40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

Form 40-F

(Check One)

¨      Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

x     Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2009

Commission File Number: 001-32179

InterOil Corporation

(Exact name of registrant as specified in its charter)

Yukon Territory, Canada

(Province or other jurisdiction of incorporation or organization)

1311	Not Applicable
(Primary Standard Industrial Classification Code)	(I.R.S. Employer Identification Number)

Level 1

60-92 Cook Street

Cairns, QLD 4870, Australia

Telephone Number:  +61 (7) 4046-4600

(Address and telephone number of registrant’s principal executive offices)

CT Corporation Systems

111 Eighth Avenue

New York, New York 10011

Telephone Number:  (212) 894-8940

(Name, address (including zip code) and telephone number

(including area code) of agent for service in the United States)

Copy to:

Mark Laurie

InterOil Corporation

Level 1

60-92 Cook Street

Cairns, QLD 4870, Australia

Telephone Number:  +61 (7) 4046-4600

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Shares	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:  None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:  None

For annual reports, indicate by check mark the information filed with this form:

x Annual Information Form x Audited Annual Financial Statements

As of December 31, 2009, 43,545,654 of the issuer’s common shares were outstanding.

Indicate by check mark whether the registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”).  If “Yes” is marked, indicate the filing number assigned to the registrant in connection with such rule.  ¨ Yes  82-______    x No

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.  x Yes    ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). o Yes    x No

PRINCIPAL DOCUMENTS

The following documents have been filed as part of this Annual Report on Form 40-F (“Report”) for InterOil Corporation (the “Company”):

A.  Annual Information Form

The 2009 Annual Information Form for the Company is incorporated herein by reference.

B.  Audited Annual Financial Statements

The audited consolidated financial statements of the Company for the years ended December 31, 2009, 2008 and 2007, including the report of PricewaterhouseCoopers (the Company’s independent auditors) with respect thereto, are incorporated herein by reference.  For a reconciliation of important differences between Canadian and United States generally accepted accounting principles, see Note 30 of the Notes to the audited consolidated financial statements incorporated herein by reference.

C.  Management’s Discussion and Analysis

The Management Discussion and Analysis for the Company for the year ended December 31, 2009 (“MD&A”) is incorporated herein by reference.

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EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “ Exchange Act”). This term refers to the controls and procedures of an issuer that are designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (the “Commission”) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2009.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING

Responsibility

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). The 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 in accordance with Generally Accepted Accounting Principles (GAAP).

Inherent Limitations

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of a change in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Assessment

Management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, using the criteria set forth in the framework established by the Committee of Sponsoring Organizations of the Treadway Commission entitled Internal Controls — Integrated Framework. Based on this assessment, the Company’s management determined that the Company’s internal control over financial reporting was effective as of December 31, 2009.

Management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers, an independent registered public accounting firm, as stated in their report included on page 2of the consolidated financial statements in this Annual Report on Form 40-F.

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MATERIAL CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in internal control over financial reporting during fiscal year 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

AUDIT COMMITTEE

The Audit Committee of the Company’s Board of Directors is comprised of Dr. Gaylen Byker, Mr. Edward Speal and Mr. Roger Lewis. The Board of Directors has affirmatively determined that each member of the Audit Committee is financially literate and is an independent director for purposes of the New York Stock Exchange rules applicable to members of the audit committee.  Additionally, the Board of Directors has determined that Mr. Speal has the accounting or financial management expertise to be considered a “financial expert” as defined by the final rules approved by the Commission implementing the requirements set forth in Section 407 of the Sarbanes-Oxley Act of 2002.

CODE OF ETHICS AND BUSINESS CONDUCT

The Company’s Board of Directors has adopted a Code of Ethics and Business Conduct which applies to all directors, officers and employees of the Company.  The Board has not granted any waivers to the Code of Ethics and Business Conduct.  The Code of Ethics and Business Conduct is accessible on the Company’s website http://www.interoil.com.  Any amendments to or waivers of the Code of Ethics and Business Conduct that applies to the Company’s Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller will also be posted on the Company’s website.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees.  Fees billed for professional services rendered related to the audit of the Company’s annual consolidated financial statements for the fiscal years ended December 31, 2009 and December 31, 2008 by PricewaterhouseCoopers for services that are normally provided by such accountant in connection with statutory or regulatory filings or engagements for such fiscal years were $1,557,328 and $1,416,583, respectively, including out-of-pocket expenses.

Audit-Related Fees.  Fees billed for professional services rendered related to audit-related services for the Company for the fiscal years ended December 31, 2009 and December 31, 2008 by PricewaterhouseCoopers not otherwise reported above were $35,144 and $170,404, respectively.  The audit-related services provided by PricewaterhouseCoopers during 2009 and 2008 consisted of procedures performed with respect to the registration statements and work on the shelf prospectus prepared for private placement during that year.

Tax Fees.  Fees billed for professional services rendered related to tax compliance, tax advice, and tax planning services for the Company for the fiscal years ended December 31, 2009 and December 31, 2008 by PricewaterhouseCoopers were $557,693 and $473,493, respectively. 

All Other Fees.  Fees billed for professional services rendered related to all other services for the Company for the fiscal years ended December 31, 2009 and December 31, 2008 by PricewaterhouseCoopers were $47,718 and $39,192, respectively.  The fees related to procedures performed in connection with the quarterly financial reporting of the Company’s subsidiaries.

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Pre-Approval.  The Audit Committee of the Company’s Board of Directors pre-approves all auditing services, including the compensation and terms of the audit engagement, and all other non-audit services to be performed by the Company’s independent auditors.  Non-audit services subject to the de-minimus exceptions described in Section 10A(i)(1)(B) of the Exchange Act may be approved by the Audit Committee prior to the completion of the audit.  All of the services provided by the Company’s independent auditors during 2008 and 2009 were pre-approved by the audit committee.

OFF BALANCE SHEET ARRANGEMENTS

Please see the section titled “Liquidity and Capital Resources—Off Balance Sheet Arrangements” in the Company’s MD&A, which is incorporated herein by reference.

CONTRACTUAL OBLIGATIONS

Please see the section titled “Liquidity and Capital Resources—Contractual Obligations and Commitments” in the Company’s MD&A, which is incorporated herein by reference.

UNDERTAKINGS

The Company undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to:  the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICE PROCESS

The Company has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this Report arises.

DISCLOSURE REQUIRED BY NEW YORK STOCK EXCHANGE

The Company is classified as a “foreign private issuer” in connection with its listing on the New York Stock Exchange (“NYSE”).  As a result, many of the governance rules of the NYSE that apply to U.S. domestic companies do not apply to the Company. However, as a Canadian public company, the Company has in place a system of corporate governance practices that meets Canadian requirements.

Additionally, the NYSE listing standards require foreign private issuers to make certain corporate governance disclosures, including disclosure of any significant differences between its governance practices and the NYSE governance rules.  The following is the NYSE required disclosure:

Presiding Director at Meetings of Non-Management Directors.  Section 303A.03 of the NYSE Listed Company Manual requires “non-management directors” to schedule regular executive sessions with members of management present.  “Non-management directors” are defined in Section 303A.03 as all directors who are not executive officers.  The Company schedules executive sessions on a regular basis in which the Company's non-management directors meet without management participation. Dr. Gaylen Byker serves as the presiding director (the “Presiding Director”) at such sessions. The Board of Directors is responsible for determining whether or not each director is independent. The Board of Directors has adopted the director independence standards contained in Section 303A.02 of the NYSE’s Listed Company Manual for the purposes of satisfying the NYSE’s applicable governance requirements.

5

Communication with Non-Management Directors. Shareholders may send communications to the Company's non-management directors by writing to the Presiding Director, c/o Mark Laurie, Corporate Secretary, at Level 1, 60-92 Cook Street, Cairns, Queensland 4870 Australia, Telephone: +61 7 4046 4600.  Communications will be referred to the Presiding Director for appropriate action.  The status of all outstanding concerns addressed to the Presiding Director will be reported to the Board of Directors as appropriate.

Audit Committee.  Section 303A.06 of the NYSE Listed Company Manual requires listed companies to have an audit committee composed entirely of independent directors.  The Company has established an Audit Committee composed entirely of independent directors who qualify as independent under the requirements of Rule 10A-3 of the Exchange Act, and Section 303A.07 of the NYSE Listed Company Manual. The Company also complies with Canadian Multilateral Instrument 52-110-Audit Committees, which sets out detailed requirements regarding the composition of the Audit Committee and its responsibilities.

Corporate Governance Guidelines.  According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed company’s website. The Company operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, many of which are described under the heading “Statement of Corporate Governance Practice” in the Company’s Annual Information Circular.   However, the Company has not codified its corporate governance principles into formal guidelines in order to post them on its website.

Shareholder Meeting Quorum Requirement.  The NYSE governance rules do not contain a minimum quorum requirement for a shareholder meeting, but gives careful consideration to provisions in a listed company’s by-laws that fixes a quorum for a shareholders’ meeting at less than a majority of the outstanding shares.  The Company’s quorum requirement is set forth in its By-Laws.  A quorum for a meeting of shareholders is present, irrespective of the number of persons actually present at the meeting, if the holder or holders of five percent (5%) of the shares entitled to vote at the meeting are present in person or represented by proxy.

Proxy Delivery Requirement.  The NYSE requires the solicitation of proxies and delivery of proxy statements for all shareholder meetings, and requires that these proxies shall be solicited pursuant to a proxy statement that conforms to the Commission’s proxy rules.  The Company is a “foreign private issuer” as defined in Rule 3b-4 under the Exchange Act, and the equity securities of the Company are accordingly exempt from the proxy rules set forth in Sections 14(a), 14(b), 14(c) and 14(f) of the Exchange Act.  The Company solicits proxies in accordance with applicable rules and regulations in Canada.

Board Committee Mandates.  The mandates of the Company’s Audit Committee, Compensation Committee, Reserves Committee and Nominating and Corporate Governance Committee are each available for viewing on the Company’s website at www.interoil.com/governance.asp, and are available in print to any shareholder who requests them. Requests for copies of these documents should be made by contacting Mark Laurie, Corporate Secretary, at Level 1, 60-92 Cook Street, Cairns, Queensland 4870 Australia, Telephone: +61 7 4046 4600.

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SIGNATURES

Pursuant to the requirements of the Exchange Act, the Company certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	INTEROIL CORPORATION
	/s/ Phil E. Mulacek
	Phil E. Mulacek
	Chairman of the Board, Chief Executive Officer
	and President
Date:  March 1, 2010

EXHIBIT INDEX

The following exhibits have been filed as part of the Annual Report:

EXHIBIT NUMBER	DESCRIPTION
1.	Annual Information Form for the year ended December 31, 2009.
2.	Audited annual consolidated financial statements for the year ended December 31, 2009, including a reconciliation to United States generally accepted accounting principles.
3.	Management’s Discussion and Analysis for the year ended December 31, 2009.
4.	Consent of PricewaterhouseCoopers dated March 1, 2010.
5.	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
6.	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
7.	Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.
8.	Certification of Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.

EX-99.1

InterOil Corporation   Annual Information Form   For the Year Ended December 31, 2009 March 1, 2010   

TABLE OF CONTENTS

TABLE OF CONTENTS	1
PRELIMINARY NOTES	2
GENERAL	2
NON-GAAP MEASURES AND RECONCILIATION	2
LEGAL NOTICE – FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	4
CONVERSION	5
GLOSSARY OF TERMS	5
CORPORATE STRUCTURE	8
GENERAL DEVELOPMENT OF THE BUSINESS	9
BUSINESS STRATEGY	14
DESCRIPTION OF OUR BUSINESS	15
UPSTREAM - EXPLORATION AND PRODUCTION	15
MIDSTREAM - REFINING	18
MIDSTREAM - LIQUEFACTION	21
DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION	22
RESOURCES	23
THE ENVIRONMENT AND COMMUNITY RELATIONS	25
RISK FACTORS	26
DIVIDENDS	36
DESCRIPTION OF CAPITAL STRUCTURE	36
MARKET FOR SECURITIES	38
DIRECTORS AND EXECUTIVE OFFICERS	39
AUDIT COMMITTEE	42
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	43
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	44
MATERIAL CONTRACTS	44
TRANSFER AGENT AND REGISTRAR	47
INTERESTS OF EXPERTS	48
ADDITIONAL INFORMATION	48
Schedule A – Report of Management and Directors on Oil and Gas Disclosure	49
Schedule B – Report on Reserves Data by Independent Qualified Reserves Evaluator	50
Schedule 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, 2009.  It should be read in conjunction with InterOil’s audited consolidated financial statements and notes for the year ended December 31, 2009 and Management’s Discussion and Analysis for the year ended December 31, 2009 (“2009 MDA”), 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 and/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, 2009 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 2009 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 an LNG plant and condensate stripping facility in Papua New Guinea; the development of such LNG plant and stripping facility; 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 an LNG and condensate stripping facility; 

· the uncertainty in our ability to attract capital; 

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

· the inherent uncertainty of oil and gas exploration activities;

· potential effects from oil and gas price declines ; 

· the availability of crude feedstock at economic rates;

· our ability to timely construct and commission our LNG and condensate stripping facility;

· difficulties with the recruitment and retention of qualified personnel; 

· losses from our hedging activities;

· fluctuations in currency exchange rates;

· the uncertainty of success in pending lawsuits and other proceedings; 

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

· our ability to meet maturing indebtedness; 

· 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 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.

· payments from exploration partners;

· 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; 

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

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

· law enforcement difficulties.

Annual Information Form   INTEROIL CORPORATION     3

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 Gas
bbl	one barrel equalling 34.972 Imperial gallons or 42 U.S. gallons	btu	British Thermal Units
bblpd	barrels per day	mscf	thousand standard cubic feet
boe(1)	barrels of oil equivalent	mscfpd	thousand standard cubic feet per day
boepd	barrels of oil equivalent per day	mmbtu	million British Thermal Units
mboe	thousand barrels of oil equivalent	mmbtupd	million British Thermal Units per day
mbbl	thousand barrels	mmscf	million standard cubic feet
mmbbls	million barrels	mmscfpd	million standard cubic feet per day
mmboe	million barrels of oil equivalent
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma	scfpd	standard cubic feet per day
bscf	billion standard cubic feet	tcf	trillion 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 By
mcf	cubic metres	28.317
cubic metres	cubic feet	35.315
bbls	cubic metres	0.159
cubic metres	bbls	6.289
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

GLOSSARY OF TERMS

“AIF” means this Annual Information Form for the year ended December 31, 2009.

“API” means the American Petroleum Institute.

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

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

“Board”  means the board of directors of InterOil

“BP” BP Singapore Pte Limited.

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

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

“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.

“Debentures” means the 8% subordinated convertible debentures of InterOil due May 9, 2013.

“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”.

“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” Front end engineering and design.

“Feedstock” Raw material used in a processing plant.

“FID” Final investment decision.

Annual Information Form   INTEROIL CORPORATION     5

“GAAP” 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.

“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 Independent Consumer and Competition Commission in Papua New Guinea.

“IPI holders” means investors holding IPWIs in certain exploration wells required to be drilled pursuant to the Amended and Restated Indirect Participation Interest Agreement dated February 25, 2005.

“IPF” means InterOil power fuel.   InterOil’s marketing name for low sulfur waxy residue oil 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 by InterOil LNG Holdings Inc., an affiliate of InterOil, MLPLC and Pac LNG to construct the proposed LNG plant.  Under an agreement reached in February 2009, MLPLC no longer holds any interest in PNG LNG. (See “Material Contracts – Share Purchase and Sale and Settlement Agreement dated February 27, 2009)

“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.

“LNG Project” means the potential development by us of an LNG processing facility 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.

“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 residual fuel oil.

“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.

“MLPLC” Merrill Lynch PNG LNG Corp., a company organized under the laws of the Cayman Islands and an affiliate of Merrill Lynch, Pierce, Fenner & Smith Inc. and Merrill Lynch & Co.

“Naphtha” That portion of the distillate obtained from the refinement of petroleum which is an intermediate between the lighter gasoline and the heavier benzene, has a specific gravity of about 0.7, and is used as a solvent for varnishes, illuminant, and other similar products.

“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.

Annual Information Form   INTEROIL CORPORATION     6

“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.

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

“Petromin” meansPetromin PNG Holdings Limited, a company incorporated in Papua New Guinea and mandated by the State to invest in resource projects on its behalf.

“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.

“Royalties” refers to royalties paid to others.  The royalties deducted from the reserves are based on the percentage royalty calculated by applying the applicable royalty rate or formula.

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

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

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

“Working interest” means the percentage of undivided interest held by InterOil in an oil and natural gas property.

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

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CORPORATE STRUCTURE

Name, Address and Incorporation

InterOil Corporation is a Yukon Territory corporation, continued under that Territory’s YBCA on August 24, 2007.  In November 2007, InterOil amended its articles to authorize 1,035,554 Series A Preferred Shares.

Our registered office	Our corporate office	Our corporate office
In Canada is located at:	in Australia is located at:	in Papua New Guinea is located at:
Suite 300,204 Black Street Whitehorse, Yukon Y1A 2M9	Level 1, 60-92 Cook Street, Portsmith, Queensland 4870	Level 6 Defens Haus Cnr Champion Parade and Hunter Street, Port Moresby

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.

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GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History

InterOil is developing a fully integrated energy company operating in Papua New Guinea and its surrounding Southwest Pacific region.  The following is a summary of significant events in the development of InterOil’s businesses and corporate activities over the past three years.

Upstream – Exploration and Production

Over the past three years, 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. We continue to evaluate the size and structure of the Elk and Antelope fields by drilling additional appraisal wells.  Our ability to commercialize these discoveries will depend, in part, on the results of these appraisal wells.  In addition, there is no market for natural gas in PNG, so our ability to sell natural gas production from our discoveries will depend upon the development of a liquefied natural gas facility in PNG.  This project will require substantial amounts of financing and will take a number of years to complete. As discussed below, we are evaluating the construction of both a liquefied natural gas facility near our refinery in PNG and a condensate stripping facility within the Elk and Antelope fields.  No assurances can be given that we will be able to successfully construct such facilities, or as to the timing of such construction.

We spudded the Elk-2 well in February 2007.  The Elk-2 well was the first appraisal well to help delineate the extent of the Elk structure.  Elk-2 was drilled to a depth of 3,329 metres but did not flow gas at commercial rates having penetrated the reservoir below the gas-water contact.

During 2007, a seismic program was conducted with 12 lines totaling 230 kilometres acquired.  Of this, 44 kilometres related to PPL 237, with the remaining 186 kilometres over PPL 238.  Final processing of the 12 lines of Elk appraisal seismic was completed in December 2007.

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 4½ 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 resources on the Elk and Antelope fields and PPL’s 236, 237 and 238.  A right of first refusal to purchase hydrocarbon condensates from these licenses was retained.

On October 30, 2008, Petromin entered into an agreement with us to take a direct interest in the Elk/ Antelope field 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, Petromin has agreed to pay us 20.5% of all other sunk costs incurred by InterOil prior to entering into the agreement.  Until the PDL is granted, any payment made by Petromin 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 Petromin between the existing interest holders (InterOil, IPI holders and PNGDV) 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.  Drill Stem Test (“DST”) 1 flowed 13.1 mmscfpd. Drilling continued to 2,710 metres and the well was logged. Subsequent drill stem tests 3 and 6 were performed (DST’s 2, 4 and 5 were mechanically unsuccessful).   The well was then completed with 7 inch tubing and flow tested at 382 mmscfpd. After plugging back to 2,355 metres, a sidetrack was commenced with the objective to drill ahead in order to re-test an interval suspected to include a gas/oil or gas/water contact. At 2,416 metres drilling was suspended and testing operations commenced. DST 8 was conducted within the interval from 2,380 metres and 2,416 metres recovered oil and oil emulsion (approximately 44 API gravity).  Flow information from the sidetrack was considered unreliable as a result of the sidetrack’s close proximity to the original wellbore.  A second sidetrack was commenced in an attempt to deviate far enough from the original wellbore and sidetrack 1 to obtain more reliable information. Further DST’s were then conducted with DST 12 (which tested an interval from 2,347 metres to 2,402 metres) recovering gas and condensate. DST 14 (which tested an interval from 2,420 metres to 2,452 metres) recovered gas and condensate. In both cases the water recovered was measured as drilling fluid and not formation water.  The Antelope-1 side track was completed with 2 7/8 inch tubing and the well was made ready for future production and/or long term flow testing.

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On July 27, 2009, the Antelope 2 well, located approximately 4 kilometers south of Antelope 1 and within the boundaries of PPL237 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” tubing and a high rate flow test to confirm deliverability was performed in early December 2009. This flow test recorded a maximum flow rate of 705 mmcfd including 11,200 bbls of condensate per day.  Subsequent to this flow test, the 7inch tubing was removed and a 7inch liner was run.  A 6 ¼ inch hole was then drilled to 2325 metres and DST 2 was performed.  This DST confirmed gas and condensate with a stabilized condensate to gas ratio (“CGR”) of over 20Bbl/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.  The well is currently being sidetracked to drill a horizontal section in the pay interval of the lower part of the reservoir.

In September 2009, a 100 kilometer 2D seismic program to appraise the Antelope field was commenced and recording of seismic data is continuing.

During the third quarter of 2009, Pac LNG (which company 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 in furtherance of an option granted to it in 2007 and in exchange for $25 million, together with payment of certain historical exploration costs and the transfer to InterOil of 2.5% of Pacific LNG’s economic interest in the Joint Venture Company.

On December 15, 2009, we completed the second stage of an exchange of certain indirect participation interests held by a number of IPI holders under the Amended and Restated Indirect Participation Agreement dated February 2005 (the “IPI Agreement” – see ‘Material Contracts’) for a number of our common shares. Pursuant to this exchange, we acquired each 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 of the four exploration wells still to be drilled under the IPI Agreement.  In exchange for these interests, InterOil issued 1,344,710 common shares to those investors having an aggregate value of US$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 $2.0 million.  The decision was made to allow us to focus our resources on the Elk and Antelope fields and PPL’s 236, 237 and 238.  We are currently seeking approval from the State to allow this divestment to be finalized.

During 2009, we continued efforts to commercialize the Elk and Antelope fields. The commercialization of any resource discovered in the Elk and Antelope fields remains uncertain.  We are evaluating the feasibility of a condensate stripping facility which would extract condensate from the resource ahead of a planned LNG Plant.  If feasible, such a facility would not commence operations prior to 2012.  The discovery is located in an area requiring construction of a pipeline and a gas liquefaction facility in order to process any gas extracted, which we would not expect to be operational prior to 2015.  We are also undertaking a continuing process exploring the sale of a portion of the ownership in the proposed LNG Project and the Elk and Antelope fields to industry investors with a view to assisting us to pursue the LNG Project.

Due to the substantial expected infrastructure capital requirements, additional wells are required to develop sufficient condensate and/or natural gas resources to feed a condensate stripping and/or LNG facility.  Only once economic and technical uncertainties have been resolved, will InterOil (and any strategic investors) be in a position to make a Financial Investment Decision (“FID”) to proceed with the construction of the necessary condensate stripping and/or LNG plant infrastructure.  No assurances can be given that we will be able to successfully construct such facilities, or as to the timing of such construction.

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In order to progress the development and commercialization of the Elk and Antelope fields, we are required to apply for one or more PDLs, which will consist of the acreage surrounding the field and also acreage on which to locate facilities and pipeline rights of way.  An application for a PRL in respect of the Elk and Antelope fields was submitted in August 2009 for an area on PPL 238 totaling 105,445 acres (42,178 hectares).  Grant of the PRL would allow us to evaluate the technical and commercial feasibility of condensate and/or gas production from the Elk and Antelope fields.

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 in the costs of crude feedstock 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. Finalisation 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 outcome of the review 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 bblspd to 36,500 bblspd.

During 2009, our total throughput per day (excluding shut down days) was 21,155 bbls per operating day versus 22,034 bbl per operating day in 2008, and 19,713 bbls per operating day in 2007.  The total number of barrels processed into product at our refinery for 2009 was 5.72 million as compared with 5.67 million for 2008, and 5.57 million in 2007.  2008 marked the first time that we achieved a net income from our refining operations for the year, with such profitability also occurring in 2009.

Midstream – Liquefaction segment

In May 2006, we entered into a memorandum of understanding with the State for natural gas development projects in Papua New Guinea and a tri-partite agreement with Merrill Lynch Commodities (Europe) Limited and Pac LNG.   The tri-partite agreement related to a proposal for the construction of a liquefaction plant to be built adjacent to our refinery.

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 and the Joint Venture Company for the development of a gas liquefaction facility and associated infrastructure referred to as the LNG Project.  The LNG Project is targeting a facility that will produce up to nine million tons per annum of LNG and condensates.  The infrastructure contemplated includes a condensate storage and handling facility, a gas pipeline from the Elk and Antelope fields, as well as sourced suppliers of gas, and LNG storage and handling.  The LNG facility would be designed to interface with our existing refining facilities.

In 2008, certain disputes arose among Merrill Lynch and the other partners to the LNG Project, including InterOil. In February 27, 2009, a settlement agreement was entered into whereby InterOil LNG Holdings Inc. and Pac LNG acquired Merrill Lynch Commodities (Europe) Limited’s  interests in the Joint Venture Company.  InterOil ultimately issued 499,834 common shares valued at $11.25 million for its share of the consideration payable to Merrill Lynch in relation to the settlement.  As a result of this transaction, Merrill Lynch has not retained any ownership in the LNG Project or in the Joint Venture Company.  (See “Material Contracts – Share Purchase and Sale and Settlement Agreement dated February 27, 2009”).

In March 2008, Bechtel was retained to undertake the FEED and engineering, procurement and contracting work for the proposed LNG facility.

In 2009, technology supporting work in advance of potential FEED was completed by Bechtel and InterOil.  This work included initial Environment Impact Statement (EIS) development, review of alternate onshore and offshore pipeline routes, preliminary sizing of the pipeline and associated compression.

On December 23, 2009, the LNG Project Agreement between the State and Liquid Niugini Gas Ltd (a wholly owned subsidiary of the Joint Venture Company incorporated under the laws of PNG) was executed.  The agreement contains provisions for development of the LNG Project, along with pipeline infrastructure to deliver gas from InterOil’s 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 Petromin, 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 over required land, passage of enabling legislation and a FID.

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We are also undertaking a continuing process to explore the sale of a portion of the ownership in the proposed LNG Project and the Elk and Antelope fields to industry investors with a view to assisting us to finance and pursue the project.

Downstream – Wholesale and Retail Distribution

During 2007, we acquired three additional aviation fuelling depots in Papua New Guinea.  During 2007 and 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.

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.

In June 2009, Papua New Guinea’s competition authority, the Independent Consumer & Competition Commission (ICCC), commenced a review into the pricing arrangements for petroleum products in PNG.  The last such review was undertaken during 2004 and pricing regulations established as a result of that were due to expire on December 31, 2009. The purpose of the review is 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.  We have provided detailed submissions to the ICCC.  The ICCC has recently advised that its final report will be issued in March 2010. It is possible that the ICCC may determine to increase regulation of pricing and reduce the margins able to be obtained by our distribution business.  Such a decision, if made, may negatively affect our downstream business and require a review of its operations. (See “Risk Factors”).  The existing pricing regulations have been carried over subsequent to December 31, pending this decision.

During 2009 we negotiated an agreement with Airlines of PNG, PNG’s second largest airline, to supply their aviation fuel requirements.

As of December 31, 2009, we provided petroleum products to 56 retail service stations with 43 operating under the InterOil brand name and the remaining 13 operating under their own independent brand.  Of the 56 service stations that we supply, 17 are either owned by or head leased to us with a sublease to company-approved operators.  The remaining 39 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.

Financing

In 2007, InterOil undertook the following financing transactions:

· In July 2007, we entered into the LNG Project Shareholders Agreement (see “Material Contracts – LNG Project Shareholders Agreement dated July 30, 2007”) which had the effect of freezing the interest rate on the now retired $130.0 million secured credit bridging facility provided by Pac LNG and MLPLC and entered into in May 2006, at 4% for the life of that loan.

· In November and December 2007, we undertook a private placement of 1,078,514 common shares with institutional investors at an issue price of $23.18 per share and received net proceeds of $23.5 million.

· In November 2007, we issued 517,777 series A preferred shares at an issue price of $28.97.  We received net proceeds of $14.3 million.  In July and August 2008, all $15.0 million series A preferred shares issued in November 2007 were converted into 517,777 common shares.

Annual Information Form   INTEROIL CORPORATION     12

· In December 2007, we amended our OPIC loan agreement (see “Material Contracts - OPIC Loan Agreement”) in order to defer two installments of $4.5 million, each due on December 31, 2007, to be repaid by January 31, 2008 and February 29, 2008 respectively.

In 2008, InterOil undertook the following financing transactions:

· In February 2008, payment of the two installments of $4.5 million to OPIC, originally deferred in 2007 was deferred further until the end of the OPIC loan period.  They are now due to be repaid by June 30, 2015 and December 31, 2015, respectively.

· In May 2008, we converted $60.0 million of the expiring $130.0 million bridging facility into common shares.  The balance of $70.0 million 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 worth of the $95.0 million principal amount of Debentures were 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.

· In August 2008, we filed a short form base shelf prospectus with the Ontario Securities Commission and a corresponding registration statement on Form F-10/A with the United States Securities and Exchange Commission, to provide financial flexibility for the future and issue, from time to time until expiry of the prospectus in September 2010, up to a total of $200.0 million of debt securities, common shares, preferred shares and/or warrants in one or more offerings.  A portion of this amount was used 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.  (See “Material Contracts – Secured Revolving Crude Import Facility”)  In 2008, the facility limit was increased by $20.0 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 $55.5 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 and Westpac Bank PNG Limited. 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. As at December 31, 2009 we had drawn $7.8 million of the combined facility

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 3,159,000 common shares.

· On June 8, 2009, we completed a registered direct stock offering under the base shelf prospectus filed in August 2008 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 Bank of South Pacific Limited.  The existing facility had a facility limit of 70.0 million Kina (approximately $25.9 million). However, on renewal, the facility limit was reduced to 50.0 million Kina (approximately $18.5 million).  The Westpac facility is for an initial term of three years and is due for renewal in October 2011.  No changes were made to this facility.  The total combined facility limit was reduced to 130.0 million Kina (approximately $48.1 million).  The BSP facility is renewable annually and is next due for renewal in October 2010. 

Annual Information Form   INTEROIL CORPORATION     13

Management Team

During 2007, 2008 and 2009, InterOil’s Board and senior management changed as follows:

· On June 12, 2007, Mr. Mark Laurie was appointed as General Counsel and Corporate Secretary.

· 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.

BUSINESS STRATEGY

InterOil’s 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 InterOil shareholders, while being environmentally responsible, providing a quality working environment and contributing positively to the communities in which InterOil operates.  A significant element of that strategy is to establish and develop gas reserves and an LNG facility in Papua New Guinea and export the LNG.  InterOil is aiming to pursue this strategy by:

Developing our position as a prudent and responsible business operator

· Build on 15 years of engagement in Papua New Guinea

· Maintain sound health, safety and security record

· Continue developing good relationships with government, partners and stakeholders

· 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

· Explore improved transport efficiencies and economics

Maximizing the value of our exploration assets

· Seek possible early cash flows from condensate production

· Establish gas volumes sufficient to underpin the LNG Project

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

Building an export gas liquefaction business in Papua New Guinea

· Select and contract with strategic partners

· Establish LNG Project’s commercial viability and structure

· Seek licences, enabling legislation and approvals required for the LNG Project from the State.

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Positioning for long term success

· Accelerate exploration activity to extract full value from exploration licenses

· Undertake seismic work to identify additional exploration opportunities

DESCRIPTION OF OUR BUSINESS

Overview

Our operations are organized into four major business segments:

Segments	Operations
Upstream	Exploration and Production – Explores and appraises potential oil and natural gas structures in Papua New Guinea with a view to commercializing significant discoveries. Current commercialisation of the Elk and Antelope fields includes the development of a condensate stripping and recycling facility and development of gas production facilities for liquefied natural gas.
Midstream	Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for spot export. Liquefaction - Developing an onshore and/or offshore LNG processing facility in Papua New Guinea.
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, 2009, we had 680 full-time employees in all segments, with 114 in upstream, 121 in midstream, 368 in downstream and 77 in corporate.  Our work force is not unionized.

UPSTREAM - - EXPLORATION AND PRODUCTION

Description of Properties

As at December 31, 2009 we had interests in four PPLs in Papua New Guinea covering approximately 4.7 million gross acres, of which approximately 4.1 million net acres were operated by InterOil.  PPL’s 236, 237 and 238 are located in the Eastern Papuan Basin northwest of Port Moresby.  All of our licenses are located onshore in Papua New Guinea, except for PPL 244 which is offshore in the Gulf of Papua.

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, 2009:

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License	Location	Operator	InterOil Current Working Interest 1			Acreage Gross		Acreage Net
PPL 236	Onshore	InterOil		100.00	%		1,122,224		1,122,224
PPL 237	Onshore	InterOil		100.00	%		809,267		809,267
PPL 238	Onshore	InterOil		100.00	%		2,084,326		2,084,326
PPL 244	Offshore	Talisman		15.00	%		675,400		101,310
Total							4,691,217		4,117,127

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

Operated License Commitments, Terms, Expiry and Re-Application

The primary six year terms of our operated exploration licenses expired in March 2009.  Under the relevant legislation in Papua New Guinea, a licensee is permitted to apply for a second exploration term for a further five year period, but is required to relinquish 50% of the acreage granted under the primary term.  In March 2009, all three licenses were renewed in respect of what we considered the most prospective 50% of the license acreage.

The PPL license renewals also required that we make further commitments on spending within those license areas during the renewed license term.  Set out below are InterOil’s applicable commitments for each PPL based on the approved renewals in March 2009:

License	License Issued for second  term in	Second Term	Commitment Years 1— 2 (US $ Millions)		Commitment Years 3 - 5 (US $ Millions)		Total License Commitment (US $ Millions)		License Expiry
PPL 236	March 2009	5 years	$	5.0	$	10.0	$	15.0	March 2014
PPL 237	March 2009	5 years	$	14.0	$	34.0	$	48.0	March 2014
PPL 238	March 2009	5 years	$	2.0	$	30.0	$	32.0	March 2014
		Totals	$	21.0	$	74.0	$	95.0

Petroleum License Details

Net Working Interests on PPL236, PPL237 & PPL238 (the Operated Exploration Licenses)

The Operated Exploration Licenses are located onshore in the eastern Papuan Basin, northwest of Port Moresby and are wholly owned by InterOil, subject to investor elections to earn a working interest in any discoveries under our various indirect participation interest agreements.  The State also 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.  Finally, Pac LNG holds a 2.5% working interest in gas and condensate in the Elk and Antelope fields (which fields are located on PPL 237 and PPL 238) under an agreement entered into in 2009.  The agreement grants Pac LNG rights to be registered on the PRL applied for in respect of the fields and on any subsequent PDL.  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 exercises their rights to acquire their allocated interests in the Elk and Antelope discoveries.

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Participant	Working interests *			With State participation
InterOil		74.1614	%		57.4751	%
IPI holders		16.5886	%		12.8562	%
PNGDV		6.75	%		5.2312	%
Pac LNG		2.50	%		1.9375	%
State entitlement (Petromin)		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, 2009 elect to participate.

Our current exploration efforts are focused on the Operated Exploration Licenses, with the vast majority of our exploration expenditure relating to PPL’s 238 and 237, where the Elk and Antelope fields are located.

On October 30, 2008, Petromin entered into an agreement to take a 20.5% direct interest in the Elk and Antelope fields.  If certain conditions in the agreement are met, Petromin has agreed to fund 20.5% of the costs of developing the Elk and Antelope fields.  The State’s right to invest arises under legislation and is exercisable upon issuance of the PDL, which has not yet occurred.  The agreement contains certain provisions applicable in the event that the PDL is not issued within a certain timeframe. During 2009, the State confirmed Petromin’s nomination to exercise its interest in the Elk and Antelope fields.

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 the license.  This license covers an area that includes our refinery and has limited road access. We conducted desktop studies over this license area in September and October 2009.

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.  In 2007, 28 miles (44 kilometres) of the 144 mile (230 kilometres) Elk appraisal 2D seismic program were acquired over PPL 237. 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.  On December 2, 2009, a short term surface flow test of Antelope-2 was conducted resulting in an estimated 705 mmscfpd of gas and associated condensate of approximately 11,200 bbls per day. During 2009, we also undertook various continuing desktop and surface studies.

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, Elk 4A and Antelope-1 have been gas/condensate discovery wells. On March 2, 2009 a short term surface flow test of Antelope-1 was conducted resulting in an estimated 382 mmscfpd of gas and associated condensate of approximately 5,000 bblpd.  This well encountered a dolomitized reef and penetrated approximately 2,000 feet of reservoir with matrix porosity averaging around 8%. On November 28, 2008, we applied for a Declaration of Location over our discovery block and an additional 8 blocks in the license that comprised the Elk and Antelope fields and a development corridor.  The declaration of location is a necessary pre-condition to the application for a PRL or a PDL and was granted in March 2009. In August 2009, we applied for a PRL over the declared location.  The PRL is yet to be granted. Subject to an election to be made by Petromin to acquire a 20.5% interest on behalf of the State, we will have a 97.5% interest in the PRL once it is granted, recognizing the 2.5% direct working interest held by Pacific LNG Operations Limited acquired during 2009.

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Petroleum Prospecting License 244

We currently have a 15% working interest in PPL 244 although we have agreed to terms to divest all of our interest in this license.  This divestment is currently pending approval from the State, at which point it will become unconditional and the transaction will be finalized.  Talisman Oil Limited is the operator of this license.  This license was granted on February 25, 2005 for a six year term ending February 25, 2011.  This license is located offshore in the Gulf of Papua and the operator is preparing to drill a commitment well in the second half of 2010.

Petroleum Development License (”PDL”)

In order to progress the proposed development and commercialization of the Elk and Antelope fields, we are required to apply for one or more PDLs, which will consist of the acreage surrounding the Elk and Antelope fields and also acreage on which to locate facilities and pipelines.  We have commenced preparation of an application for a PDL which encompasses the Elk and Antelope fields and this work is ongoing.

The State’s Department of Petroleum and Energy (“DPE”) will review any PDL application and an initial development plan and consider awarding a PDL.  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, if the State elects to take up 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 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.  IPI holders hold interests totaling 16.5886% of each of these existing and future wells, including those in the Elk and Antelope fields.

In addition to the above, PNG Energy Investors (“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, 2009, we have drilled less than 9 exploration wells.   In order to participate, PNGEI would be required to contribute a proportionate amount of drilling costs related to these future wells.

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

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 Pacific LNG to be registered on the PRL applied for in respect of the Elk and Antelope fields.

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.  Under our 30 year agreement with the State which expires in 2035, the State has undertaken to ensure that domestic distributors purchase their refined petroleum product needs from the refinery, or any refinery which is constructed in Papua New Guinea, at an IPP.  (See under the heading “Sales” below for a further discussion of IPP).  Our refinery’s production capacity is more than sufficient to meet all of the domestic demand for the refined products we produce in Papua New Guinea.  However, during 2008 and continuing through 2009, not all domestic demand was sourced from our refinery, as some competing product was imported and sold in Papua New Guinea by distributors in contravention of our rights under our agreement with the State.  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 naphtha and low sulfur waxy residue.  To the extent that we do not convert naphtha to gasoline, we export it to the 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 domestically and by export and is valued by more complex refineries as cracker feedstock.

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Facilities and Major Subcontractors

Our refinery includes a jetty with two berths for loading and off-loading ships 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 12,000 to 130,000 dwt crude and product tankers.  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, 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 when it was renewed for a further 12 months until June 2010.  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.  Our supply agreement with BP provides BP with financial incentives to secure the most economically attractive crude feedstock 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 low sulfur waxy residue.  Under our 30 year agreement with the State, the State has agreed to ensure that all domestic distributors purchase their refined petroleum product needs from our refinery, (and from any 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 is no longer being updated, to ”Mean of Platts Singapore” (”MOPS”) which is the 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 the Company’s relationship with the Independent State of Papua New Guinea.  However, it is the current IPP calculation mechanism being monitored by the ICCC (see “Material Contracts – Refinery Project Agreement”).

The major export product from our refinery is naphtha, which was historically sold to Shell International Eastern Trading Company on a term basis pursuant to a contract that expired in September 2008.  A 12 month term contract was then signed with Sojitz Corporation for export sales of naphtha from October 1, 2008 to September 30, 2009.  From October 1, 2009, a new term agreement with Dalian Fujia Dahua Petrochemicals, which operates a petrochemical plant in China, has been put in place providing for export sales of naphtha until September 30, 2010.

During 2009, there were six export cargoes of naphtha averaging approximately 27,000 metric tons each for a total of approximately 166,000 tonnes or 1.55 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 2007 or 2008. However, we made an export sale of diesel and gasoline to the Pacific Island of Nauru in November 2009.

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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.

Until the conversion in 2006, of the main process furnaces and commissioning of the Hyundai generators which burn low sulfur waxy residue, we were a net consumer of LPG.  With the installation of the low sulfur waxy residue 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.  As a result, we are currently the only beneficiary of the IPP structure and the associated requirement for domestic refined product needs to be procured from domestic refineries as described under the heading “Sales” above.  We do not envision any new entrants into the refining business within Papua New Guinea under the current market conditions.  However, domestic distributors did not source all of their requirements from the refinery during 2008 and 2009 and a volume of competing finished product is currently being imported, in contravention of our rights under our Refinery Project Agreement.  Excess diesel, gasoline, naphtha and low sulfur waxy residue 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 gases and low sulfur waxy residue to all domestic distributors.  Our main domestic customer is our downstream business segment, however we also distribute fuel products to Niugini Oil Company (NOC) and Exxon Mobil, with gases sold to Origin PNG.

Our major exports are naphtha and low sulfur waxy residue (“LSWR”).  Previously we sold all naphtha exports under term contracts with Shell and Sojitz Corporation.  Since October 2009, all sales of naphtha have been under our 12 month term contract with Dalian Petrochemical Plant.  Sales of export LSWR were also under a term contract with Shell International Eastern Trading Company which expired in December 2008.  We have not renewed the term contracts for sales of low sulfur waxy residue and, since such time, sell LSWR in the spot market.

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 two months in advance, whereas the supply or export of finished products takes place after the crude feedstock is discharged and processed.  This timing difference impacts upon 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 use various derivative instruments to reduce or hedge the risks of changes in the relative prices of our crude feedstock and refined products.  These derivatives, which we use to manage our price risk, 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 instrument which we generally use is an over-the-counter swap.  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 and Dubai.  Using these tools, we actively engage in hedging activities to manage margins. Occasionally, there is insufficient liquidity in the crude swaps market, and we then use other derivative instruments such as Brent futures on the International Petroleum Exchange to hedge our crude costs.

The high volatility of crude prices in 2008 meant that we faced significant timing and margin risk on our crude cargos during the year.  During May 2008, we entered into short and long term hedges which helped us to manage significant portion of this timing and margin risk.  Our hedges netted us $27.8 million profit during the year with a further $18.2 million of hedging gains recognized in our 2009 refinery profit as the underlying transactions occurred.  In light of lower volatility, no new hedges were entered into during 2009 and there are no outstanding derivative hedge contracts as at December 31, 2009.

MIDSTREAM - - LIQUEFACTION

InterOil is developing an LNG Project for the potential construction of liquefaction facilities that would be built adjacent to our refinery.  The LNG Project targets facilities that would produce up to nine million tons per annum of LNG and associated condensates.  The infrastructure currently being contemplated includes condensate storage and handling, a gas pipeline from the Elk and Antelope fields and LNG storage and handling.  Initial design for the liquefaction facilities incorporates interface with our existing refining facilities.

On July 30, 2007, a shareholders’ agreement was signed between InterOil LNG Holdings Inc., Pacific LNG Operations Ltd., Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc. (“Joint Venture Company”).  The signing of this shareholders’ agreement meant that PNG LNG Inc. was no longer a subsidiary of InterOil Corporation and became a jointly controlled entity between InterOil and the other parties to the shareholders’ agreement.  This shareholders agreement established the Joint Venture Company as the basis for participation in and furtherance of the LNG Project.

On February 27, 2009, a settlement agreement was entered into whereby InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd acquired Merrill Lynch’s interests in the Joint Venture Company in equal shares.  InterOil ultimately issued 499,834 common shares valued at $11.25 million for its share of the consideration to Merrill Lynch.  As a result of this transaction, Merrill Lynch has not retained any ownership in LNG Project or in the Joint Venture Company.  (See “Material Contracts – Share Purchase and Sale and Settlement Agreement dated February 27, 2009”)

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 near the proposed liquefaction facility site at Napa Napa, 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 our joint venture partner to equalize their investment in the Joint Venture Company with that of InterOil.  As of December 31, 2009, 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 Pacific LNG is entitled to 47.5%.

Our shareholders’ agreement recognises that the Final Investment Division for the project is expected to be approved when all of the joint venture partners agree that each and all of the following steps have been completed.

(i) conclusion of FEED for certain (phase 1) facilities;

(ii) execution of the major project contracts;

(iii) approval of the construction plan and budget;

(iv) approval of the financing plan; and

(v) receipt of each material governmental approval required for the project.

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Initial engineering design has been 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.  Aside from the extensive negotiation process associated with this agreement, effort has been focused towards, establishing the availability of sufficient gas quantities to underpin this project.

We are also undertaking a continuing process to explore the sale of a portion of the ownership in the LNG Project and the Elk and Antelope fields, to industry investors with a view to assisting us to finance the project.

Completion of liquefaction facilities will require substantial amounts of financing and construction will take a number of years to complete.  No assurances can be given that we will be able to successfully finance or construct such 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.  As of December 31, 2009, we believe we supplied approximately 70% of Papua New Guinea’s total refined petroleum product needs.

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.  In June 2009, ICCC commenced a review into the pricing arrangements for petroleum products in PNG.  The last such review was undertaken during 2004 and was due to expire on December 31, 2009.  The purpose of the review is 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.  We have provided detailed submissions to the ICCC.  The ICCC have most recently advised that its final report will be issued in March 2010.  It is possible that the ICCC may determine to increase regulation of pricing and reduce the margins able to be obtained by our distribution business.  Such a decision, if made, may negatively affect our downstream business and require a review of its operations.

Supply of Products

Our retail and wholesale distribution business distributes diesel, jet fuel, gasoline, kerosene and fuel oil as well as Shell 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.  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.  We are responsible for the scheduling of all the deliveries made by these tankers to the petroleum industry participants and customers in Papua New Guinea.  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.

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Retail Distribution

As of December 31, 2009, we provided petroleum products to 56 retail service stations with 43 operating under the InterOil brand name and the remaining 13 operating under their own independent brand.  Of the 56 service stations that we supply, 17 are either owned by or head leased to us with a sublease to company-approved operators.  The remaining 39 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 12 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 eleven 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 2009 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.

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.  We believe that throughout 2009, our competitors progressively increased their direct importation of refined petroleum products activity rather than sourcing products from our refinery.  We have been able to obtain refined products for our distribution business at competitive prices to date, but our competitive position is threatened by the importing activity of our competitors.  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.

Customers

We sell approximately 20% 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.  At present, no contract is in place with OTML with the previous contract having expired in December 2009.  Agreement has been reached in principle for a new three year supply arrangement and we are currently working to finalise the agreement.

We also sell approximately 10% of our refined petroleum products to Shell Oil Products Ltd (SOPL) in Papua New Guinea pursuant to a wholesale supply contract for the international airport. Due to the amount of petroleum products provided to SOPL, the loss of this customer, at least in the short term would adversely affect the profitability of our wholesale distribution business segment and of the refinery.  At present, no contract is in place with SOPL with the previous contract having expired in October 2009. SOPL’s owner is engaged in the process of tendering for the divestment of SOPL and the aviation refueling business conducted by it at Port Moresby’s international airport.  We participated in the tender process during 2009 and entered into an agreement to acquire SOPL as the preferred bidder.  The agreement was subject to approval by Papua New Guinea’s competition authority, the Independent Consumer and Competition Commission (ICCC).  The ICCC refused to authorize the acquisition by us on the basis of our existing market share and the agreement was terminated.  Shell’s owners have reinstated the sale process.

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.

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The Elk and Antelope fields (see “Description of Our Business”), located in Papua New Guinea, is 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 structural field penetrated by the Antelope-1 and Antelope-2 wells 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., an independent qualified reserves evaluator, as of December 31, 2009, and was prepared in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101.  All resources estimated are classified as contingent resources – economic status undetermined as follows:

Gross Resources Estimate for Gas and Condensate*

	Case
As at December 31, 2009	Low		Best		High
Initial Recoverable Sales Gas (tcf)		6.19		8.18		9.94
Initial Recoverable Condensate (mmbbls)		117.1		156.5		194.7
Initial Recoverable (mmboe)		1,148.8		1,519.8		1,851.4

*These estimates represent 100% of the Elk/Antelope Field. InterOil currently has a 97.50% working interest in the Elk and Antelope fields

Resource Estimate for Gas and Condensate – Net to InterOil*

	Case
As at December 31, 2009	Low		Best		High
Initial Recoverable Sales Gas Resources (tcf)		3.56		4.70		5.71
Initial Recoverable Condensate (mmbbls)		67.3		89.9		111.9
Initial Recoverable (mmboe)		660.6		873.2		1063.6

*These estimates are based upon InterOil holding a 57.4751% working interest in the Elk and Antelope fields, which assumes that: (i) the State and landowners elect to participate in the Elk and Antelope fields to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Elk/Antelope field and (ii) all elections are made to participate in the Field by all investors pursuant to relevant indirect participation interest agreements with InterOil, including to participate fully and directly in the PDL.

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

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

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

· Determination of economic viability.

Although a final project has not yet been sanctioned, pre-FEED studies are ongoing for LNG and condensate stripping operations 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 2009.  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.

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Environmental and Social Policies

We have developed and implemented an environmental policy which acknowledges that the principles of sustainable development are integral to responsible resource management and will strive to minimize impacts on the physical environment. Other environmental initiatives embrace the introduction of “ Environmental Risk Analysis“ for major projects in which hazards to the environment are identified, mitigating controls implemented and a “ Hazard Register “developed to monitor any residual risks. We are also developing project specific “ Environmental Management, Monitoring & Reporting Plans “, in compliance with the PNG environmental legislation and in order to monitor our ongoing compliance and performance,  we have established corporate level controls in which all “ near miss and real incidents “ are reported, and investigated.

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

We have established a dedicated Community Relations department to oversee the management of community assistance programs and to manage land acquisition related compensation claims and payments. Our development philosophy is based on “bottom-up planning” thus ensuring that all planning and development takes the local community into account.  In relation to our midstream 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 formulating an application for a PDL to develop the Elk and Antelope fields as required under PNG’s Oil & Gas Act. As a pre-requisite to the grant of a PDL, we are required to undertake specific studies and investigations designed to define land boundaries and landowners as well as addressing the potential impact of the project, in terms of its social, economic and environmental impact.  To this end, we have engaged specialist external consultants to assist us in a full scale social mapping and land owner identification program, a social economic impact assessment (SEIA) program and an environmental impact statement (EIS) program.  These studies 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 an 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 plant or LNG facility is contingent on our ability to obtain significant funding.

Our share of additional equity contribution for the construction of a LNG facility 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 facility.  Our existing cost estimates are subject to change due to such items as cost overruns, change orders, delays in construction, increased material costs, escalation of labor costs, and increased spending to maintain the construction schedule.

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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.  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 prospects at such time. In addition, 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.  Additionally, 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 LNG facility or our condensate stripping plant.

We depend upon access to the capital markets to fund our growth strategy.  Currently, the capital and credit markets are continuing to experience disruption which, if it continues for an extended period of time, is likely to adversely affect our growth strategy.

As a result of this 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 all financial institutions has diminished and risk premiums have increased.  As future capital expenditures will be financed out of funds generated from operations, borrowings and possible future equity or 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 impaired, 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 development of our exploration assets, our proposed condensate stripping facility, and the LNG Project, each of which would require significant capital.  However, if funds generated from operations are lower than expected or capital costs for these projects exceed current estimates, if we incur major unanticipated expenses related to development or maintenance of our existing properties or if any of our existing facilities are unable to be renewed, we may be required to seek additional capital to maintain capital expenditures at planned levels in relation to our operating, refining and distribution businesses as well.  Significant capital will be required in order to fund additional exploration and development of the Elk and Antelope fields and meet our exploration license commitments.  Additionally, significant capital would be required to develop the condensate stripping facility and the LNG Project.  Failure to obtain any financing necessary for our capital expenditure plans will likely result in delays in these activities.

There is uncertainty associated with the regulated prices at which our products are sold, both by our refinery and our distribution businesses.

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.

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 finalized 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.

The wholesale distribution margins able to be obtained by our downstream business are also closely regulated in Papua New Guinea. Papua New Guinea’s competition authority is currently undertaking a review of pricing regulation and wholesale margins.  It is possible that the authority may determine to increase regulation and/or decrease margins which may have the affect of reducing our profitability and, in a more extreme case, negatively affecting the viability of our downstream business, in whole or in part.

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

As of December 31, 2009, 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 in our PPL’s.  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 exploration 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 geoscience 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 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 projects.  We will continue to gather information about our exploration projects, and it is possible that additional information may cause us to alter our schedule or determine that a project should not be pursued at all.  You should understand that our plans regarding our projects 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 initial estimates.

If there is a sustained economic downturn or recession in PNG or globally, oil and natural gas prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

Many economists are predicting that the effects from this current global economic crisis or recession will be long lasting, at least in certain parts of the world.  The reduced economic activity associated with an economic crisis or recession may substantially reduce the demand for oil and natural gas and refined products, which could adversely affect the results of operations in our midstream and downstream businesses and the viability of our development projects.

Our refinery’s financial condition may be materially adversely affected if we are unable to obtain crude feedstocks at economic rates for our refinery.

While we have a number of possible sources we employ for crude supply, our agreement with BP currently provides for the delivery of crude feedstock.  The BP crude supply agreement expires on June 30, 2010.    We cannot assure you that we will continue to be able to source adequate feedstock for our refinery.

Various crude oils that are suitable for use as refinery feedstock are available in the nearby region.  However, our access 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 it to refine.  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.

Even if we obtain sufficient funding for our LNG facility and condensate stripping plant, we may not be able to timely construct and commission them.

We may not complete construction of our LNG facility or condensate stripping facility in a timely manner, 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:

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

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

· shortages of materials or delays in delivery of materials;

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

· difficulties or delays in obtaining gas for commissioning activities necessary to achieve commercial operability of the LNG or condensate stripping plant;

· 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

· local economic and infrastructure conditions.

Our inability to timely complete (or complete at all) our LNG facility or our condensate stripping plant may prevent us in part or in whole from commencing operations.  Thus, as a result, we may not receive any cash revenues from the condensate stripping plant or LNG facility on time or at all.

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 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 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 impact on our 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 feed stocks 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, which risk has increased with the global financial and credit market crisis; 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 feed stocks.

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

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

Our results of operations and financial condition may be affected by currency exchange rates.  Exchange rates may fluctuate widely in response to international political conditions, general economic conditions and other factors beyond our control. While our oil 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 verses 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.

We are a party to lawsuits and other proceedings in which we may not be successful.

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

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

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

Political conditions have at times been unstable in Papua New Guinea.  We attempt to conduct our business in such a manner that political and economic events of this nature will have minimal effects on our operations.  We believe that oil exploration and refinery operations are in the long term best interests of Papua New Guinea and that we will continue to have the support of the current government.  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.  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.

Our inability to generate sufficient cash flow to pay off or refinance our indebtedness with near-term maturities could have a material adverse effect on our financial condition.

We cannot assure that our business will generate cash flows from operations or that future borrowings will be available to us in an amount sufficient to enable us to pay our maturing indebtedness as it falls due.  As a result, we may need to refinance all or a portion of the debt, or to secure new financing before maturity.  This, to some extent, is subject to general economic, financial, legislative and regulatory factors and other factors that are beyond our control.  We cannot be sure that we will be able to obtain the refinancing or new financing on reasonable terms or at all.

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.  From March 31, 2009 through February 19, 2010, the highest sales price of the common shares on the New York Stock Exchange has been U.S. $84.05 and the lowest sales price of the common shares on such exchange has been U.S. $24.35.  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

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• 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 InterOil or its 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.

Title to certain of our properties may be defective or challenged by third party landowner claims, and landowner action may impede access to or activity on our properties.

While we believe that we have satisfactory title to our properties, some risk exists that title to certain properties may be defective or subject to challenge.  In particular, our properties 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.

The implementation of new Papua New Guinean laws, may have a material adverse effect on our operations and financial condition.

Our operations require licenses and permits from various governmental authorities to drill wells, develop the LNG Project, operate the refinery and market our refined products.  We believe that we hold all necessary licenses and permits under applicable laws and regulations for our 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.  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 LNG Project and our proposed condensate stripping facility.  There can be no guarantee that we will be able to obtain such licenses and permits.

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.

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Our refinery has not operated at full capacity for an extended period of time and our profitability may be materially negatively affected if it continues not to do so.

Our refinery did not operate at full capacity during 2009.  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; 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.

We sell approximately 20% of our refined petroleum products to Ok Tedi Mining Limited (OTML) in Papua New Guinea pursuant to wholesale distribution contracts.  We do not anticipate that the loss of other wholesale distribution contracts would have a material impact on this business segment.  However, 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.  At present, no contract is in place with OTML with the previous contract having expired in December 2009.  Agreement has been reached in principle for a new three year supply arrangement and we are currently working to formalise it.

We also sell approximately 10% of our products to Shell Oil Products Limited (SOPL) in Papua New Guinea pursuant to a wholesale supply agreement for the international airport.  The loss of this customer, at least in the short term, would adversely affect the profitability of the refinery and the wholesale distribution business.  At present, no long term contract is in place, the previous agreement having expired in October 2009. Additionally, SOPL’s owner is engaged in the process of tendering for the divestment of SOPL and the aviation refueling business conducted by it at Port Moresby’s international airport.

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 2009 as some competing product has been imported and sold in Papua New Guinea in contravention of our rights.

Our refinery is rated to process up to 32,500 barrels of oil per day and is proven to be able to process up to 36,500 barrels of oil per day.  We are able to fulfill the domestic market in Papua New Guinea’s demand for our products by refining approximately 18,000 barrels of crude feedstock a day. We are currently operating the refinery at less than full capacity due to an inability to profitably export our refined products and to the incidence 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 recent changes in Australia’s regulations regarding permitted sulfur and benzene content that our refined products currently do not meet.

In addition, our project agreement 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 oil 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;

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· 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;

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

· The availability of alternate fuel sources.

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.  Most 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 we have 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 feed stocks and for outlets for our refined products.  Many of our competitors obtain a significant portion of their feed stocks from company-owned production, which may enable them to obtain feed stocks 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.

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 feed stocks 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, 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.

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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 in accordance with GAAP.  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 GAAP, 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.  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 refining and distribution operations expose us to risks, not all of which are insured.

Our refining and distribution operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards and uncontrollable flows of crude oil 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.

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.  This default risk has been heightened by the global financial market and credit crisis.  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.

We depend on partners to timely fund their portion of the costs of our drilling program.

We are the operator of our PPL’s and thus are responsible for contracting on behalf of all the remaining parties participating in the project.  We rely on the timely payment of cash calls by our partners to pay for the percentage of the budget for which they are responsible.  In our current wells, that percentage is over 16%.  If our partners fail to pay their share of project costs or do not pay on a timely basis, we may have a limited ability, particularly in the current economic environment, to expend the capital necessary to undertake or complete future drilling programs on a timely basis or at all.  We cannot assure that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

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 would result in a $0.1 million change in our annual interest expense.

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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 byproduct 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.

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

As of December 31, 2009, we had $44.5 million in long-term debt with OPIC which matures in 2015, together with principal repayments due during 2010 totaling $9.0 million.  We also operate 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.  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 facility and other infrastructure associated with that proposed LNG Project, our proposes condensate stripping facility 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 refining margins, lower oil or gas prices, delays, operating difficulties, construction costs, lack of drilling success, the global financial and credit market crisis or other reasons we may not have the ability to expend the capital necessary to undertake or complete future drilling programs 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.

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

We believe that during 2009, our competitors progressively increased 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 could have a negative affect on our business and materially affect our results from operations.

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 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, 2009, 43,545,654 common shares were issued and outstanding.  All of the series A preferred shares that have been issued were converted into common shares during 2008 and none remain outstanding as at December 31, 2009.

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.

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Series A Preferred Shares

Effective November 17 2007, InterOil amended its articles to establish the series A preferred shares in connection with a US$15 million private placement financing.  The financing closed on November 21, 2007, at which time, 517,777series A preferred shares were issued.  As at the date hereof, all such shares have been converted into common shares and no series A preferred shares are outstanding.  InterOil does not intend to issue any series A preferred shares in the future, as the provisions governing such shares were established as a result of negotiation with the purchasers of such shares pursuant to the private placement.

Shareholder Rights Plan

On May 27, 2007, the Company 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 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.  The rights plan will expire on the date of our annual and special meeting of shareholders to be held in June 2010, unless our shareholders resolve to reconfirm or replace it at that meeting.

Options

InterOil has a stock incentive plan, authorised by our shareholders at the annual and special meeting held on June 19, 2009, that allows employees to acquire common shares of InterOil.  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 two years 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 granted under predecessor plans approved in 2004 and 2006 also remain in effect.  No further grants may now be made under these superseded plans.

As of December 31, 2009, there were options outstanding to purchase 1,838,500 common shares pursuant to our stock incentive plans.

Restricted Stock Awards

In addition to the options noted above, the InterOil Corporation 2009 Stock Incentive Plan also allows employees to acquire common shares of the Company pursuant to restricted stock units granted by InterOil. As of December 31, 2009, restricted stock units entitling employees rights to 41,400 common shares were outstanding pursuant to the stock incentive plan.  The restricted stock units provided those employees with the right to receive common shares on certain vesting dates.  Vesting dates occur in equal tranches during April 2010 and April 2011.

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 P.I.E. can exchange its remaining 5,000 shares in SPI InterOil LDC on a one-for-one basis for our common shares.  This election may be made by P.I.E. at any time.

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, 2009, rights to convert up to 527,147 common shares remained.

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MARKET FOR 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 Kina. Our common shares traded on the Toronto Stock Exchange (TSX) in Canadian dollars under the symbol IOL until the close of trade on January 27, 2009, at which time they were voluntarily de-listed from the TSX. Our common shares also traded on the NYSE Alternext Exchange (formerly the American Stock Exchange) in United States dollars under the symbol of IOC until March 31, 2009, at which time they were voluntarily de-listed from that exchange.  On the same day, our common shares began trading on the New York Stock Exchange (NYSE) in United States dollars and under the same symbol.    The following tables disclose the monthly high and low trading prices and volumes of our common shares as traded, during 2009:

Toronto Stock Exchange (TSL:IOL) in Canadian Dollars

Month	High		Low		Volume
January	$	25.99	$	17.85		2,411,400
Total						2,411,400

NYSE Alternext Exchange (NYSE Alternext:IOC) / New York Stock Exchange (NYSE:IOC) in United States Dollars

Month	High		Low		Volume
January	$	20.89	$	13.53		10,898,200
February	$	20.11	$	16.50		4,869,100
March	$	29.00	$	19.25		11,418,000
April	$	33.97	$	26.70		10,467,300
May	$	38.10	$	31.86		11,977,100
June	$	38.06	$	24.35		13,327,600
July	$	31.47	$	25.00		8,389,200
August	$	34.24	$	26.80		6,607,500
September	$	41.90	$	27.20		17,287,100
October	$	54.32	$	37.09		19,149,300
November	$	58.02	$	42.83		14,357,300
December	$	78.43	$	59.16		25,515,500
Total						154,290,400

Prior sales

· 231,750 common shares were issued during 2009 upon the exercise of stock options by employees at various prices defined by the option grant terms in accordance with relevant stock incentive plans.

· 499,834 common shares were issued pursuant to an agreement entered into whereby InterOil LNG Holdings Inc. and Pacific LNG Operations Limited, acquired Merrill Lynch’s interests in the Joint Venture Company (See “Material Contracts – Share Purchase and Sale and Settlement Agreement dated February 27, 2009”).  InterOil issued 652,931 common shares valued at $11.25 million for its share of the consideration payable to Merrill Lynch in relation to the settlement.  InterOil’s consideration was subject to a post closing balancing adjustment which resulted in the cancellation of 153,097 of the common shares originally issued.

· 70,548 common shares were issued to on May 11, 2009 at a deemed price of $33.34 as payment of a proportion of the second interest installment due to holders of our 8% convertible subordinate Debentures.

· During May and June of 2009, 3,159,000 common shares were issued to Debenture holders who elected or were mandatorily required to convert their Debentures into common shares.

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· 2,013,815 common shares were issued on June 8, 2009 on completion of a registered direct stock offering to a number of institutional investors at a purchase price of $34.98 per share, raising $70.4 million.

· 302,305 common shares were issued in August 2009 on the exercise of warrants at an exercise price of $21.91 per share.

· A total of 1,344,710 common shares were issued in two tranches in September and December 2009 at an average, calculated price of $46.84 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”).

DIRECTORS AND EXECUTIVE OFFICERS

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

Directors and Executive Officers

Name, Address	Position with InterOil	Date of Appointment
Phil E. Mulacek Texas, USA	Chairman and Chief Executive Officer	May 29, 1997
Christian Vinson Port Moresby, PNG	Vice President Corporate Development and Government Affairs, Director	May 29, 1997
Gaylen Byker Michigan, USA	Director(1) (4)	May 29, 1997
Roger Grundy Derbyshire, UK	Director (4)	May 29, 1997
Edward N. Speal New York, USA	Director(2) (4)	June 25, 2003
Roger F. Lewis Western Australia, Australia	Director(3)	November 26, 2008
William Jasper III Texas, USA	President and Chief Operating Officer	September 18, 2006
Collin Visaggio Western Australia, Australia	Chief Financial Officer	October 26, 2006
Mark Laurie South Australia, Australia	General Counsel and Corporate Secretary	June 12, 2007

Notes:

(1) Gaylen Byker acts as Chairman of each of the Board’s Audit Committee, Nominating and Corporate Governance Committee and Compensation Committee and has held such positions throughout 2009.

(2) Edward Speal is a member of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee, and has held such positions throughout 2009.

(3) Roger Lewis has held the position of Director and member of the Audit Committee, Nominating and Corporate Governance Committee and Compensation Committee from his date of appointment and throughout 2009.

(4) Messrs Grundy and Speal and Dr Byker are also members of the Board’s Reserves Committee.

(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 February 19, 2010, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly, 6,211,235 common shares, representing 14.25% 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, 1,225,000 shares are issuable upon exercise of outstanding options, resulting in directors and executive officers holding 16.18% of our issued common shares on a diluted basis.

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Our Board has established an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee.  Dr. Byker, Mr. Lewis and Mr. Speal are the members of each of these committees.  Dr. Byker is the Chairman of each committee.  In addition, the Board has established a Reserves Committee. Mr Speal is Chairman of this committee while Mr Grundy and Dr Byker are 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 Petroleum Independent Exploration Corporation, 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 where he was head of development, hedging and project finance for gas exploration and transportation projects offshore.  Prior to joining OEDC, he was co-head of commodity derivatives at Phibro Energy, Inc., a subsidiary of Salomon, Inc. and head of the commodity-indexed transactions group at Banque Paribas, New York, with worldwide responsibility for hedging and financing transactions utilizing long-term commodity price risk management.  Dr. Byker was manager of commodity-indexed swaps and financings for Chase Manhattan Investment Bank, New York, and was also a lawyer at Morgan, Lewis & Bockius in Philadelphia, Pennsylvania, U.S.

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

Edward N. Speal is based in New York and is the Regional Head of Global Structured Finance for the Americas for BNP Paribas.  He has had 25 years in the banking industry.  Previously, Mr. Speal was the President and CEO for BNP Paribas (Canada). Prior to that appointment, he was the Managing Director responsible for the Energy, Project Finance and Corporate Banking businesses for BNP Paribas in Canada.  Mr. Speal was the President and Chief Executive Officer of Paribas Bank of Canada from 1997 to 1999.  Mr. Speal worked in New York for Banque Paribas running its commodity index trading group from 1992 until 1996. From 1989 to 1991, he was Managing Director of R. P. Urfer & Co., working on an exclusive basis for Banque Paribas as Advisory Director assisting in the establishment and development of its global commodity derivatives business.  From 1983 to 1989, Mr. Speal worked for the Chase Manhattan Bank of Canada. Mr. Speal is a Canadian citizen and is a graduate of Queen's University at Kingston where he obtained a Bachelor of Commerce majoring in finance.

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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.

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 and Production, Offshore Gas 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.

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

Conflicts of Interest

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

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

Annual Information Form   INTEROIL CORPORATION   41

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.

· Mr. Speal occupies a senior position with BNP Paribas in New York.  This bank provides, through its Singapore office, certain credit facilities to finance the purchase of cargoes of crude oil and other petroleum products for InterOil’s refining activities, and to support its hedging positions. (See “Material Contracts – Secured Revolving Crude Import Facility”).  The bank is also acting for InterOil in an advisory capacity associated with the sale of a portion of our interest in the Elk and Antelope fields and in the LNG Project.

· Mr. Grundy is a principal of Breckland Limited, which entity 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 Dr. Gaylen Byker, Mr. Edward Speal and Mr. Roger Lewis.  All members held their positions throughout 2009.

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

Relevant Education and Experience

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

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

Pre-Approval Policies and Procedures

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

Annual Information Form   INTEROIL CORPORATION   42

External Auditor Service Fees

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

PricewaterhouseCoopers

	2009		2008
Audit Fees(1)	$	1,557,328	$	1,416,583
Audit-Related Fees(2)	$	35,144	$	170,404
Tax Fees(3)	$	557,693	$	473,493
All Other Fees(4)	$	47,718	$	39,192
Total	$	2,197,883	$	2,099,672

Notes:

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

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

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

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

The Company's Chief Executive Officer, Phil Mulacek, and his controlled entities Petroleum Independent & Exploration Corporation and P.I.E. Group, LLC, together with the Company and certain of its subsidiaries, are defendants in Todd Peters, et. al. v. Phil Mulacek et. al.; Cause No. 05-040-03592-CV; pending in the 284th District Court of Montgomery County, Texas.  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 the Company.  Plaintiffs contend that Mr. Mulacek and his controlled entities breached fiduciary duties owed to the plaintiffs and also assert claims for common law fraud, fraudulent inducement, statutory fraud, securities fraud, breach of contract, investor oppression, conversion, theft, money had and received, and tortious interference with a contract.   Plaintiffs assert claims both individually and, in the alternative, derivatively on behalf of the partnership.  Plaintiffs seek to impose liability on the Company and certain of its subsidiaries for those alleged acts through claims of ratification, conspiracy, aiding and abetting, joint enterprise, and knowing participation in the breach of another's fiduciary duty.  Plaintiffs further seek to impose liability on the Company and certain of its subsidiaries directly through the claims of conversion, theft, constructive trust and tortious interference with a contract.   In late July 2009, plaintiffs amended their petition adding sixteen new plaintiffs.   Plaintiffs have  proposed  numerous alternative methods of calculating their alleged damages,  all of which are based at least partially on the Company's share price which fluctuates over time .  Thus, it is difficult   to determine the total amount of actual damages plaintiffs' seek.  If, however, plaintiffs are successful in obtaining a favorable verdict,  actual  damages could exceed $125,000,000.  Plaintiffs also seek unspecified punitive damages, attorneys' fees, expenses and court costs.  The case is set for trial beginning in October 2010.  The Company and other defendants are vigorously contesting the matter.  If however, plaintiffs succeed in obtaining a judgment in the amount they seek, it could have a material adverse effect on the Company or its subsidiaries.

During 2008, certain disputes and litigation arose between us and MLPLC and companies affiliated to it relating to or arising from the LNG Project and PNG LNG Inc.  On February 27, 2009, a settlement agreement was entered into whereby the parties settled and agreed to release all of their outstanding claims against each other and dismissed the litigation with prejudice.  In addition, the parties granted mutual releases and entered into arrangements for the acquisition of Merrill Lynch’s interests in the Joint Venture Company and in the LNG Project by its other existing shareholders, InterOil LNG Holdings Inc and Pacific LNG Operations Ltd. (See “Material Contracts – Share Purchase and Sale and Settlement Agreement dated February 27, 2009”).

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In addition to the above, 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

During 2009, we renewed our $190.0 million revolving crude import credit facility with BNP Paribas through its Singapore office.  This facility is employed to finance the purchase of cargoes of crude oil and other petroleum products for our refinery, and to support its hedging positions. We also engaged BNP Paribas Capital in Singapore to help advise us in relation to the sale of a portion of our interest in the Elk and Antelope fields and in the LNG Project.  One of our directors, Mr Edward Speal, is the Regional Head of Global Structured Finance for the Americas for BNP Paribas based in New York.

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 $39,416 in respect of consulting fees and expenses during 2007. 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 is the direct or indirect beneficial owner of or who exercises control or direction over, more than 10% of the outstanding common shares, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will 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 2009:

Share Purchase and Sale and Settlement Agreement dated February 27, 2009

The Settlement Agreement effected the resolution and settlement of all disputes between each of InterOil, Merrill Lynch and  Pac LNG and their respective affiliates in connection with PNG LNG, the joint venture company established in 2007 by InterOil LNG Holdings Inc. ("InterOil Holdings"), an affiliate of InterOil, MLPLC, an affiliate of Merrill Lynch, and Pac LNG to construct the proposed LNG plant on a site adjacent to InterOil's refinery in Papua New Guinea.  The parties entered into a shareholders' agreement governing PNG LNG (the "LNG Project Shareholders Agreement" referred to below), which was considered to be a key milestone in furthering the proposal for the construction of the LNG plant.  In connection with the LNG Shareholders Agreement, PNG LNG issued two class "A" shares to InterOil Holdings, two class "A" shares to MLPLC and one class "A" share to Pac LNG.  PNG LNG also issued class "B" shares with a fair value of $100,000,000 to InterOil in recognition of its contribution to the LNG Project at the time of signing the LNG Shareholders Agreement and issued class “B” shares to MLPLC and Pac LNG.  The class "A" shares represent the voting rights in PNG LNG, while the class "B" shares represent the economic interest in the LNG project.

Pursuant to the Settlement Agreement, each of InterOil, Pac LNG and their affiliates released Merrill Lynch and its affiliates, and Merrill Lynch and its affiliates released InterOil, Pac LNG and their affiliates, from all current claims arising under the LNG Shareholders' Agreement and certain other agreements entered into in connection with PNG LNG and the development of the proposed LNG plant.

As part of the Settlement Agreement, MLPLC transferred all of its interest in PNG LNG to InterOil Holdings (as to 50%) and to Pac LNG (as to 50%) in exchange for: (i) a payment by InterOil to MLPLC of $11,250,000 paid through the issuance of the Registrable Securities and (ii) a payment by Pac LNG  to MLPLC of $11,250,000 paid through the transfer of 499,834 common shares of InterOil held by Pac LNG to MLPLC and cash in an amount of $1,000,000.  Upon closing of the Settlement Agreement on February 27, 2009, InterOil (through InterOil LNG) and Pac LNG became the sole shareholders of PNG LNG and Merrill Lynch and its affiliates no longer held any interest in PNG LNG or the proposed LNG project.

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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 was contingent upon Petromin’s nomination by the State as the entity designated to hold the State’s interest in accordance with PNG’s Oil & Gas Act and upon issuance of the PDL which nomination has now occurred. 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.

Amended and Restated Common Share Purchase Agreement dated June 10, 2008

We entered into the Amended and Restated Common Share Purchase Agreement with Pac LNG, Ltd on June 10, 2008.  This agreement amended and restated, and replaced, the Common Share Purchase Agreement of May 5, 2008. Under the Agreement, Pac LNG, an affiliate of Clarion Finanz A.G., and to whom Clarion had assigned its relevant rights and interests, agreed to convert the promissory notes issued to Clarion by InterOil in May 2006 totaling $60 million (being a portion of the $130 million secured credit bridging facility provided with Merrill Lynch Capital Corporation in May 2006) into 2,649,007 of InterOil’s common shares on the basis of a calculation yielding a deemed purchase price for the shares of $22.65 per share. An additional 79,470 common shares were issued as payment of a fee for the transaction at the same deemed issue price.

LNG Project Shareholders Agreement dated July 30, 2007

The shareholders’ agreement dated July 30, 2007 by and between InterOil LNG Holdings Corporation.  Merrill Lynch PNG LNG Corporation (“Merrill”) and Pacific LNG Operations Ltd (“PAC LNG”) (the “Shareholders”) provides for the establishment 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 parties’ economic interests in the Joint Venture Company and in the LNG Project.  The 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 retained no ongoing economic interest, legal rights or involvement in the LNG Project.  This shareholders agreement, while still in effect, must still be revised to respond to that change.

For updated information, see “General Development of the Business – Three Year History – Midstream – Liquefaction Segment” and “Legal Proceedings and Regulatory Actions”.

Secured Revolving Crude Import Facility renewed on September 16, 2009 and originally dated August 12, 2005

We, through our subsidiary E.P InterOil Limited, entered into a Secured Revolving Crude Import Facility Agreement with BNP Paribas, Singapore Branch on August 12, 2005 under which credit up to $150 million was made available to us for the purchase of crude oil supplies for our refinery  in exchange for payment of certain interest and fees.  The facility is secured against crude oil inventories held by us and subject to our continuing to meet certain covenants and conditions, and to annual review and renewal. In August 2006, the facility was increased to $170 million.  In August 2007, the facility and agreement was again renewed at the same level.  In 2008, the overall facility limit was increased temporarily to $210 million and, on November 30, 2008, was reduced to $190 million to accommodate higher crude prices and resulting increases in working capital requirements.  On September 16, 2009, the facility was renewed until December 31, 2010 with a facility limit of $190.0 million.

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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 PPLs 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 InterOil to pay from the joint account all commissions and other expenses incurred in connection with structuring this Agreement, soliciting investors and otherwise entering into the 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 a proportionate amount of drilling costs related to these wells.

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 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.  Pursuant to an amendment entered into on February 14, 2008, certain principal payments, originally due during 2007, were deferred so that they are now due on June 30 and December 31, 2015, respectively. These deferred payments were subject to a requirement that if we undertook a capital raising of a certain magnitude, sold all or part of the refinery or if the net income of the refinery reached a certain level, these deferred payments would be payable to OPIC. On June 1, 2009, OPIC agreed to waive those restrictions and the schedule of payments was amended to reflect this such that the principal payment will not be due until 2015.   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 2009, the weighted average interest rate of all disbursements pursuant to this loan agreement was 6.89%.  During the year ended December 31, 2009, two installments of $4.5 million and the accrued interest on the loan were paid.

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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 2009 were done so in the ordinary course of our business or were not material to us.

TRANSFER AGENT AND REGISTRAR

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

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.

100 University Avenue, 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

Annual Information Form   INTEROIL CORPORATION   47

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, 2009.  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.

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 for our upcoming annual meeting of shareholders expected to be held in June 2010.  Additional financial information is provided in our audited consolidated financial statements for the year ended December 31, 2009 and related 2009 MD&A.  Our audited financial statements, 2009 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 financial statements, 2009 MD & A and any additional copies of this AIF may also be obtained by contacting Mr Anesti Dermedgoglou, Vice President of Investor Relations at Level 1, 60-92 Cook Street, Portsmith, Queensland 4870, Australia; Telephone:  +61 (7) 4046-4600.

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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, 2009.

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 1, 2010.

"Phil E. Mulacek"	"Roger Grundy"
Phil E. Mulacek Chief Executive Officer	Roger Grundy Director
"Collin F. Visaggio"	"Edward Speal"
Collin F. Visaggio Chief Financial Officer	Edward Speal Director

Annual Information Form   INTEROIL CORPORATION   49

FORM 51-101F2

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, 2009. The resources data are estimates of low, best and high estimates of contingent resources as at December 31, 2009.

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, 2009:

Independent Qualified Reserves	Description and Preparation Date of Assessment	Location of Reserves (Country or Foreign Geographic	Company Gross Contingent Resources MMBOE
Evaluator	Report	Area)	Low		Best		High
GLJ Petroleum Consultants	February 16, 2010	Papua New Guinea		660.6		873.2		1063.6

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 judgements 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, February 19, 2010

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 relating to the Company’s corporate accounting and financial reporting processes and the audits of the Company’s financial statements.  In fulfilling this function, the Committee’s primary duties and responsibilities are to:

· Serve as an independent and objective party to oversee the integrity of the Company’s financial statements and to monitor the Company’s financial reporting process and systems of internal controls regarding financial, accounting, and legal compliance.

· Monitor the qualifications, independence and performance of the Company’s independent auditors and the performance of the Company’s internal auditing function.

· Provide an avenue of communication between the Board and the independent auditors, management and the internal auditor.

· Report actions of the Committee to the Board with such recommendations as the Committee may deem appropriate.

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 independent 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.

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 meet the independence, or an applicable exception, financial literacy, and experience requirements of the NYSE rules and applicable Canadian and 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 financially sophisticated, as determined by the Board, for purposes of applicable NYSE rules.

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

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

Annual Information Form   INTEROIL CORPORATION   52

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.  When necessary, the Committee will meet in executive session outside the presence of any senior executive officer of the Company.  The Committee and any other independent members of the Board that are not members of the Committee will meet in executive session, without the presence of non-independent directors and management at least once annually.

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 may meet privately with management, the chief executive officer ("CEO"), the general counsel, the internal auditor, the independent auditors, and as a Committee to discuss any matters that the Committee or each of these groups believe should be discussed privately.

4. General Review Procedures.

4.1. Annual Report Review.  The Committee shall review with management, the independent auditors, and the internal auditors, the Company’s year-end financial results prior to the release of earnings 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 independent auditors and the internal auditors any significant issues or findings or any changes to the Company’s accounting principles, any items required to be communicated by the independent auditors in accordance with Statement on Auditing Standards No. 61, as amended, 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 independent auditors.  The Committee shall approve the audited financial statements and recommend to the Board whether or not the audited financial statements should be filed on SEDAR and included in the Company’s Annual Report on Form 40-F for the last fiscal year.

4.2. Quarterly Report Review.  The Committee shall review with management, the internal auditors, and the independent auditors (if the independent auditors were involved in a review of such financial statements), (i) the Company’s interim financial results prior to the release of earnings, the Company’s 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 and (ii) the operation of the Company’s internal controls and any special steps adopted in light of material control deficiencies.  The Committee shall discuss with management, the internal auditors and the independent auditors (if required by GAAP, NYSE rules, or applicable Canadian and U.S. federal securities laws), any significant findings or any changes to the Company’s accounting principles and any items required to be communicated by the independent auditors in accordance with Statement on Auditing Standards No. 61 as amended.

Annual Information Form   INTEROIL CORPORATION   53

4.3. Canadian and SEC Filings Review.  The Committee shall review with financial management and the independent auditor (if the independent auditors were involved in a review of such financial statements) 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 independent 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 independent auditors and the internal auditors together with management’s responses, including the status of previous recommendations.

4.5. Non-GAAP Financial Data Review.  The Committee shall review and discuss with management earnings including the use of “pro forma,” “adjusted” or other non-GAAP information, financial guidance and other press releases of a material financial nature, as well as financial information and earnings 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 independent 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 independent 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 employee or former employee of the independent 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 Form 40-F concerning significant deficiencies or material weaknesses in internal controls and any fraud.

4.12. Legal Counsel Review.  On at least an annual basis, the Committee shall review with the Company’s legal 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. Independent Auditors.

Auditor Performance Review.  The Committee shall confirm with the independent auditors their ultimate accountability to the Committee.  The independent auditors will report directly to the Committee.  The Committee will ensure that the independent auditors are aware that the Chairperson of the Committee is to be contacted directly by the independent 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 independent auditor team.

Annual Information Form   INTEROIL CORPORATION   54

Approval of Independent Auditor and Pre-Approval of Services.  The Committee shall be directly responsible for the appointment, compensation, retention, termination, and oversight of the work of the independent 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 to be performed by the independent 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 which are approved by the Audit Committee prior to the completion of the audit.  The Committee shall periodically discuss current year non-audit services performed by the independent auditors and review and pre-approve all permitted non-audit service engagements.

Auditor Independence.  The Committee shall oversee the independence of the independent auditors by, among other things, (i) on an annual basis, receiving from the independent auditors a formal written statement delineating all relationships between the independent auditors and the Company, consistent with Independence Standards Board Standard No. 1, that could impair the auditors’ independence; (ii) actively engaging in a dialogue with the independent auditors with respect to any disclosed relationships or services that may impact the objectivity and independence of the independent auditors; and (iii) taking, or recommending to the Board the appropriate action to be taken, in response to the independent auditors’ report to satisfy itself of the independent auditors’ independence.

Auditor Report.  The Committee shall annually obtain from the independent auditor and review a written report describing (i) the independent auditor’s internal quality-control procedures; and (ii) any material issues raised by (a) the independent 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 independent 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 independent 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 for the Company in each of the Company’s five previous fiscal years.

Internal Controls Report.  Beginning in fiscal year 2006 or earlier if required by applicable accounting rules or Canadian and U.S. federal securities laws, the Committee shall annually obtain from the independent auditor a written report in which the independent auditor attests to and reports on the assessment of the Company’s internal controls made by the Company’s management.  The Committee shall review and discuss with management, the independent auditor, and the Company’s independent auditor (i) the adequacy and effectiveness of the Company’s internal controls (including any significant deficiencies and significant changes in internal controls reported to the Committee by the independent auditor or management; (ii) the Company’s internal audit procedures; and (iii) the adequacy and effectiveness of the Company’s disclosures controls and procedures, and management reports thereon.

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

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

Annual Information Form   INTEROIL CORPORATION   55

Accounting Principles.  The Committee shall consider the independent 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 alternatives discussed with management (including the ramifications and the auditor’s preferred treatment) and any other material written communications between the independent auditor and management.

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

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

Related Party Transactions.  The Committee shall approve all related party transactions after a review of the transactions by the Committee for potential conflicts of interest and 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.

Use of Assets.  The Committee shall review Company policies and procedures with respect to executive officers’ expense accounts and prerequisites, including their use of corporate assets, and consider the results of any review of these areas by the internal auditors or the independent accountant.

Annual Information Form   INTEROIL CORPORATION   56

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 independent 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 regularly make a self-assessment of its performance, which shall include eliciting input from management, the Board and the General Counsel on the performance of the Committee.

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 independent auditor to plan or conduct audits or to determine that the Company’s financial statements are complete and accurate in accordance with GAAP.

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

Annual Information Form   INTEROIL CORPORATION   57

EX-99.2

InterOil Corporation Consolidated Financial Statements (Expressed in United States dollars)   Years ended December 31, 2009, 2008 and 2007

InterOil Corporation Consolidated Financial Statements (Expressed in United States dollars)

Table of contents
Management’s Report	1
Auditor’s Report to the Shareholders	2
Consolidated Balance Sheets	4
Consolidated Statements of Operations	5
Consolidated Statements of Cash Flows	6
Consolidated Statements of Shareholders’ Equity	7
Consolidated Statements of Comprehensive Income	8
Notes to the Consolidated Financial Statements	9
Reconciliation to accounting principles generally accepted in the United States	46

InterOil Corporation Consolidated Financial Statements (Expressed in United States dollars)

MANAGEMENT’S REPORT

The management of InterOil Corporation is responsible for the financial information and operating data presented in this Annual Report.

The consolidated financial statements have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles.  When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances.  Financial statements are not precise as they include certain amounts based on estimates and judgments.  Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects.  Financial information presented elsewhere in this Annual Report has been prepared on a basis consistent with that in the consolidated financial statements.

InterOil Corporation maintains systems of internal accounting and administrative controls.  These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded.

The Audit Committee, appointed by the Board of Directors, is composed of independent non-management directors.  The Committee meets regularly with management, as well as the external auditors, to discuss auditing, internal controls, accounting policy and financial reporting matters.  The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board.

The 2009 consolidated financial statements have been audited by PricewaterhouseCoopers, the independent auditors, in accordance with Canadian generally accepted auditing standards and auditing standards issued by the Public Company Accounting Oversight Board, on behalf of the shareholders.  PricewaterhouseCoopers has full and free access to the Audit Committee.

Phil Mulacek	Collin Visaggio
Chief Executive Officer	Chief Financial Officer

Consolidated Financial Statements   INTEROIL CORPORATION     1

INDEPENDENT AUDIT REPORT TO THE SHAREHOLDERS OF INTEROIL CORPORATION

Independent Auditors’ Report

To the Shareholders of InterOil Corporation:

We have completed integrated audits of InterOil Corporation’s 2009, 2008 and 2007 consolidated financial statements and of its internal control over financial reporting as at December 31, 2009.  Our opinions, based on our audits, are presented below.

Consolidated Financial statements

We have audited the accompanying consolidated balance sheets of InterOil Corporation as at December 31, 2009, 2008 and 2007, and the related consolidated statements of operations, comprehensive income, shareholders equity and cash flows for each of the years in the three year period ended December 31, 2009.  These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of the Company’s financial statements as at December 31, 2009 and for each of the years in the three year period then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as at December 31, 2009, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2009 in accordance with Canadian generally accepted accounting principles.

Internal control over financial reporting

We have also audited InterOil Corporation’s internal control over financial reporting as at December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

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 in accordance with generally accepted accounting principles.  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 generally accepted accounting principles, 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.

Consolidated Financial Statements   INTEROIL CORPORATION     2

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2009 based on criteria established in Internal Control — Integrated Framework issued by the COSO.

/s/ PricewaterhouseCoopers

PricewaterhouseCoopers

Melbourne, Australia

March 1, 2010

Consolidated Financial Statements   INTEROIL CORPORATION     3

InterOil Corporation Consolidated Balance Sheets (Expressed in United States dollars)

	As at
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Assets
Current assets:
Cash and cash equivalents (note 5)		46,449,819			48,970,572			43,861,762
Cash restricted (note 7)		22,698,829			25,994,258			22,002,302
Trade receivables (note 8)		61,194,136			42,887,823			63,145,444
Commodity derivative contracts (note 7)		-			31,335,050			-
Other assets		639,646			167,885			146,992
Inventories (note 9)		70,127,049			83,037,326			82,589,242
Prepaid expenses		6,964,950			4,489,574			5,102,540
Total current assets		208,074,429			236,882,488			216,848,282
Cash restricted (note 7)		6,609,746			290,782			382,058
Goodwill (note 15)		6,626,317			-			-
Plant and equipment (note 10)		221,046,709			223,585,559			232,852,222
Oil and gas properties (note 11)		172,483,562			128,013,959			84,865,127
Future income tax benefit (note 12)		16,912,969			3,070,182			2,867,312
Total assets		631,753,732			591,842,970			537,815,001
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued liabilities (note 13)		59,372,354			78,147,736			60,427,607
Commodity derivative contracts (note 7)		-			-			1,960,300
Working capital facility (note 16)		24,626,419			68,792,402			66,501,372
Current portion of secured loan (note 19)		9,000,000			9,000,000			136,776,760
Current portion of indirect participation interest - PNGDV (note 20)		540,002			540,002			1,080,004
Total current liabilities		93,538,775			156,480,140			266,746,043
Secured loan (note 19)		43,589,278			52,365,333			61,141,389
8% subordinated debenture liability (note 24)		-			65,040,067			-
Preference share liability (note 23)		-			-			7,797,312
Deferred gain on contributions to LNG project (note 14)		13,076,272			17,497,110			9,096,537
Indirect participation interest (note 20)		38,715,228			72,476,668			96,086,369
Indirect participation interest - PNGDV (note 20)		844,490			844,490			844,490
Total liabilities		189,764,043			364,703,808			441,712,140
Non-controlling interest (note 21)		13,596			5,235			4,292
Shareholders' equity:
Share capital (note 22)
Authorised - unlimited
Issued and outstanding - 43,545,654
(Dec 31, 2008 - 35,923,692)
(Dec 31, 2007 - 31,026,356)		613,361,363			373,904,356			259,324,133
Preference shares (note 23)
(Authorised - 1,035,554, issued and outstanding - nil)		-			-			6,842,688
8% subordinated debentures (note 24)		-			10,837,394			-
Contributed surplus		21,297,177			15,621,767			10,337,548
Warrants (note 26)		-			2,119,034			2,119,034
Accumulated Other Comprehensive Income		8,150,976			27,698,306			6,025,019
Conversion options (note 20)		13,270,880			17,140,000			19,840,000
Accumulated deficit		(214,104,303	)		(220,186,930	)		(208,389,853	)
Total shareholders' equity		441,976,093			227,133,927			96,098,569
Total liabilities and shareholders' equity		631,753,732			591,842,970			537,815,001

See accompanying notes to the consolidated financial statements. Commitments and contingencies (note 28), Going Concern (note 2(b))

On behalf of the Board - Phil Mulacek, Director    Christian Vinson, Director

Consolidated Financial Statements   INTEROIL CORPORATION     4

InterOil Corporation Consolidated Statement of Operations (Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Revenue
Sales and operating revenues		688,478,965			915,578,709			625,526,068
Interest		350,629			931,785			2,180,285
Other		4,228,415			3,216,445			2,666,890
		693,058,009			919,726,939			630,373,243
Expenses
Cost of sales and operating expenses		601,983,432			888,623,109			573,609,441
Administrative and general expenses		33,254,708			31,227,627			31,998,655
Derivative (gains)/losses		(1,008,585	)		(24,038,550	)		7,271,693
Legal and professional fees		9,067,413			11,523,045			6,532,646
Exploration costs, excluding exploration impairment (note 11)		208,694			995,532			13,305,437
Exploration impairment (note 11)		-			107,788			1,242,606
Short term borrowing costs		3,776,590			6,514,060			5,565,828
Long term borrowing costs		8,788,041			17,459,186			17,182,446
Depreciation and amortization		14,321,775			14,142,546			13,024,258
Gain on LNG shareholder agreement (note 19)		-			-			(6,553,080	)
Gain on sale of oil and gas properties (note 11)		(7,364,468	)		(11,235,084	)		-
Loss on extinguishment of IPI liability (note 20)		31,710,027			-			-
Foreign exchange loss/(gain)		3,305,383			(3,878,150	)		(5,078,338	)
		698,043,010			931,441,109			658,101,592
Loss before income taxes and non-controlling interest		(4,985,001	)		(11,714,170	)		(27,728,349	)
Income taxes
Current		(2,272,645	)		(1,564,038	)		(2,491,761	)
Future		13,348,634			1,482,074			1,284,869
		11,075,989			(81,964	)		(1,206,892	)
Income/(loss) before non-controlling interest		6,090,988			(11,796,134	)		(28,935,241	)
Non-controlling interest (note 21)		(8,361	)		(943	)		22,333
Net income/(loss)		6,082,627			(11,797,077	)		(28,912,908	)
Basic income/(loss) per share (note 27)		0.15			(0.35	)		(0.96	)
Diluted income/(loss) per share (note 27)		0.15			(0.35	)		(0.96	)
Weighted average number of common shares outstanding
Basic (Expressed in number of common shares)		39,900,583			33,632,390			29,998,133
Diluted (Expressed in number of common shares)		40,681,586			33,632,390			29,998,133

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements   INTEROIL CORPORATION     5

InterOil Corporation Consolidated Statement of Cash Flows (Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Cash flows provided by (used in):
Operating activities
Net profit/(loss)		6,082,627			(11,797,077	)		(28,912,908	)
Adjustments for non-cash and non-operating transactions
Non-controlling interest		8,361			943			(22,333	)
Depreciation and amortization		14,321,775			14,142,546			13,024,258
Future income tax asset		(13,842,787	)		(202,870	)		(1,600,985	)
Fair value adjustment on IPL PNG Ltd. acquisition		-			-			(367,935	)
(Gain)/loss on sale of plant and equipment		-			(16,250	)		269,321
Gain on sale of exploration assets		(7,364,468	)		(11,235,084	)		-
Impairment of plant and equipment		-			-			960,000
Amortization of discount on debentures liability		1,212,262			1,915,910			-
Amortization of deferred financing costs		223,945			260,400			421,691
(Gain)/loss on unsettled hedge contracts		(851,500	)		851,500			(47,314	)
Timing difference between derivatives recognised
and settled		15,074,050			(17,034,350	)		3,765,800
Stock compensation expense		8,290,681			5,741,086			6,062,962
Inventory revaluation		140,278			8,379,587			-
Non-cash interest on secured loan facility		-			2,189,907			6,143,660
Non-cash interest settlement on preference shares		-			372,950			-
Non-cash interest settlement on debentures		2,352,084			2,620,628			-
Oil and gas properties expensed		208,694			1,103,320			14,548,043
Loss on extinguishment of IPI Liability		31,710,027			-			-
Gain on LNG shareholder agreement		-			-			(6,553,080	)
Preference share transaction costs		-			-			390,000
Gain on buy back of minority interest		-			-			(394,290	)
Loss/(gain) on proportionate consolidation of LNG project		724,357			(811,765	)		2,375,278
Unrealized foreign exchange gain		(574,778	)		(3,728,721	)		(5,078,338	)
Change in operating working capital
(Increase)/decrease in trade receivables		(9,523,370	)		18,684,422			6,661,838
(Decrease)/increase in unrealised hedge gains		(900,000	)		900,000			-
(Increase)/decrease in other assets and prepaid expenses		(2,947,137	)		592,073			(2,698,546	)
Decrease/(increase) in inventories		12,226,616			(3,189,859	)		(6,033,038	)
(Decrease)/increase in accounts payable, accrued liabilities and income tax payable		(12,071,350	)		5,846,860			(34,533,991	)
Net cash from/(used in) operating activities		44,500,367			15,586,156			(31,619,907	)
Investing activities
Expenditure on oil and gas properties		(91,788,438	)		(63,890,512	)		(69,090,092	)
Proceeds from IPI cash calls		15,406,022			18,323,365			21,782,988
Expenditure on plant and equipment		(11,782,925	)		(5,172,133	)		(7,289,319	)
Proceeds received on sale of assets		-			312,500			65,072
Proceeds received on sale of exploration assets		-			6,500,000			-
Acquisition of subsidiary		-			-			(3,326,631	)
Proceeds from insurance claim		-			-			7,000,000
Increase in restricted cash held as security on
borrowings		(3,023,535	)		(3,900,680	)		10,134,864
Change in non-cash working capital
Increase in accounts payable and accrued liabilities		5,621,530			436,775			6,353,247
Net cash used in investing activities		(85,567,346	)		(47,390,685	)		(34,369,871	)
Financing activities
Repayments of secured loan		(9,000,000	)		(9,000,000	)		(4,500,000	)
Repayments of bridging facility, net of transaction costs		-			(70,000,000	)		-
Financing fees related to bridging facility		-			-			(100,000	)
Proceeds from PNG LNG cash call		-			9,447,250			9,450,308
Payments for deferred financing fees		-			-			(362,500	)
Proceeds from Clarion Finanz for Elk option agreement		3,577,288			5,500,000			5,922,712
Proceeds from Petromin for Elk participation agreement		6,435,000			4,000,000			-
(Repayments of)/proceeds from working capital facility		(44,165,983	)		2,291,030			29,627,864
Proceeds from issue of common shares/conversion of debt,
exercise of warrants, net of transaction costs		81,699,921			(104,975	)		23,881,721
Proceeds from issue of debentures, net of transaction costs		-			94,780,034			-
Proceeds from preference shares, net of transaction costs		-			-			14,250,000
Net cash from financing activities		38,546,226			36,913,339			78,170,105
(Decrease)/increase in cash and cash equivalents		(2,520,753	)		5,108,810			12,180,327
Cash and cash equivalents, beginning of period		48,970,572			43,861,762			31,681,435
Cash and cash equivalents, end of period (note 5)		46,449,819			48,970,572			43,861,762

See accompanying notes to the consolidated financial statements

See note 6 for non cash financing and investing activities

Consolidated Financial Statements   INTEROIL CORPORATION     6

InterOil Corporation Consolidated Statements of Shareholders' Equity (Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Share capital
At beginning of period		373,904,356			259,324,133			233,889,366
Issue of capital stock (note 22)		239,457,007			114,580,223			25,434,767
At end of period		613,361,363			373,904,356			259,324,133
Preference shares
At beginning of period		-			6,842,688			-
Issue of preference shares  (note 23)		-			-			6,842,688
Converted to common shares (note 23)		-			(6,842,688	)		-
At end of period		-			-			6,842,688
8% subordinated debentures
At beginning of period		10,837,394			-			-
Issue of debentures (note 24)		-			13,036,434			-
Conversion to common shares during the year (note 24)		(10,837,394	)		(2,199,040	)		-
At end of period		-			10,837,394			-
Contributed surplus
At beginning of period		15,621,767			10,337,548			4,377,426
Fair value of options exercised transferred to share capital (note 25)		(2,185,642	)		(456,867	)		(102,840	)
Stock compensation expense (note 25)		8,290,681			5,741,086			6,062,962
Loss on extinguishment of IPI conversion options (note 20)		(649,187	)		-			-
Lapsed warrants transferred to contributed surplus		219,558
At end of period		21,297,177			15,621,767			10,337,548
Warrants
At beginning of period		2,119,034			2,119,034			2,137,852
Conversion to common shares (note 26)		(1,899,476	)		-			(18,818	)
Lapsed warrants transferred to contributed surplus		(219,558	)
At end of period		-			2,119,034			2,119,034
Accumulated Other Comprehensive Income
Deferred hedge gain/(loss)
At beginning of period		18,012,500			-			-
Deferred hedge gain recognised on transition		-			-			1,385
Deferred hedge movement for the year, net of tax (note 7)		(18,012,500	)		18,012,500			(1,385	)
Deferred hedge gain/(loss) at end of period		-			18,012,500			-
Foreign currency translation reserve
At beginning of period		9,685,806			6,025,019			1,492,869
Foreign currency translation movement for the year, net of tax		(1,534,830	)		3,660,787			4,532,150
Foreign currency translation reserve at end of period		8,150,976			9,685,806			6,025,019
Accumulated other comprehensive income at end of period		8,150,976			27,698,306			6,025,019
Conversion options
At beginning of period		17,140,000			19,840,000			20,000,000
Movement for the year (note 20)		(3,869,120	)		(2,700,000	)		(160,000	)
At end of period		13,270,880			17,140,000			19,840,000
Accumulated deficit
At beginning of period		(220,186,930	)		(208,389,853	)		(179,476,945	)
Net income/(loss) for the year		6,082,627			(11,797,077	)		(28,912,908	)
At end of period		(214,104,303	)		(220,186,930	)		(208,389,853	)
Shareholders' equity at end of period		441,976,093			227,133,927			96,098,569

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements   INTEROIL CORPORATION     7

InterOil Corporation Consolidated Statements of Comprehensive Income (Expressed in United States dollars)

	Year ended
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Net income/(loss) as per Statement of Operations		6,082,627			(11,797,077	)		(28,912,908	)
Other comprehensive (loss)/income, net of tax		(19,547,330	)		21,673,287			4,530,765
Comprehensive (loss)/income		(13,464,703	)		9,876,210			(24,382,143	)

See accompanying notes to the consolidated financial statements

Consolidated Financial Statements   INTEROIL CORPORATION     8

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

1. Nature of operations and organization

InterOil Corporation (the "Company" or "InterOil") is a publicly traded, integrated oil and gas company operating in Papua New Guinea (“PNG”).

Management has organized the Company’s operations into four major segments - Upstream, Midstream, Downstream and Corporate.  Upstream includes Exploration and Production operations for crude oil and natural gas in PNG. Midstream consists of both Midstream Refining and Midstream Liquefaction.  Midstream Refining includes refining of products for domestic market in Papua New Guinea and exports, and Midstream Liquefaction includes the work being undertaken to further the Liquefied Natural Gas facility (”LNG project”) in PNG.  Downstream includes Wholesale and Retail Distribution of refined products in PNG.  Corporate engages in business development and improvement, common services and management, financing and treasury, government and investor relations.  Common and integrated costs are recovered from business segments on an equitable driver basis.

2. Significant accounting policies

The principal accounting policies adopted in the preparation of the financial report are set out below.  These policies have been consistently applied for all years presented, unless otherwise stated.

(a)  Basis of preparation

These financial statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”) applicable to a going concern, which, in the case of the Company, differ in certain respects from those in the United States.  These differences are described in note 30 - Reconciliation to Generally Accepted Accounting Principles in the United States.

The consolidated financial statements for the year ended December 31, 2009 are in accordance with Canadian GAAP which requires the use of certain critical accounting estimates.  It also requires management to exercise its judgment in the process of applying Company’s accounting policies.  These estimates and judgments may affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period.  Actual results could differ from these estimates. The effect of changes in estimates on future periods have not been disclosed in these consolidated financial statements as estimating it is impracticable.

Rate Regulation

InterOil is currently the sole refiner of hydrocarbons in Papua New Guinea under our 30 year agreement with the Papua New Guinea Government, which expires in 2035.  The government has undertaken to ensure that all domestic distributors purchase their refined petroleum products from our refinery, or any other refinery which is constructed in Papua New Guinea, at an Import Parity Price (”IPP”).  The IPP is regulated by the Papua New Guinea Independent Consumer and Competition Commission (”ICCC”).  In general, the IPP is the price that would be paid in Papua New Guinea for a refined product being imported.  For all price controlled products (diesel, unleaded petrol, kerosene and aviation fuel) produced and sold locally in Papua New Guinea, the IPP is calculated by adding the costs that would typically be incurred to import such product to the posted price for such product in Singapore.  In November 2007, the IPP was modified by changing the Singapore benchmark price from the ‘Singapore Posted Prices’ which is no longer being updated, to ‘Mean of Platts Singapore’ (“MOPS”) which is the 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 the Company’s relationship with the Independent State of Papua New Guinea, however, it is the current IPP calculation mechanism being regulated by the ICCC.

InterOil is also a significant participant in the retail and wholesale distribution business in Papua New Guinea.  The ICCC regulates the maximum prices that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea.  The 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.  In June 2009, the ICCC commenced a review into the pricing arrangements for petroleum products in Papua New Guinea.  The last such review was undertaken during 2004 and was due to expire on December 31, 2009. The purpose of the review is 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. We have provided detailed submissions to the ICCC.  The ICCC have most recently advised that its final report will be issued in March 2010.  It is possible that the ICCC may determine to increase regulation of pricing and reduce the margins able to be obtained by our distribution business.  Such a decision, if made, may negatively affect our downstream business and require a review of its operations.

No rate regulated assets or liabilities have been recognized as any gains or losses made due to rate regulation are to the Company’s account, and are not repayable/recoverable in the future.

Consolidated Financial Statements   INTEROIL CORPORATION     9

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

(b) Going concern

These consolidated financial statements have been prepared using Canadian GAAP applicable to a going concern, which contemplates the realization of assets and settlement of liabilities in the normal course of business as they become due.

For the year ended December 31, 2009, the Company reported a profit of $6.1 million as compared to a loss of $11.8 million for the same period of 2008.  The total operating cash inflow was $44.5 million for the year compared to $15.6 million in 2008.  The Company reported a net operating cash inflow, before working capital movements, of $57.7 million for the year compared to an outflow of $7.2 million during 2008.  The net current assets for the year ended December 31, 2009 was $114.5 million compared to $80.4 million in 2008.

The Company has cash, cash equivalents and cash restricted of $75.8 million as at December 31, 2009 (December 2008 - $75.3 million), of which $29.3 million is restricted (December 2008 - $26.3 million).

The Company has a short term total working capital facility of $190.0 million for its Midstream – Refining operation that is renewable annually with BNP Paribas.  The working capital facility is split between Facility 1 and Facility 2, with their respective sub-limits and restricted usage for each of these components (refer to note 16 for further information on the split between the two facilities).  As part of the current year renewal process which was completed in the quarter ended December 31, 2009, the facility was renewed for a period of fifteen months ending December 31, 2010.  This facility is secured by the assets it is drawn down against.  As at December 31, 2009 $73.5 million of the combined facility has been utilized, and the remaining facility of $116.5 million remains available for use.

The Company has an approximately $48.1 million (Papua New Guinea Kina 130.0 million) revolving working capital facility for its Downstream operations in Papua New Guinea from Bank of South Pacific Limited and Westpac Bank PNG Limited. Westpac facility limit is approximately $29.6 million (Papua New Guinea Kina 80.0 million) and the initial BSP facility limit was approximately $25.9 million (Papua New Guinea Kina 70.0 million) but was renewed in October 2009 at a lower limit of approximately $18.5 million (Papua New Guinea Kina 50.0 million).  The Westpac facility is for an initial term of three years and is due for renewal in October 2011. The BSP facility is renewable annually and is due for renewal in October 2010.  As at December 31, 2009 only $7.8 million of this combined facility has been utilized, and the remaining facility of approximately $40.3 million (Papua New Guinea Kina 108.9 million) remains available for use.  Management expects these facilities to be renewed in due course as these working capital facilities are fully secured against trade debtors, inventory and cash deposits.

With respect to its Upstream operations, the Company has no obligation to execute exploration activities within a set timeframe and therefore has the ability to select the timing of these activities as long as the minimum license commitments in relation to our Petroleum Prospecting Licenses (“PPL”) are met.

The Company believes that it has sufficient funds for the Midstream Refinery and Downstream operations; however, existing cash balances and ongoing cash generated from these operations will not be sufficient to facilitate further development of the Elk and Antelope fields, condensate stripping plant development, and the liquefaction plant development.  Therefore the Company must extend or secure sufficient funding through renewed borrowings, equity raising and or asset sales to enable sufficient cash to be available to further its development plans.  Management expects that the Company will be able to secure the necessary financing through one of, or a combination or the aforementioned alternatives.  Accordingly, these financial statements have been prepared on a going concern basis in the belief that the Company will realize its assets and settle its liabilities and commitments in the normal course of business and for at least the amounts stated.

(c) Principles of consolidation

Subsidiaries

The consolidated financial statements of the Company incorporates the assets, liabilities and results of InterOil Corporation and of all subsidiaries as at December 31, 2009, December 31, 2008, December 31, 2007 and for the years then ended.  Subsidiaries of InterOil Corporation as at December 31, 2009 included SP InterOil LDC (99.9%), SPI Exploration and Production Corporation (100% - one share held by PIE Corp), SPI Distribution Limited (100% - one share held by PIE Corp), InterOil LNG Holdings Inc. (100%), InterOil Australia Pty Ltd (100%), SPI InterOil Holdings Limited (100%), Direct Employment Services Company (100%), InterOil New York Inc. (100%), InterOil Singapore Pte Ltd (100%), InterOil Finance Inc. (100%) and their subsidiaries.  InterOil Corporation and its subsidiaries together are referred to in these financial statements as the Company or the consolidated entity.

Consolidated Financial Statements   INTEROIL CORPORATION     10

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

Subsidiaries are all those entities over which the Company has the right and ability to obtain future economic benefits from the resources of the enterprise and is exposed to the related risks.  Control of an enterprise is the continuing power to determine strategic operating, investing and financing policies without the cooperation of others.  The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Company controls another entity.  Subsidiaries are fully consolidated from the date on which control is transferred to the Company.  They are de-consolidated from the date that control ceases.

The purchase method of accounting is used to account for the acquisition of subsidiaries by the Company, refer to note 2(j).  Intercompany transactions, balances and unrealized gains on transactions between companies are eliminated on consolidation.  Minority interest in the results and equity of subsidiaries are shown separately in the consolidated statements of operations and balance sheets.

In June 2007, InterOil LNG Holdings Inc. was incorporated as a holding company of InterOil’s investment in PNG LNG Inc., (a Bahamas incorporated entity set up to construct and operate an LNG Project in Papua New Guinea).  InterOil LNG Holdings Inc. is a 100% subsidiary of InterOil Corporation.  During July 2007, the investment in PNG LNG Inc. was transferred from InterOil Corporation to InterOil LNG Holdings Inc.  Refer to the section ‘Proportionate consolidation of Joint Venture interests’ below for the changes to InterOil’s shareholding in PNG LNG Inc. (”Joint Venture Company”) due to the signing of the Shareholders’ Agreement in July 2007.

In April 2008, InterOil New York Inc. was incorporated as a 100% subsidiary of InterOil Corporation to evaluate potential financing arrangements in the U.S.

In May 2009, InterOil Singapore Pte Ltd. was incorporated as a 100% subsidiary of InterOil Corporation to facilitate the development and operation of the LNG Project in Papua New Guinea.  All costs incurred by this entity will be recharged to the LNG joint venture and relevant InterOil entities based on an equitable driver basis.

In December 2009, InterOil Finance Inc. was incorporated in Barbados as a 100% subsidiary of InterOil Corporation to provide financial services to the other group entities.

Proportionate consolidation of Joint Venture interests

On July 30, 2007, a Shareholders’ Agreement was signed between InterOil LNG Holdings Inc., Pacific LNG Operations Ltd., Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc..  Further shareholder transactions have taken place since this date which has impacted the shareholding of each of these joint venture partners (refer to note 14 below).  The signing of this Shareholders’ Agreement meant that PNG LNG Inc. was no longer a subsidiary of InterOil and was a jointly controlled entity, between the parties to the Shareholders’ Agreement, from the date of the agreement.  As the entity became a joint venture in July 2007, guidance under CICA 3055 – ‘Interest in Joint Ventures’ has been followed and the entity has been proportionately consolidated in InterOil’s consolidated financial statements from the date of the Shareholders’ Agreement.  The consolidated results of InterOil’s proportionate shareholding in the LNG Project has been disclosed separately within the segment notes under Midstream - Liquefaction, refer to note 4.

(d) Changes in accounting policies

Effective year ended December 31, 2009, the Company adopted the revisions to CICA 3862 – Financial Instruments – Disclosures which was amended to include additional disclosure requirements about fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements for publicly accountable enterprises.  The revisions require the disclosure of maturity analysis for derivative and non-derivative financial assets and liabilities, and additional information on liquidity risk.  The Company has made these additional disclosures within notes 3(b) Liquidity risk, and note 3(g) Fair values.

Based on the detailed review conducted by the Company of the new CICA sections, or revisions to current sections, no other items have been identified as having any material impact on the Company’s financial statements.

(e) New standards issued but not yet effective, and transition to IFRS

Based on the detailed review conducted by the Company of the new CICA sections, or revisions to current sections, that are effective for the year beginning January 1, 2010, no items have been identified as having any material impact on the Company’s financial statements.

The Accounting Standards Board (”AcSB”) will adopt International Financial Reporting Standards (“IFRS”) as Canadian GAAP, effective January 1, 2011.  In anticipation of the change, the AcSB is revising certain Canadian accounting standards to conform to IFRS in advance of the 2011 implementation date.  The required change to IFRS is mandatory for all Canadian publicly accountable entities, which includes those with public debt.

Consolidated Financial Statements   INTEROIL CORPORATION     11

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

The Securities Exchange Commission (“SEC”) currently allows foreign private issuers using IFRS as their primary GAAP to not provide reconciliation to U.S. GAAP in their financial statements.

The Company will adopt IFRS as per the guidelines issued by AcSB and report under IFRS effective January 1, 2011 with comparative IFRS numbers for 2010.

(f) Segment reporting

An operating segment (also referred to as a ”business segment”) is a component of an enterprise:

a.  that engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other segments of the same enterprise),

b.  whose operating results are regularly reviewed by the Company’s management to make decisions about resources to be allocated to the segment and assess its performance, and

c.  for which discrete financial information is available.

The Company’s assets and operations are predominantly based in Papua New Guinea and therefore are disclosed as one geographical segment.  Refer to note 1 for the management’s organization of the Company by business segment.

(g) Foreign currency translation

Functional and reporting currency

Items included in the financial statements of each of the Company’s entities are measured using the currency of the primary economic environment in which the entity operates (”the functional currency”).  The consolidated financial statements are presented in United States Dollars which is InterOil’s functional and reporting currency.

Self Sustaining and Integrated Foreign Operations

For subsidiaries considered to be self-sustaining foreign operations, all assets and liabilities denominated in foreign currency are translated to United States dollars at exchange rates in effect at the balance sheet date and all revenue and expense items are translated at the rates of exchange in effect at the time of the transactions.  Foreign exchange gains or losses are reported as a separate component of shareholders' equity as a Foreign currency translation adjustment.

For subsidiaries considered to be an integrated foreign operation, monetary items denominated in foreign currency are translated to United States dollars at exchange rates in effect at the balance sheet date and non-monetary items are translated at rates of exchange in effect when the assets were acquired or obligations incurred.  Revenue and expense items are translated at the rates of exchange in effect at the time of the transactions.  Foreign exchange gains or losses are included in the statement of operations.

(h) Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable. Amounts disclosed as revenue are net of returns, trade allowances and duties and taxes paid.  The following particular accounting policies, which significantly affect the measurement of results, have been applied.

Revenue from Midstream Refining operations:

Revenue from sales of products is recognized when products are shipped and the customer takes ownership and assumes risk of loss, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the sales price is fixed or determinable.  Sales between the business segments of the Company have been eliminated from sales and operating revenues and cost of sales.

Revenue from Downstream operations:

Sales of goods are recognized when the Company has delivered products to the customer, the customer takes ownership and assumes risk of loss, collection of the receivable is probable, persuasive evidence of an arrangement exists and the sale price is fixed or determinable. It is not the Company’s policy to sell products with a right of return.

Interest income:

Interest income is recognized on a time-proportionate basis.

(i) Income tax

The income tax expense or benefit for the period is the tax payable on the current period’s taxable income based on the national income tax rate for each jurisdiction; adjusted by changes in deferred tax assets and liabilities attributable to temporary differences between the tax bases of assets and liabilities and their carrying amounts in the financial statements and to unused tax losses.

Consolidated Financial Statements   INTEROIL CORPORATION     12

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

Deferred tax assets and liabilities are recognized for temporary differences at the tax rates expected to apply when the assets are recovered or liabilities are settled, based on those tax rates which are enacted or substantively enacted for each jurisdiction.  The relevant tax rates are applied to the cumulative amounts of deductible and taxable temporary differences to measure the deferred tax asset or liability.

Deferred tax assets are recognized for deductible temporary differences and unused tax losses only if it is more likely than not that future taxable amounts will be available to utilize those temporary differences and losses.  A valuation allowance is provided against any portion of a future tax asset which will more likely not be recovered.

In addition to income taxes, InterOil is subject to Goods and Services Tax, Excise Duty and other taxes in Papua New Guinea, Australia, Singapore and Canada.  The consolidated statement of operations is prepared on a net of Goods and Services Tax.

(j) Acquisitions of assets

The purchase method of accounting is used to account for all acquisitions of assets (including business combinations) regardless of whether equity instruments or other assets are acquired.  Cost is measured as the fair value of the assets given, shares issued or liabilities assumed at the date of exchange plus costs directly attributable to the acquisition.

Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.  The excess of the cost of acquisition over the fair value of the Company’s share of the identifiable net assets is recorded as goodwill.  If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference, to the extent possible, is allocated against acquired fixed assets in accordance with the standards on a pro rata basis.  Any further excess is presented as an extraordinary gain in the statement of operations.

Where settlement of any part of cash consideration is deferred, the amounts payable in future are discounted to their present value as at the date of exchange.  The discount rate is the Company’s incremental borrowing rate, being the rate at which similar borrowing could be obtained from an independent financier under comparable terms and conditions.

(k) Impairment of assets

Assets that are subject to amortization and goodwill recognized are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  The carrying amount of a long-lived asset is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition.

An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its fair value.  Fair value is the amount of the consideration that would be agreed upon in an arm's length transaction between knowledgeable, willing parties who are under no compulsion to act.  When no liquid market exists, the fair value is the present value of future cash flows discounted at the risk free rate of interest plus a risk premium.  If an impairment loss is recognized, the adjusted carrying amount becomes the new cost basis.

For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows.

There has been no impairment of assets or goodwill based on the assessment performed during the year.

(l) Cash and cash equivalents

Cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to insignificant risk of changes in value.

(m) Restricted cash

Restricted cash consists of cash on deposit with a maturity of less than three months at the time of purchase but which is restricted from being used in daily operations.  Restricted cash is carried at cost and any accrued interest is classified under other assets.

Consolidated Financial Statements   INTEROIL CORPORATION     13

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

(n) Trade receivables

The collectability of trade receivables is assessed on an ongoing basis.  Debts which are known to be uncollectible are written off.  A provision for doubtful receivables is established when there is objective evidence that the Company will not be able to collect all amounts due according to the original terms of the receivables.  The amount of provision is recognized in the statement of operations.

The Company sells certain trade receivables with recourse to BNP Paribas under its working capital facility.  The receivables are retained on the balance sheet as the Company retains the credit risk and control over these receivables.

(o) Inventory

Raw materials and stores and finished goods

Raw materials and finished goods are stated at the lower of costs and net realizable value.  Costs comprise direct materials, direct labor and an appropriate proportion of variable and fixed overhead expenditure.  Net realizable value is the estimated selling price in the ordinary course of the business less the estimated costs of completion and the estimated costs necessary to make the sale.  Stores are stated at cost less provision for obsolescence.

Crude oil and refined petroleum products

Crude oil and refined petroleum products are recorded on a first-in, first-out basis and the net realizable value test for crude oil and refined petroleum products are performed separately.  The cost of Midstream Refining petroleum products consist of raw material, labor, direct overheads and transportation costs.  The cost of Downstream petroleum products includes the cost of the product plus related freight, wharfage and insurance.

(p) Assets held for sale

Non-current assets are classified as held for sale and stated at the lower of their carrying amount and fair value less costs to sell if their carrying amount will be recovered principally through a sale transaction rather than through continuing use.

An impairment loss is recognized for any initial or subsequent write down of the asset (or disposal group) to fair value less costs to sell.  A gain is recognized for any subsequent increase in fair value less costs to sell an asset but not in excess of any cumulative impairment loss previously recognized.  A gain or loss not previously recognized by the date of sale of the non-current asset is recognized at the date of derecognition.

Non-current assets are not depreciated or amortized while they are classified as held for sale.  Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognized.

Non-current assets classified as held for sale are presented separately from other assets in the balance sheet.  The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the balance sheet.  There are no assets held for sale as at the end of December 31, 2009.

(q) Derivative financial instruments

Derivative financial instruments are utilized by the Company in the management of its crude purchase cost exposures and its finished products sales price exposures.  The Company's policy is not to utilize derivative financial instruments for trading or speculative purposes.  The Company may choose to designate derivative financial instruments as hedges.

When applicable, at the inception of the hedge, the Company formally documents all relationships between hedging instruments and the hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions, the nature of the risk being hedged, how the hedging instruments’ effectiveness in offsetting the hedged risk will be assessed and a description of the method for measuring effectiveness.  This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or anticipated transactions.  The Company also assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items at inception and on an ongoing basis.

Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded as a component of Other Comprehensive Income until earnings are affected by the variability in cash flows of the designated hedged item.  For cash flow hedges that have been terminated or cease to be effective, prospective gains or losses on the derivative are recognized in earnings.  Any gain or loss that has been included in accumulated other comprehensive income at the time the hedge is discontinued continues to be deferred in accumulated other comprehensive income until the original hedged transaction is recognized in earnings.  If the likelihood of the original hedged transaction occurring is no longer probable, the entire gain or loss in accumulated other comprehensive income related to this transaction is immediately reclassified to earnings.

Consolidated Financial Statements   INTEROIL CORPORATION    14

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in cash flows of the hedged item, the derivative expires or is sold, terminated or exercised, the derivative is no longer designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

There were no outstanding hedge accounted or non-hedge accounted derivative contracts outstanding as at December 31, 2009.

(r) Deferred financing costs

Deferred financing costs represent the unamortized financing costs paid to secure borrowings.  Amortization is provided on an effective yield basis over the term of the related debt and is included in expenses for the period.  Unamortized deferred financing costs are offset against the respective liability accounts.

(s) Plant and equipment

Refinery assets

The Company’s most significant item of plant and equipment is the oil refinery in Papua New Guinea which is included within Midstream Refining assets.  The pre-operating stage of the refinery ceased on January 1, 2005.  Project costs, net of any recoveries, incurred during the pre-operating stage were capitalized as part of plant and equipment.  Development costs and the costs of acquiring or constructing support facilities and equipment are also capitalized.

The refinery assets are recorded at cost.  Interest costs relating to the construction and pre-operating stage of the development project prior to commencement of commercial operations were capitalized as part of the cost of such plant and equipment.  Refinery related assets are depreciated on straight line basis over their useful lives, at an average rate of 4% per annum.  The refinery is built on land leased from the Independent State of Papua New Guinea.  The lease expires on July 26, 2097.

Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred.  Major turnaround costs will be deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround.  No major turnaround costs have been incurred during the year ended December 31, 2009.

Other assets

Property, plant and equipment are recorded at cost.  Depreciation of assets begins when the asset is in place and ready for its intended use.  Assets under construction and deferred project costs are not depreciated.  Depreciation of plant and equipment is calculated using the straight line method, based on the estimated service life of the asset.  Maintenance and repair costs are expensed as incurred.  Improvements that increase the capacity or prolong the service life of an asset are capitalized.

The depreciation rates by segment are as follows:

Downstream	0% - 25	%
Midstream	1% - 33	%
Upstream	4% - 100	%
Corporate	13% - 33	%

Leased assets

Leases of property, plant and equipment where the Company has substantially all the risks and rewards of ownership are classified as finance leases.  Finance leases are classified at the inception of the lease at the lower of the fair value of the leased property and the present value of the minimum lease payments.  The corresponding rental obligations, net of finance charges, are included in other long term payables.  Each lease payment is allocated between the liability and the finance charges so as to achieve a constant rate on the finance balance outstanding.  The interest element of the finance cost is charged to the statement of operations over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.  The property, plant and equipment acquired under finance leases are depreciated over the shorter of the asset’s useful life and the lease term.

Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases.  Operating lease payments are representative of the pattern of benefit derived from the leased asset and accordingly are included in expenses in the periods in which they are incurred.

Consolidated Financial Statements   INTEROIL CORPORATION    15

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

Asset retirement obligations

Estimated costs of future dismantlement, site restoration and abandonment of properties are provided based upon current regulations and economic circumstances at year end.  Management estimates there are no material obligations relating to future restoration and closure costs.

Environmental remediation

Remediation costs are accrued based on estimates of known environmental remediation exposure.  Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred.  Provisions are determined on an assessment of current costs, current legal requirements and current technology.  Changes in estimates are dealt with on a prospective basis.  As at December 31, 2009, no provision has been raised.

Disposal of property, plant and equipment

At the time of disposition of plant and equipment, the carrying values of the assets are written off along with accumulated depreciation and any resulting gain or loss is included in the statement of operations.

IT Development and software

Costs incurred in development products or systems and costs incurred in acquiring software and licenses that will contribute to future period financial benefits through revenue generation and/or cost reduction are capitalized to software and systems.  Costs capitalized include external direct costs of materials and service, direct payroll and payroll related costs of employees’ time spent on the project.  Amortization is calculated on a straight line bases over periods generally ranging from 3 to 5 years.  IT development costs include only those costs directly attributable to the development phase and are only recognized following completion of technical feasibility and where the Company has an intention and ability to use the asset. These amounts are capitalized as part of property, plant and equipment in the Corporate segment.

(t) Oil and gas properties

The Company uses the successful-efforts method to account for its oil and gas exploration and development activities as per the U.S. GAAP guidance under Accounting Standards Codification (“ASC”) 932 as no relevant guidance under Canadian GAAP is available to account for oil and gas transactions.  Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred.  The Company continues to carry as an asset the cost of drilling exploratory wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of economic reserves.  Capitalized costs for producing wells will be subject to depletion on the units-of-production method.

Geological and geophysical costs are expensed as incurred, except when they have been incurred to facilitate production techniques, to increase total recoverability and to determine the desirability of drilling additional development wells within a proved area.  Geological and geophysical costs capitalized would be included as part of the cost of producing wells and be subject to depletion on the units-of-production method.

(u) Accounts payable and accrued liabilities

These amounts represent liabilities for goods and services provided to the Company prior to the end of financial year which are unpaid.  These amounts are unsecured and are usually paid within 30 days of recognition.

(v) Employee entitlements

Wages and salaries, and annual leave

Liabilities for wages and salaries, including annual leave expected to be settled within 12 months of the reporting date are recognized in accounts payables in respect of employees’ services up to the reporting date and are measured at the amounts expected to be paid when liabilities are settled.

Long Service Leave

The liability for long service leave is recognized in the provision for employee benefits and measured as the present value of expected future payments to be made in respect of services provided by employees up to the reporting date.  Consideration is given to expected future wage and salary levels, experience of employee departures, periods of service and statutory obligations.

Retirement benefit obligations

The Company contributed to a defined contribution plan and the Company’s legal or constructive obligation is limited to these contributions.  Contributions to the defined contribution fund are recognized as an expense as they become payable.

Consolidated Financial Statements   INTEROIL CORPORATION    16

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

2. Significant accounting policies (cont’d)

Stock-based compensation

Stock-based compensation benefits are provided to employees pursuant to the 2009 Stock Incentive Plan (with options still in existence having been granted under the now superseded 2002 Incentive Stock Option Plan and 2006 Stock Incentive Plan).  The Company currently issues stock options and restricted stock units as part of its stock-based compensation plan.  The fair value of stock options at grant date is determined using a Black-Scholes option pricing model that takes into account the exercise price, the terms of the option, the vesting criteria, the share price at grant date and expected price volatility of the underlying share, the expected yield and risk-free interest rate for the term of the option.  Upon exercise of options, the balance of the contributed surplus relating to those options is transferred to share capital.  The fair value of restricted stock on grant date is the market value of the stock.  The Company uses the fair value based method to account for employee stock based compensation benefits.  Under the fair value based method, compensation expense is measured at fair value at the date of grant and is expensed over the award's vesting period.

Profit-sharing and bonus plans

The Company recognizes a provision where contractually obliged or where there is a past practice that has created a constructive obligation.

(w) Earnings per share

Basic earnings per share

Basic common shares outstanding are the weighted average number of common shares outstanding for each period.  The calculation of basic per share amounts is based on net earnings/(loss) divided by the weighted average of common shares outstanding.

Diluted earnings per share

Diluted per share amounts are computed similarly to basic per share amounts except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, conversion options and warrants, if dilutive.  The number of additional shares is calculated by assuming that outstanding stock options were exercised and the proceeds from such exercises were used to acquire shares of common stock at the average price during the reporting period.

(x) Reclassification

Certain minor prior years’ amounts have been reclassified to conform to current presentation.

3. Financial Risk Management

The Company’s activities expose it to a variety of financial risks; market risk, credit risk, liquidity risk and geographic risk.  The Company’s overall risk management program focuses on the unpredictability of markets and seeks to minimize potential adverse effects on the financial performance of the Company.  The Company uses derivative financial instruments to hedge certain price risk exposures.

Risk Management is carried out under policies approved by the Board of Directors.  The Finance Department identifies, evaluates and hedges financial risks in close cooperation with the Company’s operating units.  The product pricing risks are managed by the Supply and Trading Department under the guidance of the Risk Management Committee.  The Board provides written principles for overall risk management, as well as written policies covering specific areas, such as use of derivative financial instruments.

(a)  Market risk

(i) Foreign exchange risk

Foreign exchange risk arises when future commercial transactions and recognized assets and liabilities are denominated in a currency that is not the Company’s functional currency.  The Company operates internationally and is exposed to foreign exchange risk arising from currency exposures to the United States Dollar. The consolidated financial statements are presented in United States Dollars which is InterOil’s functional and reporting currency.

Most of the Company’s transactions are undertaken in United States Dollars (“USD”), Papua New Guinea Kina (“PGK”) and Australian Dollars (“AUD”).  Currently there are no foreign currency exchange hedge programmes in place.

The Papua New Guinea Kina exposures are minimal at the transactional level as the Downstream sales in local currency are used to adequately cover the operating expenses of the Midstream Refining and Downstream operations.  However, the translation of PGK denominated balances in our operating entities into USD at period ends can result in material impact on the foreign exchange gains/losses on consolidation.

Consolidated Financial Statements   INTEROIL CORPORATION    17

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

3. Financial Risk Management (cont’d)

Changes in the PGK to USD exchange rate can affect our Midstream Refining results as there is a timing difference between the foreign exchange rates utilized when setting the monthly PGK IPP price and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings.  The foreign exchange movement also impacts equity as translation gains/losses of our Downstream operations from PGK to USD is included in other comprehensive income as these are self-sustaining operations.  The PGK weakened against the USD during the three months ended March 31, 2009 (from 0.3735 to 0.3400).  However, it then strengthened against the USD during the nine months ended December 31, 2009 (from 0.3400 to 0.3700).

The financial instruments denominated in Papua New Guinea Kina translated to USD as at December 31, 2009 are as follows:

	December 31,		December 31,
	2009		2008
	$		$
Financial Assets
Cash and cash equivalents		19,026,270		28,865,339
Receivables		36,841,246		39,307,624
Other financial assets		6,459,541		3,348,716
Financial liabilities
Payables		19,808,982		17,766,660
Working capital facility		7,832,266		15,405,627

The following table summarizes the sensitivity of financial instruments held at balance sheet date to movement in the exchange rate of the US dollar to the Papua New Guinea Kina, with all other variables held constant.  Certain USD debt and other financial assets and liabilities are not held in the functional currency of the relevant subsidiary.  This results in an accounting exposure to exchange gains and losses as the financial assets and liabilities are translated into the functional currency of the subsidiary that accounts for those assets and liabilities.  These exchange gains and losses are recorded in the consolidated income statement except to the extent that they can be taken to equity under the Company’s accounting policy.  If PGK strengthens against the USD, it will result in a gain, and vice versa.

	Year ended				Year ended
	December 31, 2009				December 31, 2008
	Impact on profit		Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact
	$		$		$		$
Post-tax gain/(loss)
Effect of 5% appreciation of PGK		5,814,938		2,990,708		4,245,399		3,072,446

The changes in AUD to USD exchange rate can affect our Corporate results as the expenses our Corporate office in Australia are incurred in AUD.  The AUD exposures are minimal as funds are transferred to AUD from USD as required. No material balances are held in AUD.  However, we are exposed to the AUD fluctuations due to in country costs being incurred in AUD and our reporting for those costs being in USD.

(ii) Price risk

The Midstream Refining operations of the Company are largely exposed to price fluctuations during the period between the crude purchases and the refined products leaving the refinery when sold to Downstream operations and other distributors.  The Company actively tries to manage the price risk by entering into derivative contracts to buy and sell crude and finished products.

The derivative contracts are entered into by Management based on documented risk management strategies which have been approved by the Risk Management Committee.  All derivative contracts entered into are reviewed by the Risk Management Committee as part of the meetings of the Committee.

Consolidated Financial Statements   INTEROIL CORPORATION    18

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

3. Financial Risk Management (cont’d)

The following table summarizes the sensitivity of the crude and finished product inventory held at balance date to $10.0 movement in benchmark pricing, with all other variables held constant.

	Year ended				Year ended
	December 31, 2009				December 31, 2008
	Impact on profit		Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact
	$		$		$		$
Post-tax gain/(loss)
$10 increase in benchmark pricing		8,929,143		-		8,144,261		-

(iii) Interest rate risk

Interest rate risk is the risk that the Company’s financial position will be adversely affected by movements in interest rates that will increase the cost of floating rate debt or opportunity losses that may arise on fixed rate borrowings in a falling interest rate environment.

As the Company has no significant interest-bearing assets other than cash and cash equivalents, the Company’s income and operating cash flows are substantially independent of changes in market interest rates.

The Company’s interest-rate risk arises from borrowings and working capital financing facilities. Borrowings issued at variable rates expose the Company to cash flow interest-rate risk.  Borrowings issued at fixed rates expose the Company to fair value interest-rate risk.  The Company is actively seeking to manage its cash flow interest-rate risks.

The financial instruments exposed to cash flow and fair value interest rate risk are as follows:

	December 31, 2009		December 31, 2008		Cash flow/fair value interest rate risk
	$		$
Financial Assets
Cash and cash equivalents		1,484,987		6,571,375	fair value interest rate risk
Cash and cash equivalents		44,964,832		42,399,197	cash flow interest rate risk
Cash restricted		282,555		290,782	fair value interest rate risk
Cash restricted		29,026,020		25,994,258	cash flow interest rate risk
Financial liabilities
OPIC secured loan		53,500,000		62,500,000	fair value interest rate risk
BNP working capital facility		16,794,153		53,386,775	cash flow interest rate risk
Westpac and BSP working capital facility		7,832,266		15,405,627	cash flow interest rate risk
8% subordinated debentures		-		78,975,000	fair value interest rate risk

The following table summarizes the sensitivity of the cash flow interest-rate risk of financial instruments held at balance date, following a movement to LIBOR, with all other variables held constant.  Increase in LIBOR rates will result in a higher expense for the Company.
 

	Year ended				Year ended
	December 31, 2009				December 31, 2008
	Impact on profit		Impact on equity - excluding profit impact		Impact on profit		Impact on equity - excluding profit impact
	$		$		$		$
Post-tax loss/(gain)
LIBOR +1%		252,242		-		260,944		-

(iv) Product risk

The composition of the crude feedstock will vary the refinery output of products.  The 2009 annual output achieved includes gasoline and distillates fuels (which includes diesel and jet fuels) 61% (Dec 2008 – 56%), and naphtha and low sulphur waxy residue 33% (Dec 2008 – 40%).  The product yields obtained will vary based on the type of crude feedstock used.

Consolidated Financial Statements   INTEROIL CORPORATION    19

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

3. Financial Risk Management (cont’d)

Management endeavors to manage the product risk by actively reviewing the market for demand and supply, trying to maximize the production of the higher margin products and also renegotiating the selling prices for the lower margin products.

(b)  Liquidity risk

Liquidity risk is the risk that InterOil will not meet its financial obligations as they fall due. Prudent liquidity risk management therefore implies that, under both normal and stressed conditions, the Company maintains:

� sufficient cash and marketable securities;

� access to, or availability of, funding through an adequate amount of committed credit facilities; and

� the ability to close-out any open market positions.

The Company manages liquidity risk by continuously monitoring forecast and actual cash flows; matching maturity profiles of financial assets and liabilities; and by maintaining flexibility in funding including ensuring that surplus funds are generally only invested in instruments that are tradable in highly liquid markets or that can be relinquished with minimal risk of loss.  Refer to liquidity risk related disclosures in Note 2(b) Going Concern.

Financing arrangements

The Company had the following established undrawn borrowing facilities at the reporting date:

			Undrawn Amount
	Total Facility		2009
	$		$
Facility
OPIC secured loan		53,500,000		-
BNP Paribas working capital facility 1 (note 16)		130,000,000		66,505,847
BNP Paribas working capital facility 2 (note 16)		60,000,000		50,000,000
Westpac working capital facility		29,600,000		21,767,734
BSP working capital facility		18,500,000		18,500,000
		291,600,000		156,773,581

Maturities of financial liabilities

The tables below analyses the Company’s financial liabilities, net and gross settled derivative financial instruments into relevant maturity groupings based on the remaining period at the reporting date to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows.

	Less than 1 year		Between 1 and 5 years		More than 5 years		Total contractual cash flow
Non-derivatives
Accounts payable and accrued liabilities (note 13)		59,372,354		-		-		59,372,354
Working capital facility (note 16)		24,626,419		-		-		24,626,419
Secured loan (note 19)		9,000,000		36,000,000		8,500,000		53,500,000
Total non-derivatives		92,998,773		36,000,000		8,500,000		137,498,773
Derivatives
Commodity derivative contracts (note 7)		-		-		-		-
Total derivatives		-		-		-		-
		92,998,773		36,000,000		8,500,000		137,498,773

The ageing of accounts payables and accrued liabilities are as follows:

			Payable ageing between
Accounts payable and accrued liabilities	Total		<30 days		30-60 days		>60 days
	$		$		$		$
December 31, 2009		59,372,354		57,048,258		838,973		1,485,123
December 31, 2008		78,147,736		76,556,334		1,181,334		410,068

 Consolidated Financial Statements   INTEROIL CORPORATION    20

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

 

3. Financial Risk Management (cont’d)

(c)   Credit risk

Credit risk is the risk that a contracting entity will not complete its obligation under a financial instrument that will result in a financial loss to the Company.  The carrying amount of financial assets represents the maximum credit exposure.

The Company’s credit risk is limited to the carrying value of its financial assets.  A significant amount of the Company’s export sales are made to three customers which represented $110,068,833 (Dec 2008 - $156,518,509) or 16% (Dec 2008 – 17%) of total sales in the year ended December 31, 2009.  The Company’s domestic sales for the year ended December 31, 2009 were not dependent on a single customer or geographic region of Papua New Guinea.  The export sales to three customers is not considered a key risk as there is a ready market for InterOil export products and the prices are quoted on active markets.  The Company actively manages credit risk by routinely monitoring the credit ratings of Company’s customers and ageing of trade receivables.  The credit terms provided to customers are revised if any changes are noted to customer ratings or payment cycles.

Credit risk on cash and cash equivalents held directly by the Company are minimized as all cash amounts and certificates of deposit are held with banks which have acceptable credit ratings.

The maximum exposure to credit risk at the reporting date was as follows:

	December 31,		December 31,
	2009		2008
	$		$
Current
Cash and cash equivalents		46,449,819		48,970,572
Cash restricted		22,698,829		25,994,258
Trade receivables		61,194,136		42,887,823
Commodity derivative contracts		-		31,335,050
Non-current
Cash restricted		6,609,746		290,782

The ageing of receivables at the reporting date was as follows (the ageing days relates to balances past due):

			Receivable ageing between
Net trade receivables	Total		Current and		30-60 days		>60 days
	$		<30 days $		$		$
December 31, 2009		61,194,136		54,650,416		1,666,797		4,876,923
December 31, 2008		42,887,823		33,515,675		5,128,127		4,244,022

The impairment of receivables at the reporting date was as follows:

					Overdue		Overdue
Gross trade receivables	Total		Current		(not impaired)		(impaired)
	$		$		$		$
December 31, 2009		64,797,478		49,805,924		11,388,212		3,603,342
December 31, 2008		47,496,119		18,592,467		24,295,356		4,608,296

Impairment is assessed by our Credit department on an individual customer basis, based on customer ratings and payment cycles of the customers.  An impairment provision is taken for all receivables where objective evidence of impairment exists.  The movement in impairment is also influenced by the translation rates used to convert these amounts from local currency to USD.

Consolidated Financial Statements   INTEROIL CORPORATION    21

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

3. Financial Risk Management (cont’d)

The movement in impaired receivables for the year ended December 31, 2009 was as follows:
 

	Year ended
	December 31, 2009			December 31, 2008
	$			$
Trade receivables - Impairment provisions
Opening balance		4,608,296			3,176,806
Amounts written off during the year		(1,262,699	)		-
Additional provisions net of reversals made		257,744			1,431,490
Closing balance		3,603,342			4,608,296

(d)  Geographic risk

The operations of InterOil are concentrated in Papua New Guinea.

(e)  Financing facilities

As at December 31, 2009, the Company had drawn down against the following financing facilities:

a. BNP working capital facility (refer note 16)

b. Westpac and BSP working capital facility (refer note 16)

c. OPIC secured loan facility (refer note 19)

Repayment obligations in respect of the amount of the facilities utilized are as follows:

	December 31,		December 31,
	2009		2008
	$		$
Due:
No later than one year		33,626,419		77,792,402
Later than one year but not later than two years		9,000,000		9,000,000
Later than two years but not later than three years		9,000,000		9,000,000
Later than three years but not later than four years		9,000,000		9,000,000
Later than four years but not later than five years		9,000,000		87,975,000
Later than five years		8,500,000		17,500,000
		78,126,419		210,267,402

(f)  Effective interest rates and maturity profile

	Floating		Fixed interest maturing between																Effective
	interest		1 year										more than		Non-interest				interest
December 31, 2009	rate		or less		1-2		2-3		3-4		4-5		5 years		bearing		Total		rate
	$'000		$'000		$000		$'000		$'000		$'000		$'000		$'000		$'000		%
Financial assets
Cash and cash equivalents		44,964,832		1,484,987		-		-		-		-		-		-		46,449,819		0.57	%
Cash restricted		29,026,020		282,555		-		-		-		-		-		-		29,308,575		2.40	%
Receivables		-		-		-		-		-		-		-		61,194,136		61,194,136		-
Other financial assets		-		-		-		-		-		-		-		6,964,950		6,964,950		-
		73,990,851		1,767,543		-		-		-		-		-		68,159,086		143,917,480
Financial liabilities
Payables		-		-		-		-		-		-		-		59,372,354		59,372,354		-
Interest bearing liabilities		24,626,419		9,000,000		9,000,000		9,000,000		9,000,000		9,000,000		8,500,000		-		78,126,419		6.89	%
		24,626,419		9,000,000		9,000,000		9,000,000		9,000,000		9,000,000		8,500,000		59,372,354		137,498,773

Consolidated Financial Statements   INTEROIL CORPORATION    22

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

3. Financial Risk Management (cont’d)

	Floating		Fixed interest maturing between																Effective
	interest		1 year										more than		Non-interest				interest
December 31, 2008	rate		or less		1-2		2-3		3-4		4-5		5 years		bearing		Total		rate
	$'000		$'000		$000		$'000		$'000		$'000		$'000		$'000		$'000		%
Financial assets
Cash and cash equivalents		42,108,415		6,862,157		-		-		-		-		-		-		48,970,572		3.21	%
Cash restricted		26,285,040		-		-		-		-		-		-		-		26,285,040		4.15	%
Receivables		-		-		-		-		-		-		-		42,887,823		42,887,823		-
Other financial assets		-		-		-		-		-		-		-		35,824,624		35,824,624		-
		68,393,455		6,862,157		-		-		-		-		-		78,712,447		153,968,059
Financial liabilities
Payables		-		-		-		-		-		-		-		78,147,736		78,147,736		-
Interest bearing liabilities		68,792,402		9,000,000		9,000,000		9,000,000		9,000,000		9,000,000		17,500,000		-		131,292,402		6.30	%
Debentures liability		-		-		-		-		-		78,975,000		-		-		78,975,000		13.50	%
		68,792,402		9,000,000		9,000,000		9,000,000		9,000,000		87,975,000		17,500,000		78,147,736		288,415,138

(g)  Fair values

	December 31, 2009				December 31, 2008				Fair value
	Carrying amount		Fair value		Carrying amount		Fair value		hierarchy level	Method of
	$		$		$		$		(as required) *	valuation
Financial instruments
Loans and receivables
Receivables		61,194,136		61,194,136		42,887,823		42,887,823		Amortized Cost
Held for trading
Commodity derivative contracts (note 7)		-		-		31,335,050		31,335,050	Level 2	Fair Value - See (1) below
Financial assets
Cash and cash equivalents		46,449,819		46,449,819		48,970,572		48,970,572		Cost
Cash restricted		29,308,575		29,308,575		26,285,040		26,285,040		Cost
Financial liabilities at amortized cost
Current liabilities:
Accounts payable and accrued liabilities (note 13)		59,372,354		59,372,354		78,147,736		78,147,736		Cost
Working capital facility (note 16)		24,626,419		24,626,419		68,792,402		68,792,402		Cost
Current portion of secured loan (note 19)		9,000,000		9,255,632		9,000,000		9,012,228		Amortized cost See (2) below
Non-current liabilities
Secured loan (note 19)		43,589,278		47,696,040		52,365,333		58,753,276		Amortized cost See (2) below
8% Subordinated debenture liability (note 24)		-		-		65,040,067		65,040,067		Amortized Cost

* Where fair value of financial assets or liabilities is approximated by its carrying value, designation under the fair value hierarchy is not required.

The net fair value of cash and cash equivalents and non-interest bearing financial assets and financial liabilities of the Company approximates their carrying amounts.

The carrying values (less impairment provision if provided) of trade receivables and payables are assumed to approximate their fair values due to their short-term nature. The carrying value of financial liabilities approximates their fair values which, for disclosure purposes, are estimated by discounting the future contractual cash flows at the current market interest rate that is available to the Company for similar financial instruments.

Commodity derivative contracts’ is the only item from the above table that is measured at fair value on a recurring basis.  All the remaining financial assets and financial liabilities are measured at a fair value on a non-recurring basis and are maintained at historical amortized cost.

The fair value of financial assets and financial liabilities must be estimated for recognition and measurement or for disclosure purposes.  The Company has classified the fair value measurements using a fair value hierarchy that reflects the significance of the inputs used in making the measurements. The fair value hierarchy shall have the following levels:

Consolidated Financial Statements   INTEROIL CORPORATION    23

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

3. Financial Risk Management (cont’d)

Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities

Level 2 - inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices); and

Level 3 - inputs for the asset or liability that are not based on observable market data (unobservable inputs).

(1) Derivative contracts classified as being at fair value through profit and loss are fair valued by comparing the contracted rate to the current market rate for a contract with the same remaining period to maturity.  The fair value of the Company’s commodity derivative contracts are based on price indications provided to us by an external brokerage who enter into derivative transactions with counter parties on our behalf.  There were no commodity derivative contracts on which final pricing were to be determined in future periods as at December 31, 2009.

(2) The fair value of the secured loan is based on discounted cash flow analysis using a current market interest rate applicable for the loan arrangement, being the current interest rate on a U.S. treasury note with the same approximate maturity profile plus the OPIC spread (3%).

(h)  Capital management

The Finance department of the Company is responsible for capital management.  This involves the use of corporate forecasting models which facilitates analysis of the Company’s financial position including cash flow forecasts to determine the future capital management requirements.  Capital management is undertaken to ensure a secure, cost-effective and flexible supply of funds is available to meet the Company’s operating and capital expenditure requirements.

The Company is actively managing the gearing levels and raising equity/debt as required for optimizing shareholder returns.  The Company is managing its gearing levels by maintaining the debt-to-capital ratio (long term debt/(shareholders’ equity + long term debt)) at 50% or less, and has made considerable progress in achieving this as at December 31, 2009.  The gearing levels were reduced to 11% in December 2009 from 36% in December 2008.

The optimum gearing levels for the Company are set by Management based on the stage of development of the Company, future needs for development and capital market conditions, and will be reassessed as situations change.

This reduction in gearing levels as at December 31, 2009 as compared to December 31, 2008 was mainly due to the conversion of all outstanding $95.0 million 8% convertible subordinated debentures issued in May 2008, and the completion of the $70.4 million registered direct stock offering completed in June 2009.

On May 13, 2008, the Company completed the issue of $95.0 million unsecured 8% subordinated convertible debentures with a maturity of five years.  During the period from July 2008 to June 2009 all outstanding debentures were converted into common shares.  On June 8, 2009 the Company completed a registered direct offering of 2,013,815 shares of its common stock to a number of institutional investors at a purchase price of $34.98 per share amounting to $70.4 million.

We will evaluate further opportunities of raising capital in the future for our capital expenditure requirements.  In order to achieve this objective, the Company has filed an omnibus shelf prospectus for a total of $200.0 million securities issue with the Ontario Securities Commission on August 7, 2008 and a corresponding registration statement on Form F-10/A with the United States Securities and Exchange Commission (the "SEC") pursuant to the multi-jurisdictional disclosure system.  These filings will enable the Company to add financial flexibility in the future and issue, from time to time, up to a further $129.6 million of its debt securities, common shares, preferred shares and/or warrants ("Securities") in one or more offerings.

Consolidated Financial Statements   INTEROIL CORPORATION    24

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

4. Segmented financial information

As stated in note 1, management has identified four major business segments - Upstream, Midstream, Downstream and Corporate.  The Corporate segment includes assets and liabilities that do not specifically relate to the other business segments.  Results in this segment primarily includes management, financing costs and interest income. Consolidation adjustments relating to total assets relates to the elimination of intercompany loans and investments in subsidiaries.

Notes to and forming part of the segment information

Segment information is prepared in conformity with the accounting policies of the entity as disclosed in note 2.  Segment revenues, expenses and total assets are those that are directly attributable to a segment and the relevant portion that can be allocated to the segment on a reasonable basis.  Upstream, Midstream and Downstream include costs allocated from the Corporate activities based on a fee for services provided.  The eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventories.

Year ended December 31, 2009	Upstream			Midstream - Refining			Midstream - Liquefaction			Downstream			Corporate			Consolidation adjustments			Total
Revenues from external customers		-			299,672,617			-			388,806,348			-			-			688,478,965
Intersegment revenues		-			274,735,845			-			184,799			21,194,362			(296,115,006	)		-
Interest revenue		15,862			175,377			7,741			118,119			15,825,196			(15,791,666	)		350,629
Other revenue		3,293,325			18,618			-			916,472			-			-			4,228,415
Total segment revenue		3,309,187			574,602,457			7,741			390,025,738			37,019,558			(311,906,672	)		693,058,009
Cost of sales and operating expenses		-			516,349,148			-			359,622,975			-			(273,988,691	)		601,983,432
Administrative, professional and general expenses		7,111,918			9,900,754			7,107,900			12,910,852			29,241,213			(21,379,162	)		44,893,475
Derivative gain		-			(1,008,585	)		-			-			-			-			(1,008,585	)
Foreign exchange loss/(gain)		1,304,072			3,789,685			(41,053	)		(831,891	)		(915,430	)		-			3,305,383
Gain on sale of exploration assets		(7,364,468	)		-			-			-			-			-			(7,364,468	)
Loss on extinguishment of IPI liability		31,710,027			-			-			-			-			-			31,710,027
Exploration costs, excluding exploration impairment		208,694			-			-			-			-			-			208,694
Depreciation and amortisation		538,551			10,931,886			56,996			2,649,715			274,596			(129,969	)		14,321,775
Interest expense		9,334,719			7,149,584			1,218,258			4,130,250			3,952,132			(15,791,666	)		9,993,277
Total segment expenses		42,843,513			547,112,472			8,342,101			378,481,901			32,552,511			(311,289,488	)		698,043,010
Income/(loss) before income taxes and non-controlling interest		(39,534,326	)		27,489,985			(8,334,360	)		11,543,837			4,467,047			(617,184	)		(4,985,001	)
Income tax benefit/(expense)		-			14,316,055			(54,670	)		(3,026,953	)		(158,443	)		-			11,075,989
Non controlling interest		-			-			-			-			-			(8,361	)		(8,361	)
Total net income/(loss)		(39,534,326	)		41,806,040			(8,389,030	)		8,516,884			4,308,604			(625,545	)		6,082,627
Total assets		202,296,520			286,827,021			10,647,678			110,986,705			603,881,348			(582,885,540	)		631,753,732

 Consolidated Financial Statements   INTEROIL CORPORATION    25

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

4. Segmented financial information (cont’d)

Year ended December 31, 2008	Upstream			Midstream - Refining			Midstream - Liquefaction			Downstream			Corporate			Consolidation adjustments			Total
Revenues from external customers		-			358,895,683			-			556,683,026			-			-			915,578,709
Intersegment revenues		-			427,218,086			-			185,474			24,567,895			(451,971,455	)		-
Interest revenue		190,195			78,023			90,757			17,566			10,302,959			(9,747,715	)		931,785
Other revenue		2,507,499			11,623			-			697,323			-			-			3,216,445
Total segment revenue		2,697,694			786,203,415			90,757			557,583,389			34,870,854			(461,719,170	)		919,726,939
Cost of sales and operating expenses		-			779,831,893			-			536,919,622			-			(428,128,406	)		888,623,109
Administrative, professional and general expenses		5,919,528			10,080,835			7,022,363			14,669,401			33,752,746			(24,753,366	)		46,691,507
Derivative (gain)/loss		-			(24,038,550	)		-			-			-			-			(24,038,550	)
Foreign exchange (gain)/loss		132,874			(5,263,901	)		559,793			206,614			486,470			-			(3,878,150	)
Gain on sale of exploration assets		(11,235,084	)		-			-			-			-			-			(11,235,084	)
Exploration costs, excluding exploration impairment		995,532			-			-			-			-			-			995,532
Exploration impairment		107,788			-			-			-			-			-			107,788
Depreciation and amortisation		597,343			10,969,099			69,142			2,570,503			66,427			(129,968	)		14,142,546
Interest expense		4,027,223			9,908,268			240,782			4,838,094			10,765,759			(9,747,715	)		20,032,411
Total segment expenses		545,204			781,487,644			7,892,080			559,204,234			45,071,402			(462,759,455	)		931,441,109
Income/(loss) before income taxes and non-controlling interest		2,152,490			4,715,771			(7,801,323	)		(1,620,845	)		(10,200,548	)		1,040,285			(11,714,170	)
Income tax expense		-			-			(110,037	)		414,193			(386,120	)		-			(81,964	)
Non controlling interest		-			-			-			-			-			(943	)		(943	)
Total net income/(loss)		2,152,490			4,715,771			(7,911,360	)		(1,206,652	)		(10,586,668	)		1,039,342			(11,797,077	)
Total assets		134,485,386			326,007,879			7,269,000			100,452,756			442,464,921			(418,836,972	)		591,842,970

Year ended December 31, 2007	Upstream			Midstream - Refining			Midstream - Liquefaction			Downstream			Corporate			Consolidation adjustments			Total
Revenues from external customers		-			233,868,997			-			391,657,071			-			-			625,526,068
Intersegment revenues		-			289,947,580			-			81,062			9,482,002			(299,510,644	)		-
Interest revenue		407,348			69,721			41,215			13,679			15,093,044			(13,444,722	)		2,180,285
Other revenue		2,139,336			-			-			527,554			-			-			2,666,890
Total segment revenue		2,546,684			523,886,298			41,215			392,279,366			24,575,046			(312,955,366	)		630,373,243
Cost of sales and operating expenses		-			495,058,782			-			368,803,507			-			(290,252,848	)		573,609,441
Administrative, professional and general expenses		5,020,371			9,077,365			5,688,932			10,774,921			20,276,009			(9,563,067	)		41,274,531
Derivative (gain)/loss		-			7,271,693			-			-			-			-			7,271,693
Foreign exchange (gain)/loss		622,821			(5,889,324	)		19,954			(15,379	)		183,591			-			(5,078,337	)
Gain on LNG shareholder agreement		-			-			-			-			(6,553,080	)		-			(6,553,080	)
Exploration costs, excluding exploration impairment		13,305,437			-			-			-			-			-			13,305,437
Exploration impairment		1,242,606			-			-			-			-			-			1,242,606
Depreciation and amortisation		482,448			10,404,953			15,431			2,204,782			48,037			(131,393	)		13,024,258
Interest expense		1,033,661			16,798,634			105,304			4,437,994			11,074,173			(13,444,723	)		20,005,043
Total segment expenses		21,707,344			532,722,103			5,829,621			386,205,825			25,028,730			(313,392,031	)		658,101,592
(Loss)/income before income taxes and non-controlling interest		(19,160,660	)		(8,835,805	)		(5,788,406	)		6,073,541			(453,684	)		436,665			(27,728,349	)
Income tax expense		-			-			(12,665	)		(1,365,674	)		171,447			-			(1,206,892	)
Non controlling interest		-			20,899			-			-			-			1,434			22,333
Total net income/(loss)		(19,160,660	)		(8,814,906	)		(5,801,071	)		4,707,867			(282,237	)		438,099			(28,912,908	)
Total assets		100,054,671			318,454,252			6,595,722			133,598,054			494,852,295			(515,739,993	)		537,815,001

Consolidated Financial Statements   INTEROIL CORPORATION    26

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

 

5. Cash and cash equivalents

The components of cash and cash equivalents are as follows:

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Cash on deposit		46,449,819		46,761,362		43,861,762
Bank term deposits
- Papua New Guinea kina deposits		-		2,209,210		-
		46,449,819		48,970,572		43,861,762

In 2009, cash and cash equivalents earned an average interest rate of 0.57% per annum (2008 – 3.21%, 2007 – 4.76%).

6. Supplemental cash flow information

	Year ended
	December 31,			December 31,		December 31,
	2009			2008		2007
	$			$		$
Cash paid during the year
Interest		5,192,882			10,705,499		16,934,058
Income taxes		1,889,441			6,738,175		2,344,282
Interest received		349,082			926,878		2,176,678
Non-cash investing activities:
Fair value adjustment on IPL PNG Ltd. Acquisition		-			-		(367,955	)
Decrease in plant and equipment as a result of impairment		-			-		960,000
Reduction to plant and equipment due to negative goodwill on Enron buy-back		-			-		4,841,776
(Decrease)/increase in deferred gain on contributions to LNG project		(4,420,838	)		8,400,573		9,096,537
Increase in goodwill on acquisition of additional LNG interest		864,377			-		-
Increase in share capital from:
buyback of Merrill Lynch interest in LNG Project		11,250,000			-		-
buyback of minority interest		-			-		496,500
Non-cash financing activities:
Decrease in deferred liquefaction project liability		-			-		(6,553,080	)
Increase in share capital from:
the exercise of share options		2,185,642			456,867		102,840
the exercise of warrants		1,899,476			-		18,818
buyback of IPI #3 investor rights		62,980,161			-		-
conversion of debentures into share capital		77,089,723			15,118,483		-
conversion of preference shares into share capital		-			14,640,000		-
conversion of indirect participation interest into share capital		-			15,776,270		934,890
conversion of debt into share capital		-			60,000,000		-
placement fee obligation on conversion of debt		-			1,800,000		-
preference share interest obligation settled in shares		-			372,950		-
placement fee obligation on debentures issued		-			5,700,000		-
debentures interest obligation settled in shares		2,352,084			2,620,628		-

7. Financial instruments

Cash and cash equivalents

With the exception of cash and cash equivalents and restricted cash, all financial assets are non-interest bearing.  In 2009, the Company earned nil interest (2008 – 1.9%, 2007 – 5.0%) on the cash on deposit which related to the working capital facility.  However, the cash deposit relating to the BNP working capital facility reduced the interest costs relating to the facility usage in 2009 by 3.07% (2008 – 4.15%, 2007 – 3.10%).

Consolidated Financial Statements   INTEROIL CORPORATION    27

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

7. Financial instruments (cont’d)

Cash restricted, which mainly relates to the working capital facility, is comprised of the following:

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Cash deposit on working capital facility (0.0%)		22,698,829		25,994,258		20,240,553
Debt reserve for secured loan		-		-		1,761,749
Cash restricted - Current		22,698,829		25,994,258		22,002,302
Bank term deposits on Petroleum Prospecting Licenses (2.2%)		124,858		124,097		116,090
Cash deposit on office premises (3.0%)		157,698		166,685		265,968
Cash deposit on secured loan (0.0%)		6,327,190		-		-
Cash restricted - Non-current		6,609,746		290,782		382,058
		29,308,575		26,285,040		22,384,360

Cash held as deposit on the BNP working capital facility supports the Company’s working capital facility with BNP Paribas.  The balance is based on 20% of the outstanding balance of the BNP working capital facility 1 (refer note 16) plus any amounts that are fully cash secured.  The cash deposit on this facility did not receive interest during the year as these deposit amounts reduced the interest being charged by BNP on the facility utilization.

The cash held as deposit on secured loan is used to support the Company’s secured loan borrowings with the Overseas Private Investment Corporation (“OPIC”) and relates to one half yearly installment of $4.5 million and the related interest that will be payable with the next installment.  The waiver on this deposit requirement expired in June 2009 with the completion of the capital raising of $70.4 million.

Debt reserve for secured loan in 2007 was maintained in accordance to the terms of the Merrill Lynch bridging facility.  This facility was fully repaid in May 2008 removing the requirement to maintain any funds in the debt reserve account.

Bank term deposits on Petroleum Prospecting Licenses are unavailable for use while Petroleum Prospecting Licenses 236, 237 and 238 are being utilized by the Company.

Commodity derivative contracts

InterOil uses derivative commodity instruments to manage its exposure to price volatility on a portion of its refined product and crude inventories.

At December 31, 2009, InterOil had a net receivable of $nil (2008 – $31,335,050, 2007 – payable of $1,960,300) relating to commodity hedge contracts.  Of this total, a receivable of $nil (2008 - $16,261,000, 2007 - $nil) relates to hedge accounted contracts as at December 31, 2009 and a receivable of $nil (2008 – $15,074,050, 2007 – payable of $1,960,300) relates to outstanding derivative contracts for which hedge accounting was not applied or had been discontinued.  The gain on hedges for which final pricing will be determined in future periods was $nil (2008 - $18,012,500, 2007 - $nil) and has been included in comprehensive income.

a. Hedge accounted contracts:

There were no outstanding hedge accounted contracts on which final pricing were to be determined in future periods as at December 31, 2009.

Consolidated Financial Statements   INTEROIL CORPORATION    28

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

7. Financial instruments (cont’d)

The following summarizes the effective hedge contracts by derivative type on which final pricing was determined in future periods as at December 31, 2008:

		Notional				Fair Value
		Volumes				December 31, 2008
Derivative	Type	(bbls)		Expiry	Derivative type	$
Crude Swap	Buy Brent		300,000	Q1 2009	Cash flow hedge - Manages the crack spread		(25,493,100	)
Crude Swap	Buy Brent		300,000	Q2 2009	Cash flow hedge - Manages the crack spread		(19,529,200	)
Crude Swap	Buy Brent		300,000	Q3 2009	Cash flow hedge - Manages the crack spread		(18,441,700	)
Crude Swap	Buy Brent		300,000	Q4 2009	Cash flow hedge - Manages the crack spread		(17,682,200	)
Gasoil Swap	Sell Gasoil		300,000	Q1 2009	Cash flow hedge - Manages the crack spread		29,068,800
Gasoil Swap	Sell Gasoil		300,000	Q2 2009	Cash flow hedge - Manages the crack spread		23,425,400
Gasoil Swap	Sell Gasoil		300,000	Q3 2009	Cash flow hedge - Manages the crack spread		22,461,200
Gasoil Swap	Sell Gasoil		300,000	Q4 2009	Cash flow hedge - Manages the crack spread		21,672,800
							15,482,000
Add: Priced out but unsettled hedge accounted contracts as at December 31, 2008							779,000
							16,261,000

There were no outstanding hedge accounted contracts on which final pricing were to be determined in future periods as at December 31, 2007.

A profit of $17,180,700 was recognized from effective portion of priced out hedge accounted contracts for the year ended December 31, 2009 (Dec 2008 – $3,745,500, Dec 2007 – loss of $2,527,648).

b. Non-hedge accounted derivative contracts:

As at December 31, 2009, there were no outstanding non-hedge accounted derivative contracts.

As at December 31, 2008 the Company had the following open non-hedge accounted derivative contracts outstanding:

		Notional				Fair Value
		Volumes				December 31, 2008
Derivative	Type	(bbls)		Expiry	Derivative type	$
Brent Swap	Sell Brent		195,000	Q1 2009	Cash flow hedge - Manages the export price risk of LSWR		3,965,000
Brent Swap	Buy Brent		130,000	Q1 2009	Cash flow hedge - Manages the export price risk of LSWR		(1,129,750	)
Brent Swap	Sell Brent		165,000	Q2 2009	Cash flow hedge - Manages the export price risk of LSWR		(413,200	)
							2,422,050
Add: Priced out non-hedge accounted contracts as at December 31, 2008							12,652,000
							15,074,050

As at December 31, 2007 the Company had the following open non-hedge accounted derivative contracts outstanding:

Derivative	Type	Notional volumes (bbls)
Brent contracts to manage export price risk	Sell Brent		130,000
Naphtha swap	Sell Naphtha		150,000

Any gains/losses on these contracts are disclosed separately in the statement of operations for the period.

A profit of $658,785 was recognized on the non-hedge accounted derivative contracts for the year ended December 31, 2009 (Dec 2008 – $25,669,050, Dec 2007 – loss of $7,271,693).

Consolidated Financial Statements INTEROIL CORPORATION  29

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

8. Trade receivables

InterOil has a discounting facility with BNP Paribas on specific monetary receivables under which the Company is able to sell, on a revolving basis, receivables up to $60,000,000 (refer to note 16).  As at December 31, 2009, $nil (Dec 2008 - $3,141,238, Dec 2007 - $nil) in outstanding trade receivables had been sold with recourse under the facility.  As the sale is with recourse, the discounted receivables, if any, are retained on the balance sheet and included in the accounts receivable and the sale proceeds are recognized in the working capital facility.  The Company has retained the responsibility for administering and collecting accounts receivable sold.  The discounted receivables are usually settled within a month of their discounting and there have not been any collection issues relating to these discounted receivables.

At December 31, 2009, $17,351,783 (Dec 2008 - $10,300,542, Dec 2007 - $38,033,715) of the trade receivables secures the BNP Paribas working capital facility disclosed in note 16.  This balance includes $12,715,464 (Dec 2008 - $6,912,883, Dec 2007 - $33,703,069) of intercompany receivables which were eliminated on consolidation.

9. Inventories

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Midstream - Refining (crude oil feedstock)		5,006,608		25,556,463		3,587,786
Midstream - Refining (refined petroleum product)		32,983,010		30,167,417		43,173,806
Midstream - Refining (parts inventory)		559,667		288,643		201,526
Downstream (refined petroleum product)		31,577,764		27,024,803		35,626,124
		70,127,049		83,037,326		82,589,242

At December 31, 2009 and December 31, 2008, inventory had been written down to its net realizable value.  The write down of $140,278 at December 31, 2009 relating to crude oil feedstock and $8,529,016 at December 31, 2008 relating to refined petroleum products is included in ‘Cost of sales and operating expenses’ within the ‘Consolidated Statement of Operations’.  No write down was necessary at December 31, 2007.

At December 31, 2009, $38,549,285 (Dec 2008 - $56,012,523, Dec 2007 - $46,963,118) of the Midstream Refining inventory balance secures the BNP Paribas working capital facility disclosed in note 16.

Inventories recognized as expense during the year ended December 31, 2009 amounted to $616,305,207 (2008 - $902,765,655, 2007 - $586,633,699).

10. Plant and equipment

The majority of the Company’s plant and equipment is located in Papua New Guinea, except for items in the corporate segment with a net book value of $143,947 (2008 - $343,069, 2007 - $313,946) which are located in Australia and Singapore.  Amounts in deferred project costs and work in progress are not being amortized.

Consolidation entries relates to Midstream Refining assets which were created when the gross margin on Midstream Refining sales to the Downstream segment were eliminated in the development stage of the refinery.

December 31, 2009	Upstream			Midstream - Refining			Midstream - Liquefaction			Downstream			Corporate & Consolidated			Totals
Plant and equipment		47,315			248,863,701			97,572			47,647,154			561,038			297,216,780
Deferred project costs and work in progress		-			926,089			2,252,060			5,308,056			2,381,493			10,867,698
Consolidation entries		-			-			-			-			(2,599,361	)		(2,599,361	)
Accumulated depreciation and amortisation		(47,037	)		(54,715,462	)		(36,164	)		(29,222,654	)		(417,091	)		(84,438,408	)
Net book value		278			195,074,328			2,313,468			23,732,556			(73,921	)		221,046,709
Capital expenditure for year ended December 31, 2009		-			2,242,017			-			6,919,197			2,456,903			11,618,117

Consolidated Financial Statements INTEROIL CORPORATION  30

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)  

10. Plant and equipment (cont’d)

December 31, 2008	Upstream			Midstream - Refining			Midstream - Liquefaction			Downstream			Corporate & Consolidated			Totals
Plant and equipment		47,315			247,520,562			219,315			46,299,775			485,628			294,572,595
Deferred project costs and work in progress		-			27,211			2,134,858			1,979,253			-			4,141,322
Consolidation entries		-			-			-			-			(2,729,327	)		(2,729,327	)
Accumulated depreciation and amortisation		(43,568	)		(43,768,810	)		(80,554	)		(28,363,540	)		(142,559	)		(72,399,031	)
Net book value		3,747			203,778,963			2,273,619			19,915,488			(2,386,258	)		223,585,559
Capital expenditure for year ended December 31, 2008		-			529,033			92,494			4,108,630			95,493			4,825,651

December 31, 2007	Upstream			Midstream - Refining			Midstream - Liquefaction			Downstream			Corporate & Consolidated			Totals
Plant and equipment		1,247,201			246,561,648			140,051			42,709,718			390,135			291,048,753
Deferred project costs and work in progress		-			457,092			2,622,735			3,405,625			-			6,485,452
Consolidation entries		-			-			-			-			(2,859,295	)		(2,859,295	)
Accumulated depreciation and amortisation		(1,193,374	)		(32,799,711	)		(15,431	)		(27,737,982	)		(76,190	)		(61,822,688	)
Net book value		53,827			214,219,029			2,747,355			18,377,361			(2,545,350	)		232,852,222
Capital expenditure for year ended December 31, 2007		-			777,962			2,777,112			5,200,427			243,338			8,998,839

During the year ended December 31, 2009, InterOil recognized a gain of $nil on the disposal of assets (2008 – gain of $285,206, 2007 – loss of $269,320).

During the year 2007, there was a reduction to plant and equipment in Midstream – Refining of $4,841,776 due to negative goodwill on buyback of non controlling interest (refer note 21).

During the year 2007, InterOil booked an impairment loss of $960,000 on a barge owned by the Company.  The sale of the barge was completed in the first quarter of 2008.  This impairment loss is included in office and administrative expenses in the statement of operations.

11. Oil and gas properties

Costs of oil and gas properties which are not subject to depletion are as follows:

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Drilling equipment		17,344,759		13,857,772		14,664,179
Drilling consumables and spares		11,467,237		10,113,808		7,661,992
Petroleum Prospecting License drilling programs (Unproved)		143,671,566		104,042,379		62,538,956
Gross Capitalized Costs		172,483,562		128,013,959		84,865,127
Accumulated depletion and amortization
Unproved oil and gas properties		-		-		-
Proved oil and gas properties		-		-		-
Net Capitalized Costs		172,483,562		128,013,959		84,865,127

Consolidated Financial Statements INTEROIL CORPORATION  31

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

11. Oil and gas properties (cont’d)

The following table discloses a breakdown of the exploration costs incurred for the periods ended:

	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Property Acquisition Costs
Unproved		-			-			-
Proved		-			-			-
Total acquisition costs		-			-			-
Exploration Costs		(85,793	)		9,622,780			327,154
Development Costs		99,678,973			52,491,537			54,178,386
Add: Amounts capitalized in relation to the appraisal program cash calls on IPI interest buyback transactions		8,013,434			-			-
Less: Conveyance accounting offset against properties		(31,837,809	)		(5,798,347	)		-
Less: Costs allocated against cash calls		(31,299,202	)		(13,167,138	)		(17,164,760	)
Less: Insurance premium proceeds		-			-			(7,000,000	)
Total Costs capitalized		44,469,603			43,148,832			30,340,780
Charged to expense
Dry hole expense		-			107,788			1,242,606
Geophysical and other costs		208,694			995,532			13,305,437
Total charged to expense		208,694			1,103,320			14,548,043
Property Additions		44,678,297			44,252,152			44,888,823

The following table discloses a breakdown of the gain realized on sale of oil and gas properties for the periods ended:

	Year ended
	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Gain on sale of oil and gas properties
Sale of PRL 4 interest (43.13% of the property)		-		1,500,000		-
Sale of PRL 5 interest (28.576% of the property)		-		5,000,000		-
Conveyance accounting of IPI Agreement (note 20)		7,364,468		4,735,084		-
		7,364,468		11,235,084		-

During the prior year ended December 31, 2008, the Company divested fully its interests in Petroleum Retention Licenses 4 and 5 in Papua New Guinea.  As these properties did not have any cost base associated with them in the balance sheet, the entire sale proceeds was treated as a gain on sale of these properties.

Since the date of the IPI Agreement in February 2005 up to the quarter ended December 31, 2009, certain IPI investors’ with a combined 12.635% interest out of the remaining 16.589% IPI interest in the eight well drilling program have waived their right to convert their IPI percentage into 1,684,667 common shares.  These waivers or forfeitures of the conversion option have triggered conveyance under the IPI Agreement for their respective share of interest.  An amount of $7,364,468 (Dec 2008 - $4,735,084, Dec 2007 - $nil) for the year was recognized as a gain on conveyance following the guidance in ASC 932-360 paragraphs 55-8 and 55-9.  As at December 31, 2009, IPI investors with a combined 3.9536% interest out of the initial 25% still have the conversion rights outstanding.

Refer to Note 13 below for details of Petromin’s participation in the Elk and Antelope fields, and the treatment of the $10,435,000 advance received from them in relation to this participation agreement.

Pacific LNG Operations Limited (“Pacific LNG”) participation in Elk and Antelope fields

During September 2009, InterOil sold a 2.5% direct working interest in the Elk and Antelope fields to Pacific LNG in furtherance of the option granted to it on May 24, 2007.  The 2.5% direct interest these fields were sold in exchange for a net $25,000,000 (of which $15,000,000 had been received up to December 31, 2009) plus payment of historical costs incurred in exploring these fields.  In addition to these amounts, Pacific LNG also transferred to the Company 2.5% of their economic interest in the Joint Venture Company.  The total consideration received for this transaction was valued at $29,019,716, consisting of $25,000,000 cash consideration, $864,377 being the fair value of 2.5% of Pacific LNG’s economic interest in PNG LNG Inc., and $3,155,339 representing 2.5% of all appraisal costs incurred in the Elk and Antelope fields to be reimbursed.  The Company has applied the guidance in 932-360 paragraph 55-8 in relation to the sale of these unproved properties.  Based on the guidance, the sale proceeds were fully applied against the cost base of the Elk and Antelope fields as recovery of cost.

Consolidated Financial Statements INTEROIL CORPORATION  32

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

12. Income taxes

The combined income tax expense in the consolidated statements of operations reflects an effective tax rate which differs from the expected statutory rate (combined federal and provincial rates).  Differences for the years ended were accounted for as follows:

	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Loss before income taxes and non controlling interest		(4,985,001	)		(11,714,170	)		(27,728,349	)
Statutory income tax rate		34.00	%		34.50	%		35.10	%
Computed tax (benefit)		(1,694,900	)		(4,041,389	)		(9,732,650	)
Effect on income tax of:
Income/(losses) in foreign jurisdictions not assessable/(deductible)		440,552			(61,702	)		(2,481,828	)
Non-deductible stock compensation expense		521,091			720,825			2,128,100
Non-deductible pre-LNG Project Agreement costs		1,471,176			2,584,562			3,306,847
Non-deductible premium paid on buyback of IPI interest		10,781,409			-			-
Non-taxable gain on sale of exploration assets		(2,503,919	)		(3,876,104	)		-
Unrealized foreign exchange gains/(losses)		2,366,045			(14,059,228	)		2,069,183
Tax rate differential in foreign jurisdictions		(2,072,630	)		(134,619	)		720,014
Over provision for income tax in prior years		(88,681	)		148,823			(218,403	)
Midstream - Refining tax exempt income as per Refinery Project Agreement		(13,406,325	)		-			-
Tax losses for which no future tax benefit has been brought to account		2,857,963			19,569,753			5,012,598
Temporary differences for which no future tax benefit has been brought to account		7,160,543			(1,639,042	)		192,826
Temporary differences brought to account on acquisition of subsidiary		-			-			546,026
Movement in temporary differences in relation to inventory revaluations		(1,385,779	)		1,385,779			-
Initial recognition of future tax assets/liabilities based on recoverability assessment		(15,138,174	)		-			-
Other - net		(384,360	)		(515,694	)		(335,821	)
		(11,075,989	)		81,964			1,206,892

The future income tax asset comprised the tax effect of the following:

	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Future tax assets
Temporary differences
Plant and equipment		(7,870,673	)		(7,051,509	)		(8,338,671	)
Exploration expenditure		39,459,350			26,901,138			32,563,507
Unrealised foreign exchange losses / (gains)		3,162,307			(17,177,649	)		19,742,048
Other - net		2,789,832			1,820,931			1,549,740
		37,540,816			4,492,911			45,516,624
Losses carried forward		34,975,557			28,679,655			39,274,207
		72,516,373			33,172,566			84,790,831
Less valuation allowance		(55,603,404	)		(30,102,384	)		(81,923,519	)
		16,912,969			3,070,182			2,867,312

The future tax assets recorded in the consolidated balance sheet mainly relate to Midstream – Refining and Downstream assets in Papua New Guinea. The amounts are noncurrent as at December 31, 2009.  The valuation allowance for deferred tax assets increased by $25,501,020 (2008 – decreased by $51,821,135, 2007 – increased by $10,569,456) in the year ended December 31, 2009.

The increase in valuation allowance during the year was mainly due to the exchange rate movements between the reporting currency, being USD, and the local jurisdiction currencies of Canadian Dollars (CAD) and PGK, decreasing the deferred tax liabilities in relation to unrealized foreign exchange local currency gains.  The increase in investments into certain subsidiaries also moved certain unrealized foreign exchange gains into permanent differences resulting in derecognition of their related deferred tax liabilities.

Consolidated Financial Statements INTEROIL CORPORATION  33

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

12. Income taxes (cont’d)

During 2008, the parent entity in Canada elected to lodge USD tax returns in Canada which will enable that entity to prepare its tax returns in Canada in USD effective January 1, 2008.  At the time of filing the consolidated financial statements for the year ended December 31, 2008, the legislation allowing this election was not yet fully enacted and the Canadian entity’s tax calculation for the year ended December 31, 2008 was required to be prepared using the Canadian Dollars.  The legislation allowing the election was fully enacted in 2009, resulting in the adjustment to the deferred tax assets and valuation allowance of $25,676,554.  No deferred tax assets have been recognized for the Canadian entity as currently these assets does not satisfy the recognition criteria.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.  Management considers the actual levels of past taxable income, scheduled reversal of deferred tax liabilities, projected future taxable income, projected tax rates and tax planning strategies in making this assessment.

The Refinery Project Agreement gives “pioneer” status to InterOil Limited (”IOL”).  This status gives IOL a tax holiday beginning upon the date of the commencement of commercial production, January 1, 2005 and ending December 31, 2010.  In relation to the refinery, tax losses incurred prior to January 1, 2005 will be frozen during the tax holiday and will become available for use after the tax holiday ceases on December 31, 2010.  Tax losses incurred during the tax holiday will also be available for use after December 31, 2010.  Tax losses carried forward to offset against future earnings total K214,237,113 (US $79,267,732) at December 31, 2009.  All losses incurred by InterOil Limited have a twenty year carry forward period.

13. Accounts payable and accrued liabilities

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Accounts payable - crude import		-		25,233,525		-
Other accounts payable and accrued liabilities		48,937,354		48,914,211		57,162,039
Petromin cash calls received		10,435,000		4,000,000		-
Income tax payable		-		-		3,265,568
Total accounts payable and accrued liabilities		59,372,354		78,147,736		60,427,607

Petromin participation in Elk and Antelope fields

On October 30, 2008, Petromin PNG Holdings Limited (”Petromin”), a government entity mandated to invest in resource projects on behalf of the Independent State of Papua New Guinea (“the State”), entered into an agreement to take a 20.5% direct interest in the Elk and Antelope fields if nominated by the State to take its legislative interest.  Such nomination occurred in 2009.  Petromin contributed an initial deposit and agreed to conditionally fund 20.5% of the costs of developing these fields.  The State’s (and Petromin’s) right to take an interest arises upon issuance of the Prospecting Development Licence (”PDL”), which has not yet occurred.  The obligation to fund its portion of the costs of developing the field, including sunk costs, also applies upon issuance of the PDL.  As at December 31, 2009, $10,435,000 advance payment received from Petromin has been held under ‘Petromin cash calls received’ above.  Once the PDL is formed, conveyance accounting following the guidance in ASC 932-360 paragraphs 55-8 and 55-9 will be triggered.

14. Deferred gain on contributions to LNG Project

As noted under Note 2(c) above, on July 30, 2007, a Shareholders’ Agreement was signed between InterOil LNG Holdings Inc., Pacific LNG Operations Ltd., Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc.. As part of the Shareholders’ Agreement, five ‘A’ Class shares were issued by PNG LNG Inc. with full voting rights with each share controlling one board position.  Two ‘A’ Class shares were owned by InterOil LNG Holdings Inc., two by Merrill Lynch Commodities (Europe) Limited, and one by Pacific LNG Operations Ltd.  All key operational matters require ‘Unanimous’ or ‘Super-majority’ Board resolution which confirms that none of the joint ventures is in a position to exercise unilateral control over the joint venture.

On February 27, 2009, InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd, acquired Merrill Lynch’s interest in the Joint Venture Company. InterOil issued 499,834 common shares valued at $11,250,000 for its share of the settlement. After the completion of this transaction, Merrill Lynch did not retain any ownership or other interest in the PNG LNG project.  The two ‘A’ Class shares held by Merrill Lynch have been transferred to InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd respectively.

Consolidated Financial Statements INTEROIL CORPORATION  34

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

14. Deferred gain on contributions to LNG Project (cont’d)

A further 172 ‘A’ Class shares have been issued to InterOil LNG Holdings Inc. and 173 ‘A’ Class shares have been issued to Pacific LNG Operations Ltd bringing the ‘A’ Class shareholding of both remaining joint venture partners to 175 ‘A’ Class shares each, giving equal voting rights and board positions in the joint venture.

As part of the Shareholders’ Agreement on July 30, 2007, InterOil was also provided with ‘B’ Class shares in the Joint Venture Company with a fair value of $100,000,000 in recognition of its contribution to the LNG Project at the time of signing the Shareholders’ Agreement.  The main items contributed by InterOil into the Joint Venture Company were infrastructure developed by InterOil near the proposed LNG site at Napa Napa, stakeholder relations within Papua New Guinea, general supply agreements secured with landowners for supply of gas, advanced stage of project development, etc.  Fair value was determined based on the agreement between the independent joint venture partners.

The other Joint Venture partner is being issued ‘B’ Class shares as it contributes cash into the Joint Venture Company by way of cash calls.

During September 2009, as part of acquisition by Pacific LNG of a 2.5% direct working interest in the Elk and Antelope fields, Pacific LNG transferred to InterOil 2.5% of Pacific LNG’s unexercised economic interest in the joint venture LNG Project. Based on this transaction, as at December 31, 2009, InterOil and Pacific LNG hold 52.5% and 47.5% economic interest respectively in the LNG project, subject to the exercise of all their rights to the ‘B’ Class shares on payment of cash calls.

To date InterOil has a recognized deferred gain on its contributions to the Joint Venture based on the share of other joint venture partners in the project. As InterOil’s shareholding within the Joint Venture Company as at December 31, 2009 is 86.66% (Dec 2008 – 82.15%, Dec 2007 – 90.72%), the gain on contribution of non cash assets to the project by InterOil relating to other joint venture partners’ shareholding (13.34% - amounting to $13,076,272) has been recognized by InterOil in its balance sheet as a deferred gain. This deferred gain will increase/decrease as the other Joint Venture partners increase/decrease their shareholding in the project.  The gain has been deferred in accordance with the principles of proportionate consolidation as per CICA 3055 – ‘Interests in Joint Ventures’ and will be taken to income based on the value to be obtained from their use by the Joint Venture Company in the future.  The intangible assets of the Joint Venture Company, contributed by InterOil, have been eliminated on proportionate consolidation of the joint venture balances.

15. Goodwill

Acquisition of interest from Merrill Lynch

As noted above in note 14, On February 27, 2009, InterOil LNG Holdings Inc. acquired half of Merrill Lynch’s interest in the Joint Venture Company for $11,250,000.  As part of the acquisition, InterOil LNG Holdings Inc. was transferred 548,806 ‘B’ Class shares held by Merrill Lynch.  The amount recognized as goodwill of $5,761,940 represents the amount of purchase consideration paid to Merrill Lynch over and above the fair value of the identifiable net assets acquired.

Acquisition of interest from Pacific LNG

During September 2009, InterOil also acquired a further 2.5% of Pacific LNG’s economic interest in the joint venture LNG Project from Pacific LNG as part of the Elk and Antelope interest acquisition.  The fair value of 2.5% of Pacific LNG’s economic interest in the joint venture LNG Project was valued at $864,377 based on the previous transaction with Merrill Lynch that was completed in February 2009, being the most appropriate guide to the fair value of the interest acquired.  This fair value has been recognized as goodwill on acquisition of the LNG interest in the Balance Sheet.

16. Working capital facilities

	December 31,		December 31,		December 31,
Amounts drawn down	2009		2008		2007
	$		$		$
BNP Paribas working capital facility - midstream		16,794,153		53,386,775		66,501,372
Westpac working capital facility - downstream		7,832,266		15,405,627		-
BSP working capital facility - downstream		-		-		-
Total working capital facility		24,626,419		68,792,402		66,501,372

Consolidated Financial Statements INTEROIL CORPORATION  35

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

16. Working capital facility (cont’d)

BNP Paribas working capital facility

InterOil has a working capital credit facility with BNP Paribas (Singapore branch) with a maximum availability of $190,000,000.  The total facility is split into Facility 1 and Facility 2 as per the agreement with BNP Paribas.  Facility 1 is for $130,000,000 for the issuance of documentary letters of credit and or standby letters of credit, short term advances, advances on merchandise, freight loans, receivables financing and a sublimit of Euro 18,000,000 or USD equivalent for hedging transactions via BNP Paribas Commodity Indexed Transaction Group or other acceptable counter parties.

Facility 2 is for $60,000,000 partly cash-secured short term advances and for discounting of any monetary receivables (note 8) acceptable to BNP Paribas. The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables.

The total facility is renewable annually and as part of the current year renewal process which was completed in the quarter ended December 31, 2009, the facility was renewed for a period of fifteen months until December 31, 2010.

The facility bears interest at LIBOR + 3.5% on the short term advances.  During the year the weighted average interest rate was 2.13% (2008 – 5.11%, 2007 – 7.01%) after considering the reduction in interest due to the deposit amounts maintained which reduces the interest being charged on the facility utilization (refer section ‘Cash and cash equivalents’ under note 7).

The following table outlines the facility and the amount available for use at year end:

	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Working capital credit facility		190,000,000			190,000,000			170,000,000
Less amounts included in the working capital facility liability:
Short term advances/facilities drawn down		(16,794,153	)		(50,245,537	)		(66,501,372	)
Discounted receivables (note 8)		-			(3,141,238	)		-
		(16,794,153	)		(53,386,775	)		(66,501,372	)
Less: other amounts outstanding under the facility:
Letters of credit outstanding		(56,700,000	)		(27,600,000	)		(32,000,000	)
Bank guarantees on hedging facility		-			-			(2,500,000	)
Working capital credit facility available for use		116,505,847			109,013,225			68,998,628

At December 31, 2009, the company had one letter of credit outstanding for $56,700,000. The letter of credit was for a crude cargo and was drawn down on January 25, 2010.

The cash deposit on working capital facility, as separately disclosed in note 7, included restricted cash of $22,698,829 (2008 - $25,994,258, 2007 - $20,240,553) which is being maintained as a security margin for the facility.  In addition, inventory of $38,549,285 (2008 - $56,012,523, 2007 - $46,963,118) and trade receivables of $17,351,783 (2008 – $10,300,542, 2007 – $38,033,715) also secured the facility.  The trade receivable balance securing the facility includes $12,715,464 (2008 - $6,912,883, 2007 - $33,703,069) of inter-company receivables which were eliminated on consolidation.

Westpac and Bank South Pacific working capital facility

The Company has an approximately $48,100,000 (PGK 130,000,000) revolving working capital facility for its Downstream operations in Papua New Guinea from Bank of South Pacific Limited and Westpac Bank PNG Limited. Westpac facility limit is approximately $29,600,000 (PGK 80,000,000) and the initial BSP facility limit was approximately $25,900,000 (PGK 70,000,000) but was renewed in October 2009 at a lower limit of approximately $18,500,000 (PGK 50,000,000).  The Westpac facility is for an initial term of three years and is due for renewal in October 2011. The BSP facility is renewable annually and is due for renewal in October 2010.  As at December 31, 2009 only $7,832,266 (PGK 21,168,287) of this combined facility has been utilized, and the remaining facility of 40,267,734 (PGK 108,831,713) remains available for use.  These facilities are secured by a fixed and floating charge over the assets and liabilities of Downstream operations.

Consolidated Financial Statements INTEROIL CORPORATION  36

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

17. Establishment of subsidiaries

InterOil Finance Inc

In December 2009, InterOil Finance Inc. was incorporated as a 100% subsidiary of InterOil Corporation in Barbados to evaluate potential financing arrangements.  The Company had not undertaken any activities during 2009.

InterOil Singapore Pte Ltd

In May 2009, InterOil Singapore Pte Ltd was incorporated as a 100% subsidiary of InterOil Corporation to facilitate the operation of the LNG Project in Papua New Guinea.  All costs incurred by this entity will be recharged to the LNG joint venture and relevant InterOil entities based on an equitable driver basis.

InterOil New York Inc

In April 2008, InterOil New York Inc. was incorporated as a 100% subsidiary of InterOil Corporation to evaluate potential financing arrangements in the U.S.  The Company had not undertaken any activities since incorporation.

InterOil LNG Holdings Inc.

In June 2007, InterOil LNG Holdings Inc. was incorporated as a holding company of InterOil’s investment in PNG LNG Inc.  InterOil LNG Holdings Inc. is a 100% subsidiary of InterOil Corporation.  During July 2007, the investment in PNG LNG Inc. was transferred from InterOil Corporation to InterOil LNG Holdings Inc.

18. Related parties

Petroleum Independent and Exploration Corporation (“P.I.E”)

P.I.E is controlled by Phil Mulacek, an officer and director of InterOil and acts as a sponsor of the Company's oil refinery project.  Articles of association of SPI InterOil LDC (“SPI”) provide for the business and affairs of the entity to be managed by a general manager appointed by the shareholders of SPI and its U.S. sponsor under the Overseas Private Investment Corporation (“OPIC” - which is an agency of the U.S. Government) loan agreement.  SPI does not have a Board of Directors, instead P.I.E has been appointed as the general manager of SPI.  Under the laws of the Commonwealth of The Bahamas, the general manager exercises all powers which would typically be exercised by a Board of Directors, being those which are not required by laws or by SPI’s constituting documents to be exercised by the members (shareholders) of SPI.  InterOil is the majority shareholder of SPI and therefore has the power to appoint the general manager.

During the year, $150,000 (2008 - $150,000, 2007 - $150,000) was expensed for the sponsor's legal, accounting and reporting costs.  Of these costs, $nil (2008 - $150,000, 2007 - $150,000) were included in accrued liabilities at December 31, 2009.

Breckland Limited

This entity is controlled by Roger Grundy, a director of InterOil, and provides technical and advisory services to the Company on normal commercial terms.  Amounts paid or payable to Breckland for technical services during the year amounted to $nil (2008 - $nil, 2007 - $39,416).

Director fees

Amounts due to Directors at December 31, 2009 totaled $26,000 for Directors fees (2008 - $27,750, 2007 - $nil).  These amounts are included in accounts payable and accrued liabilities.  An amount of $117,583 (2008 - $120,000, 2007 - - $130,000) was paid or payable to the Directors for Directors fees during the year.

BNP Paribas

One of our Directors, Edward Speal, is the Managing Director of BNP Paribas (New York).  InterOil has a working capital facility with BNP Paribas (Singapore) of $190,000,000 (as per note 16) - Management does not consider this to be a related party transaction as Mr Speal does not have the ability to exercise, directly or indirectly, control, joint control or significant influence over BNP (Singapore).  BNP (Singapore) also advices the Company on the asset sell down process that is currently underway in relation to a portion of our Upstream and Midstream Liquefaction interests.

 Consolidated Financial Statements INTEROIL CORPORATION  37

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

19. Secured loan

	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Secured loan (OPIC)  - current portion		9,000,000			9,000,000			9,000,000
Secured loan (bridging facility) - current portion		-			-			127,810,093
Secured loan (bridging facility) - deferred financing costs		-			-			(33,333	)
Total current secured loan		9,000,000			9,000,000			136,776,760
Secured loan (OPIC)  - non current portion		44,500,000			53,500,000			62,500,000
Secured loan (OPIC)  - deferred financing costs		(910,722	)		(1,134,667	)		(1,358,611	)
Total non current secured loan		43,589,278			52,365,333			61,141,389
Total secured loan		52,589,278			61,365,333			197,918,149

OPIC Secured Loan

On June 12, 2001, the Company entered into a loan agreement with OPIC to secure a project financing facility of $85,000,000.  The loan agreement was last amended under which the half yearly principal payments of $4,500,000 due in December 2006 and June 2007 each were deferred to the end of the loan agreement, being June 30, 2015 and December 31, 2015.  The loan is secured over the assets of the refinery project which have a carrying value of $195,074,328 at December 31, 2009 (2008 - $203,778,963, 2007 - $214,219,029).

The interest rate on the loan is equal to the treasury cost applicable to each promissory note (at the date of draw down) outstanding plus the OPIC spread (3%).  During 2009 the weighted average interest rate was 6.89% (2008 – 7.10%, 2007 - 7.10%) and the total interest expense included in long term borrowing costs was $4,125,170 (2008 - $5,147,768, 2007 - $5,339,500).

As at December 31, 2009, two installment payments amounting to $4,500,000 each which will be due for payment on June 30, 2010 and December 31, 2010 have been classified into the current portion of the liability.  The agreement contains certain financial covenants which include the maintenance of minimum levels of tangible net worth and limitations on the incurrence of additional indebtedness.  A deposit is also required to be maintained to cover the next installment and interest payment.  As of December 31, 2009, the company was in compliance with all applicable covenants.

Deferred financing costs relating to the OPIC loan of $910,722 (2008 - $1,134,667, 2007 - $1,358,611) are being amortized over the period until December 2014 and has been offset against the long term liability in compliance with CICA 3855 Financial Instruments and are being amortized using the effective interest method.

Bank covenants under the above facility currently restrict the payment of dividends by the Company.

Bridging Facility

InterOil entered into a loan agreement for $130,000,000 on May 3, 2006 with Merrill Lynch.  On May 6, 2008, $60,000,000 of the $130,000,000 facility was converted into common shares at a price of $22.65 per share.  On May 12, 2008 the remaining $70,000,000 of the bridging facility was repaid from the proceeds of 8% subordinated convertible debentures (refer note 24).

The interest rate on the loan was 4% per annum over the life of the loan as the conditions for maintaining the discounted interest rate, i.e., signing of a definitive LNG/NGL Project Agreement, was met within an agreed time frame.  The loan was initially valued on the balance sheet based on the present value of the expected cash flows.  The interest expense was recognized based on the market rate of interest InterOil would be expected to pay on such a borrowing should it not be connected to an LNG/NGL Project.  The effective rate used in the present value calculation was 9.18%.

The difference between the book value of the loan at the time of the cash being received and the actual funds drawn down was initially reflected in the current liability section of the balance sheet as a deferred liquefaction project liability.   This deferred liability of $6,553,080 was transferred to the statement of operations as income on the execution of the definitive LNG/NGL Project Agreement by InterOil and the lenders on July 31, 2007.

Consolidated Financial Statements INTEROIL CORPORATION  38

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

20. Indirect participation interests

(i) Indirect participation interest (“IPI”)

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Indirect participation interest ("IPI")		38,715,228		72,476,668		96,086,369

The IPI balance relates to $125,000,000 received by InterOil subject to the terms of the agreement dated February 25, 2005 between the Company and a number of investors.  In exchange InterOil had provided the investors with a 25% interest in an eight well drilling program to be conducted in InterOil’s petroleum prospecting licenses 236, 237 and 238.

Under the IPI agreement, InterOil is responsible for drilling eight exploration wells, four of which will be in PPL 238, one in PPL 236, and one in PPL 237.  The location of the other two wells is yet to be determined.  The investors will be able to approve the location of the final two wells to be drilled.  In the instance that InterOil proposes appraisal or completion of an exploration or development well, the investors will be asked to contribute to the completion work in proportion to their IPI percentage and InterOil will bear the remaining cost.  InterOil has made cash calls for the completion, appraisal and development programs performed on the exploration or development wells that form part of the IPI Agreement. These cash calls are shown as a liability when received and reduced as amounts are spent on the extended well programs. Should an investor choose not to participate in the completion works of an exploration well, the investor will forfeit certain rights to the well in question as well as their right to convert into common shares.  InterOil has drilled four exploration wells under the IPI agreement as at December 31, 2009.

The funds of $125,000,000 were partly accounted for as a non-financial liability and partly as a conversion option.  The non-financial liability was initially valued at $105,000,000, being the estimated expenditures to complete the eight well drilling program, and the residual value of $20,000,000 has been allocated to the conversion option presented under Shareholder’s equity.  InterOil paid financing fees and transaction costs of $8,138,741 related to the indirect participation interest on behalf of the indirect participation interest investors in 2005.  These fees have been allocated against the non-financial liability, reducing the liability to $96,861,259.  InterOil will maintain the liability at its initial value until conveyance is triggered on the lapse of the conversion option available to the investors, or they elect to participate in the PDL for a successful well.  InterOil will account for the exploration costs relating to the eight well program under the successful efforts accounting policy adopted by the Company.  All geological and geophysical costs relating to the exploration program will be expensed as incurred and all drilling costs will be capitalized and assessed for recovery at each period.  When an investor elects to participate in a PDL or when the investor forfeits the conversion option, conveyance accounting will be applied.  This entails determination of proceeds for the interests conveyed and the cost of that interest as represented in the ‘Oil and gas properties’ in the balance sheet.  The difference between proceeds on conveyance and capitalized costs to the interests conveyed will be recognized as gain or loss in the Statement of operations following the guidance in ASC 932-360 paragraphs 55-8 and 55-9.

Under the agreement, all or part of the 25% initial indirect participation interest could have been converted to a maximum of 3,333,334 common shares in the company, at a price of $37.50 per share, between June 15, 2006 and the later of December 15, 2006, or 90 days after the completion of the eighth well.  Any partial conversion of an indirect participation interest into common shares will result in a corresponding decrease in the investors’ interest in the eight well drilling program.  As at December 31, 2009, the balance of the indirect participation interest that may be converted into shares is a maximum of 527,147 common shares (2008 – 2,160,000, 2007 – 3,306,667) as explained below.  Should the option to convert to shares not be exercised, the indirect participation interest in the eight well drilling program will be maintained and distributions from success in these wells will be paid in accordance with the agreement.

From the date of the agreement up to December 31, 2009, the following has occurred:

� certain IPI investors representing a 3.575% interest in the IPI agreement have exercised their right to convert their interest into common shares resulting in issuance of 476,667 InterOil common shares.  These conversions reduced the initial IPI liability balance of by $13,851,160 and the initial conversion option balance by $2,860,000.

� certain IPI investors representing a 12.635% interest in the IPI agreement have waived their right to convert their IPI percentage into 1,684,667 common shares.  As a result, conveyance was triggered on this portion of the IPI agreement, which reduced the IPI liability by $25,556,480.  A further $23,397,200 is retained in the balance sheet representing the future remaining obligations in relation to this 12.635% interest.

� certain IPI investors representing a 4.8364% interest in the IPI agreement have sold their interest to the Company. Detailed disclosure of this transaction is provided in the section ‘Extinguishment of IPI liability’.

As at December 31, 2009, IPI investors with a combined 3.9536% interest in the IPI agreement still have the conversion rights outstanding resulting in a maximum of 527,147 common shares being issued if all these IPI investors choose to exercise their conversion options.

Consolidated Financial Statements INTEROIL CORPORATION  39

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

20. Indirect participation interests (cont’d)

Extinguishment of IPI liability

During September 2009, the Company bought a combined 4.3364% interest in the IPI Agreement from two investors for $56,479,615 which was settled in two tranches of InterOil common shares.  The first tranche of common shares was for 35% of the total consideration and was issued on September 15, 2009.  The second tranche of shares for the remaining 65% of the total consideration was issued on December 15, 2009 based on a ten day VWAP immediately prior to the date of issue.  As part of this transaction a total number of 1,236,666 shares were issued.

During December 2009, the Company bought a further combined 0.5% interest in the IPI Agreement from two investors for $6,500,546 which was settled in two tranches of InterOil common shares.  The first tranche of common shares was for 35% of the total consideration and was issued on December 1, 2009.  The second tranche of shares for the remaining 65% of the total consideration was issued on December 15, 2009 based on a ten day VWAP immediately prior to the date of issue.  As part of this transaction a total number of 108,044 shares were issued.

Management has adopted the extinguishment of the liability model.  Under this model the consideration paid is allocated to the various components involved in the exchange transactions. These components include:

� cash calls made from the IPI investors in relation to the completion, appraisal and development program undertaken in Elk and Antelope fields as part of the IPI agreement.  These cash call amounts were previously offset against the capitalized oil and gas properties, and have been reinstated to their full historical cost basis for those programs following this exchange transaction.

� fair value of the conversion options extinguished as part of the exchange transactions

� IPI liability extinguished as part of the exchange transactions whereby the difference between the fair value of the shares issued and the book value of the IPI liability has been recorded as an expense in the statement of operations

The following table discloses a breakdown of the loss on extinguishment of IPI liability for the periods ended:

	Year ended
	December 31,			December 31,		December 31,
	2009			2008		2007
	$			$		$
Loss on extinguishment of IPI liability
Consideration paid for exchange transactions		62,980,161			-		-
less amounts capitalized in relation to the appraisal program cash calls		(8,013,434	)		-		-
less book value of IPI liability extinguished		(18,738,392	)		-		-
less book value of conversion options extinguished		(3,869,121	)		-		-
less difference between book value and fair value of conversion options extinguished taken to contributed surplus		(649,187	)		-		-
		31,710,027			-		-

(ii) Indirect participation interest – PNGDV

	December 31,		December 31,		December 31,
	2009		2008		2007
	$		$		$
Current portion		540,002		540,002		1,080,004
Non current portion		844,490		844,490		844,490
Total indirect participation interest - PNGDV		1,384,492		1,384,492		1,924,494

As at December 31, 2009, the balance of the PNG Drilling Ventures Limited ("PNGDV") indirect participation interest in the Company’s phase one exploration program within the area governed by petroleum prospecting licenses 236, 237 and 238 is $1,384,492 (2008 - $1,384,492, 2007 - $1,924,494).  This balance is based on the initial liability recognized in 2006 of $3,588,560 relating to its obligation to drill the four exploration wells on behalf of the investors, being reduced by amounts already incurred in fulfilling the obligation.  PNGDV has a 6.75% interest in the four exploration wells starting with Elk-1 (with an additional two exploration wells to be drilled after Elk-4/A).  PNGDV also has the right to participate in the 16 wells that follow the first four mentioned above up to an interest of 5.75% at a cost of $112,500 per 1% per well (with higher amounts to be paid if the depth exceed 3,500 meters and the cost exceeds $8,500,000).

During the year ended December 31, 2009, $nil (2008 – a debit of $540,002, 2007 – a credit of $3,327) of geological and geophysical costs and drilling costs have been allocated against this liability.  PNGDV liability has been accounted using conveyance accounting as there are no conversion options attached to the liability, unlike the IPI non-financial liability noted above.

Consolidated Financial Statements INTEROIL CORPORATION  40

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

20. Indirect participation interests (cont’d)

(iii) PNG Energy Investors

In addition to the above, PNG Energy Investors (“PNGEI”), an indirect participation interest investor who converted all of its interest to common shares in fiscal year 2004, 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, 2009 we have drilled 6 exploration wells since inception of our exploration program within PPL 236, 237 and 238 in Papua New Guinea.   In order to participate, PNGEI would be required to contribute a proportionate amount of drilling costs related to these wells.

21. Non controlling interest

On December 31, 2007 an agreement was reached with Enron Papua New Guinea Ltd (“Enron”), SPI’s former joint venture partner, to buy back the 1.07% minority interest held by them in the refinery in exchange of 25,000 InterOil Corporation’s shares.  At December 31, 2009, a subsidiary, SP InterOil LDC, holds 100% (2008 – 100%, 2007 – 100%) of the non-voting participating shares issued from EP InterOil Ltd.

The non controlling interest as at December 31, 2009 relates to Petroleum Independent and Exploration Corporation’s (“PIE Corp.”) 0.01% minority shareholding in SPI InterOil LDC.  InterOil has entered into an agreement with PIE Corp. under which PIE Corp. can exchange its remaining 5,000 shares of SPI InterOil LDC for Common Shares on a one-for-one basis.  This election may be made by PIE Corp. at any time.

22. Share capital

The authorized share capital of the Company consists of an unlimited number of common shares with no par value.  Each common share entitles the holder to one vote.

Common shares - Changes to issued share capital were as follows:

	Number of shares		$
January 1, 2007		29,871,180		233,889,366
Shares issued on exercise of options under Stock Incentive Plan		22,000		418,938
Shares issued on conversion of indirect participation interest		26,667		934,890
Shares issued on conversion of warrants		2,995		84,439
Shares issued on buyback of minority interest		25,000		496,500
Shares issued on Private Placement		1,078,514		23,500,000
December 31, 2007		31,026,356		259,324,133
Shares issued on Private Placement		2,728,477		58,938,305
Shares issued on exercise of options under Stock Incentive Plan		58,000		1,413,587
Shares issued on preference share conversion and interest payments		532,754		15,012,950
Share issued as placement fee on debenture issue		228,000		5,700,000
Share issued on debenture conversions		641,000		15,118,483
Shares issued on debenture interest payments		259,105		2,620,628
Shares issued on conversion of indirect participation interest		450,000		15,776,270
December 31, 2008		35,923,692		373,904,356
Shares issued on exercise of options under Stock Incentive Plan		231,750		6,818,814
Shares issued on buyback of LNG Interest (note 14)		499,834		11,250,000
Shares issued on debenture conversions (note 24)		3,159,000		77,089,722
Shares issued on debenture interest payments (note 24)		70,548		2,352,084
Shares issued on registered direct offering		2,013,815		70,443,248
Shares issued on exercise of warrants		302,305		8,522,978
Shares issued on buyback of IPI#3 Interest		1,344,710		62,980,161
December 31, 2009		43,545,654		613,361,363

Consolidated Financial Statements INTEROIL CORPORATION  41

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

23. Preference Shares

In November 2007, the Company authorized the issue of 1,035,554 convertible preference shares at an issue price of $28.97 to investors amounting to a total of $30,000,000.  517,777 of the authorized preference shares were issued to an investor in November 2007 for $15,000,000.  The preferred stock carried a fixed divided of 5% per annum payable quarterly in arrears in cash or stock at the issuers’ option.  The preference dividend payment of 5% per annum was treated as an interest expense in the Statement of Operations.  During the quarter ended September 30, 2008 all preference shares issued (517,777 shares) were converted into common shares.  The preference dividend paid for the year ended December 31, 2009 was $nil (2008 - $418,526, 2007 - $84,247).

24. 8% subordinated debentures

On May 13, 2008, the Company completed the issue of $95,000,000 unsecured 8% subordinated convertible debentures with a maturity of five years.  The debenture holders had the right to convert their debentures into common shares at any time at a conversion price of $25.00 per share.  The Company had the right to require the debenture holders to convert if the daily Volume Weighted Average Price (“VWAP”) of the common shares is at or above $32.50 for at least 15 consecutive trading days.  Accrued interest on these debentures was to be paid semi-annually in arrears, in May and November of each year, commencing November 2008.

Based on guidance under CICA 3863, the debentures were assessed based on the substance of the contractual arrangement in determining whether it exhibits the fundamental characteristic of a financial liability or equity.  Management had assessed that the debenture instrument mainly exhibits characteristics that are liability in nature; however, the embedded conversion feature was equity in nature and needed to be bifurcated and disclosed separately within equity.  Management applied residual basis and had valued the liability component first and assigned the residual value to the equity component.

Management had fair valued the liability component by discounting the expected interest payments using a nominal rate of 13.5% being Management’s estimate of the expected interest payments for a similar instrument without the conversion feature.  The liability component was valued at $81,933,311 and the remaining balance of $13,066,689 was allocated to the equity component before offsetting transaction costs.

The placement fee of $5,700,000 paid to the investors in common shares of the Company was treated to be in the nature of a debt discount and was offset against the liability component.  The transaction costs relating to the issue amounting to $219,966 has been split based on the percentages allocated to the liability and equity components; the costs relating to the liability component of $189,711 has been offset against the liability component, and costs relating to the equity component of $30,255 have been allocated against the equity component recognized.

The liability component on initial recognition after adjusting for the placement fee and transaction costs amounted to $76,043,600 and the equity component amounted to $13,036,434.  The liability component will be accreted over the five year maturity period to bring the liability back to the carrying value.  The accretion expense relating to the debenture liability for the year ended December 31, 2009 was $1,212,262 (2008 - $1,915,910).  In addition to the accretion, interest at 8% per annum has been expensed for the year ended December 31, 2009 amounting to $2,712,936 (2008 - $4,361,889). The interest payable up to May 9, 2009 was paid in a combination of cash and shares.

During the year ended December 31, 2008, certain debenture holders exercised their conversion rights for $16,025,000 resulting in issue of 641,000 common shares of the Company.  During May 2009, a further 755,000 debentures amounting to $18,875,000 were converted into common shares of the Company.  On June 8, 2009, all remaining debentures outstanding were converted into common shares due to a mandatory conversion resulting from the daily VWAP of the common shares being above $32.50 for at least 15 consecutive trading days.  The remaining book value of the liability and equity portion on the date of mandatory conversion was transferred to share capital to record this conversion.  As at December 31, 2009, of the 3,800,000 convertible debentures issued, nil (2008 – 3,159,000), were outstanding.

25. Stock compensation

Stock options

Options are issued at no less than market price to directors, certain employees and to a limited number of contractor personnel.  Options are exercisable for common shares on a 1:1 basis. Options vest at various dates in accordance with the applicable individual option agreements, vesting generally between one to four years after the date of grant, have an exercise period of three to five years after the date of grant, and are subject to the option plan rules.  Upon resignation or retirement, vested options must generally be exercised within 90 days or before expiry of the options if this occurs earlier.

Consolidated Financial Statements INTEROIL CORPORATION  42

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

25. Stock compensation (cont’d)

	December 31, 2009						December 31, 2008						December 31, 2007
Stock options outstanding	Number of options			Weighted average exercise price $			Number of options			Weighted average exercise price $			Number of options			Weighted average exercise price $
Outstanding at beginning of period		1,839,500			20.18			1,200,500			23.70			1,013,500			20.59
Granted		325,500			28.68			952,500			18.48			354,750			33.51
Exercised		(231,750	)		(19.94	)		(58,000	)		(16.50	)		(22,000	)		(14.37	)
Forfeited		(49,000	)		(30.39	)		(11,500	)		(28.68	)		(143,250	)		(25.94	)
Expired		(45,750	)		(34.09	)		(244,000	)		(25.80	)		(2,500	)		(27.00	)
Outstanding at end of period		1,838,500			22.07			1,839,500			20.18			1,200,500			23.70

At December 31, 2009, in addition to the options outstanding as per the above table, there were an additional 1,753,100 (2008 – 309,500, 2007 – 1,137,250) common shares reserved for issuance under the Company’s 2009 stock option plans as approved on June 19, 2009.

Options issued and outstanding							Options exercisable
Range of exercise prices $	Number of options		Weighted average exercise price $		Weighted average remaining term (years)		Number of options		Weighted average exercise price $
8.01 to 12.00		545,000		9.81		3.90		175,000		9.83
12.01 to 24.00		545,000		17.13		2.56		340,000		16.70
24.01 to 31.00		291,500		28.52		2.47		282,500		28.47
31.01 to 41.00		307,000		35.16		4.22		127,000		36.13
41.01 to 51.00		150,000		45.28		3.47		75,000		43.22
		1,838,500		22.07		3.31		999,500		23.28

Aggregate intrinsic value of the 1,838,500 options issued and outstanding as at December 31, 2009 is $24,625,643. Aggregate intrinsic value of 999,500 options exercisable as at December 31, 2009 is $13,594,887.

The weighted-average grant-date fair value of options granted during 2009 was $19.04 (2008 - $9.07, 2007 - $19.34).  The total intrinsic value of options exercised during the year ended December 31, 2009 was $2,185,642 (2008 - $456,867, 2007 - $102,840).  Cash received from option exercise under all share-based payment arrangements for the year ended December 31, 2009 was $4,621,410 (2008 - $956,720, 2007 - $316,100).

The fair value of the 325,500 (2008 – 952,500, 2007 – 354,750) options granted subsequent to January 1, 2009 has been estimated at the date of grant in the amount of $6,197,278 (2008 - $11,077,126, 2007 - $6,859,131) using a Black-Scholes pricing model.  An amount of $8,042,195 (2008 - $5,741,086, 2007 - $6,062,962) has been recognized as compensation expense for the year ended December 31, 2009.  The current year compensation expense of $8,042,195 (2008 - $5,741,086, 2007 - $6,062,962) was adjusted against contributed surplus under equity, out of which $2,185,642 (2008 - $456,867, 2007 - $102,840) was transferred to share capital on exercise of options, leaving a net impact of $5,856,553 (2008 - $5,284,219, 2007 - $5,960,122) on contributed surplus.

Consolidated Financial Statements   INTEROIL CORPORATION     43

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

25. Stock compensation (cont’d)

The assumptions contained in the Black Scholes pricing model are as follows:

Year	Period	Risk free interest rate (%)		Dividend yield		Volatility (%)		Weighted average expected life for options
2009	Oct 1 to Dec 31		1.5		-		89		6.0
2009	Jun 1 to Sep 30		1.7		-		83		3.0
2009	Apr 1 to Jun 30		1.4		-		83		5.0
2009	Jan 1 to Mar 31		1.1		-		83		5.0
2008	Oct 1 to Dec 31		1.5		-		83		4.3
2008	Apr 1 to Sep 30		2.7		-		80		5.0
2008	Jan 1 to Mar 31		2.2		-		73		5.0
2007	October 1 to Dec 31		3.4		-		74		5.0
2007	January 1 to Sep 30		5		-		63		5.0

Restricted stock

Restricted stock is issued to directors, certain employees and to a limited number of contractor personnel.  Restricted stock vests at various dates in accordance with the applicable restricted stock agreement, vesting generally between one to four years after the date of grant.

	December 31, 2009				December 31, 2008				December 31, 2007
Stock units outstanding	Number of stock units		Weighted Average Grant Date Fair Value per stock unit $		Number of stock units		Weighted Average Grant Date Fair Value per stock unit $		Number of stock units		Weighted Average Grant Date Fair Value per stock unit $
Outstanding at beginning of period		-		-		-		-		-		-
Granted		41,400		68.55		-		-		-		-
Exercised		-		-		-		-		-		-
Forfeited		-		-		-		-		-		-
Expired		-		-		-		-		-		-
Total		41,400		68.55		-		-		-		-

An amount of $248,486 (2008 - $nil, 2007 - $nil) has been recognized as compensation expense for the year ended December 31, 2009.  The current year compensation expense of $248,486 (2008 - $nil, 2007 - $nil) was adjusted against contributed surplus under equity.

26. Warrants

In 2004, InterOil issued five-year warrants to purchase 359,415 common shares at an exercise price equal to $21.91.  A total of nil (2008 – 337,252, 2007 – 337,252) were outstanding at December 31, 2009.  The warrants were exercisable between August 27, 2004 and August 27, 2009.  The warrants were recorded at the fair value calculated at inception as a separate component of equity.  The fair value was calculated using a Black-Scholes pricing model with the following assumptions: risk-free interest rate of 2.5%, dividend yield of nil, volatility factor of the expected market price of the Company’s common stock of 45% and a weighted average expected life of the warrants of five years.  During the quarter ended September 30, 2009, 302,305 of the warrants were exercised and converted into common shares.

All unexercised warrants lapsed on August 27, 2009 and the fair value of these lapsed warrants were transferred to contributed surplus within Shareholders’ equity.

27. Earnings/(Loss) per share

Conversion options, stock options and restricted stock units totaling 2,412,047 common shares at prices ranging from $9.80 to $68.55 were outstanding as at December 31, 2009 and were included in the computation of the diluted earnings per share for the year ended December 31, 2009.  However, the dilutive instruments outstanding at December 31, 2008 and December 31, 2007 were not included in the computation of the diluted loss per share at December 31, 2008 and December 31, 2007 because they caused the loss per share to be anti-dilutive.

Consolidated Financial Statements   INTEROIL CORPORATION     44

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

27. Earnings/(Loss) per share (cont’d)

Potential dilutive instruments outstanding	Number of shares December 31, 2009		Number of shares December 31, 2008		Number of shares December 31, 2007
Preferred stock		-		-		517,777
Employee stock options		1,838,500		1,839,500		1,200,500
Employee restricted stock units		41,400		-		-
IPI Indirect Participation interest - conversion options		527,147		2,160,000		3,306,667
8% Convertible debentures		-		3,159,000		-
Warrants		-		337,252		337,252
Others (Note 21)		5,000		5,000		5,000
Total stock options/shares outstanding		2,412,047		7,500,752		5,367,196

The income available to the common shareholders and the income available to the dilutive holders, used in the calculation of the numerator in both the normal and diluted EPS calculation is the net profit/loss as per Consolidated Statement of Operations.  This is due to the fact that the inclusion of convertible securities under ‘if-converted’ method in the calculation would result in the EPS being anti-dilutive.

The reconciliation between the ‘Basic’ and ‘Basic and Diluted’ shares, used in the calculation of the denominator in the EPS calculation is as follows:

	Year ended
	December 31,		December 31,		December 31,
	2009		2008		2007
Basic		39,900,583		33,632,390		29,998,133
Employee options (using treasury stock method)		697,811		-		-
Warrants (using treasury stock method)		83,192		-		-
Diluted		40,681,586		33,632,390		29,998,133

28. Commitments and contingencies

Commitments

Payments due by period contractual obligations are as follows:

	Total		Less than 1 year		1-2 years		2-3 years		3-4 years		4-5 years		More than 5 years
	'000		'000		'000		'000		'000		'000		'000
Secured loan		53,500		9,000		9,000		9,000		9,000		9,000		8,500
Indirect participation interest - PNGDV (note 20)		1,384		540		844		-		-		-		-
PNG LNG Inc. Joint Venture (proportionate share of commitments)		35		28		7		-		-		-		-
Petroleum prospecting and retention licenses (a)		83,000		4,500		9,500		20,000		14,850		34,150		-
		137,919		14,068		19,351		29,000		23,850		43,150		8,500

(a) The amount pertaining to the petroleum prospecting and retention licenses represents the amount InterOil has committed as a condition on renewal of these licenses.  Of this $83.0 million commitment, as at December 31, 2009, management estimates that $46,294,421 would satisfy the commitments in relation to the IPI investors.

Consolidated Financial Statements   INTEROIL CORPORATION     45

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

28. Commitments and contingencies (cont’d)

Contingencies:

The Company's Chief Executive Officer, Phil Mulacek, and his controlled entities Petroleum Independent & Exploration Corporation and P.I.E. Group, LLC, together with the Company and certain of its subsidiaries, are defendants in Todd Peters, et. al. v. Phil Mulacek et. al.; Cause No. 05-040-03592-CV; pending in the 284th District Court of Montgomery County, Texas.  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 the Company.  Plaintiffs contend that Mr. Mulacek and his controlled entities breached fiduciary duties owed to the plaintiffs and also assert claims for common law fraud, fraudulent inducement, statutory fraud, securities fraud, breach of contract, investor oppression, conversion, theft, money had and received, and tortious interference with a contract.  Plaintiffs assert claims both individually and, in the alternative, derivatively on behalf of the partnership.  Plaintiffs seek to impose liability on the Company and certain of its subsidiaries for those alleged acts through claims of ratification, conspiracy, aiding and abetting, joint enterprise, and knowing participation in the breach of another's fiduciary duty.  Plaintiffs further seek to impose liability on the Company and certain of its subsidiaries directly through the claims of conversion, theft, constructive trust and tortious interference with a contract.  In late July 2009, plaintiffs amended their petition adding sixteen new plaintiffs.  Plaintiffs have proposed numerous alternative methods of calculating their alleged damages, all of which are based at least partially on the Company's share price which fluctuates over time.  Thus, it is difficult to determine the total amount of actual damages plaintiffs' seek.  If, however, plaintiffs are successful in obtaining a favorable verdict, actual damages could exceed $125,000,000.  Plaintiffs also seek unspecified punitive damages, attorneys' fees, expenses and court costs.  The case is set for trial beginning in October 2010.  The Company and other defendants are vigorously contesting the matter.  If however, plaintiffs succeed in obtaining a judgment in the amount they seek, it could have a material adverse effect on the Company or its subsidiaries.  The Company has not provided for any amounts in relation to this matter.

In addition to the above, 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.

ICCC review of Downstream maximum margin

InterOil is also a significant participant in the retail and wholesale distribution business in Papua New Guinea.  The ICCC regulates the maximum prices that may be charged by the wholesale and retail hydrocarbon distribution industry in Papua New Guinea.  The 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.  In June 2009, the ICCC commenced a review into the pricing arrangements for petroleum products in Papua New Guinea.  The last such review was undertaken during 2004 and was due to expire on December 31, 2009. The purpose of the review is 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. We have provided detailed submissions to the ICCC.  The ICCC have most recently advised that its final report will be issued in March 2010.  It is possible that the ICCC may determine to increase regulation of pricing and reduce the margins able to be obtained by our distribution business.  Such a decision, if made, may negatively affect our downstream business and require a review of its operations.

29. Subsequent events

There are no subsequent events that require disclosure.

30. Reconciliation to generally accepted accounting principles in the United States

The audited consolidated financial statements of the Company for the year ended December 31, 2009, 2008 and 2007 have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”) which, in most respects, conforms to generally accepted accounting principles in the United States (“U.S. GAAP”).  The reconciliations and other information presented in this note are solely in relation to the consolidated financial statements.  The significant differences between Canadian GAAP and U.S. GAAP as they relate to the Company are presented throughout this note.  Additionally, where there is no significant conflict with Canadian GAAP requirements some of the additional U.S. GAAP disclosure requirements have been incorporated throughout the Canadian GAAP financial statements.

Consolidated Financial Statements   INTEROIL CORPORATION     46

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Consolidated Balance Sheets	As at
	December 31, 2009						December 31, 2008						December 31, 2007
	$						$						$
	Canadian GAAP			US GAAP			Canadian GAAP			US GAAP			Canadian GAAP			US GAAP
Assets
Current assets:
Cash and cash equivalents (5)		46,449,819			44,754,405			48,970,572			44,051,224			43,861,762			40,152,026
Cash restricted (5)		22,698,829			22,698,829			25,994,258			25,933,184			22,002,302			21,916,736
Trade receivables (5)		61,194,136			61,194,136			42,887,823			42,887,823			63,145,444			63,145,444
Commodity derivative contracts		-			-			31,335,050			31,335,050			-			-
Other assets (5)		639,646			1,496,621			167,885			125,119			146,992			120,460
Inventories		70,127,049			70,127,049			83,037,326			83,037,326			82,589,242			82,589,242
Prepaid expenses (5)		6,964,950			6,964,950			4,489,574			4,489,574			5,102,540			5,076,006
Total current assets		208,074,429			207,235,990			236,882,488			231,859,300			216,848,282			212,999,914
Cash restricted		6,609,746			6,609,746			290,782			290,782			382,058			382,058
Goodwill (5)		6,626,317			864,377			-			-			-			-
Deferred financing costs (4), (6)		-			910,722			-			1,279,145			-			1,395,066
Investment in LNG Project (5)		-			13,121,141			-			6,610,480			-			5,848,612
Plant and equipment (1), (5)		221,046,709			208,703,247			223,585,559			210,803,013			232,852,222			219,117,006
Oil and gas properties (2)		172,483,562			171,220,062			128,013,959			127,653,411			84,865,127			84,865,127
Future income tax benefit		16,912,969			16,912,969			3,070,182			3,070,182			2,867,312			2,867,312
Total assets		631,753,732			625,578,254			591,842,970			581,566,313			537,815,001			527,475,095
Liabilities
Current liabilities:
Accounts payable and accrued liabilities (5), (6)		59,372,354			58,090,593			78,147,736			77,460,413			60,427,607			59,682,621
Commodity derivative contracts		-			-			-			-			1,960,300			1,960,289
Working capital facility		24,626,419			24,626,419			68,792,402			68,792,402			66,501,372			66,501,372
Current portion of secured loan (6)		9,000,000			9,000,000			9,000,000			9,000,000			136,776,760			136,810,093
Current portion of indirect participation interest - PNGDV		540,002			540,002			540,002			540,002			1,080,004			1,080,004
Total current liabilities		93,538,775			92,257,014			156,480,140			155,792,817			266,746,043			266,034,379
Secured loan (6)		43,589,278			44,500,000			52,365,333			53,500,000			61,141,389			62,500,000
8% subordinated debenture liability (4)		-			-			65,040,067			69,710,182			-			-
Preference share liability (3)		-			-			-			-			7,797,312			-
Deferred gain on contributions to LNG project (5)		13,076,272			-			17,497,110			-			9,096,537			-
Indirect participation interest (2)		38,715,228			48,195,608			72,476,668			88,211,120			96,086,369			115,926,369
Indirect participation interest - PNGDV		844,490			844,490			844,490			844,490			844,490			844,490
Total liabilities		189,764,043			185,797,112			364,703,808			368,058,609			441,712,140			445,305,238
Non-controlling interest (8)		13,596			-			5,235			-			4,292			-
Preference shares (3)		-			-			-			-			-			14,250,000
Equity
InterOil Corporation shareholders' equity:
Share capital (4)		613,361,363			615,742,733			373,904,356			373,514,356			259,324,133			259,324,133
Preference shares (3)		-			-			-			-			6,842,688			-
8% subordinated debentures (4)		-			-			10,837,394			-			-			-
Contributed surplus (4)		21,297,177			30,747,259			15,621,767			24,422,662			10,337,548			10,337,548
Warrants		-			-			2,119,034			2,119,034			2,119,034			2,119,034
Accumulated Other Comprehensive Income		8,150,976			8,150,976			27,698,306			27,698,306			6,025,019			6,025,019
Conversion options (2)		13,270,880			-			17,140,000			-			19,840,000			-
Accumulated deficit		(214,104,303	)		(214,873,709	)		(220,186,930	)		(214,252,081	)		(208,389,853	)		(209,890,265	)
Total InterOil Corporation shareholders' equity		441,976,093			439,767,259			227,133,927			213,502,277			96,098,569			67,915,469
Non-controlling interest (8)		-			13,883			-			5,427			-			4,388
Total equity		441,976,093			439,781,142			227,133,927			213,507,704			96,098,569			67,919,857
Total liabilities and shareholders' equity		631,753,732			625,578,254			591,842,970			581,566,313			537,815,001			527,475,095

Consolidated Financial Statements   INTEROIL CORPORATION     47

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Consolidated statements of operations

The following table presents the consolidated statements of operations under U.S. GAAP compared to Canadian GAAP:

	Year ended
	December 31, 2009						December 31, 2008						December 31, 2007
	$						$						$
	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Revenue
Sales and operating revenues		688,478,965			688,478,965			915,578,709			915,578,709			625,526,068			625,526,068
Interest income		350,629			-			931,785			-			2,180,285			-
Other income		4,228,415			-			3,216,445			-			2,666,890			-
		693,058,009			688,478,965			919,726,939			915,578,709			630,373,243			625,526,068
Expenses
Cost of sales and operating expenses (excluding depreciation shown below)		601,983,432			601,983,432			888,623,109			888,623,109			573,609,441			573,609,441
Administrative and general expenses (5)		33,254,708			30,087,894			31,227,627			28,354,064			31,998,655			30,881,433
Derivative (gain)/loss		(1,008,585	)		(1,008,585	)		(24,038,550	)		(24,038,550	)		7,271,693			7,271,693
Legal and professional fees (5)		9,067,413			6,490,539			11,523,045			7,692,045			6,532,646			4,471,684
Exploration costs, excluding exploration impairment		208,694			208,694			995,532			995,532			13,305,437			13,305,437
Exploration impairment		-			-			107,788			107,788			1,242,606			1,242,606
Short term borrowing costs		3,776,590			3,776,590			6,514,060			6,514,060			5,565,828			5,565,828
Long term borrowing costs (3), (4), (5)		8,788,041			17,871,168			17,459,186			19,529,798			17,182,446			16,708,199
Depreciation and amortization (1), (5)		14,321,775			13,785,845			14,142,546			13,594,481			13,024,258			12,529,892
Gain on LNG shareholder agreement		-			-			-			-			(6,553,080	)		(6,553,080	)
Loss/(gain) on equity accounted investment (5)		-			4,739,339			-			(1,047,795	)		-			(5,561,684	)
Gain on sale of oil and gas properties (2)		(7,364,468	)		(8,846,468	)		(11,235,084	)		(12,280,084	)		-			-
Loss on extinguishment of IPI liability (2)		31,710,027			32,359,214			-			-			-			-
Foreign exchange loss/(gain) (5)		3,305,383			3,346,436			(3,878,150	)		(4,437,943	)		(5,078,338	)		(5,099,651	)
Non-controlling interest (8)		8,361			-			943			-			(22,333	)		-
Interest income (5)		-			(342,888	)		-			(841,028	)		-			(2,146,183	)
Other income		-			(4,228,415	)		-			(3,216,445	)		-			(2,666,890	)
		698,051,371			700,222,795			931,442,052			919,549,032			658,079,259			643,558,725
Loss before income taxes		(4,993,362	)		(11,743,830	)		(11,715,113	)		(3,970,323	)		(27,706,016	)		(18,032,657	)
Income tax expense/(benefit) (5), (7)		11,075,989			11,130,659			(81,964	)		28,073			(1,206,892	)		(1,194,227	)
Net profit/(loss)		6,082,627			(613,171	)		(11,797,077	)		(3,942,250	)		(28,912,908	)		(19,226,884	)
Less: Net (profit)/loss attributable to the non-controlling interest (8)		-			(8,457	)		-			(1,040	)		-			22,236
Net profit/(loss) attributable to InterOil Corporation		6,082,627			(621,628	)		(11,797,077	)		(3,943,290	)		(28,912,908	)		(19,204,648	)

Consolidated Financial Statements   INTEROIL CORPORATION     48

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Reconciliation of Canadian GAAP net income/(loss) to U.S. GAAP net income/(loss)

	Year ended
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Net profit/(loss) as shown in the Canadian GAAP financial statements		6,082,627			(11,797,077	)		(28,912,908	)
Description of items having the effect of increasing reported income
Decrease in depreciation and amortization due to difference in date of commencement of operations of refinery (1)		478,934			478,923			478,935
Decrease in non-controlling interest expense (8)		(96	)		(96	)		(96	)
Increase in reporting income due to reversal of proportionate consolidation of LNG Project and equity accounting the investment (5)		1,067,221			8,400,571			9,097,535
Decrease in long term borrowing costs relating to financing costs on preference shares expensed (3)		-			-			390,000
Decrease in long term borrowing costs relating to dividends paid to preference share holders expensed under Canadian GAAP (3)		-			418,526			84,247
Decrease in long term borrowing costs relating to reduced accretion expense on increased 8% subordinated debentures liability (4)		-			291,137			-
Increase in gain on sale of oil and gas properties arising from conveyance accounting due to the initial IPI proceeds not being bifurcated under U.S. GAAP (2)		1,482,000			1,045,000			-
Description of items having the effect of decreasing reported income
Increase in long term borrowing costs relating to immediate expense of portion of placement fees and accretion of BCF on conversion of 8% subordinated debentures (4)		(9,083,127	)		(2,780,274	)		-
Increase in loss on extinguishment of IPI liability arising from IPI buyback due to the initial IPI proceeds not being bifurcated under U.S. GAAP (2)		(649,187	)		-			-
Reduced gain on sale of minority interest under U.S. GAAP		-			-			(342,361	)
Net profit/(loss) according to US GAAP		(621,628	)		(3,943,290	)		(19,204,648	)

Statements of comprehensive income/(loss), net of tax

	Year ended
	December 31,			December 31,			December 31,
	2009			2008			2007
	$			$			$
Net loss before non-controlling interest in accordance with U.S. GAAP, net of tax		(613,171	)		(3,942,250	)		(19,226,884	)
Foreign currency translation reserve, net of tax		(1,534,830	)		3,660,787			4,532,150
Deferred hedge (loss)/gain, net of tax		(18,012,500	)		18,012,500			(1,389	)
Total other comprehensive income, net of tax		(19,547,330	)		21,673,287			4,530,761
Comprehensive (loss)/income, net of tax		(20,160,501	)		17,731,037			(14,696,123	)
Comprehensive (income)/loss attribuable to the non-controlling interest, net of tax		(8,457	)		(1,040	)		22,236
Comprehensive (loss)/income attributable to InterOil Corporation, net of tax		(20,168,958	)		17,729,997			(14,673,887	)

Consolidated Financial Statements   INTEROIL CORPORATION     49

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Reconciliation of Canadian GAAP Statement of cash flows to U.S. GAAP:

	Year ended
	December 31, 2009			December 31, 2008			December 31, 2007
	$			$			$
Cash flows provided by (used in):
Operating activities - Canadian GAAP (as per consolidated cash flows)		44,500,367			15,586,156			(31,619,907	)
Reconciling items:
Reclass exploration costs expensed including exploration impairment as investing activity for US GAAP		(208,694	)		(1,103,320	)		(14,548,043	)
Being LNG project related operating cash flows reversed for US GAAP cash flow statement		3,188,162			8,666,724			2,892,220
Operating activities - U.S. GAAP		47,479,835			23,149,560			(43,275,730	)
Investing activities - Canadian GAAP (as per consolidated cash flows)		(85,567,346	)		(47,390,685	)		(34,369,871	)
Reconciling items:
Reclass exploration costs expensed including exploration impairment as investing activity for US GAAP		208,694			1,103,320			14,548,043
Being reversal of LNG Project expenditure for US GAAP cash flows		96,846			(404,594	)		2,762,786
Being reversal of movement in restricted cash held relating to LNG Project for US GAAP cash flows		(61,074	)		(24,492	)		85,566
Investing activities - U.S. GAAP		(85,322,880	)		(46,716,451	)		(16,973,476	)
Financing activities - Canadian GAAP (as per consolidated cash flows)		38,546,226			36,913,339			78,170,105
Reconciling items:
Being reversal of PNG LNG cash calls from unrelated joint venture partners proportionately consolidated in Canadian GAAP cash flow statement		-			(9,447,250	)		(9,450,308	)
Financing activities - U.S. GAAP		38,546,226			27,466,089			68,719,797
Increase in cash and cash equivalents		703,181			3,899,198			8,470,591
Cash and cash equivalents, beginning of period (U.S.GAAP)		44,051,224			40,152,026			31,681,435
Cash and cash equivalents, end of period (U.S. GAAP)		44,754,405			44,051,224			40,152,026

Under Canadian GAAP, InterOil’s share in the LNG Joint venture project is proportionately consolidated and InterOil’s share of the JV cash flows will be taken up in InterOil consolidated cash flow statement.  The cash flows would be classified between operating, investing and financing as per the nature of the transaction.  Under U.S. GAAP, when an investment in an entity is accounted for by use of the equity method, an investor restricts its reporting in the cash flow statement to the cash flows between itself and the investee, for example, to dividends and advances.  The above cash and cash equivalents is different to the Canadian cash and cash equivalents balance due to the proportionate take up of the cash balance under Canadian GAAP, but equity accounting of the LNG investment in U.S. GAAP (refer (5) below).

Consolidated Financial Statements   INTEROIL CORPORATION     50

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Consolidated Statements of Shareholders' Equity

	Year ended						Year ended						Year ended
	December 31, 2009						December 31, 2008						December 31, 2007
	$						$						$
	Canadian GAAP			US GAAP			Canadian GAAP			US GAAP			Canadian GAAP			US GAAP
Share capital
At beginning of period		373,904,356			373,514,356			259,324,133			259,324,133			233,889,366			233,889,366
Issue of capital stock		239,457,007			242,228,377			114,580,223			114,190,223			25,434,767			25,434,767
At end of period		613,361,363			615,742,733			373,904,356			373,514,356			259,324,133			259,324,133
Preference Shares
At beginning of period		-			-			6,842,688			-			-			-
Issue of preference shares		-			-			-			-			6,842,688			-
Converted to common shares		-			-			(6,842,688	)		-			-			-
At end of period		-			-			-			-			6,842,688			-
8% subordinated debentures
At beginning of period		10,837,394			-			-			-			-			-
Issue of debentures		-			-			13,036,434			-			-			-
Conversion to common shares		(10,837,394	)		-			(2,199,040	)		-			-			-
At end of period		-			-			10,837,394			-			-			-
Contributed surplus
At beginning of period		15,621,767			24,422,662			10,337,548			10,337,548			4,377,426			4,377,426
Options exercised transferred to share capital		(2,185,642	)		(2,185,642	)		(456,867	)		(456,867	)		(102,840	)		(102,840	)
Stock compensation expense		8,290,681			8,290,681			5,741,086			5,741,086			6,062,962			6,062,962
Conversion options transferred to contributed surplus		(649,187	)		-			-			-			-			-
Lapsed warrants transferred to contributed surplus		219,558			219,558			-			-			-			-
8% Debenture issue BCF (note 4)		-			-			-			8,800,895			-			-
At end of period		21,297,177			30,747,259			15,621,767			24,422,662			10,337,548			10,337,548
Warrants
At beginning of period		2,119,034			2,119,034			2,119,034			2,119,034			2,137,852			2,137,852
Conversion to common shares		(1,899,476	)		(1,899,476	)		-			-			(18,818	)		(18,818	)
Lapsed warrants transferred to contributed surplus		(219,558	)		(219,558	)		-			-			-			-
At end of period		-			-			2,119,034			2,119,034			2,119,034			2,119,034
Accumulated Other Comprehensive Income
Deferred hedge gain/(loss)
At beginning of period		18,012,500			18,012,500			-			-			-			1,389
Deferred hedge gain recognised on transition		-			-			-			-			1,385			-
Deferred hedge (loss)/gain movement for period, net of tax		(18,012,500	)		(18,012,500	)		18,012,500			18,012,500			(1,385	)		(1,389	)
Deferred hedge gain/(loss) at end of period		-			-			18,012,500			18,012,500			-			-
Foreign currency translation reserve
At beginning of period		9,685,806			9,685,806			6,025,019			6,025,019			1,492,869			1,492,869
Foreign currency translation adjustment movement for period, net of tax		(1,534,830	)		(1,534,830	)		3,660,787			3,660,787			4,532,150			4,532,150
Foreign currency translation reserve at end of period		8,150,976			8,150,976			9,685,806			9,685,806			6,025,019			6,025,019
Accumulated other comprehensive income at end of period		8,150,976			8,150,976			27,698,306			27,698,306			6,025,019			6,025,019
Conversion options
At beginning of period		17,140,000			-			19,840,000			-			20,000,000			-
Movement for period		(3,869,120	)		-			(2,700,000	)		-			(160,000	)		-
At end of period		13,270,880			-			17,140,000			-			19,840,000			-
Accumulated deficit
At beginning of period		(220,186,930	)		(214,252,081	)		(208,389,853	)		(209,890,265	)		(179,476,945	)		(190,601,370	)
Net profit/(loss) for period		6,082,627			(621,628	)		(11,797,077	)		(3,943,290	)		(28,912,908	)		(19,204,648	)
Deduct:
Preference Share Dividends		-			-			-			(418,526	)		-			(84,247	)
At end of period		(214,104,303	)		(214,873,709	)		(220,186,930	)		(214,252,081	)		(208,389,853	)		(209,890,265	)
InterOil Corporation shareholders' equity at end of period		441,976,093			439,767,259			227,133,927			213,502,277			96,098,569			67,915,469
Non-controlling interest
At beginning of period		-			5,427			-			4,387			-			5,416,830
Movement for period		-			8,456			-			1,040			-			(5,412,442	)
At end of period		-			13,883			-			5,427			-			4,388
Total equity at end of period		441,976,093			439,781,142			227,133,927			213,507,704			96,098,569			67,919,857

Consolidated Financial Statements   INTEROIL CORPORATION     51

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Per share amounts

Basic per share amounts are computed by dividing net income available to shareholders by the weighted average number of shares outstanding for the reporting period.  Diluted per share amounts reflects the potential dilution that could occur if options or contracts to issue shares were exercised or converted into shares.

For the calculation of diluted per share amounts, the basic weighted average number of shares is increased by the dilutive effect of stock options determined using the treasury method.  No potential shares in options on issue were dilutive for the years ended December 2009, 2008 and 2007.

	Year ended
Weighted average number of shares on which earnings per share	December 31,			December 31,			December 31,
calculations are based in accordance with U.S. GAAP	2009			2008			2007
Basic		39,900,583			33,632,390			29,998,133
Effect of dilutive options		-			-			-
Diluted		39,900,583			33,632,390			29,998,133
Net loss per share in accordance with U.S. GAAP
Basic		(0.02	)		(0.12	)		(0.64	)
Diluted		(0.02	)		(0.12	)		(0.64	)

(1) Operations

The Company determined that refinery operations commenced under U.S. GAAP at December 1, 2004, which is the date management assessed that construction of the refinery was substantially complete and ready for its intended use.  The Company ceased capitalization of certain costs to the refinery project at this date and recognized one month’s results from sales, related costs of sales and operating expenses and administrative and general expenses in the statement of operations for the year ended December 31, 2004.

As disclosed in note 2(s) in the consolidated financial statements, operations commenced on January 1, 2005 under Canadian GAAP.  Therefore, the Company continued to capitalize December 2004’s results to the refinery project.  Due to the difference in the cost basis of the refinery, the depreciation expense recorded under U.S. GAAP differs from that recorded under Canadian GAAP.

The useful life for the refinery under U.S. GAAP is the same as that disclosed under Canadian GAAP.

(2) Indirect participation interest

As disclosed in note 20 in the consolidated financial statements, the Company entered into an indirect participation interest agreement in exchange for proceeds of $125,000,000.  Under Canadian GAAP, this amount was apportioned between non financial liabilities and equity.  Under U.S. GAAP, the Company has not bifurcated the amount as the Company has opted to utilize the scope exception under SFAS 133 Para 10(f) for ‘derivatives that serve as impediments to sales accounting’.

As explained in note 20, during the year ended December 31,2009, certain investors’ with a combined 12.635% interest in the eight well drilling program waived their right to convert their IPI percentage into 1,684,667 common shares. This waiver has resulted in conveyance being triggered on this portion of the IPI agreement for the year ended December 31, 2009.  As the initial IPI proceeds were not bifurcated under U.S. GAAP, the total conveyance proceeds available for the conveyed interest, the amounts offset against oil and gas properties, and the gain recognised in the statement of operations under U.S. GAAP differs to the Canadian GAAP amounts.  The following table discloses the impact of the conveyance on the IPI agreement under both U.S. GAAP and Canadian GAAP.

	Canadian GAAP			US GAAP			Difference
Impact of conveyance on IPI agreement	$			$			$
Conveyance proceeds available		15,023,049			17,408,001			2,384,952
Amount offset against oil and gas properties		(7,658,581	)		(8,561,533	)		(902,952	)
Gain recognised in the statement of operations		(7,364,468	)		(8,846,468	)		(1,482,000	)
		-			-			-

Consolidated Financial Statements   INTEROIL CORPORATION     52

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

During 2009, the Company bought a combined 4.8364% interest in the IPI Agreement from certain investors with the consideration settled in InterOil common shares (refer to section ‘Extinguishment of IPI liability’ section in note 20).  The extinguishment of liability model adopted by management for this transaction compares the fair value and book value of the IPI liability and transfers the difference to the statement of operations.  Under Canadian GAAP, $649,187 was transferred to contributed surplus as the initial liability was bifurcated between the liability and equity component, and this amount related to equity component.  However under U.S. GAAP, as the company has not bifurcated the liability, $649,187 has also been transferred to the statement of operations as an expense.

(3) Preference shares

As disclosed in Note 23 in the consolidated financial statements, 517,777 preference shares were issued to an investor in November 2007 for $15,000,000.

Under Canadian GAAP, the preference shares were assessed based on the rights attached to those shares and Management valued the equity and liability component of the instrument using the residual value basis.

As the Preference share agreement has contractual redemption provisions under ‘Fundamental change’ section mainly relating to listing requirements, shareholding etc, under U.S. GAAP, the preference shares needs to be classified under temporary equity classification in accordance with ASC 480-10.  Transaction costs amounting to $750,000 have been deducted from the total proceeds of $15,000,000.  Under Canadian GAAP the transaction costs attributable to the liability component was expensed.

In addition to the above, the 5% dividend paid has been included within long term borrowing costs within Canadian GAAP, but has been treated as a reduction to retained earnings under U.S. GAAP.

During the year ended December 31, 2008 the entire preference shares issued of 517,777 shares were converted into common shares.

(4) 8% subordinated debentures

As disclosed in Note 24 in the unaudited consolidated financial statements, on May 13, 2008, the Company completed the issue of $95,000,000 unsecured 8% subordinated convertible debentures with a maturity of five years.  Under Canadian GAAP, these debentures were assessed based on the rights attached to the instrument and Management valued the equity and liability component of the instrument using the residual value basis.

Under U.S. GAAP, Management assessed the debentures following the guidance under ASC 815 to determine whether the embedded conversion option needs to be bifurcated and disclosed separately.  The embedded conversion option did not satisfy the condition of embedded derivatives that requires separation due to the scope exception under ASC 815-10 paragraph 15-74(a) as the option is indexed to the Company’s own stock and would have been classified in Shareholder’s equity if it had been separated.

As ASC 815 bifurcation is not applicable, the provisions of ASC 470-20 requires that the instrument be assessed for any ‘Beneficial Conversion Features (”BCF”)’ included in the instrument, which should be separated using the intrinsic value method as noted.  Based on the guidance, the BCF has been valued at $8,821,320 which was separated and classified separately under equity as Contributed Surplus.  After separation, the liability component was being accreted over the life of the debentures, being 5 years till May 2013.

During the year ended December 31, 2009, all remaining debenture holders either exercised their conversion rights or were mandatorily converted into common shares due to a mandatory conversion resulting from daily VWAP of the common shares being above $32.50 for at least 15 consecutive trading days.

As U.S. GAAP requires the expensing of all unamortized deferred financing costs, placement fee, and the remaining accretion relating to debentures converted prior to its maturity in the period of the conversion.  No such expensing is required under Canadian GAAP. This amounts to an additional expense of $9,083,127 under U.S. GAAP during the year ended December 31, 2009.

(5) Investment in LNG Project/Deferred gain on contributions to LNG Project

As disclosed in Note 14 in the unaudited consolidated financial statements, a Shareholders Agreement was signed on July 30, 2007 which converted PNG LNG Inc. and its subsidiaries into a joint venture project from being a subsidiary of InterOil.  Under Canadian GAAP, joint ventures are proportionately consolidated into the Company’s consolidated financials based on the shareholding in the joint venture.

Consolidated Financial Statements   INTEROIL CORPORATION     53

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Applying the guidance under ASC 323-10, a corporate joint venture has to be equity accounted under U.S. GAAP. InterOil has also followed the guidance under ASC 505-10 wherein a gain on contributions to the joint venture is not recognised, however, a gain is recognised as a result of a change in economic interest.

On February 27, 2009, InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd, acquired Merrill Lynch’s interest in the Joint Venture Company. InterOil issued 499,834 common shares totalling $11,250,000 for its share of the settlement. This acquisition increased InterOil’s economic interest in the joint venture from 82.14% to 86.66%.

InterOil will account for the joint venture using equity accounted method.  In addition to the gain or loss recognised as part of the operations, InterOil will also recognise any difference between the Investment carried in its balance sheet and the underlying equity in net assets of the joint venture in the statement of operations and the investment balance will increase/decrease in line with this difference.

The adjustments to reflect the reversal of proportionately consolidated balances and take-up of equity accounted balances have been summarised below. Given below is the Midstream – Liquefaction consolidated balance sheet and statement of operations under Canadian GAAP and U.S. GAAP.  The statement of operations incorporates results for the year ended December 31, 2009.  PNG LNG Inc. was a subsidiary of InterOil until the date of the Shareholder’s Agreement and has been proportionately consolidated subsequent to that date.

Midstream - liquefaction				GAAP
Consolidated Balance Sheet	Canadian GAAP			Adjustments			US GAAP
Cash and cash equivalents		1,695,514			(1,695,414	)		100
Other assets		12,379			(12,379	)		-
Current assets		1,707,893			(1,707,793	)		100
Investment in PNG LNG Inc.		-			13,121,141			13,121,141
Goodwill		6,626,317			(5,761,940	)		864,377
Plant and equipment		2,313,469			(2,313,469	)		-
Total assets		10,647,679			3,337,939			13,985,618
Accounts payable and accrued liabilities		1,281,767			(1,281,767	)		0
Intercompany payables		19,085,298			(869,354	)		18,215,944
Current liabilities		20,367,065			(2,151,121	)		18,215,944
Deferred gain on contributions to LNG project		13,076,272			(13,076,272	)		-
Total non-current liabilities		13,076,272			(13,076,272	)		-
Share capital		1			-			1
Accumulated deficit		(22,795,659	)		18,565,332			(4,230,327	)
Shareholders' Equity		(22,795,658	)		18,565,332			(4,230,326	)
Total liabilities and Shareholders' equity		10,647,679			3,337,939			13,985,618

Midstream - liquefaction				GAAP
Consolidated Statement of Operation	Canadian GAAP			Adjustments			US GAAP
Interest income		7,741			(7,741	)		-
Total revenues		7,741			(7,741	)		-
Office and Administrative expenses		4,266,771			(3,166,815	)		1,099,956
Depreciation		56,996			(56,996	)		-
Professional fees		2,841,129			(2,576,874	)		264,255
Borrowing costs		1,218,258			-			1,218,258
Exchange (Gain) loss		(41,053	)		41,053			-
Loss on equity accounted investment		-			4,739,339			4,739,339
Income taxes		54,670			(54,670	)		-
Total expenses		8,396,771			(1,074,963	)		7,321,808
Net (loss)/gain		(8,389,030	)		1,067,222			(7,321,808	)

Consolidated Financial Statements   INTEROIL CORPORATION     54

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

(6) Deferred Financing costs

Deferred financial costs are offset against the respective liabilities under Canadian GAAP; however, the same is disclosed as a separate item on the face of the balance sheet under US GAAP in accordance with guidance under ASC 835-30.

(7) Income tax effect of adjustments

The income tax effect of U.S. GAAP adjustments was an increase to the future tax asset of $2,331,829 (2008 – reduction of $2,671,594, 2007 – reduction of $3,403,154) for the year ended December 31, 2009 due to an increase in the loss carry-forwards.  A corresponding increase in the valuation allowance was recorded.

(8) Non controlling interest

The non-controlling interest movements are the result of the U.S. GAAP adjustments relating to the Midstream operations described in point 1 above.  Non-controlling interests are classified under temporary equity classification on the balance sheet under Canadian GAAP; however, the same is disclosed as equity, but separate from the parent’s equity, under US GAAP in accordance with guidance under ASC 810-10.  In addition, under Canadian GAAP, net income attributable to the non-controlling interest generally was reported as an expense or other deduction in arriving at consolidated net income.  However, ASC 810-10 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest.  It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest.

Recent Accounting Pronouncements applicable to the Company

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued ASC 810.  The objective of this Statement is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  This Statement changes the way the consolidated income statement is presented. It requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest.  It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest.  Previously, net income attributable to the non-controlling interest generally was reported as an expense or other deduction in arriving at consolidated net income.  This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, except for the presentation and disclosure requirements which shall be applied retrospectively for all periods presented.  The Company has complied with the disclosure requirements under this standard for the year ended December 31, 2009.

Disclosures about derivative instruments and hedging activities

In March 2008, the FASB issued ASC 815.  This statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting.  Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  The statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation.  This disclosure better conveys the purpose of derivative use in terms of the risk that the entity is intending to manage.  Disclosing the fair values of derivative instruments and their gains and losses in a tabular format should provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period.  Disclosing information about credit-risk-related contingent features should provide information on the potential effect on an entity’s liquidity from using derivatives.  This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.  The Company has complied with the disclosure requirements under this standard for the year ended December 31, 2009.

Consolidated Financial Statements   INTEROIL CORPORATION     55

InterOil Corporation Notes to Consolidated Financial Statements (Expressed in United States dollars)

30. Reconciliation to generally accepted accounting principles in the United States (cont’d)

Subsequent events

In May 2009, the FASB issued ASC 855-10.  The objective of this statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued.  In particular, this statement sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.  This statement is effective for interim and annual periods ending after June 15, 2009.  The Company has complied with the disclosure requirements under this standard for the year ended December 31, 2009.

The FASB accounting standards codification and the hierarchy of generally accepted accounting principles

In June 2009, the FASB issued ASC 105.  The FASB Accounting Standards Codification will become the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative.  This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  Following this Statement, the Board will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates. The Board will not consider Accounting Standards Updates as authoritative in their own right. Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the bases for conclusions on the change(s) in the Codification.  The Company has complied with the disclosure requirements under this standard for the year ended December 31, 2009.

Measuring liabilities at fair value

In August 2009, the FASB issued ASU 2009-05.  This update provides amendments to the fair value measurement of liabilities.  In particular, the update provides clarification that in certain circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using either a valuation technique that uses the quoted price of the identical liability when traded as an asset or the quoted prices for similar liabilities or similar liabilities when traded as assets, or a valuation technique that is consistent with the principles of Topic 820.  This update also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability.  This update is effective for the first reporting period, including interim periods, beginning after issuance.  The Company has complied with the disclosure requirements under this standard for the year ended December 31, 2009.

Accounting for transfers of financial assets

In June 2009, the FASB issued ASC 860.  The objective of this statement is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets.  In particular, this statement removes the concept of a qualifying special-purpose entity, and removes the exception from applying ASC 810-10 relating to consolidation of Variable Interest Entities, to qualifying special-purpose entities.  This statement is effective at the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter.  The Company does not expect that the application of this standard will have a material impact on the financial statements.

Consolidation of variable interest entities

In June 2009, the FASB issued ASC 810 which addresses the effects on consolidation of Variable Interest Entities, as a result of the elimination of the qualifying special-purpose entity concept in ASC 860, and concerns about the application of certain key provisions of the standard, including those in which the accounting and disclosures do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity.  This statement is effective at the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter.  The Company does not expect that the application of this standard will have a material impact on the financial statements.

Consolidated Financial Statements   INTEROIL CORPORATION     56

EX-99.3

  
    Unassociated Document
    
    
    
    
    
    

EX-99.4

Exhibit 4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the use in this Annual Report on Form 40-F and the incorporation by reference in the Registration Statements on Form S-8 (No. 333-162139), Form S-8 (No. 333-148673), Form S-8 (No. 333-124617), Form F-10/A (No. 333-120383), Form F-10/A (No. 333-124641), Form F-10/A (No. 333-148960), Form F-10/A (No 333-152153), Form F-10/A (No. 333-152459), and Form F-10 (No. 333-157617) of InterOil Corporation of our report dated March 1, 2010 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, which is Exhibit 2 to this Form 40-F.

/s/ PricewaterhouseCoopers

PricewaterhouseCoopers

Melbourne, Australia

March 1, 2010

EX-99.5

Exhibit 5

CERTIFICATIONS

I, Phil E. Mulacek, certify that:

1. I have reviewed this annual report on Form 40-F of InterOil Corporation (the “issuer”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the issuer and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by this annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors:

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:  March 1, 2010	/s/ Phil E. Mulacek
	Phil E. Mulacek
	Chief Executive Officer

EX-99.6

Exhibit 6

CERTIFICATIONS

I, Collin F. Visaggio, certify that:

1. I have reviewed this annual report on Form 40-F of InterOil Corporation (the “issuer”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the issuer and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by this annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors:

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:  March 1, 2010	/s/ Collin F. Visaggio
	Collin F. Visaggio
	Chief Financial Officer

EX-99.7

Exhibit 7

Certification Required by Rule 13a-14(b) or Rule 15d-14(b)

of the Securities Exchange Act of 1934 and

Section 1350 of Chapter 63 of Title 18 of the United States Code

In connection with the report of InterOil Corporation (the “Company”) on Form 40-F for the fiscal year ending December 31, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Phil E. Mulacek, Chief Executive Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  March 1, 2010
	/s/ Phil E. Mulacek
	Phil E. Mulacek
	Chief Executive Officer

EX-99.8

Exhibit 8

Certification Required by Rule 13a-14(b) or Rule 15d-14(b)

of the Securities Exchange Act of 1934 and

Section 1350 of Chapter 63 of Title 18 of the United States Code

In connection with the report of InterOil Corporation (the “Company”) on Form 40-F for the fiscal year ending December 31, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Collin F. Visaggio, Chief Financial Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  March 1, 2010
	/s/ Collin F. Visaggio
	Collin F. Visaggio
	Chief Financial Officer