission of one or more strategic investors as Class A and/or B shareholders subject to the prior approval of each existing Shareholder. The agreement also allows for the State to elect to purchase up to 10% of the issued and outstanding shares in Liquid Niugini Gas Limited (a wholly owned subsidiary of PNG LNG).

Pursuant to a Share Purchase and Sale and Settlement Agreement among the shareholders dated February 27, 2009 under which we and Pac LNG acquired all of Merrill’s interest in the PNG LNG, Merrill retains no ongoing economic interest, legal rights or involvement in the LNG Project. A revised version of this shareholders agreement is still to be agreed to, to respond to that significant change, and to reflect other changes to the relationship between Pac LNG and we and to the proposed structure of the LNG Project.

Refinery Project Agreement

On May 29, 1997, we entered into a project agreement with the State under which we agreed to construct and operate a refinery in Port Moresby, Papua New Guinea. The project agreement expires on January 31, 2035. In the project agreement, the State has agreed to use its best efforts to enable us to purchase sufficient crude oil produced in Papua New Guinea for the refinery to run at full capacity. If necessary, these efforts would include proposing legislation and issuing executive orders or policy directives. In addition, the government of Papua New Guinea has agreed that future agreements between Papua New Guinea and producers of oil in Papua New Guinea will contain provisions requiring such producers to sell oil produced in Papua New Guinea to local refineries to meet Papua New Guinea’s requirements for refined petroleum products. The purchase price for this oil will be the prevailing fair market price of such oil at the time of purchase. The Refinery Project Agreement also provides that the State will take all actions necessary to ensure that local distributors of petroleum products in Papua New Guinea purchase such product first and foremost from the local refinery at the IPP.  In general, the IPP represents the equivalent price that would be paid in Papua New Guinea for a refined product if it were imported.  For each refined product produced and sold locally in Papua New Guinea, the IPP was originally calculated by adding the costs that would typically be incurred to import such product to the average Posted Price for such product in Singapore as reported by Platts.  The costs that are added to the reported Platts’ price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.  This pricing model has since been jointly reviewed by the State and us due to the cessation of Singapore Posted Prices.  The basis of calculating IPP price was revised in November 2007 to an interim agreement and then amended in June 2008 to a modified IPP formula by changing the benchmark price for each refined product from ‘Singapore Posted Prices’, which is no longer being updated, to MOPS, which is the interim benchmark price for refined products in the Asia Pacific region, plus an agreed premium.  The project agreement provides that, until December 31, 2010, income from the refinery will not be taxed.

Annual Information Form   INTEROIL CORPORATION   55

BNP-lead Syndicated Term Loan Facility Agreement

A Syndicated Term Loan Facility Agreement was entered into on 16 October 2012 pursuant to which an $100 million loan from a syndicated group of three banks, namely BNP Paribas, BSP and Australian New Zealand Banking Group PNG Limited, was lent to EP InterOil Limited and InterOil Limited, subsidiaries of ours. There was a one-time disbursement of the loan on November 9, 2012 after fulfillment of all conditions precedent in accordance with the facility agreement. The funds were used to refinance the OPIC Loan and intercompany balances and for other general corporate purposes. The loan is secured by all of our refinery’s capital assets and an InterOil parent guarantee, which will continue for the life of the loan. The loan matures on October 15, 2017 and requires semi-annual principal payments of 8% to 12% of the loan principal amount and interest which can be selectively quarterly or semi-annually payments.

Farm-In Agreement by PRE

On July 27, 2012, we entered into a farm-in agreement (and certain related agreements) with PRE under which we agreed to farm out to an affiliate of PRE a net ten percent (10%) revenue interest in PPL 237, in exchange for certain cash payments and work carry obligations. The license interest assigned to PRE was grossed up to a 12.903226% working interest to account for the potential exercise by the State of its statutory right to back-in to a 22.5% net revenue interest in any petroleum project based on a PDL granted over the area comprised in the license under certain conditions. Cash amounts are divided among an initial cash payment of US$116 million and a resource payment payable out of net sales proceeds of production, in each case subject to satisfaction of standard terms and conditions. As of December 31, 2012, US$20 million in cash had been paid on a nonrefundable basis and an additional US$20 million in cash had been advanced by PRE against the US$96 million balance due in cash at completion. A second advance of US$20 million was requested in December 2012 payable in January 2013. PRE has also agreed to an additional carry for a work program involving up to seven (7) appraisal wells in the Triceratops field located within PPL 237 and at least four (4) exploration wells in other structures in PPL 237. PRE has the right to withdraw from its interest in PPL 237 and related work carry obligations under certain conditions. In that event, up to US$96 million of the initial cash payment would be refunded to PRE from net sales proceeds of production from our interest in PRL 15. If for any reason such sales proceeds were insufficient to repay the full amount after six years, we would be required to repay the balance from corporate funds.

All other contracts entered or still in effect during 2012 were done so in the ordinary course of our business or were not material to us.

Each of the above material agreements have been filed on SEDAR and are available through the SEDAR website at, www.sedar.com.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares is Computershare Investor Services, Inc.

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.

100 University Avenue, 9^th Floor

Toronto, Ontario

Annual Information Form   INTEROIL CORPORATION   56

Canada M5J 2YI

Tel: 1-800-564-6253 (toll free North America)

Fax: 1-888-453-0330 (toll free North America)

E-mail: service@computershare.com

Website: www.computershare.com

Co-Transfer Agent (USA)

Computershare Trust Company N.A.

350 Indiana Street

Golden, Colorado 80401

U.S.A.

Tel: 1-800-962-4284 (toll free North America)

International: 1-514-982-7555

INTERESTS OF EXPERTS

PricewaterhouseCoopers, Chartered Accountants, are the Corporation's auditors and have audited the financial statements of the Corporation for the year ended December 31, 2012. As at the date hereof, PricewaterhouseCoopers are independent within the meaning of Public Company Accounting Oversight Board Rule 3520.

Information relating to reserves of the Corporation set forth in the Statement of Resources Data and Other Oil and Gas Information was evaluated by GLJ, as independent qualified reserves evaluators. As at the date hereof, the principals of GLJ, did not hold any registered or beneficial ownership interests, directly or indirectly in the common shares or the 2.75% convertible senior notes.

ADDITIONAL INFORMATION

Additional information, including that related to directors’ and officers’ remuneration, principal holders of our common shares and securities authorized for issuance under equity compensation plans was contained in our information circular for our annual meeting of shareholders held on June 21, 2011 and will be contained in our information circular for our upcoming annual meeting of shareholders expected to be held in June 2012. Additional financial information is provided in our audited consolidated financial statements for the year ended December 31, 2012 (the “Annual Financial Statements”) and related 2012 MD&A. Our Annual Financial Statements, 2012 MD&A, Information Circular and additional information can be found on the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com and on our website at www.interoil.com.

Copies of the Annual Financial Statements, 2012 MD&A, and any additional copies of this AIF may also be obtained by contacting Mr. Wayne Andrews, Vice President Capital Markets at 25025 I-45 North, Suite 420, The Woodlands, Texas 77380 Telephone: +1 281 292 1800.

Annual Information Form   INTEROIL CORPORATION   57

Schedule A – Report of Management and Directors on Oil and Gas Disclosure

FORM 51-101F3 REPORT OF

MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

Management of InterOil Corporation (the "Company") is responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with the securities regulatory requirements. This information includes (i) reserves date, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2012, and (ii) resources as at December 31, 2012.

The board of directors of the Company has determined that the Company had no reserves as at December 31, 2012.

An independent qualified reserve evaluator has evaluated the Company's resources data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The Reserves Committee of the board of directors of the Company has:

(a) reviewed the Company's procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing the Company’s oil and gas activities and resources data;

(b) the filing of the Form 51-102F2 which is the report of the independent qualified reserves evaluator on the resources data; and

(c) the content and filing of this report.

Because the resources data are based on judgments regarding future events, actual results will vary and the variations may be material.

DATED effective February, 27 2013.

“Phil E. Mulacek”	"Roger Grundy"
Phil E. Mulacek	Roger Grundy
Chief Executive Officer	Director
“Collin F. Visaggio”	“Gaylen Byker”
Collin F. Visaggio	Gaylen Byker
Chief Financial Officer	Director
“Ford Nicholson”
Ford Nicholson
Director

Annual Information Form   INTEROIL CORPORATION   58

Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator

REPORT ON RESOURCES DATA

BY

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

To the board of directors of InterOil Corporation (the "Company"):

1. We have evaluated the Company’s resources data as at December 31, 2012. The resources data are estimates of low, best and high estimates of contingent resources as at December 31, 2012.

2. The resources data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the resources data based on our assessment.

We carried out our assessment in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an assessment to obtain reasonable assurance as to whether the resources data are free of material misstatement. An assessment also includes assessing whether the resources data are in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimates of low, best and high estimates of contingent resources as at December 31, 2012:

Independent Qualified Reserves	Description and Preparation Date of Assessment	Location of Reserves (Country or Foreign Geographic	Company Gross Contingent Resources MMBOE
Evaluator	Report	Area)	Low		Best		High
GLJ Petroleum Consultants	February 7, 2012	Papua New Guinea		744.8		1002.8		1241.2

5. In our opinion, the resources data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the resources data are based on judgements regarding future events, actual results will vary and the variations may be material.

Annual Information Form   INTEROIL CORPORATION   59

8. Contingent resources estimates will not be classified as reserves until the following contingencies are satisfied: (i) sanctioning of the facilities required to process and transport marketable natural gas, (ii) confirmation of a market for the marketable natural gas, and (iii) determination of economic viability. Contingent resources entail commercial risk not applicable to reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 25, 2013

Keith M. Braaten, P. Eng.

President & CEO

Annual Information Form   INTEROIL CORPORATION   60

Schedule C – Audit Committee Charter

This Audit Committee Charter (the “Charter”) sets forth the purpose and membership requirements of the Audit Committee (the “Committee”) of the Board of Directors (the “Board”) of InterOil Corporation (the “Company”) and establishes the authority and responsibilities delegated to it by the Board.

1. Purpose. The purpose of the Committee is to assist the Board in fulfilling its oversight responsibilities. In fulfilling this purpose, the Committee’s primary duties and responsibilities are to:

· Review management's identification of principal financial risks and monitor the process to manage such risks.

· Oversee and monitor the Company’s compliance with legal and regulatory requirements.

· Oversee audits of the Company's financial statements.

· Oversee and monitor the integrity of the Company’s accounting and financial reporting processes, financial statements and system of internal controls.

· Oversee and monitor the qualifications, independence and performance of the Company’s external auditor and the performance of the Company’s internal auditors.

· Provide an avenue of communication among the Board, the external auditor, management and the internal auditors.

· Report to the Board regularly.

The Committee shall be empowered to conduct or cause to be conducted any investigation appropriate to fulfilling its responsibilities, and shall have direct access to the external auditors, the internal auditor and Company employees as necessary. The Committee shall be empowered to retain, at the Company’s expense, independent legal, accounting, or other consultants or experts as the Committee deems necessary in the performance of its duties. The Committee shall have sole authority to approve related fees and retention terms, and the Company shall provide for payment of such fees and for the compensation to the external auditor for the purpose of rendering or issuing an audit report or performing other audit, review or attest services for the Company, as well as funding for the payment of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.

2. Committee Membership.

2.1. Composition and Appointment. The Committee shall consist of three or more members of the Board. The Board shall designate members of the Committee. Membership on the Committee shall rotate at the Board’s discretion. The Board shall fill vacancies on the Committee and may remove a Committee member from the membership of the Committee at any time without cause. Members shall serve until their successors are appointed by the Board and as otherwise required by applicable law or the rules of the New York Stock Exchange (“NYSE”).

2.2. Independence and Financial Literacy. Each member of the Committee must qualify as an independent and financially literate director pursuant to National Instrument 52-110 - Audit Committees (as implemented by the Canadian Securities Administers), as amended from time to time, and meet the independence, or an applicable exception, financial literacy, and experience requirements of the NYSE rules and applicable U.S. federal securities laws, including the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). In addition, at least one member of the Committee must be an “audit committee financial expert” as defined by the SEC.

2.3. Service on Multiple Audit Committees. If a member of the Committee serves on the audit committee (or, in the absence of an audit committee, the board committee performing equivalent functions, or in the absence of such committee, the board of directors) of more than two other public companies, the Board must affirmatively determine that such simultaneous service on multiple audit committees will not impair the ability of such member to serve on the Committee.

2.4. Subcommittees. The Committee may form and delegate authority to subcommittees consisting of one or more members to grant pre-approvals of permitted non-audit services, provided that decisions of said subcommittee to grant preapprovals shall be presented to the full Committee at its next scheduled meeting.

Annual Information Form   INTEROIL CORPORATION   61

3. Meetings.

3.1. Frequency of Meetings. The Committee shall meet at least quarterly, or more frequently as circumstances dictate. The schedule for regular meetings of the Committee shall be established by the Committee. The Chairperson of the Committee may call a special meeting at any time he or she deems advisable. Meetings may be by written consent. At least annually, the Committee will meet in executive session outside the presence of any senior executive officer of the Company. The Committee may request any officer or employee of the Company or the Company’s outside counsel or external auditor to attend a meeting of the Committee or to meet with any members of, or consultants to, the Committee.

3.2. Minutes. Minutes of each meeting of the Committee shall be kept to document the discharge by the Committee of its responsibilities.

3.3. Quorum. A quorum shall consist of at least one-half of the Committee’s members, but no fewer than two persons. The act of a majority of the Committee members present at a meeting at which a quorum is present shall be the act of the Committee.

3.4. Agenda. The Chairperson of the Committee shall prepare an agenda for each meeting of the Committee, in consultation with Committee members and any appropriate member of the Company’s management or staff, as necessary. As requested by the Chairperson, members of the Company’s management and staff shall assist the Chairperson with the preparation of any background materials necessary for any Committee meeting.

3.5. Presiding Officer. The Chairperson of the Committee shall preside at all Committee meetings. If the Chairperson is absent at a meeting, a majority of the Committee members present at a meeting shall appoint a different presiding officer for that meeting.

3.6. Private Meetings. The Committee shall meet periodically in separate executive sessions with management (including the chief executive officer, chief financial officer and chief accounting officer), the internal auditors and the external auditor, and have such other direct and independent interaction with such persons from time to time as the members of the Committee deem appropriate.

4. General Review Procedures.

4.1. Annual Report Review. The Committee shall review and discuss with management, the external auditors, and the internal auditors, the Company’s year-end financial results prior to the release of earnings, or profit or loss, as applicable, and the Company’s year-end financial statements prior to filing or distribution. Such review shall also include the Company’s disclosures that are to be included in the Company’s Annual Information Form, Annual Report, Management’s Discussion and Analysis for the year and Annual Report on Form 40-F. The Committee shall also discuss with management, the external auditors and the internal auditors any significant issues, judgments or findings or any changes to the Company’s selection or application of accounting principles and any items required to be communicated by the external auditors in accordance with Statement on Auditing Standard No. 114, as amended, generally accepted accounting principles or International Financial Reporting Standards (“IFRS”), as applicable, and various topics and events that may have a significant impact on the Company or that are the subject of discussions between management and the external auditors. The Committee shall approve the audited financial statements, Management’s Discussion and Analysis, and the Annual Information Form (as to financial information included therein) and recommend to the Board whether or not the audited financial statements, Management’s Discussion and Analysis, and the Annual Information Form (as to financial information included therein) should be approved by the Board, filed on SEDAR and included in the Company’s Annual Report on Form 40-F filed on EDGAR for the last fiscal year.

Annual Information Form   INTEROIL CORPORATION   62

4.2. Quarterly Report Review. The Committee shall review and discuss with management, the internal auditors and the external auditors, the Company’s interim financial results prior to the release of earnings, or profit or loss, as applicable, and the Company’s interim financial statements and Management’s Discussion and Analysis, including the results of the external auditor’s review of the interim financial statements, prior to filing or distribution and the disclosures that are to be included in the Company’s Management’s Discussion and Analysis for each quarter and Form 6-K. The Committee shall discuss with management, the internal auditors and the external auditors, any significant issues, judgments or findings or any changes to the Company’s selection and application of accounting principles and any items required to be communicated by the external auditors in accordance with Statement on Auditing Standards No. 114 and No. 100, as amended, generally accepted accounting principles or IFRS, as applicable.

4.3. Canadian and SEC Filings Review. The Committee shall review with financial management and the external auditor filings with Canadian securities regulators and the SEC which contain or incorporate by reference the Company’s financial statements or Management’s Discussion and Analysis and consider whether the information in these documents is consistent with information contained in the financial statements.

4.4. Reporting System Review. In consultation with management, the external auditors, and the internal auditors, the Committee shall consider the integrity of the Company’s financial reporting processes and controls including computerized information system controls and security. The Committee shall review and discuss with management the Company’s significant financial risk exposures and the steps management has taken to monitor, control, and report such exposures. The Committee shall review significant findings prepared by the external auditors and the internal auditors together with management’s responses, including the status of previous recommendations.

4.5. Financial Data Review. The Committee shall review and discuss with management earnings including the use of “proforma,” “adjusted” or other non-GAAP or non-IFRS information, as applicable, financial guidance and other press releases of a material financial nature, as well as financial information, and earnings or profit or loss guidance provided to analysts and rating agencies. Such discussion may be done generally consisting of discussing the types of information to be disclosed and the types of presentations to be made.

4.6. Off-Balance Sheet Review. The Committee shall discuss with management and the external auditor the effect of regulatory and accounting initiatives as well as off-balance sheet structures on the Company’s financial statements.

4.7. Risk Assessment. Although it is the job of the CEO and senior management to assess and manage the Company’s exposure to risks, the Committee shall discuss guidelines and policies to govern the process by which risk assessment and risk management is addressed.

4.8. Audit Difficulties. The Committee shall review with the external auditor any audit problems or difficulties encountered in the course of the audit work and management’s response, any restrictions on the scope of activities or access to requested information; and any significant disagreements between auditors and management. The Committee shall work to resolve disagreements that may have occurred between auditors and management related to the Company’s financial statements or disclosures.

4.9. Hiring Approval. The Committee shall approve the hiring of any partner, former partner, employee or former employee of the external auditor.

4.10. Financial Officer Code of Ethics Review. The Committee shall review and periodically recommend modifications to the Company’s Code of Ethics for the Chief Executive Officer and Senior Financial Officers.

4.11. Certification Review. The Committee shall review disclosures made to the Committee by the Company’s CEO and CFO during the certification process for the audited annual financial statements, interim financial statements, related Management’s Discussion and Analysis and Annual Information Form/Form 40-F concerning significant deficiencies or material weaknesses in internal controls and any fraud.

4.12. Legal Counsel Review. On at least an annual basis, the Committee shall review with the Company’s general counsel any legal matters that could have a significant impact on the Company’s financial statements or the Company’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.

Annual Information Form   INTEROIL CORPORATION   63

5. External auditors.

Auditor Performance Review. The Committee shall confirm with the external auditors their ultimate accountability to the Committee. The external auditors will report directly to the Committee. The Committee will ensure that the external auditors are aware that the Chairperson of the Committee is to be contacted directly by the external auditor (i) to review items of a sensitive nature that can impact the accuracy of financial reporting or (ii) to discuss significant issues relative to the overall Board responsibility that have been communicated to management but, in their judgment, may warrant follow-up by the Committee. The Committee shall review and evaluate the performance of the auditors and the lead partner on the external auditor team.

Approval of External auditor and Pre-Approval of Services. The Committee shall recommend to the Board the appointment, compensation, retention and termination of the Company’s external auditor. The Committee shall be directly responsible for the oversight of the work of the external auditors engaged (including resolution of disagreements between management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Company. The Committee shall pre-approve all auditing services, including the compensation and terms of the audit engagement, and all other non-audit services (including the fees and terms thereof) to be performed by the external auditors, subject to the de-minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934 or applicable Canadian federal and provincial legislation and regulations which are approved by the Committee prior to the completion of the audit. The Committee shall periodically discuss current year non-audit services performed by the external auditors, including the nature and scope of any tax services to be approved, a well as the potential effects of the provisions of such services on the auditor’s independence, and review and pre-approve all permitted non-audit service engagements.

Auditor Independence. The Committee shall oversee the independence of the external auditors by, among other things, (i) on an annual basis, receiving from the external auditors a formal written statement delineating all relationships between the external auditors and the Company, consistent with rules of the Public Accounting Oversight Board, that could impair the auditors’ independence; (ii) actively engaging in a dialogue with the external auditors with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditors; and (iii) taking, or recommending to the Board the appropriate action to be taken, in response to the external auditors’ report to satisfy itself of the external auditors’ independence.

Auditor Report. The Committee shall annually obtain from the external auditor and review a written report describing (i) the external auditor’s internal quality-control procedures; and (ii) any material issues raised by (a) the external auditor’s most recent internal quality-control review, or peer review or (b) any inquiry or investigation by governmental or accounting profession authorities, in each case, within the preceding five years, respecting one or more independent audits carried out by the external auditor, and any steps taken to deal with any such issues.

Audit Partner Rotation. The Committee shall ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law. The Committee shall obtain, annually, from the external auditor a written statement confirming that neither the lead (or coordinating) audit partner having primary responsibility for the Company’s audit nor the audit partner responsible for reviewing the Company‘s audit has performed audit services in those roles for the Company prior to the Company’s five previous fiscal years.

Internal Controls Report. The Committee shall annually obtain from the external auditor a written report in which the external auditor attests to and reports on the assessment of the Company’s internal controls made by the Company’s management and its control environment as it pertains to the Company’s financial reporting process and controls. Each quarter, the Committee shall review and discuss with management, the internal auditor, and the Company’s external auditor (i) the operation, adequacy and effectiveness of the Company’s internal controls (including any significant deficiencies, any special steps adopted in light of material control deficiencies, any significant changes in internal controls and the adequacy of disclosures about changes in internal control over financial reporting); (ii) the Company’s internal controls report and the auditor’s attestation of the report; (iii) the Company’s internal audit procedures; and (iv) the adequacy and effectiveness of the Company’s disclosures controls and procedures, and management reports thereon.

National Office Consultation. The Committee shall discuss with the external auditor material issues on which the national office of the external auditor was consulted by the Company’s audit team and matters of audit quality and consistency.

Annual Information Form   INTEROIL CORPORATION   64

Audit Planning. The Committee shall review and discuss with the external auditors their audit plan and engagement letter and discuss with the external auditors and the internal auditor the scope of the audit, staffing, locations, reliance upon management, and internal audit and general audit approach.

Accounting Principles. The Committee shall consider the external auditors’ judgments about the quality and appropriateness of the Company’s accounting principles as applied in its financial reporting, including critical accounting policies and practices used by the Company, GAAP or IFRS alternatives, as applicable, discussed with management (including the ramifications and the auditor’s preferred treatment), and any other material written communications between the external auditor and management.

Auditor Assurance. The Committee shall obtain from the external auditor assurance that Section 10A of the Securities Exchange Act of 1934, addressing the reporting of illegal acts, has not been implicated.

Additional Auditors. The Committee shall review the use of auditors other than the external auditor where management has requested a second opinion or another auditor is proposed to be engaged for other reasons.

6. Internal Audit Department and Legal Compliance.

Budget and Plan. The Committee shall review the budget, planned scope of the internal audit, changes in plan, activities, organizational structure, and qualifications of the internal auditor. The internal auditor function shall be responsible to senior management, but shall have a direct reporting responsibility to the Board through the Committee. The “internal auditor” will be responsible for contacting the Chairperson of the Committee directly (i) to review items of a sensitive nature that can impact the accuracy of financial reporting or (ii) to discuss significant issues relative to the overall Board responsibility that have been communicated to management but, in the internal auditor’s judgment, may warrant follow-up by the Committee.

Approval of Internal Auditor. The Committee shall review and approve the appointment, performance, dismissal and replacement of the internal auditor or the entity retained to provide internal audit services.

Internal Audit Review. The Committee shall review a summary of findings from completed internal audits and, where appropriate, review significant reports prepared by the internal audit department together with management’s response and follow-up to these reports.

7. General Audit Committee Responsibilities.

Code of Ethics for the Chief Executive Officer and Senior Financial Officers. The Committee shall inquire of management, the external auditor and the internal auditor as to their knowledge of (i) any violation of the Code of Ethics for the Chief Executive Officer and Senior Financial Officers, (ii) any waiver of compliance with such code, and (iii) any investigations undertaken with regard to compliance with such code. The Committee may make recommendations to the Board regarding the waiver of any provision of the Code of Ethics for the Chief Executive Officer and Senior Financial Officers, however any waiver of such code may only be granted by the Board. All waivers granted by the Board shall be promptly publicly disclosed as required by the rules and regulations of the SEC and the NYSE.

Complaints Procedure. The Committee shall establish procedures to (i) receive, process, retain and treat complaints received by the Company regarding accounting, internal audit controls or auditing matters and (ii) the confidential and anonymous submission by employees of concerns regarding questionable accounting or audit practices.

Related Party Transactions. The Committee shall approve all related party transactions after a review of the transactions by the Committee for potential conflicts of interest. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed in the Company’s Management’s Discussion and Analysis or any other filings with Canadian Securities Administrators or the SEC. The Committee shall review reports and disclosures of related party transactions.

Annual Information Form   INTEROIL CORPORATION   65

General Activities. The Committee shall perform any other activities consistent with this Charter, the Company’s bylaws, the Company’s Code of Ethics and Business Conduct and governing law, as the Committee or the Board deems necessary or appropriate, including reviewing the Company’s corporate compliance activities.

8. Reports and Assessments.

8.1. Board Reports. The Chairperson shall, periodically at his or her discretion, report to the Board on Committee actions and on the fulfillment of the Committee’s responsibilities under this Charter. Such reports shall include any issues that arise with respect to the quality or integrity of the Company’s financial statements, the Company’s compliance with legal or regulatory requirements, the performance and independence of the Company’s external auditors and the performance of the Company’s internal audit function.

8.2. Charter Assessment. The Committee shall annually assess the adequacy of this Charter and advise the Board of its assessment and of its recommendation for any changes to the Charter. The Committee shall, if requested by management, assist management with the preparation of a certification to be presented annually to the NYSE affirming that the Committee reviewed and reassessed the adequacy of this Charter.

8.3. Committee Self-Assessment. The Committee shall annually make a self-assessment of its performance.

8.4. Audit Committee Report. The Committee shall prepare any Audit Committee Reports required by the rules of the Canadian Securities Administrators or the SEC to be included in the Company’s filings with such agencies.

The duties and responsibilities of a member of the Audit Committee are in addition to those duties set out for a member of the Board. While the Committee has the responsibilities and powers set forth by this Charter, it is the responsibility of management to prepare the financials and it is the responsibility of the external auditor to plan or conduct audits or to determine that the Company’s financial statements are complete and accurate in accordance with generally accepted accounting principles and IFRS, as applicable.

The material in this Charter is not soliciting material, is not deemed filed with the SEC and is not incorporated by reference in any filing of the Company under the Securities Exchange Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date this Charter is first included in the Company’s filings with the SEC and irrespective of any general incorporation language in such filings.

Annual Information Form   INTEROIL CORPORATION   66