40-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 40-F

(Check One)

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

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, 2004 Commission File Number: 001-32179

InterOil Corporation

(Exact Name of Registrant as Specified in Its Charter)

New Brunswick, Canada
(Province or Other Jurisdiction of Incorporation or Organization)

1311
(Primary Standard Industrial Classification Code)

Not Applicable
(I.R.S. Employer Identification Number)

Suite 5300, Commerce Court West, 199 Bay St.
Toronto, Ontario M5L 1B9, Canada
(416) 869-5500
(Address and Telephone Number of Registrant’s Principal Executive Offices)

Gary M. Duvall
25025 I-45 North, Suite 420
The Woodlands, Texas 77380
(281) 292-1800
(281) 292-0888 (facsimile)
Name, Address (Including Zip Code), and Telephone Number
(Including Area Code) of Agent for Service in the United States)

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

      Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

      As of December 31, 2004, 28,310,884 common shares were outstanding.

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

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

PRINCIPAL DOCUMENTS

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

A. Annual Information Form

The 2004 annual information form for InterOil Corporation (the “Company”) is included herein by reference.

B. Audited Annual Financial Statements

The audited consolidated financial statements, including the report of the auditors with respect thereto are included herein by reference. For a reconciliation of important differences between Canadian and United States generally accepted accounting principles, see Note 24 of the Notes to the audited consolidated financial statements incorporated herein by reference.

C. Management’s Discussion and Analysis

The Company’s management discussion and analysis of financial conditions and results of operations is included herein by reference.

CONTROLS AND PROCEDURES

Please see the section titled “Evaluation of Disclosure Controls and Procedures” in the Company’s Management’s Discussion and Analysis, which is included herein by reference.

AUDIT COMMITTEE

The audit committee does not include a ‘financial expert’ as defined by SEC Rules. As a foreign private issuer we are not subject to the SEC and the AMEX audit committee rules until July 31, 2005. We are in the process of ensuring that our audit committee satisfies these requirements. As part of the assessment of our audit committee, we will evaluate whether to designate a member of our audit committee as a financial expert. We believe that all of the members of our audit committee possess the financial expertise necessary for the audit committee to properly fulfill its purpose.

CODE OF ETHICS

We have adopted a Code of Business Conduct. All of our employees, directors and officers must follow our Code of Business Conduct, which provides guidelines for ethical behavior. This Code of Business Conduct includes additional guidelines for our financial officers, including the Chief Executive Officer, Chief Financial Officer and other senior financial officers. The Code of Business Conduct is accessible on our website at www.interoil.com. We will also provide to any person, without charge, upon request, a copy of the Code of Business Conduct. Requests must be made in writing to the Company Secretary of InterOil Corporation at Suite 2, Level 2, Orchid Plaza, 79 Abbott Street, PO Box 6567, Cairns, QLD 4870, Australia.

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 and review of the quarterly consolidated financial statements for the year ended December 31, 2003 by KPMG were $89,668. For the year ended December 31, 2004, fees paid and payable for professional services rendered by KPMG for the annual audit and quarterly reviews were $324,337, 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, 2003 by KPMG were $14,836. For the year ended December 31, 2004, fees paid and payable for professional services rendered by KPMG for audit-related fees were $197,182, including out-of-pocket expenses.

Tax Fees. Fees paid for professional services rendered related to tax services for the Company for the year ended December 31, 2003 by KPMG were $39,088. For the year ended December 31, 2004, fees paid and payable for professional services rendered by KPMG for tax fees were $28,234, including out-of-pocket expenses.

All Other Fees. Fees paid for professional services rendered related to all other services for the Company for the year ended December 31, 2003 by KPMG were $21,390. For the year ended December 31, 2004, fees paid and payable for professional services rendered by KPMG for all other fees were $129,772, including out-of-pocket expenses.

All of the services provided by the Company’s independent auditors during 2003 and 2004 were pre-approved by the audit committee.

OFF BALANCE SHEET ARRANGEMENTS

Please see the section titled “Off Balance Sheet Arrangements” in the Company’s Management’s Discussion and Analysis, which is included herein by reference.

CONTRACTUAL OBLIGATIONS

Please see the section titled “Contractual Obligations and Commitments” in the Company’s Management’s Discussion and Analysis, which is included 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 shares of common stock. 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 Registrant 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 to transactions in said securities.

CONSENT TO SERVICE PROCESS

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

SIGNATURES

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

INTEROIL CORPORATION
 

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chairman of the Board, Chief Executive Officer and President 

Date: March 31, 2005

EXHIBIT INDEX

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

EXHIBIT
NUMBER		DESCRIPTION
	1.	Annual Information Form for the year ended December 31, 2004
	2.	Audited annual consolidated financial statements for the year ended December 31, 2004, including a reconciliation to United States generally accepted accounting principles
	3.	Management’s Discussion and Analysis for the year ended December 31, 2004
	4.	Consent of KPMG dated March 31, 2005
	5.	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
	6.	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
	7.	Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code
	8.	Certification of Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code

EX-99.1

InterOil Corporation 2004

Annual Information Form

March 31, 2005

Corporate Structure	2
General Development of Our Business	4
Description of Our Business	5
Overview	5
Exploration and Production	6
Refining and Marketing	6
Wholesale and Retail Distribution	8
Exploration and Production Operations	9
Exploration Background	9
History	9
Exploration Results	10
2004 Exploration Activities	10
Geophysical Operations	11
Oil and Gas Wells	11
Properties with No Attributed Reserves	11
Costs Incurred	12
Exploration and Development Activities	12
Operated Permit Details	12
Social and Environmental Policy	13
Risk Factors	14
Dividends	20
Description of Capital Structure	20
Market for Securities	21
Management’s Discussion and Analysis	22
Directors and Officers	22
Board Committees	25
Audit Committee	25
Compensation Committee	26
HSE Committee	26
Disclosures	26
Shareholdings of Directors	26
Interests of Officers and Directors in Our Affairs	27
Cease Trade Orders, Bankruptcies, Penalties or Sanctions	27
Penalties or Sanctions	27
Legal Proceedings	27
Material Contracts	27
Transfer Agents and Registrars	31
Forward-looking Statements	31
Additional Information	32
Glossary of Terms	33

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Annual Information Form
March 31, 2005

All dollar amounts are stated in United States dollars unless otherwise stated.

Corporate Structure

Our corporate structure includes three business segments under the public company, InterOil Corporation: Exploration and Production; Refining and Marketing; and Wholesale and Retail Distribution. Our Exploration and Production segment is under SPI Exploration and Production Corporation. Our Refining and Marketing segment comprises the subsidiaries, SP InterOil, LDC (“SPI”), E.P. InterOil, Ltd (“EPI”) and InterOil Limited (“IOL”). Our Wholesale and Retail Distribution segment comprises SPI Distribution Limited (“SPI Distribution”) and InterOil Products Limited (“IPL”). All of our companies and subsidiaries have integrated, shared management. In this Annual Information Form references to “we”, “us”, “our” and “InterOil” refer to InterOil Corporation and its subsidiaries.

Our authorized share capital consists of an unlimited number of common shares with no par value. As of December 31, 2004 we had 28,310,884 common shares outstanding with 30,367,689 common shares outstanding on a diluted basis at March 16, 2005.

Share Capital	Number of shares
Balance, January 1, 2002		20,186,870
Shares issued for cash		399,073
Balance, December 31, 2002		20,585,943
Shares issued for cash		3,817,500
Shares issued for debt		31,240
Shares issued on exercise of options		381,278
Balance, December 31, 2003		24,815,961
Shares issued for debt		3,184,828
Shares issued on exercise of options		310,095
Balance, December 31, 2004		28,310,884
Shares issued on exercise of options (Jan-Mar 15, 2005)		162,709
Shares issued on exercise of warrants (Jan-Mar 15 2005)		19,168
Balance, March 16, 2005		28,492,761
Remaining stock options authorized		1,529,681
Remaining warrants issued		340,247
Other		5,000
Diluted March 16, 2005 (1)		30,367,689

Notes:

(1)   In 2003 and 2005, we sold indirect working participation interest in our exploration program. Investors have the right to convert, under certain circumstances, their interest to our common shares. If 100% of the investors choose to convert their interest, we would be required to issue an additional 3,961,639 common shares.

We were formed under the Business Corporations Act (New Brunswick) by articles of amalgamation dated May 29, 1997 upon the amalgamation of Cybermind Group Inc. and South Pacific InterOil Limited. Our registered office is located at Brunswick House, 10th Floor, 44 Chipman Hill, Saint John, NB E2L 4S6 and our main operating office is located at Suite 2, Level 2, Orchid Plaza, 79 Abbott Street, Cairns, QLD 4870, Australia.

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Unless otherwise noted, all of our subsidiaries are directly or indirectly 100% owned.

SPI InterOil, LDC (“SPI”)

      SPI was incorporated under the International Business Companies Act, 1989, of the Commonwealth of the Bahamas on November 22. The registered office of SPI is located in Nassau, the Bahamas. SPI was formed under the laws of the Bahamas to facilitate investment and to maximize the tax advantages available to its investors. The General Manager of SPI is Petroleum Independent and Exploration Corporation (“P.I.E.”), a privately held company registered in Texas, USA and incorporated in 1981. This structure allowed InterOil to meet US content requirements for the project financing of the refinery provided by the Overseas Private Investment Corporation, an agency of the US Government.

      During the development of InterOil, SPI negotiated the purchase of the refinery assets, which included a modular crude unit, a reformer and two ocean-going American-flagged steel deck barges. After acquiring the equipment, SPI directed the dismantling, loading and transportation of the equipment to the Texas Gulf coast.

      We have entered into an agreement with PIE Corp. to exchange on a one-for-one basis shares in SPI for fully paid shares in InterOil. This election may be made by PIE Corp at any time. There are 5,000 shares in this category. These shares provided the US content for the $85,000,000 in approved financing.

EP InterOil, Ltd. (“EPI”)

      EPI was incorporated under the Companies Law of the Cayman Islands in 1996 and was the vehicle established to form a joint venture with Enron PNG Limited (“EPNG”), a 100%-owned subsidiary of Enron. Its registered office is located in Grand Cayman. SPI controls EPI, with 100% of the voting stock, as the joint venture has terminated and EPNG has elected to take a passive role by only holding non-voting stock.

      EPI sponsored its wholly owned subsidiary, IOL, when IOL entered into the lump-sum, turn-key, engineering, procurement and construction contract (the “EPC Contract”) with Clough Niugini Limited, to build the refinery. EPI has also negotiated the purchase and refurbishment of the principal supplied equipment that will be used at the refinery and has commissioned the work to prepare the equipment movement and installation at the refinery site.

      EPNG, holds 897,542 participating non-voting shares in EPI, but has decided that the refinery is not consistent with its corporate objectives. EPNG’s interest is anticipated to be diluted on an ongoing basis as InterOil contributes more equity. As at December 31, 2004, EPNG’s interest had been diluted to 1.26%.

InterOil Limited (“IOL”)

      InterOil Limited was incorporated under the Companies Act (Chapter 146) in Papua New Guinea in 1994 to construct, own and operate the refinery. Its registered office is in Port Moresby, Papua New Guinea. InterOil Limited has played a very active role in working with the Papua New Guinea government to obtain the permits authorizations and certificates required under the Refinery State Project Agreement and has also obtained a 99-year lease over the refinery site. InterOil Limited has received “Pioneer status” in Papua New Guinea, which grants a five-year income tax holiday to InterOil Limited.

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      InterOil Limited entered into the EPC Contract with Clough Niugini Limited in March 2002 and the Facilities Management Contract with Petrofac Niugini Limited in November 2003.

SPI Exploration and Production Corporation (“SPI E&P”)

      SPI E&P was incorporated under the International Business Companies Act, 1989, of the Commonwealth of the Bahamas in 1998. The registered office of SPI E&P is located in Nassau, the Bahamas. SPI E&P was formed under the laws of the Bahamas to facilitate investment in exploration for, and the development and production of, oil and gas resources and to maximize the tax advantages available to its investors.

      SPI E&P wholly owns the specific purpose exploration companies holding and operating exploration rights in Papua New Guinea.

SPI Distribution Limited (“SPI Distribution”)

      SPI Distribution was incorporated under the International Business Companies Act, 1989, of the Commonwealth of the Bahamas in 2001. The registered office of SPI Distribution is located in Nassau, the Bahamas. SPI Distribution was formed under the laws of the Bahamas to facilitate investment in the distribution of refined products in Papua New Guinea and to maximize the tax advantages available to its investors.

      SPI Distribution will hold all of InterOil’s product distribution assets in Papua New Guinea and has acquired InterOil Products Limited (formerly BP Papua New Guinea Limited) to initiate this purpose.

InterOil Products Limited (“IPL”)

      IPL was incorporated under the Companies Act (Chapter 146) in Papua New Guinea and was formed in October 1969 as BP Papua New Guinea Limited. IPL changed its name in April 2004 after its acquisition by SPI Distribution. The registered office of IPL is in Lae, Morobe Province, Papua New Guinea. IPL owns and operates a petroleum products distribution, wholesale and retail business in Papua New Guinea and has approximately 20% of the wholesale product market in Papua New Guinea based on total volume of sales for such products, in competition with Shell, ExxonMobil and Niugini Oil Company.

General Development of Our Business

Four Year History

Over the past four years, we (or a subsidiary) have:

Corporate Activities

•   Our common shares commenced trading on the Toronto Stock Exchange in July and the American Stock Exchange in September;

•   We obtained a $100 million working capital facility with BNP Paribas; and

•   We raised $45 million through a convertible debenture offering that was fully converted to common shares.

Exploration and Production Activities

•   We established a strong exploration position by obtaining approximately eight million exploration acres in 3 key exploration licenses in Papua New Guinea;

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•   In 2003 we raised US$64.6 million through 3 private placements and sold indirect interest participation in our drilling program for US$19.8 million; and

•   We Initiated a multi-well exploration program on separate, independent structures.

Refining and Marketing Activities

•   We obtained a 99-year lease from the Papua New Guinea Government on suitable land with deep water access to construct our refinery;

•   We were granted a Petroleum Processing Facility License (“PPFL No 1”) under the Oil and Gas Act 1998 (Papua New Guinea) to operate our refinery;

•   We signed a 30-year Project Agreement with the Papua New Guinea Government, which confers certain tax and market privileges to our refinery business;

•   We reached an agreement with Shell for the purchase and marketing of the majority of the export capacity of our refinery;

•   We executed a contract with BP Singapore Pte Limited, whereby BP will act as the crude oil supplier to our refinery;

•   We obtained a US$85 million loan from the Overseas Private Investment Corporation (OPIC), an agency of the US Government, to finance our refinery;

•   We built a 32,500 bpd name-plate refinery in Papua New Guinea;

•   We achieved Mechanical Completion in 2004 at our refinery and initiated commissioning activities; and

•   Refined product quality was evidenced through the commissioning process with the sale of product from our refinery commencing in August 2004.

Wholesale and Retail Distribution Activities

•   We acquired BP’s Papua New Guinea subsidiary, BP Papua New Guinea Limited, including all its petroleum distribution assets and operations in Papua New Guinea.

Subsequent to year-end 2004, we completed the commissioning activities with performance and reliability tests completed in January 2005 followed by announcing practical completion of our refinery. In February 2005, we obtained $125 million in funding for our exploration program.

Description of Our Business

Overview

Our goal continues to be the development of a vertically-integrated energy company whose focus is Papua New Guinea and the surrounding region. Our strategy is to continue oil and gas exploration in Papua New Guinea, operation and marketing of refined product from our oil refinery, and the wholesale and retail distribution of refined petroleum products in Papua New Guinea. Our most significant activity in this regard, during 2004, was related to our acquisition of BP Papua New Guinea Limited on April, 28, 2004. This acquisition commenced our direct participation in the Papua New Guinea refined product distribution business.

Our operations are organized into three major business segments:

•   Exploration and Production, our upstream segment, which includes the exploration for and the future production of crude oil and/or natural gas;

•   Refining and Marketing, our midstream segment, which includes the refining of crude oil and the marketing of refined products both domestically and for export; and

•   Wholesales and Retail Distribution, our downstream segment, which includes wholesale and retail distribution of refined products in Papua New Guinea.

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Exploration and Production

We have an extensive upstream portfolio consisting of approximately 8 million acres of exploration licenses. The vast majority of our licenses are located onshore in the Eastern Papuan Basin, and we believe our licenses have the logistical advantage of moderate terrain, barge access to infrastructure and proximity to our refinery. We believe that this advantage will permit lower cost of development, earlier production, and better access to a local market for oil production in contrast to past oil production activities in Papua New Guinea.

Following positive fiscal policy announcements by the Government of Papua New Guinea in December 2002, we announced a commitment to an eight well drilling program. On March 28, 2003, the program commenced with the spudding of the first prospect, Moose, located in the area governed by Petroleum Prospecting License 238 (“PPL 238”) in the Eastern Papuan Basin in Papua New Guinea. Testing of the well was inconclusive due to fluid invasion of the reservoir whilst drilling. PPL 238 is further described below.

On December 9, 2003 InterOil spudded its second exploration well on the Moose Structure. On January 6, 2004 InterOil spudded its first exploration well, the Sterling Mustang — 1, on its second structure, Sterling Mustang.

Refining and Marketing

Papua New Guinea Refinery

Our refinery is our primary asset. The refinery is centrally located across the harbor from Port Moresby, the capital city of Papua New Guinea, and is 15 miles (24 kilometers) by road and 2.5 miles (4 kilometers) by water from Port Moresby.

Our refinery consists of a nameplate 32,500 barrel per stream day crude distillation unit, a 3,500 barrel per stream day hydro-desulphurization unit, a 3,500 barrel per stream day catalytic reforming unit, a two jetties with ship loading and off-loading facilities and a road tanker loading system. Our tank farm has an overall storage capacity approaching 1.9 million barrels. We are also self sufficient with a reverse osmosis desalination unit for water, steam and power generation for electricity, and other site infrastructure and support facilities including laboratory, workshops, an administration building, waste water treatment plant, staff accommodation and a fire station. Our refinery is operated from a central computerized control center.

Our refinery complies with the World Bank’s recommended environmental standards. The design configuration takes advantage of regionally available light sweet crude, which is low in sulphur content (such as the Kutubu blend crude that is produced in Papua New Guinea). We anticipate maximizing the production of higher premium products, such as diesel, which is in short supply in the region.

Designing the refinery for sweet crude feedstock resulted in fewer environmental costs and also avoided the need for hydro-treating or complex and expensive heavy oil processing operations at our refinery such as catalytic cracking and coking.

Papua New Guinea is the primary market for our refinery, with diesel and jet/kerosene yield together accounting for almost 50 percent of the expected refinery output. The nature of the crude oil being processed, light sweet crude, will result in the production of an excess of naphtha, which we expect to export to the rapidly growing Asian markets in two grades, one for petrochemical feedstock and the other for ethylene production. The shipping of two grades instead of one is expected to command a price premium as it avoids the more expensive ‘splitting’ process that

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would otherwise be required. In addition, the refinery has the flexibility to either make more gasoline, up to 15 percent of output, or sell naphtha as chemical feedstock. We can adjust the split between gasoline and naphtha as market forces from time to time dictate. Other refinery products include propane, butane, and low sulphur waxy residue (~0.12wt%S), which can be sold as fuel and is valued by more-complex refineries as cracker feedstock,

The marine and storage facilities reflect our refinery’s strategic position as both a local and regional supplier and include a large jetty, which 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. A second, smaller wharf can accommodate ships up to 18,000 dwt. Our refinery has a total storage capacity of 1.9 million barrels (300 million liters) including crude storage of 750,000 barrels (120 million liters).

The third and fourth quarters of 2004 were a major challenge for us as we transformed our refinery through the commissioning process, from a construction project to an operational industrial facility in January 2005. Various components of the refinery were progressively put into service. On July 1, 2004, oil was first processed at the refinery. This processing was followed through the commissioning process by the production and sale of refined product. Although the commissioning process was gradual and extended over several months, no major obstacles were encountered, and by year-end 2004 the refinery had processed over 3.3 million barrels of crude, achieved stable operations on all its process units and utility systems, and had operated at throughputs averaging over 30,000 barrels a day during the months of November and December, 2004. During December 2004 our refinery successfully completed its performance test run, operating at the name-plate capacity of 32,500 barrels per day and meeting yield structures and energy utilization as per design. It also proved its flexibility to process crude other than Kutubu blend. On January 31, 2005, our refinery achieved practical completion. Practical completion means construction of the refinery has been completed and that the refinery has satisfactorily completed the reliability and performance tests which were conducted as part of the acceptance and handover process.

Hydrocarbon management and product quality assurance procedures have been progressively established. With the start-up of the catalytic reformer unit in late November, 2004 and the subsequent blending and sale of motor gasoline in December, 2004, the full range of refined products has been successfully manufactured and sold into both the domestic and international markets.

Petrofac Facilities Management Limited, a leading facilities management company commenced site operations in November 2003 and has mobilized all key positions including operators. Following practical completion, Petrofac is responsible for the day-to-day operation and maintenance of our refinery.

Our refinery’s on-site laboratory is staffed and operated by an independent company, SGS, a global leader in the verification, testing and certification industry. The SGS laboratory is presently undergoing Australian NATA (National Association of Testing Authorities) accreditation, and all crude imports and finished products are tested and certified on-site to contractual specifications.

Crude Supply

On December 31, 2001, we entered into an agreement with BP Singapore (the trading arm of BP International) for the supply of crude to our refinery. This agreement is expected to ensure a reliable source of feedstock for refinery operations. This agreement terminates in June 2009. However, either party may terminate this agreement earlier by providing the other party 30 days notice. In May 2004 the first crude oil cargo was sourced by BP for our refinery. For this initial cargo of crude, BP chartered a 115,000 dwt capacity crude carrier for transportation of the crude

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from the Kumul Marine Terminal in the Gulf of Papua to the refinery. First crude discharge operations proceeded to plan without incident. An additional nine crude cargoes were purchased in 2004. Our refinery has processed both local and imported crude and will continue to review alternative light ‘sweet’ crudes that may provide improved margins for our refinery product slate.

Marketing

Papua New Guinea remains our principal market for all products except naphtha and low sulphur waxy residue. Under our 30 year agreement with the Government of Papua New Guinea, the Government undertakes 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 the Import Parity Price (“IPP”). As a result, Papua New Guinea will no longer have to rely solely on imports to meet its refined product needs. In general, the IPP is the price that would be paid in Papua New Guinea for a refined product that is being imported. For each refined product produced, the IPP is calculated by adding the cost that would typically be incurred to import such product to the PLATT’s posted price for such product in Singapore. The costs that are included in this calculation include freight cost, insurance cost, landing charges, losses incurred in the transportation of refined products, demurrage and taxes. The IPP was implemented in September 2004 by the Papua New Guinea Independent Consumer and Competition Commission for purchases of refined products from our refinery.

The first sales of diesel into the Papua New Guinea domestic market occurred in August 2004. As our refinery demonstrated its reliability during the commissioning of the refinery, there was a progressive and managed move by domestic distributors to lift their product demand from our refinery. The commissioning of the catalytic reformer and the blending of gasoline in December 2004 was an important step in completing the full range of products available from the refinery.

The full ranges of products are gasoline, diesel, jet/kerosene, naphtha, propane, butane and low sulphur waxy residue. Gasoline, diesel and jet/kerosene that was surplus to domestic sales has been exported by Shell International to the nearby North Australian markets. Our refinery is fully certified to manufacture and market Jet A1 fuel to international specifications and has already supplied product to both domestic and overseas airlines. We have also loaded several LPG vessels for domestic and export markets.

The major export product from our refinery is naphtha, which is sold to a unit of Shell on a term basis. As December 31, 2004 there have been four export cargoes of naphtha, of approximately 30,000 metric tons each. The production rate for naphtha at the refinery is variable and depends on the relative economics for gasoline and naphtha and the subsequent reformer run rate.

Wholesale and Retail Distribution

InterOil’s retail and wholesale distribution business encompasses the bulk storage, transportation, distribution, wholesaling and retailing of refined petroleum products in Papua New Guinea. This business includes distribution assets and commercial retail operations, consisting of 40 service stations and 10 terminals and depots operating under the InterOil retail brand, InterOil Products Limited (“IPL”). IPL has 175 employees and its head office is located in the industrial city of Lae, Papua New Guinea.

We completed the acquisition of IPL in the second quarter of 2004. Under the agreement, we paid BP $12.5 million, which included $6.8 million for inventory. The final payments for this acquisition were made in March 2005. Through our national network of we now deliver approximately 20 percent of Papua New Guinea’s refined petroleum product needs.

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Our near-term focus for our distribution business is to continue managing the transition from BP to InterOil. We believe that the fundamentals are sound and have enabled the business to pursue successful integration of the operations under the InterOil branded name. Several key milestones achieved during the year include:

•   We successfully launched the new InterOil retail brand and commenced a national re-branding rollout program from BP to InterOil.

•   We launched a national advertising, marketing and promotional campaign, targeted to support the re-branding rollout and promote customer awareness of the new InterOil retail brand.

•   Refined products have been lifted from our refinery to supply the Papua New Guinea market.

The achievements in the retail and wholesale distribution business over the past 12 months have strengthened our core business activities. This business unit’s management team is focused on improving operational excellence, continued tight cost management and increased profitability for the business over the coming year.

Proposed Lease-Back of Asset

In 2001, we agreed to purchase all of Shell’s retail and distribution assets in Papua New Guinea. This transaction is pending the resolution of outstanding issues with Shell and receipt of final Papua New Guinea regulatory and statutory approvals. We expect the transaction to close in 2005. The Shell portfolio is a distribution network of 70 outlets that includes terminals, depots, retail service stations and commercial refueling facilities. We will lease the retail and distribution assets back to Shell, who will continue to operate the business and have responsibility for daily operations.

Exploration and Production Operations

We have no reserves as defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). All information contained herein regarding resources are references to “undiscovered resources” under NI 51-101, whether stated or not. We have filed a Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information and Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure on SEDAR, each of which are incorporated by reference herein.

Exploration Background

In January 2002, based on the presence of hydrocarbons in Pale Sandstone cores from two stratigraphic wells, we announced that we believed we had discovered a new oil system in the Eastern Papuan Basin of Papua New Guinea. This confirmed to us that the Eastern Papuan Basin was now prospective for oil, and given the characteristics of the Pale Sandstone, had the potential for large oilfields comparable to the Kutubu oilfield located in the Papua New Guinea Fold Belt.

Analysis has been carried out which indicates that the reservoir quality of the Pale Sandstone is good, and that the oil samples are from at least two separate sources.

History

Since the discovery of oil in the Toro Sandstone in the Kutubu field, companies have focused their exploration activity on the Toro Sandstone fairway in the Fold Belt in Western Papua New Guinea. Their reasoning was that in this area there was a perceived increase in the probability for future

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discoveries as well as the development of the required infrastructure necessary to develop the oil wells.

Since 1911, the Eastern Papuan Basin, where most of InterOil’s exploration acreage is located, has been intermittently explored, with the last well drilled by Petro-Canada in 1991. The Pale Sandstone was discovered in an outcrop in 1987 by a geological field survey conducted by Petro-Canada. The nature of the sandstone, its extent and reservoir quality were unknown until we drilled in the region.

When we began to look for exploration opportunities in 1998, the Eastern Papuan Basin was open acreage except for an area around the Puri – 1 oil discovery. We considered the area to have strong petroleum potential as indicated by numerous oil and gas surface seeps; the Pale Sandstone outcrop found during the 1987 geological field survey; and oil tested at the Puri – 1 well.

Exploration Results

In August 2001, we drilled two stratigraphic wells, Subu – 1 and Subu – 2 in the area now covered by PPL 238, coring over 1,600 feet (488 meters). This core indicated 1,230 feet (375 meters) of good reservoir quality in the Pale Sandstone. Our geological survey found a second exposure of Pale Sandstone that extended the known width of the Pale Sandstone fairway to more than 37 miles (60 kilometers). We believe that the estimated true stratigraphic thickness of both of the Pale and Subu Sandstones is 877 feet (266 meters) at Subu-1 and Subu-2. Hydrocarbon residues were present throughout the coring of the sandstones and preliminary analyses suggested that these hydrocarbons were biodegraded oils.

Detailed geochemistry subsequently confirmed three separate oil families derived from separate source rocks. The first of these is the Family A oils; which are similar to Kutubu oil, sourced from a Jurassic-age rock, and the second is the Family B oils, which are derived from a marine calcareous source believed to be Palaeogene or Late Cretaceous in age. The third oil family is from an immature to marginally mature “coaly” source, which may be mature in deeper parts of the kitchens.

The Moose – 1 and – 2 wells were drilled in 2003. Cores from these wells encountered oil shows over the following intervals:

•   Moose – 1 over a drilled interval of 456 feet (139 meters) between 2,202 – 2,658 feet (671 – 810 meters); and

•   Moose – 2 over a drilled interval of 906 feet (276 meters) between 1,683 – 2,589 feet (513 – 789 meters).

Geochemical analysis has established the oil shows at Moose – 1 and Moose – 2 are mixed Family A and Family B oils.

2004 Exploration Activities

We spudded our second exploration well on the Moose structure, Moose – 2 in late 2003. Results from this well confirmed the oil shows and fractured limestone reservoir we identified in Moose – 1, which we believe demonstrates the lateral extent of the potential resource. Moose – 2 is located 2.5 miles (4 kilometers) to the southeast of Moose – 1. Difficult drilling conditions resulted in the primary target sandstones not being penetrated. The palynological dating indicates that the shales are equivalent in age to the Pale Sandstone. Since this shale unit was not completely penetrated the presence or absence of the Pale Sandstone remains conjectural and the presence of the Subu Sandstone untested. After a review of results it was decided that our next step in appraising the

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structure was to acquire 2D seismic data. In September 2004, we completed a seismic program across the Moose and adjacent structures as a further step in the full appraisal of the prospect and to delineate the primary target sandstones.

We spudded our third exploration well and the first on the Sterling Mustang structure in January 2004. This well was drilled to 9,704 feet (2,958 meters) but did not encounter the planned targets. A seismic program is planned over this prospect for 2005.

Geophysical Operations

We completed the Hadina and Orloli seismic data acquisition surveys, a total of 24 miles (38 kilometers) of 2D seismic, in January 2004. This included the 18 mile (29 kilometer) long Hadina Line in PPL 238 and the 6 mile (9 kilometer) long Orloli line in PPL 237. We integrated the results of these surveys with the data from surface mapping and our recent drilling activities. The surveys were cost effective at approximately US$62,000 per mile.

As a result of the success of the Hadina and Orloli programs, we completed an additional 13 mile (21 kilometer) survey line across the Puri, Elk, and Moose Prospects in September 2004. The program was completed at a cost of approximately US$50,000 per mile. The results of early processing were received in late 2004 and have confirmed the presence of the Elk Prospect. The data over the Moose Prospect were not as conclusive and further processing is being undertaken to improve data quality.

The seismic has defined the Elk Prospect as a shallow fractured limestone play similar to the Puri Anticline. Following the occurrence of oil shows in Moose – 1 (through a 456 foot interval) and Moose – 2 (through a 906 foot interval) we believe the Elk Prospect is promising. An airborne gravity and magnetics program similar to that flown in PPL 236 will be flown in areas surrounding the Puri, Elk and Moose Prospects in early 2005.

Based on the technical and operational success of our 2004 seismic programs, we are planning a seismic acquisition program in 2005. This acquisition program will be undertaken within both PPL 238 and PPL 237, and the primary focus will be maturing the Pale and Subu Sandstone leads and prospects with some lines also focusing on fractured carbonate prospects.

Oil and Gas Wells

The following table sets out the number and status of wells in which we have a working interest as at December 31, 2004.

Oil Wells

Gas / Condensate Wells

Working Interest

Producing

Non-Producing

Producing

Non-Producing

Location

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Papua New Guinea

0

0

4

4

0

0

0.6

0.6

Properties with No Attributed Reserves

The following table sets out our undeveloped land holdings as at December 31, 2004.

Undeveloped Acres
Location	Gross		Net
Papua New Guinea		7,978,186		7,758,776
Total		7,978,186		7,758,776

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Each Petroleum Prospecting Licence in Papua New Guinea requires a bond backed by a bank guarantee of K100,000 (US$31,500) and annual work and expenditure commitments as set by the Minister for Petroleum and Energy under the license conditions.

Costs Incurred

The following table summarizes the capital expenditure related to our exploration activities for the year ended December 31, 2004:

Property Acquisition Cost	$
Proved Properties	Nil
Undeveloped Properties	Nil
Exploration Costs	$	19,154,106
Development Costs	Nil
Total	$	19,154,106

Exploration and Development Activities

The following table sets out the gross and net exploration and development wells in which we participated during 2004:

Undeveloped Acres
Type	Gross		Net
Oil		0		0
Gas		0		0
Gas / Condensate		0		0
Service		0		0
Dry		1		1
Total		1		1

Operated Permit Details

In 2003, an increased understanding of the geology in the region led us to apply for a larger area than covered by our previous licenses. The resulting PPL’s (236, 237, and 238) cover over eight million acres.

Petroleum Prospecting License (“PPL”) 236

InterOil has 100% Ownership (subject to indirect participation interests) and is the Operator of the license.

PPL 236 was granted to us on March 28, 2003. This license covers an area that includes our refinery, with road access to the prospective locations. The proximity of PPL 236 to Port Moresby means that it may be economical for even a modest gas discovery to build a pipeline to the Port Moresby area, including to our refinery and other potential end-users such as electrical power generation facilities. We believe that even a small oil discovery this close to our refinery would be economically viable, with low development, operating and transport costs. Our first exploration well in this license, Black Bass – 1, is planned to be drilled in the first half of 2005.

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Petroleum Prospecting License (“PPL”) 237

InterOil has 100% Ownership (subject to indirect participation interests) and is the Operator of the license.

PPL 237 was granted to us on March 28, 2003. We believe that PPL 237 may contain hydrocarbons that have migrated out of the adjacent Omati and Aure Trough areas. This license contains the gas discovery well Bwata – 1 and the Puri – 1 oil discovery well. Limited exploration activity has been undertaken in this area for more than 20 years. We anticipate applying modern technologies to appraise the area. The relatively flat nature of the terrain means that low altitude airborne geophysical exploration methods such as gravity and magnetic surveys may be utilized. If successful at discovering commercial hydrocarbons, oil could be barged to our refinery on one of the several navigable rivers which connect PPL 237 to the Gulf of Papua.

Petroleum Prospecting License (“PPL”) 238

InterOil has 100% Ownership (subject to indirect participation interests) and is the Operator of the license.

PPL 238 was granted to us on March 7, 2003. We identified the potential in this area through field surveys and stratigraphic wells that we believe indicate a new oil system in the Pale/Subu Sandstones. Our first three exploration wells, Moose – 1 and 2 and Sterling Mustang – 1, are located within this license. There are numerous oil and gas seeps in the area; identified hydrocarbon shows in our Subu – 1 and Subu – 2 stratigraphic wells, and oil shows through the limestone sections in our Moose – 1 and Moose – 2 exploration wells.

Indirect Participation Agreement

In February 2005, we sold a 25% indirect participation interest in the next eight exploration wells we are going to drill in PPL 236, 237, or 238 for $125 million. Six of these wells will be drilled on locations selected by us, and two will be recommended by us and subject to approval by a majority of the investors in the indirect participation agreement. If the exploration wells discover oil or gas, the investors have the right to participate pro-rata in the development of the fields discovered. Each investor may convert its indirect participation into our common shares at any time after June 15, 2006 and before the later of December 15, 2006 and 90 days after completion of the eighth well, at a conversion price of $37.50 per common share.

Social and Environmental Policy

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

•   Providing a safe and healthy working environment for all employees and contractors;

•   Establishing community development assistance programs to enhance and improve the standard of health and education;

•   Establishing emergency response procedures that allow personnel to respond promptly and effectively; and

•   Maintaining procedures designed to ensure that our operations are conducted in compliance with applicable laws, and traditional cultural understanding.

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We have developed an active community relations program encompassing all segments of our operations. Although the refinery site is located on state owned land we have developed a long-term community development assistance program that includes local communities from 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.

Training workshops involving local communities, with participants ranging in ages from 14 to 68 years old started in April 2001. These workshops formed the basis for a five-year rolling plan covering areas such as communication, needs analysis, planning, leadership and conflict resolution. The provision of a reticulated water supply to local communities has been one of the many positive outcomes, leading to improved health and living standards.

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 the company’s 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.

The recording of verbal histories, clan boundaries and genealogies has been integrated with the 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 also to understand the quality of life of the people that inhabit the areas in which we work.

Risk Factors

Our financial results are significantly influenced by our business environment. Risks include, but are not limited to:

We have a limited operating history.

      We are a development stage company, with limited financial results upon which you may judge our potential. We may not become profitable. In the past, we have experienced delays and other problems frequently associated with a construction project such as our refinery. We may continue to experience many of the problems, delays and expenses encountered by any early stage business, many of which are beyond our control. These include, but are not limited to, substantial delays and expenses in conducting our exploration drilling program, difficulty in obtaining financing and competition from larger and more established companies.

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Our refinery has not operated at full capacity for an extended period of time.

      We have completed the construction of our refinery in Papua New Guinea. We began testing our refinery at its approximate nameplate capacity in November 2004. In January 2005, testing of our refinery was completed and we declared practical completion of the refinery. Our ability to continue to operate our refinery at its nameplate capacity must be considered in light of the risks inherent in, and the difficulties, costs, complications and delays frequently encountered by start-up companies. These risks include, without limitation, shortages of equipment, materials or labor; delays in delivery of equipment or materials; contractual disagreements; labor disruptions; political events; local or political opposition; accidents and unforeseen engineering, design or environmental problems. We were unable to operate our refinery for a period of 10 days in March 2005 as a result of a shortage of crude feedstocks. Such shortages may occur in the future as well. Accordingly, there can be no assurance of the future profitability of us or our refinery.

Our refinery operations may not be profitable.

      Our refining operations are expected to be primarily affected by the difference or margin between the sales prices of our refined products and the costs we incur to purchase crude oil and other feedstocks. Historically, refining margins have been volatile, and we expect this volatility will exist in the future. Therefore, we will be subject to the risk that the difference between the cost to us of our crude oil supply and the price at which we can sell our refined products will not be sufficient for the profitable operation of our company and to allow us to service our indebtedness. We cannot control the prices at which our feedstocks will be purchased or at which refined petroleum products can be sold.

We may not be successful in our exploration for oil.

      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. We have drilled one exploration well, suspended the drilling of two exploration wells and one exploration/appraisal well, and have plans to drill at least 8 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 available.

      In addition, our exploration and development plans may be curtailed, delayed or cancelled as a result of lack of adequate capital and other factors, such as weather, compliance with governmental regulations, landowners interference, mechanical difficulties, materials shortages, 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.

Our investments in Papua New Guinea are subject to political, legal and economic risks.

      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; the risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts; taxation policies; foreign exchange restrictions;

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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. In addition, 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.

We may not be able to market all of our refinery’s output.

      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. We have estimated that between 50% and 60% of the refinery’s net output will be used to supply the Papua New Guinea market. We will market the balance of the refinery’s output in nearby regional markets. We have signed three-year export contracts with Shell. While we will sell refined products through our domestic retail network and other distributors, these agreements are the only commercial agreements for the purchase of our refined products for export. We can give no assurances that we will be able to market the refinery’s output to these nearby regional markets and we may be unable to market all of the refinery’s output we produce. 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. In addition, early termination of the Shell export agreements could have a material adverse effect on our results of operations and financial condition.

      Further, our Project Agreement with the Papua New Guinea government 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 may not be able to obtain crude feedstocks for our refinery.

      The 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 at the IPP. 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.

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      Papua New Guinea crude oil production rates are expected to satisfy the refinery’s requirements for at least five years after commercial start-up. Alternative crude oils that are suitable for use as refinery feedstock are available in the nearby region. However, crude oil sourced from outside Papua New Guinea may be more expensive than domestic crude oil and may reduce our gross profit margins. Alternatively, imported crude oil may be selected to alter the refinery product mix in response to changing market conditions.

We may not be able to obtain all of the licenses necessary to operate our business.

      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, or will 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 commission our oil refinery facilities or to maintain continued operations that economically justify the cost.

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

      Our refining operations will be subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards and uncontrollable flows of oil and gas. 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.

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

      We operate in the highly competitive areas of oil exploration and production, and 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, the availability of alternate fuel sources, the costs of our drilling program, the development of transportation systems to bring future production to the market and transportation costs of oil are factors that affect our ability to compete in the marketplace. Many of our competitors operate in areas where they are able to sell both the oil and the natural gas that they produce.

      In our refining business, we will compete with numerous other 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 and retail outlets for our refined products. Competitors that

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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.

The volatility of oil prices could adversely affect our results of operations.

      The prices we will receive for the refined products we produce and sell are likely 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, 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. The prices for oil will affect:

•   our revenues, cash flows and earnings;

•   our ability to attract capital to finance our operations, and the cost of such capital;

•   the value of our oil properties;

•   the profit or loss we incur in refining petroleum products; and

•   the profit or loss we incur in exploring and developing our reserves.

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, 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 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. 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.

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 the United States. It may be difficult for investors to enforce, outside the United States, judgments against us that are obtained in the United States in any such actions, including actions predicated upon the civil liability provisions of the securities laws of the United States. In addition, most of our directors and officers are nationals or residents of countries outside of the United States, and all, or a substantial portion of, the assets of such persons are located outside the United States. As a result, it may be difficult for investors to affect service of process within the United States upon such persons or to enforce judgments against them obtained in United States courts, including judgments predicated upon the civil liability provisions of the securities laws of the United States.

We may not be able to generate cash flows if we are unable to raise capital.

      We make, and will continue to make, substantial capital expenditures for exploration, development, acquisition and production of oil reserves 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,

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operating difficulties, construction costs, or lack of drilling success, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

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

      As of December 31, 2004, we had $87 million in long-term debt, excluding current maturities. The level of our indebtedness will have important effects on our future operations, including:

•   a portion of our cash flow will be used to pay interest and principal on our debt and will not be available for other purposes;

•   our OPIC credit facility and BNP credit facility contain financial tests which we must satisfy in order to avoid a default under such credit facilities; and

•   our ability to obtain additional financing for capital expenditures and other purposes may be limited.

If we are unable to recruit and retain qualified personnel, it could 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 accommodate our exploration plans and to 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 (“P.I.E.”) can affect our raising of capital through the issuance of common shares or securities convertible into common shares.

      Mr. Phil E Mulacek, President and CEO of our company, controls P.I.E. P.I.E owns 433,169 of our common shares, and has a right to exchange its remaining 5,000 shares of SP 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 P.I.E. Mr. Mulacek through P.I.E. also controls 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 P.I.E. 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.

Changing regulation of corporate governance and public disclosure can 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

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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. As a result, 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. Any failure to comply with applicable laws may materially adversely affect our reputation and the value of our securities.

If we fail to comply with Section 404 of the Sarbanes-Oxley Act of 2002, our reputation and the value of our securities may be adversely affected.

      Beginning with our annual report for the year ending December 31, 2006, 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 is in the process of adopting 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 Section 404, including issuing the required management report and obtaining the attestation report on management’s assessment from our independent auditors, may materially adversely affect our reputation and the value of our securities.

Dividends

We have not paid dividends in the past and do not expect to pay dividends in the near future.

Description of 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 its 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 on securities convertible into common shares, except with, among other things, the consent of P.I.E. These are also certain pre-emptive rights in our articles granted to P.I.E. Group, LLC 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.

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Market for 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 Australian Stock Exchange in CHESS Depositary Interests in Australian dollars under the symbol IOC, which trade on a 10:1 basis to common shares. Our common shares trade as ordinary fully paid shares on the Port Moresby Stock Exchange in the local currency (Kina) under the symbol (IOC).

On February 28, 2005 we notified the Australian Stock Exchange and the Papua New Guinea Stock Exchange of our intent to delist. Subsequent to that announcement, the POMSoX provided us with a waiver allowing us to maintain our POMSoX listing as long as we met the requirements of the Toronto Stock Exchange. We still intend to delist from the Australian Stock Exchange and expect to have that accomplished by June 2005.

The following tables disclose the monthly closing price and volume of InterOil’s common shares traded on the TSX, AMEX and ASX:

Toronto Stock Exchange (TSX:IOL) in Canadian Dollars
Month	High		Low		Close		Volume
January		39.95		30.00		39.00		798,100
February		38.50		34.00		37.50		303,400
March		38.00		32.00		35.50		277,000
April		36.00		33.00		35.75		331,200
May		35.75		30.00		31.00		258,400
June		32.00		28.05		28.98		141,300
July		28.95		21.75		25.00		819,000
August		26.00		19.41		19.70		1,346,400
September		30.89		19.25		27.90		4,005,600
October		35.09		27.90		29.92		2,016,200
November		46.85		29.61		45.60		1,645,300
December		49.70		40.00		45.65		1,101,300
Total								13,043,200

Note: InterOil graduated from the TSX Venture Exchange to the TSX on July 14, 2004.

American Stock Exchange (AMEX:IOC) in United States Dollars
Month	High		Low		Close		Volume
January		n/a		n/a		n/a		n/a
February		n/a		n/a		n/a		n/a
March		n/a		n/a		n/a		n/a
April		n/a		n/a		n/a		n/a
May		n/a		n/a		n/a		n/a
June		n/a		n/a		n/a		n/a
July		n/a		n/a		n/a		n/a
August		n/a		n/a		n/a		n/a
September		24.35		15.55		22.15		3,702,800
October		27.88		22.65		24.50		5,330,100
November		39.35		24.65		38.50		6,614,000
December		40.60		32.50		37.84		5,483,700
Total								21,130,600

Note: InterOil’s AMEX listing commenced September 8, 2004.

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Australian Stock Exchange (ASX:IOC) in Australian Dollars
Month	High		Low		Close		Volume
January		36.40		30.00		36.00		34,449
February		37.70		31.00		33.50		25,727
March		37.80		31.00		35.10		43,462
April		35.80		31.50		35.30		50,391
May		36.00		31.10		31.10		36,445
June		33.10		30.10		30.60		27,964
July		30.90		23.30		27.10		41,313
August		28.30		23.00		23.00		30,276
September		31.90		21.50		31.50		35,749
October		36.60		29.60		32.50		65,868
November		47.40		31.70		47.40		110,633
December		51.50		44.20		51.00		42,578
Total								544,855

Note: On the ASX InterOil shares trade as CHESS Depository Interests on a 10:1 basis to InterOil common shares, this table has converted those to full common shares.

Prior Sales

We issued warrants to purchase 359,415 of our common shares in private placements on August 27, 2004 and September 3, 2004. 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. We have entered into an agreement dated as of February 25, 2005 with a number of investors to participate in funding our exploration drilling program. Each investor has a right to convert its interest into our common shares at a conversion price of $37.50 per share.

Management’s Discussion and Analysis

Our Management’s Discussion and Analysis (“MD&A”) for the fiscal years ended December 31, 2004 contains additional information with respect to us and our business and incorporated herein by reference and is available on SEDAR at www.sedar.com and our web site at www.interoil.com.

Directors and Officers

Our Board of Directors is responsible for the leadership and direction of InterOil, including our strategy, financial budgets, and business goals. The Board monitors our progress towards achieving these goals by means of management reports presented at meetings or as required in the case of special projects.

The Board comprises six Directors of whom three are independent (Gaylen Byker, Michael Folie and Edward Speal). Two are senior executives (InterOil’s CEO and President, Phil Mulacek and its Chief Operating Officer and Vice President, Christian Vinson) and one is a related-party (Roger Grundy). The experience and qualifications of each Director are set out below. The non-executive Directors meet regularly with the executive Directors, discussing achievements and making suggestions and recommendations. Emphasis is placed on the need for compliance with

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legislation in areas such as environment, occupational health and safety and the corporations laws of the various jurisdictions in which we operate.

Directors & Officers
Name	Address	Position	Date of Appointment
Phil E Mulacek	The Woodlands, TX USA	Chairman, CEO, & Director	May 29, 1997
Christian M Vinson	Cairns, QLD Australia	Vice President, COO & Director	May 30, 1997
Roger N Grundy	Matlock Derbyshire, UK	Director	May 29, 1997
Gaylen J Byker	Grand Rapids, MI USA	Director	May 29, 1997
G Michael Folie	Brighton, VIC Australia	Deputy Chairman & Director	January 1, 2001
Edward N Speal	Toronto, ON Canada	Director	June 25, 2003
Thomas Donovan	Cairns, QLD Australia	Chief Financial Officer	December 1, 2002
Graeme Alexander	Cairns, QLD Australia	Company Secretary	January 29, 2001
Anesti Dermedgoglou	Cairns, QLD Australia	Vice President	June 3, 2002
Gary M Duvall	The Woodlands, TX USA	Vice President	July 8, 2002

Principal Occupation of Directors and Officers during the Past 5 Years:

Phil E Mulacek is the Chairman of the Board of Directors, Chief Executive Officer, and President of InterOil, positions he has held since 1997. Mr Mulacek is the founder of Petroleum Independent Exploration Corporation (“P.I.E.”) based in Houston, Texas. P.I.E. 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. P.I.E. developed and participated in more than 90 wells at depths from 1,640 feet (500 meters) to 26,200 feet (8,000 meters). P.I.E. led the development of InterOil’s 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 has been the Chief Operating Officer for InterOil since 1995. Mr Vinson joined InterOil from P.I.E. Corp, a Houston, Texas based oil and gas exploration and production company. Before joining P.I.E. Corp, Mr Vinson was a manager with NUM Corporation, a Schneider company, in Naperville, Illinois where his responsibilities included the establishment of the company’s first USA office. As Chief Operating Officer of InterOil Mr Vinson has the in-country responsibility for government and community relations and corporate development. Mr Vinson has played a key role in the development of InterOil and was responsible for securing a 30-year Project Agreement with the Government of Papua New Guinea for InterOil’s refinery. Mr Vinson has developed long standing relationships with key government and industry leaders over the last ten years. 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 (doctorate) in international relations from the University of Pennsylvania and a JD (law) from the University of Michigan. Dr Byker is a former partner in 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, Phibro Energy, Inc., a subsidiary of Salomon, Inc. and head of Commodity-Indexed Transactions Group, 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 an associate attorney at Morgan, Lewis & Bockius in Philadelphia, Pennsylvania, USA.

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G Michael Folie is Deputy Chairman of the Board of Directors and following a distinguished career as an executive in the resource sector, is currently a consultant and independent director specializing in petroleum and mining. Dr Folie held a number of senior executive positions with Shell Australia Limited and its subsidiaries from 1979 to 1994 where he was involved in all aspects of Shell’s Australian businesses, including investments in coal, alumina, gold, LNG, oil refineries and chemical plants. From 1990 to 1994, Dr Folie was a director of Shell Australia, involved in all of Shell’s operations, including oil products and refining. From 1994, he was managing director and Chief Executive Officer of Australian Stock Exchange listed Acacia Resources Limited until it merged with AngloGold in January 2000. Dr Folie has been a director of Australian Government statutory agencies — Export Finance and Insurance Corporation from 1994 to 1997 and the Australian Research Council from 2001 to 2004. He is currently a director of the Institute of Public Affairs and Chairman of the ASX listed Regis Resources NL. Dr Folie obtained a PhD in Civil Engineering from Southampton University and a Masters in Economics from the London School of Economics and currently resides in Melbourne, Australia.

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 InterOil’s refinery and has acted as a consultant to more than 135 existing refineries on six continents for major oil companies, independents and the World Bank. Mr Grundy has 37 years experience in all areas of oil refinery and petrochemical operations and construction and holds an Honours 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 Institute of Petroleum.

Edward N Speal is based in Toronto, Ontario and is responsible for the Energy, Project Finance and Corporate Banking businesses for BNP Paribas in Canada. He was the President and Chief Executive Officer of Paribas Bank of Canada from 1996 to 2000. He previously worked in New York for Banque Paribas running its Commodity Index Trading Group (1992-1996). 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 1983-1989, he worked for the Chase Manhattan Bank of Canada. Mr Speal is a Canadian citizen and is a graduate of Queen’s University at Kingston.

Tom S Donovan is General Manager Finance/Accounts and Chief Financial Officer. Mr Donovan’s experience in international business and financial systems is a requisite for ensuring that the financial integrity of InterOil’s business segments is maintained and integrated worldwide. Prior to joining InterOil, Mr Donovan was the Director of Corporate Accounting for Rapid Design Service, Inc. RDS provided product design, development, engineering, document processing, and training through 35 locations in 11 countries. During his tenure at RDS Mr Donovan successfully managed the development and implementation of an enterprise wide integrated accounting system across the international organization. Mr Donovan also played a key role on the RDS due diligence team, and was directly responsible for managing the financial conversion process for all acquired companies. Prior to RDS, he held various positions in financial management for International Total Services, Inc. Mr Donovan has a Bachelor of Business and Administration (Accounting and Finance) from the University of Toledo, Toledo, Ohio.

Graeme Alexander is Corporate Counsel and Company Secretary. Mr Alexander has extensive legal and geological experience having worked as a Minerals Geologist for 10 years before specializing in law. Mr Alexander has significant Papua New Guinea in-country experience, developed during his position as principal commercial partner of Gadens Lawyers in Papua New Guinea. Prior to that he was senior counsel of Mobil Exploration & Production Pty Limited and Ampolex Limited, during which time he also worked on Papua New Guinea matters. Mr Alexander

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has worked in the geological and legal fields in the minerals and petroleum industries for a total of 30 years and holds a Bachelor of Applied Science (Geology) from the Canberra College of Advanced Education and a Law Degree from the University of Technology, Sydney.

Anesti Dermedgoglou is Vice President Investor & Public Relations. Mr Dermedgoglou is a former member of the Johannesburg Stock Exchange and Director of Frankel Pollack Vinderine Inc, one of the largest stock broking companies in South Africa. Prior to joining InterOil, Mr Dermedgoglou was a stock broker with Merrill Lynch in Perth, Western Australia. 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.

Gary M Duvall is Vice President Corporate Development. Mr Duvall was director of international business development at The Williams Companies. While at Williams Mr Duvall was responsible for evaluating potential acquisitions and the development of energy infrastructure projects in target countries. Mr. Duvall’s primary focus was on the Asia-Pacific Region and Europe. Mr Duvall has worked in various aspects of the energy industry for 20 years and holds a Bachelor of Science Degree in Mechanical Engineering from Oklahoma State University.

Board Committees

Our Board has formed the following Committees: Audit; Compensation; and Health Safety & Environment (HSE). The Audit and Compensation Committees comprise independent directors only.

Audit Committee

Charter

“The audit committee is a standing committee of the Board whose main purpose is to assist the Board in monitoring business and financial risks and to ensure the integrity of our financial statements through regular meetings with the Chief Financial Officer and the external auditor. It is also responsible for monitoring our compliance with legislative requirements. The audit committee has the authority to conduct or authorize investigations into any matter within the scope of its responsibility. It also has full authority to investigate any matter brought to its attention with full access to all records, facilities and employees of the company, and to retain outside legal accounting or other consultants to advise the audit committee.”

Audit Committee
Member	Independent	Financially Literate	Relevant Education and Experience
Gaylen J Byker	Yes	Yes	See biography
G Michael Folie	Yes	Yes	See biography
Edward N Speal	Yes	Yes	See biography

The audit committee does not include a ‘financial expert’ as defined by United States SEC Rules. As a foreign private issuer we are not subject to the SEC and the AMEX audit committee rules until July 31, 2005. We are in the process of ensuring that our audit committee satisfies these requirements. As part of the assessment of our audit committee, we will evaluate whether to designate a member of our audit committee as a financial expert. We believe that all of the members of our audit committee possess the financial expertise necessary for the audit committee to properly fulfill its purpose.

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Audit Fees

Year-ended December 31 ($)	2004		2003
Fees paid to independent auditors		324,337		89,668
Audited related fees		197,182		14,836
Tax fees		28,234		39,088
All other fees		129,772		21,390

Compensation Committee

The compensation committee is a standing committee of the Board whose responsibility is the compensation of our CEO and other executive officers to ensure that they are rewarded in accordance with market rates. In due course this committee will also make recommendations to shareholders regarding directors’ fees. The compensation committee meets as required, to fill vacancies on the Board as they may occur and to review compensation. The compensation committee also produces an annual report of our executive compensation practices for inclusion in the annual proxy statement in accordance with applicable rules and regulations. The compensation committee comprises Gaylen Byker, Edward Speal and Michael Folie.

HSE Committee

The HSE committee is responsible for ensuring that we comply with all applicable HSE requirements and otherwise maintains HSE standards. The HSE committee comprises Christian Vinson, Michael Folie and Roger Grundy.

Disclosures

We have adopted a Code of Business Conduct. All of our employees, directors and officers must follow our Code of Business Conduct, which provides guidelines for ethical behavior. This Code of Business Conduct includes additional guidelines for our financial officers, including the Chief Executive Officer, Chief Financial Officer and other senior financial officers. The Code of Business Conduct is accessible on our website at www.interoil.com. We will also provide to any person, without charge, upon request, a copy of the Code of Business Conduct. Requests must be made in writing to the Company Secretary of Interoil Corporation at Suite 2, Level 2, Orchid Plaza, 79 Abbott Street, PO Box 6567, Cairns, QLD 4870, Australia.

Shareholdings of Directors

Directors do not need to hold any qualifying shares.

Number of shares
Name	Position	Shares			Under Option
Phil E Mulacek	Chairman, CEO, and President		6,306,677 927,469	(I) (D)		15,000
Christian M Vinson	Director, COO, and Vice President		168,000	(D)		15,000
Roger N Grundy	Director		67,700	(D)		110,000
Gaylen J Byker	Director		553,125 199,900	(I) (D)		60,000
G Michael Folie	Director		20,000	(D)		60,000
Edward N Speal	Director		2,300	(D)		30,000

Notes:

(1) There are no escrowed, pooled or other securities.
(2) (I) = Indirect Holdings; (D) = Direct Holdings
(3) As of February 28, 2005

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Interests of Officers and Directors in Our Affairs

During 2004, Petroleum Independent and Exploration Corporation (“P.I.E.”), of which Mr Mulacek is the President, was reimbursed for P.I.E.’s legal, accounting and reporting costs of US$150,410 relating to its being appointed the General Manager of InterOil subsidiary, SP InterOil, LDC.

Breckland Ltd, of which Mr Grundy is a principal, was paid $120,426 on a commercial basis for advisory services and associated expenses it provided to InterOil’s refinery project.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

None of those persons who are directors officers or promoters of our company are, or have been within the past ten years, a director, or officer or promoter of any other corporation that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the access to any statutory exemptions for a period of more than 30 consecutive days, or was declared bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy or insolvency or been subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that person.

Penalties or Sanctions

None of those persons who are directors officers or promoters of our company are, or have been within ten years prior to the date of this Annual Information Form, subject to any penalties or sanctions imposed by a court or securities regulatory authority relating to trading in securities, promotion or management of a publicly traded corporation, or theft or fraud.

Legal Proceedings

We are not subject to any legal or other actions, current or pending, that may materially affect its operating results, financial position or property ownership.

Material Contracts

Each of these material agreements has been filed on SEDAR.

Date	Description	Parties
February 25, 2005	Indirect Participation Interest Agreement	InterOil Corporation and the investors signatory thereto
February 25, 2005	Registration Rights Agreement	InterOil Corporation and the investors signatory thereto
July 31, 2004	Purchase and Sale Agreement	InterOil Corporation and Shell Overseas Holdings Limited
March 10, 2004	Share Sale Agreement	InterOil Corporation, SPI Distribution Limited, Gas Tank Nederland B.V. and BP Papua New Guinea Limited
November 9, 2003	Facilities Management Contract	InterOil Limited and Petrofac Niugini Limited
March 26, 2002	Engineering Procurement and Construction Contract	InterOil Limited and Clough Niugini Limited
December 21, 2001	Crude Supply Agency and Sales Agreement	EP InterOil, Ltd. and BP Singapore Pte Limited
April 9, 2001	Domestic Sales Agreement	InterOil Limited and Shell Papua New Guinea Limited
March 26, 2001	Export Marketing and Shipping Agreement	EP InterOil, Ltd. and Shell International Eastern Trading Company
February 8, 2001	Agreement for the Sale and Purchase of Naphtha	EP InterOil, Ltd. and Shell International Eastern Trading Company
May 29, 1997	Refinery State Project Agreement	InterOil Limited and EP InterOil, Ltd. and The Independent State of Papua New Guinea

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Indirect Participation Interest Agreement

      We have entered into an agreement dated as of the February 25, 2005 with a number of investors listed therein (the “IPI Investors”) to participate in funding an eight (8) well exploration drilling program in our petroleum prospecting licenses (PPL) 236, 237 and 238 in Papua New Guinea.

      The IPI Investors will invest a total of $125 million to earn an aggregate 25% indirect participation interest in any discoveries resulting from that drilling program. Each IPI Investor has a right to convert its interest into our common shares at a conversion price of $37.50 per share between June 15, 2006 and the later of (i) December 15, 2006 and (ii) 90 days after the drilling and, if applicable, completion of the eight exploration well.

Registration Rights Agreement

      This agreement is between us and the IPI Investors. The agreement provides the parties thereto with the right to have common shares that may be received upon conversion of indirect participation interests registered under the United States Securities Act. Registration under the United States Securities Act permits the parties to this agreement to conduct secondary trading of these securities from time to time.

Purchase and Sale Agreement

      On July 31, 2004, we entered into an agreement with Shell to purchase Shell’s Papua New Guinea subsidiary, together with its retail and wholesale distribution assets in Papua New Guinea upon satisfaction of conditions precedent including receiving statutory approvals. The agreement includes the following key components:

(a)	Shell will lease the distribution assets back from us to continue to operate its product distribution business unabated.
(b)	The leaseback agreement terminates on the tenth anniversary of its commencement, unless terminated earlier by Shell upon giving 6 months’ notice.

Share Sale Agreement

      On April 28, 2004, we acquired BP’s distribution assets and commercial and retail operations in Papua New Guinea, comprising BP PNG’s distribution company holdings, 40 service stations and 10 terminals and depots, for a purchase price of $12.2 million for the company and its assets and inventory. BP agreed to fund the working capital of the distribution assets for one year after the effective date, whereupon we repaid to BP a working capital adjustment and certain dividend amounts, as well as the balance of the purchase price.

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Facilities Management Contract

      On November 9, 2003, we entered into a facilities management contract with Petrofac Niugini Limited. This agreement provides for the management of the day-to-day operation and maintenance of our refinery and includes the following key components:

(a)	The initial term of the agreement is for 5 years from “practical completion” of the refinery;
(b)	The agreement can be terminated by either party upon six months prior notice;
(c)	Petrofac’s remuneration is by way of a fixed management fee, which is subject to adjustment based upon achievement of performance goals; and
(d)	Petrofac Facilities Management Limited has provided a parent company guarantee of Petrofac Niugini Limited’s performance.

Engineering Procurement and Construction Contract

      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. The agreement includes the following key components:

(a)	This is a lump-sum, turnkey contract providing for a construction/commissioning period of 26 months.
(b)	Except for the defect liability provisions, this construction contract terminates upon “practical completion” of the refinery. In general, practical completion occurs when the refinery is physically complete and testing and commissioning has been carried out satisfactorily.
(c)	Clough warranties the refinery from defect for 12-months following practical completion.

Crude Supply Agency and Sales Agreement

      On December 21, 2001, we entered into a crude supply agency and sales agreement with BP. Under this agreement, BP will be the exclusive supplier of crude feedstock to the refinery for an initial period of five years from first supplying crude to the refinery in June 2004. We have agreed to pay the market price for this feedstock, which is the same as the purchase price for Kutubu Blend feedstock set forth in our project agreements with Papua New Guinea. In addition, we have agreed to pay BP a nominal marketing fee per barrel.

      BP has agreed to supply Kutubu Blend feedstock or, with our approval, alternative crude feedstocks. If BP is able to supply other less expensive feedstock to the refinery, we will share in the profit of marketing this oil. In operating the refinery, we will attempt to optimize the costs of refining different blends of crude under our marketing agreement with BP when choosing our feedstock. This agreement terminates in June 2009. However, either party may terminate the agreement earlier by providing 30 days’ notice.

Domestic Sales Agreement

      On April 9, 2001, we entered into a domestic sales agreement with Shell. Commencing with our purchase of the Shell’s retail and wholesale distribution assets, Shell has agreed to purchase from us all of the refined products that Shell requires for retail and wholesale distribution in Papua New Guinea. The domestic sales agreement provides that the purchase price for refined product is to be essentially the same as the IPP. The domestic sales agreement terminates 10 years following our purchase of the domestic retail and distribution assets from Shell.

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Export Marketing and Shipping Agreement and Agreement for the Sale and Purchase of Naphtha

      We entered into agreements with Shell with respect to the export of refined product produced at the refinery that is not sold domestically. These agreements include the following key components:

(a)	The term of the agreements is three years from the first bill of lading date for Naphtha and three years from the date of practical completion of our refinery in respect of the export marketing agreement.
(b)	The purchase price of refined products is based upon market price of such product in the export market.
(c)	Shell agrees to take 100% of any excess volumes, after domestic sales, of all products available for export including unleaded mogas, Jet-A1, kerosene and diesel and to take 100% of the refinery’s naphtha production.

Refinery State Project Agreement

      On May 29, 1997, we entered into a project agreement with the Government of Papua New Guinea under which we have agreed to construct a refinery and to operate that refinery in Port Moresby.

      In the project agreement, the Government of Papua New Guinea has agreed to propose legislation and issue executive orders or policy directives to enable us to purchase sufficient oil produced in Papua New Guinea for the refinery to run at full capacity. 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 prior to any imports into Papua New Guinea at the IPP. The term of the project agreement is 30 years from the date the refinery construction is completed. In addition, for five years from the commencement of refinery operations, the project agreement provides that income from the refinery will not be taxed.

The project agreement can be terminated by the government of Papua New Guinea if:

•   we cease operations for 90 days without government approval;

•   our refinery subsidiary terminates doing business or goes into liquidation;

•   we do not remedy a material breach of the project agreement within 60 days after receiving notice of such breach; or

•   events beyond our reasonable control, including weather conditions, events associated with active volcanoes or war, terrorism, civil unrest or expropriation prevent us from operating the refinery for 12 months.

We can terminate the project agreement if:

•   the government of Papua New Guinea expropriates or nationalizes the refinery;

•   the government of Papua New Guinea does not remedy a material breach of this agreement within 60 days after receiving notice of such breach;

•   material provisions of any of our agreements become unenforceable or unlawful;

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•   any restrictions on our ability to convert Papua New Guinea currency into U.S. dollars or restrictions on our use of foreign currency outside Papua New Guinea last for more than 180 days; or

•   events beyond our reasonable control, including weather conditions, events associated with active volcanoes or war, terrorism, civil unrest or expropriation, prevent us from operating the refinery for 12 months.

Transfer Agents and Registrars

Our transfer agent and registrar is Computershare Trust Company of Canada. In Australia and 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). The registers for transfers of our CDIs and ordinary fully paid shares as traded in Australia and Papua New Guinea, respectively, are maintained by Computershare Limited at its Sydney office in Australia. Queries should be directed to Computershare (Australia) whose principle address is Level 3, Carrington Street, Sydney NSW, 2000 Australia or at (612) 8234 5000

Forward-looking Statements

Certain statements contained in this report are forward-looking statements as defined in the U.S. federal securities laws. All statements, other than statements of historical facts, included herein or incorporated by reference herein, including without limitation, statements regarding our drilling plans, business strategy, plans and objectives of management for future operations and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates” or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that such forward-looking statements will prove to be correct.

Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from any results expressed or implied by our forward-looking statements. Risks and uncertainties include, but are not limited to:

•   our lack of substantial operating history;

•   the operation of our refinery at less than full capacity;

•   refinery and additional construction costs;

•   profitability of our refinery;

•   our ability to market refinery output;

•   the success of our exploration prospects;

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

•   anticipated markets for our refined products;

•   dependence on exclusive relationships with our supplier and customers;

•   ability to obtain necessary licenses;

•   uninsured risks;

•   the impact of competition;

•   the enforceability of legal rights;

•   the volatility of oil prices;

•   weather and unforeseen operating hazards;

•   debt covenants limiting ability to raise additional financing;

•   the cyclical nature of the refining business; and

•   other factors.

InterOil Corporation
Page 31 of 34

Important factors that could cause the actual results to differ from materially from our expectations are disclosed in more detail set forth under the heading “Risk Factors” in herein. Our forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Additional Information

Additional information, including that related to directors’ and officers’ remuneration is contained in our information circular prepared in respect of the annual meeting of shareholders held on June 29, 2004. Additional financial information is provided in our audited consolidated financial statements for the year ended December 31, 2004, which financial statements are incorporated by reference herein, and which can be found in InterOil’s 2004 Annual Report to shareholders filed on SEDAR at www.sedar.com and on our web site at www.interoil.com.

Copies of the information circular, the financial statements, including any additional copies of this Annual Information Form may also be obtained from the following individuals:

North America	Australasia
Gary M Duvall	Anesti Dermedgoglou
V.P. Corporate Development	V.P. Investor Relations
InterOil Corporation	InterOil Corporation
Gary.duvall@interoil.com	Anesti@interoil.com
Phone: 1-281-292-1800	Phone: 61-7-4046-4600

InterOil Corporation
Page 32 of 34

Glossary of Terms

Anticline. A configuration of folded, stratified rocks in which rocks dip in two directions away from a crest, generally convex upward, the core of which contains the stratigraphically older rocks. In Papua New Guinea generally seen at surface as a hill, often elongate or cigar shaped.

Basin (sedimentary). Segment of the earth’s surface which has been down-warped and infilled with sedimentary detrital or carbonate rocks. Sediments increase in thickness toward the centre of a basin.

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.

Carbonate. Sedimentary rocks composed of calcium carbonate (CaCo³). See limestone.

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

Cretaceous. The final period of the Mesozoic era, spanning the time between 145 and 65 million years ago. The name is derived from the Latin word “creta” (chalk) and was first applied to extensive deposits of this age that form white cliffs along the English Channel.

Down dip. A term used where one well is below another well due to inclination of the strata in which the reservoir lies.

Field. A natural accumulation of oil and/or gas within a reservoir below a seal rock, and within a trap.

Fold Belt. An area affected by compressional forces which results in folding (wrinkling) and thrusting. Usually separated from an undeformed foreland by a frontal fault (thrust).

Foreland. A stable area which lies in front of and is unaffected by the compressional forces which develop a Fold Belt.

Hydrocarbons. Compounds containing only hydrogen and carbon atoms. May be in solid, liquid or gaseous form.

Jurassic. The middle period of the Mesozoic era, spanning the time between 213 and 145 million years ago. It is named after the Jura Mountains between France and Switzerland, where rocks of this age were first studied.

Kitchen. A pod of buried thermally mature source rock actively generating hydrocarbons (also commonly referred to as “oil and gas window”).

Limestone. Sedimentary rock composed largely of mineral calcite, CaCO³, formed by either organic or inorganic processes. Carbonate rocks, limestone and dolomite, constitute estimated 12 to 22% of sedimentary rocks exposed above sea level.

Mesozoic. The middle era between the Paleozoic and the Tertiary 248 and 65 million years ago. Its name is from the Greek word “Mesozoic” (middle life).

InterOil Corporation
Page 33 of 34

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.

Petroleum System. A pod of active source rock and all the geologic elements and processes that are essential if a hydrocarbon accumulation is to exist.

Play. A particular combination of reservoir and structure (trap) considered to be prospective.

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.

Reservoir. Porous and permeable rock, such as sandstone which may contain significant oil or gas.

Sandstone. Detrital sedimentary rock formed by cementation of individual grains of sand size and commonly composed of mineral quartz. Sandstones constitute an estimated 12 to 28 percent of sedimentary rocks. A common rock in which oil, natural gas, and/or water can accumulate.

Seal. An impermeable layer which overlays a reservoir and prevents leakage of hydrocarbons.

Seep. A surface location where oil and/or gas appears having permeated from its subsurface source.

Source. A pod of organic rich sedimentary rock from which hydrocarbons originate.

Stratigraphic well. A well drilled to investigate the rock strata present in an area, as opposed to an exploration well drilled to evaluate a potential field.

Structure (trap). Geological structure which traps migrating hydrocarbons, allowing an oil or gas field to form.

Tertiary. The first period of the Cenozoic era (after the Mesozoic era and before the Quaternary period), spanning the time between 65 and 1.8 million years ago.

InterOil Corporation
Page 34 of 34

EX-99.2

Exhibit 2

InterOil Corporation

Consolidated Financial Statements
(Audited, Expressed in United States dollars)

Years ended December 31, 2004, 2003 and 2002 and cumulative

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of InterOil Corporation as at December 31, 2004 and 2003 and the consolidated statements of earnings, retained earnings, and cash flows for each of the years in the three-year period 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 audits.

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 2003 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.

KPMG

Sydney, Australia
March 4, 2005

COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA U.S. REPORTING DIFFERENCE

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company’s financial statements, such as the change described in Note 1(c) — Stock-based compensation — to the Company’s consolidated financial statements as at December 31, 2004 and 2003, and for each of the years in the three-year period ended December 31, 2004. Our report to the shareholders dated March 4, 2005 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

KPMG

Sydney, Australia
March 4, 2005

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 judgements. 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 of the Board of Directors, composed of independent non-management directors, 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 consolidated financial statements have been audited by KPMG, the independent auditors, in accordance with Canadian generally accepted auditing standards on behalf of the shareholders. KPMG has full and free access to the Audit Committee.

Phil Mulacek	Tom Donovan
Chief Executive Officer	Chief Financial Officer

InterOil Corporation

Consolidated Balance Sheets
(Expressed in United States dollars)

	December 31			December 31			December 31
	2004			2003			2002
	$			$			$
Assets
Current assets:
Cash and cash equivalents (note 2)		19,735,912			9,313,682			3,288,539
Temporary investments (note 9)		24,407,709			24,723,572			7,105,701
Trade receivables (note 3)		58,698,069			—			—
Commodity hedge contracts (note 9)		503,500			—			—
Other assets		806,123			486,584			503,859
Inventories (note 6)		27,916,902			—			—
Prepaid expenses		190,135			488,532			80,359
Total current assets		132,258,350			35,012,370			10,978,458
Deferred financing costs (note 11)		760,488			—			—
Plant and equipment (note 7)		244,914,355			202,309,465			121,217,700
Oil and gas properties (note 8)		6,605,360			23,018,015			2,878,703
Future income tax benefit (note 13)		1,303,631			—			—
Total assets		385,842,184			260,339,850			135,074,861
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities		26,328,544			5,835,583			6,744,515
Income tax payable		2,881,398			—			—
Short term loan facility — crude feedstock (note 18)		76,520,541			—			—
Deferred acquisition cost (note 10)		12,123,106			—			—
Due to related parties (note 5)		1,056,251			1,478,751			2,784,560
Foreign currency forward contracts (note 9)		—			—			678,648
Current portion of secured loan (note 11)		9,000,000			9,000,000			—
Current portion of indirect participation interest (note 14)		13,749,852			—			—
Total current liabilities		141,659,692			16,314,334			10,207,723
Accrued financing costs (note 11)		863,329			—			—
Secured loan (note 11)		76,000,000			74,000,000			31,000,000
Indirect participation interest (note 14)		10,608,830			16,600,000			—
Total liabilities		229,131,851			106,914,334			41,207,723
Non-controlling interest (note 15)		6,404,262			6,467,496			6,490,398
Shareholders’ equity:
Share capital (note 16)		216,813,654			157,449,200			94,120,609
Authorised — unlimited Issued and outstanding 28,310,884 (Dec 31, 2003 - 24,815,961) (Dec 31, 2002 - 20,585,943)
Contributed surplus		1,841,776			540,222			769,964
Warrants (note 12)		2,258,227			—			—
Foreign currency translation adjustment		463,200			—			—
Deferred hedge gain (note 9)		537,358			—			—
Deficit accumulated during the development stage		(71,608,144	)		(11,031,402	)		(7,513,833	)
Total shareholders’ equity		150,306,071			146,958,020			87,376,740
Total liabilities and shareholders’ equity		385,842,184			260,339,850			135,074,861

See accompanying notes to the consolidated financial statements

Commitments (note 20)

On behalf of the Board

Phil Mulacek, Director

Christian Vinson, Director

InterOil Corporation

Consolidated Statements of Operations
(Expressed in United States dollars)

										Unaudited
										cumulative amounts
										from inception of
										development
				Year ended						stages to
	December 31			December 31			December 31			December 31
	2004			2003			2002			2004
	$			$			$			$
Revenue
Sales and operating revenues (note 19)		70,644,486			—			—			70,644,486
Interest		382,461			246,912			373,015			7,349,234
Other		196,337			12,368			11,211			230,485
Equity (loss) of SP InterOil, LDC		—			—			—			(281,128	)
		71,223,284			259,280			384,226			77,943,077
Expenses
Cost of sales and operating expenses (note 19)		63,836,182			—			—			63,836,182
Inventory revaluation		1,508,334			—			—			1,508,334
Administrative and general expenses		8,470,625			2,337,255			2,241,911			19,219,202
Management fees		—			—			—			1,365,000
Management fees for prior periods waived		—			(840,000	)		—			(840,000	)
Exploration costs (note 8)		38,470,074			164,992			92,673			39,430,660
Legal and professional fees		3,573,727			1,421,390			464,253			7,233,954
Short term borrowing costs		4,705,190			—			—			4,705,190
Long term borrowing costs		1,401,256			—			—			1,401,256
Foreign exchange (gain) loss		392,805			678,774			(1,094,787	)		2,556,475
		122,358,193			3,762,411			1,704,050			140,416,253
Loss before income taxes and non-controlling interest		(51,134,909	)		(3,503,131	)		(1,319,824	)		(62,473,176	)
Income taxes (note 13)
Current		(2,538,410	)		(37,339	)		(1,446	)		(2,687,836	)
Future		663,347			—			—			663,347
		(1,875,063	)		(37,339	)		(1,446	)		(2,024,489	)
Loss before non-controlling interest		(53,009,972	)		(3,540,470	)		(1,321,270	)		(64,497,665	)
Non-controlling interest		70,091			22,901			5,383			526,381
Net loss		(52,939,881	)		(3,517,569	)		(1,315,887	)		(63,971,284	)
Basic loss per share (note 23)		(2.09	)		(0.16	)		(0.06	)
Diluted loss per share (note 23)		(2.09	)		(0.16	)		(0.06	)
Weighted average number of common shares outstanding
Basic and diluted		25,373,575			22,649,924			20,462,167

See accompanying notes to the consolidated financial statements

InterOil Corporation

Consolidated Statements of Cash Flows
(Expressed in United States dollars)

										Unaudited
										cumulative amounts
										from inception of
										development
	Year ended									stages to
	December 31			December 31			December 31			December 31
	2004			2003			2002			2004
	$			$			$			$
Cash flows from/(used in) operating activities
Net loss		(52,939,881	)		(3,517,569	)		(1,315,887	)		(63,971,283	)
Adjustments for non-cash transactions Net distributions from SP InterOil LDC		—			—			—			781,187
Non-controlling interest		(70,091	)		(22,901	)		(5,383	)		(526,300	)
Depreciation and amortization		639,075			73,068			85,657			797,800
Future income tax benefit		(663,347	)		—			—			(663,347	)
Gain on sale of other assets		(94,260	)		—			—			(94,260	)
Amortization of discount on debt		604,045			—			—			604,045
Amortization of deferred financing costs		268,873			—			—			268,873
Debt conversion settlement expense – debentures		77,589			—			—			77,589
Management fee waived		—			(840,000	)		—			(840,000	)
Stock compensation expense		1,209,921			(39,654	)		612,197			1,782,464
Capitalized oil and gas properties expensed		35,566,761			164,992			92,673			35,824,426
Ineffective hedge loss		40,715			—			678,648			719,363
Interest expense forfeited by debenture holders		998,438			—			—			998,438
Unrealized foreign exchange loss (gain)		392,805			678,774			(1,773,435	)		2,556,475
Change in non-cash working capital Decrease/(increase) in trade receivables		(50,456,671	)		—			—			(50,456,671	)
Decrease/(increase) in other assets and prepaid expenses		982,014			220,196			709,782			2,237,894
Decrease/(increase) in inventories		(22,666,150	)		—			—			(22,666,150	)
Increase (decrease) in accounts payable, accrued liabilities and income tax payable		5,880,047			(236,058	)		(1,433,211	)		(916,755	)
		(80,230,117	)		(3,519,152	)		(2,348,959	)		(93,486,212	)
Cash flows used in investing activities
Cash paid on consolidation of SP InterOil LDC		—			—			—			(14,858,947	)
Expenditure on oil and gas properties		(19,154,106	)		(19,987,946	)		(875,105	)		(37,855,204	)
Expenditure on plant and equipment		(38,484,704	)		(81,843,608	)		(42,372,277	)		(185,519,616	)
Proceeds on sale of other assets		405,353			—			—			405,353
Redemption of cash on short term investments		24,723,572			(17,617,871	)		9,894,299			—
Acquisition of InterOil Products Limited, net of cash received (note 10)		4,631,904			—			—			4,631,904
Change in non-cash working capital
Increase (decrease) in accounts payable and accrued liabilities		4,094,594			(1,351,521	)		4,749,199			7,492,272
		(23,783,387	)		(120,800,946	)		(28,603,884	)		(225,704,238	)
Cash flows from financing activities
Proceeds from secured loan		2,000,000			52,000,000			30,240,000			84,240,000
Proceeds from senior convertible debenture		45,000,000			—			—			45,000,000
Senior convertible debenture issuance costs		(3,259,766	)		—			—			(3,259,766	)
Proceeds from indirect participation interest		16,984,852			16,300,000			—			33,284,852
Proceeds from related party borrowings (note 5)		1,775,565			—			2,900,000			4,753,841
Repayment to related party (note 5)		(2,198,065	)		(776,902	)		(878,276	)		(3,853,243	)
Proceeds from issue of common shares – options		2,020,316			62,822,143			1,312,223			126,647,846
Proceeds from short term borrowing		5,100,000			—			—			5,100,000
Repayments of short term borrowings		(5,100,000	)		—			—			(5,100,000	)
Proceeds from (repayments of) working capital facility		76,520,541			—			—			76,520,541
Cash held as security for working capital facility		(24,407,709	)		—			—			(24,407,709	)
		114,435,734			130,345,241			33,573,947			338,926,362
Increase in cash and cash equivalents		10,422,230			6,025,143			2,621,104			19,735,912
Cash and cash equivalents, beginning of period		9,313,682			3,288,539			667,435			—
Cash and cash equivalents, end of period (note 2)		19,735,912			9,313,682			3,288,539			19,735,912

See accompanying notes to the consolidated financial statements

InterOil Corporation

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

	Year ended
	December 31			December 31			December 31
	2004			2003			2002
	$			$			$
Share capital
At beginning of period		157,449,200			94,120,609			92,808,387
Adjustment to reflect change in accounting for employee stock options (note 1c)		92,434			—			—
Issue of capital stock		59,272,020			63,328,591			1,312,222
At end of period		216,813,654			157,449,200			94,120,609
Contributed surplus
At beginning of period		540,222			769,964			—
Adjustment to reflect change in accounting for employee stock options (note 1c)		645,216			—			—
Stock compensation		656,338			(229,742	)		769,964
At end of period		1,841,776			540,222			769,964
Warrants
At beginning of period		—			—			—
Movement for period (note 12)		2,258,227			—			—
At end of period		2,258,227			—			—
Foreign currency translation adjustment
At beginning of period		—			—			—
Movement for period (note 1e)		463,200			—			—
At end of period		463,200			—			—
Deferred hedge gain
At beginning of period		—			—			—
Movement for period (note 9)		537,358			—			—
At end of period		537,358			—			—
Deficit accumulated during the development stage
At beginning of period		(11,031,402	)		(7,513,833	)		(6,197,946	)
Adjustment to reflect change in accounting for employee stock options (note 1c)		(737,650	)		—			—
Adjustment to reflect cumulative debentures conversion expense (note 12)		(6,899,211	)		—			—
Net (loss) for period		(52,939,881	)		(3,517,569	)		(1,315,887	)
At end of period		(71,608,144	)		(11,031,402	)		(7,513,833	)
Shareholders’ equity at end of period		150,306,071			146,958,020			87,376,740

See accompanying notes to the consolidated financial statements

InterOil Corporation

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

InterOil Corporation’s (the “Company” or “InterOil”) is a development stage enterprise whose primary business interests are the development of an oil refinery (the “Project”), oil and gas exploration in Papua New Guinea (“PNG”), and distribution of refined petroleum products in PNG.

1. Statement of significant accounting policies

(a) Basis of presentation

The consolidated financial statements for the year ended December 31, 2004 have been prepared in accordance with Canadian generally accepted accounting principles on a going concern basis which presumes the realization of assets and discharge of liabilities in the normal course of business in the future.

The consolidated financial statements of the Company include the financial statements of SP InterOil, LDC (“SPI”) (99.9%), SPI Exploration and Production Corporation (100%), SPI Distribution Limited (100%), InterOil Australia Pty Ltd (100%) and their subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation.

(b) Segment reporting

The Company operates its business in Papua New Guinea in the following segments:

•   Upstream includes the exploration for and production of crude oil and natural gas.

•   Midstream includes refinery operations. The refinery processes crude oil into naphtha, gasoline, diesel, LPG, jet/kerosene and low sulphur way residue. The midstream operations sell to the PNG domestic market as well as to export customers.

• Downstream includes the distribution of refined products and lubricants, including gasoline, diesel and fuel oils in PNG.

The above functions have been defined as the operating segments of the Company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred or where business activities are being developed; (b) whose operating results are regularly reviewed by the Company’s chief operating decision-maker to make decisions about resources to be allocated to the segment and assess its performance; and (c) for which discrete financial information is available. “Corporate” includes assets and liabilities that do not specifically relate to business segments e.g. primarily cash. Results in this segment primarily include financing costs and interest income.

Segment accounting policies are the same as those described in this summary of significant accounting policies. Upstream, midstream and downstream include costs allocated from the corporate activities. The allocation is based on a fee for service.

(c) Stock-based compensation

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. 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. 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. The effect of retroactively adopting the fair value based method, without restatement, is to increase the opening deficit accumulated during the development stage by $737,650, increase contributed surplus by $645,216 and increase share capital by $92,434.

(d) Inventories

Crude oil and refined petroleum products are valued at the lower of cost, on a first-in, first-out basis, or net realizable value. The cost of midstream refined petroleum product consists of raw material, labour, direct overheads and transportation costs. Cost of downstream refined petroleum product includes the cost of the product plus related freight, wharfage and insurance.

InterOil Corporation

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

1. Statement of significant accounting policies (cont’d)

(e) Foreign currency

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 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.

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 balance 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 income.

(f) Deferred financing costs

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

(g) Receivables

The collectability of debts is assessed at reporting date and specific provision is made for any doubtful accounts.

The Company sells certain trade receivables with recourse to BNP Paribas under its working capital facility. The receivables are retained on the balance sheet as the Company retains the risks and rewards associated with carrying the receivables. The working capital facility balance is increased for the amount of cash received on the transaction.

(h) Revenue recognition

The following particular accounting policies, which significantly affect the measurement of profit 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. Sales between business segments of the Company are eliminated from sales and operating revenues and cost of sales and between the asset for the refinery as all revenues and expenses relating to the refinery have been capitalized for the period to December 31, 2004.

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 using the effective interest method.

InterOil Corporation

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

1. Statement of significant accounting policies (cont’d)

(i) Derivative financial instruments

Derivative financial instruments are utilized by the Company in the management of its naphtha sales price exposures and its crude purchase cost exposures. The Company’s policy is not to utilize derivative financial instruments for trading or speculative purposes.

On the date a derivative contract is entered into the Company designates the derivative as a hedge of a forecasted transaction. The Company 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 ineffectiveness. 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 equity to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. The ineffective portion of the change in fair value of a derivative instrument that qualifies as a hedge is reported in earnings.

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

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 immediately in earnings gains and losses that were accumulated in a separate component of equity.

The Company enters into naphtha swaps in order to reduce the impact of fluctuating naphtha prices on its revenue. 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 naphtha price swap agreements as hedges of the underlying sale. Naphtha sales revenue is adjusted to include the payments made or received under the naphtha price swaps.

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 period 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.

(j) Income taxes

The Company uses 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 likely not be recovered.

(k) 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

InterOil Corporation

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

1. Statement of significant accounting policies (cont’d)

(k) Oil and gas properties (cont’d)

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.

(l) Plant and equipment

Refinery assets
The Company’s most significant item of plant and equipment is the oil refinery in PNG. The Company is considered to be in the construction and pre-operating stage of development of the oil refinery. Project costs, net of any recoveries, incurred during this pre-operating stage are being capitalized as part of plant and equipment. Administrative and general costs are expensed as incurred. The refinery assets are recorded at cost. Development costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Interest costs relating to the construction and pre-operating stage of the development project prior to commencement of commercial operations are capitalized as part of the cost of such plant and equipment. Refinery related assets will be depreciated on a straight line basis over their useful lives, at 4% per annum. The refinery is being built on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097 and does not outline any terms for restoration and closure costs.

Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred. Major turnaround costs will be deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround. No major turnaround costs had been incurred at December 31, 2004.

Other assets
Property, plant and equipment is recorded at cost. Depreciation of assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated. Depreciation of plant and equipment is calculated using the straight line method, based on the estimated service life of the asset. The depreciation rates used on plant and equipment range from 15% to 40%. Maintenance and repair costs are expensed as incurred. Improvements that increase the capacity or prolong the service life of an asset are capitalized.

Leased assets
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 legal obligations associated with the retirement of the refinery or with its normal operations relating to future restoration and closure costs. The refinery is being 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. As a result, 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 income.

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. No provision has been recorded at December 31, 2004, 2003 and 2002.

(m) Employee entitlements

The amounts expected to be paid to employees for their pro-rata entitlement to long service and annual leave and leave fares are accrued having regard to anticipated periods of service, remuneration levels and statutory obligations.

InterOil Corporation

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

1. Statement of significant accounting policies (cont’d)

(n) Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the year. Actual results could differ from those estimates.

(o) Per share amounts

Basic per share amounts are computed by dividing net earnings by the weighted average shares outstanding during the reporting period. Diluted per share amounts are computed similar 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.

(p) Vulnerability to concentration risk

Credit risk
The majority of the Company’s export sales are made to one customer. The Company’s domestic sales for the period ended December 31, 2004 were not dependent on a single customer or geographic region of PNG.

No export or domestic sales from the refinery have been recognized in the Consolidated Statement of Operations for the year ended December 31, 2004.

Product risk
The composition of the crude feedstock will vary the refinery output of products. The 2004 output achieved through the commissioning process includes naphtha (35.8%), diesel (32.5%) and low sulphur waxy residue (16.2%). The product yields obtained during commissioning will vary going forward as the refinery operations are optimized.

Supply risk
During 2004, the Company sourced the majority of its crude supply from two sources.

Geographic risk
The operations of InterOil are concentrated in Papua New Guinea.

(q) Temporary investments

Temporary investments are carried at the lower of cost and recoverable amount. If the carrying amount of the asset exceeds its recoverable amount, the asset is written down to the lower amount. The write-down is expensed in the reporting period in which it occurs.

(r) Presentation

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

InterOil Corporation

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

2. Cash and cash equivalents

The Company considers deposits in bank and short-term investments with original maturities of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost. Accrued interest is included with other receivables.

The components of cash and cash equivalents are as follows:

	2004		2003		2002
	$		$		$
Cash on deposit		15,313,941		6,208,785		3,206,084
Bank term deposits
- Papua New Guinea kina deposits (K 13,891,853 )		4,417,609		97,417		79,324
- Australian dollar deposits (AUD 5,595)		4,362		—		3,131
Papua New Guinea kina treasury bills		—		3,007,480		—
		19,735,912		9,313,682		3,288,539

Increase in cash for the year ended December 31, 2004 is the result of the acquisition of InterOil Products Limited, which holds cash, and proceeds from the debenture issuance and options exercised. In addition, $13,749,852 was received near year end for a new indirect participation interest.

Included in the Papua New Guinea bank term deposits is $102,096 (2003 — $97,417, 2002 — $nil) which is restricted and unavailable to the Company while Petroleum Prospecting Licenses 236, 237 and 238 are being utilized by the Company.

3. Trade receivables

At December 31, 2004, the Company had a discounting facility with BNP Paribas on specific monetary receivables (note 18). As at December 31, 2004, $13,034,904 in outstanding accounts receivable had been sold with recourse under the facility. The Company has retained the responsibility for administering and collecting accounts receivable sold and therefore has included the sold receivables in the trade receivables balance at December 31, 2004.

The increase in trade receivables over prior year is a result of the fact that the Company has sold refined product produced by the refinery during its commissioning operations. The increase in trade receivables also relates to the operations of InterOil Products Limited, a subsidiary acquired during the year (note 10).

At December 31, 2004 $46,911,393 of the trade receivables secures the BNP Paribas working capital facility disclosed in note 18.

InterOil Corporation

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

4. Supplemental cash flow information

	Dec-31			Dec-31		Dec-31
	2004			2003		2002
	$			$		$
Cash paid during the year
Interest		1,444,006			4,138,290		1,948,043
Income taxes		1,914,459			64,891		2,855
Interest received		671,479			149,631		840,337
Non-cash investing and financing activities:
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 (note 1c)		645,216			—		—
Increase in due to related parties resulting from transfer of other assets		—			311,093		—
Increase in share capital from:
oil and gas property expenditure paid for with stock		—			316,359		—
change in accounting policy for stock based compensation (note 1c)		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		9,226,260			—		—
inducement paid on conversion of debentures		6,976,800			—		—
prepaid 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 4 relate to the “corporate” segment except for those involving the other payables capitalized as part of plant and equipment (midstream), the recording of deferred hedge gain (midstream), and the oil and gas property expenditure paid for with stock (upstream).

5. Related parties

Amounts due to related parties of $1,056,251 (2003 — $1,478,751, 2002 — $2,784,560) represents monies owed to Petroleum Independent and Exploration Corporation (PIE) which acts as a sponsor of the Company’s oil refinery project. PIE is controlled by an officer and director of InterOil. During the year, $422,500 of the loan to PIE was repaid . The loan has interest charged at a rate of 5.75% (2003 — 5.75%, 2002 — 5.75%) per annum. During the year ended December 31, 2004, PIE also advanced InterOil Corporation $1,775,565, which was repaid prior to December 31, 2004. The advance had interest charged at a rate of 6% per annum. During the year the Company incurred total interest to PIE amounting to $246,745 (2003 — $105,374, 2002 — $127,639).

SPI does not have a Board of Directors. Instead, its articles of association provide for the business and affairs of SPI to be managed by a general manager appointed by the shareholders of SPI and it is the US sponsor under the Overseas Private Investment Corporation (OPIC), an agency of the US Government, loan. PIE 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, $150,410 (2003 — $150,000, 2002 — $150,000) was expensed for the sponsor’s (PIE) legal, accounting and reporting costs. This amount was included in accounts payable and accrued liabilities at December 31, 2004. During 2003, PIE also waived $840,000 of management fees due to it for prior periods and this was reflected in the Consolidated Statement of Operations.

Breckland Limited provides technical and advisory services to the Company and/or subsidiaries on normal commercial terms. This party is related by virtue of common directorships. Amounts paid or payable to Breckland during the year amounted to $120,426 (2003 — $131,250, 2002 — $204,522).

InterOil Corporation

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

5. Related parties (cont’d)

The services of certain executive officers and senior management of the Company are provided under a management services agreement with Direct Employment Services Corp. (“DESC”). DESC is a U.S. private Company administered by executive officers of the Company and which was established for the purposes of providing non-profit management services to the Company. During 2004 DESC was paid $708,104 (2003 — $535,855, 2002 — $435,661).

Amounts due to Directors at December 31, 2004 totaled $61,000 for Directors fees (2003 — $30,500, 2002 — $26,000) and $320,000 for Directors bonuses (2003 — nil, 2002 — nil) and are included in accounts payable and accrued liabilities.

6. Inventories

	Dec-31		Dec-31		Dec-31
	2004		2003		2002
	$		$		$
Midstream (crude oil feedstock)		3,971,982		—		—
Midstream (refined petroleum product)		16,396,975		—		—
Downstream (refined petroleum product)		7,547,945		—		—
		27,916,902		—		—

Midstream inventories have increased between December 31, 2003 and December 31, 2004 as a result of the refinery entering its commissioning stage. Further, downstream inventories have increased as a result of the acquisition of InterOil Products Limited.

At December 31, 2004 $20,368,957 of the midstream inventory balance secures the BNP Paribas working capital facility disclosed in note 18.

InterOil Corporation

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

7. Plant and equipment

Year ended December 31, 2004
	Upstream			Midstream			Downstream			Corporate and consolidations			Totals
Plant and equipment		5,659,248			237,102,876			12,331,522			263,217			255,356,863
Deferred project costs		—			—			406,077						406,077
Consolidation entries		—			—			—			(2,002,214	)		(2,002,214	)
Accumulated depreciation and amortization		(19,792	)		(419,629	)		(8,230,060	)		(176,890	)		(8,846,371	)
Net book value		5,639,456			236,683,247			4,507,539			(1,915,887	)		244,914,355
Capital expenditure for year		1,131			40,532,990			1,320,644			83,920			41,938,685

Year ended December 31, 2003
	Upstream			Midstream			Downstream		Corporate and consolidations			Totals
Plant and equipment		5,658,117			43,218,420			—		179,472			49,056,009
Deferred project costs		—			153,298,736			321,817					153,620,553
Consolidation entries		—			—			—		(165,647	)		(165,647	)
Accumulated depreciation and amortization		(7,282	)		(107,643	)		—		(86,525	)		(201,450	)
Net book value		5,650,835			196,409,513			321,817		(72,700	)		202,309,465
Capital expenditure for year		5,658,117			81,226,712			100,333		53,791			87,038,953

Year ended December 31, 2002
	Upstream		Midstream		Downstream		Corporate and consolidations			Totals
Plant and equipment		—		47,959,600		—		132,615			48,092,215
Deferred project costs		—		73,076,344		221,484					73,297,828
Consolidation entries		—		—		—		(128,296	)		(128,296	)
Accumulated depreciation and amortization		—		—		—		(44,047	)		(44,047	)
Net book value		—		121,035,944		221,484		(39,728	)		121,217,700
Capital expenditure for year		—		39,069,313		45,398		46,128			39,160,839

InterOil Corporation

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

8. Oil and gas properties

Costs of oil and gas properties, including major development projects, excluded from costs subject to depletion and depreciation were as follows:

	Dec 31, 2004		Dec 31, 2003		Dec 31, 2002
	$		$		$
Petroleum Prospecting Licence 238, at cost
Equipment and inventories		5,353,471		6,992,867		—
Drilling programs		1,251,889		14,199,188		1,193,910
Other exploration properties, at cost		—		1,825,960		1,684,793
		6,605,360		23,018,015		2,878,703

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

	Dec 31, 2004		Dec 31, 2003		Dec 31, 2002
	$		$		$
Exploration costs expensed as incurred		2,903,313		—		—
Capitalized oil and gas properties expensed
Costs incurred in prior years		16,576,982		70,016		84,362
Costs incurred in current years		18,989,779		94,976		8,311
		38,470,074		164,992		92,673

Capitalized oil and gas properties expensed during the period include costs relating to the Moose and Sterling Mustang wells. These wells were suspended during the year. Due to the uncertainty of reentering these wells and without any proven reserves established, the cost of drilling these exploratory wells to date has been expensed.

9. Financial instruments

With the exception of cash and cash equivalents and short term investments, all financial assets are non interest bearing. Cash and cash equivalents earned average interest rates of 1.6% per annum (2003 — 1.5%, 2002 — 3.5%).

Temporary investments	Dec-31, 2004		Dec-31, 2003		Dec-31, 2002
Cash deposit on working capital facility (1.98%)		24,407,709		—		—
Managed trust (1.5%)		—		24,626,154		—
Pledged deposit (1.6%)		—		97,418		7,105,701
Total		24,407,709		24,723,572		7,105,701

Credit risk is minimized as all cash amounts and certificate 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, short and long term debt and amounts due to related parties approximate fair values due to the short term maturities of these instruments.

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 inventories and accounts receivables.

Foreign currency hedge contracts
The Company had no outstanding foreign currency forward contracts at December 31, 2004 and 2003. At December 31, 2002, the Company had contracts valued at $62,000,000 to acquire Australian dollar amounts payable pursuant to the refinery construction. These hedging contracts have all matured during 2003. At December 31, 2002, the Company had an unrealized loss of $4,001,462 resulting

InterOil Corporation

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

from hedge contracts. An unrealized exchange loss of $678,648 was recognized on the balance sheet for contracts in excess of specific commitments at December 31, 2002.

9. Financial instruments (cont’d)

To define a maximum potential amount payable on the outstanding hedge contracts, the Company acquired Australia dollar put options during the year ended December 31, 2003 for total premiums of $218,430 (2002 — $85,000). The maturity dates and nominal amounts of the put options coincided with the exercise dates and nominal amounts of the outstanding hedge contracts. There were no outstanding put options at December 31, 2003 or December 31, 2004.

At December 31, 2002, as a requirement of the hedging contracts a collateral arrangement was entered into whereby an amount of $7,105,701 was held on deposit and had been pledged in favor of the provider of the hedge and recorded as cash. Funds required to be held on deposit as collateral reduced over time as project expenditure was undertaken and the foreign currency forward contracts were closed out. These amounts had reduced to nil as at December 31, 2003 and December 31, 2004.

Commodity hedge contracts
InterOil uses derivative commodity instruments to manage exposure to price volatility on a portion of its refined product. As at December 31, 2004, InterOil had entered into naphtha and crude swap agreements to hedge a portion of the anticipated January and February 2005, sales of naphtha and the purchase of associated crude feedstock. The unrealized gain on hedge contracts deemed to be effective at December 31, 2004 amounted $537,358 (2003 — $nil, 2002 — $nil) and is recognized in the financial statements under deferred hedge gain. A summary of the outstanding hedge contracts is as follows:

		Notional Volumes
Derivative	Type	(bbls)		Expiry	Price USD per Barrel		$ Receivable
Naphtha fixed price	Sell		50,000	Jan-05	$	43.90	$	280,000
Naphtha fixed price	Sell		50,000	Feb-05	$	41.00	$	112,500
Crude fixed price	Buy		50,000	Feb-05	$	38.90	$	111,000
Total							$	503,500

10. Acquisition of subsidiary

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 has been paid. The remaining purchase price of $12,226,854, which is included in current liabilities at December 31, 2004, was discounted to $11,895,349 at the time of acquisition. The discount is being amortised over the period to the payment date of March 1, 2005 and the amortised amount is included in short term borrowing costs. At December 31, 2004 the discounted amount of the debt was $12,123,106.

InterOil Corporation

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

10. Acquisition of subsidiary (cont’d)

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

The net assets acquired is equal to the adjusted purchase price, less the discount on the balance owing for the purchase at the time 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 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.

11. 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 facility is fully drawn down at December 31, 2004. The loan is secured over the assets of the refinery project which have a carrying value of $236,683,247 at December 31, 2004 (2003 — $196,409,513, 2002 — $121,035,944).

The loan expires June 30, 2014 with half yearly repayments of $4,500,000 commencing June 30, 2005. 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. The interest rate is equal to the treasury cost applicable to each promissory note outstanding plus the OPIC spread. The OPIC spread was 3% per annum during 2004. From practical completion, achieved on January 31, 2005, the OPIC margin will increase to 3.5%.

Deferred financing costs of $760,488 are being amortized over the period of the loan (10 years) until June 2014. The accrued financing costs of $863,329 include discounting of the liability for a 12 month period. The total liability is $950,000 and will be due for payment in June 2006.

12. Debentures and warrants

On August 28, 2004 and September 4, 2004 InterOil issued a total of $45.0 million 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 US$20.16 per share on December 31, 2004 at the investors’ option. The Company also issued 180,000 additional shares to debenture holders in connection with their conversion of the debt to equity. As a result of the issuance of the 180,000 additional shares, share capital increased by $6,976,800 which represents the fair market value of the shares on the date they were issued. In connection with these additional shares $77,589 was recognized as a debt conversion expense and $6,899,211 was recorded to accumulated deficit during the year ended December 31, 2004.

In connection with the issuance of the senior convertible debentures, InterOil issued to the investors five-year warrants to purchase 359,415 common shares at an exercise price equal to US$21.91. All warrants were outstanding at December 31, 2004 and were not impacted by the debt conversion. 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

InterOil Corporation

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

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.

13. Income taxes

The combined income tax expense in the consolidated statements of operations reflects an effective tax rate which differs from the expected statutory rate (combined federal and provincial rates). Differences for the years ended December 31 were accounted for as follows:

	2004			2003			2002
	$			$			$
(Loss) before income taxes and non controlling interest		(51,134,909	)		(3,503,131	)		(1,319,824	)
Statutory income tax rate		35.12	%		35.12	%		38.62	%
Computed tax (benefit)		(17,958,580	)		(1,230,300	)		(509,716	)
Effect on income tax of:
Losses in foreign jurisdictions not deductible		2,273,530			(56,527	)		(183,802	)
Non-deductible stock compensation expense		424,924			(13,926	)		236,431
Gains and losses on foreign exchange		58,659			302,499			—
Tax rate differential in foreign jurisdictions		(341,613	)		143,502			188,788
Over provision for tax in prior years		(42,874	)		—			(332	)
Tax losses for which no future tax benefit has been brought to account		2,696,330			836,142			346,526
Temporary differences for which no future tax benefit has been brought to account		14,552,726			—			158,204
Temporary differences brought to account on acquisition of subsidiary		(488,027	)		—			—
Other — net		699,988			55,949			(234,653	)
		1,875,063			37,339			1,446

      The future income tax asset at December 31 comprised the tax effect of the following:

	2004			2003			2002
	$			$			$
Future tax assets:
Temporary differences
Property, plant and equipment		2,263,654			—			—
Exploration expenditure		11,541,022			—			—
Other — net		127,240			(1,194,314	)		671,323
		13,931,916			(1,194,314	)		671,323
Loss carry forwards		4,850,380			2,558,406			1,366,190
		18,782,296			1,364,092			2,037,513
Less valuation allowance		(17,478,665	)		(1,364,092	)		(2,037,513	)
Net future tax asset		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, 2004.

The valuation allowance for deferred tax assets increased by $16,164,716 in the year ended December 31, 2004, decreased by $673,421 in the year ended December 31, 2003 and increased by $622,646 in the year ended December 31, 2002.

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

InterOil Corporation

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

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-forwards is appropriate as of December 31, 2004 in respect of losses generated from the refinery pre-commissioning activities.

14. Indirect participation interest

On May 17, 2004, PNG Energy Investors converted their $7,650,000 indirect participation interest (IPI) to 683,140 common shares of InterOil Corporation.

In March 2004, the Company received an additional $3,235,000 from PNG Drilling Ventures Limited (“PNGDV”) relating to PNGDV’s indirect interest in the Company’s phase one exploration program within the area governed by Petroleum Prospecting Licences 236, 237 and 238. This additional receipt brought the total invested by PNGDV in the indirect participation interest to $12,185,000. This interest is subject to the terms of the agreement dated July 21, 2003 between the Corporation and PNG Drilling Ventures Limited, under which all or part of the indirect participation interest, up to a maximum of $11,620,000 may be converted to common shares in the Company at a price no less than C$20.85 per common share. Alternatively, an amount up to $1,969,000 of the indirect participation interest may be converted to debt due in December 2005 and December 2006. Should neither of these conversion rights be exercised,the indirect participation in the drilling program will be maintained and distributions will be paid in accordance with the agreements. In January 2004, $75,500 of the PNGDV interest was converted to 5,000 common shares of InterOil Corporation and a further $1,500,670 of the interest was converted to 84,545 common shares on September 30, 2004 in accordance with the indirect participation interest agreement. The balance of PNGDV’s indirect participation interest at December 31, 2004 is $10,608,830 (December 31, 2003 — $8,950,000).

Prior to December 31, 2004, the Company received deposits of $13,749,852 toward an additional indirect participation interest.

15. 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. The capital structure of the joint venture was composed of voting, non-participating shares and non-voting, participating shares. Enron no longer actively participates in the development of the refinery project 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 project. Enron does not hold any transfer or conversion rights into shares of InterOil Corporation.

At December 31, 2004, a subsidiary, SPI, holds 98.74% (2003 — 98.66%, 2002 — 98.55%) of the non-voting participating shares issued from EPI.

16. 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.

	Number of Shares		$
Balance, January 1, 2002		20,186,870		92,808,387
Shares issued for cash		399,073		1,312,222
Balance, December 31, 2002		20,585,943		94,120,609
Shares issued for cash		3,817,500		61,060,640
Shares issued for debt		31,240		316,359
Shares issued on exercise of options		381,278		1,951,592
Balance, December 31, 2003		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
Balance, December 31, 2004		28,310,884		216,813,654

InterOil Corporation

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

17. Stock options

At December 31, 2004, 1,692,390 common shares were 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 Group 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.

	2004					2003					2002
				Weighted					Weighted					Weighted
				average					average					average
Stock options	Number of			exercise price		Number of			exercise price		Number of			exercise price
outstanding	options			$		options			$		options			$
Outstanding at beginning of year		1,363,265			7.55		1,510,085			5.48		1,165,600			4.00
Granted		224,460			26.30		257,802			14.09		762,585			6.53
Exercised		(310,095	)		6.52		(381,278	)		4.62		(393,000	)		3.26
Expired		(115,308	)		23.04		(23,344	)		5.75		(25,100	)		5.68
Outstanding at end of year		1,162,322			9.91		1,363,265			7.55		1,510,085			5.48

2004	Options issued and outstanding						Options exercisable
Range of exercise			Weighted average		Weighted average				Weighted average
prices			exercise price		remaining terms				exercise price
$	Number of options		$		(years)		Number of options		$
2.75 to 5.00		504,463		4.37		0.61		494,463		4.36
5.01 to 8.00		211,834		6.31		1.91		151,834		6.06
8.01 to 12.00		231,200		11.18		0.98		83,200		11.30
12.01 to 24.00		143,100		23.05		3.54		134,000		23.12
24.00 to 31.00		71,725		29.25		2.73		7,125		26.50
		1,162,322		9.91		2.07		870,622		8.39

The fair value of the 224,460 (2003 — 257,802, 2002 — 762,585 ) options granted subsequent to January 1, 2004 has been estimated at the date of grant in the amount of $1,122,938 (2003 — $1,087,131, 2002 — $976,900) using a Black-Scholes option 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 options of 3.8 years. An amount of $1,209,921 has been recognized in 2004 as a compensation expense. In 2003, $530,794 (2002 — $206,936) was recognized as a proforma compensation expense disclosure. The estimated fair value of the options is expensed over the option’s vesting period, which is identified in the individual’s option agreement.

18. Working capital facility

During the year ended December 31, 2004, InterOil obtained a working capital credit facility with BNP Paribas (Singapore branch) with a maximum availability of $100,000,000. 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. 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 4.36%.

InterOil Corporation

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

At December 31, 2004, $9,479,459 of the total facility remained available for use.

At December 31, 2004, the Company had one letter of credit outstanding for $14,000,000. Cash totaling $24,407,709 was being maintained as a security margin for the facility, as separately disclosed in note 9. In addition, inventory of $20,368,957 and receivables of $46,911,393 secured the facility.

19. Operations

Sales and operating revenues include the tradeout of a crude cargo which resulted in sales income of $26,309,547 and cost of goods sold of $27,685,347. The tradeout related to refinery commissioning issues and is not considered to be part of normal trading operations which were capitalized up to December 31, 2004. Downstream sales of $44,334,939 and cost of good sold of $36,150,835 are also included.

20. Commitments

Payment due by period
			Less than						More than
Contractual obligations	Total		1 year		1 – 3 years		3 - 5 years		5 years
Long-Term Debt Obligations	$	85,000,000	$	9,000,000	$	18,000,000	$	18,000,000	$	40,000,000
Indirect Participation Interests(1)	$	6,885,000	$	3,442,500	$	3,442,500	nil		nil
Acquisition of BP assets in PNG(2)	$	12,226,854	$	12,226,854	nil		nil		nil
BP Services Agreement(3)	$	1,000,000	$	1,000,000	nil		nil		nil
Purchase Obligations(4)	$	5,000,000	$	1,000,000	$	2,000,000	$	2,000,000	nil
Operating Leases	$	300,000	$	300,000	nil		nil		nil
Petroleum Prospecting and Retention License(5)	$	8,233,937	nil		$	8,233,937	nil		nil
Total	$	118,645,791	$	26,969,354	$	31,676,437	$	20,000,000	$	40,000,000

Notes

(1)	The Indirect Participation Interest terms provide for various conversion options. The amount provided is the maximum amount that can be converted to debt and differs to the amount presented in the December 31, 2004 Consolidated Balance Sheet due to conversion requirements into the Company’s paid common shares.
(2)	The aggregate purchase price was $13,226,854. A down payment of $1,000,000 of the purchase price was paid in 2004.
(3)	Management service agreement with BP.
(4)	Arises from management fees payable under the 5 year refinery facilities and management contract.
(5)	Amount necessary for the next 2 years under the work program to maintain our exploration licenses. The committed amount can be spent in any proportion over the two years.

InterOil Corporation

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

21. Segment reporting
The following tables present the Company’s results by segment.

Year ended December 31, 2004
	Upstream			Midstream			Downstream			Corporate			Consol			Total
Operating results
External sales		—			26,309,547			62,410,291			—			(18,075,352	)		70,644,486
Intersegment revenue		—			—			489,111			1,557,621			(2,046,732	)		—
Interest revenue		—			—			—			382,461			—			382,461
Other unallocated revenue		—			—			—			196,337			—			196,337
Total segment revenue		—			26,309,547			62,899,402			2,136,419			(20,122,084	)		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			3,133,095			3,146,905			8,309,537			(1,537,415	)		14,701,313
Geological and geophysical expenses		2,903,313			—			—			—			—			2,903,313
Depreciation and amortization		12,510			311,986			224,214			90,365			—			639,075
Exploration impairment		35,566,761			—			—			—			—			35,566,761
Interest expense		4,932			843,888			455,368			1,899,027			—			3,203,215
Loss from ordinary activities before income taxes		(40,136,707	)		(5,664,769	)		5,914,178			(8,162,510	)		(3,085,101	)		(51,134,909	)
Income tax expenses		—			—			(2,250,960	)		24,740			351,157			(1,875,063	)
Non controlling interest		—			—			—			70,091			—			70,091
Total net income/(loss)		(40,136,707	)		(5,664,769	)		3,663,218			(8,067,679	)		(2,733,944	)		(52,939,881	)

Year ended December 31, 2003
	Upstream			Midstream			Downstream			Corporate			Consol			Total
Operating results		—			—			—			—			—			—
External sales		—			—			—			—			—			—
Intersegment revenue		—			—			—			1,068,746			(1,068,746	)		—
Interest revenue		—			—			—			246,912			—			246,912
Other unallocated revenue		—			—			—			12,368			—			12,368
Total segment revenue		—			—			—			1,328,026			(1,068,746	)		259,280
Cost of sales and operating expenses		—			—			—			—			—			—
Office and Admin and other expenses		520,270			222,067			24,939			3,730,502			(1,078,801	)		3,418,977
Depreciation and amortization		10,282			8,254			—			54,532			—			73,068
Exploration expenses		164,992			—			—			—			—			164,992
Interest expense		—			—			—			105,374			—			105,374
Loss from ordinary activities before income taxes		(695,545	)		(230,321	)		(24,939	)		(2,562,382	)		10,055			(3,503,131	)
Income tax expenses		—			—			—			(37,339	)		—			(37,339	)
Non controlling interest		—			—			—			22,901			—			22,901
Total net income/(loss)		(695,545	)		(230,321	)		(24,939	)		(2,576,820	)		10,055			(3,517,569	)

Year ended December 31, 2002
	Upstream			Midstream			Downstream			Corporate			Consol			Total
Operating results		—			—			—			—			—			—
External sales		—			—			—			—			—			—
Intersegment revenue		—			—			—			645,434			(645,434	)		—
Interest revenue		—			—			—			373,015			—			373,015
Other unallocated revenue		—			—			—			11,211			—			11,211
Total segment revenue		—			—			—			1,029,660			(645,434	)		384,226
Cost of sales and operating expenses
Office and Admin and other expenses		(215,836	)		(123,626	)		3,258			1,847,812			14,112			1,525,720
Depreciation and amortization		—			—			—			85,657			—			85,657
Exploration write off		92,673			—			—			—			—			92,673
Interest expense		—			—			—			—			—			—
Loss from ordinary activities before income taxes		123,163			123,626			(3,258	)		(903,809	)		(659,546	)		(1,319,824	)
Income tax expenses		—			—			—			(1,446	)		—			(1,446	)
Non controlling interest		—			—			—			5,383			—			5,383
Total net income/(loss)		123,163			123,626			(3,258	)		(899,872	)		(659,546	)		(1,315,887	)

InterOil Corporation

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

The following tables present the Company’s total assets by segment:

Year ended December 31, 2004
	Upstream		Midstream		Downstream		Corporate and consolidations		Totals
		21,570,221		269,301,052		34,436,144		60,534,767		385,842,184

Year ended December 31, 2003
	Upstream		Midstream		Downstream		Corporate and consolidations		Totals
		60,129,239		181,660,129		321,817		18,228,665		260,339,850

Year ended December 31, 2002
	Upstream		Midstream		Downstream		Corporate and consolidations			Totals
		3,047,177		136,253,078		221,485		(4,446,879	)		135,074,861

Interest capitalized during the year to midstream plant and equipment was $5,949,270 (2003 - $4,025,004 , 2002 — $1,820,404)

Refer to note 7 for plant and equipment presented by business segment.

22. Subsequent events

On January 28, 2005 InterOil Corporation obtained a $20,000,000 Term Loan Facility from Clarion Finanz AG of which a tranche of $10,000,000 was received on January 31, 2005 and the balance of $10,000,000 was received on February 25, 2005. The loan has an interest rate equal to 5% per annum payable quarterly in arrears, and includes a 1% arrangement fee of the face amount. The term of the loan is fifteen months from the disbursement dates, and is repayable at any time prior to expiry with no penalty.

The certificate for practical completion of the refinery project in PNG was received on January 31, 2005.

InterOil applied for delisting from the Australian Stock Exchange on February 18, 2005.

InterOil executed investment agreements in respect of its ongoing exploration program in Papua New Guinea on February 28, 2005. Under these agreements, certain institutional and accredited investors have agreed to invest $125,000,000 for an aggregate 25% indirect participation interest in the exploration program.

InterOil made the final payment for the acquisition of BP Papua New Guinea on March 1, 2005, excluding a services agreement fee of $1,000,000 which is due on April 1, 2005.

23. Loss per share

Warrants, indirect participation conversion options and stock options totaling 2,155,042 common shares at prices ranging from $2.75 to $30.40 per share were outstanding in 2004 (2003 — 2,769,940 common shares at prices ranging from $2.75 to $30.40 per share, 2002 — 1,515,085 common shares at prices ranging from $2.75 to $12.00 per share) but were not included in the computation of diluted loss per share because they caused the loss per share to be antidilutive.

24. United States generally accepted accounting principles disclosures

The audited consolidated financial statements of the Company for the twelve month periods ended December 31, 2004, 2003 and 2002 have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”) which, in most respects, conforms with generally accepted accounting principles in the United States (“U.S. GAAP”). The reconciliations and other

InterOil Corporation

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

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.

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

	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
	Dec 31, 2004						Dec 31, 2003						Dec 31, 2002
	$			$			$			$			$			$
Revenue
Sales and operating revenues(1)		70,644,486			121,974,268			—			—			—			—
Interest		382,461			382,461			246,912			246,912			373,015			373,015
Other		196,337			196,337			12,368			12,368			11,211			11,211
		71,223,284			122,553,066			259,280			259,280			384,226			384,226
Expenses
Cost of sales and operating expenses(1)		63,836,182			128,362,792			—			—			—			—
Administrative and general expenses(1)		7,831,550			8,577,513			2,264,187			2,264,187			2,156,254			2,156,254
Inventory revaluation		1,508,334			1,508,334
Depreciation and amortization (1)		639,075			1,462,953			73,068			73,068			85,657			85,657
Management fees for prior periods waived		—			—			(840,000	)		(840,000	)		—			—
Debt conversion expense(5)		—			6,976,800			—			—			—			—
Exploration costs		38,470,074			38,470,074			164,992			164,992			92,673			92,673
Legal and professional fees		3,573,727			3,655,631			1,421,390			1,421,390			464,253			464,253
Short term borrowing costs		4,705,190			4,705,190			—			—			—			—
Long term borrowing costs		1,401,256			1,401,256			—			—			—			—
Foreign exchange (gain) loss(2)		392,805			392,805			678,774			(7,392,002	)		(1,094,787	)		(8,829,287	)
Non-controlling interest		(70,091	)		(265,624	)		(22,901	)		94,341			(5,383	)		108,617
		122,288,102			195,247,724			3,739,510			(4,214,024	)		1,698,667			(5,921,833	)
Income/(loss) before income taxes		(51,064,818	)		(72,694,658	)		(3,480,230	)		4,473,304			(1,314,441	)		6,306,059
Income tax expense(3)		(1,875,063	)		(1,875,063	)		(37,339	)		(37,339	)		(1,446	)		(1,446	)
Income/(loss) before cumulative effect of accounting change		(52,939,881	)		(74,569,721	)		(3,517,569	)		4,435,965			(1,315,887	)		6,304,613
Cumulative effect of accounting change(4)		—			(737,650	)		—			—			—			—
Net income/(loss)		(52,939,881	)		(75,307,371	)		(3,517,569	)		4,435,965			(1,315,887	)		6,304,613

InterOil Corporation

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

Statement of comprehensive income (loss),
net of tax

	Twelve months ended
	December 31,
	2004			2003		2002
	$			$		$
Net income/(loss) in accordance with U.S. GAAP		(75,307,371	)		4,435,965		6,304,613
Foreign currency translation reserve		463,200			—		—
Deferred hedge gain		537,358			—		—
Other comprehensive income		1,000,558			—		—
Comprehensive income/(loss)		(74,306,813	)		4,435,965		6,304,613

	Foreign				Accumulated
	currency				other
Statement of accumulated other	translation		Deferred		comprehensive
comprehensive income, net of tax (AOCI)	reserve		hedge gain		income
AOCI balance as of December 31, 2001		—		—		—
Current period change		—		—		—
AOCI balance as at December 31, 2002		—		—		—
Current period change		—		—		—
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

Per share amounts

Basic per share amounts 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 antidilutive for the year ended December 31, 2004. Antidilutive shares on issue for the year ended December 31, 2003 were 35,822 and December 31, 2002 were 152,917.

InterOil Corporation

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

	Year ended December 31,
Weighted average number of shares on which earnings per
share calculations are based in accordance with U.S. GAAP	2004			2003		2002
Basic		25,373,575			22,649,924		20,462,167
Effect of dilutive options		—			1,542,214		338,551
Diluted		25,373,575			24,192,138		20,800,718
Net income/(loss) per share in accordance with U.S. GAAP
Basic		(2.97	)		0.20		0.31
Diluted		(2.97	)		0.18		0.30

The following table presents the consolidated balance sheets under U.S. GAAP compared to Canadian GAAP:

	As of				As of
	December 31, 2004				December 31, 2003
	Canadian				Canadian
	GAAP		U.S. GAAP		GAAP		U.S. GAAP
Current assets		132,258,350		132,258,350		35,012,370		35,012,370
Oil and gas properties		6,605,360		6,605,360		23,018,015		23,018,015
Capital assets (1)		244,508,278		232,641,229		48,854,559		48,854,559
Deferred project costs (2)		406,077		406,077		153,454,906		156,514,019
Deferred charges		760,488		760,488		—		—
Future income tax benefit (3)		1,303,631		1,303,631		—		—
Total assets		385,842,184		373,975,135		260,339,850		263,398,963
Current liabilities		141,659,692		141,659,692		16,314,334		16,314,334
Deferred financing costs		863,329		863,329		—		—
Long term debt		86,608,830		86,608,830		90,600,000		90,600,000
Non-controlling interest		6,404,262		6,063,971		6,467,496		6,322,739
Shareholders’ equity (1) (2) (4)		150,306,071		138,779,313		146,958,020		150,161,890
Total liabilities & shareholders’ equity		385,842,184		373,975,135		260,339,850		263,398,963

(1)	Operations: The Company determined that refinery operations commenced under U.S. GAAP at December 1, 2004, which is the date management assessed that construction of the refinery was substantially complete and ready for its intended use. The Company ceased capitalization of certain costs to the refinery project at this date and recognized one month’s results from sales, related costs of sales and operating expenses and administrative and general expenses in the statement of operations for the year ended December 31, 2004.
	As disclosed in note 21 in the consolidated financial statements, operations commenced after December 31, 2004 under Canadian GAAP. Therefore, the Company continued to capitalize December 2004’s results to the refinery project.
	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. The useful life for the refinery under U.S. GAAP is the same as that disclosed under Canadian GAAP in note 1(l) in the consolidated financial statements.
	The Company was a development stage enterprise in prior years in respect of the refinery construction. Classification as a development stage enterprise under U.S. GAAP ceased in conjunction with operations commencement at December 1, 2004.
	The Company made sales from the refinery of $30,539,560 (59.5%) to one customer during the year.
(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.

InterOil Corporation

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

	The Company elected not to adopt the FASB’s optional hedge accounting provisions when SFAS No. 133 became effective on January 1, 2001. Accordingly unrealized gains and losses resulting from the valuation of derivatives at fair value arising during the years ended December 31, 2003 and 2002 were recognized in income as the gains and losses arose under U.S. GAAP. Under Canadian GAAP for these years, the Company continued to recognize the gains and losses on derivative contracts designated as hedges concurrently with the recognition of the transactions being hedged.
	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. The hedge accounting for the new hedges is disclosed in notes 1(i) and 8 in the consolidated financial statements of the Company for the year ended December 31, 2004.
(3)	Income tax effect of adjustments: The income tax effect of U.S. GAAP adjustments was a tax benefit of $7,665,071 for the year ended December 31, 2004 for which a corresponding increase in the valuation allowance was recorded. No income tax expense was recorded in the years ended December 31, 2003 and 2002 due to the tax relief available in PNG through five years after the refinery commences operations.
(4)	Stock based compensation: FASB Statement No. 123, “Accounting for Stock-based Compensation” (“SFAS No. 123”), establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees.
	Prior and during the years ended December 31, 2003 and 2002, the Company issued options to non-employees that were direct awards of stock or that called for settlement by the issuance of equity instruments using the fair value method. The Company followed the provisions of the Canadian Institute of Chartered Accountants in Handbook Section 3870, “Stock-based compensation and other stock-based payments” (“CICA 3870”), which resulted in recognition of compensation expense for stock options issued to non-employees under Canadian GAAP on a basis consistent with the requirements of SFAS No. 123.
	As permitted under SFAS No. 123, the Company also issued options to employees that were direct awards of stock using the intrinsic value method, which is provided for in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”. Where options were granted with exercise prices equal to the market price when the options were granted, no compensation expense was recorded at the time of the option grants. Had compensation cost for the Company’s stock options been determined based on the fair market value at the grant dates of the awards, and amortized on a straight-line basis, consistent with methodology prescribed by SFAS No. 123, the Company’s net income and net income per share for the years ended December 31, 2003 and 2002 would have been the pro forma amounts indicated as follows:

	Year ended December 31,
	2003			2002
Net income in accordance with U.S. GAAP		4,435,965			6,304,613
Pro forma stock based compensation		(530,794	)		(206,856	)
Pro forma net income		3,905,171			6,097,757
Earnings per share as reported
Basic		0.20			0.31
Diluted		0.18			0.30
Pro forma earnings per share
Basic		0.17			0.30
Diluted		0.16			0.29

The fair values of all common share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of options granted during the year and the assumptions used in their determination are the same as note 16 to the consolidated financial statements.

InterOil Corporation

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

	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 1(c) 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 adjust 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, 2004, 2003 and 2002.
	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.
(5)	Debt conversion expense:
	As disclosed in note 12 in the consolidated financial statements, 100% of the convertible debentures were converted before 31 December 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.

Acquisition of InterOil Products Limited (“IPL”)
The following summary audited 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 9 in the consolidated financial statements.

InterOil Corporation

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

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 the current estimates.

The pro forma information does not purport to represent what the financial position and results of operations actually would 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 for 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
	(audited)			(unaudited)		(unaudited)
Twelve months ended December 31, 2004
Sales and operating revenue — Canadian GAAP		70,644,486			27,317,000		97,961,486
Sales and operating revenue — U.S. GAAP		121,974,268			27,317,000		149,291,268
Net loss — Canadian GAAP		(52,939,881	)		2,350,000		(50,589,881	)
Net loss — U.S. GAAP		(75,307,371	)		2,350,000		(72,957,371	)
Basic loss per share (cents per share)
Canadian GAAP (2)		(2.08	)				(1.99	)
U.S. GAAP (3)		(2.97	)				(2.87	)
Diluted loss per share (cents per share)
Canadian GAAP (2)		(2.08	)				(1.99	)
U.S. GAAP (3)		(2.97	)				(2.87	)
Twelve months ended December 31, 2003
Sales and operating revenue — Canadian and U.S. GAAP		—			69,897,000		69,897,000
Net income/(loss) — Canadian GAAP		(3,517,569	)		6,474,000		2,956,431
Net income — U.S. GAAP		4,435,965			6,474,000		10,909,965
Basic income/(loss) per share (cents per share)
Canadian GAAP (2)		(0.15	)				0.14
U.S. GAAP (3)		0.20					0.49
Diluted income/(loss) per share (cents per share)
Canadian GAAP (2)		(0.15	)				0.13
U.S. GAAP (3)		0.18					0.45

(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.

EX-99.3

Exhibit 3

InterOil Corporation 2004

Management’s Discussion and Analysis

Overview	2
Business Environment	3
Risk Factors	3
Forward-looking statements	9
Business Plan	9
Results of Operations	10
Upstream	10
Midstream	11
Downstream	12
Corporate and consolidation	13
Consolidated income taxes	14
Quarterly Financial Summary	14
Capital Resources	15
Operating Activities	15
Investing Activities	16
Financing Activities	18
Liquidity	19
Sources of Capital	19
Capital Requirements	20
Contractual Obligations and Commitments	21
Our Material Contracts	21
Off Balance Sheet Arrangements	22
Share Capital	22
Transactions with Related Parties	23
Financial and Derivative Instruments	23
Foreign currency hedge contracts	24
Commodity hedge contracts	24
Critical Accounting Estimates	24
New Accounting Standards	26
Stock Based Compensation Plans	26
Asset Retirement Obligations	26
Inventory Costs	27
Accounting For Variable Interest Entities	27
Accounting For Exchanges of Nonmonetary Assets	27
Evaluation of Disclosure Controls and Procedures	27
Public Securities Filings	28

InterOil Corporation
Page 1 of 28

March 31, 2005

Management’s Discussion and Analysis

The following discussion and analysis is prepared by management of our company with respect to its financial performance for the periods covered by the financial statements, along with an analysis of our financial position and prospects. It should be read in conjunction with our audited annual consolidated financial statements and notes thereto. The financial statements and the financial information herein have been prepared in accordance with generally accepted accounting principles in Canada and are presented in United States dollars. The effect of significant differences between Canadian and United States accounting principles is disclosed in note 24 of the consolidated financial statements. References to “we”, “us”, “our” and “InterOil” refer to InterOil Corporation and its subsidiaries.

Overview

Summary of Results

Our operations are organized into three major business segments:

•   Exploration and Production, our upstream segment, which includes the exploration for and the future production of crude oil and/or natural gas;

•   Refining and Marketing, our midstream segment, which includes the refining of crude oil and the marketing of refined products both domestically and for export; and

•   Wholesales and Retail Distribution, our downstream segment, which includes wholesale and retail distribution of refined products in Papua New Guinea.

The following table sets forth certain selected consolidated data for the past three years:

Selected consolidated data
Year-ended December 31 ($)	2004			2003			2002
Total revenue		71,223,284			259,280			384,226
Sales and Operating Revenues		70,644,486		nil			nil
Cash flows used in operations		(80,230,117	)		(3,519,152	)		(2,348,959	)
Net loss before discontinued operations and extraordinary items		(52,939,881	)		(3,517,569	)		(1,315,887	)
Net loss per share		(2.09	)		(0.16	)		(0.06	)
Net loss per diluted share		(2.09	)		(0.16	)		(0.06	)
Net loss		(52,939,881	)		(3,517,569	)		(1,315,887	)
Net loss per share		(2.09	)		(0.16	)		(0.06	)
Net loss per diluted share		(2.09	)		(0.16	)		(0.06	)
Total assets		385,842,184			260,339,850			135,074,861
Long-term debt		87,472,159			90,600,000			31,000,000
Cash dividends declared per share	nil			nil			nil

We generated our first operational income in 2004 following the acquisition of BP Papua New Guinea Limited, but were not profitable in 2004 as our refinery project remained in the construction and pre-operating stage of development throughout the year. Sales and operating revenues in the year ended December 31, 2004 was confined to sales from the acquired BP entity on products that

InterOil Corporation
Page 2 of 28

were not obtained from the refinery of $44.3 million and a trade out of crude feedstock during refinery commissioning of $26.3 million. The costs of refinery testing and commissioning activities, in addition to crude purchases and revenues generated from both PNG domestic sales and export sales, are included in the capital costs of the refinery until the completion of the performance testing and the issuance of the construction practical completion certificate in January 2005. Increased costs in the year were related to our business development activities and capital raisings, a $35.6 million impairment of our unproved oil and gas properties, and $2.9 million of geophysical and geological activities.

Business Environment

Risk Factors

Our financial results are significantly influenced by our business environment. Risks include, but are not limited to:

We have a limited operating history.

      We are a development stage company, with limited financial results upon which you may judge our potential. We may not become profitable. In the past, we have experienced delays and other problems frequently associated with a construction project such as our refinery. We may continue to experience many of the problems, delays and expenses encountered by any early stage business, many of which are beyond our control. These include, but are not limited to, substantial delays and expenses in conducting our exploration drilling program, difficulty in obtaining financing and competition from larger and more established companies.

Our refinery has not operated at full capacity for an extended period of time.

      We have completed the construction of our refinery in PNG. We began testing our refinery at its approximate nameplate capacity in November 2004. In January 2005, testing of our refinery was completed and we declared practical completion of the refinery. Our ability to continue to operate our refinery at its nameplate capacity must be considered in light of the risks inherent in, and the difficulties, costs, complications and delays frequently encountered by start-up companies. These risks include, without limitation, shortages of equipment, materials or labor; delays in delivery of equipment or materials; contractual disagreements; labor disruptions; political events; local or political opposition; accidents and unforeseen engineering, design or environmental problems. We were unable to operate our refinery for a period of 10 days in March 2005 as a result of a shortage of crude feedstocks. Such shortages may occur in the future as well. Accordingly, there can be no assurance of the future profitability of us or our refinery.

Our refinery operations may not be profitable.

      Our refining operations are expected to be primarily affected by the difference or margin between the sales prices of our refined products and the costs we incur to purchase crude oil and other feedstocks. Historically, refining margins have been volatile, and we expect this volatility will exist in the future. Therefore, we will be subject to the risk that the difference between the cost to us of our crude oil supply and the price at which we can sell our refined products will not be sufficient for the profitable operation of our company and to allow us to service our indebtedness. We cannot control the prices at which our feedstocks will be purchased or at which refined petroleum products can be sold.

InterOil Corporation
Page 3 of 28

We may not be successful in our exploration for oil.

      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. We have drilled one exploration well, suspended the drilling of two exploration wells and one exploration/appraisal well, and have plans to drill at least 8 additional exploration wells in PNG 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 available.

      In addition, our exploration and development plans may be curtailed, delayed or cancelled as a result of lack of adequate capital and other factors, such as weather, compliance with governmental regulations, landowners interference, mechanical difficulties, materials shortages, 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.

Our investments in PNG are subject to political, legal and economic risks.

      Our investments in PNG involve risks typically associated with investments in developing countries, such as uncertain political, economic, legal and tax environments; expropriation and nationalization of assets; the risks of war, expropriation, nationalization, 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 PNG. 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. In addition, we believe that oil exploration and refinery operations are in the long term best interests of PNG 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 PNG 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.

We may not be able to market all of our refinery’s output.

      The Project Agreement described under “Material Contracts” gives us certain rights to supply the domestic market in PNG with our refined products. We have entered into domestic sales contracts with the major distributors in PNG under which they will purchase refined products for distribution in PNG exclusively from us. We have estimated that between 50% and 60% of the refinery’s net output will be used to supply the PNG market. We will market the balance of the

InterOil Corporation
Page 4 of 28

refinery’s output in nearby regional markets. We have signed three-year export contracts with Shell. While we will sell refined products through our domestic retail network and other distributors, these agreements are the only commercial agreements for the purchase of our refined products for export. We can give no assurances that we will be able to market the refinery’s output to these nearby regional markets and we may be unable to market all of the refinery’s output we produce. 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. In addition, early termination of the Shell export agreements could have a material adverse effect on our results of operations and financial condition.

      Further, our Project Agreement with the PNG government provides that if there is more than one refinery operating in PNG 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 PNG, our share of the domestic market will be diminished.

We may not be able to obtain crude feedstocks for our refinery.

      The Project Agreement requires the government of PNG to take action to ensure that domestic crude oil producers sell us their PNG domestic crude production for use in our refinery and that refined products for domestic PNG use will be purchased from us at the IPP. 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.

      PNG crude oil production rates are expected to satisfy the refinery’s requirements for at least five years after commercial start-up. Alternative crude oils that are suitable for use as refinery feedstock are available in the nearby region. However, crude oil sourced from outside PNG may be more expensive than domestic crude oil and may reduce our gross profit margins. Alternatively, imported crude oil may be selected to alter the refinery product mix in response to changing market conditions.

We may not be able to obtain all of the licenses necessary to operate our business.

      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, or will hold, all necessary licenses and permits under applicable laws and regulations for our operations in PNG 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 commission our oil refinery facilities or to maintain continued operations that economically justify the cost.

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

      Our refining operations will be subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards and uncontrollable flows of oil and gas. 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

InterOil Corporation
Page 5 of 28

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.

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

      We operate in the highly competitive areas of oil exploration and production, and 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, the availability of alternate fuel sources, the costs of our drilling program, the development of transportation systems to bring future production to the market and transportation costs of oil are factors that affect our ability to compete in the marketplace. Many of our competitors operate in areas where they are able to sell both the oil and the natural gas that they produce.

      In our refining business, we will compete with numerous other 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 PNG reduces the availability of alternate fuel sources and retail outlets for our refined products. Competitors that have their own production or extensive distribution networks are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, new technology is making refining more efficient, which could lead to lower prices and reduced margins.

The volatility of oil prices could adversely affect our results of operations.

      The prices we will receive for the refined products we produce and sell are likely 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, 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. The prices for oil will affect:

•   our revenues, cash flows and earnings;

•   our ability to attract capital to finance our operations, and the cost of such capital;

•   the value of our oil properties;

•   the profit or loss we incur in refining petroleum products; and

•   the profit or loss we incur in exploring and developing our reserves.

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, 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

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damage and suspension of operations. Our PNG operations are subject to a variety of additional operating risks such as earthquakes, mudslides, tsunamis 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. 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.

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 the United States. It may be difficult for investors to enforce, outside the United States, judgments against us that are obtained in the United States in any such actions, including actions predicated upon the civil liability provisions of the securities laws of the United States. In addition, most of our directors and officers are nationals or residents of countries outside of the United States, and all, or a substantial portion of, the assets of such persons are located outside the United States. As a result, it may be difficult for investors to affect service of process within the United States upon such persons or to enforce judgments against them obtained in United States courts, including judgments predicated upon the civil liability provisions of the securities laws of the United States.

We may not be able to generate cash flows if we are unable to raise capital.

      We make, and will continue to make, substantial capital expenditures for exploration, development, acquisition and production of oil reserves 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 have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

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

      As of December 31, 2004, we had $87 million in long-term debt, excluding current maturities. The level of our indebtedness will have important effects on our future operations, including:

•   a portion of our cash flow will be used to pay interest and principal on our debt and will not be available for other purposes;

•   our OPIC credit facility and BNP credit facility contain financial tests which we must satisfy in order to avoid a default under such credit facilities; and

•   our ability to obtain additional financing for capital expenditures and other purposes may be limited.

If we are unable to recruit and retain qualified personnel, it could 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

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personnel, to accommodate our exploration plans and to 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 (“P.I.E.”) can affect our raising of capital through the issuance of common shares or securities convertible into common shares.

      Mr. Phil E Mulacek, President and CEO of our company, controls P.I.E. P.I.E owns 433,169 of our common shares, and has a right to exchange its remaining 5,000 shares of SP 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 P.I.E. Mr. Mulacek through P.I.E. also controls 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 P.I.E. 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.

Changing regulation of corporate governance and public disclosure can 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. As a result, 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. Any failure to comply with applicable laws may materially adversely affect our reputation and the value of our securities.

If we fail to comply with Section 404 of the Sarbanes-Oxley Act of 2002, our reputation and the value of our securities may be adversely affected.

      Beginning with our annual report for the year ending December 31, 2006, 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 is in the process of adopting 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 Section 404, including issuing the required management report and obtaining

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the attestation report on management’s assessment from our independent auditors, may materially adversely affect our reputation and the value of our securities.

Forward-looking statements

Certain statements contained in this report are forward-looking statements as defined in the U.S. federal securities laws. All statements, other than statements of historical facts, included herein or incorporated by reference herein, including without limitation, statements regarding our drilling plans, business strategy, plans and objectives of management for future operations and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates” or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that such forward-looking statements will prove to be correct.

Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from any results expressed or implied by our forward-looking statements. Risks and uncertainties include, but are not limited to:

•   our lack of substantial operating history;

•   the operation of our refinery at less than full capacity;

•   refinery and additional construction costs;

•   profitability of our refinery;

•   our ability to market refinery output;

•   the success of our exploration prospects;

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

•   anticipated markets for our refined products;

•   dependence on exclusive relationships with our supplier and customers;

•   ability to obtain necessary licenses;

•   uninsured risks;

•   the impact of competition;

•   the enforceability of legal rights;

•   the volatility of oil prices;

•   weather and unforeseen operating hazards;

•   debt covenants limiting ability to raise additional financing;

•   the cyclical nature of the refining business; and

•   other factors.

Important factors that could cause the actual results to differ from materially from our expectations are disclosed in more detail set forth under the heading “Risk Factors” in herein. Our forward-looking statements are expressly qualified in their entirety by this cautionary statement.

We currently have no reserves as defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). All information contained herein regarding resources are references to undiscovered resources under NI 51-101, whether stated or not. See our filings with the Canadian securities regulators for additional risks and information about our business.

Business Plan

Our goal continues to be the development of a vertically-integrated energy company whose focus is PNG and the surrounding region. Our strategy is to continue oil and gas exploration in PNG, operation and marketing of refined product from our oil refinery, and the wholesale and retail

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distribution of refined petroleum products in PNG. Our most significant activity in this regard during 2004 was related to our acquisition of BP Papua New Guinea Limited on April, 28, 2004. This acquisition commenced our direct participation in the PNG refined product distribution business.

Results of Operations

Upstream

2004 compared with 2003

Our net loss from the upstream segment increased by $39.4 million to $40.1 million in 2004 from $0.70 million in 2003.

The following table sets forth the results for our upstream segment for the years ended December 31, 2004, 2003, and 2002:

Upstream
Year-ended December 31 ($thousands)	2004			2003			2002
Operating results
External sales		—			—			—
Inter-segment revenue		—			—			—
Total segment revenue		0			0			0
Cost of sales and operating expenses		—			—			—
Office and administration and other expenses		1,649			520			(216	)
Geological and geophysical expenses		2,903			—			—
Depreciation and amortization		13			10			—
Exploration write off		35,567			165			93
Interest expense		5			—			—
Loss from ordinary activities before income taxes		(40,137	)		(696	)		123
Income tax expenses		—			—			—
Total net income (loss)		(40,137	)		(696	)		123

Revenues

We have not discovered any oil and gas reserves that are deemed to be proved, probable or possible and therefore we have not generated operational revenues from the upstream operations.

Expenses

Total expenses from our upstream segment were $40.1 million in 2004 compared with $0.7 million in 2003. Our 2004 expenses are primarily related to our geological and geophysical activities and to adjustments related to the impairment of our oil and gas properties.

Geological and geophysical expenses in the year ended December 31, 2004 were on our Puri, Elk, and Moose Prospects.

We follow the successful efforts method of accounting for oil and gas exploration and development activities, and in accordance with the capitalization requirements of this policy have expensed $35.6 million in 2004 compared to $0.17 million in 2003. The 2004 adjustments were mainly related to capitalized drilling expenditures on Moose — 1, on Moose — 2 and on Sterling Mustang — 1. Based on the Statement of Financial Accounting Standards No. 19, in compliance with US

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GAAP, it was necessary to expense these drilling expenditures that were previously capitalized as the recent activity on these prospects has been geological and geophysical in nature whilst waiting the arrival of new drilling equipment. The passage of time in recommencing drilling activities, and not having a definite plan for recommencing drilling of the suspended wells at December 31, 2004 has triggered the expensing requirement. In addition, in 2004, oil and gas costs previously capitalized on Petroleum Retention License’s 4 and 5 have been expensed due to the lack of commercial gas contracts and no immediate development plans for these licenses.

Midstream

2004 compared with 2003

Our net loss from the midstream segment increased by $5.4 million to $5.7 million in 2004 from $0.23 million in 2003.

The following table sets forth the results for our midstream segment for the years ending December 31, 2004, 2003, and 2002:

Midstream
Year-ended December 31 ($thousands)	2004			2003			2002
Operating results
External sales		26,310			—			—
Inter-segment revenue		—			—			—
Total segment revenue		26,310			0			0
Cost of sales and operating expenses		27,686			—			—
Office and administration and other expenses		3,133			222			(124	)
Depreciation and amortization		312			8			—
Interest expense		844			—			—
Loss from ordinary activities before income taxes		(5,665	)		(230	)		124
Income tax expenses		—			—			—
Total net income (loss)		(5,665	)		(230	)		124

Revenues

Throughout the year we were in the construction and pre-operating stage of the development of our oil refinery. Project costs, net of any recoveries generated through the sale of refined products, incurred during this construction and pre-operating stage were capitalized as plant and equipment. The $26.3 million of external sales was generated from a trade out of a crude cargo during commissioning.

Our refinery completed its reliability testing on January 6, 2005 and we issued the refinery’s practical completion certificate on January 31, 2005.

Expenses

Total expenses from our midstream segment were $32.0 million in 2004 compared with $0.2 million in 2003. Our 2004 cost of sales and operating expenses of $27.7 million was related to the crude cargo trade out in the year. The majority of the other expenses in the 2004 year are primarily related to the financing costs on the crude feedstock supplied to the refinery during the commissioning process. While the cost of crude feedstock is capitalized to the refinery in the year ended December 31, 2004, the associated financing costs are expensed as incurred.

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Downstream

2004 compared with 2003

Our downstream earnings increased to $3.7 million in 2004 from a loss of $0.02 million in 2003.

On April 28, 2004 through our wholly owned subsidiary, SPI Distribution Limited, we 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.

The following table sets forth the results for our downstream segment for the years ended December 31, 2004, 2003, and 2002:

Downstream
Year-ended December 31 ($thousands)	2004			2003			2002
Operating results
External sales		62,410			—			—
Inter-segment revenue		489			—			—
Total segment revenue		62,899			0			0
Cost of sales and operating expenses		53,159			—			—
Office and administration and other expenses		3,147			25			3
Depreciation and amortization		224			—			—
Interest expense		455			—			—
Loss from ordinary activities before income taxes		5,914			(25	)		(3	)
Income tax expenses		(2,251	)		—			—
Total net income (loss)		3,663			(25	)		(3	)

Revenues

Our increase in sales and operating revenue over 2003 is a result of the operations of InterOil Products Limited, a subsidiary we purchased during the year. IPL sold the following volumes of product since InterOil gained control of the subsidiary:

Sales volumes (liters)	May 1, 2004 thru December 31, 2004
Diesel		91,909,146
Fuel Oil		26,487,621
Gasoline		13,886,660
DPK		9,103,003
Lubricants		1,122,786
Total		142,509,216

Following the confirmation of our midstream business refinery having refined products available for the PNG market, the Papua New Guinea Independent Consumer & Competition Committee (“ICCC”) introduced on September 8, 2004 a new pricing regime in the downstream sector over three petroleum products (diesel, gasoline and kerosene). This new pricing regime establishes a maximum wholesale margin of 24 toea per liter (previously 30 to 50 toea per liter), and includes

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components to capture both sea and land freights. As this new pricing template impacts the entire Papua New Guinea distribution business, IPL’s sales from September 8, 2004 forward have been impacted.

Expenses

The increase in expenses over 2003 is a result of the operations of InterOil Products Limited, a subsidiary purchased in the year. The cost of sales and operating expenses is derived from either importing or purchasing products from our refinery for wholesale distribution in PNG. In August 2004 our distribution subsidiary, IPL, started purchasing products from our refinery at the import parity price. By December 31, 2004 our refinery was supplying 100% of IPL’s diesel, gasoline and DPK requirements. IPL will continue to import its fuel oil and lubricant products as these products are not produced by our refinery.

Corporate and consolidation

Year-ended December 31 ($thousands)	2004			2003			2002
External sales — elimination (1)		(18,075	)		—			—
Inter-segment revenue elimination (2)		(489	)		—			—
Interest revenue		382			247			373
Other unallocated revenue		196			12			11
Total segment revenue		(17,986	)		259			384
Cost of sales and operating expenses (1)		(15,500	)		—			—
Office and administration and other expenses		6,773			2,651			1,862
Depreciation and amortization		90			55			85
Interest expense		1,899			105			—
Loss from ordinary activities before income taxes		(11,248	)		(2,552	)		(1,563	)
Income tax expenses		376			(37	)		(1	)
Other unallocated expenses		70			22			5
Total net income (loss)		(10,802	)		(2,567	)		(1,559	)

Notes

(1) In 2004 the InterOil refinery project was considered to be in the construction and pre-operating stage of development. Therefore all associated sales of refined products during the commissioning of the refinery to downstream subsidiaries has been reversed out of the Statement of Operations upon consolidation and has been capitalized as plant and equipment to the refinery project.

(2) Elimination upon consolidation of downstream sales of start —up fuels to the refinery.

Expenses

Our total corporate office and administration and other expenses were $6.8 million in 2004 compared to $2.6 million in 2003. The $4.2 million increase was due to:

•   increase in legal and professional services related to the Toronto Stock Exchange and the American Stock Exchange listings, and financing activities;

•   stock based compensation recorded in 2004 (refer to the section “New Accounting Standards”);

•   higher administrative expenses; and

•   the difference attributable to a one-time adjustment in 2003 where P.I.E. Corporation, a related party, waived prior years’ management fees totaling $840,000 that had previously been accrued.

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Consolidated income taxes

The consolidated 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 December 31, 2004, 2003 and 2002 were accounted for as follows:

Income tax
Year-ended December 31 ($)	2004			2003			2002
Loss before income taxes		(51,134,909	)		(3,503,131	)		(1,319,824	)
Statutory income tax rate		35.12	%		35.12	%		38.62	%
Expected income tax (benefit)		(17,958,580	)		(1,230,300	)		(509,716	)
Effect on income tax of:
Losses (profits) in foreign jurisdictions not deductible (taxable)		2,273,530			(56,527	)		(183,802	)
Non-deductible stock compensation expense		424,924			(13,926	)		236,431
Gains and losses on foreign exchange		58,659			302,499			—
Tax rate differential in foreign jurisdictions		(341,613	)		143,502			188,788
Over provision in prior year		(42,874	)		—			(332	)
Tax losses for which no future tax benefit has been brought to account		2,696,330			836,142			346,526
Temporary differences for which no future tax benefit has been brought to account		14,552,726			—			158,204
Temporary difference brought to account on acquisition of subsidiary		(488,027	)		—			—
Other — net		699,988			55,949			(234,653	)
Income tax expense		1,875,063			37,339			1,446

Quarterly Financial Summary

The following table summarizes financial information for each quarter of 2004 and 2003:

Quarters ended	2004												2003
	31-Dec			30-Sep (1)			30-Jun			31-Mar			31-Dec			30-Sep			30-Jun			31-Mar
Total Revenue		22,151,046			36,226,109			12,690,533			155,596			203,964			13,349			27,717			14,250
Net Income (Loss) before discontinued operations and extraordinary items		(43,855,413	)		(4,917,262	)		(2,522,279	)		(1,644,927	)		(1,489,036	)		(1,510,516	)		(1,204,678	)		686,659
Net Income (Loss) per share		(1.73	)		(0.19	)		(0.10	)		(0.07	)		(0.07	)		(0.07	)		(0.05	)		0.03
Diluted Income (Loss) per share		(1.73	)		(0.19	)		(0.10	)		(0.07	)		(0.07	)		(0.07	)		(0.05	)		0.03
Net Income (Loss)		(43,855,413	)		(4,917,262	)		(2,522,279	)		(1,644,927	)		(1,489,036	)		(1,510,516	)		(1,204,678	)		686,659
Net Income (Loss) per share		(1.73	)		(0.19	)		(0.10	)		(0.07	)		(0.07	)		(0.07	)		(0.05	)		0.03
Diluted Net Income (Loss) per share		(1.73	)		(0.19	)		(0.10	)		(0.07	)		(0.07	)		(0.07	)		(0.05	)		0.03

Notes

(1)   It was identified in the fourth quarter 2004 that the statement of operations for the quarter ending September 30, 2004 included sales and cost of sales of our refined products sold by InterOil downstream subsidiaries during the commissioning of the refinery and this activity was adjusted to plant and equipment in the fourth quarter 2004. For comparative purposes the September 30, 2004 amounts in the table include subsequent period adjustments

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of revenue ($11,336,839) and cost of sales ($9,397,373). The net impact of these adjustments has increased the net loss by $1,939,466.

Revenue

•   September 30, 2004 to December 31, 2004 — IPL revenue on refined products was not produced at our refinery. Refinery remains in the construction and development stage.

•   June 30, 2004 to September 30, 2004 — increase in revenue related to $26.3 million of external sales was generated from a trade out of a crude cargo during refinery commissioning.

•   March 31, 2004 to June 30, 2004 — increase in revenue generated from acquisition of lPL on April 28, 2004. Refinery remains in the construction and development stage.

•   January 1, 2003 to March 31, 2004 — revenue per quarter is primarily interest on investments as the company remains in the construction and development stage.

Expenses

•   September 30, 2004 to December 31, 2004 — A $35.6 million expense of oil and gas exploration and development activities that were previously capitalized. An increase in legal and professional expenses related to the American Stock Exchange listing and the convertible debenture transaction.

•   June 30, 2004 to September 30, 2004 — increase in cost of sales and operating expenses of revenue relate to $27.7 million from a trade out of a crude cargo during refinery commissioning. Increase in legal and professional expenses associated with the Toronto Stock Exchange listing.

•   March 31, 2004 to June 30, 2004 — increase in cost of sales and operating expenses from the acquisition of lPL on April 28, 2004. A $1.4 million expense of oil and gas exploration and development activities that were previously capitalized.

•   December 31, 2003 to March 31, 2004 — legal and professional fees were incurred relating to 2003 capital raisings that matured in the first quarter of 2004.

•   September 30, 2003 to December 31, 2003 — A $164,992 expense was recorded for oil and gas exploration and development activities that were previously capitalized.

•   March 31, 2003 to June 30, 2003 — there was a foreign currency loss of $252,938 at June 30, 2003 versus a gain of $554,296 at March 31, 2003. The difference is attributable to a one-time adjustment at March 31, 2003 where P.I.E., a related party, waived prior years’ management fees totaling $840,000 that had previously been accrued.

Capital Resources

Operating Activities

In 2004 net cash used by our operating activities was $80.2 million, compared to $3.5 million recorded in 2003. The positive operational cash flows derived from our acquisition of InterOil Products Limited on April 28, 2004 were insufficient to prevent a consolidated deficit as our refinery project remained in the pre-operating stage throughout the year. Operational cash flows from our refinery commenced in January 2005.

Cash flows from/(used in) operating activities
Year-ended December 31 ($)	2004			2003			2002
Net (loss)		(52,939,881	)		(3,517,569	)		(1,315,887	)
Adjustments for non-cash transactions
Non-controlling interest		(70,091	)		(22,901	)		(5,383	)
Depreciation and amortization		639,075			73,068			85,657
Future income tax benefit		(663,347	)		—			—

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Cash flows from/(used in) operating activities
Year-ended December 31 ($)	2004			2003			2002
Gain on sale of other assets		(94,260	)		—			—
Amortization of discount on debt		604,045			—			—
Amortization of deferred financing costs		268,873			—			—
Debt conversion expense — debentures		77,589			—			—
Management fees for prior periods waived		—			(840,000	)		—
Stock compensation expense		1,209,921			(39,654	)		612,197
Capitalized oil and gas properties expensed		35,566,761			164,992			92,673
Ineffective hedge loss		40,715			—			678,648
Interest expense forfeited by debenture holders		998,438			—			—
Unrealized foreign exchange loss (gain)		392,805			678,774			(1,773,435	)
Change in non-cash working capital
Decrease (increase) in trade receivables		(50,456,671	)		—			—
Decrease (increase) in other assets and prepaid expenses		982,014			220,196			709,782
Decrease (increase) in inventories		(22,666,150	)		—			—
Increase (decrease) in accounts payable, accrued liabilities and income tax payable		5,880,047			(236,058	)		(1,433,211	)
Total		(80,230,117	)		(3,519,152	)		(2,348,959	)

Investing Activities

Cash used in investing activities amounted to $23.8 million in 2004, a decrease of $97.0 million from the $120.8 million in 2003.

Cash flows used in investing activities
Year-ended December 31 ($)	2004			2003			2002
Expenditure on oil and gas properties		(19,154,106	)		(19,987,946	)		(875,105	)
Expenditure on plant and equipment		(38,484,704	)		(81,843,608	)		(42,372,277	)
Proceeds on sale of other assets		405,353			—			—
Redemption of short term investments		24,723,572			(17,617,871	)		9,894,299
Acquisition of InterOil Products Limited, net of cash received		4,631,904			—			—
Increase (decrease) in accounts payable and accrued liabilities		4,094,594			(1,351,521	)		4,749,199
Total		(23,783,387	)		(120,800,946	)		(28,603,884	)

Upstream Capital Expenditures

During 2004, our capital expenditures for exploration and development in Papua New Guinea totaled $19.2 million compared with $20.0 million during 2003.

We spudded our second exploration well on the Moose structure, Moose — 2 in late 2003. Results from this well confirmed the oil shows and fractured limestone reservoir we identified in Moose — 1, which we believe demonstrates the lateral extent of the potential limestone resource. Moose — 2 is located 2.5 miles (4 kilometers) to the southeast of Moose — 1. Difficult drilling conditions resulted in the primary target sandstones not being penetrated. The palynological dating indicates that the shales are equivalent in age to the Pale Sandstone. Since this shale unit was not completely penetrated the presence or absence of the Pale Sandstone remains conjectural and the presence of the Subu Sandstone untested. After a review of results it was decided that our next step in appraising the structure was to acquire 2D seismic data. In September 2004, we completed a seismic program across the Moose and adjacent structures as a further step in the full appraisal of the prospect and to delineate the primary target sandstones.

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We spudded our third exploration well and the first on the Sterling Mustang structure in January 2004. This well was drilled to 9,704 feet (2,958 meters) but did not encounter the planned targets before the rig hit depth and pressure limits. A seismic program is planned over this prospect for 2005.

Midstream Capital Expenditures

Our refinery is our primary asset and is centrally located across the harbor from Port Moresby, the capital city of Papua New Guinea and is 15 miles (24 kilometers) by road and 2.5 miles (4 kilometers) by water from Port Moresby.

Our refinery consists of a nameplate 32,500 barrel per stream day crude distillation unit, a 3,500 barrel per stream day hydro-desulphurization unit, a 3,500 barrel per stream day catalytic reforming unit, two jetties with ship loading and off-loading facilities and a road tanker loading system. Our tank farm has an overall storage capacity approaching 1.9 million barrels. We are also self sufficient with a reverse osmosis desalination unit for water, steam and power generation for electricity, and other site infrastructure and support facilities including laboratory, workshops, an administration building, waste water treatment plant, staff accommodation and a fire station. Our refinery is operated from a central computerized control center.

The third and fourth quarters of 2004 were a major challenge for us as we transformed the refinery through the commissioning process from a construction project to an operational industrial facility in January 2005. Various components of the refinery were progressively put into service. On July 1, 2004, oil was first processed at the refinery. This processing was followed through the commissioning process by the production and sale of refined product. Although the commissioning process was gradual and extended over several months, no major obstacles were encountered, and by year-end 2004 the refinery had processed over 3.3 million barrels of crude, achieved stable operations on all its process units and utility systems, and had operated at throughputs averaging over 30,000 barrels a day during the months of November and December, 2004. During December 2004, our refinery successfully completed its performance test run, operating at the name-plate capacity of 32,500 barrels per day and meeting yield structures and energy utilization as per its design. It also proved its flexibility to process crude other than Kutubu blend. On January 31, 2005, our refinery achieved practical completion. Practical completion means construction of the refinery has been completed and that the refinery has satisfactorily completed the reliability and performance tests which were conducted as part of the acceptance and handover process.

During 2004, capital expenditures for the midstream refinery totaled $40.5 million compared with $81.2 million during 2003. The total capital cost of the refinery at December 31, 2004 was $236.7 million.

Downstream Capital Expenditures

During 2004, capital expenditures for our downstream business were related to the acquisition of InterOil Products Limited. The adjusted purchase price was $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 has been paid. The remaining $12,226,854 (discounted amount $12,123,106) was paid on March 1, 2005 and is included in current liabilities in the financial statements at December 31, 2004.

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

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Estimated fair value	$
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 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.

Financing Activities

Cash generated from financing activities was $114.4 million compared to $130.3 million in 2003.

Cash Flows from Financing Activities
Year-ended December 31 ($)	2004			2003			2002
Proceeds from secured loan (1)		2,000,000			52,000,000			30,240,000
Proceeds from senior convertible debenture (2)		45,000,000			—			—
Senior convertible debenture issuance costs (2)		(3,259,766	)		—			—
Proceeds from indirect participation interest (3)		16,984,852			16,300,000			—
Proceeds from related party borrowings (4)		1,775,565			—			2,900,000
Repayments to related party (4)		(2,198,065	)		(776,902	)		(878,276	)
Proceeds from issue of common shares — stock options (5)		2,020,316			62,822,143			1,312,223
Proceeds from short term borrowing (6)		5,100,000			—			—
Repayments of short term borrowings (6)		(5,100,000	)		—			—
Proceeds from (repayments of) short term working capital facility (7)		76,520,541			—			—
Cash held as security for working capital facility (7)		(24,407,709	)		—			—
Total		114,435,734			130,345,241			33,573,947

Notes

(1)

On June 12, 2001, we entered into a loan agreement with the Overseas Private Investment Corporation (OPIC), an agency of the US Government, to secure a project financing facility of $85,000,000. The remaining balance of $2.0 million was drawndown in 2004, and the facility was fully drawn down at December 31, 2004. The loan is secured over the assets of the refinery project which have a carrying value of $236,683,247 at December 31, 2004 (2003 — $196,409,513, 2002 — $121,035,944).

(2)

On August 28, 2004 and September 4, 2004 we issued a total of $45.0 million 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 of our common shares at a fixed conversion price of US$20.16 per share on December 31, 2004 at the investor’s option. We also issued 180,000 additional shares to debenture holders in connection with their conversion of the debt to equity. As a result of the issuance of the 180,000 additional shares, share capital increased by $6,976,800 which represents the fair market value of the shares on the date they were issued. In connection with these additional shares $77,589 was recognized as a debt conversion expense during the year ended December 31, 2004, and an adjustment to accumulated deficit of $6,899,211. In connection with the issuance of the senior convertible debentures, we issued to the investors five-year warrants to purchase 359,415 common shares at an exercise price equal to US$21.91. All warrants were

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outstanding at December 31, 2004 and were not impacted by the debt conversion. 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 our common shares of 45%, and a weighted average expected life of the warrants of five years.

(3)

On March 2004, we received an additional $3,235,000 from PNG Drilling Ventures Limited (“PNGDV”) relating to PNGDV’s indirect interest in our phase one exploration program within the area governed by Petroleum Prospecting Licenses 236, 237 and 238. This additional receipt brought the total invested by PNGDV in the indirect participation interest to $12,185,000. This interest is subject to the terms of the agreement dated July 21, 2003 between us and PNG Drilling Ventures Limited, under which all or part of the indirect participation interest, up to a maximum of $11,620,000 may be converted to our common shares at a price no less than C$20.85 per common share. Alternatively, an amount up to $1,969,000 of the indirect participation interest may be converted to debt due in December 2005 and December 2006. Should neither of these conversion rights be exercised, the indirect participation in the drilling program will be maintained and distributions will be paid in accordance with the agreements. In January 2004, $75,500 of the PNGDV interest was converted into 5,000 of our common shares and a further $1,500,670 of the interest was converted to 84,545 common shares on September 30, 2004 in accordance with the indirect participation interest agreement. The balance of PNGDV’s indirect participation interest at December 31, 2004 is $10,608,830 (December 31, 2003 — $8,950,000).

	Prior to December 31, 2004, we received deposits of $13,749,852 toward an additional indirect participation interest.
(4)	During the year ended December 31, 2004, Petroleum Independent and Exploration Corporation (P.I.E.) advanced us $1,775,568, which was repaid prior to December 31, 2004. The advance had interest charged at a rate of 6% per annum which was the cost of P.I.E. and included no premium. During the year we incurred total interest to P.I.E. amounting to $246,745 (2003 — $105,374, 2002 — $127,639). P.I.E. is controlled by one of our officers and directors.
(5)	During the year the company received $2,020,316 from the exercise of stock options.
(6)	On June 24, 2004, we entered into a loan agreement with Clarion Finanz AG for $3,000,000. On July 30, 2004 we increased it to $4,500,000. Interest was calculated at 12% per annum compounded daily. The loan was repaid in full on August 31, 2004. On June 29, 2004 we entered into a promissory note for $600,000 with Global Asset Management LLC. The fees related to this promissory note were $67,500. The loan was repaid in full on August 31, 2004.
(7)	During the year ended December 31, 2004, we obtained a working capital credit facility with BNP Paribas (Singapore branch) with a maximum availability of $100,000,000. This financing facility supports our ongoing procurement of crude oil for our refinery and includes related hedging transactions.

Liquidity

Sources of Capital

Upstream

We entered into investment agreements in respect of our ongoing exploration program in Papua New Guinea on February 28, 2005. Under these agreements, certain institutional and accredited investors have agreed to invest $125,000,000 for an aggregate 25% indirect participation interest in an eight well exploration program to be completed by the end of 2006.

Midstream

During the year ended December 31, 2004, we obtained a working capital credit facility with BNP Paribas (Singapore branch) with a maximum availability of $100,000,000. This financing facility supports our ongoing procurement of crude oil for our 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

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monetary receivables. 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 4.36%.

At December 31, 2004, $9,479,459 of the total facility remained available for use.

At December 31, 2004, we had one letter of credit outstanding for $14,000,000. Cash totaling $24,407,709 was being maintained as a security margin for the balance open on the facility. In addition, crude and product inventories of $20,368,957 and receivables of $46,911,393 secured the facility.

Subsequent to December 31, 2004, our refinery completed its reliability testing and we issued the practical completion certificate. With the completion of this event, starting in January 2005 the refinery construction and commissioning came to an end and the refinery commenced full operations.

Downstream

Our downstream working capital and capital programs are funded by cash provided through operating activities. As a result of the new pricing regime introduced in September 2004 (see downstream results of operations above), the expected annual 2005 cash flows in the downstream business will be lower than the annualized cash flows generated in 2004 but will continue to support the ongoing business activities.

Corporate

On January 28, 2005 we obtained a $20 million Term Loan Facility from Clarion Finanz AG of which a tranche of $10 million was received on January 31, 2005 and the balance of $10 million was received on February 25, 2005. The loan has an interest rate equal to 5% per annum payable quarterly in arrears, and includes a 1% arrangement fee of the face amount. The term of the loan is fifteen months from the disbursement dates, and is repayable at any time prior to expiry with no penalty. In addition we have provided to Clarion Finanz AG an irrevocable right to participate in our next equity financing for an amount up to $40 million.

Capital Requirements

Upstream

We are obligated under our agreement with indirect participation holders to drill eight exploration wells. We expect to drill these eight wells through year-end 2006 and we believe that the funding raised from the interest holders, $125 million, is sufficient to meet these obligation.

Midstream

As we completed construction on our refinery and obtained practical completion on January 31, 2005, we see no immediate material specific capital need for 2005. However, we will continue to assess this as we move further into operations and may need to make capital additions.

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Downstream

Under our acquisition agreement of BP Papua New Guinea Limited in 2004, we agreed to finalize payment of the acquisition of $12.2 million in March 2005. This payment was made on March 1, 2005. We are in negotiations with Shell for the acquisition of their wholesale and retail assets in Papua New Guinea and expect to close this acquisition in mid-year 2005 requiring a capital payment of $2.8 million.

Contractual Obligations and Commitments

The following table contains information on payments for contracted obligations we have over the next five years and it should be read in conjunction with our financial statements and the notes thereof.

Payment due by period
			Less than						More than
Contractual obligations	Total		1 year		1 – 3 years		3 – 5 years		5 years
Long-Term Debt Obligations	$	85,000,000	$	9,000,000	$	18,000,000	$	18,000,000	$	40,000,000
Indirect Participation Interests(1)	$	6,885,000	$	3,442,500	$	3,442,500		nil		nil
Acquisition of BP assets in PNG(2)	$	12,226,854	$	12,226,854		nil		nil		nil
BP Services Agreement(3)	$	1,000,000	$	1,000,000		nil		nil		nil
Acquisition of Shell assets in PNG(4)	$	18,000,000	$	2,800,000	$	15,200,000		nil		nil
Purchase Obligations(5)	$	5,000,000	$	1,000,000	$	2,000,000	$	2,000,000		nil
Capital Lease Obligations		nil		nil		nil		nil		nil
Operating Leases	$	300,000	$	300,000		nil		nil		nil
Petroleum Prospecting and Retention License(6)	$	8,233,937		nil	$	8,233,937		nil		nil
Total	$	136,645,791	$	29,769,354	$	46,876,437	$	20,000,000	$	40,000,000

Notes

(1)	The Indirect Participation Interest terms provide for various conversion options. The amount provided is the maximum amount that can be converted to debt and differs to the amount presented in the 31 December 2004 Consolidated Balance Sheet due to conversion requirements into our fully paid common shares.
(2)	The adjusted purchase price was $13,226,854. A down payment of $1,000,000 of the purchase price was paid in 2004.
(3)	Management service agreement with BP.
(4)	The acquisition is expected to take place within 6 months following practical completion of the refinery.
(5)	Arises from management fees payable under the 5 year refinery facilities and management contract.
(6)	Amount necessary for the next 2 years under the work program to maintain our exploration licenses.

Our Material Contracts

Date	Description	Parties
February 25, 2005	Indirect Participation Interest Agreement	InterOil Corporation and the investors signatory thereto
February 25, 2005	Registration Rights Agreement	InterOil Corporation and the investors signatory thereto
July 31, 2004	Purchase and Sale Agreement	InterOil Corporation and Shell Overseas Holdings Limited
March 10, 2004	Share Sale Agreement	InterOil Corporation, SPI Distribution Limited, Gas Tank Nederland B.V. and BP Papua New Guinea Limited
November 9, 2003	Facilities Management Contract	InterOil Limited and Petrofac Niugini Limited

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Date	Description	Parties
March 26, 2002	Engineering Procurement and Construction Contract	InterOil Limited and Clough Niugini Limited
December 21, 2001	Crude Supply Agency and Sales Agreement	EP InterOil, Ltd. and BP Singapore Pte Limited
April 9, 2001	Domestic Sales Agreement	InterOil Limited and Shell Papua New Guinea Limited
March 26, 2001	Export Marketing and Shipping Agreement	EP InterOil, Ltd. and Shell International Eastern Trading Company
February 8, 2001	Agreement for the Sale and Purchase of Naphtha	EP InterOil, Ltd. and Shell International Eastern Trading Company
May 29, 1997	Refinery State Project Agreement	InterOil Limited and EP InterOil, Ltd. and The Independent State of Papua New Guinea

Off Balance Sheet Arrangements

At December 31, 2004 and 2003, we did not have any off balance sheet arrangements, including any relationships with unconsolidated entities or financial partnerships to enhance perceived liquidity.

Share Capital

Our authorized share capital consists of an unlimited number of common shares with no par value. As of December 31, 2004 we had 28,310,884 common shares outstanding with 30,367,689 diluted common shares at March 16, 2005.

Share Capital	Number of shares
Balance, January 1, 2002		20,186,870
Shares issued for cash		399,073
Balance, December 31, 2002		20,585,943
Shares issued for cash		3,817,500
Shares issued for debt		31,240
Shares issued on exercise of options		381,278
Balance, December 31, 2003		24,815,961
Shares issued for debt		3,184,828
Shares issued on exercise of options		310,095
Balance, December 31, 2004		28,310,884
Shares issued on exercise of options (Jan-Mar 15, 2005)		162,709
Shares issued on exercise of warrants (Jan-Mar 15 2005)		19,168
Balance, March 16, 2005		28,492,761
Remaining stock options authorized		1,529,681
Remaining warrants issued		340,247
Other		5,000
Diluted March 16, 2005 (1)		30,367,689

Notes

(1)   In 2003 and 2005, we sold indirect working participation interest in our exploration program. Investors have the right to convert, under certain circumstances, their interest to our common shares. If 100% of the investors choose to convert their interest, we would be required to issue an additional 3,961,639 common shares.

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Transactions with Related Parties

Amounts due to related parties of $1,056,251 (2003 — $1,478,751, 2002 — $2,784,560) represents monies owed to Petroleum Independent and Exploration Corporation (P.I.E.) which acts as a sponsor of the Company’s oil refinery project. P.I.E. is controlled by Phil E Mulacek, an officer and director of InterOil. During the year ended December 31, 2004, $422,500 of the loan to P.I.E. was repaid. The loan charges interest at a rate of 5.75% (2003 — 5.75%, 2002 — 5.75%) per annum. During the year ended December 31, 2004, P.I.E. also advanced us $1,775,565, which was repaid prior to December 31, 2004. The advance had interest charged at a rate of 6% per annum. During the year we incurred total interest to P.I.E. amounting to $246,745 (2003 — $105,374, 2002 — $127,639).

SPI does not have a Board of Directors. Instead, its articles of association provide for the business and affairs of SPI to be managed by a general manager appointed by the shareholders of SPI and its the US sponsor under the OPIC loan. 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, $150,410 (2003 — $150,000, 2002 — $150,000) was expensed for the sponsor’s (P.I.E.) legal, accounting and reporting costs. This amount was included in accounts payable and accrued liabilities at December 31, 2004. During 2003, P.I.E. also waived $840,000 of management fees due to it for prior periods and this was reflected in the Consolidated Statement of Operations.

Breckland Limited provides technical and advisory services to us and/or our subsidiaries on normal commercial terms. This party is related by virtue of common directorships, Roger N Grundy. Amounts paid or payable to Breckland during the year amounted to $120,426 (2003 — $131,250, 2002 - $204,522).

Financial and Derivative Instruments

With the exception of cash and cash equivalents and short term investments, all financial assets are non interest bearing. Cash and cash equivalents earned average interest rates of 1.6% per annum (2003 — 1.5%, 2002 — 3.5%).

Temporary investments
Year-ended December 31 ($)	2004		2003		2002
Cash deposit on working capital facility (1.98%)		24,407,709		—		—
Managed trust (1.5%)		—		24,626,154		—
Pledged deposit (1.6%)		—		97,418		7,105,701
Total		24,407,709		24,723,572		7,105,701

Cash held as deposit on the working capital facility supports our 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 inventories and accounts receivables.

Credit risk is minimized as all cash amounts and certificate 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, short and long term debt and amounts due to related parties approximate fair values due to the short term maturities of these instruments.

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Foreign currency hedge contracts

We had no outstanding foreign currency forward contracts at December 31, 2004 and 2003. At December 31, 2002, we had contracts valued at $62,000,000 to acquire Australian dollar amounts payable pursuant to the refinery construction. These hedging contracts have all matured during 2003. At December 31, 2002, we had an unrealized loss of $4,001,462 resulting from hedge contracts. An unrealized exchange loss of $678,648 was recognized on the balance sheet for contracts in excess of specific commitments at December 31, 2002.

To define a maximum potential amount payable on the outstanding hedge contracts, we acquired Australia dollar put options during the year ended December 31, 2003 for total premiums of $218,430 (2002 — $85,000). The maturity dates and nominal amounts of the put options coincided with the exercise dates and nominal amounts of the outstanding hedge contracts. There were no outstanding put options at December 31, 2003 or December 31, 2004.

At December 31, 2002, as a requirement of the hedging contracts a collateral arrangement was entered into whereby an amount of $7,105,701 was held on deposit and had been pledged in favor of the provider of the hedge and recorded as cash. Funds required to be held on deposit as collateral reduced over time as project expenditure was undertaken and the foreign currency forward contracts were closed out. These amounts had reduced to nil as at December 31, 2003 and December 31, 2004.

Commodity hedge contracts

We use derivative commodity instruments to manage exposure to price volatility on a portion of its refined product. As at December 31, 2004, we had entered into naphtha and crude swap agreements to hedge a portion of the anticipated January and February 2005, sales of naphtha and the purchase of associated crude feedstock. The unrealized gain on hedge contracts deemed to be effective at December 31, 2004 amounted $537,358 (2003 — $nil, 2002 — $nil) and is recognized in the financial statements under deferred hedge gain. A summary of the outstanding hedge contracts is as follows:

		Notional			Price USD
Derivative	Type	Volumes (bbls)		Expiry	per Barrel		Receivable
Naphtha fixed price	Sell		50,000	Jan-05	$	43.90	$	280,000
Naphtha fixed price	Sell		50,000	Feb-05	$	41.00	$	112,500
Crude fixed price	Buy		50,000	Feb-05	$	38.90	$	111,000
TOTAL							$	503,500

Critical Accounting Estimates

(a)   Inventories

Crude oil and refined petroleum products are valued at the lower of cost, on a first-in, first-out basis, or net realizable value. The cost of midstream refined petroleum product consists of raw material, labor, direct overheads and transportation costs. Cost of downstream refined petroleum product includes the cost of the product plus related freight, wharfage and insurance.

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(b)   Revenue recognition

The following particular accounting policies, which significantly affect the measurement of profit 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. Sales between our business segments are eliminated from sales and operating revenues and cost of sales and between the asset for the refinery as all revenues and expenses relating to the refinery have been capitalized for the period to December 31, 2004.

Revenue from downstream operations:

Sales of goods are recognized when we have 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 our policy to sell products with a right of return.

Interest income

Interest income is recognized on a time-proportionate basis using the effective interest method.

(c)   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 likely not be recovered.

(d)   Oil and gas properties

We use 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. 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 on the units-of-production method. Geological and geophysical costs are expensed as incurred.

(e)   Plant and equipment

Refinery assets

Our most significant item of plant and equipment is our oil refinery in Papua New Guinea. In 2004, we were considered to be in the construction and pre-operating stage of development of our oil refinery. Project costs, net of any recoveries, incurred during this pre-operating stage are being capitalized as part of plant and equipment. Administrative and general costs are expensed as incurred. The refinery assets are

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recorded at cost. Development costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Interest costs relating to the construction and pre-operating stage of the development project prior to commencement of commercial operations are capitalized as part of the cost of such plant and equipment. Refinery related assets will be depreciated on a straight line basis over their useful lives, at 4% per annum. Our refinery is built on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097 and does not outline any terms for restoration and closure costs.

Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred. Major turnaround costs will be deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround. No major turnaround costs had been incurred at December 31, 2004.

New Accounting Standards

Stock Based Compensation Plans

In September 2003, the AcSB released CICA section 3870 that revised transitional provisions to these standards to provide the same alternative methods of transition as is provided in the US for voluntary adoption of the fair value based method of accounting. These provisions permit either retroactive (with or without restatement) or prospective application of the recognition provisions to awards not previously accounted for at fair value. Prospective application is available only to enterprises that elect to apply the fair value based method of accounting to that type of award for fiscal years beginning before January 1, 2004. The AcSB has also amended the standards to require that all transactions whereby goods and services are received in exchange for stock-based compensation and other payments result in expenses that should be recognized in financial statements, and that this requirement would be applicable for financial periods beginning on or after January 1, 2004. The standards require that share-based transactions should be measured on a fair value basis. After January 1, 2004 the fair value of stock-based compensation will be recognized as an expense in the financial statements.

In accordance with one of the transitional options permitted under amended Section 3870, we have retroactively applied the fair value based method to all employee stock options granted on or after January 1, 2002, without restatement to prior periods. The effect of retroactively adopting the fair value based method, without restatement, is to increase the opening deficit accumulated during the development stage by $737,650, increase contributed surplus by $645,216 and increase share capital by $92,434.

Asset Retirement Obligations

In March 2003, the AcSB issued CICA section 3110, which harmonizes Canadian GAAP with SFAS No. 143, Accounting for Asset Retirement Obligations. The standards were established for the recognition, measurement and disclosure of liabilities for asset retirement obligations and the associated asset retirement costs. The standards apply to legal obligations associated with the retirement of a tangible long-lived asset that results from acquisition, construction, development or normal operations. The standards require an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and when a reasonable estimate of fair value can be made. The standards describe the fair value of a liability for an asset retirement obligation as the amount at which that liability could be settled in a current transaction between willing parties, that is, other than in a forced or liquidation transaction. An entity is subsequently required to allocate that asset retirement cost to expense using a systematic and rational method

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over the estimated useful life of the related asset. The standards are effective for fiscal years beginning on or after January 1, 2004.

We estimate there are no legal obligations associated with the retirement of the refinery, downstream business or with its normal operations relating to future restoration and closure costs. The refinery is being 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 or closure costs. There are no environmental remediation laws or regulations in PNG, requiring restoration of the land on which we operate.

Inventory Costs

In November 2004, the FASB issued FAS 151, “Inventory Costs” that clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material as they relate to inventory costing. FAS 151 requires these items to be recognized as current period expenses. Additionally, the allocation of fixed production overheads to the cost of inventory should be based on the normal capacity of the production facilities.

Our management is in the process of determining the impact of this change as operations come on-line in 2005.

Accounting For Variable Interest Entities

In January 2003, the FASB issued Financial Interpretation 46, “Accounting for Variable Interest Entities” (“FIN 46”) that requires the consolidation of Variable Interest Entities (“VIEs”). VIEs are entities that have insufficient equity or their equity investors lack one or more of the specified elements that a controlling entity would have. The VIEs are controlled through financial interests that indicate control (referred to as “variable interests”). Variable interests are the rights or obligations that expose the holder of the variable interest to expected losses or expected residual gains of the entity. The holder of the majority of an entity’s variable interests is considered the primary beneficiary of the VIE and is required to consolidate the VIE. In December 2003, the FASB issued FIN 46(R) which superseded FIN 46 and restricts the scope of the definition of entities that would be considered VIEs that require consolidation.

The Canadian Accounting Standards Board issued Accounting Guideline 15, Consolidation of Variable Interest Entity (“Ac-G 15”), which is similar to FIN 46(R). This standard effective is for us beginning January 1, 2005.

We do not believe FIN 46(R) or Ac-G 15 result in the consolidation of any additional entities.

Accounting For Exchanges of Nonmonetary Assets

In December 2004, the FASB issued FAS 153 which deals with the accounting for the exchanges of nonmonetary assets. FAS 153 is an amendment of APB Opinion 29 requires that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. FAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for nonmonetary exchanges of similar productive assets and introduce a broader exception for exchanges of nonmonetary assets that do not have commercial substance. FAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005.

We do not believe that the application of FAS 153 will have a material impact on our financial statements.

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and

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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 by the Securities and Exchange Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report.

There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 the Form 40-F, which is filed with the United States Securities and Exchange Commission at www.sec.gov.

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EX-99.4

Exhibit 4

Consent of Independent Chartered Accountants

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, as Exhibit 4, 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 statement (No.333-120383) on Form F-10 of InterOil Corporation.

KPMG

Sydney, Australia
March 31, 2005

EX-99.5

Exhibit 5

Certifications

I, Phil E. Mulacek certify that:

1.	I have reviewed this annual report on Form 40-F of InterOil Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) 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 the 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 officers 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 issuer’s board of directors (or persons performing the equivalent function(s)):

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.

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chairman of the Board, Chief Executive Officer and President 

Date: March 31, 2005

EX-99.6

Exhibit 6

Certifications

I, Tom S. Donovan certify that:

1.	I have reviewed this annual report on Form 40-F of InterOil Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) 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 the 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 officers 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 issuer’s board of directors (or persons performing the equivalent functions):

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.

/s/ Tom S. Donovan  

Tom S. Donovan 

Chief Financial Officer 

Date: March 31, 2005

EX-99.7

Exhibit 7

Certification required by Rule 13a-14(b) or Rule 15d-14(b)
of the Securities Exchange Act of 1934 and
Section 1350 of Chapter 63 of Title 18 of the United States Code

In connection with the report of InterOil Corporation (the “Company”) on the Form 40-F for the fiscal year ended December 31, 2004 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 the 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.

/s/ Phil E. Mulacek  

Phil E. Mulacek 

Chairman of the Board, Chief Executive Officer and President 

Date: March 31, 2005

EX-99.8

Exhibit 8

Certification required by Rule 13a-14(b) or Rule 15d-14(b)
of the Securities Exchange Act of 1934 and
Section 1350 of Chapter 63 of Title 18 of the United States Code

In connection with the report of InterOil Corporation (the “Company”) on the Form 40-F for the fiscal year ended December 31, 2004 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Tom S. Donovan, 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 the 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.

/s/ Tom S. Donovan  

Tom S. Donovan 

Chief Financial Officer 

Date: March 31, 2005