Exhibit 3

InterOil Corporation
Management
Discussion and Analysis
For the year ended December 31, 2015
March 30, 2016

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	7
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	12
DISCOUNTINUED OPERATIONS	20
LIQUIDITY AND CAPITAL RESOURCES	20
INDUSTRY TRENDS AND KEY EVENTS	25
RISK FACTORS	26
CRITICAL ACCOUNTING ESTIMATES	26
NEW ACCOUNTING STANDARDS	27
NON-GAAP MEASURES AND RECONCILIATION	27
PUBLIC SECURITIES FILINGS	28
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	28

This MD&A (as defined herein) should be read in conjunction with our Consolidated Financial Statements (as defined herein) and our 2015 AIF (as defined herein). This MD&A was prepared by management and provides a review of our performance for the year ended December 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 December 31, 2015 and for the quarter and year ended December 31, 2015 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 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 and central processing facility 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:

· our financial condition may be adversely affected if there are long term declines in oil and natural gas prices;  

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

· our limited sources of revenue;

· 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;

· risks associated with the transition of our operatorship of PRL 15 to Total;

· 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 and the decline in commodity prices, including hydrocarbon commodity prices;

· risk of legal action against us;

· law enforcement difficulties; and

· dilution of our common shares.

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.

Management Discussion and Analysis INTEROIL CORPORATION 2

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 2015 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
MMboe	thousand barrels of oil equivalent	MMcf	million standard cubic feet
Mbbl	thousand barrels	MMcfpd	million standard cubic feet per day
MMbbls	million barrels
MMboe	million barrels of oil equivalent	scfpd	standard cubic feet per day
MMstb	millions of stock tank barrels	Tcfe(2)	trillion standard cubic feet equivalent
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma	psi	pounds per square inch
bscf	billion standard cubic feet

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’s 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)

Tcfe’s 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.

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 the 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 have evaluated our resources data for the Elk and Antelope field and Triceratops field; and RISC Operations Pty Limited, an independent qualified reserve evaluator based in Perth, Australia have evaluated our resources data for the Raptor and Bobcat fields as at December 31, 2015 in accordance with NI 51-101. These evaluations are summarized in our 2015 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 defined herein), as at December 31, 2015.

Well flow test results are not necessarily indicative of long-term performance or of ultimate recovery.

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

“2015 AIF” means InterOil’s Annual Information Form for the year ended December 31, 2015.

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

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

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

“BSP” means Bank of South Pacific Limited.

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“CBA” means Commonwealth Bank of Australia.

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

“Consolidated Financial Statements” means the audited consolidated financial statements for the years ended December 31, 2015, 2014 and 2013.

“Convertible Notes” means our 2.75% convertible senior notes which matured on November 15, 2015 and were fully paid on the same day.

"Contingent Resources" are those quantities of natural gas and condensate estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.  The economic status of the resources is undetermined and there is no certainty that it will be commercially viable to produce any portion of the resources. 

“conventional natural gas” means natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized, structural, depositional or erosional geological features.

“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”.

“Farm-In Agreement” means the Farm-In Agreement dated July 27, 2012 between us and PRE.

“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, an independent qualified reserves evaluator.

“GLJ” means GLJ Petroleum Consultants Limited, an independent qualified reserves evaluator.

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

“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, as amended.

“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.

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“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.

“Macquarie” means Macquarie Group Limited.

“MD&A” means this Management’s Discussion and Analysis for the year ended December 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.

“natural gas liquids” means those hydrocarbon components that can be recovered from natural gas as a liquid including, but not limited to, ethane, propane, butanes, pentanes plus and condensates.

“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 PNG, and its subsidiaries.

“PacLNG” means with Pacific LNG Operations Ltd., an affiliate of Clarion Finanz A.G.

“Papua LNG Project” means the Elk-Antelope liquefied natural gas joint venture project operated by Total on behalf of the PRL 15 joint venture, which includes Total, Oil Search and us.

“PGK” means the kina, currency of PNG.

“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 Exploration and Production Corporation (formerly Pacific Rubiales Energy Corporation), 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.

“PRL 15 Joint Venture” means the current license holders in respect of PRL 15 and parties to the Elk / Antelope JVOA, dated September 26, 2013 (as amended and restated).

“Puma” means Puma Energy Pacific Holdings Pte Ltd.

“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.

“RISC” means RISC Operations Pty Limited, an independent qualified reserves evaluator.

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

“SocGen” means Société Generale Hong Kong branch.

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“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 SPA” means the sales and purchase agreement dated December 6, 2013 with Total where we agreed to sell a gross 61.2903% 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 the share purchase agreement under which Total acquired, through the purchase of all of the shares of SPI (200) Limited (now known as Total E&P PNG 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 oil and gas business with a sole focus on Papua New Guinea. Our assets include the Elk, Antelope, Triceratops, Raptor and Bobcat fields in the Gulf Province of Papua New Guinea, and exploration licenses covering about 16,000 square kilometers (about 4 million acres) in Papua New Guinea. 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 December 31, 2015, we had 220 full-time employees.  

BUSINESS STRATEGY

Our strategy is to unlock significant value to shareholders by finding oil and gas safely and competitively; enabling its development through the right partnerships, funding and project development capability; co-developing these opportunities to producing assets whilst maintaining a material interest; and repeating this process to fully exploit our acreage position. The focus areas for our strategy are to:

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

- Enable our discovered resources;

- 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 2015 AIF available at www.sedar.com.

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

A summary of the key operational matters and events for the year is as follows:

· Airborne Field Survey

- In January 2015, CGG Aviation (Australia) Pty Ltd began the acquisition of high resolution airborne gravity gradiometry over all of our PPLs and PRLs. As at December 31, 2015, we had completed 82% of the planned survey.

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· Seismic

- The Murua Seismic Survey in PPL 474 commenced in November 2014 and was completed in March 2015.  The appraisal seismic program over the Raptor discovery commenced in January 2015 and was completed in May 2015.  The appraisal seismic program over the Bobcat discovery commenced in March 2015 and was completed in June 2015.  An appraisal seismic survey over Triceratops field commenced in April 2015 and was completed in July 2015.

- The Murua Phase 2 seismic program in PPL 476 commenced in June 2015 and was completed in September 2015.  

· PPL 474 –  Wahoo

- Wahoo-1 exploration well was drilled about 170 kilometers southeast of our Elk and Antelope gas fields. The well was initially spudded in March 2014. However, in July 2014, we suspended drilling after intersecting gas and higher-than expected pressures.    

- In June 2015, we resumed drilling at Wahoo with the Wahoo-1 side-track exploration well. In August 2015, we reported that the Wahoo-1 sidetrack operations had not intersected a carbonate reservoir and the well was plugged and abandoned.   

· PPL 475 – Raptor

- Raptor-1 exploration well was drilled about 12 kilometers west of our Elk and Antelope gas fields. The well was spudded in March 2014, and in October 2014, we announced that well intersected 200 meters of the Kapau Limestone target zone.  In November 2014, conventional natural gas and natural gas liquids were recorded at surface and directed through the flare at the well site and we notified the DPE of a discovery at the Raptor-1 well.  

- Results from the testing program, including pressure measurements, support the presence of a hydrocarbon column in excess of the 200 meter gross gas interval already encountered by the well. The well was drilled to a final total depth of 4,032 meters.  

- During the year ended December 31, 2015, we engaged RISC to provide an independent assessment of the Contingent Resources within the discovered field; and their certification is summarized within the ”Description of Our Business” section of our 2015 AIF.

- In August 2015, we received notification from PRE of their intention to withdraw from PPL 475.  The Farm-In Agreement requires us to refund to PRE $3.0 million in monthly installments commencing in the month subsequent to our receipt of any net cash proceeds from commercial sale of product from PRL 15, although the $3.0 million must be repaid in full within six years of receiving the notification, or if our interest in PRL 15 becomes less than 30%.  Subsequent to PRE’s withdrawal, our interest in the Raptor field will be 79.1114%, and our interest in PPL 475 (excluding the Raptor field) will be 100% (94.25% assuming PNGDV elects to exercise their option to participate at their 5.75% interest election).

· PPL 476 – Bobcat

- Bobcat-1 exploration well was drilled about 30 kilometers northwest of our Elk and Antelope gas fields.  The well was spudded in March 2014, and in November 2014 the well was drilled to a total depth of 3,207 meters after intersecting an interval of about 320 meters of Kapau Limestone.  

- In December 2014, we announced that the well was tested over an interval of about 320 meters of Kapau limestone, the upper section of the target reservoir, and flowed and flared hydrocarbons at surface, and we notified the DPE of a discovery at the Bobcat-1 exploration well.  Seismic mapping, wireline logging and testing results indicate the well is close to the gas-water contact in the transition zone.  The well was further deepened in 2014 to 3,501 meters as the first part of the appraisal program to appraise reservoir quality.  

- During the year ended December 31, 2015, we engaged RISC to provide an independent assessment of the Contingent Resources within the discovered field; and their certification is summarized within the “Description of Our Business” section of our 2015 AIF.

· PRL 39 – Triceratops-3

- The Triceratops-3 appraisal well was drilled about 5.6 kilometers west-north-west of Triceratops-1 and 35 kilometers north-west of the Elk and Antelope gas fields, and was spudded on June 15, 2015.   

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- On September 18, 2015, an open hole Drill String Test was carried out over the Kapau limestone.  The well flowed Conventional Natural Gas post acid stimulation at 17.1 mmcfpd and Natural Gas Liquids at an average of 200.3 bblspd measured through a 72/64” choke. Stabilized flow rates were obtained over several five-hour intervals and were measured through various choke sizes without significant pressure depletion. The cumulative production was estimated to be 29 mmcf gas with an average CGR of 18 bbls/mmcf.  The well was drilled to a total depth of 2,090 meters (6,856 feet).

- An update to the GLJ independent assessment of the Contingent Resources in the field is summarized within the ‘Description of Our Business’ section of our 2015 AIF.    

- In fourth quarter of 2015, we received notification from PRE of their intention to withdraw from further participation in PRL 39.  The Farm-In Agreement provides that following an effective withdrawal by PRE, we are required to refund to PRE $93.0 million in monthly instalments commencing in the month subsequent to our receipt of any net cash proceeds from commercial sale of product from PRL 15 and the $93.0 million must be repaid in full within six years of receiving the withdrawal notification, or if our interest in PRL 15 becomes less than 30%.  Following withdrawal of PRE, we also have a receivable of $29.7 million, which is refundable from Pacific LNG Operations Ltd, and other indirect participating interest holders, under the same terms as the amount refundable to PRE.

- Subject to PRE withdrawing, our interest in the Triceratops discovery will be 78.1114%, and our interest in PRL 39 (excluding the Triceratops discovery) our interest will be 100% (94.25% assuming PNGDV elects to exercise their option to participate at their 5.75% interest election).

· PRL 15 – Appraisal Program

- In September 2014, we spudded the Antelope-4 appraisal well, which intersected the top reservoir at 1,911 meters.  On April 27, 2015, the well was suspended because of drilling difficulties and the Western Drilling Limited rig was replaced by Rig 103.  

- Antelope-4 well operations resumed on August 13, 2015.  On August 27, 2015 PRL 15 Joint Venture started drilling a side-track well at the Antelope-4 site. The side-track was initiated at a measured depth of 862 meters (2,828 feet).  On September 18, 2015, the Antelope-4 side track intersected the reservoir 36 meters (118 feet) higher than the original Antelope-4 penetration. On November 12, 2015, the well had drilled to a planned total depth of 2,262 meters (7,421 feet true vertical depth sub-sea) and wireline logs were run to evaluate the reservoir properties. Subsequent well abandonment operations were completed on December 23, 2015.

- 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 2,307 meters on February 24, 2015.

- On April 27, 2015, the well was open to clean up. On June 2, 2015, after downhole gauges were run on Antelope-5 the flow testing commenced.  The purpose of the test was to flow sufficient volumes of gas from the Kapau Limestone to create measurable depletion in order to allow volume estimates of gas in place and improve the understanding of productivity and connectivity.  The well was produced via two parallel choke manifolds at four different chokes sizes, 32/64”, 40/64”, 44/64” and 48/64” per manifold over a 72 hour period. Corresponding rates were approximately 30, 40, 50 and 60 mmcfpd. The flow test was completed mid June 2015.  A total of 152.9 mmcf gas, 2008.4 bbls of condensate and 46.2 bbls of water were produced.

- During the test, gauges were also installed at the base of the reservoir in the Antelope-1 well to observe reservoir pressure response from the Antelope 5 flowing.  Pressure response showed  no significant pressure depletion and excellent reservoir connectivity.

- During April 2015, the PRL 15 Joint Venture also approved the drilling of third appraisal well Antelope-6 to define the eastern flank of the reservoir.  Consequently, we adjusted the expected cash flow timing of the interim resource payment under the Total SSA from December 2015 to June 2016 to accommodate the delayed drilling of Antelope-4 and drilling of Antelope-6.  The Antelope-6 appraisal well was spudded by the PRL 15 Joint Venture on December 24, 2015.  The well has a proposed total depth of around 2,464 meters (8,084 feet) true vertical depth sub-sea and is located about 2km east-south-east of Antelope-3.  Subsequent to the year end, on January 29 2016, we announced that the Antelope-6 appraisal well encountered top reservoir within expectations at approximately 2,076 meters (6,811 feet) true vertical depth sub-sea.

Management Discussion and Analysis INTEROIL CORPORATION 9

- During the month of February, 9-5/8” liner was run to the Antelope-6 top reservoir, four cores were cut from the upper section of the reservoir and intermediate logs were run.  The four cores were cut over an interval of 2,080 to 2,142 meters true vertical depth sub-sea and the well reached a depth within the reservoir section of 2,142 meters true vertical depth sub-sea.  Preliminary interpretation shows 12 meters of dolomite is present in the drilled section with the remainder of the section being limestone of good reservoir quality.  An intermediate, multi-rate flow test was conducted over an interval from 2,072 to 2,142 meters true vertical depth sub-sea to assess the deliverability of the matrix in the absence of major fractures.  The test over the upper Kapau Limestone, completed in early March 2016, obtained a final stabilized flow rate of approximately 13 mmcfd over a 24 hour period, measured through a 40/64” choke. At the timing of this report pressure gauges were still to be retrieved from the well.

- Following the test, it is planned to drill through the gas-water-contact to a proposed total depth of approximately 2,650 meters MDRT and then run a full suite of wireline logs. Once logs have been obtained, a decision will be made regarding the need for further testing.

- Subsequent to the year end, on January 21, 2016, we were advised by Total that the second planned extended well test has commenced at Antelope-5.  The second extended well test on Antelope-5 was completed and the well flowed for a total of 343 hours producing a total volume of approximately 760 mmcf with a condensate gas ratio of 12.5 to 13.0 bbls/mmcf, water rates were too low to be measured. The well was then shut-in for 16.75 days to record the subsequent pressure build-up. The majority of the stabilized flow occurred on a 48/64” choke at a rate of approximately 57 mmcfd.  Downhole pressure gauges have been successfully retrieved from both Antelope-5 and Antelope-1 (observation well) and data has been extracted for analysis.  Preliminary analysis has confirmed the excellent reservoir quality and connectivity seen in the initial Antelope-5 production test conducted in mid-2015. The test has also provided further support to the volumetric estimates derived from the initial Antelope-5 production test.  The forward plan is to undertake further analysis to quantify nearby reservoir properties and volumetric estimates.  

- An update to the GLJ independent assessment of the Contingent Resources in the Elk and Antelope fields are summarized within the “Description of Our Business” section of our 2015 AIF.

· PRL15 License Extension Application

- On May 27, 2015, the operator of the PRL15 Joint Venture, lodged an extension application with Department of Petroleum and Energy, in respect of PRL 15 which was due to expire on 29 November 2015 (the “Extension Application”).  As part of the Extension Application, the PRL 15 joint venture proposed new work programs and commitments for the extension term.

- The Extension Application is still being considered.  Pursuant to section 45(10) of the Oil & Gas Act 1997 (PNG), PRL15 is deemed to continue in full force and effect until the Extension Application is determined.  

· Papua LNG Project

- In February 2015, the ICC International Court of Arbitration (the “ICA”) dismissed all claims by the PacLNG companies, affiliates of Oil Search, over their claim to have pre-emptive rights over the Total SSA under the JVOA, and declared that Oil Search had no pre-emptive rights as per their claims. Subsequently in June 2015, the ICA made various costs awards in respect of the arbitration. As a consequence of these orders, we received a net payment of $1.377 million from the claimants.

- On February 27, 2015, the parties to the PRL 15 Joint Venture unanimously appointed Total as operator of the PRL 15 Joint Venture which includes the Papua LNG Project.  The formal change of operatorship from InterOil to Total occurred on August 1, 2015.  InterOil continued to provide certain technical services for Total until early 2016.  

- On July 2, 2015, the PRL 15 Joint Venture unanimously endorsed locations for key infrastructure sites for development of the Papua LNG Project. The central processing facility is expected to be near the Purari River in the Gulf Province, about 360 kilometers north-west of Port Moresby, and will be connected to the LNG facility by onshore and offshore gas and condensate pipelines. Caution Bay near Port Moresby has been selected as the site for the liquefied natural gas plant.

- During the fourth quarter of 2015, the PRL 15 Joint Venture initiated basis of design work and began discussions on LNG marketing and project financing.

Management Discussion and Analysis INTEROIL CORPORATION 10

· Other matters

- On January 1, 2015, Dr. Ellis Armstrong, former BP PLC Group E&P - Chief Financial Officer; and Ms. Katherine Hirschfeld, former Australasia BP Executive Director; were appointed as our non-executive directors.

- 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.  He replaced Mr. Samuel Delcamp as a director, who formally retired from the Board on March 12, 2015. 

- On May 13, 2015, Mr. Saxon Palmer, a former executive with BP and BHP Billiton, was appointed as the Senior Vice President, Exploration.

- On June 9, 2015, Mr. Isikeli Taureka, our Executive Vice President, was elected as a director at our Annual Meeting of Shareholders.

- On July 8, 2015, we filed a final short-form base shelf prospectus in the with the Alberta Securities Commission and with the SEC pursuant to a registration statement on Form F-10 to enable us to add financial flexibility and to issue up to an aggregate of $1.0 billion of securities in one or more offerings over 25 months.  These issuances may consist of one or more of common shares, preferred shares, warrants, debt securities or a combination thereof.

- On August 1, 2015, Ms. Sheree Ford replaced Mr. Geoff Applegate as the General Counsel and Corporate Secretary.

- On September 1, 2015, Mr. Thomas Nador was appointed as Executive Vice President, PNG Business Operations. Mr. Nador’s appointment follows the election of Mr. Isikeli Taureka, the Executive Vice President, PNG, to the company’s board of directors. Mr. Taureka became Executive Director, PNG.

- On November 15, 2015, we fully repaid the Convertible Notes on their maturity date.

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SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Year Ended December 31, 2015, 2014 and 2013

Consolidated – Operating results	Year ended December 31,
($ thousands, except per share data)	2015			2014			2013
Interest revenue		19,664			1,991			71
Other		3,419			11,168			2,692
Total revenue		23,083			13,159			2,763
Administrative and general expenses		(42,718	)		(39,245	)		(19,165	)
Derivative losses		-			-			(146	)
Legal and professional fees		(3,747	)		(14,091	)		(9,801	)
Exploration costs, excluding exploration impairment		(121,830	)		(34,529	)		(18,794	)
Exploration impairment		(78,236	)		-			-
Finance costs, excluding interest expense		(11,970	)		(18,578	)		(4,687	)
Gain on conveyance of exploration and evaluation assets		-			340,540			500
Gain on available-for-sale investment		-			-			3,720
Foreign exchange gains/(losses)		1,139			4,421			(467	)
Share of net (loss)/profit of joint venture partnership accounted for using the equity method		-			(17,558	)		2,274
EBITDA (1)		(234,279	)		234,119			(43,803	)
Depreciation and amortization		(526	)		(3,628	)		(5,733	)
Interest expense		(6,122	)		(11,409	)		(8,440	)
(Loss)/profit for the year from continuing operations before income taxes		(240,927	)		219,082			(57,976	)
Income tax expense		(1,029	)		(1,119	)		(940	)
(Loss)/profit for the year from continuing operations		(241,956	)		217,963			(58,916	)
(Loss)/profit for the period from discontinued operations, net of tax		-			71,803			18,558
(Loss)/profit for the year		(241,956	)		289,766			(40,358	)
Basic (loss)/earnings per share		(4.89	)		5.84			(0.83	)
From continuing operations		(4.89	)		4.39			(1.21	)
From discontinued operations		-			1.45			0.38
Diluted (loss)/earnings per share		(4.89	)		5.82			(0.83	)
From continuing operations		(4.89	)		4.38			(1.21	)
From discontinued operations		-			1.44			0.38
Total assets		1,191,395			1,340,130			1,305,799
Total liabilities		391,722			311,477			572,978
Total long-term liabilities		87,588			96,000			236,741

Notes:

(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 12

Analysis Comparing Financial Condition as at December 31, 2015, 2014 and 2013

As at December 31, 2015, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 14%, compared to 6% as at December 31, 2014 and 26% as at December 31, 2013, which is below our targeted maximum gearing level of 50%. Gearing targets are based on factors that include operating cash flows, 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 2.2 times as at December 31, 2015, compared to 4.5 times as at December 31, 2014 and 1.0 times as at December 31, 2013. The current ratio satisfied our internal target of above 1.5 times as at December 31, 2015.

Variance in Total Assets:

As at December 31, 2015, our total assets amounted to $1,191.4 million, compared with $1,340.1 million as at December 31, 2014 and $1,305.8 million as at December 31, 2013. The decrease of $148.7 million, or 11%, from December 31, 2014, was primarily due to:

- $360.4 million decrease in cash and cash equivalents and restricted cash, mainly attributable to the seismic activities, drilling of Triceratops-3 well, drilling of Wahoo-1 side track well, drilling of Antelope-4 and Antelope-4 side track well, drilling costs of Antelope-5 well, the site preparation costs incurred for Antelope-6 well, conceptual development studies for PRL 15, and Corporate and financing costs incurred during the year ended December 31, 2015.

These decreases have been partially offset by:

- $176.7 million increase in exploration and evaluation assets costs capitalized during the year ended December 31, 2015, primarily associated with drilling costs for Triceratops-3 in PRL 39; Raptor-1 in PPL 475; Bobcat-1 in PPL 476; Antelope-4, Antelope-4 side track and Antelope-5 in PRL 15; conceptual development studies for PRL 15; site preparation for Antelope-6 in PRL 15; and appraisal seismic. These increases were partially reduced by the recognition of $78.2 million exploration impairment for the Wahoo exploration costs, which was plugged and abandoned during the quarter ended September 30, 2015.

- $42.5 million increase in trade and other receivables, mainly due to higher cash call receivables in relation to transition services agreement from Total as at the current year ended December 31, 2015.

Comparing December 31, 2014 to December 31, 2013, the increase of total assets of $34.3 million or 3% was primarily due to the $286.5 million increase in cash and cash equivalents and restricted cash, mainly from the receipt of net proceeds from the Puma Transaction, receipt of the completion payment in relation to the Total SSA, offset by expenditure on appraisal and exploration of our licenses, repayment of secured term loan facilities, and the redemption of our shares during the year ended December 31, 2014; and the $467.7 million increase in trade and other receivables, largely as a result of the recognition of the interim resource payment receivable in relation to the conveyance proceeds from Total SSA calculated using the best case scenario provided by GCA of 7.10 Tcfe for the Elk and Antelope fields. These increases have been partially offset by a $259.8 million decrease in exploration and evaluation assets, primarily resulting from the allocation of Total SSA conveyance proceeds against the respective PRL 15 capitalized costs on the balance sheet prior to recognizing any gain on conveyance during the year; a $17.6 million decrease in investments accounted for using equity method, which is attributable to our share of losses incurred by the PNG LNG Inc. joint venture with PacLNG resulting from the impairment of joint venture assets, as we are now progressing the Papua LNG Project development jointly with Total; and the Puma Transaction resulted in the decrease in plant and equipment by $232.1 million, inventories by $158.1 million and deferred tax assets by $48.2 million.

Variance in Total Liabilities:

As at December 31, 2015, our total liabilities amounted to $391.7 million, compared with $311.5 million at December 31, 2014 and $573.0 million as at December 31, 2013. The increase of $80.2 million, or 26%, from December 31, 2014, was primarily due to:

- $32.4 million increase in trade and other payables resulting mainly due to provisions for onerous rig rental and telecommunications contracts amounting to $56.5 million recognized as at December 31, 2015. These provisions were recognized due to the restructuring of our activities as a result of the transition of operatorship of PRL 15 to Total and also our plan to defer further exploration and appraisal work until the Elk-Antelope appraisal program is completed.

- $130.0 million increase in secured loans as a result of drawdowns on the Credit Suisse syndicated secured loan during the current year ended December 31, 2015.

Management Discussion and Analysis INTEROIL CORPORATION 13

These increases have been partially offset by:

- $66.5 million decrease in the Convertible Notes liability following repayment in November 2015.

- $15.9 million decrease in other non-current liabilities as a result of a fair value adjustment to the repayment obligation to PRE following their notification of intention to withdraw from further participation in PRL 39.

Comparing December 31, 2014 to December 31, 2013, the decrease of $261.5 million or 46% was primarily due to a decrease of $200.5 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 and BNP syndicated loan facilities in connection with the Puma Transaction, and the full repayment in April 2014 of the Credit Suisse syndicated secured loan post receipt of the Total SSA completion payment. The Puma Transaction also resulted in the decrease in working capital facilities by $36.4 million and income tax payable by $15.3 million.

Analysis of Consolidated Financial Results Comparing Quarters and Years Ended December 31, 2015 and 2014

Our net loss for the quarter ended December 31, 2015 was $83.8 million, compared with a net loss of $64.2 million for the same quarter in 2014, an increase of $19.6 million. This was primarily due to the $54.7 million increase in exploration costs, mainly from the recognition of $48.5 million of provision for onerous rig rental contracts recognized at December 31, 2015 for both Rig 115 and Rig 116 to the end of their respective contract period, and an increase in administrative and general expenses of $11.8 million, mainly due to the recognition of corporate restructuring costs associated with onerous telecommunications contracts and the retrenchment of employees in connection with the transition of operatorship of PRL 15 to Total. These increases have been partly reduced by the $26.5 million increase in interest accretion income on the receivables recognized in relation to interim resource payments expected under the Total SSA, and the $17.5 million share of losses incurred by PNG LNG, Inc. incurred during the prior year ended December 31, 2014, resulting from the impairment of joint venture assets, as we are now progressing the Papua LNG Project with Total.

Our net loss for the year ended December 31, 2015 was $242.0 million, compared with a net profit of $289.8 million for the same period in 2014, a decrease of profit by $531.8 million. This decrease primarily resulted from the recognition of the $340.5 million gain on conveyance of exploration and evaluation assets under the Total SSA during the prior year ended December 31, 2014; the $71.8 million profit from discontinued operations during the prior year ended December 31, 2014; the $78.2 million exploration impairment recognized during the year for the write off of the Wahoo exploration well costs; and the $87.3 million increase in exploration costs incurred for the Murua and exploratory seismic program in PPL 474, 475 and PPL 476, Rig 116 stack costs during the year and provision for onerous drilling contracts recognized, Rig 3 demobilization costs and airborne gravity survey costs during the year ended December 31, 2015.

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

		Quarterly Variance ($ millions)	Yearly Variance ($ millions)
		($19.6)	($531.8)	Net (loss)/profit variance for the comparative periods primarily due to:
Ø	Interest revenue	$26.5	$17.7	Interest income was primarily attributable to interest accretion income on receivables for interim resource payments expected under the Total SSA for the Elk and Antelope fields.

Management Discussion and Analysis INTEROIL CORPORATION 14

Ø	Other revenue	($1.6)	($7.7)	Following divestment of our midstream and downstream businesses on June 30, 2014, we have ceased to operate a shared services model that resulted in the recognition of other revenue from the internal support of exploration and development.  These costs have been allocated to those activities as a recovery of cost, rather than as other revenue.  Other revenues for the quarter and year ended December 31, 2015 were comprised of support services (post divestment) recharged to Puma.
Ø	Administrative and general expenses	($11.8)	($3.5)	The increase in administrative and general expenses was mainly due to the recognition of restructuring costs in connection with onerous telecommunication contracts and retrenchment of employees related to the transition of operatorship of PRL 15 to Total from August 1, 2015, and also our plan to defer further exploration and appraisal work till the Elk-Antelope appraisal program is completed.
Ø	Legal and professional fees	$2.1	$10.3	The decrease in legal and professional fees was mainly due to lower consultant fees during the quarter and year ended December 31, 2015, due to completion of the office transition from Cairns, Australia, and the arbitration on PRL 15 from 2014.
Ø	Exploration costs	($54.7)	($87.3)	The increase in exploration costs was primarily attributable to the expensing of seismic activities in PPL 474 and PPL 476, exploration seismic carried out over PPL 475, airborne gravity survey costs incurred for PPL 476, PPL 477 and PRL15, Rig 116 stack costs during the year and provision for onerous rig rental contracts recognized for $48.5 million as at December 31, 2015 for both Rig 115 and Rig 116 to the end of their respective contract period due to the deferral of further exploration and appraisal work until the Elk-Antelope appraisal program is completed and rig 3 demobilization costs during the quarter and year ended December 31, 2015.
Ø	Exploration impairment	$0.0	($78.2)	The increase in exploration impairment was attributable to the recognition of exploration impairment associated with the write off of the Wahoo exploration costs, after the Wahoo exploration well was plugged and abandoned during the year ended December 31, 2015.
Ø	Finance costs	$0.5	$6.6	The decrease in finance costs was primarily due to lower facility renewal and commitment fees for the Credit Suisse led syndicated facility, and repayment of the Westpac and BSP bridge facility during the year ended December 31, 2014. During the quarter and year ended December 31, 2015, finance costs comprised of facility fees for the maturity date extension of the Credit Suisse facility to December 2016 and commitment fees on the undrawn facility.
Ø	Gain on conveyance of exploration and evaluation assets	$0.0	($340.5)	The gain on conveyance of exploration and evaluation assets for completion of the Total SSA was recognized during the year ended December 31, 2014 under which Total acquired, through the purchase of all shares of a wholly owned subsidiary, a gross participating interest in PRL 15 of 40.1275% (net 31.0988%, after the State back-in right of 22.5%), which contains the Elk and Antelope gas fields.

Management Discussion and Analysis INTEROIL CORPORATION 15

Ø	Foreign exchange (losses)/ gains	$0.4	($3.3)	The decrease in foreign exchange gains was primarily due to lower depreciation of the PGK against the USD during the year ended December 31, 2015 as compared to the prior year ended December 31, 2014.
Ø	Depreciation and amortization	$0.2	$3.1	The decrease in depreciation expense was due to capitalization of depreciation for supporting assets to respective projects during the year ended December 31, 2015.  Depreciation of assets supporting exploration costs that were expensed has been included in the exploration costs line above.
Ø	Share of losses of joint venture partnership accounted for using equity method	$17.5	$17.6	The year ended December 31, 2014 share of losses of joint venture partnership with PacLNG accounted for using equity method was attributable to the impairment of PNG LNG Inc. joint venture assets, as we are now progressing the Papua LNG Project development jointly with Total.
Ø	Interest expense	($0.2)	$5.3	The decrease in interest expense was largely due to the higher utilization use of the Credit Suisse led syndicated facility and the Westpac and BSP bridge facility during the prior year ended December 31, 2014. The Credit Suisse led syndicated facility was not utilized during the year ended December 31, 2015 until November 2015.
Ø	(Loss)/profit from discontinued operations	$1.7	($71.8)	The decrease in profit from discontinued operations resulted from the sale of the refinery, distribution and shipping business during the year ended December 31, 2014 in connection with the Puma Transaction.

Comparing the year ended December 31, 2014 to the year ended December 31, 2013, the increase in net profit of $330.1 million was primarily driven by the gain on conveyance of exploration and evaluation assets in relation to the Total SSA and from discontinued operations in connection with the Puma Transaction, partially offset an by increase in office and administrative and other expenses, exploration costs and finance costs.

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

As at December 31, 2015, we had cash, cash equivalents, and restricted cash of $41.3 million (December 31, 2014 - $401.7 million and December 31, 2013 - $115.2 million), of which $8.2 million (December, 2014 - $8.3 million and December 31, 2013 - $53.2 million) was restricted. Of the total restricted cash at December 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 for lease of 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 quarters and years ended December 31, 2015, 2014 and 2013 in the table below:

Management Discussion and Analysis INTEROIL CORPORATION 16

	Year ended December 31,
($ thousands)	2015			2014			2013
Net cash (outflows)/inflows from:
Operations		(100,250	)		(81,206	)		70,643
Investing		(320,088	)		640,136			(133,464	)
Financing		60,002			(227,492	)		75,101
Net cash movement		(360,336	)		331,438			12,280
Opening cash		393,405			61,967			49,721
Exchange losses on cash and cash equivalents		-			-			(34	)
Closing cash		33,069			393,405			61,967

Cash flows (used in)/generated from operating activities

Cash outflows from operating activities for the quarter ended December 31, 2015 were $39.1 million compared with an outflow of $20.3 million for the quarter ended December 31, 2014, a net increase in cash outflows of $18.8 million. Cash outflows from operating activities for the year ended December 31 2015 were $100.3 million compared with an outflow of $81.2 million for the year ended December 31, 2014, a net increase in cash outflows of $19.1 million.

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

		Quarterly variance ($ millions)	Yearly variance ($ millions)
		($18.8)	($19.1)	Variance for the comparative periods primarily due to:
Ø	Cash used in operations, before changes in operating working capital	($62.6)	($126.0)	The increase in cash used in operations, before changes in operating working capital for the year, was mainly due to the increase in net loss mainly from exploration activities expensed as incurred, financing costs and administrative expenses and the net cash inflows from the sale of discontinued operations in the year ended December 31, 2014. The increase in cash used in operations, before changes in operating working capital for the quarter, was mainly due to the increase in net loss mainly from exploration activities expensed as incurred, financing costs and administrative expenses.
Ø	Cash generated from operations relating to changes in operating working capital	$43.8	$106.9	The increase in cash generated from operations relating to changes in operating working capital was due to reduced working capital requirements as a result of the Puma Transaction, offset by restructuring and onerous contract provisions recognized at December 31, 2015.

Management Discussion and Analysis INTEROIL CORPORATION 17

Cash flows (used in)/generated from investing activities

Cash outflows from investing activities for the quarter ended December 31, 2015 were $105.9 million compared with an outflow of $28.7 million for the quarter ended December 31, 2014, a net increase in cash outflows of $77.2 million. Cash outflows from investing activities for the year ended December 31, 2015 were $320.1 million compared with a cash inflow of $640.1 million for the year ended December 31, 2014, a net increase in cash outflows of $960.2 million.

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

		Quarterly variance ($ millions)	Yearly variance ($ millions)
		($77.2)	($960.2)	Variance for the comparative periods primarily due to:
Ø	Proceeds from Total for interest in PRL 15	$0.0	($401.3)	Receipt of a $401.3 million completion payment from Total in accordance with the Total SSA during the year ended December 31, 2014.
Ø	Proceeds from sale of subsidiaries, net of transaction costs	$0.0	($428.0)	Receipt of $525.6 million gross proceeds from the Puma Transaction less $39.4 million of cash and cash equivalents held by those businesses, $52.9 million of secured loan repayments undertaken as part of the Puma Transaction, and $4.3 million of transaction costs during the year ended December 31, 2014.
Ø	Decrease in restricted cash held as security on borrowings	$0.0	($44.8)	The movement in restricted cash held as security on borrowings for the year was mainly due to the restricted cash requirements under the midstream refining segment which were withdrawn as the secured loan and working capital facilities under these entities were either repaid or transferred to Puma following the Puma Transaction during the year ended December 31, 2014.
Ø	Expenditure on exploration and evaluation assets net of JV contributions	$42.7	$77.1	The decrease in expenditure on exploration and evaluation assets is due to a reduction in exploration drilling with higher equity interests in the year ended December 31, 2015 compared to activities in prior year ended December 31, 2014 which included Bobcat-1, Raptor-1 and Wahoo-1 wells.
Ø	Expenditure on plant and equipment	($2.4)	$8.8	The decrease in expenditure on plant and equipment for the year was mainly due to sale of the refinery and distribution businesses to Puma during the year ended December 31, 2014.
Ø	Cash used in investing activities relating to change in non-operating working capital	($119.9)	($175.1)	The movement in non-operating working capital was primarily related to trade payables and accruals in our exploration and development operations, in addition to an increase in receivables due to billings to Total under the transitional services arrangements post transfer of operatorship of PRL 15 to Total.

Management Discussion and Analysis INTEROIL CORPORATION 18

Cash flows generated from/(used in) financing activities

Cash inflows from financing activities for the quarter ended December 31, 2015 were $60.0 million compared with nil for the quarter ended December 31, 2014, a net increase in cash inflows of $60.0 million. Cash inflows from financing activities for the year ended December 31, 2015 amounted to $60.0 million, compared with an outflow of $227.5 million for the year ended December 31, 2014, a net decrease in cash outflows of $287.5 million.

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

		Quarterly variance ($ millions)	Yearly variance ($ millions)
		$60.0	$287.5	Variance for the comparative periods primarily due to:
Ø	Repayments of BSP and Westpac secured facility	$0.0	$24.8	Net repayment of the BSP and Westpac combined secured loan facility during the year ended December 31, 2014.
Ø	Proceeds from drawdown of Credit Suisse secured facility	$130.0	$80.0	Drawdown of $50.0 million from the Credit Suisse led syndicated secured loan facility during the year ended December 31, 2014, compared with drawdown on the facility of $130.0 million during the year ended December 31, 2015.
Ø	Repayment of Credit Suisse secured facility	$0.0	$150.0	Repayment of the $150.0 million Credit Suisse led syndicated secured loan facility during the year ended December 31, 2014.
Ø	Proceeds from working capital facility	$0.0	($20.9)	Movement in use of the BNP Paribas working capital facility in our discontinued operations during the year ended December 31, 2014.
Ø	Repayments of ANZ, BSP & BNP syndicated loan	$0.0	$84.0	Repayment of the ANZ, BSP and BNP Paribas syndicated loan during the year ended December 31, 2014.
Ø	Proceeds from issuance of common shares	$0.0	($2.2)	Movement due to cash receipts from the exercise of stock options during the year ended December 31, 2014.
Ø	Payment on share buyback	$0.0	$41.8	Movement due to the cash paid for the purchase of 730,000 common shares during the year ended December 31, 2014.
Ø	Payment on repayment of convertible notes	($70.0)	($70.0)	Movement due to the repayment of the Convertible Notes during the quarter and year ended December 31, 2015.

Management Discussion and Analysis INTEROIL CORPORATION 19

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

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

Quarters ended	2015												2014
($ thousands except per share data)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Total revenues		11,690			11,822			(13,643	)		13,215			(13,182	)		10,749			13,689			1,903
EBITDA (1)		(81,543	)		(101,838	)		(30,583	)		(20,317	)		(60,443	)		(12,133	)		(10,253	)		316,948
Net (loss)/profit		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(64,205	)		(16,930	)		52,265			318,636
From continuing operations		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(62,474	)		(14,622	)		(15,765	)		310,824
From discontinued operations		-			-			-			-			(1,731	)		(2,308	)		68,030			7,812
Basic (loss)/earnings per share		(1.69	)		(0.29	)		(0.66	)		(0.44	)		(1.30	)		(0.34	)		1.05			6.46
From continuing operations		(1.69	)		(0.29	)		(0.66	)		(0.44	)		(1.26	)		(0.29	)		(0.31	)		6.30
From discontinued operations		-			-			-			-			(0.04	)		(0.05	)		1.36			0.16
Diluted (loss)/earnings per share		(1.69	)		(2.09	)		(0.66	)		(0.44	)		(1.30	)		(0.34	)		1.05			6.38
From continuing operations		(1.69	)		(2.09	)		(0.66	)		(0.44	)		(1.26	)		(0.29	)		(0.31	)		6.22
From discontinued operations		-			-			-			-			(0.04	)		(0.05	)		1.36			0.16

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

DISCOUNTINUED OPERATIONS

We had previously organized our operations into Upstream, Midstream, Downstream and Corporate. On June 30, 2014, we disposed of our Midstream Refining and Downstream businesses as a result of the Puma Transaction. As a result, these businesses have been classified as discontinued operations for reporting purposes. At December 31, 2015, no additional discontinued operations have been recognized.

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

This table summarizes the debt facilities available to us and the balances outstanding as at December 31, 2015:

Organization	Facility		Balance outstanding December 31, 2015		Weighted average interest rate			Maturity date
Credit Suisse led syndicated, senior secured financing facility	$	300,000,000	$	130,000,000		5.36	%	December 2016

During the fourth quarter of 2015, we fully repaid the Convertible Notes, which matured on November 15, 2015.

Management Discussion and Analysis INTEROIL CORPORATION 20

Credit Suisse led Syndicated Secured Loan

On June 17, 2014, we entered into a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. The facility was supported by the participating lenders CBA, ANZ, UBS, Macquarie, BSP, Westpac, MUFG and SocGen. The facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2016.

During the fourth quarter of 2015, we drew down $130.0 million under this facility. As at December 31, 2015, we were in compliance with the debt covenants. As at the date of the filing, we had drawn down $190.0 million under the facility.

Other Sources of Capital

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

Capital Expenditure

Net capital expenditure on exploration and evaluation assets

Net capital expenditures on our exploration and evaluation assets in PNG for the quarter ended December 31, 2015 were $41.5 million, compared with $83.6 million during the same period of 2014. Total net capital expenditure for the year ended December 31, 2015 was $176.7 million, compared with $355.7 million for the same period in 2014.

This analysis outlines key net capital expenditure in the quarter and year ended December 31, 2015:

	Quarterly movement ($ millions)	Yearly movement ($ millions)
	$460.2	$325.0	Opening balance of exploration and evaluation assets
	$41.5	$176.7	Net capital expenditure consisting of following:
Ø	$8.5	$9.8	Costs for site preparation, pre-spud work and drilling of the Raptor-1 side track well.
Ø	($0.0)	($36.0)	Recognition of exploration impairment relating to the Wahoo exploration well costs, which was plugged and abandoned during the year ended December 31, 2015.
Ø	$2.7	$9.0	Costs for testing of the Bobcat-1 well.
Ø	$17.8	$69.4	Costs for site preparation, pre-spud work and drilling of the Triceratops-3 well.
Ø	$0.3	$1.7	Costs for site preparation of the Triceratops-4 well.
Ø	($3.1)	$14.6	Costs for drilling of the Antelope-4 well.
Ø	$19.8	$39.5	Costs for site preparation, pre-spud work and drilling of the Antelope-4 side track well.
Ø	$0.5	$17.6	Costs for drilling and interference test for the Antelope-5 well.
Ø	$1.6	$10.6	Costs for site preparation and pre-spud work for the Antelope-6 well.
Ø	($0.9)	$8.7	Appraisal seismic over the Raptor field.
Ø	($3.1)	$10.2	Appraisal seismic over the Bobcat and Triceratops fields.

Management Discussion and Analysis INTEROIL CORPORATION 21

Ø	($24.7)	($23.0)	Decrease in inventories for the year was mainly due to the consumption of inventory in operations and inventories sold to Total.
Ø	$4.9	$10.7	Costs for development survey, environmental and societal studies, preparation works, project finance and operator transition for Papua LNG Project.
Ø	$0.0	$8.7	Expenditure for concept select studies led by Total for the Elk and Antelope fields in PRL 15.
Ø	$12.6	$12.6	Expenditure related to the move of Rig 115.
Ø	$4.6	$12.6	Other expenditures, including equipment purchases, indirect project support costs and field care and maintenance for PRL 15, and site preparation costs of the Antelope South well.
	$501.7	$501.7	Closing balance of exploration and evaluation assets

Gross capital expenditure on exploration and evaluation assets

Gross capital expenditure on our exploration and evaluation assets in PNG for the quarter ended December 31, 2015 was $68.7 million. Total gross capital expenditure for the year ended December 31, 2015 was $464.2 million.

This analysis outlines key gross capital expenditures in the quarter and year ended December 31, 2015:

	Quarterly movement ($ millions)	Yearly movement ($ millions)
	$68.7	$464.2	Gross capital expenditure consisting of following:
Ø	$8.6	$12.4	Costs for site preparation, pre-spud work and drilling of the Raptor-1 side track well.
Ø	($1.3)	$12.6	Appraisal seismic over the Raptor field.
Ø	$5.0	$7.0	Costs for care and maintenance of the suspended Wahoo-1 well.
Ø	$6.8	$44.7	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 side track.
Ø	$2.7	$10.2	Costs for testing of the Bobcat-1 well.
Ø	($3.6)	$13.4	Appraisal seismic over the Bobcat and Triceratops fields.
Ø	$27.8	$118.5	Costs for site preparation, pre-spud and drilling work for the Triceratops-3 well.
Ø	$0.4	$2.6	Costs for site preparation of the Triceratops-4 well.
Ø	$0.2	$1.4	Testing costs for the Antelope-1 well.
Ø	($1.5)	$43.8	Costs for drilling of the Antelope-4 well.
Ø	$20.8	$54.3	Costs for site preparation, pre-spud work and drilling of the Antelope-4 side track well.
Ø	$2.2	$61.2	Costs for drilling and interference test for the Antelope-5 well.
Ø	$1.7	$38.9	Costs for site preparation and pre-spud work for the Antelope-6 well.
Ø	$0.2	$6.7	Costs for site preparation of the Antelope South well.

Management Discussion and Analysis INTEROIL CORPORATION 22

Ø	$0.0	$26.6	Expenditure and true up costs for concept select studies led by Total for the Elk and Antelope fields in PRL 15.
Ø	$4.9	$10.8	Costs for development survey, environmental and societal studies, preparation works, project finance and operator transition for Papua LNG Project.
Ø	$12.6	$12.6	Expenditure related to the move of Rig 115.
Ø	($24.7)	($23.0)	Decrease in inventories for the year was mainly due to the consumption of inventory in operations and inventories sold to Total.
Ø	$5.9	$9.5	Other expenditures, including equipment purchases, indirect project support costs and field care and maintenance for PRL 15.

Capital Requirements

Our primary use of capital resources has been the exploration and development activities. We have to execute exploration activities within a set timeframe to meet the minimum license commitments in relation to our PPLs and PRLs. 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. Subject to meeting the license commitment requirements, our capital expenditure can be accelerated or decelerated at our discretion.

We are expecting interim resource certification over Elk and Antelope fields to be completed in mid-2016, following which we will receive the interim resource certification payment under the Total SSA. This interim certification is currently estimated using a certification provided by GCA, which certified a best case scenario of 7.1 tcfe of natural gas and natural gas liquids in the Elk and Antelope fields. We believe that existing cash balances, estimated interim certification proceeds under Total SSA and available credit facilities will be sufficient to settle debt obligations and to facilitate further necessary development of the Elk and Antelope fields, and exploration and appraisal activities that have been planned to meet our license commitments.

We believe that the secured financing facility of $300.0 million led by Credit Suisse will enable us to fund operations until the estimated interim certification payment is received. If required, we can also raise additional funding through asset sales or extending existing facilities to ensure sufficient cash to be available to further our development plans. We are in discussion with our lenders to increase and extend the secured financing facility. We expect that we will be able to secure the necessary financing through one, or a combination of, the aforementioned alternatives.

In addition, in July 2015, we filed a short form base shelf prospectus with the Alberta Securities Commission and a corresponding registration statement on Form F-10 with the SEC pursuant to the multi-jurisdictional disclosure system. These filings will enable us to add financial flexibility in the future and issue, from time to time, up to an aggregate of $1.0 billion of securities in one or more offerings for a period of 25 months from the effective date of the prospectus. These securities may be debt securities, common shares, preferred shares, warrants or a combination thereof.

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 PRL 15 Joint Venture share of costs of construction of a liquefaction plant, central processing facility and other infrastructure associated with the proposed Papua LNG Project may amount to billions of dollars and thus exceed our existing cash balances. No assurance can be given that we will obtain new capital or refinance current facilities on terms that are acceptable to us, particularly with market volatility.

Management Discussion and Analysis INTEROIL CORPORATION 23

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 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
PPLs and PRLs		380,885		8,861		27,436		149,288		-		195,300		-
Secured loans		131,775		131,775		-		-		-		-		-
Other non-current liabilities (1)		96,000		-		-		96,000		-		-		-
Total		608,660		140,636		27,436		245,288		-		195,300		-

(1) Refer to Note 16 of our Consolidated Financial Statements. The timing of the expected payment to PRE is estimated to be in the first quarter of 2018 when it is expected that the State of Papua New Guinea will elect to exercise its option to participate within the PRL 15 development, resulting in our interest becoming less than 30%.

The PPL and PRL amounts represent our commitments for these licenses as at December 31, 2015. The terms of grant of our PPLs includes commitments for us to spend $351.8 million over the remainder of the six-year terms. The terms of grant of PRL 39 require us to spend $29.0 million on the license area by the end of 2018.

The following table contains information on payments required to meet our operating lease commitments. It should be read in conjunction with our Consolidated Financial Statements and respective notes thereto.

	Year ended December 31,
($ thousands)	2015		2014		2013
Not later than 1 year		5,014		4,026		15,513
Later than 1 year and not later than 5 years		3,617		1,641		9,715
Later than 5 years		-		-		2,445
Total		8,631		5,667		27,673

Off Balance Sheet Arrangements

During the quarter ended, nor as at December 31, 2015, we had no off balance sheet arrangements or relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

Other than remuneration paid to key management personnel, no related party transaction took place during the quarter and year ended December 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 December 31, 2015, we had 49,572,811 common shares issued and outstanding (50,167,765 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at December 31, 2015 included employee stock options and restricted stock in respect of 594,954 common shares.

Management Discussion and Analysis INTEROIL CORPORATION 24

As of March 29, 2016, we had 49,678,460 common shares issued and outstanding (50,402,149 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 29, 2016 included employee stock options and restricted stock in respect of 723,689 common shares.

INDUSTRY TRENDS AND KEY EVENTS

Oil and Gas Prices

Oil and natural gas prices are determined by supply and demand and in the case of oil prices, political factors and a variety of additional factors beyond our control. These factors include but are not limited to economic conditions, both in North America and worldwide, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability, the increased capacity to bring new production on stream due to technology such as multistage fracturing, the foreign supply of oil and natural gas, supply disruption, transportation disruption and the availability of alternative fuel sources. North America has an abundance of natural gas reserves, primarily as a result of advancements in hydraulic fracturing techniques.

During the second half of 2014 and throughout 2015, oil, natural gas and natural gas liquids prices experienced a significant decline that continued into 2015. Any substantial and extended decline in the price of oil and natural gas could have an adverse effect on our borrowing capacity, levels of capital expenditures and ultimately on our financial condition.

Financing Arrangements

We continue to monitor liquidity risk by setting and monitoring acceptable gearing. Our aim is to maintain our debt-to-capital ratio, or gearing levels, (debt divided by (shareholders’ equity plus debt)) at 50% or less. This was achieved throughout 2014 and 2015. Gearing was 14% in December 2015, 6% in December 2014 and 26% in December 2013.

We had cash, cash equivalents and cash restricted of $41.3 million as at December 31, 2015, of which $8.2 million was restricted. For details of other financial arrangements, see “Liquidity and Capital Resources – Summary of Debt Facilities”.

On June 17, 2014, we entered into a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. The facility is supported by the participating lenders CBA, ANZ, UBS, Macquarie, BSP, Westpac, MUFG and SocGen. The facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2016. As at December 31, 2015, $130.0 million of the facility was drawn down. As at the date of the filing, we had drawn down $190.0 million under the facility.

Exchange Rates

The PGK interbank reference rate has weakened considerably against the USD in the year ended December 31, 2015 (from 0.3855 to 0.3325). Changes in the AUD and SGD to USD exchange rates can affect our results as expenses of the corporate office in Singapore are incurred in SGD and we also incur operational costs with AUD vendors. PGK, AUD and SGD exposures are minimal currently as funds are transferred to PGK, AUD and SGD from USD as required. No material balances are held in PGK, AUD or SGD. However, we are exposed to translation risks resulting from PGK, AUD and SGD fluctuations as in country costs are being incurred in PGK, AUD and SGD and reporting for those costs are in USD.

Management Discussion and Analysis INTEROIL CORPORATION 25

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 2015 AIF 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 Consolidated 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 Consolidated Financial Statements as estimating it is impracticable. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations.

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

Environmental Remediation

Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. We currently do not have any amounts accrued for environmental remediation obligations as current legislation does not require it and our current environmental footprint is minimal. This assumption will be reassessed in future periods as PRL 15 license development progresses with the final investment decision on the Papua LNG Project. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.

Share-based payments

The fair value of stock options at grant date is determined using a Black-Scholes option pricing model that takes into account the exercise price, the terms of the option, the vesting criteria, the share price at grant date, the expected price volatility of the underlying share, and the expected yield and risk-free interest rate for the term of the option. On exercise of options, the balance of the contributed surplus relating to those options is transferred to share capital. The fair value of restricted stock on grant date is the market value of the stock. We use the fair value based method to account for employee stock based compensation benefits. Under the fair value based method, compensation expense is measured at fair value at the date of grant and is expensed over the award's vesting period. We have not used a forfeiture rate as the assumption is for a 100% vesting of the granted options, however, if the options are forfeited prior to vesting, then any amounts expensed in relation to those forfeited shares are reversed.

Exploration and Evaluation Assets

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

Management Discussion and Analysis INTEROIL CORPORATION 26

The conveyance accounting for the Total SSA was initially accounted for in the year ended December 31, 2014. This recognized the interim resource certification payments expected in addition to the completion payment that was received from Total during the year. The interim resource certification payments were estimated based on a certification provided by GCA, which certified a best case scenario of 7.1 tcfe of natural gas and natural gas liquids in the Elk and Antelope fields. GCA is a recognized certifier under the Total SSA. The interim resource certification under the Total SSA will vary post the completion of appraisal wells that will be drilled within Elk and Antelope fields prior to the certification.

Impairment of Long-Lived Assets

We are required to review the carrying value of all property, plant and equipment, including the carrying value of exploration and evaluation assets, and goodwill for potential impairment. We test long-lived assets for recoverability when events or changes in circumstances indicate that its carrying amount may not be recoverable by future discounted cash flows. Due to the significant subjectivity of the assumptions used to test for recoverability and to determine fair value, changes in market conditions could result in significant impairment charges in the future, thus affecting our earnings. Our impairment evaluations are based on assumptions that are consistent with our business plans.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at December 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 15 ‘Revenue from contracts with customers’ (effective from January 1, 2018): 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.

- IFRS 16 ‘Leases’ (effective from January 1, 2019): The new standard now requires lessees to recognize a lease liability reflecting future lease payments and a ‘right-of-use asset’ for virtually all lease contracts. The standard has an optional exemption for certain short-term leases and leases of low-value assets; however, this exemption can only be applied by lessees. The standard also provides guidance on the definition of a lease (as well as the guidance on the combination and separation of contracts). We are currently evaluating the impact of 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. Accordingly, they may not be comparable to similar measures provided by other issuers.

Management Discussion and Analysis INTEROIL CORPORATION 27

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.

	2015												2014
Quarters ended ($ thousands)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Earnings before interest, taxes, depreciation and amortization		(81,543	)		(101,838	)		(30,583	)		(20,317	)		(60,443	)		(12,133	)		(10,253	)		316,948
Interest expense		(1,639	)		(1,513	)		(1,492	)		(1,477	)		(1,464	)		(1,367	)		(4,409	)		(4,170	)
Income taxes		(495	)		(256	)		(207	)		(70	)		(211	)		(199	)		(194	)		(514	)
Depreciation and amortisation		(153	)		(118	)		(249	)		(5	)		(356	)		(923	)		(909	)		(1,440	)
From continuing operations		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(62,474	)		(14,622	)		(15,765	)		310,824
From discontinued operations		-			0			0			-			(1,731	)		(2,308	)		68,030			7,812
Net (loss)/profit		(83,830	)		(103,725	)		(32,531	)		(21,869	)		(64,205	)		(16,930	)		52,265			318,636

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2015 AIF, in documents filed with the Canadian Securities Administrators at www.sedar.com, and in documents, including our Form 40-F, filed with the 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, 2015 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.

Management Discussion and Analysis INTEROIL CORPORATION 28

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, 2015, for the foregoing purpose.

Material Changes in Internal Control over Financial Reporting

No material change in our internal controls over financial reporting were identified during the year ended December 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 29