40-F/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 40-F/A

(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, 2006

Commission File Number: 001-32179

InterOil Corporation

(Exact Name of Registrant as Specified in Its Charter)

The Yukon Territory, Canada
(Province or Other Jurisdiction of Incorporation or Organization)

2911	Not Applicable
(Primary Standard Industrial Classification Code)	(I.R.S. Employer Identification Number)

Level 1
60-92 Cook Street
Cairns, QLD 4870, Australia
+61 (7) 4046-4600
(Address and Telephone Number of Registrant’s Principal Executive Offices)

CT Corporation Systems
111 8th Avenue
New York, New York 10011
(212) 894-8940
(Name, Address (Including Zip Code), and Telephone Number
(Including Area Code) of Agent for Service in the United States)

Copy to:

InterOil Corporation
25025 I-45 North, Suite 420
The Woodlands, TX 77380
Attention: General Counsel
(281) 292-1800
Facsimile: (281) 292-0888

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	American 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, 2006, 29,871,180 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

EXPLANATORY NOTE
 
Overview

InterOil Corporation (‘IOC’) is filing this amendment to its Annual Report on Form 40-F for the years ended December 31, 2006 and 2005, to amend and restate financial statements and other financial information for these years in relation to the Indirect Participation (‘IPI’)Agreement . The restatement adjusts our accounting for the IPI Agreement transaction based on discussions with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005.

Background

Management’s original model, as certified by our auditor’s, determined that conveyance accounting under SFAS 19 was triggered from day one as the intent of the IPI agreement was for the investors to fund an eight well exploration program in Papua New Guinea in return for a twenty five percent interest in any successful wells.

The SEC staff’s view was that the conversion option feature present in the IPI agreement acts as an impediment to conveyance accounting under SFAS 19 of the IPI Agreement. The non-financial liability should be maintained at initially recognized value till the conversion feature in the agreement lapses or is exercised.

After considering the SEC staff’s view, management recommended to the Audit Committee of our Board of Directors that previously reported financial results be restated to reflect the revised model as agreed with the SEC. The Audit Committee discussed and agreed with this recommendation. At a meeting on October 24 2007, the Board of Directors adopted the recommendation of the Audit Committee and determined that previously reported results for IOC should be restated and, therefore, that the previously filed financial statements and other financial information should be revised.

The revised model adopted by the management proposes that conveyance accounting should not be applied till the investors elect to transfer their indirect participation interest in the program into a direct interest in the Production Development Licence (‘PDL’) for a successful well or forfeiture of the conversion option occurs as per the agreement. This was based on the view that the investors have the option to convert into InterOil’s shares at any point in time from the date of the agreement till the option lapses on the occurrence of any of the conditions outlined in the contract. The exercise of the option by the investors during the exploration program would have resulted in funding provided by the IPI investors being in the nature of purchase price for InterOil’s shares rather than funding for a participation interest in InterOil’s exploration program.

We believe that our revised accounting treatment of IPI Agreement complies with the requirements of SFAS 133 and SFAS 19.

Effects of Restatement

In summary, conveyance accounting under SFAS 19 adopted by the Company from day one under the original model has been reversed and non-financial liability maintained at initially recognized value of $105,000,000, being the estimated cost of completing the eight well program, less transaction costs. The remaining $20,000,000 has been bifurcated and presented under

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equity for conversion options under residual basis. Under the revised model adopted, conveyance accounting will be triggered only on the lapse of conversion option available to the investors or they elect to participate in the PDL for a successful well. As conveyance accounting is not triggered from day one under the revised model, the Company will account for the exploration costs relating to the eight well program under successful efforts accounting policy adopted by the Company as noted under note 3(r) – ‘Oil and gas properties’.

For a detailed explanation of the restatements made to the financial statements for the year ended December 31, 2006 and 2005, refer Note 2 of the revised consolidated financial statements.

PRINCIPAL DOCUMENTS

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

A. Annual Information Form

The revised 2006 Annual Information Form for InterOil Corporation (the “Company”) is incorporated herein by reference.

B. Audited Annual Financial Statements

The revised audited consolidated financial statements of the Company for the years ended December 31, 2006, 2005 and 2004, 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 26 of the Notes to the audited financial statements incorporated herein by reference.

C. Management’s Discussion and Analysis

The Company’s revised Management’s Discussion and Analysis for the year ended December 31, 2006 (“MD&A”) is incorporated herein by reference.

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. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a Company 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 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 Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

On March 30 2007, the time that our original Annual Report on Form 40-F for the year ended December 31, 2006 was filed, our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) concluded that our disclosure controls and procedures were effective as of December 31, 2006.

Subsequent to that evaluation, and due to our restatement of our Consolidated Financial Statements for the year ended December 31, 2006 and 2005, our CEO and CFO concluded that our disclosure controls and procedures were not effective as of December 31, 2006 because of the existence of material weakness in our internal control over financial reporting relating to the

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fair value of the Indirect Participation Interest (IPI) non-financial liability and related accretion expense as of December 31, 2006. The material weakness in our internal control over financial reporting is discussed in more detail below. Notwithstanding this material weakness, management has concluded that the Company’s consolidated financial statements for the periods covered by and included in this restated Annual Report on Form 40 -F/A are fairly stated in all material respects in accordance with Generally Accepted Accounting Principles (GAAP) for each of the periods presented.

Management’s Report on Internal Control Over Financial Reporting (Restated)

In Management’s Report on Internal Control Over Financial Reporting included in our original Annual Report on Form 40-F for the year ended December 31, 2006, Our management, including the CEO and CFO, concluded that we maintained effective internal control over financial reporting as of December 31, 2006. Our management, including our CEO and CFO, has subsequently concluded that the material weakness associated with the accretion of the IPI non-financial liability described further below existed as of December 31, 2006. As a result, and based on the criteria in Internal Control- Integrated Framework issued by the COSO we have concluded that we did not maintain effective internal control over financial reporting as of December 31, 2006, Accordingly, management has restated it’s report on Internal Control Over Financial Reporting.

Responsibility

Our management is responsible for establishing and maintaining adequate internal over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities and Exchange Act of 1934, as amended). The company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with 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 change in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Assessment

Under the supervision of our CEO and CFO, management conducted an assessment on the effectiveness of our internal control over financial reporting as of December 31 2006, using the criteria set forth in the framework established by the Committee of Sponsoring Organizations (COSO) entitled — Internal Controls — Integrated Framework.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. In connection with management’s assessment of our internal control over financial reporting as required under Section 404 of the Sarbanes-Oxley Act of 2002, we identified the following material weaknesses in our internal control over financial reporting as of December 31, 2006.

Accretion and Fair Value of Non-Financial Liability: We did not maintain effective internal control over the accuracy, valuation, and disclosure of the IPI agreement non-financial liability and the related accretion expense. Specifically, we did not maintain effective control to provide reasonable assurance that the fair value measurement of the liability was determined in accordance with GAAP.

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The control deficiency stated above resulted in restatement of our consolidated financial statements for the year ended December 31, 2006 and December 31, 2005. Restatements have also been made to our interim consolidated financial statements for the quarters ended June 30, 2007 and 2006; and March 31, 2007 and 2006. Additionally, this control deficiency could result in misstatements of the aforementioned financial statement accounts that would result in a material misstatement of our annual consolidated financial statements that would not be prevented or detected. Accordingly, management has determined that this control deficiency constitutes a material weakness.

Because of the material weakness described above, management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2006, based on the Internal Control—Integrated Framework issued by COSO.

Management has excluded IPL (PNG) Limited, a former Shell PNG’s wholesale and distribution businesses (acquired in a business combination in October 2006) from its assessment of internal control over financial reporting as of December 31, 2006. The acquired business represented approximately six percent of 2006 consolidated net sales and nine percent of consolidated total assets at December 31, 2006.

This annual report does not include an audit report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to audit by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

Remediation of Material Weaknesses in Internal Control over Financial Reporting

As a result of the SEC comment letter process, management identified that the use of a discounted cash flow model for the determination of the fair values of the debt component of the IPI agreement was not an appropriate alternative fair value method for allocating the components of fair value to complex non-financial instruments. We have engaged in, and continue to engage in, efforts to address the material weaknesses in our internal control over financial reporting and the ineffectiveness of our disclosure controls and procedures. It is management’s goal to remediate the material weakness in 2007. Management has identified the need to strengthen internal control over the fair value models for unusual and complex contracts and will implement changes to our internal control over financial reporting subsequent to December 31, 2006 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting:

Management’s Consideration of the Restatement

As disclosed in Note 2, “Restatement of Consolidated Financial Statements for the year ended December 31, 2006 and 2005”, to our consolidated financial statements included in this Annual Report on Form 40F, we restated our previously issued 2006 and 2005 financial statements to correct for a misstatement in our accounting for the IPI agreement related to the conveyance and separately, the fair value of the IPI non-financial liability and the associated accretion expense. The material weakness related to the accretion expense and fair value of the non-financial liability is discussed in Management’s Report on Internal Control Over Financial Reporting (Restated).

In coming to the conclusion that our disclosure controls and procedures and our internal control over financial reporting were not effective as of December 31, 2006, management considered, among other things, the control deficiencies related to accounting for the IPI agreement related to conveyance accounting, which resulted in the need to restate our previously issued financial statements as disclosed in Note 2, “Restatement of Consolidated Financial Statements for the year ended December 31, 2006 and 2005”. Management has concluded that the control deficiencies, other then the “Accretion and Fair Value of the Non-Financial Liability“ that resulted in the restatement of the previously issued financial statements did not constitute a material weakness as

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of December 31, 2006 because management determined that as of December 31, 2006 there were effective controls designed and in place to prevent or detect a material misstatement and therefore the likelihood of the affected accounts listed in Note 2 of the financial statements being materially misstated is not more than remote.

Changes in internal control over financial reporting

There were no changes to the Company’s internal control over financial reporting during the period covered by this Report that have materially affected, or are reasonable 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. Byker, Mr. Speal and Mr Hansen . The Board of Directors has affirmatively determined that each of the members is financially literate and is an independent director for purposes of American 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 Securities Exchange Act of 1934.

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, principle accounting officer or controller will also be posted on the Company’s website.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees Paid to Independent Auditors. Fees paid for professional services rendered related to the audit of the Company’s annual consolidated financial statements for the year ended December 31, 2006 by PricewaterhouseCoopers were $618,669 (2005 – $333,344) including out-of-pocket expenses.

Audit-Related Fees. Fees paid for professional services rendered related to audit-related services for the Company for the year ended December 31, 2006 by PricewaterhouseCoopers were $84,383 (2005 – 10,180). The audit-related services provided by PricewaterhouseCoopers during 2006 and 2005 consisted of reviewing the Company’s preparations for complying with the Sarbanes-Oxley Act of 2002.

Tax Fees. Fees paid for professional services rendered related to tax services for the Company for the year ended December 31, 2006 by PricewaterhouseCoopers were nil (2005 – $9,900).

All Other Fees. Fees paid for professional services rendered related to all other services for the Company for the year ended December 31, 2006 by PricewaterhouseCoopers were $124,364, out of which $91,253 related to involvement in responding to SEC queries on 40-F of December 31, 2005 and $33,111 consisted of agreed upon procedures performed in connection with the quarterly financial reporting of the Company’s subsidiaries. The other services provided by PricewaterhouseCoopers in 2005 of $22,884 consisted of procedures performed in connection with the quarterly financial reporting of the Company’s subsidiaries.

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Pre-Approval. The Audit Committee of the Company’s Board of Directors pre-approves all auditing services, including the compensation and terms of the audit engagement, and all other non-audit services to be performed by the Company’s independent auditors. Non-audit services subject to the de-minimus exceptions described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934 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 2004 and 2005 were pre-approved by the audit committee.

OFF BALANCE SHEET ARRANGEMENTS

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

CONTRACTUAL OBLIGATIONS

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

AMEX CORPORATE GOVERNANCE

The Company’s common shares are listed on The American Stock Exchange (“AMEX”). Section 110 of the AMEX company guide permits AMEX to consider the laws, customs and practices of foreign issuers in relaxing certain AMEX listing criteria, and to grant exemptions from AMEX listing criteria based on these considerations. A company seeking relief under these provisions is required to provide written certification from independent local counsel that the non-complying practice is not prohibited by home country law. A description of the significant ways in which the Company’s governance practices differ from those followed by domestic companies pursuant to AMEX standards is as follows:

Shareholder Meeting Quorum Requirement. The AMEX minimum quorum requirement for a shareholder meeting is one-third of the outstanding common shares. In addition, a company listed on AMEX is required to state its quorum requirement in its bylaws. The Company’s quorum requirement is set forth in its By-Laws. A quorum for a meeting of members of the Company is two persons present in person, each being a shareholder entitled to vote thereat, or a duly appointed proxy for an absent shareholder so entitled.

Proxy Delivery Requirement. The AMEX 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 SEC proxy rules. The Company is a “foreign private issuer” as defined in Rule 3b-4 under the Securities Exchange Act of 1934, 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 Securities Exchange Act of 1934, as amended. The Company solicits proxies in accordance with applicable rules and regulations in Canada.

The foregoing are consistent with the laws, customs and practices in Canada.

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.

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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.

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TABLE OF CONTENTS

Revised Annual Information Form

Revised Audited Annual Consolidated Financial Statements

Revised Management's Discussion and Analysis

Consent of PricewaterhouseCoopers LLP

Consent of KPMG

Certification of CEO Pursuant to Rule 13a-14(a)

Certification of CFO Pursuant to Rule 13a-14(a)

Certification of CEO Pursuant to Rule 13a-14(b)

Certification of CFO Pursuant to Rule 13a-14(b)

SIGNATURES

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

INTEROIL CORPORATION
 

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chairman of the Board,
Chief Executive Officer and President 

Date: October 29, 2007

EXHIBIT INDEX

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

EXHIBIT
NUMBER	DESCRIPTION
1.	Revised Annual Information Form for the year ended December 31, 2006
2.	Revised Audited annual consolidated financial statements for the year ended December 31, 2006, including a reconciliation to United States generally accepted accounting procedures
3.	Revised SOA Section 404 (Management Report on Internal Controls over Financial Report) (included in Exhibit 2).
4.	Revised Management’s Discussion and Analysis for the year ended December 31, 2006
5.	Consent of PricewaterhouseCoopers LLP dated October 29, 2007
6.	Consent of KPMG dated October 29, 2007
7.	Credit Agreement between InterOil Corporation and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Clarion Finanz AG dated May 4 2006 (incorporated by reference to Exhibit 7 to the Company’s annual report in Form 40-F for the year ended December 31, 2006 and filed on March 30, 2007).
8.	Memorandum of Understanding between InterOil Corporation, Merrill Lynch and Clarion Finanz AG (incorporated by reference to Exhibit 8 to the Company’s annual report in Form 40-F for the year ended December 31, 2006 and filed on March 30, 2007).
9.	Loan Agreement between EP InterOil, Ltd. and Overseas Private Investment Corporation dated June 12, 2001, as amended (incorporated by reference to Exhibit 9 to the Company’s annual report in Form 40-F for the year ended December 31, 2006 and filed on March 30, 2007).
10.	Secured Revolving Crude Import Facility dated 14 August 2006 (incorporated by reference to Exhibit 10 to the Company’s annual report in Form 40-F for the year ended December 31, 2006 and filed on March 30, 2007).
11.	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
12.	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
13.	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
14.	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

Exhibit 1

InterOil Corporation
Revised Annual Information Form

For the Year Ended December 31, 2006
October 29, 2007

TABLE OF CONTENTS

General	1
Non-Gaap Measures	3
Legal Notice – Forward-Looking Statements	4
Corporate Structure	5
General Development Of The Business	8
Business Strategy	12
Description Of Our Business	15
Exploration And Production	15
Liquefaction, Refining And Marketing	20
Wholesale And Retail Distribution	24
Community Relations, Safety And The Environment	26
Risk Factors	28
Dividends	34
Description Of Our Capital Structure	35
Market For Our Securities	35
Directors And Officers	37
Board Committees	40
Interests Of Management And Others In Material Transaction	40
Legal Proceedings	41
Material Contracts	41
Transfer Agent And Registrar	44
Additional Information	47
Glossary Of Terms	48

GENERAL

The following Revised Annual Information Form (Revised AIF) should be read in conjunction with: the audited Revised Consolidated Financial Statements and Notes for the year ended December 31, 2006 and the 2006 Revised Management Discussion and Analysis. The Revised AIF was prepared by the management of InterOil with respect to our financial performance for the periods covered by the related interim financial statements, along with a detailed analysis of our financial position and prospects.

In this Revised AIF, references to “we”, “us”, “our”, “Company”, and “InterOil” refer to InterOil Corporation and its subsidiaries, unless the context requires otherwise. All dollar amounts are stated in United States dollars unless otherwise stated.

Annual Information Form   INTEROIL CORPORATION   1

As noted in the superseded consolidated financial statements for the Company for the year ended December 31, 2006 issued on March 30, 2007, Management has been liaising with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005. The queries were primarily in relation to the accounting treatment of the Indirect Participation Interest agreement # 3 as a conveyance in accordance with SFAS 19 – ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’. The SEC staff had also raised comments about other matters related to the accounting treatment of Indirect Participation Interest agreement # 3 such as the bifurcation of the derivative, the fair value methodologies applied and the application of accretion expense.

Based on discussions with the SEC staff, Management has restated the consolidated financial statements for the years ended December 31, 2006 and 2005 to reflect a revised model for the accounting treatment of non-financial liability relating to indirect participation interest. These revised consolidated financial statements reflect all changes that have been made in relation to the revised model for the accounting treatment of this non-financial liability in the balance sheet of InterOil as at December 31, 2006 and December 31, 2005, and the statements of operations, shareholders’ equity and cash flows for each of the years then ended. This Revised AIF will have the effect of superseding the previously issued revised Annual Information Form for year ended December 31, 2006 dated June 22, 2007.

For further details regarding the revisions made to the consolidated financial statements, and reconciliations of the restated and superseded balances, please refer note 2 of the revised consolidated financial statements for the year ended December 31, 2006.

Annual Information Form   INTEROIL CORPORATION   2

NON-GAAP MEASURES

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 InterOil 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 Canadian generally accepted accounting principles. Further, EBITDA is not a measure of cash flow under Canadian generally accepted accounting principles and should not be considered as such. The following table reconciles net income/(loss), to EBITDA, for each of the last eight quarters.

Quarters ended	2006 (restated)(2), (3)												2005 (restated)(1), (2)
($ thousands) (unaudited)	Dec 31			Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Earnings before interest, taxes, depreciation and amortization		6,873			1,370			(10,323	)		(12,014	)		(19,668	)		(8,192	)		(5,375	)		(4,346	)
Upstream		(719	)		(1,107	)		(1,922	)		(5,136	)		(16,464	)		(13,333	)		(1,134	)		(91	)
Midstream – Refining and Marketing		9,144			1,674			(8,188	)		(5,230	)		(6,333	)		6,070			(6,796	)		(3,405	)
Midstream – Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		1,143			1,954			3,559			(326	)		3,963			2,522			2,550			584
Corporate & Consolidated		(2,299	)		(853	)		(3,770	)		(1,322	)		(834	)		(3,451	)		5			(1,434	)
Subtract:
Interest expense		5,649			5,349			3,609			2,666			2,989			2,455			2,996			2,547
Upstream		2			1			1			1			(6	)		2			2			2
Midstream – Refining and Marketing		2,479			3,329			2,731			2,342			2,756			2,320			2,735			2,351
Midstream – Liquefaction		—			—			—			—			—			—			—			—
Downstream		37			38			39			38			44			42			140			—
Corporate & Consolidated		3,131			1,981			838			285			195			91			119			194
Income taxes & non-controlling interest		1,049			244			1,031			(245	)		910			1,000			301			253
Upstream		—			—			—			—			—			—			—			—
Midstream – Refining and Marketing		42			(46	)		(137	)		(118	)		(129	)		19			(333	)		81
Midstream – Liquefaction		—			—			—			—			—			—			—			—
Downstream		996			416			1,005			(144	)		1,062			965			570			159
Corporate & Consolidated		11			(126	)		163			17			(23	)		16			64			13
Depreciation & amortization		3,554			3,100			2,862			2,837			2,700			2,943			2,699			2,695
Upstream		233			202			173			198			96			213			2			3
Midstream – Refining and Marketing		2,805			2,700			2,626			2,598			2,662			2,663			2,641			2,632
Midstream – Liquefaction		—			—			—			—			—			—			—			—
Downstream		537			222			89			62			55			55			51			43
Corporate & Consolidated		(21	)		(24	)		(26	)		(21	)		(113	)		12			5			17

Annual Information Form   INTEROIL CORPORATION   3

Quarters ended	2006 (restated)(2), (3)												2005 (restated)(1), (2)
($ thousands) (unaudited)	Dec 31			Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Net income (loss) per segment(1)		(3,379	)		(7,323	)		(17,825	)		(17,272	)		(26,267	)		(14,590	)		(11,371	)		(9,841	)
Upstream		(954	)		(1,310	)		(2,098	)		(5,335	)		(16,554	)		(13,548	)		(1,138	)		(96	)
Midstream – Refining and Marketing		3,818			(4,309	)		(13,408	)		(10,052	)		(11,622	)		1,068			(11,839	)		(8,469	)
Midstream – Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		(427	)		1,278			2,426			(282	)		2,802			1,460			1,789			382
Corporate & Consolidated		(5,420	)		(2,684	)		(4,745	)		(1,603	)		(893	)		(3,570	)		(183	)		(1,658	)

(1)	Our comparative quarterly results for all quarters during 2005 and 2006 have been represented to confirm with the presentation adopted at December 31, 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(2)	Our September 2006 quarterly results have been represented to separate out our Midstream-Liquefaction segment from the Midstream Refining and Marketing segment.

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. 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 expanding our business segments, business strategy, contingent liabilities, environmental matters, and plans and objectives for future operations, future capital and other expenditures. By its very nature, such forward-looking information requires InterOil to make assumptions that may not materialize or that may not be accurate.

Each forward-looking statement reflects our current view of future events and is subject to known and unknown risks, uncertainties and other factors that could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties include, but are not limited to; the exploration and production, the refining and the distribution businesses are competitive; our refinery has not operated at full capacity for an extended period of time and our profitability may be materially affected if it is not able to do so; 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; if our refining margins do not meet our expectations and our refinery operations are not profitable; we may be required to write down the value of our refinery; our refinery financial condition may be materially adversely affected if we are unable to obtain crude feedstocks for our refinery; our refining operations expose us to risks, some of which are not insured; our hedging activities may incur losses; we may not be successful in our exploration for oil and gas; if we are unable to renew our petroleum licenses with the Papua New Guinea government, we may be required to discontinue our exploration activities in Papua New Guinea; our investments in Papua New Guinea are subject to political, legal and economic risks that could materially adversely affect their value; new legislative, administrative or judicial actions that constrain licenses and permits from various government authorities may have a material affect on the company’s operations; weather and unforeseen operating hazards may impact our operating activities; our significant debt levels and our debt covenants may limit our future flexibility in obtaining additional financing; our ability to recruit and retain qualified personnel may have a material adverse effect on our operating results and stock price; Petroleum Independent and Exploration Corporation can affect our raising of capital through the issuance of common shares or securities convertible into common shares; compliance with and changes in environmental laws could adversely affect our performance; you may be unable to enforce your legal rights against us; changing regulations regarding corporate governance and public disclosure could cause additional expenses and failure to comply may adversely affect our reputation and the value of our securities; and the risks described under the heading “Risk Factors” in our Annual Information Form.

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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.

Readers are cautioned that the foregoing list of important factors affecting forward-looking information is not exhaustive. Furthermore, the forward-looking information contained in this quarterly report is made as of the date of this report and, except as required by applicable law, InterOil does not undertake any obligation to update publicly or to revise any of the included forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained in this report is expressly qualified by this cautionary statement.

We currently have no production or reserves as defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. All information contained in this AIF regarding resources are references to undiscovered resources under Canadian National Instrument 51-101, whether stated or not.

CORPORATE STRUCTURE

InterOil Corporation was formed under the Business Corporations Act (New Brunswick).

Our registered office	Our corporate office
in Canada is located at:	in Australia is located at:
Brunswick House	Level 1, 60-92 Cook Street
10th Floor, 44 Chipman Hill	Portsmith, QLD 4870,
Saint John, NB E2L 4S6	Australia

We are a developing fully-integrated energy company whose focus is on operations in Papua New Guinea (“PNG”) and its surrounding region. We have four business segments:

Segments	Objective	Entity Shading
Upstream	Exploration and Production
Midstream	Liquefaction, Refining and Marketing
Downstream	Wholesale and Retail Distribution
Corporate	Corporate and Consolidations

We operate these business segments through various subsidiaries which have integrated shared management. Our material subsidiaries are described below. Unless otherwise noted, all of our subsidiaries are directly or indirectly 100% owned by InterOil Corporation.

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Upstream – Exploration and Production

S.P.I. Exploration and Production Corp. was incorporated in the Commonwealth of the Bahamas in 1998. S.P.I. Exploration and Production Corp. is a holding company that owns our upstream operating subsidiaries which hold exploration licenses and conduct exploration activities in Papua New Guinea. InterOil owns 9,999 (99.99%) of the outstanding ordinary shares of S.P.I. Exploration and Production Corp. and P.I.E. Group LLC, a Delaware limited liability company incorporated in 1996 that is controlled by Phil Mulacek, our Chief Executive Officer, owns 1 (0.01%) ordinary share of S.P.I. Exploration and Production Corp. Entities controlled by Gaylen Byker, one of our directors, also have an ownership interest in P.I.E. Group LLC.

Midstream – Liquefaction, Refining and Marketing

S.P. InterOil, LDC was incorporated in the Commonwealth of the Bahamas in 1996. S.P. InterOil, LDC is a holding company that owns our midstream operating subsidiaries. These operating subsidiaries own and operate our refinery located in Port Moresby, Papua New Guinea. The General Manager of S.P. InterOil, LDC is Petroleum Independent and Exploration Corporation (“P.I.E.”), a Texas corporation incorporated in 1981. Phil Mulacek, our Chief Executive Officer, is the President of, and owns an interest in P.I.E,. InterOil owns 20,152,870 (99.98%) and P.I.E. owns 5,000 (0.02%) of the outstanding ordinary shares of S.P. InterOil, LDC. We have entered into an agreement with P.I.E. to exchange, on a one-for-one basis, the 5,000 shares of S.P. InterOil, LDC that it holds for an equal number of shares of InterOil Corporation. P.I.E.’s ownership of these shares provided the U.S. content necessary for us to obtain $85 million in project financing from the Overseas Private Investment Corporation (“OPIC”), an agency of the U.S. Government. The proceeds of this financing were used to construct our refinery in Papua New Guinea.

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EP InterOil, Ltd. was incorporated in the Cayman Islands in 1996. EP InterOil, Ltd. was used to finance the development of our refinery and is currently used for additional financing purposes. EP InterOil, Ltd. owns InterOil Limited, the operating subsidiary that owns our refinery. S.P. InterOil, LDC owns 100% of the voting ordinary shares and, as of March 31, 2006, owned 82.0 million (98.9%) of the non-voting ordinary shares of EP InterOil, Ltd. Enron Papua New Guinea Limited, a wholly-owned subsidiary of Enron, owns 897,542 (1.1%) of the non-voting ordinary shares of EP InterOil, Ltd. Enron Papua New Guinea Limited has decided that the refinery is not consistent with its corporate objectives and it has abandoned any further financing of the refinery. Enron Papua New Guinea Limited’s interest is anticipated to be diluted on an ongoing basis as we contribute more equity to EP InterOil, Ltd.

InterOil Limited was incorporated in Papua New Guinea in 1994. InterOil Limited owns and operates our refinery in Port Moresby, Papua New Guinea.

PNG LNG, Inc. was incorporated in the Commonwealth of the Bahamas in 2006. InterOil Corporation owns 100% of the outstanding ordinary shares of PNG LNG, Inc. Liquefied Nuigini Gas Ltd, which was incorporated in Papua New Guinea in 2006, is 100% owned by PNG LNG, Inc. Liquefied Nuigini Gas Ltd is currently involved in a project developing a Liquefied Natural Gas (“LNG”) business in Papua New Guinea.

Downstream – Wholesale and Retail Distribution

S.P.I. Distribution Limited was incorporated in the Commonwealth of the Bahamas in 2001. S.P.I. Distribution Limited is a holding company that owns our operating subsidiaries which in turn, own our wholesale and retail distribution operations, including InterOil Products Limited. InterOil Corporation owns 9,999 (99.99%) of the outstanding ordinary shares of S.P.I. Distribution and P.I.E. Group LLC, a Delaware limited liability company controlled by our Chief Executive Officer, owns 1 (0.01%) ordinary share of S.P.I. Distribution Limited .

InterOil Products Limited (formerly BP Papua New Guinea Limited) was incorporated in Papua New Guinea in 1969. We acquired InterOil Products Limited, which owns and operates our petroleum products distribution, wholesale and retail business in Papua New Guinea, in 2004. In 2006, InterOil Products Limited acquired Shell Papua New Guinea Ltd., whose name was then changed to IPL (PNG) Limited. IPL (PNG) was originally incorporated in Papua New Guinea January 6, 1977.

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GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History

The following is a summary of significant events in the general development of InterOil’s business over the past three years.

2006

In 2006, InterOil undertook a number of activities to optimize and expand on its existing business assets.

Upstream

In the upstream segment, the year was dominated by the drilling of the Elk-1 well on the Elk structure in the Eastern Papua Basin in Papua New Guinea. We commenced drilling in February 2006 using our purpose built heli-portable rig. The rig, which was acquired in 2005, has allowed us to explore for oil and gas at a time when there have been significant delays worldwide due to the prevailing shortage of suitable drilling equipment.

The Elk-1 discovery well was completed on November 23, 2006. We currently have four exploration licenses and two retention licenses covering approximately nine million acres that are the focus of our exploration activities. We have funded our exploration efforts through indirect participation interest agreements, pursuant to which agreements, investors are not required to spend any additional amounts to drill the exploration wells drilled in connection with the agreements. Investors currently have the right to approximately a 31.55% working interest in any exploration wells drilled and, in any resulting fields by paying their share of all testing and development costs, including the costs of all development wells drilled.

Midstream

During 2006, we completed the revamp of our refinery which began in the second quarter of 2006. The revamp, which was completed in the third quarter of 2006, has resulted in production economies at our refinery in Papua New Guinea. In addition, the refinery team has concentrated on optimizing the crude being processed in order to obtain higher yields of distillates, which are higher margin products. The revamp and crude optimization efforts have resulted in an improving EBITDA figures for our midstream segment in the third and fourth quarters of 2006.

In May 2006, InterOil entered into a Memorandum of Understanding (“MOU”) with the Government of Papua New Guinea for natural gas development projects in Papua New Guinea pursuant to which InterOil will assist in the domestic processing of natural gas in Papua New Guinea. This memorandum of understanding is subject to a binding agreement to be negotiated. In May 2006, InterOil entered into a tri-party agreement with Merrill Lynch Commodities (Europe) Limited and an affiliate of Clarion Finanz AG that resulted in the formation of the National Gas Development Company, which will seek to build and develop a liquid natural gas (“LNG”) facility in Papua New Guinea.

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Downstream

For our downstream business, January 2006 began with InterOil entering into an agreement with Shell Overseas Holdings Limited (“Shell”) to indirectly purchase all of Shell’s retail and distribution assets in Papua New Guinea. The closing of this transaction was subject to the approval of several governmental authorities in Papua New Guinea, and closed effective October 1, 2006. The net purchase price of this business was $25.8 million, which is subject to working capital adjustments. The Shell asset portfolio is a distribution network that comprises 4 terminals, 3 depots and 28 retail sites.

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 storage availability. The East Sepik province has experienced substantial growth in commercial and economic activity in recent years and this additional infrastructure will place us in a strong position to continue to service the needs of that market.

Financing

In 2006, InterOil undertook the following financing transactions:

ü	In May 2006, InterOil entered into a secured credit agreement for $130.0 million. The loan is divided into two tranches. Tranche 1, which represents $100.0 million of the facility, was available for drawdown from the time the agreement was signed. Tranche 2 drawdown was dependent upon milestones being reached with relation to the prospective building of a liquefied natural gas processing facility in Papua New Guinea. The full balance of the loan is repayable in May 2008. The interest rate payable on the loan is 4% from May 2006 and ending in March 2007. Between March 2007 and the end of the facility, the interest rate will be 10% unless a definitive Project Agreement is executed by InterOil and the lenders on or before March 2007. If the Project Agreement is delivered on or before March 2007, the interest rate will continue to be 4% for the full life of the loan. The loan was fully drawn down as at December 31, 2006.
ü	In May 2006, we repaid $25.0 million in unsecured borrowings (see January 2005 financing transactions under our, unsecured term loan facility, below).
ü	In May 2006, we entered into an agreement to amend the terms of the original PNG Drilling Ventures Limited, Agreement, whereby, PNG Drilling Ventures Limited converted their interest under the agreement into 575,575 InterOil common shares and also retained a 6.75% interest in the next four wells (the first of which is Elk-1) to be drilled by InterOil. PNG Drilling Ventures also has the right to participate in the 16 wells that follow the first four mentioned above up to an interest of 5.75% by contributing their share of costs.
ü	In August 2006, the credit limit under the BNP facility entered into in 2004 was increased to $170.0 million. The credit limit is comprised of a $130.0 million facility to provide letters of credit and short term loans to finance the purchase of crude cargoes and bank guarantees to facilitate hedging and a $40.0 million facility that allows us to discount eligible U.S. dollar receivables and fully cash back loans under the first facility.
ü	In December 2006, we renegotiated the terms of the OPIC secured loan where the half yearly principle payment due in December 2006 and June 2007 of $4.5 million each, have been deferred until December 31, 2007 and interest previously due on December 31, 2006 and June 30, 2007 were deferred until September 30, 2007. The normal repayment of interest and principal will recommence on September 30, 2007 and December 31, 2007, respectively.

Management Team

During 2006 the management team had the following movements

ü	Effective July 1, 2006, Dr Jack Hamilton was appointed as President of InterOil.
ü	On August 3, 2006, InterOil announced that Tom S. Donovan, Chief Financial Officer of InterOil had completed his employment agreement on July 31, 2006.

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ü	On August 30, 2006, InterOil announced that William J. Jasper III was appointed as President and Chief Operating Officer of InterOil. At this time, it was agreed that Christian Vinson, the former Chief Operating Officer, would focus on corporate development and government relations in Papua New Guinea and Dr. Jack Hamilton, the former President, was nominated by InterOil to serve as Chief Executive Officer of the recently formed PNG LNG Inc., which is the vehicle used to develop the proposed LNG facility adjacent to the InterOil refinery in Papua New Guinea.
ü	On October 1, 2006, Dr. Michael Folie retired as a director of InterOil for personal reasons.
ü	On October 26, 2006, Collin F Visaggio was appointed as Chief Financial Officer of InterOil.
ü	On December 29, 2006, Don R. Hansen was appointed as an independent director of InterOil and also agreed to serve as a member of the Audit and Compensation Committees of InterOil’s board of directors.

2005

Upstream

In 2005, our upstream business completed two exploration wells and a regional phase of 2D seismic acquisition in Petroleum Prospecting License 238 and an extensive airborne gravity and magnetic survey in Petroleum Prospecting Licenses 237 and 238 in Papua New Guinea. In addition, in October 2005, we acquired a purpose built heli-portable drilling rig that we plan to use to drill our future wells. The rig cost $7.6 million and is capable of drilling to depths of up to 13,500 feet.

Midstream

In January 2005, our midstream business announced the practical completion of our refinery in Papua New Guinea. Our refinery is rated to process up to 32,500 barrels of oil per day. The project agreement that we executed with the government of Papua New Guinea in May 1997 will provide us with tax benefits until December 31, 2010 and with other market privileges for a period of 30 years from the date of practical completion. We have executed an agreement with BP Singapore Pte Limited to act as the crude supplier for our refinery. Our agreement with BP Singapore does not expire until June 2009. In the second quarter of 2005, we commenced a refinery optimization program.

Financing

In 2005, InterOil undertook the following financing transactions:

ü In January 2005, we entered into a $20.0 million unsecured term loan facility. The interest rate on this loan is 5%. In July 2005, we increased the availability under this loan facility to $25.0 million. Borrowings under this facility are due 15 months after all funds are disbursed. As of December 31, 2005, $3.5 million remained available for future borrowings under this facility. (See May, 2006 for information regarding repayment of this loan)

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ü	In February 2005, we entered into an amended and restated indirect participation agreement with institutional accredited investors in which the investors paid us a total of $125.0 million and we agreed to drill eight exploration wells in Papua New Guinea. See “Indirect Participation Interest Agreements”.
ü	In August 2005, the secured revolving crude import facility with BNP Paribus initially entered into in March 2004, was increased to $150.0 million. At December 31, 2005, $44.0 million remained available for use.
ü	As of December 31, 2005, PNG Drilling Ventures Limited had converted $2.5 million of their investment into 141,545 of our common shares pursuant to an indirect participation interest agreement. See “Indirect Participation Interest Agreement”.

2004

Upstream

Our upstream business completed drilling Moose-2, which was commenced late in 2003 and also drilled Sterling Mustang. In 2004, our upstream business also completed seismic program across the Puri, Elk and Moose Prospects.

Midstream

In 2004, our midstream business continued the construction of our refinery in Papua New Guinea. In June 2004, the first crude was delivered to the refinery for processing during the commissioning of the refinery. In August 2004, we made our first sale of product from our refinery.

Downstream

In 2004, our downstream business also earned its first operating revenue after acquiring BP Papua New Guinea Limited, a distributor of refined petroleum products in Papua New Guinea, for $13.2 million in April. The assets held by BP Papua New Guinea Limited included existing inventories, three larger depots and seven terminals, and contracts to supply refined petroleum products to more than 30 independently-operated retail stations. Following the acquisition, we changed the name of this entity to InterOil Products Limited. InterOil Products Limited owns and operates our wholesale and retail distribution business in Papua New Guinea.

Financing

In 2004, InterOil undertook the following financing transactions:

ü In March 2004, we received an additional $3.2 million from PNG Drilling Ventures Limited for our second indirect interest participation agreement program. This, together with funds received in 2003, made the total contribution under the drilling participation agreement with PNG Drilling Ventures $12.2 million.

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ü	In May 2004, PNG Energy Investors converted their $7.7 million indirect participation interest into 683,140 common shares of InterOil.
ü	In July 2004, our common shares commenced trading on the Toronto Stock Exchange.
ü	In September 2004, our common shares commenced trading on the American Stock Exchange.
ü	In the third quarter of 2004, we issued $45.0 million in 8.875% senior convertible debentures due 2009 that were subsequently converted into 2.4 million common shares. We also issued warrants to acquire 359,415 common shares at a price of $21.91. The warrants have a five year term. As of December 31, 2006, warrants to purchase 340,247 common shares remained outstanding.

BUSINESS STRATEGY

InterOil’s strategy is developing a vertically integrated world class energy company in Papua New Guinea and the 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 value to the communities in which InterOil operates. InterOil has taken a three-pronged approach when planning to achieve this strategy.

Capitalize On and Expand the Existing Business Assets

Our refinery team focused on optimization efforts to improve the profitability of our refinery, this has resulted in a positive EBITDA in the third quarter 2006 of $1.7 million and fourth quarter of 2006 of $9.1 million. Our ongoing crude selection efforts and recent refinery revamp have increased the percentage yield of jet fuel and diesel, commonly referred to as middle distillates, produced by our refinery in relation to the amount of naphtha and low sulfur waxy residue produced per barrel of crude feedstock processed. This has allowed us to process fewer barrels of crude feedstocks to meet growing middle distillate demand to the Papua New Guinea domestic market. Middle distillates that we sell to the domestic Papua New Guinea market improve gross margin whereas export naphtha and low sulfur waxy residue reduce gross margin. As part of the revamp activities, we installed new generators powered by low sulfur waxy residue and made modifications to the furnaces and boilers to also operate on low sulfur waxy residue. The refinery optimization works have improved the product slate, improved reliability and reduced fuel costs.

Our downstream business has expanded its existing product line to include the distribution of low sulfur waxy residue, which is marketed in Papua New Guinea as InterOil Power Fuel (IPF) to Papua New Guinea’s Moitaka Power Station. The downstream business secured this business late in 2006 after InterOil conducted a trial with the Moitaka management to demonstrate the benefits of IPF in running the generators at the power station.

In 2007, InterOil’s priorities for capitalizing and expanding on existing business assets will include continuing to improve the refinery’s profitability using a disciplined approach to costs, evaluating improvements, modifications and additional equipment to improve flexibility and profitability of the refinery, and looking to increase the domestic market for IPF. The upstream business will continue to evaluate the potential gas and condensate discovery at the Elk location by drilling the appraisal well Elk-2 and conducting a 100-mile appraisal seismic program. In addition, we expect to drill an exploration well in Petroleum Retention License 5 and to re-enter and test the Stanley discovery in Petroleum Retention License 4 along with our joint venture partners in these licenses. The downstream business will focus on the further integration of the recently acquired Shell business into the existing distribution business to achieve economies of scale and synergies.

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Target Acquisitions and Growth Opportunities in Papua New Guinea and the Surrounding Area

In 2006, InterOil completed the acquisition of the Shell PNG Limited business. The addition of these assets to our distribution business on October 1 has made us the leading wholesale and retail distributor of hydrocarbons in Papua New Guinea.

During 2007, InterOil will continue to evaluate other potential opportunities in the wholesale and resale distribution business segment in Papua New Guinea and the surrounding area. In particular, the company is examining potential complementary business acquisitions and petroleum exports.

Our business strategy and operating plan has evolved to include as a primary business objective, the development of an onshore liquefied natural gas processing facility that will be built and operated at Napa Napa adjacent to our refinery. In May, InterOil signed a Memorandum of Understanding with the Independent State of Papua New Guinea for natural gas development projects in Papua New Guinea and a tri-party agreement with Merrill Lynch Commodities (Europe) Limited and an affiliate of Clarion Finanz AG related to the same. This objective received additional impetus with the potential gas discovery at Elk which will be appraised during 2007. During 2007 the company anticipates entering into a shareholder agreement relating to the LNG project and progressing development activities relating to the financing and construction of the infrastructure.

Position InterOil for Long-Term Oil and Gas Business Success

In 2006 our upstream business has made a potential natural gas and condensate discovery at the Elk location on Petroleum Prospecting License 238. The Company also increased its ownership in Petroleum Retention Licenses 4 and 5, which contain pre-existing gas and condensate discoveries of Stanley, Ketu and Elevala.

We currently have four exploration licenses and two retention licenses in Papua New Guinea covering approximately nine million acres of which amount, approximately 8.2 million nett acres are operated by InterOil. In 2006, our seismic acquisition program surveyed a total of 79 miles, all in Petroleum Prospecting License 238 using 2D seismic at a cost of $5.2 million. The 2006 seismic program complemented the 136 miles of seismic program that we acquired during the previous three years. As of December 31, 2006, we had acquired over 1,000 miles of 2D seismic data covering Petroleum Prospecting Licenses 236, 237 and 238, including the 215 miles we have recorded since acquiring these licenses. In addition to our seismic acquisition program, during 2006 we conducted 2,471 miles of airborne gravity and magnetic surveys in Petroleum Prospecting License 237 and 3,773 miles in Petroleum Prospecting License 238. Airborne gravity and magnetic methods have enabled us to better identify the quality of leads derived from surface geology, to identify previously unmapped leads and to optimize the location of our 2D seismic programs.

During 2007 we plan to conduct a detailed 2D seismic survey over the Elk discovery and leads on-trend with the Elk discovery that have been identified from seismic data and airborne gravity and magnetic surveys acquired by the Company to date.

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Summary of Strategic Priorities

Following is a table outlining the Company’s progress towards the strategic priorities of the Company and its goals for 2007.

Strategic
Priorities	2006 Progress	2007 Initiatives
Capitalize on and Expand on the Existing Business Assets	ü   Completed refinery optimization project, which included the installation of new generators powered by low sulfur waxy residue and modifications of the furnaces and boilers to improve reliability and reduce fuel costs. ü   Secured a contract to provide InterOil Power Fuel to Papua New Guinea’s Moitaka Power Station.	ü   Evaluate feasibility of improvements, modifications and additional equipment to improve flexibility and profitability of the refinery. ü   Continue to seek out potential markets for InterOil Power Fuel and distillate export opportunities to increase contribution to fixed costs. ü   Cost reduction program targeting 10% reduction.
Target Acquisitions and Growth Opportunities in Papua New Guinea and the Surrounding Area	ü   Finalized the terms of acquisition for Shell Papua New Guinea’s distribution network. The Shell Papua New Guinea business was transferred to InterOil on October 1. ü   Examined other potential downstream growth opportunities. ü   Progressed discussions for liquefied natural gas opportunity in Papua New Guinea with government and other potential partners.	ü   Pursue opportunities to purchase a business or assets in the business of distributing fuel to the aviation sector. ü   Pursue other potential downstream growth opportunities. ü   Sign a project agreement relating to the LNG opportunity in Papua New Guinea and begin taking steps to advance project. ü   Finalize investment decision and development plans for LNG project.
Position InterOil for Long-Term Oil and Gas Business Success	ü   Made potential gas and condensate discovery at Elk location on existing Petroleum Prospecting License 238. ü   Conducted seismic and airborne gravity and magnetic surveys on licenses to expand knowledge base of existing prospects and to identify new prospects.	ü   Obtain further information about the Elk structure by drilling the Elk-2 appraisal well and conducting 100 miles of appraisal seismic. ü   Conduct detailed 2D seismic surveys over the Elk discovery and lead on-trend with the Elk discovery that have been identified from seismic data and airborne gravity/magnetic surveys acquired by the company to date.

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DESCRIPTION OF OUR BUSINESS

Overview

Our operations are organized into four major business segments:

Segments	Operations
Upstream	Exploration and Production – Explores and appraises potential oil and gas bearing structures in Papua New Guinea with a view to commercializing discoveries.
Midstream	Liquefaction, Refining and Marketing – Markets the refined products it produces in Papua New Guinea both domestically and for export. Since early 2006, our business plan and operating strategy has evolved to include as a business objective, the development of an onshore liquefied natural gas processing facility in Papua New Guinea.
Downstream	Wholesale and Retail Distribution – Distributes refined products in Papua New Guinea on a wholesale and retail basis.
Corporate	Corporate and Consolidations – 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. Our corporate segment results also include consolidation adjustments.

As of December 31, 2006, we had 551 full-time employees comprising: 48 in our upstream segment, 104 in our midstream segment, 353 in our downstream and 46 in our corporate segment.

EXPLORATION AND PRODUCTION

InterOil does not have any reserves and does not have any oil or gas production or related future net revenue.

We currently have four exploration licenses and two retention licenses in Papua New Guinea covering approximately nine million acres of which amount, approximately 8.2 million nett acres are operated by InterOil. Petroleum Prospecting Licenses 236, 237 and 238 are located in the Eastern Papuan Basin northwest of Port Moresby. We own a 100% working interest in, and our current exploration efforts are focused on, these three licenses. Our indirect participation interest investors have the right to a 31.55% working interest in the exploration wells currently being drilled and any resulting fields. These investors have a 31.55% interest in the next three exploration wells and a 24.8% interest in the two subsequent exploration wells. In addition, we own a 15% working interest in Petroleum Prospecting License 244, located offshore in the Gulf of Papua. As of December 31, 2006, we also owned a 43.13% working interest in Petroleum Retention Licenses 4 and a 28.576% working interest in Petroleum Retention License 5. All of InterOil’s oil and gas properties are located onshore in Papua New Guinea.

Petroleum License Details

Traditionally, exploration for oil and gas in Papua New Guinea has focused on the western part of the country. The majority of our exploration acreage in located in the Eastern Papuan Basin in Papua New Guinea. Each of our six licenses in Papua New Guinea is described below.

In general, the initial term a petroleum prospecting license is five years. Petroleum prospecting licenses may be renewed for an additional six years. However, 50% of the license area must be surrendered in order to obtain the renewal.

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Each petroleum prospecting license in Papua New Guinea requires a bond backed by a bank guarantee of approximately $33,000, an annual license fee and annual work and expenditure commitments as set by the Minister for Petroleum and Energy under the license conditions. Petroleum prospecting licenses are granted for an initial term of six years. The aggregate annual license fee for Petroleum Prospecting Licenses 236, 237 and 238 for 2006 was approximately $60,000. We are required to submit to the government of Papua New Guinea for approval a work program that includes our exploration plans and minimum expenditures every two years. Under our existing work commitments, we have no additional well obligations in any of our operated petroleum prospecting licenses through the end of March 2007. Our minimum biannual expenditure requirements for all of our petroleum prospecting license areas have been met through March 2007. We submitted our proposed work programs for the final two year period of each license to the Department of Petroleum and Energy in January 2007 and are awaiting approval. The work programs, if approved as submitted, total $20 million in minimum expenditures and consist of one well in each license and seismic programs in Petroleum Prospecting Licenses 237 and 238.

Petroleum retention licenses may be granted to licensees of petroleum prospecting licenses in which gas fields or parts of gas fields have been discovered to permit time for the licensee to develop commercialization alternatives for the gas discoveries. Petroleum Retention Licenses 4 and 5 were carved out of Petroleum Prospecting License 157 as a result of the Stanley, Elevala and Ketu gas discoveries We participated directly in drilling Stanley but Elevala and Ketu were drilled by the licensees from whom we acquired our working interest in Petroleum Prospecting License 157 prior to our entering into the license. The initial period of a petroleum retention license is for five years and an extension of five years may be granted. In connection with an application for, or a renewal of, a petroleum retention license, we are required to submit a one year work program and a work program for the remaining four years that is contingent on the results of the first year’s operations.

Petroleum Prospecting License 236

We have a 100% working interest in Petroleum Prospecting License 236, subject to elections made by holders of indirect participation interests described below, and are the operator of the license. This license was granted to us on March 28, 2003. We drilled an exploration well in this area in 2005 that satisfied the well obligation for this license through March 2007. 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 does have 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.

Petroleum Prospecting License 237

We have a 100% working interest in Petroleum Prospecting License 237, subject to elections made by holders of indirect participation interests described below, and are the operator of the license. This license was granted to us on March 28, 2003. We drilled an exploration well in this area in 2005. In 2006, we carried out an airborne gravity/magnetic survey consisting of 2,471 miles over the western and southern parts of this license.

Petroleum Prospecting License 238

Each petroleum prospecting license in Papua New Guinea requires a bond backed by a bank guarantee of approximately $33,000, an annual license fee and annual work and expenditure commitments as set by the Minister for Petroleum and Energy under the license conditions. We have a 100% working interest in Petroleum Prospecting License 238, subject to elections made by holders of indirect participation interests described below, and are the operator of the license. This license was granted to us on March 7, 2003. We drilled our first three exploration wells in this area. During 2006, we conducted an airborne gravity/magnetic survey consisting of 3,773 miles over the northern part of this license and conducted 79 miles of 2D seismic. Our Elk-1 well, which we commenced drilling in February 2006, will satisfy the well obligation for this license through March 2007.

Petroleum Prospecting License 244

We have a 15% working interest in Petroleum Prospecting License 244. Talisman Oil Ltd. is the operator of this license. This license was granted to us on February 25, 2005. This license is located offshore Papua New Guinea in the Gulf of Papua.

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Petroleum Retention License 4

We had a 43.13% working interest in Petroleum Retention License 4 at December 31, 2006. This license was granted to us on September 1, 2000. An application for a five year extension of the term of this license was submitted on August 26, 2005, but we have not yet received an approval of this extension request. This license is located in western Papua New Guinea. This license contains the Stanley-1 gas discovery well. During 2005, Santos Nuigini Exploration Ltd., the prior operator of this license, withdrew from this license and was replaced by Trans-Orient Petroleum (PNG) Limited. Also during 2005, Greenslopes Limited and Carnavon Petroleum Limited announced their intent to sell their interests in Petroleum Retention Licenses 4 and 5. We exercised our preemptive rights in connection with these transfers and the transfers were completed during 2006 which led to an increase in our working interest in Petroleum Retention License 4 from 20% to 43.13%.

Petroleum Retention License 5

We had a 28.576% working interest in Petroleum Retention License 5 at December 31, 2006. Santos Niugini Exploration Pty Limited is the operator of this license. This license was granted to us on February 15, 2000 and was renewed for an additional five year term on February 15, 2005. This license is located in western Papua New Guinea and contains the Elevala and Ketu gas discovery wells. As a result of the exercise and subsequent government approval of the preemptive rights discussed above, our working interest in Petroleum Retention License 5 increased from 20% to 28.576% during 2006.

2006 Exploration Activities

We are currently engaged in an eight well exploration program covering Petroleum Prospecting Licenses 236, 237 and 238 that was commenced in April 2005. During 2006, we drilled one well under this program and anticipate drilling an additional five wells by the end of 2008. In February 2006, we commenced drilling the Elk-1 well on Petroleum Prospecting License 238. On June 11, 2006 this well encountered high pressure gas at a depth of 5,543 feet and was shut in while well control equipment was mobilized to the site. Well control operations and reconfiguration of the rig were undertaken to enable managed pressure drilling and we resumed drilling the Elk-1 well on September 15, 2006. The well reached a total depth of 6,504 feet on October 7, 2006. A drill stem test was performed and wireline logs were acquired in the interval 5,379 to 6,087 feet. The data obtained from these operations indicate the possibility of a large gas accumulation. The well was completed as a potential producer on November 23, 2006. The Elk-2 well was spudded in the first quarter of 2007 to appraise the Elk-1 discovery.

In 2006, our seismic acquisition program surveyed a total of 79 miles, all in Petroleum Prospecting License 238 using 2D seismic methods at a cost of $5.2 million. The 2006 seismic program complemented 136 miles of seismic that we recorded during the previous three years. As of December 31, 2006, we had acquired over 1,000 miles of 2D seismic data covering Petroleum Prospecting Licenses 236, 237 and 238, including the 215 miles we have recorded since acquiring these licenses. During the first quarter of 2007, we mobilized a seismic crew to conduct a detailed 2D seismic survey over the Elk discovery and leads on-trend with the Elk discovery that have been identified from seismic data and airborne gravity/magnetic surveys acquired by InterOil.

In addition to our seismic acquisition program, during 2006, we conducted 2,471 miles of airborne gravity and magnetic surveys in Petroleum Prospecting License 237 and 3,773 miles in Petroleum Prospecting License 238. Airborne gravity and magnetic methods have enabled us to better identify the quality of leads derived from surface geology, to identify previously unmapped leads and to optimize the location of our 2D seismic programs.

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Oil and Gas Wells

We did not have an interest in any oil wells or producing gas wells as of December 31, 2006. The following table sets out the number and status of non-producing gas wells in which we have a working interest as of December 31, 2006. InterOil does did not have any interests in any non-producing oil/gas wells as at December 31, 2006.

Working Interest in Non Producing Gas Wells

Location	Gross		Net
Papua New Guinea		5		3

Properties with No Attributed Reserves

All of InterOil’s properties are unproved properties, all of which are located in Papua New Guinea. The following table sets out our undeveloped land holdings as of December 31, 2006.

Undeveloped Acres

Location	Gross		Net
Papua New Guinea		8,981,232		8,223,614
Total		8,981,232		8,223,614

Abandonment and Reclamation

Our abandonment and reclamation costs for all of our current licenses are estimated to be $80,000. These costs consist of the costs to rehabilitate two drilling locations that still need additional surface rehabilitation and are based on the costs we have incurred rehabilitating similar properties.

Costs Incurred

The following table summarizes the capital expenditure related to our exploration activities for the year ended December 31, 2006.

Expenditure	Amount ($ millions)
Property Acquisition Costs		0.3
Proved Properties		—
Undeveloped Properties		0.3
Exploration Costs		48.0
Development Costs		—
Total Expenditure		48.3

Tax Horizon

Since we have not generated any income from our exploration activities, we have not paid any income taxes with respect to such activities. We do not know when or if we will incur income taxes related to our oil and gas exploration and development activities.

Exploration and Development Activities

The following table sets out the results of our exploration activities during 2006. We did not have any development wells in 2006.

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Undeveloped Wells

Type	Gross		Net
Oil		—		—
Gas		1		0.68
Service		—		—
Dry		—		—
Total		1		0.68

Indirect Participation Agreements

In February 2005, we entered into an agreement with institutional accredited investors in which the investors paid us an aggregate of $125 million and we agreed to drill eight exploration wells in Papua New Guinea on Petroleum Prospecting Licenses 236, 237 and 238. When we choose to test or complete any of these wells, the investors have the right to a 25% working interest by paying their share of a budgeted testing amount. If the tested or completed well is a commercial success, the investors, by continuing to pay their 25% share of all future appraisal and development costs, such as seismic, development drilling, production facilities and pipelines, retain their right to a 25% working interest in the resulting field and production. In addition, between June 15, 2006 and 90 days after the drilling of the eighth exploration well, each investor may elect to convert its interest under the agreement into our common shares. An investor’s interest, or any portion thereof, may be converted into a number of common shares equal to the amount paid by the investor for its interest divided by $37.50. If all of the investors converted their entire indirect participation interest into common shares, we would be obligated to issue 3,333,334 common shares.

In May 2006, we entered into an agreement to amend the terms of the original indirect participation interest agreement signed with PNG Drilling Ventures in 2003. Under the amendment, PNG Drilling Ventures Limited (PNGDV) converted their remaining balance into InterOil common shares and also retained a 6.75% interest in the next four wells (the first of which is Elk-1). Like the above indirect participation interest, when we choose to test or complete any of these wells, the investors have the right to a 6.75% working interest by paying their share of the costs. PNGDV also has the right to participate in the 16 wells that follow the initial four wells up to an interest of 5.75%. The cost of participation in the additional sixteen wells is $112,500 per 1% per well, subject to target depths and expected expenditure.

In addition to the above, PNG Energy Investors (PNGEI), an indirect participation interest investor, that converted all of its interest to common shares in fiscal year 2004, has the right to participate up to a 4.25% interest in wells nine to 24. In order to participate, PNGEI would be required to contribute a proportionate amount of drilling costs related to these wells.

Strategic Priorities

Following is a table outlining the upstream segments progress towards the strategic priorities of the Company and its goals for 2007.

Strategic
Priorities	2006 Progress	2007 Initiatives
Target Acquisitions and Growth Opportunities in Papua New Guinea and the Surrounding Area	ü   Acquired additional interest in PRL 4 and PRL 5 during the year.	ü    Evaluate productive potential of the Stanley gas discovery in PRL 4 ü   Drill Elevala-2 appraisal well in PRL 5 ü   Complete evaluation of prospectivity of PPL 244. ü   Participate in the Papua New Guinea offshore bid round

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Strategic
Priorities	2006 Progress	2007 Initiatives
Position InterOil for Long-Term Oil and Gas Business Success	ü   Natural gas and condensate discovery at Elk location on existing PPL 238. ü   Conducted seismic and airborne gravity and magnetic surveys on licenses to expand knowledge base of existing leads and prospects and to identify new leads and prospects. ü   Modified InterOil’s Rig 2 to enable drilling into similar reservoir conditions encountered in Elk-1.	ü   Further define the Elk structure and reservoir by drilling the Elk-2 appraisal well and conducting 100 miles of appraisal seismic. ü   Conduct detailed 2D seismic surveys over the Elk discovery and Big Horn structure on-trend with the Elk discovery. ü   Drill Antelope-1 new structure south of Elk. ü   Prove up sufficient gas reserves to support the construction of a pipeline and liquefaction plant in Papua New Guinea.

LIQUEFACTION, REFINING AND MARKETING

Refining and Marketing

Our refinery located across the harbor from Port Moresby, the capital city of Papua New Guinea is the sole refiner of hydrocarbons in Papua New Guinea. Under our 30 year agreement with the Government of Papua New Guinea, the government has undertaken to ensure that all domestic distributors purchase their refined petroleum product needs from the refinery, or any refinery which is constructed in Papua New Guinea, at an Import Parity Price. (See “Marketing” for the definition of Import Parity Price). Our refinery’s output is sufficient to meet 100% of the domestic demand for the refined products we produce in Papua New Guinea. Jet fuel, diesel and gasoline are the primary products that we produce for the domestic market. The refining process also results in the production of naphtha and low sulfur waxy residue. To the extent that we do not convert this naphtha to gasoline, we export it to the rapidly growing Asian markets in two grades, light naphtha and mixed naphtha, which are predominately used as petrochemical feedstocks. Low sulfur waxy residue can be sold as fuel and is valued by more complex refineries as cracker feedstock.

Refinery Optimization

We completed an optimization program at our refinery in the second half of 2006, which has 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 revamp 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. The installation was effected on time and within the budget allowed for, in July 2006. These new generators have the distinct advantage that they can use the low sulfur waxy residue produced at our refinery, as a power fuel.

We performed a 30-day complete site turnaround and inspection at our refinery in June and July 2006 to facilitate the conversion of the existing crude distillation furnaces to burn low sulfur waxy residue, as their primary fuel, and to increase their overall fuel efficiency.

During the fourth quarter of 2006, a major operational reorganization took place that has resulted in cost savings and improved efficiencies at our refinery. We expect that these measures will result in the reduction in our refinery’s operating fixed costs by between 10% to 15% per annum.

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As discussed below under, (“Crude Supply and Throughput”), we evaluated multiple crude feedstocks to determine which feedstocks will allow us to achieve our target mix of refined products. These crude selection efforts were an integral part of our refinery optimization efforts. While we will continue to evaluate alternative crudes, we identified several crude feedstocks that now allow us to achieve our target production slate. In addition to our crude selection and ongoing optimization program, KBC Advanced Technologies a leading independent consulting and technology group, identified low cost modifications and assisted our staff in proving that we can run the crude unit at 27,500 bpd using low gas crude as feedstock, without major capital investment. This throughput allows us to meet the local demand and to potentially supply refined product to selected export sectors.

Facilities and Major Subcontractors

We have 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 meters) and has been designed to accommodate 12,000 to 110,000 dwt crude and product tankers. Our smaller berth can accommodate ships with a capacity of up to 20,500 dwt. Our tank farm has the ability to store approximately 750,000 barrels of crude feedstocks 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 accommodations and a fire station.

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 operation of the refinery and terminated the Petrofac contract. Our management of the refinery allows us to better control the costs and performance of the facilities.

Our refinery’s on-site laboratory is staffed and operated by an independent company, SGS Australia Pty Ltd. (“SGS”), which is an ISO 9000 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 whereby (“BP”) is the exclusive supplier of crude feedstocks to our refinery. This agreement runs through to 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 feedstocks for our refinery. Our contract with BP limits our ability to purchase directly from producers or from other traders and marketers in the region. BP has potential conflicts of interest since it acts as a marketer for producers, procurer for BP refineries in the region and as procurer on our behalf.

During 2006, five different crude feedstocks, compared to eight in 2005, were processed as part of our crude optimization program initiated to improve our refining margins. We will continue to review alternative light sweet crudes that may provide improved margins for our refinery’s product slate. As a means of maximizing distillate yields, we also processed combinations of blended crude and pure (100% of a single crude) cargoes. During 2006, our refinery processed nine crude cargoes versus the eleven in 2005. In 2006, the refinery processed solely imported crude, due to the cargo economics and yield structure of the crudes. . The average daily crude throughput at our refinery for 2006 was approximately 19,784 barrels per day.

Marketing

Papua New Guinea is our principal market for all the products our refinery produces, other than naphtha and low sulfur waxy residue. Under our 30 year agreement with the Government of Papua New Guinea, the government has undertaken to ensure that all domestic distributors purchase their refined petroleum product needs from our refinery, or any refinery which is later constructed in Papua New Guinea, at an import parity price. In general, the import parity price 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 import parity price 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.

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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 import parity pricing mechanism was implemented in September 2004 by the Papua New Guinea Independent Consumer and Competition Commission for purchases of refined products from our refinery.

The major export product from our refinery is naphtha, which is sold to Shell International Eastern Trading Company on a term basis pursuant to a contract that expires in September 2008. During 2006, there were four export cargoes of naphtha averaging approximately 30,000 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 nor middle distillates in 2006 due to the tightened product quality specifications in the Australian market. However, we are pursuing export opportunities in other regional market places.

Our products meet the specification in the nearby Pacific Island markets that we are currently targeting. Our refinery is fully certified to manufacture and market Jet A-1 fuel to international specifications and markets Jet A-1 product to both domestic Papua New Guinea and overseas airlines.

Due to the percentage of crudes we processed with lower LPG content, and until the conversion of the main process furnaces and commissioning of the Hyundai Generators which burn low sulfur waxy residue, we were a net importer of LPG. With the installation of the low sulfur waxy residue firing, improved facilities for recovering LPG from the reformer off-gas and increased percentages of sweet crudes containing LPG, we are looking to provide LPG to the local market in 2007 via an agreement with a third party.

Competition

Due to their favorable properties, light sweet crudes from the Southeast Asian and Northwestern Australian region are highly sought after by refiners. Therefore, there is significant competition to secure cargoes of these crude types. We rely on our relationship with our crude supplier, BP Singapore Pte Limited, to secure all of our crude feedstock needs at acceptable prices and in sufficient quantities. 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. To date, our relationship with BP has generally allowed us to obtain suitable crudes at competitive pricing.

We own the only refinery in Papua New Guinea. As a result, we are currently the only beneficiary of the import parity pricing structure and the ensuing requirement for domestic refined product needs to be procured from domestic refineries as described under “Marketing”. We do not envision there being any new entrants into the refining business within Papua New Guinea under the current market conditions. 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 parcel 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.

Trading and Risk Management

Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks 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 are required to purchase crude feedstock two months forwarding advance, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Because of this timing difference, there is an impact on our cost of crude feedstocks 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 as a tool to reduce the risks of changes in the relative prices of our crude

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feedstocks 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 feedstocks contracts are 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 vis-à-vis our acquisition price of crude feedstocks expands or increases, then the benefits would be limited to the locked-in margin.

The derivative instrument which we generally use is the over-the-counter swap. The swaps transactions are concluded between the counterparties in the derivatives swaps market. It is common place among major refiners and trading companies in the Asia Pacific market to use the derivative swaps as a tool to hedge their price exposures and margins. Due to the wide usage of the 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, InterOil actively engages 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 Exchange to hedge our crude costs.

We will continue with our hedging and risk management program in 2007, and we will continue to evaluate new approaches to enhance our hedging arrangement and margin protection.

Liquefaction

During 2006, InterOil, along with two other partners, have proposed a project proposal for the construction of a natural gas liquefaction plant to be built adjacent to our refinery. We are targeting a facility that will 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 location as well as other potential suppliers of gas, and LNG storage and handling. The LNG facility will also interface with our existing refining facilities.

Strategic Priorities

Following is a table outlining the midstream segments progress towards the strategic priorities of the Company and its goals for 2007.

Strategic
Priorities	2006 Progress	2007 Goals
Capitalize and Expand on the Existing Business Assets	ü   Completed refinery optimization project to improve product slate, improve reliability and reduce fuel costs. ü   Completed InterOil Power Fuel project at Moitaka Power Station. The downstream business won a tender to provide IPF to Moitaka supplied out of the refinery. ü   Continued with crude optimization initiatives.	ü   Evaluate feasibility of improvements, modifications and additional equipment to improve flexibility and profitability of the refinery ü   Continue to seek out potential markets for InterOil Power Fuel ü   Seek profitable distillate export opportunities to increase contribution to fixed costs ü   Cost reduction program targeting 10% reduction.
Target Acquisitions and Growth Opportunities in Papua New Guinea	ü   Commenced consultation with key stakeholders to discuss ways to stimulate local demand from the refinery ü   Progressed discussions for LNG opportunity in Papua New Guinea with government and other potential partners.	ü   Achieve growth in local demand for products from the refinery ü   Sign shareholder agreement and project agreement relating to the proposed LNG plant. ü   Complete basis of design and commence front end engineering design.

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Strategic
Priorities	2006 Progress	2007 Goals
Position InterOil for Long-Term Oil and Gas Business Success	ü   Improved refinery profitability to almost a breakeven position in second half of 2006.	ü   Maintain the positive momentum achieved in third and fourth quarter 2006 and achieve a profitable outcome for 2007

WHOLESALE AND RETAIL DISTRIBUTION

Following the closing of the transaction to acquire Shell’s Papua New Guinea distribution assets in October 2006, we have the largest wholesale and retail petroleum product retail distribution base in Papua New Guinea. This business includes bulk storage, transportation distribution, and the wholesaling and retailing of refined petroleum products. We believe that the Shell acquisition has provided us with the level of business that exceeds the critical mass required to provide financial returns. Our downstream business supplies petroleum products nationally through a portfolio of retail service stations and commercial customers. As of December 31, 2006, we supplied approximately 67% of Papua New Guinea’s refined petroleum product needs. The head office for our wholesale and retail distribution business is currently located in Lae, the industrial center of Papua New Guinea.

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 refining and marketing business segment. We import the commercial and industrial lubricants, which constitute a small percentage of our sales. We also import fuel oil that we sell to a domestic power plant. Sales of imported fuel oil constituted approximately 6% of the volume of refined products that we sold in 2006 and involve low margins.

All of the companies engaged in the distribution of petroleum products in Papua New Guinea utilize two shared tankers to supply petroleum products from our refinery to their terminals and depots. All of our terminals and depots, with the exception of three inland depots, are supplied petroleum products from these shared tankers. We do not own these tankers; but rather, they are engaged 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 in Papua New Guinea. The inland depots are supplied by road tankers which are owned and operated by third party independent transport operators.

We utilize our terminal and depot network to distribute 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 and incur and pass on the cost of transportation charges for these services.

Retail Distribution

As of December 31, 2006, we provided petroleum products to 60 retail service stations that now operate under the InterOil brand name. Of the 60 service stations that we supply, 21 are either owned by or leased to us with a sublease to company approved operators. The remaining 39 service stations are independently owned and operated. We supply products to each of these service stations pursuant to distribution supply agreements. Under the cover of an equipment loan agreement, we also provide fuel pumps and related infrastructure to the operators of the majority of these retail service stations that are not owned or leased by us.

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Wholesale Distribution

In addition to our retail distribution network, we also supply petroleum products as a wholesaler to commercial clients. 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 2006 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 mark-up margin.

Competition

Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. . We also compete with smaller local distributors of petroleum products. We believe that we will be able to obtain refined products for our distribution business at competitive prices. We also believe that our commitment to growing our distribution business in Papua New Guinea at a time when major-integrated oil and gas companies have indicated a desire to exit the Papua New Guinea 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 expand much more rapidly in this market than we can, if they chose to do so.

Customers

We sell approximately 20% of our refined petroleum products to Ok Tedi Mining Limited 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 Ok Tedi Mining Limited, the loss of this customer, at least in the short term, would adversely affect the profitability of our retail and wholesale distribution business segment.

Strategic Priorities

Following is a table outlining the downstream segments progress towards the strategic priorities of the Company and its goals for 2007.

Strategic
Priorities	2006 Progress	2007 Goals
Capitalize and Expand on the Existing Business Assets	ü   Secured a contract to provide IPF to Papua New Guinea’s Moitaka Power Station. ü   Completed the construction of a 2 million liter diesel storage tank at our terminal in the province of East Sepik, to augment storage availability at that location.	ü   Further integrate Shell distribution assets into the existing InterOil business to capitalize on cost efficiencies and operational synergies. ü   Continue to seek out potential markets for InterOil Power Fuel. ü   To carry out full retail network plan and rationalize or expand the retail network as a result
Target Acquisitions and Growth Opportunities in Papua New Guinea	ü   Finalized the terms of acquisition for Shell Papua New Guinea’s distribution network. The Shell Papua New Guinea business was transferred to InterOil on October 1. ü   Examined other potential downstream growth opportunities.	ü   Pursue acquisition opportunities in the aviation distribution business. ü   Pursue other potential downstream growth opportunities. ü   To target new mining ventures currently in the start up phase in Papua New Guinea. ü   To complete a 5-year strategic plan to identify future growth within the surrounding region.

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COMMUNITY RELATIONS, SAFETY AND THE ENVIRONMENT

Our Human Resources, Compensation, Environmental, Health and Safety Committees undertake with the Board of Directors and management, all necessary procedures, policies and industry and country best practices that are designed to protect InterOil’s employees, contractors, members of the public, and the environment. We regularly assess our operations in consultation with our stakeholders in order to help identify opportunities to improve on our best practices. We believe that through these efforts we have contributed towards the creation of a safer environment for our employees, stakeholders and the citizens of Papua New Guinea.

Environment

Our operations in Papua New Guinea are subject to a comprehensive range of environmental laws and regulations and a variety of local and international conventions. The Papua New Guinea environmental law regime provides for laws concerning:

ü	Emissions of substances into, and pollution and contamination of, the atmosphere, waters and land;
ü	Production, use, handling, storage, transportation and disposal of waste, hazardous substances and dangerous goods;
ü	Conservation of natural resources;
ü	The protection of threatened and endangered flora and fauna; and
ü	The health and safety of people.

Specifically, this environmental legislation provides for restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with our operations in the oil and gas industry. With respect to our exploration and production business segment, these environmental laws require that our sites be operated, maintained, abandoned and reclaimed to standards set out in the relevant legislation. The significant Papua New Guinea laws applicable to our operations include the Environment Act 2000; the Oil & Gas Act 1998; the Dumping of Wastes at Sea Act (Ch. 369); the Conservation Areas Act (Ch.362); and the International Trade (Flora and Fauna) Act (Ch.391).

The Environment Act 2000 is the single most significant legislation affecting our operations. This act 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. The Environment Act 2000 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, 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. 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.

Our goal is to implement and maintain positive environmental practices and high standards of safety and social responsibility in all our operations. We actively review and improve our programs with the support of our staff, the Papua New Guinea government and local communities.

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Community Relations

The objectives of the Community Relations and Land Management Program encompass;

ü	Managing the expectations and demands of benefit streams perceived as a result of the establishment of the refinery;
ü	Managing expectations of community assistance programs to community institutions, and;
ü	To manage land acquisition related compensation claims, demands and payments;

Although our refinery is located on state owned land we have developed a long-term community development assistance program that includes local communities from the three main villages in the vicinity. In compliance with Papua New Guinea law, our development philosophy is based on “bottom-up planning” thus ensuring that all planning and development takes the local community into account.

In our exploration areas we have a team of land and industrial relations officers who operate in the field. This team undertakes initial “land-owner” identification and assists with the recruitment of local village personnel. Other duties include the establishment of communication channels with the community and their leaders to ensure minimum social disruption and the smooth running of exploration activities. The officers also have the responsibility of paying compensation to land-owners with respect to our activities. Other activities include the provision of health and medical services to our employees, contractors and the local communities in the areas in which our exploration activities are conducted. This has led to improved health and living standards.

The recording of verbal histories, clan boundaries and genealogies has been integrated with our extensive geological mapping, seismic and drilling activities and provides a valuable resource for future use. Preliminary social mapping and landowner identification studies of the customary land owners in our license areas is carried out on a consultative basis with the relevant stakeholders prior to conducting geological and exploration activities. The social mapping and landowner identification studies are undertaken in order to understand the social structure, how society functions and its relationship to the land, as well as identifying the actual owners and occupiers of the customary land on which all of our exploration activities are conducted.

We also work closely with the national and provincial governments, landowners and the community in order to ensure all our activities have a minimum environmental impact on the flora and fauna and to understand the quality of life of the people that inhabit the areas in which we work.

We are committed to:

ü	Comply with all applicable laws, regulations and standards and where laws do not exist adopt and apply standards that reflect the company’s commitment to socially and environmentally responsible behaviors.
ü	Maintain close liaison with the Department of Petroleum and Energy and all relevant Government departments to ensure that InterOil complies with all government legislation and regulations relevant to its activities in Papua New Guinea.
ü	Providing a safe and healthy working environment for all employees and contractors, and establishing emergency response procedures that allow personnel to respond promptly and effectively.
ü	Establishing community development assistance programs to enhance and improve the standard of health and education.
ü	Pursuing socially responsible community relations initiatives that reflect the community’s needs, enhance our reputation and recognize the importance of the culture, heritage and traditional rights of the communities in which we operate.
ü	Understanding the traditional and contemporary culture, beliefs and social dynamics of locals in all project areas with particular reference to land matters, in order to better manage socio-economic changes in oil and gas exploration and in our refinery operations in Papua New Guinea.
ü	Ensuring community affairs issues are a major focus in the planning, management and delivery of our activities, while ensuring that our health, safety and environment operating procedures are adhered to in every task performed;

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ü	Communicating with employees, contractors, partners, government and the local project impacted communities in a transparent, open and proactive manner;
ü	Providing cultural awareness information and training to our employees and contractors at all levels;
ü	Ensuring compliance with all applicable industrial relations legislation and procedures in all employment arrangements with our contractors and sub-contractors; and
ü	Providing business development advice and support to appropriate, representative and sustainable community owned enterprises where they have the capability to provide cost effective and competent services.

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

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.

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 us. 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 will compete with several companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. BP has agreed to supply all of our feedstock. However, many of our competitors obtain a significant portion of their feedstocks from company-owned production, which may enable them to obtain feedstocks at a lower cost. The high cost of transporting goods to and from Papua New Guinea reduces the availability of alternate fuel sources

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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 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 2006. 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.

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 described under “Material Contracts” gives us certain rights to supply the domestic market in Papua New Guinea with our refined products. We have entered into domestic sales contracts with the major distributors in Papua New Guinea under which they will purchase refined products for distribution in Papua New Guinea exclusively from us. However, 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.

We are able to fulfill the domestic market in Papua New Guinea’s demand for our products by refining approximately 16,000 barrels of crude feedstock a day. Our refinery is rated to process up to 32,500 barrels of oil per day and our current optimization efforts are intended to further increase our daily throughput capacity. 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.

We plan to market the balance of the refinery’s output in nearby regional markets. Although we have signed export contracts with Shell that expire in September 2007 and January 2008, we are currently operating the refinery at less than full capacity due to an inability to profitably export our refined products. We can give no assurances that we will be able to profitably market the refinery’s output to these regional markets and we may be unable to market all of the refinery’s output we produce. In addition, if our relationship with Shell were to terminate for any reason, we cannot assure you that we will be able to enter into other commercial agreements for the export of our refinery’s output.

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

The determination of our refinery’s fair market value is highly dependent upon the difference between the sale price we receive for refined products that we produce and the cost of the crude feedstocks used to produce those refined products. This difference is commonly referred to as refining margin. The optimization work recently 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

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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:

ü	Our revenues, cash flows and earnings;
ü	Our ability to attract capital to finance our operations, and the cost of such capital;
ü	The value of our oil properties;
ü	The profit or loss we incur in refining petroleum products; and
ü	The profit or loss we incur in exploring for and developing reserves.

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

Our project agreement requires the government of Papua New Guinea 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 import parity price. However, our agreement with BP Singapore is our only commercial agreement for the delivery of crude feedstock. The BP agreement expires on June 14, 2009. If our relationship with BP were to terminate for any reason, we cannot assure you that we will be able to enter into other commercial agreements to supply adequate feedstock to our refinery. In addition, early termination of the BP agreement could have a material adverse effect on our results of operations and financial condition.

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 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 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.

Our hedging activities may result in losses.

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

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ü	If the amount of refined products produced is less than expected or is not produced or sold during the planned time period;
ü	If the other party to the hedging contract defaults on its contract obligations; or
ü	If there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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

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

We currently do not have any oil or gas reserves that are deemed proved, probable or possible pursuant to National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. As of December 31, 2006, we had drilled five unsuccessful exploration wells and have one discovery well which we are in the process of appraising. We plan to drill at least five additional exploration wells in Papua New Guinea during the next two years. 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.

In addition, 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, 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.

The successful acquisition and development of oil and gas properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property, or may not recognize an acceptable return from properties we acquire. In addition, we cannot assure you that our exploitation activities will result in the discovery of any reserves. Our operations may be curtailed, delayed or canceled as a result of a lack of adequate capital and other factors, such as title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties, or shortages or delays in the delivery of equipment. In addition, the costs of exploration and development may materially exceed initial estimates.

If we are unable to renew our petroleum licenses with the Papua New Guinea government, we may be required to discontinue our exploration activities in Papua New Guinea.

Our petroleum prospecting licenses are granted for a period of six years. However, every two years we are required to submit a work program containing our minimum expenditures for the succeeding biannual period. In order for us to retain our licenses, the Papua New Guinea government could require us to expend more than we have budgeted or deem appropriate. If we are unable to meet the minimum expenditure levels or determine that making such expenditures is not in our best interests, we will be required to relinquish our petroleum prospecting licenses.

Our petroleum retention licenses are granted for a period of five years. In connection with an application for, or a renewal of, a petroleum retention license, we are required to submit a one year work program and a work program for the remaining four years that is contingent on the results of the first year’s operations. If we determine that the contingent work is not justified or requires revision, we may be required to renegotiate the terms of the work program with the government of Papua New Guinea in order

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to retain our retention license. If we were unable to agree upon a revised work program for the remaining term of the retention license, we may be required to forfeit the license.

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.

New legislative, administrative or judicial actions that constrain licenses and permits from various government authorities may have a material adverse affect on the companies operations.

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 in various circumstances. 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 for continued operations.

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, 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.

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

As of December 31, 2006, we had $184.2 million in long-term debt, excluding current maturities. The level of our indebtedness will have important effects on our future operations, including:

ü	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;
ü	Our OPIC loan agreement, secured loan agreement and BNP credit facility contain financial tests which we must satisfy in order to avoid a default under such credit facilities; and
ü	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, 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 prices, delays, operating difficulties, construction costs, or lack of drilling success, 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.

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.

Petroleum Independent and Exploration Corporation can affect our raising of capital through the issuance of common shares or securities convertible into common shares.

Mr. Phil E. Mulacek, our Chief Executive Officer, is the President of, and has an ownership interest in, Petroleum Independent and Exploration Corporation. Petroleum Independent and Exploration Corporation owns 433,169 of our common shares, and has a right to exchange its remaining 5,000 shares of S.P. InterOil, LDC on a one-for-one basis for our common shares. Our articles of amalgamation contain restrictions on our issuance of common shares or securities convertible into common shares, except with, among other things, the consent of Petroleum Independent and Exploration Corporation. Mr. Mulacek has an ownership interest in, and Petroleum Independent and Exploration Corporation is the sole general manager of, P.I.E. Group, LLC, which, with Commodities Trading International Corporation, have pre-emptive rights in respect of issuances of our common shares or securities convertible into common shares. Therefore, through his control of Petroleum Independent and Exploration Corporation and P.I.E. Group, LLC, Mr. Mulacek or any successor to his interest in those companies can prevent us from raising capital through the issuance of common shares or securities convertible into common shares.

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.

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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.

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

We are a New Brunswick, 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.

Changing regulations regarding corporate governance and public disclosure could cause additional expenses and failure to comply may adversely affect our reputation and the value of our securities.

Changing laws, regulations and standards relating to corporate governance and public disclosure, including the Sarbanes-Oxley Act of 2002, new SEC regulations and new and changing provisions of Canadian securities laws, are creating uncertainty because of the lack of specificity and varying interpretations of the rules. As a result, the application of the rules may evolve over time as new guidance is provided by regulatory and governing bodies, which could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices. We are committed to maintaining high standards of corporate governance and public disclosure. Our efforts to comply with evolving laws, regulations and standards have resulted in, and are likely to continue to result in, increased general and administrative expenses and a diversion of management time and attention from revenue-generating activities to compliance activities.

Beginning with our annual report for the year ending December 31, 2007, Section 404 of the Sarbanes-Oxley Act of 2002 will require us to include an internal control report of management with our annual report on Form 40-F, which is to include management’s assessment of the effectiveness of our internal control over financial reporting as of the end of the fiscal year. That report will also be required to include a statement that our independent auditors have issued an attestation report on management’s assessment of our internal control over financial reporting.

In order to achieve compliance with Section 404 within the prescribed period, management has adopted a detailed project work plan to assess the adequacy of our internal control over financial reporting, validate through testing that controls are functioning as documented, remediate any control weaknesses that may be identified, and implement a continuous reporting and improvement process for internal control over financial reporting. Any failure to comply with applicable laws relating to corporate governance and public disclosure may materially adversely affect our reputation and the value of our securities.

DIVIDENDS

To date we have not paid dividends on our common shares and currently reinvest all cash flow from operations for the future operation and development of our business. Our OPIC loan agreement restricts the subsidiaries that operate our refining business segment from paying dividends to its parent companies and ultimately to InterOil.

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DESCRIPTION OF OUR CAPITAL STRUCTURE

We are authorized to issue an unlimited number of common shares. Holders of common shares are entitled to one vote per share at meetings of our shareholders, to receive dividends on common shares when declared by our Board of Directors and to receive pro-rata our remaining property and assets upon our dissolution or winding up, subject to any rights having priority over the common shares.

Our articles of amalgamation contain restrictions on our issuance of common shares or securities convertible into common shares without the approval of Petroleum Independent and Exploration Corporation, a corporation controlled by Phil Mulacek, our Chief Executive Officer. There are also pre-emptive rights in our articles granted to P.I.E. Group LLC, a company controlled by our Chief Executive Officer, and Commodities Trading International Corporation in respect of issuances of our common shares or securities.

Our by-laws and governing statute, the Business Corporations Act (New Brunswick), provide for cumulative voting for the election for directors such that each shareholder entitled to vote for the election of directors has the right to cast a number of votes equal to the number of votes attached to the common shares held by such shareholder multiplied by the number of directors to be elected, and may cast all such votes in favor of one candidate or distribute them among all candidates in any manner.

MARKET FOR OUR SECURITIES

Our common shares trade on the Toronto Stock Exchange under the symbol IOL in Canadian dollars, on the American Stock Exchange under the symbol IOC in US dollars, and on the Port Moresby Stock Exchange under the symbol IOC in Papua New Guinea Kina. The following tables disclose the monthly high and low trading prices and volume of our common shares traded on the TSX and AMEX during 2006:

Toronto Stock Exchange (TSX:IOL) in Canadian Dollars

Month	High		Low		Volume
January	$	31.30	$	18.75		771,500
February	$	20.53	$	18.30		481,100
March	$	19.83	$	14.70		504,500
April	$	17.97	$	15.10		261,000
May	$	18.95	$	13.55		371,500
June	$	22.95	$	14.37		316,800
July	$	22.75	$	19.31		109,700
August	$	21.99	$	13.32		339,900
September	$	21.76	$	16.22		187,400
October	$	21.75	$	17.30		459,800
November	$	34.99	$	20.56		1,430,400
December	$	35.41	$	29.44		441,900
Total						5,675,500

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

Month	High		Low		Volume
January	$	26.41	$	16.00		7,592,100
February	$	18.75	$	15.80		3,655,900
March	$	17.50	$	12.64		6,285,700
April	$	15.82	$	13.05		3,348,200
May	$	17.26	$	12.75		5,848,000
June	$	20.54	$	12.96		6,014,200
July	$	20.14	$	16.70		3,976,600
August	$	19.46	$	12.14		7,848,000
September	$	19.50	$	14.50		5,553,700
October	$	19.59	$	15.20		1,000,500
November	$	30.80	$	18.05		21,506,200
December	$	30.50	$	26.12		10,009,700
Total						92,638,800

Prior Sales

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. Investors are able to convert their interests under the agreement into a maximum of 3,333,334 of our common shares.

We issued $45.0 million in 8.875% senior convertible debentures due 2009 and warrants to purchase 359,415 of our common shares in private placements on August 27, 2004 and September 3, 2004. The debentures were subsequently converted into 2.4 million of our common shares. Each warrant entitles the holder to purchase one common share at an exercise price of $21.91, subject to certain adjustments, until August 27, 2009. As of December 31, 2006, warrants to purchase 340,247 common shares remained outstanding.

During 2004, we raised $12.2 million from PNG Drilling Ventures Limited for our second indirect interest participation agreement program. As of December 31, 2005, PNG Drilling Ventures Limited had converted $2.5 million of their investment into 141,545 of our common shares. As of December 31, 2006, PNG Drilling Ventures Limited had converted their remaining interest into 575, 575 shares and also retained 6.75% in the next four wells. Elk–1 is the first of these wells. PNG Drilling Ventures Limited also has the right to participate in the 16 wells to follow the four mentioned above up to interest of 5.75% at a cost of $112,500 per well (with higher amounts to be paid if the depth exceeds 3,500 meters and the cost exceeds $8.5 million).

In addition to the above, PNG Energy Investors (“PNGEI”), an indirect participation interest investor, that converted all of its interests to common shares in fiscal year 2004, has the right to participate up to 4.25% interest in wells 9 to 24. In order to participate, PNGEI would be required to contribute a proportionate amount of drilling costs related to these wells.

Annual Information Form     INTEROIL CORPORATION     36

DIRECTORS AND OFFICERS

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

Directors and Officers

Name	Address	Position	Date of Appointment
Phil E. Mulacek	The Woodlands, TX, USA	Chairman, CEO, & Director	May 29, 1997
Christian M. Vinson	The Woodlands, TX,USA	Vice President of Corporate Development and Government Affairs, & Director	May 29, 1997
Gaylen J. Byker	Grand Rapids, MI, USA	Director(1)	May 29, 1997
Roger N. Grundy	Matlock Derbyshire, UK	Director	May 29, 1997
Donald R. Hansen	Calgary, AB, Canada	Director(2)	December 29, 2006
Edward N. Speal	Toronto, ON, Canada	Director(3)	June 25, 2003
Anesti Dermedgoglou	Cairns, QLD, Australia	Vice President of Investor Relations	June 3, 2002
Peter Diezmann	Lae, Papua New Guinea	General Manager — Wholesale and Retail Distribution	March 1, 2005
Gerry Gilbert	Cairns, QLD, Australia	General Manager — Exploration and Production	July 1, 2005
William J. Jasper III	Cairns, QLD, Australia	President and Chief Operating Officer	August 30, 2006
Anthony Poon	Sydney, NSW, Australia	General Manager — Supply and Trading	October 1, 2005
Collin F Visaggio	Perth, WA, Australia	Chief Financial Officer	October 26, 2006

(1)	Gaylen Byker acted as Chairman of the Audit Committee, the Nominating and Corporate Governance Committee and Compensation Committee.
(2)	Donald Hansen acted as a member of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee from the date of his appointment, December 29, 2006.
(3)	Edward Speal acted as a member of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee

As of February 28, 2007, our directors and executive officers as a group beneficially owned 7,519,381 common shares, representing 25.2% of our outstanding common shares. The common shares beneficially owned by our directors and executive officers exclude 662,000 shares issuable upon exercise of outstanding options.

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

Annual Information Form     INTEROIL CORPORATION     37

Phil E. Mulacek is the Chairman of our Board of Directors and our Chief Executive Officer. He has held these positions since the inception of InterOil in 1996. 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 Executive Vice President of InterOil and head of 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 his responsibilities included the establishment 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. 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 serves as the Technical Director for our refinery and 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 Institution of Mechanical Engineers, Member of the American Institute of Chemical Engineers and a Member of the Energy Institute.

Donald R. Hansen is currently Managing Director with Scotia Waterous in their Calgary, Alberta head office. His focus is on the Private Equity side of their business. Mr. Hansen is also Chief Executive Officer of his privately owned oil and gas consulting company, Red Deer River Energy Corp. Formerly, Mr. Hansen was Vice President, International Energy Operations for Unocal Corp. in Houston, Texas. In his capacity with Unocal in Houston, Mr. Hansen had regional VP responsibilities for West Africa, Latin America, Caspian, China, Europe, Russia, Alaska and Canada as well as new international ventures. Prior to moving to Houston with Unocal, Mr. Hansen resided in Calgary, Alberta and was President and CEO of Northrock Resources Ltd., the Canadian business unit and a wholly owned subsidiary of Unocal Corporation. Northrock Resources Ltd. was a Canadian publicly traded exploration and production company that was sold to Unocal in 2000. Mr. Hansen was President and CEO of Northrock Resources Ltd., and helped build the company from a virtual start-up to over 30,000 boed of production. Prior to Northrock, Mr. Hansen was Vice President Operations for Sceptre Resources and held positions in production engineering, exploitation and gas marketing at Dome Petroleum and Amoco Canada.

Mr. Hansen has had over 26 years of Exploration and Production experience. He joins InterOil with significant board experience and has served on the boards of Black Gold Energy LLC, several Unocal domestic and foreign subsidiaries, Asia Society Texas, Houston, the Unocal Foundation and Northrock Resources Ltd. Mr. Hansen has also served two terms as Governor, Canadian Association of Petroleum Producers in Calgary, and has served on the boards of; YMCA, Calgary, North West Family Church, Calgary, and a private technology company, Outland Technologies Inc. In 1980, Mr. Hansen earned a Bachelor of Science degree in engineering from the University of Saskatchewan with great distinction.

Annual Information Form     INTEROIL CORPORATION     38

Edward N. Speal is based in Toronto, Ontario and is President and CEO of BNP Paribas (Canada). Previously, Mr. Speal was 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 1996 to 2000. 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.

Anesti Dermedgoglou is our Vice President of Investor & Public Relations. Mr. Dermedgoglou joined us in 2002. From 1998 until joining us, Mr. Dermedgoglou was a stock broker with Merrill Lynch in Perth, Western Australia. From 1996 to 1998 Mr. Dermedgoglou was a stock-broker at Porter Western Limited in Perth, Western Australia. Mr. Dermedgoglou was a Director of Frankel Pollack Vinderine Inc, one of the largest stock broking companies in South Africa, from 1986 to 1996. Mr. Dermedgoglou is a former member of the Johannesburg Stock Exchange. Mr. Dermedgoglou has worked in the stock broking industry for 16 years and holds a Bachelor of Commerce Degree from The University of South Africa.

Peter Diezmann is General Manager of our Wholesale and Retail Distribution business segment. Mr. Diezmann joined us in March 2005. Prior to joining us, Mr. Diezmann had worked first for Amoco Oil Company and then following it’s acquisition by BP, for BP Australia since 1981, serving in various capacities, including retail, wholesale, distributor, and terminals & logistics management positions, and as General Manager of BP Papua New Guinea for four years prior to our acquisition of that business. Mr. Diezmann holds a Masters of Business Administration (MBA) Degree from James Cook University in Queensland, Australia.

Gerry Gilbert is General Manager of our Exploration and Production business segment. Mr. Gilbert joined us in July 2005. Mr. Gilbert was CEO of Oluma, Inc., a company that designs, manufactures, and markets a suite of fiber-optic products and systems from July 2004 until May 2005. From September 2001 to June 2004, Mr. Gilbert was the Senior VP—International for Transworld Exploration and Production and was responsible for the company’s exploration and production activities which were largely focused in West Africa, New Zealand and Indonesia. From August 2000 until September 2001, Mr. Gilbert worked as an independent consultant to the exploration and production industry. From July 1995 until August 2000, Mr. Gilbert was Executive VP and President, respectively, for Western Atlas’ and Baker Hughes’ exploration and production groups. Mr. Gilbert’s professional career spans 37 years in the upstream oil and gas industry and oil service industry. Mr. Gilbert has held senior management positions in the geophysical service divisions of Western Atlas, Halliburton and Texas Instruments. Mr. Gilbert has a Bachelor of Science Degree in Electrical Engineering from the University of Texas at Austin, a Master of Science Degree in Electrical Engineering from Southern Methodist University and has also completed The Management Program at Rice University. Mr. Gilbert is a member of the Geology Foundation Advisory Council at UT Austin, the Society of Petroleum Engineers, the Society of Exploration Geophysicists, the American Association of Petroleum Geologists, the European Association of Geoscientists and Engineers and the IEEE.

William J Jasper III is President and Chief Operating Officer of InterOil Corporation. Mr. Jasper joined us on August 30, 2006. Mr. Jasper, as President of InterOil leads the refining and downstream business. Prior to joining us, Mr. Jasper had worked for Chevron Pipe Line Company since 1974, serving in leadership and management capacities over facilities, pipelines and terminals. Mr. Jasper has an extensive background in operations and maintenance. Prior to this role Mr. Jasper had served 4 years as Chairman of the West Texas LPG Partnership Board of Directors. Mr. Jasper was also past President and General Manager of Kenai Pipe Line Company in Alaska, and West Texas Gulf Pipeline in Texas.

Annual Information Form     INTEROIL CORPORATION     39

Anthony Poon is General Manager of our Supply, Trading & Risk Management department. Mr. Poon joined us in October 2005. From January 2003 until joining us, 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 the International Crude Oil Trading Department for Caltex in Singapore 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 Chief Financial Officer of InterOil. Mr. Visaggio joined us on July 17, 2006 and was appointed to the position of Chief Financial Officer on October 26, 2006. Mr. Visaggio is a Certified Practicing Accountant with a Bachelor and a Masters Degree in Business. He has also attended the Stanford Senior Executive Program in Management.

Mr. Visaggio is a seasoned oil and gas executive who has 24 years’ 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 spent most of his career at Woodside Petroleum from March 1988 to 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 implementing governance. Prior to this and during his 17 years with Woodside he was Deputy Chief Financial Officer and Financial Analysis and Planning Manager within Corporate Finance. 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 Chairman of the Finance Committee of Santa Maria Ladies College. Mr Visaggio has served as Director and Officer of Santa Maria College since February 2004.

BOARD COMMITTEES

Our Board of Directors has formed an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. Dr. Byker, Mr. Hansen and Mr. Speal are the members of each of these committees. Dr. Byker is the Chairman of the Audit Committee and the Nominating and Corporate Governance Committee. Dr. Byker is also the Chairman of the Compensation Committee. Dr. Folie, who resigned as a director effective October 1, 2006, was previously a member of both of these committees and prior to his resignation acted as the Chairman of the Compensation Committee.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTION

Phil Mulacek, our Chief Executive Officer, and Gaylen Byker, a director of InterOil is has ownership interests in certain subsidiaries of InterOil, which are described under “Corporate Structure”, as follows:

ü

Mr. Mulacek controls P.I.E. Group LLC and entities controlled by Mr. Byker, also have an ownership interest in P.I.E. Group LLC. P.I.E. Group LLC. owns 0.01% interest of S.P.I. Exploration and Production Corporation. S.P.I. Exploration and Production Corporation is a holding company that owns InterOil’s upstream operating subsidiaries that hold exploration licenses and conduct exploration activities in Papua New Guinea.

ü

Petroleum Independent and Exploration Corporation (“P.I.E.”) has a 0.02% interest of S.P. InterOil, LDC, which is a holding company of InterOil that owns InterOil’s midstream operating subsidiaries that own and operate InterOil’s refinery in Papua New Guinea. Mr. Mulacek is the President of, and has an ownership interest in, P.I.E. P.I.E. was paid a management fee of $150,000, $150,000, and $150,410 during 2006, 2005 and 2004, respectively. This management fee relates to Petroleum Independent and Exploration Company being appointed the General Manager of our subsidiary, S.P. InterOil, LDC.

Annual Information Form     INTEROIL CORPORATION     40

ü

P.I.E. has a 0.01% interest of S.P.I. Distribution Limited, which is a holding company of InterOil that owns InterOil’s wholesale and retail distribution operations.

ü

We had no loans with P.I.E. in 2006. In 2005 and 2004, we made interest payments of $9,376, and $246,745, and loan principal payments of $1.1 million and $2.2 million to P.I.E. As of December 31, 2005, we had repaid all amounts that we owed to P.I.E. The loans outstanding to P.I.E. were for amounts loaned by lending institutions to P.I.E. These loans were collateralized by barges legally owned by P.I.E. but beneficially owned by us and common shares of ours owned by P.I.E. The interest rates charged to us by P.I.E. reflected the actual interest rates paid by P.I.E. to the lending institutions.

Breckland Limited provides technical and advisory services to us on normal commercial terms. Roger Grundy, one of our directors, is also a director of Breckland and he provides consulting services to us as an employee of Breckland. Breckland was paid $140,165, $179,608 and $120,426 in fees and expenses during 2006, 2005 and 2004, respectively.

LEGAL PROCEEDINGS

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.

The Company currently has an outstanding $10.6 million cost of control insurance claim for the Elk well which is being assessed by the loss adjusters. The amount and timing of any payment related to this claim is currently unknown.

MATERIAL CONTRACTS

Each of the following material agreements has been filed on SEDAR at www.sedar.com.

Date	Description
May 4, 2006	Credit Agreement between InterOil Corporation and Merrill Lynch ,Pierce, Fenner & Smith Incorporated and Clarion Finanz AG
May 4, 2006	Memorandum of Understanding between InterOil Corporation, Merrill Lynch and Clarion Finanz AG
January 4, 2006	Purchase and Sale Agreement between InterOil Products Limited and Shell Overseas Holdings Limited
December 27, 2005	Code of Ethics and Business Conduct
August 12, 2005	$150 Million Secured Revolving Crude Import Facility between EP InterOil, Ltd. and BNP Paribas, Singapore Branch. Amended August 14, 2006 and increased to $170 million.
February 25, 2005	Amended and Restated Indirect Participation Interest Agreement between InterOil Corporation and the Investors signatory thereto
May 12, 2004	Amended Indirect Participation Interest Agreement between InterOil Corporation and PNG Energy Investors, LLC
July 21, 2003	Drilling Participation Agreement between InterOil Corporation and PNG Drilling Ventures Limited. Amended in May 2006
March 26, 2002	Engineering, Procurement and Construction Contract for InterOil Refinery between InterOil Limited and Clough Niugini Limited
June 12, 2001	Loan Agreement between EP InterOil, Ltd. and Overseas Private Investment Corporation, as amended

Annual Information Form     INTEROIL CORPORATION     41

Date	Description
December 21, 2001	Crude Supply Agency and Sales Agreement between EP InterOil, Ltd. and BP Singapore Pte Limited
March 23, 2001	Export Marketing and Shipping Agreement between EP InterOil, Ltd. and Shell International Eastern Trading Company
February 6, 2001	Agreement for the Sale and Purchase of Naphtha between EP InterOil, Ltd. and Shell International Eastern Trading Company
May 29, 1997	Refinery State Project Agreement between InterOil Limited, EP InterOil, Ltd. and The Independent State of Papua New Guinea

Credit Agreement dated May 4, 2006

The Credit Agreement dated May 4, 2006 between us, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Clarion Finanz AG (as co-lead arrangers and co-bookrunners) and others provides for the establishment of a $130.0 million secured credit facility for us.

The loan notes issued under the credit facility have a 24 month maturity and require quarterly interest payments in arrears. The applicable interest rate is 4% until the fourth quarterly payment date, after which it will increase to 10%. If we enter into a joint venture / project development agreement to pursue an LNG/NGL project in Papua New Guinea with Clarion Finanz AG and Merrill Lynch Commodities (Europe) Limited (or affiliates) by that payment date, the interest rate will remain at 4%.

The loans are repayable on maturity with optional prepayments. The Credit Agreement also provides for mandatory prepayments out of net cash proceeds in respect of certain prepayment events.

As a condition of the Credit Agreement, we entered into a memorandum of understanding with Clarion Finanz AG and Merrill Lynch Commodities (Europe) Limited (outlining the terms under which the parties have the right to participate in certain LNG/NGL projects in Papua New Guinea) and an engagement letter with Merrill Lynch, Pierce, Fenner & Smith Incorporated and Clarion Finanz AG (relating to certain potential securities offerings by us or our subsidiaries).

Purchase and Sale Agreement dated January 4, 2006

The Purchase and Sale Agreement dated January 4, 2006 with Shell Overseas Holdings Limited provides for the purchase by us of all of the outstanding shares of Shell Papua New Guinea Limited. Shell Papua New Guinea Limited owns wholesale and retail distribution assets in Papua New Guinea. The purchase price for the shares is $10.0 million, plus the value of Shell Papua New Guinea Limited’s net current assets. This agreement provides that the closing of the acquisition is subject to the approval of several governmental authorities in Papua New Guinea. The transaction contemplated by this agreement closed on October 1, 2006.

Code of Ethics and Business Conduct dated December 27, 2005

We established a Corporate code of ethics and business conduct on December 27, 2005. The code applies to all directors, officers and employees of InterOil and its subsidiaries. It covers a number of key corporate compliance areas and serves as a guide to all directors, officers and employees.

$150 Million Secured Revolving Crude Import Facility dated August 12, 2005

We entered into a $150.0 Million Secured Revolving Crude Import Facility with BNP Paribas, Singapore Branch on August 12, 2005. The terms of this agreement are described under “General Development of Our Business.” On August 14, 2006 this facility was increased to an amount of $170.0 million and renewed until June 30, 2007.

Annual Information Form     INTEROIL CORPORATION     42

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 $125.0 million and we agreed to drill eight exploration wells in Papua New Guinea on Petroleum Prospecting Licenses 236, 237 or 238. The terms of this agreement are described under “Description of Our Business—Exploration and Production—Indirect Participation Interest 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 the right to acquire up to a 4.25% working interest in 16 exploration wells following our drilling of an initial eight exploration wells. As of December 31, 2006, we had drilled five exploration wells. PNG Energy Investors will have the right to acquire a working interest in the ninth through the 24^th exploration well. PNG Energy Investors is required to pay us for its initial interest in such exploration wells and for all completion and future development costs attributable to its interest in any wells in which it acquires an interest.

Drilling Participation Agreement dated July 21, 2003

During 2004, we raised $12.2 million from PNG Drilling Ventures Limited, as agent and trustee for its investors, pursuant to the Drilling Participation Agreement. Under this agreement PNG Drilling Ventures has the right to acquire a working interest in our first 16 exploration wells equal to 13.5% multiplied by the result of eight divided by the number of exploration wells we drill. PNG Drilling Ventures will be required to pay its share of any completion costs for future exploration wells or future development costs if an exploration well is a commercial success. As of December 31, 2005, PNG Drilling Ventures Limited had converted $2.5 million of their investment into 141,545 of our common shares. As of December 31, 2006, PNG Drilling Ventures Limited had converted their remaining interest into 575, 575 shares and also retained 6.75% in the next four wells. Elk–1 is the first of these wells. PNG Drilling Ventures Limited also has the right to participate in the 16 wells to follow the four mentioned above up to interest of 5.75% at a cost of $112,500 per well (with higher amounts to be paid if the depth exceeds 3,500 meters and the cost exceeds $8.5 million).

Engineering Procurement and Construction Contract dated March 26, 2002

On March 26, 2002, we entered into an engineering procurement and construction contract with Clough Niugini Limited, which provides for the design, procurement, and construction of our refinery. This agreement was a lump-sum, turnkey contract providing for a construction/commissioning period of 26 months. Except for the defect liability provisions which expired in January 2006, this construction contract terminated upon practical completion of the refinery in January 2005. Pursuant to a settlement agreement between us and Clough, all outstanding issues between us regarding the terms of this contract and the warranties have been resolved.

OPIC Loan Agreement dated June 12, 2001

Our $85.0 million loan from OPIC was used to finance the construction of our refinery 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 $4,500,000 and semi-annual interest payments. Each disbursement under the loan bears interest at a rate equal to a weighted average of treasury rates at the time of disbursement plus 3.0%. During 2005, the weighted average interest rate of all disbursements pursuant to this loan agreement was 7.1%.

Crude Supply Agency and Sales Agreement

In December 2001, we entered into an agreement with BP Singapore Pte Limited whereby BP will supply crude feedstocks to our refinery through June 2009. Our agreement with BP provides BP with financial incentives to secure the most economically attractive crude feedstocks for our refinery. Our contract with BP may limit our ability to purchase directly from producers or from other traders and marketers in the region. Under this agreement, we pay BP the market price for crude feedstocks that it provides plus a nominal marketing fee per barrel.

Annual Information Form     INTEROIL CORPORATION     43

Export Marketing and Shipping Agreement dated March 23, 2001

We entered into an agreement with Shell International Eastern Trading Company whereby Shell will market and distribute or purchase all petroleum products, other than naphtha which is governed by a separate agreement, exported by our refinery. Subject to limited exceptions, Shell has the exclusive right under this agreement to market, sell and distribute all products exported from the refinery other than marine diesel. Shell also agrees to purchase all of our refined products that exceed the domestic Papua New Guinea demand and are not covered by other export contracts. This agreement expires in January 2008.

Agreement for the Sale and Purchase of Naphtha dated February 6, 2001

We entered into an agreement with Shell International Eastern Trading Company whereby Shell will market and distribute or purchase all naphtha exported by our refinery. Under this contract, Shell agrees to purchase all of the naphtha produced by the refinery that is available for export. This agreement expires in September 2008.

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 import parity price prior to any imports into Papua New Guinea. In general, the import parity price 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 import parity price 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 project agreement provides that, until December 31, 2010, income from the refinery will not be taxed.

TRANSFER AGENT AND REGISTRAR

Our transfer agent and registrar is Computershare Trust Company of Canada. In Papua New Guinea our transfer agent and registrar is Computershare Ltd. The registers for transfers of our common shares are maintained by Computershare Trust Company of Canada at its principal offices in Toronto, Ontario. Queries should be directed to Computershare Trust Company at 1-888-267-6555 (toll free in North America).

Annual Information Form     INTEROIL CORPORATION     44

AUDIT COMMITTEE

Charter of the Audit Committee

A copy of the Charter of the Audit Committee is attached at Schedule “B” hereto.

Composition of the Audit Committee

The current members of the Audit Committee are: Gaylen J. Byker, Edward Speal and Donald R. Hansen. Mr. Hansen was appointed a director of InterOil and a member of the Audit Committee on December 29, 2006.

Each of Mr. Bykes, Speal and Hansen is independent and financially literate within the meaning of MI 52-110.

Relevant Education and Experience

The current members of the Audit Committee have the following relevant education and experience:

Gaylen J. Byker	Gaylen J. Byker is President of Calvin College, a liberal arts institution of higher learning, located in Grand Rapids, Michigan. 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.
Edward Speal	Edward N. Speal is based in Toronto, Ontario and is President and CEO of BNP Paribas (Canada). Previously, Mr. Speal was 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 1996 to 2000. 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.
Donald R. Hansen	Donald R. Hansen is currently Managing Director with Scotia Waterous in their Calgary, Alberta head office. His focus is on the Private Equity side of their business. Mr. Hansen is also Chief Executive Officer of his privately owned oil and gas consulting company, Red Deer River Energy Corp. Formerly, Mr. Hansen was Vice President, International Energy Operations for Unocal Corp. in Houston, Texas. In his capacity with Unocal in Houston, Mr. Hansen had regional VP responsibilities for West Africa, Latin America, Caspian, China, Europe, Russia, Alaska and Canada as well as new international ventures. Prior to moving to Houston with Unocal, Mr. Hansen resided in Calgary, Alberta and was President and CEO of Northrock Resources Ltd., the Canadian business unit and a wholly owned subsidiary of Unocal Corporation. Northrock Resources Ltd. was a Canadian publicly traded exploration

Annual Information Form     INTEROIL CORPORATION     45

and production company that was sold to Unocal in 2000. Mr. Hansen was President and CEO of Northrock Resources Ltd., and helped build the company from a virtual start-up to over 30,000 boed of production. Prior to Northrock, Mr. Hansen was Vice President Operations for Sceptre Resources and held positions in production engineering, exploitation and gas marketing at Dome Petroleum and Amoco Canada.

Mr. Hansen has had over 26 years of Exploration and Production experience. He joins InterOil with significant board experience and has served on the boards of Black Gold Energy LLC, several Unocal domestic and foreign subsidiaries, Asia Society Texas, Houston, the Unocal Foundation and Northrock Resources Ltd. Mr. Hansen has also served two terms as Governor, Canadian Association of Petroleum Producers in Calgary, and has served on the boards of; YMCA, Calgary, North West Family Church, Calgary, and a private technology company, Outland Technologies Inc. In 1980, Mr. Hansen earned a Bachelor of Science degree in engineering from the University of Saskatchewan with great distinction.

Reliance on Exemptions

InterOil relied on the exemption in Section 3.5 of MI 52-110 as a result of the resignation by Michael Foley as a director of InterOil and a member of the Audit Committee effective October 1, 2006. With the appointment of Mr. Hansen as a director of InterOil and member of the Audit Committee on December 29, 2006, InterOil no longer is relying on any exemption from the application of MI 52-110.

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, Audited – Related Fees, Tax Fees and All Other Fees billed by PricewaterhouseCoopers and, prior to June 6, 2005, KPMG in each of the last two financial years ended December 31, 2006.

	2005		2006
Audit Fees(1)	$	333,334	$	618,669
Audit-Related Fees(2)	$	10,180	$	84,383
Tax Fees(3)	$	9,900	$	nil
All Other Fees(4)	$	22,884	$	124,364
Total	$	376,298	$	827,416

Notes:
(1)	“Audit Fees” means the aggregate fees billed by the issuer’s external auditor in each of the last two fiscal years for audit fees.
(2)	“Audit-Related Fees” means the aggregate fees billed in each of the last two fiscal years for assurance and related services by the issuer’s external auditor that are reasonably related to the performance of the audit or review of the issuer’s financial statements and are not reported under clause (a) above.
(3)	“Tax Fees” means the aggregate fees billed in each of the last two fiscal years for professional services rendered by the issuer’s external auditor for tax compliance, tax advice, and tax planning.
(4)	“All Other Fees” means the aggregate fees billed in each of the last two fiscal years for products and services provided by the issuer’s external auditor, other than the services reported under clauses Audit-Related Fees, Tax Fees and All Other Fees above and principally relate to assistance responding to the SEC queries on 40-F of December 31, 2005 and also the quarterly review of financial statements.

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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 management information circular for our upcoming annual meeting of shareholders. Additional financial information is provided in our audited consolidated financial statements and related management’s discussion and analysis for the year ended December 31, 2006. Our audited financial statements, management’s discussion and analysis and additional information can be found on SEDAR at www.sedar.com and on our web site 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 Anesti Dermedgoglou, Vice President of Investor Relations at level 1, 60-92 Cook Street, Portsmith, QLD 4870, Australia; Australian Phone: +61 (7) 4046-4600.

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GLOSSARY OF TERMS

Barrel, Bbl (petroleum) Unit volume measurement used for petroleum and its products; 1 barrel = 42 US gallons, 35 Imperial gallons (approx.), or 159 liters (approx.); 7.3 barrels = 1 ton (approx.); 6.29 barrels = 1 cubic meter = 35.32 cubic feet.

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.

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.

Feedstock Raw material used in a processing plant.

GAAP Generally accepted accounting principles.

IPF InterOil Power Fuel. InterOil’s marketing name for low sulphur waxy residue oil.

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.

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. Acceptable first reference abbreviation. LNG is moved in tankers, not via pipelines. LNG, which is predominantly methane, artificially liquefied, is not to be confused with NGLs, natural gas liquids, heavier fractions which occur naturally as liquids. See also natural gas.

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.

Mark-to-market To revalue futures/option positions using current market prices to determine profit/loss. The profit/loss can then be paid, collected or simply tracked daily.

Naphtha That portion of the distillate obtained in the refinement of petroleum which is intermediate between the lighter gasoline and the heavier benzene, and has a specific gravity of about 0.7, used as a solvent for varnishes, illuminant, etc.

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.

Natural gas measurements The following are some of the standard abbreviations used in natural gas measurement.

Mcf: standard abbreviation for 1,000 cubic feet.
Bil cu ft: Billion cubic feet. Also abbreviated to bcf.
Tcf: trillion cubic feet.

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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.

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.

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Schedule A

FORM 51-101F3

REPORT OF MANAGEMENT AND
DIRECTORS ON OIL AND GAS DISCLOSURE

Management of InterOil Corporation (the “Company”) is responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and
	(ii)	the related estimated future net revenue; and
(b)	(i)	proved oil and gas reserves estimated as at December 31, 2006 using constant prices and costs; and
	(ii)	the related estimated future net revenue.

The Company does not have any reserves as defined under National Instrument 51-101.

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 approved:

(a)	the content and filing with securities regulatory authorities of the other oil and gas information;
(b)	the content and filing of this report.

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

/s/ Phil E. Mulacek	/s/ Gaylen J. Byker
Phil E. Mulacek, Chairman and	Gaylen J. Byker, Director
Chief Executive Officer
/s/ Christian M. Vinson	/s/ Roger N. Grundy
Christian M. Vinson,	Roger N. Grundy, Director
Officer and Director
Dated: March 30, 2007

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Schedule B

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.

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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.

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

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	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.
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 “proforma,” “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.

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

5. Independent Auditors.

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

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

Annual Information Form     INTEROIL CORPORATION     54

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.

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

Annual Information Form     INTEROIL CORPORATION     55

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.

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 generally accepted accounting principles.

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

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EX-99.2

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

Years ended December 31, 2006, 2005 and 2004

1

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

Table of contents

Management’s Report	1
Auditor’s Report to the Shareholders	4
Revised Consolidated Balance Sheets	6
Revised Consolidated Statements of Operations	7
Revised Consolidated Statements of Cash Flows	8
Revised Consolidated Statements of Shareholders’ Equity	9
Notes to the Revised Consolidated Financial Statements	10
Revised Reconciliation to accounting principles generally accepted in the United States	39

2

InterOil Corporation
Revised 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 2006 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.

As noted in the superseded consolidated financial statements for the Company for the year ended December 31, 2006 issued on March 30, 2007, Management has been liaising with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005. The queries were primarily in relation to the accounting treatment of the Indirect Participation Interest agreement # 3 (refer to note 19) as a conveyance in accordance with SFAS 19 – ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’. The SEC staff had also raised comments about other matters related to the accounting treatment of Indirect Participation Interest agreement # 3 such as the bifurcation of the derivative, the fair value methodologies applied and the application of accretion expense.

Based on discussions with the SEC staff, Management has restated the consolidated financial statements for the year ended December 31, 2006 and 2005 to reflect a revised model for the accounting treatment of non-financial liability relating to indirect participation interest. These revised consolidated financial statements reflect all changes that have been made in relation to the revised model for the accounting treatment of this non-financial liability in the balance sheet of InterOil as at December 31, 2006 and December 31, 2005, and the statements of operations, shareholders’ equity and cash flows for each of the years then ended. These revised consolidated financial statements will have the effect of superseding the previously issued consolidated financial statements for year ended December 31, 2006 and 2005 on March 30, 2007.

Management’s original model, reflected in the superseded consolidated financial statements, considered there was sufficient evidence within the terms of the agreement to support the view that the conveyance of a mineral interest had occurred and should be accounted for in accordance was SFAS 19. Management applied judgment to the facts presented and concluded that sufficient risks and benefits of ownership had passed to the IPI investors. The equity conversion option was considered incidental and designed to recoup some of the initial investment if all 8 wells in the program were dry and abandoned.

Management has adopted a revised model which recognizes the equity conversion option feature present in the IPI agreement as an impediment to conveyance accounting under SFAS 19. Based on the revised treatment, the non-financial liability will be maintained at the previously determined undiscounted value ($105,000,000 less transaction costs) until the conveyance is deemed to have occurred. The conveyance will take place if the share conversion option is forfeited which occurs when the investors decide to convert their indirect participation interest in the program into a direct interest in the Production Development Licence (‘PDL’) for a successful well or by other means as specified in the agreement. This is based on the view that the investors have the option to convert their IPI interest into InterOil’s shares at any point in time from the date of the agreement until the equity conversion option is forfeited. The conversion of the option to shares during the exploration program would have resulted in funding provided by the IPI investors being the purchase price for InterOil’s shares rather than funding for a participation interest in InterOil’s exploration program.

1

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

Management has adopted an accounting policy change to value the liability component first and assign the residual value to the equity component. This is in contrast to the relative fair value approach adopted earlier to value the liability and equity components in the contract. The residual basis methodology has been adopted due to difficulties in reliably estimating the fair value of the equity component (taking into account all the scenarios in which the values of both the drilling program interests and common shares could change) and appropriately applying the relative fair value approach. The non-financial liability has been valued at $105,000,000, being the estimated expenditures to complete the eight well drilling program (same estimate as disclosed in December 31, 2005 financials), and the residual value of $20,000,000 has been allocated to conversion option presented under Shareholder’s equity.

Given below is a summary of revised accounting treatment of the indirect participation interest contract and its impact on the consolidated financial statements:

- Conveyance accounting under SFAS 19 adopted by the Company from day one under the original model has been reversed and non-financial liability maintained at initially recognized value of $105,000,000, being the estimated cost of completing the eight well program, less transaction costs. The remaining $20,000,000 has been bifurcated and presented under equity for conversion options under residual basis. Under the revised model adopted, conveyance accounting will be triggered only on the lapse of conversion option available to the investors or they elect to participate in the PDL for a successful well. This adjustment has the effect of increasing the IPI liability from the superseded balance as at December 31, 2006 by $51,259,148 (2005 — $31,774,513).

- As conveyance accounting is not triggered from day one under the revised model, the Company will account for the exploration costs relating to the eight well program under successful efforts accounting policy adopted by the Company as noted under note 3(r) – ‘Oil and gas properties’. All geological and 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. Under the earlier model, all costs relating to the eight well exploration program (covered by the IPI Agreement) was directly offset against the IPI liability and not capitalized to ‘Oil and gas properties’ or expensed in InterOil’s Statement of income. This was based on Management’s view that the conveyance had occurred from day one of the Agreement and these exploration costs were being expended on behalf of the IPI Investors, reducing the IPI liability in the process. This adjustment would result in higher exploration expenses and exploration impairment in both financial years, 2006 and 2005, relating to G&G costs and exploration impairment relating to Black Bass and Triceratops prospects. This adjustment has the effect of increasing the exploration costs for the year ended December 31, 2006 by $4,519,195 (2005 – $11,009,434) and exploration impairment for the year ended December 31, 2006 by $1,230,262 (2005 – $17,425,644).

- Management has adopted an accounting policy change to use residual value approach and value the liability component first and assign the residual value to the equity component. The residual basis methodology has been adopted due to difficulties in reliably estimating the fair value of the equity component (taking into account all the scenarios in which the values of both the drilling program interests and common shares could change) and appropriately applying the relative fair value approach. The non-financial liability has been valued at $105,000,000, being the estimated expenditures to complete the eight well drilling program (same estimate as disclosed in December 31, 2005 financials), and the residual value of $20,000,000 has been allocated to conversion option presented under Shareholder’s equity. This adjustment has the effect of increasing the IPI liability from the superseded balance as at December 31, 2006 by $5,475,368 (2005 — $5,475,368).

- For U.S. GAAP reporting, the Company has opted to utilize the scope exception under SFAS 133 Para 10(f) for ‘derivatives that serve as impediments to sales accounting’. This will result in non-financial liability maintained at full value of $125,000,000 less the transaction costs. This adjustment has the effect of increasing the IPI liability from the superseded balance as at December 31, 2006 by $27,249,587 (2005 — $27,249,587). The IPI liability balance will also be impacted by the revaluation of the conversion option noted below.

- As a result of adopting the revised model, the conversion option will no longer be bifurcated and revalued under U.S. GAAP. This will result in the reversal of all revaluations performed at each period end for U.S. GAAP reporting. This adjustment will have the impact of reducing the U.S. GAAP loss for year ended December 31, 2006 by $19,755,017 (2005 — increase the loss by $4,279,284). This adjustment will also have the corresponding effect on ‘IPI liability’ balance carried forward in the balance sheet.

- Under Canadian GAAP, should the conversion option be exercised by an investor, the non-financial liability and conversion option feature relating to that investor would be transferred to share capital for the number of shares issued. Under U.S. GAAP, should the conversion option be exercised by an investor, only the non-financial liability relating to that investor would be transferred to share capital as the conversion option is no longer bifurcated. There were no exercise of the conversion option to InterOil shares during the financial years ended December 31, 2006 and 2005.

2

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

- As noted above, the Company had, under the original model, bifurcated the non-financial liability and equity conversion option feature, and based on this allocation, the initial value of the non-financial liability did not represent the total expected cash costs to fulfill the contract. InterOil had accreted the non-financial liability upwards to reflect the cost of completion of the eight well program over the budgeted timeline of the program. Based on the revised model, the liability is maintained at full value and accretion costs are no longer recognized. This adjustment has the effect of reducing the loss for the year ended December 31, 2006 by $3,514,368 (2005 – $5,647,491).

- Management has applied the same methodology on the discounting and accretion expense in relation to the PNG Drilling Ventures liability and reversed the initial discounting of the liability on recognition and the related accretion charges. This adjustment has the effect of increasing the ‘Loss on amendment of Indirect Participation Interest – PNGDV’ by $404,520 (2005 – nil) and decreasing the accretion expense by $226,886 (2005 – nil) resulting in a net income statement impact of increasing the loss for the for the year ended December 31, 2006 by $177,634 (2005 – nil). These adjustments have the corresponding effect of increasing the Indirect Participation Interest – PNGDV’ liability as at December 31, 2006 by the net amount.

- When conveyance is triggered on election by the investors to participate in a Production Development Licence (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. There is no impact on the consolidated financial statements for the years ended December 31, 2006 and 2005 due to this adjustment as conveyance has not yet occurred under the revised model during these years.

- The net receipt of funds from IPI investors as part of the IPI#3 Agreement amounting to $116,861,259 was previously disclosed as part of proceeds from investing activities in the Statement of Cash flows. This has now been revised and the amount disclosed as proceeds from financing activities.

- Under Canadian GAAP, the impact of all the above adjustments on the consolidated statement of income for the years ended December 31, 2006 and 2005 has been an increase in the loss by $2,412,723 ($0.08 per share) and $22,787,587 ($0.79 per share) respectively.

- Under U.S. GAAP, the impact of all the above adjustments on the consolidated statement of income for the years ended December 31, 2006 and 2005 has been an decrease in the loss by $17,342,294 ($0.59 per share) and increase in the loss by $27,066,871 ($0.94 per share) respectively.

- In accordance with IPI Agreement, InterOil has made cash calls for the extended well programs performed on the exploratory wells that form part of the IPI Agreement, i.e. Black Bass and Triceratops. These are additional cash calls made from the IPI investors for their interest in specific extended well programs undertaken by the Company. These cash calls were shown as a liability when received and reduced as amounts were spent on the extended well programs. There has been no change to the accounting treatment of the cash calls as these amounts are received for specific programs and there is no conversion option feature or any changes to the investor participation interest due to contributions to these cash calls.

Management would like to emphasize that the changes to the accounting treatment resulting from the adoption of the revised model for the recording of the IPI Agreement will not affect the cash position of the company.

For further details regarding the revisions made to the consolidated financial statements, and reconciliations of the restated and superseded balances, please refer note 2 of the consolidated financial statements.

Phil Mulacek	Collin Visaggio
Chief Executive Officer	Chief Financial Officer

3

INDEPENDENT AUDIT REPORT TO THE SHAREHOLDERS OF INTEROIL CORPORATION

We have audited the revised balance sheet of InterOil Corporation as at December 31, 2006 and December 31, 2005, and the revised statements of operations, shareholders’ equity and cash flows for each of the years 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 audit.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these revised financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2006 and December 31, 2005 and the results of its operations and its cash flows for each of the years then ended in accordance with Canadian generally accepted accounting principles.

Our previous report dated March 30, 2007 has been withdrawn and the financial statements have been revised as explained in Note 2 and the US GAAP reconciliation in Note 27.

(Signed) PricewaterhouseCoopers

Melbourne, Australia
March 30, 2007, except as to Note 2 and Note 27 which are as of October 29, 2007

4

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheet of InterOil Corporation as at December 31, 2004 and the consolidated statements of operations, shareholders’ equity, and cash flows for the year ended December 31, 2004. 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 audit.

We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2004 and the results of its operations and its cash flows for the year ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.

(signed) KPMG

Sydney, Australia
March 4, 2005

5

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

	As at
	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Assets
Current assets:
Cash and cash equivalents (note 6)		31,681,435			59,601,807			28,544,398
Cash restricted (note 8)		29,301,940			16,452,216			15,497,127
Trade receivables (note 9)		67,542,902			49,958,973			58,698,069
Commodity derivative contracts (note 8)		1,759,575			1,482,798			503,500
Other assets		2,954,946			1,011,195			806,123
Inventories (note 10)		67,593,558			44,087,484			27,916,902
Prepaid expenses		880,640			638,216			190,135
Total current assets		201,714,996			173,232,689			132,156,254
Cash restricted (note 8)		3,217,284			210,053			102,096
Deferred financing costs (note 18)		1,716,757			1,256,816			1,311,488
Plant and equipment (note 11)		242,642,077			237,399,148			244,363,355
Oil and gas properties (note 12)		54,524,347			19,738,927			6,605,360
Future income tax benefit (note 13)		1,424,014			1,058,898			1,303,631
Total assets		505,239,475			432,896,531			385,842,184
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities		73,310,793			26,005,034			26,328,544
Income tax payable		2,784,576			3,900,459			2,881,398
Working capital facility — crude feedstock (note 14)		36,873,508			70,724,322			76,520,541
Deferred hedge gain (note 8)		1,385			1,016,998			537,358
Business combination financing (note 15)		—			—			12,123,106
Unsecured loan (note 17)		—			21,453,132			—
Due to related parties (note 16)		—			—			1,056,251
Deferred liquefaction project liability (note 18)		6,553,080			—			—
Current portion of secured loan (note 18)		13,500,000			9,000,000			9,000,000
Current portion of indirect participation interest — PNGDV (note 19)		730,534			—			—
Total current liabilities		133,753,876			132,099,945			128,447,198
Accrued financing costs (note 18)		1,087,500			921,109			863,329
Secured loan (note 18)		184,166,433			71,500,000			76,000,000
Indirect participation interest (note 19)		96,861,259			96,861,259			13,749,852
Indirect participation interest — PNGDV (note 19)		1,190,633			9,685,830			10,608,830
Total liabilities		417,059,701			311,068,143			229,669,209
Non-controlling interest (note 20)		5,759,206			6,023,149			6,404,262
Shareholders’ equity:
Share capital (note 21)		233,889,366			223,934,500			216,813,654
Authorised — unlimited
Issued and outstanding - 29,871,180 (Dec 31, 2005 - 29,163,320) (Dec 31, 2004 - 28,310,884)
Contributed surplus		4,377,426			2,933,586			1,841,776
Warrants (note 23)		2,137,852			2,137,852			2,258,227
Foreign currency translation adjustment		1,492,869			477,443			463,200
Conversion options (note 19)		20,000,000			20,000,000			—
Accumulated deficit		(179,476,945	)		(133,678,142	)		(71,608,144	)
Total shareholders’ equity		82,420,568			115,805,239			149,768,713
Total liabilities and shareholders’ equity		505,239,475			432,896,531			385,842,184

See accompanying notes to the consolidated financial statements. Commitments and contingencies (note 25)

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

6

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

	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Revenue
Sales and operating revenues		511,087,934			481,180,645			70,644,486
Interest		3,223,995			1,830,808			382,461
Other		3,747,603			528,270			196,337
		518,059,532			483,539,723			71,223,284
Expenses
Cost of sales and operating expenses		499,494,540			467,246,990			65,344,516
Administrative and general expenses		20,728,618			14,672,793			7,831,550
Depreciation and amortization		12,352,672			11,036,550			639,075
Exploration costs, excluding exploration impairment (note 12)		6,176,866			11,009,434			2,903,313
Exploration impairment (note 12)		1,647,185			19,570,073			35,566,761
Legal and professional fees		3,937,517			3,606,415			3,573,727
Short term borrowing costs		8,478,540			8,855,857			4,705,190
Long term borrowing costs		11,856,872			6,351,337			1,401,256
Loss on amendment of indirect participation interest — PNGDV (note 19)		1,851,421			—			—
Foreign exchange loss/(gain)		(4,744,810	)		796,590			392,805
		561,779,421			543,146,039			122,358,193
Loss before income taxes and non-controlling interest		(43,719,889	)		(59,606,316	)		(51,134,909	)
Income taxes
Current		(1,232,487	)		(2,605,265	)		(2,538,410	)
Future		(1,110,386	)		(226,729	)		663,347
		(2,342,873	)		(2,831,994	)		(1,875,063	)
Loss before non-controlling interest		(46,062,762	)		(62,438,310	)		(53,009,972	)
Non-controlling interest (note 20)		263,959			368,312			70,091
Net loss		(45,798,803	)		(62,069,998	)		(52,939,881	)
Basic loss per share (note 21)		(1.55	)		(2.15	)		(2.09	)
Diluted loss per share (note 21)		(1.55	)		(2.15	)		(2.09	)
Weighted average number of common shares outstanding
Basic and diluted		29,602,360			28,832,263			25,373,575

See accompanying notes to the consolidated financial statements

7

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

	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Cash flows provided by (used in):
Operating activities
Net (loss) (note 5)		(45,798,803	)		(62,069,998	)		(52,939,881	)
Adjustments for non-cash transactions
Non-controlling interest		(263,959	)		(381,113	)		(70,091	)
Depreciation and amortization		12,352,672			11,036,550			639,075
Future income tax asset		1,333,108			244,733			(663,347	)
Loss/(gain) on sale of other assets		—			—			(94,260	)
Loss/(gain) on sale of plant and equipment		263,945			(95,053	)		—
Impairment of plant and equipment		755,857			—			—
Amortization of discount on debt		28,891			161,255			604,045
Amortization of deferred financing costs		219,033			154,672			268,873
Debt conversion settlement expense — debentures (note 23)		—			—			77,589
Interest expense forfeited by debenture holders		—			—			998,438
Loss/(gain) on unsettled hedge contracts		(71,875	)		119,200			33,858
Gain on derivative contracts		(1,220,500	)		(585,000	)		—
Stock compensation expense		1,976,072			1,668,896			1,209,921
Inventory revaluation		—			355,215			1,508,334
Oil and gas properties expensed		7,824,051			30,579,507			38,470,074
Loss on amendment of indirect participation interest — PNGDV		1,851,421			—			—
Unrealized foreign exchange loss/(gain)		(4,744,810	)		796,590			392,805
Non-cash interest on secured loan facility		2,926,025			—			—
Change in non-cash operating working capital
(Increase)/decrease in trade receivables		(6,663,218	)		8,751,789			(49,224,125	)
(Increase) in commodity derivative contracts		—			(33,858	)		—
(Increase)/decrease in other assets and prepaid expenses		4,051			(653,153	)		982,014
Decrease/ (increase) in inventories		2,642,493			(16,515,467	)		(23,240,590	)
Increase in accounts payable, accrued liabilities and income tax payable		28,773,008			3,752,531			4,183,664
		2,187,462			(22,712,704	)		(76,863,604	)
Investing activities
Expenditure on oil and gas properties		(47,990,758	)		(43,023,990	)		(22,057,419	)
Expenditure on plant and equipment		(13,585,792	)		(5,575,194	)		(38,947,904	)
Proceeds received on sale of assets		3,770,080			112,229			405,353
Redemption of short-term investments		—			—			24,723,572
Acquisition of subsidiary net of cash received (note 15)		(25,820,515	)		—			4,631,904
Repayment of business combination financing		—			(12,226,581	)		—
(Increase) in restricted cash held as security on borrowings		(15,856,955	)		(1,063,046	)		(15,501,806	)
Change in non-cash working capital
Increase/(decrease) in accounts payable and accrued liabilities		2,412,621			(3,165,756	)		4,094,594
		(97,071,319	)		(64,942,338	)		(42,651,706	)
Financing activities
Repayments of secured loan		(4,500,000	)		(4,500,000	)		—
Proceeds from indirect participation interest		—			103,111,405			13,749,852
Proceeds from secured loan, net of transaction costs		125,293,488			—			2,000,000
Net proceeds from senior convertible debentures and warrants		—			—			41,740,234
Proceeds from conversion options		—			—			3,235,000
Proceeds from related party borrowings		—			—			1,775,565
(Repayments) to related parties		—			(1,056,251	)		(2,198,065	)
Proceeds from unsecured borrowings		—			21,453,132			5,100,000
Repayments of unsecured borrowings		(21,453,132	)		—			(5,100,000	)
Proceeds from/(repayments of) working capital facility		(33,850,814	)		(5,796,219	)		76,520,541
Proceeds from issue of common shares		1,473,943			5,500,384			2,020,316
		66,963,485			118,712,451			138,843,443
Increase/(decrease) in cash and cash equivalents		(27,920,372	)		31,057,409			19,328,133
Cash and cash equivalents, beginning of period		59,601,807			28,544,398			9,216,265
Cash and cash equivalents, end of period (note 6)		31,681,435			59,601,807			28,544,398

See accompanying notes to the consolidated financial statements

See note 5 for non cash financing and investing activities

8

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

	Year ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Share capital
At beginning of period		223,934,500			216,813,654			157,449,200
Adjustment to reflect change in accounting for employee stock options (note 3(t))		—			—			92,434
Issue of capital stock (note 21)		9,954,866			7,120,846			59,272,020
At end of period		233,889,366			223,934,500			216,813,654
Contributed surplus
At beginning of period		2,933,586			1,841,776			540,222
Adjustment to reflect change in accounting for employee stock options (note 3(t))		—			—			645,216
Stock compensation (note 22)		1,443,840			1,091,810			656,338
At end of period		4,377,426			2,933,586			1,841,776
Warrants
At beginning of period		2,137,852			2,258,227			—
Movement for period (note 23)		—			(120,375	)		2,258,227
At end of period		2,137,852			2,137,852			2,258,227
Foreign currency translation adjustment
At beginning of period		477,443			463,200			—
Movement for period, net of tax		1,015,426			14,243			463,200
At end of period		1,492,869			477,443			463,200
Conversion options
At beginning of period		20,000,000			—			—
Movement for period (note 19)		—			20,000,000			—
At end of period		20,000,000			20,000,000			—
Accumulated deficit
At beginning of period		(133,678,142	)		(71,608,144	)		(11,031,402	)
Adjustment to reflect change in accounting for employee stock options (note 3(t))		—			—			(737,650	)
Adjustment to cummulative debentures conversion expense (note 23)		—			—			(6,899,211	)
Net (loss) for period		(45,798,803	)		(62,069,998	)		(52,939,881	)
At end of period		(179,476,945	)		(133,678,142	)		(71,608,144	)
Shareholders’ equity at end of period		82,420,568			115,805,239			149,768,713

See accompanying notes to the consolidated financial statements

9

InterOil Corporation
Notes to Revised 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 includes Liquefaction, Refining and Marketing of products both domestically in Papua New Guinea and for export. 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. Restatement of Consolidated financial statements for the year ended December 31, 2006 and 2005

As noted in the superseded consolidated financial statements for the Company for the year ended December 31, 2006 issued on March 30, 2007, Management has been liaising with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005. The queries were primarily in relation to the accounting treatment of the Indirect Participation Interest agreement # 3 (refer to note 19) as a conveyance in accordance with SFAS 19 – ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’. The SEC staff had also raised comments about other matters related to the accounting treatment of Indirect Participation Interest agreement # 3 such as the bifurcation of the derivative, the fair value methodologies applied and the application of accretion expense.

Based on discussions with the SEC staff, Management has restated the consolidated financial statements for the year ended December 31, 2006 and 2005 to reflect the revised model for the accounting treatment for non-financial liability relating to indirect participation interest. These revised consolidated financial statements reflect all changes that have made in relation to the revised model for the accounting treatment of this non-financial liability in the balance sheet of InterOil as at December 31, 2006 and December 31, 2005, and the statements of operations, shareholders’ equity and cash flows for each of the years then ended. These revised consolidated financial statements will have the effect of superseding the previously issued consolidated financial statements for year ended December 31, 2006 and 2005 on March 30, 2007.

Management has adopted a revised model which recognizes the conversion option feature present in the IPI agreement as an impediment to conveyance accounting under SFAS 19 from day one of the IPI Agreement. Based on the revised treatment, the non-financial liability will be maintained at initially recognized value ($105,000,000 less transaction costs) till the conversion feature in the agreement lapses or is exercised. The revised model proposes that conveyance accounting should not be applied till the investors elect to transfer their indirect participation interest in the program into a direct interest in the Production Development Licence (‘PDL’) for a successful well or forfeiture of the conversion option occurs as per the agreement. This was based on the view that the investors have the option to convert into InterOil’s share at any point in time from the date of the agreement till the option lapses on the occurrence of any of the conditions outlined in the contract. The exercise of the option by the investors during the exploration program would have resulted in funding provided by the IPI investors being in the nature of purchase price for InterOil’s shares rather than funding for a participation interest in InterOil’s exploration program.

Management’s original model, reflected in the superseded consolidated financial statements, was that conveyance accounting under SFAS 19 was triggered from day one as the intent of the IPI agreement was for the investors to fund eight well exploration program in Papua New Guinea in return for a twenty five percent interest in successful wells. Management’s earlier view was that the conversion option was considered only incidental to recoup some of the initial investment and would only be exercised if all the wells were dry and abandoned. The conversion option was fair valued by the management, bifurcated and disclosed separately, under equity, from the non-financial liability.

The conversion option feature in the IPI Agreement was valued and bifurcated using relative fair value approach based on CICA 3861 – ‘Financial Instruments Disclosure and Presentation’. CICA 3861 Para .22 gives the option to value the components using the relative fair value approach (as adopted earlier) or the residual method by valuing the easier component first. Management has adopted an accounting policy change to value the liability component first and assign the residual value to the equity component. This revised residual basis methodology has been adopted due to difficulties in reliably estimating the fair value of the equity component (taking into account all the scenarios in which the values of both the drilling program interests and common shares could change) and appropriately applying the relative fair value approach. The non-financial liability has been valued at $105,000,000, being the estimated expenditures to complete the eight well drilling program (same estimate as disclosed in December 31, 2005 financials), and the residual value of $20,000,000 has been allocated to conversion option presented under Shareholder’s equity.

10

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

2. Restatement of Consolidated financial statements for the year ended December 31, 2006 and 2005 (cont’d)

Management has also resolved not to discount the liability on recognition and accrete the balance over the life of the exploration program. The transaction costs relating to the transaction amounting to $8,138,742 has been presented in accordance with EIC-94 – “Accounting for Corporate Transaction Costs”, which indicates that costs that are related to debt, should be presented as a non-current deferred charge in a classified balance sheet. The investors signed an amendment to the IPI agreement which clarified certain provisions of the IPI Agreement on the nature of costs that could be incurred with the IPI funds, including deductibility of transaction costs relating to the IPI Agreement from the IPI proceeds received on signing the agreement. As a result, the full amount of the costs relating to the IPI Agreement will be netted off against the liability.

Given below is a summary of revised accounting treatment of the indirect participation interest contract and its impact on the consolidated financial statements:

Restatement to Consolidated Balance Sheets

	December 31, 2006									December 31, 2005
	Original						Restated			Original					Restated
	Balance			Adjustments			Balance			Balance		Adjustments			Balance			Reference
	$			$			$			$		$			$
Non-current assets
Oil and gas properties (note 12)		37,449,734			17,074,613			54,524,347			16,399,492		3,339,435			19,738,927		(i), (ii)
Current and Non-current liabilities
Indirect participation interest (note 19)		49,288,602			47,572,657			96,861,259			65,258,869		31,602,390			96,861,259		(i), (iii), (iv)
Indirect participation interest — PNGDV (note 19)		1,743,533			177,634			1,921,167			9,685,830		—			9,685,830		(vi)
Shareholders’ Equity
Conversion options (note 19)		25,475,368			(5,475,368	)		20,000,000			25,475,368		(5,475,368	)		20,000,000		(iii)
Accumulated deficit (Refer ‘Restatement to Consolidated Statement of Operations’ below)		(154,276,635	)		(25,200,310	)		(179,476,945	)		(110,890,555		) (22,787,587	)		(133,678,142	)

Restatement to Consolidated Statement of Operations

	Year ended December 31, 2006							Year ended December 31, 2005
	Original					Restated		Original					Restated
	Balance		Adjustments			Balance		Balance		Adjustments			Balance		Reference
	$		$			$		$		$			$
Expenses
Exploration costs, excluding exploration impairment (note 12)		1,657,671		4,519,195			6,176,866		—		11,009,434			11,009,434	(ii)
Exploration impairment (note 12)		416,923		1,230,262			1,647,185		2,144,429		17,425,644			19,570,073	(ii)
Accretion expense (note 19)		3,741,254		(3,741,254	)		—		5,647,491		(5,647,491	)		—	(iv), (vi)
Loss on amendment of indirect participation interest — PNGDV (note 19)		1,446,901		404,520			1,851,421		—		—			—	(vi)
Total restated expenses		7,262,749		2,412,723			9,675,472		7,791,920		22,787,587			30,579,507
Net loss		43,386,080		2,412,723			45,798,803		39,282,411		22,787,587			62,069,998

11

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

2. Restatement of Consolidated financial statements for the year ended December 31, 2006 and 2005 (cont’d)

(i) Conveyance accounting under SFAS 19 adopted by the Company from day one under the original model has been reversed and non-financial liability maintained at initially recognized value of $105,000,000, being the estimated cost of completing the eight well program, less transaction costs. The remaining $20,000,000 has been bifurcated and presented under equity for conversion options under residual basis. Under the revised model, conveyance accounting will be triggered only on the lapse of conversion option available to the investors or they elect to participate in the PDL for a successful well. This adjustment has the effect of increasing the ‘IPI liability’ and ‘Oil and gas properties’ from the superseded balance as at December 31, 2006 by $51,259,148 (2005 — $31,774,513).

(ii) As conveyance accounting is not triggered from day one under the revised model, the Company will account for the exploration costs relating to the eight well program under successful efforts accounting policy adopted by the Company as noted under note 3(r) – ‘Oil and gas properties’. All geological and 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. Under the earlier model, all costs relating to the eight well exploration program (covered by the IPI Agreement) was directly offset against the IPI liability and not capitalized to ‘Oil and gas properties’ or expensed in InterOil’s Statement of income. This was based on Management’s view that the conveyance had occurred from day one of the Agreement and these exploration costs were being expended on behalf of the IPI Investors, reducing the IPI liability in the process. This adjustment results in higher exploration expenses and exploration impairment in both financial years, 2006 and 2005, relating to G&G costs and exploration impairment relating to Black Bass and Triceratops prospects. This adjustment has the effect of increasing the exploration costs for the year ended December 31, 2006 by $4,519,195 (2005 – $11,009,434) and exploration impairment for the year ended December 31, 2006 by $1,230,262 (2005 – $17,425,644). These increases to the exploration costs have the corresponding effect of reducing the ‘Oil and gas properties’ carried forward in the balance sheet from the superseded balance (and the adjustments noted above in (i)) as at December 31, 2006 and 2005 by $34,184,535 and $28,434,078 respectively.

(iii) In the superseded financial statements, the conversion option feature in the IPI Agreement was valued and bifurcated using relative fair value approach based on CICA 3861 – ‘Financial Instruments Disclosure and Presentation’. CICA 3861 Para .22 gives the option to value the components using the relative fair value approach (as adopted earlier) or the residual method by valuing the easier component first. Based on discussions with the SEC, Management has adopted an accounting policy change to value the liability component first and assign the residual value to the equity component. This revised residual basis methodology has been adopted due to difficulties in reliably estimating the fair value of the equity component (taking into account all the scenarios in which the values of both the drilling program interests and common shares could change) and appropriately applying the relative fair value approach. The non-financial liability has been valued at $105,000,000, being the estimated expenditures to complete the eight well drilling program (same estimate as disclosed in December 31, 2005 financials), and the residual value of $20,000,000 has been allocated to conversion option presented under Shareholder’s equity. This revision was made as it was determined that the non-financial liability component was more easily measurable that the conversion option feature. This adjustment has the effect of increasing the IPI liability and correspondingly reducing the Conversion options from the superseded balance as at December 31, 2006 by $5,475,368 (2005 — $5,475,368).

(iv)

As noted above, the Company had, under the original model, bifurcated the non-financial liability and conversion option feature, and based on this allocation, the initial value of the non-financial liability did not represent the total expected cash costs to fulfill the contract. InterOil had drawn comparisons between this situation and the accounting approach that is adopted with respect to mandatory redeemable securities, where there can also be a difference between the initial value of the security and the redemption price, and accreted the non-financial liability upwards to reflect the cost of completion of the eight well program over the budgeted timeline of the program. Based on the revised model, the liability is maintained at the undiscounted value and accretion costs are no longer recognized. This adjustment has the effect of reducing the loss for the year ended December 31, 2006 by $3,514,368 (2005 – $5,647,491).

These decreases to the accretion expenses have the corresponding effect of increasing the IPI liability in the balance sheet as at December 31, 2006 and 2005 from the superseded balance by $9,161859 and $5,647,491 respectively.

(v) 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. There is no impact on the consolidated financial statements for the years ended December 31, 2006 and 2005 due to this adjustment as conveyance has not been triggered based on this revised model during these years.

12

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

2.	Restatement of Consolidated financial statements for the year ended December 31, 2006 and 2005 (cont’d)
(vi)	Management has applied the same methodology on the discounting and accretion expense in relation to the PNG Drilling Ventures liability and reversed the initial discounting of the liability on recognition and the related accretion charges. This adjustment has the effect of increasing the ‘Loss on amendment of Indirect Participation Interest – PNGDV’ by $404,520 (2005 – nil) and decreasing the accretion expense by $226,886 (2005 – nil) resulting in a net income statement impact of increasing the loss for the for the year ended December 31, 2006 by $177,634 (2005 – nil). These adjustments have the corresponding effect of increasing the Indirect Participation Interest – PNGDV’ liability as at December 31, 2006 by the net amount.
(vii)	The impact of all the above adjustments on the consolidated statement of income for the years ended December 31, 2006 and 2005 has been an increase in the loss by $2,412,723 ($0.08 per share) and $22,787,587 ($0.79 per share) respectively.
(viii)	The net receipt of funds from IPI investors as part of the IPI#3 Agreement amounting to $116,861,259 was previously disclosed as part of proceeds from investing activities in the Statement of Cash flows. This has now been revised and the amount disclosed as proceeds from financing activities in the respective years.
(ix)	In accordance with IPI Agreement, InterOil has made cash calls for the extended well programs performed on the exploratory wells that form part of the IPI Agreement, i.e. Black Bass and Triceratops. These are additional cash calls made from the IPI investors for their interest in specific extended well programs undertaken by the Company. These cash calls were shown as a liability when received and reduced as amounts were spent on the extended well programs. There has been no change to the accounting treatment of the cash calls as these amounts are received for specific programs and there is no conversion option feature or any changes to the investor participation interest due to contributions to these cash calls.

Management would like to emphasize that the changes to the accounting treatment resulting from the adoption of the revised model for the recording of the IPI Agreement will not affect the cash position of the company.

3. 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 27, Reconciliation to Accounting Principles Generally Accepted in the United States.

The consolidated financial statements for the year ended December 31, 2006 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.

(b) Principles of consolidation

The consolidated financial statements of the Company incorporates the assets and liabilities of InterOil Corporation as at December 31, 2006, December 31, 2005, December 31, 2004 and the results of all subsidiaries for the years then ended. Subsidiaries of InterOil Corporation include SP InterOil, LDC (“SPI”) (99.9%), SPI Exploration and Production Corporation (100%), SPI Distribution Limited (100%), InterOil Australia Pty Ltd (100%), SPI InterOil Holdings Limited (100%), Direct Employment Services Company (100%), PNG LNG, 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 is 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 has set up PNG LNG (Inc), a Bahamas incorporated entity, to construct and operate a Liquefied Natural Gas facility (‘LNG Project’) in PNG. The results of the LNG Project has been disclosed separately within the segment notes, refer to note 5.

13

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

3. Significant accounting policies (cont’d)

Subsidiaries are all those entities over which the Company has the power to govern the financial and operating policies generally accompanying a shareholding of more than one-half of the voting rights. 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 3(h). 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.

(c) Going concern

These consolidated financial statements assume that InterOil will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of operations and therefore the consolidated financial statements do not include any adjustments relating to the recoverability of assets.

As shown in the consolidated financial statements, the Company incurred a net loss of $45.8 million (2005 — $62.1 million, 2004 – $53.0 million) and generated cash from its operating activities of $2.2 million (2005 — $22.7 million, 2004 — $79.8 million) during the year ended December 31, 2006. The Company had cash and cash equivalents of $31.7 million (2005 — $59.6 million, 2004 — $28.5 million) and $32.5 million (2005 — $16.7 million, 2004 — $15.6 million) in restricted cash as at December 31 2006. The Company believes that this is sufficient to fund on-going operations. The current financial condition, among other factors, indicates that with focused management and the continued support of lenders InterOil has the ability to continue as a going concern.

The Company’s continuation as a going concern is dependent upon its ability to internally generate or externally raise additional cash to allow for the satisfaction of its obligations on a timely basis. InterOil is actively optimizing the business, improving cash generated from operations and exploring various financing alternatives. Management has initiated business improvement programs and will continue to manage value enhancing opportunities and reduce expenses until optimal operations are achieved. While the Company is exploring all opportunities to improve its financial condition, there is no assurance that these programs will be successful.

(d) 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 segment of the same enterprise),
b.	whose operating results are regularly reviewed by the Company’s management to make decisions about resources to be allocated to the segment and assess its performance, and
c.	for which discrete financial information is available.

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

(e) Foreign currency translation

Functional and presentation 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 presentation currency.

Group companies

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.

14

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

3.	Significant accounting policies (cont’d)
(f)	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 and of financial position, 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. During the years ended December 31, 2006 and December 31, 2005, sales between the business segments of the Company have been eliminated from sales and operating revenues and cost of sales.

Up to December 31, 2004, the sales between business segments of the Company were eliminated from sales, operating revenues, cost of sales and refinery assets as all revenues and expenses relating to the refinery were capitalized as part of the development stage activities.

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.

(g) 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.

(h) 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.

(i) 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.

15

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

3. Significant accounting policies (cont’d)

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.

(j) 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.

(k) 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.

(l) Trade receivables

The collectibility 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.

(m) Inventory

Raw materials and stores and finished goods

Raw materials and stores 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.

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, labour, direct overheads and transportation costs. The cost of downstream refined petroleum product includes the cost of the product plus related freight, wharfage and insurance.

(n) 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.

16

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

3.	Significant accounting policies (cont’d)
(o)	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 in a separate component of liabilities until earnings are affected by the variability in cash flows of the designated hedged item.

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.

In all situations in which hedge accounting is discontinued, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the Company recognizes it immediately in earnings gains and losses that were previously accumulated in a separate component of liabilities.

The Company enters into crude swaps in order to reduce the impact of fluctuating crude prices on its cost of sales. These swap agreements require the periodic exchange of payments without the exchange of the notional product amount on which the payments are based. The Company designates its crude price swap agreements as hedges of the underlying purchase. Cost of sales is adjusted to include the payments made or received under the crude purchase cost swaps.

The Company enters into naphtha, diesel and jet kerosene swaps in order to reduce the impact of fluctuating naphtha, jet kerosene and diesel prices respectively on its revenue. These swap agreements require the periodic exchange of payments without the exchange of the notional product amounts on which the payments are based. The Company designates its naphtha, diesel and jet kerosene price swap agreements as hedges of the underlying sale. Sales revenue of the respective product is adjusted to include the payments made or received under the price swaps.

(p) Deferred financing costs

Deferred financing costs represent the unamortized financing costs paid to secure borrowings. Amortization is provided on a straight-line basis over the term of the related debt and is included in expenses for the period.

(q) 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. During 2004, the Company was considered to be in the construction and pre-operating stage of development of the oil refinery, however, the pre-operating stage 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.

17

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

3. Significant accounting policies (cont’d)

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 had been incurred at December 31, 2006.

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 has adopted a deminimus threshold of $5,000 below which all capital purchases are expensed in the period of purchase.

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 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, 2006, no provision has been raised.

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.

(r) 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 economical 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.

18

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

3.	Significant accounting policies (cont’d)
(s)	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.

(t) 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 via the Company Option plan and an employee share scheme. The fair value at grant date is independently 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.

Prior to January 1, 2004, the Company applied the fair value based method only to employee stock appreciation rights, and applied the settlement method of accounting to employee stock options. Under the settlement method, any consideration paid by employees on the exercise of stock options or purchase of stock was credited to share capital and no compensation expense was recognized. The Company adopted the fair value based method to account for employee stock options, beginning January 1, 2004. In accordance with one of the transitional options permitted, the Company has retroactively applied the fair value based method to all employee stock options granted on or after January 1, 2002, without restatement to prior periods in the year ended December 31, 2004. The effect of retroactively adopting the fair value based method to the 2004 financial statements, without restatement, was to increase the opening accumulated deficit by $737,650, increase contributed surplus by $645,216 and increase share capital by $92,434.

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.

(u) Earnings per share

Basic earnings per share

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

Diluted earnings per share

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

(v) Reclassification

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

19

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

4. Financial Risk Management

The Company’s activities expose it to a variety of financials 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.

(a) Market risk

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 transactions are undertaken in United States Dollars, hence reducing the foreign exchange risk exposure of the Company. The Papua New Guinea Kina exposures are minimized as the downstream sales in local currency is used to adequately cover the operating expenses of the midstream refinery and downstream operations.

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.

The derivative contracts are entered into by the 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.

Product risk

The composition of the crude feedstock will vary the refinery output of products. The 2006 output achieved includes distillates fuels, which includes diesel, gasoline and jet fuels (65%) (2005 – 55%) and naphtha and low sulphur waxy residue (28%) (2005 – 39%). 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 tries 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) Credit risk

A significant amount of the Company’s export sales are made to one customer in Singapore which represented $86,156,904 (2005 -$151,106,105) or 17% (2005 – 32%) of total sales in the year ended December 31, 2006. The Company’s domestic sales for the period ended December 31, 2006 were not dependent on a single customer or geographic region of Papua New Guinea.

The export sales to one customer cannot be considered a key risk as there is a ready market for InterOil export products and the prices are quoted on active markets.

(c) Liquidity risk

Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and the availability of funding through an adequate amount of committed credit facilities. Due to the dynamic nature of the underlying business, Company Finance aims at maintaining flexibility in funding by keeping committed credit lines available.

(d) Cash flow and fair value interest rate risk

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

20

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

4. Financial Risk Management (cont’d)

The Company’s interest-rate risk arises from long-term 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’s long term borrowings mainly consists of OPIC and Merrill Lynch facilities (refer note 18) and the working capital financing facility is provided by BNP Paribas (refer note 14). Company is actively seeking to manage its cash flow and fair value interest-rate risks.

(e) Geographic risk

The operations of InterOil are concentrated in Papua New Guinea.

5. Segmented financial information (Restated)

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 the Company has started incurring costs in relation to the Liquefaction project which has been reported separately under Midstream – Liquefaction project below.

The foreign exchange loss/(gain) for the years have been disclosed separately during the year to provide additional information to the reader. This item was classified under office and administration and other expenses in the prior periods. The prior period comparatives have been reclassified to reflect the change in disclosure.

During the year, management has also decided to reclassify the interest and other income to the relevant segments to provide additional information to the reader.

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 3.

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.

21

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

5. Segmented financial information (Restated) (cont’d)

Year ended December 31, 2006 (Restated)	Upstream			Midstream - Refining and Marketing			Midstream - Liquefaction			Downstream			Corporate			Consolidation 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
Office and admin and other expenses		6,370,436			8,017,245			694,416			7,671,208			15,378,963			(8,552,604	)		29,579,664
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

				Midstream -
				Refining and			Midstream -								Consolidation
Year ended December 31, 2005 (Restated)	Upstream			Marketing			Liquefaction		Downstream			Corporate			adjustments			Total
Revenues from external customers		—			356,326,763			—		124,853,882			—			—			481,180,645
Intersegment revenues		—			80,094,501			—		6,202			5,345,017			(85,445,720	)		—
Interest revenue		1,011,511			244,157			—		95,317			686,718			(206,895	)		1,830,808
Other revenue		283,634			496			—		245,760			30,509			(32,129	)		528,270
Total segment revenue		1,295,145			436,665,917			—		125,201,161			6,062,244			(85,684,744	)		483,539,723
Cost of sales and operating expenses		—			436,490,554			—		110,857,139			—			(80,100,703	)		467,246,990
Office and admin and other expenses		2,426,909			9,204,613			—		4,724,568			11,608,822			(5,465,658	)		22,499,254
Foreign exchange (gain)/loss		(689,084	)		1,434,498			—		843			50,333			—			796,590
Exploration costs, excluding exploration impairment		11,009,434			—			—		—			—			—			11,009,434
Exploration impairment		19,570,073			—			—		—			—			—			19,570,073
Depreciation and amortisation		314,467			10,598,134			—		204,247			49,732			(130,030	)		11,036,550
Interest expense		—			10,161,899			—		225,450			806,694			(206,895	)		10,987,148
Total segment expenses		32,631,799			467,889,698			—		116,012,247			12,515,581			(85,903,286	)		543,146,039
(Loss)/income before income taxes and non-controlling interest		(31,336,654	)		(31,223,781	)		—		9,188,914			(6,453,337	)		218,542			(59,606,316	)
Income tax expense		—			—			—		(2,755,845	)		(76,149	)		—			(2,831,994	)
Non controlling interest		—			362,140			—		—			—			6,172			368,312
Total net income/(loss)		(31,336,654	)		(30,861,641	)		—		6,433,069			(6,529,486	)		224,714			(62,069,998	)
Total assets		78,926,578			314,904,035			—		47,342,109			317,227,597			(325,503,788	)		432,896,531

22

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

5. Segmented financial information (Restated) (cont’d)

				Midstream -
				Refining and			Midstream -								Consolidation
Year ended December 31, 2004	Upstream			Marketing			Liquefaction		Downstream			Corporate			adjustments			Total
Revenues from external customers		—			26,309,547			—		62,410,291			—			(18,075,352	)		70,644,486
Intersegment revenues		—			—			—		489,111			3,787,944			(4,277,055	)		—
Interest revenue		151,780			8,761			—		56,896			165,024			—			382,461
Other revenue		(39,267	)		(63,031	)		—		205,836			92,799			—			196,337
Total segment revenue		112,513			26,255,277			—		63,162,134			4,045,767			(22,352,407	)		71,223,284
Cost of sales and operating expenses		—			27,685,347			—		53,158,737			—			(15,499,568	)		65,344,516
Office and admin and other expenses		1,649,191			3,167,216			—		3,146,905			10,538,730			(3,766,608	)		14,735,434
Exchange (Gain)/loss		—			(34,121	)		—		—			—			—			(34,121	)
Exploration costs, excluding exploration impairment		2,903,313			—			—		—			—			—			2,903,313
Exploration impairment		35,566,761			—			—		—			—			—			35,566,761
Depreciation and amortisation		12,510			311,986			—		224,214			90,365			—			639,075
Interest expense		4,932			843,888			—		455,368			1,899,027			—			3,203,215
Total segment expenses		40,136,707			31,974,316			—		56,985,224			12,528,122			(19,266,176	)		122,358,193
(Loss)/income before income taxes and non-controlling interest		(40,024,194	)		(5,719,039	)		—		6,176,910			(8,482,355	)		(3,086,231	)		(51,134,909	)
Income tax expense		—			—			—		(1,899,803	)		24,740			—			(1,875,063	)
Non controlling interest		—			68,961			—		—			—			1,130			70,091
Total net income/(loss)		(40,024,194	)		(5,650,078	)		—		4,277,107			(8,457,615	)		(3,085,101	)		(52,939,881	)
Total assets		21,570,219			310,941,494			—		34,436,144			211,530,962			(192,636,636	)		385,842,184

6. Cash and cash equivalents

The components of cash and cash equivalents are as follows:

	December 31,		December 31,		December 31,
	2006		2005		2004
	$		$		$
Cash on deposit		31,681,435		59,597,724		24,224,523
Bank term deposits
- Papua New Guinea kina deposits		—		—		4,315,513
- Australian dollar deposits		—		4,083		4,362
		31,681,435		59,601,807		28,544,398

23

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

7. Supplemental cash flow information

	December 31,		December 31,		December 31,
	2006		2005		2004
	$		$		$
Cash paid during the year
Interest		8,548,552		13,373,832		1,444,006
Income taxes		2,306,218		1,656,985		1,914,459
Interest received		3,154,380		1,800,062		671,479
Non-cash investing and financing activities:
Deferred financing costs included in accounts payable and accrued liabilities		500,000		100,000		—
Accrued financing costs and deferred financing costs		—		—		834,439
Increase in additional paid up capital as a result of a change in accounting policy for stock based compensation (3(t))		—		—		645,216
Decrease in plant and equipment as a result of impairment		755,857		—		—
Deferred liquefaction project liability		6,553,080		—		—
Increase in share capital from:
the exercise of share options		532,232		577,086		646,216
the exercise of warrants		—		120,375		—
change in accounting policy for stock based compensation (note 3(t))		—		—		92,434
transfer of deferred transaction costs on conversion of the debenture		—		—		(3,093,734	)
transfer of carrying value of debentures to share capital on conversion of the securities		—		—		42,890,448
conversion of indirect participation interest into share capital		7,948,691		923,000		9,226,260
shares issued to induce conversion of debentures		—		—		6,976,800
transaction costs being attributed to share capital transaction		—		—		300,000
Movement in accumulated deficit as a result of the inducement paid on conversion of the debentures		—		—		(6,899,211	)

All non-cash investing and financing activities disclosed in note 7 relate to the “corporate” segment except for that involving the decrease in plant and equipment as a result of impairment (upstream).

8. 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 2006, the Company earned 5.0% (2005 – 2.9%) on the cash on deposit which related to the working capital facility. In 2006, cash and cash equivalents earned an average interest rate of 5.1% per annum (2005 – 1.3%, 2004 – 1.6%) on cash, other than the cash on deposit that was related to the working capital facility.

Credit risk is 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 carrying values of cash and cash equivalents, trade receivables, all other assets, accounts payable and accrued liabilities, all short-term loan facilities and amounts due to related parties approximate fair values due to the short term maturities of these instruments.

24

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

8. Financial instruments (cont’d)

Cash restricted

All other components of cash and cash equivalents are non-interest bearing. Restricted cash, which mainly relates to the working capital facility, is comprised of the following:

	December 31,		December 31,		December 31,
	2006		2005		2004
	$		$		$
Cash deposit on working capital facility (5.0%)		29,301,940		16,452,216		15,497,127
Cash restricted — Current		29,301,940		16,452,216		15,497,127
Cash deposit on secured loan (3.9%)		647,502		106,267		—
Debt reserve for secured loan		2,420,000		—		—
Bank term deposits on Petroleum Prospecting Licenses (0.8%)		107,997		103,786		102,096
Cash deposit on office premises (4.5%)		41,785		—		—
Cash restricted — Non-current		3,217,284		210,053		102,096
		32,519,224		16,662,269		15,599,223

Cash held as deposit on the working capital facility supports the Company’s working capital facility with BNP Paribas. The balance is initially based on 20% of the outstanding balance of the facility subject to fluctuations or variations in inventory and accounts receivables. The cash held as deposit on secured loan supports the Company’s secured loan borrowings with the Overseas Private Investment Corporation (“OPIC”).

The debt reserve for secured loan supports the bridging facility. As part of the facility, InterOil is required to maintain two quarterly interest repayments 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.

The prior year balances of restricted cash have been reclassified to correctly reflect the current and non-current component, consistent with the current year presentation.

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, 2006, InterOil had a net receivable of $1,759,575 (2005 – $1,482,798, 2004 –$503,500) relating to commodity hedge contracts. Of this total, a payable of $45,925 (2005 – receivable of $897,798, 2004 – receivable of $503,500) relates to hedges deemed effective at December 31, 2006 and a receivable of $1,805,500 (2005 – $585,000, 2004 — $nil) relates to outstanding derivative contracts for which hedge accounting was not applied or had been discontinued. The gain/(loss) on hedges for which final pricing will be determined in future periods was $1,385 (2005 — $1,016,998, 2004 – $537,358). This amount has been included in the deferred hedge gain/(loss) account on the balance sheet.

As at December 31, 2006, InterOil had entered into naphtha swap agreements to hedge a portion of first quarter 2007 naphtha sales. These transactions have been hedge accounted and tested for effectiveness on a regular basis. If any of hedge accounted transactions are found to be ineffective in comparison to management’s risk mitigation policies, hedge accounting is discontinued on those transactions. The gain or loss on derivative contracts that have been hedge accounted are charged to sales or cost of sales depending on the timing of the risk the hedge was expected to cover. The unrealized gain/loss on these hedge transactions are included in deferred hedge gain/(loss) in the balance sheet until these transactions are settled. The gain on the derivative contracts for which hedge accounting has been discontinued is included in general and administration expenses for the year.

During the year, InterOil entered into Brent contracts to hedge a portion of its anticipated low sulphur waxy residue sales by buying and selling the raw material component, crude at fixed prices to match the timing of the purchase and sale respectively. These transactions are not hedge accounted and any gain/loss on these contracts are included in general and administration expenses for the year. As at December 31, 2006 of the $1,805,500 from non-hedge accounted transactions, $1,745,500 (2005 — $nil, 2004 — $nil) relates to transactions for which hedge accounting was not applied and $60,000 (2005 — $585,000, 2004 — $nil) relates to transactions for which hedge accounting was discontinued.

25

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

8. Financial instruments (cont’d)

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

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

As at December 31, 2005:

Derivative	Type	Notional volumes (bbls)
Crude swap	Sell crude	300,000
Crude swap	Buy crude	250,000
Jet kerosene crack spread swap	Sell jet kerosene/buy crude	249,999

As at December 31, 2004:

Derivative	Type	Notional volumes (bbls)
Naphtha swap	Sell naphtha	50,000
Naphtha crack spread swap	Sell naphtha/buy crude	50,000

9. 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, specific monetary receivables up to $40,000,000 (refer to note 14). As at December 31, 2006, $23,671,568 (2005 — $23,196,914, 2004 — $13,034,904) in outstanding accounts receivable had been sold with recourse under the facility. As the sale is with recourse, the receivables 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.

At December 31, 2006, $55,955,400 (2005 — $39,430,264, 2004 — $49,989,840) of the trade receivables secures the BNP Paribas working capital facility disclosed in note 14. This balance includes $20,186,665 (2005 — $5,059,192, 2004 — $3,078,447) of intercompany receivables which were eliminated on consolidation.

10. Inventories

	December 31,		December 31,		December 31,
	2006		2005		2004
	$		$		$
Midstream — refining and marketing (crude oil feedstock)		12,795,356		5,019,580		3,971,982
Midstream — refining and marketing (refined petroleum product)		22,329,270		25,967,357		16,396,975
Midstream — refining and marketing (parts inventory)		46,646		—		—
Downstream (refined petroleum product)		32,422,296		13,100,547		7,547,945
		67,593,568		44,087,484		27,916,902

At December 31, 2006, all inventory balances are carried at cost where as in 2005 and 2004 the balances reflected net realizable value. The net realizable value write downs for prior year 2005 and 2004 of $355,215 and $1,508,334 are included in cost of sales.

At December 31, 2006, $35,171,272 (2005 — $30,986,937, 2004 — $20,368,957) of the midstream inventory balance secures the BNP Paribas working capital facility disclosed in note 14.

26

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

11. 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 $118,644 (2005 — $132,375, 2004 — $86,327) 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.

										Corporate &
December 31, 2006	Upstream			Midstream			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		—			11,948,960			10,543,842			156,817			22,649,619

										Corporate &
December 31, 2005	Upstream			Midstream			Downstream			Consolidated			Totals
Plant and equipment		5,657,125			238,078,544			12,164,417			331,183			256,231,269
Deferred project costs and work in progress		—			1,987,085			1,386,488			—			3,373,573
Consolidation entries		—			—			—			(3,120,718	)		(3,120,718	)
Accumulated depreciation and amortisation		(308,378	)		(11,245,748	)		(7,332,042	)		(198,808	)		(19,084,976	)
Net book value		5,348,747			228,819,881			6,218,863			(2,988,343	)		237,399,148
Capital expenditure		—			3,284,108			1,902,334			95,782			5,282,224

										Corporate &
December 31, 2004	Upstream			Midstream			Downstream			Consolidated			Totals
Plant and equipment		5,659,248			236,551,876			10,875,211			263,217			253,349,552
Deferred project costs and work in progress		—			—			949,924			—			949,924
Consolidation entries		—			—			—			(2,002,214	)		(2,002,214	)
Accumulated depreciation and amortisation		(19,792	)		(419,629	)		(7,317,596	)		(176,890	)		(7,933,907	)
Net book value		5,639,456			236,132,247			4,507,539			(1,915,887	)		244,363,355
Capital expenditure		1,131			40,532,990			1,320,644			83,920			41,938,685

During the year ended December 31, 2006, InterOil recognized a loss of $263,945 (2005 – gain of $95,053, 2004 – gain of $94,260) on the disposal of assets.

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. This loss is included in office and administrative expenses in the statement of operations.

27

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

12. Oil and gas properties (Restated)

For detailed reconciliation of the restated and superseded balance, refer note 2 above.

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

	December 31,		December 31,		December 31,
	2006		2005		2004
	$ (Restated)		$ Restated)		$
Drilling equipment		18,242,972		15,100,860		5,353,471
Petroleum Prospecting License drilling programs at cost		36,281,375		4,638,067		1,251,889
		54,524,347		19,738,927		6,605,360

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

	December 31,		December 31,		December 31,
	2006		2005		2004
	$ (Restated)		$ (Restated)		$
Exploration costs, excluding exploration impairment		6,176,866		11,009,434		2,903,313
Exploration impairment
Costs incurred in prior years		—		2,059,367		16,576,982
Costs incurred in current year		1,647,185		17,510,706		18,989,779
Total exploration impairment		1,647,185		19,570,073		35,566,761
		7,824,051		30,579,507		38,470,074

13. Income taxes (Restated)

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,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
(Loss) before income taxes and non controlling interest		(43,719,889	)		(59,606,317	)		(51,134,909	)
Statutory income tax rate		35.10	%		35.10	%		35.12	%
Computed tax (benefit)		(15,345,681	)		(20,921,817	)		(17,958,580	)
Effect on income tax of:
Losses in foreign jurisdictions not deductible		251,639			2,834,689			2,273,530
Non-deductible stock compensation expense		693,601			585,783			424,924
Gains and losses on foreign exchange		(1,687,001	)		268,843			58,659
Tax rate differential in foreign jurisditions		1,103,122			696,307			(341,613	)
Over provision for tax in prior years		(51,632	)		(113,950	)		(42,874	)
Tax losses for which no future tax benefit has been brought to account		12,166,624			8,390,975			2,696,330
Temporary differences for which no future tax benefit has been brought to account		3,124,836			11,104,170			14,552,726
Temporary differences brought to account on acquisition of subsidiary		1,135,181			(34,902	)		(488,027	)
Other — net		952,183			21,896			699,988
		2,342,872			2,831,994			1,875,063

28

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

13. Income taxes (Restated) (cont’d)

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

	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Future tax assets
Temporary differences
Plant and equipment		3,030,479			2,665,173			2,263,654
Exploration expenditure		41,870,390			26,940,837			11,541,022
Other — net		122,713			99,833			127,240
		45,023,582			29,705,843			13,931,916
Losses carried forward		27,754,495			15,390,109			4,850,380
		72,778,077			45,095,952			18,782,296
Less valuation allowance		(71,354,064	)		(44,037,054	)		(17,478,665	)
		1,424,013			1,058,898			1,303,631

All future tax assets recorded in the consolidated balance sheet relate to Papua New Guinea. The amounts are non current at December 31, 2006.

The valuation allowance for deferred tax assets increased by $27,317,010 (2005 – $26,558389, 2004 – $16,114,573) in the year ended December 31, 2006. 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, 2006 in respect of losses generated from the operations.

The Refinery Project Agreement gives “pioneer” status to InterOil Limited. This status gives the Company a tax holiday beginning upon the date of the commencement of commercial production, January 1, 2005 and ending in four years on December 31, 2010.

In relation to the refinery, tax losses incurred prior to January 1, 2005 will be frozen during the five year tax holiday and will become available for use after the tax holiday ceases on December 31, 2010. Tax losses carried forward to offset against future earnings total K169,689,231 (US $54,690,839) at December 31, 2006. All losses incurred by InterOil have a twenty year carry forward period.

14. Working capital facility – crude feedstock

As at the beginning of 2006, InterOil has a working capital credit facility with BNP Paribas (Singapore branch) with a maximum availability of $150,000,000. During the year this facility was increased to a maximum availability of $170,000,000.

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 a cash secured short term facility and a discounting facility on specific monetary receivables (note 9). The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables.

The facility bears interest at LIBOR + 2.5% on the short term advances. During the year the weighted average interest rate was 7.28% (2005 – 5.81%, 2004 – 4.36%).

29

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

14. Working capital facility – crude feedstock (cont’d)

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

	December 31,			December 31,			December 31,
	2006			2005			2004
	$			$			$
Working capital credit facility		170,000,000			150,000,000			100,000,000
Less amounts included in the working capital facility liability:
Short term advances		(13,201,940	)		(47,527,408	)		(63,485,637	)
Discounted receivables (note 9)		(23,671,568	)		(23,196,914	)		(13,034,904	)
		(36,873,508	)		(70,724,322	)		(76,520,541	)
Less: other amounts outstanding under the facility:
Letters of credit outstanding		(79,000,000	)		(33,765,000	)		(14,000,000	)
Hedging facility		(1,500,000	)		(1,500,000	)		—
Working capital credit facility available for use		52,626,492			44,010,678			9,479,459

At December 31, 2006, the company had two letters of credit outstanding for $79,000,000, which expire in January 2007. A letter of credit of $42,000,000 relates to a December crude receipt and expires on January 1, 2007 and a letter of credit of $37,000,000 relates to January crude receipt and expires on January 25, 2007.

The cash deposit on working capital facility, as separately disclosed in note 8, included restricted cash of $29,301,940 (2005 — $16,452,216, 2004 — $15,497,127) which was being maintained as a security market for the facility. In addition, inventory of $35,171,272 (2005 — $30,986,937, 2004 — $20,368,957) and trade receivables of $55,955,400 (2005 — $34,371,072, 2004 — $46,911,393) also secured the facility. The trade receivable balance securing the facility includes $20,186,665 (2005 — $5,059,192, 2004 — $3,078,447) of inter-company receivables which were eliminated on consolidation.

15. Acquisition of a subsidiary

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 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 is $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 exceed the net current assets in the year end 2005 accounts by more than Kina 500,000, then InterOil will pay the amount of excess to the vendor.

The transfer date accounts are being reviewed by an independent accountant to establish the final settlement of the purchase price. As at December 31, 2006, InterOil has paid $30,639,000 in cash to Shell and this balance will be further subject to a working capital adjustment. As at December 31, 2006, InterOil has accrued $1,771,000 as expected adjustment to purchase price for the working capital adjustment. In addition to the amounts paid and accrued by IPL, $171,410 of acquisition related costs have been incurred on the transaction.

30

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

15. Acquisition of a subsidiary (cont’d)

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		8,799,691
Total assets acquired		44,396,598
Accounts payable and accrued liabilities		(11,815,188	)
Net assets acquired		32,581,410

The net cash paid on purchase of IPL PNG of $25,820,515 is comprised of $30,639,000 paid to Shell during the year and $171,410 transaction costs incurred, less $4,989,895 held by IPL PNG at the time of acquisition.

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.

Direct Employment Services Company and SPI InterOil Holdings Limited

In 2005, InterOil acquired 100% of the issued share capital of Direct Employment Services Company (“DESC”) and SPI InterOil Holdings Limited for a total cost of $2,000 which was paid in cash. The purchase price reflected the book value of the shares at the time of acquisition.

DESC was initially established for the purposes of providing non-profit management services to the Company for its U.S. employees and it has continued to provide management services to the Company since its acquisition. Prior to its acquisition, DESC was partially owned by Christian Vinson, the Company’s Chief Operating Officer.

SPI InterOil Holdings Limited is a dormant shelf company to be used for a future business endeavor.

InterOil Products Limited

On April 28, 2004, InterOil, through its wholly owned subsidiary, SPI Distribution Limited, acquired 100% of the outstanding common shares of BP Papua New Guinea Limited which was subsequently renamed InterOil Products Limited (“IPL”). IPL is a distributor of refined petroleum products in Papua New Guinea.

The results of IPL’s operations have been included in the consolidated financial statements since April 28, 2004, the date control of IPL’s shares was transferred to InterOil. Under the purchase agreement, InterOil Corporation was entitled to the profit of IPL from March 1, 2004. The profit earned after tax between March 1, 2004 and April 28, 2004 of $1,243,746 was recognized as a reduction in the acquisition cost.

The adjusted purchase price is $13,226,854, including a service agreement for $1,000,000 related to the purchase. A deposit of $1,000,000 of the purchase price was paid in 2004. The remaining $12,226,854 (discounted amount $12,123,106) was paid on March 1, 2005 and was included in current liabilities in the financial statements at December 31, 2004.

31

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

15. Acquisition of a subsidiary (cont’d)

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

	$
Cash		5,859,517
Trade receivables		8,241,400
Inventory		6,759,089
Other assets		1,614,249
Future income tax benefit		640,284
Property, plant and equipment		3,180,530
Total assets acquired		26,295,069
Accounts payable and accrued liabilities		(13,399,720	)
Net assets acquired		12,895,349

The net cash received from the purchase of IPL (excluding the deferred settlement) of $4,631,904 is comprised of $5,859,517 held by IPL at the time of acquisition less $1,000,000 paid relating to the acquisition price and $227,613 paid in transaction costs and in stamp duty.

16. 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 (2005 — $150,000, 2004 — $150,410) was expensed for the sponsor’s legal, accounting and reporting costs. These costs were included in accrued liabilities at December 31, 2006.

During the prior year ended December 31, 2005, a balance outstanding from 2004 of $1,056,251 was repaid in full. The loan had interest charged at 5.75% per annum while it was outstanding in 2005. For the year ended December 31, 2005, the Company incurred total interest to P.I.E amounting to $9,376 (2004 – $246,745). All of the interest collected by P.I.E on this loan was used to pay interest incurred under the Wells Fargo facility.

Breckland Limited

The 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 during the year amounted to $140,165 (2005 — $179,608, 2004 — $120,426).

Direct Employment Services Company (“DESC”)

The services of certain executive officers and senior management of the Company are provided under a management services agreement with DESC. DESC is a U.S. private Company that was partially owned by Christian Vinson, the Company’s Chief Operating Officer prior to its acquisition by InterOil on November 23, 2005 (note 15). In 2005, InterOil acquired 100% of the issued share capital of the entity for a total cost of $1,000 which was paid in cash. Christian Vinson received $500 for his 50% interest in the entity. The purchase price reflects the book value of the shares at the time of acquisition. Prior to the acquisition, DESC was paid $549,978 for its management services in the nine months ended September 30, 2005 (year ended 2004 – $708,104).

32

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

16. Related parties (cont’d)

Director fees

Amounts due to Directors and executives at December 31, 2006 totaled $18,000 for Directors fees (2005 — $30,500, 2004 — $61,000) and $nil for executive bonuses (2005 — $573,571, 2004- $320,000). These amounts are included in accounts payable and accrued liabilities.

BNP Paribas

One of our Directors — Edward Speal, is the President and CEO of BNP Paribas (Canada). InterOil has a working capital facility with BNP Paribas (Singapore) of $170,000,000 (as per note 14) - 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).

17. Unsecured loan

On January 28, 2005, InterOil obtained a $20 million term loan facility. The loan had an interest rate equal to 5% per annum payable quarterly in arrears and includes a 1% arrangement fee of the face amount. On July 21, 2005, the short term loan facility increased from $20 million to $25 million. The term of the loan was fifteen months from the initial disbursement dates, and was repayable at any time prior to expiry with no penalty.

The loan and all accrued interest was repaid during 2006 and therefore the total balance outstanding at December 31, 2006 is $nil (2005 — $21,453,132).

18. Secured loan

	December 31,		December 31,		December 31,
	2006		2005		2004
	$		$		$
Secured loan (OPIC) — current portion		13,500,000		9,000,000		9,000,000
Secured loan (OPIC) — non current portion		62,500,000		71,500,000		76,000,000
Secured loan (bridging facility) — non current portion		121,666,433		—		—
Total non current secured loan		184,166,433		71,500,000		76,000,000
Total secured loan		197,666,433		80,500,000		85,000,000

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 is secured over the assets of the refinery project which have a carrying value of $228,704,267 at December 31, 2006 (2005 — $225,669,179, 2004 — $236,132,247).

The interest rate on the loan is equal to the treasury cost applicable to each promissory note outstanding plus the OPIC spread (3%). During 2006 the weighted average interest rate was 7.01% (2005 — 7.10%, 2004 — 6.65%) and the total interest expense included in long term borrowing costs was $5,512,975 (2005 — $6,038,887, 2004 — $nil).

The loan agreement was last amended on December 29, 2006. Under the amendment, the half yearly principal payment due in December 2006 and June 2007 of $4,500,000 each have been deferred until December 31, 2007 and interest previously due on December 31, 2006 and June 30, 2007 were deferred until September 30, 2007. The normal repayment of interest and principal will recommence on September 30, 2007 and December 31, 2007 respectively. Interest relating to the loan is accrued in the financial statements and has been included in accounts payable and accrued liabilities. Fees of $500,000 associated with the amendment have been included in deferred financing costs and accrued financing costs at December 31, 2006.

33

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

18. Secured loan (cont’d)

Due to the amendment of the loan agreement, three installment payments amounting to $13,500,000 which become due for payment on December 31, 2007 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. Under the amendment, the covenants related to minimum levels of tangible net worth have been waived until June 2008.

Deferred financing costs relating to OPIC loan of $1,582,555 (2005 — $1,256,816, 2004 — $1,311,488) are being amortized over the period until December 2014.

The accrued financing costs of $1,450,000 (2005 — $921,109, 2004 — $863,329) included discounting of the liability. The total liability is $1,450,000 and will be due for payment in four quarterly installments of $362,500 commencing on December 31, 2007. As at December 31, 2006 $1,087,500 is included under non-current liabilities and the balance is included under current liabilities.

Bridging Facility

InterOil entered into a loan agreement for $130,000,000 on May 3, 2006. The loan is divided into two Tranche’s — Tranche 1, which represents $100,000,000 and Tranche 2, which represented the remaining balance of $30,000,000. As at December 31, 2006, InterOil has drawn down the full facility of $130,000,000. The agreement contains certain financial covenants which include the maintenance of minimum levels of fixed charge ratios, a maximum leverage ratio and limitations on the incurrence of additional indebtedness. The loan is secured over the assets of the downstream business and secondary security over refinery assets.

The full balance of the loan will be repayable on May 3, 2008 with interest payable quarterly in arrears. The interest rate on the loan will be 4% commencing on May 3, 2006 and ending on May 3, 2008. The discounted interest rate of 4% rate is applicable as definitive LNG/NGL Project Agreement has been executed by InterOil and the lenders subsequent to the year ended December 31, 2006, on July 30, 2007.

The loan is valued on the balance sheet based on the present value of the expected cash flows. The expected cash flows include not only interest payments but also a 3.5% commitment fee payable to the lenders at the time of each draw down. The expected cash flows have been adjusted to take into account the likelihood of different interest rate outcomes relevant to the second year of the facility. Interest expense is 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 calculation is 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 is the Deferred liquefaction project liability in the current liability section of the balance sheet. This liability of $6,553,080 will be transferred to the profit and loss account as income if a definitive LNG/NGL Project Agreement is executed by InterOil and the lenders on or before March 31, 2007.

Annual administration fees of $100,000 has been included under deferred financing costs and amortized over the year until May 2007. The balance as at December 31, 2006 was $33,333.

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

19. Indirect participation interests (Restated)

Indirect participation interest (“IPI”)

	December 31,		December 31,		December 31,
	2006		2005		2004
	$ (Restated)		$ (Restated)		$
Indirect participation interest (“IPI”)		96,861,259		96,861,259		13,749,852

For detailed reconciliation of the restated and superseded balance relating to the IPI liability, refer note 2 above.

The IPI balance relates to $125,000,000 received by InterOil subject to the terms of the agreement dated February 25, 2005 between the corporation and certain 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. Prior to December 31, 2004, the Company received deposits of $13,749,852 and the remaining $111,250,148 was received in 2005.

34

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

19. Indirect participation interests (Restated) (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 conversion 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.

Under the IPI agreement, InterOil is responsible for drilling the eight 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 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, the investor will forfeit their right to the well in question as well as their right to convert into common shares.

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 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 till conveyance is triggered on the lapse of conversion option available to the investors and they elect to participate in the PDL for a successful well. InterOil will account for the exploration costs relating to the eight well program under successful efforts accounting policy adopted by the Company. All 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.

If conversion option is exercised by an investor, the non-financial liability relating to that investor would be transferred to share capital for the number of shares issued. There were no exercise of conversion option to InterOil shares during the financial years ended December 31, 2006 and 2005.

Indirect participation interest – PNGDV (Restated)

	December 31,		December 31,		December 31,
	2006		2005		2004
	$ (Restated)		$ (Restated)		$
Current portion		730,534		—		—
Non current portion		1,190,633		9,685,830		10,608,830
Total indirect participation interest — PNGDV		1,921,167		9,685,830		10,608,830

For detailed reconciliation of the restated and superseded balance relating to the Indirect Participation Interest – PNGDV liability, refer note 2 above.

As at December 31, 2006, 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 $1,921,167 (2005 — $9,685,830, 2004 - $10,608,830). This is the result of an amendment 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 wells (the first of the four wells is Elk-1). 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 four wells on behalf of the investors of $3,184,040. Initial liability taken up on amendment of the agreement is $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.

35

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

19. Indirect participation interests (Restated) (cont’d)

During the year ended December 31, 2006, $1,667,396 of geological and geophysical costs and drilling costs have been allocated against the liability of $3,588,560 bringing the remaining balance to $1,921,167. PNGDV liability has been accounted using conveyance accounting as there are no conversion options attached to the liability, unlike IPI non-financial liability noted above.

Other

In addition to the above, PNG Energy Investors (“PNGEI”), an indirect participation interest investor, that converted all of its interest to common shares in fiscal year 2004, has the right to participate up to a 4.25% interest in wells 9 to 24. 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 September 11, 1998 Enron Papua New Guinea Ltd (“Enron”), SPI’s former joint venture partner, exercised its option (pursuant to a January 1997 joint venture agreement with SPI) to terminate the joint venture agreement. Consequently, SPI purchased Enron’s voting, non-participating shares in E.P. InterOil Limited (“EPI”), a wholly owned subsidiary of SPI, for a nominal amount. Enron no longer actively participates in the refinery operations but continues to be a non-voting participating shareholder in EPI. SPI now holds all voting non-participating shares issued from EPI and has sole responsibility for managing the refinery. Enron does not hold any transfer or conversion rights into shares of InterOil Corporation.

At December 31, 2006, a subsidiary, SP InterOil LDC, holds 98.92% (2005 — 98.83%) of the non-voting participating shares issued from EPI.

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, 2004		24,815,961		157,449,200
Shares issued for debt		3,184,828		56,698,121
Shares issued on exercise of options		310,095		2,666,333
December 31, 2004		28,310,884		216,813,654
Shares issued for debt		52,000		923,000
Shares issued on exercise of warrants		19,168		540,346
Shares issued on exercise of options		781,268		5,657,500
December 31, 2005		29,163,320		223,934,500
Shares issued on exercise of options		132,285		2,006,175
Shares issued on amendment of indirect participation interest — PNGDV		575,575		7,948,691
December 31, 2006		29,871,180		233,889,366

36

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

22. Stock compensation

At December 31, 2006, there were 2,570,500 (2005 – 911,068) common shares reserved for issuance under the Company stock option plan.

Options are issued at no less than market price to directors, staff and contractors. Options are exercisable on a 1:1 basis. Options vest at various dates in accordance with the applicable option agreement, have an exercise period of three to five years assuming continuous employment by the InterOil Company and may be exercised at any time after vesting within the exercise period. Upon resignation or retirement, vested options must be exercised within 30 days for employees and 90 days for directors.

	December 31, 2006						December 31, 2005						December 31, 2004
	Number of			Weighted average			Number of			Weighted average			Number of			Weighted average
Stock options outstanding	options			exercise price $			options			exercise price $			options			exercise price $
Outstanding at beginning of year		746,800			22.23			1,162,322			9.91			1,363,265			7.55
Granted		725,500			15.87			516,450			25.82			224,460			26.30
Exercised		(132,285	)		(11.14	)		(781,322	)		(6.50	)		(310,095	)		(6.52	)
Forfeited		(285,433	)		(18.01	)		(74,000	)		(13.11	)		(100,308	)		(25.28	)
Expired		(41,082	)		(15.36	)		(76,650	)		(26.01	)		(15,000	)		(8.00	)
Outstanding at end of year		1,013,500			20.59			746,800			22.23			1,162,322			9.91

	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 $
5.01 to 8.00		10,000		5.27		0.39		10,000		5.27
13.01 to 24.00		714,000		18.03		3.63		150,000		18.84
24.00 to 31.00		289,500		27.44		1.93		77,500		30.27
		1,013,500		20.59		2.97		237,500		22.00

The fair value of the 725,500 (2005 — 516,450, 2004 — 224,460) options granted subsequent to January 1, 2006 has been estimated at the date of grant in the amount of $6,447,315 (2005 - $4,834,139, 2004 — $1,122,938) using a Black-Scholes pricing model. An amount of $1,976,072 (2005 - - $1,668,896, 2004 — $1,202,921) has been recognized as compensation expense for the year ended December 31, 2006. Of the current year compensation expense of $1,976,072 (2005 — $1,668,896, 2004 - - $1,202,921), $1,443,840 (2005 – $1,091,810, 2004 – $656,338) was adjusted against contributed surplus under equity and $532,230 (2005 – $577,086, 2004 – $546,583) was applied to share capital.

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
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
2005	July 1 to December 31		2.5		—		55		3.6
2005	January 1 to June 30		2.5		—		45		3.2
2004	January 1 to December 31		2.5		—		45		3.8

37

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

23. Debentures and warrants

In 2004, InterOil issued a total of $45,000,000 in senior convertible debentures. The debentures were to mature on August 28, 2009 and bore interest at a rate of 8.875% per annum, payable quarterly. The debentures were converted into 2,232,143 common shares of the Company at a fixed conversion price of $20.16 per share on December 31, 2004 at the investors’ option.

In 2004, in connection with the issuance of senior convertible debentures, InterOil issued five-year warrants to purchase 359,415 common shares at an exercise price equal to $21.91. A total of 340,247 (2005 – 340,247, 2004 – 359,415) were outstanding at December 31, 2006. 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.

24. Loss per share

Warrants, conversion options and stock options totaling 4,687,081 common shares at prices ranging from $5.27 to $37.50 were outstanding as at December 31, 2006 but were not included in the computation of the diluted loss per share because they caused the loss per share to be anti-dilutive.

25. Commitments and contingencies

Payments due by period contractual obligations are as follows:

			Less than 1										More than 5
	Total		year		1-2 years		2-3 years		3-4 years		4-5 years		years
	’000		’000		’000		’000		’000		’000		’000
Secured loan obligations		197,666		13,500		130,666		9,000		9,000		9,000		26,500
Accrued financing costs		1,450		363		1,087		—		—		—		—
Acquisition of subsidiary — IPL PNG Ltd		1,771		1,771		—		—		—		—		—
Indirect participation interest — PNGDV (note 19)		1,921		731		1,190		—		—		—		—
Indirect participation interest (note 19) (a)		96,861		—		96,861		—		—		—		—
Petroleum prospecting and retention licenses (b)		5,237		1,877		3,360		—		—		—		—
		304,906		18,242		233,164		9,000		9,000		9,000		26,500

(a)

The liability presented in relation to indirect participation interest is not a cash commitment and will be resolved once the IPI investors have elected to convert their interests into a joint venture interest or shares in InterOil Corporation. InterOil’s commitment is to complete the eight well drilling program. As at December 31, 2006, management estimate that a further $48,126,000 will be required to be spent to fulful this commitment.

(b)

The amount pertaining to the petroleum prospecting and retention licenses represents the amount InterOil has committed to spend to its joint venture partners. In addition to this amount, InterOil must drill an exploration well on PPL 237 in the two year period commencing March 2007. As the cost of drilling this well cannot be estimated, it is not included within the above table.

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 favour, 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.

The Company currently has an outstanding $10.6 million cost of control insurance claim for the Elk well which is being assessed by the loss adjusters. The amount and timing of any payment related to this claim is currently unknown.

The Company has income tax filings that are subject to audit and potential reassessment. The findings may impact the tax liability of the Company. The final results are not reasonably determinable at this time and management believes that it has adequately provided for current and future income taxes.

26. Subsequent events

The definitive LNG/NGL Project Agreement which was required to be executed by InterOil and the bridging facility lenders for the discounted interest rate of 4% rate being applicable till the end of the facility was executed subsequent to the year ended December 31, 2006, on July 30, 2007.

38

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

27. Reconciliation to accounting principles generally accepted in the United States (Restated)

The audited consolidated financial statements of the Company for the twelve month periods ended December 31, 2006, 2005 and 2004 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.

Restatement of Consolidated financial statements for the year ended December 31, 2006 and 2005

As noted in the superseded consolidated financial statements for the Company for the year ended December 31, 2006 issued on March 30, 2007, Management has been liaising with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005. The queries were primarily in relation to the accounting treatment of the Indirect Participation Interest agreement # 3 (refer to note 19) as a conveyance in accordance with SFAS 19 – ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’. The SEC staff had also raised comments about other matters related to the accounting treatment of Indirect Participation Interest agreement # 3 such as the bifurcation of the derivative, the fair value methodologies applied and the application of accretion expense.

Based on discussions with the SEC staff, Management has restated the consolidated financial statements for the year ended December 31, 2006 and 2005 to reflect the revised model for the accounting treatment for non-financial liability relating to indirect participation interest. Refer to Note 2 above for detailed analysis of the revisions made to the financial statements under Canadian GAAP.

Restatement to Consolidated Balance Sheets

	December 31, 2006									December 31, 2005									Canadian	U.S.
	Original						Restated			Original						Restated			GAAP	GAAP
	Balance			Adjustments			Balance			Balance			Adjustments			Balance			Reference	Reference
	$			$			$			$			$						$ (Note 2)	(below)
Non-current assets
Oil and gas properties (note 12)		37,449,734			17,074,613			54,524,347			16,399,492			3,339,435			19,738,927		(i), (ii)
Current and Non-current liabilities
Indirect participation interest (note 19)		74,763,970			42,097,289			116,861,259			86,454,953			30,406,306			116,861,259		(i), (iii), (iv)	(i), (ii)
Indirect participation interest — PNGDV (note 19)		1,743,533			177,634			1,921,167			9,685,830			—			9,685,830		(vi)
Shareholders’ Equity
Accumulated deficit (Refer ‘Restatement to Consolidated Statement of Operations’ below )		(187,776,004	)		(9,724,577	)		(197,500,581	)		(125,375,528	)		(27,066,871	)		(152,442,399	)

39

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

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

Restatement to Consolidated Statement of Operations

	Year ended December 31, 2006							Year ended December 31, 2005								Canadian	U.S.
	Original					Restated		Original						Restated		GAAP	GAAP
	Balance		Adjustments			Balance		Balance			Adjustments			Balance		Reference	Reference
	$		$			$		$			$			$		(Note 2)	(below)
Expenses
Exploration costs, excluding exploration impairment (note 12)		1,657,671		4,519,195			6,176,866		—			11,009,434			11,009,434	(ii)
Exploration impairment (note 12)		416,923		1,230,262			1,647,185		2,144,429			17,425,644			19,570,073	(ii)
Accretion expense (note 19)		3,741,254		(3,741,254	)		—		5,647,491			(5,647,491	)		—	(iv), (vi)
Loss on amendment of indirect participation interest — PNGDV (note 19)		1,446,901		404,520			1,851,421		—			—			—	(vi)
Loss/(gain) on revaluation of conversion options		19,755,017		(19,755,017	)		—		(4,279,284	)		4,279,284			—		(ii)
Total restated expenses		27,017,766		(17,342,294	)		9,675,472		3,512,636			27,066,871			30,579,507
Net loss		62,400,476		(17,342,294	)		45,058,182		34,971,620			27,066,871			62,038,491

In addition to the changes made under Canadian GAAP (refer note 2), the following adjustments were made to the U.S. GAAP treatment of the IPI agreement to reflect the U.S. GAAP differences and reconcile the differences between both GAAP’s.

(i) Under U.S. GAAP, the conversion option feature in the IPI Agreement was valued and bifurcated on day one as a result of adopting the allocation method for the hybrid instrument required by DIG issue B6 “Allocating the Basis of a Hybrid Instrument to the Host Contract and the Embedded Derivative”. Based on the revised model agreed with the SEC, the conversion option will no longer be bifurcated as Company has opted to utilize the scope exception under SFAS 133 Para 10(f) for ‘derivatives that serve as impediments to sales accounting’. This will result in non-financial liability maintained at full value of $125,000,000 less the transaction costs. This adjustment has the effect of increasing the IPI liability from the superseded balance as at December 31, 2006 by $27,249,587 (2005 — $27,249,587). The IPI liability balance will also be impacted by the revaluation of the conversion option noted below.

(ii) The conversion option feature in superseded financial statements had also resulted in GAAP differences between Canadian and U.S. GAAP as under U.S. GAAP the fair value of the option was treated as a separate liability (rather than equity under Canadian GAAP which was not revalued) which had to be revalued to fair value at each period end. As a result of adopting the revised model, the conversion option will no longer be bifurcated and revalued under US GAAP. The revised model does not bifurcate the conversion option feature under U.S. GAAP resulting in reversal of all revaluations performed at each period end. This adjustment will have the impact of reducing the US GAAP loss for year ended December 31, 2006 by $19,755,017 (2005 — increase the loss by $4,279,284). This adjustment will also have the corresponding effect on ‘IPI liability’ balance carried forward in the balance sheet. The IPI liability balance as at December 31, 2006 will decrease by $15,475,733, and as at December 2005 will increase by $4,279,284 from the superseded balances due to this adjustment.

(iii) Under U.S. GAAP, the impact of all the adjustments as explained under Note 2 and noted above on the consolidated statement of income for the years ended December 31, 2006 and 2005 has been an decrease in the loss by $17,342,294 ($0.59 per share) and increase in the loss by $27,066,871 ($0.94 per share) respectively. The difference between this U.S. GAAP and Canadian GAAP impact to statement of income is the reversal of revaluations as explained above which has reduced the US GAAP loss for year ended December 31, 2006 by $19,755,017 (2005 - increase the loss by $4,279,284).

40

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

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

Consolidated statements of operations (Restated)

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

	Year ended
	December 31, 2006						December 31, 2005						December 31, 2004
	$ (Restated)						$ (Restated)						$
	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Revenue
Sales and operating revenues (1)		511,087,934			511,189,438			481,180,645			481,180,645			70,644,486			121,974,268
Interest income		3,223,995			—			1,830,808			—			382,461			—
Other income		3,747,603			—			528,270			—			196,337			—
		518,059,532			511,189,438			483,539,723			481,180,645			71,223,284			121,974,268
Expenses
Cost of sales and operating expenses (excluding depreciation shown below) (1)		499,494,540			499,584,532			467,246,990			467,400,576			65,344,516			129,871,126
Administrative and general expenses (1), (2)		20,728,618			20,762,574			14,672,793			14,687,717			7,831,550			8,081,740
Depreciation and amortization (1)		12,352,672			11,591,513			11,036,550			10,836,696			639,075			1,462,953
Exploration costs, excluding exploration impairment		6,176,866			6,176,866			11,009,434			11,009,434			2,903,313			2,903,313
Exploration impairment		1,647,185			1,647,185			19,570,073			19,570,073			35,566,761			35,566,761
Legal and professional fees (1)		3,937,517			3,937,517			3,606,415			3,606,415			3,573,727			3,655,631
Short term borrowing costs		8,478,540			8,478,540			8,855,857			8,855,857			4,705,190			4,705,190
Long term borrowing costs (1)		11,856,872			11,856,872			6,351,337			6,351,337			1,401,256			1,897,029
Debt conversion expense (5)		—			—			—			—			—			6,976,800
Loss on amendment of indirect participation interest -
PNGDV		1,851,421			1,851,421			—			—			—			—
Foreign exchange loss/(gain) (2)		(4,744,810	)		(4,744,810	)		796,590			796,590			392,805			392,805
Non-controlling interest (7)		(263,959	)		(265,865	)		(368,312	)		(368,475	)		(70,091	)		(265,624	)
Interest income		—			(3,223,995	)		—			(1,830,808	)		—			(382,461	)
Other income		—			(3,747,603	)		—			(528,270	)		—			(196,337	)
		561,515,462			553,904,747			542,777,727			540,387,142			122,288,102			194,668,926
Loss before income taxes		(43,455,930	)		(42,715,309	)		(59,238,004	)		(59,206,497	)		(51,064,818	)		(72,694,658	)
Income tax expense (3)		(2,342,873	)		(2,342,873	)		(2,831,994	)		(2,831,994	)		(1,875,063	)		(1,875,063	)
Loss before cumulative effect of accounting change		(45,798,803	)		(45,058,182	)		(62,069,998	)		(62,038,491	)		(52,939,881	)		(74,569,721	)
Cumulative effect of accounting change (4)		—			—			—			—			—			(737,650	)
Net loss		(45,798,803	)		(45,058,182	)		(62,069,998	)		(62,038,491	)		(52,939,881	)		(75,307,371	)

41

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

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

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

	Year ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Net loss as shown in the Canadian GAAP financial statements		(45,798,803	)		(62,069,998	)		(52,939,881	)
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)		761,159			199,854			—
Decrease in non-controlling interest expense (7)		1,907			163			195,533
Decrease in administrative and general expenses from ineffective portion of hedges (2)		—			22,456			—
Increase in sales as a result of items being ineligible for capitalization due to difference in date of commencement of operations of refinery(1)		—			—			51,329,782
Increase in sales from ineffective portion of hedges (2)		101,504			—			—
Description of items having the effect of decreasing reported income
Increase in depreciation and amortization due to difference in date of commencement of operations of refinery (1)		—			—			(823,878	)
Increase in cost of sales and operating expenses as a result of items being ineligible for capitalization due to difference in date of commencement of operations of refinery (1)		—			(153,586	)		(64,526,610	)
Increase in cost of sales from ineffective portion of hedges (2)		(89,992	)		—			—
Increase in administrative and general expenses from ineffective portion of hedges (2)		(33,956	)		—			—
Increase in administrative and general expenses as a result of items being ineligible for capitalization due to difference in date of commencement of operations of refinery (1)		—			(37,380	)		(250,190	)
Increase in legal and professional fees as a result of items being ineligible for capitalization due to difference in date of commencement of operations of refinery (1)		—			—			(81,904	)
Increase in long term borrowing costs as a result of items being ineligible for capitalization due to difference in date of commencement of operations of refinery (1)		—			—			(495,773	)
Debt conversion expense (5)		—			—			(6,976,800	)
Cumulative effect of accounting change relating to stock compensation (4)		—			—			(737,650	)
Net loss according to US GAAP		(45,058,182	)		(62,038,491	)		(75,307,371	)

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

				Year ended
	December 31,			December 31,			December 31,
	2006			2005			2004
	$ (Restated)			$ (Restated)			$
Net loss in accordance with U.S. GAAP, net of tax		(45,058,182	)		(62,038,491	)		(75,307,371	)
Foreign currency translation reserve, net of tax		1,015,426			14,243			463,200
Deferred hedge gain, net of tax		(993,153	)		457,184			537,358
Total other comprehensive income, net of tax		22,273			471,427			1,000,558
Comprehensive loss, net of tax		(45,035,909	)		(61,567,064	)		(74,306,813	)

Statements of cash flows

There are no material differences in the statement of cash flows between Canadian and U.S. GAAP except for the classification of ‘Expenditure on oil and gas properties’ which is classified under investing activities under Canadian GAAP. Under U.S. GAAP this item is classified as an operating activity.

42

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

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

Statements of accumulated other comprehensive income, net of tax (AOCI)

						Total
						accumulated
	Foreign currency					other
	translation		Deferred hedge			comprehensive
	reserve		gain			income
AOCI balance as of December 31, 2003		—		—			—
Current period change		463,200		537,358			1,000,558
AOCI balance as of December 31, 2004		463,200		537,358			1,000,558
Current period change		14,243		457,184			471,427
AOCI balance as of December 31, 2005		477,443		994,542			1,471,985
Current period change		1,015,426		(993,153	)		22,273
AOCI balance as of December 31, 2006		1,492,869		1,389			1,494,258

Per share amounts (Restated)

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, 2006, 2005 and December 31, 2004.

Weighted average number of shares on which earnings per share	Year ended December 31,
calculations are based in accordance with U.S. GAAP	2006			2005			2004
Basic		29,602,360			28,832,263			25,373,575
Effect of dilutive options		—			—			—
Diluted		29,602,360			28,832,263			25,373,575
Net income/(loss) per share in accordance with U.S. GAAP	(Restated)			(Restated)
Basic		(1.52	)		(2.15	)		(2.97	)
Diluted		(1.52	)		(2.15	)		(2.97	)

Consolidated balance sheets (Restated)

	December 31, 2006				December 31, 2005				December 31, 2004
	(Restated)				(Restated)
	Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP
Current assets		201,714,996		201,714,996		173,232,689		173,232,689		132,258,350		132,258,350
Oil and gas properties		54,524,347		54,524,347		19,738,927		19,738,927		6,605,360		6,605,360
Capital assets (1), (2)		242,642,077		231,175,281		237,399,148		225,171,193		244,363,355		232,496,306
Deferred financing costs		1,716,757		1,716,757		1,256,816		1,256,816		1,311,488		1,311,488
Restricted Cash		3,217,284		3,217,284		210,053		210,053		—		—
Future income tax benefit (3)		1,424,014		1,424,014		1,058,898		1,058,898		1,303,631		1,303,631
Total assets		505,239,475		493,772,679		432,896,531		420,668,576		385,842,184		373,975,135
Current liabilities (2), (6)		133,753,876		133,752,491		132,099,945		131,082,948		142,197,050		141,659,692
Accrued financing costs		1,087,500		1,087,500		921,109		921,109		863,329		863,329
Long term debt (6)		282,218,325		302,218,325		178,047,089		198,047,089		86,608,830		86,608,830
Non-controlling interest (7)		5,759,206		5,416,831		6,023,149		5,682,695		6,404,262		6,063,971
Shareholders’ equity (1) (2) (4) (5) (6)		82,420,568		51,297,532		115,805,239		84,934,735		149,768,713		138,779,313
Total liabilities and shareholders’ equity		505,239,475		493,772,679		432,896,531		420,668,576		385,842,184		373,975,135

(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.

43

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

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

	As disclosed in note 3(q) 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 during 2005.
	In the prior year, in addition to recognizing December 2004’s results in the statement of operations, one month of depreciation expense was also recorded under U.S. GAAP for the refinery during 2004. The useful life for the refinery under U.S. GAAP is the same as that disclosed under Canadian GAAP in note 3(q) in the consolidated financial statements.
(2)	Derivative instruments and hedging
	The Company accounts for derivatives and hedging activities in accordance with FASB Statement No. 133, “Accounting for Derivative Instruments and Certain Hedging Activities”, as amended (“SFAS No. 133”), which requires that all derivative instruments be recorded on the balance sheet at their respective fair values.
	The Canadian Institute of Chartered Accountants issued Accounting Guideline 13 “Hedging Relationships” (“AcG-13”), which became effective January 1, 2004. This guideline was issued to align certain accounting principles under Canadian GAAP with SFAS No. 133, including hedge documentation and assessing hedge effectiveness. The Company adopted the hedge accounting provisions in AcG-13 and SFAS No. 133 in respect of the commodity forward contracts it transacted beginning in July 2004. Under Canadian GAAP, the Company includes hedges which are unsettled at period end in current liabilities based on a marked to market calculation. Under SFAS No. 133 the marked to market amount for the unsettled hedges is included in other comprehensive income to the extent that they are effective. The ineffective portion is expensed. Details of hedge accounting is disclosed in notes 3(o) and 8 in the consolidated financial statements of the Company for the year ended December 31, 2006.
(3)	Income tax effect of adjustments
	The income tax effect of U.S. GAAP adjustments was a reduction to the future tax asset of $259,957 (2005 – reduction of $11,059) for the year ended December 31, 2006 due to an decrease in the loss carry-forwards. A corresponding decrease in the valuation allowance was recorded. No income tax expense was recorded in the years ended December 31, 2006, 2005 and 2004 due to the tax holiday period in Papua New Guinea through five years after the refinery commences operations.
(4)	Stock based compensation
	At January 1, 2004, the Company adopted the provisions of CICA 3870 in respect of the employee stock-based awards, which resulted in recognition of compensation expense for such awards under Canadian GAAP on a basis consistent with the fair value provisions of SFAS No. 123. As disclosed in note 3(t) to the consolidated financial statements, the Company retroactively applied the fair value method to all employee stock options granted on or after January 1, 2002, without restatement to prior years.
	This is not consistent with the modified prospective transition method allowed for a voluntary change to the fair value method under FASB Statement No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment of FASB Statement No. 123” (“SFAS No. 148”). The modified prospective method requires retroactive consideration of all employee stock awards granted, modified or settled on or after January 1, 1995. The Company did not adjusted for this GAAP difference as there were no options granted, modified or settled between January 1, 1995 and January 1, 2002 that would have materially impacted net income for the years ended December 31, 2005, 2004 and 2003.
	The cumulative effect of this change in accounting principle of $737,650 was recorded to opening accumulated deficit under Canadian GAAP. This is required to be disclosed as a cumulative change in accounting principle in the statement of operations under U.S. GAAP.

44

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

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

(5)	Debt conversion expense
	As disclosed in note 23 in the consolidated financial statements, 100% of the convertible debentures were converted before December 31, 2004. The Company issued an additional 180,000 shares to induce conversion before the end of the year. Under Canadian GAAP, the fair value of these shares was recorded as an increase in share capital of $6,976,800 with offsetting adjustments to retained earnings of $6,899,211 and a conversion expense of $77,589.
	FASB Statement No. 84, “Induced Conversions of Convertible Debt” requires an expense to be recorded when convertible debt is converted under an inducement. The Company recognized the entire fair value of the inducement shares of $6,976,800 as a conversion expense under U.S. GAAP.
(6)	Indirect participation interest
	As disclosed in note 2 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, Company has not bifurcated the amount as the Company has opted to utilize the scope exception under SFAS 133 Para 10(f) for ‘derivatives that serve as impediments to sales accounting’.
(7)	Non controlling interest
	The non-controlling interest movements are the result of the U.S. GAAP adjustments relating to the midstream operations described in points 1 to 4 above.

Acquisition of InterOil Products Limited (“IPL”)

The following summary unaudited pro forma condensed consolidated financial information for the twelve month periods ended December 31, 2004 and 2003 shows the estimated pro forma impact on the Company’s consolidated financial statements of the acquisition of IPL as of April 28, 2004. Refer to note 15 of the consolidated financial statements. This pro forma information is based on management’s current estimates of, and good faith assumptions regarding, the adjustments arising from the transactions described above. The pro forma adjustments are based on currently available information and actual adjustments could differ materially from current estimates.

The pro forma information does not purport to represent what the financial position and results of operations would actually have been had the acquisition of IPL been consummated on the dates indicated or to project the financial position of any future date of operations of any future period.

The following pro forma statements of earnings for the years ended December 31, 2004 and 2003 give effect to the acquisition of IPL as if it had occurred on January 1, 2003.

	InterOil			IPL (1)		Pro forma
Twelve months ended December 31, 2004	(audited)			(unaudited)		(unaudited)
Sales and operating revenue — Canadian GAAP		70,644,486			27,317,000		97,961,486
Sales and operating revenue — US GAAP		121,974,268			27,317,000		149,291,268
Net profit/(loss) — Canadian GAAP		(52,939,881	)		2,350,000		(50,589,881	)
Net profit/(loss) — U.S. GAAP		(75,307,371	)		2,350,000		(72,957,371	)
Basic loss per share (cents per share)
Canadian GAAP (2)		(208	)				(199	)
U.S. GAAP (3)		(297	)				(287	)
Diluted loss per share (cents per share)
Canadian GAAP (2)		(208	)				(199	)
U.S. GAAP (3)		(297	)				(287	)

45

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

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

	InterOil			IPL (1)		Pro forma
Twelve months ended December 31, 2003	(audited)			(unaudited)		(unaudited)
Sales and operating revenue — Canadian and U.S. GAAP		—			69,897,000		69,897,000
Net profit/(loss) — Canadian GAAP		(3,517,569	)		6,474,000		2,956,431
Net profit — U.S. GAAP		4,435,965			6,474,000		10,909,965
Basic earnings/(loss) per share (cents per share)
Canadian GAAP (2)		(15	)				14
U.S. GAAP (3)		20					49
Diluted earnings/(loss) per share (cents per share)
Canadian GAAP (2)		(15	)				13
U.S. GAAP (3)		18					45

(1) Financial data for the year ended December 31, 2004 represents results for the period from January 1, 2004 to April 28, 2004, the effective date the Company gained control of IPL, and is derived from the unaudited management accounts of IPL. Financial data for the year ended December 31, 2003 represents the actual results for the year ended December 31, 2003.

(2) The weighted average number of shares used in the earnings per share information is consistent with that used under Canadian GAAP for the respective periods.

(3) The weighted average number of shares used in the earnings per share information is consistent with that used under U.S. GAAP for the respective periods.

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 does not expect that the application of FAS 157 will have a material impact on the financial statements.

Accounting for uncertainty in income taxes

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The standard is effective for fiscal years beginning after December 15, 2006. The Company does not expect that the application of FIN 48 will have a material impact on the financial statements.

Accounting for certain hybrid financial instruments

In March 2006, the FASB issued FAS 155 which amends FASB Statements No. 133, Accounting for Derivative Instruments and Hedging Activities, and No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. The standard is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company does not expect that the application of FAS 155 will have a material impact on the financial statements.

46

EX-99.4

EXHIBIT 4

InterOil Corporation
Revised Management
Discussion and Analysis
For the Year Ended December 31, 2006
October 29, 2007

TABLE OF CONTENTS

Overview	3
Non-Gaap Measures	3
Legal Notice – Risk Factors And Forward-Looking Statements	4
Business Environment	5
Risk Management	8
Business Strategy	10
Financial Results	12
Year In Review	16
Midstream Refining And Marketing Year In Review	19
Midstream Liquefaction Year In Review	24
Downstream Year In Review	25
Corporate Year In Review	29
Liquidity And Capital Resources	30
Critical Accounting Estimates	36
New Accounting Standards	38
Non-Gaap Measures Reconciliation	40
Statement Regarding Disclosure Controls	41
Public Securities Filings	41
Glossary Of Terms	41

The following Revised Management’s Discussion and Analysis (Revised MD&A) should be read in conjunction with the audited Revised Consolidated Financial Statements and Notes for the year ended December 31, 2006 and the 2006 Revised Annual Information Form. The Revised MD&A was prepared by the management of InterOil with respect to our financial performance for the periods covered by the related consolidated financial statements, along with a detailed analysis of our financial position and prospects.

As noted in the superseded consolidated financial statements for the Company for the year ended December 31, 2006 issued on March 30, 2007, Management has been liaising with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005. The queries were primarily in relation to the accounting treatment of the Indirect Participation Interest agreement # 3 as a conveyance in accordance with SFAS 19 – ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’. The SEC staff had also raised comments about other matters related to the accounting treatment of Indirect Participation Interest agreement # 3 such as the fair value methodologies applied and the application of accretion expense.

Based on discussions with the SEC staff, Management has restated the consolidated financial statements for the years ended December 31, 2006 and 2005 to reflect a revised model for the accounting treatment of non-financial liability relating to indirect

Management Discussion and Analysis   INTEROIL CORPORATION   1

participation interest. These revised consolidated financial statements reflect all changes that have been made in relation to the revised model for the accounting treatment of this non-financial liability in the balance sheet of InterOil as at December 31, 2006 and December 31, 2005, and the statements of operations, shareholders’ equity and cash flows for each of the years then ended. This Revised MD&A will have the effect of superseding the previously issued MD&A for year ended December 31, 2006 and 2005 on March 30, 2007.

For further details regarding the revisions made to the consolidated financial statements, and reconciliations of the restated and superseded balances, please refer note 2 of the revised consolidated financial statements.

Our financial statements and the financial information contained in this Revised MD&A have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada and are presented in United States dollars (USD) unless otherwise specified. References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation and its subsidiaries.

Management Discussion and Analysis   INTEROIL CORPORATION   2

OVERVIEW

InterOil is developing a vertically integrated world class 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, Marketing & Liquefaction – Markets the refined products it produces in Papua New Guinea both domestically and for export. Since early 2006, our business plan and operating strategy has evolved to include as a business objective, the development of an onshore liquefied natural gas processing facility in Papua New Guinea.
Downstream	Wholesale and Retail Distribution – Distributes refined products in Papua New Guinea on a wholesale and retail basis.
Corporate	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. Our corporate segment results also include consolidation adjustments.

NON-GAAP MEASURES

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 InterOil 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 Canadian generally accepted accounting principles. Further, EBITDA is not a measure of cash flow under Canadian generally accepted accounting principles 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 this MD&A.

Management Discussion and Analysis   INTEROIL CORPORATION   3

LEGAL NOTICE – RISK FACTORS AND 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. 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 expanding our business segments, business strategy, contingent liabilities, environmental matters, and plans and objectives for future operations, future capital and other expenditures. By its very nature, such forward-looking information requires InterOil to make assumptions that may not materialize or that may not be accurate.

Each forward-looking statement reflects our current view of future events and is subject to known and unknown risks, uncertainties and other factors that could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties include, but are not limited to; the exploration and production, the refining and the distribution businesses are competitive; our refinery has not operated at full capacity for an extended period of time and our profitability may be materially affected if it is not able to do so; 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; if our refining margins do not meet our expectations and our refinery operations are not profitable; we may be required to write down the value of our refinery; our refinery financial condition may be materially adversely affected if we are unable to obtain crude feedstocks for our refinery; our refining operations expose us to risks, some of which are not insured; our hedging activities may incur losses; we may not be successful in our exploration for oil and gas; if we are unable to renew our petroleum licenses with the Papua New Guinea government, we may be required to discontinue our exploration activities in Papua New Guinea; our investments in Papua New Guinea are subject to political, legal and economic risks that could materially adversely affect their value; new legislative, administrative or judicial actions that constrain licenses and permits from various government authorities may have a material affect on the company’s operations; weather and unforeseen operating hazards may impact our operating activities; our significant debt levels and our debt covenants may limit our future flexibility in obtaining additional financing; our ability to recruit and retain qualified personnel may have a material adverse effect on our operating results and stock price; Petroleum Independent and Exploration Corporation can affect our raising of capital through the issuance of common shares or securities convertible into common shares; compliance with and changes in environmental laws could adversely affect our performance; you may be unable to enforce your legal rights against us; changing regulations regarding corporate governance and public disclosure could cause additional expenses and failure to comply may adversely affect our reputation and the value of our securities; and the risks described under the heading “Risk Factors” in our Annual Information Form.

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, 2006.

Readers are cautioned that the foregoing list of important factors affecting forward-looking information is not exhaustive. Furthermore, the forward-looking information contained in this quarterly report is made as of the date of this report and, except as required by applicable law, InterOil does not undertake any obligation to update publicly or to revise any of the included forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained in this report is expressly qualified by this cautionary statement.

We currently have no production or reserves as defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. All information contained in this MD&A regarding resources are references to undiscovered resources under Canadian National Instrument 51-101, whether stated or not.

Management Discussion and Analysis   INTEROIL CORPORATION   4

BUSINESS ENVIRONMENT

InterOil is a vertically integrated energy company with business segments through the whole hydrocarbon supply chain. InterOil is therefore exposed to the usual hydrocarbon production, refining and marketing business environment and regulatory regime of the hydrocarbon industry. Following is a summary of the hydrocarbon business environment to which InterOil is exposed.

Competitive Environment and Regulated Pricing

InterOil is the sole refiner of hydrocarbons in Papua New Guinea and under our 30 year agreement with the Government of Papua New Guinea, the government has undertaken to ensure that all domestic distributors purchase their refined petroleum product needs from the refinery, or any refinery which is constructed in Papua New Guinea, at an Import Parity Price (IPP). For each of the refined products produced and sold locally in Papua New Guinea, the monthly IPP is calculated by adding the costs that would typically be incurred to import such products to the average monthly posted price in Singapore as reported by Platts. The import parity price is regulated by the Papua New Guinea Independent Consumer and Competition Commission (ICCC).

InterOil is a significant participant in the distribution business in Papua New Guinea. Its major competitors have included Mobil and Shell; however, InterOil has completed the purchase of Shell Papua New Guinea’s distribution assets on October 1. The ICCC sets the maximum margins that may be charged by the wholesale and retail 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.

Interest Rates

The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant amount of the interest rate exposure.

The LIBOR USD overnight rate has steadily increased from around 2.3% to around 5.3% between 2005 and 2006.

Rate increases add additional cost to financing our crude cargoes. In 2007, indications are that interest rates will be more likely to fall.

Skill and Resource Scarcity

Similar to our competitors, we are facing a shortage of skilled labor to work in our business. 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 there are a limited number of people with the requisite knowledge and experience.

Management Discussion and Analysis   INTEROIL CORPORATION   5

Crude Prices

Crude prices have continued to be volatile throughout the year. The price of Tapis crude oil, as quoted by the Asian Petroleum Price Index (APPI), is a 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 2006 averaged $68.15 per barrel compared to $56.85 per barrel during 2005. The pricing formula used to determine the domestic sales price of our refined products does not allow us to fully recover the increased costs of working capital that result from increases in the cost of crude feedstocks. The Tapis monthly average for January 2007 was at 19 month low at $53.69 per barrel but has since recovered and is trading above $60 per barrel. We expect Tapis, and crude in general, to continue to trade at similar prices as experienced over the last two years. However, unforeseeable global events can affect this expectation. In January 2007, we commenced providing TAPIS crude price assessments to the Asian Petroleum Price Index.

Refining Margin

The benchmark price for refined products in the region we operate is the average spot price quotations for refined products from Singapore as reported by Platts. This benchmark, the Mean of Platts Singapore, is commonly referred to as the MOPS price for the relevant refined product.

The distillation process our refinery uses 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 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 during the first six months of 2006 then gave up this increase during the third quarter 2006 before improving slightly during fourth quarter. Volatility has increased during the past 18 months and we believe that hydroskimming margins will continue to remain volatile given oil pricing uncertainty.

Exchange Rates

Changes in the Papua New Guinea Kina (PGK) to United States dollar (USD) exchange rate can affect our midstream results as there is a small timing difference between the foreign exchange rates utilized when setting the monthly PGK IPP price and the foreign exchange rate used to convert subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK strengthened against the USD during 2006 (from 0.323 to 0.330). During 2007 we expect the PGK to remain relatively stable against the USD.

Management Discussion and Analysis   INTEROIL CORPORATION   6

Domestic Demand

Refinery sales trends indicate that domestic demand for middle distillates has grown by 14% during 2006 versus 2005.

The refinery on average sold 11,900 bbls/day to the domestic market during the second half of 2006 as compared to 10,400 bbls/day in the second half of 2005.

The majority of the demand increase was driven by the growing investment in the resource sector of Papua New Guinea. We expect this trend to continue into 2007 as current world demand for commodities results in increased foreign investment in Papua New Guinea.

Impact of Key Factors on Earnings

The following table shows the estimated after-tax effects that changes in certain factors would have on InterOil’s 2006 net earnings from continuing operations had these changes occurred. Amounts are in USD unless otherwise specified.

				Annual Net Earnings Impact
Factor(1)(2)	Change (+)			(thousands of dollars)		($/share)(3)
Change in domestic demand		1	%		383		0.01
Change in hydro-skimming margin	$1.00/bbl				6,655		0.22
Change in IPP pricing margin for retail and distribution business	0.01 PGK/litre				1,815		0.06
Change in LIBOR rate		1	%		730		0.03

(1)	The impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the impact of any inter-relationship among the factors.
(2)	The impact of these factors is illustrative and based off of sales and borrowings made during the 2006 year.
(3)	Per share amounts are based on the number of shares outstanding at December 31, 2006.

Management Discussion and Analysis   INTEROIL CORPORATION   7

RISK MANAGEMENT

Risk Factors

InterOil’s financial results are influenced by the business environment in which we operate. These risk factors can be found under the heading “Risk Factors” in our 2006 Annual Information Form available at www.sedar.com.

InterOil’s Risk Profile

InterOil’s risk exposures are mitigated and managed by management’s strategy for handling risks within the business. These risks have been categorized into four broad categories: business risks; operational risks; market risks and regulatory risks. Management believes that each risk requires a unique response and while some risks are managed through internal controls and business processes, others are managed through insurance and hedging. The following describes InterOil’s approach to managing major risks.

Business Risks

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 could have a material adverse impact on our results of operations. It is very important that we attract and retain highly skilled personnel, including technical personnel, to operate our refinery, accommodate our exploration plans, and manage the strategic direction of the business. Our human resources team manages our exposure in this area by engaging in active recruitment and retention programs.

Unrelated entities manage the operation of assets in which InterOil has an interest, such as upstream operations in our Petroleum Retention License 4 (43.1% interest) and Petroleum Retention License 5 (28.6% interest) leases. Inappropriate third-party operation of these assets could adversely affect InterOil’s financial performance; however, InterOil takes steps to partially mitigate this exposure by playing an active role on joint venture committees.

InterOil makes, and will continue to make, substantial capital expenditures for exploration, development, acquisition and production of oil and gas reserves, 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. The Board of Directors and executive management team proactively manage this exposure by continually reviewing business models, business plans and financing plans to meet the company’s strategic direction.

Operational Risks

We cannot assure our shareholders that our exploration activities will result in the discovery of any reserves; however, we take active steps to maximize the possibility of success by hiring highly qualified management and technical personnel and by engaging in activities such as seismic acquisition programs to enhance the possibility of success of our prospective drilling activities.

Exploring for, refining, transporting and marketing hydrocarbons involves operational hazards. These hazards include well blowouts, fires, explosions, and migration of harmful substances. Any of these operational incidents could cause personal injury, environmental contamination or damage and destruction of the Company’s assets. These incidents could also interrupt operations. InterOil manages operational risks primarily through its environmental, health and safety policies and committees as well as ensuring that we have suitably trained and qualified personnel in each of our operations.

The Company also purchases insurance to transfer the financial impact of some operational risks to third-party insurers. InterOil regularly evaluates its exposures related to operational risk and then adjusts the nature of its coverage, including deductibles

Management Discussion and Analysis   INTEROIL CORPORATION   8

and limits. Although InterOil maintains insurance in line with customary industry practices, the Company cannot and does not fully insure against all risks. Losses resulting from operational incidents that are not covered by insurance could have a material adverse impact on the Company.

Our midstream operations are dependent on the company’s ability to obtain suitable crude feedstock. Our project agreement requires the government of Papua New Guinea to take action to ensure that domestic crude oil producers sell us their domestic crude production for use in our refinery should we elect to utilize it. We are also able to obtain crude from outside of Papua New Guinea. During our crude optimization efforts, the refinery identified that lighter crudes that result in increased distillate yields, which are produced outside of Papua New Guinea, are the preferred source of crude for our refinery. In order to help mitigate the risk that we will be unable to enter into commercial arrangements for crude, either domestically or internationally, we have entered into an exclusive crude supply agreement with BP Singapore. Under this agreement which expires on June 14, 2009, BP Singapore acts as our agent in the procurement of crude.

Market Risks

Our midstream operations are highly dependent on the difference between the sale price we receive for refined products that we produce and the cost of the crude feedstocks used to produce those refined products. This difference is commonly referred to as refining margin. We use various derivative instruments and risk management techniques to minimize our exposure to market fluctuations in refining margins and also to the inventory holding price risk. Inventory holding price risk refers to changes in prices that occur between the time that we purchase feedstocks and the price of finished product at the time that we subsequently sell refined products. This holding period varies according to the sales cycle of each refined product.

The Company, due to its extensive borrowing requirement, will be adversely impacted by increases to interest rates. To balance this risk we have adopted a strategy of maintaining a mix of both fixed and floating interest rates on our debt portfolio.

Due to its operations being in Papua New Guinea, our Company is exposed to foreign exchange risk as revenues and expenditures or capital expenditure and investment proceeds could be in differing currencies from each other. Our primary foreign exchange risk is between the USD and the PGK. Our exploration business which incurs expenditure in PGK whilst holding its available funds in USD partially offsets the risk in the midstream operations, which incurs costs in USD whilst deriving the majority of its revenue in PGK. This exposure is further managed by a program of obtaining forward dated foreign exchange transactions.

Regulatory Risks

InterOil’s operations are based in Papua New Guinea and as a result 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. In addition, InterOil’s operations are regulated by and could be intervened upon by, the Papua New Guinea government. InterOil endeavors to mitigate the impact of its operational location and the related government regulations by maintaining co-operative relationships with its regulators and the government of Papua New Guinea. InterOil’s business development team aims to have regular, constructive communication with regulators and the government so issues can be resolved in a mutually acceptable fashion.

InterOil’s operations 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, jet and diesel fuels. Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, the monetary cost of environmental compliance could increase in the future. InterOil manages its environmental risks primarily through its environmental, health and safety policies and committees as well as an extensive third party testing program at the refinery.

Management Discussion and Analysis   INTEROIL CORPORATION   9

InterOil must comply with many changing laws, regulations and standards relating to corporate governance and public disclosure, including the Sarbanes-Oxley Act of 2002, new Securities and Exchange Commission (SEC) regulations and new and changing provisions of Canadian securities laws. The Company would face a wide variety of impacts should it fail to meet the requirements of new legislation. To manage this exposure, InterOil tasks its in-house legal, internal audit, and accounting teams with monitoring changes in legislation, regulation and accounting standards. Where necessary, InterOil also uses external professional advisors. InterOil has an internal audit function which test its controls and procedures to ensure compliance with Sarbanes-Oxley.

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 value to the communities in which InterOil operates. InterOil has taken a three-pronged approach when planning to achieve this strategy.

Q: What is InterOil’s business strategy?

A: To develop a vertically integrated energy company in Papua New Guinea.

Summary of Strategic Priorities

Following is a table outlining the Company’s progress towards the strategic priorities of the Company and its goals for 2007. Refer to the Annual Information Form for a summary of strategic priorities by segment.

Strategic
Priorities	2006 Progress	2007 Initiatives
Capitalize on and Expand on the Existing Business Assets	ü   Completed refinery optimization project, which included the installation of new generators and modifications of the furnaces and boilers to improve reliability and reduce fuel costs. ü   Secured a contract to provide InterOil Power Fuel to Papua New Guinea’s Moitaka Power Station.	ü   Evaluate feasibility of improvements, modifications and additional equipment to improve flexibility and profitability of the refinery. ü   Continue to seek out potential markets for InterOil Power Fuel and distillate export opportunities to increase contribution to fixed costs. ü    Cost reduction program targeting 10% reduction.

Management Discussion and Analysis   INTEROIL CORPORATION   10

Strategic
Priorities	2006 Progress	2007 Initiatives
Target Acquisitions and Growth Opportunities in Papua New Guinea and the Surrounding Area	ü   Finalized the terms of acquisition for Shell Papua New Guinea’s distribution network. The Shell Papua New Guinea business was transferred to InterOil on October 1. ü   Examined other potential downstream growth opportunities. ü   Progressed discussions for liquefied natural gas opportunity in Papua New Guinea with government and other potential partners.	ü    Pursue opportunities to purchase a business or assets in the business of distributing fuel to the aviation sector. ü    Pursue other potential downstream growth opportunities. ü    Sign a shareholder agreement relating to the LNG opportunity in Papua New Guinea and begin taking steps to advance project. ü    Finalize FEED decision and development plans for LNG project.
Position InterOil for Long-Term Oil and Gas Business Success	ü   Made potential gas and condensate discovery at Elk location on existing Petroleum Prospecting License 238. ü   Conducted seismic and airborne gravity and magnetic surveys on licenses to expand knowledge base of existing prospects and to identify new prospects.	ü   Obtain further information about the Elk structure by drilling the Elk-2 appraisal well and conducting 100 miles of appraisal seismic. ü    Conduct detailed 2D seismic surveys over the Elk discovery and lead on-trend with the Elk discovery that have been identified from seismic data and airborne gravity/magnetic surveys acquired by the company to date.

Management Discussion and Analysis   INTEROIL CORPORATION   11

FINANCIAL RESULTS

Summary of Consolidated Annual Financial Results

Annual Consolidated Financial Results

Consolidated results for year ended December 31, 2006 compared to year ended December 31, 2005 and 2004

	Years ended December 31,
Consolidated – Operating results	2006			2005			2004(2)
($ thousands, unless otherwise indicated)	(restated)(1)			(restated)
Sales and operating revenues		511,088			481,181			70,644
Interest revenue		3,224			1,831			382
Other non-allocated revenue		3,748			528			196
Total revenue		518,060			483,540			71,222
Cost of sales and operating expenses		(499,495	)		(467,247	)		(65,344	)
Office and administration and other expenses		(24,834	)		(23,296	)		(14,701	)
Exploration costs		(6,177	)		(11,009	)		(2,903	)
Exploration impairment		(1,647	)		(19,570	)		(35,567	)
Earnings before interest, taxes, depreciation and amortization (unaudited)		(14,094	)		(37,582	)		(47,293	)
Depreciation and amortization		(12,353	)		(11,037	)		(639	)
Interest expense		(17,273	)		(10,987	)		(3,203	)
Loss from ordinary activities before income taxes		(43,720	)		(59,606	)		(51,135	)
Income tax expense		(2,343	)		(2,832	)		(1,875	)
Non-controlling interest		264			368			70
Total net loss(3)		(45,799	)		(62,070	)		(52,940	)
Net loss per share (dollars)		(1.55	)		(2.15	)		(2.09	)
Net loss per diluted share (dollars)		(1.55	)		(2.15	)		(2.09	)
Total assets		505,239			432,897			385,842
Non current liabilities		283,306			178,968			101,222
Cash flows provided by/(used in) operations		2,187			(22,713	)		(76,864	)
Cash dividends declared per share		—			—			—

(1)	Our wholesale and retail distribution business segment acquired the business of Shell PNG Limited on October 1, 2006 and information in this table includes the results of the Shell business from this date.
(2)	Our refinery began commercial operations on January 1, 2005. During 2004 we were still constructing and commissioning our refinery and the costs associated with the construction and commissioning of our refinery were capitalized rather than expensed. As a result of our refinery not having any commercial operations in 2004, our 2004 to 2005 and 2006 results are not comparable. In addition, our wholesale and retail distribution business segment was acquired on April 28, 2004 and only operated for eight months during 2004. As a result of our downstream results not having a full year operations in 2004, our 2004 to 2005 and 2006 results are not comparable.
(3)	We did not have any discontinued operations or extraordinary items during the periods covered by this table.

Management Discussion and Analysis   INTEROIL CORPORATION   12

Annual Restated Consolidated Financial Result Analysis

EBITDA and total net loss position improved by $23.5 million and $16.3 million over 2005 due to lower exploration costs and exploration impairment. The EBITDA improvement is primarily due to decreased exploration costs relating to G&G costs and exploration impairment relating to Black Bass and Triceratops prospects taken up in 2005,. The total net loss position was influenced by higher depreciation and interest expense, in addition to the exploration costs, during 2006 as compared to 2005. A more detailed explanation of our consolidated 2006 results is contained below. A detailed analysis of each segments earning is contained under the heading “Year in Review”.

Consolidated results analysis for year ended December 31, 2006 compared to year ended December 31, 2005

InterOil’s net loss decreased from $62.1 million ($2.15/share) in 2005 to $45.8 million ($1.55/share) in 2006 and InterOil’s EBITDA improved from a loss of $37.6 million ($1.30/share) in 2005 to a loss of $14.1 million ($0.48/share) in 2006.

While a complete discussion of each of the segment’s result can be found under the section “Year in Review,” the following points highlight some of the key movements that have resulted in a $16.3 million decrease in our net loss between 2006 and 2005.

ü	Lower G&G expenses by $4.8 million in our Upstream segment and lower exploration impairment of $17.9 million as prior year impairment mainly consisted of Black Bass and Triceratops prospects which were abandoned in 2005.
ü	The refinery operations experienced a gross margin improvement of $0.5 million between 2005 and 2006. Although the gross margin suffered in the first half of 2006 due to shut down days, the positive impact of the revamp and optimization efforts have resulted in a net improvement for the year.
ü	In addition, the midstream operations experienced a $4.6 million exchange gain in 2006 as compared to a $1.4 million exchange loss in 2005 which partially resulted from the strengthening of the PGK against the USD. During the year we negotiated improved rates on our PGK to USD transactions.
ü	The refinery experienced higher interest expense in 2006 as a result of market increases in the cost of crude feedstock being financed, increases in the LIBOR indicator rates and increases to the volume of inventory on hand during the optimization shutdown.
ü	During 2006 we started our midstream liquefaction segment and up to the end of 2006 we had incurred $0.7 million of costs relating to the preliminary stages of a liquefied natural gas plant project.
ü	Our downstream business had a $0.7 million increase in depreciation expense, primarily due to the acquisition of Shell Papua New Guinea on October 1, 2006.
ü	During the year, we recognized a $0.8 million loss on the impairment of one of our two barges. One of these barges was sold during the year.
ü	Our interest expense for the year has increased as a result of the $130 million secured loan financing.
ü	We incurred a $1.9 million expense relating to the amendment of the PNG Drilling Ventures indirect participation interest agreement.

Management Discussion and Analysis   INTEROIL CORPORATION   13

Summary of Consolidated Quarterly Financial Results

Quarterly Consolidated Financial Results

Consolidated results for each quarter, 2006 compared to each quarter 2005 by business segment.

Quarters ended	2006 (restated)(1), (2)												2005 (restated)(1),
($ thousands unless stated
otherwise)	Dec 31			Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Sales and operating revenues		172,776			110,982			124,409			109,892			125,216			129,465			125,275			103,584
Upstream		705			900			2,684			959			854			404			37			—
Midstream – Refining and Marketing		147,538			94,687			106,825			103,105			108,625			115,273			114,717			98,051
Midstream – Liquefaction		—			—			—			—			—			—			—			—
Downstream		91,990			39,527			37,995			27,808			39,044			32,449			29,993			23,715
Corporate & Consolidated		(67,457	)		(24,132	)		(23,095	)		(21,980	)		(23,307	)		(18,661	)		(19,472	)		(18,182	)
Earnings before interest, taxes, depreciation and amortization (unaudited)		6,873			1,370			(10,323	)		(12,014	)		(19,668	)		(8,192	)		(5,375	)		(4,346	)
Upstream		(719	)		(1,107	)		(1,922	)		(5,136	)		(16,464	)		(13,333	)		(1,134	)		(91	)
Midstream – Refining and Marketing		9,144			1,674			(8,188	)		(5,230	)		(6,333	)		6,070			(6,796	)		(3,405	)
Midstream – Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		1,143			1,954			3,559			(326	)		3,963			2,522			2,550			584
Corporate & Consolidated		(2,299	)		(853	)		(3,770	)		(1,322	)		(834	)		(3,451	)		5			(1,434	)
Net income (loss) per segment(4)		(3,379	)		(7,323	)		(17,825	)		(17,272	)		(26,267	)		(14,590	)		(11,371	)		(9,841	)
Upstream		(954	)		(1,310	)		(2,098	)		(5,335	)		(16,554	)		(13,548	)		(1,138	)		(96	)
Midstream – Refining and Marketing		3,818			(4,309	)		(13,408	)		(10,052	)		(11,622	)		1,068			(11,839	)		(8,469	)
Midstream – Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		(427	)		1,278			2,426			(282	)		2,802			1,460			1,789			382
Corporate & Consolidated		(5,420	)		(2,684	)		(4,745	)		(1,603	)		(893	)		(3,570	)		(183	)		(1,658	)
Net income (loss) per share(4)(dollars)
Per Share – Basic		(0.11	)		(0.25	)		(0.60	)		(0.59	)		(0.90	)		(0.50	)		(0.39	)		(0.36	)
Per Share – Diluted		(0.11	)		(0.25	)		(0.60	)		(0.59	)		(0.90	)		(0.50	)		(0.39	)		(0.36	)

(1)	Our comparative quarterly results for all quarters during 2005 and 2006 have been represented to confirm with the presentation adopted at December 31, 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(2)	Our September 2006 quarterly results have been represented to separate out our Midstream-Liquefaction segment from the Midstream-Refining and Marketing segment as the liquefaction business has become an increasingly important component of our business.
(3)	We did not have any discontinued operations or extraordinary items during the periods covered by this table.

Quarterly results have been affected by movements in refining gross margins (as described in the Business Environment section), the impact of fluctuating production levels at the refinery resulting from maintenance and other shutdowns, the level of

Management Discussion and Analysis   INTEROIL CORPORATION   14

exploration activity not funded by our indirect participation interest agreement, changes in our borrowings, the acquisition of additional assets in our downstream business, and changes in volumes sold by our downstream business.

Quarterly Restated Consolidated Financial Results Analysis

Consolidated results analysis for three Months to December 2006 versus three Months to December 2005

EBITDA improved by $26.5 million from a loss of $19.7 million (loss of $0.67/share) to a profit of $6.9 million ($0.23/share).
InterOil’s net loss improved from a loss of $26.3 million ($1.01/share) in the fourth quarter of 2005 to $3.4 million ($0.11/share) in the fourth quarter of 2006.

Our fourth quarter 2006 net loss has improved by $22.9 million over our fourth quarter 2005 loss. The primary reasons for the change between the 2005 and 2006 quarters are as follows:

ü	Our upstream operations incurred lower G&G expenses and exploration impairment in fourth quarter of 2006 as compared to same period of 2005 resulting in an improvement of net loss by 15.6 million for the segment. The higher exploration impairment in fourth quarter of 2005 related to Triceratops prospects which was plugged and abandoned.
ü	The refinery operations experienced a gross margin improvement of $12.9 million between the 2005 quarter and the 2006 quarter. This is the result of the positive impact of the revamp and optimization efforts which has resulted in a more profitable product mix in 2006 and lower associated fuel costs for the refinery. In addition, the fourth quarter of 2006 benefited from changes that we negotiated in our low sulphur waxy residue and naphtha sales contracts.
ü	In addition, the midstream operations experienced a $0.4 million exchange gain in 2006 as compared to a $1.2 million exchange loss in 2005 which partially resulted from the strengthening of the PGK against the USD. During the year we negotiated improved rates on our PGK and USD transactions.
ü	The office and administration and other costs for the fourth quarter of 2006 have decreased by approximately $1.1 million. This is largely the result of a gain on derivative instruments that were not subject to hedge accounting.
ü	During 2006 we started our midstream liquefaction segment and during the fourth quarter of 2006 we incurred $0.4 million of costs relating to the preliminary stages of a liquefied natural gas plant project.
ü	Our downstream business had a $3.2 million decrease in its net income for the quarter over the prior year. This primarily related to product pricing. The IPP dropped from 1.56 PGK (USD $0.50) in September to 1.49 PGK (USD $0.48) at the beginning of January 2007. As the IPP declined each month, any inventory holdings purchased in preceding periods were sold at lower IPP prices, resulting in lower margins. The effect of this was compounded by our acquisition of Shell. Although we gained additional sales volume in the quarter, our gross margin declined. Sales volumes for our downstream business increased from 655 kilolitres per day in the fourth quarter of 2005 to 1,472 kilolitres per day in the fourth quarter of 2006.
ü	Depreciation associated with our midstream and upstream segment increased as a result of a full quarter of depreciation being recognized on our rig and exploration warehouse and also as the result of depreciation being recognized on the capitalized revamp costs.

Our interest expense for the quarter has increased by $2.7 million as a result of the $130.0 million secured loan financing. We entered the facility in May 2006.

For further analysis of the first through third quarter results, refer to InterOil’s quarterly MD&A available on the Company’s website at www.interoil.com or on www.sedar.com.

Management Discussion and Analysis   INTEROIL CORPORATION   15

YEAR IN REVIEW

The following section provides a review of 2006 for each of our business segments. It includes a business summary, an operational review of the year, a review of financial results, and an analysis of each stream’s contribution to InterOil’s corporate strategy.

Upstream Year In Review

Upstream Business Summary

Our upstream business currently has four exploration licenses and two retention licenses in Papua New Guinea covering approximately nine million acres, of which amount, approximately 8.2 million nett acres are operated by InterOil. Petroleum Prospecting Licenses 236, 237 and 238 are located in the Eastern Papuan Basin northwest of Port Moresby and are 100% owned and operated by the Company. Our current exploration efforts are focused on these three licenses. Our indirect participation interest investors have the right to a 31.55% working interest in the exploration wells currently being drilled and any resulting fields. These investors have a 31.55% interest in the next three exploration wells and a 24.8% interest in the two subsequent exploration wells. In addition, we own a 15% working interest in Petroleum Prospecting License 244, located offshore in the Gulf of Papua, a 43.1% working interest in Petroleum Retention License 4 and a 28.6% working interest in Petroleum Retention License 5.

Q: How much property in Papua New Guinea does the InterOil upstream buslness encompass?

A: InterOil has four exploration licenses and two retention licenses covering approximately 9 million acres.

Upstream Operating Review

Key Upstream Metrics	2006		2005
Wells drilled		1		2
Total wells drilled in eight well indirect participation interest program		3		2
Total feet drilled		6,087		12,597
2D seismic miles acquired		79		100
Airborne gravity and magnetic survey miles acquired		6,244		3,800
Total spent on seismic acquisition ($ millions)		6.8		11.0
Total spent on drilling ($ millions)		37.9		22.9

During the year we continued the eight well drilling program covering Petroleum Prospecting Licenses 236, 237 and 238 which we commenced in April 2005. In 2006, the Company drilled the third well in this program, Elk-1 on Petroleum Prospecting Licenses 238. This well, which was spudded in February 2006, encountered high pressure gas at a depth of 5,543 feet on June 11, 2006

Management Discussion and Analysis   INTEROIL CORPORATION   16

and was shut-in while well control equipment was mobilized to the site. Well control operations and modifications to the rig were undertaken to enable managed pressure drilling and we resumed drilling Elk-1 on September 15, 2006. The well reached a total depth of 6,087 feet. A drill-stem test was performed and wireline logs were acquired in the interval 5,379 to 6,087 feet. The data obtained from these operations indicate the possibility of a significant natural gas and condensate accumulation. The Elk-2 well was spudded on February 9, 2007 to appraise the Elk-1 discovery and to explore for an oil zone in this structure.

During 2006, we acquired a total of 79 miles of 2D seismic over Petroleum Prospecting License 238 at a cost of $5.2 million. The 2006 seismic program complemented the 136 miles of seismic program that we acquired during the previous three years. As of year end, we had access to 1,000 miles of 2D seismic data covering Petroleum Prospecting Licenses 236, 237 and 238, including the 215 miles we have recorded since acquiring these licenses. During the first quarter of 2007 we mobilized a seismic crew to conduct a detailed 2D seismic survey over the Elk discovery and leads on-trend with the Elk discovery that have been identified from seismic data and airborne gravity and magnetic surveys acquired by InterOil.

In addition to the seismic program, we also conducted 2,471 miles of airborne gravity and magnetic surveys in 237 and 3,773 miles in Petroleum Prospecting License 238. Airborne gravity and magnetic methods have enabled us to better identify the quality of leads derived from surface geology, to identify previously unmapped leads and to optimize the location of our 2D seismic programs.

Upstream Financial Results

	Years ended December 31,
Upstream - Operating results	2006			2005			2004(1)
($ thousands)	(restated)			(restated)(1)
External sales		—			—			—
Inter-segment revenue		—			—			—
Other non-allocated revenue		5,249			1,295			113
Total segment revenue		5,249			1,295			113
Cost of sales and operating expenses		—			—			—
Office and administration and other expenses		(5,553	)		(1,738	)		(1,648	)
Exploration costs		(6,177	)		(11,009	)		(2,903	)
Exploration impairment		(1,647	)		(19,570	)		(35,567	)
Impairment expense on barge sale		(757	)		—			—
Earnings before interest, taxes, depreciation and amortization (unaudited)		(8,885	)		(31,022	)		(40,005	)
Depreciation and amortization		(806	)		(314	)		(13	)
Interest expense		(5	)		—			(5	)
Loss from ordinary activities before income taxes		(9,696	)		(31,336	)		(40,023	)
Income tax expense		—			—			—
Total net loss		(9,696	)		(31,336	)		(40,023	)

(1) Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.

Management Discussion and Analysis   INTEROIL CORPORATION   17

Upstream Restated Financial Results Analysis

During 2006, the upstream business had a net loss of $9.7 million as compared to a loss of $31.3 million in 2005.

The key variances in the year ended 2006 as compared to the year ended 2005 are explained as follows:

ü	A decrease of $4.8 million in exploration expenses relating to the seismic program undertaken in 2006 as more G&G costs were incurred at the start of the eight well exploration program initiated in 2005.
ü	A decrease of $17.9 million in exploration impairment is the result of the drilling and testing costs relating to the Black Bass and Triceratops wells being expensed in 2005 whereas in 2006 the majority of the expense relates to the acquisition of additional interests in our PRL 4 and PRL 5 licenses.
ü	An increase in other revenues of $3.9 million in 2006 primarily related to the rental of our company-owned rig being charged against our indirect participation interest at current market day rents. Because we expense the costs of owning and maintaining this rig, the amounts charged to the indirect participation interest liability are recognized as revenue by our upstream business segment. The increase is also contributed by intercompany interest revenue of $1.4m received by Upstream from Corporate on account of the use of IPI funds. The revenue also relates to the one-time rental of camp facilities and providing logistics support to another exploration company.
ü	An increase of $2.7 million, included in office and administration and other expenses, related to the costs of owning and maintaining the rig.
ü	An increase of $0.8 million for the impairment expense on a barge sale. The Company sold one of its two barges to a third party during the year.
ü	An increase in depreciation expense of $0.5 million in 2006 as a result of a full year of depreciation being recognized on the rig, offices and warehouse which were purchased part way through 2005.

Outlook for 2007

2007 planned activity

ü	Drill appraisal well, Elk-2, and exploration well Antelope-1
ü	Conduct 100 miles of appraisal seismic over the Elk structure
ü	Drill one well in PRL 5
ü	Re-enter and test the Stanley gas discovery in PRL 4

Key factors that will affect our 2007 progress

ü	Results from Elk-2 and Antelope-1
ü	Ability to attract and retain staff in a competitive oil and gas industry
ü	Conclusion of an exploration funding agreement with an industry major
ü	Proving sufficient gas reserves to guarantee the liquefaction project

Management Discussion and Analysis   INTEROIL CORPORATION   18

MIDSTREAM REFINING AND MARKETING YEAR IN REVIEW

Midstream Refining and Marketing Business Summary

The midstream operations predominately relate to our refinery situated in Port Moresby, the capital city of Papua New Guinea. Our refinery comprises of a 32,500b/d crude distillation unit (CDU) and a 3,500b/d catalytic reforming unit (CRU) which were commissioned during the second half of 2004 and began commercial operations in 2005. InterOil is the sole refiner of hydrocarbons in Papua New Guinea and the refinery’s output is sufficient to meet 100% of the domestic demand in Papua New Guinea. Diesel, jet fuel and gasoline are the primary products that we produce for the domestic market.

Operation of the CDU also results in the production of naphtha and low sulfur waxy residue and sometimes limited volumes of LPG’s are produced depending on the crude feedstock. To the extent that we do not convert naphtha to gasoline within the CRU, we export it to the Asian markets in two grades, light naphtha and mixed naphtha, which are predominately used as petrochemical feedstocks. To the extent that we do not consume the low sulfur waxy residue as part of the refinery’s fuel requirement or sell it within Papua New Guinea as fuel for electricity generation — a profitable new niche market we have recently created — the low sulfur waxy residue is exported as it is valued by more complex refineries as cracker feedstock or may be utilized as fuel in large power stations.

Q: How much of the domestic demand in Papua New Guinea does the refinery supply?

A: The refinery’s output is sufficient to meet 100% of the domestic demand in Papua New Guinea.

Midstream Refining and Marketing Operating Review

Key Refining and Marketing Metrics	2006			2005
Net income/(loss) ($ millions)	$	(24.0	)	$	(30.9	)
EBITDA ($ millions)	$	(2.6	)	$	(10.5	)
Throughput (barrels per day)(1)		19,784			23,117
Cost of production per barrel(2)	$	3.46		$	3.09
Working capital financing cost per barrel of production(2)	$	1.16		$	0.96
Distillates as percentage of production		65	%		55	%

(1)	Throughput per day has been calculated excluding shut down days.
(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.

The refining and marketing stream has been improved by reducing its net loss and increasing its EBITDA by $7.9 million from 2005 to 2006. The improvements in the results are explained in detail in the optimization efforts section below as well as in the summary of financial results.

Management Discussion and Analysis     INTEROIL CORPORATION     19

In 2006 our total throughput for the year was 19,784 bbls per day versus 23,117 bbls per day in 2005. The decrease in throughput from 2005 to 2006 is the result of improved distillate yields. In addition, during 2005 the refinery was run at higher throughputs in the early part of the year in order to complete commissioning requirements.

The decrease in throughput has resulted in higher costs of production per barrel. Although total operating costs were down approximately $0.8 million, total notional throughput was also down by approximately 1 million barrels over the course of the year. The refinery is undertaking a cost reduction program in 2007 with the goal of reducing operating costs by approximately 10%.

Our working capital financing costs have increased, primarily due to the substantial increase in the LIBOR rate which has increased from approximately 2.3% to approximately 5.3% between 2005 and 2006.

During 2006, the refinery’s objective was to satisfy the domestic Papua New Guinea demand for diesel, jet, kerosene and gasoline while minimizing production of naphtha and low sulphur waxy residue. The refinery was able to achieve this objective through optimization efforts which have resulted in an increased distillate output as a percentage of total production. Naphtha and low sulphur waxy residue are exported at a lower margin than the distillates which are sold in Papua New Guinea.

Optimization Efforts

Our midstream business operations were focused on optimization projects to improve profitability throughout 2006. Most of the optimization occurred in June and July when we shutdown the refinery to install new generators and to modify the furnaces and boilers to also run on low sulfur waxy residue. These works improved the product slate, improved reliability and reduced fuel costs. The shutdown had minor short-term cost impacts whilst facilitating major long-term profitability improvements. Despite the cost impacts resulting from the shutdown of the refinery, the refinery’s performance in the second half of 2006 was significantly improved from that of the first half of 2006.

Q: How do the “revamp” works and crude optimization efforts undertaken in 2006 improve profitability?

A: These initiatives have resulted in increased yields of higher value products and lower fuel consumption at the refinery.

Management Discussion and Analysis     INTEROIL CORPORATION     20

Distillates, such as jet fuel and diesel, produced for the domestic market contribute a higher gross margin than naphtha and low sulphur waxy residue. As a result, increasing the yield of distillates produced has resulted in a higher gross margin for the business. In addition to reducing the yield of naphtha and low sulphur waxy residue, the revamp works have resulted in a reduced fuel requirement. This reduces the cost of production and therefore contributes to an improvement in gross margin.

The completion of optimization activities and various other cost saving initiatives undertaken by the company, have contributed to a significant improvement in the results of the second half of 2006 as compared to the first half of 2006 which are explained below.

Gross margin improved $16.5 million between the first and second half of 2006 due to the combination of competing factors:

Controllable

+	Improved yield structure post shutdown
+	Decreased fuel consumption post shutdown
+	Decreased fuel cost post shutdown
+	Improved premiums negotiated on export products

Non controllable

+	Improved margins on domestic sales of distillates
–	Decreased margins versus benchmark prices on export sales
–	Decreasing price environment in second half versus increasing price environment in first half
–	Decreasing benchmark refining margin (Singapore Tapis Hydroskimming)

ü Foreign exchange gains in the second half of 2006 were $4.5 million compared to $0.1 million for the first half of 2006. During the year we negotiated improved rates on our PGK to USD transactions.

Management Discussion and Analysis     INTEROIL CORPORATION     21

ü	The effect of non-hedge accounted derivatives on earnings increased by $2.7 million from the first half to the second half of 2006. During the second half of the year we introduced a new derivative instrument into our risk management program. This instrument, coupled with the technique by which we utilize it, was deemed not to be subject to hedge accounting and as a result all movements on these derivative contracts are recognized in the statement of operations below the gross margin level. Realized and unrealized gains from this new risk management instrument are largely responsible for the $2.7 million movement between the two periods.
ü	Borrowing costs increased by $0.7 million in the second half of 2006 due to the combination of increased LIBOR rates on our working capital facility and increased working capital borrowing requirements as a result of the refinery holding excess inventory through the shutdown period. These two factors were partially offset by decreased LC fees and the increased utilization of the cash backing component of our working capital facility. The cash backing allows us to reduce the cost of our net borrowings.
ü	General and administrative expenses decreased by $0.8 million between first and second half of 2006 as a result of various cost saving initiatives undertaken by the refinery management team and a decrease in legal costs as a result of the settlement of our dispute with Clough Niugini Limited at the end of the first half of 2006.
ü	Depreciation increased by $0.3 million as a direct result of the capital revamp works undertaken during the year.

Outlook for 2007

2006 improvements set to show full year benefit in 2007

ü	Contract premium improvements to export products
ü	Improvement to negotiated foreign exchange rates on PGK and USD transactions
ü	Improvement to working capital interest rates
ü	Improved product yields
ü	Decreased fuel costs

2007 Initiatives:

ü	Conduct negotiations to reduce working capital costs
ü	Implement strategies to further improve foreign exchange rates
ü	Reduce direct operating costs
ü	Eliminate unplanned downtime
ü	Expand niche market for InterOil Power Fuel
ü	Reduce length of working capital cycle
ü	Seek out and exploit operational and tax planning synergies in conjunction with the newly expanded downstream business

Management Discussion and Analysis     INTEROIL CORPORATION     22

Midstream Refining and Marketing Annual Financial Results

Midstream
Refining and Marketing - Operating results	Years ended December 31,
($ thousands)	2006			2005(2)			2004(1),(2)
External sales		315,211			356,327			26,310
Inter-segment revenue		136,584			80,094			—
Interest and other revenue		360			245			(55	)
Total segment revenue		452,155			436,666			26,255
Cost of sales and operating expenses		(451,374	)		(436,491	)		(27,686	)
Office and administration and other expenses		(10,577	)		(9,747	)		(3,189	)
Gain on derivative contracts		2,560			542			34
Foreign exchange gain/(loss)		4,636			(1,434	)		22
Earnings before interest, taxes, depreciation and amortization (unaudited)		(2,600	)		(10,464	)		(4,563	)
Depreciation and amortization		(10,729	)		(10,598	)		(312	)
Interest expense		(10,881	)		(10,162	)		(844	)
Loss from ordinary activities before income taxes		(24,210	)		(31,224	)		(5,719	)
Income tax expense		—			—			—
Non controlling interest		259			362			69
Total net loss		(23,951	)		(30,862	)		(5,650	)

(1)	Our refinery began commercial operations on January 1, 2005. During 2004 we were still constructing and commissioning our refinery and the costs associated with the construction and commissioning of our refinery were capitalized rather than expensed. As a result of our refinery not having any commercial operations in 2004, our 2004 to 2005 and 2006 results are not comparable.
(2)	Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.

Midstream Refining and Marketing Annual Financial Results Analysis

During the year ended 2006, the midstream business had a net loss of $24.0 million as compared to a loss of $30.9 million in 2005. The key variances in the year ended 2006 as compared to the year ended 2005 are explained as follows:

ü	An increase to gross margin of $0.5 million for the year was primarily the result of the revamp improvements made in the second half of 2006 and price risk management activities over the year.
ü	Higher office and administration and other expenses of $0.8 million was due to a number of factors including increased repairs and maintenance, corporate allocations, travel costs, and management salaries and contractor costs.
ü	An increase to the gain on derivative contracts of $2.0 million due to increased price risk management activity that is deemed not to be subject to hedge accounting.
ü	An increase in foreign exchange gain/(loss) of $6.1 million was due to the strengthening of the PGK against USD and negotiating improved rates on our PGK to USD transactions during 2006.
ü	Higher depreciation expense of $0.1 million was due to the addition of depreciable assets from the refinery revamp program.
ü	An increase in interest expense of $0.7 million was due to increasing LIBOR rates and increased borrowing requirements due to higher oil prices partially offset by a decrease in line of credit (LC) fees.

Management Discussion and Analysis     INTEROIL CORPORATION     23

MIDSTREAM LIQUEFACTION YEAR IN REVIEW

Q: What type of liquefaction facility does InterOil currently envisage?

A: A facility that will produce 9 million tons per annum of liquefied natural gas

Midstream Liquefaction Operating Review

Our liquefaction segment is in the early stages of its development. In May, InterOil signed a Memorandum of Understanding with the Independent State of Papua New Guinea for natural gas development projects in Papua New Guinea and a tri-party agreement with Merrill Lynch Commodities (Europe) Limited and an affiliate of Clarion Finanz AG. The tri-party agreement relates to a proposal for the construction of a liquefaction plant to be built adjacent to our refinery. We are targeting a facility that will produce up to nine million tons per annum of Liquefied Natural Gas (LNG) and condensates. The infrastructure currently being contemplated includes condensate storage and handling, a gas pipeline from the Elk location as well as sourced suppliers of gas, and LPG storage and handling. The LNG facility will also interface with our existing refining facilities.

As at year end 2006, significant progress was made on the key components necessary to bring to fruition a successful LNG project. During 2007 the company anticipates entering into a shareholder agreement relating to the project and further development stage activities relating to the construction and financing of the plant.

Midstream Liquefaction Annual Financial Results

Midstream
Refining and Marketing - Operating results	Years ended December 31,
($ thousands)	2006			2005(1)		2004(1)
External sales		—			—		—
Inter-segment revenue		—			—		—
Total segment revenue		—			—		—
Cost of sales and operating expenses		—			—		—
Office and administration and other expenses		(694	)		—		—
Earnings before interest, taxes, depreciation and amortization (unaudited)		(694	)		—		—
Depreciation and amortization		—			—		—
Interest expense		—			—		—
Loss from ordinary activities before income taxes		(694	)		—		—
Income tax expense		—			—		—
Total net loss		(694	)		—		—

(1) Our liquefaction segment was formed in 2006 and as a result there is no comparative information for 2005 and 2004. The liquefaction segment is in its early stage of development.

Management Discussion and Analysis     INTEROIL CORPORATION     25

Midstream Liquefaction Annual Financial Results Analysis

All costs relating to the liquefaction segment are currently being expensed. These costs include expenses relating to employees, office premises, and consultants.

DOWNSTREAM YEAR IN REVIEW

Downstream Business Summary

Our wholesale and retail distribution business is the largest and most comprehensive asset distribution base in Papua New Guinea. It encompasses bulk storage, aviation refueling, and the wholesaling and retailing of refined petroleum products which, at the end of 2006, supplies approximately 67% of Papua New Guinea’s refined petroleum product needs. Our retail and wholesale distribution business distributes diesel, jet fuel, gasoline, kerosene, avgas, and fuel oil as well as Shell & 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 refining and marketing business segment with the exception of lubricants, fuel oil and avgas.

Q: How prominent is InterOil’s wholesale and retail distribution business in Papua New Guinea.

A: The InterOil name is associated with 49 service stations, 11 depots and 6 terminals. InterOil supplies 67% of Papua New Guinea’s refined petroleum product needs.

As of 2006, we provided petroleum products to 49 retail service stations that now operate under the InterOil brand name. Of the 49 service stations that we supply, 21 are owned by us or head leased, with a sublease to company approved operators. The remaining 28 service stations are independently owned and operated. We supply products to each of these service stations pursuant to retail supply agreements. In addition to our retail distribution network, we supply petroleum products as a wholesaler to commercial clients and also operate 14 aviation locations throughout Papua New Guinea. We own and operate 6 larger terminals and 11 depots that we use to supply product throughout Papua New Guinea. More than two-thirds of the volume of petroleum products that we sold during 2006 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.

Management Discussion and Analysis     INTEROIL CORPORATION     25

Downstream Operating Review

Key Downstream Metrics	2006			2005
Net income ($ millions)	$	3.0		$	6.4
EBITDA ($ millions)	$	6.3		$	9.6
Market share (1)		67	%		29	%
Sales volumes (millions of liters)(2)		291.8			210.4
Cost of distribution per liter ($  per liter)(3)	$	0.06		$	0.05

(1)	Market share has been calculated based on domestic purchases of product from the refinery during the final quarter of each year.
(2)	Sales volumes reflect the actual sales volumes achieved for the year and therefore only include the effect of the Shell acquisition from October 1, 2006.
(3)	Cost of distribution per liter includes land based freight costs and operational costs. It excludes depreciation and interest.

In January 2006, InterOil entered into an agreement with Shell Overseas Holdings Limited to purchase all of Shell’s retail and distribution assets in Papua New Guinea and all aviation facilities except Shell’s interest in the aviation facility in Port Moresby. The closing of this transaction was subject to the approval of several governmental authorities in Papua New Guinea. On October 1, 2006 the transfer of ownership occurred, adding 4 terminals, 4 depots, 17 retail sites and 14 aviation facilities to the existing downstream asset base. All of these assets now operate under the InterOil Products brand name. The purchase price of this business was $25.8 million, net of cash received, and is subject to adjustment pending verification of the acquired working capital.

The Shell acquisition makes InterOil the largest distribution business in Papua New Guinea. Other major commercial customer wins have also increased our presence in the Papua New Guinea market. Our market share has increased from 29% in the final quarter of 2005 to 67% in the final quarter of 2006 as a result of acquiring Shell and growing our commercial customer base.

Management Discussion and Analysis     INTEROIL CORPORATION     26

The increase in sales volume from commercial customers has resulted in a lower cost of distribution per litre. However, despite the significant increase in total sales made by the downstream business and a decline in the cost of distribution per litre, the net profit has declined. This is largely attributable to a substantial decline in the IPP price over the fourth quarter of 2006. In 2005, the company benefited from increases in the IPP prices.

The diesel IPP price fell from 1.65 PGK on October 8, 2006 to 1.49 PGK on January 8, 2007. . The IPP price is set on the eighth day of each month. In a market where IPP is declining, the price change results in all inventory being revalued to, and subsequently sold at, the lower amount. This in turn causes a decrease in the gross margin earned by the downstream business. During 2005 the diesel IPP price increased steadily from 1.10 PKG to 1.61 PGK.

In July 2006 the downstream business completed the construction of a 2 million litre diesel storage tank at our terminal Wewak, East Sepik, to augment storage availability at that location. The East Sepik province has experienced substantial growth in recent years. In addition, Mobil and Shell closed their operations in the town of Wewak. The additional infrastructure will place us in a strong position to continue to service the needs of the East Sepik market and take advantage of the changes that have occurred.

Management Discussion and Analysis   INTEROIL CORPORATION   27

Downstream Financial Results

Downstream - Operating results	Years ended December 31,
($ thousands)	2006(1)			2005(2)			2004(2),(3)
External sales		195,877			124,854			62,410
Inter-segment revenue		22			6			489
Interest and other revenue		1,421			341			263
Total segment revenue		197,320			125,201			63,162
Cost of sales and operating expenses		(183,511	)		(110,857	)		(53,159	)
Office and administration and other expenses		(7,479	)		(4,725	)		(3,147	)
Earnings before interest, taxes, depreciation and amortization (unaudited)		6,330			9,619			6,856
Depreciation and amortization		(910	)		(204	)		(224	)
Interest expense		(152	)		(226	)		(455	)
Income from ordinary activities before income taxes		5,268			9,189			6,177
Income tax expenses		(2,273	)		(2,756	)		(1,900	)
Total net income		2,995			6,433			4,277

(1)	Our wholesale and retail distribution business segment acquired the business of Shell Papua New Guinea Limited on October 1, 2006 and contains the results of the Shell business from this date.
(2)	Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(3)	Our wholesale and retail distribution business segment was acquired on April 28, 2004 and only operated for eight months during 2004. As a result of our downstream results not having a full year of operations in 2004, our 2004 to 2005 and 2006 results are not comparable.

Downstream Financial Results Analysis

During the year ended December 31, 2006, the downstream business earned a net income of $2.9 million as compared to $6.4 million in 2005.

The key variances in the year ended 2006 as compared to the year ended 2005 are explained as follows:

ü	A decrease to gross margin of $1.6 million for the year 2006 over the year 2005 was most significantly the result of continuous drops in IPP over the fourth quarter of 2006. The IPP dropped from K1.65 in September to K1.49 at the beginning of January 2007. As the IPP declined each month, any inventory holdings purchased in preceding periods were sold at lower IPP prices, resulting in lower margins. The effect of this was compounded as our acquisition of Shell and its corresponding inventory balance coincided with the decline in IPP pricing.
ü	An increase in office and administration and other expenses of $2.8 million due to a number of factors including, higher insurance costs as a result of the acquisition of the Shell business and expansion of the aviation business, higher corporate allocations, increased repairs and maintenance costs, and increased travel costs.
ü	An increase in depreciation expense of $0.7 million over 2005 related primarily to the addition of the Shell assets on October 1 and the completion of the 2 million litre East Sepik tank project.
ü	Our income tax expense as a percentage of income from ordinary activities has increased during 2006 as the result of a reduction to the future income tax benefit being recognized on the revaluation of the Shell plant and equipment acquired on October 1.

Management Discussion and Analysis   INTEROIL CORPORATION   28

Outlook for 2007

2007 capital spending plans

ü	Upgrades to terminal, depots and aviation sites
ü	Aviation upgrade and refueller vehicles
ü	New customer base pumps and tankage requirements
ü	Finance system software installation

2007 growth plans:

ü	Consider commercial bunkering opportunities
ü	Secure contracts to supply new mining and petroleum companies
ü	Pursue opportunities in organic growth agriculture sector
ü	Explore market opportunities in North Solomon’s Province, including strategic alliances with key distributors

CORPORATE YEAR IN REVIEW

Corporate Restated Annual Financial Results

	Years ended December 31,
Corporate - Operating results	2006			2005
($ thousands)	(restated)(5)			(restated)			2004
External sales elimination		—			—			(18,075	)
Inter-segment revenue elimination(1)		(136,606	)		(80,101	)		(489	)
Interest revenue		(58	)		480			165
Other unallocated revenue		—			(1	)		91
Total segment revenue		(136,664	)		(79,622	)		(18,306	)
Cost of sales and operating expenses elimination(1)		135,391			80,101			15,500
Office and administration and other expenses(2)		(6,971	)		(6,193	)		(6,773	)
Earnings before interest, taxes, depreciation and amortization (unaudited)		(8,244	)		(5,714	)		(9,581	)
Depreciation and amortization(3)		92			79			(90	)
Interest expense(4)		(6,235	)		(599	)		(1,899	)
Income from ordinary activities before income taxes		(14,387	)		(6,234	)		(11,570	)
Income tax expenses		(69	)		(76	)		25
Non-controlling interest		4			6			1
Total net income		(14,452	)		(6,304	)		(11,544	)

(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)	Represents the amortization of a portion of costs capitalized to assets on consolidation.
(4)	Includes the elimination of interest accrued between segments.
(5)	Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.

Management Discussion and Analysis   INTEROIL CORPORATION   29

Corporate Annual Results Analysis

Key movements in our corporate services segment between 2006 and 2005 were as follows:

ü	A decrease of $0.3 million in stock compensation expense recognized in office and administration and other expenses.
ü	An increase in interest expense of $5.6 million primarily relating to the increased borrowings made under the secured loan facility entered into in May 2006.

LIQUIDITY AND CAPITAL RESOURCES

Summary of Cash Flows

($ thousands)	2006 (restated)			2005 (restated)			2004
Net cash inflows/(outflows) from:
Operations		2,187			(22,713	)		(79,767	)
Investing		(97,071	)		(64,942	)		(29,024	)
Financing		66,964			118,712			128,119
Net cash movement		(27,920	)		31,057			19,328
Opening cash		59,601			28,544			9,216
Closing cash		31,681			59,601			28,544

Operating Activities

For the year ended 2006 cash generated by our operating activities was $2.2 million compared with cash used in operating actitives of $22.7 million in 2005. Reasons for the $24.9 million improvement in net cash movements include:

ü	Our cash used in operations, prior to changes in non-cash working capital increased by $4.6 million. This is primarily due to interest paid on the $130.0 million secured loan facility entered into in 2006.
ü	Our non-cash working capital provided a cash inflow from operations of $24.8 million in 2006 as compared to contributing $4.7 million to the cash outflows in 2005. These working capital movements relate to the timing of receipts, payments and inventory purchases.

Investing Activities

For the year 2006, cash used in our investing activities was $97.1 million compared with $64.9 million for the year 2005. During these periods, the cash used on investing activities consisted primarily of:

ü	$15.9 million increase in our secured cash balances in 2006 versus an increase of $1.1 million in 2005.
ü	$25.8 million, net of cash received, used to acquire Shell Papua New Guinea on October 1.
ü	$48.0 million on oil and gas exploration expenditure on Elk prospect in 2006 versus $43.0 million in 2005 mainly related to drilling and seismic activities on Black Bass and Triceratops prospects.
ü	$13.6 million on plant and equipment in 2006 versus $5.6 million in 2005 which is primarily related to the revamp and optimization activities undertaken by the refinery and the additional diesel tank built by the downstream business in East Sepik.

Management Discussion and Analysis   INTEROIL CORPORATION   30

Financing Activities

For the year 2006, cash proceeds from our financing activities were $67.0 million. During 2006, the cash movements caused by financing activities were primarily due to:

ü	$125.3 million of net proceeds from our secured loan facility entered into in May 2006.
ü	$1.5 million from the issuance of common shares in 2006 as compared to $5.5 million received in 2005.
ü	$33.9 million of repayments on the crude import facility in 2006 versus $5.8 million of repayments made in the 2005 period.
ü	$21.5 million in repayments of unsecured loans in 2006. These proceeds were received in 2005.

In 2005, $103.1 million was provided by the indirect participation interest investors for the eight well drilling program.

Capital Expenditures

Upstream Capital Expenditures

Our capital expenditures for exploration in Papua New Guinea for the year ended December 31, 2006 were $48.0 million compared with $43.0 million during the same periods in 2005. Our capital expenditures for 2006 consisted of:

ü	$33.1 million for the drilling and testing of the Elk-1 exploration well. The Elk-1 well expenditures were higher than expected as a result of encountering high pressure gas that required significant expenditures to control the well pressure before we could continue drilling the well. Our drilling progress was impeded for three months.
ü	$3.0 million of pre-drill costs on the Elk-2 structure, including site preparation, camp construction, rig mobilization and supplier standby costs.
ü	$1.0 million of demobilization costs from the Triceratops drill site.
ü	$5.6 million for seismic acquisition.
ü	$1.1 million for airborne gravity survey work.
ü	$3.8 million for rig equipment, primarily in relation to increasing the capacity of the mud circulation system.
ü	$0.6 million for inventory and other costs includes drilling consumables such as mud, casing and drill bits, as well as spare parts for all the rig equipment.
ü	$0.3 million of pre-drill costs for the Antelope-1 well which includes preliminary site clearing and the construction of a helicopter pad. We anticipate mobilizing to Antelope-1 wellsite immediately after rig release from Elk-2 well. The Antelope structure is located approximately 4 miles from of Elk-1 well and 8 miles from the Elk-2 well.

The increase in capital expenditures during 2006 compared to the same period of 2005 is due to the increased costs relating to drilling the Elk-1 well.

Midstream Capital Expenditures

Our capital expenditures for our refining and marketing business segment for the year 2006 were $12.0 million compared with $3.3 million during 2005. The increase in capital expenditures during 2006 is primarily related to our refinery optimization program that was completed during the third quarter of 2006.

Downstream Capital Expenditures

Our capital expenditures for our wholesale and retail distribution business segment for 2006 were $27.6 million compared with $14.0 million during the same period in 2005. Our 2006 capital expenditures consisted of costs associated with the completion of the East Sepik and the purchase of storage tanks, mine packs, new fuel distribution software and satellite storage. In addition

Management Discussion and Analysis   INTEROIL CORPORATION   31

we acquired commercial storage tanks and pumps for the Shell business. Also included in our capital expenditures for 2006 is $25.8 million, net of cash received, for the Shell Papua New Guinea acquisition. The 2005 expenditure primarily related to a $12.1 million payment made to BP International for the acquisition of InterOil Products Limited and $1.9 million for a storage tank, barge facility and a number of other smaller capital items.

Sources of Capital

Upstream

We currently fund all of our upstream capital expenditures using the proceeds of the $125.0 million Indirect Participation Interest Agreement that we entered into in February 2005.

Midstream

In August 2006, we renewed our Secured Revolving Crude Import Facility with BNP Paribas (Singapore Branch), increasing the facility from $150.0 million to $170.0 million. This crude import facility is used to finance purchases of crude feedstock for our refinery. Our ability to borrow additional amounts under this crude import facility expires on June 30, 2007, at which time we expect to have renewed the facility or entered into an alternate funding arrangement. As of December 31, 2006, $52.6 million remained outstanding under the crude import facility. The weighted average interest rate under the crude import facility was 7.3% for the year ended December 31, 2006.

In December 2006, our OPIC secured loan was amended. Under the amendment, the half year principal payments due in December 2006 and June 2007 of $4.5 million each have been deferred until December 31, 2007 and interest payments previously due on December 31, 2006 and June 30, 2007 have been deferred until September 30, 2007. Repayments of interest and principal will recommence on December 31, 2007.

Downstream

Our downstream working capital and capital programs are funded by cash provided by operating activities.

Corporate

On May 4, we entered into a $130.0 million two-year secured loan facility. The initial interest rate under this secured loan facility is 4%, increasing to 10% if we do not enter into an agreement with the lenders under this facility related to the development of a liquefied natural gas facility. We received $65.0 million in gross proceeds on the closing date of this secured loan facility and a further $35.0 million on June 29. A further drawdown of $18.0 million was made in September. A portion of these proceeds was used to repay $25.3 million in principal and interest outstanding under an unsecured loan that we entered into on January 28, 2005. On October 27, $12.0 million, representing the balance available under this facility, was drawn down.

Capital Requirements

The capital requirements for each of our business segments are discussed below. The oil and gas industry is capital intensive and our business plans involve raising additional capital. The availability and cost of such capital is highly dependent on market conditions at the time we raise such capital.

Upstream

We are obligated under our $125.0 million indirect participation agreement entered into in February 2005 to drill eight exploration wells. We completed our third exploration well (Elk-1) in November 2006, pursuant to this indirect participation interest agreement, where drilling costs have increased as a result of a discovery with high pressure gas and gas liquids. The higher costs incurred at the Elk-1 well may be partially offset by the payment of a pending insurance claim under our “Control of Well” policy. We believe the potential recovery under the insurance claim, combined with the funds remaining under the indirect participation agreement

Management Discussion and Analysis   INTEROIL CORPORATION   32

should be sufficient to meet our obligation to drill the remaining five wells under the program, however, in the event we do not recover on our insurance claim, we may require additional capital to complete the program. No assurance can be given that we will be successful in obtaining new sources of capital on terms that are acceptable to us if such new capital is needed. The cost of drilling exploration wells in Papua New Guinea is subject to numerous factors, including the location where such wells are drilled. We believe that we will be able to reduce the cost of future exploration wells; however, if we are unable to drill future exploration wells at a cost per well that is significantly lower than the current cost of the Elk discovery well drilled pursuant to this agreement, we may not have sufficient funds to satisfy our obligations under the indirect participation agreement, and would look to farmout or raise additional capital. However, we can provide no assurances that a farmout will be completed or that the terms of any such farmout will be acceptable to us. As of December 31, 2006, we had incurred $76.9 million in capital expenditures related to the drilling of exploration wells required to be drilled pursuant to the indirect participation interest agreement.

In order to evaluate the discovery of gas and gas liquids disclosed under “Results of Operations - Upstream -Exploration and Production,” we will be required to drill additional appraisal wells. We are not currently permitted to use proceeds raised under our indirect participation interest agreement to drill these wells. As a result, we will be required to obtain the consent of the investors under the indirect participation interest agreement to use these funds to drill non-exploration wells or we will be required to raise additional funds to support this development. We can provide no assurances that we will be able to obtain such approvals or financing on terms that are acceptable to us.

Midstream

We believe that we will have sufficient funds from the proceeds of our secured loan facility entered into on May 4, 2006 to pay our estimated capital expenditures for 2007. As of December 31, 2006, our primary lender for the midstream had agreed to defer interest payable until September 30, 2007 and principal until December 31, 2007 to assist our cash flows. We can give you no assurance that our primary lender will be willing to defer interest on principal. In addition, while cash flows from operations are expected to be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility, 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.

Downstream

We believe that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2007.

Management Discussion and Analysis   INTEROIL CORPORATION   33

Contractual Obligations and Commitments

The following table contains information on payments for contracted obligations due for each of the next five years and thereafter and should be read in conjunction with our financial statements and the notes thereto:

	Payments Due by Period
			Less										More
Contractual obligations			than 1		1 – 2		2 – 3		3 – 4		4 – 5		than 5
($ thousands)	Total		year		years		years		years		years		years
Secured loan obligations		197,666		13,500		130,666		9,000		9,000		9,000		26,500
Accrued financing costs		1,450		363		1,087		—		—		—		—
Acquisition of subsidiary		1,771		1,771		—		—		—		—		—
Indirect participation interest(1)		1,921		731		1,190		—		—		—		—
Indirect participation interest(2)		96,861		—		96,861		—		—		—		—
Petroleum prospecting and retention licenses(3)		5,237		1,877		3,360		—		—		—		—
Total		304,906		18,242		233,164		9,000		9,000		9,000		26,500

(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 19 to our audited financial statements for the years ended December 31, 2006, 2005 and 2004.
(2)	The liability presented in relation to indirect participation interest is not a cash commitment and will be resolved once the IPI investors have elected to convert their interests into a joint venture interest or shares in InterOil Corporation. InterOil’s commitment is to complete the eight well drilling program. As at December 31, 2006, management estimate that a further $48,126,000 will be required to be spent to fulful this commitment.
(3)	The amount pertaining to the petroleum prospecting and retention licenses represents the amount InterOil has committed to spend to its joint venture partners. In addition to this amount, InterOil must drill an exploration well in Petroleum Prospecting License 237 prior to the end of March 2009 in order to retain this license. As the cost of drilling this well cannot be estimated, it is not included within the above table.

Off Balance Sheet Arrangements

As of December 31, 2006, we did not have any off balance sheet arrangements and did not enter into any during the year 2006, including any relationships with unconsolidated entities or financial partnerships to enhance perceived liquidity.

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 2006 (2005 — $150,000). This management fee relates to Petroleum Independent and Exploration Corporation being appointed the General Manager of one of our subsidiaries, S.P. InterOil, LDC.

Breckland Limited provides technical and advisory services to us on normal commercial terms. Roger Grundy, one of our directors, is also a director of Breckland Limited and he provides consulting services to us as an employee of Breckland. Amounts paid or payable to Breckland during the year ended December 31, 2006 amounted to $140,165 (2005 — $179,608).

Amounts due to directors for directors’ fees totaled $18,000 at December 31, 2006 (2005 — $30,500). In 2005 there were executive bonuses of $573,571 (2004 — $320,000); however these were paid in 2006.

Management Discussion and Analysis     INTEROIL CORPORATION     34

Share Capital

Our authorized share capital consists of an unlimited number of common shares with no par value. As of February 28 2007, we had 29,897,847 common shares outstanding and 34,575,761 common shares on a fully diluted basis.

Share Capital	Number of shares
Balance December 31, 2005	29,163,320
Shares issued on exercise of options		132,285
Shares issued on amendment of indirect participation interest (PNGDV)		575,575
Balance December 31, 2006		29,871,180
Shares issued on exercise of options		—
Shares issued on conversion of indirect participation interest		26,667
Balance February 28, 2007		29,897,847
Remaining stock options authorized		1,026,000
Remaining shares issuable upon exercise of warrants		340,247
Remaining conversion rights authorized(1)		3,306,667
Other		5,000
Balance February 28, 2007 Diluted		34,575,761

(1) In 2005, we sold indirect participation working interests in our exploration program. Some of the investors under our indirect participation interest agreement entered into in February 2005 have the right to convert, under certain circumstances, their interest to our common shares. If 100% of the investors under our indirect participation interest agreement choose to convert their interests, we would be required to issue an additional 3,306,667 common shares.

Derivative Instruments

Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks 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 are required to purchase crude feedstock two months forward, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Because of this timing difference, there is an impact on our cost of crude feedstocks 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 as a tool to reduce the risks of changes in the relative prices of our crude feedstocks 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 feedstocks contracts are 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 vis-à-vis our acquisition price of crude feedstocks expands or increase, 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 IPE and Nymex Exchanges. 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 crudes such as Tapis and Dubai. Using these

Management Discussion and Analysis     INTEROIL CORPORATION     35

tools, InterOil actively engages in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instrument such as Brent futures on the IPE Exchange to hedge our crude costs.

For a description of our current derivative contracts as of December 31, 2006, see Note 8 to our financial statements for the years ended December 31, 2006, 2005, and 2004.

InterOil recognized a net gain of $4.8 million from the use of derivative instruments during 2006. These movements were recorded as a $2.7 million decrease to sales, a $4.9 million decrease to cost of goods sold and a $2.6 million decrease to office and administrative and other expenses.

The fair value of financial instruments are determined by marking the open contracts to market, based on pricing information provided to us by BNP Paribas. As a December 31, 2006, there were no material contracts on which a gain or loss had been deferred. In 2005, there were $0.7 million of contracts on which a gain had been deferred. These contracts settled during 2006 and the actual gains and losses realized are included in the net income movement of $4.8 million described above.

We will continue with our hedging and risk management program in 2007 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 Canadian 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 3 of the notes to our consolidated financial statements for the year ended December 31, 2006, 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 or substantively 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 or substantive enactment. A valuation allowance is provided against any portion of a future tax asset which will more than likely not be recovered. 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, 2006 and 2005 were $1.4 million and $1.1 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

Management Discussion and Analysis     INTEROIL CORPORATION     36

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, 2006 and 2005 were $19.2 million and $1.3 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 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, 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 monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.

Management Discussion and Analysis     INTEROIL CORPORATION     37

NEW ACCOUNTING STANDARDS

Comprehensive Income, Financial Instruments and Hedges

In April 2005, the CICA released three new Handbook sections which deal with the recognition and measurement of financial instruments:

• Section 1530, Comprehensive Income;

• Section 3855, Financial Instruments — Recognition and Measurement; and

• Section 3865, Hedges.

The new standards are an attempt to harmonize Canadian GAAP with U.S. GAAP. Initial measurement of all financial instruments is to be based on their fair values. The subsequent measurement of the financial instrument will depend on whether it is classified as a loan or receivable; held to maturity investment; available for sale financial asset; held for trading asset or liability; or, other financial liability. Available for sale financial assets and held for trading assets or liabilities are measured at fair value on an ongoing basis. The other financial instruments are recognized at amortized cost using the effective interest method. The gains and losses on held for trading financial instruments are recognized immediately in net income. The gains and losses on available for sale financial assets will be recognized in other comprehensive income and are transferred to net income when the asset is derecognized.

Other comprehensive income is a new equity category where revenues, expenses, gains and losses are temporarily presented outside of net income but included in comprehensive income. Unrealized gains or losses on qualifying hedging instruments and available for sale financial assets are included in other comprehensive income and reclassified to net income when realized.

Hedge accounting continues to be an option and the new Handbook section provides detailed guidance on the application of hedge accounting and the required disclosures.

These new standards are effective for fiscal years beginning on or after October 1, 2006. We expect to adopt the pending accounting standards on January 1, 2007. The impact of this standard on our financial statements will be as follows:

Section 1530, Comprehensive Income:

The new standard would require InterOil to present comprehensive income and its components in a financial statement with the same prominence as other financial statements. Effective January 1, 2007, all quarterly and annual financial statements issued by InterOil would display a new statement — ‘Statement of Comprehensive Income’ which would reconcile the net income/loss for the period to the Comprehensive Income for the period.

Statement of Comprehensive Income
($ thousands)	Years ended December 31,
	2006			2005
	(restated)			(restated)			2004
Net Loss		(45,799	)		(62,070	)		(52,940	)
Foreign currency translation reserve, net of tax		1,015			14			463
Deferred hedge gain, net of tax		—			—			—
Other Comprehensive Income		1,015			14			463
Comprehensive Income		(44,783	)		(62,056	)		(52,477	)

Management Discussion and Analysis     INTEROIL CORPORATION     38

As per the transitional provisions of the standard, only the foreign currency translation reserve will be disclosed in the periods prior to 2007. In 2007, deferred hedge gain/losses will also be reported as a separate line item under other comprehensive income.

Section 3855, Financial Instruments — Recognition and Measurement:

InterOil will provide some additional disclosures relating to financial instruments as a result of this new standard and will also change its method for accounting for hedges described below.

Section 3865, Hedges:

This standard will require InterOil to reclassify the deferred hedge gains/(losses) line item from the liabilities section to shareholder’s equity as accumulated other comprehensive income. The new standard also requires that the portion of the hedge gain or loss that is effective be recognized in other comprehensive income while the ineffective portion of the gain or loss would be recognized immediately in net income. Currently, InterOil defers the full amount of the gain or loss. The standard will be prospectively applied from January 1, 2007 and in accordance with the transitional provisions the prior period comparatives will not be restated.

Management Discussion and Analysis     INTEROIL CORPORATION     39

NON-GAAP MEASURES RECONCILIATION

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

Quarters ended	2006 (restated)(1) ,(2)												2005 (restated)(1)
($ thousands) (unaudited)	Dec 31			Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Earnings before interest, taxes, depreciation and amortization		6,873			1,370			(10,323	)		(12,014	)		(19,668	)		(8,192	)		(5,375	)		(4,346	)
Upstream		(719	)		(1,107	)		(1,922	)		(5,136	)		(16,464	)		(13,333	)		(1,134	)		(91	)
Midstream — Refining and Marketing		9,144			1,674			(8,188	)		(5,230	)		(6,333	)		6,070			(6,796	)		(3,405	)
Midstream — Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		1,143			1,954			3,559			(326	)		3,963			2,522			2,550			584
Corporate & Consolidated		(2,299	)		(853	)		(3,770	)		(1,322	)		(834	)		(3,451	)		5			(1,434	)
Subtract:
Interest expense		5,649			5,349			3,609			2,666			2,989			2,455			2,996			2,547
Upstream		2			1			1			1			(6	)		2			2			2
Midstream — Refining and Marketing		2,479			3,329			2,731			2,342			2,756			2,320			2,735			2,351
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		37			38			39			38			44			42			140			—
Corporate & Consolidated		3,131			1,981			838			285			195			91			119			194
Income taxes & non-controlling interest		1,049			244			1,031			(245	)		910			1,000			301			253
Upstream		—			—			—			—			—			—			—			—
Midstream — Refining and Marketing		42			(46	)		(137	)		(118	)		(129	)		19			(333	)		81
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		996			416			1,005			(144	)		1,062			965			570			159
Corporate & Consolidated		11			(126	)		163			17			(23	)		16			64			13
Depreciation & amortization		3,554			3,100			2,862			2,837			2,700			2,943			2,699			2,695
Upstream		233			202			173			198			96			213			2			3
Midstream — Refining and Marketing		2,805			2,700			2,626			2,598			2,662			2,663			2,641			2,632
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		537			222			89			62			55			55			51			43
Corporate & Consolidated		(21	)		(24	)		(26	)		(21	)		(113	)		12			5			17
Net income (loss) per segment(1)		(3,379	)		(7,323	)		(17,825	)		(17,272	)		(26,267	)		(14,590	)		(11,371	)		(9,841	)
Upstream		(954	)		(1,310	)		(2,098	)		(5,335	)		(16,554	)		(13,548	)		(1,138	)		(96	)
Midstream — Refining and Marketing		3,818			(4,309	)		(13,408	)		(10,052	)		(11,622	)		1,068			(11,839	)		(8,469	)
Midstream — Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		(427	)		1,278			2,426			(282	)		2,802			1,460			1,789			382
Corporate & Consolidated		(5,420	)		(2,684	)		(4,745	)		(1,603	)		(893	)		(3,570	)		(183	)		(1,658	)

Management Discussion and Analysis     INTEROIL CORPORATION     40

(1)	Our comparative quarterly results for all quarters during 2005 and 2006 have been represented to conform with the presentation adopted at December 31, 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(2)	Our September 2006 quarterly results have been represented to separate out our Midstream-Liquefaction segment from the Midstream Refining and Marketing segment.

STATEMENT REGARDING DISCLOSURE CONTROLS

As of December 31, 2006, an evaluation was carried out, under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures as defined under Multilateral Instrument 52-109. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer identified control deficiencies in the Company’s internal controls over financial reporting as of December 31 2006. These control deficiencies, their potential effects on the financial statements, and the Company’s plans for remediation have been described in Management’s S404 Certification.

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our Annual Information Form, which is filed with the Canadian Securities Administrators at www.sedar.com, and our Form 40-F, which is filed with the U.S. Securities and Exchange Commission at www.sec.gov.

GLOSSARY OF TERMS

Barrel, Bbl (petroleum) Unit volume measurement used for petroleum and its products; 1 barrel = 42 US gallons, 35 Imperial gallons (approx.), or 159 liters (approx.); 7.3 barrels = 1 ton (approx.); 6.29 barrels = 1 cubic meter = 35.32 cubic feet.

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.

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.

Farmout 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 fulfilling contractually specified conditions. The farmout agreement often stipulates that the other party must drill a well to a certain depth, at a specified location, within a certain time frame; furthermore, the well typically must be completed as a commercial producer to earn an assignment. 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

Feedstock Raw material used in a processing plant.

GAAP Generally accepted accounting principles.

IPF InterOil Power Fuel. InterOil’s marketing name for low sulphur waxy residue oil.

Management Discussion and Analysis     INTEROIL CORPORATION     41

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.

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. Acceptable first reference abbreviation. LNG is moved in tankers, not via pipelines. LNG, which is predominantly methane, artificially liquefied, is not to be confused with NGLs, natural gas liquids, heavier fractions which occur naturally as liquids. See also natural gas.

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.

Mark-to-market To revalue futures/option positions using current market prices to determine profit/loss. The profit/loss can then be paid, collected or simply tracked daily.

Naphtha That portion of the distillate obtained in the refinement of petroleum which is intermediate between the lighter gasoline and the heavier benzene, and has a specific gravity of about 0.7, used as a solvent for varnishes, illuminant, etc.

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.

Natural gas measurements The following are some of the standard abbreviations used in natural gas measurement.

Mcf: standard abbreviation for 1,000 cubic feet.
Bil cu ft: Billion cubic feet. Also abbreviated to bcf.
Tcf: trillion cubic feet.

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.

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.

Management Discussion and Analysis     INTEROIL CORPORATION     42

EX-99.5

Exhibit 5

PricewaterhouseCoopers

ABN 52 780 433 757

Freshwater Place

2 Southbank Boulevard

SOUTHBANK VIC 3006

GPO Box 1331L

MELBOURNE VIC 3001

DX 77

Website:www.pwc.com/au

Telephone 61 3 8603 1000

Facsimile 61 3 8603 1999

www.pwc.com/au

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the use in this restated Annual Report on Form 40-F/A and the incorporation by reference in the Registration Statements on Form S-8 (No. 333-124167), Form F-10/A (No. 333-120383) and Form F-10/A (No. 333-124641) of InterOil Corporation of our report dated March 30, 2007 and October 29, 2007 relating to the consolidated balance sheet as of December 31, 2006 and the consolidated statements of operations, shareholders’ equity and cash flows for the year ended December 31, 2006, which are incorporated by reference to Exhibit 4 of the Restated Annual Report on Form 40-F/A dated October 29, 2007.

PricewaterhouseCoopers
Melbourne, Australia
October 29, 2007

Liability limited by a scheme approved under Professional Standards Legislation

EX-99.6

Exhibit 6

Consent of Independent Registered Public Accounting Firm

The Board of Directors
InterOil Corporation

We consent to the use of our report dated March 4, 2005 included in this annual report on Form 40-F/A, to be filed with the United States Securities and Exchange Commission pursuant to the Securities and Exchange Act of 1934, as amended, and as incorporated by reference in registration statements (No.333-120383 and No.333-124641) on Form F-10 and registration statement on Form S-8 (No.333-124617) of InterOil Corporation.

(signed) KPMG

Brisbane, Australia
October 29, 2007

EX-99.11

Exhibit 11

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 registrant’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)) 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)	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
(c)	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: October 29, 2007

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chief Executive Officer 

EX-99.12

Exhibit 12

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 registrant’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)) 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)	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
(c)	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: October 29, 2007

/s/ Collin F. Visaggio  

Collin F. Visaggio 

Chief Financial Officer 

EX-99.13

Exhibit 13

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, 2006 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 as of and for the periods presented in the Report.

Date: October 29, 2007

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chief Executive Officer 

EX-99.14

Exhibit 14

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, 2005 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 as of and for the periods presented in the Report.

Date: October 29, 2007

/s/ Collin F. Visaggio  

Collin F. Visaggio 

Chief Financial Officer