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InterOil Corporation Year Ended 2005

Management’s Discussion and Analysis

March 31, 2006


Overview			2
Summary of Annual Results			2
Business Environment			4
Risk Factors			4
Forward-looking statements			4
Results of Operations			5
Upstream—Exploration and Production			6
Midstream—Refining and Marketing			7
Downstream—Wholesale and Retail Distribution			14
Corporate and Consolidation			15
Summary of Quarterly Results			17
Non-GAAP Measures			19
Capital Resources			20
Operating Activities			20
Investing Activities			20
Financing Activities			21
Upstream Capital Expenditure			21
Midstream Capital Expenditures			21
Downstream Capital Expenditures			21
Liquidity			22
Sources of Capital			22
Capital Requirements			23
Contractual Obligations and Commitments			24
Off-Balance Sheet Arrangements			24
Transactions with Related Parties			24
Share Capital			25
Financial and Derivative Instruments			26
Foreign Currency Hedge Contracts			26
Commodity Hedge Contracts			26
Critical Accounting Estimates			27
New Accounting Standards			29
Pending Accounting Standards			29
Public Securities Filings			29


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March 31, 2006
Management’s Discussion and Analysis

The following Management’s Discussion and Analysis (MD&A), dated March 31, 2006, was prepared by the management of InterOil with respect to our financial performance for the periods covered by the related audited annual financial statements, along with a detailed analysis of our financial position and prospects. The information in this MD&A was approved by our Audit Committee on behalf of our Board of Directors on March 31, 2006 and incorporates all relevant considerations to that date. This MD&A should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2005. Our financial statements and the financial information contained in the MD&A have been prepared in accordance with generally accepted accounting principles in Canada and are presented in United States dollars. References to “we,” “us,” “our,” and “InterOil” refer to InterOil Corporation and its subsidiaries.

Overview

Our goal continues to be the development of a vertically-integrated energy company whose focus is on operations in Papua New Guinea and the surrounding region. Our strategy is to continue conducting oil and gas exploration operations in Papua New Guinea, operating our refinery and marketing the refined products it produces, and operating our wholesale and retail distribution business for refined petroleum products in Papua New Guinea. Our operations are organized into three major business segments:

	•		Exploration and Production. Our upstream business segment explores for oil and natural gas in Papua New Guinea.

	•		Refining and Marketing. Our midstream business segment operates our refinery in Papua New Guinea and markets the refined products it produces both domestically in Papua New Guinea and for export.

	•		Wholesale and Retail Distribution. Our downstream business segment is engaged in the wholesale and retail distribution of refined products in Papua New Guinea.

Summary of Annual Results

The following table summarizes selected consolidated information for the years ended December 31, 2005, 2004 and 2003:


Summary Annual Results	Years ended December 31,
($ thousands)	2005			2004			2003
Total revenue		483,540			71,223			259
Sales and operating revenues		481,181			70,644			—
Cash flows used in operations		(22,713	)		(79,767	)		(3,519	)
Net loss (1)		(39,282	)		(52,940	)		(3,518	)
Net loss per share		(1.36	)		(2.09	)		(0.16	)
Net loss per diluted share		(1.36	)		(2.09	)		(0.16	)
Total assets		429,557			385,842			260,340
Long term debt		112,273			87,472			90,600
Cash dividends declared per share		—			—			—


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In February 2005, we raised $125 million pursuant to an indirect participation interest agreement whereby the investors have the right to a 25% working interest in any discoveries made in connection with the eight wells to be drilled under this agreement. The amounts acquired under this agreement are being used to fund an eight well exploration program in Papua New Guinea. We drilled the first two exploration wells under this program during 2005 and plan to drill the remaining six wells we are obligated to drill under the indirect participation interest agreement before year-end 2007. Our first two exploration wells under this new program were unsuccessful, but we believe that the extensive seismic acquisition and airborne gravity and magnetic surveys conducted during 2005 and being continued into 2006 will lead to enhanced prospect selection. In February 2006, we began drilling our third exploration well under this exploration program, Elk-1. This well will be the first well drilled using our new purpose built heli-portable drilling rig. We believe that owning our own rig will protect us from cost overruns in a market where drilling rig costs are increasing.

Business Environment

Risk Factors

Our financial results are significantly influenced by the business environment in which we operate. A summary of the various risks can be found under the heading “Risk Factors” in our 2005 Annual Information Form dated March 31, 2006 available at www.sedar.com.

Forward-looking statements

This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. All statements, other than statements of historical fact, included in or incorporated by reference in this MD&A are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our plans for expanding our business segments, business strategy, plans and objectives for future operations, future capital and other expenditures, and those statements preceded by, followed by or that otherwise include the words “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,” “estimates” or similar expressions or variations on such expressions. Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors that could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties include, but are not limited to:

	•		our lack of a substantial operating history;

	•		the ability of our refinery to operate at full capacity and to operate profitability;

	•		our ability to market refinery output;

	•		uncertainty involving the geology of oil and gas deposits and reserve estimates;

	•		the results of our exploration program and our ability to transport crude oil and natural gas to markets;

	•		delays and changes in plans with respect to exploration or development projects or capital expenditures;

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

	•		our dependence on exclusive relationships with our suppliers and customers;

	•		our ability to obtain necessary licenses, permits and other approvals;

	•		the impact of competition;

	•		the enforceability of your legal rights;

	•		the volatility of prices for crude oil and refined products, and the volatility of the difference between our purchase price for oil feedstocks and the sales price of our refined products;

	•		adverse weather, explosions, fires, natural disasters and other operating risks and hazards, some of which may not be insured;

	•		the uncertainty of our ability to attract capital;

	•		covenants in our financing and other agreements that may limit our ability to engage in business activities, raise additional financing or respond to changes in markets or competition; and

	•		the risks described under the heading “Risk Factors” in our 2005 Annual Information Form dated March 31, 2006.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this MD&A will prove to be accurate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in our 2005 Annual Information Form dated March 31, 2006 and elsewhere in this MD&A. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise. In making these statements, we disclaim any obligation to address or update each factor in future filings with Canadian securities regulatory authorities or the U.S. Securities and Exchange Commission, or communications regarding our business or results, and we do not undertake to address how any of these factors may have caused changes to discussions or information contained in previous filings or communications. In addition, any of the matters discussed above may have affected our past results and may affect future results so that our actual results may differ materially from those expressed in this MD&A and in prior or subsequent communications.

Our forward-looking statements are expressly qualified in their entirety by this cautionary statement.


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

Results of Operations


Summary Annual Results	Years ended December 31,
($ thousands)	2005			2004			2003
Total revenue		483,540			71,223			259
Upstream		—			—			—
Midstream		436,421			26,310			—
Downstream		124,860			62,899			—
Corporate & Consolidated		(77,741	)		(17,986	)		259
Cost of sales and operating expenses		467,247			65,345			—
Upstream		—			—			—
Midstream		436,491			27,686			—
Downstream		110,857			53,159			—
Corporate & Consolidated		(80,101	)		(15,500	)		—
Revenue less cost of sales and operating expenses		16,293			5,878			259
Upstream		—			—			—
Midstream		(70	)		(1,376	)		—
Downstream		14,003			9,740			—
Corporate & Consolidated		2,360			(2,486	)		259
Office and administration and other expenses		23,296			14,701			3,420
Upstream		1,738			1,649			521
Midstream		10,639			3,133			222
Downstream		4,726			3,147			25
Corporate & Consolidated		6,193			6,772			2,652
Exploration costs (impairment and accretion expense)		7,791			38,470			165
Earnings before interest, taxes, depreciation and amortization (unaudited) (1)		(14,794	)		(47,293	)		(3,326	)
Upstream		(9,530	)		(40,119	)		(686	)
Midstream		(10,708	)		(4,509	)		(222	)
Downstream		9,278			6,593			(25	)
Corporate & Consolidated		(3,834	)		(9,258	)		(2,393	)
Interest expense		10,987			3,203			105
Upstream		—			5			—
Midstream		10,162			844			—
Downstream		225			455			—
Corporate & Consolidated		600			1,899			105
Income taxes & non-controlling interest		2,464			1,805			14
Upstream		—			—			—
Midstream		—			—			—
Downstream		2,756			1,900			—
Corporate & Consolidated		(292	)		(95	)		14
Depreciation & amortization		11,037			639			73
Upstream		314			13			10
Midstream		10,598			312			8
Downstream		205			224			—
Corporate & Consolidated		(80	)		90			55
Net income/(loss) per segment		(39,282	)		(52,940	)		(3,518	)
Upstream		(9,844	)		(40,137	)		(696	)
Midstream		(31,468	)		(5,665	)		(230	)
Downstream		6,092			4,014			(25	)
Corporate & Consolidated		(4,062	)		(11,152	)		(2,567	)
Net loss per share		(1.36	)		(2.09	)		(0.16	)
Net loss per diluted share		(1.36	)		(2.09	)		(0.16	)
Total assets		429,557			385,842			260,340
Long term debt		112,273			87,472			90,600


(1)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. For a reconciliation of net income (loss), a Canadian generally accepted accounting principles measure, to EBITDA, a non-GAAP measure, see “Non-GAAP Measures.”


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Upstream—Exploration and Production

Year Ended December 31, 2005 compared to Year Ended December 31, 2004

Our exploration and production business segment recognized a loss of $9.8 million for the year ended December 31, 2005 compared to a loss of $40.1 million for the year ended December 31, 2004. The primary reason for the reduction in losses during 2005 was the treatment of exploration and production costs incurred under our $125 million indirect participation interest agreement which is described below.

The following table shows the results for our exploration and production business segment for the years ended December 31, 2005 and 2004:


Upstream — Operating results	Years ended December 31,
($ thousands)	2005			2004
External sales		—			—
Inter-segment revenue		—			—
Total segment revenue		—			—
Cost of sales and operating expenses		—			—
Office and administration and other expenses		1,738			1,649
Geological and geophysical expenses		—			2,903
Depreciation and amortization		314			13
Exploration impairment		2,144			35,567
Accretion expense		5,647			—
Interest expense		—			5

Loss from ordinary activities before income taxes		(9,844	)		(40,137	)

Income tax expenses		—			—
Total net loss		(9,844	)		(40,137	)

Revenues

As of December 31, 2005, we have not discovered any oil or gas reserves that are deemed to be proved, probable or possible and; therefore, we have not generated any operational revenues from our upstream business segment.

Expenses

During 2005, all exploration costs incurred as a result of obligations under our $125 million indirect participation interest agreement were paid for by our indirect participation investors and have therefore not been recognized as expenses. During 2005, $11.0 million in geological and geophysical costs, $20.8 million in drilling costs, and $6.4 million in finance and transaction costs were incurred.

Expenses decreased to $9.8 million for the twelve months ended December 31, 2005 from $40.1 million during the same period in 2004. The majority of this decrease is a result of $38.2 million in expenses being credited against the indirect participation interest liability rather than being recognized as an expense as discussed above. We incurred $5.6 million in accretion expense related to the amortization of the discount calculated on the non-financial liability component of the indirect participation interest during 2005. During the year ended December 31, 2004, we recognized $35.6 million in expenses for unsuccessful exploration wells and $2.9 million in geological and geophysical expenses.

Depreciation expense for the year ended December 31, 2005 increased compared to 2004 due to the acquisition of our drilling rig and the completion of our exploration and production offices and warehouse facilities adjacent to our refinery. Depreciation of these new assets commenced during the fourth quarter of 2005.


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Midstream—Refining and Marketing

Year Ended December 31, 2005 compared to Year Ended December 31, 2004

Our refinery commenced operations in the first quarter of 2005. For the year ended December 31, 2005, the operations start-up year of our refinery, our refining and marketing business segment recognized a loss of $31.5 million compared with a loss of $5.7 million for the year ended December 31, 2004. Prior to January 2005, we were still constructing and commissioning our refinery. The costs associated with the construction and commissioning of our refinery were capitalized rather than expensed. As a result of our refinery not having any operations in 2004, our 2004 and 2005 operating results are not comparable.

The following table shows the results for our refining and marketing business segment for the years ended December 31, 2005 and 2004:


Midstream — Operating results	Years ended December 31,
($ thousands)	2005			2004
External sales		356,327			26,310
Inter-segment revenue		80,094			—
Total segment revenue		436,421			26,310
Cost of sales and operating expenses		436,491			27,686
Office and administration and other expenses		10,639			3,133
Earnings before interest, taxes, depreciation and amortization (1) (unaudited)		(10,708	)		(4,509	)
Depreciation and amortization		10,597			312
Interest expense		10,162			844

Loss from ordinary activities before income taxes		(31,468	)		(5,665	)

Income tax expenses		—			—
Total net loss		(31,468	)		(5,665	)


(1)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. For a reconciliation of net income (loss), a Canadian generally accepted accounting principles measure, to EBITDA, a non-GAAP measure, see “Non-GAAP Measures.”

Revenues

We generated revenues of $436.4 million during the twelve month period ended December 31, 2005. The increase in revenues during the year ended December 31, 2005 compared to 2004 is related to the fact that we began generating operational income from the sale of refined products for the first time during the first quarter of 2005. Our revenue of $26.3 million during the year ended December 31, 2004 was from the sale of a crude cargo in the third quarter of 2004 that our refinery was not ready to accept.

The primary products produced by our refinery are jet fuel and diesel (commonly referred to as middle distillates), gasoline, naphtha and low sulfur waxy residue. Our refinery’s reformer is able to convert a portion of the naphtha produced by our crude distillation unit into reformate which is then blended to produce gasoline. Currently, jet fuel, diesel and gasoline are the primary products that we produce for the Papua New Guinea market. Due to the lack of a local market in Papua New Guinea, the excess naphtha and low sulfur waxy residue is sold in export markets. We believe that the three primary factors that limited our ability to profitably export our products during 2005 were our geographical position, our limited access to regional markets, and our limited storage capacity for refined products. We believe that our location and size may provide competitive advantages if we supply refined products to the small and fragmented South Pacific


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regional markets. We are currently seeking to expand our exports to these regional markets in order to support an increase in the throughput of our refinery.

Revenues from our refining operations were adversely affected by our inability to operate our refinery for a period of 12 days during March 2005 and 14 days in November 2005 as a result of a shortage of crude feedstocks that were caused by the closure of the Kumul loading platform in Papua New Guinea and production disruptions affecting our crude supply. These shortages, which were beyond our control, resulted in shut-downs that reduced our throughputs during the first and fourth quarters of 2005. During the fourth quarter, we processed a new crude feedstock that did not perform as originally expected and produced a poor yield of higher margin refined products. These crude disruptions and poor crude feedstock were significant factors in the loss recognized by our midstream business segment during 2005.

We believe that the crude selection and refinery optimization efforts will improve our revenues and profitability going forward. Our ongoing crude selection efforts have increased the percentage of middle distillates produced by our refinery in relation to the amount of naphtha and low sulfur waxy residue produced. The amount of middle distillates and gasoline produced per barrel of crude feedstock increased by approximately 87% during the fourth quarter of 2005 compared to the third quarter of 2004, the first quarter during which any crude oil was processed by our refinery. The reduction in the amount of naphtha and low sulfur waxy residue being produced has reduced the amount of products we are required to export as a percentage of revenues from approximately 48% during the first quarter of 2005 to approximately 25% during the fourth quarter of 2005. We believe this reduction in these exports will improve our overall operating margins since exports of naphtha and low sulfur waxy residue result in negative product margins. The completion of our optimization efforts during 2006 should further increase our refinery’s profitability by increasing the internal use of low sulfur waxy residue for power generation and increasing the amount of diesel that may be sold.

Cost of Sales and Operating Expenses

Costs of sales and operating expenses were $436.5 million during the year ended December 31, 2005. The increase in costs of sales and operating expenses during year ended December 31, 2005 compared to 2004 is primarily related to the fact that we did not begin generating operational income from the sale of refined products until the first quarter of 2005. Our costs of sales and operating of $27.7 million during the year ended December 31, 2004 was from the purchase a crude cargo in that the third quarter of 2004 that we were required to sell because our refinery was not ready to accept it.

Our cost of sales was materially adversely impacted by the closure of the Kumul loading platform in Papua New Guinea during the first quarter 2005. This event necessitated a prompt purchase of an alternative crude cargo and the procurement of a diesel cargo to assure scheduled product delivery obligations were not adversely impacted. The purchase of these two cargoes on short-term notice resulted in higher costs than we would have incurred if the Kumul loading platform had remained open.

Office and Administration and Other Expenses

Office and administration expenses were $10.6 million for the year ended December 31, 2005 compared to $3.1 million during 2004. The increase is primarily due to the refinery commencing full operations in 2005.

Crude Prices

Revenues from our refining and marketing business segment are derived from the sale of refined products. The prices for refined products and the crude feedstocks used to produce those products are extremely volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is always a time difference between the purchase and processing of a crude feedstock and the sale of finished products to the various markets. We enter into derivative instruments to reduce the risks of changes in the relative prices of our crude feedstocks and refined products as a result of timing differences in the purchase of crude feedstocks and the sale of refined products. While these hedging activities have materially reduced our exposure to changes in crude oil prices, we are still exposed to some risks.


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The price of Tapis crude oil, as quoted by the Asian Petroleum Price Index (APPI), is a benchmark for setting crude prices within the region where we operate and is used by us when we purchase crude feedstock for our refinery. The price of APPI Tapis increased significantly through the nine month period ended September 30, 2005 before easing in the fourth quarter of 2005. APPI Tapis opened at $38.18 per barrel on January 1, 2005, peaked at $70.64 per barrel on September 22, 2005 and closed at $58.16 per barrel on December 29, 2005. The average APPI Tapis price was $50.30 per barrel for the first quarter 2005, $54.27 per barrel for the second quarter of 2005, $64.65 per barrel for the third quarter of 2005 and $59.19 per barrel for the fourth quarter. Generally, refineries achieve increased margins on refined products in a rising oil price environment and decreased margins in a falling oil price environment. The following chart shows the price of Tapis crude for year ended December 31, 2005, as reported by the APPI.

Market Pricing

The crack spread of a refined petroleum product refers to the difference between the price of such product and the price of the crude feedstock used to make such products. During 2005, unprecedented demand for diesel and jet fuels resulted in increased prices and margins for these products and has driven refineries worldwide to maximize the production of these products. As a result, incrementally more naphtha and low sulfur waxy residue in the case of hydro-skimming refineries such as ours, is produced. Because there has not been the same increase in demand for naphtha and low sulfur waxy residue as there has been for middle distillates, the margin for these products has, subject to short-term fluctuations, generally decreased. This decrease in margins for naphtha and low sulfur waxy residue partially offsets the increased margins expected from middle distillates.

The benchmark price for refined products in the region we operate is the average spot price quotations for refined products from Singapore reported by Platts. This benchmark is commonly referred to as the MOPS price for the relevant refined product. The following table is based on information obtained from APPI and Platts Global Alert service and shows the crack spread, or margin, between the benchmark crude for our feedstock, Tapis, and the relevant MOPS refined product benchmark. The actual prices we pay for our crude feedstock and receive for our refined product will differ from, but will be generally be related to, the Tapis and MOPS benchmarks.


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The impact of hurricanes Katrina and Rita in the Gulf of Mexico in August and September 2005 contributed to the increase in middle distillate and gasoline crack spreads, and also in the price per barrel of crude feedstocks during the third quarter of 2005. Price movements improved our revenues on Papua New Guinea domestic sales of middle distillates and gasoline during the fourth quarter of 2005. However, our overall margins on refined products decreased during the fourth quarter of 2005 due to higher prices paid for crude feedstock procured towards the end of the third quarter and early in fourth quarter of 2005. We believe that our hedging programs that were enhanced in late 2005 will reduce our exposure to the risks associated with these price movements in the future.

Sales of naphtha and low sulfur waxy residue in the third and fourth quarters of 2005 were significantly affected by the impact on commodities prices resulting from the hurricanes in the Gulf of Mexico in the third quarter of 2005. The higher pricing of naphtha and low sulfur waxy residue in the month of September 2005 resulted in better than average returns on naphtha and low sulfur waxy residue sales during the third quarter of 2005. The improved pricing during the third quarter of 2005 was offset by increased prices paid for crude feedstock in the third quarter of 2005 and the decrease in the prices of naphtha and low sulfur waxy residue in the fourth quarter of 2005.

Production Slate, Optimization of Crude Diet & Run Rates

During 2005, the first year of operations for our refinery, eight different crude feedstocks, including the PNG Kutubu crude, were processed and evaluated as part of our crude selection program. This program was initiated to determine the types of crude feedstocks that could have the most beneficial impact on our refining margins as we transition from our start-up phase to regular operations. Five of these different crude feedstocks were processed in the third and fourth quarters of 2005. This process has provided us with valuable operational data to continue the ongoing optimization of our refinery. While we will continue to identify and evaluate new crude feedstocks as part of our crude optimization initiatives aimed at improving the yield of our more profitable products, we have now identified a number of crude feedstocks and crude blends for our refinery that we expect will meet our production targets and which we intend to utilize, to the extent available, during 2006.

The mix of refined products produced by a refinery is referred to as its production slate. The following chart shows the progressive improvement in the middle distillate and gasoline yield due to changes in the crude feedstocks processed and improvements to operational procedures since the start-up of our refinery in 2004. Our basic objective was and continues to be to maximize the amount of higher margin middle distillates and


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gasoline produced per barrel of crude feedstock used at the expense of the relatively lower margin products, consisting of naphtha and low sulfur wax residue. Our target yield is subject to the prevailing demand for various refined products, the availability and cost of alternative crude feedstocks, projected product margins and logistics at the time of production.

As illustrated in the chart below, middle distillate and gasoline yields increased significantly since the third quarter of 2004. The fluctuations in gasoline production are primarily a result of our ability to reform enough naphtha into gasoline to fulfill all of the demand for Papua New Guinea’s domestic market while operating our reformer on a part-time basis.

Middle Distillates and Gasoline Production Slate

Naphtha and Low Sulfur Waxy Residue (LSWR) Production

The following chart shows the decrease in the net production of low sulfur waxy residue and naphtha since the start-up of our refinery. Our operational focus will be to continue to attempt to increase gasoline sales and to reduce the volume of low sulfur waxy residue produced per barrel of crude feedstock. We are able to produce more gasoline than is needed to service the domestic market in Papua New Guinea and believe we will be able to produce sufficient quantities to service the regional export market’s demand for gasoline once we expand into that market. Increased gasoline sales will result in a proportionally lower volume of naphtha since naphtha is used in the production of gasoline. The increased net naphtha production in third quarter 2005 is primarily as a result of decreased reforming activities as discussed in the preceding paragraph. We were generally able to decrease the production of low sulfur waxy residue throughout the year. The production of low sulfur waxy residue in the fourth quarter of 2005 was impacted by the testing of a crude feedstock that generated a poor production slate. We expect the low sulfur waxy residue production to decrease during 2006.


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Naphtha and Low Sulfur Waxy Residue Production

Refinery Throughput

Our refinery is rated to process up to 32,500 barrels of oil per day using Kutubu crude as the feedstock and established a peak rate of 34,500 barrels of oil per day during testing using Kutubu crude. During 2005, we processed a total of approximately 7.4 million barrels of crude feedstock. Our current optimization efforts are intended to further increase our daily throughput capacity while maintaining a production slate that produces a high percentage of middle distillates and gasoline. Depending on the type of crude feedstock used and prevailing domestic product demand, we are able to fulfill the domestic market in Papua New Guinea’s demand for our products by refining approximately 16,000 to 22,000 barrels of crude feedstock a day. While we are still in the process of expanding our exports into the regional export markets discussed above, we are focusing on minimizing the amount of crude feedstocks processed by our refinery. With the exception of the start up period, the amount of crude feedstock processed by our refinery has decreased over time due to our operational focus on optimizing crude feedstocks such that we process feedstocks with high middle distillate yield to meet Papua New Guinea’s domestic demand for diesel, jet fuel and gasoline, while reducing the amount of naphtha and low sulfur waxy residue we are required to export at a negative margin. During 2006 and 2007, we will focus on securing exports to the Pacific Island regional market to which we believe we can profitably export our products. Securing these export markets will permit us to increase our product output and maximize the use of our refining assets.

The previously discussed shut-downs of our refinery in March and November as a result of shortages of crude feedstocks that were beyond our control reduced our throughputs during the first and fourth quarters of 2005.


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The following chart illustrates the decrease in throughput since the start-up of our refinery:

Refinery Throughput

Commodity Derivatives

From time to time, we enter into derivative instruments to reduce the risks of changes in the relative prices of our crude feedstocks and refined products. The derivatives reduce our exposure to the timing differences inherent in our purchase of crude feedstocks and the sale of refined products produced using such feedstocks and to fluctuations in refining margins on the volumes hedged. However, these derivatives limit the benefit we might otherwise have received from any increases in refining margins on the hedged volumes.

Our derivative activities resulted in a gain of $746,648 for the year ended December 31, 2005, including contracts that have been marked to market at year end. As a result of our derivative activities, for the year ended December 31, 2005 we have recognized a loss of $270,350 in our statement of operations and a gain of $1,016,998 has been included in the deferred hedge gain liability account in our consolidated balance sheet.

During 2005, we entered into hedges on the margins, or crack spreads, of diesel and jet fuel, some of which extend into 2006. As a result of changes in physical product sales, some of these hedges were closed out during the fourth quarter of 2005 for a net unrealized gain. These hedges were made to take advantage of high crack spreads and are intended to help secure margins on a portion of our sales. During 2005, we entered into various hedges intended to better match the timing of our purchase of crude feedstocks and the sale of refined products produced from those crude feedstocks.

During December 2005, we also initiated “trigger pricing” on part of a crude cargo with our crude supplier, BP Singapore, which, although not a derivative hedge, forms part of our risk management strategy to secure margin from sales of domestic products. Trigger pricing allows us, at our option, to purchase a portion of a crude cargo at a fixed price rather than unknown future prices. The fixed price we would receive upon making a trigger pricing election is generally similar to what can be achieved using derivative financial instruments on the date a trigger pricing election is made.


InterOil Corporation Page 13 of 29

Downstream—Wholesale and Retail Distribution

Year Ended December 31, 2005 compared to Year Ended December 31, 2004

Our wholesale and retail distribution business segment recognized after-tax net income of $6.1 million for the year ended December 31, 2005 compared to after-tax net income of $4.0 million for the year ended December 31, 2004. The primary reason for the increase in net income is due to the fact that we acquired our wholesale and retail distribution business segment on April 28, 2004 and only operated it for eight months during 2004.

The following table shows the results for our refining and marketing business segment for years ended December 31, 2005 and 2004:


Downstream — Operating results	Years ended December 31,
($thousands)	2005			2004
External sales		124,854			62,410
Inter-segment revenue		6			489
Total segment revenue		124,860			62,899
Cost of sales and operating expenses		110,857			53,159
Office and administration and other expenses		4,725			3,147
Depreciation and amortization		204			224
Interest expense		225			455
Net income from ordinary activities before income taxes		8,848			5,914
Income tax expenses		(2,756	)		(1,900	)
Total net income		6,092			4,014

Revenues

Total revenues for the year ended December 31, 2005 were $124.9 million compared with $62.4 million for the year ended December 31, 2004. Our revenues for the year ended December 31, 2004 include sales from April 29, 2004. The increase in sales and operating revenue for the year ended December 31, 2005 compared to the year ended December 31, 2004 is primarily the result of the additional period of operations during 2005. In addition, revenues increased as a result of a significant increase in product prices during 2005 as a result of the worldwide increase in crude prices. Revenues also increased as a result of an increase in the net volumes of refined products sold. The average quarterly volume of refined products sold by our wholesale and retail distribution business increased by 21% compared to the amount of refined products sold by the business during the quarter immediately prior to the acquisition date. Our downstream business sold 210 million liters of product during 2005, compared to 162 million liters of product in 2004. The average sales price of products sold per liter was $0.59 in 2005 compared to $0.38 for 2004.

Expenses

The main cost of sales and operating expenses is derived from either purchasing products from our refinery or importing products not produced at our refinery from other parties. Our refinery supplies 100% of our downstream business’ diesel, gasoline, and jet fuel requirements. Our downstream business segment will continue to import other fuels, such as fuel oil, and lubricant products as our refinery does not produce these products.

Costs of sales and operating expenses were $110.9 million during 2005 compared to $53.2 million during 2004. The increase in expenses is a result of the additional period of operations during 2005 and the average price of products sold per liter increasing from $0.33 during 2004 to $0.53 during 2005.


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Corporate and Consolidation

Year Ended December 31, 2005 compared to Year Ended December 31, 2004

The following table shows our corporate level expenses and our results on a consolidated basis for the years ended December 31, 2005 and 2004:


Corporate and consolidation	Years ended December 31,
($ thousands)	2005			2004
External sales—elimination		—			(18,075	)
Inter-segment revenue elimination (1)		(80,101	)		(489	)
Interest revenue		1,831			382
Other unallocated revenue		528			196
Total segment revenue		(77,742	)		(17,986	)
Cost of sales and operating expenses elimination (1)		(80,101	)		(15,500	)
Office and administration and other expenses (2)		6,193			6,773
Depreciation and amortization (3)		(80	)		90
Interest expense (4)		600			1,899
Loss from ordinary activities before income taxes		(4,354	)		(11,248	)
Income tax expenses		(76	)		25
Non-controlling interest		368			70
Total net loss		(4,062	)		(11,153	)


(1)		Represents the elimination upon consolidation of our refinery sales to other segments and other minor inter-company product sales.

(2)		Includes the elimination of inter-segment administration service fees.

(3)		Represents the amortization of a portion of costs capitalized to assets on consolidation.

(4)		Includes the elimination of interest accrued between segments.

Expenses

Our total corporate office and administration and other expenses were $6.2 million for the year ended December 31, 2005, compared to $6.8 million for the same year ended December 31, 2004. The decrease in expenses is primarily due to the administrative and legal costs incurred in connection with our issuance of debentures in 2004 which were not incurred in 2005. Interest expense decreased by $1.3 million for the year ended December 31, 2005 compared to the year ended December 31, 2004 as a result of the conversion of the debentures to equity in December 2004.


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Consolidated 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, 2005 and 2004 were accounted for as follows:


Consolidated Income Taxes	Years ended December 31,
($ thousands)	2005			2004
Loss before income taxes and non controlling interest		(36,818	)		(51,135	)
Statutory income tax rate		35.10	%		35.12	%
Computed tax expense (benefit)		(12,923	)		(17,959	)
Effect on income tax of:
Non-deductible losses in foreign jurisdictions		2,835			2,274
Non-deductible stock compensation expense		586			425
Gains and losses on foreign exchange		269			59
Tax rate differential in foreign jurisdictions		1,224			(342	)
Over provision for tax in prior years		(114	)		(43	)
Tax losses for which no future tax benefit has been recognized		9,845			2,696
Temporary differences for which no future tax benefit has been recognized		1,123			14,553
Temporary differences recognized on acquisition of subsidiary		(35	)		(488	)
Other—net		22			700
Income tax expense		2,832			1,875

Summary of Quarterly Results

The following table and discussion in this section and the table containing quarterly financial information included under “Non-GAAP Measures” have been derived from our interim 2005 consolidated financial statements. These interim financial statements have not been subject to audit, review or any quarterly procedures in accordance with generally accepted auditing standards.

The following table summarizes financial information for the fourth quarter of 2005 and the preceding seven quarters:


Quarters ended	2005												2004
($ thousands, except per
share data) (unaudited)	Dec 31			Sept 30			June 30			Mar 31(1)			Dec 31			Sep 30(2)			Jun 30(3)			Mar 31
Sales and operating revenues		130,200			124,481			125,275			103,584			22,151			36,226			12,691			156
Upstream		—			—			—			—			—			—			—			—
Midstream		108,488			115,203			114,734			97,996			—			26,310			—			—
Downstream		43,741			27,470			30,062			23,588			39,811			10,134			12,954			—
Corporate & Consolidated		(22,029	)		(18,192	)		(19,521	)		(18,000	)		(17,660	)		(218	)		(264	)		156
Earnings before interest, taxes, depreciation and amortization (4)		(7,848	)		11,634			(13,812	)		(4,769	)		(40,306	)		(3,534	)		(1,856	)		(1,597	)
Upstream		(5,262	)		6,105			(9,770	)		(603	)		(37,395	)		(360	)		(1,883	)		(482	)
Midstream		(6,470	)		6,001			(6,778	)		(3,461	)		(2,684	)		(1,538	)		(205	)		(82	)
Downstream		3,673			2,527			2,448			629			3,441			1,734			1,451			(32	)
Corporate & Consolidated		211			(2,999	)		288			(1,334	)		(3,668	)		(3,370	)		(1,219	)		(1,001	)
Net income (loss) per segment (5)		(14,207	)		5,251			(19,972	)		(10,354	)		(43,856	)		(4,917	)		(2,522	)		(1,645	)
Upstream		(5,352	)		5,890			(9,774	)		(608	)		(37,405	)		(362	)		(1,879	)		(492	)
Midstream		(11,887	)		1,017			(12,155	)		(8,443	)		(3,840	)		(1,400	)		(334	)		(91	)
Downstream		2,515			1,465			1,857			255			2,347			761			938			(32	)
Corporate & Consolidated		517			(3,121	)		100			(1,558	)		(4,960	)		(3,916	)		(1,247	)		(1,030	)
Net income (loss) per share (5)
Per share—Basic		(0.49	)		0.18			(0.69	)		(0.36	)		(1.73	)		(0.19	)		(0.10	)		(0.07	)
Per share—Diluted		(0.49	)		0.18			(0.69	)		(0.36	)		(1.73	)		(0.19	)		(0.10	)		(0.07	)


(1)		Practical completion of our refinery occurred in the first quarter of 2005. For quarterly comparative purposes as well as for the years ended December 2005 and the 2004, the commencement of refining operations should be taken into account when analyzing the respective financial statements. Refining operations on a progressive start-up basis commenced in the first quarter of 2005.

(2)		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 our downstream business segment during the commissioning of our refinery. These sales and costs of sales were adjusted to plant and equipment in the fourth quarter of 2004. For comparative purposes, the September 30, 2004 amounts in the table include subsequent period adjustments 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.

(3)		We acquired our downstream business on April 28, 2004. For quarterly comparative purposes as well as for the years ended December 2005 and 2004, the date we acquired our downstream business segment should be taken into account when analyzing the respective financial statements.

(4)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. For a reconciliation of net income (loss), a Canadian generally accepted accounting principles measure, to EBITDA, a non-GAAP measure; see “Non-GAAP Measures” below.

(5)		We did not have any discontinued operations or extraordinary items during the periods covered by this table.


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Our consolidated net loss after tax for the quarter ended December 31, 2005 was $14.2 million compared to a loss of $43.8 million for the same period in 2004. Our consolidated net loss after tax decreased primarily because of a change in the treatment of our exploration impairment expenses as described under “—Upstream—Exploration and Production.”

During the fourth quarter of 2005, our revenues were reduced due to a drop in export sales related to our crude optimization efforts yielding a lower production of naphtha and low sulfur waxy residue and our net income was reduced due to:

	•		the testing and processing of a new crude feedstock during the fourth quarter of 2005 which produced a poor yield; and

	•		a reduction in throughput as a result of unplanned shutdowns due to delays in receiving crude feedstocks that were beyond our control;

	•		increased prices for crude feedstocks acquired during the third and early in the fourth quarter of 2005 which were used to produce the refined products sold during the fourth quarter of 2005 and, consequently, reduced our refining margins; and

	•		higher crude feedstock financing fees as a result of higher crude prices.

Net income from our downstream business segment was $2.5 million during the fourth quarter of 2005 compared to a net income of $2.0 million for the same period in 2004. The increase is primarily attributable to the general increase in refined product prices during 2005. The average sales price of products sold by our downstream business segment was $0.72 per liter during the fourth quarter of 2005, compared to $0.68 per liter during the fourth quarter of 2004. During the fourth quarter of 2005, the volume of products sold by our downstream business segment also increased slightly. Our downstream business segment sold 60.24 million liters of product during the fourth quarter of 2005, compared to 58.54 million liters of product during the fourth quarter of 2004.

The net loss for our upstream business segment of $5.4 million during the fourth quarter of 2005 compared to a loss of $37.4 million in the same quarter of 2004 is primarily due to drilling and related expenses incurred as a result of obligations under our indirect participation interest agreement having been paid for by our indirect participation investors. As a result, these amounts have not been recognized as expenses as they were during 2004. The majority of expenses during the fourth quarter of 2005 consisted of the accretion expense related to the amortization of the discount calculated on the non-financial portion of the indirect participation interest liability.


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Non-GAAP Measures

Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. We believe that EBITDA provide shareholders with useful information with which to analyze and compare our operating performance with other companies in our industry. EBITDA does not have a standardized meaning prescribed by Canadian generally accepted accounting principles and, therefore, may not be comparable with the calculation of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results. Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash provided from operating activities and other measures of financial performance prepared in accordance with Canadian generally accepted accounting principles. Further, EBITDA is not a measure of cash flow under Canadian generally accepted accounting principles and should not be considered as such.

The following tables reconcile net income (loss), a Canadian generally accepted accounting principles measure, to EBITDA, a non-GAAP measure.


Summary Annual Results (unaudited)	Years ended December 31,
($ thousands)	2005			2004			2003
Earnings before interest, taxes, depreciation and amortization (unaudited)		(14,794	)		(47,293	)		(3,326	)
Upstream		(9,530	)		(40,119	)		(686	)
Midstream		(10,708	)		(4,509	)		(222	)
Downstream		9,278			6,593			(25	)
Corporate & Consolidated		(3,834	)		(9,258	)		(2,393	)
Subtract:
Interest expense		10,987			3,203			105
Upstream		—			5			—
Midstream		10,162			844			—
Downstream		225			455			—
Corporate & Consolidated		600			1,899			105
Income taxes & non-controlling interest		2,464			1,805			14
Upstream		—			—			—
Midstream		—			—			—
Downstream		2,756			1,900			—
Corporate & Consolidated		(292	)		(95	)		14
Depreciation & amortization		11,037			639			73
Upstream		314			13			10
Midstream		10,598			312			8
Downstream		205			224			—
Corporate & Consolidated		(80	)		90			55
Net income/(loss) per segment		(39,282	)		(52,940	)		(3,518	)
Upstream		(9,844	)		(40,137	)		(696	)
Midstream		(31,468	)		(5,665	)		(230	)
Downstream		6,092			4,014			(25	)
Corporate & Consolidated		(4,062	)		(11,152	)		(2,567	)

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Quarters ended	2005												2004
($ thousands) (unaudited)	Dec 31			Sept 30			June 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Earnings before interest, taxes, depreciation and amortization		(7,847	)		11,634			(13,812	)		(4,769	)		(40,306	)		(3,534	)		(1,856	)		(1,597	)
Upstream		(5,262	)		6,105			(9,770	)		(603	)		(37,395	)		(360	)		(1,883	)		(482	)
Midstream		(6,470	)		6,001			(6,778	)		(3,461	)		(2,684	)		(1,538	)		(205	)		(82	)
Downstream		3,674			2,527			2,448			629			3,441			1,734			1,451			(32	)
Corporate & Consolidated		211			(2,999	)		288			(1,334	)		(3,668	)		(3,370	)		(1,219	)		(1,001	)
Subtract:
Interest expense		2,989			2,454			2,997			2,547			2,605			573			23			2
Upstream		(6	)		2			2			2			5			—			—			—
Midstream		2,755			2,320			2,736			2,351			844			—			—			—
Downstream		43			42			140			—			423			31			1			—
Corporate & Consolidated		197			90			119			194			1,333			542			22			2
Income taxes & non-controlling interest		673			984			635			172			687			622			496			—
Upstream		—			—			—			—			—			—			—			—
Midstream		—			—			—			—			—			—			—			—
Downstream		1,061			965			571			159			772			625			502			—
Corporate & Consolidated		(388	)		19			64			13			(85	)		(3	)		(6	)		—
Depreciation & amortization		2,698			2,945			2,528			2,866			258			188			147			46
Upstream		96			213			2			3			5			2			(4	)		10
Midstream		2,662			2,664			2,641			2,631			312			(138	)		129			9
Downstream		55			55			(120	)		215			(103	)		317			10			—
Corporate & Consolidated		(115	)		13			5			17			44			7			12			27
Net income (loss) per segment		(14,207	)		5,251			(19,972	)		(10,354	)		(43,856	)		(4,917	)		(2,522	)		(1,645	)
Upstream		(5,352	)		5,890			(9,774	)		(608	)		(37,405	)		(362	)		(1,879	)		(492	)
Midstream		(11,887	)		1,017			(12,155	)		(8,443	)		(3,840	)		(1,400	)		(334	)		(91	)
Downstream		2,515			1,465			1,857			255			2,347			761			938			(32	)
Corporate & Consolidated		517			(3,121	)		100			(1,558	)		(4,960	)		(3,916	)		(1,247	)		(1,030	)

Capital Resources

Operating Activities

For the year ended December 31, 2005, cash used in our operating activities was $22.7 million compared with $79.8 million for the year ended December 31, 2004. For the year ended December 31, 2005, we had a consolidated net loss of $39.3 million compared to a consolidated net loss of $52.9 million for 2004. Our primary uses of cash for operating activities during 2005, other than the activity related to deriving net income (loss), were $16.5 million attributable to an increase in crude feedstock prices and a small increase in our physical inventory, less an $8.7 million decrease in our trade receivables. For the year ended December 31, 2004, our primary uses of cash for operating activities were $24.2 million for increases in inventory balances of crude and refined product and $50.5 million for increases in trade receivables.

Investing Activities

For the year ended December 31, 2005, cash received from our investing activities was $15.5 million compared with a use of $29.0 million for the year ended December 31, 2004. During 2005, cash received from investing activities mainly consisted of $80.4 million in proceeds from the $125 million indirect participation interest agreement. Cash used in investing activities consisted primarily of $11.2 million for oil and gas exploration, $4.1 million for purchases of plant and equipment, $31.8 million for expenditures

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applied against the indirect participation interest, $1.1 million for restricted cash to support the working capital facility and $12.2 million for the acquisition of our downstream business. For the year ended December 31, 2004, cash used in investing operations consisted primarily of $19.1 million for oil and gas exploration, $15.5 million for restricted cash to support the working capital facility and $39.0 million for refinery plant and equipment investments. During 2004, cash used in investing activities was offset by cash received of $24.7 million from short term investments, $0.4 million from the sale of assets and $4.6 million in cash balances received upon the acquisition of our downstream business.

Financing Activities

For the year ended December 31, 2005, cash received from our financing activities was $38.3 million compared with $128.1 million for the year ended December 31, 2004. During 2005, amounts received from financing activities included $22.7 million of net proceeds from the indirect participation interest agreement, $21.5 million in proceeds from a short term loan, and $5.5 million in proceeds from the issuance of common shares upon the exercise of options and warrants. Cash received from financing proceeds were offset by a $4.5 million principal repayment on the OPIC loan, $5.8 million in repayment to our working capital facility, and $1.1 million in related party repayments to Petroleum Independent and Exploration Corporation for the loans discussed under “Transactions with Related Parties” below. Amounts received from financing activities in during 2004 consisted of $2.0 million in loans from the Overseas Private Investment Corporation, net proceeds of $41.7 million from the issuance of senior convertible debentures, net proceeds of $76.5 million from borrowings under our working capital facility, $6.3 million of net proceeds from the indirect participation interest agreement and $2.0 million from the issuance of common shares upon exercise of options. Cash received from financing activities during 2004 was partially offset by $2.2 million in related party repayments to Petroleum Independent and Exploration Corporation for the loans discussed under “Transactions with Related Parties” below.

Upstream Capital Expenditure

During 2005, our capital expenditures for exploration in Papua New Guinea totaled $43.8 million compared with $19.2 million during 2004. Our capital expenditures during 2005 consisted of $22.9 million for the drilling of exploration wells, $11.0 million for seismic, airborne gravity and magnetic surveys, $7.6 million for the purchase of our drilling rig, and $2.3 million for the construction of offices and warehouses, the acquisition of inventory and other capital purchases.

Midstream Capital Expenditures

During 2005, capital expenditures for our refining and marketing business segment were $3.3 million compared with $40.5 million during 2004. Our 2005 capital expenditures related to work initiated in connection with our refinery optimization program.

Downstream Capital Expenditures

During 2005, capital expenditures for our wholesale and retail distribution business segment were approximately $14.0 million compared with $2.3 million during 2004. Our 2005 capital expenditures consisted of the payment of $12.1 million to BP International for the acquisition of InterOil Products Limited and $1.9 million for a storage tank, a barge facility and a number of other smaller capital items.

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Liquidity

Sources of Capital

Upstream

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

Midstream

In August 2005, we entered into a $150 Million Secured Revolving Crude Import Facility with BNP Paribas, Singapore Branch. The facility, which is up for renewal on June 30, 2006, is used to finance purchases of crude feedstocks for our refinery. The facility provides for the issuance of up to $120 million of letters of credit with a maximum term of 30 days and short terms loans relating to previously issued letters of credit with a maximum term of 60 days. The short term loans bear interest at LIBOR plus 2.5% per annum. In addition, the facility provides for up to $40 million in borrowings that are secured by our receivables or cash deposits. The actual interest rate for borrowings under the $40 million portion of the facility is dependent upon the type of security used but in all cases is lower than the interest rates charged for short-term loans. As of December 31, 2005, the maximum aggregate principal amount permitted to be outstanding at any one time under the facility was $150 million and $44 million remained available for use under the facility. This credit limit is subject to adjustment at the discretion of BNP Paribas. Borrowings from BNP under this facility are secured by our crude and refined product inventories, receivables and specified cash deposits. During 2005, the weighted average interest rate under this facility was 5.8%.

Downstream

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

Corporate

On January 28, 2005, we obtained a $20 million term loan facility. Amounts under this loan were disbursed in two installments of $10 million each on January 31, 2005 and February 25, 2005. On July 21, 2005, the facility was increased from $20 million to $25 million. The additional funds are to be used for capital expenditures related to our refinery optimization initiatives. During the third and fourth quarters of 2005, we received a further drawdown on this facility of $1.5 million to support this activity. The loan has an interest rate equal to 5% per annum, payable quarterly in arrears, and includes a 1% arrangement fee on the original $20 million face amount. The term of the loan is fifteen months from the disbursement dates, and is repayable at any time prior to expiration with no penalty. In addition, we have provided the lender under the term loan facility with an irrevocable right to participate in a future equity or debt financing for an amount of up to $40 million.

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Capital Requirements

Upstream

We are obligated under our indirect participation interest agreement to drill eight exploration wells. Two of these wells were drilled during 2005. The remaining six wells are scheduled to be drilled in 2006 and 2007. We believe that the $125 million raised from investors pursuant to this agreement is sufficient to meet these obligations. As of December 31, 2005, approximately $16 million of the funds raised pursuant to this program were committed to restricted cash accounts which support our midstream operations. We have received waivers from some, but not all, of the participants in the indirect participation interest agreement to temporarily place the proceeds of this agreement in these restricted cash accounts. The amount of cash currently available from the proceeds of our indirect participation interest agreement is expected to be sufficient to fund our estimated capital expenditures for our exploration and production business segment for 2006 of $31.6 million. During 2006, we expect to complete our current seismic acquisition program and airborne gravity and magnetic surveys, and drill two exploration wells. These expenditures will be funded using the proceeds of our $125 million indirect participation interest agreement financing.

We are engaged in negotiations for debt financing which we believe will be sufficient to fulfill the restricted cash requirements discussed above and, if necessary, to fund our remaining obligations to drill a total of eight exploration wells under our $125 million indirect participation interest agreement. However, no assurance can be given that we will be successful in obtaining this new debt financing or other sources of capital.

Midstream

Since 2004, the price of crude oil that we use as feedstocks for our refinery has risen dramatically. As a result of these price increases, we have been required to use increasing amounts of our available liquidity to finance the purchase of crude feedstocks. In addition, the costs associated with our refinery optimization efforts have further reduced our available liquidity. As discussed above, this lack of liquidity has required us to allocate funds raised under our upstream indirect participation interest agreement to restricted cash accounts that support our crude purchase facility.

Most of our budgeted capital expenditures for 2006 for our refining and marketing business segment are related to our refinery optimization initiatives and are expected to be incurred during the second and third quarters of 2006. Our estimated capital expenditures for our refining and marketing business segment for 2006 are $10.0 million. We believe that the debt financing we are currently negotiating to obtain will enable us to pay for these capital expenditures. However, no assurance can be given that we will be successful in raising the needed additional capital.

Downstream

We believe that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment during 2006 of $2.4 million. In order to complete the acquisition of Shell’s downstream distribution business in Papua New Guinea, we will be required to obtain debt or other financing.

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Contractual Obligations and Commitments

The following table contains information on payments for contracted obligations as of December 31, 2005 that we have over the next five years and it should be read in conjunction with our financial statements and the notes thereto:


Payments Due by Period
			Less than		1 - 2		2 - 3		3 - 4		4 - 5		More than
Contractual obligations	Total		1 year		years		years		years		years		5 years
Long-term debt obligations	$	80,500	$	9,000	$	9,000	$	9,000	$	9,000	$	9,000	$	35,500
Indirect participation interest (non-current) (1)	$	5,500		—	$	5,500		—		—		—		—
Indirect participation interest (current)	$	65,259	$	35,093	$	30,166		—		—		—		—
Unsecured term loan	$	21,453	$	21,453		—		—		—		—		—
Capital expenditure commitments relating to refinery optimization program	$	4,600	$	4,600		—		—		—		—		—
Petroleum prospecting and retention licenses (2)	$	160	$	160		—		—		—		—		—
Total	$	177,472	$	70,306	$	44,666	$	9,000	$	9,000	$	9,000	$	35,500


(1)		The terms of the indirect participation interest agreement provide for various conversion options. The amount provided is the maximum amount that can be converted to debt and differs from the amount presented in the December 31, 2005 Consolidated Balance Sheet due to conversion requirements into our fully paid common shares.

(2)		The amount pertaining to the petroleum prospecting and retention licenses represents the amount we are required to spend over the next two years to maintain the exploration licenses. The committed amount can be spent in any proportion over the two years. In addition, we have an obligation to drill an exploration well in Petroleum Prospecting License 237 prior to the end of March 2007. The costs to drill this well are not included in the above table because they cannot be estimated at this time.

Off-Balance Sheet Arrangements

As of December 31, 2005, we did not have any off balance sheet arrangements and did not enter into any during the twelve month period ended December 31, 2005, including any relationships with unconsolidated entities or financial partnerships to enhance perceived liquidity.

Transactions with Related Parties

Petroleum Independent and Exploration Corporation, a company owned by Mr. Mulacek, our Chairman of the Board of Directors and Chief Executive Officer, was paid a management fee of $150,000, $150,410 and $150,000 during 2005, 2004 and 2003, respectively. This management fee relates to Petroleum Independent and Exploration Company being appointed the General Manager of our subsidiary, S.P. InterOil, LDC.

We also made interest payments of $9,376, $246,745 and $105,374, and loan principal payments of $1.1 million, $2.2 million and $1.4 million to Petroleum Independent and Exploration Corporation during 2005, 2004 and 2003, respectively. As of December 31, 2005 we had repaid all amounts that we owed to Petroleum Independent and Exploration Company. The loans outstanding to Petroleum Independent and Exploration Corporation were for amounts loaned by lending institutions to Petroleum Independent and Exploration Company. These loans were collateralized by barges legally owned by Petroleum Independent and Exploration Company but beneficially owned by us and common shares of ours owned by Petroleum Independent and Exploration Company that were used as collateral to assist us. All of the proceeds of these loans were passed through to us and the interest rates charged to us by Petroleum Independent and Exploration Company reflected the actual interest rates paid by Petroleum Independent and Exploration Company to the lending institutions.

Breckland Limited provides technical and advisory services to us on normal commercial terms. Roger Grundy, one of our directors, is also a director of Breckland and he provides consulting services to us as an employee of Breckland. Breckland was paid $179,608, $120,426 and $131,250 during 2005, 2004 and 2003, respectively.

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On November 22, 2005, we acquired Direct Employment Services Corp. for $1,000. Christian Vinson, our Chief Operating Officer and a director, was paid $500, the par value of his shares of Direct Employment Services Corp. Prior to November 22, 2005, the services of certain of our executive officers and senior management were provided under a management services agreement with Direct Employment Services Corp. Direct Employment Services Corp. was established for the purposes of providing non-profit management services to us for our U.S. employees. Direct Employment Services Corp. invoiced us for its direct costs in providing the services of these employees but did not recognize any income from providing these services to us. Direct Employment Services Corp. was paid $549,978, $708,104, and $535,855 during 2005, 2004 and 2003, respectively.

Share Capital

Our authorized share capital consists of an unlimited number of common shares with no par value. As of March 16, 2006, we had 29,163,320 common shares outstanding and 33,990,325 common shares on a fully diluted basis.


Share Capital	Number of shares
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		781,268
Shares issued on exercise of warrants		19,168
Shares issued for debt		52,000
Balance December 31, 2005		29,163,320
Shares issued from January 1, 2006 to March 16, 2006		—
Balance March 16, 2006		29,163,320
Remaining stock options authorized		911,068
Remaining shares issuable upon exercise of warrants		340,247
Remaining conversion rights authorized (1)		3,570,690
Other		5,000
Balance March 16, 2006 Diluted		33,990,325


(1)		In 2003 and 2005, we sold indirect participation working interests in our exploration program. Some of the investors under our indirect participation interest agreements still have the right to convert, under certain circumstances, their interest to our common shares. If 100% of the investors under all of out indirect participation interest agreements choose to convert their interests, we would be required to issue an additional 3,570,690 common shares.

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Financial and Derivative Instruments

With the exception of cash and cash equivalents and temporary investments, all financial assets are non-interest bearing. Cash and cash equivalents earned average interest rates on bank term deposits of 1.3%, 1.6%, and 1.5% per annum during 2005, 2004 and 2003, respectively. All other components of cash and cash equivalents are non-interest bearing. Temporary investments are comprised of the following:


Restricted cash	Years ended December 31,
As at December 31, 2005	2005		2004
Cash deposit on working capital facility (2.9%)		16,452,216		15,497,127
Cash deposit on secured loan (2.1%)		106,266		—
Bank term deposits on Petroleum Prospecting licenses (1.3%)		103,786		102,096
Total		16,662,268		15,599,223

Credit risk is minimized as all cash amounts and certificates of deposit are held with large banks which have acceptable credit ratings as determined by a recognized rating agency. The carrying values of cash and cash equivalents, trade receivables, all other assets, accounts payable and accrued liabilities, all short-term loan facilities and amounts due to related parties approximate fair values due to the short term maturities of these instruments.

Cash held as a deposit on the working capital facility secures our working capital facility with BNP Paribas. The required balance, which can be satisfied with cash, inventory and accounts receivable, is initially based on 20% of the outstanding balance of the facility. The cash held as a deposit on the secured loan provides a portion of the security for our secured loan borrowings with the Overseas Private Investment Corporation.

Foreign Currency Hedge Contracts

We had no outstanding foreign currency forward contracts at December 31, 2005 and 2004.

Commodity Hedge Contracts

From time to time, we enter into derivative instruments to reduce the risks of changes in the relative prices of our crude feedstocks and refined products. The derivatives reduce our exposure on the hedged volumes based on timing differences and also to decreases in refining margins. However, these derivatives limit the benefit we might otherwise have received from any increases in refining margins on the hedged volumes. We use derivative commodity instruments to manage exposure to price volatility on a portion of its refined product and crude inventories.

As of December 31, 2005, we had entered into jet fuel crack spread swap agreements to hedge a portion of the anticipated 2006 sales of this product. We also entered into crude swap agreements to hedge a portion of our anticipated first quarter 2006 diesel, naphtha and low sulfur waxy residue sales. The unrealized gain on unsettled hedge contracts deemed to be effective at December 31, 2005 was $1,016,998 and is recognized in the financial statements as a deferred hedge gain liability.

As of December 31, 2005, we had a net receivable of $1,482,798 relating to commodity hedge contracts. Of this total, $897,798 relates to hedges deemed effective as of December 31, 2005 and $585,000 relates to derivative contracts that were closed and for which hedge accounting has been discontinued. The gain on the closed derivative contracts is included in general and administrative expenses for the year ended December 31, 2005.

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The following table summarizes our effective hedge contracts by derivative type which were unsettled and not priced out as of December 31, 2005:


Outstanding Hedging Contracts
Derivative	Type	Notional Volumes (Bbls)
Crude swap	Sell crude		300,000
Crude swap	Buy crude		250,000
Jet fuel/ kerosene crack spread swap	Sell jet/ buy crude		249,999

Critical Accounting Estimates

The preparation of financial statements in accordance with Canadian generally accepted accounting principles requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. The information about our critical accounting estimates should be read in conjunction with Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2005, which summarizes our significant accounting policies.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment. A valuation allowance is provided against any portion of a future tax asset which will more likely not be recovered. If actual results differ from the estimates or we adjust the estimates in future periods, we may need to record a valuation allowance. The net deferred income tax assets as of December 31, 2005 and 2004 were $1.1 million and $1.3 million, respectively.

Oil and Gas Properties

We use the successful-efforts method to account for our oil and gas exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. We continue to carry as an asset the cost of drilling exploratory wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future, or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of economical reserves. Capitalized costs for producing wells will be subject to depletion using the units-of-production method. Geological and geophysical costs are expensed as incurred. If our plans change or we adjust our estimates in future periods, a reduction in our oil and gas properties asset will result in a corresponding increase in the amount of our exploration expenses. The net costs of drilling exploratory wells carried as an asset as of December 31, 2005 and 2004 were $1.3 million and $1.3 million.

Asset Retirement Obligations

Estimated costs of future dismantlement, site restoration and abandonment of properties are provided based upon current regulations and economic circumstances at year end. Management estimates that there are no material obligations associated with the retirement of the refinery or with its normal operations relating to future restoration and closure costs. The refinery is located on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.

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Environmental Remediation

Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. We currently do not have any amounts accrued for environmental remediation obligations. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.

Impairment of Long-Lived Assets

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

Fair value of Financial Instruments

We utilize derivative financial instruments in the management of our price exposures for our refined products and crude feedstocks. We disclose the estimated fair value of outstanding hedging contracts as of the end of a reporting period. The estimation of the fair value of certain hedging derivatives requires considerable judgment. The estimate of fair value for our derivative contracts is determined primarily through quotes from financial institutions. Accounting rules for transactions involving derivative instruments are complex and subject to a range of interpretation. The Financial Accounting Standards Board has established the Derivative Implementation Group Task Force, which, on an ongoing basis, considers issues arising from interpretation of these accounting rules. The potential exists that the task force may promulgate interpretations that differ from ours. In this event, our policy would be modified and our deferred hedge gain may be adjusted with a corresponding increase to revenues and expenses. The deferred hedge gains as of December 31, 2005 and 2004 were $1.0 million and $0.5 million, respectively.

We accounted for $125,000,000 in proceeds received under the indirect participation interest agreement signed in February 2005 as a non financial liability with an equity component. In determining the split between liabilities and equity, our management estimated the fair value of the liability and equity components and allocated the $125,000,000 in proceeds from the agreement based on the pro rata share of the fair market value of each component. The calculation of the fair market value of each component was based on a wide range of variables, including the expected timing of expenditures, total overall expenditure, and applicable interest rates. If the liability and equity components were allocated in different amounts, our December 31, 2005 accounts may have presented a different interest expense and/or increased amounts of exploration expenditures.

Legal and other contingent matters

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

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New Accounting Standards

Non-Monetary Transactions

In June 2005, the AcSB issued CICA section 3831, “Non-monetary Transactions” which replaced section 3830 of the same name. The new recommendations require that all non-monetary transactions are measured based on fair value unless the transaction lacks commercial substance or is an exchange of product or property held for sale in the ordinary course of business. The guidance is effective for all non-monetary transactions initiated in periods beginning on or after January 1, 2006. We do not believe that the application of CICA section 3831 will have a material impact on our financial statements.

Pending Accounting Standards

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

	•		Section 1530, Comprehensive Income;

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

	•		Section 3865, Hedges.

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

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

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

These new standards are effective for fiscal years beginning on or after October 1, 2006. We expect to adopt the pending accounting standards on January 1, 2007. Management at this time is still in the process of assessing the impact of these standards.

Public Securities Filings

You may access additional information about us, including our Annual Information Form, which is filed with the Canadian Securities Administrators at www.sedar.com, and our Form 40-F, which is filed with the U.S. Securities and Exchange Commission at www.sec.gov.

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	•		the processing of eight different crude feedstocks to determine which crude feedstocks our refinery can most profitably process;

	•		a full review of operational procedures and the implementation of changes to procedures that were identified as capable of improving our refinery’s efficiency; and

	•		an analysis of equipment modifications that would support our ongoing optimization efforts.

	•		reducing the net amount of low margin naphtha and low sulfur waxy residue that we sell.

	•		improving the percentage of higher margin products, jet fuel, diesel and gasoline, which our refinery produces per barrel of crude feedstock processed.