Exhibit 99.1

InterOil Corporation Management Discussion and Analysis   For the quarter and nine months ended September 30, 2014 November 14, 2014  

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	9
DISCOUNTINUED OPERATIONS	15
LIQUIDITY AND CAPITAL RESOURCES	17
RISK FACTORS	21
CRITICAL ACCOUNTING ESTIMATES	21
NEW ACCOUNTING STANDARDS	21
NON-GAAP MEASURES AND RECONCILIATION	22
PUBLIC SECURITIES FILINGS	22
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	23

This Management Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2013 and our annual information form (the “2013 Annual Information Form”) for the year ended December 31, 2013. This MD&A was prepared by management and provides a review of our performance for the quarter and nine months ended September 30, 2014, and of our financial condition and future prospects.

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

References to “we,” “us,” “our,” “Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information is presented as at September 30, 2014 and for the quarter and nine months ended September 30, 2014 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this MD&A.

Management Discussion and Analysis       INTEROIL CORPORATION         1

FORWARD-LOOKING STATEMENTS

This MD&A contains “forward-looking statements” as defined in U.S. federal and Canadian securities laws. Such statements are generally identifiable by the terminology used such as “may,” “plans,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “forecasts,” “budgets,” “targets” or other similar wording suggesting future outcomes or statements regarding an outlook. We have based these forward-looking statements on our current expectations and projections about future events. All statements, other than statements of historical fact, included in or incorporated by reference in this MD&A are forward-looking statements.

Forward-looking statements include, without limitation, statements regarding our business strategies and plans; plans for our exploration (including drilling plans) and other business activities and results therefrom; characteristics of our properties; construction and development of a proposed LNG plant in Papua New Guinea; the timing and cost of such construction and development; commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; and timing, maturity and amount of future capital and other expenditures.

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

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

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

· inherent uncertainty of oil and gas exploration;

· the 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;

· 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;

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

· 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.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements will eventuate. In light of the significant uncertainties inherent in our forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved. Some of these assumptions and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading “Risk Factors” in our 2013 Annual Information Form.

Management Discussion and Analysis       INTEROIL CORPORATION         2

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

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

Note:

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

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

Management Discussion and Analysis       INTEROIL CORPORATION         3

OIL AND GAS DISCLOSURES

We are required to comply with Canadian Securities Administrators’ NI 51-101 (as defined herein), which prescribes disclosure of oil and gas reserves and resources. GLJ Petroleum Consultants Ltd., an independent qualified reserve evaluator based in Calgary, Canada, has evaluated our resources data as at December 31, 2013 in accordance with NI 51-101. This evaluation is summarized in our 2013 Annual Information Form available at www.sedar.com. We do not have any production or reserves, including proved reserves, as defined under NI 51-101 or as per the guidelines set by the SEC, as at September 30, 2014.

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

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

GLOSSARY OF TERMS

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

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

“Board” means the board of directors of InterOil.

“BSP” means Bank of South Pacific Limited.

“CBA” means Commonwealth Bank of Australia.

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

“CSP” or “Condensate Stripping Project” means the proposed condensate stripping facilities, including gathering and condensate pipeline, condensate storage and associated facilities which were to have been developed by the CSP Joint Venture.

“Condensed Consolidated Interim Financial Statements” means the unaudited condensed consolidated interim financial statements for the quarter and nine months ended September 30, 2014.

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

“Credit Suisse” means Credit Suisse A.G.

“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”.

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

“GAAP” means Canadian generally accepted accounting principles.

Management Discussion and Analysis       INTEROIL CORPORATION         4

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

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

“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.

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

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

“natural gas” means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth's surface, often in association with petroleum. The principal constituent is methane.

“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities adopted by the Canadian Securities Administrators.

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

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

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

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

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

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

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

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

“Puma Transaction” means the transaction by which Puma acquired all of the shares of certain of our subsidiaries that held our refinery and petroleum products distribution businesses for approximately $525.6 million, by way of two share sale and purchase agreements, which include adjustments for cash and working capital. The transaction was completed on June 30, 2014.

Management Discussion and Analysis       INTEROIL CORPORATION         5

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

“SocGen” means Societe Generale Hong Kong branch.

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

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

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

“Total SSA” means an agreement under which Total acquired, through the purchase of all of the shares of SPI (200) Limited, a wholly owned subsidiary, a gross 40.1275% interest in PRL 15. This agreement replaced the Total SPA on March 26, 2014.

“UBS” means UBS A.G.

“USD” means United States dollars.

“Westpac” means Westpac Bank PNG Limited.

Management Discussion and Analysis       INTEROIL CORPORATION         6

INTRODUCTION

We are an independent oil and gas business with a primary focus on Papua New Guinea. Our assets include the Elk, Antelope and Triceratops 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 September 30, 2014, we had 378 full-time employees.  

Prior to the Puma Transaction, our operations were organized into four major segments; further details of these segments can be found in the “Discontinued Operations” section of this MD&A. Following the Puma Transaction, we are an upstream exploration and production business.

BUSINESS STRATEGY

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

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

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

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

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

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

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

· Geophysical programs

- During the quarter, we acquired seismic data across a number of leads during the Zebra seismic program targeting PPL 476, and across the Antelope field in PRL 15 during the Antelope South appraisal program.

- During the quarter, we also commenced a geophysical survey over the Antelope field in PRL 15, Antelope Deep prospect in PRL 15 with survey extensions into PPL 476, and Mule Deer lead in PPL 475.

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

- On September 16, 2014, we spudded the Antelope-4 appraisal well.

- We have also started the site preparation activities for the Antelope-5 well. Spudding of the Antelope-5 appraisal well is expected during the last quarter of 2014.

- Progress continues with engineering and technical studies being conducted by Total towards concept selection of the development option for the PRL15 gas fields.

· PRL 39 – Triceratops-3 appraisal well

- We have contracted a drilling rig to be mobilized to Papua New Guinea in 2015. This rig will be utilized for drilling of the Triceratops-3 appraisal well.

Management Discussion and Analysis       INTEROIL CORPORATION         7

· PPL 474 - Wahoo drilling program

- Wahoo-1 exploration well is about 170 kilometers southeast of our Elk and Antelope gas fields.

- On July 14, 2014, we announced that we had suspended drilling the Wahoo-1 well in PPL 474 after intersecting gas and higher-than expected pressures that could compromise rig safety. Significant concentrations of methane, ethane, propane and butane were recorded, believed to be entering the well bore from permeable zones above the predicted reservoir zone, which was yet to be penetrated. Further drilling is required to confirm the presence of a reservoir below the current total depth of the well before Wahoo can be considered a discovery. The State Department of Petroleum and Energy approved this suspension to enable us to re-evaluate the drilling plan.

- We intend to resume operations following a detailed review of well engineering, equipment, options, and following regulatory approval of our revised plans. Our current expectation is for the re-drill of the Wahoo prospect to commence in 2015.

· PPL 475 – Raptor drilling program

- Raptor-1 exploration well is about 12 kilometers west of our Elk and Antelope gas fields.

- On October 21, 2014, we announced that Raptor-1 well has intersected 200m of the Kapau Limestone target zone, with wireline logs indicating the presence of hydrocarbons. On November 6, 2014, we further announced that gas and condensate has been recorded at surface and directed through the flare at the well site. We plan to conduct well testing to determine the hydrocarbon type, column, flow rate and reservoir quality.

· PPL 476 – Bobcat drilling program

- Bobcat-1 exploration well is about 30 kilometers northwest of our Elk and Antelope gas fields.

- On October 21, 2014, we announced that Bobcat-1 well has successfully drilled through the Orubadi seal section and into the Kapau Limestone. After running and cementing a 5 inch liner, we continued to drill further into the target zone. During the week commencing November 10, 2014, the well was drilled to a final total depth of 3,208 meters after intersecting an interval of about 320 meters of Kapau Limestone. Wireline logging operations are currently underway to determine the presence of hydrocarbons.

· Other matters

- During the quarter, we redeemed and terminated 730,000 common shares for a total purchase price of $41.8 million.

- On August 10, 2014, we appointed Chris Finlayson, former BG Group Chief Executive Officer and Shell executive, as our Chairman-designate. Mr. Finlayson has nearly 40 years’ global experience and has led exploration and production ventures with BG Group and Shell. He replaced Dr. Gaylen Byker as our Chairman on October 16, 2014, who formally retired from the Board on the same date.

- On September 8, 2014, Laurie Brown was appointed as Senior Vice President, Exploration. Mr. Brown has more than 30 years’ international industry experience, including with BP, and as a Shell Global Consultant. He oversees our exploration strategy, exploration portfolio management, geoscience, and field data acquisition programs, including seismic and other technologies. His focus will be on identifying new exploration opportunities in our exploration licenses as we seek to expand and maximize the value of our portfolio.

Management Discussion and Analysis       INTEROIL CORPORATION         8

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Quarters and Nine Months Ended September 30, 2014 and 2013

Consolidated – Operating results	Quarter ended September 30,						Nine months ended September 30,
($ thousands, except per share data)	2014			2013			2014			2013
				(revised)  (2)						(revised)  (2)
Interest revenue		8,799			17			17,205			63
Other		1,950			600			9,136			1,987
Total revenue		10,749			617			26,341			2,050
Adminstrative and general expenses		(7,662	)		(2,833	)		(28,116	)		(15,615	)
Derivative gains/(losses)		-			45			-			(146	)
Legal and professional fees		(4,841	)		(1,781	)		(10,583	)		(4,390	)
Exploration costs, excluding exploration impairment		(6,963	)		(2,992	)		(21,509	)		(3,963	)
Finance costs, excluding interest expense		(2,883	)		(633	)		(16,626	)		(633	)
Gain on conveyance of exploration and evaluation assets		-			-			340,540			500
Gain on available-for-sale investment		-			4,747			-			3,720
Foreign exchange (losses)/gains		(528	)		153			4,542			(319	)
Share of net (losses)/gains of joint venture partnership accounted for using the equity method		(7	)		2,578			(26	)		2,265
EBITDA (1)		(12,135	)		(99	)		294,563			(16,531	)
Depreciation and amortization		(922	)		(1,483	)		(3,272	)		(4,318	)
Interest expense		(1,367	)		(2,212	)		(9,946	)		(5,894	)
(Loss)/profit for the period from continuing operations before income taxes		(14,424	)		(3,794	)		281,345			(26,743	)
Income tax (expense)/benefit		(198	)		239			(907	)		(149	)
(Loss)/profit for the period from continuing operations		(14,622	)		(3,555	)		280,438			(26,892	)
(Loss)/profit for the period from discontinued operations, net of tax		(2,309	)		(2,763	)		73,534			11,347
(Loss)/profit for the period		(16,931	)		(6,318	)		353,972			(15,545	)
Basic (loss)/earnings per share		(0.34	)		(0.13	)		7.12			(0.32	)
From continuing operations		(0.29	)		(0.07	)		5.64			(0.55	)
From discontinued operations		(0.05	)		(0.06	)		1.48			0.23
Diluted (loss)/earnings per share		(0.34	)		(0.13	)		7.12			(0.32	)
From continuing operations		(0.29	)		(0.07	)		5.64			(0.55	)
From discontinued operations		(0.05	)		(0.06	)		1.48			0.23
Total assets		1,337,452			1,263,110			1,337,452			1,263,110
Total liabilities		244,952			512,705			244,952			512,705
Total long-term liabilities		161,521			249,058			161,521			249,058

Notes:

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

(2) Revised to effect reclassification of discontinued operations – refer to Note 4 of the Condensed Consolidated Interim Financial Statements for further details.

Management Discussion and Analysis       INTEROIL CORPORATION         9

Analysis Comparing Financial Condition as at September 30, 2014 and 2013

As at September 30, 2014, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 6%, compared to 20% as at September 30, 2013, well below our targeted maximum gearing level of 50%. Gearing targets are based on several factors including operating cash flows, future cash needs for development, capital market and economic conditions, and are assessed regularly. Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 12.4 times as at September 30, 2014, compared to 1.3 times as at September 30, 2013. The current ratio satisfied our internal target of above 1.5 times as at September 30, 2014.

Variance in Total Assets:

As at September 30, 2014, our total assets amounted to $1,337.5 million, compared with $1,263.1 million as at September 30, 2013. This increase of $74.4 million, or 6%, from September 30, 2013 was primarily due to:

- $371.4 million increase in cash and cash equivalents and restricted cash, mainly due to 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 quarter ended September 30, 2014; and

- $499.6 million increase in trade and other receivables, 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:

- $324.8 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 period; and

- Puma Transaction resulted in the decrease in plant and equipment by $231.8 million, inventories by $178.5 million and deferred tax assets by $53.7 million.

Variance in Total Liabilities:

As at September 30, 2014, our total liabilities amounted to $245.0 million, compared with $512.7 million at September 30, 2013. The decrease of $267.7 million, or 52%, from September 30, 2013 was primarily due to:

- A decrease of $123.3 million in secured and unsecured loans payable due to the full repayment in June 2014 of the BSP and Westpac combined secured loan facility, and the ANZ, BSP and BNP syndication loan facility;

- Puma Transaction resulted in the decrease in working capital facilities by $107.6 million and income tax payable by $13.5 million.

Analysis of Consolidated Financial Results Comparing Quarters and Nine Months Ended September 30, 2014 and 2013

Our net loss for the quarter ended September 30, 2014 was $16.9 million, compared with a net loss of $6.3 for the same quarter in 2013, an increase of $10.6 million.

Our net profit for the nine months ended September 30, 2014 was $354.0 million, compared with a net loss of $15.5 for the same period in 2013, an increase of profit by $369.5 million which was primarily driven by the gain on conveyance in relation to the Total SSA and the Puma Transaction.

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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, 2014 and 2013:

	Quarterly Variance ($ millions)	Nine Month Variance ($ millions)
	($10.6)	$369.5	Net (loss)/profit variance for the comparative periods primarily due to:
Ø	$0.0	$340.0	Gain on conveyance of exploration and evaluation assets in relation to the completion of the Total SSA on March 26, 2014 under which Total acquired, through the purchase of all shares of a wholly owned subsidiary, a gross participating interest of 40.1275% (net 31.0988%, after the State back-in right of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields.
Ø	$0.5	$62.2	Increase in profit from discontinued operations for the nine months ended September 30, 2014, primarily derived from the $49.5 million gain from the Puma Transaction and the profits of the operating business during the first half of 2014 prior to the Puma Transaction.
Ø	($4.8)	($12.5)	Increase in office and administration and other expenses for the quarter was mainly due to a $1.9 million increase in share compensation expenses due to a new grant of restricted stock units and accelerated stock compensation expenses on options owned by retired senior management or employees affected by the Puma Transaction; an increase in the support and management costs incurred as a result of increased operations regarding three wells being drilled simultaneously and a $0.9 million restructuring costs relating to the closure of the corporate office in Cairns, Australia.
			Increase in office and administration and other expenses for the nine month period resulted from $4.8 million restructuring costs relating to the closure of the corporate office in Cairns, Australia; an increase in the support and management costs incurred as a result of increased operations regarding three wells being drilled simultaneously; a $2.3 million increase in share compensation expenses due to a new grant of restricted stock units and accelerated stock compensation expenses on options owned by retired senior management or employees affected by Puma Transaction; and offset by a $2.5 million decrease in redundancy payroll costs as a result of the retirement of senior executives paid during the nine months ended September 30, 2013.
Ø	($3.1)	($6.2)	Increase in legal and professional fees was primarily associated with the group restructure transactions undertaken during the current period in association with the sell down of PRL 15 interests and divestment of operations, and Oil Search arbitration related expenditure.
Ø	($4.0)	($17.5)	Increase in exploration costs was mainly attributable to the expensing of seismic activities over the Bobcat, Zebra-Razorback leads and Antelope Deep prospects during the periods.
Ø	($2.3)	($16.0)	Increase in finance costs is primarily a result of the facility fees incurred for Credit Suisse facility that was obtained in Q4 2013 and refinanced in June 2014.  As at September 30, 2014, there were no draw downs made on the refinanced Credit Suisse facility.
Ø	$8.8	$17.1	Increase in interest income was attributable to the interest accretion income on the receivables recognized in relation to interim resource payments expected from Total SSA calculated using the best case scenario provided by GCA of 7.10 Tcfe for the Elk and Antelope fields.
Ø	$1.3	$7.1	Increase in other revenues for the quarter resulted from recharges to Puma on certain transition services provided post divestment.  Increase in other revenues for the nine months ended September 30, 2014 resulted from higher recoveries and increased utilization relating to exploration services (offset by an increase in the costs incurred by these services as a result of increased operations).  Following the divestment of the 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 the exploration and development activities.  These costs have been allocated to those activities as a recovery of cost, rather than as other revenue.  We are also moving to more outsourced services model with third party rigs and services rather than internally servicing the exploration and development operations.

Management Discussion and Analysis       INTEROIL CORPORATION         11

Ø ($4.7) ($3.7) Decrease in gain on available-for-sale investment was due to the gain recognized for the sale of FLEX LNG shares during the quarter and nine months ended September 30, 2013.

Analysis of Consolidated Cash Flows Comparing Quarters and Nine Months Ended September 30, 2014 and 2013

As at September 30 2014, we had cash, cash equivalents, and restricted cash of $450.7 million (September 30, 2013 - $79.3 million), of which $8.3 million (September 30, 2013 - $38.9 million) was restricted. Of the total restricted cash, $8.0 million (September 30, 2013 - $Nil) was restricted as a debt reserve under the Credit Suisse syndicated secured loan and the balance was made up of a cash deposit on office premises and term deposits on our PPLs.

Cash flows from discontinued operations have been combined with the cash flows from continuing operations in the consolidated statements of cash flows for the quarter and nine months ended September 30, 2014 and 2013.

	Quarter ended September 30,						Nine Months ended September 30,
($ thousands)	2014			2013			2014			2013
Net cash (outflows)/inflows from:
Operations		(50,621	)		26,140			(60,905	)		9,500
Investing		(32,337	)		(25,626	)		668,806			(89,042	)
Financing		(41,754	)		(24,929	)		(227,492	)		70,260
Net cash movement		(124,712	)		(24,415	)		380,409			(9,282	)
Opening cash		567,088			64,842			61,967			49,721
Exchange losses on cash and cash equivalents		-			(22	)		-			(32	)
Closing cash		442,376			40,405			442,376			40,405

Cash flows (used in)/generated from operating activities

Cash outflows from operating activities for the quarter ended September 30, 2014 were $50.6 million compared with an inflow of $26.1 million for the quarter ended September 30, 2013, a net increase in cash outflows of $76.7 million. Cash outflows from operating activities for the nine months ended September 30, 2014 were $60.9 million compared with an inflow of $9.5 million for the quarter ended September 30, 2013, a net increase in cash outflows of $70.4 million.

Management Discussion and Analysis       INTEROIL CORPORATION         12

This table outlines key variances in the cash (outflows)/inflows from operating activities between the quarters and nine months ended September 30, 2014 and 2013:

	Quarterly variance ($ millions)	Nine Month variance ($ millions)
	($76.7)	($70.4)	Variance for the comparative periods primarily due to:
Ø	($17.8)	($26.9)	Increase in cash used in operations prior to changes in operating working capital for the quarter was mainly due to the increase in net loss from operations adjusted for the increased accretion income on receivable. Increase in cash used in operations prior to changes in operating working capital for the nine month period was mainly due to the increase in net profit from operations adjusted for the increase in gain on conveyance of PRL 15, gain on the Puma Transaction, and accretion income on non-current receivable; and partly offset by the increased amortization of deferred financing costs.
Ø	($58.9)	($43.5)	Increase in cash employed by operations relating to changes in operating working capital for the quarter was due to a $39.3 million increase in trade and other receivables, a $35.9 million decrease in accounts payable and accrued liabilities, and offset by a $12.4 million decrease in inventories and a $3.9 million decrease in other current assets and prepaid expenses mainly on completion of Puma Transaction. Increase in cash employed by operations relating to changes in operating working capital for the nine month period was due to a $69.8 million increase in trade and other receivables and a $1.6 million increase in inventories; and offset by a $23.9 million increase in accounts payable and accrued liabilities and a $4.0 million decrease in other current assets and prepaid expenses mainly on completion of Puma Transaction.

Cash flows (used in)/generated from investing activities

Cash outflows from investing activities for the quarter ended September 30, 2014 were $32.3 million compared with an outflow of $25.6 million for the quarter ended September 30, 2013. Cash inflows from investing activities for the nine months ended September 30, 2014 were $668.8 million compared with an outflow of $89.0 million for the quarter ended September 30, 2013.

This table outlines key variances in cash (outflows)/inflows from investing activities between the quarters and nine months ended September 30, 2014 and 2013:

	Quarterly variance ($ millions)	Nine Month variance ($ millions)
	($6.7)	$757.8	Variance for the comparative periods primarily due to:
Ø	$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.
Ø	$0.0	$401.3	Receipt of a $401.3 million completion payment from Total in accordance with the Total SSA during quarter ended March 31, 2014.
Ø	$23.8	$34.8	The reduction in restricted cash requirements during the nine months ended September 30, 2014, was mainly due to the transfer of restricted cash balances to Puma as part of the Puma Transaction. During the quarter ended September 30, 2014, a total of $17.5 million cash held as deposit on a rig lease was released from restricted cash and replaced with a non-cash backed letter of credit.

Management Discussion and Analysis       INTEROIL CORPORATION         13

Ø	($69.4)	($196.5)	Increase in cash outflows on exploration and development expenditures was mainly due to the increased drilling activities (3 wells being drilled simultaneously in current period as opposed to no drilling in prior periods) and transaction costs associated with the completion of the Total SSA.
Ø	$23.6	$32.2	Higher cash calls and related inflows from joint venture partners relating to the receipt of funds from PRE for historical Triceratops-2 well costs, the receipt of funds from Oil Search in relation to the Tagula seismic program, and the receipt of cash calls from Total and Oil Search on PRL 15 appraisal programs.
Ø	$16.3	$57.4	Movement in non-operating working capital for the periods were primarily related to trade payables and accruals in our exploration and development operations.

Cash flows (used in)/generated from financing activities

Cash outflows from financing activities for the quarter ended September 30, 2014 amounted to $41.8 million, compared with an outflow of $24.9 million for the quarter ended September 30, 2013. Cash outflows from financing activities for the nine months ended September 30, 2014 amounted to $227.5 million, compared with an inflow of $70.3 million for the nine months ended September 30, 2013.

This table outlines key variances in cash (outflows)/inflows from financing activities between quarters and nine months ended September 30, 2014 and 2013:

	Quarterly variance ($ millions)	Nine Month variance ($ millions)
	($16.9)	($297.8)	Variance for the comparative periods primarily due to:
Ø	$34.4	$34.4	Termination settlement to Mitsui for the Condensate Stripping Project funding provided by Mitsui and related interests during quarter ended September 30, 2013.
Ø	$10.7	$12.9	Full settlement of the outstanding secured loan from Westpac during quarter ended September 30, 2013.
Ø	($34.6)	($59.4)	Net repayment of the BSP and Westpac combined secured loan facility during the nine months ended September 30, 2014.
Ø	$0.0	($100.0)	Drawdown of $50.0 million from the Credit Suisse syndicated secured loan facility during the quarter ended March 31, 2014, a further $100.0 million during the quarter ended June 30, 2014 and the full loan repayment of $150.0 million in June 2014.
Ø	$0.0	($73.6)	Receipt of a $76.0 million staged cash payment from PRE for the sale of a 10.0% net (12.9% gross) participating interest in PPL 237 (now PPL 475) during the quarter ended March 31, 2013 and a $2.4 million commission was subsequently paid to PacLNG for facilitating the transaction during the quarter ended June 30, 2013.
Ø	$14.4	$7.6	Movement in utilization of the BNP working capital facility in our discontinued operations from Puma Transaction.
Ø	$0.0	($76.0)	Full repayment of the ANZ, BSP and BNP syndicated loan was made in June 2014.
Ø	($41.8)	($41.8)	During the quarter ended September 30, 2014, we redeemed 730,000 common shares with a total purchase price of $41.8 million.

Management Discussion and Analysis       INTEROIL CORPORATION         14

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended September 30, 2014 on a consolidated basis.

	2014								2013												2012
Quarters ended ($ thousands except per share data)	Sep-30			Jun-30 (2)			Mar-31 (2)		Dec-31 (2)			Sep-30 (2)			Jun-30 (2)			Mar-31 (2)			Dec-31 (2)
Total revenues		10,749			13,689			1,903		712			617			831			602			8,188
EBITDA (1)		(12,135	)		(10,252	)		316,949		(27,272	)		(99	)		(11,293	)		(5,138	)		(22,452	)
Net (loss)/profit		(16,931	)		52,266			318,637		(24,812	)		(6,318	)		(13,230	)		4,003			(3,732	)
From continuing operations		(14,622	)		(15,764	)		310,825		(32,024	)		(3,555	)		(15,240	)		(8,096	)		(27,512	)
From discontinued operations		(2,309	)		68,030			7,812		7,212			(2,763	)		2,010			12,099			23,780
Basic (loss)/earnings per share		(0.34	)		1.05			6.46		(0.50	)		(0.13	)		(0.27	)		0.08			(0.08	)
From continuing operations		(0.29	)		(0.31	)		6.30		(0.65	)		(0.07	)		(0.31	)		(0.17	)		(0.57	)
From discontinued operations		(0.05	)		1.36			0.16		0.15			(0.06	)		0.04			0.25			0.49
Diluted (loss)/earnings per share		(0.34	)		1.05			6.38		(0.50	)		(0.13	)		(0.27	)		0.08			(0.09	)
From continuing operations		(0.29	)		(0.31	)		6.22		(0.65	)		(0.07	)		(0.31	)		(0.17	)		(0.57	)
From discontinued operations		(0.05	)		1.36			0.16		0.15			(0.06	)		0.04			0.25			0.48

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

(2) Revised to effect reclassification of discontinued operations – refer to Note 4 of the Condensed Consolidated Interim Financial Statements for the quarter and nine months ended September 30, 2014 and 2013 for further details.

DISCOUNTINUED OPERATIONS

Prior to the Puma Transaction, our operations were organized into four major segments:

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

The subsidiaries sold pursuant to the Puma Transaction were previously included within the Midstream Refining and Downstream segments respectively. In addition, the shipping business which was previously included within the Corporate segment has also been transferred to Puma. Following the Puma Transaction, the results of these operations have been classified as ‘discontinued operations’ and we are no longer organized as separate segments for reporting purposes. All balance sheet items under refinery and distribution businesses were derecognized from the consolidated balance sheet as of June 30, 2014.

Management Discussion and Analysis       INTEROIL CORPORATION         15

We made a gain on the Puma Transaction of $49.5 million during the quarter ended June 30, 2014. The gain has been calculated as follows:

($ thousands)	June 30, 2014
Consideration
Cash		525,590
Less settlement of intercompany debt		(52,877	)
Less amount refundable to Puma		(1,038	)
Less transaction costs		(4,258	)
Total consideration		467,417
Assets and liabilities disposed of
Cash and cash equivalents		39,432
Trade and other receivables		150,375
Other current assets		94
Inventories		143,542
Prepaid expenses		3,547
Plant and equipment		230,682
Deferred tax assets		46,354
Trade and other payables		(110,338	)
Income tax payable		(21,190	)
Derivative financial instruments		(2,243	)
Working capital facilities		(57,234	)
Asset retirement obligations		(5,140	)
Net assets disposed of		417,881
Net gain on sale of subsidiaries		49,536

Summary of Debt Facilities Repaid or Transferred to Puma

Below is a table listing the debt facilities that were either repaid in full or transferred to Puma in connection with the Puma Transaction on June 30, 2014.

Organization	Segment	Facility		Original Maturity dates
ANZ, BSP and BNP syndicated secured loan facility	Midstream - Refining	$	100,000,000	November 2017
BNP working capital facility	Midstream - Refining	$	270,000,000	February 2015
BNP non-recourse discounting facility	Midstream - Refining	$	80,000,000	February 2015
Westpac PGK working capital facility	Downstream	$	18,540,000	November 2014
BSP PGK working capital facility	Downstream	$	18,540,000	November 2014
BSP and Westpac combined secured facility	Downstream	$	24,780,077	August 2014

Management Discussion and Analysis       INTEROIL CORPORATION         16

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, 2014.

Organization	Facility		Balance outstanding September 30, 2014		Weighted average interest rate			Maturity date
Credit Suisse syndicated, senior secured capital expenditure facility	$	300,000,000		$Nil		Nil%		December 2015
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 Syndicated Secured Loan

On June 17, 2014, we replaced our $250.0 million loan with Credit Suisse with a $300.0 million syndicated, senior secured capital expenditure facility through a consortium of banks led by Credit Suisse. CBA, ANZ, UBS, Macquarie, BSP, BNP and Westpac, each of which was a participating lender under the original facility, in addition to new banks, MUFG and SocGen, support the new facility. The new facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2015. No draw downs have been made under the new facility as at September 30, 2014.

Unsecured 2.75% Convertible Notes

On November 10, 2010, we completed the issuance of $70.0 million of Convertible Notes. 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 syndicated secured loan facility, trade payables and lease obligations.

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

Other Sources of Capital

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

Cash calls are made on Total, Oil Search and PNGDV for their share and carry (where applicable) of expenditure on appraisal wells and extended well programs under agreements we have with them. Cash calls will also be made on PRE for exploration activities in PPL 475 (formerly PPL 237) and appraisal activities in the Triceratops field.

Management Discussion and Analysis       INTEROIL CORPORATION         17

With the immediate cash payment from the Puma Transaction, we are able to focus on the funding of our exploration and appraisal programs, as well as our growth strategy.

Capital Expenditure

Net expenditure on exploration and evaluation assets

Net capital expenditures on our exploration and evaluation assets in Papua New Guinea for the quarter ended September 30, 2014 were $78.4 million, compared with $31.2 million during the same period of 2013. Total net expenditures for the nine month period ended September 30, 2014 were $272.2 million compared to $59.1 million during the same period in 2013.

This analysis outlines key net expenditures in the quarter and nine months ended September 30, 2014:

	Quarterly movement ($ millions)	Nine Month movement ($ millions)
	$166.7	$584.8	Opening balance of exploration and evaluation assets
	$78.3	$272.1	Net capital expenditure consisting of following:
Ø	$27.3	$63.7	Costs for site preparation, pre-spud work and drilling of the Raptor-1 well.
Ø	$7.0	$33.5	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 well.
Ø	$21.6	$53.7	Costs for site preparation, pre-spud work and drilling of the Bobcat-1 well.
Ø	$0.8	$46.8	Costs incurred for financial advisor fees and transaction costs for the monetization of the Elk and Antelope fields.
Ø	$0.0	$41.5	Premium paid on buyback of 1.0536% indirect participation interest in PRL 15.
Ø	$1.8	$6.9	Seismic over the Antelope field in PRL 15.
Ø	$1.6	$2.1	Costs for site preparation, pre-spud work and drilling of the Antelope-4 well.
Ø	$1.3	$1.5	Costs for site preparation, pre-spud work for Antelope-5 well.
Ø	$11.1	$13.5	Expenditure on drilling inventory.
Ø	$5.8	$8.9	Other expenditure, including equipment purchases and a portion of Antelope-4 and Antelope-5 well costs that have been carried by Total but included in our net share of costs as the carry has been offset against the Interim Resource Payment receivable from Total.
	$0.0	($611.9)	Allocation of costs against Total SSA proceeds
	$245.0	$245.0	Closing balance of exploration and evaluation assets

Gross expenditure on exploration and evaluation assets

Gross capital expenditures on our exploration and evaluation assets in Papua New Guinea for the quarter ended September 30, 2014 was $105.5 million. Total gross expenditures for the nine month period ended September 30, 2014 were $341.8 million.

This analysis outlines key gross expenditures in the quarter and nine months ended September 30, 2014:

Management Discussion and Analysis       INTEROIL CORPORATION         18

	Quarterly movement ($ millions)	Nine Month movement ($ millions)
	$105.5	$341.8	Gross capital expenditure consisting of following:
Ø	$32.6	$88.5	Costs for site preparation, pre-spud work and drilling of the Raptor-1 well.
Ø	$6.5	$35.1	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 well.
Ø	$20.9	$58.1	Costs for site preparation, pre-spud work and drilling of the Bobcat-1 well.
Ø	$0.8	$46.8	Costs incurred for financial advisor fees and transaction costs for the monetization of the Elk and Antelope fields.
Ø	$0.0	$41.5	Premium paid on buyback of 1.0536% indirect participation interest in PRL 15.
Ø	$4.9	$15.9	Seismic over the Antelope field in PRL 15.
Ø	$16.2	$21.5	Costs for site preparation, pre-spud work and drilling of the Antelope-4 well.
Ø	$7.2	$9.9	Costs for site preparation, pre-spud work for Antelope-5 well.
Ø	$11.1	$13.5	Expenditure on drilling inventory.
Ø	$5.3	$11.0	Other expenditure, including equipment purchases.

Capital expenditure on plant and equipment

In addition, $3.3 million was incurred on corporate related capital expenditure for the nine months ended September 30, 2014, including $2.1 million for renovation costs of our new Singapore office and $0.7 million for the acquisition of corporate apartments and office renovations in Papua New Guinea.

Capital Requirements

Existing cash balances will be sufficient to settled debt obligations and facilitate further necessary development of the Elk and Antelope fields, appraisal of Triceratops field and exploration activities planned to meet our license commitment requirements. However, oil and gas exploration and development and liquefaction are capital intensive and our business plans involve raising capital, which depends on market conditions when we raise such capital. No assurance can be given that we will be successful in obtaining new capital on terms that are acceptable to us, particularly with market volatility.

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 and notes thereto.

Management Discussion and Analysis       INTEROIL CORPORATION         19

	Payments Due by Period
Contractual obligations ($ thousands)	Total		Less than 1 year		1 - 2 years		2 - 3 years		3 - 4 years		4 - 5 years		More than 5 years
Petroleum prospecting and retention licenses		467,403		69,362		72,850		93,275		93,515		97,713		40,688
Convertible Notes obligations		72,244		1,925		70,319		-		-		-		-
Total		539,647		71,287		143,169		93,275		93,515		97,713		40,688

The amount pertaining to the petroleum prospecting and retention licenses represents the amount the Company has committed on these licenses as at September 30, 2014. On March 6, 2014, the Company’s applications for new petroleum prospecting licenses were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238 and included new license commitments. The new commitments require the Company to spend an additional $381.0 million over the remainder of their six year term.

Further, the terms of grant of PRL 15 require the Company to spend a further $20.2 million on the development of the Elk and Antelope fields by the end of 2015 and the grant of PRL 39 requires the Company to spend a further $66.2 million on the license area by the end of 2018.

Off Balance Sheet Arrangements

Neither during the quarter ended, nor as at September 30, 2014, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Transactions with Related Parties

During the nine months ended September 30, 2014, former Chief Financial Officer, Collin Visaggio, former Chief Operating Officer, William Jasper, and former Vice President of Investor Relation, Wayne Andrews retired.  Compensation paid or payable to these officers upon their retirement was $1.3 million, $0.65 million and $0.2 million respectively.

Share Capital

Our authorized share capital consists of an unlimited number of common shares and unlimited number of preferred shares, of which 1,035,554 series A preferred shares are authorized (none of which are outstanding). As of September 30, 2014, we had 49,404,087 common shares issued and outstanding (50,671,062 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at September 30, 2014 included employee stock options and restricted stock in respect of 410,000 common shares and 124,971 common shares relating to the $70.0 million principal amount Convertible Notes.

As of November 7, 2014, we had 49,409,788 common shares (50,693,639 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at November 7, 2014 included employee stock options and restricted stock in respect of 551,847 common shares and 732,004 common shares relating to the $70.0 million principal amount 2.75% convertible senior notes due November 15, 2015.

During the quarter, we redeemed and terminated 730,000 common shares for a total purchase price of $41.8 million.

Management Discussion and Analysis       INTEROIL CORPORATION         20

RISK FACTORS

Our business operations and financial position are subject to risks. A summary of the key risks that may affect matters addressed in this document have been included under “Forward Looking Statements” above. Detailed risk factors can be found under “Risk Factors” in our 2013 Annual Information Form available at www.sedar.com.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires our management to make estimates and assumptions that affect the amounts reported in the Condensed Consolidated Interim Financial Statements and accompanying notes. Actual results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the Condensed Consolidated Interim Financial Statements as estimating it is impracticable. During the quarter ended September 30, 2014, there were no changes in the critical accounting estimates disclosed in our annual management discussion and analysis for the year ended December 31, 2013.

For a discussion of those accounting policies, please refer to Note 2 of the notes to our audited annual consolidated financial statements for the year ended December 31, 2013, available at www.sedar.com, which summarizes our significant accounting policies.

However, we would like to highlight that we have a total of approximately $179.4 million in temporary differences and carried forward losses for exploration expenditure in Papua New Guinea. No deferred tax assets have been recognized for this exploration expenditure as at September 30, 2014. The initial tax benefit to be recognized would be 30% of the temporary differences and losses carried forward through the income statement. We will consider recognition of the deferred tax assets when we have more certainty around the timing of assessable income in the exploration and development operations.

Legal and Other Contingent Matters

We are required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the amount of a contingent loss is determined it is charged to earnings. We continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted.

On March 27, 2014, we received notification from Oil Search Limited of a dispute under the Joint Venture Operating Agreement relating to PRL 15 in Papua New Guinea. The dispute relates to the sale by us of a subsidiary, SPI (200) Limited, to Total. The entity held a 40.1% interest in PRL 15 at the time of the sale. The matter has been referred to arbitration and is scheduled to be heard in late November 2014 by the ICC International Court of Arbitration. We do not expect the claim to be successful and do not expect the dispute to have any financial impact, except for the incurring of legal expenses which may not be recovered.

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at September 30, 2014

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

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

Management Discussion and Analysis       INTEROIL CORPORATION         21

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

- IFRS 15 ‘Revenue from contracts with customers’ (effective from January 1, 2015): 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. This standard will not have a material impact on InterOil.

NON-GAAP MEASURES AND RECONCILIATION

Non-GAAP measures, including EBITDA, included in this MD&A are not defined nor have a standardized meaning prescribed by IFRS or our previous GAAP. Accordingly, they may not be comparable to similar measures provided by other issuers.

EBITDA represents our net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is used by us to analyze operating performance. EBITDA does not have a standardized meaning prescribed by GAAP (i.e. IFRS) and, therefore, may not be comparable with the calculation of similar measures for other companies. The items excluded from EBITDA are significant in assessing our operating results. Therefore, EBITDA should not be considered in isolation or as an alternative to net earnings, operating profit, net cash provided from operating activities and other measures of financial performance prepared in accordance with IFRS. Further, EBITDA is not a measure of cash flow under IFRS and should not be considered as such.

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

	2014									2013												2012
Quarters ended ($ thousands)	Sep-30			Jun-30			Mar-31 (1)			Dec-31 (1)			Sep-30 (1)			Jun-30 (1)			Mar-31 (1)			Dec-31 (1)
Earnings before interest, taxes, depreciation and amortization		(12,135	)		(10,252	)		316,949			(27,272	)		(99	)		(11,293	)		(5,138	)		(22,452	)
Interest expense		(1,367	)		(4,409	)		(4,170	)		(2,546	)		(2,212	)		(2,082	)		(1,600	)		(1,601	)
Income taxes		(198	)		(195	)		(514	)		(791	)		239			(458	)		70			(497	)
Depreciation and amortisation		(922	)		(908	)		(1,440	)		(1,415	)		(1,483	)		(1,407	)		(1,428	)		(2,962	)
From continuing operations		(14,622	)		(15,764	)		310,825			(32,024	)		(3,555	)		(15,240	)		(8,096	)		(27,512	)
From discontinued operations		(2,309	)		68,030			7,812			7,212			(2,763	)		2,010			12,099			23,780
Net (loss)/profit		(16,931	)		52,266			318,637			(24,812	)		(6,318	)		(13,230	)		4,003			(3,732	)

(1) Revised to effect reclassification of discontinued operations – refer to Note 4 of the Condensed Consolidated Interim Financial Statements for further details.

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2013 Annual Information Form, in documents filed with the Canadian Securities Administrators at www.sedar.com, and in documents, including our Form 40-F, filed with the U.S. Securities and Exchange Commission at www.sec.gov. Additional information is also available on our website www.interoil.com.

Management Discussion and Analysis       INTEROIL CORPORATION         22

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to us is made known to our Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by us in our annual filings, interim filings or other reports filed or submitted by us under securities legislation is recorded, processed, summarized and reported within the time specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our disclosure controls and procedures at our financial year-end and have concluded that our disclosure controls and procedures are effective at December 31, 2013 for the foregoing purposes.

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

Internal Controls over Financial Reporting

Our Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of our internal controls over financial reporting at our financial year-end and concluded that our internal control over financial reporting is effective, at December 31, 2013, for the foregoing purpose.

Material Changes in Internal Control over Financial Reporting

Effective July 1, 2014, as a result of the Puma Transaction, we ceased operating approximately 40% of our key controls that were specific to the divested operations. In addition, during the quarter ended September 30, 2014, we have relocated most of our core finance and information management functions from our office in Cairns, Australia, to our offices in Singapore and Papua New Guinea. In particular, the relocation of these functions resulted in changes to personnel, especially those associated with operating key controls or modification of processes associated with key controls.  These changes have been evaluated against our key account balances, and based on this evaluation, we believe that we have designed adequate and appropriate internal control over financial reporting to ensure that the financial statements are materially accurate for the nine months ended September 30, 2014.

Other than the changes resulting from the Puma Transaction and the office relocation, there have been no changes in internal control over financial reporting during the nine months ended September 30, 2104 that have materially affected, or are reasonably likely to materially affect, our internal control 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         23