InterOil Corporation Management Discussion and Analysis   For the quarter ended March 31, 2013 May 13, 2013

TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS	2
OIL AND GAS DISCLOSURES	3
INTRODUCTION	4
BUSINESS STRATEGY	4
OPERATIONAL HIGHLIGHTS	5
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	7
QUARTER IN REVIEW	12
LIQUIDITY AND CAPITAL RESOURCES	20
RISK FACTORS	28
CRITICAL ACCOUNTING ESTIMATES	28
NEW ACCOUNTING STANDARDS	28
NON-GAAP MEASURES AND RECONCILIATION	29
PUBLIC SECURITIES FILINGS	31
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	31
GLOSSARY OF TERMS	31

This Management Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2012 and our annual information form (the “2012 Annual Information Form”) for the year ended December 31, 2012. The MD&A was prepared by management and provides a review of our performance in the quarter ended March 31, 2013, and of our financial condition and future prospects.

Our financial statements and the financial information contained in this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board applicable to the preparation of financial statements and are presented in United States dollars (“USD” or “$”) unless otherwise specified.

References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information presented in this MD&A is as at March 31, 2013 and for the quarter ended March 31, 2013 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this MD&A.

Management Discussion and Analysis   INTEROIL CORPORATION     1

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. We have based these forward-looking statements on our current expectations and projections about future events. 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 business strategies and plans; plans for our exploration (including drilling plans) and other business activities and results therefrom; characteristics of our properties; entering into definitive agreements with joint venture partners; the construction and development of the LNG Project and the Condensate Stripping Project in Papua New Guinea; the timing and cost of such construction and development; the commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; re-commissioning of our CRU; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; the timing, maturity and amount of future capital and other expenditures.

Many risks and uncertainties may affect the matters addressed in these forward-looking statements, including but not limited to:

· our ability to finance the construction and development of the LNG Project and the Condensate Stripping Project; 

· our ability to negotiate definitive agreements following conditional agreements or heads of agreement relating to the development of the LNG Project and the Condensate Stripping Project, or to otherwise negotiate and secure arrangements with other entities for such development and the associated financing thereof;

· the uncertainty associated with the availability, terms and deployment of capital; 

· our ability to construct and commission the LNG Project and the Condensate Stripping Project together with the construction of the common facilities and pipelines, on time and within budget;

· our ability to obtain and maintain necessary permits, concessions, licenses and approvals from relevant State authorities to develop our gas and condensate resources and to develop the LNG Project and the Condensate Stripping Project within reasonable time periods and upon reasonable terms;

· the inherent uncertainty of oil and gas exploration activities;

· the availability of crude feedstock at economic rates;

· the uncertainty associated with the regulated prices at which our products may be sold;  

· difficulties with the recruitment and retention of qualified personnel; 

· losses from our hedging activities;

· fluctuations in currency exchange rates;

· political, legal and economic risks in Papua New Guinea; 

· landowner claims and disruption; 

· compliance with and changes in Papua New Guinean laws and regulations, including environmental laws;

· the inability of our refinery to operate at full capacity;

· the impact of competition;

· the adverse effects from importation of competing products contrary to our legal rights;

· the margins for our products and adverse effects on the value of our refinery;

· inherent limitations in all control systems, and misstatements due to errors that may occur and not be detected;

· exposure to certain uninsured risks stemming from our operations;

· contractual defaults.

· interest rate risk;

· weather conditions and unforeseen operating hazards;

Management Discussion and Analysis   INTEROIL CORPORATION     2

· general economic conditions, including any further economic downturn, the availability of credit, the European sovereign debt credit crisis and the downgrading of United States government debt;

· the impact of our current debt on our ability to obtain further financing;

· risk of legal action against us; and

· law enforcement difficulties.

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial conditions and performance, business prospects, strategies, regulatory developments, the ability to attract joint venture partners, future hydrocarbon commodity prices, the ability to secure adequate capital funding, the ability to obtain equipment and qualified personnel in a timely manner to carry out development activities, the ability to market products successfully to current and new customers, the effects from increasing competition, the ability to obtain financing on acceptable terms, and the ability to develop reserves and production through development and exploration activities. Although we consider these assumptions to be reasonable based on information currently available to us, they may prove to be incorrect.

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 will eventuate. 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 2012 Annual Information Form.

Furthermore, the forward-looking information contained in this MD&A is made as of the date hereof and, except as required by applicable law, we will not update publicly or revise any of this forward-looking information. The forward-looking information contained in this report is expressly qualified by this cautionary statement.

OIL AND GAS DISCLOSURES

We are required to comply with Canadian Securities Administrators’ NI 51-101, which prescribes disclosure of oil and gas reserves and resources. GLJ Petroleum Consultants Ltd., an independent qualified reserve evaluator based in Calgary, Canada, has evaluated our resources data as at December 31, 2012 in accordance with NI 51-101, which evaluation is summarized in our 2012 Annual Information Form available at www.sedar.com. We do not have any production or reserves, including proved reserves, as defined under NI 51-101 or as per the guidelines set by the SEC, as at March 31, 2013.

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, possible and probable reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We include in this MD&A information that the SEC’s guidelines generally prohibit U.S registrants from including in filings with the SEC.

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet of natural gas to one barrel of crude equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation. A barrel of oil equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Management Discussion and Analysis   INTEROIL CORPORATION     3

INTRODUCTION

We are developing a fully integrated energy company operating in Papua New Guinea and the surrounding Southwest Pacific region. Our operations are organized into four major segments:

Segments	Operations
Upstream	Exploration and Production – Explores, appraises and develops crude oil and natural gas structures in Papua New Guinea.  Developing infrastructure for the Elk and Antelope fields which includes wells, gas gathering pipelines, condensate stripping facilities and pipelines for the proposed delivery of natural gas to the Midstream Liquefaction segment and condensate to the Midstream - Refining segment. This segment also conducts appraisal drilling of the Triceratops field and manages our construction business which services our development projects underway in Papua New Guinea.
Midstream	Refining – Produces refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea for the domestic market and for export. Liquefaction – Developing liquefaction and associated facilities in Papua New Guinea for the export of LNG.
Downstream	Wholesale and Retail Distribution – Markets and distributes refined products domestically in Papua New Guinea on a wholesale and retail basis.
Corporate	Corporate – Provides support to our other business segments by engaging in business development and improvement activities and providing general and administrative services and management, undertakes financing and treasury activities, and is responsible for government and investor relations.  General and administrative and integrated costs are recovered from business segments on an equitable basis.  This segment also manages our shipping business which currently operates two vessels transporting petroleum products for our Downstream segment and external customers, both within PNG and for export in the South Pacific region.  Our Corporate segment results also include consolidation adjustments.

BUSINESS STRATEGY

Our strategy is to develop a vertically integrated energy company in Papua New Guinea and the surrounding region, focusing on niche market opportunities which provide financial rewards for our shareholders, while being environmentally responsible, providing a quality working environment and contributing positively to the communities in which we operate. A significant element of that strategy is to develop gas liquefaction and condensate stripping facilities in Papua New Guinea and to establish gas and gas condensate reserves.

We plan to achieve this strategy by:

· Developing our position as a prudent and responsible business operator;

· Enhancing our existing refining and distribution businesses;

· Monetizing our discovered resources;

· Maximizing the value of our exploration assets; and

· Positioning for long term success.

Further details of our business strategy can be found under the heading “Business Strategy” in our 2012 Annual Information Form available at www.sedar.com.

Management Discussion and Analysis   INTEROIL CORPORATION     4

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

A summary of the key operational matters and events for the quarter, for each of the segments is as follows:

Upstream

· Pacific Rubiales Farm-In Agreement:

– On April 18, 2012, we signed a binding HOA with PRE for it to earn a 10.0% net (12.9% gross) participating interest in the PPL 237 onshore PNG, including the Triceratops structure located within that license. On March 13, 2013, the Farm-In Agreement with PRE was completed and we received a completion settlement from PRE of $56.0 million on March 24, 2013. This payment does not include PRE’s 35% carry of historical costs relating to the drilling Triceratops 2, which will be paid to us separately.

– Pac LNG is participating on a 25% beneficial equity basis in the portion of the farm-in transaction with PRE relating to the Triceratops structure (2.5% net and 3.2% gross participating interest), by reducing Pac LNG’s indirect participating interest in the Triceratops structure. Certain other indirect participating interest holders have also elected to participate in the farm-in transaction and as such have been credited with their proportional share of the completion settlement.

– On January 24, 2013, the DPE approved and registered the transfer of interest in PPL 237 to PRE and the related PRE JVOA. During the quarter, an application was submitted for a Petroleum Retention License over the Triceratops discovery.

· Antelope field appraisal program

On January 24, 2013, we completed the logging program on the Antelope-3 well. Conventional wireline logs (porosity, resistivity and sonic) were acquired in addition to formation imaging, vertical well bore seismic and rotary sidewall coring was conducted. The independent formation evaluation indicates an average porosity in the pay interval of 10.2%, which compares favorably with the results from the Antelope-1 and Antelope-2 wells with average porosities of 8.8% and 13.1% respectively. We believe these results indicate that the reservoir quality at the Antelope-3 well location has similar quality to the Antelope-1 and Antelope-2 wells. Production logging was completed and the well suspended for future completion as a production well. Our Rig#2 remains on location at the Antelope-3 well site, and is undergoing inspection and partial refurbishment in preparation for mobilization to the next location.

· Elk field appraisal program:

– During the quarter, the DPE approved our PRE JVOA relating to operations in PRL 15.

– As at March 31, 2013, our Rig#3 remains in position on Elk-3. Certification of the rig was granted by the DPE on January 3, 2013, and the rig is currently on stand-by status with a minimum crew.

· Seismic and exploration program:

– Proposed well locations have currently been selected for the Tuna and Wahoo prospects. Potential exploration well locations for future lease obligation wells were selected following completion of seismic acquisition, processing and mapping. However, with the success of the Triceratops gas discovery and the better than expected results of the Antelope-3 well, we have had discussions with the DPE on our forward focus and priorities. We believed that a clear mutual objective is to focus on progressing the LNG Project. To progress development of our core assets, we applied for variations to modify the well commitments for PPL 236 and PPL 238. On March 28, 2013, the DPE approved the deferral of the well commitments for PPL 236 and PPL 238.

– During the quarter, discussions were held with Oil Search Limited, which holds exploration acreage adjacent to PPL 237. These discussions relate to access within PPL 237 for a joint seismic program over both licenses with a tie to the Triceratops structure. It was agreed that we will conduct the joint seismic program which will be fully funded by Oil Search. The resulting data will be shared and separately analyzed.

Management Discussion and Analysis   INTEROIL CORPORATION     5

Midstream – Refining

· Total refinery throughput for the quarter ended March 31, 2013 was 27,525 barrels per operating day, compared with 23,759 barrels per operating day during the quarter ended March 31, 2012.

· Capacity utilization of the refinery for the quarter ended March 31, 2013, based on 36,500 barrels per day operating capacity, was 74% compared with 55% for quarter ended March 31, 2012. During the quarters ended March 31, 2013 and 2012, our refinery was shut down for 1 day and 15 days, respectively, for general maintenance activities.

· The CRU, which allows the refinery to produce reformate for gasoline has been shutdown since August 3, 2012 for maintenance and catalyst replacement. During the quarter ended March 31, 2013, we did not produce gasoline and we supplied the domestic market through imports. In April 2013, the CRU was restarted and is currently being operated to meet domestic demand for gasoline.

Midstream – Liquefaction

· We have received bids from potential partners in connection with the development of the LNG Project and an interest in the Elk and Antelope fields in Papua New Guinea. Confidential negotiations with more than one bidder are ongoing, and the process is moving forward as planned.

Downstream

· The PNG economy has slowed slightly in the first quarter of 2013 as the construction phase of the Exxon Mobil led PNG LNG project nears completion, and the construction contractors complete their projects. Total sales volumes for the first quarter ended March 31, 2013 were 183.7 million litres (March 2012 – 188.9 million litres), a decrease of 5.2 million litres, or 2.7% over the same period in 2012.

· Our retail business accounted for approximately 15% of our total downstream sales in the first quarter of 2013 (March 2012 – 14%). We continue to invest in new forecourt technology and in new retail fuel distribution systems. During the quarter, we re-opened a completely refurbished retail site after it was purchased from a dealer.

· On December 14, 2012, the ICCC advised that margins for wholesale will increase in line with the ICCC mandated formula for a five year period. A consumer price index increase of 2.0% is reflected in these revised margins. These increases apply to unleaded gasoline, diesel and kerosene and are effective for the fiscal year ending December 31, 2013.

Management Discussion and Analysis   INTEROIL CORPORATION     6

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarters Ended March 31, 2013 and 2012

Consolidated – Operating results	Quarter ended March 31,
($ thousands, except per share data)	2013			2012
				(revised) (4)
Sales and operating revenues		349,324			335,319
Interest revenue		15			174
Other non-allocated revenue		992			2,657
Total revenue		350,331			338,150
Cost of sales and operating expenses		(314,759	)		(301,336	)
Office and administration and other expenses		(11,284	)		(11,604	)
Derivative losses		(471	)		(418	)
Exploration costs		(450	)		(7,363	)
Gain on conveyance of oil and gas properties		500			-
Loss on Flex LNG Investment		(340	)		-
Foreign exchange (losses)/gains		(5,476	)		10,118
Share of net loss of joint venture partnership accounted for using the equity method (4)		(96	)		(10	)
EBITDA (1)		17,955			27,537
Depreciation and amortization		(5,698	)		(6,091	)
Interest expense		(4,333	)		(3,436	)
Profit before income taxes		7,924			18,010
Income tax expense		(3,921	)		(8,574	)
Net profit		4,003			9,436
Net profit per share (basic)		0.08			0.20
Net profit per share (diluted)		0.08			0.19
Total assets		1,368,581			1,061,790
Total liabilities		589,229			288,004
Total long-term liabilities		267,979			136,921
Gross margin (2)		34,565			33,983
Cash flows generated by/(used in) operating activities (3)		40,583			(28,491	)

Notes:

(1) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(2) Gross margin is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(3) Refer to “Liquidity and Capital Resources – Summary of Cash Flows” for detailed cash flow analysis.

(4) Revised to effect the transition to IFRS 11- Joint arrangements, refer to Note 2(c)(ii) of our Condensed Consolidated Interim Financial Statements for further details. Note that the share of net loss of joint venture partnership accounted for using the equity method above consists of the Company’s share of depreciation expense incurred by the PNG LNG joint venture, which were included in the EBITDA calculation.

Analysis of Financial Condition Comparing Quarters Ended March 31, 2013 and 2012

During the quarter ended March 31, 2013, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 19% (13% as at March 31, 2012), well below our targeted maximum gearing level of 50%. Gearing targets are based on a number of factors including operating cash flows, future cash needs for development, capital market conditions, economic conditions, and are assessed regularly.

Management Discussion and Analysis   INTEROIL CORPORATION     7

Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 1.5 times as at March 31, 2013 (2.4 times as at March 31, 2012). The quick ratio (or acid test ratio (being [current assets less inventories] divided by current liabilities)), which is a more conservative measure of our ability to meet short term obligations, was 0.8 times as at March 31, 2013 (1.3 times as at March 31, 2012). These ratios were below our internal targets of above 1.5 times for the current ratio and 1.0 times for the quick ratio. The closing of the transactions whereby a party will participate in the development of the LNG Project and acquired an interest in the Elk and Antelope fields, are expected to bring these ratios well within our internal targets.

As at March 31, 2013, our total assets amounted to $1,368.6 million, compared with $1,061.8 million as at March 31, 2012. This increase of $306.8 million, or 29%, from March 31, 2012 was primarily due to expenditure of $138.5 million on our oil and gas properties associated with the appraisal and development of the Elk and Antelope fields including the drilling of Antelope-3 well, preparation and drilling of the Triceratops-2 well, and Herd Base and Hou Creek infrastructure construction; a $50.6 million increase in inventory balances due to the timing of shipments; an increase in our trade and other receivables balance of $29.1 million on higher joint venture billings to upstream partners; a $29.7 million increase in non-current receivables was attributable to the credits given to Pac LNG and other indirect participating interest holders on account of their participation in the Farm-in transaction with PRE; a $27.1 million increase in deferred tax benefits mainly related to the increased refinery’s carried forward tax losses; a $26.2 million net increases in our cash, cash equivalents, and restricted cash primarily due to receipt of PRE’s $76.0 million initial staged cash payment, partially offset by expenditure on the development of oil and gas properties during the quarter; a $5.1 million increase in plant and equipment (after depreciation) from Downstream infrastructure upgrades across locations, office building works and tank works; and a $2.5 million increase in prepayments to upstream suppliers. These increases however were partially offset by a $3.5 million decrease in the value of our investment in FLEX LNG.

As at March 31, 2013, our total liabilities amounted to $589.2 million, compared with $288.0 million at March 31, 2012. The increase of $301.2 million, or 105%, from March 31, 2012 was primarily due to an increase of $139.5 million in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases; receipts of PRE’s $96.0 million initial staged cash payment held as a liability due to their option to exit the Farm-In Agreement; a net increase of $58.4 million in secured loans payable on drawdown of the ANZ, BSP and BNP syndicated secured loan facility of $95.9 million (net of transaction costs), partially reduced by the OPIC loan repayment of $35.5 million during the last quarter of 2012; a $5.2 million increase in income tax payable on profit before tax earned by our Downstream and Shipping business during the quarter; and a $3.5 million increase in 2.75% convertible note liability due to the convertible liability accretion expense incurred. These increases however have been partially offset by a $5.1 million reduction in IPI liability mainly attributed to the waiver or forfeiture of a total of 2.6% IPI interest conversion rights into common shares of the Company.

Analysis of Consolidated Financial Results Comparing Quarters Ended March 31, 2013 and 2012

Quarterly Comparative

Our net profit for the quarter ended March 31, 2013 was $4.0 million compared with a net profit of $9.4 million for the same quarter of 2012, a decrease of $5.4 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the quarter of $18.5 million (2012 - $28.6 million), while the investments in development segments of Upstream and Midstream - Liquefaction resulted in a net loss of $14.5 million (2012 - $19.2 million).

The decrease in net profit for the quarter ended March 31, 2013 compared to the same period in 2012 of $5.4 million was mainly the result of a $15.6 million increase in foreign exchange losses, due to the weakening of the PGK against USD (foreign exchange rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (foreign exchange rate increased from 0.4665 to 0.4820) and the one-off transfer of $7.8 million in foreign exchange gains (previously included in other comprehensive income) to the profit and loss upon repayment of certain intercompany loans during the prior quarter ended March 31, 2012; and a $1.7 million decrease in other income, primarily attributable to lower recovery of expenses relating to Upstream construction and drilling related activities. These decreases in profit have been partially offset by a $6.9 million reduction in exploration costs incurred primarily for seismic activity on PPL 236 in the prior period; and a $4.7 million decrease in income tax expenses, resulting mainly from lower Downstream current quarter profit earned and the impact of unfavorable foreign exchange movements impacting temporary differences on translation of the nonmonetary assets of the Midstream - Refinery operation using period end rates.

Management Discussion and Analysis   INTEROIL CORPORATION     8

Total revenues increased by $12.1 million from $338.2 million in the quarter ended March 31, 2012 to $350.3 million in the quarter ended March 31, 2013, primarily due to higher sales volumes during the quarter. The total volume of all products sold by us was 2.4 million barrels for the quarter ended March 31, 2013, compared with 2.2 million barrels in the same quarter of 2012.

The Upstream segment realized a net loss of $13.8 million in the quarter ended March 31, 2013 (2012 – $17.2 million). The reduction in the loss for the quarter ended March 31, 2013 by $3.4 million compared to the same period of 2012 was mainly due to a $6.9 million decrease in exploration costs incurred for seismic activity on PPL 236. This decrease has been partially offset by a $2.5 million increase on intercompany interest charges due to an increase in inter-company loan balances provided to fund exploration and development activities, and a $1.7 million decrease in other non-allocated revenues due to lower recovery of expenses related to construction and drilling related activities.

The Midstream - Refining segment generated a net profit of $5.9 million in the quarter ended March 31, 2013 (2012 - $11.3 million). The decrease in profit resulted from a $7.1 million increase in foreign exchange losses, mainly due to the weakening of Kina against the USD (FX rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (increased from 0.4665 to 0.4820). This however has been partially offset by a $1.8 million increase in gross margin due to higher margins earned from export sales, a decrease in standard cost per barrel throughput due to increased number of operating days, and increased crack spreads for IPP priced domestic sales.

The Midstream Liquefaction segment had a net loss of $0.7 million during the quarter ended March 31, 2013 (2012 –$2.0 million). The reduction in net loss from 2012 was mainly due to reduced activity until the sell down process is completed.

The Downstream segment generated a net profit of $6.0 million in the quarter ended March 31, 2013 (2012 – $13.2 million). The decreased profit was mainly due to a $8.9 million decrease in foreign exchange gains, attributable to the one-off transfer of $7.8 million in foreign exchange gains (previously included in other comprehensive income) to the profit and loss upon repayment of certain intercompany loans during the prior quarter ended March 31, 2012, and the weakening of Kina against the USD (FX rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (FX rate increased from 0.4665 to 0.4820). In addition, we experienced a $3.0 million decrease in gross profit margin due to the impact of a decreasing price environment, which lead to lower margins on inventories sold. These decreases in profit have been partially offset by a $3.3 million decrease in income tax expense, which is in line with the lower profit before income tax earned during the quarter.

The Corporate segment generated a net profit of $7.3 million (2012 – $6.3 million). The improvement over the same period in 2012 was primarily due to a $0.6 million increase in interest charges to other business segments relating to increased intercompany loan balances and a $0.7 million decrease in income tax expense due to higher deductible temporary differences recognized for the provisions and non-monetary assets held by the Corporate segment.

Variance Analysis

A complete discussion of each of our business segments’ results can be found under the section “Quarter in Review”. The following analysis outlines the key variances, the net of which are the primary explanations for the changes in the consolidated results between the quarters ended March 31, 2013 and 2012.

Management Discussion and Analysis   INTEROIL CORPORATION     9

	Quarterly Variance ($ millions)
	($5.4)	Net profit variance for the comparative period primarily due to:
Ø	($1.7)	Other non-allocated revenue relates to the utilization of construction and drilling related activities performed internally, including civil works and related infrastructure development associated with the LNG Project.  Recoveries in relation to our percentage interest of the development projects are offset against the relevant expenses, while the recoveries of the portion relating to external party interests in the development projects are classified under other non-allocated revenue.  The reduction in this item was due to lower activities and related recoveries relating to the construction and drilling related activities during the period.
Ø	$6.9	Lower exploration costs incurred for seismic activity for PPL 236 during the quarter.
Ø	($15.6)	Increase in foreign exchange losses for the quarter was mainly due to the weakening of Kina against the USD (FX rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (increased from 0.4665 to 0.4820), and the one-off transfer foreign exchange gains of $7.8 million previously included in other comprehensive income to profit and loss upon partial repayment of intercompany loans during the prior quarter ended March 31, 2012.
Ø	$4.7	Decrease in income tax expense for the quarter primarily resulting from lower Downstream current quarter profit earned and the impact of unfavorable foreign exchange movements impacting temporary differences on translation of the non-monetary assets of the refinery operation using period end rates.

Analysis of Consolidated Cash Flows Comparing Quarters Ended March 31, 2013 and 2012

As at March 31, 2013, we had cash, cash equivalents, and restricted cash of $107.4 million (March 31, 2012 – $81.1 million), of which $38.9 million (March 31, 2012 - $41.3 million) was restricted. Of the total restricted cash of $38.9 million, $27.3 million (March 31, 2012 - $35.0 million) was restricted pursuant to the BNP working capital facility utilization requirements, $11.3 million (March 31, 2012 – $5.9 million) was restricted as a cash deposit on the secured loans (ANZ, BSP and BNP syndicated secured loan facility as at March 31, 2013, and OPIC facility as at March 31, 2012), and the balance was made up of a cash deposit on office premises together with term deposits on our PPLs.

Cash flows from operations

Our cash inflows from operations for the quarter ended March 31, 2013 were $40.6 million compared with an outflow of $28.5 million for the quarter ended March 31, 2012, a net increase in cash inflows of $69.1 million. This increase in cash inflows was mainly due to a $71.7 million net increase in working capital inflows associated with trade and other receivables, inventories and accounts payables and a $2.6 million decrease in net cash inflow used in operations prior to changes in operating working capital, related to the net profit generated by the operations less any non-cash expenses for the quarter ended March 31, 2013.

Cash flows from investing activities

Cash outflows for investing activities for the quarter ended March 31, 2013 were $35.7 million compared with $32.9 million for the quarter ended March 31, 2012. These outflows mainly relate to the net cash expenditures on exploration, appraisal and development activities (net of IPI cash calls) of $36.2 million, expenditures on plant and equipment of $3.8 million and a $5.8 million decrease in working capital requirements of development segments relating to the timing of payments. These outflows were partially offset by a $10.1 million decrease in restricted cash held as security under the BNP working capital facility.

Management Discussion and Analysis   INTEROIL CORPORATION     10

Cash flows from financing activities

Cash inflows from financing activities for the quarter ended March 31, 2013 amounted to $13.9 million, compared with inflows of $31.7 million for the quarter ended March 31, 2012. These cash inflows are primarily due to a total receipt of $76.0 million initial staged cash payments from PRE for interests in PPL 237. This inflow was partially offset by a $60.0 million net repayment of working capital facilities and the repayment of principal to the Westpac secured loan in the amount of $2.1 million.

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

The following is a table containing the consolidated results for the eight quarters ended March 31, 2013 by business segment, and on a consolidated basis.

Quarters ended ($ thousands except per share	2013			2012												2011
data)	Mar-31			Dec-31  (2)			Sep-30  (2)			Jun-30  (2)			Mar-31  (2)			Dec-31  (2)			Sep-30  (2)			Jun-30  (2)
Upstream		1,862			4,136			2,216			1,727			2,284			1,891			2,645			4,638
Midstream – Refining		305,172			301,925			274,671			236,006			302,310			237,640			231,455			262,111
Midstream – Liquefaction (2)		-			-			-			-			-			-			-			-
Downstream		208,046			220,512			201,749			223,620			218,974			209,678			186,304			191,431
Corporate		34,923			37,552			26,880			24,742			24,757			21,831			25,078			26,548
Consolidation entries		(199,672	)		(207,686	)		(178,652	)		(186,991	)		(210,174	)		(181,428	)		(163,584	)		(180,945	)
Total revenues		350,331			356,439			326,864			299,104			338,151			289,612			281,898			303,783
Upstream		(1,311	)		(873	)		956			(5,730	)		(6,374	)		665			(6,169	)		593
Midstream – Refining		12,701			12,370			13,417			(42,647	)		18,933			2,604			3,461			27,967
Midstream – Liquefaction (2)		(123	)		192			11			672			(1,410	)		(4,129	)		(3,608	)		(4,041	)
Downstream		10,062			12,258			9,275			11,102			21,414			6,808			3,570			5,777
Corporate		10,044			14,133			9,841			9,975			9,188			10,134			1,548			13,940
Consolidation entries		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,216	)		(11,280	)		(10,263	)		(5,269	)
EBITDA (1)		17,955			25,881			18,997			(36,499	)		27,535			4,802			(11,461	)		38,967
Upstream		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)		(15,080	)		(6,703	)
Midstream – Refining		5,855			13,401			5,358			(32,969	)		11,320			15,684			(1,201	)		17,314
Midstream – Liquefaction		(681	)		(394	)		(573	)		93			(1,969	)		(4,574	)		(3,980	)		(4,309	)
Downstream		6,005			7,716			5,626			6,045			13,195			3,621			1,146			2,306
Corporate		7,342			10,519			7,849			8,445			6,270			7,616			(473	)		11,275
Consolidation entries		(744	)		384			(1,988	)		2,205			(2,136	)		252			(190	)		3,657
Net profit/(loss)		4,003			18,545			5,336			(31,713	)		9,436			13,197			(19,778	)		23,540
Net profit/(loss) per share (dollars)
Per Share – Basic		0.08			0.38			0.11			(0.66	)		0.20			0.27			(0.41	)		0.49
Per Share – Diluted		0.08			0.38			0.11			(0.66	)		0.19			0.27			(0.41	)		0.48

(1) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(2) Revised to effect the transition to IFRS 11- Joint arrangements, refer to Note 2(c)(ii) of our Condensed Consolidated Interim Financial Statements for further details. Note that the share of net loss of joint venture partnership accounted for using the equity method above consists of the Company’s share of depreciation expense incurred by the PNG LNG joint venture, which were included in the EBITDA calculation.

Management Discussion and Analysis   INTEROIL CORPORATION     11

QUARTER IN REVIEW

The following section provides a review of the quarter ended March 31, 2013 for each of our business segments.

UPSTREAM – QUARTER IN REVIEW

Upstream – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
Other non-allocated revenue		592			2,284
Inter-segment revenue - Recharges		1,270			-
Total revenue		1,862			2,284
Office and administration and other expenses		(3,218	)		(673	)
Exploration costs		(450	)		(7,363	)
Gain on conveyance of oil and gas properties		500			-
Foreign exchange loss		(5	)		(622	)
EBITDA (1)		(1,311	)		(6,374	)
Depreciation and amortization		(522	)		(1,462	)
Interest expense		(11,941	)		(9,408	)
Loss before income taxes		(13,774	)		(17,244	)
Income tax expense		-			-
Net loss		(13,774	)		(17,244	)

(1) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Analysis of Upstream Financial Results Comparing the Quarters Ended March 31, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters ended March 31, 2013 and 2012.

	Quarterly Variance ($ millions)
	$3.5	Net loss variance for the comparative period primarily due to:
Ø	($1.7)	Other non-allocated revenue relates to the utilization of construction and drilling related activities performed internally, including civil works and related infrastructure development associated with the LNG Project.  Recoveries in relation to our percentage interest of the development projects are offset against the relevant expenses, while the recoveries of the portion relating to external party interests in the development projects are classified under other non-allocated revenue.  The reduction in this item was due to lower activities and related recoveries relating to the construction and drilling related activities during the period.
Ø	$1.3	Inter-segment revenue - recharges of $1.3 million relates to charges made to other segments for use of construction and logistics services.
Ø	($2.5)	The $2.5 million increase in office and administration and other expenses for the quarter was mainly due to higher expenses and share compensation costs related to executive management that were not capitalized.

Management Discussion and Analysis   INTEROIL CORPORATION     12

Ø	$6.9	Reduction in exploration costs incurred for seismic activity for PPL 236 during the current quarter. The seismic costs were in relation to the Kwalaha and Tuna seismic acquisition programs.
Ø	$0.5	The increase in gain on conveyance of oil and gas properties for the quarter was attributable to the gain recognized on the waiver of a combined 1.0536% interest by certain investors who converted their rights of IPI percentage into 140,480 common shares of InterOil. Following these waivers, there were no longer any conversion rights outstanding as at March 31, 2013.
Ø	$0.6	Decrease in foreign exchange losses during the current quarter was mainly due the weakening of Kina against the USD (FX rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (FX rate increased from 0.4665 to 0.4820), which resulted in a lower revaluation loss on the net Kina denominated liabilities.
Ø	$0.9	Decrease in depreciation expense for the current quarter was mainly due to the reallocation of our share of depreciation expense to offset the construction revenue, which was in effect from the second quarter of 2012.
Ø	($2.5)	Higher interest expense due to an increase in inter-company loan balances provided to fund exploration and development activities.

MIDSTREAM - REFINING – QUARTER IN REVIEW

Midstream Refining – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
External sales		141,697			116,693
Inter-segment revenue - Sales		163,472			178,834
Inter-segment revenue - Recharges		-			6,622
Interest and other revenue		3			161
Total segment revenue		305,172			302,310
Cost of sales and operating expenses		(285,301	)		(277,475	)
Office and administration and other expenses		(1,597	)		(7,431	)
Derivative losses		(471	)		(429	)
Foreign exchange (losses)/gains		(5,102	)		1,958
EBITDA (1)		12,701			18,933
Depreciation and amortization		(3,122	)		(2,894	)
Interest expense		(2,454	)		(2,771	)
Profit before income taxes		7,125			13,268
Income tax expense		(1,270	)		(1,948	)
Net profit		5,855			11,320
Gross Margin (2)		19,868			18,052

(1) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(2) Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue – sales” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Management Discussion and Analysis   INTEROIL CORPORATION     13

Midstream - Refining Operating Review

	Quarter ended March 31,
Key Refining Metrics	2013			2012
Throughput (barrels per day)(1)		27,525			23,759
Capacity utilization (based on 36,500 barrels per day operating capacity)		74	%		55	%
Cost of production per barrel	$	2.95		$	3.85
Working capital financing cost per barrel of production	$	0.37		$	0.80
Distillates as percentage of production		51.6	%		62.0	%

(1) Throughput per day has been calculated excluding shut down days. During quarters ended March 2013 and 2012, the refinery was shut down for 1 day and 15 days, respectively.

Analysis of Midstream - Refining Financial Results Comparing the Quarters Ended March 31, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters ended March 31, 2013 and 2012.

Quarterly Variance ($ millions)
($5.5)		Net profit variance for the comparative period primarily due to:
Ø	$1.8	Increase in gross margin for the quarter was mainly due to the following contributing factors:
		+	Gains due to increased gross refinery margin on Naphtha rich crudes vs middle distillate rich crudes and associated decreases in premiums and freight, which was partially offset by lower yield structure (i.e. reduced distillate yield)
		+	Decrease in standard costs per BBL throughput due to increased number of operating days and BBLs processed and a decreasing cost base
		+	Increased margins and more frequent (monthly) export Naphtha loadings   resulting in less exposure to price fluctuations
		+	Increased crack spreads for IPP priced domestic sales
		-	Decreases in crude and product prices contributing to reduced inventory gains for all products.
Ø	($6.6)	Decrease in inter-segment recharges for the quarter was mainly due to the incorporation of our wholly-owned subsidiary, InterOil Corporate PNG Limited which began operating in October 2012 for the purpose of employing all corporate staff in PNG and to capture their associated costs.  In addition, this entity has taken over the operation of the Napa Napa camp and all costs associated with the operation of the camp are now captured in this entity.  All costs incurred by this entity are recharged to relevant InterOil entities on an equitable basis.  The corporate costs incurred from January 2012 to March 2012 were captured within the Midstream - Refining segment and then recharged to other segments.
Ø	$5.8	Decrease in office and administrative expense mainly due to the costs associated with corporate employees in PNG and the operation of the Napa Napa camp now being captured in the Corporate segment since October 1, 2012.  These costs were captured within the Midstream - Refining segment in the quarter ended March 31, 2012.

Management Discussion and Analysis   INTEROIL CORPORATION     14

Ø ($7.1) Increase in foreign exchange losses for the quarter was mainly due to the weakening of Kina against the USD (FX rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (FX rate increased from 0.4665 to 0.4820).

MIDSTREAM - LIQUEFACTION – QUARTER IN REVIEW

Midstream Liquefaction – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
					(revised) (2)
Interest and other revenue		-			-
Total segment revenue		-			-
Office and administration and other expenses		(27	)		(1,400	)
Share of net loss of joint venture partnership accounted for using the equity method		(96	)		(10	)
EBITDA (1)		(123	)		(1,410	)
Interest expense		(558	)		(559	)
Loss before income taxes		(681	)		(1,969	)
Income tax expense		-			-
Net loss		(681	)		(1,969	)

(1) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(2) Revised to effect the transition to IFRS 11- Joint arrangements, refer to Note 2(c)(ii) of our Condensed Consolidated Interim Financial Statements for further details.

Analysis of Midstream - Liquefaction Financial Results Comparing the Quarters Ended December 31, 2013 and 2012

This segment’s results include our interest in the joint venture development of the proposed midstream facilities of the LNG Project. The development of these facilities is being progressed in joint venture with Pac LNG through PNG LNG. We currently have an economic interest of 84.582% in PNG LNG.

In accordance with IFRS 11 “Joint Arrangement” (which superseded IAS 31 “Interests in Joint Ventures”), we have reclassified our involvement with PNG LNG Inc from a jointly controlled entity to a joint venture. Our interests in PNG LNG Inc that were previously accounted for using the proportionate consolidation method are now accounted for using the equity method of accounting. This change of accounting method was performed retrospectively, resulting in a revision of financial results for the same period in 2012. Refer to Note 2(c)(ii) of our Condensed Consolidated Interim Financial Statements for further details.

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters ended March 31, 2013 and 2012.

Quarterly Variance ($ millions)
$1.3		Net loss variance for the comparative period primarily due to:
Ø	$1.4	Decrease in office, administration and other expenses was due to reduced activity until the sell down process is completed.

Management Discussion and Analysis   INTEROIL CORPORATION     15

DOWNSTREAM – QUARTER IN REVIEW

Downstream – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
External sales		207,559			218,581
Inter-segment revenue - Sales		85			18
Interest and other revenue		402			375
Total segment revenue		208,046			218,974
Cost of sales and operating expenses		(193,390	)		(201,329	)
Office and administration and other expenses		(4,381	)		(4,892	)
Foreign exchange (losses)/gains		(213	)		8,661
EBITDA (1)		10,062			21,414
Depreciation and amortization		(1,180	)		(1,240	)
Interest expense		(422	)		(1,233	)
Profit before income taxes		8,460			18,941
Income tax expense		(2,455	)		(5,746	)
Net profit		6,005			13,195
Gross Margin (2)		14,254			17,270

(1) EBITDA is a non-GAAP measure and is reconciled to under the heading “Non-GAAP Measures and Reconciliation”.

(2) Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue - sales” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Downstream Operating Review

	Quarter ended March 31,
Key Downstream Metrics	2013		2012
Sales volumes (millions of liters)		183.7		188.9
Average sales price per liter	$	1.12	$	1.16

Analysis of Downstream Financial Results Comparing the Quarters Ended March 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters ended March 31, 2013 and 2012.

Quarterly Variance ($ millions)
($7.2)		Net profit variance for the comparative period primarily due to:
Ø	($3.0)	Gross margins decreased compared to the prior period mainly due to slightly reduced volumes, combined with the impact of a decreasing price environment, which lead to lower margins on inventories sold

Management Discussion and Analysis   INTEROIL CORPORATION     16

Ø	($8.9)	Movement in foreign exchange loss was primarily the result of the one-off transfer of foreign exchange gains of $7.8 million (previously included in other comprehensive income) to profit and loss upon  repayment of certain intercompany loans during the quarter ended March 31, 2012. In addition, the weakening of Kina against the USD (FX rate decreased from 0.4755 to 0.4675) compared to the first quarter of 2012 (FX rate increased from 0.4665 to 0.4820) further increased the foreign exchange losses incurred during the current quarter.
Ø	$0.8	Decrease in interest expense for the quarter was mainly due to the repayment of intercompany loans and lower utilization of working capital facilities.
Ø	$3.3	Decrease in income tax expense was mainly due to lower taxable profits.

CORPORATE – QUARTER IN REVIEW

Corporate – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
External sales		68			46
Inter-segment revenue - Sales		6,894			4,694
Inter-segment revenue - Recharges		15,309			7,963
Interest revenue		12,652			12,054
Total revenue		34,923			24,757
Cost of sales and operating expenses		(5,657	)		(3,891	)
Office and administration and other expenses		(18,726	)		(11,812	)
Derivative gains		-			11
Foreign exchange (losses)/gains		(156	)		123
Loss on Flex LNG investment		(340	)		-
EBITDA (1)		10,044			9,188
Depreciation and amortization		(906	)		(528	)
Interest expense		(1,600	)		(1,510	)
Profit before income taxes		7,538			7,150
Income tax expense		(196	)		(880	)
Net profit		7,342			6,270
Gross Margin (2)		1,305			849

(1) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

(2) Gross margin is a non-GAAP measure and is “external sales” and “inter-segment revenue - sales” less “cost of sales and operating expenses” and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Management Discussion and Analysis   INTEROIL CORPORATION     17

Analysis of Corporate Financial Results Comparing the Quarters Ended March 31, 2013 and 2012

The following analysis outlines the key movements, the net of which primarily explains the variance in the results between the quarters ended March 31, 2013 and 2012.

Quarterly Variance ($ millions)
$1.1		Net profit variance for the comparative period primarily due to:
Ø	$0.5	Increase in external sales and inter-segment sales less cost of sales was mainly due to higher profit margin earned by our shipping business during the quarter.
Ø	$7.3	Increase in inter-segment recharges for the quarter was mainly due to the incorporation of InterOil Corporate PNG Limited, which began operating in October 2012 for the purpose of employing all corporate staff in PNG and to capture their associated costs.  In addition, this entity has taken over the operation of the Napa Napa camp and all costs associated with the operation of the camp are now captured in this entity.  All costs incurred by this entity are recharged to relevant InterOil entities on an equitable basis.
Ø	$0.6	Higher interest revenue for the quarter was due to an increase in inter-company loan balances.
Ø	($6.9)	Increase in office and administrative expense mainly due to the costs associated with corporate employees in PNG and the operation of the Napa Napa camp now being captured in the Corporate segment since October 1, 2012.  These costs were captured within the Midstream - Refining segment in the quarter ended March 31, 2012.
Ø	($0.3)	Increase in loss on available-for-sale investment was due to the impairment losses recognized during the current quarter for the reduction in fair value of the FLEX LNG investment as of March 31, 2013.
Ø	($0.4)	Increase in depreciation expense was mainly due to the depreciation expense incurred for the camps and other equipments transferred from the Midstream -Refinery segment to InterOil Corporate PNG Limited.
Ø	$0.7	Decrease in income tax expense was mainly due to deductible temporary difference arising from the provisions and non-monetary assets held by the Corporate segment.

Management Discussion and Analysis   INTEROIL CORPORATION     18

CONSOLIDATION ADJUSTMENTS – QUARTER IN REVIEW

Consolidation adjustments – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
Inter-segment revenue - Sales		(170,451	)		(183,547	)
Inter-segment revenue - Recharges		(16,579	)		(14,584	)
Interest revenue (1)		(12,642	)		(12,044	)
Total revenue		(199,672	)		(210,175	)
Cost of sales and operating expenses (2)		169,589			181,359
Office and administration and other expenses (3)		16,665			14,602
EBITDA (4)		(13,418	)		(14,214	)
Depreciation and amortization (5)		32			33
Interest expense (1)		12,642			12,045
Loss before income taxes		(744	)		(2,136	)
Income tax expense		-			-
Net loss		(744	)		(2,136	)
Gross Margin (6)		(862	)		(2,188	)

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

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

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

(4) EBITDA is a non-GAAP measure and is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

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

(6)  Gross margin is a non-GAAP measure and is “inter-segment revenue elimination” less “cost of sales and operating expenses” and represents elimination upon consolidation of our refinery sales to other segments. This measure is reconciled to IFRS under the heading “Non-GAAP Measures and Reconciliation”.

Analysis of Consolidation Adjustments Comparing the Quarters Ended March 31, 2013 and 2012

The following table outlines the key movements, the net of which primarily explains the variance in the results between the quarters ended March 31, 2013 and 2012.

Quarterly Variance ($ millions)
$1.4		Net loss variance for the comparative period primarily due to:
Ø	$1.4	Variance in net income was due to changes in intra-group profit eliminated on consolidation between Midstream - Refining and Downstream segments in the quarter ended March 31, 2012 relating to the Midstream Refining segment’s profit component of inventory on hand in the Downstream segment at period ends.

Management Discussion and Analysis   INTEROIL CORPORATION     19

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

Summarized below are the debt facilities available to us and the balances outstanding as at March 31, 2013.

Organization	Facility		Balance outstanding March 31, 2013			Effective interest rate			Maturity date
ANZ, BSP and BNP syndicated secured loan facility	$	100,000,000	$	100,000,000			6.79	%	November 2017
BNP working capital facility	$	240,000,000	$	33,118,821	(1)		2.61	%	See detail below
Westpac PGK working capital facility	$	42,075,000	$	1,178,475			9.50	%	November 2014
BSP PGK working capital facility	$	23,375,000		-			9.45	%	August 2013
Westpac secured loan	$	12,857,000	$	10,714,000			4.62	%	September 2015
2.75% convertible notes	$	70,000,000	$	70,000,000			7.91	%(3)	November 2015
Mitsui unsecured loan (2)	$	11,912,297	$	11,912,297			6.20	%	See detail below

⁽¹⁾ Excludes letters of credit totaling $136.1 million, which reduces the available borrowings under the facility to $70.8 million at March 31, 2013.

⁽²⁾ Facility is to fund our share of the Condensate Stripping Project costs as they are incurred pursuant to the CSP JVOA with Mitsui.

⁽³⁾ Effective rate after bifurcating the equity and debt components of the $70 million principal amount of 2.75% convertible senior notes due 2015.

While cash flows from operations are expected to be sufficient to cover our operating commitments, should there be a major long term deterioration in refining or wholesale and retail margins, our operations may not generate sufficient cash flows to cover all of the interest and principal payments under our debt facilities noted above. Also, our exploration and development activities, planned development of the LNG Project and Condensate Stripping Project require funding beyond our operational cash flows and the cash balances we currently hold. As a result, we will 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 debt facilities, or, if available, that the terms of any such capital raising or refinancing will be acceptable to us.

ANZ, BSP and BNP Syndicated Secured Loan (Midstream- Refinery)

On October 16, 2012, we entered into a five year amortizing $100.0 million syndicated secured term loan facility with BNP, BSP, and ANZ. The loan is secured over the fixed assets of the refinery. The balance outstanding under the loan facility as at March 31, 2013 was $100.0 million. The interest rate on the loan is equal to LIBOR plus 6.5%. During the quarter ended March 31, 2013, the weighted average interest rate under the facility was 6.79%.

The principal of the syndicated secured loan facility is repayable in ten half yearly installments over the period of five years. The first four half yearly installments are for an amount of $8.0 million each, the next two installments are for an amount of $10.0 million each, and the final four installments are for an amount of $12.0 million each. The interest payments are to be made either in quarterly or half yearly payments, at our election, which has to be made in advance of the interest period. As at March 31, 2013, we have two installment payments of $8.0 million each due for payment on this secured loan on May 9, 2013 and November 9, 2013. A cash restricted balance of $11.3 million was held on deposit as at March 31, 2013 to secure our principal installment due on May 9, 2013 and interest payments on the syndicated secured loan facility. Subsequent to quarter end, on May 9, 2013, we made the principal installment and interest payment.

Management Discussion and Analysis   INTEROIL CORPORATION     20

BNP Paribas Working Capital Facility (Midstream - Refinery)

This working capital facility is used to finance purchases of crude feedstock for our refinery. In accordance with the agreement with BNP, the total facility is split into two components, Facility 1 and Facility 2. In October 2012, the working capital facility agreement with a maximum availability of $240.0 million was amended so that the facility was made evergreen and the annual renewal requirement removed. As at March 31, 2013, Facility 1 has a sublimit of $180.0 million and finances the purchases of crude and hydrocarbon products through the issuance of documentary letters of credit and standby letters of credit, short term advances, advances on merchandise, freight loans, and has a sublimit of Euro 18.0 million or the USD equivalent for hedging transactions. Facility 2 allows borrowings of up to $60.0 million and can be used for partly cash-secured short term advances and for discounting of any monetary receivables acceptable to BNP in order to reduce Facility 1 balances. The facility is secured by sales contracts, purchase contracts, certain cash accounts associated with the refinery, all crude and refined products of the refinery and trade receivables.

As of March 31, 2013, $70.8 million remained available for use under the facility. The facility bears interest at LIBOR plus 3.5% on short term advances. The weighted average interest rate under the working capital facility was 2.61% for the quarter ended March 31, 2013 (compared with 3.01% for the same period of 2012), after including the reduction in interest due to the deposit amounts (restricted cash) maintained as security.

Bank South Pacific and Westpac Working Capital Facility (Downstream)

On October 24, 2008, we secured a combined revolving working capital facility for our Downstream wholesale and retail petroleum products distribution business from BSP and Westpac. The facility limit as at March 31, 2013 was PGK 140.0 million (approximately $65.5 million).

The Westpac facility limit is PGK 90.0 million (approximately $42.1 million). This facility was for an initial term of three years and was renewed in November 2011 for a further three years to November 2014. The Westpac facility was increased in February 2012 by PGK 10.0 million (approximately $4.7 million). The BSP facility limit is PGK 50.0 million (approximately $23.4 million), and was renewed in November 2012 for another year ending in August 2013. As at March 31, 2013, PGK 2.5 million (approximately $1.2 million) of this combined facility has been utilized, and PGK 137.5 million (approximately $64.3 million) of this facility remains available for use.

The weighted average interest rate under the Westpac facility was 9.50% for the quarter ended March 31, 2013, and the weighted average interest rate under the BSP facility was 9.45% for the quarter ended March 31, 2013.

Westpac Secured Loan (Downstream)

In year 2012, we obtained a secured loan of $15.0 million from Westpac which is repayable in equal installments over 3.5 years with an interest rate of LIBOR plus 4.4% per annum. The loan agreement stipulates semi-annual principal payments of $2.1 million, with the final repayment to be made in August 2015. The loan is secured by a fixed and floating charge over the assets of Downstream operations. The balance outstanding under the loan as at March 31, 2013 was $10.7 million.

2.75% Convertible Notes (Corporate)

On November 10, 2010, we completed the issuance of $70.0 million unsecured 2.75% convertible notes with a maturity of five years. The convertible notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the BNP working capital facility, the ANZ, BSP and BNP syndicated secured loan facility, the Westpac secured loan facility, the BSP and Westpac working capital facilities, the Mitsui preliminary financing agreement, trade payables and lease obligations.

Management Discussion and Analysis   INTEROIL CORPORATION     21

We pay interest on the notes semi-annually on May 15 and November 15. The notes are convertible into cash or common shares, based on an initial conversion rate of 10.4575 common shares per $1,000 principal amount, which represents an initial conversion price of approximately $95.625 per common share. The initial conversion price is subject to standard anti-dilution provisions designed to maintain the value of the conversion option in the event we take certain actions with respect to our common shares, such as stock splits, reverse stock splits, stock dividends and cash dividends, that affect all of the holders of our common shares equally and that could have a dilutive effect on the value of the conversion rights of the holders of the notes or that confer a benefit upon our current shareholders not otherwise available to the convertible notes. Upon conversion, holders will receive cash, common shares or a combination thereof, at our option. The convertible notes are redeemable at our option if our share price has been at least 125% ($119.53 per share) of the conversion price for at least 15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change of control, holders may require us to repurchase their convertible notes for cash at a purchase price equal to the principal amount of the notes to be repurchased, plus accrued and unpaid interest.

Mitsui Unsecured Loan (Upstream)

On April 15, 2010, we entered into preliminary joint venture and financing agreements with Mitsui relating to the Condensate Stripping Project. On August 4, 2010, we entered into the CSP Joint Venture with Mitsui for the development of the condensate stripping facilities. Mitsui and InterOil hold equal interest in the joint venture. Mitsui is to be responsible for arranging or providing financing for the capital costs of the condensate stripping facility.

The portion of funding that relates to Mitsui’s share of the Condensate Stripping Project as at March 31, 2013, amounting to approximately $13.5 million, is held in current liabilities as the agreement requires refund of all funds advanced by Mitsui under the preliminary financing agreement if a positive FID was not reached by February 28, 2013. We are currently finalizing with Mitsui to extend the positive FID date to June 30, 2013. The portion of funding that relates to our share of the Condensate Stripping Project (amounting to $11.9 million), funded by Mitsui, is classed as an unsecured loan and interest accrues daily based on LIBOR plus a margin of 6%. During the quarter ended March 31, 2013, the weighted average interest rate was 6.20%.

Other Sources of Capital

Currently our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by a combination of contributions made by capital raising activities, operational cash flows, IPI holders, PNGDV, joint venture partners and asset sales.

Cash calls are made on IPI holders, PNGDV and Pac LNG (for its 2.5% direct interest in the Elk and Antelope fields acquired during 2009) for their share of amounts spent on certain appraisal wells and extended well programs where they participate in such wells and programs pursuant to the relevant agreements in place with them. Cash calls will also be made on PRE for exploration activities in PPL 237 and appraisal activities in the Triceratops field.

The preliminary financing agreement entered into with Mitsui provides for funding by Mitsui of all the costs relating to the Condensate Stripping Project. 50% of the funding is for Mitsui’s share of the project and the other 50% is funding by Mitsui of our share of the project. The total contributions received from Mitsui as at March 31, 2013 are $25.4 million. As noted above, this preliminary financing agreement required positive FID to be reached by February 28, 2013, however, we are currently finalizing with Mitsui to extend the positive FID date to June 30, 2013. In the event that a positive FID is not reached or made within the time specified, we will be required to refund all of Mitsui’s contributions (i.e. for our share and Mitsui’s) within a specified period.

On April 18, 2012, we signed a binding HOA with PRE for PRE to be able to earn a 10.0% net (12.9% gross) participating interest in the PPL 237 onshore Papua New Guinea, including the Triceratops structure located within that license. The transaction contemplates staged initial cash payments totaling $116.0 million, an additional carry of 25% of the costs of an agreed exploration work program, and a final resource payment. On July 27, 2012, we executed a Farm-In Agreement with PRE relating to the Triceratops structure and the participating interest in the PPL 237 license materially in line with the HOA signed on April 18, 2012. As at March 31, 2013, PRE has paid the full amount of the staged cash payments ($116.0 million), being $96.0 million paid in accordance with the Farm-In Agreement, and the Initial Cash Payment of $20.0 million. The $96.0 million of the staged cash payment is refundable if PRE decides to exit the program, with the payment to be refunded within six years.

Management Discussion and Analysis   INTEROIL CORPORATION     22

Summary of Cash Flows

	Quarter ended March 31,
($ thousands)	2013			2012
				(revised)
Net cash inflows/(outflows) from:
Operations		40,583			(28,491	)
Investing		(35,702	)		(32,910	)
Financing		13,864			31,711
Net cash movement		18,745			(29,690	)
Opening cash		49,721			68,575
Exchange gains on cash and cash equivalents		(4	)		992
Closing cash		68,462			39,877

Analysis of Cash Flows Generated From/(Used In) Operating Activities Comparing the Quarters Ended March 31, 2013 and 2012

The following table outlines the key variances in the cash inflows/(outflows) from operating activities between the quarters ended March 31, 2013 and 2012:

Quarterly variance ($ millions)
$69.1		Variance for the comparative period primarily due to:
Ø	($2.6)	Increase in cash employed by operations prior to changes in operating working capital for the quarter, mainly due to the decrease in net profit from operations adjusted for lower future income tax benefits and higher share compensation expenses.
Ø	$71.7	The movements in cash generated by operations relating to changes in operating working capital were due primarily to a $127.6 million increase in the movement of accounts payable and accrued liabilities for the year, a $27.6 million increase in the movement of trade and other receivables, a $27.1 million increase in the movement of inventories due to timing of crude and export shipments, and a $1.3 million increase in the movement of other current assets and prepaid expenses.

Analysis of Cash Flows Used In Investing Activities Comparing the Quarters Ended March 31, 2013 and 2012

The following table outlines the key variances in the cash outflows from investing activities between the quarters ended March 31, 2013 and 2012:

Quarterly variance ($ millions)
($2.8)		Variance for the comparative period primarily due to:
Ø	$7.1	Lower cash outflows on exploration and development program expenditures mainly due to a reduction in drilling activities, resulting from the ongoing sell down process.
Ø	$4.3	Lower expenditure on plant and equipment in the Downstream and Midstream - Refinery segments in current quarter as compared to same period in 2012.

Management Discussion and Analysis   INTEROIL CORPORATION     23

Ø	($11.8)	Maturity of short term PGK Treasury bills during the quarter ended March 31, 2012.
Ø	$12.1	Lower cash outflows due to increase in our cash restricted balance held under the BNP working capital facility due to lower utilization of the working capital facility as at March 31, 2013.
Ø	($14.3)	Movements in non-operating working capital relating to accounts payable and accruals in our Upstream and Midstream Liquefaction operations.

Analysis of Cash Flows Generated From Financing Activities Comparing the Quarters Ended March 31, 2013 and 2012

The following table outlines the key variances in the cash inflows from financing activities between quarters ended March 31, 2013 and 2012:

Quarterly variance ($ millions)
($17.8)		Variance for the comparative periods primarily due to:
Ø	($17.1)	Movement in the Westpac secured loan was attributable to a $15.0 million drawdown made in the quarter ended March 31, 2012 and a $2.1 million semi-annual principal loan repayment made to Westpac during the current quarter ended March 31, 2013.
Ø	$76.0	Receipt of a $76.0 million staged cash payment from PRE for the sell down of a net 10.0% (12.9% gross) participating interest in PPL 237.
Ø	($74.8)	Movement in utilization of the BNP, Westpac and BSP working capital facilities is due to changes in working capital requirements.
Ø	($1.9)	Decrease was due to the receipts of cash from the exercise of stock options in the first quarter of 2012 with no stock options being exercised in the first quarter of 2013.

Capital Expenditures

Upstream Capital Expenditures

Capital expenditures for our Upstream segment in Papua New Guinea for the quarter ended March 31, 2013 were $34.3 million, compared with $43.6 million during the same period of 2012.

The following table outlines the key expenditures in the quarter ended March 31, 2013:

Quarterly ($ millions)
$34.3		Expenditures in the quarter ended March 31, 2013 primarily due to:
Ø	$3.2	Project management teams’ costs and sub-contractors costs incurred for the LNG Project, including costs incurred for pipeline works, which mainly consists of work done by Cronus on geotechnical survey, centerline survey and field to coast pipeline FEED, and costs for works in respect of the Condensate Stripping Project, which mainly includes the costs incurred for submittal and evaluation of the revised tender.
Ø	$4.6	Costs for works at Hou Creek, which includes the construction of a road and a complex in the north of the Elk and Antelope fields.  The complex includes facilities such as wharf, camp, warehouse and related earth works.  The road is to connect the Hou Creek complex to the Antelope-2 well and to the south road which commences at Herd Base.

Management Discussion and Analysis   INTEROIL CORPORATION     24

Ø	$7.4	Costs incurred for Antelope-3 drilling and testing works.
Ø	$3.7	Costs incurred for Elk-3 well site preparation, spud works, drilling and standby works.
Ø	$2.0	Costs incurred for Herd Base to Antelope field road construction.
Ø	$11.1	General Management costs recharged to the projects, and under recoveries in relation to the drilling services, construction equipment, labor, logistics and warehousing services provided due to reduced activities during the period.
Ø	$2.3	Other expenditures, including equipment purchases and drilling inventory.

Midstream – Refining Capital Expenditures

Capital expenditures totaled $1.8 million in our Midstream - Refining segment for the quarter ended March 31, 2013, mainly associated with office building works and tank works.

Downstream Capital Expenditures

Capital expenditures for the Downstream segment totaled $2.3 million for the quarter ended March 31, 2013. These expenditures mainly related to a number of upgrade projects across various terminals and depots.

Capital Requirements

The oil and gas exploration and development, refining and liquefaction industries are capital intensive and our business plans necessitate raising of additional capital. The availability and cost of such capital is highly dependent on market conditions at the time we raise such capital. No assurance can be given that we will be successful in obtaining new capital on terms that are acceptable to us, particularly given current market volatility.

The majority of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities” is used in our appraisal and development programs for the Elk, Antelope, and Triceratops fields in PNG. Our net cash from operating activities is not sufficient to fund those appraisal and development programs, the LNG Project or the Condensate Stripping Project.

Upstream

We are required under our $125.0 million IPI Agreement of 2005 to drill eight exploration wells. We have drilled four wells to date. As at March 31, 2013, we are committed under the terms of our exploration licenses or PPL’s to spend a further $48.0 million through 2014. As at March 31, 2013, management estimates that satisfying these license commitments with the expenditure of $48.0 million would also satisfy our commitments to the IPI investors in relation to drilling the final four wells and satisfy the commitments in relation to the IPI Agreement. The actual aggregate cost of drilling the final four exploration wells in relation to the IPI Agreement may ultimately end up costing us more than what is required to satisfy our license commitments.

In addition, the terms of the grant of PRL 15 require us to spend $73.0 million on the development of the Elk and Antelope fields by the end of 2014. All work program commitments with the exception of two wells, are complete. We have spent $352.4 million on PRL 15 which includes seismic, Herd Base/Hou Creek wharf and camps, roads, FEED for wells, gas gathering, condensate stripping, and pipelines. $67.0 million of the expenditures to date relates to the $73.0 million commitment. Expenditure on the drilling of the Elk-3 well will, in addition to a second well prior to license renewal date in 2014, meet our well commitment requirements under the license.

We do not have sufficient funds to complete planned exploration and development activities and we will need to raise additional funds in order for us to complete the programs and meet our exploration commitments. Therefore, we must extend or secure sufficient funding through renewed borrowings, equity raising and/or asset sales to enable the availability of sufficient cash to meet these obligations over time and complete these long term plans. No assurances can be given that we will be successful in obtaining new capital on terms acceptable to us, or at all, particularly given recent market volatility.

Management Discussion and Analysis   INTEROIL CORPORATION     25

We will also be required to obtain substantial amounts of financing for the development of the Elk, Antelope and Triceratops fields, condensate stripping and associated facilities, pipelines and LNG export terminal facilities, and it will take a number of years to complete these projects. In the event that positive FID is reached in respect of these projects, we seek to be in a position to access the capital markets and/or sell an interest in our upstream properties in order to raise adequate capital. In September 2011, we retained financial advisors to help solicit and evaluate proposals from potential strategic partners to acquire interests in our Elk and Antelope fields, LNG Project and exploration licenses. The solicitation process is now under way and we believe if successful, it will provide a further source of funds for exploration and development activities. No assurances can be given that we will be able to attract strategic partners on terms acceptable to us.

The availability and cost of various sources of financing is highly dependent on market conditions and our condition at the time we raise such capital and we can provide no assurances that we will be able to obtain such financing or conduct such sales on terms that are acceptable.

Midstream - Refining

We believe that we will have sufficient funds from our operating cash flows to pay our estimated capital expenditures associated with our Midstream - Refining segment in 2013. We also believe cash flows from operations will be sufficient to cover the costs of operating our refinery and the financing charges incurred under our crude import facility. Should there be long term deterioration in refining margins, 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.

Midstream - Liquefaction

Completion of the LNG Project will require substantial amounts of financing and construction will take a number of years to complete. As a joint venture partner in development, if the project is completed, we would be required to fund our share of certain common facilities of the development. No assurances can be given that we will be able to source sufficient gas, successfully construct such a facility, or as to the timing of such construction. The availability and cost of capital is highly dependent on market conditions and our circumstances at the time we raise such capital.

In September 2011, we retained Morgan Stanley & Company LLC, Macquarie Capital (USA) Inc. and UBS AG to help solicit and evaluate proposals from potential strategic partners to, amongst other things, obtain an interest in, operate and help finance the development of the LNG Project. We have received conforming and non-conforming bids for the LNG partnering and sell down of an interest in the Elk and Antelope fields that we believe would be accretive to shareholders. Final bids were received during the quarter ended March 31, 2013 and are now in the process of being assessed. The end result of the partnering process is expected to fully satisfy all the terms of the 2009 LNG Project Agreement. No assurances can be given that we will be able to attract a strategic partner on terms acceptable to us, and we cannot advise at this time as to how such an agreement will affect our current LNG Project plans or whether such a partner will be acceptable to the PNG government.

Downstream

We believe on the basis of current market conditions and the status of our business that our cash flows from operations will be sufficient to meet our estimated capital expenditures for our wholesale and retail distribution business segment for 2013. Should there be a major long-term deterioration in wholesale or retail margins, our Downstream operations may not generate sufficient cash flows to cover all of the interest and principal payments under our loan agreements. As a result, we may be required to raise additional capital and/or refinance these facilities in the future.

Management Discussion and Analysis   INTEROIL CORPORATION     26

Contractual Obligations and Commitments

The following table contains information on payments required to meet contracted exploration and debt obligations due for each of the next five years and thereafter. It should be read in conjunction with our Condensed Consolidated Interim Financial Statements and the notes thereto:

	Payments Due by Period
Contractual obligations ($ thousands)	Total		Less than 1 year		1 – 2 years		2 – 3 years		3 – 4 years		4 – 5 years		More than 5 years
Petroleum prospecting and retention licenses (a)		68,652		58,552		10,100		-		-		-		-
Secured and unsecured loans		155,766		37,779		27,362		29,005		30,810		30,810		-
2.75% Convertible notes obligations		75,133		1,925		1,925		71,283		-		-		-
Indirect participation interest - PNGDV		1,384		1,384		-		-		-		-		-
Total		300,935		99,640		39,387		100,288		30,810		30,810		-

(a) The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed as a condition on renewal of these licenses. We are committed to spend a further $48.0 million as a condition of renewal of our petroleum prospecting licenses through 2014 under our exploration licenses. As at March 31, 2013, management estimates that satisfying this license commitment with the expenditure of $48.0 million would also satisfy our commitments to the IPI investors in relation to drilling the final four exploration wells and satisfy the commitments in relation to the IPI agreement. In addition, the terms of grant of PRL 15, requires us to spend a further $20.7 million on the development of the Elk and Antelope fields by the end of 2014.

Off Balance Sheet Arrangements

Neither during the quarter ended, nor as at March 31, 2013, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

During the quarter ended March 31, 2013, we did not have any transactions with any related parties.

Share Capital

Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 series A preferred shares are authorized (none of which are outstanding). As of March 31, 2013, we had 48,652,640 common shares (51,012,444 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 31, 2013 included employee stock options and restricted stock in respect of 1,287,299 common shares and 732,025 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

Derivative Instruments

Our revenues are derived from the sale of refined products. Prices for refined products and crude feedstocks can be volatile and sometimes experience large fluctuations over 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 purchase crude feedstock two months in advance, whereas the supply/export of finished products will take place after the crude feedstock is discharged and processed. Due to the fluctuation in prices during this period, 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. 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 is reduced. Conversely, when we have locked-in the refinery margin and if the difference between our sales price of the refined products and our acquisition price of crude feedstocks expands or increases, then the benefits would be limited to the locked-in margin.

Management Discussion and Analysis   INTEROIL CORPORATION     27

The derivative instruments which we generally use are over-the-counter swaps. The swap transactions are concluded between counterparties in the derivatives swaps market, unlike futures which are transacted on the Intercontinental Exchange and NYMEX Exchanges. We believe these hedge counterparties to be credit worthy. 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 hedging and risk management activities. The derivatives swap instrument covers commodities or products such as jet and kerosene, diesel, naphtha, and also bench-mark crudes such as Tapis and Dubai. By using these tools, we actively engage in hedging activities to lock in margins. Occasionally, there is insufficient liquidity in the crude swaps market and we then use other derivative instruments such as Brent futures on the Intercontinental Exchange to hedge our crude costs.

At March 31, 2013, we had a net receivable of $0.4 million (March 31, 2012 – receivable of $0.7 million) relating to open contracts to sell gasoil crack swaps; buy/sell dated Brent swaps; and sell Naphtha crack swaps for which hedge accounting has not been applied, and the swaps that have been priced out as of March 31, 2013 and will be settled in future.

RISK FACTORS

Our business operations and financial position are subject to a range of risks. A summary of the key risks that may impact upon the matters addressed in this document have been included under section “Forward Looking Statements” above. Detailed risk factors can be found under the heading “Risk Factors” in our 2012 Annual Information Form available at www.sedar.com.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires our management to make estimates and assumptions that affect the amounts reported in the Condensed Consolidated Interim Financial Statements and accompanying notes. Actual results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the Condensed Consolidated Interim Financial Statements as estimating it is impracticable. During the quarter ended March 31, 2013, there were no changes in the critical accounting estimates disclosed in our annual management discussion and analysis for the year ended December 31, 2012. For a discussion of those accounting policies, please refer to Note 2 of the notes to our audited annual consolidated financial statements for the year ended December 31, 2012, available at www.sedar.com, which summarizes our significant accounting policies.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at March 31, 2013

The following new standards have been issued but are not yet effective for the financial year beginning January 1, 2013 and have not been early adopted:

- IFRS 9 ‘Financial Instruments’ (effective from January 1, 2015): This addresses the classification and measurement of financial assets. The standard is not applicable until January 1, 2015 but is available for early adoption. The Company is yet to assess IFRS 9’s full impact, but it does not expect any material changes due to this standard. The Company has not yet decided whether to early adopt IFRS 9.

Management Discussion and Analysis   INTEROIL CORPORATION     28

NON-GAAP MEASURES AND RECONCILIATION

Non-GAAP measures, including gross margin and EBITDA, included in this MD&A are not defined nor have a standardized meaning prescribed by IFRS or our previous GAAP; accordingly, they may not be comparable to similar measures provided by other issuers. Gross margin is a non-GAAP measure and is “sales and operating revenues” less “cost of sales and operating expenses”. The following table reconciles sales and operating revenues, a GAAP measure, to gross margin:

Consolidated – Operating results	Quarter ended March 31,
($ thousands)	2013			2012
Midstream – Refining		305,169			295,527
Downstream		207,644			218,599
Corporate		6,962			4,740
Consolidation Entries		(170,451	)		(183,547	)
Sales and operating revenues		349,324			335,319
Midstream – Refining		(285,301	)		(277,475	)
Downstream		(193,390	)		(201,329	)
Corporate (1)		(5,657	)		(3,891	)
Consolidation Entries		169,589			181,359
Cost of sales and operating expenses		(314,759	)		(301,336	)
Midstream – Refining		19,868			18,052
Downstream		14,254			17,270
Corporate (1)		1,305			849
Consolidation Entries		(862	)		(2,188	)
Gross Margin		34,565			33,983

(1) Corporate expenses are classified below the gross margin line and mainly relates to ‘Office and admin and other expenses’ and ‘Interest expense’.

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 us to analyze operating performance. EBITDA does not have a standardized meaning prescribed by GAAP (i.e. IFRS) 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 IFRS. Further, EBITDA is not a measure of cash flow under IFRS and should not be considered as such.

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

Management Discussion and Analysis   INTEROIL CORPORATION     29

Quarters ended	2013			2012												2011
($ thousands)	Mar-31			Dec-31  (1)			Sep-30  (1)			Jun-30  (1)			Mar-31  (1)			Dec-31  (1)			Sep-30  (1)			Jun-30  (1)
Upstream		(1,311	)		(873	)		956			(5,730	)		(6,374	)		665			(6,169	)		593
Midstream – Refining		12,701			12,370			13,417			(42,647	)		18,933			2,604			3,461			27,967
Midstream – Liquefaction (1)		(123	)		192			11			672			(1,410	)		(4,129	)		(3,608	)		(4,041	)
Downstream		10,062			12,258			9,275			11,102			21,414			6,808			3,570			5,777
Corporate		10,044			14,133			9,841			9,975			9,188			10,134			1,548			13,940
Consolidation Entries		(13,418	)		(12,199	)		(14,503	)		(9,871	)		(14,214	)		(11,280	)		(10,263	)		(5,270	)
Earnings before interest, taxes, depreciation and amortization		17,955			25,881			18,997			(36,499	)		27,537			4,802			(11,461	)		38,966
Subtract:
Upstream		(11,941	)		(11,734	)		(11,438	)		(10,517	)		(9,408	)		(8,712	)		(7,806	)		(7,142	)
Midstream – Refining		(2,454	)		(11,390	)		(1,654	)		(2,011	)		(2,771	)		(3,285	)		(2,494	)		(2,211	)
Midstream – Liquefaction		(558	)		(586	)		(584	)		(579	)		(559	)		(445	)		(372	)		(268	)
Downstream		(422	)		(337	)		(394	)		(909	)		(1,233	)		(1,170	)		(1,233	)		(1,116	)
Corporate		(1,600	)		(1,601	)		(1,540	)		(1,535	)		(1,510	)		(1,498	)		(1,477	)		(1,641	)
Consolidation Entries		12,642			12,552			12,482			12,044			12,045			11,500			10,041			8,894
Interest expense		(4,333	)		(13,096	)		(3,128	)		(3,507	)		(3,436	)		(3,610	)		(3,341	)		(3,484	)
Upstream		-			-			-			-			-			-			-			-
Midstream – Refining		(1,270	)		16,574			(3,484	)		14,580			(1,948	)		19,243			678			(5,677	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(2,455	)		(3,070	)		(1,791	)		(2,907	)		(5,746	)		(595	)		(297	)		(1,449	)
Corporate		(196	)		(1,330	)		177			535			(880	)		(493	)		(195	)		(629	)
Consolidation Entries		-			-			-			-			-			-			-			-
Income taxes		(3,921	)		12,174			(5,098	)		12,208			(8,574	)		18,155			186			(7,755	)
Upstream		(522	)		(474	)		(454	)		715			(1,462	)		(1,355	)		(1,105	)		(154	)
Midstream – Refining		(3,122	)		(4,153	)		(2,921	)		(2,891	)		(2,894	)		(2,878	)		(2,846	)		(2,764	)
Midstream – Liquefaction (1)		-			-			-			-			-			-			-			-
Downstream		(1,180	)		(1,135	)		(1,464	)		(1,241	)		(1,240	)		(1,422	)		(894	)		(906	)
Corporate		(906	)		(683	)		(629	)		(530	)		(528	)		(527	)		(349	)		(395	)
Consolidation Entries		32			31			33			32			33			32			32			32
Depreciation and amortisation		(5,698	)		(6,414	)		(5,435	)		(3,915	)		(6,091	)		(6,150	)		(5,162	)		(4,187	)
Upstream		(13,774	)		(13,081	)		(10,936	)		(15,532	)		(17,244	)		(9,402	)		(15,080	)		(6,703	)
Midstream – Refining		5,855			13,401			5,358			(32,969	)		11,320			15,684			(1,201	)		17,314
Midstream – Liquefaction		(681	)		(394	)		(573	)		93			(1,969	)		(4,574	)		(3,980	)		(4,309	)
Downstream		6,005			7,716			5,626			6,045			13,195			3,621			1,146			2,306
Corporate		7,342			10,519			7,849			8,445			6,270			7,616			(473	)		11,275
Consolidation Entries		(744	)		384			(1,988	)		2,205			(2,136	)		252			(190	)		3,657
Net profit/(loss) per segment		4,003			18,545			5,336			(31,713	)		9,436			13,197			(19,778	)		23,540

(1) Revised to effect the transition to IFRS 11- Joint arrangements, refer to Note 2(c)(ii) of our Condensed Consolidated Interim Financial Statements for further details. Note that the share of net loss of joint venture partnership accounted for using the equity method above consists of the Company’s share of interest on depreciation expense incurred by the joint venture, which were included in the EBITDA calculation.

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PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2012 Annual Information Form, in documents filed with the Canadian Securities Administrators at www.sedar.com, and in documents, including our Form 40-F, filed with the U.S. Securities and Exchange Commission at www.sec.gov. Additional information is also available on our website www.interoil.com.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to us is made known to our Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by us in our annual filings, interim filings or other reports filed or submitted by us under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our disclosure controls and procedures at our financial year-end and have concluded that our disclosure controls and procedures are effective at December 31, 2012 for the foregoing purposes.

It should be noted that while our Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will necessarily prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Internal Controls over Financial Reporting

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our internal controls over financial reporting at our financial year-end and concluded that our internal control over financial reporting is effective, at December 31, 2012, for the foregoing purpose.

No material change in our internal controls over financial reporting were identified during the three months ended March 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

It should be noted that a control system, including our disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

GLOSSARY OF TERMS

“2012 Annual Information Form” means our Annual Information Form for the year ended December 31, 2012.

“AUD” means Australian dollars.

“ANZ” means Australia and New Zealand Banking Group (PNG) Limited

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“Barrel, Bbl” (petroleum) Unit volume measurement used for petroleum and its products.

“BNP” means BNP Paribas Capital (Singapore) Limited.

“Board” means the board of directors of InterOil.

“BSP” means Bank of South Pacific Limited.

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

“Condensed Consolidated Interim Financial Statements” means the unaudited condensed consolidated interim financial statements for the quarter and three months ended March 31, 2013.

“Convertible notes” means the 2.75% convertible senior notes of InterOil due November 15, 2015.

“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.

“CRU” means catalytic reformer unit.

“Crude oil” A mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulfur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

“CSP Joint Venture” or “CSP JV” means the joint venture with Mitsui pursuant to the Joint Venture Operating Agreement (“JVOA”) entered into for the proposed condensate stripping facilities with Mitsui.

“CSP JVOA” means the Joint Venture Operating Agreement entered into with Mitsui for the proposed condensate stripping facilities.

“CSP” or “Condensate Stripping Project” means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and associated facilities being progressed in joint venture with Mitsui.

“DPE” means Department of Petroleum and Energy of Papua New Guinea.

“EBITDA” EBITDA represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is a non-GAAP measure used to analyze operating performance. See “Non-GAAP Measures and Reconciliation”.

“Farm-In Agreement” means an agreement entered into between parties to transfer a participating interest in an oil and gas property.

“FEED” means front end engineering and design.

“Feedstock” means raw material used in a refinery or other processing plant.

“FID” means final investment decision. Such a decision is ordinarily the point at which a decision is made to proceed with a project and it becomes unconditional. However, in some instances the decision may be qualified by certain conditions, including being subject to necessary approvals by the State.

“FLEX LNG” means FLEX LNG Limited, a British Virgin Islands Company listed on the Oslo Stock Exchange.

“FX” means foreign exchange.

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“GAAP” means Canadian generally accepted accounting principles.

“Gas” means a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulfur or other non-hydrocarbon compounds.

“HOA” means Head of Agreement.

“ICCC” means Papua New Guinea’s competition authority, the Independent Consumer and Competition Commission.

“IFRS” means International Financial Reporting Standards as issued by the International Accounting Standards Board.

“IPI” means an indirect participation interest.

“IPI Agreement” means the Amended and Restated Indirect Participation Agreement dated February 25, 2005, as amended.

“IPI holders” means investors holding IPIs in certain exploration wells required to be drilled pursuant to the IPI Agreement.

“IPP” means import parity price. For each refined product produced and sold locally in Papua New Guinea, IPP is calculated under agreement with the State by adding the costs that would typically be incurred to import such product to an average posted price for such product in Singapore as reported by Platts. The costs added to the reported Platts price include freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, demurrage and taxes.

“LIBOR” means daily reference rate based on the interest rates at which banks borrow unsecured funds from banks in the London wholesale money market.

“LNG” means liquefied natural gas. Natural gas may be converted to a liquid state by pressure and severe cooling for transportation purposes, and then returned to a gaseous state to be used as fuel. LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas liquids, which are heavier fractions that occur naturally as liquids.

“LNGL” means Liquid Niugini Gas Limited, a wholly owned subsidiary of PNG LNG, incorporated under the laws of in Papua New Guinea to contract with the State and pursue the LNG Project, including construction of the proposed liquefaction facilities.

“LNG Project” means the development by us of liquefaction facilities in the Gulf Province of Papua New Guinea described as our Midstream Liquefaction business segment and being undertaken as a joint venture with Pac LNG and with other potential partners, including the State.

“LNG Project Agreement” means the LNG Project Agreement between the State and LNGL dated December 23, 2009.

“Mitsui” refers to Mitsui & Co., Ltd., a company organized under the laws of Japan and/or certain of its wholly-owned subsidiaries (as the context requires).

“MOPS” means Mean of Platts Singapore, which is the benchmark price for refined products in the region in which we operate.

“Mtpa” means million tonnes per annum.

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“Naphtha” means that portion of the distillate obtained from the refinement of petroleum which is an intermediate between the lighter gasoline and the heavier benzene. It is a feedstock destined either for the petrochemical industry or for gasoline production by reforming or isomerisation within a refinery.

“Natural gas” means 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.

“NI 51-101” means National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities

“NRV” means net realizable value.

“OPIC” means Overseas Private Investment Corporation, an agency of the United States Government.

“Pac LNG” means Pacific LNG Operations Ltd., a company incorporated under the laws of the Bahamas and affiliated with Clarion Finanz A.G. This company is our joint venture partner in the LNG Project (holding equal voting shares in PNG LNG), holds a 2.5% direct interest in the Elk and Antelope fields, is an IPI holder and a majority shareholder in PNGDV.

“PDL” means Petroleum Development License. The right granted by the State to develop a field for commercial production.

“Petromin” means Petromin PNG Holdings Limited, a company incorporated under the laws of Papua New Guinea by the State.

“PGK” means the Kina, currency of Papua New Guinea.

“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered into an indirect participation agreement in May 2003, as amended.

“PNG LNG” means PNG LNG, Inc., a joint venture company established in 2007 to hold the interests of certain joint venturers in the venture to construct the proposed liquefaction facilities. Shareholders are InterOil LNG Holdings Inc., a wholly-owned subsidiary of InterOil, and Pac LNG.

“PPL” means Petroleum Prospecting License. The tenement given by the State to explore for oil and gas.

“PRE” means Pacific Rubiales Energy Corp., a company incorporated under the laws of British Columbia, Canada.

“PRE JVOA” means the Joint Operating Agreement entered into with PRE for PPL 237 based on the provisions defined in the HOA and the Farm-In Agreement with PRE.

“PRL” means Petroleum Retention License. The tenement given by the State to allow the license holder to evaluate the commercial and technical options for the potential development of an oil and/or gas field.

“SEC” means the United States Securities and Exchange Commission.

“State” or “PNG” means the Independent State of Papua New Guinea.

“USD” or “US” means United States Dollars.

“Westpac” means Westpac Bank PNG Limited.

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