40-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

Form 40-F

(Check One)

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

or

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

For the fiscal year ended December 31, 2008

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	NYSE Amex 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:

  þ Annual Information Form þ Audited Annual Financial Statements

As of December 31, 2008, 35,923,692 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. o Yes 82-                     þ 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. þ Yes o 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 2008 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, 2008, 2007 and 2006, including the report of 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 29 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, 2008 (“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, 2008.

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 2008, 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, 2008.

     Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers, an independent registered public accounting firm, as stated in their report included on page 2 of the consolidated financial statements in this Annual Report on Form 40-F.

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MATERIAL CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

     During 2008, the Company enhanced internal controls over account reconciliations for the downstream business segment and over the financial reporting process for foreign currency translation. Specifically, management increased training for reconciliations and account analysis, and increased documentation in relation to and monitoring of related internal controls over financial reporting. Other than these control enhancements, there have been no changes in internal control over financial reporting during fiscal year 2008 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. Mr. Donald Hansen was a member of the Committee until his resignation on October 14, 2008. Mr. Lewis became a member of the Audit Committee on November 26, 2008. 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 NYSE Amex Stock Exchange and 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, 2008 and December 31, 2007 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 $1,416,583 and $968,316, 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, 2008 and December 31, 2007 by PricewaterhouseCoopers not otherwise reported above were $170,404 and $14,887, respectively. The audit-related services provided by PricewaterhouseCoopers during 2008 consisted of procedures performed with respect to the registration statements and work on the shelf prospectus prepared for private placements during that year. The audit-related services provided by PricewaterhouseCoopers during 2007 consisted of procedures performed with respect to the shelf prospectus prepared for private placements 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, 2008 and December 31, 2007 by PricewaterhouseCoopers were $473,493 and $148,621, respectively.

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     All Other Fees. Fees billed for professional services rendered related to all other services for the Company for the fiscal years ended December 31, 2008 and December 31, 2007 by PricewaterhouseCoopers were $39,192 and $266,870, respectively. Of the fees billed in 2008, all $39,192 related to procedures performed in connection with the quarterly financial reporting of the Company’s subsidiaries. Of the fees billed in 2007, $38,533 related to procedures performed in connection with the quarterly financial reporting of the Company’s subsidiaries, and $228,337 related to involvement in responding to the Commission’s comments relating to the Company’s accounting for the fair value of the Indirect Participation Interests described in the Company’s 2008 Annual Information Form.

     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 2007 and 2008 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”), which the Company anticipates will be effective on March 31, 2009. 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 or exceeds 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:

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     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.

     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 bylaws that fix 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.

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     Board Committee Mandates. The mandates of the Company’s Audit Committee, Compensation 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 and Chief Executive Officer 

Date: March 27, 2009

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, 2008.
2.	Audited annual consolidated financial statements for the year ended December 31, 2008, including a reconciliation to United States generally accepted accounting principles.
3.	Management’s Discussion and Analysis for the year ended December 31, 2008.
4.	Consent of PricewaterhouseCoopers dated March 27, 2009.
5.	Consent of GLJ Petroleum Consultants Limited dated March 27, 2009.
6.	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
7.	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
8.	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.
9.	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

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	3
CONVERSION	4
GLOSSARY OF TERMS	4
CORPORATE STRUCTURE	7
GENERAL DEVELOPMENT OF THE BUSINESS	8
BUSINESS STRATEGY	12
DESCRIPTION OF OUR BUSINESS	13
UPSTREAM — EXPLORATION AND PRODUCTION	13
MIDSTREAM — REFINING	17
MIDSTREAM — LIQUEFACTION	19
DOWNSTREAM — WHOLESALE AND RETAIL DISTRIBUTION	20
INTEROIL RESOURCES	21
THE ENVIRONMENT AND COMMUNITY RELATIONS	23
RISK FACTORS	24
DIVIDENDS	33
DESCRIPTION OF CAPITAL STRUCTURE	33
MARKET FOR SECURITIES	37
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	45
TRANSFER AGENT AND REGISTRAR	48
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, 2008. It should be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2008 and the 2008 management’s discussion and analysis, copies of which may be obtained online from SEDAR at www.sedar.com.

In this AIF, references to “we”, “us”, “our”, “Company”, 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, 2008 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

Earnings before interest, taxes, depreciation and amortization, commonly referred to as 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 EBITDA to the net income (loss) under GAAP, refer to the Non-GAAP Measures Reconciliation of our 2008 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, statements regarding our plans for our exploration activities and other business segments and results therefrom, expanding our business segments, 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 impact the matters addressed in these forward-looking statements, including but not limited to:

• the inherent uncertainty of oil and gas exploration activities;

• potential effects of oil and gas price declines;

• the uncertain outcome of our negotiations with the Papua New Guinea government to determine the price at which our refined products may be sold;

• the availability of crude feedstock at economic rates;

• the ability to meet maturing indebtedness;

• the uncertainty in our ability to attract capital;

• general economic conditions and illiquidity in financial and credit markets

• interest rate risk;

Annual Information Form INTEROIL CORPORATION      2

• the impact of competition

• losses from our hedging activities;

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

• fluctuations in currency exchange rates;

• the recruitment and retention of qualified personnel;

• the availability and cost of drilling rigs, oilfield equipment, and other oilfield exploration services;

• our ability to finance the development of our LNG facility;

• our ability to timely construct and commission our LNG facility;

• the margins for our refined products;

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

• difficulties in marketing our refinery’s output;

• exposure to certain uninsured risks stemming from our refining operations;

• weather conditions and unforeseen operating hazards;

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

• compliance with and changes in foreign governmental laws and regulations, including environmental laws;

• landowner claims;

• the uncertainty in being successful in pending lawsuits and other proceedings;

• law enforcement difficulties;

• the impact of legislation regulating emissions of greenhouse gases on current and potential markets for our products;

• stock price volatility; and

• contractual defaults.

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, future oil and natural gas 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 impact of increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop production and reserves 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 included in this AIF will prove to be accurate. 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 have no obligation to 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

Annual Information Form INTEROIL CORPORATION      3

Crude Oil and Natural Gas Liquids			Natural Gas
	mbbl	thousand barrels		mmscf	million standard cubic feet
	mmbbls	million barrels		mmscfpd	million standard cubic feet per day
	NGL or NGLs	natural gas liquids, consisting of any one or more of propane, butane and condensate		scf	standard cubic feet
	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 and does not represent a value equivalency at the wellhead.

CONVERSION

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or 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

“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.

“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

Annual Information Form INTEROIL CORPORATION      4

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.

“GAAP” Generally accepted accounting principles.

“Gas” 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” Independent Consumer and Competition Commission in Papua New Guinea.

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

“IPF” InterOil power fuel. InterOil’s marketing name for low sulfur waxy residue oil or LSWR.

“IPP” Import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP 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” 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, an affiliate of Merrill Lynch, and PacLNG to construct the proposed LNG plant.

“LNG” Liquefied natural gas. Natural gas converted to a liquid state by pressure and severe cooling, 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.

“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” Low sulfur waxy residual fuel oil.

Annual Information Form INTEROIL CORPORATION      5

“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” 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.

“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.

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

“OPIC” Overseas Private Investment Corporation.

“Pac LNG” Pacific LNG Operations Ltd., a company incorporated in the Bahamas and affiliated with Clarion Finanz A.G.

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

“PGK” Currency of Papua New Guinea.

“PDL” Petroleum Development License. The right given by the State to develop a field in readiness for commercial production.

“PNGDV” PNG 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 – Indirect Participation Interest Agreements”).

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

“PRL” Petroleum Retention License. The tenement given by the Independent State of Papua New Guinea 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 natural gas which are not producing due to lack of available transportation facilities, available markets or other reasons.

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

“Sweet/sour crude” Definitions which describe 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.

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CORPORATE STRUCTURE

Name, Address and Incorporation

InterOil Corporation is a Yukon Territory corporation, continued under that Territory’s Business Corporations Act.

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

Intercorporate 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 whose focus is on operations in Papua New Guinea and its surrounding region. The following is a summary of significant events in the general development of InterOil’s businesses and at a corporate level 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 have defined as the Elk/Antelope field in Papua New Guinea under the Indirect Participation Interest agreement dated February 25, 2005. (See “Description of Our Business — Upstream Exploration and Production — Indirect Participation Interest Agreements” for further information) This has led to hydrocarbon discoveries in the Elk and Antelope structure. We continue to evaluate the size and structure of the Elk and Antelope fields by drilling additional development wells. Our ability to commercialize these discoveries will depend on the results of these development wells. In addition, there is no market for natural gas in PNG, so our ability to sell 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 years to complete. As discussed below, we are evaluating the construction of a liquefied natural gas facility near our refinery in PNG. No assurances can be given that we will be able to successfully construct such a facility, or as to the timing of such construction..

In 2006, activity centered around drilling the Elk-1 well in the Eastern Papua Basin, on PPL 238. The Elk-1 well was an exploration well spudded in February 2006 to test a fractured limestone target in the Elk structure. It encountered highly pressured gas from a fracture system at around 1,694 metres depth. The Elk-1 discovery well was completed in November 2006, at a total depth of 1,983 metres.

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 4 ¹/2 inch tubing as a potential producer and completion work ended on August 31, 2008. On September 4, 2008, the well recorded a short term gas flow rate of 105 mmscfpd.

The Antelope 1 well was spudded on October 15, 2008. On December 31, 2008, gas was encountered at 1,748 metres in a limestone/dolomite reservoir which was 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 1 flowed 13.1 mmscfpd. Drilling continued to 2,710 metres, the well was logged and 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.

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/Antelope field and PPLs 236, 237 and 238. A right of first refusal to purchase hydrocarbon condensates from these licenses was retained.

In October 2008, Petromin, a government entity mandated to invest in resource projects on behalf of the State, entered into an agreement with us to take a direct interest in the Elk/Antelope field and fund 20.5% of the costs of its development, subject to a PDL being granted within a certain timeframe. (See “Material Contracts – Investment Agreement dated October 30, 2008”) 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

Annual Information Form INTEROIL CORPORATION      8

is formed, 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 formed, the conveyance of this interest to the State is able to be formalized, 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. Under the licensing regulations of Papua New Guinea, the State has the right to purchase a 20.5% working interest in any hydrocarbon discovery. The State may also elect to participate in a further 2.0% working interest on behalf of the landowners of the licensed areas.

The commercialization of any resource discovered by Elk/Antelope field is uncertain at present and is not expected to prior to 2014, as the discovery is located in an area requiring construction of a pipeline and a gas liquefaction facility in order to process any gas extracted, in addition to required approvals. Due to the substantial expected infrastructure capital requirements, additional wells would be required to develop sufficient natural gas resources to feed an LNG facility. Only once economic and technical uncertainties have been resolved, will a Financial Investment Decision (FID) be able to be made to proceed with the construction of the necessary LNG plan infrastructure. No assurances can be given that we will be able to successfully construct such a facility, or as to the timing of such construction.

In order to progress the development and commercialization of the Elk/Antelope discoveries, 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/Antelope field is being prepared in respect of an area on PPL 238 totalling 105,445 acres (42,178 hectares). Grant of this PRL would allow us to evaluate the technical and commercial feasibility of gas production from the Elk/Antelope field.

Midstream – Refining segment

During the 2006 year, we completed an optimization program at our refinery which resulted in an improvement in the production slate and in particular, an improvement in the quantity of higher value refined products as a percentage of total products produced. The program included the study of methods by which we could reduce our exposure to low margin product sales and improve the efficiency of fuel firing and power generation at the refinery. A part of this program included the acquisition and installation of a new set of three Hyundai generators, each with an output capacity of 1.5 megawatts. These new generators are powered by the low sulfur waxy residue produced at our refinery.

Petrofac Facilities Management Limited, a facilities management company, was responsible for the day-to-day operation and maintenance of our refinery until October 31, 2006, when we assumed direct operation of the refinery and terminated the Petrofac contract. This change was made so as to better control the costs and performance of the refinery.

From November 2007, the basis of calculating the IPP at which products from our refinery may be sold domestically in PNG was revised on an interim basis which more closely mirrored changes in the costs of crude feedstock than the previous pricing formula. The interim IPP formula was modified 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. Minor additional adjustments to this interim formula were made in June 2008 based on ongoing discussions with the government, with a view to finalizing a permanent replacement to the IPP formula as is required under our Project Agreement with the State (See “Material Contracts – Project Agreement”). However, the outcome of the review is uncertain and the application of the revised formula may be discontinued. See “Risk Factors”.

During 2007, we negotiated and implemented a hosting arrangement with Origin Energy LPG Limited for InterOil to store propane and butane products.

During 2008, our total throughput per day (excluding shut down days) was 22,011 bbls per operating day versus 19,713 bbls per operating day in 2007. The total number of barrels processed at our refinery for 2008 was 5.67 million as compared to 5.57 million in 2007. 2008 marked the first time that we achieved an operating profit from our refining operations for the year. In addition, during 2008 further improvements were made to the refinery such that its operational capacity has expanded from its nameplate 32,500 bblspd up to 36,500 bblspd.

In 2008 we faced significant 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. In May 2008, we entered into short and long term hedges which helped us to manage a portion of this timing and margin risk. Our hedges netted us

Annual Information Form INTEROIL CORPORATION      9

$27.8 million profit during the year with a further $18.0 million of unrealized hedging gains carried forward in our balance sheet for unsettled hedge accounted transactions as at year end. Subsequent to year end, in January 2009, these unrealized hedges were terminated and the mark-to-market gains were realized on a cash basis and will be accounted for during 2009 as the underlying transactions occur.

We fund our working capital requirements for the refinery by means of a facility provided by BNP Paribas. This facility is subject to annual review. (See “Material Contracts – Secured Revolving Crude Import Facility”) In 2008, the overall facility limit was increased by $20.0 million to $190.0 million to accommodate higher crude prices and resulting increases in working capital requirements.

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 Pacific LNG Operations Ltd., an affiliate of Clarion Finanz A.G. The tri-partite agreement related to a proposal for the construction of a liquefaction plant to be built adjacent to our refinery. The joint venture 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/Antelope field, 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.

On July 30, 2007, a shareholders’ agreement was signed between InterOil LNG Holdings Inc., a subsidiary of InterOil, Pacific LNG Operations Ltd., Merrill Lynch Commodities (Europe) Limited and PNG LNG Inc. (“Joint Venture Company”) for the development of the gas liquefaction facility and associated infrastructure. Some progress has been made on a number of the key components necessary to develop the proposed LNG Project including certain engineering work.

In March 2008, Bechtel was selected to undertake the front end engineering and design (FEED) and engineering, procurement and contracting work for the proposed LNG facility.

In 2008, certain disputes arose among Merrill Lynch and the other partners to the LNG Project, including InterOil. (See “Legal Proceedings and Regulatory Actions”).

In February 27, 2009, a settlement agreement was entered into whereby InterOil LNG Holdings Inc. and Pacific LNG Operations Limited, acquired Merrill Lynch’s interests in the Joint Venture Company. 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 is subject to a post closing balancing payment. 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”).

Downstream – Wholesale and Retail Distribution

In January 2006, we entered into an agreement to acquire all of Shell Papua New Guinea Limited’s retail and distribution assets in Papua New Guinea in exchange for $29.1 million. This transaction closed effective October 1, 2006, and resulted in the additions of 4 terminals, 4 depots, 17 retail sites and 14 aviation facilities to our existing downstream asset base. All of these assets now operate under the InterOil Products brand name.

In July 2006, we completed the construction of a two million liter diesel storage tank at our terminal in Wewak, East Sepik province in Papua New Guinea, to augment our storage availability. The East Sepik province has experienced substantial growth in commercial and economic activity in recent years.

In 2007, we acquired three additional aviation fuelling depots, making us the largest aviation fuel supplier in Papua New Guinea outside Port Moresby. During 2007 and 2008, we conducted a terminal and depot asset rationalization and refurbishment program. This program is substantially complete.

As of December 31st, 2008, we provided petroleum products to 51 retail service stations that operate under the InterOil brand name. Of the 51 service stations that we supply, 19 are owned by InterOil or head leased, with a sublease to company-approved operators. The other 32 service stations are independently owned and operated. We supply products to each of these service stations pursuant to retail supply agreements.

Annual Information Form INTEROIL CORPORATION      10

Financing

In 2006, InterOil undertook the following financing transactions:

• In May 2006, InterOil entered into a secured credit bridging facility for $130.0 million provided by Merrill Lynch Capital Corporation and Clarion Finanz A.G., repayable in May 2008. The loan was fully drawn down by December 31, 2006 and was repaid in May 2009.

• In May 2006, we repaid $25.0 million of our unsecured borrowings.

• In May 2006, we entered into an agreement to amend the terms of the original PNGDV indirect participation agreement whereby PNGDV converted their interest into 575,575 InterOil common             shares while retaining a 6.75% interest in the next four wells (the first of which was Elk-1) to be drilled by InterOil. PNGDV also retained the right to participate for up to an interest of 5.75% in the 16 wells that follow the four wells mentioned above by contributing their share of well costs.

• In August 2006, the credit limit under the BNP Paribas working capital facility entered into in 2004 was increased to $170.0 million from $100.0 million.

• In December 2006, we renegotiated the terms of the secured loan with OPIC (see “Material Contracts — OPIC Loan Agreement”) where the half yearly principal payment due in December 2006 and June 2007 of $4.5 million each, were deferred until December 31, 2007 and interest previously due on December 31, 2006 and June 30, 2007 was deferred until September 30, 2007.

In 2007, InterOil undertook the following financing transactions:

• In July 2007, we entered into the LNG Project Shareholders Agreement which had the effect of freezing the interest rate on the $130.0 million secured credit bridging facility 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.

• In December 2007, we amended our OPIC loan agreement in order to defer two installments of $4.5 million, each due on December 31, 2007, until the final year of the OPIC loan. They are now due 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 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 was repaid on May 12, 2008 with funds raised from the issuance of $95.0 million worth of 8% subordinated convertible debentures. In July and August 2008, $15.0 million worth of the $95.0 million 8% debentures issued in May were converted into 600,000 common shares. In November, a further $1.0 million of the $95.0 million 8% debentures were converted into 41,000 common shares.

• In August 2008, we filed a short form 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, which enables us to provide financial flexibility for the future and issue, from time to time during the following 25 months, up to a total of $200.0 million of debt securities, common shares, preferred shares and/or warrants in one or more offerings.

• During 2008, we negotiated increases to and the renewal of our crude working capital facility with BNP Paribas. As a result of variations in crude oil prices, a temporary increase from a total of $170 million to $220 million was required. This limit was decreased to $190 million on November 30, 2008. As of

Annual Information Form INTEROIL CORPORATION     11

December 31, 2008, $109 million remained available for use under the crude working capital facility. The weighted average interest rate under the crude working capital facility was 5.11% for the year ended December 31, 2008.

•

In October 2008, we secured a Papua New Guinea 150.0 million Kina (approximately $57.5 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. As at December 31, 2008, the weighted average interest rate for the facilities was 7.25%. The Westpac facility has an initial term of three years and is due for renewal in August 2011. The BSP facility is renewable annually and is due for renewal in August 2009. As at December 31, we had drawn $15.4 million of the combined facility

Management Team

During 2006, 2007 and 2008, InterOil’s Board of directors and senior management changed as follows:

• Effective July 1, 2006, Dr. Jack Hamilton was appointed President.

• On August 3, 2006, InterOil announced that Mr. Tom Donovan, Chief Financial Officer, left us following completion of his employment agreement.

• On August 30, 2006, InterOil announced that Mr. William Jasper III was appointed President and Chief Operating Officer. At the same time, Mr. Christian Vinson, the former Chief Operating Officer, was appointed Executive Vice President Corporate Development and Government Relations, while Dr. Jack Hamilton, the former President, was nominated by InterOil to serve as Chief Executive Officer of the recently formed PNG LNG Inc.

• On October 1, 2006, Dr. Michael Folie retired as a director.

• On October 26, 2006, Mr. Collin Visaggio was appointed Chief Financial Officer.

• On December 29, 2006, Mr. Donald Hansen was appointed as an independent director and also agreed to serve as a member of the Audit, Nominating and Governance and Compensation committees.

• 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 the Audit, Compensation and Nominating and Governance committees.

BUSINESS STRATEGY

InterOil’s strategy is to develop a vertically integrated energy company in Papua New Guinea and surrounding regions, 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 with the produced LNG exported overseas. InterOil is aiming to pursue this strategy by:

Developing our position as a business operator in Papua New Guinea

• Build on 14 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 in Papua New Guinea

• Continue growth in profitable market share in the region

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

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• Explore improved transport efficiencies and economics

Maximizing the value of our exploration assets

• Seek possible early cash flows from NGLs production

• Establish gas volumes sufficient to underpin the LNG Project

• Introduce strategic investors through the partial sale of Elk/ Antelope field, the LNG Project and associated LNG off-take to accelerate exploration and development activities.

Building an export gas liquefaction business in Papua New Guinea

• Finalize agreement with the State establishing the fiscal and regulatory regime applicable to the LNG Project.

• Select and contract with strategic partners

• Establish LNG Project’s commercial viability and structure

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.
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 LNG processing facility in Papua New Guinea (the LNG Project).
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, 2008, we had 620 full-time employees in all segments, with 69 in upstream, 138 in midstream, 348 in downstream and 65 in corporate.

UPSTREAM — EXPLORATION AND PRODUCTION

Description of Properties

As at December 31, 2008 we had interests in four PPLs in Papua New Guinea covering approximately 8.7 million gross acres, of which approximately 8.0 million net acres were operated by InterOil. PPLs 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 Papua New Guinea in the Gulf of Papua.

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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, 2008:

			InterOil Working			Acreage		Acreage
License	Location	Operator	Interest			Gross		Net
PPL 236	Onshore	InterOil		100.00	%		2,244,449		2,244,449
PPL 237	Onshore	InterOil		100.00	%		1,618,534		1,618,534
PPL 238	Onshore	InterOil		100.00	%		4,168,651		4,168,651
PPL 244	Offshore	Talisman		15.00	%		675,400		101,310
			Total				8,707,034		8,132,944

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. Subsequent to year end, in March, 2009, all three licenses were renewed in respect of what we considered the most prospective 50% of the license acreage. With the Elk/Antelope discoveries lying primarily within PPL 238, our expenditures on that license exceeded the license commitment under the primary term. On each of the other two licenses, PPL 236 and 237, we were granted a deferred commitment into the second term. As a result of the relinquishments made upon the renewals, our operated exploration licenses now cover an area totaling 4,015,817 acres, including 105,445 acres in the Elk/Antelope field.

With the approval of our extension applications subsequent to year end, the exploration acreage for the three renewed PPLs has been reduced as follows:

			Second Term
License	Initial Acreage		Acreage (50%)
PPL 236		2,244,449		1,122,224
PPL 237		1,618,534		809,267
PPL 238		4,168,651		2,084,326
Total		8,031,634		4,015,817

The PPL license renewals also require that we make further commitments on spending within those license areas during the license term. Set out below are the applicable commitments based on the approved renewals in March 2008:

	License
	Issued for		Commitment		Commitment		Total License
	second	Second	Years 1 - 2		Years 3 - 5		Commitment		License
License	term in	Term	(US $ Millions)		(US $ Millions)		(US $ Millions)		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

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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 100% 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 to acquire a 22.5% interest in any PDL, by contributing its share of exploration and development costs. The table below sets forth the potential dilution of existing working interests in a discovery in the event that the State exercises its right to acquire its allocated interest in a discovery.

				With State
Participant	Working interests *			participation
InterOil Corporation		71.825	%		55.67	%
IPWI Investors		21.425	%		16.60	%
PNGDV		6.75	%		5.23	%
State		0.00	%		22.50	%
Total		100.00	%		100.00	%

* These interests assume all existing partners as at December 31, 2008 elect to participate.

Our current exploration efforts are focused on the Operated Exploration Licenses, with the vast majority of our exploration expenditure relating to PPLs 238 and 237, where the Elk/Antelope field is located.

On October 30, 2008, Petromin, a government entity mandated to invest in resource projects on behalf of the State, entered into an agreement to take a 20.5% direct interest in the Elk/Antelope field. If certain conditions in the agreement are met, Petromin has agreed to fund 20.5% of the costs of developing the Elk/Antelope field. The State’s right to invest arises 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, or if the State does not designate Petromin to hold its interest at that time. In the event the PDL is not granted for the Elk/Antelope field, Petromin will be issued InterOil common shares. We expect the PDL to be granted in due course and that no shares will be issued to Petromin.

Petroleum Prospecting License 236

We have a 100% working interest in PPL 236, subject to elections made by holders of indirect participation interests described below. We are the operator of the license. During 2006, we conducted an extensive review of available data in this license in preparation for submission of a work program to further our exploration of the license in 2007. This license covers an area that includes our refinery and it has limited road access. We believe that the proximity of this license area to Port Moresby would reduce the costs of developing any future oil or gas discoveries. We conducted a ground geological survey over this license area in the fourth quarter of 2008.

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 2006, we carried out an airborne gravity/magnetic survey consisting of 2,471 miles over the western and southern parts of this license. In 2007, 28 miles (44 kilometres) of the 144 mile (230 kilometres) Elk appraisal 2D seismic program were acquired over PPL 237. Our current geological interpretation indicates that a portion of the Elk/Antelope field lies on PPL 237, and the Antelope-2 well location, currently under construction is located in this license area. This well would satisfy our obligation to drill a well on PPL 237 in the first year of the second term of the PPL 237 license.

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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/Antelope field 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.

Petroleum Prospecting License 244

We have a 15% working interest in PPL 244. 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 applying for State approval for a deferral of the 2009 well commitment.

Petroleum Development License (“PDL”)

In order to progress the development and commercialization of the Elk/Antelope discoveries, 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. We expect to submit an application covering five graticular blocks in PPL238 identified on government maps as blocks 2606, 2678, 2679, 2751 and 2823.

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 is held, subject to periodic review. It is at this stage that the State interest would be novated on the Papua New Guinea Petroleum register as a partner on the license, if the State opts to take up such interest.

Indirect Participation Agreements

On December 31, 2008, two groups of investors held the right to participate in up to a 28.175% working interest in the Elk/Antelope field, by paying their share of all testing, completion, appraisal well and subsequent field infrastructure costs under certain participation agreements. Our current interest in the Elk/Antelope field is therefore 71.825%.

In May 2003, we entered into an indirect participation agreement with PNGDV. In May 2006, we entered into a further agreement to amend the terms of the original PNGDV indirect participation agreement under which PNGDV converted its interest into 575,575 InterOil common shares while retaining a 6.75% interest in the next four wells (the first of which was Elk-1) 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 IPI agreement with institutional accredited investors (IPI holders) pursuant to which the investors 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.

In addition to the above, PNG Energy Investors (“PNGEI”), an indirect participation interest investor who converted all of its then existing interest into 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, 2008 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 wells.

For further details on these Indirect Participation Agreements, refer to the “Material Contracts” section of this AIF.

If a PDL is granted, investors in our indirect participation interest programs 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.

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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 “Marketing” 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, not all domestic demand was sourced from our refinery, as some competing product was imported and sold in Papua New Guinea 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 and is valued by more complex refineries as cracker feedstock.

Facilities and Major Subcontractors

Our refinery includes a jetty with two berths for loading and off-loading ships and a road tanker loading system. 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 staffed and operated by an independent company, SGS Australia Pty Limited, which is an ISO 9000 quality management system accredited company. The laboratory received Australian National Association of Testing Authorities (“NATA”) accreditation in 2006. All crude imports and finished products are tested and certified on-site to contractual specifications. SGS also provides independent certification of quantities loaded and discharged at the refinery.

Crude Supply and Throughput

In December 2001, we entered into an agreement with BP Singapore Pte Limited for the supply of crude feedstock to our refinery. This agreement continues until June 2009. 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 are currently reviewing 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.

Marketing

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 an Import Parity Price or IPP. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product that is being imported. For each refined product 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 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. The basis of calculating IPP was revised in November 2007 on an interim basis which more closely mirrored changes in the costs of crude feedstock than the previous pricing formula. The interim IPP formula was modified 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. Minor adjustments to this interim formula were made in

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June 2008 based on ongoing discussions with the government with a view to finalizing a permanent replacement to the IPP formula.

The major export product from our refinery is naphtha, which was sold to Shell International Eastern Trading Company on a term basis pursuant to a contract that expired in September 2008. A new 12 month term contract was signed with Sojitz Corporation for sales of export Naphtha from October 1, 2008 to September 30, 2009. During 2008, there were six export cargoes of naphtha averaging approximately 172,000 metric tons each. 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 due to the tightened product quality specifications in the Australian market. However, we are pursuing export opportunities in other Pacific Island markets where our products meet existing quality specifications.

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 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 “Marketing” 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 a volume of competing finished product is currently being imported, contrary to our rights under our Project Agreement with the State. Excess jet fuel, 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 InterOil Products Limited, 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. Previously we sold all naphtha exports under a term contract which expired in September 2008 to Shell. Since September 2008, all sales of naphtha have been under our 12 month term contract with Sojitz Corporation. Sales of export low sulfur waxy residue 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 are selling in the spot market.

Trading and Risk Management

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

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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.

The derivative instrument which we generally use is the 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 $18.0 million of unrealized hedging gains carried forward in our balance sheet for unsettled hedge accounted transactions as at year end. Subsequent to year end, in January 2009, these unrealized hedges were terminated and the mark-to-market gains will be realized during 2009 as the underlying transactions occur.

MIDSTREAM — LIQUEFACTION

During 2006, InterOil proposed a project for the potential construction of an LNG plant that would be built adjacent to our refinery. The project targets a facility that would produce up to nine million tons per annum of LNG and condensates. The infrastructure currently being contemplated includes condensate storage and handling, a gas pipeline from the Elk/Antelope field as well as other potential suppliers of gas, and LNG storage and handling. The LNG facility is being designed to 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 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 between the parties and the joint venture company as the vehicle for this.

As part of the shareholders’ agreement, five ‘A’ Class shares were issued with full voting rights with each share controlling one board position. Two ‘A’ Class shares are owned by InterOil, two were owned by Merrill Lynch Commodities (Europe) Limited, and one is owned by Pacific LNG Operations Ltd. All key operational matters require either a unanimous or supermajority Board resolution.

We were also provided with ‘B’ Class shares in the Joint Venture Company with a fair value of $100.0 million in recognition of our contribution to the LNG Project. Our contribution to the Joint Venture Company included, among other things, infrastructure developed by us near the proposed LNG plant 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 shareholders’ agreement, we are not required to contribute towards cash calls from the Joint Venture Company until a total of $200.0 million has been contributed by the other joint venture partners to equalize their shareholding in the Joint Venture Company with that of InterOil. As of December 31, 2008, InterOil held 82.15% of the B class or economic shareholding in the Joint Venture Company.

A total of $40.0 million has been provided to fund cash costs incurred through Front End Engineering and Design (“FEED”) phase until the Final Investment Decision (“FID”) milestone is achieved. The shareholders’ agreement provides that the FID recommendation is to be approved when all of the joint venture partners agree that each and all of the following steps have been completed.

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(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.

Progress has been made on a number of the key components necessary to develop the proposed LNG project. During 2008, we continued our negotiations with the State for a definitive project agreement providing certain authorizations for the project and establishing the fiscal regime applicable to it. If and when State approval is given, completion of an LNG facility 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 a facility, or as to the timing of such construction. In addition, no assurance can be given that we will have access to sufficient gas reserves, whether from the Elk/Antelope location or otherwise, to support or justify an LNG facility.

In 2008, certain disputes arose among Merrill Lynch and the other partners to the LNG Project, including InterOil. (See “Legal Proceedings and Regulatory Actions").

On February 27, 2009, a settlement agreement was entered into whereby InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd acquired of Merrill Lynch’s interests in the Joint Venture Company in equal shares. InterOil issued 652,931 common shares valued at $11.25 million for its share of the consideration paid to Merrill Lynch in relation to the settlement. InterOil’s consideration is subject to a post closing balancing payment. 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")

DOWNSTREAM — WHOLESALE AND RETAIL DISTRIBUTION

We have the largest wholesale and retail petroleum product retail distribution base in Papua New Guinea. This business includes bulk storage, transportation distribution, 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, 2008, we believe we supplied approximately 77% of Papua New Guinea’s total refined petroleum product needs.

Supply of Products

Our retail and wholesale distribution business distributes diesel, jet fuel, gasoline, kerosene and fuel oil as well as Shell and BP 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 tankers. These tankers deliver the refined products to distribution terminals and depots, including those owned by us. We do not own these tankers 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 operators.

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

Retail Distribution

As of December 31, 2008, we provided petroleum products to 51 retail service stations operating under the InterOil brand name. Of the 51 service stations that we supply, 19 are either owned by or head leased to us with a sublease to company-approved operators. The remaining 32 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.

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Wholesale Distribution

We also supply petroleum products as a wholesaler to commercial clients. We operate 12 aviation refueling stations throughout Papua New Guinea. In 2007, we acquired three additional aviation fuelling depots, making us the largest aviation supplier in PNG outside the main center, 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 2008 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 have been able to obtain refined products for our distribution business at competitive prices to date. 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 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 2008. Agreement has been reached in principle for a twelve month extension to the previous supply arrangements. We are also exploring our assuming management of all OTML’s fuel needs.

INTEROIL RESOURCES

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

The Elk/Antelope gas condensate field, 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 block overlies the northern end of the Antelope block 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 block penetrated by the Antelope-1 well consists of a dominantly shallow water reef/platform complex with a dolomite cap with well developed secondary porosity and permeability.

An evaluation of the potential resources of gas and condensate for the Elk/Antelope field (see "Description Of Our Business”) has been completed by GLJ Petroleum Consultants Ltd., an independent qualified reserves evaluator, as of December 31, 2008. The estimates presented are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Additional data from the drilling of the Antelope 1 well has been obtained since December 31, 2008 which may impact the resource volumes stated above.

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Gross Resource Estimate for Gas and Condensate

	Case
As at December 31, 2008	Low		Best		High
Contingent Gas Resources (Tcf)		2.32		3.43		4.73
Contingent Condensate Resources (MMBbls)		36.7		59.3		87.9
Contingent Resources MMBOE		423.4		631.0		876.2

Resource Estimate for Gas and Condensate — Net to InterOil*

	Case
As at December 31, 2008	Low		Best		High
Contingent Gas Resources (Tcf)		1.3		1.9		2.6
Contingent Condensate Resources (MMBbls)		20.4		33.0		48.9
Contingent Resources MMBOE		235.7		351.3		487.8

* 55.67% Working Interest assumes all IPWI Investors and the State elect to fully participate after a Production Development License has been granted.

In relation to the tables above, 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. If probabilistic methods are 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. If probabilistic methods are 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. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Marketable gas estimates exclude CO2, shrinkage and gas used for fuel.

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development. There is no certainty that it will be commercially viable to produce any portion of the resources. These resource estimates are not classified as reserves primarily due to lack of marketing infrastructure, further project application, facility and reservoir design work. There is no guarantee that all or any part of the estimated resources will be recovered. Although a final project has not yet been sanctioned, pre — Front End Engineering and Design (FEED) studies are ongoing for LNG and condensate stripping operations as options for monetization of the gas and condensate. The proposed LNG plant will consist of a 220 mile pipeline from the Elk/Antelope field to the plant which is to be located adjacent to the InterOil refinery near Port Moresby. An export terminal will also be constructed at the LNG plant. However, commerciality of any monetization project has not been implemented for the purposes of deriving the resource estimates.

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.

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THE ENVIRONMENT AND COMMUNITY RELATIONS

Environmental Protection

Our operations in Papua New Guinea are subject to an environmental law regime which provides for 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 2008. 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 note expect our operations to be affected any differently than other similarly situated domestic competitors.

Environmental and Social Policies

We have not adopted any specific social or environmental 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

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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.

RISK FACTORS

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

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

As of December 31, 2008, we had drilled eight exploration wells and four appraisal wells since the inception of our exploration program in our PPLs. Of these, we consider two exploration wells and one appraisal well have been successful. We plan to drill additional wells in Papua New Guinea during the coming years in line with our commitments under our PPLs. 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.

Oil and gas prices have recently declined substantially. If there is a sustained economic downturn or recession in the PNG or globally, oil and natural gas prices may continue to 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 this current global economic crisis or recession will be long lasting. 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 reduce our ability to finance our exploration activities and LNG facility, and adversely affect the results of operations in our midstream and downstream businesses.

We may not be successful in our negotiations with the State with respect to revising the price for which we sell refined product in Papua New Guinea, which, if not revised, may reduce our profit and cause us to cease operating the refinery.

Under our agreement with the State, refined products produced by us 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. We are negotiating changes to how the IPP is set with the State.

In contrast, we are purchasing our crude at a fluctuating spot market price. Thus, a primary reason for the renegotiation of the project agreement with the State is 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 renegotiated to be based on a market price marker recognized by the petroleum industry, then there is a possibility that such continuing 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.

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

Our project agreement requires the State to take action to ensure that domestic crude oil producers sell us their Papua New Guinea domestic crude production for use in our refinery and that refined products for domestic Papua New Guinea use will be purchased from us by distributors at the IPP. 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 agreement expires on June 14, 2009 and we are exploring the potential for its extension or replacement. 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. 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.

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.

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

As of December 31, 2008, we had $53.5 million in long-term debt with OPIC which matures in 2014, together with principal repayments due during 2009 totalling $9 million. We also had on issue Debentures totaling $78.975 million which mature in 2013. 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 the proposed LNG Project, refinery expansions and improvements, acquisitions of distribution assets, and for further capital acquisitions and expenses. We will need additional financing to complete our business plans. If we are unable to obtain debt or equity financing because of lower 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. We also intend to make offers to acquire oil and gas properties and distribution assets in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially. 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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We depend upon access to the capital markets to fund our growth strategy. Currently, the capital and credit markets are experiencing an unprecedented disruption which, if it continues for an extended period of time, will 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 become 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 and the LNG project, both 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 were unable to be renewed, we may be required to seek additional capital to maintain its 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/Antelope field and would be required to develop the LNG Project. Failure to obtain any financing necessary for our capital expenditure plans will likely result in delays in these activities.

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

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. If interest rates increase, 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 $0.3 million change in our annual interest expense.

The exploration and production, the refining and the 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 will 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:

ü	Our access to the capital necessary to drill wells and acquire properties;
ü	Our ability to acquire and analyze seismic, geological and other information relating to a property;
ü	Our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
ü	The development of, and our ability to access, transportation systems to bring future production to the market, and the costs of such transportation systems;
ü	The standards we establish for the minimum projected return on an investment of our capital; and
ü	The availability of alternate fuel sources.

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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. 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.

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.

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.

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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 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.

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 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, 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. 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.

Shortages or unavailability of drilling rigs, oilfield equipment, and other oilfield exploration services could have a material adverse affect on our results of operations.

The demand for qualified and experienced companies to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the gas and oil industry can fluctuate significantly, often in correlation with gas and oil prices, causing possible shortages. Demand for rigs and equipment may increase along with the number of wells being drilled. Shortages combined with increased demand also may cause significant increases in costs for equipment, services and related personnel. Generally, higher gas and oil prices also stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Moreover, due to the limited supply of drilling rigs, oilfield equipment and other oilfield exploration services in Papua New Guinea, we may have difficulty obtaining additional drilling rigs and other oilfield exploration services. Any shortages or price increases could have a material adverse affect on our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

Our ability to develop our planned 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 in order to maintain our existing ownership interest in the joint venture and amount to hundreds of millions of dollars. 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.

To fund this development project, 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. Our ability to obtain such significant funding will depend, in part, on factors beyond our control, such as the status of capital and

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industry markets at the time financing is sought and such markets’ view of our industry and prospects at such time. Accordingly, 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.

Even if we obtain sufficient funding for our LNG terminal, we may not be able to timely construct and commission our LNG terminal.

We may not complete construction of our LNG terminal 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 of the LNG terminal;

• shortages of materials or delays in delivery of materials;

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

• difficulties or delays in obtaining gas for commissioning activities necessary to achieve commercial operability of the LNG terminal;

• failure to obtain all required governmental and third-party permits, licenses and approvals for the construction and operation of the LNG facility;

• 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 development of an LNG facility due to safety, environmental or security concerns; and

• local economic and infrastructure conditions.

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

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. The optimization work performed at our refinery has improved its operating efficiency. However, 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:

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• 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.

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

Our refinery did not operate at full capacity during 2008. 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 2008. Agreement has been reached in principle for a twelve month extension to the previous supply arrangements.

If we are not able to market all of our refinery’s output, we will not be able to operate our refinery at its full capacity and our financial condition and results of operations may be materially adversely affected.

The project agreement with the government of Papua New Guinea gives us certain rights to supply the domestic market in Papua New Guinea with our refined products. However, not all domestic demand was sourced from our refinery during 2008 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.

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

Our refining 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, our refining 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

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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.

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.

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, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of Canada or the United States.

The 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, 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.

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Title to certain of our properties may be defective or challenged by third party landowner claims.

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.

Compliance with and changes in environmental laws could adversely affect our performance.

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.

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 that arise in the course of our business. There is a risk that we are not 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.

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.

The enactment of legislation responsive to the Kyoto Protocol or similar global governmental initiatives 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.

Recent 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. If the Kyoto Protocol or other comprehensive legislation focused on reducing greenhouse gas emissions is enacted by Papua New Guinea or countries in which we desire to operate, it could have the effect of adversely affecting our operations and the demand for our products, consequently reducing our revenues and profitability.

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 February 1, 2008 through February 26, 2009, the highest sales price of the Common Shares on the NYSE Amex has been U.S. $41.62 and the lowest sales price of the Common Shares on such

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exchange has been U.S. $8.90. 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;

• material events public announcements concerning our business and operations;

• changes in stock market analyst recommendations or earnings estimates regarding the Common Shares;

• 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.

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 its cash flow from operations.

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, other than the requirement that holders of our Debentures approve any cash dividend on our common shares. During 2008, we paid a dividend on our series A preferred shares prior to their conversion. This dividend was paid by issuing 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 of Directors 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, 2008, 35,923,692 common shares were issued and outstanding. All of the Series A Preferred Shares were converted into common shares during 2008 and none remain outstanding.

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.

Annual Information Form INTEROIL CORPORATION    33

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 Business Corporations Act (Yukon), 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.

Series A Preferred Shares

517,777 series A preferred shares were issued on November 21, 2007. All such shares have been converted into common shares.

Voting. Holders of series A preferred shares are entitled to vote on any matter presented to the shareholders of InterOil for their action or consideration at any meeting of the shareholders of InterOil (or by written consent of the shareholders in lieu of a meeting), and shall be entitled to cast the number of votes equal to the number of common shares into which the series A preferred shares held by such holder are convertible as of the record date for determining shareholders entitled to vote on such matter.

Dividends. Subject to the rights, privileges, restrictions and conditions attaching to any other series of shares of InterOil ranking in priority thereto, the holders of the series A preferred shares shall be entitled to rank ahead of all other classes or series of shares of InterOil as to dividends. The holders of the series A preferred shares shall be entitled to a fixed cumulative dividend at the rate of 5% per annum for each series A preferred share, payable quarterly on December 31, March 31, June 30 and September 30, commencing on December 31, 2007.

Conversion. The series A preferred shares shall be convertible into common shares, at the option of (a) the holder at any time and from time to time, and without the payment of additional consideration therefore, and (a) InterOil at any time from the date of a Triggering Event. A “Triggering Event” shall occur if the VWAP of the common shares equals or has exceeded U.S.$36.94 per share for a period of at least 10 consecutive trading days on the principal market. The number of common shares issuable upon conversion of each series A preferred share shall initially be 1.00, subject to certain adjustments. The “VWAP” is the daily volume weighted average price of the common shares on the AMEX (if the common shares are not listed on the AMEX, then NYSE or NASDAQ) calculated by dividing the total value by the total volume of the common shares traded for the relevant period on such market (which market is, as at the date hereof, the AMEX).

Fundamental Change. In the event of a “Fundamental Change” (as defined in the share provisions), holders of the series A preferred shares are entitled to require InterOil to redeem or purchase at any time all or any of the series A preferred shares registered in the name of such holder by providing written notice to the InterOil accompanied by the certificate(s) representing the series A preferred shares in respect of which the holder desires to have InterOil redeem or purchase for the redemption amount of $28.97, subject to certain adjustments.

Shareholder Rights Plan

On May 27, 2007, the Company adopted the 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 proportion of the common shares of InterOil and, subject to certain grandfather provisions in the Rights Plan, his shareholdings will not trigger the Rights Plan.

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

Annual Information Form INTEROIL CORPORATION    34

8% Subordinate Convertible Debentures

$95 million principal amount of Debentures were issued on May 12, 2008.

Principal Amount and Interest. The Debentures bear interest at 8% per annum, which interest is payable semi-annually in arrears, on May 9 and November 9 of each year, commencing on November 9, 2008, until maturity on May 9, 2013 or upon acceleration, conversion or redemption. The principal amount of the Debentures and all accrued but unpaid interest thereon, if any, is payable in lawful money of the United States of America. The Debentures may not be pre-paid in whole or in part without the consent of the holders. The initial holders have the option for the first four interest payments to have interest paid by InterOil in cash or common shares, and thereafter InterOil, at its option, has the right to pay interest on each in cash or common shares, or a combination thereof. The number of common shares to be issued for such interest payment shall be the number determined by dividing (i) the amount of interest by (ii) the VWAP for the ten consecutive trading days immediately before the applicable interest payment date. The “VWAP” is the daily volume weighted average price of common shares on the principal market the common shares trade on(which includes the NYSE AMEX and the New York Stock Exchange).

Conversion. The Debentures are convertible at the holder’s option at any time into such number of fully paid and non-assessable common shares as is determined by dividing the outstanding principal amount being converted by the conversion price of $25.00 (subject to adjustment). If (i) the daily VWAP of the common shares has been at or above $32.50 for at least 15 trading days, (ii) the common shares to be received upon conversion are freely tradable pursuant to an effective registration statement or by non-affiliates pursuant to Rule 144 (or any successor or similar provision thereto) and (iii) the common shares are listed on a principal market (which includes the NYSE AMEX and the New York Stock Exchange), then InterOil may require the holders to convert the Debentures in whole, provided that this election must apply to all Debentures equally.

Change of Control Transaction. In the event a “Change Of Control Transaction” occurs, the holders have the right, at their option, to (i) convert the Debenture, in whole or in part, at the Conversion Price in effect as of the day before the closing date of the change in control transaction, into the shares of stock or other securities, cash and/or property, if any, receivable by holders of Common Shares following such Change in Control Transaction, or (ii) to require InterOil (or its successor) to redeem the Debenture in cash at 110% of the principal amount (plus accrued but unpaid interest). A “Change of Control Transaction” arises where (i) there occurs any consolidation, merger or other business combination of InterOil or any other corporate reorganization or transaction or series of related transactions in which in any of such events the existing voting stockholders of InterOil immediately prior to such event cease to own more than 50% of the voting stock of the surviving corporation after such event (including without limitation any “going private” transaction), (ii) any person together with its affiliates and associates beneficially owns or is deemed to beneficially own in excess of 50% of our voting power, (iii) there is a replacement of more than one-half of the members of our board of directors which is not approved by those individuals who are members of or nominated by the board of directors of a subcommittee of the board of directors, (iv) in one or a series of related transactions, there is a sale or transfer of all or substantially all of the assets of InterOil, determined on a consolidated basis, or (v) a transaction occurs as a result of which the common shares ceases to be listed on a principal market.

Subordination. The Debentures are subordinate and subject in right of payment to the prior payment in full of all “Senior Indebtedness”, whether outstanding on the date of hereof or thereafter created, incurred, assumed or guaranteed; provided, however, that the Debentures shall rank equally with, or prior to, all existing and future unsecured indebtedness of InterOil that is subordinated to Senior Indebtedness. “Senior Indebtedness” means the principal of, premium (if any) and accrued and unpaid interest payable on or in connection with, and all fees, charges, expenses, reimbursement obligations, guarantees and other amounts payable under or in connection with (a) indebtedness, in a principal amount at any time outstanding not to exceed $85,000,000, that is designated by its terms as senior to the Debentures and (b) the “Designated Senior Indebtedness”, which includes the OPIC loan and the working capital facilities, including the working capital facility with BNP Paribus pursuant to the letter dated August 15, 2005, as amended and restated.

Events of Default. An “Event of Default” of the Debentures is: (i) a default in payment of the principal amount; (ii) a default in the payment of any accrued and unpaid interest which default continues for 10 days; (iii) failure to convert any portion of the principal amount of the Debenture in accordance with its terms following exercise by the holder of the right to convert the Debenture which default continues for 15 days; (iv) a failure by InterOil to comply with any of its other obligations under this Debenture which failure continues for 15 days; (v) the suspension from trading or failure of the common shares to be listed on the principal market or other national trading market for a period of five consecutive days or for more than an aggregate of

Annual Information Form INTEROIL CORPORATION    35

10 days in any 365-day period; (vi) any default after any cure period under, or acceleration prior to maturity of, any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by InterOil or any of its subsidiaries for in excess of $10,000,000 or for money borrowed the repayment of which is guaranteed by InterOil any of its subsidiaries for in excess of $10,000,000, whether such indebtedness or guarantee now exists or shall be created hereafter; (vii) a final judgment or judgments for the payment of money aggregating in excess of $25,000,000 are rendered against InterOil or any of its subsidiaries and which judgments are not, within 60 days after the entry hereof, bonded, discharged or stayed pending appeal, or are not discharged within 60 days after the expiration of such stay; provided, however, that any judgment which is covered by insurance or an indemnity from a credit worthy party shall not be included in calculating the $25,000,000 amount set forth above so long as InterOil provides the holder a written statement from such insurer or indemnity provider (which written statement shall be reasonably satisfactory to the holder) to the effect that such judgment is covered by insurance or an indemnity InterOil will receive the proceeds of such insurance or indemnity within 60 days of the issuance of such judgment; or (viii) if InterOil or any of its subsidiaries is subject to any “Bankruptcy Event”.

A “Bankruptcy Event” is any of the following events: (a) InterOil or any subsidiary commences a case or other proceeding under any bankruptcy, reorganization, arrangement, adjustment of debt, relief of debtors, dissolution, insolvency or liquidation or similar law of any jurisdiction relating to InterOil or any subsidiary thereof; (b) there is commenced against InterOil or any subsidiary any such case or proceeding that is not dismissed within 60 days after commencement; (c) InterOil or any subsidiary is adjudicated insolvent or bankrupt or any order of relief or other order approving any such case or proceeding is entered; (d) InterOil or any subsidiary suffers any appointment of any custodian or the like for it or any substantial part of its property that is not discharged or stayed within 60 days; (e) InterOil or any subsidiary makes a general assignment for the benefit of creditors; (f) InterOil or any subsidiary fails to pay, or states that it is unable to pay, its debts generally as they become due; (g) InterOil or any subsidiary calls a meeting of its creditors with a view to arranging a composition, adjustment or restructuring of its debts; or (h) InterOil or any subsidiary, by any act or failure to act, expressly indicates its consent to, approval of or acquiescence in any of the foregoing or takes any corporate or other action for the purpose of effecting any of the foregoing.

If an Event of Default occurs and is continuing with respect to any of the Debentures, the holders may declare all of the then outstanding principal amount of the Debentures, including any interest due thereon, to be due and payable immediately in cash (except in the case of an Event of Default arising from the failure to convert any portion of the principal amount of the Debentures), the Debenture shall become due and payable without further action or notice. In the event of an acceleration, the amount due and owing to the holder shall be 105% of the principal amount of the Debentures (including all accrued and unpaid interest, if any). InterOil shall pay interest on such amount in cash at a rate equal to the lesser of 12% or the maximum rate permitted by applicable law to the holder if such amount is not paid within 15 days of holder’s request.

Ratings. InterOil has not asked for and received a stability rating, and it is not aware that it has received any other kind of rating, including a provisional rating, from one or more approved rating organizations for outstanding securities of InterOil, which rating or ratings continue in effect.

Options

InterOil has a stock incentive plan that allows employees to acquire common shares of the Company. 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. Default provisions in the plan rules provide for immediate vesting of granted options and expiry ten years after the grant date. Some granted under a predecessor plan also remain on foot.

As of December 31, 2008, there were options outstanding to purchase 1,839,500 common shares pursuant to our stock incentive plans.

Warrants

As of December 31, 2008, there were warrants outstanding to purchase 337,252 common shares. The warrants expire on August 27, 2009.

Annual Information Form INTEROIL CORPORATION    36

Other instruments Convertible into or Exchangeable for Common Shares

We have entered into an agreement with Petroleum Independent and Exploration Corporation (“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 the parties to an indirect participation agreement, (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. At December 31, 2008 rights to convert up to 2,160,000 common shares remained.

MARKET FOR SECURITIES

During 2008, our common shares traded on the Toronto Stock Exchange (“TSX”) under the symbol IOL in Canadian dollars, on the American Stock Exchange (“AMEX”) now known as the NYSE Amex, under the symbol IOC in U.S. dollars, and on the Port Moresby Stock Exchange under the symbol IOC in Papua New Guinea Kina. Effective from the close of markets on February 27, 2009, our common shares were delisted from the TSX. The following tables disclose the monthly high and low trading prices and volumes of our common shares as traded on the TSX and AMEX during 2008:

Toronto Stock Exchange (TSX:IOL) in Canadian Dollars

Month	High		Low		volume
January	$	21.88	$	15.93		1,728,700
February	$	23.92	$	18.51		1,076,800
March	$	23.22	$	16.50		974,900
April	$	21.24	$	16.25		1,296,400
May	$	30.00	$	21.30		2,118,300
June	$	36.50	$	24.36		1,678,400
July	$	31.17	$	25.27		1,086,100
August	$	33.21	$	26.07		740,500
September	$	33.88	$	23.25		921,500
October	$	29.00	$	10.99		1,059,600
November	$	18.00	$	11.40		647,700
December	$	17.35	$	12.28		909,600
Total						14,238,500

American Stock Exchange (AMEX:IOC) in United States Dollars

Month	High		Low		Volume
January	$	21.94	$	15.78		12,268,100
February	$	23.90	$	18.40		12,586,500
March	$	23.50	$	16.06		12,778,300
April	$	20.73	$	15.98		12,834,900
May	$	30.22	$	20.95		27,588,500
June	$	41.62	$	24.10		25,851,300
July	$	30.74	$	24.56		20,483,400
August	$	32.04	$	24.54		14,388,600
September	$	31.85	$	21.72		19,069,000
October	$	27.18	$	9.10		15,702,600
November	$	15.50	$	8.90		7,817,200
December	$	14.24	$	10.20		5,705,900
Total						187,074,300

Annual Information Form INTEROIL CORPORATION    37

Prior sales

• 58,000 common shares were issued during 2008 upon the exercise of stock options at various prices defined by the option grant terms in accordance with relevant stock incentive plans.

• Clarion Finanz A.G. converted its $60 million share of the Company’s $130 million secured bridging credit facility into 2,728,477 common shares on May 9, 2008 at a deemed price of $22.65.

• $95 million principal amount of 8% Subordinated Convertible Debentures due 2013 (the “Debentures”) were issued by us to certain investors on a private placement basis on May 9, 2008. See “Description of Capital Structure”.

• 9,347 common shares were issued on May 20, 2008 at a deemed price of $19.95 and 5,630 Common Shares were issued on August 8, 2008 at a deemed price of $33.12 as payment of dividends on the series A preferred shares for the quarters ended March 31, 2008 and June 30, 2008, respectively.

• 228,000 common shares were issued on June 5, 2008 at a deemed price of $25.00 as payment of a finder’s fee in connection with the private placement of the Debentures.

• 317,700 common shares were issued on July 10, 2008 and 200,077 common shares were issued on August 22, 2008 upon conversion of all of the then issued series A preferred shares.

• 450,000 common shares were issued on August 15, 2008 at a deemed price of $37.50 to IPI holders who exercised their rights to convert to common shares under the IPI Agreement (see “Material Contracts – Amended and Restated Indirect Participation Interest Agreement dated February 25, 2005”). In addition, two holders agreed during 2008 to waive their rights to convert their interest into 696,667 common shares under the Agreement.

• 259,105 common shares were issued to on December 16, 2008 at a deemed price of $10.11 as payment of a proportion of the first interest installment. 641,000 common shares were issued to holders who elected to convert their Debentures into common shares during 2008 in accordance with the provisions of the Debentures.

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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
Anthony Poon New South Wales, Australia	General Manager — Supply Trading and Risk Management	October 1, 2005(5)
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 the Board’s Audit Committee, the Nominating and Corporate Governance Committee and Compensation Committee and has held such positions throughout 2008.
(2)	Edward Speal is a member of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee, and has held such positions throughout 2008.
(3)	Roger Lewis replaced Donald Hansen as a Director. Mr Hansen retired as a Director and member of the Audit Committee, the Nominating and Corporate Governance Committee and Compensation Committee on October 14, 2008. Mr. Lewis has held the position of Director and member of the Audit Committee, the Nominating and Corporate Governance Committee and Compensation Committee from his date of appointment.
(4)	Messrs Grundy and Speal and Dr Byker are also members of the Board’s Reserves Committee established in June 2008.
(5)	Mr Poon ceased employment on January 15, 2009.

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

As of March 30, 2009, our directors and executive officers as a group beneficially owned, or controlled or directed (directly or indirectly) 6,811,681 common shares, representing 18.6% of our outstanding common shares. In addition to the common shares owned or controlled or directed (directly or indirectly) by our directors and executive officers, 1,187,500 shares are issuable upon exercise of outstanding options, resulting in directors and executive officers holding 21.85% of issued common shares on a diluted basis.

Our Board of Directors 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 established a

Annual Information Form INTEROIL CORPORATION    39

Reserves Committee in June 2008. Mr Speal is Chairman of the 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 150 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.

Roger F. Lewis is an Australian and a former senior finance executive, having spent 22 years with Woodside Energy Ltd in Western Australia, finishing as Group Financial Controller. Prior to that he worked in commercial and finance roles for over 15 years in the heavy manufacturing industry both in Australia and overseas. He is a Fellow Certified Practicing Accountant (FCPA) with the Australian Society of Accountants and, since 2000, has been a Commissioner of the Lottery Commission of Western Australia, with particular

Annual Information Form INTEROIL CORPORATION    40

responsibility for finance and accounting matters. He is a member of the Commission’s Audit, Remuneration and Major Projects subcommittees.

William J Jasper III is President and Chief Operating Officer of InterOil. Mr. Jasper joined the Company on August 30, 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.

Anthony Poon was General Manager of our Supply, Trading & Risk Management until January 2009 after having joined us in October 2005. From January 2003 until joining InterOil, Mr. Poon was a private oil trading and risk management consultant. During 2002, Mr. Poon served as a Business Manager/Operations Leader with ChevronTexaco Singapore. Prior to joining ChevronTexaco, Mr. Poon had been employed by Caltex in Singapore for more than 30 years. Mr. Poon’s last position with Caltex was head of its international crude oil trading department where he was responsible for crude and derivatives trading and price risk management, including crude supply to Caltex’s refineries worldwide. During his tenure at Caltex, Mr. Poon held various positions involving refinery supply operations, shipping, terminalling, demurrage and oil loss claims, and crude and refined product operations.

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. Mr. Visaggio currently serves as Chairman of the Board of Directors and of the Finance Committee of Santa Maria Ladies College. Mr Visaggio has served as a director of Santa Maria Ladies College since February 2004.

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

Certain directors and officers of InterOil are directors and officers of other private and public companies. Some of these private and public companies may from time to time be involved in business transactions or banking relationships which may create situations in which conflicts might arise. In accordance with the Business Corporations Act (Yukon), directors who have an interest in a material contract or a material transaction, whether made or proposed, with InterOil are required, subject to certain exceptions, to disclose the nature and extent of the interest. A director required to disclose such interest shall abstain from voting on any resolution to approve the contract or transaction, except as otherwise permitted by the Business

Annual Information Form INTEROIL CORPORATION    41

Corporations Act (Yukon). In addition, each officer and director is required to act honestly and in good faith with a view to the best interests of InterOil.

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 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 it hedging positions. See “Material Contracts – Secured Revolving Crude Import Facility”.

• Mr. Grundy is a principal of Breckland Limited, which entity provides technical and 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. Mr. Donald Hansen resigned as a member of the Audit Committee on October 14, 2008 and was replaced by Mr. Lewis on November 26, 2008. Dr. Byker and Mr Speal held their positions throughout 2008.

Dr. Byker, Mr. Speal and Mr. Lewis are, and Mr. Hansen was, independent and financially literate within the meaning of Multilateral Instrument 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 preformed by the external auditors, save where such services are subject to the de-minimis exceptions described in the 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

	2008		2007
Audit Fees(1)	$	1,416,583	$	968,316
Audit-Related Fees(2)	$	170,404	$	14,887
Tax Fees(3)	$	473,493	$	167,491
All Other Fees(4)	$	39,192	$	266,870
Total	$	2,099,672	$	1,417,565

Notes:

“Audit Fees” means the aggregate fees billed by the issuer’s external auditor in each of the last two fiscal years for audit fees.

“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.

“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.

“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 assistance responding to the SEC queries on our Form 40-F of December 31, 2005 and also the unaudited quarterly reporting of our subsidiaries.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

The Company, certain of its subsidiaries, the Company’s Chief Executive Officer, Phil Mulacek, and his controlled entities Petroleum Independent & Exploration Corporation and P.I.E. Group, LLC are defendants in Todd Peters, et. al. v. Phil Mulacek et. al.; Cause No. 05-040035920-CV; in the 284th District Court of Montgomery County, Texas. The plaintiffs claim to be members of a partnership that bought a modular oil refinery and subsequently, through a series of transactions, sold it to a subsidiary of the Company. Plaintiffs contend that the defendants, including the Company, breached their fiduciary duties to the plaintiffs as part of these transactions and also assert claims for knowing participation in a breach of a fiduciary duty, common law fraud, fraudulent inducement, statutory fraud, securities fraud, breach of contract, investor oppression and conspiracy. Plaintiffs are seeking actual damages of up to $118,068,759.00 and unspecified punitive damages, attorneys’ fees, expenses and court costs, an accounting and access to books and records. The Company and other defendants are vigorously contesting the matter. Management does not believe the litigation will 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.

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.

Annual Information Form INTEROIL CORPORATION    43

Regulatory Actions

During the second half of the 2008 year, the Ontario Securities Commission (the “Commission”) directed that the Company undertake a review of its option granting practices from January 1, 2001 and provide the Commission with certain specific information and documentation.

A Special Committee of InterOil, comprised solely of independent directors, recently completed the internal review of InterOil’s historical option granting practices. The Special Committee concluded its review and found irregularities with respect to the administration of certain historical stock options grants, with the majority of these irregularities occurring prior to 2002 and well prior to the retention of those currently responsible for administration of stock options at InterOil. The Special Committee determined that these irregularities were not the result of any internal misconduct, but due to the failure to maintain adequate internal and accounting controls and some lack of understanding by those involved at the time. The Special Committee concluded that the total value of such errors is small and, relative to the InterOil’s current operations, not material. No restatement of the Company’s financial statements is required as a result of these determinations.

Based on the results of its investigation, the Special Committee provided a report to the Board of Directors and recommended to the Board of Directors that it adopt a number of remedial actions, which the Board, by vote, promptly accepted. Such remedial actions include: re-pricing the small number of existing options held by current employees, contractors, officers or directors where the options were granted below market price or prior to the commencement of employment; requesting that the current officer who has exercised options granted below market price refund InterOil the difference between the exercise price of such options and the proper market price as provided for under the relevant stock incentive plan; requiring the Compensation Committee provide written confirmation to the Board of Directors in respect of all future grants of options that such options were granted in accordance with the applicable stock incentive plan rules; adopting further specific, written procedures for the administrative tasks surrounding the granting of options; and adopting a specific option granting procedure for grants to new hires. These remedial actions have been or are being implemented by management.

A report of the results of the review and containing the information and documentation requested was provided to the Commission at the end of February 2009. The Commission is currently reviewing the report.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

During 2008, 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. 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, $140,165 in respect of consulting fees and expenses during 2007 and 2006, respectively. No payments for consulting services were made to Breckland Limited in 2008.

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”.

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MATERIAL CONTRACTS

The following represent material contracts entered into or still in effect during 2008:

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 Pacific LNG Operations Ltd. (“PacLNG”) 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 PacLNG 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 PacLNG. 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 PacLNG. 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, PacLNG and their affiliates released Merrill Lynch and its affiliates, and Merrill Lynch and its affiliates released InterOil, PacLNG 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 PacLNG (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, subject to certain post-closing adjustments; and (ii) a payment by PacLNG to MLPLC of $11,250,000 paid through the transfer of 594,893 common shares of InterOil held by PacLNG 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 PacLNG 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.

Investment Agreement dated October 30, 2008

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”), 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/Antelope field and to fund 20.5% of the costs of developing that field. The interest and funding is contingent upon Petromin’s nomination by the State as the entity designated to hold the State’s interest in accordance with PNG’s Oil & Gas Act and upon issuance of the PDL 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. The agreement contains certain provisions applicable in the event that the State does not designate Petromin to hold its interest at the time the PDL is granted. In this event, Petromin will either elect to participate in the field as a joint venture partner having a working interest between 1 and 2.5% or, subject to corporate and regulatory approvals, be entitled under the terms of certain warrants granted to it to be issued with InterOil common shares, with the number of shares based on a formula set out in the agreement based upon the funding amount contributed by Petromin and an average of InterOil’s share price at the relevant date.

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

We entered into the Amended and Restated Common Share Purchase Agreement with Pacific LNG Operations (“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

Annual Information Form INTEROIL CORPORATION      45

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 PNG LNG, Inc. (the “Project 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 Project 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 Project Company. Class B shares recognize the parties’ economic interests in the Project 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 Independent State of Papua New Guinea 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).

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 August 31, 2008 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. During 2008, the overall facility limit was increased temporarily to $220 million and, from November 30, to $190.0 million to accommodate higher crude prices and resulting increases in working capital requirements.

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. The terms of this agreement are described under the heading “Description of Our Business—Upstream-Exploration and Production—Indirect Participation Agreements.” 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, 2008, we had drilled four exploration wells. 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 has 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

Annual Information Form INTEROIL CORPORATION      46

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. 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 was used to finance the construction of the refinery at Napa Napa, Port Moresby (see under the heading “Description of the Business – Midstream-Refining Liquefaction”) and is secured by all of the refinery’s capital assets. The loan matures on December 31, 2014 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. 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 2008, the weighted average interest rate of all disbursements pursuant to this loan agreement was 7.1%. During year ended December 31 2008, two installments of $4.5 million and the accrued interest on the loan were paid.

Refinery State Project Agreement

On May 29, 1997, we entered into a project agreement with the government of Papua New Guinea 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 government of Papua New Guinea 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 project agreement provides that the government of Papua New Guinea will take all actions necessary such that any refinery constructed in Papua New Guinea, including ours, will have the exclusive right to sell refined products at the IPP prior to any imports into Papua New Guinea. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product that is being imported. For each refined product produced and sold locally in Papua New Guinea, the IPP was to originally be 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 is currently being jointly reviewed by the Papua New Guinea government and by InterOil. The basis of calculating IPP price was revised in November 2007 by an interim agreement which more closely mirrors changes in the costs of crude feed stocks than the previous pricing formula. The interim IPP formula was modified 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. Minor adjustments to this interim formula were made in June 2008 based on ongoing discussions with the government with a view to finalizing a permanent replacement to the IPP formula as is required under our agreement.

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 2008 were done so in the ordinary course of our business or were not material to us.

Annual Information Form INTEROIL CORPORATION      47

TRANSFER AGENT AND REGISTRAR

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

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.
100 University Avenue, 9^th Floor
Toronto, Ontario
Canada M5J 2YI
Tel: 1-800-564-6253 (toll free North America)
Fax: 1-800-249-7775 (toll free North America)
E-mail: service@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

In Papua New Guinea, our transfer agent and registrar for our common shares is PNG Registrars Limited, PO Box 1265, Port Moresby NCD, Papua New Guinea, telephone (675) 321 6377, fax (675) 321 6379, email: ssimon@online.net.pg.

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, 2008. 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 to be held on June 19, 2009. Additional financial information is provided in our audited consolidated financial statements and related management discussion and analysis (“MD&A”) for the year ended December 31, 2008. Our audited financial statements, 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, Management’s Discussion and Analysis and any additional copies of this Annual Information Form 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

REPORT OF MANAGEMENT AND DIRECTORS
ON RESOURCE DATA AND OTHER INFORMATION

Management of InterOil (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.

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

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

(a)	reviewed the Company’s procedures for providing information to the independent qualified resources evaluator;
(b)	met with the independent qualified resources evaluator to determine whether any restrictions affected the ability of the independent qualified resources evaluator to report without reservation; and
(c)	reviewed the reserves data with management and the independent qualified resources 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 report of the independent qualified resources evaluator on the resources data; and
(c)	the content and filing of this report.

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

DATED effective March 27, 2009.

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

Annual Information Form INTEROIL CORPORATION      49

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

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, 2008. The resources data are estimates of low, best and high estimates of contingent resources as at December 31, 2008.
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, 2008:

		Location of
	Description and	Reserves
	Preparation Date	(Country or	Company Gross
Independent	of	Foreign	Contingent Resources
Qualified Reserves	Assessment	Geographic	MMBOE
Evaluator	Report	Area)	Low		Best		High
GLJ Petroleum Consultants	March 20, 2009	Papua New Guinea		235.7		351.2		487.8

5.	In our opinion, the resources data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.
6.	We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.
7.	Because the resources data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that resources are categorized according to the probability of their recovery.
8.	Contingent resources estimates are not classified as reserves at this time, pending further reservoir delineation, project application, facility and reservoir design work. Contingent resources entail commercial risk not applicable to reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

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EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 23, 2009

Keith M. Braaten, P. Eng.
Executive Vice-President

Annual Information Form INTEROIL CORPORATION      51

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 American Stock Exchange (“AMEX”).
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 AMEX 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 AMEX 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.

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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, AMEX 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

Annual Information Form INTEROIL CORPORATION      54

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.

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 AMEX.

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.

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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 AMEX 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, 2008, 2007 and 2006

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	44

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 2008 consolidated financial statements have been audited by PricewaterhouseCoopers, the independent auditors, in accordance with Canadian generally accepted auditing standards 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 2008 and 2007 consolidated financial statements and an audit of its 2006 consolidated financial statements. We have also completed an audit of its internal control over financial reporting as at December 31, 2008. 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, 2008, 2007 and 2006, and the related consolidated statements of operations, comprehensive income, shareholders’ equity and cash flows for each of the years in the three year then ended. 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, 2008 and 2007 and for each of the years in the two year period then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Company’s financial statements for the year ended December 31, 2006 in accordance with Canadian generally accepted auditing standards. 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, 2008, 2007 and 2006 and the results of its operations and its cash flows for each of the years in the three year period then ended 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, 2008, 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 appearing under Item 15. 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, 2008 based on criteria established in Internal Control — Integrated Framework issued by the COSO.

PricewaterhouseCoopers
Melbourne, Australia
March 27, 2009

Consolidated Financial Statements  INTEROIL CORPORATION     3

InterOil Corporation

Consolidated Balance Sheets

(Expressed in United States dollars)

	As at
	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Assets
Current assets:
Cash and cash equivalents (note 5)		48,970,572			43,861,762			31,681,435
Cash restricted (note 7)		25,994,258			22,002,302			29,301,940
Trade receivables (note 8)		42,887,823			63,145,444			67,542,902
Commodity derivative contracts (note 7)		31,335,050			—			1,759,575
Other assets		167,885			146,992			2,954,946
Inventories (note 9)		83,037,326			82,589,242			67,593,558
Prepaid expenses		4,489,574			5,102,540			880,640
Total current assets		236,882,488			216,848,282			201,714,996
Cash restricted (note 7)		290,782			382,058			3,217,284
Deferred financing costs		—			—			1,716,757
Plant and equipment (note 10)		223,585,559			232,852,222			242,642,077
Oil and gas properties (note 11)		128,013,959			84,865,127			54,524,347
Future income tax benefit (note 12)		3,070,182			2,867,312			1,424,014
Total assets		591,842,970			537,815,001			505,239,475
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities (note 13)		78,147,736			60,427,607			76,095,369
Commodity derivative contracts (note 7)		—			1,960,300			—
Working capital facility (note 15)		68,792,402			66,501,372			36,873,508
Deferred hedge gain (note 7)		—			—			1,385
Deferred liquefaction project liability (note 18)		—			—			6,553,080
Current portion of secured loan (note 18)		9,000,000			136,776,760			13,500,000
Current portion of indirect participation interest — PNGDV (note 19)		540,002			1,080,004			730,534
Total current liabilities		156,480,140			266,746,043			133,753,876
Accrued financing costs (note 18)		—			—			1,087,500
Secured loan (note 18)		52,365,333			61,141,389			184,166,433
8% subordinated debenture liability (note 23)		65,040,067			—			—
Preference share liability (note 22)		—			7,797,312			—
Deferred gain on contributions to LNG project (note 14)		17,497,110			9,096,537			—
Indirect participation interest (note 19)		72,476,668			96,086,369			96,861,259
Indirect participation interest — PNGDV (note 19)		844,490			844,490			1,190,633
Total liabilities		364,703,808			441,712,140			417,059,701
Non-controlling interest (note 20)		5,235			4,292			5,759,206
Shareholders’ equity:
Share capital (note 21)		373,904,356			259,324,133			233,889,366
Authorised — unlimited
Issued and outstanding - 35,923,692 (Dec 31, 2007 - 31,026,356) (Dec 31, 2006 - 29,871,180)
Preference shares (note 22)		—			6,842,688			—
(Authorised - 1,035,554, issued and outstanding — nil)
8% subordinated debentures (note 23)		10,837,394			—			—
Contributed surplus (note 24)		15,621,767			10,337,548			4,377,426
Warrants (note 25)		2,119,034			2,119,034			2,137,852
Accumulated Other Comprehensive Income		27,698,306			6,025,019			1,492,869
Conversion options (note 19)		17,140,000			19,840,000			20,000,000
Accumulated deficit		(220,186,930	)		(208,389,853	)		(179,476,945	)
Total shareholders’ equity		227,133,927			96,098,569			82,420,568
Total liabilities and shareholders’ equity		591,842,970			537,815,001			505,239,475

See accompanying notes to the consolidated financial statements. Commitments and contingencies (note 27), 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)

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Revenue
Sales and operating revenues		915,578,709			625,526,068			511,087,934
Interest		931,785			2,180,285			3,223,995
Other		3,216,445			2,666,890			3,747,603
		919,726,939			630,373,243			518,059,532
Expenses
Cost of sales and operating expenses		888,623,109			573,609,441			499,494,540
Administrative and general expenses		31,227,627			31,998,655			23,288,330
Derivative (gain)/loss		(24,038,550	)		7,271,693			(2,559,712	)
Legal and professional fees		11,523,045			6,532,646			3,937,517
Exploration costs, excluding exploration impairment (note 11)		995,532			13,305,437			6,176,866
Exploration impairment (note 11)		107,788			1,242,606			1,647,185
Short term borrowing costs		6,514,060			5,565,828			8,478,540
Long term borrowing costs		17,459,186			17,182,446			11,856,872
Depreciation and amortization		14,142,546			13,024,258			12,352,672
Loss on amendment of indirect participation interest — PNGDV (note 19)		—			—			1,851,421
Gain on LNG shareholder agreement (note 18)		—			(6,553,080	)		—
Gain on sale of oil and gas properties (note 11)		(11,235,084	)		—			—
Foreign exchange gain		(3,878,150	)		(5,078,338	)		(4,744,810	)
		931,441,109			658,101,592			561,779,421
Loss before income taxes and non-controlling interest		(11,714,170	)		(27,728,349	)		(43,719,889	)
Income taxes (note 12)
Current		(1,564,038	)		(2,491,761	)		(1,232,487	)
Future		1,482,074			1,284,869			(1,110,386	)
		(81,964	)		(1,206,892	)		(2,342,873	)
Loss before non-controlling interest		(11,796,134	)		(28,935,241	)		(46,062,762	)
Non-controlling interest (note 20)		(943	)		22,333			263,959
Net loss		(11,797,077	)		(28,912,908	)		(45,798,803	)
Basic loss per share (note 26)		(0.35	)		(0.96	)		(1.55	)
Diluted loss per share (note 26)		(0.35	)		(0.96	)		(1.55	)
Weighted average number of common shares outstanding
Basic and diluted		33,632,390			29,998,133			29,602,360

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)

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$ (restated) *			$
Cash flows provided by (used in):
Operating activities
Net loss		(11,797,077	)		(28,912,908	)		(45,798,803	)
Adjustments for non-cash and non-operating transactions
Non-controlling interest		943			(22,333	)		(263,959	)
Depreciation and amortization		14,142,546			13,024,258			12,352,672
Future income tax asset		(202,870	)		(1,600,985	)		1,333,108
Fair value adjustment on IPL PNG Ltd. acquisition		—			(367,935	)		—
(Gain)/loss on sale of plant and equipment		(16,250	)		269,321			263,945
Gain on sale of exploration assets		(11,235,084	)		—			—
Impairment of plant and equipment		—			960,000			755,857
Amortization of discount on debt		—			—			28,891
Amortization of discount on debentures liability		1,915,910			—			—
Amortization of deferred financing costs		260,400			421,691			219,033
(Gain)/loss on unsettled hedge contracts		851,500			(47,314	)		(71,875	)
(Gain)/loss on derivative contracts		(17,034,350	)		3,765,800			(1,220,500	)
Stock compensation expense		5,741,086			6,062,962			1,976,072
Inventory revaluation		8,379,587			—			—
Non-cash interest on secured loan facility		2,189,907			6,143,660			2,926,025
Non-cash interest settlement on preference shares		372,950			—			—
Non-cash interest settlement on debentures		2,620,628			—			—
Oil and gas properties expensed		1,103,320			14,548,043			7,824,051
Loss on amendment of indirect participation interest — PNGDV		—			—			1,851,421
Gain on LNG shareholder agreement		—			(6,553,080	)		—
Preference share transaction costs		—			390,000			—
Gain on buy back of minority interest		—			(394,290	)		—
(Gain)/loss on proportionate consolidation of LNG project		(811,765	)		2,375,278			—
Unrealized foreign exchange gain		(3,728,721	)		(5,078,338	)		(4,744,810	)
Change in operating working capital
Decrease/(increase) in trade receivables		18,684,422			6,661,838			(6,663,218	)
Increase in unrealised hedge gains		900,000			—			—
Decrease/(increase) in other assets and prepaid expenses		592,073			(2,698,546	)		4,051
Decrease/(increase) in inventories		(3,189,859	)		(6,033,038	)		2,642,493
(Decrease)/Increase in accounts payable, accrued liabilities and income tax payable		5,846,860			(34,533,991	)		28,773,008
Net cash from/(used in) operating activities		15,586,156			(31,619,907	)		2,187,462
Investing activities
Expenditure on oil and gas properties		(63,890,512	)		(69,090,092	)		(47,990,758	)
Proceeds from IPI cash calls		18,323,365			21,782,988			—
Expenditure on plant and equipment		(5,172,133	)		(7,289,319	)		(13,585,792	)
Proceeds received on sale of assets		312,500			65,072			3,770,080
Proceeds received on sale of exploration assets		6,500,000			—			—
Acquisition of subsidiary (note 16)		—			(3,326,631	)		(25,820,515	)
Proceeds from insurance claim		—			7,000,000			—
(Increase)/decrease in restricted cash held as security on borrowings		(3,900,680	)		10,134,864			(15,856,955	)
Change in non-cash working capital
Increase/(decrease) in accounts payable and accrued liabilities		436,775			6,353,247			2,412,621
Net cash (used in)/from investing activities		(47,390,685	)		(34,369,871	)		(97,071,319	)
Financing activities
Repayments of secured loan		(9,000,000	)		(4,500,000	)		(4,500,000	)
(Repayments of)/proceeds from bridging facility, net of transaction costs		(70,000,000	)		—			125,293,488
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	)		—
Repayments of unsecured borrowings		—			—			(21,453,132	)
Proceeds from Clarion Finanz for Elk option agreement		5,500,000			5,922,712			—
Proceeds from Petromin for Elk participation agreement		4,000,000			—			—
Proceeds from/(repayments of) working capital facility		2,291,030			29,627,864			(33,850,814	)
Proceeds from/(payments for) issue of common shares/conversion of debt, net of transaction costs		(104,975	)		23,816,100			1,473,943
Proceeds from issue of debentures, net of transaction costs		94,780,034			—			—
Proceeds from preference shares, net of transaction costs		—			14,250,000			—
Proceeds from conversion of warrants		—			65,621			—
Net cash from/(used in) financing activities		36,913,339			78,170,105			66,963,485
Increase/(decrease) in cash and cash equivalents		5,108,810			12,180,327			(27,920,372	)
Cash and cash equivalents, beginning of period		43,861,762			31,681,435			59,601,807
Cash and cash equivalents, end of period (note 5)		48,970,572			43,861,762			31,681,435

See accompanying notes to the consolidated financial statements

See note 6 for non cash financing and investing activities

* See note 2(x) for details of restatement of 2007 cash flows

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,
	2008			2007			2006
	$			$			$
Share capital
At beginning of period		259,324,133			233,889,366			223,934,500
Issue of capital stock (note 21)		114,580,223			25,434,767			9,954,866
At end of period		373,904,356			259,324,133			233,889,366
Preference shares
At beginning of period		6,842,688			—			—
Issue of preference shares (note 22)		—			6,842,688			—
Converted to common shares		(6,842,688	)		—			—
At end of period		—			6,842,688			—
8% subordinated debentures
At beginning of period		—			—			—
Issue of debentures (note 23)		13,036,434			—			—
Conversion to common shares during the year		(2,199,040	)		—			—
At end of period		10,837,394			—			—
Contributed surplus
At beginning of period		10,337,548			4,377,426			2,933,586
Fair value of options exercised transferred to share capital (note 24)		(456,867	)		(102,840	)		(532,232	)
Stock compensation expense (note 24)		5,741,086			6,062,962			1,976,072
At end of period		15,621,767			10,337,548			4,377,426
Warrants
At beginning of period		2,119,034			2,137,852			2,137,852
Movement for period (note 25)		—			(18,818	)		—
At end of period		2,119,034			2,119,034			2,137,852
Accumulated Other Comprehensive Income
At beginning of period		6,025,019			1,492,869			477,443
Deferred hedge gain recognised on transition		—			1,385			—
Deferred hedge (loss)/gain movement for period, net of tax		18,012,500			(1,385	)		—
Foreign currency translation movement for period, net of tax (note 2(g))		3,660,787			4,532,150			1,015,426
At end of period		27,698,306			6,025,019			1,492,869
Conversion options
At beginning of period		19,840,000			20,000,000			20,000,000
Movement for period (note 19)		(2,700,000	)		(160,000	)		—
At end of period		17,140,000			19,840,000			20,000,000
Accumulated deficit
At beginning of period		(208,389,853	)		(179,476,945	)		(133,678,142	)
Net loss for period		(11,797,077	)		(28,912,908	)		(45,798,803	)
At end of period		(220,186,930	)		(208,389,853	)		(179,476,945	)
Shareholders’ equity at end of period		227,133,927			96,098,569			82,420,568

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)

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Net loss as per Statement of Operations		(11,797,077	)		(28,912,908	)		(45,798,803	)
Other comprehensive income, net of tax		21,673,287			4,530,765			1,015,426
Comprehensive income/(loss)		9,876,210			(24,382,143	)		(44,783,377	)

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 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 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 29, Reconciliation to Generally Accepted Accounting Principles in the United States.

The consolidated financial statements for the year ended December 31, 2008 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.

(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, 2008, the Company reported a loss of $11.8 million as compared to a loss of $28.9 million for the same period of 2007. The total operating cash inflow was $15.6 million for the year compared to a cash outflow of $31.6 million in 2007. The Company reported a net operating cash outflow, before working capital movements, of $7.2 million for the year compared to $5.0 million inflow during 2007. The net current assets for the year ended December 31, 2008 was $80.4 million compared to a net current asset deficit of $49.9 million in 2007.

The Company has cash, cash equivalents and cash restricted of $75.3 million as at December 31, 2008 (December 2007 — $66.3 million), of which $26.3 million is restricted (December 2007 — $22.4 million). The Company has a short term working capital facility of $190.0 million for its Midstream — Refining operation that is renewable annually with BNP Paribas. This facility is secured by the assets it is drawn down against. The overall facility limit has been increased by $20.0 million as part of the annual renewal process. As at December 31, 2008 only $81.0 million has been utilized, and the remaining facility remains available for use. This facility is due to be renewed in August 2009. During 2008 the Company also secured a $57.5 million (Papua New Guinea Kina 150.0 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 Papua New Guinea Kina 80.0 million (approximately $30.7 million) and BSP facility limit is Papua New Guinea Kina 70.0 million (approximately $26.8 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 August 2009. As at December 31, 2008 only $15.4 million of this combined facility has been utilized, and the remaining facility 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 postpone these activities in the event sufficient funding is not available.

Consolidated Financial Statements  INTEROIL CORPORATION     9

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

2. Significant accounting policies (cont’d)

The Company believes that it has sufficient funds for the Midstream Refinery and Downstream operations; however, existing cash balances and ongoing cash generated from operations will not be sufficient to facilitate further development of the Elk/Antelope well prospect and the Midstream Liquefaction LNG 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, 2008, December 31, 2007, December 31, 2006 and for the years then ended. Subsidiaries of InterOil Corporation as at December 31, 2008 include SP InterOil, LDC (“SPI”) (99.9%), SPI Exploration and Production Corporation (100%), SPI Distribution Limited (100%), 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%) and their subsidiaries. InterOil Corporation and its subsidiaries together are referred to in these financial statements as the Company or the consolidated entity.

Effective October 1, 2006 the Company acquired 100% shareholding of Shell Papua New Guinea Ltd from Shell. The acquired entity has been renamed IPL (PNG) Ltd and became a fully owned subsidiary of InterOil Products Limited. The results of IPL (PNG) Ltd have been incorporated into the Company consolidation from October 1, 2006.

During the year 2006, the Company set up PNG LNG Inc., a Bahamas incorporated entity, to construct and operate a Liquefied Natural Gas facility (‘LNG Project’) in PNG. 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. Refer to the section ‘Proportionate consolidation of Joint Venture interests’ below for the changes to InterOil’s shareholding in PNG LNG Inc. 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.

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 Company 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.

Proportionate consolidation of Joint Venture interests

During July 2007, the investment in PNG LNG Inc. (“Joint Venture Company” — previously 100% subsidiary of InterOil) was transferred from InterOil Corporation to InterOil LNG Holdings Inc. 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.. 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, refer to note 4. For further details on the impact of Shareholders Agreement and proportionate consolidation of the joint venture balances, refer to note 14 below.

Consolidated Financial Statements  INTEROIL CORPORATION     10

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

2. Significant accounting policies (cont’d)

(d) Changes in accounting policies

Effective January 1, 2008 the Company adopted the following new Canadian Institute of Chartered Accountants (CICA) sections:

• CICA 1400 — General standards of financial statement presentation

• CICA 1535 — Capital Disclosures

• CICA 3031 — Inventories

• CICA 3862 — Financial Instruments — Disclosures; and

• CICA 3863 — Financial Instruments — Presentation

These new accounting standards provide requirements for the presentation and disclosure of financial instruments and capital disclosures. The standards have been adopted prospectively and as such the comparative consolidated financial statements have not been restated. The adoption of these Handbook sections had no impact on opening retained earnings or accumulated other comprehensive income.

General standards of financial statement presentation

This Section has been amended to include requirements to assess and disclose an entity’s ability to continue as a going concern. The new requirements are applicable to all entities and are effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008.

Capital Disclosures

This Section establishes standards for disclosing information about an entity’s capital and how it is managed. This section has resulted in InterOil disclosing information in note 3(h) below that enables users of its financial statements to evaluate the Company’s objectives, policies and processes for managing capital.

Inventories

This section establishes standards for the measurement and disclosure of inventories. It provides the Canadian equivalent to International Financial Reporting Standard IAS 2, “Inventories”. There is no impact due to this new standard on the accounting policies of the Company.

Financial Instruments — Disclosure and Presentation

The objectives of these Sections are to require entities to provide disclosures in their financial statements that enable users to evaluate:

a.	the significance of financial instruments for the entity’s financial position and performance
b.	the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks; and
c.	to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows.

These revised sections have resulted in InterOil disclosing additional information on the risk arising from financial instruments to which InterOil is exposed to, refer note 3 below for detailed information.

(e) New standards issued but not yet effective

Based on the detailed review conducted by the Company of the new CICA sections, or revisions to current sections, that are effective January 1, 2009, no items have been identified as having any material impact on the Company’s financial statements.

(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.

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 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 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 revenue 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.

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 and Canada. The consolidated statement of operations is prepared on a net basis by the Company.

Consolidated Financial Statements  INTEROIL CORPORATION     12

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

2. Significant accounting policies (cont’d)

(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 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.

(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.

(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 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.

Consolidated Financial Statements  INTEROIL CORPORATION     13

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

2. Significant accounting policies (cont’d)

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 refined petroleum product consists of raw material, labor, direct overheads and transportation costs. The cost of downstream refined petroleum product 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.

(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 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.

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.

(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. In accordance with revised guidance under CICA Section 3861 — Financial Instruments — disclosure and presentation, InterOil has reclassified the unamortized deferred financing costs amounting to $1,716,757 as at January 1, 2007, previously disclosed as a separate item under Non-current assets, to offset the respective liability accounts.

Consolidated Financial Statements  INTEROIL CORPORATION     14

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

2. Significant accounting policies (cont’d)

(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 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 and does not outline any terms for restoration and closure costs.

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, 2008.

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 category are as follows:

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

During the year 2006, InterOil adopted a deminimus threshold of $5,000 below which all capital purchases are expensed in the period of purchase. This was effected retrospectively and all individual items not meeting the capitalization criteria adopted, were written off in 2006.

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 lease’s inception 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.

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 associated with the retirement of the refinery or with its normal operations relating to future restoration and closure costs.

The refinery is built on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097.

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, 2008, no provision has been raised.

Consolidated Financial Statements  INTEROIL CORPORATION     15

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

2. Significant accounting policies (cont’d)

Disposal of property, plant and equipment

At the time of disposition of plant and equipment, accounts are relieved of the asset values and accumulated depreciation and any resulting gain or loss is included in the statement of operations.

(t) Oil and gas properties

The Company uses the successful-efforts method to account for its oil and gas exploration and development activities. 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.

Stock-based compensation

Stock-based compensation benefits are provided to employees pursuant to the 2006 Stock Incentive Plan (with some options still in existence having been granted under the now superseded Incentive Stock Option Plan of 2002). The fair value 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 Company uses the fair value based method to account for employee stock options. 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.

Consolidated Financial Statements  INTEROIL CORPORATION     16

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

2. Significant accounting policies (cont’d)

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

Nine month period ended September 30, 2008, six month period ended June 30, 2008, three month period ended March 31, 2008 and year ended December 31, 2007 cash flows have been adjusted to correctly reflect the classification of deferred gain in relation to the LNG project. For details of adjustments made to the previously published financial statements, refer to the following table:

				Six Month period			Three Month
	Nine Month period ended			ended			period ended			Year ended
	September 30, 2008			June 30, 2008			March 31, 2008			December 31, 2007
	$			$			$			$
Cash flows provided by (used in):
Operating activities — Canadian GAAP (as per published financial statements)		(23,024,574	)		(25,662,285	)		6,997,815			(40,716,444	)
Reclassification made:
Being reclassified due to movement in Deferred gain in relation to the LNG Project previously classified in Investing activities as compared to Operating activites.		8,400,573			3,107,330			3,107,330			9,096,537
Operating activities — Canadian GAAP (revised)		(14,624,001	)		(22,554,955	)		10,105,145			(31,619,907	)
Investing activities — Canadian GAAP (as per published financial statements)		(19,029,830	)		(24,805,959	)		(2,921,286	)		(25,273,334	)
Reclassification made:
Being reclassified due to movement in Deferred gain in relation to the LNG Project previously classified in Investing activities as compared to Operating activites.		(8,400,573	)		(3,107,330	)		(3,107,330	)		(9,096,537	)
Investing activities — Canadian GAAP (revised)		(27,430,403	)		(27,913,289	)		(6,028,616	)		(34,369,871	)
Financing activities — Canadian GAAP (as per published financial statements)		45,158,740			35,417,731			(30,849,094	)		78,170,105
Reclassification made:
None		—			—			—			—
Financing activities — Canadian GAAP (revised)		45,158,740			35,417,731			(30,849,094	)		78,170,105

During the year, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream — Liquefaction segments to reflect a more accurate view of its segment results. The prior year comparatives have been reclassified to conform to the current classification.

3. Financial Risk Management

The Company’s activities expose it to a variety of financial risks; market risk, credit risk, liquidity risk and cash flow interest rate 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 by the Finance Department 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 Board provides written principles for overall risk management, as well as written policies covering specific areas, such as use of derivative financial instruments.

Consolidated Financial Statements  INTEROIL CORPORATION     17

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

3. Financial Risk Management (cont’d)

(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.

Most of the Company’s transactions are undertaken in United States Dollars (USD) and Papua New Guinea Kina (PGK). Currently there are no foreign 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 refinery and Downstream operations. However, the translation of USD intercompany balances in PGK operating entities at period ends can result in material impact on the foreign exchange gains/losses on consolidation.

Changes in the PGK to USD exchange rate can affect our Midstream refinery 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 strengthened against the USD during the year ended December 31, 2008 (from 0.3525 to 0.3735).

The financial instruments denominated in Papua New Guinea Kina as at December 31, 2008 are as follows:

	December 31,
	2008
	$
Financial Assets
Cash and cash equivalents		28,865,339
Receivables		39,307,624
Other financial assets		3,348,716
Financial liabilities
Payables		17,766,660
Working capital facility		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, including intra-group balances, 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
	December 31, 2008
			Impact on equity -
	Impact on profit		excluding profit impact
	$		$
Post-tax gain/(loss)
USD/PGK — effect of 5% change		4,245,399		3,072,446

(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 on sales 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.

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 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.

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
	December 31, 2008
			Impact on equity -
	Impact on profit		excluding profit impact
	$		$
Post-tax gain/(loss)
$10 increase in benchmark pricing		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,
	2008		Cash flow/fair value
	$		interest rate risk
Financial Assets
Cash and cash equivalents		6,571,375	fair value interest rate risk
Cash and cash equivalents		42,399,197	cash flow interest rate risk
Cash restricted		290,782	fair value interest rate risk
Cash restricted		25,994,258	cash flow interest rate risk
Financial liabilities
OPIC secured loan		62,500,000	fair value interest rate risk
BNP working capital facility		53,386,775	cash flow interest rate risk
Westpac working capital facility		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
	December 31, 2008
			Impact on equity -
	Impact on profit		excluding profit impact
	$		$
Post-tax loss/(gain)
LIBOR +1%		260,944		—

Consolidated Financial Statements  INTEROIL CORPORATION     19

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

3. Financial Risk Management (cont’d)

(iv) Product risk

The composition of the crude feedstock will vary the refinery output of products. The 2008 output achieved includes distillates fuels, which includes diesel and jet fuels (56%) (Dec 2007 — 60%) and naphtha and low sulphur waxy residue (40%) (Dec 2007 — 30%). The product yields obtained will vary going forward as the refinery operations are optimized and will vary based on the type of crude feedstock used.

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

Prudent liquidity risk management implies maintaining sufficient cash and the availability of funding through an adequate amount of committed credit facilities. Due to the nature of the Upstream segment of the Company, funding is secured by means of indirect participation interests, capital raisings and other financing sources as required. The Company endeavors to manage the liquidity risk by continually reviewing the liquidity position including cash flow forecasts to determine the forecast cash requirements and maintain appropriate liquidity levels. All accounts payable and accrued liabilities are payable within one year. Changes in crude price environment will have impact on our liquidity position due to our working capital requirements. For further details on our working capital facilities, refer to (e) below.

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

			Payable ageing between
	Total		<30 days		30-60 days		>60 days
December 31, 2008	$		$		$		$
Accounts payable and accrued liabilities		78,147,736		76,556,334		1,181,334		410,068

(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 one customer in Singapore which represented $156,518,509 (Dec 2007 — $124,502,170) or 17% (Dec 2007 — 20%) of total sales in the year ended December 31, 2008. The Company’s domestic sales for the year ended December 31, 2008 were not dependent on a single customer or geographic region of Papua New Guinea. The export sales to one customer 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 large banks which have acceptable credit ratings determined by a recognized rating agency.

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

	December 31,
	2008
	$
Current
Cash and cash equivalents		48,970,572
Cash restricted		25,994,258
Trade receivables		42,887,823
Commodity derivative contracts		31,335,050
Non-current
Cash restricted		290,782

Consolidated Financial Statements  INTEROIL CORPORATION     20

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

3. Financial Risk Management (cont’d)

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

			Receivable ageing between
	Total		Current and		30-60 days		>60 days
December 31, 2008	$		<30 days $		$		$
Net trade receivables		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
	Total		Current		(not impaired)		(impaired)
December 31, 2008	$		$		$		$
Gross trade receivables		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.

The movement in impaired receivables for the year ended December 31, 2008 was as follows:

	Year ended
	$
Trade receivables — Impairment provisions
Opening balance		3,176,807
Movement for period		1,431,490
Closing balance		4,608,296

(d) Geographic risk

The operations of InterOil are concentrated in Papua New Guinea.

(e) Financing facilities

As at December 31, 2008, the Company had drawn down against the following financing facilities:

• BNP working capital facility (refer note 15)

• Westpac working capital facility (refer note 15)

• OPIC secured loan facility (refer note 18)

• 8% subordinated debentures (refer note 23)

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

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

Consolidated Financial Statements  INTEROIL CORPORATION     21

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

3. Financial Risk Management (cont’d)

(f) Effective interest rates and maturity profile

	Floating		Fixed interest maturing between																	Effective
	interest		1 year											more than		Non-interest				interest
	rate		or less		1-2			2-3		3-4		4-5		5 years		bearing		Total		rate
December 31, 2008	$’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		1.93	%
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	%
Other financial liabilities		—		—		—			—		—		—		—		—		—		—
		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, 2008
	Carrying amount		Fair value
	$		$
Financial instruments
Loans and receivables
Receivables		42,887,823		42,887,823
Held for trading
Commodity derivative contracts (note 7)		31,335,050		31,335,050
Financial assets
Cash and cash equivalents		48,970,572		48,970,572
Cash restricted		26,285,040		26,285,040
Financial liabilities at amortized cost
Current liabilities:
Accounts payable and accrued liabilities (note 13)		78,147,736		78,147,736
Working capital facility (note 15)		68,792,402		68,792,402
Current portion of secured loan (note 18)		9,000,000		9,012,228
Non-current liabilities
Secured loan (note 18)		52,365,333		58,753,276
8% Subordinated debenture liability (note 23)		65,040,067		65,040,067

The fair value of the secured loan is based on discounted cash flow analysis using a current market interest rate applicable for similar loan arrangements. The 8% Subordinated debenture liability has an equity component on the balance sheet of $10,837,394 and a redemption amount of $78,975,000 as shown in table (f) above.

(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 capital/debt as required for optimizing shareholder returns. The Company is actively trying to manage 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, 2008. The gearing levels were reduced to 36% in December 2008 from 67% in December 2007.

Consolidated Financial Statements  INTEROIL CORPORATION     22

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

3. Financial Risk Management (cont’d)

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, 2008 as compared to December 31, 2007 was mainly due to the conversion of $60,000,000 of the $130,000,000 Bridging facility into common shares in May 2008.

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 conversion price applicable to these debentures is $25.00 per share, with mandatory conversion 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 is to be paid semi-annually in arrears, in May and November of each year, commencing November 2008. During July 2008, $15,000,000 of the outstanding debentures were converted to common shares, leading to the issue of 600,000 common shares. During November 2008, a further $1,025,000 of the outstanding debentures was converted to common shares, leading to the issue of 41,000 common shares.

We are also evaluating further opportunities of raising capital in the short term for our capital expenditure requirements. In order to achieve this objective, the Company has filed a preliminary short form base shelf prospectus with the Ontario Securities Commission and a corresponding registration statement on Form F-10 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 $200.0 million of its debt securities, common shares, preferred shares and/or warrants (“Securities”) in one or more offerings. This preliminary short form base shelf prospectus has since been replaced with an omnibus shelf prospectus filed and accepted by the Ontario Securities Commission on August 7, 2008. The corresponding registration statement on Form-10/A has also been filed with the SEC.

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 include financing costs and interest income.

During the year 2006, the Company started incurring costs in relation to the Liquefaction project, which have been reported separately under Midstream — Liquefaction project below. During 2007 a joint venture was formed to further the LNG project as disclosed in note 2(c) above. The joint venture balances have been proportionately consolidated and disclosed within the Midstream Liquefaction segment in addition to InterOil LNG Holdings Inc. which was incorporated to hold InterOil’s interest in the Joint Venture Company.

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.

During the year, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream — Liquefaction segments to reflect a more accurate view of its segment results. During the year management decided to transfer notional interest to development segments for the intercompany loans that have been provided interest free. The prior year comparatives have been reclassified to conform to the current classification. For the year 2007, notional interest of $1,033,661 and $105,304 has been transferred from Corporate Segment to Upstream and Midstream — Liquefaction respectively.

Consolidated Financial Statements  INTEROIL CORPORATION     23

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

4. Segmented financial information (cont’d)

				Midstream -			Midstream -									Consolidation
Year ended December 31, 2008	Upstream			Refining			Liquefaction			Downstream			Corporate			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

				Midstream -			Midstream -									Consolidation
Year ended December 31, 2007	Upstream			Refining			Liquefaction			Downstream			Corporate			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     24

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

4. Segmented financial information (cont’d)

				Midstream -			Midstream -									Consolidation
Year ended December 31, 2006	Upstream			Refining			Liquefaction			Downstream			Corporate			adjustments			Total
Revenues from external customers		—			315,211,130			—			195,876,804			—			—			511,087,934
Intersegment revenues		—			136,583,916			—			22,480			8,669,933			(145,276,329	)		—
Interest revenue		2,820,888			360,319			—			100,750			1,601,491			(1,659,453	)		3,223,995
Other revenue		2,427,816			—			—			1,319,787			—			—			3,747,603
Total segment revenue		5,248,704			452,155,365			—			197,319,821			10,271,424			(146,935,782	)		518,059,532
Cost of sales and operating expenses		—			451,374,165			—			183,511,182			—			(135,390,806	)		499,494,541
Administrative, professional and general expenses		6,370,436			10,576,957			694,416			7,671,208			15,378,963			(8,552,604	)		32,139,376
Derivative (gain)/loss		—			(2,559,712	)		—			—			—			—			(2,559,712	)
Foreign exchange (gain)/loss		(61,423	)		(4,635,878	)		(219	)		(192,433	)		145,142			—			(4,744,811	)
Exploration costs, excluding exploration impairment		6,176,866			—			—			—			—			—			6,176,866
Exploration impairment		1,647,185			—			—			—			—			—			1,647,185
Depreciation and amortisation		806,142			10,729,546			—			909,767			37,247			(130,030	)		12,352,672
Interest expense		5,428			10,880,779			—			151,730			7,894,820			(1,659,453	)		17,273,304
Total segment expenses		14,944,634			476,365,857			694,197			192,051,454			23,456,172			(145,732,893	)		561,779,421
(Loss)/income before income taxes and non-controlling interest		(9,695,930	)		(24,210,492	)		(694,197	)		5,268,367			(13,184,748	)		(1,202,889	)		(43,719,889	)
Income tax expense		—			—			—			(2,273,773	)		(69,100	)		—			(2,342,873	)
Non controlling interest		—			259,169			—			—			—			4,790			263,959
Total net income/(loss)		(9,695,930	)		(23,951,323	)		(694,197	)		2,994,594			(13,253,848	)		(1,198,099	)		(45,798,803	)
Total assets		85,335,500			325,351,819			(683,582	)		98,722,803			393,700,711			(397,187,776	)		505,239,475

5. Cash and cash equivalents

The components of cash and cash equivalents are as follows:

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
Cash on deposit		46,761,362		43,861,762		31,681,435
Bank term deposits
— Papua New Guinea kina deposits		2,209,210		—		—
		48,970,572		43,861,762		31,681,435

Consolidated Financial Statements  INTEROIL CORPORATION     25

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

6. Supplemental cash flow information

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Cash paid during the year
Interest		10,705,499			16,934,058			8,548,552
Income taxes		6,738,175			2,344,282			2,306,218
Interest received		926,878			2,176,678			3,154,380
Non-cash investing and financing activities:
Deferred financing costs included in accounts payable and accrued liabilities		—			—			500,000
Increase in deferred gain on contributions to LNG project		8,400,573			9,096,537			—
(Gain)/loss on proportionate consolidation of LNG project		(811,765	)		2,375,278			—
Fair value adjustment on IPL PNG Ltd. acquisition (note 16)		—			(367,935	)		—
Decrease in plant and equipment as a result of impairment		—			960,000			755,857
Transfer to plant and equipment to assets held for sale		—			—
(Decrease)/increase in deferred liquefaction project liability		—			(6,553,080	)		6,553,080
Reduction to plant and equipment due to negative goodwill on Enron buy-back		—			4,841,776			—
Increase in share capital from:
the exercise of share options		456,867			102,840			532,232
the exercise of warrants		—			18,818			—
conversion of debentures into share capital		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			7,948,691
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		2,620,628			—			—
buyback of minority interest		—			496,500			—

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 2008, the Company earned 1.9% (2007 — 5.0%, 2006 — 5.0%) on the cash on deposit which related to the working capital facility. In 2008, cash and cash equivalents earned an average interest rate of 3.21% per annum (2007 — 4.76%, 2006 — 5.1%) on cash, other than the cash on deposit that was related to the working capital facility.

Restricted cash, which mainly relates to the working capital facility, is comprised of the following:

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
Cash deposit on working capital facility (1.9%)		25,994,258		20,240,553		29,301,940
Debt reserve for secured loan		—		1,761,749		—
Cash restricted — Current		25,994,258		22,002,302		29,301,940
Cash deposit on secured loan		—		—		647,502
Debt reserve for secured loan		—		—		2,420,000
Bank term deposits on Petroleum Prospecting Licenses (0.9%)		124,097		116,090		107,997
Cash deposit on office premises (6.7%)		166,685		265,968		41,785
Cash restricted — Non-current		290,782		382,058		3,217,284
		26,285,040		22,384,360		32,519,224

Consolidated Financial Statements  INTEROIL CORPORATION     26

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

7. Financial instruments (cont’d)

Cash held as deposit on the 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 base facility plus any amounts that are fully cash secured. The cash held as deposit on secured loan used to support the Company’s secured loan borrowings with the Overseas Private Investment Corporation (“OPIC”). This cash deposit requirement was waived until December 31, 2008 by way of an amendment in December 2006.

Debt reserve for secured loan was maintained in accordance to the terms of the Merrill Lynch bridging facility. This facility was fully repaid in May 2008 resulting in no further requirement to maintain any funds in the debt reserve account.

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

Commodity derivative contracts

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

At December 31, 2008, InterOil had a net receivable of $31,335,050 (2007 — payable of $1,960,300, 2006 — receivable of $1,759,575) relating to commodity hedge contracts. Of this total, a receivable of $16,261,000 (2007 — $nil, 2006 — payable of $45,925) relates to hedge accounted contracts as at December 31, 2008 and a receivable of $15,074,050 (2007 — payable of $1,960,300, 2006 — receivable of $1,805,500) 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 $18,012,500 (2007 — $nil) and has been included in comprehensive income. Subsequent to year end, these unrealized hedges were terminated and the mark-to-market gains were realized. However, these gains will be released into the Statement of Operations as the anticipated transactions that these hedges were initially taken to cover will occur. The gain on hedges in 2006 for which final pricing was to be determined in future periods was $1,385, and was included within liabilities in compliance with the superseded hedging standards applicable for that year.

a. Hedge accounted contracts:

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

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

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

The following summarizes the effective hedge contracts by derivative type on which final pricing was determined in future periods as at December 31, 2006:

Derivative	Type	Notional volumes (bbls)
Naphtha swap	Sell Naphtha		175,000

Consolidated Financial Statements  INTEROIL CORPORATION       27

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

7. Financial instruments (cont’d)

b. Non-hedge accounted derivative contracts:

In addition to the above hedge accounted contracts, as at December 31, 2008, the Company had the following open non-hedge accounted derivative contracts outstanding. Any gains/losses on these contracts are included in derivative (gain)/loss for the period.

As at December 31, 2008:

		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

A profit of $24,038,550 was recognized on the non-hedge accounted derivative contracts for the year ended December 31, 2008 (Dec 2007 — loss of $7,271,693).

As at December 31, 2007:

Derivative	Type	Notional volumes (bbls)
Brent contracts to manage export price risk	Sell Brent		130,000
Naphtha swap	Sell Naphtha		150,000
As at December 31, 2006:
Derivative	Type	Notional volumes (bbls)
Brent contracts to manage export price risk	Sell Brent		320,000

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 15). As at December 31, 2008, $3,141,238 (Dec 2007 — $nil, Dec 2006 — $23,671,568) 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 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, 2008, $10,300,542 (Dec 2007 — $38,033,715, Dec 2006 — $55,955,400) of the trade receivables secures the BNP Paribas working capital facility disclosed in note 15. This balance includes $6,912,883 (Dec 2007 — $33,703,069, Dec 2006 — $20,186,665) of intercompany receivables which were eliminated on consolidation.

Consolidated Financial Statements  INTEROIL CORPORATION       28

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

9. Inventories

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
Midstream — refining and marketing (crude oil feedstock)		25,556,463		3,587,786		12,795,356
Midstream — refining and marketing (refined petroleum product)		30,167,417		43,173,806		22,329,270
Midstream — refining and marketing (parts inventory)		288,643		201,526		46,636
Downstream (refined petroleum product)		27,024,803		35,626,124		32,422,296
		83,037,326		82,589,242		67,593,558

At December 31, 2008, inventory had been written down to its net realizable value. The write down of $8,529,016 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 or 2006.

At December 31, 2008, $56,012,523 (Dec 2007 — $46,963,118, Dec 2006 — $35,171,262) of the midstream inventory balance secures the BNP Paribas working capital facility disclosed in note 15.

Inventories recognized as expense during the year ended December 31, 2008 amounted to $902,765,655 (2007 — $586,633,699, 2006 — $511,847,212).

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 $343,069 (2007 — $313,946, 2006 — $118,644) which are located in Australia. Amounts in deferred project costs and work in progress are not being amortized.

Consolidation entries relates to midstream assets which were created when the gross margin on 2004 refinery sales to the downstream segment were eliminated in the development stage of the refinery.

				Midstream -			Midstream -						Corporate &
December 31, 2008	Upstream			Refining			Liquefaction			Downstream			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
				Midstream -			Midstream -						Corporate &
December 31, 2007	Upstream			Refining			Liquefaction			Downstream			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

Consolidated Financial Statements  INTEROIL CORPORATION       29

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

10. Plant and equipment (cont’d)

				Midstream -			Midstream -					Corporate &
December 31, 2006	Upstream			Refining			Liquefaction		Downstream			Consolidated			Totals
Plant and equipment		1,247,201			249,741,042			—		37,697,458			146,797			288,832,498
Deferred project costs and work in progress		—			723,566			—		715,653			—			1,439,219
Consolidation entries		—			—			—		—			(2,990,688	)		(2,990,688	)
Accumulated depreciation and amortisation		(153,455	)		(21,760,341	)		—		(22,697,003	)		(28,153	)		(44,638,952	)
Net book value		1,093,746			228,704,267			—		15,716,108			(2,872,044	)		242,642,077
Capital expenditure for year ended December 31, 2006		—			11,948,960			—		10,543,842			156,817			22,649,619

During the year ended December 31, 2008, InterOil recognized a gain of $285,206 on the disposal of assets (2007 — loss of $269,320, 2006 — loss of $263,945).

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 20).

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. During 2006, InterOil sold one of the two barges included in the upstream segment. Prior to the sale, an impairment assessment was performed and an impairment loss of $755,857 was recognized. These impairment losses are 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,
	2008		2007		2006
	$		$		$
Drilling equipment		13,857,772		14,664,179		13,949,238
Inventory		10,113,808		7,661,992		4,293,734
Petroleum Prospecting License drilling programs at cost		104,042,379		62,538,956		36,281,375
		128,013,959		84,865,127		54,524,347

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

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
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 19)		4,735,084		—		—
		11,235,084		—		—

During the year ended December 31, 2008, the Company has 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 carried forward in the balance sheet, the entire sale proceeds were treated as a gain on sale of these properties.

In addition to the above divestments, on May 5, 2008, one of the investors who had a 4.1% interest in the eight well drilling program (19.1% of the IPI Agreement) waived their right to convert their IPI percentage into common shares pursuant to the agreement dated February 25, 2005. On September 23, 2008, another investor who had a 1.125% interest in the eight well drilling program (5.3% of the IPI agreement) also waived its right to convert its IPI percentage into common shares.

Consolidated Financial Statements  INTEROIL CORPORATION       30

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

11. Oil and gas properties

These waivers have triggered a conveyance under the IPI Agreement for their share of interest in the program. An amount of $4,735,084 was recognized as a gain on conveyance following the guidance in paragraphs 47(h) and 47(j) of SFAS 19 (refer note 19 for further details).

Refer to Note 13 below for details of Petromin participation in the Elk/Antelope field and the treatment of the $4,000,000 advance received from them in relation to this participation agreement.

The following table discloses a breakdown of the exploration expenses presented in the statements of operations for the periods ended:

	Year ended
	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
Exploration costs, excluding exploration impairment		995,532		13,305,437		6,176,866
Exploration impairment
Costs incurred in prior years		—		—		—
Costs incurred in current year		107,788		1,242,606		1,647,185
Total exploration impairment		107,788		1,242,606		1,647,185
		1,103,320		14,548,043		7,824,051

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,
	2008			2007			2006
	$			$			$
(Loss) before income taxes and non controlling interest		(11,714,170	)		(27,728,349	)		(43,719,889	)
Statutory income tax rate		34.50	%		35.10	%		35.10	%
Computed tax (benefit)		(4,041,389	)		(9,732,650	)		(15,345,681	)
Effect on income tax of:
Losses/(income) in foreign jurisdictions not deductible/(assessable)		(61,702	)		(2,481,828	)		251,639
Non-deductible stock compensation expense		720,825			2,128,100			693,601
LNG Project Establishment costs		2,584,562			3,306,847			1,925,090
Non-taxable gain on sale of exploration assets		(3,876,104	)		—			—
Gains and losses on foreign exchange unrealized		(14,059,228	)		2,069,183			(1,687,001	)
Tax rate differential in foreign jurisdictions		(134,619	)		720,014			1,103,122
Over provision for tax in prior years		148,823			(218,403	)		(51,632	)
Tax losses for which no future tax benefit has been brought to account		19,569,753			5,012,598			10,241,534
Temporary differences for which no future tax benefit has been brought to account		(253,262	)		192,826			3,124,836
Temporary differences brought to account on acquisition of subsidiary		—			546,026			1,135,181
Other — net		(515,695	)		(335,821	)		952,184
		81,964			1,206,892			2,342,873

All future tax assets recorded in the consolidated balance sheet relate to downstream assets in Papua New Guinea. The amounts are noncurrent at December 31, 2008. The valuation allowance for deferred tax assets decreased by $51,821,135 (2007 — increased by $10,569,456, 2006 — increased by $27,317,010) in the year ended December 31, 2008.

Consolidated Financial Statements  INTEROIL CORPORATION       31

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

12. Income taxes (cont’d)

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

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Future tax assets
Temporary differences
Plant and equipment		(7,051,509	)		(8,338,671	)		3,030,479
Exploration expenditure		26,901,138			32,563,507			41,870,390
Unrealised foreign exchange losses / (gains)		(17,177,649	)		19,742,048			—
Other — net		1,820,931			1,549,740			122,713
		4,492,911			45,516,624			45,023,582
Losses carried forward		28,679,655			39,274,207			27,754,495
		33,172,566			84,790,831			72,778,077
Less valuation allowance		(30,102,384	)		(81,923,519	)		(71,354,063	)
		3,070,182			2,867,312			1,424,014

The decrease 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, increasing the deferred tax liabilities in relation to unrealized foreign exchange local currency gains. During the year, the Company has elected to lodge USD tax returns in Canada — this legislation has been substantially enacted subsequent to the yearend which will enable to Company to prepare its tax returns in Canada, effective January 1, 2008, in USD. 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 not 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. Management has determined that a 100% valuation allowance of the net operating loss carry-forward is appropriate as of December 31, 2008 in respect of losses generated from the operations, carried forward exploration expenditure and other temporary differences.

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 K200,433,616 (US $74,861,956) at December 31, 2008. 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,
	2008		2007		2006
	$		$		$
Accounts payable — crude import		25,233,525		—		41,006,000
Other accounts payable and accrued liabilities		52,914,211		57,162,039		32,304,793
Income tax payable		—		3,265,568		2,784,576
Total accounts payable and accrued liabilities		78,147,736		60,427,607		76,095,369

Petromin participation in Elk/Antelope field

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”), agreed to take a 20.5% direct interest in the Elk/Antelope field. Petromin will contribute an initial deposit and will conditionally fund 20.5% of the costs of developing the Elk/Antelope field. The relevant legislation on the State’s right to invest arises upon issuance of the Prospecting Development Licence (‘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, or the State does not designate Petromin to hold its interest at that time. In the event the PDL is not granted for the Elk/Antelope field, Petromin will be issued InterOil common shares based on a five day Volume Weighted Average Price (‘VWAP’) immediately prior to the date of issue. As at December 31, 2008, $4,000,000 advance payment received from Petromin has been held under ‘Other accounts payable and accrued liabilities’ above. Once the PDL is formed, conveyance accounting following the guidance in paragraphs 47(h) and 47(j) of SFAS 19 will be triggered.

Consolidated Financial Statements  INTEROIL CORPORATION       32

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

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.. The signing of the Agreement was a key milestone in furthering the proposal for the construction of a liquefaction plant to be built adjacent to our refinery. 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 are owned by InterOil, 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.

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 other 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 partners are being issued ‘B’ Class shares as they contribute cash into the Joint Venture Company by way of cash calls. Based on the Agreement, InterOil is not required to contribute towards cash calls from the Joint Venture Company until a total of $200,000,000 has been contributed by the other Joint Venture partners to equalize their shareholding in the Joint Venture Company with that of InterOil.

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, 2008 is 82.15%, the gain on contribution of non cash assets to the project by InterOil relating to other joint venture partners’ shareholding (17.85% — amounting to $17,497,110) has been recognized by InterOil in its balance sheet as a deferred gain. This deferred gain will increase as the other Joint Venture partners increase 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.

Subsequent to year ended December 31, 2008, 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 652,931 common shares for its share of $11,250,000 in relation to the settlement. The final number of shares is subject to a post closing balancing payment. After the completion of this transaction, Merrill Lynch does not retain any ownership in the PNG LNG project.

15. Working capital facility

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
BNP Paribas working capital facility — midstream		53,386,775		66,501,372		36,873,508
Westpac working capital facility — downstream		15,405,627		—		—
Total working capital facility		68,792,402		66,501,372		36,873,508

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 facility is renewable annually and as part of the current year renewal process, which was completed in the quarter ended September 30, 2008, the overall facility limit was increased by $20,000,000 to $190,000,000 to accommodate higher crude prices and resulting increases in working capital requirements. For the period until December 1, 2008 in the quarter ended December 31, 2008, the facility limit was temporarily increased to $210,000,000, reducing back to $190,000,000 on December 1, 2008.

This financing facility supports the ongoing procurement of crude oil for the refinery and includes related hedging transactions. The facility comprises a base facility to accommodate the issuance of letters of credit followed by secured loans in the form of short term advances. In addition to the base facility, the agreement offers both; cash secured short term facility, and a discounting facility on specific monetary receivables (note 8). 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.

Consolidated Financial Statements  INTEROIL CORPORATION      33

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

15. Working capital facility (cont’d)

The facility bears interest at LIBOR + 3.5% on the short term advances. During the year the weighted average interest rate was 5.11% (2007 — 7.01%, 2006 — 7.28%).

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

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Working capital credit facility		190,000,000			170,000,000			170,000,000
Less amounts included in the working capital facility liability:
Short term advances		(50,245,537	)		(66,501,372	)		(13,201,940	)
Discounted receivables (note 8)		(3,141,238	)		—			(23,671,568	)
		(53,386,775	)		(66,501,372	)		(36,873,508	)
Less: other amounts outstanding under the facility:
Letters of credit outstanding		(27,600,000	)		(32,000,000	)		(79,000,000	)
Bank guarantees on hedging facility		—			(2,500,000	)		(1,500,000	)
Working capital credit facility available for use		109,013,225			68,998,628			52,626,492

At December 31, 2008, the company had one letter of credit outstanding totaling $27,600,000. The letter of credit was for a crude cargo and was drawn down on January 13, 2009.

The cash deposit on working capital facility, as separately disclosed in note 7, included restricted cash of $25,994,258 (2007 — $20,240,553, 2006 — $29,301,940) which is being maintained as a security margin for the facility. In addition, inventory of $56,012,523 (2007 — $46,963,118, 2006 — $35,171,272) and trade receivables of $10,300,542 (2007 — $38,033,715, 2006 — $55,955,400) also secured the facility. The trade receivable balance securing the facility includes $6,912,883 (2007 — $33,703,069, 2006 — $20,186,665) of inter-company receivables which were eliminated on consolidation.

Westpac and Bank South Pacific working capital facility

On October 24, 2008 the Company secured a Papua New Guinea Kina 150,000,000 (approximately $57,500,000) combined revolving working capital facility for its wholesale and retail petroleum products distribution business in Papua New Guinea from Bank of South Pacific Limited (‘BSP’) and Westpac Bank PNG Limited. Westpac facility limit is Papua New Guinea Kina 80,000,000 (approximately $30,700,000) and BSP facility limit is Papua New Guinea Kina 70,000,000 (approximately $26,800,000). The Westpac facility is for an initial term of three years and is due for renewal in October 2011. The BSP facility is renewable annual and is due for renewal in August 2009. As at December 31, 2008 only the Westpac facility has been utilized for $15,405,627, and the entire BSP facility remains available for use. These facilities are secured by a fixed and floating charge over the assets and liabilities of Downstream operations.

16. Acquisition of a subsidiary

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 as at December 31, 2008.

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.

PNG LNG Inc. and Liquid Niugini Gas Ltd

In 2006, InterOil acquired 100% of the issued share capital of PNG LNG, Inc. and Liquid Niugini Gas Ltd for a total cost of $1,001. The purchase price reflected the book value of the shares at the time of acquisition as both were dormant shelf companies at the time of acquisition. These companies comprise the Midstream — liquefaction segment reported in these financials. In July 2007, InterOil Corporation transferred its investment in PNG LNG Inc. to InterOil LNG Holdings Inc. Refer to Note 2(c) for changes to InterOil’s shareholding in these entities due to the signing of the Shareholders’ Agreement on July 30, 2007.

Consolidated Financial Statements  INTEROIL CORPORATION      34

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

16. Acquisition of a subsidiary (cont’d)

IPL PNG Ltd.

On October 1, 2006, InterOil, through its wholly owned subsidiary, InterOil Products Limited acquired 100% of the outstanding common shares of Shell Papua New Guinea Limited which was subsequently renamed IPL PNG Ltd (“IPL PNG”). IPL PNG is a distributor of refined petroleum products in Papua New Guinea. The operations of IPL PNG was merged with InterOil Products Limited, and the entity registration cancelled in July 2008.

The results of IPL PNG’s operations have been included in the consolidated financial statements since October 1, 2006, the date on which control of IPL PNG’s shares was transferred to InterOil. The purchase price was $10,000,000 plus an amount equal to the net current assets of Shell based on the year ended 2005 accounts. However, if the net current assets at the transfer date exceeded the net current assets in the year end 2005 accounts by more than Kina 500,000, then InterOil would pay the amount of excess to the vendor.

As at December 31, 2006, InterOil had paid $30,639,000 in cash to Shell and a further balance was to be paid subject to a working capital adjustment. During the year ended December 31, 2007, InterOil paid $2,679,435 as final payment of the purchase price for the working capital adjustment. In addition to the amounts paid and accrued by IPL, $818,606 of acquisition related costs were incurred on the transaction.

The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition.

	$
Cash		4,989,895
Trade receivables		6,288,834
Inventory		20,429,728
Other assets		2,190,226
Future income tax benefit		1,698,224
Property, plant and equipment		10,355,322
Total assets acquired		45,952,229
Accounts payable and accrued liabilities		(11,815,188	)
Net assets acquired		34,137,041

The net cash paid on purchase of IPL PNG of $29,147,146 is comprised of $33,318,435 paid to Shell and $818,606 transaction costs incurred, less $4,989,895 held by IPL PNG at the time of acquisition.

17. 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.

During the year, $150,000 (2007 — $150,000, 2006 — $150,000) was expensed for the sponsor’s legal, accounting and reporting costs. These costs were included in accrued liabilities at December 31, 2008. InterOil is the majority shareholder of SPI and therefore has the power to appoint the general manager.

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 (2007 — $39,416, 2006 — $140,165). An amount of $9,562 was reimbursed by the Company in February 2008 for expenses associated with Mr. Grundy’s travel for board meetings.

Consolidated Financial Statements  INTEROIL CORPORATION      35

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

17. Related parties

Director fees

Amounts due to Directors at December 31, 2008 totaled $27,750 for Directors fees (2007 — $nil, 2006 - - $18,000) and $nil for Executive Director bonuses (2007 — $nil, 2006 — $nil,). These amounts are included in accounts payable and accrued liabilities. An amount of $120,000 (2007 — $130,000, 2006 - - $91,500) was paid to the Directors for Directors fees during the year. In addition to the above fees, each director is issued with 15,000 options each year for their services.

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 15) - Management does not consider this to be related party transaction as the Director does not have the ability to exercise, directly or indirectly, control, joint control or significant influence over BNP (Singapore).

18. Secured loan

	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Secured loan (OPIC) — current portion		9,000,000			9,000,000			13,500,000
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			136,776,760			13,500,000
Secured loan (OPIC) — non current portion		53,500,000			62,500,000			62,500,000
Secured loan (OPIC) — deferred financing costs		(1,134,667	)		(1,358,611	)		—
Secured loan (bridging facility) — non current portion		—			—			121,666,433
Total non current secured loan		52,365,333			61,141,389			184,166,433
Total secured loan		61,365,333			197,918,149			197,666,433

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. As part of the amendment, OPIC also waived the requirement to have cash deposits against the next two interest payments until December 31, 2008. The loan is secured over the assets of the refinery project which have a carrying value of $203,778,963 at December 31, 2008 (2007 — $214,219,029, 2006 — $228,704,267).

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 2008 the weighted average interest rate was 7.10% (2007 — 7.10%, 2006 — 7.01%) and the total interest expense included in long term borrowing costs was $5,147,768 (2007 — $5,339,500, 2006 — $5,512,975).

During the quarter ending December 31, 2008, an installment of $4,500,000 and the accrued interest on the loan was paid. As at December 31, 2008, two installment payments amounting to $4,500,000 each which will be due for payment on June 30, 2009 and December 31, 2009 have been reclassified 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. As of December 31, 2008, the company was in compliance with all applicable covenants.

Deferred financing costs relating to the OPIC loan of $1,134,667 (2007 — $1,358,611, 2006 - $1,582,555) are being amortized over the period until December 2014. Effective January 1, 2007 the deferred financing costs have been offset against the long term liability in compliance with CICA 3855 Financial Instruments and are being amortized using the effective interest method.

The accrued financing costs of $nil (2007 — $1,087,500, 2006 — $1,450,000) included discounting of the liability and costs in relation to the modification of the loan repayments. The total liability of $1,450,000 was due for payment in four quarterly installments of $362,500 commencing on December 31, 2007. The installments due for payment within twelve months were included within accounts payable and accrued liabilities. All four of these installments have been made as at December 31, 2008.

Consolidated Financial Statements  INTEROIL CORPORATION      36

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

18. Secured loan (cont’d)

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 23).

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 profit and loss account as income on the execution of the definitive LNG/NGL Project Agreement by InterOil and the lenders on July 31, 2007.

19. Indirect participation interests

Indirect participation interest (“IPI”)

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
Indirect participation interest (“IPI”)		72,476,668		96,086,369		96,861,259

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 has 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 the eight exploration wells, four of which will be in PPL 238, one in PPL 236, and one in PPL 237. 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. Should an investor choose not to participate in the completion works of an exploration well, the investor will forfeit their right 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, 2008.

The non-financial liability has been 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 and they elect to participate in the Petroleum Development License (‘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 & Geophysical (‘G&G’) 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 conveyance is triggered on election by the investors to participate in a PDL or when the investor forfeits the conversion option, conveyance accounting will be applied. This would entail 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 paragraphs 47(h) and 47(j) of SFAS 19.

Consolidated Financial Statements  INTEROIL CORPORATION      37

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

19. Indirect participation interests (cont’d)

Under the agreement, all or part of this indirect participation interest may be converted to a maximum of 3,333,334 common shares in the company between June 15, 2006 and the later of December 15, 2006, or until 90 days after the completion of the eighth well at a price of $37.50 per share. 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 agreements. 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. The balance of the indirect participation interest that may be converted into shares is a maximum of 2,160,000 common shares (Dec 2007 — 3,306,667, Dec 2006 - 3,333,334) due to the conversion of 476,667 shares and waiver of rights to 696,667 shares as explained below.

During 2007, one of the IPI investors exercised their right to convert their interest into 26,667 common shares. During the quarter ended September 30, 2008 two IPI investors also exercised their conversion rights into 450,000 InterOil common shares. The conversions during quarter ended September 30, 2008 reduced the IPI liability balance by $13,076,270 and the conversion option balance by $2,700,000 as compared to the balance at December 31, 2007.

During the year ended December 31, 2008, two of the investors’ with a combined 5.225% interest in the eight well drilling program waived their right to convert their IPI percentage into 696,667 common shares. These waivers have resulted in conveyance being triggered on this portion of the IPI agreement for the year ended December 31, 2008.

The Company has applied the guidance in paragraph 47(h) of SFAS 19 in relation to sale of these unproved properties and directly apportioned the proceeds to each of the 8 wells in the program. Based on the guidance, the proceeds attributed to each well have been assessed against the capitalized costs relating to each of these properties. Proceeds of $4,735,084 relating to wells that have no capitalized costs on the balance sheet, which have been expensed in previous years, have been recognized as a gain in the Statement of Operations. Proceeds of $5,798,347 have been allocated to the capitalized costs in relation to the conveyance of wells that do have capitalized costs on the balance sheet. The proceeds on conveyance for the portion relating to the remaining obligations under the IPI Agreement, is still being maintained as part of the IPI liability.

Indirect participation interest — PNGDV

	December 31,		December 31,		December 31,
	2008		2007		2006
	$		$		$
Current portion		540,002		1,080,004		730,534
Non current portion		844,490		844,490		1,190,633
Total indirect participation interest — PNGDV		1,384,492		1,924,494		1,921,167

As at December 31, 2008, 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 (2007 — $1,924,494, 2006 - $1,921,167). In 2006 an amendment was made to the original agreement whereby PNG Drilling Ventures Limited converted their remaining balance of $9,685,830 into 575,575 InterOil common shares and also retained a 6.75% interest in the next four exploration wells (the first of the four wells is 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).

The accounting for the amendment to the agreement resulted in the fair value of the shares issue of $7,948,691 being recognized as share capital. The Company has also recognized an initial liability relating to its obligation to drill the above four wells on behalf of the investors of $3,588,560. The difference between the opening balance and the amount allocated to share capital and the revised amount allocated to the liability of $1,851,421 has been expensed as a cost of amending the original transaction.

During the year ended December 31, 2008, $540,002 (Dec 2007 — a credit of $3,327, Dec 2006 — a debit of $1,667,396) of geological and geophysical costs and drilling costs in relation to the Elk-4A exploratory well have been allocated against the liability bringing the remaining balance to $1,384,492. 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      38

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

19. Indirect participation interests (cont’d)

Other

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, 2008 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.

20. 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, 2008, a subsidiary, SP InterOil LDC, holds 100% (Dec 2007 — 100%, Dec 2006 — 98.92%) of the non-voting participating shares issued from EP InterOil Ltd.

The non controlling interest as at December 31, 2008 relates to Petroleum Independent and Exploration Corporation’s (“PIE Corp.”) 0.02% 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.

21. 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, 2006		29,163,320		223,934,500
Shares issued on exercise of options		132,285		2,006,175
Shares issued on conversion of indirect participation interest		575,575		7,948,691
December 31, 2006		29,871,180		233,889,366
Shares issued on exercise of options		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		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

On May 6, 2008, $60,000,000 of the $130,000,000 Bridging facility was converted into common shares at a price of $22.65 per share resulting in the issue of 2,649,007 shares. In addition to the issue of these shares, there was also a 3% fee payable in additional shares resulting in an additional 79,470 shares being issued.

Consolidated Financial Statements  INTEROIL CORPORATION      39

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

21. Share capital

On May 13, 2008, the Company completed the issue of $95,000,000 unsecured 8% subordinated convertible debentures with a maturity of five years. As part of the debenture agreement, the investors were to be given a placement fee of 6% which could be settled in shares or cash. During the year ended December 31, 2008, the Company issued 228,000 shares amounting to $5,700,000 to settle this liability. During the year, 641,000 debentures have been converted into common shares of the Company. In addition to the issue of these shares, the interest payable on the debentures for the period up to November 9, 2008 were paid in shares and cash resulting in an additional 259,105 shares being issued.

During the year ended 31 December, 2008, 517,777 preference shares were converted into common shares. In addition to the issue of these shares, the interest payable on the preference shares for the first and second quarter of 2008 were paid in shares resulting in an additional 14,977 shares being issued.

On August 15, 2008, two IPI investors converted their interest into 450,000 common shares.

The numbers in the table above are net of transaction costs.

22. 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 on March 31, June 30, September 30 and December 31 of each year, commencing on December 31, 2007. The holder can convert into common shares at any time.

Based on guidance under CICA 3863, the preference shares were assessed based on the rights attached to those shares in determining whether it exhibited the fundamental characteristic of a financial liability or equity. Management has assessed that although the preference shares issued exhibit some characteristics of an equity instrument, the fixed interest right is in the nature of a liability. Management had applied residual basis and has valued the liability component first and assigned the residual value to the equity component. Management has fair valued the liability component by discounting the expected interest payments using a nominal rate of 8.9% being Management’s estimate of the expected interest payments for a similar instrument without the conversion feature. The liability component was valued at $7,797,312 and the remaining balance of $7,202,688 was allocated to the equity component before offsetting transaction costs. The transaction costs relating to the preference share issue amounting to $750,000 has been split based on the percentages allocated to the liability and equity components; the costs relating to the liability component has been expensed, and costs relating to the equity component have been allocated against the equity component recognized.

The preference dividend payment of 5% per annum is treated as an interest expense and is expensed in the Statement of Operations for the year. The preference dividend paid for the year ended December 31, 2008 was $418,526 (2007 — $84,247). During the quarter ended September 30, 2008 all preference shares issued (517,777 shares) were converted into common shares.

23. 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 have the right to convert their debentures into common shares at any time at a conversion price of $25.00 per share. The Company has 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 is 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 should be assessed based on the substance of the contractual arrangement in determining whether it exhibits the fundamental characteristic of a financial liability or equity. Management has assessed that the debenture instrument mainly exhibits characteristics that are liability in nature; however, the embedded conversion feature is equity in nature and needs to be bifurcated and disclosed separately within equity. Management has applied residual basis and has valued the liability component first and assigned the residual value to the equity component.

Management has 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.

Consolidated Financial Statements  INTEROIL CORPORATION      40

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

23. 8% subordinated debentures (cont’d)

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 period since issue up to December 31, 2008 was $1,915,910. In addition to the accretion, interest at 8% per annum has been expensed for the period since issue up to December 31, 2008 amounting to $4,361,889. The interest payable up to November 9, 2008 was paid in a combination of cash and shares. The interest accrued at December 31, 2008 is $897,611.

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. As at December 31, 2008, of the 3,800,000 convertible debentures issued, 3,159,000 (December 2007 — nil), were outstanding.

24. Stock compensation

Options are issued at no less than market price to directors, certain employees and to a limited number of contractor personnel. Options are exercisable on a 1:1 basis. Options vest at various dates in accordance with the applicable option agreement, 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 be exercised within 90 days or before expiry of the options if this occurs earlier.

	December 31, 2008						December 31, 2007						December 31, 2006
				Weighted						Weighted						Weighted
	Number of			average			Number of			average			Number of			average
Stock options outstanding	options			exercise price $			options			exercise price $			options			exercise price $
Outstanding at beginning of period		1,200,500			23.70			1,013,500			20.59			746,800			22.23
Granted		952,500			18.48			354,750			33.51			725,500			15.87
Exercised		(58,000	)		(16.50	)		(22,000	)		(14.37	)		(132,285	)		(11.14	)
Forfeited		(11,500	)		(28.68	)		(143,250	)		(25.94	)		(285,433	)		(18.01	)
Expired		(244,000	)		(25.80	)		(2,500	)		(27.00	)		(41,082	)		(15.36	)
Outstanding at end of period		1,839,500			21.03			1,200,500			23.70			1,013,500			20.59

At December 31, 2008, in addition to the options outstanding as per the above table, there were an additional 309,500 (2007 — 1,137,250, 2006 — 2,570,500) common shares reserved for issuance under the Company’s stock option plans. The decrease in the shares reserved from 2007 is mainly due to the cancellation of certain shares reserved under the 2002 plan after the new stock option plan was issued in 2006.

		Options issued and outstanding					Options exercisable
Range of exercise			Weighted average		Weighted average				Weighted average
prices $	Number of options		exercise price $		remaining term (years)		Number of options		exercise price $
8.01 to 12.00		545,000		9.81		4.90		40,000		9.92
12.01 to 24.00		645,000		17.71		2.45		452,000		17.45
24.01 to 31.00		245,500		29.10		2.63		93,000		29.40
31.01 to 41.00		314,000		34.67		6.57		90,000		33.82
41.01 to 51.00		90,000		43.22		1.90		90,000		43.22
		1,839,500		21.03		3.93		765,000		23.47

Consolidated Financial Statements  INTEROIL CORPORATION      41

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

24. Stock compensation (cont’d)

Aggregate intrinsic value of the 1,839,500 options issued and outstanding as at December 31, 2008 is $22,465,826. Aggregate intrinsic value of 765,000 options exercisable as at December 31, 2008 is $10,147,743.

The weighted-average grant-date fair value of options granted during the years 2008, 2007, and 2006 was $9.07, $19.34 and $8.89 respectively. The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006, was $456,867, $102,840 and $532,232 respectively. Cash received from option exercise under all share-based payment arrangements for the years ended December 31, 2008, 2007, and 2006, was $956,720, $316,100 and $1,473,942 respectively.

The fair value of the 952,500 (2007 — 354,750, 2006 — 725,500) options granted subsequent to January 1, 2008 has been estimated at the date of grant in the amount of $11,077,126 (2007 - $6,859,131, 2006 — $6,447,315) using a Black-Scholes pricing model. An amount of $5,741,086 (2007 - - $6,062,962, 2006 — $1,976,072) has been recognized as compensation expense for the year ended December 31, 2008. The current year compensation expense of $5,741,086 (2007 — $6,062,962, 2006 - $1,976,072) was adjusted against contributed surplus under equity, out of which $456,867 (2007 - $102,840, 2006 — $532,230) was transferred to share capital on exercise of options, leaving a net impact of $5,284,219 (2007 — $5,960,122, 2006 — $1,443,840) on contributed surplus.

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

							Weighted average
		Risk free interest rate					expected life for
Year	Period	(%)		Dividend yield	Volatility (%)		options
2008	Oct 1 to Dec 31		1.5	—		83		4.3
2008	April 1 to Sep 30		2.7	—		80		5.0
2008	January 1 to March 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
2006	October 1 to December 31		4.6	—		65		5.0
2006	July 1 to September 30		5.1	—		68		4.2
2006	January 1 to June 30		4.4	—		60		4.8

25. 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 337,252 (2007 — 337,252, 2006 — 340,247) were outstanding at December 31, 2008. The warrants are exercisable between August 27, 2004 and August 27, 2009. The warrants are 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.

26. Earnings/(Loss) per share

Preferred stock, warrants, conversion options and stock options totaling 7,500,752 common shares at prices ranging from $9.80 to $43.22 were outstanding as at December 31, 2008 but were not included in the computation of the diluted earnings per share because they caused the loss per share to be anti-dilutive.

	Number of shares		Number of shares		Number of shares
Potential dilutive instruments outstanding	December 31, 2008		December 31, 2007		December 31, 2006
Preferred stock		—		517,777		—
Employee stock options		1,839,500		1,200,500		1,013,500
IPI Indirect Participation interest - conversion options		2,160,000		3,306,667		3,333,334
8% Convertible debentures		3,159,000		—		—
Warrants		337,252		337,252		340,247
Others		5,000		5,000		5,000
Total stock options/shares outstanding		7,500,752		5,367,196		4,692,081

Consolidated Financial Statements  INTEROIL CORPORATION      42

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

27. Commitments and contingencies

Commitments

Payments due by period contractual obligations are as follows:

			Less than 1										More than
	Total		year		1-2 years		2-3 years		3-4 years		4-5 years		5 years
		’000		’000		’000		’000		’000		’000		’000
Secured loan and debenture obligations		141,475		9,000		9,000		9,000		9,000		87,975		17,500
Accrued financing costs		—		—		—		—		—		—		—
Indirect participation interest - PNGDV (note 19)		1,384		540		844		—		—		—		—
PNG LNG Inc. Joint Venture (proportionate share of commitments)		904		884		20		—		—		—		—
Petroleum prospecting and retention licenses (a)		95,000		16,500		4,500		23,333		35,333		15,334		—
		238,763		26,924		14,364		32,333		44,333		103,309		17,500

(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 commitment, as at December 31, 2008, management estimates that $43,926,310 would satisfy the commitments in relation to the IPI investors .

Contingencies:

a) The Company, certain of its subsidiaries, the Company’s Chief Executive Officer, Phil Mulacek, and his controlled entities Petroleum Independent & Exploration Corporation and P.I.E. Group, LLC are defendants in Todd Peters, et. al. v. Phil Mulacek et. al.; Cause No. 05-040035920-CV; in the 284th District Court of Montgomery County, Texas. The plaintiffs claim to be members of a partnership that bought a modular oil refinery and subsequently, through a series of transactions, sold it to a subsidiary of the Company. Plaintiffs contend that the defendants, including the Company, breached their fiduciary duties to the plaintiffs as part of these transactions and also assert claims for knowing participation in a breach of a fiduciary duty, common law fraud, fraudulent inducement, statutory fraud, securities fraud, breach of contract, investor oppression and conspiracy. Plaintiffs are seeking actual damages of up to $118,068,759 and unspecified punitive damages, attorneys’ fees, expenses and court costs, an accounting and access to books and records. The Company and other defendants are vigorously contesting the matter. Management does not believe the litigation will have a material adverse effect on the Company or its subsidiaries.

b) During 2008, certain disputes and litigation arose between us and Merrill Lynch, Pierce, Fenner and Smith Inc. and Merrill Lynch and Co (“Merrill Lynch”) 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.

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.

Consolidated Financial Statements  INTEROIL CORPORATION     43

InterOil Corporation

Notes to Consolidated Financial Statements

(Expressed in United States dollars)

27. Commitments and contingencies (cont’d)

Regulatory Actions

During the second half of the 2008 year, the Ontario Securities Commission (the “Commission”) directed that the Company undertake a review of its option granting practices from January 1, 2001 and provide the Commission with certain specific information and documentation.

A Special Committee of InterOil, comprised solely of independent directors, recently completed the internal review of InterOil’s historical option granting practices. The Special Committee concluded its review and found irregularities with respect to the administration of certain historical stock options grants, with the majority of these irregularities occurring prior to 2002 and well prior to the retention of those currently responsible for administration of stock options at InterOil. The Special Committee determined that these irregularities were not the result of any internal misconduct, but due to the failure to maintain adequate internal and accounting controls and some lack of understanding by those involved at the time. The Special Committee concluded that the total value of such errors is small and, relative to the InterOil’s current operations, not material. No restatement of the Company’s financial statements is required as a result of these determinations.

Based on the results of its investigation, the Special Committee provided a report to the Board of Directors and recommended to the Board of Directors that it adopt a number of remedial actions, which the Board, by vote, promptly accepted. Such remedial actions include: re-pricing the small number of existing options held by current employees, contractors, officers or directors where the options were granted below market price or prior to the commencement of employment; requesting that the current officer who has exercised options granted below market price refund InterOil the difference between the exercise price of such options and the proper market price as provided for under the relevant stock incentive plan; requiring the Compensation Committee provide written confirmation to the Board of Directors in respect of all future grants of options that such options were granted in accordance with the applicable stock incentive plan rules; adopting further specific, written procedures for the administrative tasks surrounding the granting of options; and adopting a specific option granting procedure for grants to new hires. These remedial actions have been or are being implemented by management. A report of the results of the review and containing the information and documentation requested was provided to the Commission at the end of February 2009. The Commission is currently reviewing the report.

Import Parity Price (‘IPP’) formula

The Company has also been negotiating with the Papua New Guinea government to revise the Import Parity Price (‘IPP’) formula which governs refined product sales in Papua New Guinea. Since the period beginning November 30, 2007, an interim arrangement has been in place with the PNG Government to apply a revised IPP formula for all sales from that date. This interim formula was adjusted in June 2008 based on ongoing discussions with the government with a view to finalizing a permanent replacement to the IPP formula as is required under our agreement

28. Subsequent events

Commodity derivative contracts

As at December 31, 2008, InterOil had $18.0 million of unrealized hedging gains carried forward in the balance sheet for unsettled hedge accounted transactions as at year end. Subsequent to year end, these unrealized hedges were terminated and the mark-to-market gains were realized. However, these gains will be released into the Statement of Operations as the anticipated transactions that these hedges were initially taken to cover will occur.

Merrill Lynch’s PNG LNG Inc interest buyback

Subsequent to year ended December 31, 2008, 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 652,931 common shares for its share of $11.25 million in relation to the settlement. The final number of shares is subject to a post closing balancing payment.

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

The audited consolidated financial statements of the Company for the year ended December 31, 2008, 2007, and 2006 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     44

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

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

Consolidated Balance Sheets	As at
		December 31, 2008						December 31, 2007						December 31, 2006
		$						$						$
		Canadian GAAP			US GAAP			Canadian GAAP			US GAAP			Canadian GAAP			US GAAP
Assets
Current assets:
Cash and cash equivalents (5)			48,970,572			44,051,224			43,861,762			40,152,026			31,681,435			31,681,435
Cash restricted (5)			25,994,258			25,933,184			22,002,302			21,916,736			29,301,940			29,301,940
Trade receivables			42,887,823			42,887,823			63,145,444			63,145,444			67,542,902			67,542,902
Commodity derivative contracts			31,335,050			31,335,050			—			—			1,759,575			1,759,575
Other assets (5)			167,885			125,119			146,992			120,460			2,954,946			2,954,946
Inventories			83,037,326			83,037,326			82,589,242			82,589,242			67,593,558			67,593,558
Prepaid expenses (5)			4,489,574			(50,145,093	)		5,102,540			5,076,006			880,640			880,640
Total current assets			236,882,488			177,224,633			216,848,282			212,999,914			201,714,996			201,714,996
Cash restricted			290,782			290,782			382,058			382,058			3,217,284			3,217,284
Deferred financing costs (4), (6)			—			1,279,145			—			1,395,066			1,716,757			1,716,757
Investment in LNG Project (5)			—			6,610,480			—			5,848,612			—			—
Plant and equipment (1), (5)			223,585,559			210,803,013			232,852,222			219,117,006			242,642,077			231,175,281
Oil and gas properties (2)			128,013,959			127,653,411			84,865,127			84,865,127			54,524,347			54,524,347
Future income tax benefit			3,070,182			3,070,182			2,867,312			2,867,312			1,424,014			1,424,014
Total assets			591,842,970			526,931,646			537,815,001			527,475,095			505,239,475			493,772,679
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities (6), (5)			78,147,736			77,460,413			60,427,607			59,682,621			76,095,369			76,095,369
Commodity derivative contracts			—			—			1,960,300			1,960,289			—			—
Working capital facility			68,792,402			68,792,402			66,501,372			66,501,372			36,873,508			36,873,508
Deferred hedge gain (2)			—			—			—			—			1,385			—
Deferred liquefaction project liability			—			—			—			—			6,553,080			6,553,080
Current portion of secured loan			9,000,000			9,000,000			136,776,760			136,810,093			13,500,000			13,500,000
Current portion of indirect participation interest — PNGDV			540,002			540,002			1,080,004			1,080,004			730,534			730,534
Total current liabilities			156,480,140			155,792,817			266,746,043			266,034,379			133,753,876			133,752,491
Accrued financing costs			—			—			—			—			1,087,500			1,087,500
Secured loan (6)			52,365,333			(1,134,667	)		61,141,389			62,500,000			184,166,433			184,166,433
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)			17,497,110			—			9,096,537			—			—			—
Indirect participation interest (2)			72,476,668			88,211,120			96,086,369			115,926,369			96,861,259			116,861,259
Indirect participation interest — PNGDV			844,490			844,490			844,490			844,490			1,190,633			1,190,633
Total liabilities			364,703,808			313,423,942			441,712,140			445,305,238			417,059,701			437,058,316
Non-controlling interest (8)			5,235			5,427			4,292			4,388			5,759,206			5,416,831
Preference shares (3)			—			—			—			14,250,000			—			—
Shareholders’ equity:
Share capital			373,904,356			373,514,356			259,324,133			259,324,133			233,889,366			233,889,366
Preference shares (3)			—			—			6,842,688			—			—			—
8% subordinated debentures (4)			10,837,394			—			—			—			—			—
Contributed surplus (4)			15,621,767			24,422,662			10,337,548			10,337,548			4,377,426			4,377,426
Warrants			2,119,034			2,119,034			2,119,034			2,119,034			2,137,852			2,137,852
Accumulated Other Comprehensive Income			27,698,306			27,698,306			6,025,019			6,025,019			1,492,869			1,494,258
Conversion options (2)			17,140,000			—			19,840,000			—			20,000,000			—
Accumulated deficit			(220,186,930	)		(214,252,081	)		(208,389,853	)		(209,890,265	)		(179,476,945	)		(190,601,370	)
Total shareholders’ equity			227,133,927			213,502,277			96,098,569			67,915,469			82,420,568			51,297,532
Total liabilities and shareholders’ equity			591,842,970			526,931,646			537,815,001			527,475,095			505,239,475			493,772,679

Consolidated Financial Statements   INTEROIL CORPORATION      45

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

29. 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, 2008						December 31, 2007						December 31, 2006
	$						$ (restated) (*)						$
	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Revenue
Sales and operating revenues		915,578,709			915,578,709			625,526,068			625,526,068			511,087,934			511,189,438
Interest income		931,785			—			2,180,285			—			3,223,995			—
Other income		3,216,445			—			2,666,890			—			3,747,603			—
		919,726,939			915,578,709			630,373,243			625,526,068			518,059,532			511,189,438
Expenses
Cost of sales and operating expenses (excluding depreciation shown below)		888,623,109			888,623,109			573,609,441			573,609,441			499,494,540			499,584,532
Administrative and general expenses (5)		31,227,627			28,354,064			31,998,655			30,881,433			23,288,330			23,322,286
Derivative (gain)/loss		(24,038,550	)		(24,038,550	)		7,271,693			7,271,693			(2,559,712	)		(2,559,712	)
Legal and professional fees (5)		11,523,045			7,692,045			6,532,646			4,471,684			3,937,517			3,937,517
Exploration costs, excluding exploration impairment		995,532			995,532			13,305,437			13,305,437			6,176,866			6,176,866
Exploration impairment		107,788			107,788			1,242,606			1,242,606			1,647,185			1,647,185
Short term borrowing costs		6,514,060			6,514,060			13,212,112			13,212,112			8,478,540			8,478,540
Long term borrowing costs (3), (4)		17,459,186			19,529,798			9,536,162			9,061,915			11,856,872			11,856,872
Depreciation and amortization (1), (5)		14,142,546			13,594,481			13,024,258			12,529,892			12,352,672			11,591,513
Loss on amendment of indirect participation interest — PNGDV		—			—			—			—			1,851,421			1,851,421
Gain on LNG shareholder agreement		—			—			(6,553,080	)		(6,553,080	)		—			—
Gain on equity accounted investment (5)		—			(1,047,795	)		—			(5,561,684	)		—			—
Gain on sale of oil and gas properties (2)		(11,235,084	)		(12,280,084	)		—			—			—			—
Foreign exchange loss/(gain) (5)		(3,878,150	)		(4,437,943	)		(5,078,338	)		(5,099,651	)		(4,744,810	)		(4,744,810	)
Non-controlling interest (8)		943			1,040			(22,333	)		(22,236	)		(263,959	)		(265,865	)
Interest income (5)		—			(841,028	)		—			(2,146,183	)		—			(3,223,995	)
Other income		—			(3,216,445	)		—			(2,666,890	)		—			(3,747,603	)
		931,442,052			919,550,072			658,079,259			643,536,489			561,515,462			553,904,747
Loss before income taxes		(11,715,113	)		(3,971,363	)		(27,706,016	)		(18,010,421	)		(43,455,930	)		(42,715,309	)
Income tax expense (5), (7)		(81,964	)		28,073			(1,206,892	)		(1,194,227	)		(2,342,873	)		(2,342,873	)
Net loss		(11,797,077	)		(3,943,290	)		(28,912,908	)		(19,204,648	)		(45,798,803	)		(45,058,182	)

(*) Comparative results for the year ended December 31, 2007 have been adjusted to rectify for misclassification of the following items in the U.S. GAAP Consolidated statement of operations as per the December 31, 2007 consolidated financial statements:

December 31, 2007 (as per U.S. GAAP reconciliation)	Original		Revised		Adjustments
Expenses
Legal and professional fees		6,038,280		4,471,684		1,566,596
Short term borrowing costs		11,151,150		13,212,112		(2,060,962	)
Long term borrowing costs		9,536,162		9,061,915		474,247
Depreciation and amortization		12,550,011		12,529,892		20,119
Net impact to the U.S. GAAP Statement of Operations						—

Consolidated Financial Statements    INTEROIL CORPORATION     46

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

29. 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,
	2008			2007			2006
	$			$			$
Net loss as shown in the Canadian GAAP financial statements		(11,797,077	)		(28,912,908	)		(45,798,803	)
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)		478,923			478,935			761,159
Decrease in non-controlling interest expense (8)		(96	)		(96	)		1,907
Increase in reporting income due to reversal of proportionate consolidation of LNG Project and equity accounting the investment (5)		8,400,571			9,097,535			—
Increase in sales from ineffective portion of hedges		—			—			101,504
Decrease in long term borrowing costs relating to financing costs on preference shares expensed		—			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)		1,045,000			—			—
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)		(2,780,274	)		—			—
Reduced gain on sale of minority interest under U.S. GAAP		—			(342,361	)		—
Increase in cost of sales from ineffective portion of hedges		—			—			(89,993	)
Increase in administrative and general expenses from ineffective portion of hedges		—			—			(33,956	)
Net loss according to US GAAP		(3,943,290	)		(19,204,648	)		(45,058,182	)

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

	Year ended
	December 31,			December 31,			December 31,
	2008			2007			2006
	$			$			$
Net loss in accordance with U.S. GAAP, net of tax		(3,943,290	)		(19,204,648	)		(45,058,182	)
Foreign currency translation reserve, net of tax		3,660,787			4,532,150			1,015,426
Deferred hedge gain, net of tax		18,012,500			(1,389	)		(993,153	)
Total other comprehensive income, net of tax		21,673,287			4,530,761			22,273
Comprehensive income/(loss), net of tax		17,729,997			(14,673,887	)		(45,035,909	)

Consolidated Financial Statements    INTEROIL CORPORATION      47

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

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

Consolidated Statements of Shareholders’ Equity

	Year ended
	December 31, 2008						December 31, 2007						December 31, 2006
	$						$						$
	Canadian GAAP			US GAAP			Canadian GAAP			US GAAP			Canadian GAAP			US GAAP
Share capital
At beginning of period		259,324,133			259,324,133			233,889,366			233,889,366			223,934,500			223,934,500
Issue of capital stock		114,580,223			114,190,223			25,434,767			25,434,767			9,954,866			9,954,866
At end of period		373,904,356			373,514,356			259,324,133			259,324,133			233,889,366			233,889,366
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		—			—			—			—			—			—
Issue of debentures		13,036,434			—			—			—			—			—
Conversion to common shares		(2,199,040	)		—			—			—			—			—
At end of period		10,837,394			—			—			—			—			—
Contributed surplus
At beginning of period		10,337,548			10,337,548			4,377,426			4,377,426			2,933,586			2,933,586
Options exercised transferred to share capital		(456,867	)		(456,867	)		(102,840	)		(102,840	)		(532,232	)		(532,232	)
Stock compensation expense		5,741,086			5,741,086			6,062,962			6,062,962			1,976,072			1,976,072
8% Debenture issue BCF (note 4)		—			8,800,895			—			—			—			—
At end of period		15,621,767			24,422,662			10,337,548			10,337,548			4,377,426			4,377,426
Warrants
At beginning of period		2,119,034			2,119,034			2,137,852			2,137,852			2,137,852			2,137,852
Movement for period		—			—			(18,818	)		(18,818	)		—			—
At end of period		2,119,034			2,119,034			2,119,034			2,119,034			2,137,852			2,137,852
Accumulated Other Comprehensive Income
At beginning of period		6,025,019			6,025,019			1,492,869			1,494,258			477,443			1,471,985
Deferred hedge gain recognised on transition		—			—			1,385			—			—			—
Deferred hedge (loss)/gain movement for period, net of tax		18,012,500			18,012,500			(1,385	)		(1,389	)		—			(993,153	)
Foreign currency translation adjustment movement for period, net of tax		3,660,787			3,660,787			4,532,150			4,532,150			1,015,426			1,015,426
At end of period		27,698,306			27,698,306			6,025,019			6,025,019			1,492,869			1,494,258
Conversion options
At beginning of period		19,840,000			—			20,000,000			—			20,000,000			—
Movement for period		(2,700,000	)		—			(160,000	)		—			—			—
At end of period		17,140,000			—			19,840,000			—			20,000,000			—
Accumulated deficit
At beginning of period		(208,389,853	)		(209,890,265	)		(179,476,945	)		(190,601,370	)		(133,678,142	)		(145,543,188	)
Net loss for period		(11,797,077	)		(3,943,290	)		(28,912,908	)		(19,204,648	)		(45,798,803	)		(45,058,182	)
Deduct:
Preference Share Dividends		—			(418,526	)		—			(84,247	)		—			—
At end of period		(220,186,930	)		(214,252,081	)		(208,389,853	)		(209,890,265	)		(179,476,945	)		(190,601,370	)
Shareholders’ equity at end of period		227,133,927			213,502,277			96,098,569			67,915,469			82,420,568			51,297,532

Consolidated Financial Statements  INTEROIL CORPORATION     48

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

29. 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, 2008			December 31, 2007			December 31, 2006
	$			$ (restated) (*)			$
Cash flows provided by (used in):
Operating activities — Canadian GAAP (as per consolidated cash flows)		15,586,156			(31,619,907	)		2,187,462
Reconciling items:
Reclass exploration costs expensed including exploration impairment as investing activity for US GAAP		(1,103,320	)		(14,548,043	)		(7,824,051	)
Being LNG project related operating cash flows reversed for US GAAP cash flow statement		8,666,724			2,892,220			—
Operating activities — U.S. GAAP		23,149,560			(43,275,730	)		(5,636,589	)
Investing activities — Canadian GAAP (as per consolidated cash flows)		(47,390,685	)		(34,369,871	)		(97,071,319	)
Reconciling items:
Reclass exploration costs expensed including exploration impairment as investing activity for US GAAP		1,103,320			14,548,043			7,824,051
Being reversal of LNG Project expenditure for US GAAP cash flows		(404,594	)		2,762,786			—
Being reversal of movement in restricted cash held relating to LNG Project for US GAAP cash flows		(24,492	)		85,566			—
Investing activities — U.S. GAAP		(46,716,451	)		(16,973,476	)		(89,247,268	)
Financing activities — Canadian GAAP (as per consolidated cash flows)		36,913,339			78,170,105			66,963,485
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		27,466,089			68,719,797			66,963,485
(Decrease)/increase in cash and cash equivalents		3,899,198			8,470,591			(27,920,372	)
Cash and cash equivalents, beginning of period (U.S.GAAP)		40,152,026			31,681,435			59,601,807
Cash and cash equivalents, end of period (U.S. GAAP)		44,051,224			40,152,026			31,681,435

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     49

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

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

(*) Comparative results for the year ended December 31, 2007 have been adjusted to correctly reflect the reconciling items related to the LNG Project. For details of adjustments made to the Reconciliation of Canadian GAAP Statement of cash flows to U.S. GAAP as per the December 31, 2007 consolidated financial statements, refer to the following table:

	Operating activities			Investing activities			Financing activities			Total
	$			$			$			$
Cash flows provided by/(used in) — (as per original U.S. GAAP reconciliation)		(57,062,320	)		(12,637,194	)		78,170,105			8,470,591
Adjustments:
Transfer of reversal of PNG LNG cash call proportionately consolidated in cash flow statement reconciling item from Investing activities to Financing activities (at amount originally disclosed in reconciliation)		—			(65,072	)		65,072			—
Adjust reversal of PNG LNG cash call proportionately consolidated in cash flow statement reconciling item to correct amount		9,515,380			—			(9,515,380	)		—
Add reversal of movement in non-cash working capital relating to LNG Project (increase in accounts payable and accrued liabilities)		7,119,562			(7,119,562	)		—			—
Add reconciling item for reversal of expenditure on plant and equipment relating to LNG Project		(2,762,786	)		2,762,786			—			—
Add reconciling item for reversal of movement in restricted cash held relating to LNG Project		(85,566	)		85,566			—			—
Cash flows provided by/(used in) — (as per adjusted U.S. GAAP reconciliation)		(43,275,730	)		(16,973,476	)		68,719,797			8,470,591

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 31, 2008, 2007 and 2006.

	Year ended December 31,
	2008			2007			2006
Weighted average number of shares on which earnings per share calculations are based in accordance with U.S. GAAP
Basic		33,632,390			29,998,133			29,602,360
Effect of dilutive options		—			—			—
Diluted		33,632,390			29,998,133			29,602,360
Net income/(loss) per share in accordance with U.S. GAAP
Basic		(0.12	)		(0.64	)		(1.52	)
Diluted		(0.12	)		(0.64	)		(1.52	)

Consolidated Financial Statements  INTEROIL CORPORATION     50

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

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

(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 19 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 between liability and equity 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 19, during the year ended December 31, 2008, two of the investors’ with a combined 5.225% interest in the eight well drilling program waived their right to convert their IPI percentage into 696,667 common shares. These waivers have resulted in conveyance being triggered on this portion of the IPI agreement for the year ended December 31, 2008. As the initial IPI proceeds were not bifurcated under U.S. GAAP, the total conveyance proceeds available for the conveyed interest is $11,938,979 (higher by $1,405,548 from the CGAAP balance), the amounts offset against oil and gas properties is $6,158,895 (higher by $360,548 from CGAAP balance), and the gain recognised in the statement of operations is $5,780,084 (higher by $1,045,000 from CGAAP balance).
(3)	Preference shares
	As disclosed in Note 22 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 ASR 268. 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 for the twelve month period amounting to $418,526 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 23 in the 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.

Consolidated Financial Statements  INTEROIL CORPORATION     51

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

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

	Under U.S. GAAP, Management assessed the debentures following the guidance under FAS 133 to decide 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 FAS 133 Para 11(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 FAS 133 bifurcation is not applicable, the provisions of EITF 00-27 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 in EITF 98-5. Based on the guidance, the BCF has been valued at $8,821,320 which will be separate and classified separately under equity as Contributed Surplus. After separation, the liability component would be accreted over the life of the debentures, being 5 years until May 2013. If the conversion occurs prior to the stated redemption date, the entire unamortized value related to the converted portion would be immediately recognized in the Statement of operations as an ordinary interest expense.
	The accretion expense of the liability component for the period ending December 31, 2008 was $1,569,709 (accretion expense under US GAAP is less due to the higher liability component of the instrument).
	In addition to the above, deferred financing 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. As at December 31, 2008, there was $144,478 of deferred finance costs which were not amortized in relation to the 8% convertible debentures.
	During the year ended December 31, 2008, debenture holders exercised their conversion rights for $16,025,000 resulting in issue of 641,000 common shares of the Company. As at December 31, 2008, of the 3,800,000 convertible debentures issued, 3,159,000 (December 2007 — nil), were outstanding.
	Under U.S. GAAP, a portion of the placement fees and BCF accretion are expensed immediately on conversion. The additional financing expense recognized under U.S. GAAP due to the conversion of the debentures during the year ended December 31, 2008 was $2,780,274.
(5)	Investment in LNG Project/Deferred gain on contributions to LNG Project
	As disclosed in Note 14 in the 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.
	Applying the guidance under APB 18, a corporate joint venture has to be equity accounted under U.S. GAAP. InterOil has also followed the guidance under SAB Topic 5H 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.
	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, 2008. 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.

Consolidated Financial Statements  INTEROIL CORPORATION     52

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

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

Midstream - liquefaction				GAAP
Consolidated Balance Sheet	Canadian GAAP			Adjustments			US GAAP
Cash and cash equivalents		4,919,448			(4,919,348	)		100
Cash restricted		61,074			(61,074	)		—
Other assets		21,710			(21,710	)		—
Prepaid expenses		—			—			—
Current assets		5,002,232			(5,002,132	)		100
Investment in PNG LNG Inc.		—			6,610,480			6,610,480
Plant and equipment		2,273,619			(2,273,619	)		—
Total assets		7,275,851			(665,271	)		6,610,580
Accounts payable and accrued liabilities		687,327			(687,327	)		—
Intercompany payables		3,498,042			21,056			3,519,098
Current liabilities		4,185,369			(666,271	)		3,519,098
Deferred gain on contributions to LNG project		17,497,110			(17,497,110	)		—
Total non-current liabilities		17,497,110			(17,497,110	)		—
Share capital		1			—			1
Accumulated deficit		(14,406,629	)		17,498,110			3,091,481
Shareholders’ Equity		(14,406,628	)		17,498,110			3,091,482
Total liabilities and Shareholders’ equity		7,275,851			(665,271	)		6,610,580

Midstream - liquefaction				GAAP
Consolidated Statement of Operation	Canadian GAAP			Adjustments			US GAAP
Interest income		90,757			(90,757	)		—
Total revenues		90,757			(90,757	)		—
Office and Administrative expenses		3,213,034			(2,873,563	)		339,471
Depreciation		69,142			(69,142	)		—
Professional fees		3,809,329			(3,831,000	)		(21,671	)
Borrowing costs		240,782			—			240,782
Exchange (Gain) loss		559,793			(559,793	)		—
Loss on proportionate consolidation of PNG LNG Inc		—			—			—
Gain on equity accounted investment		—			(1,047,795	)		(1,047,795	)
Income taxes		110,037			(110,037	)		—
Total expenses		8,002,117			(8,491,330	)		(489,213	)
Net gain/(loss)		(7,911,360	)		8,400,573			489,213

(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 APB 21.
(7)	Income tax effect of adjustments
	The income tax effect of U.S. GAAP adjustments was a reduction to the future tax asset of $2,671,594 (year ended December 31, 2007 — $3,403,154) for the year ended December 31, 2008 due to a decrease in the loss carry-forwards. A corresponding decrease 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.

Consolidated Financial Statements  INTEROIL CORPORATION      53

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

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

Recent Accounting Pronouncements

Fair value measurements

In September 2006, the FASB issued FAS 157 which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. The standard is effective for fiscal years beginning after November 15, 2007 and all interim periods within those fiscal years. The Company has complied with the disclosure requirements under this standard for the year ended December 31, 2008.

Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, the FASB issued FAS 159 which permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement is expected to expand the use of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. This standard does not have any material impact on the financial statements of the Company.

Business combinations

In December 2007, the FASB issued FAS 141 (revised 2007) to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. 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. This will have no impact unless the Company undertakes a business combination subsequent to adoption of this standard.

Non-controlling interests in consolidated financial statements

In December 2007, the FASB issued FAS 160. 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 noncontrolling 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 noncontrolling 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 noncontrolling interest. Previously, net income attributable to the noncontrolling 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. This will have no impact unless the Company undertakes a business combination involving a non-controlling interest subsequent to adoption of this standard.

Disclosures about derivative instruments and hedging activities

In March 2008, the FASB issued FAS 161. 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 does not expect that the application of FAS 161 will have a material impact on the financial statements.

Consolidated Financial Statements   INTEROIL CORPORATION      54

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

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

Hierarchy of generally accepted accounting principles

In May 2008, the FASB issued FAS 162. This statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements by nongovernmental entities that are presented in accordance with the US GAAP. This statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. The SEC approved the amendments on September 16, 2008. The Company does not expect that the application of FAS 161 will have a material impact on the financial statements.

Accounting for financial guarantee insurance contracts

In May 2008, the FASB issued FAS 163 which clarifies how FAS 60 applies to financial guarantee insurance contracts, including the recognition and measurement to be used to account for premium revenue and claim liabilities. The statement requires recognition of a claim liability prior to an event of default when there is evidence that credit deterioration has occurred in an insured financial obligation. The statement also required expanded disclosures about financial guarantee insurance contracts. This statement is effective for years beginning after December 15, 2008 and interim periods within those years, except for certain disclosure requirements which are effective for the first period (including interim periods) beginning after May 23, 2008. The Company does not expect that the application of FAS 163 will have any impact on the financial statements.

Consolidated Financial Statements  INTEROIL CORPORATION     55

EX-99.3

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
OIL AND GAS DISCLOSURES	3
INTRODUCTION	4
INDUSTRY TRENDS AND KEY EVENTS	4
RISK FACTORS	6
BUSINESS STRATEGY	7
OPERATIONAL HIGHLIGHTS	7
SELECTED ANNUAL FINANCIAL INFORMATION AND HIGHLIGHTS	9
YEAR AND QUARTER IN REVIEW	13
LIQUIDITY AND CAPITAL RESOURCES	20
CRITICAL ACCOUNTING ESTIMATES	27
NEW ACCOUNTING STANDARDS	28
NON-GAAP MEASURES AND RECONCILIATION	30
PUBLIC SECURITIES FILINGS	31
DISCLOSURE CONTROLS AND PROCEDURES	32
GLOSSARY OF TERMS	32

The following Management Discussion and Analysis (MD&A) should be read in conjunction with our audited consolidated financial statements and accompanying notes for the year ended December 31, 2008 and annual information form for the year ended December 31, 2008. The MD&A was prepared by management and provides a review of our performance in the year ended December 31, 2008, and of our financial condition and future prospects.

Our financial statements and the financial information contained in this MD&A have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and are presented in United States dollars (‘USD’) unless otherwise specified. References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation and/or InterOil Corporation and its subsidiaries as the context requires. Information presented in this MD&A is as at and for the year ended December 31, 2008 unless otherwise specified.

We are not presenting all the U.S. GAAP information in this MD&A. Readers should review note 29 - ‘Reconciliation to the generally accepted accounting principles in the United States’ to the audited financial statements for the year ended December 31, 2008 for the reconciliation of the Canadian GAAP and U.S. GAAP information.

Management Discussion and Analysis  INTEROIL CORPORATION      1

FORWARD-LOOKING STATEMENTS

This MD&A 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 MD&A are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our plans for our exploration activities and other business segments and results therefrom, expanding our business segments, 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 impact the matters addressed in these forward-looking statements, including but not limited to:

• the inherent uncertainty of oil and gas exploration activities;

• potential effects of oil and gas price declines;

• the uncertain outcome of our negotiations with the Papua New Guinea government to determine the price at which our refined products may be sold;

• the availability of crude feedstock at economic rates;

• the ability to meet maturing indebtedness;

• the uncertainty in our ability to attract capital;

• general economic conditions and illiquidity in financial and credit markets

• interest rate risk;

• the impact of competition

• losses from our hedging activities;

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

• fluctuations in currency exchange rates;

• the recruitment and retention of qualified personnel;

• the availability and cost of drilling rigs, oilfield equipment, and other oilfield exploration services;

• our ability to finance the development of our LNG facility;

• our ability to timely construct and commission our LNG facility;

• the margins for our refined products;

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

• difficulties in marketing our refinery’s output;

• exposure to certain uninsured risks stemming from our refining operations;

• weather conditions and unforeseen operating hazards;

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

• compliance with and changes in foreign governmental laws and regulations, including environmental laws;

• landowner claims;

• the uncertainty in being successful in pending lawsuits and other proceedings;

• law enforcement difficulties;

• the impact of legislation regulating emissions of greenhouse gases on current and potential markets for our products;

• stock price volatility; and

• contractual defaults.

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, future oil and natural gas 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 impact of increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop production and reserves through development and exploration activities.

Management Discussion and Analysis  INTEROIL CORPORATION      2

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 included in this MD&A will prove to be accurate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should 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 our Annual Information Form for the year ended December 31, 2008 (“2008 Annual Information Form”) and in the “Risk Management” section below.

Furthermore, the forward-looking information contained in this MD&A is made as of the date hereof, unless otherwise specified and, except as required by applicable law, we have no obligation to 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.

OIL AND GAS DISCLOSURES

We are required to comply with Canadian National Instrument 51-101 standards for Disclosure of Oil and Gas Activities, which prescribes disclosure of oil and gas reserves and resources. During 2008, we retained GLJ Petroleum Consultants Ltd, a independent qualified reserve evaluator in Calgary, Canada, to evaluate our resources data as at December 31, 2008 in accordance with NI 51-101, which has been summarized in our 2008 Annual Information Form. We do not have any reserves, including proved reserves, as per the guidelines set by the SEC under SFAS 19, as at December 31, 2008.

The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company includes in this MD&A information that the SEC’s guidelines generally prohibit U.S registrants from including in filings with the SEC. Investors are urged to consider closely the disclosure in the Company’s Form 40-F, available from us at www.interoil.com or from the SEC at www.sec.gov.

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. Barrels of oil equivalent may be misleading, particularly if used in isolation. A barrel of oil equivalent 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.

Management Discussion and Analysis  INTEROIL CORPORATION      3

INTRODUCTION

We are developing a vertically integrated energy company in Papua New Guinea and the surrounding region. Our operations are organized into four major 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.
Midstream	Refining — Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export. Liquefaction — Developing an onshore liquefied natural gas processing facility in Papua New Guinea.
Downstream	Wholesale and Retail Distribution — Markets and distributes refined petroleum 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. Our corporate segment results also include consolidation adjustments.

INDUSTRY TRENDS AND KEY EVENTS

Competitive Environment and Regulated Pricing

We are 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 gas) 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 interim agreement 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 interim benchmark price for refined products in the region in which we operate. As revised, the IPP more closely mirrors changes in the prices of crude feedstocks than the previous formula. In addition, minor adjustments to this interim IPP formula were made in June 2008 based on ongoing discussions with the government with a view to finalizing a permanent replacement to the IPP formula.

We are a significant participant in the retail and wholesale distribution business in Papua New Guinea, which business was built from the acquisition of BP and Shell Papua New Guinea distribution assets. Our major competitor in the distribution segment is Mobil, who we believe controls approximately a quarter of the Papua New Guinea retail market. 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.

Management Discussion and Analysis  INTEROIL CORPORATION      4

Credit Crisis and Financing Arrangements

The U.S. and other world economies are currently in a recession which could last well into 2009 and beyond. The financial and credit markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. These market disruptions have resulted in a reduced capacity of the financial institutions to finance new projects and renew existing facilities with their clients. In May 2008, our $130.0 million bridging facility came due. The negotiations on the refinancing of this facility started towards the end of 2007. We were able to convert $60.0 million of this facility into common shares, and effect repayment of the remaining $70.0 million by the due date. This repayment was made from the proceeds of the $95.0 million of unsecured 8% subordinated convertible debentures due May 2013. See “Liquidity and Capital Resources — Summary of Debt Facilities”.

The part conversion of the bridging facility and the debenture placement helped us to reduce our Debt-To-Capital Ratio (Long term Debt/(Shareholders’ equity + Long term Debt)), to 36% in December 2008 from 67% in December 2007.

We have filed a short form base shelf prospectus with the Ontario Securities Commission and a corresponding registration statement on Form F-10 with the United States Securities and Exchange Commission (the “SEC”) pursuant to the multi-jurisdictional disclosure system. These filings will enable us to add financial flexibility in the future and issue, from time to time, up to an aggregate of $200.0 million of securities. These securities may be debt securities, common shares, preferred shares, warrants or a combination thereof. Although due to pricing we may not wish to issue securities in the current financial market, this shelf provides us the means to quickly access the debt and equity markets. Additionally, the global credit crisis may affect our ability to proceed with and close any such offering.

Our main working capital facility which is led by BNP Paribas and has a limit of $190.0 million, and is renewable annually. At the last renewal which was completed in October 2008, the facility limit was increased by $20.0 million, from $170.0 million in the prior year. The facility is fully secured against trade debtors, inventory and cash deposits. Our association with BNP Paribas began in 2004 with the working capital facility and has expanded over time to include certain other aspects of our business including managing our hedging trades. See “Liquidity and Capital Resources — Summary of Debt Facilities”.

As at December 31, 2008, we had cash, cash equivalents and cash restricted of $75.3 million, of which $26.3 million was restricted (as governed by BNP working capital facility utilization requirements). With regard to our cash and cash equivalents, we invest in bankers acceptances and money market instruments with major financial institutions that we believe are creditworthy. We also had $109.0 million of the BNP working capital facility available for use in our Midstream - Refining operations, and $42.1 million of the Westpac/BSP combined working capital facility available for use in our Downstream operations.

Crude Prices

Crude prices were highly volatile throughout 2008 with the price of Tapis crude oil (as quoted by the Asian Petroleum Price Index (APPI)) starting the year at $102/bbl, peaking at $147/bbl and then falling to $39/bbl by the end of the year. Tapis is the benchmark for setting crude prices within the region where we operate and is used by us when we purchase crude feedstock for our refinery. The price of Tapis during 2008 averaged $101/bbl per barrel compared to $77/bbl during 2007. The significant increase in crude prices during the year increased our working capital requirements, and as a result our BNP working capital facility was increased from $170.0 million to $210.0 million for a certain period of time during second half of 2008. As at December 31, 2008, $81.0 million was drawn down on this facility.

The high volatility of crude prices also meant that we faced significant timing and margin risk on our crude cargos during the year. A significant portion of this timing and margin risk was managed by us through short and long term hedges that were put in place during the year. We believe our hedge counterparties to be creditworthy. However, as we do not fully hedge, the volatility resulted in significantly reduced gross margins due to lower refined product prices and net realizable value write downs of our inventory. Despite the above volatility, 2008 was the first year that our refining operations achieved a net profit, with a profit of $4.7 million as compared with a net loss of $8.8 million in 2007.

Management Discussion and Analysis  INTEROIL CORPORATION      5

Refining Margin

The distillation process used by our refinery to convert crude feedstocks into refined products is commonly referred to as hydroskimming. While the Singapore Tapis hydroskimming margin is a useful indicator of the general margin available for hydroskimming refineries in the region in which we operate, it should be noted that the differences in our approach to crude selection, transportation costs and IPP pricing work to assist our refinery in generally outperforming the Singapore Tapis hydroskimming margin. Therefore, our refinery realizes additional margins due to its niche location when compared to the benchmark for the region.

Singapore Tapis hydroskimming margins increased in volatility during 2008, while average margins decreased slightly in comparison with the previous year.

Domestic Demand

Sales results for our refinery indicate that Papua New Guinea domestic demand for middle distillates from the refinery decreased by approximately 8% during 2008 compared with 2007. We believe that this decrease in demand is partially the result of higher prices caused by high crude prices during the year. In addition, certain volumes of such products were imported by third party distributors rather than being sourced from the refinery.

The refinery on average sold 10,900 bbls/day of refined petroleum products to the domestic market during fiscal year 2008 as compared to 11,900 bbls/day in 2007.

Interest Rates

The London Interbank Offered Rate (‘LIBOR’) USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant proportion of our interest rate exposure. The LIBOR USD overnight rate has decreased from around 4.4% to around 1.1% during 2008 in line with underlying Federal Reserve rate cuts. Any rate increases would add additional cost to financing our crude cargoes and vice versa as our BNP Paribas working capital facility is linked to LIBOR rates. See “Liquidity and Capital Resources — Summary of Debt Facilities”.

Skill and Resource Scarcity

Although all key positions with our company are currently filled, we have generally been faced with a shortage of skilled labor to work in our business and have historically experienced difficulties with receiving and retaining suitably qualified personnel in certain positions. Our success depends in large part on the continued services of our executive officers, our senior managers and other key technical personnel. Competition for qualified personnel can be intense and recruitment difficult. There are a limited number of people with the requisite knowledge and experience to work in certain of our key positions.

Exchange Rates

Changes in the Papua New Guinea Kina (PGK) to USD exchange rate can affect our Midstream Refinery results as there is a timing difference between the foreign exchange rates utilized when setting the monthly IPP, which is set in PGK, and the foreign exchange rate used to convert the subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK generally strengthened against the USD during 2008 (from 0.3525 to 0.3735).

RISK FACTORS

Our business operations and financial position are subject to a range of risks. A summary of the key risks that may impact the matters addressed in this document have been included under section “Legal Notice — Risk Factors and Forward Looking Statements” above. Detailed risk factors can be found under the heading “Risk Factors” in our 2008 Annual Information Form available at www.sedar.com.

Management Discussion and Analysis  INTEROIL CORPORATION      6

BUSINESS STRATEGY

Our business strategy is to develop a vertically integrated energy company in Papua New Guinea and surrounding regions, focusing on niche market opportunities which provide financial rewards for our shareholders, while being environmentally responsible, providing a quality working environment and contributing positively to the communities in which InterOil operates. A significant element of that strategy is to establish and develop gas reserves and an LNG facility in Papua New Guinea with the produced LNG exported overseas. InterOil plans to achieve this strategy by:

• Developing our position as a business operator in Papua New Guinea

• Enhance the refining and distribution business in Papua New Guinea

• Maximizing the value of our exploration assets

• Building an export liquefaction gas business in Papua New Guinea

• Positioning ourselves for long term success

Further details of our business strategy can be found under the heading “Business Strategy” in our 2008 Annual Information Form available at www.sedar.com.

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

A summary of the key operational matters and events for the year, for each of the segments is as follows:

Upstream

• On May 1, 2008, the Elk-4A well flowed natural gas and gas liquids to surface confirming a discovery in the Antelope structure. Elk-4 well was completed as a potential producer and completion work ended on August 31, 2008.

• On May 5, 2008, an Indirect Participation Interest (‘IPI’) investor waived conversion rights to 546,667 of our common shares under the IPI agreement.

• On June 1, 2008, we sold our 28.56% interest in Petroleum Retention License No. (PRL) 5 for $5.0 million and our 43.13% interest in PRL 4 for $1.5 million.

• On June 4, 2008, we appointed an independent engineering firm to evaluate the Elk and Antelope fields in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Their evaluation, in compliance with National Instrument 51-101, is provided in the Annual Information Form for the year ended December 31, 2008.

• On August 15, 2008, an IPI investor converted its 3.375% indirect participation interest into 450,000 common shares.

• On September 4, 2008, the Elk-4 well flowed gas at a rate equivalent to 105 mmscf per day. Based on our drill stem test results of 18bbl/mmcfd, this equates to a rate of 1,890 bbl/day of condensate.

• On September 23, 2008, an IPI investor waived conversion rights to 150,000 of our common shares under the IPI agreement.

• Antelope-1 well was spudded on October 15, 2008.

• On October 30, 2008 Petromin PNG Holdings Limited entered into an agreement to acquire a 20.5% interest in the Elk/Antelope field on behalf of the Papua New Guinea Government.

• In December 2008, we submitted applications for the extension of our PPL 238, 237 and 236 licenses for a second term. These licenses were expiring in March 2009.

• Subsequent to year end, on March 2, 2009, Antelope-1 well flowed gas at a rate equivalent to 382 mmscf per day with 5,000 bbl/day of condensate for a total 68,700 barrels of oil equivalent per day.

• Subsequent to year end, on March 5, 2009, all three licenses have been re-issued for a five year term covering what we believe the most prospective 50% of the acreage on these licenses.

Management Discussion and Analysis  INTEROIL CORPORATION       7

Midstream — Refining

• Net income was $4.7 million for fiscal year 2008 which is the first year of profitable operations for the refinery.

• Refining operations had a gross margin of $6.3 million and EBITDA, a non-GAAP measure, of $25.6 million for the year.

• Total refinery throughput was 22,034 barrels per operating day compared with 19,713 barrels per operating day in 2007.

• BNP Paribas working capital facility was increased by $20.0 million to $190.0 million as part of current year renewal process.

Midstream — Liquefaction

• Net loss was $7.9 million during the year ended December 31, 2008, being our share of expenses incurred by the PNG LNG Inc. Joint Venture during the year on progressing the LNG Project.

• In late October 2008, certain steps were taken with a view to ensuring that offtake arrangements for the proposed LNG plant were able to be negotiated with industry-based entities.

• Subsequent to year ended December 31, 2008, InterOil LNG Holdings Inc. and Pacific LNG Operations Ltd, acquired equal share of Merrill Lynch’s interest in the Joint Venture Company. Following this transaction, Merrill Lynch does not own any interest in the LNG project and have agreed to release all of their outstanding claims relating to the joint venture.

• Negotiations on a project agreement with the Papua New Guinea government were progressed.

• Progressed engineering design activities for the proposed liquefaction plant.

Downstream

• Downstream operations net loss was $1.2 million for the year, principally as a result of a $4.3 million inventory write down due to a rapid decrease in product prices following crude price movements.

• Downstream operations generated gross margin of $19.9 million and EBITDA of $5.8 million for the year ended December 31, 2008.

• Total Downstream sales volumes were 548.0 million liters in 2008, compared with 556.4 million liters in 2007.

• We secured a PGK 150.0 million (approximately $57.5 million) combined revolving working capital facility from Bank of South Pacific Limited and Westpac Bank PNG Limited.

Corporate

• On May 5, 2008, we converted $60.0 million of the expiring $130.0 million bridging facility into common shares and repaid the balance of $70.0 million on May 12, 2008 with funds raised from the issuance of $95.0 million of 8% subordinated convertible debentures.

• In July and August 2008, all $15.0 million worth of issued Series A preference shares were converted into 517,777 common shares.

• In July and August 2008, $15.0 million of 8% debentures were converted into 600,000 common shares.

• In August 2008, we filed an omnibus 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 which will enable us to issue, from time to time up to an aggregate of $200.0 million of debt securities, common shares, preferred shares, warrants or a combination thereof in one or more offerings.

• In November 2008, $1.0 million of 8% debentures were converted into 41,000 common shares.

Management Discussion and Analysis  INTEROIL CORPORATION      8

SELECTED ANNUAL FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the year ended December 31, 2008 compared to year ended December 31, 2007 and 2006

Consolidated - Operating results	Year ended December 31,
($ thousands, except per share data)	2008			2007			2006
Sales and operating revenues		915,579			625,526			511,088
Interest revenue		932			2,180			3,224
Other non-allocated revenue		3,216			2,667			3,748
Total revenue		919,727			630,373			518,060
Cost of sales and operating expenses		(888,623	)		(573,609	)		(499,495	)
Office and administration and other expenses		(42,814	)		(36,196	)		(27,395	)
Derivative gain/(loss)		24,039			(7,272	)		2,560
Gain on LNG shareholder agreement		—			6,553			—
Exploration costs		(996	)		(13,305	)		(6,177	)
Exploration impairment		(108	)		(1,243	)		(1,647	)
Gain on sale of oil and gas properties assets		11,235			—			—
Earnings before interest, taxes, depreciation and amortization (non-GAAP measure) (1)		22,460			5,301			(14,094	)
Depreciation and amortization		(14,143	)		(13,024	)		(12,353	)
Interest expense		(20,032	)		(20,005	)		(17,273	)
Loss before income taxes and non-controlling interest		(11,715	)		(27,728	)		(43,720	)
Income tax expense		(81	)		(1,207	)		(2,343	)
Non-controlling interest		(1	)		22			264
Net loss		(11,797	)		(28,913	)		(45,799	)
Loss per share (dollars) (basic)		(0.35	)		(0.96	)		(1.55	)
Loss per share (dollars) (diluted)		(0.35	)		(0.96	)		(1.55	)
Total assets		591,843			537,815			505,239
Total liabilities		364,704			441,712			417,060
Total long-term liabilities		208,224			174,966			283,306
Gross margin (2)		26,956			51,917			11,593
Cash flows (used in)/provided by operating activities (3)		15,586			(31,620	)		2,187
U.S. GAAP net profit (loss) (4)		(3,943	)		(19,205	)		(45,058	)

(1)	Earnings before interest, taxes, depreciation and amortization, or EBITDA, is a non-GAAP measure and is reconciled to Canadian GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.
(2)	Gross Margin is a non-GAAP measure and is ‘sales and operating revenues’ less ‘cost of sales and operating expenses’.
(3)	Refer to “Liquidity and Capital Resources — Summary of Cash Flows” for detailed cash flow analysis.
(4)	We are not presenting all the U.S. GAAP information in this MD&A. Readers should review note 29 — ‘Reconciliation to the generally accepted accounting principles in the United States’ to the audited financial statements for the year ended December 31, 2008 for the reconciliation of the Canadian GAAP and U.S. GAAP information.

Analysis of Financial Condition Comparing Year Ended December 31, 2008 and 2007

During the year ended December 31, 2008, the Company strengthened its financial position with the conversion of $60.0 million of the $130.0 million bridging facility into common shares, and the 8% subordinated convertible debentures placement of $95.0 million, both of which occurred in May 2008. These transactions during the year reduced our Debt-To-Capital Ratio to 36% in December 2008 from 67% in December 2007, which is a significant improvement from the prior year.

Management Discussion and Analysis  INTEROIL CORPORATION      9

As at December 31, 2008, our total assets amounted to $591.8 million as compared to $537.8 million as at December 31, 2007, which is an increase of $54.0 million or 10%. The increase mainly contributed by the increase in oil and gas properties (net of cash calls from IPI investors) by $43.1 million in relation to the drilling and testing our exploration and appraisal wells during the year. The increase was also contributed by $31.3 million of mark to market gains and receivables on derivative contracts that were outstanding as at year end. These short and long term hedge contracts were taken by us during the year to manage the timing and margin risk in relation to crude prices.

As at December 31, 2008, our total liabilities amounted to $364.7 million as compared to $441.7 million as at December 31, 2007, which is a decrease in liability of $77.0 million or 17.4%. The decrease was mainly in relation to the conversion of the $60.0 million of bridging facility into common shares  and repayment of $70.0 million of the bridging facility out of the funds raised from the $95.0 million 8% convertible debenture issue in May 2008. During the year, $16.0 million principal amount of this convertible debenture issue was converted into common shares and the entire principal amount of $15.0 million in relation to Series A preferred shares issued in November 2007 were converted into common shares. The exercise of conversion option by some IPI investors and the waiver of conversion rights during the year by two IPI investors also resulted in the reduction of the IPI liability by $23.6 million.

Our current ratio (being current assets/current liabilities) which measures the ability to meet short term obligations improved to 1.51 as at December 31, 2008 from 0.81 as at December 31, 2007. The quick ratio (or Acid test ratio, being ([current assets less inventories]/current liabilities) which is a more conservative measure of an entity’s ability to meet short term obligations improved to 0.98 as at December 31, 2008 from 0.50 as at December 31, 2007.

Analysis of Consolidated Cash Flows Comparing Year Ended December 31, 2008 and 2007

As at December 31, 2008, we had cash, cash equivalents and cash restricted of $75.3 million (2007 - $66.2 million), of which $26.3 million (2007 — $22.4 million) was restricted as governed by the BNP Paribas working capital facility utilization requirements.

Our cash inflows from operations for the year ended December 31, 2008 was $15.6 million as compared to an outflow of $31.6 million for the year ended December 31, 2007. The improved cash flows from operations were mainly due to the reduced working capital requirements in the fourth quarter of 2008 due to decreased feedstock price environment.

Cash outflows for investing activities for the year ended December 31, 2008 was $47.4 million as compared to $34.4 million during 2007. These outflows mainly relate to the net cash expenditure on the oil and gas properties after the IPI cash calls. The increase in restricted cash held as security on the BNP Paribas working capital facility also contributed to the increase in outflow as compared to the prior year.

Cash inflows from financing activities for the year ended December 31, 2008 was $36.9 million as compared to $78.1 million during 2007. Current year inflows were mainly related to the $94.8 million net receipt from the issue of debentures, less repayment of $70.0 million bridging facility to Merrill Lynch both of which occurred in May 2008. 2007 cash inflows from financing activities were mainly due to the increased utilization of the BNP Paribas working capital facility and issue of common shares.

Analysis of Consolidated Financial Results Comparing Year and Quarter Ended December 31, 2008 and 2007

Net loss for the year ended December 31, 2008 was $11.8 million compared with a net loss of $28.9 million for the same period in 2007, showing an improvement of $17.1 million. The operating segments of Corporate, Midstream Refining and Downstream collectively had a net loss for the year of $6.0 million and the development segments of Upstream and Midstream Liquefaction had a net loss of $5.8 million for an aggregate net loss of $11.8 million. EBITDA for the year ended December 31, 2008 was $22.4 million, an increase of $17.2 million over the $5.3 million for the same period in 2007.

Management Discussion and Analysis  INTEROIL CORPORATION      10

Sales and operating revenue for the year ended December 31, 2008 was $919.7 million compared with $630.4 million for the same period in 2007.

The net loss for the quarter ended December 31, 2008 was $34.2 million compared with a loss of $2.7 million for the same quarter of 2007, an increase of $31.5 million. EBITDA for the quarter ended December 31, 2008 was negative $28.8 million, compared with positive $6.9 million in the 2007 December quarter, a reduction of $35.7 million. The increase in the loss for the quarter was due to the decrease in gross margins resulting from the fall in crude prices and related IPP during the last quarter of 2008. We estimate that the fall in crude prices in the last quarter of 2008 reduced the gross margins by approximately $52.3 million, $45.9 million for the refinery and $6.4 million for the wholesale and retail distribution segment. These losses were partly offset by our short and long term hedges. Our short and long term hedges put in place in 2008 netted a $27.8 million profit during the year with a further $18.0 million of unrealized hedging gains carried forward in our balance sheet for unsettled hedge accounted transactions as at year end.

The operating segments of Corporate, Midstream — Refining and Downstream collectively derived a net loss for the quarter of $27.6 million and the development segments of Upstream and Midstream Liquefaction made a net loss of $6.6 million for an aggregate net loss of $34.2 million.

Sales and operating revenue increased $45.8 million from $172.8 million in the quarter ended December 31, 2007 to $218.6 million in the quarter ended December 31, 2008.

A complete discussion of each of the business segment’s results can be found under the section ‘Year and Quarter in Review’. The following analysis outlines the key variances, the net of which are the primary explanations for the changes in the results between the years and quarters ended December 31, 2008 and 2007.

	Yearly			Quarterly
	Variance			Variance
	($ millions)			($ millions)
		$17.1			($31.5	)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø		($25.0	)		($61.3	)	Decrease in gross margin due to negative effects of IPP movements due to fall in crude prices, and the associated timing and margin risk. Part of these margin declines have been offset by the gains from non-hedge accounted derivatives noted below. The results for the quarter and year ended December 31, 2008 also included an inventory write-down of $8.4 million. No write-downs were necessary for the same periods in 2007.
Ø		$31.3			$29.1		Increase in gains from derivative transactions that were not hedge accounted.
Ø		($5.4	)		$1.0		Increase in office and administration and other expenses during the year primarily due to higher legal consulting expenses on account of capital raisings and legal opinions in relation to the Merrill Lynch arbitration, higher employee expenses due to increase in employees and wage increases, higher share compensation expense, higher rig repairs and maintenance expenses and an increase in insurance costs.
Ø		($1.2	)		($4.8	)	Increase in office and administration and other expenses due to lower foreign exchange gains with lower appreciation of PGK against USD compared to prior periods.
Ø		$6.5			—		Gain on sale of our interest in PRL4 and PRL5 to Horizon Oil Limited in June 2008.

Management Discussion and Analysis  INTEROIL CORPORATION      11

	Yearly			Quarterly
	Variance			Variance
	($ millions)			($ millions)
Ø		$4.7			—	Gain from conveyance accounting following decisions by two IPI investors’ decision to waive their conversion rights under the IPI agreement.
Ø		$12.3			$0.2	Higher exploration costs expensed during prior periods as the Elk seismic program was being conducted; the costs of which were expensed as incurred under the successful efforts method of accounting.
Ø		($6.6	)		—	One-time gain recognized in 2007 on the signing of the LNG Shareholder’s Agreement in relation to the discounted interest rate received on the bridging facility from Merrill Lynch.
Ø		$1.1			$5.3	Lower income tax expense primarily in Downstream operations in the quarter due to lower profits.

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

The following is a table containing the consolidated results for the eight quarters ended December 31, 2008 by business segment, and on a consolidated basis.

Quarters ended	2008												2007
($ thousands except per share				Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
data)	Dec-31			(restated)			(restated)			(restated)			(restated)			(restated)			(restated)			(restated)
Upstream		487			698			895			618			579			1,176			397			395
Midstream — Refining		194,617			216,750			197,864			176,973			137,509			168,737			114,584			103,055
Midstream — Liquefaction		23			35			19			13			26			10			5			—
Downstream		128,540			172,528			140,467			116,048			118,495			102,786			93,186			77,812
Corporate and Consolidated		(105,100	)		(126,280	)		(94,231	)		(101,238	)		(83,776	)		(82,605	)		(67,633	)		(54,366	)
Sales and operating revenues		218,567			263,731			245,014			192,414			172,833			190,104			140,539			126,896
Upstream		(2,483	)		231			10,164			(1,135	)		(3,128	)		(5,015	)		(5,492	)		(4,009	)
Midstream — Refining		(13,976	)		17,516			16,329			5,724			9,589			(1,332	)		3,775			6,336
Midstream — Liquefaction		(2,501	)		(1,570	)		(1,784	)		(1,636	)		(797	)		(4,104	)		(444	)		(322	)
Downstream		(7,244	)		610			7,893			4,529			3,627			3,301			2,760			3,028
Corporate and Consolidated		(2,639	)		27			(5,248	)		(347	)		(2,394	)		(3,105	)		4,959			(1,931	)
Earnings before interest, taxes, depreciation and amortization (1)		(28,843	)		16,814			27,354			7,135			6,897			(10,255	)		5,558			3,102
Upstream		(4,003	)		(1,039	)		9,188			(1,993	)		(3,736	)		(4,893	)		(6,008	)		(4,524	)
Midstream — Refining		(19,490	)		12,660			11,344			202			2,990			(12,199	)		(1,117	)		1,511
Midstream — Liquefaction		(2,597	)		(1,677	)		(1,909	)		(1,728	)		(877	)		(4,157	)		(444	)		(322	)
Downstream		(5,901	)		(886	)		3,383			2,198			670			(255	)		2,242			2,050
Corporate and Consolidated		(2,238	)		169			(6,405	)		(1,075	)		(1,760	)		3,612			2,373			(4,069	)
Net profit/(loss) per segment		(34,229	)		9,227			15,601			(2,396	)		(2,713	)		(17,892	)		(2,954	)		(5,354	)
Net profit/(loss) per share (dollars)
Per Share — Basic		(0.63	)		0.26			0.48			(0.08	)		(0.09	)		(0.60	)		(0.10	)		(0.18	)
Per Share — Diluted		(0.63	)		0.22			0.40			(0.08	)		(0.09	)		(0.60	)		(0.10	)		(0.18	)

(1)	Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.
(2)	During Q4 2008, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream — Liquefaction segments to reflect a more accurate view of its segment results. The prior period comparatives have been reclassified to conform to the current classification.

Management Discussion and Analysis  INTEROIL CORPORATION      12

YEAR AND QUARTER IN REVIEW

The following section provides a review of the year and quarter ended December 31, 2008 for each of our business segments.

UPSTREAM — YEAR AND QUARTER IN REVIEW

Upstream – Operating results	Year ended December 31,
($ thousands, unless otherwise indicated)	2008			2007 (restated)
Other non-allocated revenue		2,697			2,547
Total revenue		2,697			2,547
Office and administration and other expenses		(6,051	)		(5,643	)
Exploration costs		(996	)		(13,305	)
Exploration impairment		(108	)		(1,243	)
Gain on sale of oil and gas properties		11,235			—
Earnings before interest, taxes, depreciation and amortization (non-GAAP measure) (1)		6,777			(17,644	)
Depreciation and amortization		(597	)		(483	)
Interest expense (2)		(4,027	)		(1,034	)
Profit/(loss) before income taxes and non-controlling interest		2,153			(19,161	)
Income tax expense		—			—
Net profit/(loss)		2,153			(19,161	)

(1)

Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.

(2)

During the year, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream — Liquefaction segments to reflect a more accurate view of its segment results. The prior year comparatives have been reclassified to conform to the current classification. The entire interest expense in this segment relates to this notional interest cost transferred from Corporate segment.

Analysis of Upstream Financial Results Comparing Quarter and Year Ended December 31, 2008 and 2007

The following analysis outlines the key movements, the net of which primarily explains the improvements in the results between the years and quarters ended December 31, 2008 and 2007.

	Yearly		Quarterly
	Variance		Variance
	($ millions)		($ millions)
		$21.3		($0.3	)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø		$6.5	—			Gain on sale of our interest in PRL4 and PRL5 to Horizon in June 2008.
Ø		$4.7	—			Gain from conveyance accounting following the decisions by two IPI investors’ to waive their conversion rights under the IPI agreement.
Ø		$12.3		$0.2		Lower exploration costs expensed during current periods as the Elk seismic program was completed in the prior period; costs relating to the seismic program were expensed as incurred under the successful efforts method of accounting.
Ø		$1.1		$0.7		Lower exploration impairment during current period. Prior year expense related mainly to the write off of cash calls paid by us for seismic and exploratory activities in PRL 4 and 5 conducted by the joint venture operator.

Ø ($3.0 ) ($0.9 ) Higher interest expense due to an increase in the inter-company loan balances from Corporate segment.

Management Discussion and Analysis   INTEROIL CORPORATION       13

MIDSTREAM REFINING — QUARTER AND YEAR IN REVIEW

Midstream Refining – Operating results	Year ended December 31,
($ thousands, unless otherwise indicated)	2008			2007
External sales		358,896			233,869
Inter-segment revenue		427,218			289,947
Interest and other revenue		90			70
Total segment revenue		786,204			523,886
Cost of sales and operating expenses		(779,832	)		(495,059	)
Office and administration and other expenses		(4,817	)		(3,188	)
Derivative gain/(loss)		24,039			(7,272	)
Earnings before interest, taxes, depreciation and amortization (non-GAAP measure) (1)		25,594			18,367
Depreciation and amortization		(10,969	)		(10,405	)
Interest expense		(9,908	)		(16,798	)
Profit/(loss) before income taxes and non-controlling interest		4,717			(8,836	)
Income tax expense		—			—
Non-controlling interest		—			21
Net profit/(loss)		4,717			(8,815	)
Gross Margin (2)		6,282			28,757

(1)	Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.
(2)	Gross Margin is a non-GAAP measure and is external sales and inter-segment revenue less cost of sales and operating expenses.

Midstream Refining Operating Review

	Quarter ended						Year ended
	December 31,						December 31,
Key Refining Metrics	2008			2007			2008			2007
Throughput (barrels per day)(1)		21,206			19,646			22,034			19,713
Cost of production per barrel(2)	$	2.45		$	3.03		$	2.97		$	2.54
Working capital financing cost per barrel of production(2)	$	0.57		$	0.98		$	1.01		$	0.83
Distillates as percentage of production		53.60	%		63.70	%		56.00	%		60.05	%

(1)	Throughput per day has been calculated excluding shut down days. During 2008 and 2007, the refinery was shut down for 101 days and 71 days, respectively.
(2)	Our cost of production per barrel and working capital financing cost per barrel have been calculated based on a notional throughput. Our actual throughput has been adjusted to include the throughput that would have been necessary to produce the equivalent amount of diesel that we imported during the year.

Management Discussion and Analysis   INTEROIL CORPORATION       14

Analysis of Midstream Refining Financial Results Comparing the Year and Quarter Ended December 31, 2008 and 2007

During the year ended December 31, 2008 the Midstream Refining business generated a net profit of $4.7 million, compared with an $8.8 million net loss in the same period 2007. During the fourth quarter of 2008, the Midstream Refining business generated a net loss of $19.5 million, compared with a net profit of $3.0 million in the same quarter of 2007.

The following analysis outlines the key movements, the net of which primarily explains the improvements in the results between the year and quarter ended December 31, 2008 and 2007.

	Yearly			Quarterly
	Variance			Variance
	($ millions)			($ millions)
		$13.5			($22.5	)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø		($22.5	)		($47.6	)	Change in Gross Margin was due to the following contributing factors:
							- Decreasing feedstock price environment resulting in lower product prices
							- Available crude feedstock composition resulted in poorer refining yield structure
							+ Full year 2008 utilizing revised IPP pricing formula vs. one month in fourth quarter 2007.
							+ Improved Naphtha premium in contract
							+ Improved distillate margins
							+ Improved low sulphur waxy residue margins in fourth quarter 2008
							We estimate that the fall in crude prices in the fourth quarter of 2008 reduced the gross margins of our refinery operations by approximately $45.9 million. This includes a year end inventory revaluation of $4.2 million.
Ø		$31.3			$29.1		Increase in derivative gains from non-hedge accounted contracts.
Ø		$ 6.9			$1.6		Reduction in interest expense as a result of a decrease in inter-company loans (due to transfer of certain loans to investments) and installment repayments made on OPIC loan balance.
Ø		($0.6	)		($5.2	)	Reduction in foreign exchange gains due to the currency fluctuations between PGK and the U.S. Dollar. This item is included within the office and administration and other expenses classification in the table above.

Management Discussion and Analysis   INTEROIL CORPORATION       15

MIDSTREAM LIQUEFACTION — YEAR AND QUARTER IN REVIEW

Midstream Liquefaction – Operating results	Year ended December 31,
($ thousands, unless otherwise indicated)	2008			2007 (restated)
Interest and other revenue		91			41
Total segment revenue		91			41
Office and administration and other expenses		(7,582	)		(5,708	)
Earnings before interest, taxes, depreciation and amortization (non-GAAP measure) (1)		(7,491	)		(5,667	)
Depreciation and amortization		(69	)		(16	)
Interest expense (2)		(241	)		(105	)
Loss before income taxes and non-controlling interest		(7,801	)		(5,788	)
Income tax expense		(110	)		(13	)
Net loss		(7,911	)		(5,801	)

(1)

Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.

(2)

During the year, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream — Liquefaction segments to reflect a more accurate view of its segment results. The prior year comparatives have been reclassified to conform to the current classification. The entire interest expense in this segment relates to this notional interest cost transferred from Corporate segment.

Analysis of Midstream Liquefaction Financial Results Comparing the Years and Quarters Ended December 31, 2008 and 2007

All costs to the date of entering into the shareholders’ agreement relating to the LNG Project have been expensed. These costs included expenses relating to employees, office premises and consultants.

All costs incurred, subsequent to the execution of the shareholders’ agreement on July 31, 2007, during the pre-acquisition and construction stage will be expensed as incurred, unless they can be directly identified with the property, plant and equipment of the LNG Project. As at December 31, 2008, we have capitalized $2.1 million in direct costs of the project.

During the year ending December 31, 2008, the Midstream Liquefaction business had a net loss of $7.9 million compared with a loss of $5.8 million during the same period of 2007.

During the quarter ending December 31, 2008, the Midstream Liquefaction business had a net loss of $2.6 million, compared with a net loss of $0.9 million in the same quarter 2007.

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the year and quarter ended December 31, 2008 and 2007.

	Yearly			Quarterly
	Variance			Variance
	($ millions)			($ millions)
		($2.1	)		($1.7	)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø		($5.1	)		($1.6	)	Increased office and administration and other expenses, excluding the loss on proportionate consolidation explained below, mainly due to professional fees incurred in negotiations with the Government of Papua New Guinea on the LNG Project Agreement and work on drafting the engineering, procurement and commissioning contract for the LNG project. Employee and general administration costs have also increased during 2008 with increased activity on the Project.

Management Discussion and Analysis   INTEROIL CORPORATION       16

	Yearly		Quarterly
	Variance		Variance
	($ millions)		($ millions)
Ø	$	3.2		($0.1	)	Relates to the loss on proportionate consolidation of PNG LNG Inc. recognized initially of $2.4 million on signing of the Shareholders Agreement in 2007. These losses and any subsequent losses incurred will be recouped during the period as the other JV partners equalize their JV interest through payment of cash calls. $0.8 million of these losses were recouped in 2008.

DOWNSTREAM YEAR AND QUARTER IN REVIEW

Downstream – Operating results	Year ended December 31,
($ thousands, unless otherwise indicated)	2008			2007
External sales		556,683			391,657
Inter-segment revenue		185			81
Interest and other revenue		715			541
Total segment revenue		557,583			392,279
Cost of sales and operating expenses		(536,920	)		(368,803	)
Office and administration and other expenses		(14,876	)		(10,759	)
Earnings before interest, taxes, depreciation and amortization (non-GAAP measure) (1)		5,787			12,717
Depreciation and amortization		(2,571	)		(2,205	)
Interest expense		(4,838	)		(4,438	)
Profit/(loss) before income taxes and non-controlling interest		(1,622	)		6,074
Income tax expense		414			(1,366	)
Net profit/(loss)		(1,208	)		4,708
Gross Margin (2)		19,948			22,935

(1)	Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.
(2)	Gross Margin is a non-GAAP measure and is ‘external sales’ and ‘inter-segment revenue’ less ‘cost of sales and operating expenses’.

Downstream Operating Review

	Quarter Ended				Year Ended
	December 31,				December 31,
Key Downstream Metrics	2008		2007		2008		2007
Sales volumes (millions of liters)		151.4		151.5		548.0		556.4
Cost of distribution per liter ($ per liter)(1)	$	0.07	$	0.06	$	0.06	$	0.06

(1) Cost of distribution per liter includes land based freight costs and operational costs. It excludes depreciation and interest.

Analysis of Downstream Financial Results Comparing the Years and Quarters Ended December 31, 2008 and 2007

During the year ended December 31, 2008, the Downstream business had a net loss of $1.8 million compared with a net profit of $4.7 million in the same period in 2007. During the quarter ended December 31 2008, the Downstream business recorded a net loss of $6.5 million compared with a net profit of $0.7 million in the same period of 2007.

Management Discussion and Analysis   INTEROIL CORPORATION       17

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the years and quarters ended December 31, 2008 and 2007.

	Yearly			Quarterly
	Variance			Variance
	($ millions)			($ millions)
		($5.9	)		($6.6	)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø		($2.8	)		($14.5	)	We estimate that the fall in IPP in the last quarter of 2008 reduced the gross margins of our Downstream operations by approximately $6.4 million. This includes a net realizable value write down of $4.3 million on our year end finished products inventory held by our distribution operations.
Ø		($4.1	)		$3.9		Increase in office and administration and other expenses for the full year mainly due to higher Corporate allocations and Midstream recharges for storage facilities. The quarterly expense decreased compared to prior period due to reduced trade receivables provisions and rationalization of overhead costs following the Shell acquisition.
Ø		($0.4	)		($1.0	)	Increase in interest expense charged on inter-company loans from Corporate.
Ø		$1.8			$5.4		Reduction in income tax expense due to lower operating profits.

CORPORATE YEAR AND QUARTER IN REVIEW

Corporate – Operating results	Year ended December 31,
($ thousands, unless otherwise indicated)	2008			2007 (restated)
Inter-segment revenue elimination (1)		(427,404	)		(290,028	)
Interest revenue		555			1,648
Other non-allocated revenue		—			—
Total revenue		(426,849	)		(288,380	)
Cost of sales and operating expenses elimination (1)		428,128			290,253
Office and administration and other expenses (2)		(9,486	)		(10,897	)
Gain on LNG shareholder agreement		—			6,553
Earnings before interest, taxes, depreciation and amortization (non-GAAP measure) (3)		(8,207	)		(2,471	)
Depreciation and amortization (4)		64			83
Interest expense (5) (6)		(1,018	)		2,371
Loss before income taxes and non-controlling interest		(9,161	)		(17	)
Income tax expense		(386	)		171
Non-controlling interest		(1	)		2
Net profit/(loss)		(9,548	)		156
Gross Margin (7)		724			225

(1)	Represents the elimination upon consolidation of our refinery sales to other segments and other minor inter-company product sales.
(2)	Includes the elimination of inter-segment administration service fees.
(3)	Earnings before interest, taxes, depreciation and amortization is a non-GAAP measure and is reconciled to GAAP in the section to this document entitled ‘Non-GAAP measures and reconciliation’.
(4)	Represents the amortization of a portion of costs capitalized to assets on consolidation.

Management Discussion and Analysis   INTEROIL CORPORATION       18

(5)	Includes the elimination of interest accrued between segments.
(6)	During the year, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream — Liquefaction segments to reflect a more accurate view of its segment results. The prior year comparatives have been reclassified to conform to the current classification.
(7)	Gross Margin is a non-GAAP measure and is ‘inter-segment revenue elimination’ less ‘cost of sales and operating expenses’ and represents elimination upon consolidation of our refinery sales to other segments.

Analysis of Corporate Financial Results Comparing the Years and Quarters Ended December 31, 2008 and 2007

The following table outlines the key movements, the net of which primarily explains the variance in the results for between the years and quarters ended December 31, 2008 and 2007.

	Yearly			Quarterly
	Variance			Variance
	($ millions)			($ millions)
		($9.7	)		($0.5	)	Net profit/(loss) variance for the comparative periods primarily due to:
Ø		($4.5	)		($0.4	)	Reduction in interest revenue less interest expenses. This is due to a reduction in the intercompany loan balances on which other segments are charged interest expense based on market rates. Some of the intercompany balances have been converted into investments in our subsidiaries which has reduced the intercompany balances on which interest is charged.
Ø		($6.6	)	—			$6.6 million one-time gain recognized in the quarter ended June 30, 2007 due to the signing of the LNG shareholders’ agreement governing the development of the LNG Project.
Ø		$0.5			$0.9		Increase in net income on intra-group profit eliminated on consolidation between Midstream — Refining and Downstream segments.
Ø		$1.4			($0.9	)	Reduction in office and administration and other expenses due to additional recharges to the operating streams.

Management Discussion and Analysis   INTEROIL CORPORATION       19

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt facilities

Summarized below are the debt facilities available to us and the balances outstanding as at December 31, 2008.

			Balance
			outstanding
Organization	Facility		December 31, 2008			Maturity date
OPIC secured loan	$	62,500,000	$	62,500,000		December 2015
Unsecured 8% convertible debentures	$	95,000,000	$	78,975,000		May 2013
BNP Paribas working capital facility	$	190,000,000	$	53,386,775	(1)	August 2009
Westpac working capital facility	$	30,700,000	$	15,405,627		October 2011
BSP working capital facility	$	26,800,000	$	nil		August 2009

(1) Excludes letters of credit totaling $27.6 million.

Overseas Private Investment Corporation (‘OPIC’) Secured Loan (Midstream)

On September 12, 2001, we entered into a loan agreement with OPIC to secure a project financing facility of $85.0 million. The loan is secured by the assets of the refinery. The interest rate on the loan is equal to the agreed U.S. Government treasury cost applicable to each promissory note outstanding plus 3%, and is payable quarterly in arrears. Principal repayments of $4.5 million each are due on June 30 and December 31 of each year until the end of the loan or December 31, 2015. During year ended December 31 2008, two installments of $4.5 million each and the accrued interest on the loan were paid.

Unsecured 8% Subordinated Convertible Debentures (Corporate and Upstream)

On May 13, 2008, we issued $95.0 million of unsecured 8% subordinated convertible debentures with a five year maturity. The conversion price applicable to these debentures is $25.00 per share, we have the right to require the debenture holders to convert to common shares if the daily volume weighted average price (‘VWAP’) of our common shares is at or above $32.50 for at least 15 consecutive trading days. Accrued interest on these debentures is to be paid semi-annually in arrears, in May and November of each year, commencing in November 2008. $70.0 million of the funds raised from the issuance of these debentures was used to repay a portion of the $130.0 million bridging facility to Merrill Lynch. The remaining funds are being used for appraisal and development of the Elk/Antelope structures.

During the quarter ended September 30, 2008, a debenture holder exercised its conversion rights for $15.0 million principal amount of the debentures, resulting in the issue of 600,000 common shares. During the quarter ended December 31, 2008 a further $1.025 million worth of debentures were converted resulting in the issue of 41,000 common shares. The balance outstanding at December 31, 2008 was $79.0 million. The half yearly interest payment due in November was paid during quarter ended December 31, 2008 with the issuance of 260,768 common shares and payment of $848,400 in cash.

BNP Paribas Working Capital Facility (Midstream)

During the third quarter of 2008, the renewal of the $170.0 million secured revolving crude import Facility with BNP Paribas (Singapore Branch) was completed. The overall facility limit was increased to $190.0 million to accommodate higher crude prices and resulting increases in working capital requirements. The facility limit was temporarily increased to $210.0 million, and ultimately decreased to $190.0 million on December 1, 2008. This crude import facility is used to finance purchases of crude feedstock for our refinery. As of December 31, 2008, $109 million remained available for use under the facility. The

Management Discussion and Analysis   INTEROIL CORPORATION       20

weighted average interest rate under the crude import facility was 5.11% for the year ended December 31, 2008. The interest rate applicable on this facility has reduced in line with the reduction in LIBOR rates during the year.

Bank South Pacific and Westpac Working Capital Facility (Downstream)

On October 24, 2008 we secured a PGK 150.0 million (approximately $57.5 million) combined revolving working capital facility for our downstream wholesale and retail petroleum products distribution business in Papua New Guinea from Bank of South Pacific Limited and Westpac Bank PNG Limited. The Westpac facility limit is PGK 80.0 million (approximately $30.7 million) and the BSP facility limit is PGK 70.0 million (approximately $26.8 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 August 2009. As at December 31, 2008 only $15.4 million of this combined facility has been utilized, and the remaining facility remains available for use. The weighted average interest rate under the facility for the period was 7.25%.

While cash flows from operations are expected to be sufficient to cover our operating commitments, should there be a major deterioration in refining or downstream margins, our operations may not generate sufficient cash flows to cover all of the interest and principal payments under our debt facilities noted above. As a result, we may be required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these debt facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us. The global credit crisis may further impact our ability to refinance these debt facilities.

Other Sources of Capital

Upstream

Currently for expenditures on exploration wells, appraisal wells and extended well programs, funding of our share of these costs is sourced from operational cash flows, secured and unsecured borrowings, asset sales and/or equity raising activities.

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”), agreed to take a 20.5% direct interest in the Elk/Antelope field. Petromin contributed an initial deposit and will fund 20.5% of the costs of developing the Elk/Antelope field. The relevant legislation containing the State’s right to invest arises 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, or the State does not designate Petromin to hold its interest at that time. In the event the PDL is not granted for the Elk/Antelope field, Petromin will be issued with common shares based on a five day volume weighted average price (‘VWAP’) immediately prior to the date of issue. As at December 31, 2008, $4.0 million had been received from Petromin.

Cash calls are made on IPI investors and Petromin for their share of appraisal wells and extended well programs.

Summary of Cash Flows

	Year ended December 31,
($ thousands)	2008			2007			2006
Net cash inflows/(outflows) from:
Operations		15,586			(31,620	)		2,187
Investing		(47,391	)		(34,370	)		(97,071	)
Financing		36,913			78,170			66,963
Net cash movement		5,108			12,180			(27,921	)
Opening cash		43,862			31,681			59,602
Closing cash		48,970			43,861			31,681

Management Discussion and Analysis   INTEROIL CORPORATION       21

Analysis of Cash Flows Provided By/(Used In) Operating Activities Comparing the Years Ended December 31, 2008 and 2007

The following table outlines the key variances, the net of which primarily explains the variance in the cash flows from operating activities from an outflow of $31.6 million in the year ended December 31, 2007 as compared to an inflow of $15.6 million in 2008:

	Yearly
	Variance
	($ millions)
		$47.2		Variance for the comparative periods primarily due to:
Ø		($12.2	)	Increase in cash used by operations prior to changes in operating segments working capital.
Ø		$59.4		Increase in cash provided by operations due to working capital movements. These working capital movements relate to the timing of receipts, payments and inventory purchases, along with the decreasing crude and refined product price environment.

Analysis of Cash Flows Provided By/(Used In) Investing Activities Comparing the Years Ended December 31, 2008 and 2007

The following table outlines the key variances, the net of which primarily explains the variance in the cash flows from investing activities from an outflow of $34.3 million in the year ended December 31, 2007 as compared to $47.3 million in 2008:

	Yearly
	Variance
	($ millions)
		($13.0	)	Variance for the comparative periods primarily due to:
Ø		$5.2		Lower cash outflow on oil and gas exploration expenditure — the current year outflows related to the Elk-4A and Antelope drilling and extended well drilling program. The extended well program is partly funded by cash calls to the IPI investors.
Ø		($3.5	)	Lower cash inflows from cash calls made from IPI investors in relation to the Elk/Antelope extended well programs.
Ø		$2.1		Reduction in expenditure on plant and equipment.
Ø		$6.5		Proceeds received from the sale of our interest in PRL 4 and 5.
Ø		($14.0	)	Higher cash outflows due to movement in our secured cash restricted balances in line with the usage of the BNP working capital facility at period ends.
Ø		($5.9	)	Decrease in cash used in our development segments for working capital requirements. This working capital relates to movement in accounts payables and accruals of our Upstream and LNG segment.
Ø		($7.0	)	$7.0 million received in the third quarter of 2007 on settlement of the insurance claim for the Elk well blowout.
Ø		$3.3		Final settlement payment of the $3.3 million made in 2007 for the acquisition of Shell’s PNG distribution assets.

Management Discussion and Analysis   INTEROIL CORPORATION       22

Analysis of Cash Flows Provided By/(Used In) Financing Activities Comparing the Years Ended December 31, 2008 and 2007

The following table outlines the key variances, the net of which primarily explains the variance in the cash flows from financing activities from an inflow of $78.2 million in the year ended December 31, 2007 as compared to $36.9 million in 2008:

	Yearly
	Variance
	($ millions)
		($41.3	)	Variance for the comparative periods primarily due to:
Ø		($27.3	)	Higher repayment of the BNP Paribas working capital facility.
Ø		$94.8		Net proceeds from the issuance of debentures during May 2008.
Ø		($14.3	)	Net proceeds from the issuance of preference shares during December 2007
Ø		($70.0	)	Repayment of the Merrill Lynch bridging facility during May 2008.
Ø		($4.5	)	Repayment of two installments of the OPIC secured loan in June 2008 and December 2008 compared to only one payment made during 2007.
Ø		($0.4	)	Lower cash inflows relating to the Elk option agreement — $5.5 million in the year to December 31, 2008 compared with $5.9 million in the same period of 2007.
Ø		$4.0		Net payments received from Petromin in the quarter ended December 31, 2008.
Ø		($23.9	)	Net proceeds from the issuance of common shares during 2007.

Capital Expenditures

Upstream Capital Expenditures

Gross capital expenditures for exploration in Papua New Guinea for the year ended December 31, 2008 were $63.9 million compared with $69.1 million during the same period of 2007.

The following table outlines the key expenditures in the year ended December 31, 2008:

	Yearly
	($ millions)
		$63.9	Expenditures in the year ended December 31, 2008 due to:
Ø		$8.3	Drilled the Elk-4 appraisal well as part of the Elk extended well program.
Ø		$9.3	Drilled the Elk-4A exploratory well intersecting the Antelope structure.
Ø		$17.1	Tested the Elk-4A appraisal well as part of the Elk extended well program.
Ø		$22.6	Preparatory/drilling costs on the Antelope-1 appraisal well.
Ø		$1.0	Preparatory costs on our next appraisal well Antelope-2.
Ø		$0.9	Costs incurred in developing Elk PDL.
Ø		$1.1	Field geology costs on PPL 236 and PPL 237.
Ø		$4.4	Fixed assets additions and inventory purchases.

Management Discussion and Analysis   INTEROIL CORPORATION       23

The IPI investors are required to fund 28.175% of the Elk extended well program costs to maintain their interest in that well program. The amounts capitalized in our books, or expensed as incurred, in relation to the extended well program are the net amounts after adjusting for the IPI investors’ interest in the program.

Petromin has contributed an initial $3.0 million deposit towards past costs and will fund 20.5% of ongoing costs for developing the fields. Petromin contributed an additional $1.0 million towards these ongoing costs in December 2008. All funds received are being treated as a deposit until a PDL is granted.

Midstream Capital Expenditures

There were no major capital expenditures in our Midstream refinery business segment for the year ended December 31, 2008.

Downstream Capital Expenditures

Capital expenditures for the Downstream wholesale and retail distribution business segment were $4.1 million for year ended December 31, 2008. These expenditures mainly related to major tankage repairs in Rabaul.

Capital Requirements

The oil and gas industry is capital intensive and our business plans necessarily involve raising additional capital. The availability and cost of such capital is highly dependent on market conditions at the time we raise such capital. No assurance can be given that we will be successful in obtaining new sources of capital on terms that are acceptable to us, particularly given the current market conditions.

Upstream

We are obliged under our $125.0 million IPI agreement entered into in February 2005 to drill eight exploration wells. As at December 31, 2008, we estimate that a further $43.9 million will be required to fulfill this commitment. The timing of this is subject to our discretion.

We will need to raise additional funds in order for us to complete the program and meet the obligation to drill the remaining four wells under the IPI agreement. The cost of drilling exploration wells in Papua New Guinea is subject to numerous factors. Existing cash balances and ongoing cash generated from operations will not be sufficient to facilitate further development of the Elk/Antelope well prospect and to satisfy our obligations under the IPI agreement. Therefore we must extend or secure sufficient funding through renewed borrowings, equity raising and or asset sales to enable sufficient cash to be available to meet these obligations and further our development plans. No assurances can be given that we will be successful in obtaining new sources of capital on terms acceptable to us, particularly given the current market conditions.

In the event that we establish sufficient gas resources and reserves, we will also be required to obtain substantial amounts of financing for the Elk field development and delivery of gas to the LNG project and it would take a number of years to complete these projects. In the event that the viability of the LNG project is established, we plan to use a combination of debt, equity and the partial sale of capitalized properties to strategic investors to raise adequate capital. The availability and cost of various sources of financing is highly dependent on market conditions at the time and we can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable. If the disruption in the financial and credit markets continue for an extended period of time, this financing may be more expensive and difficult to obtain.

Midstream — Refining

We believe that we will have sufficient funds from our operating cashflows to pay our estimated capital expenditures for 2009. We also believe cash flows from operations will be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be a major deterioration in refining margins or the IPP review not yield an agreement for the revision of the IPP

Management Discussion and Analysis   INTEROIL CORPORATION       24

formula applicable to our refined product, our refinery may not generate sufficient cash flows to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us, particularly given the current market conditions.

Midstream — Liquefaction

Completion of any LNG Project will require substantial amounts of financing and construction will take a number of years to complete. As a joint venture partner in the project, if the project proceeds we would be required to fund our share of the development costs. No assurances can be given that we will be able to source sufficient gas reserves, successfully construct such a facility, or as to the timing of such construction. The availability and cost of capital is highly dependent on market conditions at the time we raise such capital. We can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable to us. If the disruption in the financial and credit markets continue for an extended period of time, this financing may be more expensive and difficult to obtain.

Downstream

We believe on the basis of current market conditions and the status of our business that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2009.

Contractual Obligations and Commitments

The following table contains information on payments for contracted obligations due for each of the next five years and thereafter. It should be read in conjunction with our financial statements for the year ended December 31, 2008 and the notes thereto:

	Payments Due by Period ($ thousands)
Contractual obligations			Less than										More than
($ thousands)	Total		1 Year		1 - 2 years		2 - 3 years		3 - 4 years		4 - 5 years		5 Year
Secured loan and debenture obligations		141,475		9,000		9,000		9,000		9,000		87,975		17,500
Indirect participation interest (1)		1,384		540		844		—		—		—		—
PNG LNG Inc. Joint Venture (proportionate share of commitments)		904		884		20		—		—		—		—
Petroleum prospecting and retention licenses (2)		95,000		16,500		4,500		23,333		35,333		15,334		—
Total		238,763		26,924		14,364		32,333		44,333		103,309		17,500

(1)	These amounts represent the estimated cost of completing our commitment to drill exploration wells under our indirect participation interest agreement entered into in July 2003. See Note 18 to our audited financial statements for the year ended December 31, 2008.
(2)	The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed as a condition on renewal of these licenses. Of this commitment, as at December 31, 2008, management estimates that $43,926,310 would satisfy the commitments in relation to the IPI investors

Off Balance Sheet Arrangements

Neither during the quarter or year ended, nor as at December 31, 2008, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Management Discussion and Analysis   INTEROIL CORPORATION   25

Transactions with Related Parties

Petroleum Independent and Exploration Corporation, a company owned by Mr. Mulacek, our Chairman and Chief Executive Officer, earned management fees of $150,000 during the year ended December 31, 2008 (December 2007 — $150,000). This management fee relates to Petroleum Independent and Exploration Corporation acting as the General Manager of one of our subsidiaries, S.P. InterOil, LDC, in compliance with OPIC loan requirements.

Amounts due to directors and executives at December 31, 2008 totaled $27,750 for directors fees (December 2007 — $nil) and $nil for executive bonuses (December 2007 — $nil).

Share Capital

Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 series A preferred shares are authorized. As of December 31, 2008, we had 35,923,692 common shares and nil preferred shares outstanding (43,424,444 common shares on a fully diluted basis).

Derivative Instruments

Our revenues are derived from the sale of refined products. Prices for refined products and crude feed stocks are extremely 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 the various markets.

Generally, we purchase crude feedstock two months in advance, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Due to the fluctuation in prices during this period, we use various derivative instruments as a tool to reduce the risks of changes in the relative prices of our crude feed stocks and refined products. Such an activity is better known as hedging and risk management. These derivatives, which we use to manage our price risk, effectively enable us to lock-in the refinery margin such that we are protected in the event that the difference between our sale price of the refined products and the acquisition price of our crude feed stocks contracts is reduced. On the flip side, when we have locked-in the refinery margin and if the difference between our sales price of the refined products and our acquisition price of crude feed stocks expands or increases, then the benefits would be limited to the locked-in margin.

The derivatives instrument which we generally use is the over-the-counter (OTC) swap. The swaps transactions are concluded between counterparties in the derivatives swaps market, unlike futures which are transacted on the International Petroleum Exchange (IPE) and Nymex Exchanges. We believe these hedge counterparties to be credit worthy. However, given the financial and credit market crisis, the creditworthiness of our hedge counterparties could change quickly. It is common place among refiners and trading companies in the Asia Pacific market to use derivatives swaps as a tool to hedge their price exposures and margins. Due to the wide usage of derivatives tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for the hedging and risk management activities. The derivatives swaps instrument covers commodities or products such as jet and kerosene, diesel, naphtha, and also bench-mark crudes such as Tapis and Dubai. Using these tools, we actively engage in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instruments such as Brent futures on the IPE to hedge our crude costs.

At December 31, 2008, InterOil had a net receivable of $31.3 million relating to commodity hedge contracts. Of this total, a receivable of $16.3 million relates to hedge accounted contracts as at December 31, 2008 and a receivable of $15.1 million 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 $18.0 million and has been included in comprehensive income. Subsequent to year end, these unrealized hedges were terminated and the mark-to-market gains were realized. However, these gains will not be realized in our Statement of Operations until the period that these hedges were initially taken to cover.

Management Discussion and Analysis   INTEROIL CORPORATION   26

A profit of $3.7 million was recognized from the effective portion of priced out hedge accounted contracts for the year ended December 31, 2008 (Dec 2007 – loss of $2.5 million), and a profit of $24.0 million was recognized on the non-hedge accounted derivative contracts and the ineffective portion of hedge accounted contracts for the year ended December 31, 2008 (Dec 2007 – loss of $7.3 million).

For a detailed description of our current derivative contracts as of December 31, 2008, see Note 7 to our financial statements for the year ended December 31, 2008.

We will continue with our hedging and risk management program in 2009 and we will continue to evaluate new approaches to enhance our hedging arrangement and margin protection.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. The information about our critical accounting estimates should be read in conjunction with Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2008, which summarizes our significant accounting policies.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment. A valuation allowance is provided against any portion of a future tax asset which will more than likely not be recovered. In considering the recoverability of future tax assets and liabilities, we consider a number of factors, including the consistency of profits generated from the refinery, likelihood of production from Upstream operations to utilize the carried forward exploration costs, etc. If actual results differ from the estimates or we adjust the estimates in future periods, we may need to record a valuation allowance. The net deferred income tax assets as of December 31, 2008 and 2007 were $4.3 million and $2.9 million, respectively.

Oil and Gas Properties

We use the successful-efforts method to account for our oil and gas exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. We continue 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 economical reserves. Capitalized costs for producing wells will be subject to depletion using the units-of-production method. Geological and geophysical costs are expensed as incurred. If our plans change or we adjust our estimates in future periods, a reduction in our oil and gas properties asset will result in a corresponding increase in the amount of our exploration expenses. The net costs of drilling exploratory wells carried as an asset as of December 31, 2008 and 2007 were $103.1 million and $62.5 million.

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

Management Discussion and Analysis     INTEROIL CORPORATION     27

material obligations associated with the retirement of the refinery or with its normal operations relating to future restoration and closure costs. The refinery is located on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating 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. We currently do not have any amounts accrued for environmental remediation obligations. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.

Impairment of Long-Lived Assets

We are required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. We test long-lived assets for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings. In order to determine fair value, our management must make certain estimates and assumptions including, among other things, an assessment of market conditions (including estimation of gross refining margins, crude price environments and its impact on IPP, etc), projected cash flows, investment rates, interest/equity rates and growth rates, that could significantly impact the fair value of the asset being tested for impairment. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans. However, providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates.

Legal and Other Contingent Matters

We are required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the amount of a contingent loss is determined it is charged to earnings. Our management continually monitors known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.

NEW ACCOUNTING STANDARDS

Standards adopted effective January 1, 2008

Effective January 1, 2008 the Company adopted the following new Canadian Institute of Chartered Accountants (CICA) sections:

• CICA 1400 – General standards of financial statement presentation

• CICA 1535 – Capital Disclosures

• CICA 3031 – Inventories

• CICA 3862 – Financial Instruments – Disclosures; and

• CICA 3863 – Financial Instruments – Presentation

These new accounting standards provide requirements for the presentation and disclosure of financial instruments and capital disclosures. The standards have been adopted prospectively and as such the comparative consolidated financial statements have not been restated. The adoption of these Handbook sections had no impact on opening retained earnings or accumulated other comprehensive income.

Management Discussion and Analysis   INTEROIL CORPORATION   28

General standards of financial statement presentation

This Section has been amended to include requirements to assess and disclose an entity’s ability to continue as a going concern. The new requirements are applicable to all entities and are effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2008.

Capital Disclosures

This Section establishes standards for disclosing information about an entity’s capital and how it is managed. This section has resulted in InterOil disclosing information in note 3(h) below that enables users of its financial statements to evaluate the Company’s objectives, policies and processes for managing capital.

Inventories

This section establishes standards for the measurement and disclosure of inventories. It provides the Canadian equivalent to International Financial Reporting Standard IAS 2, “Inventories”. There is no impact due to this new standard on the accounting policies of the Company.

Financial Instruments – Disclosure and Presentation

The objectives of these Sections are to require entities to provide disclosures in their financial statements that enable users to evaluate:

a. the significance of financial instruments for the entity’s financial position and performance

b. the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks; and

c. to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows.

New Accounting standards not yet applicable as at December 31, 2008

Based on the detailed review conducted by the Company of the new CICA sections, or revisions to current sections, that are effective January 1, 2009, no items have been identified as having any material impact on the Company’s financial statements.

In 2006, the Accounting Standards Board (AcSB) announced its intentions to adopt International Financial Reporting Standards (IFRS) as Canadian GAAP, tentatively effective January 1, 2011. In anticipation of the change, the AcSB began 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.

The 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 AcSB in Canada is also evaluating the possibility of allowing entities to early adopt IFRS reporting.

We will strongly consider early adopting IFRS, if allowed by the AcSB, to benefit from the exemption from U.S. GAAP reconciliation. We have set up a Steering Committee and Project Management Team to evaluate the key differences between Canadian GAAP and IFRS and prepare for the transition. The Steering Committee will report to the Audit Committee on a regular basis on the progress of the transition project and key differences that need to be addressed for the transition.

Based on the preliminary work performed on evaluating key differences between Canadian GAAP and IFRS as applicable to us, no major differences were noted that would have significant impact on transition to IFRS.

Management Discussion and Analysis     INTEROIL CORPORATION     29

NON-GAAP MEASURES AND RECONCILIATION

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

Consolidated – Operating results	Year ended December 31,
($ thousands, except per share data)	2008			2007			2006
Sales and operating revenues		915,579			625,526			511,088
Cost of sales and operating expenses		(888,623	)		(573,609	)		(499,495	)
Gross Margin		26,956			51,917			11,593

Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used by us to analyze operating performance. EBITDA does not have a standardized meaning prescribed by United States or Canadian generally accepted accounting principles 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 GAAP. Further, EBITDA is not a measure of cash flow under GAAP and should not be considered as such. For reconciliation of EBITDA to the net income (loss) under GAAP, refer to the following table.

Management Discussion and Analysis   INTEROIL CORPORATION   30

The following table reconciles net income (loss), a GAAP measure, to EBITDA, a non-GAAP measure for each of the last eight quarters.

	2008												2007
Quarters ended				Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
($ thousands)	Dec-31			(restated)			(restated)			(restated)			(restated)			(restated)			(restated)			(restated)
Upstream		(2,483	)		231			10,164			(1,135	)		(3,128	)		(5,015	)		(5,492	)		(4,009	)
Midstream – Refining		(13,976	)		17,516			16,329			5,724			9,589			(1,332	)		3,775			6,336
Midstream – Liquefaction		(2,501	)		(1,570	)		(1,784	)		(1,636	)		(797	)		(4,104	)		(444	)		(322	)
Downstream		(7,244	)		610			7,893			4,529			3,627			3,301			2,760			3,028
Corporate and Consolidated		(2,639	)		27			(5,248	)		(347	)		(2,394	)		(3,105	)		4,959			(1,931	)
Earnings before interest, taxes, depreciation and amortization		(28,843	)		16,814			27,354			7,135			6,897			(10,255	)		5,558			3,102
Subtract:
Upstream		(1,345	)		(1,137	)		(841	)		(704	)		(474	)		(177	)		(178	)		(206	)
Midstream – Refining		(2,771	)		(2,113	)		(2,263	)		(2,761	)		(4,397	)		(8,155	)		(2,156	)		(2,091	)
Midstream – Liquefaction		(65	)		(63	)		(60	)		(53	)		(53	)		(53	)		—			—
Downstream		(2,232	)		(885	)		(715	)		(1,005	)		(1,145	)		(3,320	)		66			(39	)
Corporate and Consolidated		546			152			(1,050	)		(667	)		624			6,483			(2,590	)		(2,146	)
Interest expense (1) (2)		(5,867	)		(4,046	)		(4,929	)		(5,190	)		(5,445	)		(5,222	)		(4,858	)		(4,482	)
Upstream		0			—			—			—			—			—			—			—
Midstream – Refining		—			—			—			—			(44	)		69			12			(17	)
Midstream – Liquefaction		(12	)		(25	)		(49	)		(24	)		(13	)		—			—			—
Downstream		4,297			82			(3,213	)		(752	)		(1,112	)		261			(32	)		(483	)
Corporate and Consolidated		(159	)		(24	)		(124	)		(81	)		(12	)		214			(15	)		(13	)
Income taxes and non-controlling interest		4,126			33			(3,386	)		(857	)		(1,181	)		544			(35	)		(513	)
Upstream		(175	)		(134	)		(135	)		(154	)		(134	)		299			(338	)		(309	)
Midstream – Refining		(2,742	)		(2,742	)		(2,723	)		(2,761	)		(2,158	)		(2,781	)		(2,748	)		(2,717	)
Midstream – Liquefaction		(19	)		(19	)		(16	)		(15	)		(15	)		—			—			—
Downstream		(722	)		(693	)		(582	)		(573	)		(700	)		(497	)		(552	)		(456	)
Corporate and Consolidated		14			15			17			18			21			20			20			21
Depreciation and amortisation		(3,644	)		(3,573	)		(3,439	)		(3,485	)		(2,986	)		(2,959	)		(3,618	)		(3,461	)
Upstream		(4,003	)		(1,039	)		9,188			(1,993	)		(3,736	)		(4,893	)		(6,009	)		(4,524	)
Midstream – Refining		(19,490	)		12,660			11,345			202			2,990			(12,199	)		(1,117	)		1,511
Midstream – Liquefaction		(2,596	)		(1,677	)		(1,910	)		(1,728	)		(878	)		(4,157	)		(444	)		(322	)
Downstream		(5,900	)		(886	)		3,383			2,198			670			(254	)		2,242			2,050
Corporate and Consolidated		(2,238	)		171			(6,405	)		(1,075	)		(1,761	)		3,612			2,374			(4,069	)
Net profit (loss) per segment		(34,227	)		9,229			15,601			(2,396	)		(2,715	)		(17,891	)		(2,954	)		(5,354	)

(1)	The inter-company interest charges have been restated for quarter ended March 31, 2008 and June 30, 2008 to reflect transfer of certain inter-company loan balances to inter-company investments.
(2)	During the year, the Company has transferred notional interest cost from Corporate segment to the Upstream and Midstream – Liquefaction segments to reflect a more accurate view of its segment results. The prior year comparatives have been reclassified to conform to the current classification.

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our Annual Information Form for the year ended December 31, 2008, in documents filed with the Canadian Securities Administrators at www.sedar.com, and in

Management Discussion and Analysis   INTEROIL CORPORATION   31

documents, including our Form 40-F, filed with the U.S. Securities and Exchange Commission at www.sec.gov. Additional information is also available on our website www.interoil.com.

DISCLOSURE CONTROLS AND PROCEDURES

The CEO, Mr. Mulacek, and the CFO, Mr. Visaggio, evaluated the effectiveness of our disclosure controls and procedures (“DC&P”) for the period ending December 31, 2008. Our DC&P are designed to provide reasonable assurance that all material information relating to InterOil is made known to the CEO and CFO by others and that all information required to be disclosed by InterOil for all reports and filings pursuant to applicable Canadian securities legislation is recorded, processed, summarized and reported within the prescribed time periods. Based on their evaluation, the CEO and CFO concluded that our DC&P are effective to provide reasonable assurance with respect to the foregoing objectives.

Internal Control Over Financial Reporting

The CEO and the CFO have also evaluated the effectiveness of InterOil’s internal controls over financial reporting (“ICFR”) for the period ending December 31, 2008. InterOil’s ICFR are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. However, because of its inherent limitations, ICFR 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 making their evaluation, they used the criteria set forth in the framework established by the Committee of Sponsoring Organizations (COSO) entitled – Internals Controls – Integrated Framework. Based on their evaluation, the CEO and CFO concluded that our ICFR are effective to provide reasonable assurance with respect to the objectives of our ICFR.

GLOSSARY OF TERMS

Barrel, Bbl Unit volume measurement used for petroleum and its products, equivalent to 42 U.S. gallons.

BP BP Singapore Pte Limited.

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 sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

EBITDA Earnings before interest, taxes, depreciation and amortization. EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used to analyze operating performance.

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 stipulates that the other 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.

Management Discussion and Analysis   INTEROIL CORPORATION   32

Feedstock Raw material used in a processing plant.

FID Final investment decision

GAAP Generally accepted accounting principles.

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

ICCC Independent Consumer and Competition Commission in Papua New Guinea.

IPP Import Parity Price. For each refined product produced and sold locally in Papua New Guinea, IPP is 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.

IPI Indirect Participation Interest.

LIBOR Daily reference rate based on the interest rates at which banks borrow unsecured funds from banks in the London wholesale money market.

LNG Liquefied natural gas. Natural gas converted to a liquid state by pressure and severe cooling, then returned to a gaseous state to be used as fuel. LNG is moved in tankers, not via pipelines. 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.

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.

Naphtha That portion of the distillate obtained in 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 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.

PGK Currency of Papua New Guinea.

PPL Petroleum Prospecting License. The tenement given by the Independent State of Papua New Guinea to explore for oil and gas.

PRL Petroleum Retention License. The tenement given by the Independent State of Papua New Guinea to allow the licensee holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.

Working interest An interest in a mineral property that entitles the owner of such interest to a share of the mineral productions from the property with the share based on such owner’s relative interest.

Mcf standard abbreviation for 1,000 cubic feet.

Bil cu ft Billion cubic feet. Also abbreviated to bcf.

Tcf trillion cubic feet.

Management Discussion and Analysis   INTEROIL CORPORATION   33

EX-99.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on 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 27, 2009 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 27, 2009

EX-99.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, we hereby consent to all references to our firm included in this Form 40-F for the year ended December 31, 2008 and in the Registration Statements on 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) with respect to our estimates of the natural gas and natural gas liquids resources of InterOil Corporation.

/s/ GLJ Petroleum Consultants Limited

GLJ Petroleum Consultants Limited
Calgary, Canada
March 27, 2009

EX-99.6

Exhibit 6

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 27, 2009	/s/ Phil E. Mulacek
	Phil E. Mulacek
	Chief Executive Officer

EX-99.7

Exhibit 7

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 27, 2009	/s/ Collin F. Visaggio
	Collin F. Visaggio
	Chief Financial 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, 2008 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 27, 2009

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chief Executive Officer 

EX-99.9

Exhibit 9

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, 2008 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 27, 2009

/s/ Collin F. Visaggio  

Collin F. Visaggio 

Chief Financial Officer