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November 14, 2006

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis (MD&A), dated November 14, 2006, was prepared by the management of InterOil with respect to our financial performance for the periods covered by the related interim financial statements, along with a detailed analysis of our financial position and prospects. The information in this MD&A was approved by our Audit Committee on behalf of our Board of Directors on November 11, 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 and our unaudited interim financial statements and accompanying notes for the three and nine month periods ended September 30, 2006. Our financial statements and the financial information contained in this 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 is to develop a vertically-integrated energy company whose focus is on operations in Papua New Guinea and the surrounding region. Our operations are organized into four major segments:

•

Upstream Business Segment — Exploration and Production. Our upstream business segment explores for oil and natural gas in Papua New Guinea.

•

Midstream Business Segment — 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.

•

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

•

Corporate Services Segment — Corporate. Our corporate services segment is engaged in business development and improvement, common services and management, financing and treasury, government and investor relations. Common and integrated costs are recovered from business segments on an equitable driver basis.

SUMMARY OF QUARTERLY RESULTS

Our consolidated net loss for the quarter ended September 30, 2006 was $7.6 million, compared to the loss of $2.9 million for the same period in 2005. Our consolidated net loss for the nine month period ended September 30, 2006 was $39.7 million, compared to the loss of $27.1 million for the same period in 2005.

The summarized results for each of our business segments is as follows:

•

Upstream — Exploration and Production

Third Quarter 2006 vs. Third Quarter 2005 — The net loss is attributable to the ongoing exploration drilling program for our upstream business segment during the quarter ended September 30, 2006 was $1.9 million, compared to a loss of $2.3 million in the same quarter of 2005. The primary reason for the decreased loss during the third quarter of 2006 compared to the same period in 2005 was a decrease in the accretion expense for the indirect participation interest liability, which will continue to decrease in the future.

Nine Months ended September 30, 2006 vs. Nine Months ended September 30, 2005 — The net loss for our upstream business segment during the nine month period ended September 30, 2006 was $8.8 million, compared to a loss of $6.5 million for the same period in 2005. The primary reason

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for the increased loss during the nine months ended September 30, 2006 as compared to the same period in 2005 was an increase in exploration costs that are not credited against the indirect participation interest liability related to the indirect participation interest agreements. In addition, the recognition of an asset impairment expense of $0.8 million related to the sale of a barge increased the loss during the nine month period ended September 30, 2006 compared to the same period in 2005. These increases in the nine month periods were partially offset by the decrease in accretion expense for the indirect participation interest liability.

•

Midstream — Refining and Marketing

Third Quarter 2006 vs. Third Quarter 2005 — For the quarter ended September 30, 2006, our midstream business segment recognized a loss of $4.8 million compared to a profit of $1.0 million for the same quarter of 2005. The primary reason for the loss is due to the refinery being shutdown for 25 days during the quarter ended September, 2006 when compared to nil days for the same quarter in 2005. When compared to the second quarter ending June 30, 2006, earnings before interest, taxes, depreciation and amortization increased by $11.4 million from a loss before interest, taxes, depreciation and amortization of $10.3 million. The increase in earnings before interest, taxes, depreciation and amortization resulted primarily from the optimization work undertaken in June and July. Please see “Non-GAAP Measures.”

Nine Months ended September 30, 2006 vs. Nine Months ended September 30, 2005 — For the nine month period ended September 30, 2006, our midstream business segment recognized a loss of $28.7 million compared to a loss of $19.6 million for the same period in 2005. The primary reason for the increased loss is the refinery was shut down for 93 days during the nine month period ended September 30, 2006 compared to 12 days during the nine month period ended September 30, 2005. The refinery shut down days in 2006 related to the optimization work undertaken at the refinery during June and July and crude supply disruptions beyond our control which occurred in the first quarter of 2006.

•

Downstream — Marketing and Distribution

Third Quarter 2006 vs. Third Quarter 2005 — Net income after tax during the quarter ended September 30, 2006 from our downstream business segment was $1.2 million compared to net income after tax of $1.5 million for the same period in 2005. The decrease in net income after tax is attributable to an increase in repairs and maintenance costs in relation to the terminal and depot facilities as well as an increase in general corporate overheads.

Nine Months ended September 30, 2006 vs. Nine Months ended September 30, 2005 — The net income after tax for the nine months ended September 30, 2006 was $3.3 million as compared to $3.6 million for the same period in 2005. The decrease in net income is attributable to an increase in repairs and maintenance costs in relation to the terminal and depot facilities as well as an increase in general corporate overheads.

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The following table summarizes unaudited financial information for the three months ended September 30, 2006 and the preceding seven quarters.


Quarters ended
($ thousands, except
per share data)	2006									2005 (adjusted)⁽¹⁾												2004
(unaudited)	Sep30			Jun30			Mar31			Dec31⁽²⁾			Sep30⁽²⁾			Jun30			Mar31⁽³⁾			Dec31
Sales and operating revenues		111,372			124,671			110,283			125,216			129,465			125,275			103,584			22,151
Upstream		950			1,196			996			—			—			—			—			—
Midstream		94,566			106,693			103,009			108,488			115,203			114,734			97,996			—
Downstream		39,494			37,963			27,776			38,757			32,454			30,062			23,588			39,811
Corporate		(23,638	)		(21,181	)		(21,498	)		(22,029	)		(18,192	)		(19,521	)		(18,000	)		(17,660	)
Earnings before interest, taxes, depreciation and amortization⁽⁴⁾		1,140			(10,258	)		(9,105	)		(5,565	)		3,485			(6,856	)		(5,688	)		(40,306	)
Upstream		(1,676	)		(4,013	)		(2,581	)		(3,217	)		(2,058	)		(2,651	)		(1,604	)		(37,395	)
Midstream		1,254			(8,320	)		(5,326	)		(6,470	)		6,000			(6,778	)		(3,460	)		(2,684	)
Downstream		1,921			3,527			(358	)		3,674			2,526			2,619			629			3,441
Corporate		(359	)		(1,452	)		(840	)		448			(2,983	)		(46	)		(1,253	)		(3,668	)
Net income (loss) per segment⁽⁵⁾		(7,554	)		(17,761	)		(14,363	)		(12,162	)		(2,912	)		(12,853	)		(11,355	)		(43,856	)
Upstream		(1,880	)		(4,187	)		(2,780	)		(3,307	)		(2,273	)		(2,655	)		(1,609	)		(37,405	)
Midstream		(4,775	)		(13,677	)		(10,266	)		(11,887	)		1,017			(12,155	)		(8,443	)		(3,840	)
Downstream		1,245			2,394			(314	)		2,515			1,465			1,857			255			2,349
Corporate		(2,144	)		(2,291	)		(1,003	)		517			(3,121	)		100			(1,558	)		(4,960	)
Net income (loss) per share⁽⁵⁾
Per share—Basic		(0.25	)		(0.60	)		(0.49	)		(0.42	)		(0.10	)		(0.45	)		(0.40	)		(1.73	)
Per share—Diluted		(0.25	)		(0.60	)		(0.49	)		(0.42	)		(0.10	)		(0.45	)		(0.40	)		(1.73	)


(1)		Comparative quarterly results for all quarters during 2005 have been adjusted and re-presented to include the adopted accounting treatment for exploration expenses associated with our $125 million Indirect Participation Interest Agreement entered into in February 2005 as reviewed by our auditors in the third quarter of 2005. The adjusted results present the quarterly financial information as if the indirect participation interest accounting policy we adopted during the third quarter of 2005 had been adopted at the inception of the agreement. See Note 23 to our unaudited financial statements for the three and nine month periods ended September 30, 2006 and 2005.

(2)		The sales and operating revenues for the downstream segment have been adjusted from those previously disclosed. The effect of the adjustment was to increase sales and operating revenues and cost of goods sold in the September 2005 quarter by $4,984 and decrease sales and cost of goods sold in the December 2005 quarter by $4,984. There was no impact on the net income reported in either quarter.

(3)		Practical completion of our refinery occurred in the first quarter of 2005. For quarterly comparative purposes 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.

(4)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) less (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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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. Except to the extent supplemented in our MD&A dated August 14, 2006, we do not believe that our business risks have materially changed since the date of our 2005 Annual Information Form.

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 short 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

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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.

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

RESULTS OF OPERATIONS

Upstream—Exploration and Production

Quarter and nine months ended September 30, 2006 compared to the same periods in 2005

Third Quarter 2006 vs. Third Quarter 2005 — For the quarter ended September 30, 2006, our exploration and production business segment reported a loss of $1.9 million compared to a loss of $2.3 million for the same quarter of 2005. The decrease in the loss of $0.4 million between the quarter ended September 30, 2006 as compared to the same quarter in 2005 was primarily the result of a decrease in the accretion expense recognized for the indirect participation interest.

Nine Months ended September 30, 2006 vs. Nine Months ended September 30, 2005 — The loss for the nine months ended September 30, 2006 was $8.8 million compared with a loss of $6.5 million for the same period of 2005. The primary reason for the increased loss during the nine months ended September 30, 2006 compared to the same period in 2005 was an increase in exploration costs that are not credited against our indirect participation interest liability related to the indirect participation interest agreements. In addition to the increase in exploration costs, the recognition of an asset impairment expense prior to the sale of a barge increased the loss during the nine month period ended September 30, 2006 compared to the same period in 2005.

The following commentary reviews the results for our upstream business segment for the three and nine month periods ended September 30, 2006 and 2005 by category:

	•		*Revenues*

			As of September 30, 2006, we had not generated any operational revenues from our upstream business segment. The other unallocated revenue is due to the value of our company-owned rig being charged against our indirect participation interest liability at current market day rates. Because we expense the costs of owning and maintaining this rig, the amounts charged to the indirect participation interest liability are recognized as revenue by our upstream business segment. In addition, during the second quarter of 2006, we assisted a third party oil exploration company with their logistics and re-charged helicopter and camp services.

			As of September 30, 2006, we discovered and tested gas and gas liquids in our Elk-1 well located in Petroleum Prospecting License 238. The Elk #1 discovery well did confirm a gas and gas liquids flow to the surface at rates between 7.1 millions of standard cubic feet per day and over 50 millions of standard cubic feet per day through various choke sizes. Positive indications have been confirmed to this date; however, more drilling and technical work will need to be completed before a final confirmation is made on the potential of the discovery, and to determine the quantities of any gas reserves that may be classified as proved or probable.

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	•		*Office and Administration and Other*

			Office and administrative and other expenses during the quarter ended September 30, 2006 increased by $1.6 million compared to the third quarter of 2005. Office and administration and other expenses during the nine month period ended September 30, 2006 increased by $4.0 million compared to the same period in 2005. The increase during the quarter ended September 30, 2006 compared to the same period during 2005 was primarily due to expenses of $0.8 million associated with the rental of our rig and $0.5 million increase in general office and administration costs. The increase during the nine month period ending September 30, 2006 as compared to the same period in 2005 was primarily due to expenses of $2.3 million associated with the rental of our rig and the re-charge of helicopter and camp services, $0.5 million relating to increased senior management wages allocated to the exploration operations, and $0.4 million associated with the disposal of plant and equipment. The remaining increase relates to a general increase in the office and administration costs, such as accounting support, IT support, insurance costs, and legal costs.

	•		*Impairment Expense on Barge Sale*

			During the nine month period ended September 30, 2006, we recognized an impairment loss of $0.8 million prior to the sale of one of our barges. There was no similar transaction in the prior year.

	•		*Exploration Costs and Exploration Impairment*

			The accounting treatment for exploration expenses associated with our indirect participation interest agreements requires us to deduct the majority of our costs incurred in the drilling of exploration wells and acquisition of seismic and airborne gravity data against the liability to the participants under these indirect participation interest agreements. Exploration costs that are deducted from the indirect participation interest liability are not expensed in our statement of operations. Due to the ability of the participants in this agreement to elect to convert their investment into our common shares, a portion of the proceeds that we received under this agreement are accounted for as an equity contribution and not a liability. As a result, the portion of our exploration costs associated with the indirect participation interest agreements that are deemed to be paid for with proceeds from the equity contribution are directly expensed.

			During the nine month period ended September 30, 2006, exploration costs increased by $1.4 million compared to the same period in 2005. The increase in exploration costs is primarily due to the acquisition of seismic during the nine months to September 30, 2006 as compared to the corresponding period in 2005.

	•		*Depreciation and Amortization*

			The increase in depreciation expense for the nine month period ended September 30, 2006 of $0.4 million relates to depreciation on our company-owned rig which was not commissioned until the first quarter of 2006.

	•		*Accretion Expense*

			Accretion expenses relate to the amortization of the discount calculated on the liability component of the indirect participation interest agreements. Accretion expenses during the quarter ended September 30, 2006 decreased by $0.8 million compared to the third quarter of 2005 and during the nine month period ended September 30, 2006 by $1.0 million compared to the same period in 2005. Accretion expenses decreased during these periods primarily due to a decrease in the indirect participation interest liability and will continue to decrease in the future.

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The following table shows the results for our upstream business segment for the three and nine month periods ended September 30, 2006 and 2005.


	Three months ended						Nine months ended
Upstream Operating results	September 30,						September 30,
($ thousands)	2006			2005 (adjusted)			2006			2005 (adjusted)
External sales		—			—			—			—
Inter-segment revenue		—			—			—			—
Other unallocated revenue		950			—			3,142			—

Total segment revenue		950			—			3,142			—
Cost of sales and operating expenses		—			—			—			—
Office and administration and other expenses		1,920			333			5,241			1,227
Impairment expense on barge sale		—			—			756			—
Exploration costs		52			218			1,716			306
Exploration impairment		35			117			300			397
Accretion expense		619			1,390			3,399			4,383

Earnings before interest, taxes, depreciation and amortization⁽¹⁾		(1,676	)		(2,058	)		(8,270	)		(6,313	)
Depreciation and amortization		202			213			573			218
Interest expense		2			2			4			6

Loss from ordinary activities before income taxes		(1,880	)		(2,273	)		(8,847	)		(6,537	)
Income tax expenses		—			—			—			—

Total net loss		(1,880	)		(2,273	)		(8,847	)		(6,537	)


(1)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) less (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.

Midstream—Refining and Marketing

Quarter and nine months ended September 30, 2006 compared to the same periods in 2005

Third Quarter 2006 vs. Third Quarter 2005 — For the quarter ended September 30, 2006, our midstream business segment recognized a loss of $4.8 million compared to a profit of $1.0 million for the same quarter of 2005. The primary reason for the loss is due to the refinery being shutdown for 25 days during the quarter ended September, 2006 when compared to nil days for the same quarter of 2005. Earnings before interest, taxes, depreciation and amortization increased by $9.6 million in the quarter ending September 30, 2006 when compared to the prior quarter ending June 30, 2006. This improvement was primarily the result of the optimization work undertaken in June and July of 2006.

Nine Months ended September 30, 2006 vs. Nine Months ended September 30, 2005 — For the nine month period ended September 30, 2006, our midstream business segment recognized a loss of $28.7 million compared to a loss of $19.6 million for the same period in 2005. The increased losses during the nine month period ended September 30, 2006 when compared to the same period in 2005 was due to crude supply disruptions beyond our control during the first quarter of 2006, the planned optimization shut down during the second and third quarters of 2006 and a write-down of product inventories due to the drop in oil prices. Other general areas that impact the midstream segment have been the general decline of the Singapore Tapis Hydroskimming margin, which reduced our margins under the import parity pricing formula.

The refinery shutdown in the second and third quarters of 2006 impacted net income in the third quarter of 2006. The optimization work that commenced during the second quarter of 2006 was concluded in the third

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quarter of 2006. This work included the installation of new generators powered by low sulfur waxy residue and modifications of the furnaces and boilers to improve reliability and reduce fuel costs. During the shutdowns in 2006 crude throughputs were reduced compared to the same periods in 2005, therefore in order to continue to satisfy domestic supply obligations the refinery imported distillates in the first and second quarter and sold these distillates during the first, second and third quarters of 2006. The business receives significantly lower margins on the sale of imported products.

The following commentary reviews the results for our midstream business segment for the three and nine month periods ended September 30, 2006 and 2005 by category:

	•		*Revenues*

			Revenues for the quarter ended September 30, 2006 decreased by $20.6 million when compared with the quarter ended September 30, 2005, and by $23.7 million for the nine month period ended September 30, 2006, respectively, when compared to the same period in 2005. Sales of products by volume for the quarter and nine month periods ended September, 30, 2006 were 1.01 million and 3.75 million barrels compared to 1.73 million and 5.48 million barrels for the same periods in 2005. The reduction in product sales by volume for the quarter and nine month periods ended September 30, 2006 was primarily the result of our crude optimization efforts that have allowed us to produce a higher percentage of higher value products per barrel of crude processed. This, in association with the shutdown period meant that no sales of Naphtha and Low Sulphur Waxy Residue were recorded during third quarter 2006. Sales of higher value products to the PNG market, primarily jet fuel, diesel and gasoline, increased by $16.8 million during the nine month period ended September 30, 2006 compared to the same period in 2005.

			We believe that the refinery optimization efforts which commenced during the second quarter of 2006 and were completed during the third quarter of 2006, and the use of optimum crudes, when available, will continue to improve our profitability going forward. Evidence of the positive impact of the optimization is reflected in improved results for the third quarter 2006 compared with the second quarter 2006. During the quarter and nine month periods ended September 30, 2006 we processed approximately 1.29 million and 3.64 million barrels compared to 1.85 million and 5.99 million barrels during the same periods in 2005. 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. During 2006, the impact of crude shortages and the optimization shutdown (necessitating product import) has meant that throughputs fell below the expected level to satisfy PNG distillate demand, reaching a minimum in second quarter 2006. We expect the throughput to continue to increase slightly from the third quarter levels to reach a sustainable level to satisfy PNG demand at around 16,000 to 18,000 barrels per day depending on crude feedstock.

			Our ongoing crude selection efforts have increased the percentage of jet fuel and diesel, commonly referred to as middle distillates, produced by our refinery in relation to the amount of naphtha and low sulfur waxy residue produced per barrel of crude feedstock processed. This has allowed us to process fewer barrels of crude feedstocks while continuing to sell approximately the same amount of middle distillates to the Papua New Guinea domestic market. Middle distillates that we sell to the domestic Papua New Guinea market have a positive gross margin whereas export naphtha and low sulfur waxy residue have a negative gross margin. The chart below shows the general reduction in export sales of negative margin products that we have been able to achieve since the refinery began operations.

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Reduction in Naphtha and LSWR Production

•

Cost of Sales and Operating Expenses

Costs of sales and operating expenses during the quarter ended September 30, 2006 decreased by $11.8 million compared to the same quarter of 2005 and during the nine month period ended September 30, 2006 by $11.3 million compared to the same period in 2005. The decrease in costs of sales during the three and nine month periods ended September 30, 2006 compared to the same periods in 2005 is primarily due to an increase in the cost of crude feedstocks offset by a greater reduction in the volume of products sold during the three and nine month periods ended September 30, 2006 compared to the same periods in 2005.

•

Office and Administration and Other Expenses

Office and administration and other expenses during the quarter ended September 30, 2006 decreased by $4.1 million compared to the same quarter of 2005 and during the nine month period ended September 30, 2006 by $4.2 million compared to the same period in 2005. The decrease in office and administration and other expenses during the quarter ended September 30, 2006 compared to the quarter ended September 30, 2005 is primarily due to foreign exchange losses/gains increasing from a gain of $0.4 million in 2005 to a gain of $4.1 million in 2006. The remaining difference relates to a general reduction in overhead costs as a result of cost saving methods undertaken at the refinery. The decrease in office and administration and other expenses during the nine month period ended September 30, 2006 compared to the nine month period ending September 30, 2005 is primarily due to foreign exchange losses/gains decreasing from a loss of $0.2 million in 2005 to a gain of $4.2 million in 2006.

•

Borrowing Expense

Borrowing expenses during the quarter and nine months ended September 30, 2006 increased by $1.0 million as compared to the quarter and nine months ended September 30, 2005. The increase in borrowing expense results from general increases to the cost of crude feedstock being financed, increased LIBOR indicator rates and an increase to the volume of inventory on hand predominantly

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as a result of the optimization shutdown. This is offset by reduced letter of credit fees charged by our working capital providers. The chart below shows the LIBOR USD overnight rate which has steadily increased from 2.32% to 5.375% between January 2005 and September 2006.

LIBOR USD Overnight Rate

•

Crude Prices

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 that changes in the price of these products during this time period expose us to as described below under “Commodity Derivatives.” The price of Tapis crude oil, as quoted by the Asian Petroleum Price Index, is a benchmark for setting crude prices within the region where we operate and is used by us when we purchase crude feedstock for our refinery. The price of Tapis during the quarter and nine month periods ended September 30, 2006 averaged $72.66 and $70.36 per barrel compared to $64.65 and $56.49 during the same periods in 2005. The pricing formula used to determine the sales price of our refined products to the domestic Papua New Guinea market does not allow us to fully recover the increased costs of working capital that result from increases in the cost of crude feedstocks.

•

Refinery Margin

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 distillation process our refinery uses to convert crude feedstocks into refined products is commonly referred to as hydroskimming. While the Singapore Tapis hydroskimming margin is a useful indicator of the general margin available for hydroskimming refineries in the region in which we operate, it should be noted that the crude feedstocks we use produce a different mix of refined products per barrel of crude feedstock processed and we have different transportation costs than refineries located in Singapore. The differences in our approach to crude selection and transportation costs work to assist our midstream segment in outperforming the Singapore hydroskimming margin. Therefore, our refinery may realize additional margins due to its niche location when compared to refiners located in Singapore. Theoretical hydroskimming margins increased during the first six months of 2006 but have given up most of this increase during third quarter 2006. Volatility has increased during the past 18 months

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			and the underlying trend continues to indicate a decrease in hydroskimming refining margins. In addition, we believe that hydroskimming margins will remain volatile given oil pricing uncertainty.

	•		*Commodity Derivatives and Risk Management*

			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. These 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.

			Derivatives and Trigger pricing/intermonth rolls initiated on the pricing of physical crude purchases resulted in a realized and mark to market gain of $0.97m for strategies executed during third quarter 2006. The net gain predominantly relates to efforts to protect export products against flat price movements (which happened to be trending downwards during third quarter) and trigger pricing executed to lock in crude prices against known import parity prices (i.e. locking in an import parity price margin). These risk management efforts did not compensate for the full decline in prices and margins experienced during the quarter. This predominantly relates to difficulties in accurately forecasting the timing of product sales (particularly export products) as a result of optimization shutdowns and crude slate and timing changes.

The following table shows the results for our midstream business segment for the quarters and nine months ended September 30, 2006 and 2005:


	Three months ended					Nine months ended
Midstream — Operating results	September 30,					September 30,
($ thousands)	2006			2005		2006			2005
External sales		69,901			96,652		235,577			271,436
Inter-segment revenue		24,665			18,551		68,690			56,497

Total segment revenue		94,566			115,203		304,267			327,933

Cost of sales and operating expenses		95,052			106,863		312,710			324,010
Office and administration and other expenses⁽¹⁾		(1,740	)		2,340		3,949			8,161

Earnings before interest, taxes, depreciation and amortization⁽²⁾		1,254			6,000		(12,392	)		(4,238	)

Depreciation and amortization		2,700			2,663		7,924			7,936
Interest expense		3,329			2,320		8,402			7,407

Loss from ordinary activities before income taxes		(4,775	)		1,017		(28,718	)		(19,581	)

Income tax expenses		—			—		—			—

Total net loss		(4,775	)		1,017		(28,718	)		(19,581	)


(1)		Included in office and administration and other expenses for the quarter ended September 30, 2006 is a foreign exchange gain.

(2)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) less (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.

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Downstream—Wholesale and Retail Distribution
Quarter and nine months ended September 30, 2006 compared to the same periods in 2005

Third Quarter 2006 vs. Third Quarter 2005 — Our downstream business segment’s net income after tax during the quarter ended September 30, 2006, decreased by $0.2 million when compared to the same period in 2005. The decrease in after tax net income for the third quarter of 2006 compared to the same period in 2005 is primarily attributable to increase in repairs and maintenance costs in relation to terminal and depot facilities as well as an increase in general corporate overhead.

Nine Months ended September 30, 2006 vs. Nine Months ended September 30, 2005 — During the nine month period ended September 30, 2006 net income after tax decreased by $0.3 million when compared to the same period in 2005. The decrease in net income is primarily attributable to an increase in repairs and maintenance costs in relation to the terminal and depot facilities as well as an increase in general corporate overheads.

The following commentary reviews the results for our downstream business segment for the three and nine month periods ended September 30, 2006 and 2005 by category:

	•		*Revenues*

			Revenues for the quarter ended September 30, 2006 increased by $7.0 million and for the nine month period ended September 30, 2006 by $19.1 million when compared to the same periods in 2005. The increase in sales revenue for the three and nine month periods ended September 30, 2006 compared to the previous year is primarily the result of an increase in the selling price of refined products. The average sales price of products sold per liter during the quarter and nine month periods ended September 30, 2006 was $0.73 and $0.67 compared to $0.68 and $0.57 during the same periods in 2005. During the quarter and nine month periods ended September 30, 2006 our downstream business sold 54.4 million liters and 156.3 million liters of product compared to 47.2 million liters and 150.2 million liters of product during the same periods in 2005.

	•		*Cost of Sales and Operating Expenses*

			The main cost of sales and operating expenses are derived from either purchasing products from our refinery or importing products not produced at our refinery from other parties. Costs of sales and operating expenses for the quarter ended September 30, 2006 increased by $5.3 million and for the nine month period ended September 30, 2006 by $15.2 million when compared to the same periods in 2005. The increase in expenses is a result of increases in the cost of refined products during the three and nine month periods ended September 30, 2006 when compared to the same periods in 2005 and an increase in volume of sales during the third quarter of 2006 when compared to the same period in 2005. The average cost of refined products purchased for the quarter and nine month periods ended September 30, 2006 was $0.63 and $0.58 per liter compared to $0.48 per liter and $0.45 per liter for the same periods in 2005.

	•		*Office and Administration and Other Expenses*

			Office and administration and other expenses for the quarter ended September 30, 2006 increased by $2.4 million and for the nine month period ended September 30, 2006 by $4.6 million when compared to the same periods in 2005. The primary reason for the increase in office administration and other expenses for the three and nine month periods ended September 30, 2006 compared to the same periods in 2005 was an increase in repair and maintenance costs and administrative costs.

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The following table shows the results for our downstream business segment for the quarters and nine months ended September 30, 2006 and 2005:


	Three months ended						Nine months ended
Downstream — Operating results	September 30,						September 30,
($thousands)	2006			2005			2006			2005
External sales		39,451			32,140			105,181			85,661
Inter-segment revenue		43			313			52			443

Total segment revenue		39,494			32,453			105,233			86,104

Cost of sales and operating expenses		34,116			28,863			91,111			75,924
Office and administration and other expenses		3,457			1,064			9,032			4,406

Earnings before interest, taxes, depreciation and amortization⁽¹⁾		1,921			2,526			5,090			5,774
Depreciation and amortization		222			54			373			320
Interest expense		38			42			115			182

Net income (loss) from ordinary activities before income taxes		1,661			2,430			4,602			5,272

Income tax expenses (benefit)		(416	)		(965	)		(1,277	)		(1,695	)

Total net income (loss)		1,245			1,465			3,325			3,577


(1)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) less (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.

Corporate
Quarter and nine months ended September 30, 2006 compared to the same period in 2005

The following commentary reviews our corporate services segment for the three and nine month periods ended September 30, 2006 and 2005 by category:

	•		*Expenses*

			Corporate office and administration and other expenses for the quarter ended September 30, 2006 decreased by $1.2 million when compared to the same period in 2005 and for the nine month period ended September 30, 2006 increased by $0.6 million when compared to the same period in 2005. The primary reason for the decrease in the third quarter of 2006 of $1.2 million was a decrease of $0.9 million in the stock compensation expense recognized as compared to the amount recognized in the same period in 2005. The remaining change relates to a decrease in the general and administrative costs which were unallocated to the segments.

			The increase for the nine month period ended September 30, 2006 of $0.6 million related to the recognition of a $1.4 million loss in connection with the amendment in May 2006 of the indirect participation interest agreement entered into in July 2003 which was offset by a decrease of $0.9 million in professional fees and executive salaries which were incurred in 2005 but not repeated in 2006.

	•		*Interest*

			Corporate interest expense for the quarter ended September 30, 2006 increased by $1.9 million and for the nine month period ended September 30, 2006 by $2.7 million when compared to the same periods in 2005. The primary reason for these increases was the borrowings under the secured loan facility entered into in May 2006.

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The following table shows our expenses and results for the corporate segment and consolidation entries for the three and nine month periods ended September 30, 2006 and 2005:


	Three months ended						Nine months ended
Corporate and Consolidations	September 30,						September 30,
($ thousands)	2006			2005			2006			2005
External sales		—			—			—			—
Inter-segment revenue elimination ⁽¹⁾		(24,708	)		(18,865	)		(68,742	)		(56,940	)
Interest revenue		1,048			586			2,375			985
Other unallocated revenue		23			87			50			242

Total segment revenue		(23,637	)		(18,192	)		(66,317	)		(55,713	)

Cost of sales and operating expenses elimination ⁽¹⁾		(24,708	)		(17,805	)		(68,742	)		(55,860	)
Office and administration and other expenses ⁽²⁾		1,430			2,596			5,076			4,429

Earnings before interest, taxes, depreciation and amortization⁽⁵⁾		(359	)		(2,983	)		(2,651	)		(4,282	)

Depreciation and amortization⁽³⁾		(24	)		13			(70	)		35
Interest expense ⁽⁴⁾		1,981			90			3,104			403

Loss from ordinary activities before income taxes		(2,316	)		(3,086	)		(5,685	)		(4,720	)

Income tax expenses		125			(19	)		(60	)		(96	)
Non-controlling interest		47			(15	)		307			237

Total net loss		(2,144	)		(3,121	)		(5,438	)		(4,579	)


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

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

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

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

(5)		Earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA, represents our net income (loss) less (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.

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.

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


Quarters ended	2006									2005 (adjusted)⁽¹⁾												2004
($ thousands) (unaudited)	Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31			Dec 31
Earnings before interest, taxes, depreciation and amortization		1,140			(10,258	)		(9,105	)		(5,565	)		3,485			(6,856	)		(5,688	)		(40,306	)
Upstream		(1,676	)		(4,013	)		(2,581	)		(3,217	)		(2,058	)		(2,651	)		(1,604	)		(37,395	)
Midstream		1,254			(8,320	)		(5,326	)		(6,470	)		6,000			(6,778	)		(3,460	)		(2,684	)
Downstream		1,921			3,527			(358	)		3,674			2,526			2,619			629			3,441
Corporate & Consolidated		(359	)		(1,452	)		(840	)		448			(2,983	)		(46	)		(1,253	)		(3,668	)
Subtract:
Interest expense		5,350			3,609			2,666			2,989			2,454			2,997			2,547			2,605
Upstream		2			1			1			(6	)		2			2			2			5
Midstream		3,329			2,731			2,342			2,755			2,320			2,736			2,351			844
Downstream		38			39			38			43			42			140			—			423
Corporate & Consolidated		1,981			838			285			197			90			119			194			1,333
Income taxes & non-controlling interest		244			1,032			(245	)		910			1,000			301			253			687
Upstream		—			—			—			—			—			—			—			—
Midstream		—			—			—			—			—			—			—			—
Downstream		416			1,005			(144	)		1,061			965			571			159			772
Corporate & Consolidated		(172	)		27			(101	)		(151	)		35			(270	)		94			(85	)
Depreciation & amortization		3,100			2,862			2,837			2,698			2,943			2,699			2,867			258
Upstream		202			173			198			96			213			2			3			5
Midstream		2,700			2,626			2,598			2,662			2,663			2,641			2,632			312
Downstream		222			89			62			55			54			51			215			(103	)
Corporate & Consolidated		(24	)		(26	)		(21	)		(115	)		13			5			17			44
Net income (loss) per segment		(7,554	)		(17,761	)		(14,363	)		(12,162	)		(2,912	)		(12,853	)		(11,355	)		(43,856	)
Upstream		(1,880	)		(4,187	)		(2,780	)		(3,307	)		(2,273	)		(2,655	)		(1,609	)		(37,405	)
Midstream		(4,775	)		(13,677	)		(10,266	)		(11,887	)		1,017			(12,155	)		(8,443	)		(3,840	)
Downstream		1,245			2,394			(314	)		2,515			1,465			1,857			255			2,349
Corporate & Consolidated		(2,144	)		(2,291	)		(1,003	)		517			(3,121	)		100			(1,558	)		(4,960	)


(1)		Comparative quarterly results for all quarters during 2005 have been adjusted and re-presented to include the adopted accounting treatment for exploration expenses associated with our $125 million Indirect Participation Interest Agreement entered into in February 2005 as reviewed by our auditors in the third quarter of 2005. The adjusted results present the quarterly financial information as if the indirect participation interest accounting policy we adopted during the third quarter of 2005 had been adopted at the inception of the agreement. See Note 23 to our unaudited financial statements for the three and nine month periods ended September 30, 2006 and 2005.

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The following table reconciles net income (loss), a Canadian generally accepted accounting principles measure, to EBITDA, a non-GAAP measure for the nine month periods ending September 30, 2006 and September 30, 2005.


Nine months ended	Sep 30			Sep 30
($ thousands) (unaudited)	2006			2005
Earnings before interest, taxes, depreciation and amortization		(18,223	)		(9,059	)
Upstream		(8,270	)		(6,313)	)
Midstream		(12,392	)		(4,238	)
Downstream		5,090			5,774
Corporate & Consolidated		(2,651	)		(4,282	)
Subtract:
Interest expense		11,625			7,998
Upstream		4			6
Midstream		8,402			7,407
Downstream		115			182
Corporate & Consolidated		3,104			403
Income taxes & non-controlling interest		1,031			1,554
Upstream		—			—
Midstream		—			—
Downstream		1,277			1,695
Corporate & Consolidated		(246	)		(141	)
Depreciation & amortization		8,799			8,509
Upstream		573			218
Midstream		7,924			7,936
Downstream		373			320
Corporate & Consolidated		(71	)		35
Net income (loss) per segment		(39,678	)		(27,120	)
Upstream		(8,847	)		(6,537	)
Midstream		(28,718	)		(19,581	)
Downstream		3,325			3,577
Corporate & Consolidated		(5,438	)		(4,579	)

CAPITAL RESOURCES

Operating Activities

For the quarter ended September 30, 2006, cash generated in our operating activities was $1.1 million compared with $21.2 million generated from operating activities for the same quarter in 2005. For the quarter ended September 30, 2006, we had a consolidated net loss of $7.6 million compared to a consolidated net loss of $2.9 million for the same quarter in 2005. Our primary uses of cash for operating activities during the third quarter of 2006, other than the activity related to deriving net income (loss), were $3.7 million attributable to increases in inventory balances for crude and refined product, offset by a $5.0 million increase in accounts payable and accrued liabilities. For the quarter ended September 30, 2005, our primary uses of cash for operating activities were $16.3 million for increases in inventories, $16.9 million for decreases in trade receivables and $17.6 million for increases in accounts payable and accrued liabilities.

For the nine months ended September 30, 2006, cash used in our operating activities amounted to $17.6 million compared with $14.5 million for the same period in 2005. The primary uses of cash for operating

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activities during the nine month period ended September 30, 2006 were $68.0 million for increases in inventories offset by $16.6 million in decrease in trade receivables and $46.5 million in increase in accounts payable. For the nine months ended September 30, 2005, the primary use of cash in operating activities were $38.9 million in increase in inventories offset by a $13.3 million increase in accounts payable and accrued liabilities and a $24.1 million decrease in trade receivables.

Investing Activities

For the quarter ended September 30, 2006, cash used in our investing activities was $53.8 million compared with $12.4 million for the quarter ended September 30, 2005. During the third quarter of 2006, cash used on investing activities consisted primarily of a $12.3 million increase to our secured cash balances, $26.1 million related to the acquisition of the Shell Papua New Guinea business which was acquired in October 2006, $12.5 million spent on oil and gas exploration, and $3.0 million spent on plant and equipment. For the quarter ended September 30, 2005, cash used in investing activities consisted primarily of $11.3 million for oil and gas exploration, $0.2 million for restricted cash to support our crude import facility and $1.0 million for plant and equipment investments.

For the nine months ended September 30, 2006, cash used on investing activities amounted to $95.5 million compared to cash received of $26.3 million for the comparative period in 2005. During the nine month period ended September 30, 2006, cash used in investing activities consisted primarily of a $22.1 million increase to our secured cash balances, $32.6 million spent on oil and gas properties, $13.2 million spent on plant and equipment, and $30.6 million on the acquisition of Shell’s downstream assets in PNG, offset by proceeds on the sale of assets of $3.8 million. For the nine months ended September 30, 2005, cash received from investing activities amounted to $80.4 million in proceeds from the indirect participation interest agreement entered into in February 2005 and a $3.1 million increase in accounts payable and accrued liabilities. These amounts were offset by expenditures on oil and gas properties of $25.3 million, the payment of $12.2 million in financing for the BP acquisition transaction, the payment of $2.9 million on plant and equipment and a $16.9 million increase in restricted cash balances to support our crude import facility.

Financing Activities

For the quarter ended September 30, 2006, cash proceeds from our financing activities were $22.3 million compared with cash used of $27.9 million for the quarter ended September 30, 2005. During the third quarter of 2006, amounts received from financing activities included $34.3 million of net proceeds from a secured loan facility entered into in May 2006, which were offset by repayments of $12.2 million on the crude import facility. Amounts received from financing activities during the third quarter of 2005 consisted of $0.6 million of net proceeds from the issuance of common shares upon exercise of options and $0.9 million received on an unsecured loan. Cash received from financing activities during the third quarter of 2005 was offset by $29.4 million in repayments on our crude import facility.

For the nine months ended September 30, 2006, cash received from financing activities amounted to $84.1 million compared to cash received of $24.2 million for the comparative period in 2005. During the nine month period ended September 30, 2006, cash received from financing activities consisted primarily of $113.7 million in proceeds from a secured loan facility entered into in May 2006, and $0.7 million received from the issue of common shares upon exercise of options. These inflows were offset by $21.5 million in repayments of an unsecured loan, $4.5 million of repayments of the secured loan agreement entered into in September 2001 and $4.3 million in repayments on the working capital facility. For the nine months ended September 30, 2005, cash received from financing activities primarily consisted of $20.9 million from an unsecured loan, $22.7 million as proceeds from the indirect participation interest agreement entered into in February 2005, and $4.6 million in proceeds from the issue of common shares from option conversion offset by $1.1 million in repayments to related parties $22.9 million in repayments on our crude import facility.

Upstream Capital Expenditures

Our capital expenditures for exploration in Papua New Guinea for the quarter ended September 30, 2006 were $12.3 million and for the nine month period ended September 30, 2006 $32.4 million compared with $9.9 million and $20.3 million during the same periods in 2005. Our capital expenditures during the third quarter of 2006 consisted of $10.7 million for the drilling and testing of the Elk-1 exploration well, $0.5 million for seismic and airborne gravity surveys, and $1.1 million for rig equipment. The $10.7 million incurred on Elk-1 during the quarter was the result of the fact that we encountered high pressure gas and gas liquids that

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required significant extraordinary expenditures to control the well pressure before we could continue drilling the well. The increase in capital expenditures during the three and nine month periods ended September 30, 2006 compared to the same periods of 2005 is due to increased drilling operations and conducting seismic and airborne gravity surveys that were not performed during the same periods in 2005.

Midstream Capital Expenditures

Our capital expenditures for our refining and marketing business segment for the quarter ended September 30, 2006 were $3.4 million and for the nine month period ended September 30, 2006 $12.0 million compared with $0.1 million and $2.7 million during the same periods in 2005. The increase in capital expenditures during the three and nine month periods ended September 30, 2006 is primarily related to our refinery optimization program that was initiated in the second half of 2005 and was completed during the third quarter of 2006.

Downstream Capital Expenditures

Our capital expenditures for our wholesale and retail distribution business segment for the quarter ended September 30, 2006 were $1.0 million and for the nine month period ended September 30, 2006 $2.0 million compared with $0.5 million and $1.3 million during the same periods in 2005. Our third quarter 2006 capital expenditures consisted of costs associated with the construction and purchase of storage tanks and related infrastructure, the purchase of a new fuel distribution software for the downstream business, and costs related to the acquisition of Shell PNG, which was finalized in October 2006.

LIQUIDITY

Sources of Capital

•

Upstream

We currently fund all of our upstream capital expenditures using the proceeds of the $125 million Indirect Participation Interest Agreement that we entered into in February 2005.

•

Midstream

In August 2006, we renewed our Secured Revolving Crude Import Facility with BNP Paribas (Singapore Branch), increasing the facility from $150 million to $170 million. This crude import facility is used to finance purchases of crude feedstocks for our refinery. Our ability to borrow additional amounts under this crude import facility expires on June 30, 2007. As of September 30, 2006, $66.4 million remained outstanding under the crude import facility. The weighted average interest rate under the crude import facility was 7.36% for the nine month period ended September 30, 2006.

•

Downstream

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

•

Corporate

On May 4, 2006, we entered into a $130 million two year secured loan facility. The initial interest rate under this secured loan facility is 4%, increasing to 10% if we do not enter into an agreement with the lenders under this facility related to the development of a liquefied natural gas facility (LNG). We received $65 million in gross proceeds on the closing date of this secured loan facility and a further $35 million on June 29, 2006. A further drawdown of $18 million was made in September 2006. A portion of these proceeds was used to repay $25.3 million in principal and interest outstanding under an unsecured loan that we entered into on January 28, 2005. On October 27, 2006, $12 million, representing the balance available under this facility, was drawn down.

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Capital Requirement

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

•

Upstream

We are obligated under our $125 million indirect participation agreement entered into in February 2005 to drill eight exploration wells. We are currently drilling our third exploration well (Elk #1), pursuant to this indirect participation interest agreement, where drilling costs have increased as a result of a discovery with high pressure gas and gas liquids. The higher costs of the Elk #1 well may be partially offset by the payment of a pending insurance claim under our control of well policy. We believe the potential recovery under the insurance claim, combined with funds remaining under the indirect participation agreement should be sufficient to meet this obligation. The cost of drilling exploration wells in Papua New Guinea is subject to numerous factors, including the location where such wells are drilled. We believe that we will be able to reduce the cost of future exploration wells; however, if we are unable to drill future exploration wells at a cost per well that is significantly lower than the current cost of the Elk discovery well drilled pursuant to this agreement, we may not have sufficient funds to satisfy our obligations under the indirect participation agreement, and would look to farm-in or raise additional capital. However, we can provide no assurance that a farm-in will be completed or that the terms of any such farm-in will be acceptable to us. As of September 30, 2006, we had incurred $74.2 million in capital expenditures related to the drilling of exploration wells required to be drilled pursuant to the indirect participation interest agreement.

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

•

Midstream

We believe that we will have sufficient funds from the proceeds of our secured loan facility entered into in May 2006 to pay our estimated capital expenditures for the remaining quarter of 2006. As of September 30, 2006, our primary lender for the midstream have agreed to defer interest payable until September 30, 2007 and principal until December 31, 2007 to assist our cash flows. While cash flows from operations are expected to be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility, our refinery may not generate sufficient cash flows to cover all of the interest and principal payments under our secured loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future. We can provide no assurances that we will be able to obtain such additional capital or that our lenders will agree to refinance these facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us.

•

Downstream

We believe that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for the fourth quarter of 2006. We acquired Shell’s distribution business in Papua New Guinea for $10 million on October 1, 2006. We have already paid the acquisition price. In addition to the payment of the purchase price of $10.0 million, we have paid $20.6 million for receivables and existing inventories of refined products after the closing date which is subject to a final reconciliation.

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CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The following table contains information on payments for contracted obligations as of September 30, 2006 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


Contractual obligations
(in thousands)	Total		Less than 1 year		1 — 2 years		2 — 3 years		3 — 4 years		4 — 5 years		More than 5 years
Secured loan obligations	$	194,000		—	$	127,000	$	9,000	$	9,000	$	9,000	$	40,000
Accrued financing costs	$	1,450		—	$	1,450		—		—		—		—
Indirect participation interest⁽¹⁾	$	1,750	$	1,750		—		—		—		—		—
Indirect participation interest⁽²⁾	$	51,768	$	20,500	$	31,268		—		—		—		—
Petroleum prospecting and retention licenses⁽³⁾	$	51	$	51		—		—		—		—		—

Total	$	249,019	$	22,301	$	159,718	$	9,000	$	9,000	$	9,000	$	40,000


(1)		These amounts represent the estimated of the cost of completing our commitment to drill exploration wells under our indirect participation interest agreement entered into in July 2003. See Note 16 to our unaudited financial statements for the three and nine month periods ended September 30, 2006 and 2005.

(2)		These amounts represent the estimated cost of completing our commitment to drill exploration wells under our indirect participation interest agreement entered into in February 2005. See Note 16 to our unaudited financial statements for the three and nine month periods ended September 30, 2006 and 2005.

(3)		The amount pertaining to the petroleum prospecting and retention licenses represents the amount InterOil has committed to spend to its joint venture partners. In addition to this amount, InterOil must drill an exploration well in Petroleum Prospecting License 237 prior to the end of March 2009 in order to retain this license. As the cost of drilling this well cannot be estimated, it is not included within the above table.

OFF-BALANCE SHEET ARRANGEMENTS

As of September 30, 2006, we did not have any off balance sheet arrangements and did not enter into any during the three month period ended September 30, 2006, including any relationships with unconsolidated entities or financial partnerships to enhance perceived liquidity.

TRANSACTIONS WITH RELATED PARTIES

Petroleum Independent and Exploration Corporation, a company owned by Mr. Mulacek, our Chairman and Chief Executive Officer, earned a management fee of $37,500 during the third quarter of 2006. This management fee relates to Petroleum Independent and Exploration Corporation being appointed the General Manager of one of our subsidiaries, S.P. InterOil, LDC.

Breckland Limited provides technical and advisory services to us on normal commercial terms. Roger Grundy, one of our directors, is also a director of Breckland Limited and he provides consulting services to us as an employee of Breckland. Amounts paid or payable to Breckland during the nine months ended September 30, 2006 amounted to $108,422 during the nine months ended September 30, 2006 and $95,562 during the same period in 2005.

Amounts due to directors for directors’ fees totaled $22,500 at September 30, 2006 compared to $30,500 at September 30, 2005.

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SHARE CAPITAL

Our authorized share capital consists of an unlimited number of common shares with no par value. As of September 30, 2006, we had 29,829,513 common shares outstanding and 36,189,194 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 31, 2006		—
Balance March 31, 2006		29,163,320
Shares issued on exercise of options		60,618
Shares issued on conversion of indirect participation interest		575,575
Balance June 30, 2006		29,799,513
Shares issued on exercise of options		30,000
Balance September 30, 2006		29,829,513
Remaining stock options authorized		2,681,100
Remaining shares issuable upon exercise of warrants		340,247
Remaining conversion rights authorized⁽¹⁾		3,333,334
Other		5,000
Balance September 30, 2006 Diluted		36,189,194


(1)		In 2005, we sold indirect participation working interests in our exploration program. Some of the investors under our indirect participation interest agreement entered into in February 2005 have the right to convert, under certain circumstances, their interest to our common shares. If 100% of the investors under our indirect participation interest agreement choose to convert their interests, we would be required to issue an additional 3,333,334 common shares.

FINANCIAL AND DERIVATIVE INSTRUMENTS

With the exception of cash and cash equivalents and restricted cash, all financial assets are non-interest bearing. During the nine months ended September 30, 2006, we earned 3.8% on the cash on deposit related to the crude import facility. In the nine months ended September 30, 2006, cash and cash equivalents earned an average interest rate of 4.6% per annum on cash, other than the cash on deposit that was related to the crude import facility, compared to 1.6% during the same period in 2005.

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, all short-term loan

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facilities and amounts due to related parties approximate fair values due to the short term maturities of these instruments.

Restricted Cash

Restricted cash is comprised of the following:


	Balance at September 30,
Restricted cash	2006		2005
Cash deposit on crude import facility (4.7%)		35,652,911		27,364,638
Cash deposit on secured loan agreement (3.8%)		642,165		5,070,202
Bank term deposits on Petroleum Prospecting licenses (1.0%)		107,740		104,640
Debt reserve for secured loan facility		2,368,901		—
Cash deposit on office premises (4.5%)		39,572		—

Total		38,811,289		32,539,480

Cash held as a deposit on the crude import facility secures a portion our crude import facility entered into in August 2006. The cash held as a deposit on the secured loan agreement provides a portion of the security for our secured loan agreement entered into in September 2001. Bank term deposits on Petroleum Prospecting Licenses are unavailable to us while Petroleum Prospecting Licenses 236, 237 and 238 are being utilized.

Foreign Currency Hedge Contracts

We had no outstanding foreign currency forward contracts at September 30, 2006 and 2005.

Commodity Derivative 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 our refined product and crude inventories.

For a description of our current derivative contracts as of September 30, 2006, see Note 6 to our unaudited financial statements for the three and nine month periods ended September 30, 2006 and 2005.

CRITICAL ACCOUNTING ESTIMATES

Certain of our accounting policies require that we make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. For a discussion of those accounting policies, please refer to our Management’s Discussion and Analysis for the year ended December 31, 2005 available at www.sedar.com.

NEW ACCOUNTING STANDARDS

For a discussion of the new accounting standards to be used by us in 2006, please refer to our Management’s Discussion and Analysis for the year ended December 31, 2005 available at www.sedar.com.

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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Table of Contents

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Management’s Discussion and Analysis			2
Overview			2
Summary of Quarterly Results			2
Business Environment			5
Risk Factors			5
Forward-looking statements			5
Results of Operations			6
Upstream—Exploration and Production			6
Midstream—Refining and Marketing			8
Downstream—Wholesale and Retail Distribution			14
Corporate			15
Non-GAAP Measures			16
Capital Resources			18
Operating Activities			18
Investing Activities			19
Financing Activities			19
Upstream Capital Expenditures			19
Midstream Capital Expenditures			20
Downstream Capital Expenditures			20
Liquidity			20
Sources of Capital			20
Capital Requirements			21
Contractual Obligations and Commitments			22
Off-Balance Sheet Arrangements			22
Transactions with Related Parties			22
Share Capital			23
Financial and Derivative Instruments			23
Restricted Cash			24
Foreign Currency Hedge Contracts			24
Commodity Derivative Contracts			24
Critical Accounting Estimates			24
New Accounting Standards			24
Public Securities Filings			24





INTEROIL CORPORATION
3rd Quarter, 2006