InterOil Corporation
Management Analysis and Discussion

For the Year Ended December 31, 2006
March 30, 2007

TABLE OF CONTENTS

Overview	2
Non-Gaap Measures	2
Legal Notice – Risk Factors And Forward-Looking Statements	3
Business Environment	4
Risk Management	7
Business Strategy	9
Financial Results	11
Year In Review	17
Midstream Refining And Marketing Year In Review	20
Midstream Liquefaction Year In Review	25
Downstream Year In Review	26
Corporate Year In Review	30
Liquidity And Capital Resources	31
Critical Accounting Estimates	37
New Accounting Standards	39
Non-Gaap Measures Reconciliation	41
Statement Regarding Disclosure Controls	42
Public Securities Filings	42
Glossary Of Terms	42

The following Management’s Discussion and Analysis (MD&A) should be read in conjunction with: the audited Consolidated Financial Statements and Notes for the year ended December 31, 2006 and the 2006 Annual Information Form. The MD&A 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.

Our financial statements and the financial information contained in this MD&A have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada and are presented in United States dollars (USD) unless otherwise specified. References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation and its subsidiaries.

Management Discussion and Analysis      INTEROIL CORPORATION     1

OVERVIEW

InterOil is developing a vertically integrated world class energy company in Papua New Guinea and the surrounding region. Our operations are organized into four major segments:

Segments	Operations
Upstream	Exploration and Production — Explores and appraises potential oil and natural gas structures in Papua New Guinea with a view to commercializing significant discoveries.
Midstream	Refining, Marketing & Liquefaction — Markets the refined products it produces in Papua New Guinea both domestically and for export. Since early 2006, our business plan and operating strategy has evolved to include as a business objective, the development of an onshore liquefied natural gas processing facility in Papua New Guinea.
Downstream	Wholesale and Retail Distribution — Distributes refined products in Papua New Guinea on a wholesale and retail basis.
Corporate	Corporate — Engages 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. Our corporate segment results also include consolidation adjustments.

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. EBITDA is used by InterOil to analyze operating performance. EBITDA does not have a standardized meaning prescribed by United States or 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. For reconciliation of EBITDA to the net income (loss) under GAAP, refer to the Non GAAP Measures Reconciliation of this MD&A.

Management Discussion and Analysis      INTEROIL CORPORATION     2

LEGAL NOTICE — RISK FACTORS AND FORWARD-LOOKING STATEMENTS

This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements are generally identifiable by the terminology used, such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “forecasts,” “budgets,” “targets” or other similar wording suggesting future outcomes or statements regarding an outlook. 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, contingent liabilities, environmental matters, and plans and objectives for future operations, future capital and other expenditures. By its very nature, such forward-looking information requires InterOil to make assumptions that may not materialize or that may not be accurate.

Each forward-looking statement reflects our current view of future events and is subject to known and unknown 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; the exploration and production, the refining and the distribution businesses are competitive; our refinery has not operated at full capacity for an extended period of time and our profitability may be materially affected if it is not able to do so; if we are not able to market all of our refinery’s output, we will not be able to operate our refinery at its full capacity and our financial condition and results of operations may be materially adversely affected; if our refining margins do not meet our expectations and our refinery operations are not profitable; we may be required to write down the value of our refinery; our refinery financial condition may be materially adversely affected if we are unable to obtain crude feedstocks for our refinery; our refining operations expose us to risks, some of which are not insured; our hedging activities may incur losses; we may not be successful in our exploration for oil and gas; if we are unable to renew our petroleum licenses with the Papua New Guinea government, we may be required to discontinue our exploration activities in Papua New Guinea; our investments in Papua New Guinea are subject to political, legal and economic risks that could materially adversely affect their value; new legislative, administrative or judicial actions that constrain licenses and permits from various government authorities may have a material affect on the company’s operations; weather and unforeseen operating hazards may impact our operating activities; our significant debt levels and our debt covenants may limit our future flexibility in obtaining additional financing; our ability to recruit and retain qualified personnel may have a material adverse effect on our operating results and stock price; Petroleum Independent and Exploration Corporation can affect our raising of capital through the issuance of common shares or securities convertible into common shares; compliance with and changes in environmental laws could adversely affect our performance; you may be unable to enforce your legal rights against us; changing regulations regarding corporate governance and public disclosure could cause additional expenses and failure to comply may adversely affect our reputation and the value of our securities; and the risks described under the heading “Risk Factors” in our Annual Information Form.

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 Annual Information Form for the year ended December 31, 2006.

Readers are cautioned that the foregoing list of important factors affecting forward-looking information is not exhaustive. Furthermore, the forward-looking information contained in this quarterly report is made as of the date of this report and, except as required by applicable law, InterOil does not undertake any obligation to update publicly or to revise any of the included forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained in this report is expressly qualified by this cautionary statement.

We currently have no production or 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.

Management Discussion and Analysis      INTEROIL CORPORATION     3

BUSINESS ENVIRONMENT

InterOil is a vertically integrated energy company with business segments through the whole hydrocarbon supply chain. InterOil is therefore exposed to the usual hydrocarbon production, refining and marketing business environment and regulatory regime of the hydrocarbon industry. Following is a summary of the hydrocarbon business environment to which InterOil is exposed.

Competitive Environment and Regulated Pricing

InterOil is the sole refiner of hydrocarbons in Papua New Guinea and under our 30 year agreement with the Government of Papua New Guinea, the government has undertaken to ensure that all domestic distributors purchase their refined petroleum product needs from the refinery, or any refinery which is constructed in Papua New Guinea, at an Import Parity Price (IPP). For each of the refined products produced and sold locally in Papua New Guinea, the monthly IPP is calculated by adding the costs that would typically be incurred to import such products to the average monthly posted price in Singapore as reported by Platts. The import parity price is regulated by the Papua New Guinea Independent Consumer and Competition Commission (ICCC).

InterOil is a significant participant in the distribution business in Papua New Guinea. Its major competitors have included Mobil and Shell; however, InterOil has completed the purchase of Shell Papua New Guinea’s distribution assets on October 1. The ICCC sets the maximum margins that may be charged by the wholesale and retail distribution industry in Papua New Guinea. Our downstream business may charge less than the maximum margin set by the ICCC in order to maintain its competitiveness with other participants in the market.

Interest Rates

The LIBOR USD overnight rate is the benchmark floating rate used in our midstream working capital facility and therefore accounts for a significant amount of the interest rate exposure.

The LIBOR USD overnight rate has steadily increased from around 2.3% to around 5.3% between 2005 and 2006.

Rate increases add additional cost to financing our crude cargoes. In 2007, indications are that interest rates will be more likely to fall.

Skill and Resource Scarcity

Similar to our competitors, we are facing a shortage of skilled labor to work in our business. Our success depends in large part on the continued services of our executive officers, our senior managers and other key technical personnel. Competition for qualified personnel can be intense, and there are a limited number of people with the requisite knowledge and experience.

Management Discussion and Analysis      INTEROIL CORPORATION     4

Crude Prices

Crude prices have continued to be volatile throughout the year. The price of Tapis crude oil, as quoted by the Asian Petroleum Price Index (APPI), is a benchmark for setting crude prices within the region where we operate and is used by us when we purchase crude feedstock for our refinery. The price of Tapis during 2006 averaged $68.15 per barrel compared to $56.85 per barrel during 2005. The pricing formula used to determine the domestic sales price of our refined products does not allow us to fully recover the increased costs of working capital that result from increases in the cost of crude feedstocks. The Tapis monthly average for January 2007 was at 19 month low at $53.69 per barrel but has since recovered and is trading above $60 per barrel. We expect Tapis, and crude in general, to continue to trade at similar prices as experienced over the last two years. However, unforeseeable global events can affect this expectation. In January 2007, we commenced providing TAPIS crude price assessments to the Asian Petroleum Price Index.

Refining Margin

The benchmark price for refined products in the region we operate is the average spot price quotations for refined products from Singapore as reported by Platts. This benchmark, the Mean of Platts Singapore, 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 differences in our approach to crude selection, transportation costs and IPP pricing work to assist our refinery in outperforming the Singapore Tapis hydroskimming margin. Therefore, our refinery realizes additional margins due to its niche location when compared to the benchmark for the region.

Singapore Tapis hydroskimming margins increased during the first six months of 2006 then gave up this increase during the third quarter 2006 before improving slightly during fourth quarter. Volatility has increased during the past 18 months and we believe that hydroskimming margins will continue to remain volatile given oil pricing uncertainty.

Exchange Rates

Changes in the Papua New Guinea Kina (PGK) to United States dollar (USD) exchange rate can affect our midstream results as there is a small timing difference between the foreign exchange rates utilized when setting the monthly PGK IPP price and the foreign exchange rate used to convert subsequent receipt of PGK proceeds to USD to repay our crude cargo borrowings. The PGK strengthened against the USD during 2006 (from 0.323 to 0.330). During 2007 we expect the PGK to remain relatively stable against the USD.

Management Discussion and Analysis      INTEROIL CORPORATION     5

Domestic Demand

Refinery sales trends indicate that domestic demand for middle distillates has grown by 14% during 2006 versus 2005.

The refinery on average sold 11,900 bbls/day to the domestic market during the second half of 2006 as compared to 10,400 bbls/day in the second half of 2005.

The majority of the demand increase was driven by the growing investment in the resource sector of Papua New Guinea. We expect this trend to continue into 2007 as current world demand for commodities results in increased foreign investment in Papua New Guinea.

Impact of Key Factors on Earnings

The following table shows the estimated after-tax effects that changes in certain factors would have on InterOil’s 2006 net earnings from continuing operations had these changes occurred. Amounts are in USD unless otherwise specified.

				Annual Net Earnings Impact
Factor(1)(2)	Change (+)			(thousands of dollars)		($/share)(3)
Change in domestic demand		1	%		383		0.01
Change in hydro-skimming margin	$1.00/bbl				6,655		0.22
Change in IPP pricing margin for retail and distribution business	0.01 PGK/litre				1,815		0.06
Change in LIBOR rate		1	%		730		0.03

(1)	The impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the impact of any inter-relationship among the factors.
(2)	The impact of these factors is illustrative and based off of sales and borrowings made during the 2006 year.
(3)	Per share amounts are based on the number of shares outstanding at December 31, 2006.

Management Discussion and Analysis      INTEROIL CORPORATION     6

RISK MANAGEMENT

Risk Factors

InterOil’s financial results are influenced by the business environment in which we operate. These risk factors can be found under the heading “Risk Factors” in our 2006 Annual Information Form available at www.sedar.com.

InterOil’s Risk Profile

InterOil’s risk exposures are mitigated and managed by management’s strategy for handling risks within the business. These risks have been categorized into four broad categories: business risks; operational risks; market risks and regulatory risks. Management believes that each risk requires a unique response and while some risks are managed through internal controls and business processes, others are managed through insurance and hedging. The following describes InterOil’s approach to managing major risks.

Business Risks

Our success depends in large part on the continued services of our executive officers, our senior managers and other key personnel. The loss of these people could have a material adverse impact on our results of operations. It is very important that we attract and retain highly skilled personnel, including technical personnel, to operate our refinery, accommodate our exploration plans, and manage the strategic direction of the business. Our human resources team manages our exposure in this area by engaging in active recruitment and retention programs.

Unrelated entities manage the operation of assets in which InterOil has an interest, such as upstream operations in our Petroleum Retention License 4 (43.1% interest) and Petroleum Retention License 5 (28.6% interest) leases. Inappropriate third-party operation of these assets could adversely affect InterOil’s financial performance; however, InterOil takes steps to partially mitigate this exposure by playing an active role on joint venture committees.

InterOil makes, and will continue to make, substantial capital expenditures for exploration, development, acquisition and production of oil and gas reserves, refinery expansions and improvements, acquisitions of distribution assets, and for further capital acquisitions and expenses. We will need additional financing to complete our business plans. The Board of Directors and executive management team proactively manage this exposure by continually reviewing business models, business plans and financing plans to meet the company’s strategic direction.

Operational Risks

We cannot assure our shareholders that our exploration activities will result in the discovery of any reserves; however, we take active steps to maximize the possibility of success by hiring highly qualified management and technical personnel and by engaging in activities such as seismic acquisition programs to enhance the possibility of success of our prospective drilling activities.

Exploring for, refining, transporting and marketing hydrocarbons involves operational hazards. These hazards include well blowouts, fires, explosions, and migration of harmful substances. Any of these operational incidents could cause personal injury, environmental contamination or damage and destruction of the Company’s assets. These incidents could also interrupt operations. InterOil manages operational risks primarily through its environmental, health and safety policies and committees as well as ensuring that we have suitably trained and qualified personnel in each of our operations.

The Company also purchases insurance to transfer the financial impact of some operational risks to third-party insurers. InterOil regularly evaluates its exposures related to operational risk and then adjusts the nature of its coverage, including deductibles and limits. Although InterOil maintains insurance in line with customary industry

Management Discussion and Analysis      INTEROIL CORPORATION     7

practices, the Company cannot and does not fully insure against all risks. Losses resulting from operational incidents that are not covered by insurance could have a material adverse impact on the Company.

Our midstream operations are dependent on the company’s ability to obtain suitable crude feedstock. Our project agreement requires the government of Papua New Guinea to take action to ensure that domestic crude oil producers sell us their domestic crude production for use in our refinery should we elect to utilize it. We are also able to obtain crude from outside of Papua New Guinea. During our crude optimization efforts, the refinery identified that lighter crudes that result in increased distillate yields, which are produced outside of Papua New Guinea, are the preferred source of crude for our refinery. In order to help mitigate the risk that we will be unable to enter into commercial arrangements for crude, either domestically or internationally, we have entered into an exclusive crude supply agreement with BP Singapore. Under this agreement which expires on June 14, 2009, BP Singapore acts as our agent in the procurement of crude.

Market Risks

Our midstream operations are highly dependent on the difference between the sale price we receive for refined products that we produce and the cost of the crude feedstocks used to produce those refined products. This difference is commonly referred to as refining margin. We use various derivative instruments and risk management techniques to minimize our exposure to market fluctuations in refining margins and also to the inventory holding price risk. Inventory holding price risk refers to changes in prices that occur between the time that we purchase feedstocks and the price of finished product at the time that we subsequently sell refined products. This holding period varies according to the sales cycle of each refined product.

The Company, due to its extensive borrowing requirement, will be adversely impacted by increases to interest rates. To balance this risk we have adopted a strategy of maintaining a mix of both fixed and floating interest rates on our debt portfolio.

Due to its operations being in Papua New Guinea, our Company is exposed to foreign exchange risk as revenues and expenditures or capital expenditure and investment proceeds could be in differing currencies from each other. Our primary foreign exchange risk is between the USD and the PGK. Our exploration business which incurs expenditure in PGK whilst holding its available funds in USD partially offsets the risk in the midstream operations, which incurs costs in USD whilst deriving the majority of its revenue in PGK. This exposure is further managed by a program of obtaining forward dated foreign exchange transactions.

Regulatory Risks

InterOil’s operations are based in Papua New Guinea and as a result involve risks typically associated with investments in developing countries, such as uncertain political, economic, legal and tax environments; expropriation and nationalization of assets; war; renegotiation or nullification of existing contracts; taxation policies; foreign exchange restrictions; international monetary fluctuations; currency controls; and foreign governmental regulations that favor or require the awarding of service contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, InterOil’s operations are regulated by and could be intervened upon by, the Papua New Guinea government. InterOil endeavors to mitigate the impact of its operational location and the related government regulations by maintaining co-operative relationships with its regulators and the government of Papua New Guinea. InterOil’s business development team aims to have regular, constructive communication with regulators and the government so issues can be resolved in a mutually acceptable fashion.

InterOil’s operations are subject to extensive laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures and the characteristics and composition of gasoline, jet and diesel fuels. Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, the monetary cost of environmental compliance could increase in the future. InterOil manages its environmental risks primarily through its environmental, health and safety policies and committees as well as an extensive third party testing program at the refinery.

Management Discussion and Analysis      INTEROIL CORPORATION     8

InterOil must comply with many changing laws, regulations and standards relating to corporate governance and public disclosure, including the Sarbanes-Oxley Act of 2002, new Securities and Exchange Commission (SEC) regulations and new and changing provisions of Canadian securities laws. The Company would face a wide variety of impacts should it fail to meet the requirements of new legislation. To manage this exposure, InterOil tasks its in-house legal, internal audit, and accounting teams with monitoring changes in legislation, regulation and accounting standards. Where necessary, InterOil also uses external professional advisors. InterOil has an internal audit function which test its controls and procedures to ensure compliance with Sarbanes-Oxley.

BUSINESS STRATEGY

InterOil’s strategy is to develop a vertically integrated energy company in Papua New Guinea and surrounding regions, focusing on niche market opportunities which provide financial rewards for InterOil shareholders, while being environmentally responsible, providing a quality working environment and contributing value to the communities in which InterOil operates. InterOil has taken a three-pronged approach when planning to achieve this strategy.

Q:

What is InterOil’s business strategy?

A:

To develop a vertically integrated energy company in Papua New Guinea.

Summary of Strategic Priorities

Following is a table outlining the Company’s progress towards the strategic priorities of the Company and its goals for2007. Refer to the Annual Information Form for a summary of strategic priorities by segment.

Strategic
Priorities	2006 Progress	2007 Initiatives
Capitalize on and Expand on the Existing Business Assets	ü   Completed refinery optimization project, which included the installation of new generators and modifications of the furnaces and boilers to improve reliability and reduce fuel costs. ü   Secured a contract to provide InterOil Power Fuel to Papua New Guinea’s Moitaka Power Station.	ü   Evaluate feasibility of improvements, modifications and additional equipment to improve flexibility and profitability of the refinery. ü   Continue to seek out potential markets for InterOil Power Fuel and distillate export opportunities to increase contribution to fixed costs. ü   Cost reduction program targeting 10% reduction.

Management Discussion and Analysis      INTEROIL CORPORATION     9

Strategic
Priorities	2006 Progress	2007 Initiatives
Target Acquisitions and Growth Opportunities in Papua New Guinea and the Surrounding Area	ü   Finalized the terms of acquisition for Shell Papua New Guinea’s distribution network. The Shell Papua New Guinea business was transferred to InterOil on October 1. ü   Examined other potential downstream growth opportunities. ü   Progressed discussions for liquefied natural gas opportunity in Papua New Guinea with government and other potential partners.	ü   Pursue opportunities to purchase a business or assets in the business of distributing fuel to the aviation sector. ü   Pursue other potential downstream growth opportunities. ü   Sign a shareholder agreement relating to the LNG opportunity in Papua New Guinea and begin taking steps to advance project. ü   Finalize FEED decision and development plans for LNG project.
Position InterOil for Long-Term Oil and Gas Business Success	ü   Made potential gas and condensate discovery at Elk location on existing Petroleum Prospecting License 238. ü   Conducted seismic and airborne gravity and magnetic surveys on licenses to expand knowledge base of existing prospects and to identify new prospects.	ü   Obtain further information about the Elk structure by drilling the Elk-2 appraisal well and conducting 100 miles of appraisal seismic. ü   Conduct detailed 2D seismic surveys over the Elk discovery and lead on-trend with the Elk discovery that have been identified from seismic data and airborne gravity/magnetic surveys acquired by the company to date.

Management Discussion and Analysis      INTEROIL CORPORATION     10

FINANCIAL RESULTS

Summary of Consolidated Annual Financial Results

Annual Consolidated Financial Results

Consolidated results for year ended December 31, 2006 compared to year ended December 31, 2005 and 2004

Consolidated – Operating results	Years ended December 31,
($ thousands, unless otherwise indicated)	2006(1)			2005			2004(2)
Sales and operating revenues		511,088			481,181			70,644
Interest revenue		3,224			1,831			382
Other non-allocated revenue		3,748			528			196
Total revenue		518,060			483,540			71,222
Cost of sales and operating expenses		(499,495	)		(467,247	)		(65,344	)
Office and administration and other expenses		(24,430	)		(23,296	)		(14,701	)
Exploration costs		(1,658	)		—			(2,903	)
Exploration impairment		(417	)		(2,144	)		(35,567	)
Accretion expense		(3,741	)		(5,647	)		—
Earnings before interest, taxes, depreciation and amortization (unaudited)		(11,681	)		(14,794	)		(47,293	)
Depreciation and amortization		(12,353	)		(11,037	)		(639	)
Interest expense		(17,273	)		(10,987	)		(3,203	)
Loss from ordinary activities before income taxes		(41,307	)		(36,818	)		(51,135	)
Income tax expense		(2,343	)		(2,832	)		(1,875	)
Non-controlling interest		264			368			70
Total net loss(3)		(43,386	)		(39,282	)		(52,940	)
Net loss per share (dollars)		(1.47	)		(1.36	)		(2.09	)
Net loss per diluted share (dollars)		(1.47	)		(1.36	)		(2.09	)
Total assets		488,165			429,557			385,842
Non current liabilities		223,095			112,273			87,472
Cash flows used in operations		(3,246	)		(22,713	)		(79,767	)
Cash dividends declared per share		—			—			—

(1)	Our wholesale and retail distribution business segment acquired the business of Shell PNG Limited on October 1, 2006 and information in this table includes the results of the Shell business from this date.
(2)	Our refinery began commercial operations on January 1, 2005. During 2004 we were still constructing and commissioning our refinery and the costs associated with the construction and commissioning of our refinery were capitalized rather than expensed. As a result of our refinery not having any commercial operations in 2004, our 2004 to 2005 and 2006 results are not comparable. In addition, our wholesale and retail distribution business segment was acquired on April 28, 2004 and only operated for eight months during 2004. As a result of our downstream results not having a full year operations in 2004, our 2004 to 2005 and 2006 results are not comparable.
(3)	We did not have any discontinued operations or extraordinary items during the periods covered by this table.

Management Discussion and Analysis      INTEROIL CORPORATION     11

Annual Consolidated Financial Result Analysis

EBITDA improved by $3.1 million over 2005 whilst total net loss increased by $4.1 million due to higher depreciation and interest expense. The EBITDA improvement is primarily due to increased interest revenues, increased upstream revenues from the rental of our rig, helicopters and camp sites to third parties and a decrease in the accretion expense recognized on the indirect participation interest liability, which has declined as 2006 seismic and drilling costs were offset against it. A more detailed explanation of our consolidated 2006 results is contained below. A detailed analysis of each segments earning is contained under the heading “Year in Review”.

Consolidated results analysis for year ended December 31, 2006 compared to year ended December 31, 2005.

Net Loss Comparison Based on Key Differences
(millions of USD, after-tax)

InterOil’s net loss increased from $39.3 million ($1.36/share) in 2005 to $43.4 million ($1.47/share) in 2006. However, InterOil’s EBITDA improved from a loss of $14.8 million ($0.53/share) to a loss of $11.7 million ($0.39/share). Much of the increased loss in 2006 relates to higher depreciation and interest costs.

(1)	The movement in the midstream gross margin is calculated as the total midstream revenues from operations less cost of goods sold and operating expenses. Gross margin 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.
(2)	Other mainly includes movements in office and administration expenses.

While a complete discussion of each of the segment’s result can be found under the section “Year in Review,” the following points highlight some of the key movements that have resulted in a $4.1 million increase in our net loss between 2006 and 2005.

ü The refinery operations experienced a gross margin improvement of $0.5 million between 2005 and 2006. Although the gross margin suffered in the first half of 2006 due to shut down days, the positive impact of the revamp and optimization efforts have resulted in a net improvement for the year.

Management Discussion and Analysis      INTEROIL CORPORATION     12

ü	In addition, the midstream operations experienced a $4.6 million exchange gain in 2006 as compared to a $1.4 million exchange loss in 2005 which partially resulted from the strengthening of the PGK against the USD. During the year we negotiated improved rates on our PGK to USD transactions.
ü	The refinery experienced higher interest expense in 2006 as a result of market increases in the cost of crude feedstock being financed, increases in the LIBOR indicator rates and increases to the volume of inventory on hand during the optimization shutdown.
ü	During 2006 we started our midstream liquefaction segment and up to the end of 2006 we had incurred $0.7 million of costs relating to the preliminary stages of a liquefied natural gas plant project.
ü	Our downstream business had a $0.7 million increase in depreciation expense, primarily due to the acquisition of Shell Papua New Guinea on October 1, 2006.
ü	Our upstream operations experienced lower accretion expense as a result of a decrease in the related indirect participation interest liability. The indirect participation interest liability is decreased as the obligation to complete the drilling program is being met.
ü	During the year, we recognized a $0.8 million loss on the impairment of one of our two barges. One of these barges was sold during the year.
ü	Our interest expense for the year has increased as a result of the $130 million secured loan financing.
ü	We incurred a $1.4 million expense relating to the amendment of the PNG Drilling Ventures indirect participation interest agreement.

Management Discussion and Analysis      INTEROIL CORPORATION     13

Summary of Consolidated Quarterly Financial Results

Quarterly Consolidated Financial Results

Consolidated results for each quarter, 2006 compared to each quarter 2005 by business segment.

Quarters ended
($ thousands unless stated	2006(2), (3)												2005 (adjusted)(1),(2)
otherwise) (unaudited)	Dec 31			Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Sales and operating revenues		171,734			111,372			124,671			110,283			125,216			129,465			125,275			103,584
Upstream		(337	)		1,290			2,946			1,350			854			404			37			—
Midstream — Refining and Marketing		147,538			94,687			106,825			103,105			108,625			115,273			114,717			98,051
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		91,990			39,527			37,995			27,808			39,044			32,449			29,993			23,715
Corporate & Consolidated		(67,457	)		(24,132	)		(23,095	)		(21,980	)		(23,307	)		(18,661	)		(19,472	)		(18,182	)
Earnings before interest, taxes, depreciation and amortization		6,541			1,140			(10,257	)		(9,105	)		(5,566	)		3,486			(6,856	)		(5,858	)
Upstream		(1,051	)		(1,337	)		(2,262	)		(2,227	)		(2,362	)		(1,655	)		(2,615	)		(1,603	)
Midstream — Refining and Marketing		9,144			1,674			(8,188	)		(5,230	)		(6,333	)		6,070			(6,796	)		(3,405	)
Midstream — Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		1,143			1,954			3,559			(326	)		3,963			2,522			2,550			584
Corporate & Consolidated		(2,299	)		(853	)		(3,366	)		(1,322	)		(834	)		(3,451	)		5			(1,434	)
Net income (loss) per segment(4)		(3,711	)		(7,553	)		(17,759	)		(14,363	)		(12,165	)		(2,912	)		(12,852	)		(11,353	)
Upstream		(1,286	)		(1,540	)		(2,436	)		(2,426	)		(2,452	)		(1,870	)		(2,619	)		(1,608	)
Midstream — Refining and Marketing		3,818			(4,309	)		(13,408	)		(10,052	)		(11,622	)		1,068			(11,839	)		(8,469	)
Midstream — Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		(427	)		1,278			2,426			(282	)		2,802			1,460			1,789			382
Corporate & Consolidated		(5,420	)		(2,684	)		(4,341	)		(1,603	)		(893	)		(3,570	)		(183	)		(1,658	)
Net income (loss) per share(4) (dollars)
Per Share — Basic		(0.13	)		(0.25	)		(0.60	)		(0.49	)		(0.42	)		(0.10	)		(0.45	)		(0.40	)
Per Share — Diluted		(0.13	)		(0.25	)		(0.60	)		(0.49	)		(0.42	)		(0.10	)		(0.45	)		(0.40	)

(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)	Our comparative quarterly results for all quarters during 2005 and 2006 have been represented to confirm with the presentation adopted at December 31, 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(3)	Our September 2006 quarterly results have been represented to separate out our Midstream-Liquefaction segment from the Midstream-Refining and Marketing segment as the liquefaction business has become an increasingly important component of our business.
(4)	We did not have any discontinued operations or extraordinary items during the periods covered by this table.

Management Discussion and Analysis      INTEROIL CORPORATION     14

Quarterly results have been affected by movements in refining gross margins (as described in the Business Environment section), the impact of fluctuating production levels at the refinery resulting from maintenance and other shutdowns, the level of exploration activity not funded by our indirect participation interest agreement, changes in our borrowings, the acquisition of additional assets in our downstream business, and changes in volumes sold by our downstream business.

Quarterly Consolidated Financial Results Analysis

Consolidated results analysis for three Months to December 2006 versus three Months to December 2005

Net Income/(Loss) Comparison Based on Key Differences
(millions of USD, after-tax)

EBITDA improved by $12.1 million from a loss of $5.6 million (loss of $0.19/share) to a profit of $6.5 million ($0.22/share).
InterOil’s net loss improved from a loss of $12.2 million ($0.42/share) in the fourth quarter of 2005 to $3.7 million ($0.12/share) in the fourth quarter of 2006.

(1)	The movement in the midstream gross margin is calculated as the total midstream revenues from operations less cost of goods sold and operating expenses. Gross margin 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.
(2)	Other mainly includes movements in office and administration expenses.

Our fourth quarter 2006 net loss has improved by $8.5 million over our fourth quarter 2005 loss. The primary reasons for the change between the 2005 and 2006 quarters are as follows:

ü The refinery operations experienced a gross margin improvement of $12.9 million between the 2005 quarter and the 2006 quarter. This is the result of the positive impact of the revamp and optimization efforts which has resulted in a more profitable product mix in 2006 and lower associated fuel costs for the refinery. In addition, the fourth quarter of 2006 benefited from changes that we negotiated in our low sulphur waxy residue and naphtha sales contracts.

Management Discussion and Analysis      INTEROIL CORPORATION     15

ü	In addition, the midstream operations experienced a $0.4 million exchange gain in 2006 as compared to a $1.2 million exchange loss in 2005 which partially resulted from the strengthening of the PGK against the USD. During the year we negotiated improved rates on our PGK and USD transactions.
ü	The office and administration and other costs for the fourth quarter of 2006 have decreased by approximately $1.1 million. This is largely the result of a gain on derivative instruments that were not subject to hedge accounting.
ü	During 2006 we started our midstream liquefaction segment and during the fourth quarter of 2006 we incurred $0.4 million of costs relating to the preliminary stages of a liquefied natural gas plant project.
ü	Our downstream business had a $3.2 million decrease in its net income for the quarter over the prior year. This primarily related to product pricing. The IPP dropped from 1.56 PGK (USD $0.50) in September to 1.49 PGK (USD $0.48) at the beginning of January 2007. As the IPP declined each month, any inventory holdings purchased in preceding periods were sold at lower IPP prices, resulting in lower margins. The effect of this was compounded by our acquisition of Shell. Although we gained additional sales volume in the quarter, our gross margin declined. Sales volumes for our downstream business increased from 655 kilolitres per day in the fourth quarter of 2005 to 1,472 kilolitres per day in the fourth quarter of 2006.
ü	Our upstream operations experienced lower accretion expense as a result of a decrease in the related indirect participation interest liability. The indirect participation interest liability is decreased as the obligation to complete the drilling program is being met.
ü	In 2005 we recognized $1.4 million in exploration expenses, primarily relating to the costs of testing the Black Bass and Triceratops wells. In 2006, there were no similar exploration costs that were recognized. The majority of our fourth quarter 2006 expenditures were allocated against the indirect participation interest agreement.
ü	Depreciation associated with our midstream and upstream segment increased as a result of a full quarter of depreciation being recognized on our rig and exploration warehouse and also as the result of depreciation being recognized on the capitalized revamp costs.

Our interest expense for the quarter has increased by $2.7 million as a result of the $130.0 million secured loan financing. We entered the facility in May 2006.

For further analysis of the first through third quarter results, refer to InterOil’s quarterly MD&A available on the Company’s website at www.interoil.com or on www.sedar.com. An analysis of our fourth quarter 2006 results is contained on pages 13 to 15 under the heading “Results for quarter ended December 31, 2006”.

Management Discussion and Analysis      INTEROIL CORPORATION     16

YEAR IN REVIEW

The following section provides a review of 2006 for each of our business segments. It includes a business summary, an operational review of the year, a review of financial results, and an analysis of each stream’s contribution to InterOil’s corporate strategy.

Upstream Year In Review

Upstream Business Summary

Our upstream business currently has four exploration licenses and two retention licenses in Papua New Guinea covering approximately nine million acres, of which amount, approximately 8.2 million nett acres are operated by InterOil. Petroleum Prospecting Licenses 236, 237 and 238 are located in the Eastern Papuan Basin northwest of Port Moresby and are 100% owned and operated by the Company. Our current exploration efforts are focused on these three licenses. Our indirect participation interest investors have the right to a 31.55% working interest in the exploration wells currently being drilled and any resulting fields. These investors have a 31.55% interest in the next three exploration wells and a 24.8% interest in the two subsequent exploration wells. In addition, we own a 15% working interest in Petroleum Prospecting License 244, located offshore in the Gulf of Papua, a 43.1% working interest in Petroleum Retention License 4 and a 28.6% working interest in Petroleum Retention License 5.

Q:

How much property in Papua New Guinea does the InterOil upstream business encompass?

A:

InterOil has four exploration licenses and two retention licenses covering approximately 9 million acres.

Upstream Operating Review

Key Upstream Metrics	2006		2005
Wells drilled		1		2
Total wells drilled in eight well indirect participation interest program		3		2
Total feet drilled		6,087		12,597
2D seismic miles acquired		79		100
Airborne gravity and magnetic survey miles acquired		6,244		3,800
Total spent on seismic acquisition ($ millions)		6.8		11.0
Total spent on drilling ($ millions)		37.9		22.9

During the year we continued the eight well drilling program covering Petroleum Prospecting Licenses 236, 237 and 238 which we commenced in April 2005. In 2006, the Company drilled the third well in this program, Elk-1 on Petroleum Prospecting Licenses 238. This well, which was spudded in February 2006, encountered high pressure gas at a depth of 5,543 feet on June 11, 2006 and was shut-in while well control equipment was mobilized to the site. Well control operations and modifications to the rig were undertaken to enable managed

Management Discussion and Analysis      INTEROIL CORPORATION     17

pressure drilling and we resumed drilling Elk-1 on September 15, 2006. The well reached a total depth of 6,087 feet. A drill-stem test was performed and wireline logs were acquired in the interval 5,379 to 6,087 feet. The data obtained from these operations indicate the possibility of a significant natural gas and condensate accumulation. The Elk-2 well was spudded on February 9, 2007 to appraise the Elk-1 discovery and to explore for an oil zone in this structure.

During 2006, we acquired a total of 79 miles of 2D seismic over Petroleum Prospecting License 238 at a cost of $5.2 million. The 2006 seismic program complemented the 136 miles of seismic program that we acquired during the previous three years. As of year end, we had access to 1,000 miles of 2D seismic data covering Petroleum Prospecting Licenses 236, 237 and 238, including the 215 miles we have recorded since acquiring these licenses. During the first quarter of 2007 we mobilized a seismic crew to conduct a detailed 2D seismic survey over the Elk discovery and leads on-trend with the Elk discovery that have been identified from seismic data and airborne gravity and magnetic surveys acquired by InterOil.

In addition to the seismic program, we also conducted 2,471 miles of airborne gravity and magnetic surveys in 237 and 3,773 miles in Petroleum Prospecting License 238. Airborne gravity and magnetic methods have enabled us to better identify the quality of leads derived from surface geology, to identify previously unmapped leads and to optimize the location of our 2D seismic programs.

Upstream Financial Results

Upstream – Operating results	Years ended December 31,
($ thousands)	2006			2005(1)			2004(1)
External sales		—			—			—
Inter-segment revenue		—			—			—
Other non-allocated revenue		5,249			1,295			113
Total segment revenue		5,249			1,295			113
Cost of sales and operating expenses		—			—			—
Office and administration and other expenses		(5,553	)		(1,738	)		(1,648	)
Exploration costs		(1,658	)		—			(2,903	)
Exploration impairment		(417	)		(2,145	)		(35,567	)
Impairment expense on barge sale		(757	)		—			—
Accretion expense		(3,741	)		(5,647	)		—
Earnings before interest, taxes, depreciation and amortization (unaudited)		(6,877	)		(8,235	)		(40,005	)
Depreciation and amortization		(806	)		(314	)		(13	)
Interest expense		(5	)		—			(5	)
Loss from ordinary activities before income taxes		(7,688	)		(8,549	)		(40,023	)
Income tax expense		—			—			—
Total net loss		(7,688	)		(8,549	)		(40,023	)

(1) Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.

Management Discussion and Analysis      INTEROIL CORPORATION     18

Upstream Financial Results Analysis

During 2006, the upstream business had a net loss of $7.7 million as compared to a loss of $8.5 million in 2005.

The key variances in the year ended 2006 as compared to the year ended 2005 are explained as follows:

ü	An increase in other revenues of $3.9 million in 2006 primarily related to the rental of our company-owned rig being charged against our indirect participation interest at current market day rents. 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. The increase is also contributed by intercompany interest revenue of $1.4m received by Upstream from Corporate on account of the use of IPI funds. The revenue also relates to the one-time rental of camp facilities and providing logistics support to another exploration company.
ü	An increase of $2.7 million, included in office and administration and other expenses, related to the costs of owning and maintaining the rig.
ü	An increase of $1.7 million in exploration expenses relating to the seismic program undertaken in 2006. In 2005, all seismic costs were allocated against our indirect participation interest liability rather than being expensed. In 2006, in accordance with the accounting treatment adopted for the indirect participation interest liability, a portion of our exploration costs were allocated against the liability, but the remaining component was recognized as an expense item.
ü	A decrease of $1.7 million in exploration impairment is the result of the testing costs relating to the Black Bass and Triceratops wells being expensed in 2005 whereas in 2006 the majority of the expense relates to the acquisition of additional interests in our PRL 4 and PRL 5 licenses.
ü	An increase of $0.8 million for the impairment expense on a barge sale. The Company sold one of its two barges to a third party during the year.
ü	Accretion expense decreased by $1.9 million in 2006 as a result of a decrease in the indirect participation interest liability. During 2006, the indirect participation liability has decreased as the obligation to complete the drilling program is being met.
ü	An increase in depreciation expense of $0.5 million in 2006 as a result of a full year of depreciation being recognized on the rig, offices and warehouse which were purchased part way through 2005.

Outlook for 2007

2007 planned activity

ü	Drill appraisal well, Elk-2, and exploration well Antelope-1
ü	Conduct 100 miles of appraisal seismic over the Elk structure
ü	Drill one well in PRL 5
ü	Re-enter and test the Stanley gas discovery in PRL 4

Key factors that will affect our 2007 progress

ü	Results from Elk-2 and Antelope-1
ü	Ability to attract and retain staff in a competitive oil and gas industry
ü	Conclusion of an exploration funding agreement with an industry major
ü	Proving sufficient gas reserves to guarantee the liquefaction project

Management Discussion and Analysis      INTEROIL CORPORATION     19

MIDSTREAM REFINING AND MARKETING YEAR IN REVIEW

Midstream Refining and Marketing Business Summary

The midstream operations predominately relate to our refinery situated in Port Moresby, the capital city of Papua New Guinea. Our refinery comprises of a 32,500b/d crude distillation unit (CDU) and a 3,500b/d catalytic reforming unit (CRU) which were commissioned during the second half of 2004 and began commercial operations in 2005. InterOil is the sole refiner of hydrocarbons in Papua New Guinea and the refinery’s output is sufficient to meet 100% of the domestic demand in Papua New Guinea. Diesel, jet fuel and gasoline are the primary products that we produce for the domestic market.

Operation of the CDU also results in the production of naphtha and low sulfur waxy residue and sometimes limited volumes of LPG’s are produced depending on the crude feedstock. To the extent that we do not convert naphtha to gasoline within the CRU, we export it to the Asian markets in two grades, light naphtha and mixed naphtha, which are predominately used as petrochemical feedstocks. To the extent that we do not consume the low sulfur waxy residue as part of the refinery’s fuel requirement or sell it within Papua New Guinea as fuel for electricity generation — a profitable new niche market we have recently created — the low sulfur waxy residue is exported as it is valued by more complex refineries as cracker feedstock or may be utilized as fuel in large power stations.

A:

The refinery’s output is sufficient to meet 100% of the domestic demand in Papua New Guinea.

Q:

How much of the domestic demand in Papua New Guinea does the refinery supply?

Midstream Refining and Marketing Operating Review

Key Refining and Marketing Metrics	2006			2005
Net income/(loss) ($ millions)	($	24.0	)	($	30.9	)
EBITDA ($ millions)	($	2.6	)	($	10.5	)
Throughput (barrels per day)(1)		19,784			23,117
Cost of production per barrel(2)	$	3.46		$	3.09
Working capital financing cost per barrel of production(2)	$	1.16		$	0.96
Distillates as percentage of production		65	%		55	%

(1)	Throughput per day has been calculated excluding shut down days.
(2)	Our cost of production per barrel and working capital financing cost per barrel have been calculated based on a notional throughput. Our actual throughput has been adjusted to include the throughput that would have been necessary to produce the equivalent amount of diesel that we imported during the year.

The refining and marketing stream has been improved by reducing its net loss and increasing its EBITDA by $7.9 million from 2005 to 2006. The improvements in the results are explained in detail in the optimization efforts section below as well as in the summary of financial results.

Management Discussion and Analysis      INTEROIL CORPORATION     20

In 2006 our total throughput for the year was 19,784 bbls per day versus 23,117 bbls per day in 2005. The decrease in throughput from 2005 to 2006 is the result of improved distillate yields. In addition, during 2005 the refinery was run at higher throughputs in the early part of the year in order to complete commissioning requirements.

The decrease in throughput has resulted in higher costs of production per barrel. Although total operating costs were down approximately $0.8 million, total notional throughput was also down by approximately 1 million barrels over the course of the year. The refinery is undertaking a cost reduction program in 2007 with the goal of reducing operating costs by approximately 10%.

Our working capital financing costs have increased, primarily due to the substantial increase in the LIBOR rate which has increased from approximately 2.3% to approximately 5.3% between 2005 and 2006.

During 2006, the refinery’s objective was to satisfy the domestic Papua New Guinea demand for diesel, jet, kerosene and gasoline while minimizing production of naphtha and low sulphur waxy residue. The refinery was able to achieve this objective through optimization efforts which have resulted in an increased distillate output as a percentage of total production. Naphtha and low sulphur waxy residue are exported at a lower margin than the distillates which are sold in Papua New Guinea.

Optimization Efforts

Our midstream business operations were focused on optimization projects to improve profitability throughout 2006. Most of the optimization occurred in June and July when we shutdown the refinery to install new generators and to modify the furnaces and boilers to also run on low sulfur waxy residue. These works improved the product slate, improved reliability and reduced fuel costs. The shutdown had minor short-term cost impacts whilst facilitating major long-term profitability improvements. Despite the cost impacts resulting from the shutdown of the refinery, the refinery’s performance in the second half of 2006 was significantly improved from that of the first half of 2006.

A:

These initiatives have resulted in increased yields of higher value products and lower fuel consumption at the refinery.

Q:

How do the “revamp” works and crude optimization efforts undertaken in 2006 improve profitability?

Management Discussion and Analysis      INTEROIL CORPORATION     21

Distillates, such as jet fuel and diesel, produced for the domestic market contribute a higher gross margin than naphtha and low sulphur waxy residue. As a result, increasing the yield of distillates produced has resulted in a higher gross margin for the business. In addition to reducing the yield of naphtha and low sulphur waxy residue, the revamp works have resulted in a reduced fuel requirement. This reduces the cost of production and therefore contributes to an improvement in gross margin.

The completion of optimization activities and various other cost saving initiatives undertaken by the company, have contributed to a significant improvement in the results of the second half of 2006 as compared to the first half of 2006 which are explained below.

Gross margin improved $16.5 million between the first and second half of 2006 due to the combination of competing factors:

Controllable

+	Improved yield structure post shutdown
+	Decreased fuel consumption post shutdown
+	Decreased fuel cost post shutdown
+	Improved premiums negotiated on export products

Non controllable

+	Improved margins on domestic sales of distillates
–	Decreased margins versus benchmark prices on export sales
–	Decreasing price environment in second half versus increasing price environment in first half
–	Decreasing benchmark refining margin (Singapore Tapis Hydroskimming)
ü	Foreign exchange gains in the second half of 2006 were $4.5 million compared to $0.1 million for the first half of 2006. During the year we negotiated improved rates on our PGK to USD transactions.
ü	The effect of non-hedge accounted derivatives on earnings increased by $2.7 million from the first half to the second half of 2006. During the second half of the year we introduced a new derivative instrument into our risk management program. This instrument, coupled with the technique by which we utilize it, was deemed not to be subject to hedge accounting and as a result all movements on these derivative contracts are

Management Discussion and Analysis      INTEROIL CORPORATION     22

	recognized in the statement of operations below the gross margin level. Realized and unrealized gains from this new risk management instrument are largely responsible for the $2.7 million movement between the two periods.
ü	Borrowing costs increased by $0.7 million in the second half of 2006 due to the combination of increased LIBOR rates on our working capital facility and increased working capital borrowing requirements as a result of the refinery holding excess inventory through the shutdown period. These two factors were partially offset by decreased LC fees and the increased utilization of the cash backing component of our working capital facility. The cash backing allows us to reduce the cost of our net borrowings.
ü	General and administrative expenses decreased by $0.8 million between first and second half of 2006 as a result of various cost saving initiatives undertaken by the refinery management team and a decrease in legal costs as a result of the settlement of our dispute with Clough Niugini Limited at the end of the first half of 2006.
ü	Depreciation increased by $0.3 million as a direct result of the capital revamp works undertaken during the year.

Outlook for 2007

2006 improvements set to show full year benefit in 2007

ü	Contract premium improvements to export products
ü	Improvement to negotiated foreign exchange rates on PGK and USD transactions
ü	Improvement to working capital interest rates
ü	Improved product yields
ü	Decreased fuel costs

2007 Initiatives:

ü	Conduct negotiations to reduce working capital costs
ü	Implement strategies to further improve foreign exchange rates
ü	Reduce direct operating costs
ü	Eliminate unplanned downtime
ü	Expand niche market for InterOil Power Fuel
ü	Reduce length of working capital cycle
ü	Seek out and exploit operational and tax planning synergies in conjunction with the newly expanded downstream business

Management Discussion and Analysis      INTEROIL CORPORATION     23

Midstream Refining and Marketing Annual Financial Results

Midstream
Refining and Marketing – Operating results	Years ended December 31,
($ thousands)	2006			2005(2)			2004(1),(2)
External sales		315,211			356,327			26,310
Inter-segment revenue		136,584			80,094			—
Interest and other revenue		360			245			(55	)
Total segment revenue		452,155			436,666			26,255
Cost of sales and operating expenses		(451,374	)		(436,491	)		(27,686	)
Office and administration and other expenses		(10,577	)		(9,747	)		(3,189	)
Gain on derivative contracts		2,560			542			34
Foreign exchange gain/(loss)		4,636			(1,434	)		22
Earnings before interest, taxes, depreciation and amortization (unaudited)		(2,600	)		(10,464	)		(4,563	)
Depreciation and amortization		(10,729	)		(10,598	)		(312	)
Interest expense		(10,881	)		(10,162	)		(844	)
Loss from ordinary activities before income taxes		(24,210	)		(31,224	)		(5,719	)
Income tax expense		—			—			—
Non controlling interest		259			362			69
Total net loss		(23,951	)		(30,862	)		(5,650	)

(1)	Our refinery began commercial operations on January 1, 2005. During 2004 we were still constructing and commissioning our refinery and the costs associated with the construction and commissioning of our refinery were capitalized rather than expensed. As a result of our refinery not having any commercial operations in 2004, our 2004 to 2005 and 2006 results are not comparable.
(2)	Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.

Midstream Refining and Marketing Annual Financial Results Analysis

During the year ended 2006, the midstream business had a net loss of $24.0 million as compared to a loss of $30.9 million in 2005. The key variances in the year ended 2006 as compared to the year ended 2005 are explained as follows:

ü	An increase to gross margin of $0.5 million for the year was primarily the result of the revamp improvements made in the second half of 2006 and price risk management activities over the year.
ü	Higher office and administration and other expenses of $0.8 million was due to a number of factors including increased repairs and maintenance, corporate allocations, travel costs, and management salaries and contractor costs.
ü	An increase to the gain on derivative contracts of $2.0 million due to increased price risk management activity that is deemed not to be subject to hedge accounting.
ü	An increase in foreign exchange gain/(loss) of $6.1 million was due to the strengthening of the PGK against USD and negotiating improved rates on our PGK to USD transactions during 2006.
ü	Higher depreciation expense of $0.1 million was due to the addition of depreciable assets from the refinery revamp program.
ü	An increase in interest expense of $0.7 million was due to increasing LIBOR rates and increased borrowing requirements due to higher oil prices partially offset by a decrease in line of credit (LC) fees.

Management Discussion and Analysis      INTEROIL CORPORATION     24

MIDSTREAM LIQUEFACTION YEAR IN REVIEW

A:

A facility that will produce 9 million tons per annum of liquefied natural gas

Q:

What type of liquefaction facility does InterOil currently envisage?

Midstream Liquefaction Operating Review

Our liquefaction segment is in the early stages of its development. In May, InterOil signed a Memorandum of Understanding with the Independent State of Papua New Guinea for natural gas development projects in Papua New Guinea and a tri-party agreement with Merrill Lynch Commodities (Europe) Limited and an affiliate of Clarion Finanz AG. The tri-party agreement relates to a proposal for the construction of a liquefaction plant to be built adjacent to our refinery. We are targeting a facility that will produce up to nine million tons per annum of Liquefied Natural Gas (LNG) and condensates. The infrastructure currently being contemplated includes condensate storage and handling, a gas pipeline from the Elk location as well as sourced suppliers of gas, and LPG storage and handling. The LNG facility will also interface with our existing refining facilities.

As at year end 2006, significant progress was made on the key components necessary to bring to fruition a successful LNG project. During 2007 the company anticipates entering into a shareholder agreement relating to the project and further development stage activities relating to the construction and financing of the plant.

Midstream Liquefaction Annual Financial Results

Midstream
Liquefaction – Operating results	Years ended December 31,
($ thousands)	2006			2005(1)		2004(1)
External sales		—			—		—
Inter-segment revenue		—			—		—
Total segment revenue		—			—		—
Cost of sales and operating expenses		—			—		—
Office and administration and other expenses		(694	)		—		—
Earnings before interest, taxes, depreciation and amortization (unaudited)		(694	)		—		—
Depreciation and amortization		—			—		—
Interest expense		—			—		—
Loss from ordinary activities before income taxes		(694	)		—		—
Income tax expense		—			—		—
Total net loss		(694	)		—		—

(1) Our liquefaction segment was formed in 2006 and as a result there is no comparative information for 2005 and 2004. The liquefaction segment is in its early stage of development.

Management Discussion and Analysis      INTEROIL CORPORATION     25

Midstream Liquefaction Annual Financial Results Analysis

All costs relating to the liquefaction segment are currently being expensed. These costs include expenses relating to employees, office premises, and consultants.

DOWNSTREAM YEAR IN REVIEW

Downstream Business Summary

Our wholesale and retail distribution business is the largest and most comprehensive asset distribution base in Papua New Guinea. It encompasses bulk storage, aviation refueling, and the wholesaling and retailing of refined petroleum products which, at the end of 2006, supplies approximately 67% of Papua New Guinea’s refined petroleum product needs. Our retail and wholesale distribution business distributes diesel, jet fuel, gasoline, kerosene, avgas, and fuel oil as well as Shell & BP branded commercial and industrial lubricants such as engine and hydraulic oils. In general, all of the refined products sold pursuant to our wholesale and retail distribution business are purchased from our refining and marketing business segment with the exception of lubricants, fuel oil and avgas.

A:

The InterOil name is associated with 49 service stations, 11 depots and 6 terminals. InterOil supplies 67% of Papua New Guinea’s refined petroleum product needs.

Q:

How prominent is InterOil’s wholesale and retail distribution business in Papua New Guinea.

As of 2006, we provided petroleum products to 49 retail service stations that now operate under the InterOil brand name. Of the 49 service stations that we supply, 21 are owned by us or head leased, with a sublease to company approved operators. The remaining 28 service stations are independently owned and operated. We supply products to each of these service stations pursuant to retail supply agreements. In addition to our retail distribution network, we supply petroleum products as a wholesaler to commercial clients and also operate 14 aviation locations throughout Papua New Guinea. We own and operate 6 larger terminals and 11 depots that we use to supply product throughout Papua New Guinea. More than two-thirds of the volume of petroleum products that we sold during 2006 was supplied to commercial customers. Although the volume of sales to commercial customers is far larger than through our retail distribution network, these sales have a lower margin.

Management Discussion and Analysis      INTEROIL CORPORATION     26

Downstream Operating Review

Key Downstream Metrics	2006			2005
Net income ($ millions)	$	3.0		$	6.4
EBITDA ($ millions)	$	6.3		$	9.6
Market share (1)		67	%		29	%
Sales volumes (millions of liters) (2)		291.8			210.4
Cost of distribution per liter ($  per liter) (3)	$	0.06		$	0.05

(1)	Market share has been calculated based on domestic purchases of product from the refinery during the final quarter of each year.
(2)	Sales volumes reflect the actual sales volumes achieved for the year and therefore only include the effect of the Shell acquisition from October 1, 2006.
(3)	Cost of distribution per liter includes land based freight costs and operational costs. It excludes depreciation and interest.

In January 2006, InterOil entered into an agreement with Shell Overseas Holdings Limited to purchase all of Shell’s retail and distribution assets in Papua New Guinea and all aviation facilities except Shell’s interest in the aviation facility in Port Moresby. The closing of this transaction was subject to the approval of several governmental authorities in Papua New Guinea. On October 1, 2006 the transfer of ownership occurred, adding 4 terminals, 4 depots, 17 retail sites and 14 aviation facilities to the existing downstream asset base. All of these assets now operate under the InterOil Products brand name. The purchase price of this business was $25.8 million, net of cash received, and is subject to adjustment pending verification of the acquired working capital.

The Shell acquisition makes InterOil the largest distribution business in Papua New Guinea. Other major commercial customer wins have also increased our presence in the Papua New Guinea market. Our market share has increased from 29% in the final quarter of 2005 to 67% in the final quarter of 2006 as a result of acquiring Shell and growing our commercial customer base.

Management Discussion and Analysis      INTEROIL CORPORATION     27

The increase in sales volume from commercial customers has resulted in a lower cost of distribution per litre. However, despite the significant increase in total sales made by the downstream business and a decline in the cost of distribution per litre, the net profit has declined. This is largely attributable to a substantial decline in the IPP price over the fourth quarter of 2006. In 2005, the company benefited from increases in the IPP prices.

The diesel IPP price fell from 1.65 PGK on October 8, 2006 to 1.49 PGK on January 8, 2007. . The IPP price is set on the eighth day of each month. In a market where IPP is declining, the price change results in all inventory being revalued to, and subsequently sold at, the lower amount. This in turn causes a decrease in the gross margin earned by the downstream business. During 2005 the diesel IPP price increased steadily from 1.10 PKG to 1.61 PGK.

In July 2006 the downstream business completed the construction of a 2 million litre diesel storage tank at our terminal Wewak, East Sepik, to augment storage availability at that location. The East Sepik province has experienced substantial growth in recent years. In addition, Mobil and Shell closed their operations in the town of Wewak. The additional infrastructure will place us in a strong position to continue to service the needs of the East Sepik market and take advantage of the changes that have occurred.

Management Discussion and Analysis      INTEROIL CORPORATION     28

Downstream Financial Results

Downstream Operating results	Years ended December 31,
($ thousands)	2006(1)			2005(2)			2004(2),(3)
External sales		195,877			124,854			62,410
Inter-segment revenue		22			6			489
Interest and other revenue		1,421			341			263
Total segment revenue		197,320			125,201			63,162
Cost of sales and operating expenses		(183,511	)		(110,857	)		(53,159	)
Office and administration and other expenses		(7,479	)		(4,725	)		(3,147	)
Earnings before interest, taxes, depreciation and amortization (unaudited)		6,330			9,619			6,856
Depreciation and amortization		(910	)		(204	)		(224	)
Interest expense		(152	)		(226	)		(455	)
Income from ordinary activities before income taxes		5,268			9,189			6,177
Income tax expenses		(2,273	)		(2,756	)		(1,900	)
Total net income		2,995			6,433			4,277

(1)	Our wholesale and retail distribution business segment acquired the business of Shell Papua New Guinea Limited on October 1, 2006 and contains the results of the Shell business from this date.
(2)	Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(3)	Our wholesale and retail distribution business segment was acquired on April 28, 2004 and only operated for eight months during 2004. As a result of our downstream results not having a full year of operations in 2004, our 2004 to 2005 and 2006 results are not comparable.

Downstream Financial Results Analysis

During the year ended December 31, 2006, the downstream business earned a net income of $2.9 million as compared to $6.4 million in 2005.

The key variances in the year ended 2006 as compared to the year ended 2005 are explained as follows:

ü	A decrease to gross margin of $1.6 million for the year 2006 over the year 2005 was most significantly the result of continuous drops in IPP over the fourth quarter of 2006. The IPP dropped from K1.65 in September to K1.49 at the beginning of January 2007. As the IPP declined each month, any inventory holdings purchased in preceding periods were sold at lower IPP prices, resulting in lower margins. The effect of this was compounded as our acquisition of Shell and its corresponding inventory balance coincided with the decline in IPP pricing.
ü	An increase in office and administration and other expenses of $2.8 million due to a number of factors including, higher insurance costs as a result of the acquisition of the Shell business and expansion of the aviation business, higher corporate allocations, increased repairs and maintenance costs, and increased travel costs.
ü	An increase in depreciation expense of $0.7 million over 2005 related primarily to the addition of the Shell assets on October 1 and the completion of the 2 million litre East Sepik tank project.
ü	Our income tax expense as a percentage of income from ordinary activities has increased during 2006 as the result of a reduction to the future income tax benefit being recognized on the revaluation of the Shell plant and equipment acquired on October 1.

Management Discussion and Analysis       INTEROIL CORPORATION       29

Outlook for 2007

2007capital spending plans

ü	Upgrades to terminal, depots and aviation sites
ü	Aviation upgrade and refueller vehicles
ü	New customer base pumps and tankage requirements
ü	Finance system software installation

2007 growth plans:

ü	Consider commercial bunkering opportunities
ü	Secure contracts to supply new mining and petroleum companies
ü	Pursue opportunities in organic growth agriculture sector
ü	Explore market opportunities in North Solomon’s Province, including strategic alliances with key distributors

CORPORATE YEAR IN REVIEW

Corporate Annual Financial Results

Corporate Operating results	Years ended December 31,
($ thousands)	2006(5)			2005			2004
External sales elimination		—			—			(18,075	)
Inter-segment revenue elimination(1)		(136,606	)		(80,101	)		(489	)
Interest revenue		(58	)		480			165
Other unallocated revenue		—			(1	)		91
Total segment revenue		(136,664	)		(79,622	)		(18,306	)
Cost of sales and operating expenses elimination(1)		135,391			80,101			15,500
Office and administration and other expenses(2)		(6,567	)		(6,193	)		(6,773	)
Earnings before interest, taxes, depreciation and amortization (unaudited)		(7,840	)		(5,714	)		(9,581	)
Depreciation and amortization(3)		92			79			(90	)
Interest expense(4)		(6,235	)		(599	)		(1,899	)
Income from ordinary activities before income taxes		(13,983	)		(6,234	)		(11,570	)
Income tax expenses		(69	)		(76	)		25
Non-controlling interest		4			6			1
Total net income		(14,048	)		(6,304	)		(11,544	)

(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)	Our 2005 and 2004 segment results have been represented to confirm with the presentation adopted in 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.

Management Discussion and Analysis       INTEROIL CORPORATION      30

Corporate Annual Results Analysis

Key movements in our corporate services segment between 2006 and 2005 were as follows:

ü	A decrease of $0.3 million in stock compensation expense recognized in office and administration and other expenses.
ü	An increase in interest expense of $5.6 million primarily relating to the increased borrowings made under the secured loan facility entered into in May 2006.

LIQUIDITY AND CAPITAL RESOURCES

Summary of Cash Flows

($ thousands)	2006			2005			2004
Net cash inflows/(outflows) from:
Operations		(3,246	)		(22,713	)		(79,767	)
Investing		(91,638	)		15,468			(29,024	)
Financing		66,964			38,302			128,119
Net cash movement		(27,920	)		31,057			19,328
Opening cash		59,601			28,544			9,216
Closing cash		31,681			59,601			28,544

Operating Activities

For the year ended 2006 cash used in our operating activities was $3.2 million compared with $22.7 million in 2005. Reasons for the $19.5 million improvement in net cash movements include:

ü

Our cash used in operations, prior to changes in non-cash working capital increased, by $6.2 million. This is primarily due to interest paid on the $130.0 million secured loan facility entered into in 2006.

ü

Our non-cash working capital provided a cash inflow from operations of $21 million in 2006 as compared to contributing $4.7 million to the cash outflows in 2005. This change of $25.7 million is primarily attributable to an increase in our accounts payable, accrued liabilities and income tax payable creating a cash inflow of $25.0 million, $19.2 million relating to movements in our inventories and an offsetting $19.2 million as a result of an increase in trade receivables.

Investing Activities

For the year 2006, cash used in our investing activities was $91.6 million compared with cash generated of $15.5 million for the year 2005. During these periods, the cash used on investing activities consisted primarily of:

ü	$15.9 million increase in our secured cash balances in 2006 versus an increase of $1.1 million in 2005.
ü	$25.8 million, net of cash received, used to acquire Shell Papua New Guinea on October 1.
ü	$42.6 million on oil and gas exploration expenditure in 2006 versus $43.0 million in 2005 mainly related to drilling and seismic activities.
ü	$13.6 million on plant and equipment in 2006 versus $5.6 million in 2005 which is primarily related to the revamp and optimization activities undertaken by the refinery and the additional diesel tank built by the downstream business in East Sepik.

In 2005, $80.4 million was provided by the indirect participation interest investors for the eight well drilling program.

Management Discussion and Analysis       INTEROIL CORPORATION       31

Financing Activities

For the year 2006, cash proceeds from our financing activities were $67.0 million. During 2006, the cash movements caused by financing activities were primarily due to:

ü	$125.3 million of net proceeds from our secured loan facility entered into in May 2006.
ü	$1.5 million from the issuance of common shares in 2006 as compared to $5.5 million received in 2005.
ü	$33.9 million of repayments on the crude import facility in 2006 versus $5.8 million of repayments made in the 2005 period.
ü	$21.5 million in repayments of unsecured loans in 2006. These proceeds were received in 2005.

In 2005, $22.7 million was received from the indirect participation interest investors relating to the conversion options included under the indirect participation interest agreement. No new indirect participation interest funds were received in 2006.

Capital Expenditures

Upstream Capital Expenditures

Our capital expenditures for exploration in Papua New Guinea for the year ended December 31, 2006 were $48.5 million compared with $43.8 million during the same periods in 2005. Our capital expenditures for 2006 consisted of:

ü	$33.1 million for the drilling and testing of the Elk-1 exploration well. The Elk-1 well expenditures were higher than expected as a result of encountering high pressure gas that required significant expenditures to control the well pressure before we could continue drilling the well. Our drilling progress was impeded for three months.
ü	$3.0 million of pre-drill costs on the Elk-2 structure, including site preparation, camp construction, rig mobilization and supplier standby costs.
ü	$1.0 million of demobilization costs from the Triceratops drill site.
ü	$5.6 million for seismic acquisition.
ü	$1.1 million for airborne gravity survey work.
ü	$3.8 million for rig equipment, primarily in relation to increasing the capacity of the mud circulation system.
ü	$0.6 million for inventory and other costs includes drilling consumables such as mud, casing and drill bits, as well as spare parts for all the rig equipment.
ü	$0.3 million of pre-drill costs for the Antelope-1 well which includes preliminary site clearing and the construction of a helicopter pad. We anticipate mobilizing to Antelope-1 wellsite immediately after rig release from Elk-2 well. The Antelope structure is located approximately 4 miles from of Elk-1 well and 8 miles from the Elk-2 well.

The increase in capital expenditures during 2006 compared to the same period of 2005 is due to the increased costs relating to drilling the Elk-1 well.

Midstream Capital Expenditures

Our capital expenditures for our refining and marketing business segment for the year 2006 were $12.0 million compared with $3.3 million during 2005. The increase in capital expenditures during 2006 is primarily related to our refinery optimization program that was completed during the third quarter of 2006.

Downstream Capital Expenditures

Our capital expenditures for our wholesale and retail distribution business segment for 2006 were $27.6 million compared with $14.0 million during the same period in 2005. Our 2006 capital expenditures consisted of costs associated with the completion of the East Sepik and the purchase of storage tanks, mine packs, new fuel

Management Discussion and Analysis       INTEROIL CORPORATION       32

distribution software and satellite storage. In addition we acquired commercial storage tanks and pumps for the Shell business. Also included in our capital expenditures for 2006 is $25.8 million, net of cash received, for the Shell Papua New Guinea acquisition. The 2005 expenditure primarily related to a $12.1 million payment made to BP International for the acquisition of InterOil Products Limited and $1.9 million for a storage tank, barge facility and a number of other smaller capital items.

Sources of Capital

Upstream

We currently fund all of our upstream capital expenditures using the proceeds of the $125.0 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 $150.0 million to $170.0 million. This crude import facility is used to finance purchases of crude feedstock for our refinery. Our ability to borrow additional amounts under this crude import facility expires on June 30, 2007, at which time we expect to have renewed the facility or entered into an alternate funding arrangement. As of December 31, 2006, $52.6 million remained outstanding under the crude import facility. The weighted average interest rate under the crude import facility was 7.3% for the year ended December 31, 2006.

In December 2006, our OPIC secured loan was amended. Under the amendment, the half year principal payments due in December 2006 and June 2007 of $4.5 million each have been deferred until December 31, 2007 and interest payments previously due on December 31, 2006 and June 30, 2007 have been deferred until September 30, 2007. Repayments of interest and principal will recommence on December 31, 2007.

Downstream

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

Corporate

On May 4, we entered into a $130.0 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. We received $65.0 million in gross proceeds on the closing date of this secured loan facility and a further $35.0 million on June 29. A further drawdown of $18.0 million was made in September. 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, $12.0 million, representing the balance available under this facility, was drawn down.

Capital Requirements

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 $125.0 million indirect participation agreement entered into in February 2005 to drill eight exploration wells. We completed our third exploration well (Elk-1) in November 2006, 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 incurred at 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 the funds remaining under the

Management Discussion and Analysis       INTEROIL CORPORATION      33

indirect participation agreement should be sufficient to meet our obligation to drill the remaining five wells under the program; however, in the event we do not recover on our insurance claim, we may require additional capital to complete the program. No assurance can be given that we will be successful in obtaining new sources of capital on terms that are acceptable to us if such new capital is needed. 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 farmout or raise additional capital. However, we can provide no assurances that a farmout will be completed or that the terms of any such farmout will be acceptable to us. As of December 31, 2006, we had incurred $23.6 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 currently 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 on May 4, 2006 to pay our estimated capital expenditures for 2007. As of December 31, 2006, our primary lender for the midstream had agreed to defer interest payable until September 30, 2007 and principal until December 31, 2007 to assist our cash flows. We can give you no assurance that our primary lender will be willing to defer interest or, principal in the future. In addition, 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 2007.

Management Discussion and Analysis       INTEROIL CORPORATION       34

Contractual Obligations and Commitments

The following table contains information on payments for contracted obligations due for each of the next five years and thereafter and should be read in conjunction with our financial statements and the notes thereto:

	Payments Due by Period
													More
Contractual obligations			Less		1 – 2		2 – 3		3 – 4		4 – 5		than 5
($ thousands)	Total		than 1 year		years		years		years		years		years
Secured loan obligations		197,666		13,500		130,666		9,000		9,000		9,000		26,500
Accrued financing costs		1,450		363		1,087		—		—		—		—
Acquisition of subsidiary		1,771		1,771		—		—		—		—		—
Indirect participation interest(1)		1,744		731		1,031		—		—		—		—
Indirect participation interest(2)		49,289		12,461		21,087		15,740		—		—		—
Petroleum prospecting and retention licenses(3)		5,237		1,877		3,360		—		—		—		—
Total		257,157		30,703		157,213		24,740		9,000		9,000		26,500

(1)	These amounts represent the estimated cost of completing our commitment to drill exploration wells under our indirect participation interest agreement entered into in July 2003. See Note 18 to our unaudited financial statements for the years ended December 31, 2006, 2005 and 2004.
(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 18 to our unaudited financial statements for the years ended December 31, 2006, 2005 and 2004.
(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 December 31, 2006, we did not have any off balance sheet arrangements and did not enter into any during the year 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 management fees of $150,000 during 2006 (2005 - $150,000). 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 year ended December 31, 2006 amounted to $140,165 (2005 — $179,608).

Amounts due to directors for directors’ fees totaled $18,000 at December 31, 2006 (2005 — $30,500). In 2005 there were executive bonuses of $573,571 (2004 — $320,000); however these were paid in 2006.

Management Discussion and Analysis       INTEROIL CORPORATION       35

Share Capital

Our authorized share capital consists of an unlimited number of common shares with no par value. As of February 28 2007, we had 29,897,847 common shares outstanding and 34,575,761 common shares on a fully diluted basis.

Share Capital	Number of shares
Balance December 31, 2005		29,163,320
Shares issued on exercise of options		132,285
Shares issued on amendment of indirect participation interest (PNGDV)		575,575
Balance December 31, 2006		29,871,180
Shares issued on exercise of options		—
Shares issued on conversion of indirect participation interest		26,667
Balance February 28, 2007		29,897,847
Remaining stock options authorized		1,026,000
Remaining shares issuable upon exercise of warrants		340,247
Remaining conversion rights authorized(1)		3,306,667
Other		5,000
Balance February 28, 2007 Diluted		34,575,761

(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 3,306,667 common shares.

Derivative Instruments

Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks are extremely volatile and sometimes experience large fluctuations over short periods of time as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. Due to the nature of our business, there is always a time difference between the purchase of a crude feedstock and its arrival at the refinery and the supply of finished products to the various markets.

Generally, we are required to purchase crude feedstock two months forward, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Because of this timing difference, there is an impact on our cost of crude feedstocks and the revenue from the proceeds of the sale of products, due to the fluctuation in prices during the time period. Therefore, we use various derivative instruments as a tool to reduce the risks of changes in the relative prices of our crude feedstocks and refined products. Such an activity is better known as Hedging and Risk Management. These derivatives, which we use to manage our price risk, effectively enable us to lock-in the refinery margin such that we are protected in the event that the difference between our sale price of the refined products and the acquisition price of our crude feedstocks contracts are reduced. On the flip side, when we have locked-in the refinery margin and if the difference between our sales price of the refined products vis-à-vis our acquisition price of crude feedstocks expands or increase, then the benefits would be limited to the locked-in margin.

The derivatives instrument which we generally use is the over-the-counter (OTC) swap. The swaps transactions are concluded between counterparties in the derivatives swaps market, unlike futures which are transacted on the IPE and Nymex Exchanges. It is common place among refiners and trading companies in the Asia Pacific market to use derivatives swaps as a tool to hedge their price exposures and margins. Due to the wide usage of derivatives tools in the Asia Pacific region, the swaps market generally provides sufficient liquidity for the hedging and risk management activities. The derivatives swaps instrument covers commodities or products such as jet and kerosene, diesel, naphtha, and also crudes such as Tapis and Dubai. Using these tools, InterOil

Management Discussion and Analysis       INTEROIL CORPORATION       36

actively engages in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instrument such as Brent futures on the IPE Exchange to hedge our crude costs.

For a description of our current derivative contracts as of December 31, 2006, see Note 7 to our financial statements for the years ended December 31, 2006, 2005, and 2004.

InterOil recognized a net gain of $4.8 million from the use of derivative instruments during 2006. These movements were recorded as a $2.7 million decrease to sales, a $4.9 million decrease to cost of goods sold and a $2.6 million decrease to office and administrative and other expenses.

The fair value of financial instruments are determined by marking the open contracts to market, based on pricing information provided to us by BNP Paribas. As a December 31, 2006, there were no material contracts on which a gain or loss had been deferred. In 2005, there were $0.7 million of contracts on which a gain had been deferred. These contracts settled during 2006 and the actual gains and losses realized are included in the net income movement of $4.8 million described above.

We will continue with our hedging and risk management program in 2007 and we will continue to evaluate new approaches to enhance our hedging arrangement and margin protection.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with Canadian GAAP requires our management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations. The information about our critical accounting estimates should be read in conjunction with Note 2 of the notes to our consolidated financial statements for the year ended December 31, 2006, which summarizes our significant accounting policies.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment. A valuation allowance is provided against any portion of a future tax asset which will more than likely not be recovered. If actual results differ from the estimates or we adjust the estimates in future periods, we may need to record a valuation allowance. The net deferred income tax assets as of December 31, 2006 and 2005 were $1.4 million and $1.1 million, respectively.

Oil and Gas Properties

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

Management Discussion and Analysis       INTEROIL CORPORATION       37

exploration expenses. The net costs of drilling exploratory wells carried as an asset as of December 31, 2006 and 2005 were $19.2 million and $1.3 million.

Asset Retirement Obligations

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

Environmental Remediation

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

Impairment of Long-Lived Assets

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

Fair Value of Financial Instruments

We utilize derivative financial instruments in the management of our price exposures for our refined products and crude feedstocks. We disclose the estimated fair value of outstanding hedging contracts as of the end of a reporting period. The estimation of the fair value of certain hedging derivatives requires considerable judgment. The estimate of fair value for our derivative contracts is determined primarily through quotes from financial institutions. Accounting rules for transactions involving derivative instruments are complex and subject to a range of interpretation. The Financial Accounting Standards Board has established the Derivative Implementation Group Task Force, which, on an ongoing basis, considers issues arising from interpretation of these accounting rules. The potential exists that the task force may promulgate interpretations that differ from ours. In this event, our policy would be modified and our deferred hedge gain may be adjusted with a corresponding increase to revenues and expenses. The deferred hedge gains as of December 31, 2006 and 2005 were $nil million and $1.0 million, respectively.

We accounted for $125 million in proceeds received under the indirect participation interest agreement signed in on February 28, 2005 as a non-financial liability with an equity component. In determining the split between liabilities and equity, our management estimated the fair value of the liability and equity components and

Management Discussion and Analysis       INTEROIL CORPORATION      38

allocated the $125.0 million in proceeds from the agreement based on the pro rata share of the fair market value of each component. The calculation of the fair market value of each component was based on a wide range of variables, including the expected timing of expenditures, total overall expenditure, and applicable interest rates. If the liability and equity components were allocated in different amounts, our December 31, 2006 and 2005 accounts may have presented a different accretion expense and/or increased amounts of exploration expenditures. We are currently discussing the accounting treatment adopted with the SEC.

Management is currently liaising with the Securities Exchange Commission (‘SEC’ or ‘Commission’) in relation to comments initially raised by the SEC staff in July 2006 on the Form 40-F filed for the year ended December 31, 2005. The queries are primarily in relation to the accounting treatment of the Indirect Participation Interest agreement # 3 (refer to note 18) as a conveyance in accordance with SFAS 19 — ‘Financial Accounting and Reporting by Oil and Gas Producing Companies’. The SEC staff have also raised comments about other issues related to the accounting treatment of Indirect Participation Interest agreement # 3 such as the bifurcation of the derivative, the fair value methodologies applied and the application of accretion expense. Discussions regarding the 2005 Form 40-F are ongoing and may result in modifications to that document or to this Form 40-F. The Company will continue to work with the SEC to reach resolution of any outstanding issues and will provide updates if any material developments occur. Any changes based on the revised accounting treatment, if made, will not affect the cash position of the Company.

Legal and Other Contingent Matters

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

NEW ACCOUNTING STANDARDS

Comprehensive Income, Financial Instruments and Hedges

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

• Section 1530, Comprehensive Income;

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

• Section 3865, Hedges.

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

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

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

These new standards are effective for fiscal years beginning on or after October 1, 2006. We expect to adopt the pending accounting standards on January 1, 2007. The impact of this standard on our financial statements will be as follows:

Management Discussion and Analysis       INTEROIL CORPORATION      39

Section 1530, Comprehensive Income:

The new standard would require InterOil to present comprehensive income and its components in a financial statement with the same prominence as other financial statements. Effective January 1, 2007, all quarterly and annual financial statements issued by InterOil would display a new statement — ‘Statement of Comprehensive Income’ which would reconcile the net income/loss for the period to the Comprehensive Income for the period.

Statement of Comprehensive Income	Years ended December 31,
($ thousands)	2006			2005			2004
Net Loss		(43,386	)		(39,282	)		(52,940	)
Foreign currency translation reserve, net of tax		1,019			14			463
Deferred hedge gain, net of tax		—			—			—
Other Comprehensive Income		1,019			14			463
Comprehensive Income		(42,367	)		(39,268	)		(52,477	)

As per the transitional provisions of the standard, only the foreign currency translation reserve will be disclosed in the periods prior to 2007. In 2007, deferred hedge gain/losses will also be reported as a separate line item under other comprehensive income.

Section 3855, Financial Instruments — Recognition and Measurement:

InterOil will provide some additional disclosures relating to financial instruments as a result of this new standard and will also change its method for accounting for hedges described below.

Section 3865, Hedges:

This standard will require InterOil to reclassify the deferred hedge gains/(losses) line item from the liabilities section to shareholder’s equity as accumulated other comprehensive income. The new standard also requires that the portion of the hedge gain or loss that is effective be recognized in other comprehensive income while the ineffective portion of the gain or loss would be recognized immediately in net income. Currently, InterOil defers the full amount of the gain or loss. The standard will be prospectively applied from January 1, 2007 and in accordance with the transitional provisions the prior period comparatives will not be restated.

Management Discussion and Analysis       INTEROIL CORPORATION       40

NON-GAAP MEASURES RECONCILIATION

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(2),(3)												2005 (adjusted)(1),(2)
($ thousands) (unaudited)	Dec 31			Sep 30			Jun 30			Mar 31			Dec 31			Sep 30			Jun 30			Mar 31
Earnings before interest, taxes, depreciation and amortization		6,541			1,140			(10,257	)		(9,105	)		(5,566	)		3,486			(6,856	)		(5,858	)
Upstream		(1,051	)		(1,337	)		(2,262	)		(2,227	)		(2,362	)		(1,655	)		(2,615	)		(1,603	)
Midstream — Refining and Marketing		9,144			1,674			(8,188	)		(5,230	)		(6,333	)		6,070			(6,796	)		(3,405	)
Midstream — Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		1,143			1,954			3,559			(326	)		3,963			2,522			2,550			584
Corporate & Consolidated		(2,299	)		(853	)		(3,366	)		(1,322	)		(834	)		(3,451	)		5			(1,434	)
Subtract:
Interest expense		5,649			5,349			3,609			2,666			2,989			2,455			2,996			2,547
Upstream		2			1			1			1			(6	)		2			2			2
Midstream — Refining and Marketing		2,479			3,329			2,731			2,342			2,756			2,320			2,735			2,351
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		37			38			39			38			44			42			140			—
Corporate & Consolidated		3,131			1,981			838			285			195			91			119			194
Income taxes & non-controlling interest		1,049			244			1,031			(245	)		910			1,000			301			253
Upstream		—			—			—			—			—			—			—			—
Midstream — Refining and Marketing		42			(46	)		(137	)		(118	)		(129	)		19			(333	)		81
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		996			416			1,005			(144	)		1,062			965			570			159
Corporate & Consolidated		11			(126	)		163			17			(23	)		16			64			13
Depreciation & amortization		3,554			3,100			2,862			2,837			2,700			2,943			2,699			2,695
Upstream		233			202			173			198			96			213			2			3
Midstream — Refining and Marketing		2,805			2,700			2,626			2,598			2,662			2,663			2,641			2,632
Midstream — Liquefaction		—			—			—			—			—			—			—			—
Downstream		537			222			89			62			55			55			51			43
Corporate & Consolidated		(21	)		(24	)		(26	)		(21	)		(113	)		12			5			17
Net income (loss) per segment(1)		(3,711	)		(7,553	)		(17,759	)		(14,363	)		(12,165	)		(2,912	)		(12,852	)		(11,353	)
Upstream		(1,286	)		(1,540	)		(2,436	)		(2,426	)		(2,452	)		(1,870	)		(2,619	)		(1,608	)
Midstream — Refining and Marketing		3,818			(4,309	)		(13,408	)		(10,052	)		(11,622	)		1,068			(11,839	)		(8,469	)
Midstream — Liquefaction		(396	)		(298	)		—			—			—			—			—			—
Downstream		(427	)		1,278			2,426			(282	)		2,802			1,460			1,789			382
Corporate & Consolidated		(5,420	)		(2,684	)		(4,341	)		(1,603	)		(893	)		(3,570	)		(183	)		(1,658	)

Management Discussion and Analysis       INTEROIL CORPORATION       41

(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)	Our comparative quarterly results for all quarters during 2005 and 2006 have been represented to conform with the presentation adopted at December 31, 2006. Previously, interest revenue and non-controlling interest were allocated to the corporate segment. Amounts associated with these line items are now included in each operating segments result.
(3)	Our September 2006 quarterly results have been represented to separate out our Midstream-Liquefaction segment from the Midstream Refining and Marketing segment.

STATEMENT REGARDING DISCLOSURE CONTROLS

As of December 31, 2006, an evaluation was carried out, under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures as defined under Multilateral Instrument 52-109. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer identified three control deficiencies in the Company’s internal controls over financial reporting as of December 31 2006. These control deficiencies, their potential effects on the financial statements, and the Company’s plans for remediation have been described in Management’s S404 Certification.

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.

GLOSSARY OF TERMS

Barrel, Bbl (petroleum) Unit volume measurement used for petroleum and its products; 1 barrel = 42 US gallons, 35 Imperial gallons (approx.), or 159 liters (approx.); 7.3 barrels = 1 ton (approx.); 6.29 barrels = 1 cubic meter = 35.32 cubic feet.

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

Crack spread The simultaneous purchase or sale of crude against the sale or purchase of refined petroleum products. These spread differentials which represent refining margins are normally quoted in dollars per barrel by converting the product prices into dollars per barrel and subtracting the crude price.

EBITDA Earnings before interest, taxes, depreciation and amortization. EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used to analyze operating performance.

Farmout A contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for fulfilling contractually specified conditions. The farmout agreement often stipulates that the other party must drill a well to a certain depth, at a specified location, within a certain time frame; furthermore, the well typically must be completed as a commercial producer to earn an assignment. The assignor of the interest usually reserves a specified overriding royalty interest, with the option to convert the overriding royalty interest to a specified working interest upon payout of drilling and production expenses

Management Discussion and Analysis       INTEROIL CORPORATION       42

Feedstock Raw material used in a processing plant.

GAAP Generally accepted accounting principles.

IPF InterOil Power Fuel. InterOil’s marketing name for low sulphur waxy residue oil.

IPP Import Parity Price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated by adding the costs that would typically be incurred to import such product to the average posted price for such product in Singapore as reported by Platts. The costs that are added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.

LNG Liquefied natural gas. Natural gas converted to a liquid state by pressure and severe cooling, then returned to a gaseous state to be used as fuel. Acceptable first reference abbreviation. LNG is moved in tankers, not via pipelines. LNG, which is predominantly methane, artificially liquefied, is not to be confused with NGLs, natural gas liquids, heavier fractions which occur naturally as liquids. See also natural gas.

LPG Liquefied petroleum gas, typically ethane, propane butane and isobutane. Usually produced at refineries or natural gas processing plants, including plants that fractionate raw natural gas plant liquids. LPG can also occur naturally as a condensate.

LSWR Low sulfur waxy residual fuel oil.

Mark-to-market To revalue futures/option positions using current market prices to determine profit/loss. The profit/loss can then be paid, collected or simply tracked daily.

Naphtha That portion of the distillate obtained in the refinement of petroleum which is intermediate between the lighter gasoline and the heavier benzene, and has a specific gravity of about 0.7, used as a solvent for varnishes, illuminant, etc.

Natural gas A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.

Natural gas measurements The following are some of the standard abbreviations used in natural gas measurement.

Mcf: standard abbreviation for 1,000 cubic feet.
Bil cu ft: Billion cubic feet. Also abbreviated to bcf.
Tcf: trillion cubic feet.

PGK Currency of Papua New Guinea

PPL Petroleum Prospecting License. The tenement given by the Independent State of Papua New Guinea to explore for oil and gas.

PRL Petroleum Retention License. The tenement given by the Independent State of Papua New Guinea to allow the licensee holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.

Sweet/sour crude Definitions which describe the degree of a given crude’s sulfur content. Sour crudes are high in sulfur, sweet crudes are low.

Management Discussion and Analysis       INTEROIL CORPORATION       43