6-K

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO
RULE 13a-16 OR 15d-16 OF THE SECURITIES EXCHANGE ACT OF 1934

For the month of November 2006

Commission File Number: 001-32179

INTEROIL CORPORATION

(Exact name of registrant as specified in its charter)

NEW BRUNSWICK, CANADA
(State or other jurisdiction of incorporation or organization)

60-92 COOK STREET
PORTSMITH, QLD 4870, AUSTRALIA
(Address of principal executive offices)

Registrant’s telephone number, including area code: (61) 7 4046 4600

     Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

     Form 20-F  o           Form 40-F  þ

     Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):      

     Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):      

     Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

     Yes  o           No  þ

     If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

INTEROIL CORPORATION
By:	/s/ PHIL MULACEK
	Phil Mulacek
	Chief Executive Officer

Date: November 14, 2006

INTEROIL CORPORATION
FORM 6-K FOR THE MONTH OF NOVEMBER 2006

Exhibit Index

1. Management’s Discussion and Analysis for the three and nine month periods ended September 30, 2006.

2. Unaudited Consolidated Financial Statements for three and nine month periods ended September 30, 2006 and 2005.

EX-99.1

INTEROIL CORPORATION
3rd Quarter, 2006

Management’s Discussion and Analysis

November 14, 2006

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
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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 Sale of Negative-Margin Exports

Increase in Middle Distillate Production

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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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Page 23 of 24

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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EX-99.2

Exhibit 2

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

Nine months and quarter ended September 30, 2006 and 2005

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

	As at
	September 30,			December 31,			September 30,
	2006			2005			2005
	$			$			$
	(unaudited)			(audited)			(unaudited)
							(adjusted — note 23)
Assets
Current assets:
Cash and cash equivalents (note 4)		30,597,797			59,601,807			64,512,686
Cash restricted (note 6)		38,811,289			16,662,269			32,539,480
Trade receivables (note 7)		33,353,429			49,958,973			34,604,923
Commodity derivative contracts (note 6)		1,703,100			1,482,798			317,750
Deferred hedge loss (note 6)		—			—			442,463
Other assets		95,265			1,011,195			424,469
Inventories (note 8)		103,125,128			44,087,484			66,660,952
Prepaid expenses		1,509,444			638,216			885,357
Deposit on business acquisition (note 24)		30,639,000			—			—
Total current assets		239,834,452			173,442,742			200,388,080
Deferred financing costs (note 15)		1,831,073			1,256,816			1,195,484
Plant and equipment (note 9)		236,989,837			237,399,148			238,923,484
Oil and gas properties (note 10)		28,044,170			16,399,492			13,491,944
Future income tax benefit		1,203,600			1,058,898			1,094,416
Total assets		507,903,132			429,557,096			455,093,408
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities		72,362,650			26,005,034			42,401,468
Income tax payable		3,492,900			3,900,459			3,180,057
Working capital facility — crude feedstock (note 11)		66,425,433			70,724,322			53,580,043
Deferred hedge gain (note 6)		959,687			1,016,998			—
Unsecured loan (note 14)		—			21,453,132			20,889,196
Deferred LNG project liability (note 15)		5,092,097			—			—
Current portion of secured loan (note 15)		—			9,000,000			9,000,000
Current portion of indirect participation interest — PNGDV (note 16)		1,749,626			—			—
Current portion of indirect participation interest (note 16)		19,533,513			35,092,558			38,614,902
Total current liabilities		169,615,906			167,192,503			167,665,666
Accrued financing costs (note 15)		1,450,000			921,109			906,664
Secured loan (note 15)		186,053,775			71,500,000			76,000,000
Indirect participation interest (note 16)		29,794,048			30,166,311			39,183,290
Indirect participation interest — PNGDV (note 16)		—			9,685,830			9,685,830
Total liabilities		386,913,729			279,465,753			293,441,450
Non-controlling interest (note 17)		5,726,684			6,023,149			6,160,667
Shareholders’ equity:
Share capital (note 18)		232,678,088			223,934,500			222,727,624
Authorised — unlimited
Issued and outstanding — 29,829,513
(Dec 31, 2005 — 29,163,320)
(Sep 30, 2005 — 29,062,920)
Contributed surplus		4,196,247			2,933,586			2,637,705
Warrants (note 20)		2,137,852			2,137,852			2,137,852
Foreign currency translation adjustment		1,343,294			477,443			1,241,146
Conversion options (note 16)		25,475,368			25,475,368			25,475,368
Accumulated deficit		(150,568,130	)		(110,890,555	)		(98,728,404	)
Total shareholders’ equity		115,262,719			144,068,194			155,491,291
Total liabilities and shareholders’ equity		507,903,132			429,557,096			455,093,408

See accompanying notes to the consolidated financial statements

-2-

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

	Quarter ended						Nine months ended
	September 30			September 30			September 30			September 30
	2006			2005			2006			2005
	$			$			$			$
	(unaudited)			(unaudited)			(unaudited)			(unaudited)
				(adjusted- note 23)						(adjusted- note 23)
Revenue
Sales and operating revenues		109,351,784			128,792,531			340,758,419			357,097,185
Interest		1,047,618			586,034			2,375,543			984,670
Other		972,448			86,828			3,191,978			242,019
		111,371,850			129,465,393			346,325,940			358,323,874
Expenses
Cost of sales and operating expenses		104,460,372			117,921,375			335,078,455			344,074,031
Administrative and general expenses		8,008,969			5,484,711			22,051,328			12,563,127
Depreciation and amortization		3,099,858			2,943,295			8,799,170			8,338,380
Exploration costs, excluding exploration impairment (note 10)		52,244			218,360			1,715,614			306,275
Exploration impairment (note 10)		34,997			116,762			299,815			397,237
Legal and professional fees		886,676			450,524			2,803,935			2,431,709
Short term borrowing costs		2,444,277			1,839,753			6,625,549			6,725,207
Long term borrowing costs		3,478,351			1,600,798			7,247,211			4,789,360
Accretion expense (note 16)		617,807			1,390,351			3,399,114			4,383,124
Loss on amendment of indirect participation interest — PNGDV (note 16)		—			—			1,446,901			—
Foreign exchange loss/(gain)		(4,402,024	)		(588,438	)		(4,493,566	)		(118,616	)
		118,681,527			131,377,491			384,973,526			383,889,834
Loss before income taxes and non-controlling interest		(7,309,677	)		(1,912,098	)		(38,647,586	)		(25,565,960	)
Income tax recovery/(expense)		(291,165	)		(984,009	)		(1,336,932	)		(1,791,038	)
Loss before non-controlling interest		(7,600,842	)		(2,896,107	)		(39,984,518	)		(27,356,998	)
Non-controlling interest (note 17)		47,241			(15,630	)		306,943			236,738
Net loss		(7,553,601	)		(2,911,737	)		(39,677,575	)		(27,120,260	)
Basic loss per share (note 21)		(0.25	)		(0.10	)		(1.34	)		(0.94	)
Diluted loss per share (note 21)		(0.25	)		(0.10	)		(1.34	)		(0.94	)
Weighted average number of common shares outstanding
Basic and diluted		29,802,448			29,030,677			29,523,026			28,757,305

See accompanying notes to the consolidated financial statements

-3-

InterOil Corporation
Consolidated Statements of Cash Flows
(Unaudited, Expressed in United States dollars)

	Quarter ended						Nine months ended
	September 30			September 30			September 30			September 30
	2006			2005			2006			2005
	$			$			$			$
	(unaudited)			(unaudited)			(unaudited)			(unaudited)
				(adjusted- note 23)						(adjusted- note 23)
Cash flows provided by (used in):
Operating activities
Net (loss) (note 5)		(7,553,601	)		(2,911,737	)		(39,677,575	)		(27,120,260	)
Adjustments for non-cash transactions
Non-controlling interest		(47,241	)		15,630			(306,943	)		(236,738	)
Depreciation and amortization		3,099,858			2,943,295			8,799,170			8,338,380
Future income tax asset		(241,124	)		148,422			(144,702	)		209,215
Loss/(gain) on sale of plant and equipment		(19,894	)		(70,118	)		236,499			(70,118	)
Impairment of plant and equipment		—			—			755,857			—
Amortization of discount on debt		—			14,445			28,891			146,810
Amortization of deferred financing costs		6,376			38,668			104,717			116,004
Accretion of discount on indirect participation interest		617,807			1,390,351			3,399,114			4,383,124
Loss/(gain) on unsettled hedge contracts		(906,205	)		22,595			(315,485	)		(21,200	)
Gain on derivative contracts		177,050			(779,728	)		48,350			(779,728	)
Stock compensation expense/(recovery)		600,251			1,584,919			1,403,122			1,086,115
Capitalized oil and gas properties expensed		34,997			116,762			299,815			397,237
Inventory revaluation		6,269,821			225,671			13,342,181			225,671
Loss on amendment of indirect participation interest — PNGDV		—			—			1,446,901			—
Unrealized foreign exchange (gain)		(4,402,024	)		(588,438	)		(4,493,566	)		(118,616	)
Non-cash interest on secured loan facility		1,040,005			—			1,432,383			—
Change in non-cash operating working capital Increase in foreign currency translation adjustment		682,934			160,248			865,851			777,946
(Increase)/decrease in trade receivables		(319,215	)		16,893,625			16,605,544			24,093,144
(Increase)/decrease in other assets and prepaid expenses		708,551			714,235			44,702			(313,567	)
(Increase) in inventories		(3,686,325	)		(16,321,830	)		(68,001,866	)		(38,851,105	)
Increase in accounts payable, accrued liabilities and income tax payable		5,023,161			17,614,553			46,484,783			13,252,835
		1,085,182			21,211,568			(17,642,257	)		(14,484,851	)
Investing activities
Expenditure on oil and gas properties		(9,051,135	)		(2,154,686	)		(11,828,885	)		(7,283,820	)
Expenditure on plant and equipment		(2,950,647	)		(996,200	)		(13,179,740	)		(2,905,179	)
Proceeds from indirect participation interest		—			—			—			80,410,591
Expenditure on oil and gas properties applied against indirect participation interest (note 16)		(3,461,981	)		(9,168,841	)		(20,764,839	)		(17,970,822	)
Proceeds received on sale of assets		50,562			76,788			3,797,526			76,788
Repayment of business combination financing		—			—			—			(12,226,581	)
Deposit on business acquisition (note 24)		(26,139,000	)		—			(30,639,000	)		—
(Increase) in restricted cash held as security on borrowings		(12,302,122	)		(233,808	)		(22,149,020	)		(16,940,257	)
Change in non-cash working capital
Increase/(decrease) in accounts payable and accrued liabilities		12,479			73,507			(713,699	)		3,118,750
		(53,841,844	)		(12,403,240	)		(95,477,657	)		26,279,470
Financing activities
Proceeds from/(repayments of) unsecured loan		—			889,196			(21,453,132	)		20,889,196
(Repayments of) secured loan		—			—			(4,500,000	)		—
Proceeds from secured loan, net of transaction costs		34,257,500			—			113,713,489			—
Increase in deferred financing fees related to secured loan		100,000			—			—			—
Proceeds from conversion options		—			—			—			22,700,814
(Repayments) to related parties		—			—			—			(1,056,251	)
(Repayments) of working capital facility		(12,197,693	)		(29,384,454	)		(4,298,889	)		(22,940,498	)
Proceeds from issue of common shares		158,101			597,733			654,436			4,580,408
		22,317,908			(27,897,525	)		84,115,904			24,173,669
Increase/(decrease) in cash and cash equivalents		(30,438,754	)		(19,089,197	)		(29,004,010	)		35,968,288
Cash and cash equivalents, beginning of period		61,036,551			83,601,883			59,601,807			28,544,398
Cash and cash equivalents, end of period (note 4)		30,597,797			64,512,686			30,597,797			64,512,686

See accompanying notes to the consolidated financial statements

See note 5 for non cash financing and investing activities

-4-

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

	Nine months ended			Year ended			Nine months ended
	September 30,			December 31,			September 30,
	2006			2005			2005
	$			$			$
	(unaudited)			(audited)			(unaudited)
							(adjusted — note 23)
Share capital
At beginning of period		223,934,500			216,813,654			216,813,654
Issue of capital stock (note 18)		8,743,588			7,120,846			5,913,970
At end of period		232,678,088			223,934,500			222,727,624
Contributed surplus
At beginning of period		2,933,586			1,841,776			1,841,776
Stock compensation (note 19)		1,262,661			1,091,810			795,929
At end of period		4,196,247			2,933,586			2,637,705
Warrants
At beginning of period		2,137,852			2,258,227			2,258,227
Movement for period (note 20)		—			(120,375	)		(120,375	)
At end of period		2,137,852			2,137,852			2,137,852
Foreign currency translation adjustment
At beginning of period		477,443			463,200			463,200
Movement for period, net of tax		865,851			14,243			777,946
At end of period		1,343,294			477,443			1,241,146
Conversion options
At beginning of period		25,475,368			25,475,368			—
Movement for period (note 16)		—			—			25,475,368
At end of period		25,475,368			25,475,368			25,475,368
Accumulated deficit
At beginning of period		(110,890,555	)		(71,608,144	)		(71,608,144	)
Net (loss) for period		(39,677,575	)		(39,282,411	)		(27,120,260	)
At end of period		(150,568,130	)		(110,890,555	)		(98,728,404	)
Shareholders’ equity at end of period		115,262,719			144,068,194			155,491,291

See accompanying notes to the consolidated financial statements

-5-

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

1. Nature of operations and organization

InterOil Corporation (the “Company” or “InterOil”) is a publicly traded, integrated oil and gas company operating in Papua New Guinea (“PNG”).

Management has segmented the company’s business based on differences in products and services and management strategy and responsibility. The Company’s business is conducted predominantly through three major business segments – upstream, midstream and downstream.

Upstream includes exploration for and development of crude oil and natural gas. Midstream includes refinery operations. The refinery processes crude oil into naphtha, gasoline, diesel, LPG, jet/kerosene, and low sulphur waxy residue. The midstream operations sell to the PNG domestic market as well as to the export market. Downstream includes the distribution of refined products and lubricants, including gasoline, diesel and fuel oil in PNG.

2. Significant accounting policies

(a) Principles of consolidation and the preparation of financial statements

These financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) applicable to a going concern.

The consolidated financial statements for the nine months ended September 30, 2006 are in accord with Canadian GAAP requiring management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from these estimates.

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

(b) Going concern

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

As shown in the consolidated financial statements, the Company incurred a net loss of $39.7 million and used cash in its operating activities of $17.6 million during the nine months ended September 30, 2006. The Company had cash and cash equivalents of $69.4 million at September 30 2006, $38.8 million being in restricted cash. The Company believes that this is sufficient to fund on-going operations. The current financial condition, among other factors, indicates that with focused management and the continued support of lenders InterOil has the ability to continue as a going concern.

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

(c) Cash and cash equivalents

Cash and cash equivalents consist of cash on hand and deposits with a maturity of less than three months at the time of purchase and excludes restricted cash. Cash and cash equivalents are carried at cost. Accrued interest is included with other receivables.

(d) Restricted cash

Restricted cash consists of cash on deposit with a maturity of less than three months at the time of purchase but which is restricted from being used in daily operations. Restricted cash is carried at cost. Accrued interest is included with other receivables.

(e) Trade receivables

The collectibility of debts is assessed at the reporting date and specific provision is made for any doubtful accounts. The Company sells certain trade receivables with recourse to BNP Paribas under its working capital facility. The receivables are retained on the balance sheet as the Company retains the risks and rewards associated with carrying the receivables.

-6-

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

2. Significant accounting policies (cont’d)

(f) Inventory

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

(g) Derivative financial instruments

Derivative financial instruments are utilized by the Company in the management of its crude purchase cost exposures and its naphtha, low sulphur waxy residue, diesel and jet kerosene sales price exposures. The Company’s policy is not to utilize derivative financial instruments for trading or speculative purposes. The company may choose to designate derivative financial instruments as hedges.

When applicable, at the inception of the hedge, the Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions, the nature of the risk being hedged, how the hedging instruments’ effectiveness in offsetting the hedged risk will be assessed and a description of the method for measuring ineffectiveness. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or anticipated transactions. The Company also assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items at inception and on an ongoing basis.

Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in a separate component of liabilities, until earnings are affected by the variability in cash flows of the designated hedged item.

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

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

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

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

(h) Deferred financing costs

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

-7-

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

2. Significant accounting policies (cont’d)

(i) Plant and equipment

Refinery assets

The Company’s most significant item of plant and equipment is the oil refinery in PNG. The refinery is included within midstream assets. During 2004, the company was considered to be in the construction and pre-operating stage of development of the oil refinery, however, the pre-operating stage ceased on January 1, 2005. Project costs, net of any recoveries, incurred during the pre-operating stage were capitalized as part of plant and equipment. The refinery assets are recorded at cost. Development costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Interest costs relating to the construction and pre-operating stage of the development project prior to commencement of commercial operations were capitalized as part of the cost of such plant and equipment. Refinery related assets are depreciated on straight line basis over their useful lives, at an average rate of 4% per annum. The refinery is built on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097 and does not outline any terms for restoration and closure costs.

Repairs and maintenance costs, other than major turnaround costs, are charged to earnings as incurred. Major turnaround costs will be deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround. No major turnaround costs had been incurred up to September 30, 2006.

Other assets

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

Downstream	0% - 25	%
Midstream	1% - 33	%
Upstream	4% - 100	%
Corporate	13% - 33	%

Leased assets

Operating lease payments are representative of the pattern of benefit derived from the leased asset and accordingly are included in expenses in the periods in which they are incurred.

Asset retirement obligations

Estimated costs of future dismantlement, site restoration and abandonment of properties are provided based upon current regulations and economic circumstances at year end. Management estimates there are no material obligations associated with the retirement of the refinery or with its normal operations relating to future restoration and closure costs. The refinery is built on land leased from the Independent State of Papua New Guinea. The lease expires on July 26, 2097.

Disposal of property, plant and equipment

At the time of disposition of plant and equipment, accounts are relieved of the asset values and accumulated depreciation and any resulting gain or loss is included in the statement of operations.

Environmental remediation

Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. No provision has been raised.

(j) Assets held for sale

Non-current assets are classified as held for sale and stated at the lower of their carrying amount and fair value less costs to sell if their carrying amount will be recovered principally through a sale transaction rather than through continuing use.

An impairment loss is recognized for any initial or subsequent write down of the asset (or disposal group) to fair value less costs to sell. A gain is recognized for any subsequent increase in fair value less costs to sell an asset, but not in excess of any cumulative impairment loss previously recognized. A gain or loss not previously recognized by the date of sale of the non-current asset is recognized at the date of derecognition.

Non-current assets are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognized.

Non-current assets classified as held for sale are presented separately from other assets in the balance sheet.

-8-

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

2. Significant accounting policies (cont’d)

(k) Oil and gas properties

The Company uses the successful-efforts method to account for its oil and gas exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The Company continues to carry as an asset the cost of drilling exploratory wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future or when exploration and evaluation activities have not yet reached a stage to allow reasonable assessment regarding the existence of economical reserves. Capitalized costs for producing wells will be subject to depletion on the units-of-production method. Geological and geophysical costs are expensed as incurred.

(l) Future income taxes

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment. A valuation allowance is provided against any portion of a future tax asset which will more likely not be recovered.

(m) Employee entitlements

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

(n) Revenue recognition

The following particular accounting policies, which significantly affect the measurement of profit and of financial position, have been applied.

Revenue from midstream operations:

Revenue from sales of products is recognized when products are shipped and the customer takes ownership and assumes risk of loss, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the sales price is fixed or determinable. During the period ended September 30, 2006, sales between the business segments of the Company have been eliminated from sales and operating revenues and cost of sales. Up to December 31, 2004, the sales between business segments of the Company were eliminated from sales and operating revenues and cost of sales and the asset for the refinery as all revenues and expenses relating to the refinery were capitalized as part of the development stage activities.

Revenue from downstream operations:

Sales of goods are recognized when the Company has delivered products to the customer, the customer takes ownership and assumes risk of loss, collection of the receivable is probable, persuasive evidence of an arrangement exists and the sale price is fixed or determinable. It is not the Company’s policy to sell products with a right of return.

Interest income:

Interest income is recognized on a time-proportionate basis.

(o) Foreign currency translation

For subsidiaries considered to be self-sustaining foreign operations, all assets and liabilities denominated in foreign currency are translated to United States dollars at exchange rates in effect at the balance date and all revenue and expense items are translated at the rates of exchange in effect at the time of the transactions. Foreign exchange gains or losses are reported as a separate component of shareholders’ equity.

For subsidiaries considered to be an integrated foreign operation, monetary items denominated in foreign currency are translated to United States dollars at exchange rates in effect at balance date and non-monetary items are translated at rates of exchange in effect when the assets were acquired or obligations incurred. Revenue and expense items are translated at the rates of exchange in effect at the time of the transactions. Foreign exchange gains or losses are included in the statement of operations.

(p) Stock-based compensation

The Company uses the fair value based method to account for employee stock options. Under the fair value based method, compensation expense is measured at fair value at the date of grant and is expensed over the award’s vesting period.

-9-

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

2. Significant accounting policies (cont’d)

(q) Per share amounts

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

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

(r) Vulnerability to concentration risk

Credit risk

A significant amount of the Company’s export sales are made to one customer which represented $41,645,434 (Sep 2005 — $124,088,986) or 12% (Sep 2005 – 35%) of total sales in the nine months ended September 30, 2006. The Company’s domestic sales for the period ended September 30, 2006 were not dependent on a single customer or geographic region of PNG.

Product risk

The composition of the crude feedstock will vary the refinery output of products. The 2006 output achieved includes distillates fuels, which includes diesel, gasoline and jet fuels (64%) (Sep 2005 – 53%) and naphtha and low sulphur waxy residue (27%) (Sep 2005 – 42%). The product yields obtained will vary going forward as the refinery operations are optimized and will vary based on the type of crude feedstock used.

Geographic risk

The operations of InterOil are concentrated in Papua New Guinea.

(s) Reclassification

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

-10-

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

3. Segmented financial information

As stated in note 1, management has identified three major business segments—upstream, midstream and downstream. In addition, the corporate segment is also presented. The corporate segment includes assets and liabilities that do not specifically relate to the other business segments. Results in this segment primarily include financing costs and interest income.

Segment accounting policies are the same as those described in note 2, significant accounting policies. Upstream, midstream and downstream include costs allocated from the corporate activities. The allocation is based on a fee for service. The eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventories. All sales are attributable to the Asia Pacific region.

The foreign exchange loss/(gain) for the period has been included under office and administration and other expenses resulting in negative balances for some segments during the period.

Consolidation adjustments relating to total assets relates to the elimination of intercompany loans and investments in subsidiaries.

													Consolidation
Quarter ended September 30, 2006	Upstream			Midstream			Downstream			Corporate			adjustments			Total
Revenues from external customers		—			69,900,864			39,450,920			—			—			109,351,784
Intersegment revenues		—			24,664,998			42,907			1,581,307			(26,289,212	)		—
Interest revenue		—			—			—			1,047,618			—			1,047,618
Other unallocated revenue		949,831			—			—			22,617			—			972,448
Total segment revenue		949,831			94,565,862			39,493,827			2,651,542			(26,289,212	)		111,371,850
Cost of sales and operating expenses		—			95,051,873			34,116,405			—			(24,707,906	)		104,460,372
Office and admin and other expenses		1,921,097			(1,740,249	)		3,456,662			3,010,545			(1,581,308	)		5,066,747
Exploration costs, excluding exploration impairment		52,244			—			—			—			—			52,244
Exploration impairment		34,997			—			—			—			—			34,997
Depreciation and amortisation		202,262			2,699,917			221,557			8,629			(32,507	)		3,099,858
Accretion expense		617,807			—			—			—			—			617,807
Interest expense (i)		1,349			3,329,153			38,111			2,053,056			(72,167	)		5,349,502
Loss from ordinary activities before income taxes		(1,879,925	)		(4,774,832	)		1,661,092			(2,420,688	)		104,676			(7,309,677	)
Income tax expense		—			—			(416,011	)		124,846			—			(291,165	)
Non controlling interest		—			—			—			47,241			—			47,241
Total net income/loss		(1,879,925	)		(4,774,832	)		1,245,081			(2,248,601	)		104,676			(7,553,601	)

-11-

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

3. Segmented financial information (cont’d)

Quarter ended September 30, 2005												Consolidation
(adjusted - note 23)	Upstream			Midstream		Downstream			Corporate			adjustments			Total
Revenues from external customers		—			96,652,246		32,140,285			—			—			128,792,531
Intersegment revenues		—			18,551,357		313,227			555,312			(19,419,896	)		—
Interest revenue		—			—		—			586,034			—			586,034
Other unallocated revenue		—			—		—			86,828			—			86,828
Total segment revenue		—			115,203,603		32,453,512			1,228,174			(19,419,896	)		129,465,393
Cost of sales and operating expenses		—			106,863,681		28,862,860			—			(17,805,166	)		117,921,375
Office and admin and other expenses		333,360			2,339,659		1,063,813			3,336,708			(740,695	)		6,332,845
Exploration costs, excluding exploration impairment		218,360			—		—			—			—			218,360
Exploration impairment		116,762			—		—			—			—			116,762
Depreciation and amortisation		212,642			2,663,526		54,525			12,602			—			2,943,295
Accretion expense		1,390,351			—		—			—			—			1,390,351
Interest expense		1,811			2,320,212		41,884			164,024			(73,428	)		2,454,503
Loss from ordinary activities before income taxes		(2,273,286	)		1,016,525		2,430,430			(2,285,160	)		(800,607	)		(1,912,098	)
Income tax expense		—			—		(965,001	)		(19,008	)		—			(984,009	)
Non controlling interest		—			—		—			(15,630	)		—			(15,630	)
Total net income/loss		(2,273,286	)		1,016,525		1,465,429			(2,319,798	)		(800,607	)		(2,911,737	)

													Consolidation
Nine months ended September 30, 2006	Upstream			Midstream			Downstream			Corporate			adjustments			Total
Revenues from external customers		—			235,577,338			105,181,081			—			—			340,758,419
Intersegment revenues		—			68,690,096			51,821			2,910,046			(71,651,963	)		—
Interest revenue		—			—			—			2,375,543			—			2,375,543
Other unallocated revenue		3,142,218			—			—			49,760			—			3,191,978
Total segment revenue		3,142,218			304,267,434			105,232,902			5,335,349			(71,651,963	)		346,325,940
Cost of sales and operating expenses		—			312,709,827			91,110,544			—			(68,741,917	)		335,078,454
Office and admin and other expenses		5,997,059			3,950,050			9,032,332			7,985,832			(2,910,045	)		24,055,228
Exploration costs, excluding exploration impairment		1,715,614			—			—			—			—			1,715,614
Exploration impairment		299,815			—			—			—			—			299,815
Depreciation and amortisation		573,157			7,923,499			372,931			27,105			(97,522	)		8,799,170
Accretion expense		3,399,114			—			—			—			—			3,399,114
Interest expense (i)		4,019			8,402,419			115,531			4,723,809			(1,619,647	)		11,626,131
Loss from ordinary activities before income taxes		(8,846,560	)		(28,718,361	)		4,601,564			(7,401,397	)		1,717,168			(38,647,586	)
Income tax expense		—			—			(1,276,860	)		(60,072	)		—			(1,336,932	)
Non controlling interest		—			—			—			306,943			—			306,943
Total net income/loss		(8,846,560	)		(28,718,361	)		3,324,704			(7,154,526	)		1,717,168			(39,677,575	)
Total assets		65,965,530			344,288,862			83,803,927			383,366,085			(370,021,272	)		507,403,132

-12-

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

3. Segmented financial information (cont’d)

Nine months ended September 30, 2005													Consolidation
(adjusted-note 23)	Upstream			Midstream			Downstream			Corporate			adjustments			Total
Revenues from external customers		—			271,436,013			85,661,172			—			—			357,097,185
Intersegment revenues		—			56,497,379			442,579			1,412,887			(58,352,845	)		—
Interest revenue		—			—			—			984,670			—			984,670
Other unallocated revenue		—			—			—			242,019			—			242,019
Total segment revenue		—			327,933,392			86,103,751			2,639,576			(58,352,845	)		358,323,874
Cost of sales and operating expenses		—			324,010,324			75,924,057			—			(55,860,350	)		344,074,031
Office and admin and other expenses		1,227,840			8,162,013			4,576,487			6,024,841			(1,598,270	)		18,392,911
Exploration costs, excluding exploration impairment		306,275			—			—			—			—			306,275
Exploration impairment		397,237			—			—			—			—			397,237
Depreciation and amortisation		218,011			7,935,623			149,450			35,296			—			8,338,380
Accretion expense		4,383,124			—			—			—			—			4,383,124
Interest expense		5,579			7,406,239			181,942			540,736			(136,620	)		7,997,876
Loss from ordinary activities before income taxes		(6,538,066	)		(19,580,807	)		5,271,815			(3,961,297	)		(757,605	)		(25,565,960	)
Income tax expense		—			—			(1,694,610	)		(96,428	)		—			(1,791,038	)
Non controlling interest		—			—			—			236,738			—			236,738
Total net income/ loss		(6,538,066	)		(19,580,807	)		3,577,205			(3,820,987	)		(757,605	)		(27,120,260	)
Total assets		92,171,151			331,064,472			43,150,517			231,583,218			(242,875,950	)		455,093,408

4. Cash and cash equivalents

The components of cash and cash equivalents are as follows:

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Cash on deposit		30,597,797		59,601,807		64,512,686

5. Supplemental cash flow information

All non-cash investing and financing activities disclosed in note 5 relate to the “corporate” segment except for that involving the decrease in plant and equipment as a result of impairment (upstream).

	Quarter ended				Nine months ended
	September 30		September 30		September 30		September 30
	2006		2005		2006		2005
	$		$		$		$
Cash paid during the year
Interest		1,648,663		1,246,730		8,199,040		5,062,917
Income taxes		497,566		8,712		1,811,005		17,551
Interest received		1,169,643		—		2,370,265		200,497
Non-cash investing and financing activities:
Decrease in plant and equipment as a result of impairment		—		—		755,857		—
Increase in deferred LNG project liability		1,517,532		—		5,092,097		—
Increase in share capital from:
the exercise of share options		—		62,390		140,461		255,637
the exercise of warrants		—		120,375		—		120,375
conversion of indirect participation interest (PNGDV) into share capital		—		923,000		7,948,691		923,000

-13-

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

6. Financial instruments

Cash and cash equivalents

With the exception of cash and cash equivalents and restricted cash, all financial assets are non-interest bearing. In the nine months ended September 30, 2006, the company earned 4.7% on the cash on deposit which related to the working capital facility. In the nine months ended September 30, 2006, cash and cash equivalents earned an average interest rate of 4.6% per annum (Sep 2005 — 1.6%) on cash, other than the cash on deposit that was related to the working capital facility.

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

Cash restricted

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

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Cash deposit on working capital facility (4.7%)		35,652,911		16,452,216		27,364,638
Cash deposit on secured loan (3.8%)		642,165		106,267		5,070,202
Debt reserve for secured loan		2,368,901		—		—
Bank term deposits on Petroleum Prospecting Licenses (0.8%)		107,740		103,786		104,640
Cash deposit on office premises (4.5%)		39,572		—		—
		38,811,289		16,662,269		32,539,480

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

Bank term deposits on Petroleum Prospecting Licenses are unavailable to the company while Petroleum Prospecting Licenses 236, 237 and 238 are being utilized by the Company.

Commodity derivative contracts

InterOil uses derivative commodity instruments to manage exposure to price volatility on a portion of its refined product and crude inventories. As at September 30, 2006, InterOil had entered into a naphtha swap agreement to hedge a portion of the anticipated fourth quarter 2006 sales of naphtha, and crude swap agreements to hedge a portion of the anticipated 2006 sales of finished products. InterOil had also entered into a crude swap agreement to hedge a portion of its anticipated fourth quarter 2006 low sulphur waxy residue sales by buying and selling the raw material component, crude at fixed prices to match the timing of the purchase and sale respectively.

At September 30, 2006, InterOil had a net receivable of $1,703,100 (Dec 2005 — $1,482,798, Sep 2005 —$317,750) relating to commodity hedge contracts. Of this total, a receivable of $1,166,450 (Dec 2005 —$897,798, Sep 2005 — $317,750) relates to hedges deemed effective at September 30, 2006 and a receivable of $536,650 (Dec 2005 — receivable of $585,000, Sep 2005 — $nil) relates to derivative contracts that were closed and for which hedge accounting has been discontinued. The gain on the derivative contracts for which hedge accounting was discontinued is included in general and administration expenses for the nine months ended September 30, 2006. The gain on the hedges on which final pricing will be determined in future periods of $959,687 (Dec 2005 — gain of $1,016,998, Sep 2005 — loss of $442,463) has been included in the deferred hedge gain/(loss) account on the balance sheet.

The following summarizes the effective hedge contracts by derivative type on which final pricing will be determined in future periods as at September 30, 2006:

Derivative	Type	Notional volumes (bbls)
Crude swap	Sell crude	50,000
Crude swap	Buy crude	100,000
Naphtha spread	Sell naphtha	75,000

-14-

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

6. Financial instruments (cont’d)

As at December 31, 2005:

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

As at September 30, 2005:

Derivative	Type	Notional volumes (bbls)
Crude swap	Sell crude	150,000
Diesel crack spread swap	Sell diesel/buy crude	150,000

7. Trade receivables

At September 30, 2006, the Company had a discounting facility with BNP Paribas on specific monetary receivables (note 11). Under the facility, the company is able to sell on a revolving basis specific monetary receivables up to $40,000,000. As at September 30, 2006, $nil (Dec 2005 — $23,196,914, Sep 2005 — $17,048,558) in outstanding accounts receivable had been sold with recourse under the facility. As the sale is with recourse, the receivables are retained on the balance sheet and included in the accounts receivable and the proceeds are recognized in the working capital facility. The Company has retained the responsibility for administering and collecting accounts receivable sold.

At September 30, 2006, $20,258,634 (Dec 2005 — $39,430,264, Sep 2005 — $27,125,075) of the trade receivables secures the BNP Paribas working capital facility disclosed in note 11. This balance includes $5,578,923 (Dec 2005 — $5,059,192, Sep 2005 — $2,905,771) of intercompany receivables which were eliminated on consolidation.

8. Inventories

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Midstream (crude oil feedstock)		38,752,643		5,019,580		20,595,507
Midstream (refined petroleum product)		48,183,651		25,967,357		31,981,994
Downstream (refined petroleum product)		16,188,834		13,100,547		14,083,451
		103,125,128		44,087,484		66,660,952

At September 30, 2006, inventory had been written down to its net realizable value. The write down for the nine month period of $13,342,181 (Dec 2005 — $355,215, Sep 2005 — $225,671) is included in cost of sales.

At September 30, 2006, $86,936,294 (Dec 2005 — $30,986,937, Sep 2005 — $52,577,501) of the midstream inventory balance secures the BNP Paribas working capital facility disclosed in note 11.

-15-

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

9. Plant and equipment

The majority of the Company’s plant and equipment is located in PNG, except for items in the corporate segment with a net book value of $117,777 (Dec 2005 — $132,375, Sep 2005 — $105,997) which are located in Australia. Amounts in deferred project costs and work in progress are not being amortised.

Consolidation entries relates to midstream assets which were created when the gross margin on 2004 refinery sales to the downstream segment were eliminated in the development stage of the refinery.

										Corporate &
September 30, 2006	Upstream			Midstream			Downstream			Consolidated			Totals
Plant and equipment		1,247,201			249,856,717			13,164,752			135,788			264,404,458
Deferred project costs and work in progress		—			—			2,440,171			—			2,440,171
Consolidation entries		—			—			—			(3,023,196	)		(3,023,196	)
Accumulated depreciation and amortization		(136,153	)		(18,953,631	)		(7,723,801	)		(18,011	)		(26,831,596	)
Net book value		1,111,048			230,903,086			7,881,122			(2,905,419	)		236,989,837
Capital expenditure		—			12,046,029			2,023,815			145,808			14,215,652

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

										Corporate &
September 30, 2005	Upstream			Midstream			Downstream			Consolidated			Totals
Plant and equipment		5,657,125			236,913,564			13,596,242			290,371			256,457,302
Deferred project costs and work in progress		—			1,283,947			1,187,299			—			2,471,246
Consolidation entries		—			(50,875	)		(558,646	)		(3,250,746	)		(3,860,267	)
Accumulated depreciation and amortization		(235,680	)		(7,262,007	)		(8,462,736	)		(184,374	)		(16,144,797	)
Net book value		5,421,445			230,884,629			5,762,159			(3,144,749	)		238,923,484
Capital expenditure		—			2,686,416			1,264,834			54,967			4,006,217

-16-

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

10. Oil and gas properties

Costs of oil and gas properties which are not subject to depletion and which have not been applied against the indirect participation interest liability (note 16) are as follows:

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Drilling equipment		16,710,715		15,100,860		12,087,723
Petroleum Prospecting License drilling programs at cost
PPL 238		11,333,455		1,298,632		33,446
Other properties		—		—		1,370,775
		28,044,170		16,399,492		13,491,944

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

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Exploration costs, excluding exploration impairment		1,715,614		—		306,275
Exploration impairment
Costs incurred in prior years		299,815		2,059,367		300,000
Costs incurred in current year		—		85,062		97,237
Total exploration impairment		299,815		2,144,429		397,237
		2,015,429		2,144,429		703,512

11. Working capital facility — crude feedstock

InterOil had a working capital credit facility with BNP Paribas (Singapore branch) with a maximum availability of $150,000,000. The facility was increased to $170,000,000 on August 18, 2006. The cash balance outstanding on the facility at September 30, 2006 was $66,425,433 (Dec 2005 — $70,724,322, Sep 2005 — $53,580,043) which was comprised of short term advances of $66,425,433 (Dec 2005 — $47,527,408, Sep 2005 — $36,531,485) and discounted monetary receivables of $nil (Dec 2005 — $23,196,914, Sep 2005 — $17,048,558). This financing facility supports the ongoing procurement of crude oil for the refinery and includes related hedging transactions. The facility comprises a base facility to accommodate the issuance of letters of credit followed by secured loans in the form of short term advances. In addition to the base facility, the agreement offers both a cash secured short term facility and a discounting facility on specific monetary receivables (note 7). The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables.

The facility bears interest at LIBOR + 2.5% on the short term advances. During the period the weighted average interest rate was 7.36% (Dec 2005 — 5.8%, Sep 2005 — 5.54%).

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

	September 30,			December 31,			September 30,
	2006			2005			2005
	$			$			$
Working capital credit facility		170,000,000			150,000,000			150,000,000
Less amounts outstanding:
Short term advances		(66,425,433	)		(47,527,408	)		(36,531,485	)
Discounted receivables (note 7)		—			(23,196,914	)		(17,048,558	)
Letters of credit outstanding		(46,790,000	)		(33,765,000	)		(15,571,729	)
Hedging facility		(1,500,000	)		(1,500,000	)		(1,500,000	)
Working capital credit facility available for use		55,284,567			44,010,678			79,348,228

-17-

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

11. Working capital facility — crude feedstock (cont’d)

At September 30, 2006, the company had one letter of credit outstanding for $46,970,000 (Dec 2005 — $33,765,000, Sep 2005 — $15,571,729) which expires in October 2007.

The cash deposit on working capital facility as separately disclosed in note 6 included restricted cash of $35,652,911 (Dec 2005 — $16,452,216, Sep 2005 — $27,364,638) which was being maintained as a security market for the facility. In addition, inventory of $86,936,294 (Dec 2005 — $30,986,937, Sep 2005 — $79,348,228), trade receivables of $20,258,634 (Dec 2005 — $39,430,214, Sep 2005 — $27,125,075) also secured the facility. The trade receivable balance securing the facility includes $5,578,923 (Dec 2005 — $5,059,192, Sep 2005 — $5,096,181) of inter-company receivables which were eliminated on consolidation.

12. Acquisition of a subsidiary

In 2006, InterOil acquired 100% of the issued share capital of PNG LNG, Inc. and Natural Gas Development Company Limited for a total cost of $1,001 which will be paid in cash. The purchase price reflected the book value of the shares at the time of acquisition. PNG LNG, Inc. and the Natural Gas Development Company Limited were both dormant shelf companies at the time of acquisition. These companies will be used for future liquid natural gas projects.

In 2005, InterOil acquired 100% of the issued share capital of Direct Employment Services Company (“DESC”) and SPI InterOil Holdings Limited for a total cost of $2,000 which was paid in cash. The purchase price reflected the book value of the shares at the time of acquisition. DESC was initially established for the purposes of providing non-profit management services to the Company for its U.S. employees and it has continued to provide management services to the Company since its acquisition. Prior to its acquisition, DESC was partially owned by Christian Vinson, the Company’s Chief Operating Officer. SPI InterOil Holdings Limited is a dormant shelf company to be used for a future business endeavor.

13. Related parties

During the nine months ended September 30, 2005, $1,056,251 was repaid in full to Petroleum Independent and Exploration Corporation (PIE) which acts as a sponsor of the Company’s oil refinery project. PIE is controlled by Phil Mulacek, an officer and director of InterOil. The loan had interest charged at a rate of 5.75% per annum while it was outstanding in 2005. During the period to September 30, 2005, the Company incurred total interest to PIE amounting to $9,376. All of the interest collected by PIE on this loan was used to pay interest incurred under the Wells Fargo facility.

SPI does not have a Board of Directors. Instead, its articles of association provide for the business and affairs of SPI to be managed by a general manager appointed by the shareholders of SPI and its US sponsor under the Overseas Private Investment Corporation (OPIC), an agency of the US Government, loan. PIE has been appointed as the general manager of SPI. Under the laws of the Commonwealth of The Bahamas, the general manager exercises all powers which would typically be exercised by a Board of Directors, being those which are not required by laws or by SPI’s constituting documents to be exercised by the members (shareholders) of SPI. During the period, $112,500 (Dec 2005 — $150,000, Sep 2005 — $112,500) was expensed for the sponsor’s (PIE) legal, accounting and reporting costs. $112,500 was included in accrued liabilities at September 30, 2006.

Breckland Limited, a company controlled by Roger Grundy, a director of InterOil, provides technical and advisory services to the Company and/or subsidiaries on normal commercial terms. Amounts paid or payable to Breckland during the period amounted to $108,422 (Dec 2005 — $179, 608, Sep 2005 — $95,562).

The services of certain executive officers and senior management of the Company are provided under a management services agreement with DESC. DESC is a U.S. private Company that was partially owned by Christian Vinson, the Company’s Chief Operating Officer prior to its acquisition by InterOil on November 23, 2005 (note 12). In 2005, InterOil acquired 100% of the issued share capital of Direct Employment Services Company (“DESC”) for a total cost of $1,000 which was paid in cash. Christian Vinson received $500 for his 50% interest in DESC. The purchase price reflects the book value of the shares at the time of acquisition. Prior to the acquisition, DESC was paid $670,039 for its management services in the nine months ended September 30, 2005.

Amounts due to Directors and executives at September 30, 2006 totaled $22,500 for Directors fees (Dec 2005 — $30,500, Sep 2005 — $30,500), and $nil for executive bonuses (Dec 2005 — $573,571, Sep 2005 — $320,000). These amounts are included in accounts payable and accrued liabilities.

-18-

InterOil Corporation

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

14. Unsecured loan

On January 28, 2005, InterOil obtained a $20 million term loan facility of which a tranche of $10 million was received on January 31, 2005 and the balance of $10 million was received on February 25, 2005. The loan had an interest rate equal to 5% per annum payable quarterly in arrears and includes a 1% arrangement fee of the face amount. On July 21, 2005, the short term loan facility available to InterOil increased from $20 million to $25 million. The term of the loan was fifteen months from the initial disbursement dates, and was repayable at any time prior to expiry with no penalty.

The loan and all accrued interest was repaid during the quarter ended June 30, 2006 and therefore the total balance outstanding at September 30, 2006 is $nil (Dec 2005 — $21,453,132, Sep 2005 — $20,889,196).

15. Secured loan

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Secured loan (OPIC) — current portion		—		9,000,000		9,000,000
Secured loan (OPIC) — non current portion		76,000,000		71,500,000		76,000,000
Secured loan (bridging facility) — non current portion		110,053,775		—		—
Total non current secured loan		186,053,775		71,500,000		76,000,000
Total secured loan		186,053,775		80,500,000		85,000,000

OPIC Secured Loan

On June 12, 2001, the Company entered into a loan agreement with OPIC to secure a project financing facility of $85,000,000. The loan is secured over the assets of the refinery project which have a carrying value of $230,951,086 at September 30, 2006 (Dec 2005 — $225,669,179, Sep 2005 — $228,817,564).

The loan agreement was amended on September 25, 2006. The amendment extends the life of the loan for one year, thereby extending the expiration to December 31, 2015. Under the amendment, the next two half yearly payments of principal and interest have been waived with repayments of principal to recommence on December 31, 2007 and interest previously due on December 31, 2006 and June 30, 2007 becoming due on September 30, 2007. Interest relating to the loan Is accrued in the financial statements and has been included in accounts payable and accrued liabilities. Fees of $500,000 associated with the amendment have been included in deferred financing costs and accrued financing costs at September 30, 2006. The agreement contains certain financial covenants which include the maintenance of minimum levels of tangible net worth and limitations on the incurrence of additional indebtedness. Under the amendment, the covenants related to minimum levels of tangible net worth have been waived until June 2008.

The interest rate on the loan is equal to the treasury cost applicable to each promissory note outstanding plus the OPIC spread (3%). During the nine months ended September 30, 2006 the weighted average interest rate was 7.1% (Dec 2005 – 7.1%, Sep 2005 – 7.1%) and the total interest expense included in long term borrowing costs was $4,178,100 (Dec 2005 — $6,038,887, Sep 2005 — $4,525,050).

Deferred financing costs of $1,634,431 (Dec 2005 — $1,256,816, Sep 2005 — $701,484) are being amortized over the period until June 2014.

The accrued financing costs of $1,450,000 (Dec 2005 — $921,109, Sep 2005 — $906,664) included discounting of the liability. The total liability is $1,450,000 and will be due for payment in four quarterly installments of $362,500 commencing on December 31, 2007.

Bridging Facility

InterOil entered into a loan agreement for $130,000,000 on May 3, 2006. The loan is divided into two tranches. Tranche 1, which represents $100,000,000 of the total facility, was available for drawdown from the time the agreement was signed. Up to September 30, 2006, $100,000,000 had been drawn down. Of Tranche 2, which represents the remaining $30,000,000, InterOil has drawn down $18,000,000 as at September 30, 2006. The agreement contains certain financial covenants which include the maintenance of minimum levels of fixed charge ratios, a maximum leverage ratio and limitations on the incurrence of additional indebtedness.

-19-

InterOil Corporation

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

15. Secured loan (cont’d)

The full balance of the loan will be repayable on May 3, 2008. Interest is payable quarterly in arrears. The interest rate on the loan will be 4% commencing on May 3, 2006 and ending on March 31, 2007. Between March 31, 2007 and the end of the facility (May 3, 2008), the interest rate will be 10% unless a definitive LNG/NGL Project Agreement is executed by InterOil and the lenders on or before March 31, 2007. If the Project Agreement is delivered on or before March 31, 2007, the interest rate will continue to be 4% for the full life of the loan.

The loan is valued on the balance sheet based on the present value of the expected cash flows. The expected cash flows include not only interest payments but also a 3.5% commitment fee payable to the lenders at the time of each draw down. The expected cash flows were adjusted to take into account the likelihood of different interest rate outcomes relevant to the second year of the facility. Interest expense is recognized based on the market rate of interest InterOil would be expected to pay on such a borrowing should it not be connected to an LNG/NGL Project.

The difference between the book value of the loan at the time of the cash being received and the actual funds drawn down is the LNG project agreement liability in the current liability section of the balance sheet. This liability of $5,092,097 will be transferred to the profit and loss account as income once a definitive LNG/NGL Project Agreement is executed by InterOil and the lenders on or before March 31, 2007.

16. Indirect participation interest

Indirect participation interest

	September 30,		December 31,		September 30,
	2006		2005		2005
	$		$		$
Current portion		19,533,513		35,092,558		38,614,902
Non current portion		29,794,048		30,166,311		39,183,290
Total indirect participation interest		49,327,561		65,258,869		77,798,192

Prior to December 31, 2004, the Company received deposits of $13,749,852 toward an $125,000,000 additional indirect participation interest (“IPI”). The remaining $111,250,148 was received in 2005. The $125,000,000 is subject to the terms of the agreement dated February 25, 2005 between the corporation and certain investors under which InterOil has provided the investors with a 25% interest in an eight well drilling program to be conducted in InterOil’s petroleum prospecting licenses 236, 237 and 238. Under the agreement, all or part of this indirect participation interest may be converted to a maximum of 3,333,334 common shares in the company between June 15, 2006 and the later of December 15, 2006 or until 90 days after the completion of the eighth well at a price of $37.50 per share. Should the conversion to shares not be exercised, the indirect participation interest in the eight well drilling program will be maintained and distributions from success in these wells will be paid in accordance with the agreements. Any partial conversion of an indirect participation interest into common shares will result in a corresponding decrease in the investors’ interest in the eight well drilling program.

Under the indirect participation interest, InterOil is responsible for drilling the eight wells, four of which will be in PPL 238, one in PPL 236, and one in PPL 237. The investors will be able to approve the location of the final two wells. In the instance that InterOil proposes completion of an exploration or development well, the investors will be asked to contribute to the completion work in proportion to their IPI percentage. InterOil will bear the remaining cost. Should an investor choose not to participate in the completion works, the investor will forfeit their right to the well in question as well as their right to convert into common shares.

InterOil has accounted for the $125,000,000 indirect participation interest as a non financial liability with a conversion option. The value of the conversion option was $27,249,587. The balance of $97,750,413 was allocated to the indirect participation interest liability. The initial value of the conversion option was calculated using the Black-Scholes Model with the following assumptions: a risk free rate of 3.2%, a volatility of 45%, a life of 695 days, and a dividend yield of nil. The fair value of the conversion feature as of February 4, 2005, the date the terms of the IPI agreement were initially agreed to with investors, using the Black-Scholes model was $26,121,864. The fair value of the indirect participation interest liability was calculated based on projected costs of $105,000,000 related to completing the Company’s obligations under the IPI agreement, discounted at a rate of 11.25%. The fair value of the indirect participation interest liability component was $93,705,017.

-20-

InterOil Corporation

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

16. Indirect participation interest (cont’d)

The sum of the calculated value of the conversion option and the indirect participation interest liability resulted in a calculated value for the indirect participation interest agreement of $119,826,881. The Company used the relative fair value approach to adjust the non-financial liability and the conversion feature associated with the indirect participation interest agreement to equal the total proceeds received in connection with the indirect participation interest agreement. The calculated value of the conversion option was approximately 21.80% of the total calculated value. This percentage was multiplied times the total gross proceeds from the IPI agreement of $125 million to arrive at the book value of the conversion option of $27,249,587. The book value of the indirect participation interest liability of $97,750,413 was calculated in the same manner.

The difference between the original book value of the non-financial liability ($97,740,413) and the actual expenditures, up to $105,000,000, will be treated as accretion expense over the life of the indirect participation interest agreement and is recognized in the income statement using the effective interest rate method. In the event that expenditures for the eight well drilling program exceed $105,000,000, these additional costs will be either capitalized as exploration expenditures or expensed in accordance with the successful efforts method of accounting.

All costs incurred by the company relating to the eight well drilling program, including geological and geophysical costs, and commission costs associated with structuring the agreement, will be charged against the liability to a maximum amount of $105,000,000. To September 30, 2006 a total of $50,912,655 (Dec 2005 — $31,774,513, Sep 2005 — $17,970,822) has been charged against the liability for geological and geophysical costs and drilling costs and an additional $6,364,523 (Dec 2005 — $6,364,523, Sep 2005 — $6,364,523) has been charged against the liability for finance and transaction costs. The liability and the accretion expense were increased during the period by $3,206,835 (Dec 2005 — $5,647,491, Sep 2005 — $4,383,124) for a total increase during the life of the indirect participation interest of $8,854,326 (Dec 2005 — $5,647,491, Sep 2005 — $4,383,124). This amount represents the accretion of the discount calculated on the non-financial liability component of the indirect participation interest. InterOil will bear the costs for subsequent works projects and completion activities in proportion to its remaining ownership in the eight wells. These costs are accounted for in accordance with the company’s stated accounting policies.

InterOil paid financing fees and transaction costs of $8,138,742 related to the indirect participation interest on behalf of the indirect participation interest investors in 2005. These fees have been apportioned between the indirect participation interest and the conversion options in the same proportion as the original $125,000,000 was allocated between the non financial liability and the conversion options. The indirect participation interest liability portion of the finance and transaction costs was $6,364,523 and the remaining $1,774,219 was allocated against the conversion option, reducing the conversion option value to $25,475,368.

Indirect participation interest — PNGDV

As at September 30, 2006, the balance of the PNG Drilling Ventures Limited (“PNGDV”) indirect participation interest in the Company’s phase one exploration program within the area governed by Petroleum Prospecting Licenses “PPL” 236, 237 and 238 is $1,749,626 (Dec 2005 — $9,685,830, Sep 2005 — $9,685,830). This is the result of an amendment to the original agreement whereby PNG Drilling Ventures Limited converted their remaining balance of $9,685,830 into 575,575 InterOil common shares and also retained a 6.75% interest in the next four wells (the first of the four wells is Elk-1). PNGDV also has the right to participate in the 16 wells that follow the first four mentioned above up to an interest of 5.75% at a cost of $112,500 per 1% per well (with higher amounts to be paid if the depth exceed 3,500 meters and the cost exceeds $8,500,000).

The accounting for the amendment to the agreement resulted in the fair value of the shares issue of $7,948,691 being recognized as share capital. The company has also recognized a liability relating to its obligation to drill four wells on behalf of the investors of $3,184,040. The difference between the opening balance and the amount allocated to share capital and the amount allocated to the liability of $1,446,901 has been expensed as a cost of amending the original transaction.

During the period to September 30, 2006, $1,626,694 of geological and geophysical costs and drilling costs have been allocated against the liability of $3,184,040 and the liability has increased by the accretion of $192,280, bringing the remaining balance to $1,749,626.

Other

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

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InterOil Corporation

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

17. Non controlling interest

On September 11, 1998 Enron Papua New Guinea Ltd (“Enron”), SPI’s former joint venture partner, exercised its option (pursuant to a January 1997 joint venture agreement with SPI) to terminate the joint venture agreement. Consequently, SPI purchased Enron’s voting, non-participating shares in E.P. InterOil Limited (“EPI”), a wholly owned subsidiary of SPI, for a nominal amount. Enron no longer actively participates in the refinery operations but continues to be a non-voting participating shareholder in EPI. SPI now holds all voting non-participating shares issued from EPI and has sole responsibility for managing the refinery. Enron does not hold any transfer or conversion rights into shares of InterOil Corporation.

At September 30, 2006, a subsidiary, SP InterOil LDC, holds 98.92% (Dec 2005 — 98.83%, Sep 2005 – 98.80%) of the non-voting participating shares issued from EPI.

18. Share capital

The authorized share capital of the Company consists of an unlimited number of common shares with no par value. Each common share entitles the holder to one vote.

Common shares

Changes to issued share capital were as follows:

	Number of shares		$
January 1, 2004		24,815,961		157,449,200
Shares issued for debt		3,184,828		56,698,121
Shares issued on exercise of options		310,095		2,666,333
December 31, 2004		28,310,884		216,813,654
Shares issued for debt		52,000		923,000
Shares issued on exercise of warrants		19,168		540,346
Shares issued on exercise of options		781,268		5,657,500
December 31, 2005		29,163,320		223,934,500
Shares issued on exercise of options		90,618		794,897
Shares issued on conversion of indirect participation interest		575,575		7,948,691
September 30, 2006		29,829,513		232,678,088

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

19. Stock compensation

At September 30, 2006, there were 2,681,100 (Sep 2005 – 862,650) common shares reserved for issuance under the Company stock option plan.

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

	Quarter ended September 30,												Nine months ended September 30,
	2006						2005						2006						2005
				Weighted						Weighted						Weighted						Weighted
				average						average						average						average
	Number of			exercise			Number of			exercise			Number of			exercise			Number of			exercise
Stock options outstanding	options			price $			options			price $			options			price $			options			price $
Outstanding at beginning of period		888,600			20.90			861,300			18.55			746,800			22.23			1,162,322			9.91
Granted		262,000			14.73			216,450			16.64			544,500			14.36			516,450			25.82
Exercised		(30,000	)		(5.27	)		(104,900	)		(5.71	)		(90,618	)		(8.19	)		(680,922	)		(6.11	)
Forfeited		(177,500	)		(14.16	)		(40,000	)		(12.00	)		(228,500	)		(15.69	)		(65,000	)		(11.33	)
Expired		—			—			(70,200	)		(25.95	)		(29,082	)		(12.00	)		(70,200	)		(25.95	)
Outstanding at end of period		943,100			20.95			862,650			20.81			943,100			20.95			862,650			20.81

	Options issued and outstanding						Options exercisable
					Weighted average
Range of exercise			Weighted average		remaining term				Weighted average
price $	Number of options		exercise price $		(years)		Number of options		exercise price $
5.01 to 12.00		10,000		5.27		0.64		10,000		5.27
12.01 to 24.00		615,000		17.72		2.94		102,000		23.94
24.00 to 31.00		318,100		27.70		2.20		99,300		30.30
		943,100		20.95		2.60		211,300		26.04

The fair value of the 544,500 (Sep 2005 – 516,450) options granted subsequent to January 1, 2006 has been estimated at the date of grant in the amount of $4,009,517 (Sep 2005 — $4,834,139) using a Black-Scholes pricing model with the following assumptions: risk-free interest rate of 4.35% for grants between January 1, 2006 and June 30, 2006 and 5.09% between July 1, 2006 and September 30, 2006 (Sep 2005 – 2.5%), dividend yield of nil (Sep 2005 – nil), volatility factor of the expensed market price of the Company’s common stock of 60% for grants between January 1, 2006 and June 30, 2006 and 68% between July 1, 2006 and September 30, 2006 (Sep 2005 – 45%), and a weighted average expected life of the options of 3.72 years (Sep 2005 – 3.4 years). An amount of $1,403,123 (Sep 2005 –$1,086,115) has been recognized as compensation expense for the nine month period.

20. Debentures and warrants

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

In 2004, in connection with the issuance of senior convertible debentures, InterOil issued five-year warrants to purchase 359,415 common shares at an exercise price equal to $21.91. A total of 340,247 (Sep 2005 – 340,247) were outstanding at September 30, 2006. The warrants are exercisable between August 27, 2004 and August 27, 2009. The warrants are recorded at the fair value calculated at inception as a separate component of equity. The fair value was calculated using a Black-Scholes pricing model with the following assumptions: risk-free interest rate of 2.5%, dividend yield of nil, volatility factor of the expected market price of the Company’s common stock of 45% and a weighted average expected life of the warrants of five years.

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

21. Loss per share

Warrants, conversion options and stock options totaling 4,621,681 common shares at prices ranging from $5.27 to $37.50 were outstanding as at September 30, 2006 but were not included in the computation of the diluted loss per share because they caused the loss per share to be antidilutive.

22. Commitments and contingencies

Payments due by period contractual obligations are as follows:

			Less than										More than 5
	Total		1 year		1-2 years		2-3 years		3-4 years		4-5 years		years
	’000		’000		’000		’000		’000		’000		’000
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 — PNGDV (note 16)		1,750		1,750		—		—		—		—		—
Indirect participation interest (note 16)		51,768		20,500		31,268		—		—		—		—
Petroleum prospecting and retention licenses (a)		51		51		—		—		—		—		—
		249,019		22,301		159,718		9,000		9,000		9,000		40,000

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

The company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position, results of operations or liquidity.

The company currently has an outstanding US$8.6m cost of control insurance claim for the Elk well which is being assessed by the loss adjusters. The amount and timing of any payment related to this claim is currently unknown.

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

23. Adjustment of September 2005 comparatives

During the quarter ended 30 September 2005, the company adopted an accounting policy with respect to the indirect participation interest (note 16). The policy for the indirect participation interest described in note 16, was applied beginning in the quarter ended September 2005 and some adjustments relating to the adoption of the policy were included in the September 2005 quarterly result. The treatment of the financing costs, as described in note 16, was adopted in December 2005 rather than in September 2005.

The company has re-presented the September 2005 comparatives as if the indirect participation interest accounting policy, including the treatment relating to transaction costs, had been adopted at the inception of the agreement. As a result of this re-presentation, deferred financing costs have decreased by $4,167,829, the current portion of the indirect participation interest has decreased by $42,292,424, the non-current portion of the indirect participation interest increased by $39,183,290 and the conversion options increased by $986,132 from the presentation originally adopted.

With respect to the statement of operations for the nine months to September 30, 2005, short term borrowing expenses have decreased by $2,012,055, accretion expense has increased by $4,383,124 and professional fees have decreased by $326,242 as a result of the re-presentation. The restated net loss for the nine months is $27,120,260 as opposed to the $25,075,433 originally presented. As a result of the re-presentation, the basic and diluted earnings per share has decreased by $0.07/per share from a loss of $0.87 /share to a loss of $0.94/share for the nine months ended September 30, 2005.

For the quarter ended September 30, 2005, accretion expenses have increased by $1,390,351, short term borrowing costs have decreased by $2,012,055, exploration costs, excluding exploration impairment have increased by $2,939,995, exploration impairment has increased by $5,870,986, and professional fees have decreased by $26,067 as a result of the representation. The restated net loss for the three months is $2,911,737 as opposed to the net income of $5,251,473 originally presented. As a result of the re-presentation, the basic and diluted earnings per share has decreased by $0.28/per share from a earning of $0.18/share to a loss of $0.10/share for the quarter ended September 30, 2005.

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

24. Deposit on business acquisition

During the first quarter, the company paid $4,500,000 as a down payment on the acquisition of Shell Papua New Guinea. The remaining balance of the purchase price amounting to $26,139,000 was paid on September 29, 2006, the last business day before the transfer of the Shell assets to InterOil on October 1, 2006. The purchase price of $30,639,000 may be subject to a working capital adjustment. Any such adjustment will be determined during the fourth quarter.

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