InterOil Corporation





Annual Information Form



For the Year Ended December 31, 2010

March 22, 2011
  TABLE OF CONTENTS
  TABLE OF CONTENTS
1PRELIMINARY NOTES
2GENERAL
2NON-GAAP MEASURES AND RECONCILIATION
2LEGAL NOTICE – FORWARD-LOOKING STATEMENTS
2ABBREVIATIONS AND EQUIVALENCIES
4CONVERSION
5GLOSSARY OF TERMS
5CORPORATE STRUCTURE
9GENERAL DEVELOPMENT OF THE BUSINESS
10BUSINESS STRATEGY
14DESCRIPTION OF OUR BUSINESS
16UPSTREAM - EXPLORATION AND PRODUCTION
16MIDSTREAM - REFINING
21MIDSTREAM - LIQUEFACTION
23DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION
24RESOURCES
25THE ENVIRONMENT AND COMMUNITY RELATIONS
27RISK FACTORS
28DIVIDENDS
37DESCRIPTION OF CAPITAL STRUCTURE
37MARKET FOR OUR SECURITIES
39DIRECTORS AND EXECUTIVE OFFICERS
40AUDIT COMMITTEE
43LEGAL PROCEEDINGS AND REGULATORY ACTIONS
44INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
45MATERIAL CONTRACTS
45TRANSFER AGENT AND REGISTRAR
48INTERESTS OF EXPERTS
48ADDITIONAL INFORMATION
48Schedule A – Report of Management and Directors on Oil and Gas Disclosure
49Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator
50Schedule C – Audit Committee Charter
52
 
 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, 2010.  It should be read in conjunction with InterOil’s audited consolidated financial statements and notes for the year ended December 31, 2010 and Management’s Discussion and Analysis for the year ended December 31, 2010 (“2010 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, 2010 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 by them, their places of residence and principal occupations, both present and historical, 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 United States or Canadian GAAP 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 Canadian GAAP.  Further, EBITDA is not a measure of cash flow under Canadian GAAP 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 2010 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, plans for our exploration (including drilling plans) and other business activities and results therefrom; the construction of proposed liquefaction facilities and condensate stripping facilities in Papua New Guinea; the development of such liquefaction and condensate stripping facilities; the commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate; the potential discovery of any commercial quantities of oil; cash flows from operations; sources of capital; operating costs; business strategy; contingent liabilities; environmental matters; and plans and objectives for future operations; the timing, maturity and amount of future capital and other expenditures.
 
 Many risks and uncertainties may affect the matters addressed in these forward-looking statements, including but not limited to:
  Annual Information Form   INTEROIL CORPORATION      2
 ·
our ability to finance the development of liquefaction and condensate stripping facilities;
 
 ·
our ability to negotiate final definitive agreements contemplated by the Heads of Agreement with Energy World Corporation, Ltd;
 
 ·
the uncertainty on 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;
 
 ·
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;
 
 ·
risks of legal action against us
 
 ·
political, legal and economic risks in Papua New Guinea;
 
 ·
stock price volatility;
 
 ·
landowner claims and disruption;
 
 ·
compliance with and changes in foreign governmental 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;
 
 ·
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;
 
 ·
the impact of legislation regulating emissions of greenhouse gases on current and potential markets for our products;
 
 ·
general economic conditions, including any further economic downturn and the availability of credit;
 
 ·
actions by our joint venture partners;
 
 ·
the impact of our current debt on our ability to obtain further financing; and
  Annual Information Form   INTEROIL CORPORATION      3
 
  ·
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 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, unless otherwise specified 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 report is expressly qualified by this cautionary statement.
 ABBREVIATIONS AND EQUIVALENCIES
 Abbreviations
 Crude Oil and Natural Gas Liquids

Natural Gasbbl
one barrel equalling 34.972 Imperial gallons or 42 U.S. gallons

btu
British Thermal Unitsbblspd
barrels per day

mscf
thousand standard cubic feetboe(1)
barrels of oil equivalent

mscfpd
thousand standard cubic feet per dayboepd
barrels of oil equivalent per day

mmbtu
million British Thermal Unitsbpsd
barrels per stream day

mmbtupd
million British Thermal Units per daymboe
thousand barrels of oil equivalent

mmscf
million standard cubic feetmbbl
thousand barrels

mmscfpd
million standard cubic feet per daymmbbls
million barrels

mtpa
million tonnes per annummmboe
million barrels of oil equivalent

scfpd
standard cubic feet per dayWTI
West Texas Intermediate crude oil delivered at Cushing, Oklahoma

tcf
trillion standard cubic feetbscf
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.
  Annual Information Form   INTEROIL CORPORATION      4
  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 Bymcf

cubic metres

28.317cubic metres

cubic feet

35.315bbls

cubic metres

0.159cubic metres

bbls

6.289feet

metres

0.305metres

feet

3.281miles

kilometers

1.609kilometers

miles

0.621acres

hectares

0.405hectares

acres

2.471
 
 GLOSSARY OF TERMS
 “AIF”means this Annual Information Form for the year ended December 31, 2010.
 
 “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” BP Singapore Pte Limited.
 
 “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.
 
 “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.
 
 “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”.
 
 “EWC” means Energy World Corporation Limited., a company organized under the laws of Australia.
  Annual Information Form   INTEROIL CORPORATION      5
 
 “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.
 
 “GAAP” means 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 2009 Report" means the report dated February 17, 2010 with an effective date of December 31, 2009 setting forth certain information regarding contingent resources of InterOil's interests in the Elk and Antelope fields in PNG.
 
 "GLJ 1010 Report" means the report dated March 7, 2010 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.
 
 “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 the Independent Consumer and Competition Commission in Papua New Guinea.
 
 “IPI Agreement” means the Amended and Restated Indirect Participation Agreement dated February 25, 2005 (see “Material Contracts”).
 
 “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.
 
 “Joint Venture Company” or "PNG LNG" means PNG LNG, Inc., a joint venture company established in 2007 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)
 
 “LNG”means liquefied natural gas.  Natural gas converted to a liquid state by pressure and severe cooling for transportation purposes, and then returned to a gaseous state to be used as fuel.  LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas liquids, which are heavier fractions that occur naturally as liquids.
  Annual Information Form   INTEROIL CORPORATION      6
  “LNGL” means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG formed in Papua New Guinea.
 
 “LNG Project” means the development by us of liquefaction facilities in Papua New Guinea described as our Midstream Liquefaction business segment and being undertaken as a joint venture with Pac LNG through the Joint Venture Company, presently being pursued with EWC, inter alios, in accordance with certain conditional agreements signed in February 2011.
 
 “LPG”  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”meansOverseas Private Investment Corporation, an agency of the United States Government.
 
 “Pac LNG” 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 and is an IPI holder.
 
 “PDL”meansPetroleum 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”meansPNG Drilling Ventures Limited,an entity with which we entered into an indirect participation agreement in May 2003.  (See “Description of our Business – Upstream - Exploration and Production – Participation  Agreements”, “Material Contracts – Drilling Participation Agreement dated July 21, 2003”).
 
 “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.
 Annual Information Form   INTEROIL CORPORATION      7
 
  “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 subclassified 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).
  Annual Information Form   INTEROIL CORPORATION      8
  CORPORATE STRUCTURE
  Name, Address and Incorporation
 
 InterOil Corporation is a Yukon Territory corporation, continued under the YBCA on August 24, 2007.  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 1, 60-92 Cook 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 are set out in the diagram below.
 
 
 Annual Information Form   INTEROIL CORPORATION      9
 GENERAL DEVELOPMENT OF THE BUSINESS
  Three Year History
 
 We are developing a vertically integrated energy company operating in Papua New Guinea and the surrounding Southwest Pacific region.  The following is a summary of significant events in the development of our businesses and corporate activities over the past three years.
 
 Upstream – Exploration and Production
 
 Our upstream business segment has focused on the drilling program in what we refer to as the Elk and Antelope fields in Papua New Guinea.  This has led to natural gas and natural gas liquids discoveries in those fields.  During 2010, we continued to further evaluate and delineate the size and structure of these discoveries by drilling additional appraisal wells and carrying out a number of DST’s. These discoveries are located in an area requiring construction of a pipeline and a gas liquefaction facility in order to process gas extracted.  This commercialization project will require substantial financing and will take a number of years to complete.
 
 The Elk 4/4A well was spudded in November 2007.  On May 1, 2008, while drilling at 7,402 feet (2,256 metres) the well experienced a gas kick, which resulted in a flow of natural gas and natural gas liquids to the surface and a discovery in the Antelope structure.  The well was completed with 41⁄2 inch tubing as a potential producer and completion work ended on August 31, 2008.  On September 4, 2008, the well recorded a short term gas flow rate of 105 mmscfpd.
 
 In June, 2008, we accepted an offer of $6.5 million from Horizon Oil Limited to purchase our working interests in PRL 4 and PRL 5.  The decision was made to allow us to focus our efforts on developing the Elk and Antelope fields and PPL’s 236, 237 and 238.  We retained a right of first refusal to purchase hydrocarbon condensates from these licenses.
 
 On October 30, 2008, Petromin entered into an agreement with us to take a direct interest in the Elk and Antelope fields and fund 20.5% of the costs of its development if certain conditions are met (see “Material Contracts – Investment Agreement dated October 30, 2008”). The State’s right to invest arises under legislation and is exercisable upon issuance of the PDL, which has not yet occurred.  On grant of a PDL, the State’s nominee would need to pay us 20.5% of all other sunk costs incurred by us prior to entering into the agreement.  Until the PDL is granted, any payment made by the State’s nominee is to be separately held in a liability account in accordance with the provisions of the
agreement.  Once the PDL is granted, the conveyance of this interest to the State is able to be formalized, and we are obliged to distribute the proceeds received from the State’s nominee among the existing interest holders (InterOil, IPI holders, PNGDV and Pac LNG) on a pro-rata basis based on the interest surrendered by each to the State.  The State may also elect to participate in a further 2.0% working interest on behalf of the landowners of the licensed areas.
 
 On October 15, 2008, the Antelope 1 well was spudded.  On December 31, 2008, gas was encountered at 1,748 metres in a limestone/dolomite reservoir which flowed to surface.  The well was drilled to 2,370 metres on January 7, 2009 and was logged indicating a homogenous gross reservoir of 611 metres and net reservoir of 550 metres.  Average porosity over the 550 metres was 8.4% with some dolomite zones displaying over 20% porosity which may be indicative of a reef.  On completion, the well was made ready for future production and/or long term flow testing.
  On July 27, 2009, the Antelope 2 well, located approximately 4 kilometers south of Antelope 1 and within the boundaries of PPL 237, was spudded. After drilling to 1,832 metres, a 9 5/8 inch liner was set at the top of the limestone section.  The well was drilled to 2,260 metres and temporarily completed with 7 inch tubing.  A high rate flow test was performed in December 2009 to confirm deliverability. This flow test recorded a flow rate of 705 mmcfd which rate yields 11,200 bbls of condensate per day .  Subsequent to this flow test, the 7 inch tubing was removed and a 7 inch
liner was run.  A 6 1⁄4 inch hole was then drilled to 2325 metres and DST 2 was performed.  This DST confirmed gas and condensate with a stabilized CGR of over 20 bbl/mmcf.  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.
  Annual Information Form   INTEROIL CORPORATION     10
 
 In September 2009, a 100 kilometer 2D 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 were subsequently interpreted.
 
 During the third quarter of 2009, Pac LNG (which holds voting and economic interests in the Joint Venture Company pursuing the LNG Project) acquired a 2.5% direct working interest in gas and condensate in the Elk and Antelope fields.  The interest was acquired  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 for certain historical exploration costs and transferred to us of 2.5% of Pac LNG’s economic interest in the Joint Venture Company.
 
 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% 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, InterOil issued 1,344,710 common shares to the participating investors, having an aggregate value of $62.9 million when issued.
 
 In December 2009, we agreed on terms to divest our 15% non-operated interest in PPL 244, an offshore block in the Gulf of Papua in exchange for $2.1 million.  The decision was made to allow us to focus our efforts on the Elk and Antelope fields and PPL’s 236, 237 and 238.  This divestment was approved by the State and finalized in October 2010.
 
 To further enhance our ability to explore on our prospecting licenses a second drilling rig was acquired on February 9, 2010, for approximately $4.5 million with additional costs incurred for the inspection, package and transport of the rig.  The rig was shipped from New Zealand to PNG and is currently at our facility in Napa Napa.  Preparations are under way for this rig to commence operations in the field.
 
 During 2010, InterOil continued efforts to commercialize the Elk and Antelope fields.  InterOil completed drilling and logging activities on the Antelope 2 well, having drilled a further horizontal section in order to test the CGR in the deeper section of the reservoir.  Various DST’s were performed with the DST #7 producing a stabilized CGR of approximately 24.0 to 27.7 barrels of condensate per million cubic feet of natural gas.  This was in addition to the first horizontal section drilled earlier in the year.  A total of 1,596 meters of horizontal drilling was performed from the original vertical well and these two sections improved our knowledge of the deeper portion of the Antelope reservoir.  Subsequently, this well was suspended as a producer.
 
 In the first quarter of 2010, the pre-FEED phase for the proposed CS Project was completed, and on April 15, 2010 we entered into a preliminary works joint venture and preliminary works financing agreement with Mitsui to commence FEED work.
 
 On August 4, 2010, we entered into a Joint Venture Operating Agreement ("JVOA") (see “Material Contracts”) for the CS Project with Mitsui; which agreement replaced a 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.   Mitsui will be responsible for arranging or providing financing for the capital costs of the CS Project in the event that a positive FID is made.  An option deed was also executed with Mitsui under which Mitsui has the option to acquire interests of up to a 5% in the Elk and Antelope fields, and in our proposed liquefaction
facilities.  Mitsui paid us $6.3 million in exchange for this option, with such amount to be adjusted against the final acquisition price in the event the option is exercised.
 
 On November 30, 2010, InterOil was granted PRL 15, covering blocks including and surrounding the Elk and Antelope fields, unifying the fields into a single license separate from our exploration acreage and specifying minimum work commitment activities over the next five years.
 
 On July 19, 2010 and December 16, 2010, InterOil bought back a combined total of 1.45% of IPI interests held under the 2005 Amended and Restated Indirect Participation Agreement. In exchange for these interests, we issued 754,788 common shares to those investors having an aggregate value of US$50.7 million when issued.  Our current interest in our exploration licenses after this transaction is 75.6114%, assuming that all remaining IPI investors exercise their working interest rights in such licenses and excluding the interests that the State is able to exercise under relevant legislation.
  Annual Information Form   INTEROIL CORPORATION     11
  During the third quarter of 2010, we completed  the acquisition, processing and interpretation of 100 kilometres  of development seismic over the Antelope structure and also completed two phases of 2D seismic acquisition and processing over the Bwata gas field (PPL 237) and the Wolverine prospect (PPL 238).  The second phase of this program focused on further delineation of the Bwata and Wolverine structures. The data has been processed and is currently being interpreted.  At the end of the 2010 the initial preparatory work on a seismic program for PPL 236 was well advanced with social mapping and construction of the base camp initiated.  Seismic work on PPL 236 will fulfil our licence commitment.
 
 Midstream – Refining segment
 
 Beginning in November 2007, the basis of calculating the IPP at which products from our refinery may be sold domestically in PNG was revised to more closely mirror changes regional refined product pricing than the previous pricing formula.  The IPP formula was modified by changing the benchmark price for each refined product from ”Singapore Posted Prices”, which was no longer being updated, to “Mean of Platts Singapore” (“MOPS”), which is the benchmark price for refined products in the Asia Pacific region.  Minor additional adjustments to this interim formula were made in June 2008. Finalization of the IPP formula and replacement of it in our Project Agreement with the State (See “Material Contracts
– Project Agreement”) remains subject to further review and agreement.  The State has recently reinitiated discussions in relation to the IPP formula and the outcome of the review and these discussions is uncertain.  (See “Risk Factors”).
 
 During 2008, further improvements were made to the refinery such that its operational capacity was expanded from its nameplate 32,500 bblpd to 36,500 bblpd.
 
 During 2010, our total throughput per day (excluding shut down days) was 24,682 bblpd versus 21,155 bblpd in 2009 and 22,034 bblpd in 2008.  The total number of barrels processed into product at our refinery for 2010 was 6.71 million as compared with 5.72 million for 2009, and 5.67 million in 2008.
 
 Midstream – Liquefaction segment
 
 On July 30, 2007, a shareholders’ agreement was signed between InterOil LNG Holdings Inc., a subsidiary of InterOil, Pac LNG, Merrill Lynch Commodities (Europe) Limited (“Merrill Lynch”) and the Joint Venture Company for the development of a gas liquefaction facilities and associated infrastructure referred to as the LNG Project.
 In 2008, certain disputes related to the LNG Project arose among Merrill Lynch and the other members of the Joint Venture Company, including InterOil. On February 27, 2009, a settlement agreement was entered into whereby InterOil LNG Holdings Inc. and Pac LNG acquired Merrill Lynch’s interests in the Joint Venture Company and settled all outstanding matters in dispute.  We ultimately issued 499,834 common shares valued at $11.25 million for our share of the consideration payable to Merrill Lynch in relation to the settlement.  As a result of this transaction, Merrill Lynch no longer has any ownership in the LNG Project or in the Joint Venture Company.
 
 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, along with pipeline infrastructure 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 a FID.
  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.  Thereafter, 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 in the Gulf Province of PNG.  The LNG plant is intended to be developed in two initial phases 2 mtpa followed immediately by a 1 mtpa expansion.  The contractual terms relating to the 3 mtpa plant
have been defined with the execution of the 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, less agreed deductions, and subject to adjustments based on timing and execution.  We can provide no assurances that we will enter into unconditional agreement.
 Annual Information Form   INTEROIL CORPORATION     12
  Downstream – Wholesale and Retail Distribution
 
 During 2008, we conducted a terminal and depot asset rationalization and refurbishment program.
 
 In keeping with our retail network strategy plan, during 2009 we acquired two additional retail sites and entered into a head lease for an additional site. As of December 31, 2010, 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.  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.
 
 In 2009, we entered into our first direct chartering shipping arrangement with the owner of a fuel transport vessel which will result in us being able to direct vessel movements rather than co-ordinate shipping with other distributors. During 2010, the second vessel was directly chartered and we now directly manage all our sea freight movements of fuel within PNG.
 
 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 next five year period until 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.
 
 Financing
 
 In 2008, we undertook the following financing transactions:
 
 ·
In February 2008, payment of the two installments of $4.5 million to OPIC (originally deferred in 2007) were deferred further until the end of the OPIC loan period.
 
 ·
In May 2008, we repaid $60.0 million of the expiring $130.0 million bridging facility by issuing common shares to this value.  The $70.0 million balance of this facility was repaid on May 12, 2008 with funds raised from the issuance of $95.0 million principal amount of debentures.  In July and August 2008, $15.0 million of the $95.0 million principal amount of debentures was converted into 600,000 common shares.  In November 2008, an additional $1.0 million of the $95.0 million debentures was converted into 41,000 common shares.
 
 ·
In May 2008, we entered into short and long term hedges which helped us to manage the risk that we would pay a high price for crude feedstock and, because of volatility in crude oil prices, be faced with a low margin on refined products.  These hedges resulted in $27.8 million profit during the year 2008, with a further $18.2 million of hedging gains which were settled during 2009.
  ·
We fund our working capital requirements for the refinery by means of a facility provided by BNP Paribas.  This facility is subject to an annual review.  In 2008, the limit under our working capital facility with BNP Paribas was increased from $170.0 million to $190.0 million to accommodate higher crude prices and resulting increases in working capital requirements.
 
 ·
In October 2008, we secured a Papua New Guinea 150.0 million Kina (approximately $56.8 million) combined revolving working capital facility for our wholesale and retail petroleum products distribution business in Papua New Guinea from Bank of South Pacific Limited (“BSP”) and Westpac Bank PNG Limited (“Westpac”).  The facilities are secured by the capital assets of the downstream business. The Westpac facility has an initial term of three years and is due for renewal in August 2011.  The BSP facility is renewable annually.
 
 In 2009, InterOil undertook the following financing transactions:
 
 ·
During May and June 2009, the remaining outstanding debentures (being $79.0 million principal amount) were converted into an aggregate of 3,159,000 common shares.
  Annual Information Form   INTEROIL CORPORATION     13
  ·
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 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 $266.0 million.
  ·
Subsequent to year end, 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.
  Management Team
 
 During 2008, 2009 and 2010, InterOil’s Board and senior management changed as follows:
 
 ·
On October 14, 2008, Mr. Donald Hansen resigned from the Board.
 
 ·
On November 26, 2008, Mr. Roger Lewis was appointed as an independent director and also agreed to serve as a member of each of the Audit, Compensation and Nominating and Governance committees.
 
 ·
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.
  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
  Annual Information Form   INTEROIL CORPORATION     14
  ·
Remain a significant employer in Papua New Guinea.
 
 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.
 
 Maximizing the value of our exploration assets
 
 ·
Accelerate 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 partial 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 and seek possible earlier cash flows; and
 
 ·
Seek licenses, enabling legislation and approvals required for our planned developments from the State.
 
 Positioning for long term success
 
 ·
Seek new opportunities in the Southwest Pacific region for future growth.
  Annual Information Form   INTEROIL CORPORATION     15
  
  DESCRIPTION OF OUR BUSINESS
  Overview
 
 Our operations are organized into four major business segments:
 
 Segments

OperationsUpstream

Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua New Guinea.  Currently developing the Elk Antelope infrastructure which includes condensate stripping and associated facilities, and the gas gathering and associated common facilities, in connection with commercializing significant gas discoveries.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.
 
 As of December 31, 2010, 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
  Description of Properties
 
 As at December 31, 2010 we had interests in three PPL’s and one PRL onshore in Papua New Guinea covering 3,954,041 gross acres, all of which were operated by us.  PPL’s 236, 237 and 238 are located in the Eastern Papuan Basin, northwest of Port Moresby.  All of our PPLs are located onshore in Papua New Guinea.
 
 On November 30, 2010, InterOil was granted PRL 15, covering a total of nine graticular blocks including and surrounding the Elk and Antelope fields and extracted from PPL’s 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 the details of exploration wells that have been drilled on acreage currently held by InterOil as at December 31, 2010:
  Annual Information Form   INTEROIL CORPORATION     16
  License

Numbers

Basin

Location

Operator

InterOil

Registered

License

Interest


Blocks

Covered


Acreage

Gross


Acreage

NetPPL 236

Papuan

Onshore

InterOil


100.00
%


94



1,112,468



1,112,468PPL 237

Papuan

Onshore

InterOil


100.00
%


33



694,610



694,610PPL 238

Papuan

Onshore

InterOil


100.00
%


53



1,957,561



1,957,561PRL 15

Papuan

Onshore

InterOil


100.00
%


9



189,530



189,530Total



3,954,041



3,954,041
 1See Petroleum License Details – Net Working Interest on PPL 236, PPL 237 and PPL 238
 
 Costs incurred in relation to Exploration and Development activities
 
 The following table outlines costs incurred by InterOil during the year ended December 31, 2010 for acquisitions and capital expenditure associated with exploration and development activities.
 
 Nature of Cost

Amount

(US $ million)Acquisition costs (Proved and Unproved):


-Exploration costs

$
10.2Development costs

$
89.5Total

$
99.7
 
 Additionally the following table summarizes the results of exploration and development activities during the year ended December 31, 2010.
 
 Wells

Development


Exploration


TotalGross

(US $ million)


Net

(US $ million)


Gross

(US $ million)


Net

(US $ million)


Gross

(US $ million)


Net

(US $ million)Gas

$
103.1


$
89.5


$
10.4


$
10.2


$
113.5


$
99.7Oil


-



-



-



-



-



-Service


-



-



-



-



-



-Dry


-



-



-



-



-



-Total

$
103.1


$
89.5


$
10.4


$
10.2


$
113.5


$
99.7
  During 2010 we bought back 1.45% worth of interests in the IPI Agreement in exchange for a total of 754,788 common shares valued at $50.7 million.  We have adopted the extinguishment of liability model for accounting for the buyback of 1.4% of this interest with the difference between fair value and book value of the IPI liability for this interest being expensed, amounting to an $30.6 million expense for the year, which is not included within the tables above.  For the remaining 0.05% interest, the investor had already waived their conversion right in 2009.  This meant that conveyance accounting was followed and the premium paid to the investor on buyback was capitalized to oil and gas properties, which is included in the tables above.
  Annual Information Form   INTEROIL CORPORATION     17
 
 Operated License Commitments, Terms, Expiry and Re-Application
 
 In March 2009, all three PPL’s 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 6 wells within those license areas during the renewed license term.  The first 2 year term of the license anniversaries occurs in March 2011.  We have met the portion of the license commitments applicable to that first period, save that we applied to the State for a variation to our license commitments for the first 2 year term for PPL 238, seeking that the obligation to drill a further well in that license area be deferred until the second term. The State has reviewed and considered our variation request and final approval is pending.  While there can be no assurance that such
final approval will be given, we have no reason to believe that it will be withheld or refused, or that our licence will not otherwise remain in good standing, based on our interaction with the State to date.  If such approval was not given, this may give rise to restrictions being applied to, or other negative implications for, this licence. A more minor commitment, also in relation to PPL 238, to obtain airborne gravity and magnetic data has been slowed by permitting  delays and is otherwise ready to proceed.  A work program and expenditure commitment has been proposed for the second term (March 2011 to March 2013).
 
 Following are InterOil’s applicable 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

Second

Term

Commitment

Years 1— 2

(US $ Millions)


Commitment

Years 3 - 5

(US $ Millions)


Total License

Commitment

(US $ Millions)

License

ExpiryPPL 236

March 27, 2009

5 years

$
5.0


$
10.0


$
15.0

March 27, 2014PPL 237

March 27, 2009

5 years

$
14.0


$
34.0


$
48.0

March 27, 2014PPL 238

March 6, 2009

5 years

$
2.0


$
30.0


$
32.0

March 6, 2014PRL15

November 30, 2010

5 years

$
53.0


$
20.0


$
73.0

November 30, 2015Totals

$
74.0


$
94.0


$
168.0
 
 Petroleum License Details
 
 Net Working Interests on PPL236, PPL237 & PPL238 (the “Exploration Licenses”)
 
 The Exploration 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.  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 potential dilution of existing working interests in a discovery 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.
  Annual Information Form   INTEROIL CORPORATION     18








Participant

Working interests *


With State

participationInterOil


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, 2010 elect to participate.





Petroleum Prospecting License 236





We have a 100% working interest in PPL 236, subject to elections made by holders of certain indirect participation interests described below.  We are the operator of PPL 236 which covers an area that includes our refinery and otherwise has limited road access.





At the end of the 2010 the initial preparatory work on a seismic program was well advanced with social mapping, community relations work and construction of the base camp initiated. Work on the PPL 236 seismic comprises 70 kilometres comprising 6 dip lines which transect the Whale, Tuna, Barracuda, Wahoo, Mako and Shark leads and is programmed to fulfil our licence commitment for the first 2 year term of the licence extension.





Petroleum Prospecting License 237





We have a 100% working interest in PPL 237, subject to elections made by holders of indirect participation interests described below.  We are the operator of the license.  During 2009, the Antelope-2 well was drilled in this license area. This well satisfies our obligation to drill a well on PPL 237 in the first year of the current second term of the PPL 237 license.





Additionally, InterOil also acquired, processed and interpreted 100 kilometers of appraisal seismic over the Antelope structure acquired during the first quarter of 2010 in both PPL 237 (25%) and PPL 238 (75%) along with two phases of 2D seismic acquisition and processing over the Bwata gas field, which lies solely within PPL 237.





Phase 1 of the Bwata 2D seismic acquisition consisted of 2 dip lines totalling in excess of 20 kilometers over Bwata. A second phase of seismic acquisition was undertaken on this structure in the fourth quarter of 2010.Phase 2 of the Bwata program focused on further delineation of the structure and consisted of 58 kilometers of three dip lines and one strike line. The data have been processed and are currently being interpreted.





A total of four graticular blocks have been excised from PPL 237 and incorporated into PRL 15.





Petroleum Prospecting License 238





We have a 100% working interest in PPL 238, subject to elections made by holders of indirect participation interests described below. We are the operator of the license.  We have drilled a total of seven wells on this license of which Elk-1 and Elk-4A were the Elk and Antelope gas/condensate field discovery wells, respectively.





InterOil acquired, processed and interpreted 100 kilometers of appraisal seismic over the Antelope structure acquired during the first quarter of 2010 in both PPL 238 (75%) and PPL 237 (25%) along with two phases of 2D seismic acquisition and processing over the Wolverine Lead which lies solely with PPL 238.  The Wolverine Prospect lies approximately 15 kilometers east of the Antelope gas field.





Annual Information Form  INTEROIL CORPORATION     19










A total of 5 graticular blocks have been excised from PPL238 and incorporated into PRL15.





Petroleum Prospecting License 244





We held a 15% working interest in PPL 244 for part of 2010 as State approval for the divestment of our interest in this license was pending.  During the third quarter of 2010, the State approved the divestment of our 15% non-operated interest. The divestment became unconditional and the transaction was finalized in October 2010. A further $500,000 is payable to us on the purchaser’s spudding of the next well.





Petroleum Retention License 15





Petroleum retention licenses may be granted to licensees of PPL’s 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.





Subject to elections to be made by the State’s nominee to acquire a 22.5% interest on behalf of the State and landowners and by holders of indirect participation interests, and to the registration of Pac LNG’s 2.5% interest, we have a 100% interest in the PRL.





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.





Petroleum Development License (“PDL”)





In order to progress the proposed development and commercialization of the Elk and Antelope fields, which are within PRL 15, we are required to apply for a PDL.  The PDL will consist of the acreage granted for PRL 15.  PRL 15 includes the Elk and Antelope fields and also acreage on which to locate facilities and pipelines.  We have commenced preparation of an application for such a PDL which will replace PRL 15.





The State will review any PDL application and an initial development plan.  Should the PDL be issued, the acreage would be held subject to periodic review.  It is at this stage that the State’s interest would be recorded on the Papua New Guinea Petroleum register as a partner on the license, assuming the State elects to exercise such interest.





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 right to a 6.75% interest in the next four exploration wells (the first of which was Elk-1 so that two of these four wells have now been drilled) to be drilled by us.  PNGDV also retained the right to participate for up to an interest of 5.75% in the 16 wells that follow the next four wells by contributing their share of well costs.




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 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, 2010, 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, a) $112,500 per percentage point plus actual cost over $1.0 million charged pro rata per percentage point.





For further details on these participation agreements, refer to the “Material Contracts” section of this AIF.





Annual Information Form  INTEROIL CORPORATION     20








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. The agreement grants rights to Pac LNG to be registered on PRL 15.





If a PDL is granted, investors in our participation interest programs set out above have the right to become working interest owners in 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 capital expenditures 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.  Low sulfur waxy residue 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 an Australian National Association of Testing Authorities (NATA) accredited lab.  The lab is staffed and operated by an independent nationally accredited 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 and Throughput





In December 2001, we entered into an agreement with BP for the supply of crude feedstock to our refinery.  The original agreement continued until June 2009  and has been renewed annually since.  BP is the largest marketer of crude oil in the Asia Pacific region.  This contract provides a reliable source of supply and provides access to the majority of the regional crudes suitable for our refinery.  We will continue to review these arrangements and other options for sources of supply after expiration of this contract. We do not expect that the expiration of this contract will adversely affect our ability to obtain crude feedstock for the refinery.





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, which expires in 2035, 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 November 2007, the IPP was modified 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 revised formula is yet to be formally entrenched by means of necessary amendment to the Project Agreement governing our relationship with the State.  The State has recently re-initiated discussions in relation to the IPP, the outcome of which is uncertain (see “Material Contracts – Refinery Project Agreement”).




Annual Information Form  INTEROIL CORPORATION     21








The major export product from our refinery is the two grades of Naphtha.  Effective October 1, 2009, a term agreement with Dalian Fujia Dahua Petrochemicals (“Dalian”), which operates a petrochemical plant in China, was entered into providing for export sales of Naphtha until September 30, 2010. Thereafter, the contract was renewed with Dalian for a further 12 months until September 30, 2011.





During 2010, there were eight export cargoes of Naphtha averaging approximately 28,125 metric tons each for a total of approximately 225,000 tonnes or 2.1 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 to convert Naphtha to gasoline.  We did not export any gasoline or middle distillates in 2008. However, we made an export sale of diesel and gasoline to the Pacific Island of Nauru in November 2009.  We followed this up with 3 export sales of diesel and gasoline in Nauru in 2010.





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, 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 Northwestern 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 resources of most of our competitors, we are not always able to secure the specific crudes we desire for our refinery and are required to obtain alternate crudes that are available.





We own the only refinery in Papua New Guinea.  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 2008, and a volume of competing finished product is currently being imported, in what we believe to be contravention of our rights under our Refinery Project Agreement.  Excess diesel, gasoline, Naphtha and LSWR that are exported are sold subject to prevailing commodity market conditions.  Our geographical position and limited storage capacity limits our ability to compete with the regional refining center in Singapore to secure 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 low sulfur waxy residue to domestic distributors.  Our main domestic customer is our downstream business segment, however we also distribute fuel products to Niugini Oil Company 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.





Generally, we are required to purchase crude feedstock approximately one to two months in advance of processing, whereas the supply or export of finished products takes place after the crude feedstock is discharged and processed.  This timing difference affects 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.  Therefore, we can use various derivative instruments to assist us to reduce or hedge 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.  However, 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.  We refer to this risk as timing and margin risk.




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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 swaps instrument covers commodities or products such as jet, kerosene, diesel, Naphtha, and also crudes such as Tapis, Dated Brent and Dubai.  By using these tools, we actively engage in hedging activities to manage margins. As the majority of our
physical crude purchases in the second half of 2010 were on a Dated Brent basis, this provides a more liquid derivative market in order to effectively hedge against price and margin movements. The Tapis derivative market was virtually non-existent in 2010 as Dated Brent is becoming the preferred pricing basis in our region.





During 2010, we participated in a number of short term Naphtha swap hedges, some of which were still to be priced out at December 31, 2010.





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 LNG Project targets facilities that would be expected to produce at least 3 mtpa of LNG and associated condensates, and we expect these facilities to be expandable to at least 8 mtpa.  The infrastructure currently being contemplated includes condensate storage and handling, a gas pipeline from the Elk and Antelope fields and LNG storage and handling facilities.





At present, we have equal voting rights with Pac LNG in the Joint Venture Company and all decisions are required to be unanimous. At the time the shareholders agreement was signed, we were also provided with non-voting B class shares in the Joint Venture Company reflecting a fair economic value of $100.0 million in recognition of our contribution to the LNG Project.  Our contribution included, among other things, infrastructure developed by us, our stakeholder relations within Papua New Guinea, our negotiation of natural gas supply agreements with landowners and our contribution to project development.  Under the 2007 shareholders’ agreement, we are not required to contribute towards cash calls from the Joint Venture Company until an equal amount has been contributed by Pac LNG to
equalize their investment in the Joint Venture Company with that of InterOil.  As of December 31, 2010, InterOil held 86.66% of the non-voting B class or economic shareholding in the Joint Venture Company.  Ultimately, after such equalization, we are entitled to a 52.5% economic interest in the Joint Venture Company while Pac LNG is entitled to 47.5%.





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.





During 2010, the Joint Venture Company decided to pursue the development of the LNG Project or facility 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 InterOil’s 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 signed with EWC to develop the LNG Project. Under the terms of these agreements, the LNG Project is intended to be developed in two initial phases 2 mtpa followed immediately by a 1 mtpa expansion.  The contractual terms relating to the 3 mtpa plant have been defined with the execution of the two agreements with provision to expand to up to 8 mtpa. 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, less agreed deductions, and subject to adjustments based on timing and execution.  The parties to these agreements may still elect not to proceed with the LNG Project on the terms specified or at all.




Infrastructure required for the LNG Project includes a jetty and breakwater for the LNG loading facility with expansion potential, and approximately 50 mile (80 kilometers) pipeline from the Elk and Antelope fields to the coast. The wells and processed natural gas pipeline from the CSP to the coast in the Gulf Province will be the responsibility of the owners of the Elk and Antelope fields, including InterOil and its upstream partners.




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




DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION





We have the largest wholesale and retail petroleum product distribution base in Papua New Guinea.  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 that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea.  Our Downstream business may charge less than the maximum margin set by the ICCC in order to maintain its competitiveness with other participants in the market.





Supply of Products





Our retail and wholesale distribution business distributes diesel, jet fuel, 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 and fuel oil, which constitute a small percentage of our sales.





We deliver refined products from our refinery to two tanker vessels we charter.  These vessels deliver the refined products to distribution terminals and depots, including those owned by us.  We do not own these vessels but rather lease them on a full time charter basis.  In early 2010, the inter-industry joint shipping arrangement ceased to exist and we now schedule all of our own movements and deliveries on our chartered vessels. Our inland depots are supplied by road tankers which are owned and operated by third party independent transport contractors.





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





Retail Distribution





As of December 31, 2010, 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 with a sublease to company-approved operators.  The remaining 36 service stations are 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 the majority of these retail service stations that are not owned or leased by us.





Wholesale Distribution





We also supply petroleum products as a wholesaler to commercial clients.  We operate 11 aviation refueling facilities throughout Papua New Guinea and are the largest aviation supplier in PNG, outside the main centre of Port Moresby.





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 whereby we 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 2010 was supplied to commercial customers.  Although the volume of sales to commercial customers is far larger than through our retail distribution network, these sales have a lower margin. Aviation customers represented 14% of our total volumes business.




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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 have 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 17% of our refined petroleum products to Ok Tedi Mining Limited (“OTML”) in Papua New Guinea pursuant to a wholesale distribution contract.  Due to the amount of petroleum products provided to OTML, the loss of this customer, at least in the short term, would adversely affect the profitability of our retail and wholesale distribution business segment and of the refinery.  We entered into an additional supply agreement for a two year period with OTML during 2010.





During the year ended December 31, 2010, Shell Oil Products Ltd (“SOPL”) sold its Jacksons Airport aviation refueling business to Pacific Energy Aviation (PNG) Ltd (“PEA”).  We entered into a new contract with SOPL in late 2009.  This purchase contract was for a five year period and was assigned to the PEA as part of the sale and purchase process between SOPL and PEA.  During 2010, we sold approximately 9% of our refined petroleum products under this agreement.





Our retail business accounted for approximately 15% of our total business in 2010.   Investments were made in 2010 in new electronic systems for both pumps and the forecourt control units to support the further development of this business.





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, 2010, 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:




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Gross Contingent Resources Estimate for Gas and Condensate*





CaseAs at December 31, 2010

Low


Best


HighInitial Recoverable Sales Gas (tcf)


6.47



8.59



10.44Initial Recoverable Condensate (mmbbls)


105.3



128.9



151.4Initial 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*





CaseAs at December 31, 2010

Low


Best


HighInitial Recoverable Sales Gas (tcf)


3.79



5.03



6.12Initial Recoverable Condensate (mmbbls)


61.7



75.5



88.7Initial 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.





The 2009 GLJ Report included the Mule Deer structure as contingent resources.  The GLJ 2010 Report has removed estimates of the resources within the Mule Deer structure from the contingent resources category and reclassified them as Prospective Resources on the basis of having determined that it is a separate undrilled structure. The Mule Deer structure is adjacent to the Elk and Antelope fields and in the 2009 GLJ Report, Mule Deer represented only 3.1% of the total P50 (Best) recoverable gas resource volumes in that report.  The 2010 contingent resource volumes stated above are solely from the Elk and Antelope fields.





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.





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 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.




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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 2010.  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.





We have outstanding loans with OPIC, an agency of the United States Government.  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, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.





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.




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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 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 for a PDL for the Elk and Antelope gas fields and other related licenses which will be required for pipelines and processing facilities. These studies cover social mapping, social economic Impact statements, land investigations, environmental impact and other related base line studies. These studies are a pre-requisite to the grant of a PDL 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.





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 occur, our business, financial condition and results of operations could be materially adversely affected.





Our ability to develop 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 additional equity contribution 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.  We are also seeking to develop a separate condensate stripping facilities, pipelines and common facilities.  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 committed or 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.  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 InterOil 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.




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




As a result of the weakened global economic situation, 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 capital markets and investor appetite for investments in the energy industry and our assets and securities in particular.





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





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 and other potential joint venture partners or proceed with them on satisfactory terms;




·
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;




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




·
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




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·
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 the these facilities on time or at all.





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





As of December 31, 2010, we had drilled a total of eight exploration wells and a number of appraisal wells in our PPL’s since the inception of our exploration program.  Of the exploration wells, we consider two to have been successful.  We plan to drill additional wells in Papua New Guinea during the coming years in line with our commitments under our PPL’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 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.





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, if any, 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.





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 PNG 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. 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 change.  The
State has recently reinitiated discussions concerning the formula and the outcome and review of these discussions is uncertain.  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 formally amended so as to be based on a market price marker recognized by the industry, as is in operation at present, then 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.




Annual Information Form  INTEROIL CORPORATION     30








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, our senior managers and other key personnel.  The loss of these people, especially without sufficient advance notice, could have a material adverse impact on our results of operations and our stock price.  It is also very important that we attract and retain highly skilled personnel, including technical personnel, to operate our refinery, accommodate our exploration plans, assist us with our development projects, 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 could lead to sudden changes in a counterparty’s liquidity, which could restrict their ability to perform under the terms of the hedging contract.  We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform.  Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.





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





Our results of operations and financial condition may be affected by currency exchange rates.  Exchange rates may fluctuate widely in response to international political conditions, general economic conditions and other factors beyond our control. While our domestic product sales are denominated in the Papua New Guinean currency, Kina (“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.  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.




Annual Information Form  INTEROIL CORPORATION     31








Political conditions have at times been unstable in Papua New Guinea.  We attempt to conduct our business pursuant to various agreements with the State in such a manner that political and economic events of this nature will have minimal effects on our operations.  We believe that hydrocarbon exploration, development and refinery operations are in the long term best interests of Papua New Guinea and that, as a result, we will continue to have the support of the government of the day.  Notwithstanding the current support, 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.





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.





The price of our common shares has been volatile.




The market price of the common shares has been, and is likely to continue to be, volatile and subject to wide fluctuations.  The fluctuation in the market prices of the common shares is caused by a number of factors, some of which are outside our control, including the following:




•
quarterly variations in our results of operations;





•
success or failure of our exploration activities




•
material events public announcements concerning our business and operations;





•
changes in stock market analyst recommendations or earnings estimates regarding the common shares;




•
short selling activity;




•
strategic actions, such as acquisitions by us or our competitors;





•
new laws or regulations or new interpretations of existing laws or regulations applicable to our business;





•
significant sales of the common shares;





•
the acquisition or loss of major customers or suppliers;





•
additions or departures of key personnel;





•
changes in market valuations for refining, exploration and production companies or companies participating in the retail distribution of refined oil products; and





•
changes in accounting standards, policies, guidance, interpretations or principles.





A decline in the market price of the common shares could cause you to lose some or all of your investment and, if sustained, could have an adverse effect on our ability to continue to fund or pursue our business strategy.




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





Annual Information Form  INTEROIL CORPORATION     32










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.  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 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, any major upgrades to our refinery could require material additional expenditures to comply with environmental laws and regulations.  In addition,
environmental gas laws and permits may be an obstacle to the development of our liquefaction and condensate stripping facilities.





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.  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 2010 as some competing product has been imported and sold in Papua New Guinea in what we believe is in contravention of our rights.





Our refinery is rated to process up to 32,500 barrels of oil per day and in 2008 improvements were made to expand its capacity 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 Australia’s regulations regarding permitted sulfur and benzene content that our refined products currently do not meet.





Annual Information Form  INTEROIL CORPORATION     33










In addition, our project agreement with the State provides that if there is more than one refinery operating in Papua New Guinea during the term of the project agreement, the right to supply the domestic market will be shared by the refineries in proportion to their refining capacities.  Therefore, if one or more additional refineries are built in Papua New Guinea, our share of the domestic market will be diminished.





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





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





In our exploration and production business, we compete for the purchase of licenses from the 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 the personnel necessary to properly evaluate seismic and other information relating to a property;




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





During 2010 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.




Annual Information Form  INTEROIL CORPORATION     34










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 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 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 resource planning system in 2010 and the first half of 2011, may enhance the likelihood of the occurrence of these events.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.




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





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





Annual Information Form  INTEROIL CORPORATION     35










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 2010 would have resulted in a $338,291 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.





The enactment of legislation to regulate emissions of greenhouse gases could result in a reduction in demand for fossil fuels that may reduce demand for our products in the global markets and thus negatively impact our financial condition.





Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of natural gas, are examples of greenhouse gases.  More than 160 nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the “Kyoto Protocol”, which is intended to limit or capture emissions of greenhouse gases.  The implementation of the Kyoto Protocol in a number of countries and other potential legislation limiting emissions, such as those adopted by the European Union, could affect the global demand for fossil fuels.  The Kyoto Protocol is set to expire in
2012.  The nations subject to the Kyoto Protocol have not yet reached agreement upon a successor to the Kyoto Protocol, but the parties have “taken note of” the Copenhagen Accord, a voluntary agreement to work to curb climate change.  If Papua New Guinea or other countries in which we operate or desire to operate enact legislation focused on reducing greenhouse gases, either independently or in response to the Kyoto Protocol or a successor agreement, it could have the effect of adversely affecting our operations and the demand for our products, consequently reducing our revenues and profitability.





Annual Information Form  INTEROIL CORPORATION     36







Our debt levels and debt covenants and other factors may limit our future flexibility in obtaining additional financing.
 
 As of December 31, 2010, we had $35.5 million in long-term debt with OPIC which matures in 2015, together with principal repayments due during 2011 totaling $9.0 million.  We also operate significant working capital facilities with BNP Paribas, and with Bank of South Pacific Limited and Westpac Banking PNG Limited, respectively for our midstream and downstream refining businesses, and have $70 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.
  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 further.  There is a risk that we will not be successful with respect to the legal actions to which we are a party, which could have a material adverse effect on our consolidated financial position, results of operations or cash flows, or in our ability to pursue our business strategy.
 
 You may be unable to enforce your legal rights against us.
 
 We are a Yukon Territory, Canada Corporation.  Substantially all of our assets are located outside of Canada and the United States.  It may be difficult for investors to enforce, outside of Canada and the United States, judgments against us that are obtained in Canada or the United States in any such actions, including actions predicated upon the civil liability provisions of the securities laws of Canada and the United States.  In addition, many of our directors and officers are nationals or residents of countries outside of Canada and the United States, and all, or a substantial portion of, the assets of such persons are located outside of Canada and the United States.  As a result, it may be difficult for investors to affect service of process within Canada or the United
States upon such persons or to enforce judgments against them obtained in Canadian or United States courts, including judgments predicated upon the civil liability provisions of the securities laws of Canada or the United States.
 
 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, 2010, 47,800,552 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, 2010.  We also have outstanding $70.0 million principal amount of 2.75% convertible senior notes due 2015.
  Annual Information Form  INTEROIL CORPORATION     37
  
  Common Shares
 
 Holders of common shares are entitled to vote at any meeting of the shareholders of InterOil and to one vote per share held, 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 directors of InterOil 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 million principal amount of  2.75% convertible senior notes due 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.
 
 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 pay 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 their June 22, 2010 annual and special meeting. 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 substantial 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.
  Annual Information Form  INTEROIL CORPORATION     38




Options





We have a 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, 2010, there were options outstanding to purchase 1,688,267 common shares pursuant to our stock incentive plans.





Restricted Stock Units





In addition to the options noted above, the InterOil Corporation 2009 Stock Incentive Plan also allows employees to acquire our common shares pursuant to restricted stock units granted by the Company. As of December 31, 2010, restricted stock units entitling employees rights to 124,192 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 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 entered into an agreement with Petroleum Independent and Exploration LLC (“P.I.E.”), under which the remaining 5,000 shares held by P.I.E. in SPI InterOil LDC may be exchanged at InterOil’s election on a one-for-one basis for our 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 that agreement into a certain number of our common shares.  Certain investors under that agreement have waived their conversion right.  At December 31, 2010, rights to convert up to 340,480 common shares remained.





MARKET FOR OUR SECURITIES





Our common shares are listed and posted for trading on the New York Stock Exchange under the symbol IOC. We are also listed on the Port Moresby Stock Exchange under the symbol IOC in Papua New Guinea.  The following table discloses the monthly high and low trading prices and volumes of our common shares as traded on the New York Stock Exchange during 2010:





New York Stock Exchange (NYSE:IOC) in United States DollarsMonth

High


Low


VolumeJanuary


84.05



58.29



34,208,100February


71.00



57.18



23,487,500March


72.48



57.22



31,494,700April


81.00



66.24



22,725,300May


67.13



41.67



26,529,200June


57.00



42.60



17,672,300July


61.62



44.40



12,899,600August


70.10



55.35



12,986,500September


72.93



59.15



12,293,500October


71.67



64.64



12,748,100November


81.98



71.18



17,595,800December


81.20



71.50



9,112,600Total


84.05



41.67



233,753,200




Annual Information Form  INTEROIL CORPORATION     39







Prior sales





·
479,733 common shares were issued during 2010 upon the exercise of stock options by employees at various prices defined by the option grant terms in accordance with relevant stock incentive plans.





·
20,700 common shares were issued during 2010 upon the vesting of restricted stock units granted to employees defined by the option grant terms in accordance with relevant stock incentive plans.





·
A total of 754,788 common shares were issued in July and December 2010 at an average, calculated price of $67.15 in relation to exchange transactions undertaken with certain IPI investors under which we acquired indirect participation interests held by them pursuant to the Amended and Restated Indirect Participation Interest Agreement of February 2005 (See “Material Contracts”).





·
199,677 common shares were issued on October 19, 2010 to the plaintiffs in Todd Peters et al v. Phil Mulacek et. al for the settlement of the litigation, valued at $12.0 million based on a volume weighted average price calculated over the ten trading days prior to execution of the settlement agreement.





·
2,800,000 common shares were issued on November 10, 2010 on completion of an underwritten registered direct public offering at a purchase price of $75.0 per share, raising gross proceeds of $210.0 million.





·
$70.0 million principal amount of 2.75% convertible senior notes due 2015 were issued on November 10, 2010 on completion of a public offering.





DIRECTORS AND EXECUTIVE OFFICERS





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





Directors and Executive OfficersName, Address

Position with InterOil

Date of AppointmentPhil E. Mulacek

Texas, USA

Chairman and Chief Executive Officer

May 29, 1997Christian Vinson

Port Moresby, PNG

Vice President Corporate Development and Government Affairs, Director

May 29, 1997Gaylen Byker

Michigan, USA

Director(1)

May 29, 1997Roger Grundy

Derbyshire, UK

Director (2)

May 29, 1997Roger F. Lewis

Western Australia, Australia

Director(3)

November 26, 2008Ford Nicholson

British Columbia, Canada

Director(4)

June 22, 2010William Jasper III

Texas, USA

President and Chief Operating Officer

September 18, 2006Collin Visaggio

Western Australia, Australia

Chief Financial Officer

October 26, 2006Mark Laurie

South Australia, Australia

General Counsel and Corporate Secretary

June 12, 2007




Annual Information Form  INTEROIL CORPORATION     40







Notes:


(1)
Gaylen Byker acts as Chairman of each of the Board’s Nominating and Governance Committee and Compensation Committee and has held such positions throughout 2010. He is a member of the Audit Committee and was its Chairman until June 2010.  He is also a member of the Reserves Committee


(2)
Roger Grundy was a member of the Board’s Reserves Committee throughout 2010. He was appointed Chairman of that committee in June 2010.


(3)
Roger Lewis was a member of the Audit Committee, Nominating and Governance Committee and Compensation Committee throughout 2010.  Mr. Lewis was appointed Chairman of the Audit Committee on June 22, 2010.


(4)
Ford Nicholson was appointed by shareholders at InterOil’s 2010 shareholders meeting, replacing Edward Speal who retired on that same day. Mr. Nicholson was appointed a member of the Audit Committee and Reserves Committee in June 2010.


(5)
Certain information has been furnished by our directors and executive officers.  Such information includes information as to common shares in the Company beneficially owned by them, their places of residence and principal occupations, both present and historical, 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 March 10, 2011, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly, 5,949,348 common shares, representing 12.41% of our outstanding issued common shares.  In addition to the common shares owned or controlled or directed, directly or indirectly, by our directors and executive officers, 1,190,760 shares are issuable upon exercise of outstanding options and restricted stock units, resulting in directors and executive officers holding 14.08% 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.





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.




Annual Information Form  INTEROIL CORPORATION     41







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. Lewisis 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 and, since 2000, has been a Commissioner of the Lottery Commission of Western Australia, with particular responsibility for finance and accounting matters.  He is a member of the Commission’s Audit, Remuneration and
Major Projects subcommittees.





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 IIIis 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.





Collin F. Visaggio is the Chief Financial Officer of InterOil.  Mr. Visaggio joined us 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 most recent positions being Manager, Compliance and Business for the Africa Business Unit, and Manager, Commercial and Planning for the Gas Business Unit.  His responsibilities included the 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.




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.




Annual Information Form  INTEROIL CORPORATION     42







Cease Trade Orders




One of our directors, Mr. Ford Nicholson, was a director of a company operating in Papua New Guinea, Sepik Gold Corporation (“Sepik”), from May 1996 to December 2001. Sepik did not have adequate funds to complete its 2000 year-end audit and the shares of Sepik were cease traded in December 2001, at which time Mr. Nicholson resigned from the board of that company.




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:




·
P.I.E. Group, LLC, which entity is controlled by Mr. Mulacek and in which entities controlled by Dr. Byker also have an ownership interest, holds small ownership interests (0.01%) in SPI Exploration & Production Corporation and S.P.I. Distribution Limited which are subsidiaries of the Company.  In addition, Petroleum Independent and Exploration Corporation, which company is controlled and partly owned by Mr. Mulacek, owns an interest in and acts as General Manager of SP InterOil, LDC, another subsidiary of the Company.  A fee is paid for the provision of general management services.


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




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




AUDIT COMMITTEE





Charter of the Audit Committee





The full text of the Charter of the Audit Committee is attached as Schedule C to this Annual Information Form.





Composition of the Audit Committee





The current members of the Audit Committee are Mr. Roger Lewis, Dr. Gaylen Byker and Mr. Ford Nicholson.  Mr. Lewis and Dr. Byker held their positions throughout 2010, while Mr. Nicholson was appointed on June 22, 2010. Mr. Edward Speal was a member of the committee until his resignation from the Board in June 2010.





Mr. Lewis, Dr. Byker and Mr. Nicholson are independent and financially literate within the meaning of NI 52-110.




Annual Information Form  INTEROIL CORPORATION     43





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.





PricewaterhouseCoopers2009


2010Audit Fees(1)

$
1,557,328


$
1,709,000Audit-Related Fees(2)

$
35,144


$
322,788Tax Fees(3)

$
557,693


$
355,221All Other Fees(4)

$
47,718


$
67,611Total

$
2,197,883


$
2,454,620





Notes:


1.
"Audit Fees" means the aggregate fees billed by the  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  external auditor that are reasonably related to the performance of the audit or review of our financial statements, not reported as Audit Fees above.  In addition, it includes fees for work associated with reviews of prospectuses and registration statements associated with equity and debt offerings undertaken by us during those years.


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





LEGAL PROCEEDINGS AND REGULATORY ACTIONS





On August 31, 2010, we entered into an agreement to settle all claims against us and our subsidiaries brought by various plaintiffs in the District Court of Montgomery County, Texas commenced in 2005 and styled Todd Peters et. al v. Phil Mulacek et. al.  The plaintiffs are members of a partnership that bought a modular oil refinery that was subsequently, through a series of transactions, sold to a subsidiary of ours.  The plaintiff’s sought damages based on numerous alternative methods of calculation which if successful, could have exceeded $125 million, together with unspecified punitive damages, attorney’s fees, expenses and court costs.  Pursuant to the agreed settlement, we agreed to issue common shares to the plaintiffs, valued at $12 million based on a volume
weighted average price calculated over the ten trading days prior to execution of the settlement agreement.  Under the terms of the settlement agreement, we, along with our affiliates, directors, officers, in their positions as such, and certain other related parties are released from all claims from the plaintiffs, whether asserted in the lawsuit or not. The settlement received final court approval on September 17, 2010.  A total of 199,677 common shares were issued pursuant to the settlement agreement on October 19, 2010. The settlement does not reflect any admission by us, our affiliates or our directors or officers, and was entered into on the basis that it best serves our interests and the interests of our shareholders.




Annual Information Form  INTEROIL CORPORATION     44







From time to time the Company is 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 the Company’s favor, the Company does 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 its financial position, results of operations or liquidity.





INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS





Breckland Limited provides 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 provides consulting services to us as an employee of that company.  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 2008 or 2009.





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.





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





MATERIAL CONTRACTS





The following represent material contracts entered into or still in effect during 2010:





Condensate Stripping Plant Joint Venture Operating Agreement dated August 4, 2010





The Joint Venture Operating Agreement (“JVOA”) between Mitsui and certain of InterOil’s subsidiaries, sets our 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 JVOA, 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 JVOA 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 FID is taken.





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





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





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




Annual Information Form  INTEROIL CORPORATION     45







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 has 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 is 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, is contingent upon grant
of a PDL for the field.  The interest and funding commitment may be increased to 22.5% subsequent to grant of a PDL in the event that Petromin is also nominated to hold the 2% interest also provided for under the Oil & Gas Act on behalf of relevant landowners.





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 the Joint Venture Company with respect to the LNG Project described in more detail under the heading “Description of the Business– Midstream - Liquefaction”.  It sets out the rights and obligations of the Shareholders and the terms governing their relationship and provides that the authorized share capital structure of the Joint Venture Company 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 the Joint Venture Company.  Class B shares recognize the holders’ economic interests in the Joint Venture Company 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 the Joint Venture Company).





Pursuant to the 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 Joint Venture Company, Merrill retains no ongoing economic interest, legal rights or involvement in the LNG Project.  This shareholders agreement, while still in effect, is still to be revised to respond to that change.





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





In February 2005, we entered into an agreement with institutional accredited investors in which the investors paid us $125 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.





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, 2009, 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, a) $112,500 per percentage point plus actual cost over $1.0 million charged pro rata per percentage point




Annual Information Form  INTEROIL CORPORATION     46







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.  As of 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 2010, the weighted average interest rate of all disbursements pursuant to this
loan agreement was 6.8%.  During the year ended December 31, 2010, two installments of $4.5 million and the accrued interest on the loan were paid.





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.





All other contracts entered or still in effect during 2010 were done so in the ordinary course of our business or were not material to us.


Annual Information Form  INTEROIL CORPORATION     47







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, 9th 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, 2010.  As at the date hereof, PricewaterhouseCoopers are independent within the meaning of Public Company Oversight Board Rule 3520.





Information relating to reserves of the Corporation set forth in the Statement of Reserves 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 will be contained in our information circular (“Information Circular”) for our upcoming annual meeting of shareholders expected to be held in June 2011.  Additional financial information is provided in our audited consolidated financial statements for the year ended December 31, 2010 (the “Annual Financial Statements”) and related 2010 MD&A (the “Annual MD&A”).  Our Annual Financial Statements, Annual 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, Annual 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 resources as at December 31, 2010.





An independent qualified reserve evaluator has evaluated the Company's reserves 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 resources data and other oil and gas information;





(b)
the filing of the Form 51-102F2 which is the report of the independent qualified reserves evaluator on the 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 23, 2011.





"Phil E. Mulacek"

"Roger Grundy"Phil E. Mulacek

Chief Executive Officer

Roger Grundy

Director"Collin F. Visaggio"

"Gaylen Byker"Collin F. Visaggio

Chief Financial Officer

Gaylen Byker

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, 2010. The resources data are estimates of low, best and high estimates of contingent resources as at December 31, 2010.




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, 2010:







Description

Location ofand

ReservesPreparation

(Country or

Company GrossIndependent

Date of

Foreign

Contingent ResourcesQualified Reserves

Assessment

Geographic

MMBOEEvaluator

Report

Area)

Low


Best


HighGLJ Petroleum Consultants

February 24, 2011

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.




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. However, any variations should be consistent with the fact that resources are categorized according to the probability of their recovery.




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, March 7, 2011








Keith M. Braaten, P. Eng.


Executive Vice-President




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Schedule C – Audit Committee Charter





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.




Annual Information Form  INTEROIL CORPORATION     53





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.




Annual Information Form  INTEROIL CORPORATION     54








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.





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 priorto 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 makerecommendations 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 codemay 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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