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

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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

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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.

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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

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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

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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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