InterOil Corporation Management Discussion and Analysis For the quarter ended March 31, 2014 May 14, 2014

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	4
OIL AND GAS DISCLOSURES	4
GLOSSARY OF TERMS	4
INTRODUCTION	7
BUSINESS STRATEGY	7
OPERATIONAL HIGHLIGHTS	8
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	10
QUARTER IN REVIEW	14
LIQUIDITY AND CAPITAL RESOURCES	20
RISK FACTORS	28
CRITICAL ACCOUNTING ESTIMATES	28
NEW ACCOUNTING STANDARDS	28
NON-GAAP MEASURES AND RECONCILIATION	28
PUBLIC SECURITIES FILINGS	31
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	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, 2013 and our annual information form (the “2013 Annual Information Form”) for the year ended December 31, 2013. This MD&A was prepared by management and provides a review of our performance for the quarter ended March 31, 2014, 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,” “Group”, and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information is presented as at March 31, 2014 and for the quarter ended March 31, 2014 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; construction and development of a proposed LNG plant in Papua New Guinea; the timing and cost of such construction and development; 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; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; and timing, maturity and amount of future capital and other expenditures.

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

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

· our ability to obtain and maintain necessary permits, concessions, licenses and approvals from relevant State authorities to develop our gas and condensate resources within reasonable periods and on reasonable terms or at all;

· inherent uncertainty of oil and gas exploration;

· the availability of crude feedstock at economic rates;

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

· the difficulties with recruitment and retention of qualified personnel; 

· the losses from our hedging activities;

· the fluctuations in currency exchange rates;

· the 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;

· 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;

· general economic conditions, including further economic downturn, availability of credit, European sovereign debt-credit crisis and 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 develop resources, 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.

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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 assumptions 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 2013 Annual Information Form.

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

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

Crude Oil and Natural Gas Liquids		Natural Gas
bbl	one barrel equalling 34.972 Imperial gallons or 42 U.S. gallons	btu	British Thermal Units
bblspd	barrels per day	mcf	thousand standard cubic feet
boe(1)	barrels of oil equivalent	mcfpd	thousand standard cubic feet per day
boepd	barrels of oil equivalent per day	mmbtu	million British Thermal Units
bpsd	barrels per stream day	mmbtupd	million British Thermal Units per day
mboe	thousand barrels of oil equivalent	mm	million standard cubic feet
mbbl	thousand barrels	mmcfpd	million standard cubic feet per day
MMbbls	million barrels	mtpa	million tonnes per annum
MMboe	million barrels of oil equivalent	scfpd	standard cubic feet per day
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma	tcfe	trillion standard cubic feet equivalent
bscf	billion standard cubic feet	psi	pounds per square inch

Note:

(1) All calculations converting natural gas to crude oil equivalent have been made using a ratio of six mcf of natural gas to one barrel of crude equivalent. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf 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

CONVERSION

This table outlines certain standard conversions between Standard Imperial Units and the International System of Units (metric units).

To Convert From	To	Multiply By
mcf	cubic meters	28.317
cubic meters	cubic feet	35.315
bbls	cubic meters	0.159
cubic meters	bbls	6.289
feet	meters	0.305
meters	feet	3.281
miles	kilometers	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

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, 2013 in accordance with NI 51-101. This evaluation is summarized in our 2013 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, 2014.

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.

GLOSSARY OF TERMS

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

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

“Board” means the board of directors of InterOil.

“BSP” means Bank of South Pacific Limited.

“CBA” means Commonwealth Bank of Australia.

“condensate” means a component of natural gas which is a liquid at surface conditions.

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“Condensed Consolidated Interim Financial Statements” means the unaudited condensed consolidated interim financial statements for the quarter and three months ended March 31, 2014.

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

“Credit Suisse” means Credit Suisse A.G.

“CRU” means catalytic reformer unit.

“crude oil” means 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.

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

“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”.

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

“FID” means a 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.

“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.

“IPI holders” means investors holding indirect participating working interests in certain exploration wells required to be drilled pursuant to the indirect participating interest agreement between us and certain investors dated February 25, 2005, and amended December 15, 2005 and further amended June 15, 2012.

“Intesa Sanpaolo” means Intesa Sanpaolo S.p.A.

“LIBOR” means daily reference rate based on the interest rates at which banks borrow unsecured funds from banks in the London, United Kingdom, 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.

“LNG Project” means the development by us in joint venture as a non-operator of liquefaction and related facilities for the monetization of our gas discoveries.

“Macquarie” means Macquarie Group Limited.

“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 isomerization within a refinery.

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“Natixis” means the Singapore branch of Natixis S.A.

“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 of Disclosure for Oil and Gas Activities adopted by the Canadian Securities Administrators.

“Oil Search” means Oil Search Limited, a company incorporated in Papua New Guinea; an oil and gas exploration and development company that has been operating in Papua New Guinea since 1929.

“PacLNG” means Pacific LNG Operations Ltd., a company incorporated under the laws of the Bahamas.

“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.

“PPL” means the Petroleum Prospecting License, an exploration tenement granted under the Oil & Gas Act 1997 (PNG).

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

“PRL” means the Petroleum Retention License, the tenement granted under the Oil & Gas Act 1997 (PNG) to allow the license holder to evaluate the commercial and technical options for the potential development of an oil and/or gas discovery.

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

“SPA” means sale and purchase agreement.

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

“Total” means Total S.A., a French multinational integrated oil and gas company and its subsidiaries.

“Total SPA” means the sales and purchase agreement signed on December 5, 2013 with Total where we agreed to sell a gross 61.3% interest in PRL 15, which contains the Elk and Antelope gas fields. This agreement was subsequently replaced on March 26, 2014 with the Total SSA.

“Total SSA” means an agreement under which Total acquired, through the purchase of all of the shares of SPI (200) Limited, a wholly owned subsidiary, a gross 40.1275% interest in PRL 15.

“UBS” means UBS A.G.

“USD” means United States dollars.

“Westpac” means Westpac Bank PNG Limited.

Management Discussion and Analysis   INTEROIL CORPORATION   6

INTRODUCTION

We are an independent oil and gas business with a primary focus on Papua New Guinea. Our assets include the Elk and Antelope fields in the Gulf Province of Papua New Guinea, exploration licenses covering about 16,000 square kilometers (about 4 million acres) in Papua New Guinea, Papua New Guinea’s only oil refinery, and retail and commercial petroleum distribution facilities throughout the country. We have our main offices in Singapore and Port Moresby. We are listed on the New York and the Port Moresby stock exchanges.

At March 31, 2014, we had 1,086 full-time employees in all segments, with 185 in Upstream, 128 in Midstream, 593 in Downstream and 180 in Corporate. 

Our operations are organized into four major segments:

Segments	Operations
Upstream	Exploration and Development – Explore, appraise and develop hydrocarbon structures in Papua New Guinea. Proposed activities include commercializing, monetizing and developing oil and gas structures through production facilities, including a liquefied natural gas plant.
Midstream	Refining – Produce refined petroleum products at Napa Napa in Port Moresby, Papua New Guinea, for domestic and export markets.
Downstream	Wholesale and Retail Distribution – Wholesale and retail marketing and distribution of refined petroleum products in Papua New Guinea.
Corporate	Corporate – Support business segments through business development and improvement activities, general services, administration, human resources, executive management, financing and treasury, government affairs and investor relations. This segment also manages our shipping business, which operates two vessels that transport petroleum products within Papua New Guinea and the South Pacific.

BUSINESS STRATEGY

Our strategy is to enhance shareholder value by developing our resources based on three horizons of growth:

· Horizon 1 – Operating growth: run an efficient and financially stable existing business. This includes ensuring we have capital to support investment in our existing business, reducing costs, building organizational capability, and having best practice management processes.

· Horizon 2 – Developing growth: monetize our gas resources. This involves partnerships with experienced operators to develop our gas resources and to leverage relationships that create value across exploration, development and operations.

· Horizon 3 – Future growth: explore for the future. This includes making wise investment in new exploration across frontier regions in Papua New Guinea and by being a preferred partner or operator of choice for new ventures.

Further details of our business strategy can be found under the heading “Business Strategy” in our 2013 Annual Information Form available at www.sedar.com.

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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 Exploration and Development

· PRL15 asset farm out

- As part of our strategy to monetize gas resources, we signed and completed on March 26, 2014 the Total SSA under which Total acquired, through the purchase of all shares of a wholly owned subsidiary, a gross participating interest of 40.1275% (net 31.0988%, after the State back-in right of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields. We retained 35.4839% (net 27.5%, after the State back-in right of 22.5%) of the license. Under the transaction with Total, we received $401.3 million as a completion payment, and are entitled to receive payments of $73.3 million upon a FID for an Elk and Antelope LNG Project, and $65.5 million upon the first LNG cargo from such LNG Project.

- In addition to these fixed amounts, Total is obliged to make variable payments for resources in PRL 15 that are in excess of 3.5 tcfe, based on certification by two independent certifiers following the drilling of up to three appraisal wells in PRL 15. Payments for resources greater than 5.4 tcfe will be paid at certification.

- Total will carry 75% of costs relating to InterOil’s participating interest in a maximum of three appraisal wells (up to a maximum of $50.0 million per well on a 100% basis), which are scheduled to be drilled in 2014 and 2015. Certification of the Elk and Antelope resources under our agreement with Total is expected in 2015.

- In addition to payments for the Elk and Antelope resources in PRL 15, Total has also agreed to pay $65.4 million per tcfe for volumes over one tcfe of additional resources discovered in PRL 15 from one exploration well. Any payment would be made at first gas production from a proposed Elk and Antelope LNG Project. Total will also carry 75% of costs relating to our participating interests of this exploration well to a maximum of $60.0 million on a 100% basis. Costs in excess of this are to be borne by the parties in accordance with their participating interests.

- On March 26, 2014, we also completed the acquisition from IPI holders of an additional 1.0536% in PRL 15 for $41.53 million, satisfied by the issuance of 688,654 common shares in the capital of the Company, plus additional variable resource payments if interim or final resource certification exceeds 7.0 tcfe under the Total SSA. This increased our gross interests in PRL 15 to 36.5375% (net 28.3166%, after the State back-in right of 22.5%).

· New license applications

- On October 16, 2013, we applied to the DPE for new licenses over the area covered by PPL 236, PPL 237 and PPL 238, which were due to expire on March 6, 2014 (PPL 238) and March 27, 2014 (PPLs 236 and 237). We proposed new work programs and commitments for each new license. On March 6, 2014, applications for the new licenses were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238.

· Seismic and exploration program

- In 2013, the Board approved a major exploration and appraisal drilling and seismic work program and budget for 2014-15. The program provides for the following exploration wells: PPL 474 (Wahoo-1), PPL 475 (Raptor-1), PPL 476 (Bobcat-1) and PRL 15 (Antelope Deep). Appraisal wells are scheduled for PRL 15 (Antelope-4, Antelope-5 and possibly Antelope-6) and PRL 39 (Triceratops-3). Following Board approval of the program, we spudded Wahoo-1, Raptor-1 and Bobcat-1 wells in March 2014.

- During the first quarter of 2014, we continued acquiring seismic data in Triceratops east, south-west Antelope and across two new prospects, Bobcat located in PPL 476 and Antelope Deep located in PRL 15.

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Midstream – Refining

· For the quarter ended March 31, 2014, our average daily throughput (excluding shutdown days) was 26,717 bblspd compared to 27,525 bblspd during the quarter ended March 31, 2013. The total number of bbls processed into product at our refinery for the quarter ended March 31, 2014 was 1.829 MMbbls compared with 2.389 MMbbls for the corresponding quarter in 2013.

· Capacity utilization of the refinery for the quarter ended March 31, 2014, based on operating capacity of 36,500 bblspd, was 59% compared with 74% for the quarter ended March 31, 2013. During the quarters ended March 31, 2014 and 2013, the refinery was shut down for general maintenance for 19 days and 1 day respectively.

Downstream – Wholesale and Retail Distribution

· The Papua New Guinea economy has continued to slow in the first quarter of 2014 as construction of the ExxonMobil-led LNG project nears completion. Total sales volumes for the quarter ended March 31, 2014 were 176.8 million liters (March 2013 – 183.7 million liters), a decrease of 6.9 million liters, or 3.8% over the corresponding period in 2013. Most of this decrease in volume was related to the ExxonMobil LNG project.

· Our retail business accounted for about 16.0% of our total downstream sales in the first quarter of 2014 (March 2013 – 14.9%).

Corporate

· In January 2014, Jon Ozturgut was appointed Chief Operating Officer and Don Spector was appointed Chief Financial Officer. Mr. Ozturgut has more than 27 years’ international oil and gas experience with Atlantic Richfield Company, CMS Oil and Gas Company, and Woodside Energy. He replaced William J. Jasper III who retired after seven years with the Company. Mr. Spector, who has more than 35 years’ international financial experience, including 30 years in oil and gas with BP, CRA (now Rio Tinto), Woodside Energy, and the Australian Tax Office, replaced Collin Visaggio, who resigned, also after seven years with the Company.

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SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarters Ended March 31, 2014 and 2013

Consolidated – Operating results	Quarter ended March 31,
($ thousands, except per share data)	2014			2013
Sales and operating revenues		308,223			349,324
Interest revenue		54			15
Other non-allocated revenue		2,803			992
Total revenue		311,080			350,331
Cost of sales and operating expenses		(270,714	)		(314,759	)
Office and administration and other expenses		(25,537	)		(11,284	)
Derivative gains/(losses)		935			(471	)
Exploration costs		(8,696	)		(450	)
Gain on conveyance of oil and gas properties		340,539			500
Loss on Flex LNG investment		-			(340	)
Foreign exchange losses		(14,302	)		(5,476	)
Share of net loss of joint venture partnership accounted for using the equity method		(11	)		(96	)
EBITDA (1)		333,294			17,955
Depreciation and amortization		(5,479	)		(5,698	)
Interest expense		(6,226	)		(4,333	)
Profit before income taxes		321,589			7,924
Income tax expense		(2,953	)		(3,921	)
Net profit		318,636			4,003
Net profit per share (basic)		6.45			0.08
Net profit per share (diluted)		6.38			0.08
Total assets		1,737,189			1,368,581
Total liabilities		641,605			589,229
Total long-term liabilities		218,783			267,979
Gross margin (2)		37,509			34,565
Cash flows (used in)/generated from operating activities (3)		(15,244	)		40,583

Notes:

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

(2) Gross margin/(loss) 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.

Analysis of Financial Condition Comparing Quarters Ended March 31, 2014 and 2013

During the quarter ended March 31, 2014, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 22% (19% as at March 31, 2013), well below our targeted maximum gearing level of 50%. Gearing targets are based on several factors including operating cash flows, future cash needs for development, capital market and economic conditions, and are assessed regularly. Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 1.7 times as at March 31, 2014 (1.4 times as at March 31, 2013). 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 1.3 times as at March 31, 2014 (0.8 times as at March 31, 2013). The current ratio and quick ratio satisfied our internal targets of above 1.5 and 1.0 times respectively as at March 31, 2014.

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Variance in Total Assets:

As at March 31, 2014, our total assets amounted to $1,737.2 million, compared with $1,368.6 million as at March 31, 2013. This increase of $368.6 million, or 27%, from March 31, 2013 was primarily due to:

- $551.9 million increase in non-current receivables, as a result of the recognition of long term receivables in relation to the conveyance proceeds from Total regarding the PRL15 interest sell down completed on March 26, 2014; and

- $374.8 million increase in cash and cash equivalents and restricted cash, primarily due to the receipt of the $401.3 million SPA completion payment from Total.

These increases have been partially offset by:

- $446.8 million decrease in oil and gas properties, mainly resulting from the allocation of Total’s conveyance proceeds from PRL 15 interest sell down against the respective PRL 15 capitalized costs on the balance sheet;

- $84.1 million decrease in our trade and other receivables, primarily due to change in our discounting facility to a non-recourse basis, lower downstream receivables, and lower upstream receivable from joint venture partners outstanding as at March 31, 2014;

- $13.8 million decrease in deferred tax assets mainly resulting from the impact of unfavorable foreign exchange movements affecting temporary differences on translation of non-monetary assets of the refinery operation using period-end rates; and

- $8.8 million decrease in plant and equipment mainly due to depreciation charges incurred during the period.

Variance in Total Liabilities:

As at March 31, 2014, our total liabilities amounted to $641.6 million, compared with $589.2 million at March 31, 2013. The increase of $52.4 million, or 9%, from March 31, 2013 was primarily due to:

- net increase of $134.3 million in secured loans payable mainly on a drawdown of the Credit Suisse syndicated secured loan of $150.0 million, and a drawdown of the BSP and Westpac combined secured facility of $22.7 million.

This increase has been partially offset by:

- $41.7 million decrease in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases;

- $22.1 million decrease in indirect participating interests mainly due to the allocation of indirect participating interests against exploration costs incurred during the quarter; and

- $21.6 million decrease in working capital facilities, primarily attributable to the discounted receivables under the BNP working capital facility now being non-recourse and no longer included within our liabilities, and also due to the timing of crude cargoes.

Analysis of Consolidated Financial Results Comparing Quarters Ended March 31, 2014 and 2013

A complete discussion of each of our business segments’ results can be found under the section “Quarter in Review”.

Total revenues decreased by $39.2 million to $311.1 million in the quarter ended March 31, 2014 from $350.3 million in the quarter ended March 31, 2013, primarily due to lower sales volumes during the quarter. The total volume of all products sold by us was 1.9 MMbbls for the quarter ended March 31, 2014, compared with 2.4 MMbbls in the corresponding quarter of 2013, mainly due to the timing of refinery exports between the two quarters.

Our net profit for the quarter ended March 31, 2014 was $318.6 million compared with a net profit of $4.0 million for the same quarter of 2013, an increase in profit of $314.6 million. The operating segments of Corporate, Midstream - Refining and Downstream collectively derived a net profit for the quarter of $8.6 million (2013 net profit of $18.5 million), while investments in development segments of Upstream and Midstream - Liquefaction resulted in a net profit of $310.0 million (2013 net loss of $14.5 million).

The increase in net profit for the quarter ended March 31, 2014 was mainly due to:

- $340.0 million increase in gain on conveyance of oil and gas properties in relation to the completion of the Total SSA on March 26, 2014.

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This increase in net profit has been partly offset by:

- $14.3 million increase in office and administrative expenses due to amortization of financing fees incurred on the Credit Suisse syndicated secured loan, $2.0 million compensation paid to our former Chief Financial Officer and Chief Operating Officer on their retirement, and the recognition of a $3.6 million restructuring provision as at March 31, 2014 relating to the closure of the corporate office in Cairns, Australia;

- $8.8 million increase in foreign exchange losses mainly due to the unfavorable rates from banks on the transfer of PGK refinery sales proceeds to USD compared to the prior period, due to lack of liquidity of USD in Papua New Guinea, where rates fluctuate significantly based on other exporters and importers looking to convert their USD to PGK; and

- $8.2 million increase in exploration costs mainly attributable to the expensing of seismic activities over the Bobcat and Antelope Deep (formerly Bighorn) prospects during the current quarter.

Analysis of Consolidated Cash Flows Comparing Quarters Ended March 31, 2014 and 2013

As at March 31 2014, we had cash, cash equivalents, and restricted cash of $482.2 million (March 31, 2013 - $107.4 million), of which $61.5 million (March 31, 2013 - $38.9 million) was restricted. Of the total restricted cash of $61.5 million, $25.0 million (March 31, 2013 - $27.3 million) was restricted by BNP working capital facility utilization requirements; $11.2 million (March 31, 2013 - $11.3 million) was restricted as a cash deposit on the ANZ, BSP and BNP syndicated secured loan facility; $7.4 million (March 31, 2013 - $Nil) was restricted as a debt reserve under the Credit Suisse syndicated secured loan; $17.5 million (March 31, 2013 - $Nil) was restricted as a cash deposit securing the letters of credit issued by BNP to one of our suppliers on signing of a rig lease and services agreement; and the balance was made up of a cash deposit on office premises and term deposits on our PPLs.

Cash flows (used in)/generated from operations

Cash outflows from operations for the quarter ended March 31, 2014 were $15.2 million compared with an inflow of $40.6 million for the quarter ended March 31, 2013, a net increase in cash outflows of $55.8 million. This increase in cash outflows was mainly due to a $30.4 million net increase in working capital outflows associated with trade and other receivables, inventories and accounts payables funded mostly by our working capital facilities; and a $25.4 million increase in net cash outflows from operations related to a decrease in net profit generated by operations less any non-cash expenses.

Cash flows used in investing activities

Cash inflows from investing activities for the quarter ended March 31, 2014 were $348.0 million compared with an outflow of $35.7 million for the quarter ended March 31, 2013. Cash inflows were primarily due to the $401.3 million proceeds from Total with respect to the sell down of interest in PRL 15 and a $55.2 million increase in working capital requirements of the development segments with the three wells being drilled concurrently during the quarter ended March 31, 2014. These inflows were partially offset by net cash expenditures on exploration, appraisal and development (net of cash calls from IPI holders) of $94.8 million; an $8.3 million increase in restricted cash held as security for various facilities and letter of credit requirements; and expenditures on plant and equipment of $5.4 million.

Cash flows generated from financing activities

Cash inflows from financing activities for the quarter ended March 31, 2014 amounted to $26.0 million, compared with $13.9 million for the quarter ended March 31, 2013. Cash inflows were primarily due to the $50.0 million drawdown of the Credit Suisse syndicated secured loan and $1.7 million received from the issuance of common shares during the quarter. These cash inflows have been partially offset by the $23.7 million net repayments of the working capital facilities and $2.0 million repayment of the BSP and Westpac combined secured facility.

Management Discussion and Analysis   INTEROIL CORPORATION   12

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended March 31, 2014 by business segment, and on a consolidated basis.

Quarters ended	2014			2013												2012
($ thousands except per share data)	Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30
Upstream		2,823			1,731			1,918			2,533			1,862			4,136			2,216			1,727
Midstream – Refining		249,487			353,749			251,725			289,300			305,172			301,925			274,671			236,006
Midstream – Liquefaction		-			181			-			20,089			-			-			-			-
Downstream		212,720			213,835			215,651			199,470			208,046			220,512			201,749			223,620
Corporate		32,481			31,832			31,714			36,201			34,923			37,552			26,880			24,742
Consolidation entries		(186,431	)		(202,426	)		(195,773	)		(201,932	)		(199,672	)		(207,686	)		(178,652	)		(186,991	)
Total revenues		311,080			398,902			305,235			345,661			350,331			356,439			326,864			299,104
Upstream		324,380			(19,974	)		(2,842	)		(19,478	)		(1,311	)		(873	)		956			(5,730	)
Midstream – Refining		5,988			10,246			(3,562	)		840			12,701			12,370			13,417			(42,647	)
Midstream – Liquefaction		(63	)		87			2,550			19,850			(123	)		192			11			672
Downstream		10,141			14,366			14,962			7,542			10,062			12,258			9,275			11,102
Corporate		2,223			6,055			13,446			1,745			10,044			14,133			9,841			9,975
Consolidation entries		(9,375	)		(16,082	)		(14,647	)		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)
EBITDA (1)		333,294			(5,302	)		9,907			(647	)		17,955			25,881			18,997			(36,499	)
Upstream		310,567			(33,535	)		(16,206	)		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)
Midstream – Refining		601			74			(11,074	)		(4,675	)		5,855			13,401			5,358			(32,969	)
Midstream – Liquefaction		(555	)		(430	)		2,373			19,284			(681	)		(394	)		(573	)		93
Downstream		6,013			9,237			9,435			4,346			6,005			7,716			5,626			6,045
Corporate		(684	)		2,787			10,780			(1,701	)		7,342			10,519			7,849			8,445
Consolidation entries		2,694			(2,946	)		(1,626	)		1,562			(744	)		384			(1,988	)		2,205
Net profit/(loss)		318,636			(24,813	)		(6,318	)		(13,230	)		4,003			18,545			5,336			(31,713	)
Net profit/(loss) per share (dollars)
Per Share – Basic		6.45			(0.51	)		(0.13	)		(0.27	)		0.08			0.38			0.11			(0.66	)
Per Share – Diluted		6.38			(0.51	)		(0.13	)		(0.27	)		0.08			0.38			0.11			(0.66	)

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

Management Discussion and Analysis   INTEROIL CORPORATION   13

QUARTER IN REVIEW

This section provides a review of the quarter ended March 31, 2014 for each of our business segments.

UPSTREAM – QUARTER IN REVIEW

Upstream – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
Other non-allocated revenue		1,824			592
Inter-segment revenue - Recharges		999			1,270
Total revenue		2,823			1,862
Office and administration and other expenses		(9,281	)		(3,218	)
Exploration costs		(8,696	)		(450	)
Gain on conveyance of oil and gas properties		338,182			500
Foreign exchange gains/(losses)		1,352			(5	)
EBITDA (1)		324,380			(1,311	)
Depreciation and amortization		(527	)		(522	)
Interest expense		(13,036	)		(11,941	)
Profit/(loss) before income taxes		310,817			(13,774	)
Income tax expense		(250	)		-
Net profit/(loss)		310,567			(13,774	)

(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, 2014 and 2013

This analysis outlines key movements, the net of which primarily explains the variance in results between the quarters ended March 31, 2014 and 2013 for certain of the line items set forth in the table above:

Quarterly Variance ($ millions)
$324.3	Net profit/(loss) variance for the comparative period primarily due to:
Ø $337.7	Increase in gain on conveyance of oil and gas properties in relation to the completion of the Total SSA on March 26, 2014.
Ø ($6.1)	Increase in office and administration expenses was mainly due to the amortization of the remaining $5.6 million loan facility fees incurred for the Credit Suisse syndicated secured loan, and the BSP and Westpac combined secured facility during the quarter.
Ø ($8.2)	Increase in exploration costs was primarily attributable to the expensing of exploratory seismic costs, including for Bobcat prospect in PPL 476 and Antelope Deep prospect in PRL 15.

Management Discussion and Analysis   INTEROIL CORPORATION   14

MIDSTREAM - REFINING – QUARTER IN REVIEW

Midstream Refining – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
External sales		97,158			141,697
Inter-segment revenue - Sales		152,147			163,472
Inter-segment revenue - Recharges		180			-
Interest and other revenue		2			3
Total segment revenue		249,487			305,172
Cost of sales and operating expenses		(226,623	)		(285,301	)
Office and administration and other expenses		(2,532	)		(1,597	)
Derivative gains/(losses)		935			(471	)
Foreign exchange losses		(15,279	)		(5,102	)
EBITDA (1)		5,988			12,701
Depreciation and amortization		(3,295	)		(3,122	)
Interest expense		(2,223	)		(2,454	)
Profit before income taxes		470			7,125
Income tax benefit/(expense)		131			(1,270	)
Net profit		601			5,855
Gross Margin (2)		22,682			19,868

(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”.

Midstream - Refining Operating Review

	Quarter ended March 31,
Key Refining Metrics	2014			2013
Throughput (barrels per day)(1)		26,717			27,525
Capacity utilization (based on 36,500 barrels per day operating capacity)		59	%		74	%
Cost of production per barrel	$	3.35		$	2.95
Working capital financing cost per barrel of production	$	0.68		$	0.37
Distillates as percentage of production		50.8	%		51.6	%

(1) Throughput per day has been calculated excluding shut down days. During quarters ended March 31, 2014 and 2013, the refinery was shut down for 19 days and 1 day, respectively.

Analysis of Midstream - Refining Financial Results Comparing the Quarters Ended March 31, 2014 and 2013

This analysis outlines key movements, the net of which primarily explains the variance in results between the quarters ended March 31, 2014 and 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   15

Quarterly Variance  ($ millions)
($5.3)	Net profit variance for the comparative period primarily due to:
Ø $2.8	Increase in gross margin was mainly due to overall decreased direct operating costs. This was partially offset by higher fixed costs as a result of lower refinery production for the quarter (March 31, 2014 - 1.829 MMbbls; March 2013 - 2.389 MMbbls).
Ø $1.4	Increase in derivative gains from commodity contracts
Ø ($10.2)	Increase in foreign exchange losses for the quarter was mainly due to the  transfer of PGK refinery sales proceeds to USD, due to lack of liquidity of USD in Papua New Guinea, where the rates fluctuate significantly based on other exporters and importers looking to convert their USD into PGK.

MIDSTREAM - LIQUEFACTION – QUARTER IN REVIEW

Midstream Liquefaction – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
Inter-segment revenue - Recharges		-			-
Total segment revenue		-			-
Office and administration and other expenses		(52	)		(27	)
Share of net loss of joint venture partnership accounted for using the equity method		(11	)		(96	)
EBITDA (1)		(63	)		(123	)
Interest expense		(492	)		(558	)
Loss before income taxes		(555	)		(681	)
Income tax expense		-			-
Net loss		(555	)		(681	)

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

Analysis of Midstream - Liquefaction Financial Results Comparing the Quarters Ended March 31, 2014 and 2013

This segment’s results include our interest in the previously proposed joint venture development of the proposed midstream facilities of the LNG Project. During 2013, we have modified the direction of our midstream liquefaction business and no longer plan to be the operator of an LNG liquefaction project in which we have ownership.

There were no key variance in results between the quarters ended March 31, 2014 and 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   16

DOWNSTREAM – QUARTER IN REVIEW

Downstream – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
External sales		211,018			207,559
Inter-segment revenue - Sales		51			85
Interest and other revenue		1,651			402
Total segment revenue		212,720			208,046
Cost of sales and operating expenses		(197,395	)		(193,390	)
Office and administration and other expenses		(4,592	)		(4,381	)
Foreign exchange losses		(592	)		(213	)
EBITDA (1)		10,141			10,062
Depreciation and amortization		(1,263	)		(1,180	)
Interest expense		(557	)		(422	)
Profit before income taxes		8,321			8,460
Income tax expense		(2,308	)		(2,455	)
Net profit		6,013			6,005
Gross Margin (2)		13,674			14,254

(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	2014		2013
Sales volumes (millions of liters)		176.8		183.7
Average sales price per liter ($)	$	1.10	$	1.12

Analysis of Downstream Financial Results Comparing the Quarters Ended March 31, 2014 and 2013

There were no key variance in results between the quarters ended March 31, 2014 and 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   17

CORPORATE – QUARTER IN REVIEW

Corporate – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
External sales		46			68
Inter-segment revenue - Sales		7,866			6,894
Inter-segment revenue - Recharges		13,642			15,309
Interest revenue		10,895			12,652
Other non-allocated revenue		32			-
Total revenue		32,481			34,923
Cost of sales and operating expenses		(6,703	)		(5,657	)
Office and administration and other expenses		(23,772	)		(18,726	)
Foreign exchange gains/(losses)		217			(156	)
Loss on Flex LNG investment		-			(340	)
EBITDA (1)		2,223			10,044
Depreciation and amortization		(915	)		(906	)
Interest expense		(1,466	)		(1,600	)
(Loss)/profit before income taxes		(158	)		7,538
Income tax expense		(526	)		(196	)
Net (loss)/profit		(684	)		7,342
Gross Margin (2)		1,209			1,305

(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”.

Analysis of Corporate Financial Results Comparing the Quarters Ended March 31, 2014 and 2013

This analysis outlines key movements, the net of which primarily explains the variance in results between the quarters ended March 31, 2014 and 2013 for certain of the line items set forth in the table above.

Quarterly Variance ($ millions)
($8.0)	Net (loss)/profit variance for the comparative period primarily due to:
Ø ($5.0)	Increase in office and administrative expenses was mainly resulting from $2.0 million compensation paid to our former Chief Financial Officer and Chief Operating Officer on their retirement, and the recognition of a $3.6 million restructuring provision as at March 31, 2014 relating to the closure of the corporate office in Cairns, Australia.
Ø ($1.7)	Decrease in inter-segment recharges due to reduced costs incurred, excluding the retirement compensation and restructuring provisions, which are not recharged to segments.
Ø ($1.8)	Lower interest income was due to a decrease in inter-company loan balances.

Management Discussion and Analysis   INTEROIL CORPORATION   18

CONSOLIDATION ADJUSTMENTS – QUARTER IN REVIEW

Consolidation adjustments – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
Inter-segment revenue - Sales		(160,063	)		(170,451	)
Inter-segment revenue - Recharges		(14,821	)		(16,579	)
Interest revenue (1)		(11,547	)		(12,642	)
Total revenue		(186,431	)		(199,672	)
Cost of sales and operating expenses (2)		160,007			169,589
Office and administration and other expenses (3)		14,692			16,665
Gain on conveyance of oil and gas properties		2,357			-
EBITDA (4)		(9,375	)		(13,418	)
Depreciation and amortization (5)		521			32
Interest expense (1)		11,548			12,642
Profit/(loss) before income taxes		2,694			(744	)
Income tax expense		-			-
Net profit/(loss)		2,694			(744	)
Gross Margin (6)		(56	)		(862	)

(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, 2014 and 2013

This table outlines key movements, the net of which primarily explains the variance in results between the quarters ended March 31, 2014 and 2013 for certain of the line items set forth in the table above.

Quarterly Variance ($ millions)
$3.4	Net profit/(loss) variance for the comparative period primarily due to:
$0.6	Variance in net profit/(loss) for the quarter was due to changes in intra-group profit eliminated on consolidation relating to the Midstream Refining segment’s profit component of inventory on hand in the Downstream segment at quarter end.
$2.4	Increase in gain on conveyance of oil and gas properties in relation to the profit elimination entries for services provides by other intra-group segments in prior periods relating to PRL 15 assets.

Management Discussion and Analysis   INTEROIL CORPORATION   19

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

This table summarizes the debt facilities available to us and the balances outstanding as at March 31, 2014.

Organization	Segment	Facility		Balance outstanding March 31, 2014			Weighted average interest rate			Maturity date
Credit Suisse syndicated secured loan	Upstream	$	250,000,000	$	150,000,000			5.84	%	June 2014
ANZ, BSP and BNP syndicated secured loan facility	Midstream - Refining	$	100,000,000	$	84,000,000			6.54	%	November 2017
BNP working capital facility(1)	Midstream - Refining	$	270,000,000	$	11,914,130	(2)		3.90	%	February 2015
BNP non-recourse discounting facility(1)	Midstream - Refining	$	80,000,000	$	28,337,375	(3)		1.42	%	February 2015
Westpac PGK working capital facility facility	Downstream	$	18,585,000	$	744,365			7.25	%	November 2014
BSP PGK working capital facility	Downstream	$	18,585,000	$	Nil			9.45	%	November 2014
BSP and Westpac combined secured facility	Downstream	$	24,780,077	$	22,715,070			7.94	%	August 2014
2.75% convertible notes	Corporate	$	70,000,000	$	69,998,000			7.91	%(4)	November 2015

(1) The BNP working capital facility agreement provides for a maximum availability of $350.0 million (including a $30.0 million sub-limit for discounted receivables with recourse and an $80.0 million facility for non-recourse discounted receivables). Discounted receivables which are non-recourse are not included in the balance available for use under the working capital facility as they fall within the separate $80.0 million non-recourse discounting facility with BNP.

(2) Excludes letters of credit totaling $149.6 million, which reduces the available borrowings under the facility to $108.5 million at March 31, 2014.

(3) The non-recourse discounted receivables are not retained on our balance sheet as we do not retain the credit risk and control over these receivables.

(4) Effective rate after bifurcating the equity and debt components of the $70.0 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. If this were to occur, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. We can provide no assurance that these alternative measures would be successful. Also, exploration and development activities 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. 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.

Credit Suisse Syndicated Secured Loan (Upstream)

On November 11, 2013, we secured a $250.0 million secured syndicated capital expenditure loan, for an approved seismic data acquisition and drilling program. The loan was provided by a group of banks led by Credit Suisse and included CBA, ANZ, UBS, Macquarie, BSP, BNP and Westpac. The loan is secured by our existing exploration and corporate entities, including InterOil Corporation, SPI (208) Limited, SPI (210) Limited, SPI (220) Limited, SPI Distribution Limited, InterOil Products Limited, InterOil Finance Inc., SPI Exploration and Production Limited, InterOil Corporation PNG Ltd, SPI CSP PNG Limited, InterOil Australia Pty Ltd, InterOil Singapore Pte. Ltd. and InterOil Shipping Pte. Ltd.

Management Discussion and Analysis   INTEROIL CORPORATION   20

The loan bears interest at LIBOR plus 5.5 % margin on the drawn amount for the first six months. After the first six month period the margin escalates 2% every two months to a maximum of 11.5% in the last two months of the 12-month term. During the quarter, the weighted average interest rate was 5.84%.

The loan was initially payable in full within two months of announcing any sale or disposal of our interest in the Elk and Antelope fields. During the quarter ended March 31, 2014, the lenders approved an extension to this repayment date until April 30, 2014 or the completion of the Total SSA transaction, whichever were to occur earliest. Subsequent to quarter end, the lenders approved an additional extension to the repayment date until June 30, 2014 while we work to refinance the current loan into a longer term Upstream loan. At March 31, 2014, we had drawn down $150.0 million and the remaining $100.0 million was available for use according to the terms of the loan.

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

On October 16, 2012, we secured a five year amortizing $100.0 million syndicated secured term loan facility with BNP, BSP, and ANZ. The loan was fully drawn down in November 2012, and is secured by fixed assets of the refinery. The balance outstanding under the loan facility as at March 31, 2014 was $84.0 million. The interest rate on the loan is equal to LIBOR plus 6.5% per annum. During the quarter ended March 31, 2014, the weighted average interest rate under the facility was 6.54%.

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 $8.0 million each, the next two installments are $10.0 million each, and the final four installments $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. During 2013, we made loan repayments totaling $16.0 million. As at March 31, 2014, two installment payments of $8.0 million each which will be due for payment on May 9, 2014 and November 9, 2014, and a mandatory prepayment of $12.5 million resulting from the completion of the Total SSA which was paid on April 28, 2014, have been reclassified into the current portion of the liability. The loan agreement contains certain financial covenants which include the maintenance of minimum levels of equity cover and debt service cover and limitations on the incurrence of additional indebtedness. As of March 31, 2014, we were in compliance with all applicable covenants.

BNP Working Capital Facility (Midstream - Refinery)

On July 17, 2013, we replaced our $240.0 million working capital facility with BNP for our Midstream – Refining operation with a $350.0 million working capital structured facility led by BNP. Of the $350.0 million, $270.0 million is a syndicated secured working capital facility supported by BNP, ANZ, Natixis, Intesa Sanpaolo, and BSP and includes the ability for us to discount receivables with recourse up to $30.0 million. In addition, BNP has provided an $80.0 million bilateral non-recourse discounting facility. The facility is secured by our rights, title and interest in inventory and working capital of the refinery.

As at March 31, 2014, $161.5 million of the $270.0 million facility had been used, and the remaining $108.5 million remained available. In addition, $28.3 million of the $80.0 million non-recourse discounting facility had been used. The credit portion of the facility bears interest at LIBOR plus 3.75% per annum. The facility is renewable in February 2015. During the quarter, the weighted average interest rate was 3.90%.

Westpac and BSP Working Capital Facility (Downstream)

We had an approximately $57.8 million (PGK 140.0 million) combined revolving working capital facility for our Downstream operations in Papua New Guinea from BSP and Westpac. This combined facility was decreased in 2013 by $20.7 million (PGK 50.0 million) as a result of the new combined secured loan facility from Westpac and BSP for funding exploration and drilling activities undertaken by Upstream, reducing the limit of the Downstream working capital facility to $37.2 million (PGK 90.0 million).

The Westpac facility limit is now approximately $18.6 million (PGK 45.0 million) after being reduced in August 2013 by $18.6 million (PGK 45.0 million), and the BSP facility limit is approximately $18.6 million (PGK 45.0 million) after being reduced in November 2013 by $2.1 million (PGK 5.0 million). The combined facility with both banks expires in November 2014.

Management Discussion and Analysis   INTEROIL CORPORATION   21

As at March 31, 2014, $0.7 million (PGK 1.8 million) of this combined facility had been used. These facilities are secured by a fixed and floating charge over the Downstream operations assets. During the quarter, the weighted average interest rate for the Westpac working capital facility was 7.25% and for the BSP working capital facility was 9.45%.

BSP and Westpac Combined Secured Facility (Downstream)

In August 2013, Westpac and BSP provided a one-year $75.0 million combined secured facility to be drawn in tranches of either US dollars or PGK or both. Borrowings under the facility were to be used for exploration and drilling activities with $37.5 million to be available immediately and the balance to be available upon the execution of an agreement in relation to the monetization of the Elk and Antelope fields.

The second tranche was cancelled after we secured a $250.0 million loan in November 2013 from banks led by Credit Suisse, and including Westpac and BSP. In addition, the BSP and Westpac limit was reduced to $24.8 million (PGK60.0 million) in November 2013 with the principal to be repaid in quarterly installments of approximately $1.0 million (PGK2.5 million) starting December 31, 2013 and the balance to be repaid in the third quarter of 2014.

This facility is secured by a fixed and floating charge over Downstream operations assets. The weighted average interest rate under this facility was 7.94% for the quarter ended March 31, 2014.

Unsecured 2.75% Convertible Notes (Corporate)

On November 10, 2010, we completed the issuance of $70.0 million in 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 BSP and Westpac combined secured facility, the BSP and Westpac working capital facilities, the Credit Suisse syndicated secured loan, trade payables and lease obligations.

We pay interest on the notes semi-annually on May 15 and November 15. The notes are convertible into cash or common shares in the capital of the Company, 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 on our current shareholders not otherwise available to the convertible notes. On 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. On 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.

Other Sources of Capital

Our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by capital raising activities, debt, operational cash flows, IPI holders, PNGDV, joint venture partners and asset sales.

Cash calls are made on IPI holders, PNGDV and PacLNG (for its 2.5% direct interest in the Elk and Antelope fields acquired during 2009) for their share of expenditure on appraisal wells and extended well programs where they participate under agreements we have with them. Cash calls will also be made on PRE for exploration activities in PPL 237 (now PPL 475) and appraisal activities in the Triceratops field.

Management Discussion and Analysis   INTEROIL CORPORATION   22

On March 26, 2014, we signed and completed the Total SSA, under which Total acquired through the purchase of all of the shares of a wholly owned subsidiary, a gross 40.1275% (net 31.0988%, after the State back-in right of 22.5%) interest in PRL 15. We retained 35.4839% of the license (net 27.5%, after the State back-in right of 22.5%), received $401.3 million for closing the transaction as a completion payment, and are further entitled to receive payments of $73.3 million upon a FID for an Elk and Antelope LNG Project, and $65.5 million upon the first LNG cargo from such LNG Project. In addition to these fixed amounts, variable payments must be made by Total for resources in PRL 15 that are in excess of 3.5 Tcfe, the value of which will depend on certification by two independent certifiers following the drilling of up to three appraisal wells in PRL 15.

Summary of Cash Flows

	Quarter ended March 31,
($ thousands)	2014			2013
Net cash (outflows)/inflows from:
Operations		(15,244	)		40,583
Investing		347,994			(35,702	)
Financing		25,951			13,864
Net cash movement		358,701			18,745
Opening cash		61,967			49,721
Exchange losses on cash and cash equivalents		0			(4	)
Closing cash		420,668			68,462

Analysis of Cash Flows (Used In)/Generated From Operating Activities Comparing the Quarters Ended March 31, 2014 and 2013

This table outlines key variances in the cash (outflows)/inflows from operating activities between the quarters ended March 31, 2014 and 2013:

	Quarterly variance ($ millions)
	($55.8)	Variance for the comparative period primarily due to:
Ø	($25.4)	Increase in cash used in operations prior to changes in operating working capital for the quarter ended March 31, 2014, mainly due to the net profit from operations adjusted for the gain on conveyance of exploration assets, decrease in depreciation and amortization, increase in derivative gains and increase in deferred tax benefit.  These increases in cash outflows have been partially offset by the increased deferred financing costs.
Ø	($30.4)	Increase in cash used in operations relating to changes in operating working capital for the quarter.  The movement was due primarily to a $52.2 million increase in trade and other payables; a $17.4 million increase in inventories; and a $39.3 million decrease in trade and other receivables.

Analysis of Cash Flows Used In Investing Activities Comparing the Quarters Ended March 31, 2014 and 2013

This table outlines key variances in cash outflows from investing activities between the quarters ended March 31, 2014 and 2013:

Management Discussion and Analysis   INTEROIL CORPORATION   23

Quarterly variance ($ millions)
$383.7	Variance for the comparative period primarily due to:
Ø $401.3	Receipt of a $401.3 million SPA completion payment from Total in accordance with the Total SSA.
Ø ($64.3)	Increase in cash outflows on exploration and development expenditures mainly due to the increased drilling activities and transaction costs associated with the completion of the Total SSA.
Ø $5.7	Higher cash calls and related inflows from joint venture partners relating to the receipt of funds from PRE for historical Triceratops-2 well costs and the receipt of funds from Oil Search in relation to the Tagula seismic program.
Ø ($1.6)	Movements in expenditure on plant and equipment were mainly within the Downstream segment.  The expenditures incurred during the quarter were mainly associated with tanks and upgrade projects across fuel stations, terminals and depots.
Ø ($18.4)	The net cash outflow of $8.3 million (March 31, 2013 - net cash inflow of $10.1 million) was mainly due to a $12.0 million increase in cash deposit restricted by BNP for the letters of credit issued as security for a rig lease and services agreement and partly offset by a $3.7 million decrease of cash deposit on working capital facility.
Ø $61.0	Movement in non-operating working capital for the quarter relating to trade payable and accruals in our Upstream operations.

Analysis of Cash Flows Generated From Financing Activities Comparing the Quarters Ended March 31, 2014 and 2013

This table outlines key variances in cash inflows from financing activities between quarters ended March 31, 2014 and 2013:

	Quarterly variance ($ millions)
	$12.1	Variance for the comparative period primarily due to:
Ø	$50.0	Drawdown of $50.0 million from Credit Suisse syndicated secured loan during the quarter ended March 31, 2014.
Ø	($76.0)	Receipt of a $76.0 million staged cash payment from PRE for the sale of a 10.0% net (12.9% gross) participating interest in PPL 237 (now PPL 475) during the quarter ended March 31, 2013.
Ø	$36.3	Movement in utilization of the BNP working capital facility relates to movement in working capital requirements.
Ø	$1.7	Movements were due to cash receipts from the exercise of stock options during the quarter ended March 31, 2014.

Capital Expenditure

Upstream Capital Expenditure

Capital expenditures for our Upstream segment in Papua New Guinea for the quarter ended March 31, 2014 were $125.2 million, compared with $34.3 million during the same period of 2013.

Management Discussion and Analysis   INTEROIL CORPORATION   24

This analysis outlines key expenditure in the quarter ended March 31, 2014:

	Quarterly ($ millions)
	$125.2	Expenditure in the quarter ended March 31, 2014 primarily due to:
Ø	$12.0	Costs for site preparation, pre-spud work and drilling of the Raptor-1 well.
Ø	$7.3	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 well.
Ø	$7.8	Costs for site preparation, pre-spud work and drilling of the Bobcat-1 well.
Ø	$44.8	Costs incurred for financial advisor fees and transaction costs for the monetization of the Elk and Antelope fields.
Ø	$41.5	Premium paid on buyback of 1.0536% indirect participation interest in PRL 15.
Ø	$3.9	Seismic over the Antelope field in PRL 15.
Ø	$0.6	Seismic over the Triceratops field in PPL 237 (now PPL 475).
Ø	$7.3	Other expenditure, including equipment purchases and drilling inventory.

Midstream – Refining Capital Expenditure

Capital expenditure totaled $0.8 million in our Midstream - Refining segment for the quarter ended March 31, 2014, and included upgrades to the CRU, boiler and mercury removal project.

Downstream Capital Expenditure

Capital expenditure for the Downstream segment totaled $3.7 million for the quarter ended March 31, 2014 and mostly involved upgrades to fuel stations, terminals and depots.

Capital Requirements

Oil and gas exploration and development, refining and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when 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 with market volatility.

Most of our “net cash from operating activities” adjusted for “proceeds from/(repayments of) working capital facilities” is used in exploration programs; and appraisal and development programs for the Elk, Antelope, and Triceratops fields in Papua New Guinea. Net cash from operating activities is not sufficient to fund those exploration, appraisal and development programs, or the construction of any new LNG plant.

Upstream

On March 6, 2014, the applications for new petroleum prospecting licenses were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238. The work program commitments under the new licenses require us to spend a further $485.0 million over the remainder of the six year term of the new licenses.

In addition, we are required to spend a further $41.7 million on development of the Elk and Antelope fields in PRL 15 by the end of 2014. All work program commitments with the exception of two wells and some additional exploration seismic, are complete. We are also required to spend $66.4 million on development of the Triceratops field in PRL 39 by the end of 2018. Minimal work on this commitment has been completed as at March 31, 2014.

Management Discussion and Analysis   INTEROIL CORPORATION   25

We do not have sufficient funds to complete planned exploration and development in our licenses and will need to raise additional funds to complete programs and meet our exploration commitments. Therefore, we must extend or secure sufficient funding through renewed borrowings, equity raising and/or asset sales to raise cash to meet these obligations and complete these long-term plans. No assurances can be given that we will obtain new capital on terms acceptable to us, or at all. The availability and cost of financing depends on market conditions and our condition at the time we raise capital. We can provide no assurances that we will be able to obtain financing or complete sales on terms that are acceptable.

Midstream - Refining

We believe we will have sufficient funds from operations to pay our estimated capital expenditures associated with our Midstream - Refining segment in 2014. We also believe cash flows from operations will be sufficient to cover refinery costs and financing charges under our crude import facility. Should there be long-term deterioration in refining margins, our refinery may not generate sufficient cash 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.

Downstream

On the basis of current market conditions and the status of our business, we believe that our cash flows from operations will be sufficient to meet our estimated capital expenditure for our wholesale and retail distribution business segment for 2014. Should there be a major long-term deterioration in wholesale or retail margins, our Downstream operations may not generate sufficient cash 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.

Contractual Obligations and Commitments

This table contains information on payments to meet our contracted exploration and debt obligations for each of the next five years and beyond. It should be read in conjunction with our Condensed Consolidated Interim Financial Statements and 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		593,022		85,059		124,175		93,275		94,963		97,775		97,775
Secured and unsecured loans		267,639		206,262		23,461		26,022		11,894		-		-
2.75% Convertible notes obligations		73,206		1,925		71,281		-		-		-		-
Total		933,867		293,246		218,917		119,297		106,857		97,775		97,775

The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed on these licenses as at March 31, 2014. On March 6, 2014, our applications for new petroleum prospecting licenses were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238 and included new license commitments. The new commitments require us to spend a further $485.0 million over the remainder of their six year term. The three wells, Wahoo-1, Raptor-1 and Bobcat-1, are being drilled under the new licenses, and are part of the new drilling commitments.

Further, the terms of the grant of PRL 15 require us to spend a further $41.7 million on the development of the Elk and Antelope fields by the end of 2015 and terms of the grant of PRL 39 requires us to spend a further $66.4 million on the license area by the end of 2018.

Management Discussion and Analysis   INTEROIL CORPORATION   26

Off Balance Sheet Arrangements

Neither during the quarter ended, nor as at March 31, 2014, 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, 2014, former Chief Financial Officer, Collin Visaggio, and former Chief Operating Officer, William Jasper, retired.  Compensation paid or payable to these officers upon their retirement was $1.3 million and $0.65 million, respectively.

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, 2014, we had 50,022,600 common shares issued and outstanding (51,346,931 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 31, 2014 included employee stock options and restricted stock in respect of 592,327 common shares and 732,004 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

As of May 14, 2014, we had 50,027,411 common shares (51,376,722 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at May 14, 2014 included employee stock options and restricted stock in respect of 617,307 common shares and 732,004 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 feedstock can be volatile and can fluctuate as a result of relatively small changes in supplies, weather, 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, its arrival at the refinery, and the supply of finished products to markets.

Generally, we buy crude feedstock two months in advance of it being discharged, processed and supplied or exported as finished product. Due to price fluctuations in this period, we use derivatives to reduce the risk of changes in the relative prices of our crude feedstock and refined products. These derivatives enable us to lock-in the refinery margin so we are protected from differences between our sale price of refined product and the acquisition price of our crude feedstock. 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 feedstock expands or increases, then the benefits would be limited to the locked-in margin.

The derivatives we generally use are over-the-counter swaps with credit worthy counterparties. It is common for refiners and trading companies in the Asia Pacific to use swaps to hedge their price exposures and margins, which means the swaps market is generally sufficiently liquid for hedging and risk management. Swaps cover commodities or products such as jet and kerosene, diesel, naphtha, and bench-mark crudes such as DTD Brent, Tapis and Dubai.

At March 31, 2014, we had a net receivable position of $0.1 million (March 31, 2013 – net receivable of $0.4 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. The swaps that have been priced out as of March 31, 2014 will be settled in future.

Management Discussion and Analysis   INTEROIL CORPORATION   27

RISK FACTORS

Our business operations and financial position are subject to risks. A summary of the key risks that may affect matters addressed in this document have been included under “Forward Looking Statements” above. Detailed risk factors can be found under “Risk Factors” in our 2013 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, 2014, there were no changes in the critical accounting estimates disclosed in our annual management discussion and analysis for the year ended December 31, 2013.

However, we would like to highlight that we have a total of approximately $400.7 million in temporary differences and carried forward losses for exploration expenditure in Papua New Guinea. No deferred tax assets have been recognized for this exploration expenditure as at March 31, 2014. The initial tax benefit to be recognized would be 30% of the temporary differences and losses carried forward through the income statement. We will consider recognition of the deferred tax assets when we have more certainty around the timing of assessable income in the Upstream segment.

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, 2013, available at www.sedar.com, which summarizes our significant accounting policies.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at March 31, 2014

These new standards have been issued but are not yet effective for the financial year beginning January 1, 2014 and have not been early adopted:

- IFRS 9 ‘Financial Instruments’ (effective from January 1, 2018): This addresses the classification and measurement of financial assets. The standard is not applicable until January 1, 2018 but is available for early adoption. We have yet to assess IFRS 9’s full impact, but we do not expect any material changes due to this standard. We have not yet decided whether to early adopt IFRS 9.

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”. This table reconciles sales and operating revenues, a GAAP measure, to gross margin.

Management Discussion and Analysis   INTEROIL CORPORATION   28

Consolidated – Operating results	Quarter ended March 31,
($ thousands)	2014			2013
Midstream – Refining		249,305			305,169
Downstream		211,069			207,644
Corporate		7,912			6,962
Consolidation Entries		(160,063	)		(170,451	)
Sales and operating revenues		308,223			349,324
Midstream – Refining		(226,623	)		(285,301	)
Downstream		(197,395	)		(193,390	)
Corporate (1)		(6,703	)		(5,657	)
Consolidation Entries		160,007			169,589
Cost of sales and operating expenses		(270,714	)		(314,759	)
Midstream – Refining		22,682			19,868
Downstream		13,674			14,254
Corporate (1)		1,209			1,305
Consolidation Entries		(56	)		(862	)
Gross Margin		37,509			34,565

(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.

This 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	2014			2013												2012
($ thousands)	Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30
Upstream		324,380			(19,974	)		(2,842	)		(19,478	)		(1,311	)		(873	)		956			(5,730	)
Midstream – Refining		5,988			10,246			(3,562	)		840			12,701			12,370			13,417			(42,647	)
Midstream – Liquefaction		(63	)		87			2,550			19,850			(123	)		192			11			672
Downstream		10,141			14,366			14,962			7,542			10,062			12,258			9,275			11,102
Corporate		2,223			6,055			13,446			1,745			10,044			14,133			9,841			9,975
Consolidation Entries		(9,375	)		(16,082	)		(14,647	)		(11,146	)		(13,418	)		(12,199	)		(14,503	)		(9,871	)
Earnings before interest, taxes, depreciation and amortization		333,294			(5,302	)		9,907			(647	)		17,955			25,881			18,997			(36,499	)
Subtract:
Upstream		(13,036	)		(13,056	)		(12,814	)		(12,043	)		(11,941	)		(11,734	)		(11,438	)		(10,517	)
Midstream – Refining		(2,223	)		(2,417	)		(2,351	)		(2,235	)		(2,454	)		(11,390	)		(1,654	)		(2,011	)
Midstream – Liquefaction		(492	)		(517	)		(177	)		(566	)		(558	)		(586	)		(584	)		(579	)
Downstream		(557	)		(531	)		(536	)		(263	)		(422	)		(337	)		(394	)		(909	)
Corporate		(1,466	)		(1,408	)		(1,842	)		(2,081	)		(1,600	)		(1,601	)		(1,540	)		(1,535	)
Consolidation Entries		11,548			13,103			12,989			12,677			12,642			12,552			12,482			12,044
Interest expense		(6,226	)		(4,826	)		(4,731	)		(4,511	)		(4,333	)		(13,096	)		(3,128	)		(3,507	)
Upstream		(250	)		-			-			-			-			-			-			-
Midstream – Refining		131			(4,476	)		(1,736	)		(118	)		(1,270	)		16,574			(3,484	)		14,580
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(2,308	)		(3,411	)		(3,804	)		(1,667	)		(2,455	)		(3,070	)		(1,791	)		(2,907	)
Corporate		(526	)		(950	)		108			(483	)		(196	)		(1,330	)		177			535
Consolidation Entries		-			-			-			-			-			-			-			-
Income taxes		(2,953	)		(8,837	)		(5,432	)		(2,268	)		(3,921	)		12,174			(5,098	)		12,208
Upstream		(527	)		(505	)		(550	)		(525	)		(522	)		(474	)		(454	)		715
Midstream – Refining		(3,295	)		(3,279	)		(3,425	)		(3,162	)		(3,122	)		(4,153	)		(2,921	)		(2,891	)
Midstream – Liquefaction		-			-			-			-			-			-			-			-
Downstream		(1,263	)		(1,187	)		(1,187	)		(1,266	)		(1,180	)		(1,135	)		(1,464	)		(1,241	)
Corporate		(915	)		(910	)		(932	)		(882	)		(906	)		(683	)		(629	)		(530	)
Consolidation Entries		521			33			32			31			32			31			33			32
Depreciation and amortisation		(5,479	)		(5,848	)		(6,062	)		(5,804	)		(5,698	)		(6,414	)		(5,435	)		(3,915	)
Upstream		310,567			(33,535	)		(16,206	)		(32,046	)		(13,774	)		(13,081	)		(10,936	)		(15,532	)
Midstream – Refining		601			74			(11,074	)		(4,675	)		5,855			13,401			5,358			(32,969	)
Midstream – Liquefaction		(555	)		(430	)		2,373			19,284			(681	)		(394	)		(573	)		93
Downstream		6,013			9,237			9,435			4,346			6,005			7,716			5,626			6,045
Corporate		(684	)		2,787			10,780			(1,701	)		7,342			10,519			7,849			8,445
Consolidation Entries		2,694			(2,946	)		(1,626	)		1,562			(744	)		384			(1,988	)		2,205
Net profit/(loss) per segment		318,636			(24,813	)		(6,318	)		(13,230	)		4,003			18,545			5,336			(31,713	)

Management Discussion and Analysis   INTEROIL CORPORATION   30

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2013 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 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, 2013 for the foregoing purposes.

While our Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures provide reasonable 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, 2013, for the foregoing purpose.

No material change in our internal controls over financial reporting were identified during the three months ended March 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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

Management Discussion and Analysis   INTEROIL CORPORATION   31