Exhibit 99.1

InterOil Corporation Management Discussion and Analysis   For the quarter ended March 31, 2015 May 12, 2015  

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	3
OIL AND GAS DISCLOSURES	4
GLOSSARY OF TERMS	4
INTRODUCTION	6
BUSINESS STRATEGY	6
OPERATIONAL HIGHLIGHTS	7
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	9
DISCOUNTINUED OPERATIONS	14
LIQUIDITY AND CAPITAL RESOURCES	14
RISK FACTORS	17
CRITICAL ACCOUNTING ESTIMATES	18
NEW ACCOUNTING STANDARDS	18
NON-GAAP MEASURES AND RECONCILIATION	18
PUBLIC SECURITIES FILINGS	19
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	19

This MD&A (as defined herein) should be read in conjunction with our Condensed Consolidated Interim Financial Statements (as defined herein) and accompanying notes, the Consolidated Financial Statements (as defined herein) and 2014 AIF (as defined herein). This MD&A was prepared by management and provides a review of our performance for the quarter ended March 31, 2015, 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.

In this MD&A, references to “we,” “us,” “our,” “the Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information is presented in this MD&A as at March 31, 2015 and for the quarter ended March 31, 2015 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this MD&A.

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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 and anticipated timing of our exploration and appraisal (including drilling plans) and other business activities and results therefrom; anticipated timing of certain well testing and resource certifications under the Total SSA (as defined herein); characteristics of our properties; construction and development of a proposed liquefaction 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 (as defined herein) 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;

· we will be transitioning the operatorship of PRL 15 (as defined here in) to Total (as defined herein) in accordance with the provisions of the JVOA (as defined herein);

· the difficulties with recruitment and retention of qualified personnel; 

· 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 exploration and production businesses are competitive;

· the 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;

· weather conditions and unforeseen operating hazards;

· compliance with environmental and other government regulations could be costly and could negatively impact our business;

· general economic conditions, including further economic downturn, availability of credit, European sovereign debt-credit crisis, downgrading of United States government debt and the decline in commodity prices;

· 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 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 2014 AIF.

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	mmcf	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.

(2) Tcfes may be misleading, particularly if used in isolation. A Tcfe conversion ratio of one barrel of oil to six thousand cubic feet of gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CONVERSION

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

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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 (as defined herein), 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, 2014 in accordance with NI 51-101. This evaluation is summarized in our 2014 AIF 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, 2015.

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.

GLOSSARY OF TERMS

“2014 AIF” means InterOil’s Annual Information Form for the year ended December 31, 2014.

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

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

“Board” means the board of directors of InterOil.

“BP” means BP (formerly known as British Petroleum) or a subsidiary or affiliate of that company.

“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.

“Condensed Consolidated Interim Financial Statements” means the unaudited condensed consolidated interim financial statements for the quarter ended March 31, 2015.

“Consolidated Financial Statements” means the audited consolidated financial statements for the years ended December 31, 2014, 2013 and 2012.

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

“Credit Suisse” means Credit Suisse A.G.

"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 the Department of Petroleum and Energy, a PNG government department responsible for regulating oil and gas activities in PNG.

“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”.

“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. Gas may contain sulfur or other non-hydrocarbon compounds.

“GCA” means Gaffney Cline & Associates who is a recognized certifier under the Total SSA.

“JVOA” means Joint Venture Operating Agreement.

“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 proposed development by us of liquefaction facilities in Papua New Guinea with potential partners, including Total and the State.

“Macquarie” means Macquarie Group Limited.

“MD&A” means this Management’s Discussion and Analysis for the quarter ended March 31, 2015.

“MUFG” means Bank of Tokyo-Mitsubishi UFJ, Ltd.

“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.

"PNG LNG" means PNG LNG, Inc., a joint venture company established in 2007 to hold the interests of certain joint venturers in the proposed venture to construct the proposed liquefaction facilities referred to in the LNG Project Agreement.

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“PNGDV” means PNG Drilling Ventures Limited, an entity with which we entered into an amended and restated indirect participation agreement on May 1, 2006.

“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.

“Puma” means Puma Energy Pacific Holdings Pte Ltd, a subsidiary of Trafigura, that focuses on midstream and downstream, oil businesses.

“Puma Transaction” means the transaction by which Puma acquired all of the shares of certain of our subsidiaries that held our refinery and petroleum products distribution businesses for approximately $524.6 million. The transaction was completed on June 30, 2014.

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

“SocGen” means Societe Generale Hong Kong branch.

“State” or “PNG” 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 SSA” means the share purchase 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. This agreement replaced the Total SPA on March 26, 2014.

“UBS” means UBS A.G.

“Westpac” means Westpac Bank PNG Limited.

INTRODUCTION

We are an independent upstream oil and gas business with a sole focus on PNG. Our assets include licenses covering the Elk, Antelope and Triceratops fields and, Raptor and Bobcat discoveries in the Gulf Province of PNG, and exploration licenses covering about 16,000 square kilometers (about 4 million acres) in PNG. We have our main offices in Singapore and Port Moresby. We are listed on the New York Stock Exchange and the Port Moresby Stock Exchange. At March 31, 2015, we had 352 full-time employees.  

BUSINESS STRATEGY

Our strategy is to unlock significant value to shareholders by finding oil and gas safely and competitively; enable its development through the right partnerships, funding and project development capability; and to repeat this process. Running an effective and efficient business is the core component of this strategy. This business model is founded on exploration and drilling discipline and success, strong commercial and project development acumen and being a “partner of choice”. The focus areas for our strategy are to:

- Continue to develop as a prudent and responsible business operator;

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- Enable our discovered resources with strategic joint venture partners;

- Maximize the value of our exploration assets; and

- Position for long-term success.

Further details of our business strategy can be found under the heading “Business Strategy” in our 2014 AIF available at www.sedar.com.

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

A summary of the key operational matters and events for the quarter for continuing operations is as follows:

· Airborne Field Survey

- On January 17, 2015, we commenced the acquisition of high resolution airborne Falcon gravity gradiometry over all our licenses. This survey is expected to be completed in the third quarter of 2015.

· Seismic

- The 2014 Murua Seismic Survey in PPL 474 commenced on November 1, 2014, with acquisition completed in March 2015. 

- In late 2014, we began planning and initial preparation for an appraisal seismic program over the Raptor discovery.  The Raptor seismic program commenced January 2015 and is currently underway, with expected completion in May 2015. 

- Appraisal seismic acquisition over the Bobcat discovery is also currently underway in conjunction with the Raptor program. The 2015 Bobcat Seismic Survey commenced in March 2015 with acquisition expected to be completed in June 2015.

- On April 15, 2015, the 2015 Triceratops Seismic Survey in PRL 39 commenced field production, with acquisition expected to be completed in July 2015.

- Further planning is now underway for possible seismic surveys in PPL 474 and PPL 476.  

· PPL 474 - Wahoo drilling program

- Wahoo-1 exploration well is about 170 kilometers southeast of our Elk and Antelope gas fields. On July 14, 2014, we announced that we had suspended drilling the Wahoo-1 well in PPL 474 after intersecting gas and higher-than expected pressures. The DPE approved this suspension to enable us to re-evaluate the drilling plan.

- The mobilization of crew to site is currently ongoing, and we intend to resume drilling in the second quarter of 2015.

· PPL 475 – Raptor drilling program

- Raptor-1 exploration well is about 12 kilometers west of our Elk and Antelope gas fields. On November 14, 2014, we notified the DPE of a discovery at the Raptor-1 well.

- We have started the appraisal seismic program as noted above, and will continue comprehensive planning of future Raptor appraisal work, which will include appraisal drilling and a comprehensive testing program.

· PPL 476 – Bobcat drilling program

- Bobcat-1 exploration well is about 30 kilometers northwest of our Elk and Antelope gas fields. In 2014, we notified the DPE of a discovery at the Bobcat-1 well. The well was further deepened in 2014 as the first part of the appraisal program to appraise reservoir quality.

- We have started the appraisal seismic program as noted above to further evaluate the commerciality of the field.

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· PRL 15 – Antelope-4, Antelope-5 and Antelope-6 drilling program

- On September 16, 2014, we spudded the Antelope-4 appraisal well. The Antelope-4 appraisal well intersected the top reservoir at 1,911 meters. During January 2015, a derrick structural member was noted as being slightly bowed outside tolerance. The repairs were carried out and drilling recommenced. The cores were cut in the upper part of the reservoir as planned, resulting in a recovery of 33 meters of dolomite. On April 27, 2015, we announced the suspension of the Antelope-4 appraisal well drilling at 2,134 meters. The PRL 15 Joint Venture is currently evaluating the information obtained from the well.

- On December 23, 2014, we spudded the Antelope-5 appraisal well. On February 16, 2015, we announced the Antelope-5 appraisal well had intersected the top reservoir at 1,534 meters. The well reached a total depth of 2,453 meters on February 24, 2015. We are currently continuing with the reservoir evaluation program, and we plan to conduct an extended well test at Antelope-5 with pressure gauges monitoring pressure drawdown in other appraisal wells.

- On April 27, 2015, we began flow testing at the Elk-Antelope gas field as part of the field appraisal.

- Site preparation and pre-spud of Antelope-6 appraisal well has commenced, with the current expectation that the well will be spudded in the third quarter of 2015.

· PRL 15 – Total SSA

- On February 27, 2015, all participants in PRL 15 unanimously voted to appoint Total as operator of the PRL 15 Joint Venture. The appointment will take effect in accordance with an operator transition plan and the terms of the JVOA. The appointment is subject to all necessary PNG government approvals.

- Progress continues with engineering and technical studies being conducted by Total towards concept selection (including selection of the location of the LNG Project) which is expected to be completed by June 2015. The early development work is expected to begin in 2016 and awarding of construction contracts is expected to take place in 2017.

· PRL 39 – Triceratops-3 appraisal well

- Site preparation and pre-spud (including mobilization of rig to site) is currently ongoing, with the well expected to be spudded in the second quarter of 2015.

· Financing

- On March 17, 2015, we signed an amendment to further extend the maturity date on the $300.0 million syndicated, senior secured capital expenditure facility to the end of 2016 with Credit Suisse, CBA, ANZ, UBS, Macquarie, BSP, Westpac, MUFG and SocGen participating in the extension.

· Other matters

- On January 1, 2015, Dr. Ellis Armstrong, former BP Group E&P - Chief Financial Officer, was appointed as a non-executive director. Dr. Armstrong has more than 30 years of international oil and gas experience covering strategy and operations, major integrations, acquisitions and disposals and government relations.

- On January 1, 2015, Ms. Katherine Hirschfeld, former Australasia BP Executive Director, was appointed as a non-executive director. Ms. Hirschfeld has board experience and international oil and gas experience covering oil refining, logistics, exploration and production in Australia, New Zealand, the United Kingdom and Turkey.

- On March 13, 2015, Mr. Yap Chee Keong, the current Chairman and non-executive independent director of CityNet Infrastructure Management Pte Ltd, was appointed as a non-executive director.  Mr. Yap is also a director of several Singapore based companies and also serves as a board member of the Accounting and Corporate Regulatory Authority and as a member of Singapore’s Public Accountants Oversight Committee. He replaced Mr. Samuel Delcamp as a director, who formally retired from the Board on March 12, 2015. 

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SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarter Ended March 31, 2015 and 2014

Consolidated – Operating results	Quarter ended March 31,
($ thousands, except per share data)	2015			2014
Interest revenue		11,412			53
Other		1,803			1,850
Total revenue		13,215			1,903
Adminstrative and general expenses		(6,354	)		(9,986	)
Legal and professional fees		(1,937	)		(2,345	)
Exploration costs, excluding exploration impairment		(19,261	)		(8,696	)
Finance costs, excluding interest expense		(6,671	)		(6,014	)
Gain on conveyance of exploration and evaluation assets		-			340,540
Foreign exchange gains		691			1,558
Share of net losses of joint venture partnership accounted for using the equity method		-			(11	)
EBITDA (1)		(20,317	)		316,949
Depreciation and amortization		(5	)		(1,440	)
Interest expense		(1,477	)		(4,170	)
(Loss)/profit for the period from continuing operations before income taxes		(21,799	)		311,339
Income tax expense		(70	)		(514	)
(Loss)/profit for the period from continuing operations		(21,869	)		310,825
Profit for the period from discontinued operations, net of tax		-			7,812
(Loss)/profit for the period		(21,869	)		318,637
Basic (loss)/earning per share		(0.44	)		6.46
From continuing operations		(0.44	)		6.30
From discontinued operations		0.00			0.16
Diluted (loss)/earnings per share		(0.44	)		6.38
From continuing operations		(0.44	)		6.22
From discontinued operations		0.00			0.16
Total assets		1,318,120			1,737,189
Total liabilities		307,685			641,605
Total long-term liabilities		96,000			218,783

Notes:

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

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Analysis Comparing Financial Condition as at March 31, 2015 and 2014

As at March 31, 2015, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 6%, compared to 22% as at March 31, 2014, 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 4.2 times as at March 31, 2015, compared to 1.7 times as at March 31, 2014. The current ratio satisfied our internal target of above 1.5 times as at March 31, 2015.

Variance in Total Assets:

As at March 31, 2015, our total assets amounted to $1,318.1 million, compared with $1,737.2 million as at March 31, 2014. The decrease of $419.1 million, or 24%, from March 31, 2014 was primarily due to:

- $177.5 million decrease in cash and cash equivalents and restricted cash, mainly attributable to the expenditure on exploration and evaluation assets incurred during the period.

- $33.4 million decrease in trade and other receivables mainly due to the timing/receipt of joint venture partners’ cash calls during the period.

- $17.5 million decrease in investments accounted for using equity method, which is attributable to our share of losses incurred by the PNG LNG joint venture resulting from the impairment of joint venture assets, as we are now progressing the LNG Project development jointly with Total.

- The Puma Transaction resulted in the decrease in plant and equipment by $232.8 million, inventories by $190.0 million and deferred tax assets by $48.6 million.

These decreases have been partially offset by:

- $284.7 million increase in exploration and evaluation assets, primarily associated with the drilling costs incurred for Wahoo-1 well in PPL 474, Triceratops-3 appraisal well in PRL 39 and Raptor-1 well in PPL 475, Bobcat-1 exploration well in PPL 476, Antelope-4 and Antelope-5 appraisal well in PRL 15.

Variance in Total Liabilities:

As at March 31, 2015, our total liabilities amounted to $307.7 million, compared with $641.6 million at March 31, 2014. The decrease of $333.9 million, or 52%, from March 31, 2014 was primarily due to:

- A decrease of $253.2 million in secured and unsecured loans payable due to the full repayment in June 2014 of the BSP and Westpac combined secured loan facility, the ANZ, BSP Paribas and BNP syndicated loan facility and the full repayment in April 2014 of the Credit Suisse led syndicated secured loan post receipt of the Total SSA completion payment.

- $48.0 million decrease in trade and other payables, mainly due to the sale of the refinery and distribution businesses; however, this decrease has partly been offset by the $58.3 million increase in seismic and drilling accruals as at March 31, 2015.

- The Puma Transaction also resulted in the decrease in working capital facilities by $12.7 million and income tax payable by $17.8 million.

Analysis of Consolidated Financial Results Comparing Quarter Ended March 31, 2015 and 2014

Our net loss for the quarter ended March 31, 2015 was $21.9 million, compared with a net profit of $318.6 million for the same quarter in 2014, a decrease of profit by $340.5 million, which primarily resulted from the recognition of the $340.5 million gain on conveyance of oil and gas properties in relation to the completion of the Total SSA during the quarter ended March 31, 2014.

The table below analyzes key movements, the net of which primarily explains the variance in results between the quarters ended March 31, 2015 and 2014:

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	Quarterly Variance ($ millions)
	($340.5)	Net (loss)/profit variance for the comparative periods primarily due to:
Ø	($340.5)	Gain on conveyance of exploration and evaluation assets in relation to the completion of the Total SSA recognized during the quarter ended March 31, 2014 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.
Ø	($7.8)	Decrease in profit from discontinued operations during first quarter of 2014.
Ø	$3.6	Decrease in administrative and general expenses was mainly due to the new cost methodology employed since the fourth quarter of 2014, whereby operational costs were allocated to exploration and evaluation assets, rather than a standard cost recharge process used prior to the change, which previously resulted in expensing of under recovered costs incurred for joint venture projects. A total of $1.8 million from the administrative and general expenses for the quarter ended March 31, 2015 was charged to Puma as other revenue for certain transition services provided post divestment. These transitional services mainly related to the computing and communications services and occupancy expenses in PNG.
Ø	$11.4	Increase in interest income was attributable to the interest accretion income on the receivables recognized in relation to interim resource payments expected under the Total SSA for the Elk and Antelope fields in accordance with the resource certification mechanics found in the Total SSA and the range of resources contemplated therein.
Ø	($10.6)	Increase in exploration costs primarily attributable to the expensing of seismic activities over the Murua lead in PPL 474 and exploration seismic over PPL 475, and airborne gravity survey costs incurred for PPL 476, PPL 477 and PRL 15.
Ø	$2.7	Decrease in interest expense was largely due to the non-utilization of the Credit Suisse led syndicated  facility during the quarter as compared to $150.0 million drawn under the facility in the prior year quarter.
Ø	$1.4	Decrease in depreciation expense due to capitalization of the depreciation relating to supporting assets to the respective projects undertaken during the quarter.  Depreciation in relation to assets supporting the exploration costs expensed has been included in the exploration costs line above.

Analysis of Consolidated Cash Flows Comparing Quarters Ended March 31, 2015 and 2014

As at March 31, 2015, we had cash, cash equivalents, and restricted cash of $304.7 million (March 31, 2014 - $482.2 million), of which $8.3 million (March 31, 2014 - $61.5 million) was restricted. Of the total restricted cash at March 31, 2015, $8.0 million was restricted as a debt reserve under the Credit Suisse led syndicated secured loan and the balance was made up of a cash deposit on office premises and term deposits on our PPLs.

Cash flows from discontinued operations have been combined with the cash flows from continuing operations in the consolidated statements of cash flows for the quarter ended March 31, 2014.

	Quarter ended March 31,
($ thousands)	2015			2014
Net cash (outflows)/inflows from:
Operations		(33,353	)		(15,244	)
Investing		(63,666	)		347,994
Financing		-			25,951
Net cash movement		(97,019	)		358,701
Opening cash		393,405			61,967
Closing cash		296,386			420,668

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Cash flows used in operating activities

Cash outflows from operating activities for the quarter ended March 31, 2015 were $33.4 million compared with an outflow of $15.2 million for the quarter ended March 31, 2014, a net increase in cash outflows of $18.2 million.

This table outlines key variances in the cash inflows/(outflows) from operating activities between the quarters ended March 31, 2015 and 2014:

	Quarterly variance ($ millions)
	($18.2)	Variance for the comparative periods primarily due to:
Ø	($19.8)	Increase in cash used in operations, prior to changes in operating working capital for the quarter, was mainly due to the increase in net loss from operations adjusted for the increased accretion income on receivable, gain on conveyance of PRL 15 pursuant to the Total SSA and a decrease in depreciation expense incurred during the current quarter ended March 31, 2015.
Ø	$1.6	Decrease in cash used in the operations relating to changes in operating working capital for the quarter was due to a $23.2 million increase in trade and other receivables, a $32.7 million decrease in inventories, a $7.6 million decrease in accounts payable and accrued liabilities, and a $0.3 million increase in other current assets and prepaid expenses.

Cash flows (used in)/generated from investing activities

Cash outflows from investing activities for the quarter ended March 31, 2015 were $63.7 million compared with an inflow of $348.0 million for the quarter ended March 31, 2014.

This table outlines key variances in cash (outflows)/inflows from investing activities between the quarters ended March 31, 2015 and 2014:

	Quarterly variance ($ millions)
	($411.7)	Variance for the comparative periods primarily due to:
Ø	($401.3)	Receipt of a $401.3 million completion payment from Total in accordance with the Total SSA during the quarter ended March 31, 2014.
Ø	($24.6)	Increase in cash outflows on exploration and development expenditures was mainly due to the site preparation and pre-spud costs for the Triceratops-3, Wahoo-1 Side Track and Antelope 6 well, and drilling costs incurred for the Antelope-4 and Antelope-5 wells.
Ø	$53.0	Higher cash calls and related inflows from joint venture partners relating to the receipt of cash called funds from PRE, Oil Search and Total during the quarter ended March 31, 2015.
Ø	$5.2	Movement in expenditure on plant and equipment was mainly due to the expenditures on discontinued operations (tank and upgrade projects) during the quarter ended March 31, 2014
Ø	$8.3	The reduction in restricted cash requirements held as security was mainly due to the transfer of restricted cash balances (and the associated working capital facilities) in relation to the BNP Paribas led working capital facilities as part of the Puma Transaction.
Ø	($53.0)	Movement in non-operating working capital was primarily related to trade payables and accruals in our exploration and development operations.

Management Discussion and Analysis INTEROIL CORPORATION    12

Cash flows generated from financing activities

Cash flow movement from financing activities for the quarter ended March 31, 2015 amounted to $Nil, compared with an inflow of $26.0 million for the quarter ended March 31, 2014.

This table outlines key variances in cash (outflows)/inflows from financing activities between quarters ended March 31, 2015 and 2014:

	Quarterly variance ($ millions)
	($26.0)	Variance for the comparative periods primarily due to:
Ø	$2.0	Net repayment of the BSP and Westpac combined secured loan facility during quarter ended March 31, 2014.
Ø	($50.0)	Drawdown of $50.0 million from the Credit Suisse led syndicated secured loan facility during the quarter ended March 31, 2014.
Ø	$23.7	Movement in utilization of the BNP Paribas working capital facility in our discontinued operations during March 31, 2014.
Ø	($1.7)	Movement due to cash receipts from the exercise of stock options during the quarter ended March 31, 2014.

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended March 31, 2015 on a consolidated basis.

Quarters ended ($ thousands except per share	2015			2014											2013
data)	Mar-31			Dec-31			Sep-30			Jun-30			Mar-31		Dec-31			Sep-30			Jun-30
Total revenues		13,215			(13,182	)		10,749			13,689			1,903		712			617			831
EBITDA (1)		(20,317	)		(60,443	)		(12,135	)		(10,252	)		316,949		(27,272	)		(99	)		(11,293	)
Net (loss)/profit		(21,869	)		(64,205	)		(16,931	)		52,266			318,637		(24,812	)		(6,318	)		(13,230	)
From continuing operations		(21,869	)		(62,474	)		(14,622	)		(15,764	)		310,825		(32,024	)		(3,555	)		(15,240	)
From discontinued operations		-			(1,731	)		(2,309	)		68,030			7,812		7,212			(2,763	)		2,010
Basic (loss)/earnings per share		(0.44	)		(1.30	)		(0.34	)		1.05			6.46		(0.50	)		(0.13	)		(0.27	)
From continuing operations		(0.44	)		(1.26	)		(0.29	)		(0.31	)		6.30		(0.65	)		(0.07	)		(0.31	)
From discontinued operations		-			(0.04	)		(0.05	)		1.36			0.16		0.15			(0.06	)		0.04
Diluted (loss)/earnings per share		(0.44	)		(1.30	)		(0.34	)		1.05			6.38		(0.50	)		(0.13	)		(0.27	)
From continuing operations		(0.44	)		(1.26	)		(0.29	)		(0.31	)		6.22		(0.65	)		(0.07	)		(0.31	)
From discontinued operations		-			(0.04	)		(0.05	)		1.36			0.16		0.15			(0.06	)		0.04

(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

DISCOUNTINUED OPERATIONS

We had previously organized our operations into four major segments - Upstream, Midstream, Downstream and Corporate. On June 30, 2014, we disposed of our Midstream Refining and Downstream businesses in connection with the Puma Transaction and as a result, these businesses have been classified as discontinued operations for reporting purpose. In addition, the shipping business which was previously included within the Corporate segment has also been classified as a discontinued operation as the activities previously carried out by that business have been transferred with the sale of the refining and distribution businesses. At March 31, 2015, no additional discontinued operations have been recognized.

Further details in relation to discontinued operations can be found under the heading “Discontinued Operations” in our 2014 AIF available at www.sedar.com.

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, 2015:

Organization	Facility		Balance outstanding March 31, 2015		Weighted average interest rate			Maturity date
Credit Suisse led syndicated, senior secured capital expenditure facility	$	300,000,000	$	Nil		Nil	%	December 2016
Convertible Notes	$	70,000,000	$	69,998,000		7.91	%(1)	November 2015

(1) Effective rate after bifurcating the equity and debt components of the $70.0 million principal amount of 2.75% convertible senior notes due 2015.

Credit Suisse led Syndicated Secured Loan

On June 17, 2014, we replaced our $250.0 million syndicated loan led by Credit Suisse with a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. CBA, ANZ, UBS, Macquarie, BSP, BNP Paribas and Westpac, each of which was a participating lender under the original facility, in addition to new banks, MUFG and SocGen, support the facility. The facility had an annual interest rate of LIBOR plus 5% and was to mature at the end of 2015.

On March 17, 2015, we signed an amendment to further extend the maturity date on this facility to the end of 2016 with Credit Suisse, CBA, ANZ, UBS, Macquarie, BSP, Westpac, MUFG and SocGen participating in the extension. No drawdowns have been made under this facility as at March 31, 2015. As at March 31, 2015, we are in compliance with the applicable debt covenants, which included a defined calculation for gearing not to exceed 60% at any time, and the equity does not fall below $500 million at any time.

Unsecured 2.75% Convertible Notes

On November 10, 2010, we completed the issuance of $70.0 million of Convertible Notes with a maturity of five years (November 10, 2015). The Convertible Notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the Credit Suisse led syndicated secured loan facility, trade payables and lease obligations.

We pay interest on the Convertible Notes semi-annually on May 15 and November 15. The Convertible Notes are convertible into cash or our 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 Convertible 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.

Management Discussion and Analysis INTEROIL CORPORATION    14

Only $2,000 of the Convertible Notes have been converted into cash since issuance.

Other Sources of Capital

Our share of expenditures on exploration wells, appraisal wells and extended well programs is funded by capital raising activities, debt, cash calls from joint venture partners and asset sales.

Cash calls are made on Total, Oil Search and PNGDV for their share and carry (where applicable) of expenditure on appraisal wells and extended well programs under agreements we have with them. Cash calls will also be made on PRE for exploration activities in PPL 475 and appraisal activities in the Triceratops field.

Capital Expenditure

Net expenditure on exploration and evaluation assets

Net capital expenditures on our exploration and evaluation assets in PNG for the quarter ended March 31, 2015 were $57.8 million.

This analysis outlines key net expenditures in the quarter ended March 31, 2015:

	Quarterly movement ($ millions)
	$325.0		Opening balance of exploration and evaluation assets
	$57.8		Net capital expenditure consisting of following:
Ø	($1.2	)	True up of costs for drilling and testing of the Raptor-1 well.
Ø	$1.3		Costs for care and maintenance of the suspended Wahoo-1 well.
Ø	$1.3		Costs for site preparation and pre-spud work of the Wahoo side track well.
Ø	$8.1		Costs for testing of the Bobcat-1 well.
Ø	$8.1		Costs for site preparation and pre-spud work for the Triceratops-3 well.
Ø	$7.9		Costs for drilling of the Antelope-4 well.
Ø	$7.3		Costs for drilling of the Antelope-5 well.
Ø	$1.4		Costs for site preparation, pre-spud work and rig standby costs of the Antelope-6 well.
Ø	$8.8		Appraisal seismic over the Raptor field.
Ø	$1.6		Appraisal seismic over the Bobcat and Triceratops field.
Ø	$1.8		Expenditure on drilling inventory.
Ø	$7.4		Expenditure relating to concept select studies led by Total for PRL 15.
Ø	$4.0		Other expenditures, including equipment purchases, site preparation costs of the Antelope South well, and a portion of the Antelope-4, Antelope-5 and Antelope-6 and Antelope South well costs that have been carried by Total but included in our net share of costs as the carry has been offset against the interim resource payment receivable from Total under Total SSA.
	$382.8		Closing balance of exploration and evaluation assets

Management Discussion and Analysis INTEROIL CORPORATION    15

Gross expenditure on exploration and evaluation assets

Gross capital expenditures on our exploration and evaluation assets in PNG for the quarter ended March 31, 2015 was $129.0 million.

This analysis outlines key gross expenditures in the quarter ended March 31, 2015:

	Quarterly movement ($ millions)
	$129.0		Gross capital expenditure consisting of following:
Ø	($1.6	)	True up of costs for drilling and testing of the Raptor-1 well.
Ø	$8.7		Appraisal seismic over the Raptor field.
Ø	$1.3		Costs for care and maintenance of the suspended Wahoo-1 well.
Ø	$1.3		Costs for site preparation and pre-spud work of the Wahoo side track well.
Ø	$10.2		Costs for testing of the Bobcat-1 well.
Ø	$1.6		Appraisal seismic over the Bobcat and Triceratops field.
Ø	$11.9		Costs for site preparation and pre-spud work for Triceratops-3 well.
Ø	$22.8		Costs for drilling of the Antelope-4 well.
Ø	$40.3		Costs for drilling of the Antelope-5 well.
Ø	$6.8		Costs for site preparation, pre-spud work and rig standby costs of the Antelope-6 well.
Ø	$0.9		Costs for site preparation of the Antelope South well.
Ø	$1.8		Expenditure on drilling inventory.
Ø	$20.1		Expenditure relating to concept select studies led by Total for PRL 15.
Ø	$2.9		Other expenditure, including equipment and asset purchases.

Capital Requirements

Existing cash balances will be sufficient to settle debt obligations and facilitate further development of the Elk and Antelope fields, appraisal of Triceratops field and exploration activities planned to meet our license commitment requirements. However, oil and gas exploration and development and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when we raise such capital. Additionally, our joint venture share of the costs of construction of an liquefaction plant and other infrastructure associated with the proposed liquefaction plant may amount to hundreds of millions of dollars and thus exceed our existing cash balances. 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.

Management Discussion and Analysis INTEROIL CORPORATION    16

Noted below are our contractual obligations and commitments over the next five years which are required at a minimum to maintain our licenses in good standing.

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, Consolidated Financial Statements and respective 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		404,665		40,025		89,525		87,952		97,650		89,513		-
Convertible Notes obligations		71,281		71,281		-		-		-		-		-
Total		475,946		111,306		89,525		87,952		97,650		89,513		-

The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed on these licenses as at March 31, 2015. 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 $359.0 million over the remainder of their six year term.

Further, the terms of grant of PRL 39 requires us to spend $45.6 million on the license area by the end of 2018.

Off Balance Sheet Arrangements

Neither during the quarter ended, nor as at March 31, 2015, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

No related party transaction took place during the quarter ended March 31, 2015.

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, 2015, we had 49,510,114 common shares issued and outstanding (50,740,867 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 31, 2015 included employee stock options and restricted stock in respect of 498,749 common shares and 732,004 common shares relating to the $70.0 million of Convertible Notes.

As of May 7, 2015, we had 49,510,114 common shares issued and outstanding (50,790,552 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at May 7, 2015 included employee stock options and restricted stock in respect of 548,434 common shares and 732,004 common shares relating to the $70.0 million of Convertible Notes.

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 2014 AIF available at www.sedar.com.

Management Discussion and Analysis INTEROIL CORPORATION    17

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, 2015, there were no changes in the critical accounting estimates disclosed in our 2014 MD&A.

For a discussion of those accounting policies, please refer to Note 2 of the notes to our Consolidated Financial Statements for the year ended December 31, 2014, available at www.sedar.com, which summarizes our significant accounting policies.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at March 31, 2015

These new standards have been issued but are not yet effective for the financial year beginning January 1, 2015 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.

– IFRS 14 ‘Regulatory deferral accounts’ (effective from January 1, 2016): This standard permits first-time adopters to continue to recognize amounts related to rate regulation in accordance with their previous GAAP requirements when they adopt IFRS. However, the effect of rate regulation must be presented separately from other items. This standard will have no impact on InterOil.

– IFRS 15 ‘Revenue from contracts with customers’ (effective from January 1, 2017): The new standard is based on the principle that revenue is recognized when control of a good or service transfers to a customer, so the notion of control replaces the existing notion of risks and rewards. We are currently evaluating the impact of adopting this standard.

NON-GAAP MEASURES AND RECONCILIATION

Non-GAAP measures, including 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.

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 (loss)/profit from continuing operations, a GAAP measure, to EBITDA from continuing operations, a non-GAAP measure for each of the last eight quarters.

Management Discussion and Analysis INTEROIL CORPORATION    18

Quarters ended	2015			2014												2013
($ thousands)	Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30
Earnings before interest, taxes, depreciation and amortization		(20,317	)		(60,443	)		(12,135	)		(10,252	)		316,949			(27,272	)		(99	)		(11,293	)
Interest expense		(1,477	)		(1,464	)		(1,367	)		(4,409	)		(4,170	)		(2,546	)		(2,212	)		(2,082	)
Income taxes		(70	)		(211	)		(198	)		(195	)		(514	)		(791	)		239			(458	)
Depreciation and amortisation		(5	)		(356	)		(922	)		(908	)		(1,440	)		(1,415	)		(1,483	)		(1,407	)
From continuing operations		(21,869	)		(62,474	)		(14,622	)		(15,764	)		310,825			(32,024	)		(3,555	)		(15,240	)
From discontinued operations		-			(1,731	)		(2,309	)		68,030			7,812			7,212			(2,763	)		2,010
Net (loss)/profit		(21,869	)		(64,205	)		(16,931	)		52,266			318,637			(24,812	)		(6,318	)		(13,230	)

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2014 AIF, 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. SEC 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, 2014 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, 2014, for the foregoing purpose.

Management Discussion and Analysis INTEROIL CORPORATION    19

Material Changes in Internal Control over Financial Reporting

No material change in our internal controls over financial reporting were identified during the quarter ended March 31, 2015, 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    20