InterOil Corporation        Annual Information Form   For the Year Ended December 31, 2011 March 16, 2012

TABLE OF CONTENTS

TABLE OF CONTENTS	1
PRELIMINARY NOTES	2
GENERAL	2
NON-GAAP MEASURES AND RECONCILIATION	2
LEGAL NOTICE – FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	4
CONVERSION	5
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	18
MIDSTREAM - REFINING	23
MIDSTREAM - LIQUEFACTION	25
DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION	26
RESOURCES	28
THE ENVIRONMENT AND COMMUNITY RELATIONS	29
RISK FACTORS	31
DIVIDENDS	41
DESCRIPTION OF CAPITAL STRUCTURE	41
MARKET FOR OUR SECURITIES	43
DIRECTORS AND EXECUTIVE OFFICERS	44
AUDIT COMMITTEE	47
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	48
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	48
MATERIAL CONTRACTS	48
TRANSFER AGENT AND REGISTRAR	51
INTERESTS OF EXPERTS	51
ADDITIONAL INFORMATION	51
Schedule A – Report of Management and Directors on Oil and Gas Disclosure	52
Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator	53
Schedule C – InterOil Corporation Charter of the Audit Committee of the Board of Directors	55

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, 2011. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2011 and Management’s Discussion and Analysis for the year ended December 31, 2011 (“2011 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, 2011 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.

NON-GAAP MEASURES AND RECONCILIATION

Gross Margin is a non-GAAP measure derived from ‘sales and operating revenues’ less ‘cost of sales and operating expenses’.

Earnings before interest, taxes, depreciation and amortization (“EBITDA”) represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. We use EBITDA to analyze operating performance. EBITDA does not have a standardized meaning prescribed by International Financial Reporting Standards and, therefore, may not be comparable with the calculation of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results. Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash provided from operating activities and other measures of financial performance prepared in accordance with International Financial Reporting Standards. Further, EBITDA is not a measure of cash flow under International Financial Reporting Standards and should not be considered as such.

For reconciliation of these non-GAAP measures to measures under GAAP, refer to the heading “Non-GAAP Measures and Reconciliation” in our 2011 MD&A.

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, 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; the construction of proposed liquefaction facilities and condensate stripping facilities in Papua New Guinea; the development of such liquefaction and condensate stripping facilities; 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.

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

· our ability to finance the development of liquefaction and condensate stripping facilities; 

· our ability to negotiate definitive agreements following conditional agreements or heads of agreement relating to the development of liquefaction and condensate stripping facilities, 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 our liquefaction and condensate stripping facilities 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 PNG government authorities to develop our gas and condensate resources and to develop liquefaction and condensate stripping facilities within reasonable time periods and upon reasonable terms.

· 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;

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· 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.

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 to 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	mscf	thousand standard cubic feet
boe(1)	barrels of oil equivalent	mscfpd	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	mmscf	million standard cubic feet
mbbl	thousand barrels	mmscfpd	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.

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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 metres	28.317
cubic metres	cubic feet	35.315
bbls	cubic metres	0.159
cubic metres	bbls	6.289
feet	metres	0.305
metres	feet	3.281
miles	kilometers	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

GLOSSARY OF TERMS

“2011 MD&A” means the Management’s Discussion and Analysis for the year ended December 31, 2011.

“AIF” means this Annual Information Form for the year ended December 31, 2011.

“API” means the American Petroleum Institute.

“Barrel, Bbl” (petroleum) 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 Singapore Pte Limited.

“BSP” means Bank of South Pacific Limited.

“CDU” means crude distillation unit.

“CGR” means condensate to gas ratio.

“COGE Handbook” refers to the Canadian Oil and Gas Evaluation Handbook.

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

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

“Crack spread” 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” 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 sulfur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

“CSP Joint Venture” or “CSP JV” means the Joint Venture Operating Agreement (“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.

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“CS 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” refers to a drill stem test and is a procedure for isolating and testing the surrounding geological formation through the drill pipe.

“EBITDA” EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is a non-GAAP measure used to analyze operating performance. See “Non-GAAP Measures and Reconciliation”.

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

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

“Farm out” 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.

“GAAP” means Canadian generally accepted accounting principles.

“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 2010 Report" means the report dated March 7, 2011 with an effective date of December 31, 2010 setting forth certain information regarding contingent resources of InterOil’s interests in the Elk and Antelope fields in PNG.

"GLJ 2011 Report" means the report dated February 28, 2012 with an effective date of December 31, 2011 setting forth certain information regarding contingent resources of InterOil’s interests in the Elk and Antelope fields in PNG.

“Gross reserves” refers to InterOil's working interest reserves before the deduction of royalties and before including any royalty interests.

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

“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 the Amended and Restated Indirect Participation Agreement dated February 25, 2005, as amended (see “Material Contracts”).

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

“IPF” refers to InterOil power fuel, InterOil’s marketing name for low sulfur waxy residue or 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.

“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.

“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 proposed liquefaction facilities.

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

“Naphtha” 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” means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth's surface, often in association with petroleum. The principal constituent is methane.

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

“Net wells” refers to the aggregate of the numbers obtained by multiplying each gross well by our percentage working interest in that well.

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

“NI 52-110” refers to 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.

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“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 indirect participation agreement in May 2003, as amended. (See “Description of our Business – Upstream - Exploration and Production – Participation Agreements”, “Material Contracts – Drilling Participation Agreement dated July 21, 2003”).

"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.

“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. 

“Shut-in” refers to 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” Sweetness 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 InterOil in an oil and natural gas property.

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

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CORPORATE STRUCTURE

Name, Address and Incorporation

InterOil Corporation is a Yukon Territory corporation, continued under the YBCA on August 24, 2007. In November 2007, InterOil amended its articles to authorize 1,035,554 Series A Preferred Shares, none of which are outstanding.

Our registered office in Canada is located at: Suite 300,204 Black Street Whitehorse, Yukon Y1A 2M9	Our corporate office in Australia is located at: Level 3, Cairns Square, 42 – 52 Abbott Street, Cairns, Queensland 4870	Our corporate office in Papua New Guinea is located at: Level 2, Ravalien Haus, Harbour City Port Moresby NCD,
Our office in Singapore is located at:	Our corporate office in the United States is located at:
28-01 Suntec Tower One 7 Temasek Boulevard, Singapore 038987	25025 I-45 North Suite 420, The Woodlands, Texas 77380

Copies of the Company’s current 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.

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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 primarily on the development program for the Elk and Antelope fields in Papua New Guinea. The Elk and Antelope fields are onshore gas fields with significant contingent resources, and are held within the retention license granted to us by the State, PRL 15. The development and production of hydrocarbons from these fields will require a PDL to cover the wells, infield pipelines and gas processing and condensate stripping plant. The commercialization of the hydrocarbons will require the construction of pipelines, a gas liquefaction facility and marine export facilities in order to process and transport the produced hydrocarbons to market. We have commenced the construction of certain infrastructure such as roads, wharves, warehouses and camps to support the proposed appraisal and development drilling in the Elk and Antelope gas fields.

We also undertook exploration activities in our three exploration licenses, PPL 236, PPL 237 and PPL 238 in the year ended December 2011. These exploration activities involved a regional airborne geophysical survey, various seismic surveys across a number of prospects and preparation for drilling of our next appraisal well, Triceratops 2, which was spudded in mid-January 2012.

Elk and Antelope Gas Fields Appraisal

During 2009 and 2010, we continued efforts to appraise and develop the Elk and Antelope fields. In this period we completed drilling and logging activities on the Antelope 2 well which was plugged and suspended for future work over as a producer. The well was spudded on July 27, 2009. The well satisfied the well commitment for the PPL 237 license required for that year.

In September 2009, a 100 kilometer two dimensional seismic program to appraise the Antelope field was commenced and recording of seismic data was completed. The data was processed with results available in January 2010 and subsequently interpreted.

A high rate flow test was performed in late November to early December 2009 to confirm deliverability. This flow test recorded a flow rate of 705 mmscfd which rate yields 11,200 bbls of condensate per day. Subsequent to this flow test, DST 2 was performed. This DST confirmed gas and condensate with a stabilized CGR of over 20 bbl/mmscf. The well was then drilled to 2,365 metres and DST 3 was carried out over the interval 2,320 metres to 2,365 metres. 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 metres.

On February 9, 2010, we acquired a second larger drilling rig for approximately $4.5 million with additional costs incurred for the inspection, packaging and transportation of the rig. This rig was acquired for the purpose of drilling further appraisal wells in the Elk and Antelope fields.

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

Participation Interests

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 PRL15 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 PNG Department of Petroleum and Energy, and was approved in December 2011.

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On December 15, 2009, we completed an exchange of certain indirect participation interests held by a number of IPI holders under the IPI Agreement. Pursuant to this exchange, we acquired each such IPI holder’s relevant pro rata right, title and interest in, to and under the IPI Agreement and in any future discoveries. The participation interests acquired totaled 4.8364% working interest of the Elk and Antelope fields, and their respective interests in four exploration wells still to be drilled under the IPI Agreement. In exchange for these interests, we issued 1,344,710 common shares to the participating investors, having an aggregate value of $62.9 million when issued.

On July 19, 2010 and December 16, 2010, we completed additional exchanges of certain indirect participation interests for a combined total of 1.45% of IPI interests, also held under the IPI Agreement. In exchange for these interests, we issued 754,788 common shares to those investors having an aggregate value of $50.7 million when issued.

As a result of these transactions, our current interest in our exploration licenses is 75.6114%, assuming that all remaining IPI investors exercise their working interest rights in such licenses but not taking into account the interests that the State is able to exercise under relevant legislation.

At the end of 2011, we agreed with Petromin that the Investment Agreement we entered into in 2008 was no longer valid or intended to operate and should terminate. The agreement provided for Petromin to take a direct interest in the Elk and Antelope fields and fund 20.5% of the costs of their development, if certain conditions were met. 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. (See Material Contracts – Investment Agreement dated October 30, 2008”).

Condensate Stripping Project

In the first quarter of 2010, the pre-FEED phase for the development of condensate stripping facilities 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 Joint Venture Operating Agreement ("CSP JV") (see “Material Contracts”) for the CS Project with Mitsui, which agreement replaced the preliminary agreement entered into in April 2010. The capital cost for the condensate stripping facility was then estimated at $550.0 million, with approximately $32.0 million of this to be expended for FEED. Under the CSP JV, Mitsui is responsible for arranging or providing financing for the capital costs of the CS Project in the event that a positive FID is made in respect of the CS 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 our proposed liquefaction facilities. 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 CS Project, which efforts include detailed project execution plan, execution schedule and risk assessment work.

At the end of 2011, agreement was reached with Mitsui to extend the target date for FID on the CSP Project until March 31, 2012.

Exploration Activity

In December 2009, we agreed on terms to divest our 15% non-operated interest in PPL 244 to an unrelated third party, an offshore block in the Gulf of Papua, in exchange for $2.1 million. The divestment was made to allow us to focus our efforts on our core assets, being the Elk and Antelope fields and exploration within PPL’s 236, 237 and 238. This divestment was approved by the State and finalized in October 2010.

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Between the third quarter of 2009 and the first quarter of 2011, we completed the acquisition, processing and interpretation of 100 kilometres of seismic data from the Antelope structure and also completed two phases of two dimensional seismic data acquisition and processing over the former Bwata gas field, now understood to be and renamed as the Triceratops gas field (PPL 237), and the Wolverine prospect (PPL 238). The second phase of this program focused on further delineation of the Triceratops field and the Wolverine structure. At the end of 2010, the initial preparatory work on a seismic program for PPL 236 was advanced.

The PPL 237 phase three Bwata/Triceratops field seismic data acquisition program, which included four lines for a total of 50 kilometres, was acquired during April to August 2011. This program increased our total seismic data acquisition over the Bwata/Triceratops field to 140 kilometers in eleven lines. The objective of the program was to investigate the structure, seismic character and the aerial closure of the Triceratops gas field.

After the interpretation of the new 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 over 40 years ago. As a result, the field was renamed the Triceratops field.

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. Processing and interpretation of this first phase of seismic data has been completed, and the Wahoo/Mako leads (PPL 236) and the Tuna lead (PPL 236 and PPL 238) have been selected for follow up.

Subsequently the Kwalaha seismic data acquisition program was activated consisting of 56 kilometres and seven dip lines. Work commenced on September 16, 2011 and was completed on December 20, 2011. The objective of the survey was to further delineate the Wahoo and Mako prospects and identify potential drilling locations. Processing and interpretation of the data is ongoing.

A third phase of seismic data acquisition, which consists of two dip orientated lines totaling 21 kilometres in length over the Tuna prospect, commenced on December 22, 2011. Line preparation is currently in progress.

Wells in both PPL 236 and PPL 238 are required to be drilled by March 2013 in order to meet our license commitments. Seismic data acquisition and interpretation programs have been designed with a view to determining, amongst other things, the proposed location of these wells.

In 2011, we acquired an airborne magnetic, gravity and gamma ray survey over PPL 236, PPL 237 and PPL 238. A total of five (5) acquisition blocks were acquired with a combined a total of 1,428,876 line kilometres of airborne data. Data processing of this airborne data is currently undergoing final quality control.

The preparation of the Triceratops 2 well site was completed at the end of 2011 and the Triceratops 2 well was spudded on January 15, 2012. The Triceratops 2 well is an appraisal well to test the presence of hydrocarbons and determine whether a potential reefal carbonate reservoir exists in the Triceratops field.

Midstream – Refining segment

Over the three year period ended December 2011, our refining business unit has continued to process regionally sourced 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 has remained out of service since March 2010. Prior to this shutdown, 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 and returned to service during 2012, upon the successful conclusion of major maintenance and catalyst regeneration.

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, the majority of gasoline we have sold during the period has been imported. During the fourth quarter of 2010, we undertook major turnaround maintenance on the CDU. Other than imports resulting from this scheduled event, our imports of middle distillates have been minimal and have not significantly affected our crude throughput.

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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 feedstocks has been an important part of our crude acquisition strategy. We have introduced four new feedstocks to the refinery over the past three years, including our first West African crude. During 2011, we also concluded certain term purchase agreements for some of our preferred crudes for the 2012 year.

Whilst regional hydro skimming margins have suffered, particularly in 2011, our Import Parity Price ("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 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. 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 2011, there were seven export cargoes of Naphtha averaging approximately 28,506 metric tons each for a total of approximately 200,000 tonnes or 1.8 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 by our inability to operate the CRU) to convert Naphtha to gasoline. Also during 2011, there were seven export cargoes of LSWR totaling approximately 720,571 bbls under a combination of both spot and term arrangements that will continue into 2012. During November 2009, we made an export sale of diesel and gasoline to the Pacific Island of Nauru. We made 3 additional export sales of diesel and gasoline to Nauru in 2010 and no export sales of diesel or gasoline in 2011.

During 2011, our total throughput per day (excluding shut down days) was 24,856 bblspd versus 24,682 bblspd in 2010 and 21,155 bblspd in 2009. The total number of barrels processed into product at our refinery for 2011 was 6.73 million compared with 6.71 million for 2010, and 5.72 million in 2009. During 2011, our refinery was shut down for a total of 82 days, versus 81 days in 2010 and 80 days in 2009.

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 has been recognized for this. The provision as at December 31, 2011 was $4,562,269. 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, 2011.

Midstream – Liquefaction segment

On December 23, 2009, the LNG Project Agreement between the State and LNGL was executed. The agreement contains provisions for development of the LNG Project, including development plans for the pipeline infrastructure required to deliver gas from our Elk and Antelope fields, established the fiscal and taxation regime to be applied to the LNG Project for a twenty year period and provided for the acquisition by the State, through its nominee, of an interest totaling up to 20.5% of the equity in the LNG Project. A further 2% ownership stake is expected to be assumed by directly affected landowners. The obligations under the agreement are contingent upon the finalization of certain additional agreements, the LNG Project obtaining certain approvals and authorizations, obtaining leases for required land, certain initial and conditional agreements, passage of enabling legislation and FID. The LNG Project Agreement provides for a FID sunset date to occur in mid-2013.

On September 28, 2010, we, together with LNGL, signed a heads of agreement with Energy World Corporation Ltd. (“EWC”) 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 development, construction, financing and the operation of a planned three million tonne per annum (“mtpa”) land-based modular LNG plant. We intend to develop the LNG plant in two initial phases; 2 mtpa followed immediately by a 1 mtpa expansion. Commercial and certain contractual terms relating to the 3 mtpa plant have been largely defined with the execution of these two agreements. In return for its commitment to fully fund the construction of the LNG plant EWC is to be entitled to a fee of 14.5% of the proceeds from LNG revenue from the LNG plant, less agreed deductions, and subject to adjustments based on timing and execution for a 15 year period. 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 plant by March 31, 2012. We can provide no assurances that we will reach FID by this date, that this date will not be further extended or that we will enter into unconditional or other definitive agreements with EWC.

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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 is 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. We are continuing to negotiate with FLEX LNG. Additionally, under the framework agreement we entered into with FLEX LNG, an equity purchase option was granted to InterOil 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.

During the 2011 year, site-specific engineering for the land based modular LNG and fixed-floating LNG facilities were undertaken along with other pre-investment in the LNG Project to lower bidder risks and to secure our LNG Project timeline and costs.

On June 21, 2011, our Board approved capital expenditures on certain critical steel infrastructure ahead of FID on our LNG Project in order to help preserve the proposed schedule and take advantage of advantageous steel pricing. A total of up to $100.0 million was authorized for condensate and processed gas line pipe, and other required items with long lead times.

The PNG Government’s Minister for Petroleum and Energy and the Secretary of his department issued certain press releases and correspondence during 2011 asserting that our development of the LNG Project may not, were it to continue without amendment to its current form, be in compliance with the terms of the LNG Project Agreement signed with the State in December 2009, and would not be approved by the State. We have provided appropriate assurances to the PNG Government in relation to the development of this project and are continuing to work with the PNG Government and its relevant departments in relation to our development plans for the Elk and Antelope fields and the LNG Project. Additionally, the constitution of the PNG Government became a matter of dispute during 2011 and remains so. National elections are expected to take place in mid-2012. We can provide no assurance that the PNG Government will approve our development plans as they are currently constituted.

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.

On August 3, 2011, we signed a Heads of Agreement 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 Heads of Agreement was signed with Gunvor Singapore Pte. Ltd for the supply of an additional one mtpa of LNG from the LNG Project. On December 2, 2011, a further Heads of Agreement was signed with ENN Energy Trading Company Ltd of China, for the supply of one to one and one half mtpa of LNG from the LNG Project. The Heads of Agreement, 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.

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Downstream – Wholesale and Retail Distribution

As of December 31, 2011, we provided petroleum products to 52 retail service stations with 42 operating under the InterOil brand name and the remaining 10 operating under their own independent brand. Of the 52 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 36 service stations are independently owned and operated. Three new retail sites were identified and we expect to develop these sites during the 2012 and 2013 financial years. 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.

In 2009, we entered into our first direct chartering shipping arrangement with the owner of a fuel transport vessel which resulted in us being able to direct vessel movements rather than co-ordinate shipping with other distributors. During 2010, a second vessel was directly chartered and we now directly manage all our sea freight movements of fuel within Papua New Guinea. Increased demand for fuel has led to our planning for the chartering of a larger vessel during 2012, to replace the second vessel chartered in 2010.

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. It also recommended some increases in monitoring industry activity in PNG. All recommendations were implemented in 2011.

In 2011, we signed supply agreements with several key contractors and sub-contractors associated with the Exxon Mobil LNG project, Papua New Guinea’s largest resource project in its history to date. In addition, we re-signed supply agreements with all of our existing major customers in the agricultural, commercial and aviation sectors for further three year terms.

Our retail business accounted for approximately 13% of our total downstream sales in 2011. Investments were made in 2010 and 2011 in new electronic systems for both pumps and the forecourt control units to support the further development of this business.

Financing

In 2009, InterOil undertook the following financing transactions:

· During May and June 2009, the remaining outstanding 8% convertible debentures (being $79.0 million principal amount issued in May 2008) were converted into an aggregate of 3,159,000 common shares.

· On June 8, 2009, we completed a registered direct stock offering of 2,013,815 common shares to a number of institutional investors at a purchase price of $34.98 per share, raising gross proceeds of $70.4 million.

· In August 2009, 302,305 of the 337,252 warrants then outstanding were exercised and converted into common shares at an exercise price of $21.91. All remaining unexercised warrants lapsed on August 27, 2009 in accordance with their terms.

· Our working capital facility with BNP Paribas was renewed for the existing limit amount of $190 million for a period of 15 months expiring at the end of December 2010.

· In October 2009, we renewed our revolving working capital facility with BSP. The existing facility had a facility limit of 70.0 million Kina (approximately $26.5 million). However, on renewal, the facility limit was reduced to 50.0 million Kina (approximately $18.9 million).

In 2010, InterOil 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.

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· 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, InterOil 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. Total facility limit stood at $230.0 million subsequent to its amendment. Subsequent to the year end, the facility has been extended and further amended in February 2012 with the allowance of a further $10.0 million increase in the facility limit to $240.0 million.

· 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 will be next due on August 15, 2012.

· In October 2011, the Westpac working capital facility was temporarily extended until January 2012. Subsequent to the year end, the facility was renewed for a total amount of 90.0 million Kina (approximately $42.0 million). This facility is now set to expire in October 2014.

· In addition to the Westpac working capital facility, subsequent to the year end in February 2012, Westpac also provided us a secured term loan of $15.0 million which is repayable in half yearly installments ending 3.5 years from first drawdown. InterOil Corporation is required to provide a parent guarantee supporting this additional facility.

· Subsequent to the year end in February 2012, the BNP Paribas working capital facility was renewed with an increase in the overall limit of $10.0 million, increasing the total facility to $240.0 million.

Management Team

During 2009 and 2010, our Board and senior management changed as follows:

· In January 2009, Mr. Anthony Poon resigned as General Manager of Supply, Trading & Risk Management.

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

During 2011, no changes occurred at Board or executive officer levels. However, certain important appointments were made during the year. In August, the Right Honourable Sir Rabbie Namaliu, a former Prime Minister and former Petroleum and Energy Minister of Papua New Guinea, joined us as chair of our PNG Advisory Board, a body being 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 CS Project.

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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 which 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 gas liquefaction and condensate stripping facilities 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

· Build on 16 years of engagement in Papua New Guinea;

· Maintain a sound health, safety and security record;

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

· Remain a significant employer in Papua New Guinea.

Maximizing the value of our exploration assets

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

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

· Employ our second drilling rig to develop existing discoveries.

Monetizing our discovered resources

· Introduce strategic investors through the sale of interests in the Elk and Antelope fields, the CS Project, the LNG Project and associated LNG off-take to support exploration and development activities;

· Progress our planned condensate stripping facilities and liquefaction facilities with a focus on accelerating cash flows; and

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

Enhancing the existing refining and distribution business

· Continue growth in profitable market share in the region;

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

· Explore improved transport efficiencies and economics.

Positioning for long term success

· Seek new opportunities in the Southwest Pacific region for future growth.

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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.  Currently developing infrastructure for the Elk and Antelope fields which includes condensate stripping and associated facilities, and the gas gathering and associated facilities, in connection with commercializing significant gas discoveries.  This segment also manages our construction business which services the 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 – The LNG Project. 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 the 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.

As of December 31, 2011, we had 756 full-time employees in all segments, with 124 in upstream, 114 in midstream refining, 403 in downstream and 115 in corporate. Our work force is not unionized.

UPSTREAM - EXPLORATION AND PRODUCTION

As at December 31, 2011, we had interests in three PPLs and one PRL in Papua New Guinea covering 3,996,453 gross 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 for the next five years.

The following table summarizes our interests and on acreage currently held by InterOil as at December 31, 2011:

License Numbers	Basin	Location	Operator	InterOil Registered License Interest		Blocks Covered	Acreage Gross	Acreage Net
PPL 236	Papuan	Onshore	InterOil	100.00	%	53	1,112,464	1,112,464
PPL 237	Papuan	Onshore	InterOil	100.00	%	34	715,648	715,648
PPL 238	Papuan	Onshore	InterOil	100.00	%	94	1,978,565	1,978,565
PRL 152	Papuan	Onshore	InterOil	97.50	%	9	189,776	185,032
						Total	3,996,453	3,991,709

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

²An application to transfer 2.5% interest in PRL15 to Pac LNG pursuant to an agreement entered into in 2009 was submitted to the PNG Department of Petroleum and Energy; and was approved in December 2011.

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Costs incurred in relation to Exploration and Development activities

The following table outlines costs incurred by InterOil during the year ended December 31, 2011 for acquisitions and capital expenditure associated with exploration and development activities.

Nature of Cost	Amount (US $ million)
Property acquisition costs (Proved and unproved properties):		-
Exploration costs	$	18.4
Development costs	$	107.6
Total	$	126.0

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 IPI holders, PNGDV and/or Pac LNG), as further broken down by well type, during the year ended December 31, 2011.

Wells	Development				Exploration				Total
	Gross (US $ million)		Net (US $ million)		Gross (US $ million)		Net (US $ million)		Gross (US $ million)		Net (US $ million)
Gas	$	116.5	$	107.6	$	21.2	$	18.4	$	137.7	$	126.0
Oil		-		-		-		-		-		-
Service		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total	$	116.5	$	107.6	$	21.2	$	18.4	$	137.7	$	126.0

During the year ended December 31, 2011, we have commenced the construction of certain infrastructure such as roads, wharves, warehouses and camps to support the proposed appraisal and development drilling in the Elk and Antelope gas fields. In addition, we also undertook exploration activities in our three exploration licenses, PPL 236, PPL 237 and PPL 238. These exploration activities involved a regional airborne geophysical survey, various seismic surveys across a number of prospects and preparation for drilling of our next appraisal well, Triceratops 2, which was spudded in mid-January 2012. No wells were drilled during the year ended December 31, 2011. The preparation of the Triceratops 2 well site was completed at the end of 2011 and the Triceratops 2 well was spudded on January 15, 2012. The Triceratops 2 well is an appraisal well to test the presence of hydrocarbons and determine whether a potential reefal carbonate reservoir exists in the Triceratops field.

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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 and a subsequent 3 year term. The PPL license renewals require that we expend the amounts set out below and drill a total of 6 wells within those license areas during the renewed license term. The first 2 year term of the license anniversaries occurred in March 2011. On May 17, 2011, the State approved our request to extend all three licenses for the second two year term (years 3 and 4).

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 also approved this request on May 17, 2011.

We have met all other commitments under our licenses as of December 31, 2011.

Following are our applicable expenditure commitments for each PPL and PRL based on the approved renewals in March 2009 and the PRL granted in November 2010:

License	License Issued for second term on	Term		Commitment Years 1/2 ( $ Millions)		Commitment Years 3/5 ( $ 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	$	30.0	$	32.0		March 6, 2014
PRL15	November 30, 2010	15 years		$	53.0	$	20.0	$	73.0	(1)	November 30, 2025
			Totals	$	74.0	$	94.0	$	168.0

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

Petroleum License Details

Net Working Interests in Licenses

Our licenses are located onshore in the eastern Papuan Basin, northwest of Port Moresby and are largely owned by us, subject to investor elections to earn a working interest in certain discoveries pursuant to the terms of our various indirect participation interest agreements. All properties are currently operated by us. The State has the right under relevant PNG legislation to acquire a 22.5% interest (which includes 2% on behalf of landowners) in any PDL, by contributing its share of exploration and development costs. Pac LNG holds a 2.5% working interest in gas and condensate in the Elk and Antelope fields (which fields are located on PRL 15) under an agreement entered into in 2009. The table below sets forth the working interest position in the Elk and Antelope fields, currently under PRL 15, in the event that the State, Pac LNG and indirect participation interest holders all exercise their rights to acquire their allocated interests in the Elk and Antelope discoveries.

Participant	Working interests *			With State participation
InterOil		75.6114	%		58.5988	%
IPI holders		15.1386	%		11.7324	%
PNGDV		6.75	%		5.2312	%
Pac LNG		2.50	%		1.9375	%
State entitlement		0.00	%		20.50	%
Landowners entitlement		0.00	%		2.00	%
Total		100.00	%		100.00	%

* These interests assume all existing potential partners as at December 31, 2011 elect to participate.

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Petroleum Prospecting License 236

We have a 100% working interest in PPL 236, subject to potential participation and elections made by holders of indirect participation interests and the State. The license consists of 53 graticular blocks covering an area of 4,502 square kilometres or 1,112,464 acres.

The following are the work commitments for PPL 236 for the subsequent 2 year term, 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 to determine the likely controls on the distribution and reservoir quality of the onshore Late Oligocene to Late Miocene shallow marine reefal and shelfal carbonate depositional systems, likely controls on the source rock quality and maturity and tectonostratigraphic influences on the timing of the generation and expulsion of hydrocarbons, their migration, charge and preservation.

Petroleum Prospecting License 237

We have a 100% working interest in PPL 237, subject to potential participation and elections made by holders of indirect participation interests and the State. The license 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 two year term 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 to determine the likely controls on the distribution and reservoir quality of the onshore Late Oligocene to Late Miocene shallow marine reefal and shelfal carbonate depositional systems, likely controls on the source rock quality and maturity and tectonostratigraphic influences on the timing of the generation and expulsion of hydrocarbons, their migration, charge and preservation.

Petroleum Prospecting License 238

We have a 100% working interest in PPL 238, subject to potential participation and elections made by holders of indirect participation interests and the State. The license 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 and Elk-4A gas /condensate discovery wells were drilled, were excised from PPL 238 and incorporated into PRL 15.

Following are the work commitments for PPL 238 for the two year term ending in March 2013:

· Minimum expenditure of $ 10.0 million

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

· Complete thorough petroleum system and basin study to determine the likely controls on the distribution and reservoir quality of the onshore Late Oligocene to Late Miocene shallow marine reefal and shelfal carbonate depositional systems, likely controls on the source rock quality and maturity and tectonostratigraphic influences on the timing of the generation and expulsion of hydrocarbons, their migration, charge and preservation; and

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

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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.

At the end of 2011, we still held a 97.50% registered interest in PRL 15. However, this is subject to elections to be made by the State’s nominee to acquire a 22.5% interest on behalf of the State and landowners, to elections by holders of certain indirect participation interests, as set out in the table on the preceding page.

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

The total commitment over the first five year term 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

Petroleum Development License (“PDL”)

In order to progress the proposed development and commercialization of the Elk and Antelope fields, we are required 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 gas fields and additional acreage required for facilities and pipelines. We have commenced preparation of an application for a PDL.

The application for a PDL is made to the Department of Petroleum and Energy and must be accompanied by detailed proposals for the 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. 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 amongst other things. 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.

Upon application, the State will undertake a comprehensive review of the development proposals 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 and 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 Minister for Petroleum may grant the PDL. Should the PDL be issued, the acreage would be held subject to; (i) periodic review provided for in PNG’s Oil & Gas Act, and (ii) to the license holders continuing to meet commitments associated with the license grant.

Participation Agreements

In May 2003, we entered into an indirect participation agreement with PNGDV which was amended in May 2006. Under this amended agreement, 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 $112,500 for each 1% per well (with higher amounts to be paid if the depth exceeds 3,500 meters and the cost exceeds $8,500,000).

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In February 2005, we entered into an agreement with IPI holders pursuant to which the IPI holders paid us an aggregate of $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 the 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, including those in the Elk and Antelope fields.

In addition, PNGEI has the right to participate up to a 4.25% interest in 16 wells commencing from exploration wells numbered 9 to 24.  As at the end of December 31, 2011, we have drilled 6 exploration wells since 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; $112,500 per 1% plus actual costs over $1.0 million charged pro rata for each 1%.

Pac LNG holds a 2.5% direct working interest in gas and condensate in the Elk and Antelope fields under an agreement entered into in 2009.

If a PDL is granted, investors in our participation interest programs set out above have the right to become registered direct working interest owners by having their interest 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 which may be required to bring the field into production.

MIDSTREAM - REFINING

Our refinery is located across the harbor from Port Moresby, the capital city of Papua New Guinea. Our refinery is currently the sole refiner of hydrocarbons located in Papua New Guinea.

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 metres) 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.

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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 ”Mean of Platts Singapore” (”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”).

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 has been renewed subsequently and the current term agreement with Dalian runs for an 18 month period from January 1, 2011 until June 30, 2012.

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.

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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. 

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 2011, 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

We are developing, together with our partners, an LNG Project for the construction of liquefaction facilities now being designed to be built on the coast in the Gulf Province of PNG. The Gulf LNG Project is a staged project which we currently plan to build in 3 stages.

Stage 1 - Start up production: Has an expected start up in 2015 of between 3 to 5 mtpa of LNG with a condensate stripping unit of 400 to 900 mmscf/d (subject to PNG approvals).

Stage 2 – Expected Production: The LNG Project intends to target a total of 8 mtpa LNG production to follow, with a condensate stripping facility capacity of 1,350 mmscf/d capacity.

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

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.

Other than the core liquefaction facilities, the infrastructure being contemplated includes wells, gas gathering pipelines, condensate stripping facilities, condensate storage, a condensate pipeline and export handling facilities, a dry gas pipeline from the Elk and Antelope fields and LNG storage and marine export terminal.

Initial engineering design was undertaken in relation to the LNG Project and 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.

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During 2010, we and Pac LNG, decided to pursue 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 include the potential acceleration of first production and reduced operational risks.

In line with this revised approach, certain initial conditional agreements have been entered into with EWC for development of the LNG Project. Under the terms of these agreements, the LNG Project is intended to be developed in two initial phases, with a 2 mtpa liquefaction module to be followed immediately by a 1 mtpa module expansion plant. In return for fully funding the construction of the liquefaction facilities, EWC is to be entitled to a fee of 14.5% of the proceeds from LNG revenue derived from these facilities less agreed deductions, and subject to adjustments based on timing and execution for a 15 year period. The agreements remain conditional and the parties may still elect not to proceed with the LNG Project on the terms specified or at all.

We are also exploring employment of a floating liquefaction vessel, to be constructed by FLEX LNG and Samsung Heavy Industries. The vessel would integrate with and augment the land-based modules proposed by EWC. FEED work, including work specific for the LNG Project has been carried out and commercial negotiations are being undertaken.

Infrastructure required for the LNG Project includes a jetty and breakwater for the 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 processed natural gas pipeline from the CS 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.

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.

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. We have equal voting rights in the entity but hold approximately 85% of the economic interest in it by means of the Class B shares we hold and under our shareholders agreement (see “Material Contracts – LNG Project Shareholders Agreement dated July 30, 2007”). It is intended that our interest will be reduced and Pac LNG’s and possibly other third party interest's will increase as the LNG Project proceeds, and as Pac LNG and possibly others make certain equalizing payments, whether in response to cash calls or as a result of sales of a strategic interest in the LNG Project.

We are currently seeking an internationally recognized LNG operating and equity partner for the co-development of the LNG Project, which may include their acquisition of an interest in the Elk and Antelope fields.

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 British Petroleum and Royal Dutch Shell several years ago. This business includes bulk storage, transportation distribution, 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.

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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 sales.

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

We provide petroleum products to retail service stations, both operating under the InterOil brand name and under independent brands. The service stations are either owned by us, head leased to us with a sublease to company-approved operators, or independently owned and operated. We supply products to each of these service stations pursuant to distribution supply agreements. Under the cover of an equipment loan agreement, we also provide fuel pumps and related infrastructure to the operators of many of these retail service stations that are not owned or leased by us.

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 six 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 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.

Major Customers

We sell approximately 15% 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.

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During 2011, 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.

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 Elk and Antelope gas and gas condensate fields (see “Description of Our Business”), located in Papua New Guinea and contained within PRL 15, are 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 Antelope-1 and Antelope-2 wells and the reservoir consists of a dominantly shallow water reef/platform complex with a dolomite cap with well developed secondary porosity and permeability.

An evaluation of the resources of gas and condensate for the Elk and Antelope fields has been completed by GLJ Petroleum Consultants Ltd. (“GLJ”), an independent qualified reserves evaluator, as of December 31, 2011, 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 as follows:

Gross Contingent Resources Estimate for Gas and Condensate*

	Case
As at December 31, 2011	Low	Best	High
Initial Recoverable Sales Gas (tcf)	6.47	8.59	10.44
Initial Recoverable Condensate (mmbbls)	105.3	128.9	151.4
Initial Recoverable (mmboe)	1,183.6	1,560.4	1, 891.1

*These estimates represent 100% of the Elk and Antelope fields. InterOil currently has a 97.5% working interest in the Elk and Antelope fields.

Contingent Resource Estimate for Gas and Condensate – Net to InterOil*

	Case
As at December 31, 2011	Low	Best	High
Initial Recoverable Sales Gas (tcf)	3.79	5.03	6.12
Initial Recoverable Condensate (mmbbls)	61.7	75.5	88.7
Initial Recoverable (mmboe)	693.6	914.4	1,108.1

*These estimates are based upon InterOil 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 InterOil, including to participate fully and directly in the PDL.

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. The following contingencies must be met before the resources can be classified as reserves:

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

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

· Determination of economic viability.

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

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.

The accuracy of resource estimates are 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.

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 and 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 court.

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 2011. 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.

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We have 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.

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 developed and implemented an environmental policy which acknowledges that the principles of sustainable development are integral to responsible resource management and will strive to minimize impacts on the physical environment. Other environmental initiatives embrace the introduction of “Environmental Risk Analysis” for major projects in which hazards to the environment are identified, mitigating controls implemented and a “Hazard Register” developed to monitor any residual risks. We are also developing project specific “Environmental Management, Monitoring & Reporting Plans”, in compliance with the PNG environmental legislation and 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.

We have established a dedicated Community Relations department to oversee the management of community assistance programs and to manage 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 gas fields and other related licenses which will be required for pipelines and processing facilities associated with our LNG Project. These studies cover social mapping, social economic impact statements, land investigations and other related base line studies. The environmental approval process is well advanced and we have engaged expert consultants to assist us with the preparation of a detailed environmental impact statement, a project environmental management plan, a fisheries assessment report and other baseline environmental studies. These studies are a pre-requisite to the grant of a PDL, 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 a landowner, local and provincial government level for the purpose of procuring a development agreement on benefit sharing.

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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.

Our ability to develop our resources, including developing our planned condensate stripping or liquefaction facilities, together with associated pipelines and common facilities, is contingent on our ability to obtain significant funding.

Our share of the cost for the construction of liquefaction facilities will be significant, both to maintain our existing ownership interest in the joint venture or 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. Separate condensate stripping facilities, pipelines and common facilities will also be required at significant cost. 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, such as financing at the project level and/or divestment of a portion of our interest, including through potential joint ventures with Mitsui and with EWC and through the sell down process commissioned by us in September 2011. 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 our liquefaction facilities or our condensate stripping facilities.

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 liquefaction and condensate stripping facilities, 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 liquefaction and condensate stripping facilities. 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 and the downgrading of United States government debt, we, along with all other oil and gas entities, 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.

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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.

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, our proposed condensate stripping facilities, and the liquefactions facilities, each of which would require significant capital. Significant capital will also be required in order to fund additional exploration and development of the Elk and Antelope 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 our liquefaction facilities and condensate stripping facilities, we may not be able to timely construct and commission them.

We may not complete construction of our liquefaction facilities or condensate stripping facilities 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, EWC, FLEX LNG 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 PNG’s existing political environment and pending national elections.

· 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 and Antelope 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 liquefaction or condensate stripping facilities;

· our inability to finalize binding offtake 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) our liquefaction facilities or our condensate stripping facilities 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.

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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 liquefaction and condensate stripping facilities 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 liquefaction or condensate stripping facilities, such licenses may be withdrawn, or not obtained or renewed. Additionally, our ability to renew our licenses, develop our resources and develop liquefaction and condensate stripping facilities may be dependent on our ability to secure a strategic partner for the development of our resources and/or our proposed liquefaction and condensate stripping facilities. 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 liquefaction and condensate stripping facilities 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.

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

As of December 31, 2011, we had drilled a total of eight exploration wells and a number of appraisal wells in our licenses 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 PPL’s and PRL’s. 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 reserves. 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 crude feedstock, we cannot assure you that we will continue to be able to source adequate feedstock for our refinery.

Some crude oils that are suitable for use as refinery feedstock are available in the nearby region. However, 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.

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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. The State has made certain statements indicating further review of the formula during 2010 and 2011. It is possible that the State will refuse to maintain the project formula and that it may seek to reduce our refining margins.

We are purchasing our crude at a fluctuating spot market price. A primary reason for the renegotiation of the pricing formula with the State was to establish a new pricing mechanism that will correlate more closely with the daily 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 and 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 our 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.

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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 (“PGK”), 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.

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; 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, including the unresolved constitutional crisis affecting the country beginning in the final quarter of 2011. 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 liquefaction and gas stripping facilities and 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. Elections of Papua New Guinea’s national government are due to occur during 2012 which may have an effect on such attitudes. There can be no assurance 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 our liquefaction facilities, pipelines, common facilities and condensate stripping facilities, 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 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 Enquiry is being conducted into the grants of these SPL’s which is due to conclude by April 2012. There is no guarantee that the enquiry 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.

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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 liquefaction facilities, pipelines and condensate stripping facilities, 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.

Additional licenses and permits will be required to allow us to develop our Elk and Antelope discoveries, planned liquefaction facilities, pipelines and our proposed condensate stripping facilities. 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 and 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 gas laws and permits may be an obstacle to the development of our liquefaction and condensate stripping facilities, 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. If these risks prevent us from operating at full capacity in the future, our profitability may be negatively affected.

The project agreement with the government of Papua New Guinea gives us certain rights to supply the domestic market in Papua New Guinea with our refined products. However, not all domestic demand was sourced from our refinery during 2011 as 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 18,000 barrels of crude feedstock a 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, our project agreement with the State 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.

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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 government of Papua New Guinea 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 PPL’s, and to acquire additional properties;

· 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 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 will 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. 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.

Our proposed 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 our 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 from our refinery.

During 2011, our competitors continued with their direct importation of refined petroleum products rather than sourcing 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. Such an increase in our competitors’ importation has a negative effect on our business and could materially affect our results from operations.

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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.

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 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.

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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 2011 would have resulted in a $507,666 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 climatic 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 damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect 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.

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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 damages, 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 damages caused by, among others, previous property owners or operators.  We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change and greenhouse gases, resulting in increased operating costs.  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, results of operations and liquidity. Additionally, more stringent green house gas regulation could impact demand for oil and gas.

These laws and governmental regulations, which cover matters including drilling, refinery and 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 impact on our operating costs.  While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations, no assurances can be given 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.

At the current date, we had $26.5 million in long-term debt with OPIC which matures in 2015, together with principal repayments due during 2012 totaling $9.0 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 proposed condensate stripping facilities, 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.

Annual Information Form   INTEROIL CORPORATION     40

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.

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, 2011, 48,121,071 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, 2011. 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 the shareholders of InterOil, to receive, out of all profits or surplus available for dividends, any dividends declared by InterOil on the common shares, and to receive the remaining property of InterOil in the event of liquidation, dissolution or winding up of InterOil, 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 the directors of InterOil. 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 OPIC secured loan facility, the Mitsui preliminary financing agreement, trade payables and lease obligations.

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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 InterOil. 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 of InterOil at a substantial discount to the market price at the time. Phil Mulacek, the Chairman and Chief Executive Officer of InterOil, holds a large proportion of the 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, 2011, there were options outstanding to purchase 1,457,827 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, 2011, restricted stock units entitling employees rights to 152,190 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.

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, 2011, IPI holders held rights to convert up to 340,480 common shares remained.

Annual Information Form   INTEROIL CORPORATION     42

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 2011:

New York Stock Exchange (NYSE:IOC) in United States Dollars
Month	High		Low		Volume
January		78.20		66.10		10,433,126
February		77.50		68.75		7,577,376
March		81.92		68.08		14,316,189
April		76.00		60.27		12,929,341
May		64.04		55.34		10,696,918
June		61.90		47.29		12,500,656
July		65.71		56.55		8,767,854
August		68.47		48.17		13,862,792
September		64.40		37.90		21,319,060
October		52.00		31.18		17,217,574
November		61.79		39.66		12,579,874
December		57.00		44.48		13,532,044
Total		67.41		51.98		155,732,804

Prior sales

· 265,440 common shares were issued during 2011 upon the exercise of stock options by employees, officers or directors at various prices defined by the option grant terms in accordance with relevant stock incentive plans.

· 50,079 common shares were issued during 2011 upon the vesting of restricted stock units granted to employees, officers or directors defined by the restricted stock unit grant terms in accordance with relevant stock incentive plans.

· 5,000 common shares were issued to Petroleum Independent & Exploration Corporation, a company owned and controlled by our Chairman and Chief Executive Officer, Phil Mulacek, during 2011 in exchange for an equivalent number of shares held by that entity in our subsidiary South Pacific Refining Limited (formerly SP InterOil LDC) at a deemed issue price of $48.77 per share.

Annual Information Form   INTEROIL CORPORATION     43

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
Phil E. Mulacek Texas, USA	Chairman, director and Chief Executive Officer	May 29, 1997
Christian Vinson Port Moresby, PNG	Vice President Corporate Development and Government Affairs, Director	May 29, 1997
Gaylen Byker Michigan, USA	Director(1)	May 29, 1997
Roger Grundy Derbyshire, UK	Director (2)	May 29, 1997
Roger F. Lewis Western Australia, Australia	Director(3)	November 26, 2008
Ford Nicholson British Columbia, Canada	Director (4)	June 22, 2010
William Jasper III Texas, USA	President and Chief Operating Officer	September 18, 2006
Collin Visaggio Western Australia, Australia	Chief Financial Officer	October 26, 2006
Mark Laurie South Australia, Australia	General Counsel and Corporate Secretary	June 12, 2007

Notes:

(1)   Gaylen Byker acts is the Company’s Lead Independent Director and acts as Chairman of each of the Board’s Nominating and Governance Committee and Compensation Committee and has held such positions throughout 2011. He is a member of the Audit Committee and of the Reserves Committee. He acts as deputy Chairman of the Board and chairs a number of its meetings.

(2)   Roger Grundy was Chairman of the Reserves Committee throughout 2011.

(3)   Roger Lewis was Chairman of the Audit Committee, and a member of the Nominating and Governance Committee and Compensation Committee throughout 2011.

(4)   Ford Nicholson was a member of the Audit Committee and Reserves Committee throughout 2011.

(5)   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 the directors of InterOil 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 29, 2012, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly, 4,896,898 common shares, representing 10.17% 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, 1,000,868 shares are issuable upon exercise of outstanding options and restricted stock units, resulting in directors and executive officers holding 11.63% 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. Nicholson 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 while Mr. Nicholson and Dr. Byker are additional members.

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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 the Chairman of our Board of Directors and our Chief Executive Officer. He has held these positions since InterOil’s 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 the Executive Vice President of InterOil 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 InterOil, 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 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.

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 earlier this year, 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.

William J Jasper III is President and Chief Operating Officer of InterOil. Mr. Jasper joined the Company on September 18, 2006 and leads the refining and downstream businesses. Prior to joining InterOil, 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.

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Collin F. Visaggio is the Chief Financial Officer of InterOil. 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 Masters 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 InterOil, 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.

Mark Laurie is General Counsel and Corporate Secretary of InterOil. Mr. Laurie joined us on June 12, 2007. He holds Law and Economics degrees from the University of Adelaide in South Australia. He was admitted to practice law as a barrister and solicitor in Australia in 1991. Mr. Laurie was also appointed a notary public in 1997. Prior to joining InterOil, and from August 2003, he was Company Secretary, General Counsel, Manager Corporate and Investor Relations, and Manager - Town Infrastructure with Lihir Gold Limited, a Papua New Guinea gold mining company listed in Australia, the United States and in Papua New Guinea. Mr. Laurie lived in Papua New Guinea throughout this period. Immediately prior to working for Lihir Gold, he worked as Commercial Manager for the Electronic Systems Division of Tenix Defence Pty Limited, a privately held government contractor specializing in high-tech electronic and computer engineering work for defence and other applications. Between mid-1996 and December 2001, he held positions as General Counsel, Company Secretary and Vice President of Investor Relations with F.H. Faulding and Co. Limited, an Australian based multinational pharmaceutical and health care company listed in Australia and the United States. Prior to that Mr. Laurie worked with commercial law firms in Ottawa, Canada and Adelaide, South Australia.

Conflicts of Interest

There are potential conflicts of interest to which some of the directors and officers of InterOil will be subject in connection with the operations of InterOil.  Situations may arise where some of the business activities of the directors and officers will be in direct competition with InterOil. In particular, certain directors and officers of InterOil will be in managerial or director positions with other oil and gas companies, whose operations may, from time to time, be in direct competition InterOil or entities which may, from time to time, provide financing to, or make equity investments in, competitors of InterOil.  In addition, certain of the directors have on-going relationships with other entities in respect of which InterOil has entered or may enter into material agreements or has 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. InterOil intends 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 InterOil on customary commercial terms.

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

Annual Information Form   INTEROIL CORPORATION     46

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 2011.

Composition of the Audit Committee

The current members of the Audit Committee are Mr. Roger Lewis, Dr. Gaylen Byker and Mr. Ford Nicholson. All held their positions throughout 2011.Mr. Lewis, Dr. Byker and Mr. Nicholson 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”:

This education and experience is such that each member has an understanding of the accounting principles used by InterOil to prepare its 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 InterOil’s 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 InterOil's 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
	2011		2010
Audit Fees(1)	$	1,576,187	$	1,709,000
Audit-Related Fees(2)		-	$	322,788
Tax Fees(3)	$	542,904	$	355,221
All Other Fees(4)	$	53,936	$	67,611
Total	$	2,173,027	$	2,454,620

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.     "Audit-Related Fees" means the aggregate fees billed in each of the last two fiscal years for assurance and related services by the issuer's external auditor that are reasonably related to the performance of the audit or review of the issuer's financial statements and are not reported as Audit Fees above.

3.     "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.

4.     "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.

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LEGAL PROCEEDINGS AND REGULATORY ACTIONS

During the second half of 2011, the PNG Customs Service commenced an audit of our petroleum product imports into Papua New Guinea for the years 2007 to 2010.  We received a letter in November 2011 from the then Commissioner of Customs setting out certain findings from the audit. This letter included comments alleging that payment of import GST was required and had not been made on imports of certain refined products. As well as requiring payment of GST, the letter noted that administrative penalties were able to be levied by Customs in the range of 50% to 200% of the assessed amounts as per the Customs Act. We have since met with the Customs Service and provided it with supporting documentation to demonstrate that the GST amounts claimed in their letter have all been paid. We have currently made a provision based on our best estimate in relation to this matter and are working closely with the authority to provide all requested information in order to finalize the audit.

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 or 2011.

In November of 2011, we elected to exchange the 5,000 shares held in SP InterOil LDC (now South Pacific Refining Limited) by Petroleum Investment & Exploration Corporation, a company owned and controlled by our Chairman and Chief Executive Officer, Mr. Phil Mulacek, for 5,000 shares in InterOil.

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

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 2011:

Condensate Stripping Plant Joint Venture Operating Agreement 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 InterOil’s Elk and Antelope field site in Gulf Province, Papua New Guinea. Under the CSP JV, InterOil 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”.

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

Investment Agreement dated October 30, 2008

On October 30, 2008, Petromin, a government entity mandated to invest in resource projects on behalf of the State, together with its subsidiary, Eda LNG Limited (“Eda”), entered into an agreement with InterOil and its subsidiary, SPI (208) Limited, under which Eda agreed to take a 20.5% direct interest in the Elk and Antelope fields and to fund 20.5% of the costs of developing those fields. The interest and funding was contingent upon Petromin’s nomination by the State as the entity designated to hold the State’s interest in accordance with PNG’s Oil & Gas Act and upon issuance of the PDL. Certain funding, in relation to sunk costs, was contingent upon grant of a PDL for the field. The interest and funding commitment was able to be increased to 22.5% subsequent to grant of a PDL in the event that Petromin was also nominated to hold the 2% interest also provided for under the Oil & Gas Act on behalf of relevant landowners.

At the end of the 2011 year, the parties agreed that the Agreement’s intended operation had ended and that it should terminate.

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 dated February 27, 2009 under which InterOil 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 InterOil and to the proposed aligned structure of the LNG Project.

Amended and Restated Indirect Participation Interest Agreement dated February 25, 2005

In February 2005, we entered into an indirect participation agreement with institutional accredited investors in which the investors paid us $125.0 million and we agreed to drill eight exploration wells in Papua New Guinea on PPL’s 236, 237 and/or 238. We have drilled four of these eight exploration wells to date. The terms of this agreement are described under the heading “Description of Our Business—Upstream-Exploration and Production—Indirect Participation Agreements”. Under the agreement, investors are also required to contribute their proportionate share of completion costs associated with the eight exploration wells and to subsequent development and appraisal works. In the event that exploration proves successful, investors may elect to convert their interests to direct working interests in the relevant PDL, or may continue to maintain indirect participation interests. Investors also have the right, prior to completion of the eighth well, to convert their interest into our common shares, based upon a certain formula set out in the agreement. Some investors have elected to waive this conversion right. This agreement was amended by Amendment No. 1 signed on November 5, 2007. The amendment allows us to pay from the joint account all commissions and other expenses incurred in connection with structuring this agreement, soliciting investors and otherwise entering into this agreement.

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Amended Indirect Participation Interest Agreement dated May 12, 2004

We entered into an Amended Indirect Participation Interest Agreement with PNG Energy Investors, LLC on May 12, 2004. This agreement grants PNG Energy Investors, LLC the right to acquire up to a 4.25% working interest in sixteen exploration wells following our drilling of an initial eight exploration wells. As of December 31, 2011, we had drilled six exploration wells associated with this program. PNG Energy Investors, LLC will have the right to acquire a working interest in the ninth through the twenty fourth exploration wells and in order to participate PNGEI would be required to contribute for each exploration well, $112,500 per percentage point plus actual cost over $1.0 million charged pro rata per percentage point.

Drilling Participation Agreement dated July 21, 2003

During 2004, we raised $12.2 million from PNGDV, as agent and trustee for its investors, pursuant to the Drilling Participation Agreement dated July 21, 2003 with InterOil. Under this agreement PNGDV had the right to acquire a working interest in our first sixteen exploration wells equal to 13.5% multiplied by the result of eight divided by the number of exploration wells we drill. PNGDV will be required to pay its share of any completion costs for future exploration wells or future development costs if an exploration well is a commercial success. By December 31, 2005, PNG Drilling Ventures Limited had converted $2.5 million of their investment into 141,545 of our common shares. In May 2006, PNGDV converted their remaining interest into an additional 575,575 shares and also retained a 6.75% interest in the next four wells. Elk–1 was the first of these wells and Antelope-1 the second. PNGDV also has the right to participate in a further sixteen wells to follow the four mentioned above up to a level of 5.75% at a cost per well of $112,500 per 1%, with higher amounts to be paid if the depth exceeds 3,500 metres and the cost of the well exceeds $8.5 million.

OPIC Loan Agreement dated June 12, 2001

An $85.0 million loan from OPIC to EP InterOil Limited, a subsidiary of InterOil, was used to finance the construction of our refinery at Napa Napa, Port Moresby (see under the heading “Description of the Business – Midstream - Refining”) and is secured by all of the refinery’s capital assets. The loan matures on December 31, 2015 and requires semi-annual principal payments of $4.5 million and semi-annual interest payments. Each disbursement under the loan bears interest at a rate equal to a weighted average of treasury rates at the time of disbursement plus 3.0%. During 2011, the weighted average interest rate of all disbursements pursuant to this loan agreement was 6.93%, and the two required installments, were paid. In addition, during 2011 OPIC agreed to release certain sponsor support collateral associated with the loan agreement provided by various InterOil subsidiary companies and by interests associated with Mr. Mulacek. The parent guarantee provided by InterOil is to continue for the life of the loan.

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 InterOil 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 ‘Mean of Platts Singapore’ (‘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.

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

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All other contracts entered or still in effect during 2011 were done so in the ordinary course of our business or were not material to us.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares and the Series A Preferred Shares is Computershare Investor Services, Inc.

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.

100 University Avenue, 9^th Floor

Toronto, Ontario

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, 2011. 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 Petroleum Consultants Limited, as independent qualified reserves evaluators. As at the date hereof, the principals of GLJ Petroleum Consultants Limited, 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, 2011 (the “Annual Financial Statements”) and related 2011 MD&A. Our Annual Financial Statements, 2011 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, 2011 MD&A, and any additional copies of this Annual Information Form 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.

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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, 2011, and (ii) resources as at December 31, 2011.

The board of directors of the Company has determined that the Company had no reserves as at December 31, 2011.

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 March 16, 2012.

"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

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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 prepared an assessment of the Company’s resources data as at December 31, 2011. The resources data are estimates of low, best and high estimates of contingent resources as at December 31, 2011.

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 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, 2011:

	Description		Location of
	and		Reserves
	Preparation		(Country or		Company Gross
Independent	Date of		Foreign		Contingent Resources
Qualified Reserves	Assessment		Geographic		MMBOE
Evaluator	Report		Area)		Low		Best		High
GLJ Petroleum Consultants		February 28, 2012		Papua New Guinea		693.6		914.4		1108.1

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 judgments regarding future events, actual results will vary and the variations may be material.

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.

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EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 28, 2012

Keith M. Braaten, P. Eng.

Executive Vice-President

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Schedule C

INTEROIL CORPORATION CHARTER OF THE

AUDIT COMMITTEE OF THE BOARD OF DIRECTORS

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.

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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.

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.

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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.

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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-minimus 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.

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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.

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.

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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.

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.

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