Exhibit 1

InterOil Corporation Management Discussion and Analysis   For the quarter and nine months ended September 30, 2015 November 13, 2015

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	3
OIL AND GAS DISCLOSURES	4
GLOSSARY OF TERMS	4
INTRODUCTION	7
BUSINESS STRATEGY	7
OPERATIONAL HIGHLIGHTS	7
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	10
DISCOUNTINUED OPERATIONS	17
LIQUIDITY AND CAPITAL RESOURCES	18
RISK FACTORS	21
CRITICAL ACCOUNTING ESTIMATES	21
NEW ACCOUNTING STANDARDS	22
NON-GAAP MEASURES AND RECONCILIATION	22
PUBLIC SECURITIES FILINGS	23
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	23

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 and nine months ended September 30, 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 September 30, 2015 and for the quarter and nine months ended September 30, 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:

· 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;

· 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;

· 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.

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 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(2)	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).

Management Discussion and Analysis     INTEROIL CORPORATION     3

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, 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 September 30, 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

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

“2014 MD&A” means Management’s Discussion and Analysis 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.

“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 and nine months ended September 30, 2015.

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

Management Discussion and Analysis     INTEROIL CORPORATION     4

“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.

“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.

“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 quarter and nine months ended September 30, 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 PNG, and its subsidiaries.

“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.

Management Discussion and Analysis     INTEROIL CORPORATION     5

“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.

“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.

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

“SocGen” means Société 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.

“UBS” means UBS A.G.

“Westpac” means Westpac Bank PNG Limited.

Management Discussion and Analysis     INTEROIL CORPORATION     6

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 September 30, 2015, we had 345 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;

- 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 is as follows:

· Airborne Field Survey

- On January 17, 2015, we began the acquisition of high resolution airborne gravity gradiometry over all of our PPLs and PRLs. As at September 30, 2015, we had completed 80% of the planned survey.

· Seismic

- A seismic survey over Triceratops in PRL 39 began in April 2015 and was completed in July 2015.

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

· PPL 474 – Wahoo

- On June 10, 2015, we resumed drilling at Wahoo with the Wahoo-1 side-track exploration well to follow-up Wahoo-1, which was suspended in July 2014 due to higher-than-expected pressures.

- On August 12, 2015, we advised the market that the Wahoo-1 sidetrack operations had not intersected a carbonate reservoir and the well was plugged and abandoned. As a result, we expensed $78.2 million of costs relating to the Wahoo exploration program.

· PPL 475 – Raptor

- The Raptor-1 exploration well is about 12 kilometers west of the Elk and Antelope gas fields. On November 14, 2014, we notified the DPE of a discovery at Raptor-1.  On October 19, 2015, we announced that our appraisal drilling of the Raptor discovery will be deferred, until the Elk-Antelope appraisal program is complete.

Management Discussion and Analysis     INTEROIL CORPORATION     7

- In August 2015, we received notification from PRE of their intention to withdraw from further participating in PPL 475. In accordance with the Farm-In Agreement dated July 27, 2012 between us and PRE, we are required 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 6 years of receiving the notification. Subsequent to PRE’s withdrawal, our interest in the Raptor discovery is 79.1114%, and in PPL 475 (excluding the Raptor discovery) is 100% (94.25% assuming PNGDV will elect to exercise their option to participate at their 5.75% interest election).

· PRL 15 – Antelope-4, Antelope-4 Side Track and Antelope-6

- The Antelope-4 appraisal well was spudded on September 16, 2014. On April 27, 2015, the well was suspended because of drilling difficulties and the WDL 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 the drill bit was pulling out of the hole prior to running wireline logs.

- Antelope-6 site preparation is well advanced and drilling is scheduled to commence in the fourth quarter of 2015. On October 19, 2015, we announced that one of the drilling rigs currently contracted to us will be used to drill the Antelope-6 appraisal well in PRL 15.

· Papua LNG Project

- On February 27, 2015, the PRL 15 joint venturers 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 will provide certain technical services for Total until the end of 2015.

- 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.

· PRL 39 – Triceratops-3

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

- On September 18, 2015, we announced Triceratops-3 flowed gas at 17.1 mmcfpd and condensate at an average of 200.3 bblspd. Stabilized flow rates were obtained over several five-hour intervals and were measured through a 72/64” choke with the flow constrained by tubing. The well reached a total depth of 2,090 meters (6,856 feet).

- Subsequent to the quarter end, we received notification from PRE of their intention to withdraw from further participation in PRL 39. In accordance with the Farm-In Agreement dated July 27, 2012 between us and PRE, we are required to refund to PRE $93.0 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 $93.0 million must be repaid in full within 6 years of receiving the notification. We also have a receivable of $29.7 million which is refundable from Pacific LNG Operations Ltd and other indirect participating interest holders if PRE exercised its option to terminate the Farm-In Agreement, under the same terms as the amount refundable to PRE. Subsequent to PRE’s withdrawal, our interest in the Triceratops discovery is 78.1114%, and in PRL 39 (excluding the Triceratops discovery) is 100% (94.25% assuming PNGDV will elect to exercise their option to participate at their 5.75% interest election).

Management Discussion and Analysis     INTEROIL CORPORATION     8

· Other matters

- On August 1, 2015, Ms. Sheree Ford replaced Mr. Geoff Applegate as the General Counsel and Corporate Secretary. Ms. Ford is an experienced corporate lawyer who has worked with BHP Billiton, Oil Search, Roc Oil and Pexco Energy.

- On July 8, 2015, we filed a final short-form base shelf prospectus in the Province of Alberta 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 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 becomes Executive Director, PNG.

Management Discussion and Analysis     INTEROIL CORPORATION     9

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarters and Nine Months Ended September 30, 2015 and 2014

Consolidated – Operating results	Quarter ended  September 30,						Nine months ended  September 30,
($ thousands, except per share data)	2015			2014			2015			2014
Interest revenue		11,244			8,799			8,380			17,205
Other		578			1,950			3,013			9,136
Total revenue		11,822			10,749			11,393			26,341
Adminstrative and general expenses		(6,103	)		(7,661	)		(19,762	)		(28,116	)
Legal and professional fees		414			(4,841	)		(2,345	)		(10,583	)
Exploration costs, excluding exploration impairment		(27,172	)		(6,962	)		(54,144	)		(21,509	)
Exploration impairment		(78,236	)		-			(78,236	)		-
Finance costs, excluding interest expense		(1,917	)		(2,883	)		(10,514	)		(16,626	)
Gain on conveyance of exploration and evaluation assets		-			-			-			340,540
Foreign exchange (losses)/gains		(646	)		(528	)		872			4,542
Share of net losses of joint venture partnership accounted for using the equity method		-			(7	)		-			(26	)
EBITDA (1)		(101,838	)		(12,133	)		(152,736	)		294,563
Depreciation and amortization		(118	)		(923	)		(373	)		(3,272	)
Interest expense		(1,513	)		(1,367	)		(4,483	)		(9,946	)
(Loss)/profit for the period from continuing operations before income taxes		(103,469	)		(14,423	)		(157,592	)		281,345
Income tax expense		(256	)		(199	)		(534	)		(907	)
(Loss)/profit for the period from continuing operations		(103,725	)		(14,622	)		(158,126	)		280,438
(Loss)/profit for the period from discontinued operations, net of tax		-			(2,308	)		-			73,534
(Loss)/profit for the period		(103,725	)		(16,930	)		(158,126	)		353,972
Basic (loss)/earnings per share		(2.09	)		(0.34	)		(3.19	)		7.12
From continuing operations		(2.09	)		(0.29	)		(3.19	)		5.64
From discontinued operations		-			(0.05	)		-			1.48
Diluted (loss)/earnings per share		(2.09	)		(0.34	)		(3.19	)		7.12
From continuing operations		(2.09	)		(0.29	)		(3.19	)		5.64
From discontinued operations		-			(0.05	)		-			1.48
Total assets		1,231,923			1,337,452			1,231,923			1,337,452
Total liabilities		354,756			244,952			354,756			244,952
Total long-term liabilities		96,000			161,521			96,000			161,521

Notes:

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

Analysis Comparing Financial Condition as at September 30, 2015 and 2014

As at September 30, 2015, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 7%, compared to 6% as at September 30, 2014, well 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 2.8 times as at September 30, 2015, compared to 12.4 times as at September 30, 2014. The current ratio satisfied our internal target of above 1.5 times as at September 30, 2015.

Management Discussion and Analysis     INTEROIL CORPORATION     10

Variance in Total Assets:

As at September 30, 2015, our total assets amounted to $1,231.9 million, compared with $1,337.5 million as at September 30, 2014. The decrease of $105.6 million, or 8%, from September 30, 2014, was primarily due to:

- $324.4 million decrease in cash and cash equivalents and restricted cash, mainly attributable to the seismic activities carried out during the twelve months ended September 30, 2015 in addition to drilling activities for Triceratops-3 well, Wahoo-1 side track well, Antelope-4 well, Antelope-4 side track well and Antelope-5 well, as well as the site preparation costs incurred for Antelope-6 well and Triceratops-4 well.

- $17.5 million decrease in investments accounted for using the equity method, which is attributable to our share of losses incurred by PNG LNG, Inc. (a joint venture established in 2007 to hold the interests of certain joint venturers in the proposed venture to construct the proposed liquefaction facilities for development of the Elk-Antelope discovery in PRL 15), resulting from the impairment of joint venture assets, as we are now progressing the Papua LNG Project with Total.

These decreases have been partially offset by:

- $215.1 million increase in exploration and evaluation assets costs capitalized during the twelve months ended September 30, 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 partly 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.

- $25.5 million increase in trade and other receivables, mainly due to higher outstanding cash call receivables from joint venture partners as at the current quarter ended September 30, 2015.

Variance in Total Liabilities:

As at September 30, 2015, our total liabilities amounted to $354.8 million, compared with $245.0 million at September 30, 2014. The increase of $109.8 million, or 45%, from September 30, 2014, was primarily due to:

- $105.6 million increase in trade and other payables resulting from an increase in seismic and drilling payables as at September 30, 2015 due to increased activities in comparison to the previous year and PRL 15 non-operator costs accrual as at September 30, 2015.

Analysis of Consolidated Financial Results Comparing Quarters and Nine Months Ended September 30, 2015 and 2014

Our net loss for the quarter ended September 30, 2015 was $103.7 million, compared with a net loss of $16.9 million for the same quarter in 2014, an increase of $86.8 million. This was primarily due to the recognition of the $78.2 million exploration impairment relating to the write off of the Wahoo exploration well costs and the $20.2 million increase in exploration costs, mainly from the Murua seismic program in PPL 474 and PPL 476 during the quarter ended September 30, 2015. These increases have been partly reduced by the $5.3 million decrease in legal and professional fees, resulting from the higher consultant fees for group restructuring and arbitration on PRL 15 during the quarter ended September 30, 2014 and the reimbursement of $1.5 million legal expenses from Oil Search in relation to arbitration on PRL 15 during the quarter ended September 30, 2015; and the $2.4 million increase in interest accretion income on the receivables recognized in relation to interim resource payments expected under the Total SSA.

Our net loss for the nine months ended September 30, 2015 was $158.1 million, compared with a net profit of $354.0 million for the same period in 2014, a decrease of profit by $512.1 million. This primarily resulted from the recognition of the $340.5 million gain on conveyance of exploration and evaluation assets under the Total SSA during the nine months ended September 30, 2014, the $78.2 million exploration impairment recognized for the write off of the Wahoo exploration well costs, the $73.5 million profit from discontinued operations during the nine months ended September 30, 2014, and the $32.6 million increase in exploration costs incurred for the Murua seismic program in PPL 474 and PPL 476 and Raptor in PPL 475, rig 116 stack costs, rig 3 demobilization costs and airborne gravity survey costs during the nine months ended September 30, 2015.

Management Discussion and Analysis     INTEROIL CORPORATION     11

The table below analyzes key movements, the net of which primarily explains the variance in results between the quarters and nine months ended September 30, 2015 and 2014:

		Quarterly Variance ($ millions)	Nine Month Variance ($ millions)
		($86.8)	($512.1)	Net (loss)/profit variance for the comparative periods primarily due to:
Ø	Interest revenue	$2.4	($8.8)	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.  Decrease in interest income for the nine month period was mainly due to an adjustment to the amount receivable under the Total SSA as a result of a change in the timing of interim certification payments to June 2016.
Ø	Other revenue	($1.4)	($6.1)	Following divestment of our operating 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. We have moved to a more outsourced services model with third party rigs and related services rather than internally servicing exploration and development. Other revenues for the quarter and nine months ended September 30, 2015 were comprised of support services (post divestment) recharged to Puma.
Ø	Administrative and general expenses	$1.6	$8.4	The decrease in administrative and general expenses was mainly due to the new cost methodology employed since the fourth quarter of 2014, where operational costs were allocated to exploration and evaluation assets, rather than a standard cost recharge process, which previously resulted in expensing of under-recovered costs incurred for joint venture projects. A total of $3.0 million from administrative and general expenses for the nine months ended September 30, 2015 ($0.6 million for the quarter ended September 30, 2015) was charged to Puma as other revenue for certain support services provided post divestment. These services mainly related to computing and communications services and occupancy expenses in PNG.
Ø	Legal and professional fees	$5.3	$8.2	The decrease in legal and professional fees was mainly due to lower consultant fees during the quarter and nine months ended September 30, 2015, due to completion of the office transition from Cairns, Australia, and the arbitration on PRL 15. During the quarter ended September 30, 2015, we also received a reimbursement of legal expenses amounting to $1.5 million from Oil Search in relation to arbitration regarding PRL 15.
Ø	Exploration costs	($20.2)	($32.6)	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 due to the deferral of appraisal drilling until the completion of the Elk-Antelope appraisal program and rig 3 demobilization costs during the quarter and nine months ended September 30, 2015.

Management Discussion and Analysis     INTEROIL CORPORATION     12

Ø	Exploration impairment	($78.2)	($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, which was plugged and abandoned during the quarter ended September 30, 2015.
Ø	Finance costs	$1.0	$6.1	The decrease in finance costs was primarily due to facility fees for the Credit Suisse led syndicated facility and Westpac and BSP bridge facility during the quarter and nine months ended September 30, 2014. During the quarter and nine months ended September 30, 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 recognized during the nine months ended September 30, 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.
Ø	Foreign exchange (losses)/ gains	($0.1)	($3.7)	The decrease in foreign exchange gains was primarily due to lower depreciation of the PGK against USD as compared to the nine months ended September 30, 2014.
Ø	Depreciation and amortization	$0.8	$2.9	The decrease in depreciation expense was due to capitalization of depreciation for supporting assets to respective projects during the nine months ended September 30, 2015.  Depreciation of assets supporting exploration costs that were expensed has been included in the exploration costs line above.
Ø	Interest expense	($0.1)	$5.5	The decrease in interest expense was largely due to use of the Credit Suisse led syndicated facility and the Westpac and BSP bridge facility during the quarter and nine months ended September 30, 2014. During the quarter and nine months ended September 30, 2015, the Credit Suisse led syndicated facility was not used. The interest expense comprised the interest and accretion in relation to the Convertible Notes.
Ø	(Loss)/profit from discontinued operations	$2.3	($73.5)	The decrease in profit from discontinued operations resulted from the sale of the refinery, distribution and shipping business during the nine months ended September 30, 2014 as a result of the Puma Transaction.

Analysis of Consolidated Cash Flows Comparing Quarters and Nine Months Ended September 30, 2015 and 2014

As at September 30, 2015, we had cash, cash equivalents, and restricted cash of $126.3 million (September 30, 2014 - $450.7 million), of which $8.2 million (September 30, 2014 - $8.3 million) was restricted. Of the total restricted cash at September 30, 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.

Management Discussion and Analysis     INTEROIL CORPORATION     13

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 and nine months ended September 30, 2014 in the table below:

	Quarter ended September 30,						Nine months ended September 30,
($ thousands)	2015			2014			2015			2014
Net cash (outflows)/inflows from:
Operations		(16,700	)		(50,621	)		(61,126	)		(60,905	)
Investing		(57,488	)		(32,337	)		(214,202	)		668,806
Financing		-			(41,754	)		-			(227,492	)
Net cash movement		(74,188	)		(124,712	)		(275,328	)		380,409
Opening cash		192,265			567,088			393,405			61,967
Closing cash		118,077			442,376			118,077			442,376

Cash flows used in operating activities

Cash outflows from operating activities for the quarter ended September 30, 2015 were $16.7 million compared with an outflow of $50.6 million for the quarter ended September 30, 2014, a net decrease in cash outflows of $33.9 million. Cash outflows from operating activities for the nine months ended September 30, 2015 were $61.1 million compared with an outflow of $60.9 million for the nine months ended September 30, 2014, a net increase in cash outflows of $0.2 million.

This table outlines key variances in the cash inflows/(outflows) from operating activities between the quarters and nine months ended September 30, 2015 and 2014:

		Quarterly variance ($ millions)	Nine Months variance ($ millions)
		$33.9	($0.2)	Variance for the comparative periods primarily due to:
Ø	Cash used in operations, before changes in operating working capital	($16.4)	($63.3)	The increase in cash used in operations, before changes in operating working capital for the nine month period, 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 prior nine months ended September 30, 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	$50.3	$63.1	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.

Management Discussion and Analysis     INTEROIL CORPORATION     14

Cash flows (used in)/generated from investing activities

Cash outflows from investing activities for the quarter ended September 30, 2015 were $57.5 million compared with an outflow of $32.3 million for the quarter ended September 30, 2014, a net increase in cash outflows of $25.2 million. Cash outflows from investing activities for the nine months ended September 30, 2015 were $214.2 million compared with an inflow of $668.8 million for the nine months ended September 30, 2014, a net increase in cash outflows of $883.0 million.

This table outlines key variances in cash (outflows)/inflows from investing activities between the quarters and nine months ended September 30, 2015 and 2014:

		Quarterly variance ($ millions)	Nine Months variance ($ millions)
		($25.2)	($883.0)	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 nine months ended September 30, 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 nine months ended September 30, 2014.
Ø	Decrease in restricted cash held as security on borrowings	($17.4)	($44.8)	The movement in restricted cash held as security on borrowings for the nine month period 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 nine months ended September 30, 2014. The movement in restricted cash held as security on borrowings for the quarter was mainly due to the release of cash held as deposit on a rig lease from the restricted cash and replaced with a non-cash backed letter of credit during the quarter ended September 30, 2014.
Ø	Expenditure on exploration and evaluation assets net of JV contributions	$33.7	$34.4	The decrease in expenditure on exploration and evaluation assets is due to a reduction in exploration drilling in the quarter and nine months ended September 30, 2014.
Ø	Expenditure on plant and equipment	$1.7	$11.2	The decrease in expenditure on plant and equipment for the nine month period was mainly due to sale of the refinery and distribution businesses to Puma during the nine months ended September 30, 2014.
Ø	Cash (used in)/ generated from investing activities relating to change in non-operating working capital	($43.2)	($55.2)	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 for transfer of operatorship to Total.

Management Discussion and Analysis     INTEROIL CORPORATION     15

Cash flows used in financing activities

Cash flow movement from financing activities for the quarter ended September 30, 2015 amounted to zero, compared with an outflow of $41.8 million for the quarter ended September 30, 2014, a net decrease of cash outflows of $41.8 million. Cash outflows from financing activities for the nine months ended September 30, 2015 amounted to zero, compared with an outflow of $227.5 million for the nine months ended September 30, 2014, a net decrease in cash outflows of $227.5 million.

This table outlines key variances in cash inflows/(outflows) from financing activities between quarters and nine months ended September 30, 2015 and 2014:

		Quarterly variance ($ millions)	Nine Months  variance ($ millions)
		$41.8	$227.5	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 nine months ended September 30, 2014.
Ø	Proceeds from drawdown of Credit Suisse secured facility	$0.0	($50.0)	Drawdown of $50.0 million from the Credit Suisse led syndicated secured loan facility during the nine months ended September 30, 2014.
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 nine months ended September 30, 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 nine months ended September 30, 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 nine months ended September 30, 2014.
Ø	Proceeds from issue of common shares	$0.0	($2.2)	Movement due to cash receipts from the exercise of stock options during the nine months ended September 30, 2014.
Ø	Payment on share buyback	$41.8	$41.8	Movement due to the cash paid for the redemption of 730,000 common shares during the quarter and nine months ended September 30, 2014.

Management Discussion and Analysis     INTEROIL CORPORATION     16

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended September 30, 2015 on a consolidated basis.

Quarters ended  ($ thousands except per share	2015									2014											2013
data)	Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31		Dec-31
Total revenues		11,822			(13,643	)		13,215			(13,182	)		10,749			13,689			1,903		712
EBITDA (1)		(101,838	)		(30,583	)		(20,317	)		(60,443	)		(12,133	)		(10,253	)		316,948		(27,272	)
Net (loss)/profit		(103,725	)		(32,531	)		(21,869	)		(64,205	)		(16,930	)		52,265			318,636		(24,812	)
From continuing operations		(103,725	)		(32,531	)		(21,869	)		(62,474	)		(14,622	)		(15,765	)		310,824		(32,024	)
From discontinued operations		-			-			-			(1,731	)		(2,308	)		68,030			7,812		7,212
Basic (loss)/earnings per share		(2.09	)		(0.66	)		(0.44	)		(1.30	)		(0.34	)		1.05			6.46		(0.50	)
From continuing operations		(2.09	)		(0.66	)		(0.44	)		(1.26	)		(0.29	)		(0.31	)		6.30		(0.65	)
From discontinued operations		-			-			-			(0.04	)		(0.05	)		1.36			0.16		0.15
Diluted (loss)/earnings per share		(2.09	)		(0.66	)		(0.44	)		(1.30	)		(0.34	)		1.05			6.38		(0.50	)
From continuing operations		(2.09	)		(0.66	)		(0.44	)		(1.26	)		(0.29	)		(0.31	)		6.22		(0.65	)
From discontinued operations		-			-			-			(0.04	)		(0.05	)		1.36			0.16		0.15

(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. In addition, the shipping business, which was previously included within the Corporate segment, has also been classified as a discontinued operation as the activities of that business were transferred with the sale of the refining and distribution businesses. At September 30, 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.

Management Discussion and Analysis     INTEROIL CORPORATION     17

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

This table summarizes the debt facilities available to us and the balances outstanding as at September 30, 2015:

Organization	Facility		Balance outstanding September 30, 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 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.

No drawdowns had been made under this facility as at September 30, 2015. As at September 30, 2015, we were in compliance with the debt covenants, which include a defined calculation for gearing not to exceed 60% at any time, a requirement that the equity does not fall below $500.0 million at any time and agreed expenditure limits tested for the six months period ending March 31 and September 30 each year. The Convertible Notes mature on November 15, 2015 and we intend to repay the Convertible Notes in full upon maturity.

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

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 September 30, 2015 were a net decrease of $11.2 million. Total net capital expenditure for the nine months ended September 30, 2015 was $135.2 million.

This analysis outlines key net capital expenditure in the quarter and nine months ended September 30, 2015:

Management Discussion and Analysis     INTEROIL CORPORATION     18

	Quarterly movement ($ millions)	Nine Months movement ($ millions)
	$471.4	$325.0	Opening balance of exploration and evaluation assets
	($11.2)	$135.2	Net capital expenditure consisting of following:
Ø	$1.8	$1.3	Costs for site preparation and pre-spud work of Raptor-1 side track.
Ø	($56.8)	($36.0)	Recognition of exploration impairment relating to the Wahoo exploration well costs, which was plugged and abandoned during the quarter ended September 30, 2015.
Ø	($1.1)	$6.3	Costs for testing of Bobcat-1.
Ø	$23.3	$51.6	Costs for site preparation, pre-spud work and drilling of Triceratops-3.
Ø	$1.0	$1.5	Costs for site preparation of Triceratops-4.
Ø	$1.9	$17.7	Costs for drilling of Antelope-4.
Ø	$15.5	$20.0	Costs for site preparation, pre-spud work and drilling of Antelope-4 side track.
Ø	$2.6	$17.1	Costs for drilling and interference test for Antelope-5.
Ø	$0.9	$8.9	Costs for site preparation and pre-spud work for Antelope-6.
Ø	$0.4	$9.6	Appraisal seismic over the Raptor field.
Ø	($1.3)	$13.2	Appraisal seismic over the Bobcat and Triceratops fields.
Ø	($6.2)	$1.7	Decrease in inventories for the quarter was mainly due to the consumption of inventory in operations and inventories sold to Total.
Ø	$5.8	$5.8	Costs for development survey, environmental and societal studies, preparation works, project finance and operator transition for Papua LNG Project.
Ø	($1.4)	$8.7	Expenditure for concept select studies led by Total for the Elk and Antelope fields in PRL 15.
Ø	$2.4	$7.8	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.
	$460.2	$460.2	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 September 30, 2015 was $101.1 million. Total gross capital expenditure for the nine months ended September 30, 2015 was $395.5 million.

This analysis outlines key gross capital expenditures in the quarter and nine months ended September 30, 2015:

	Quarterly movement ($ millions)	Nine Months movement ($ millions)
	$101.1	$395.5	Gross capital expenditure consisting of following:
Ø	$4.5	$3.8	Costs for site preparation and pre-spud work of Raptor-1 side track.

Management Discussion and Analysis     INTEROIL CORPORATION     19

Ø	($0.1)	$13.9	Appraisal seismic over the Raptor field.
Ø	($0.0)	$2.0	Costs for care and maintenance of the suspended Wahoo-1 well.
Ø	$19.1	$38.0	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 side track.
Ø	($1.6)	$7.5	Costs for testing of Bobcat-1.
Ø	$1.5	$17.0	Appraisal seismic over the Bobcat and Triceratops fields.
Ø	$47.7	$90.7	Costs for site preparation, pre-spud and drilling work for Triceratops-3.
Ø	$1.7	$2.2	Costs for site preparation of Triceratops-4.
Ø	$0.1	$1.2	Testing costs for Antelope-1.
Ø	$0.4	$45.3	Costs for drilling of Antelope-4.
Ø	$21.2	$33.5	Costs for site preparation, pre-spud work and drilling of Antelope-4 side track.
Ø	$2.3	$59.1	Costs for drilling and interference test for Antelope-5.
Ø	$2.2	$37.1	Costs for site preparation and pre-spud work for Antelope-6.
Ø	$2.0	$6.6	Costs for site preparation of Antelope South.
Ø	($1.0)	$26.6	Expenditure and true up costs for concept select studies led by Total for the Elk and Antelope fields in PRL 15.
Ø	$5.9	$5.9	Costs for development survey, environmental and societal studies, preparation works, project finance and operator transition for Papua LNG Project.
Ø	($6.2)	$1.7	Decrease in inventories for the quarter was mainly due to the consumption of inventory in operations and inventories sold to Total.
Ø	$1.4	$3.4	Other expenditures, including equipment purchases, indirect project support costs and field care and maintenance for PRL 15.

Capital Requirements

Existing cash balances and credit facilities will be sufficient to settle debt obligations and facilitate further development of the Elk and Antelope fields, appraisal of Triceratops and exploration to meet our license commitments. 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 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 on terms that are acceptable to us, particularly with market volatility.

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.

Management Discussion and Analysis     INTEROIL CORPORATION     20

	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
PPL and PRL		381,521		9,105		-		176,866		250		195,300		-
Convertible Notes obligations		70,319		70,319		-		-		-		-		-
Total		451,840		79,424		-		176,866		250		195,300		-

The PPL and PRL amounts represent our commitments for these licenses as at September 30, 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. The new licenses included commitments for us to spend $351.9 million over the remainder of the six-year terms.

The terms of grant of PRL 39 require us to spend $29.6 million on the license area by the end of 2018.

Off Balance Sheet Arrangements

During the quarter ended, nor as at September 30, 2015, we had no off balance sheet arrangements or relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

No related party transaction took place during the quarter and nine months ended September 30, 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 September 30, 2015, we had 49,560,160 common shares issued and outstanding (50,697,369 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at September 30, 2015 included employee stock options and restricted stock in respect of 405,205 common shares and 732,004 common shares relating to the $70.0 million of Convertible Notes.

As of November 10, 2015, we had 49,560,611 common shares issued and outstanding (50,707,095 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as November 10, 2015 included employee stock options and restricted stock in respect of 414,480 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.

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 nine months ended September 30, 2015, there were no changes in the methodology used to make critical accounting estimates to those disclosed in our 2014 MD&A.

Management Discussion and Analysis     INTEROIL CORPORATION     21

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 September 30, 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.

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.

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     22

Quarters ended	2015									2014												2013
($ thousands)	Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31			Dec-31
Earnings before interest, taxes, depreciation and amortization		(101,838	)		(30,583	)		(20,317	)		(60,443	)		(12,133	)		(10,253	)		316,948			(27,272	)
Interest expense		(1,513	)		(1,492	)		(1,477	)		(1,464	)		(1,367	)		(4,409	)		(4,170	)		(2,546	)
Income taxes		(256	)		(207	)		(70	)		(211	)		(199	)		(194	)		(514	)		(791	)
Depreciation and amortisation		(118	)		(249	)		(5	)		(356	)		(923	)		(909	)		(1,440	)		(1,415	)
From continuing operations		(103,725	)		(32,531	)		(21,869	)		(62,474	)		(14,622	)		(15,765	)		310,824			(32,024	)
From discontinued operations		-			-			-			(1,731	)		(2,308	)		68,030			7,812			7,212
Net (loss)/profit		(103,725	)		(32,531	)		(21,869	)		(64,205	)		(16,930	)		52,265			318,636			(24,812	)

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 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     23

Material Changes in Internal Control over Financial Reporting

No material change in our internal controls over financial reporting were identified during the nine months ended September 30, 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     24