EX-99.3 4 v404576_ex3.htm EXHIBIT 3

Exhibit 3

InterOil Corporation
Management
Discussion and Analysis

For the year ended December 31, 2014
March 17, 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	8
SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS	12
DISCOUNTINUED OPERATIONS	19
LIQUIDITY AND CAPITAL RESOURCES	21
RISK FACTORS	26
CRITICAL ACCOUNTING ESTIMATES	26
NEW ACCOUNTING STANDARDS	27
NON-GAAP MEASURES AND RECONCILIATION	28
PUBLIC SECURITIES FILINGS	28
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING	29

This MD&A (as defined herein) should be read in conjunction with our audited annual consolidated financial statements and accompanying notes for the year ended December 31, 2014 and our 2014 AIF (as defined herein) for the year ended December 31, 2014. This MD&A was prepared by management and provides a review of our performance for the year ended December 31, 2014, and of our financial condition and future prospects.

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

In this MD&A, references to “we,” “us,” “our,” “the Company,” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. Information is presented in this MD&A as at December 31, 2014 and for the year ended December 31, 2014 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this MD&A.

Management Discussion and Analysis INTEROIL CORPORATION 1

FORWARD-LOOKING STATEMENTS

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

Forward-looking statements include, without limitation, statements regarding our business strategies and plans; plans for 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; 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;

we will be transitioning the operatorship of PRL 15 to Total in accordance with the provisions of the JVOA;

the difficulties with recruitment and retention of qualified personnel;

the political, legal and economic risks in Papua New Guinea;

landowner claims and disruption;

compliance with and changes in Papua New Guinean laws and regulations, including environmental laws;

the exploration and production businesses are competitive;

the inherent limitations in all control systems, and misstatements due to errors that may occur and not be detected;

exposure to certain uninsured risks stemming from our operations;

contractual defaults;

weather conditions and unforeseen operating hazards;

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

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

risk of legal action against us; and

law enforcement difficulties.

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to us concerning anticipated financial conditions and performance, business prospects, strategies, regulatory developments, the ability to attract joint venture partners, future hydrocarbon commodity prices, the ability to secure adequate capital funding, the ability to obtain equipment and qualified personnel in a timely manner to develop resources, the ability to obtain financing on acceptable terms, and the ability to develop reserves and production through development and exploration activities.

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

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

GLOSSARY OF TERMS

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

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

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

“Board” means the board of directors of InterOil.

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

“BSP” means Bank of South Pacific Limited.

“CBA” means Commonwealth Bank of Australia.

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

“CSP” 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, a joint venture with Mitsui pursuant to the Joint Venture Operating Agreement entered into for the proposed condensate stripping facilities with Mitsui, which terminated on February 28, 2013.

Management Discussion and Analysis INTEROIL CORPORATION 4

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

“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 Papua New Guinea Government department responsible for regulating oil and gas activities in Papua New Guinea.

“EBITDA” represents net income/(loss) plus total interest expense (excluding amortization of debt issuance costs), income tax expense, depreciation and amortization expense. EBITDA is a non-GAAP measure used to analyze operating performance. See “Non-GAAP Measures and Reconciliation”.

“FID” means final investment decision.

“GAAP” means Canadian generally accepted accounting principles.

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

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

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

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

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

“JVOA” means Joint Venture Operating Agreement.

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

“LNG” means liquefied natural gas. Natural gas may be converted to a liquid state by pressure and severe cooling for transportation purposes, and then returned to a gaseous state to be used as fuel. LNG, which is predominantly artificially liquefied methane, is not to be confused with NGLs, natural gas liquids, which are heavier fractions that occur naturally as liquids.

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

“Macquarie” means Macquarie Group Limited.

“MD&A” means this Management’s Discussion and Analysis for the year ended December 31, 2014.

“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).

Management Discussion and Analysis INTEROIL CORPORATION 5

“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.

“PNGEI” means PNG Energy Investors LLC, a former indirect participating investor.

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

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

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

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

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

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

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

“SocGen” means Societe Generale Hong Kong branch.

“State” or “PNG” means the independent State of Papua New Guinea.

“Tcfe” means trillion standard cubic feet equivalent.

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

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

Management Discussion and Analysis INTEROIL CORPORATION 6

“UBS” means UBS A.G.

“USD” means United States dollars.

“Westpac” means Westpac Bank PNG Limited.

INTRODUCTION

We are an independent oil and gas business with a sole focus on Papua New Guinea. Our assets include licenses covering the Elk, Antelope, Triceratops, Raptor and Bobcat fields in the Gulf Province of Papua New Guinea, and exploration licenses covering about 16,000 square kilometers (about 4 million acres) in Papua New Guinea. We have our main offices in Singapore and Port Moresby. We are listed on the New York Stock Exchange and the Port Moresby Stock Exchange. At December 31, 2014, we had 361 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 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.

Management Discussion and Analysis INTEROIL CORPORATION 7

OPERATIONAL HIGHLIGHTS

Summary of operational highlights

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

New license applications

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

Airborne Field Survey

During late 2014, final contract negotiations were completed with CGG for acquisition of high resolution airborne Falcon gravity gradiometry over all our licenses. Subsequent to year end, acquisition of these surveys commenced on January 17, 2015.

Seismic

In 2014, 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 (formerly Antelope Deep) seismic appraisal program. We also commenced a geophysical survey (Magnetotellurics) over the Antelope field in PRL 15, Antelope South prospect in PRL 15 with survey extensions into PPL 476, and Mule Deer lead in PPL 475.

The Murua seismic program in PPL474 commenced on November 4, 2014 with acquisition expected to be completed mid-March 2015. In late 2014, we began planning and initial preparation for an appraisal seismic program over the Raptor discovery. The Raptor seismic program commenced January 22, 2015. Appraisal seismic acquisition over the Bobcat discovery will follow on from the Raptor program.

Exploration program and appraisal drilling

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

PPL 474 - Wahoo drilling program

Wahoo-1 exploration well is about 170 kilometers southeast of our Elk and Antelope gas fields. The well was spudded on March 10, 2014.

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. 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. Before Wahoo can be considered a discovery, further drilling is required to confirm the presence of a reservoir below the current total depth of the well. The DPE 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 regulatory approval of our revised plans. We currently expect to recommence drilling in 2015.

Management Discussion and Analysis INTEROIL CORPORATION 8

PPL 475 – Raptor drilling program

Raptor-1 exploration well is about 12 kilometers west of our Elk and Antelope gas fields. The well was spudded on March 28, 2014.

On October 21, 2014, we announced that Raptor-1 well had intersected 200 meters of the Kapau Limestone target zone, with wireline logs indicating the presence of hydrocarbons. On November 6, 2014, we announced that gas and condensate has been recorded at surface and directed through the flare at the well site.

On November 14, 2014, we notified the DPE of a discovery at Raptor-1 well. Results from the testing program, including pressure measurements, support the presence of a hydrocarbon column in excess of the 200 meter gross gas interval already encountered by the well. Logs indicate a highly fractured reservoir system and mud loss during drilling supports the likely connectivity of the fracture network.

The well was drilled to final total depth of 4,032 meters. We will continue comprehensive planning of future Raptor appraisal work, which will include additional appraisal seismic, appraisal drilling and a comprehensive testing program.

PPL 476 – Bobcat drilling program

Bobcat-1 exploration well is about 30 kilometers northwest of our Elk and Antelope gas fields. The well was spudded on March 5, 2014.

On October 21, 2014, we announced that Bobcat-1 well had successfully drilled through the Orubadi seal section and into the Kapau Limestone. During the week commencing November 10, 2014, the well was drilled to a final total depth of 3,207 meters after intersecting an interval of about 320 meters of Kapau Limestone.

On December 11, 2014, we announced that the well was tested over an interval of about 320 meters of Kapau limestone, the upper section of the target reservoir, and flowed and flared hydrocarbons at surface. Seismic mapping, wireline logging and testing results indicate the well is close to the gas-water contact in the transition zone. We notified the DPE of a discovery at the Bobcat-1 exploration well, with a total depth of 3,207 meters.

The well was further deepened to 3,501 meters by year end as the first part of the appraisal program to appraise reservoir quality. Further seismic program is planned in 2015 over the discovery to further evaluate the commerciality.

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

On September 16, 2014, we spudded the Antelope-4 appraisal well. The Antelope-4 appraisal well intersected the top reservoir at 1,911 meters. During January 2015, a derrick structural member was noted as being slightly bowed outside tolerance. The repairs were carried out and drilling recommenced post-re-certification and approval from the DPE.

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

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

PRL15 – Total SSA

As part of our strategy to monetize gas resources, we signed and completed on March 26, 2014 the Total SSA under which Total acquired, through the purchase of all shares of a wholly owned subsidiary, a gross participating interest of 40.1275% (net 31.0988%, after the State back-in right of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields.

	-	We retained 35.4839% (net 27.5%, after the State back-in right of 22.5%) of the PRL. Under the transaction with Total, we received $401.3 million as a completion payment, and are entitled to receive payments of $73.3 million upon a FID for an Elk and Antelope LNG Project, and $65.5 million upon the first LNG cargo shipment from such LNG Project.
	-	In addition to these fixed amounts, Total is obliged to make variable payments for resources in PRL 15 that are in excess of 3.5 Tcfe, based on certification by two independent certifiers following the drilling of up to three appraisal wells in PRL 15. Payments for resources greater than 5.4 Tcfe will be paid at certification.
	-	Total will carry 75% of costs relating to our participating interest in a maximum of three appraisal wells (up to a maximum of $50.0 million per well on a 100% basis). Certification of the Elk and Antelope resources under the Total SSA is expected in 2015.

Management Discussion and Analysis INTEROIL CORPORATION 9

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

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

On February 27, 2014, Oil Search agreed to acquire shares in certain PacLNG entities that hold a 22.835% interest in PRL 15 for a consideration of $900.0 million plus further contingent payments based on resource certification.

On March 27, 2014 we received notification from Oil Search Limited of a dispute under the JVOA relating to PRL 15. The dispute related to the Total SSA, and Oil Search’s claim to have pre-emptive rights over the transaction under the JVOA. The matter was referred to arbitration and was heard in late November 2014 by the ICC International Court of Arbitration (the “ICA’). The ICA dismissed all claims by the PacLNG companies, affiliates of Oil Search, and declared that Oil Search had no pre-emptive rights as per their claims.

Subsequent to the year ended December 31, 2014, on February 27, 2015, all participants in PRL 15 unanimously voted to appoint Total as operator. The appointment will take effect in accordance with an operator transition plan and the terms of the JVOA. The appointment is subject to all necessary PNG Government approvals.

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 during 2015.

Pacific Rubiales Energy farm-in

On March 13, 2013, we completed the farm-in transaction with PRE originally entered into in July 2012 related to PREs acquisition of a 10.0% net (12.9% gross) participating interest in PPL 237 (now PPL 475), including the Triceratops structure and exploration acreage located within that license. PRE funded the final payment of $55.0 million of the full $116.0 million contribution due under the farm-in agreement. PacLNG and its affiliates are participating on a 25% beneficial equity basis in the portion of the PRE farm-in relating to PRL 39 by selling PRE a 3.2258% participating interest before State participation (2.5% after State participation). Other indirect participating interest holders are also participating by selling PRE a 0.6591% participating interest before State participation, 0.5108% after State participation. Neither PacLNG Group nor any of the IPI holders participated in the sale of the indirect interest in PPL 475.

On January 17, 2014, we agreed to amend the JVOA to cap PRE’s carry for each well at $25.0 million, with costs in excess of this to be borne by the parties according to their equity participation interests.

Sale of refinery and distribution assets

On June 30, 2014, we completed the Puma Transaction for gross proceeds of $525.6 million, and made a gain on the Puma Transaction of $49.5 million. 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 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. The continuing operations are considered to be an Upstream Exploration and Production business.

Management Discussion and Analysis INTEROIL CORPORATION 10

Financing

On June 17, 2014, we replaced our $250.0 million facility 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. Subsequent to the year end, on March 17, 2015, we signed an amendment to further extend the maturity date on this facility to the end of 2016 with Credit Suisse, CBA, ANZ, UBS AG, Macquarie, BSP, Westpac, MUFG and SocGen participating in the extension.

Other matters

On July 21, 2014, we announced the plan to buy up to $50.0 million of our common shares within the next twelve months. We appointed Macquarie as our broker to handle the share buy-back. We redeemed and terminated 730,000 of our common shares during the year ended December 31, 2014 for a total purchase price of $41.8 million.

On August 10, 2014, we appointed Chris Finlayson, former BG Group Chief Executive Officer and former 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.

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

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

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

Management Discussion and Analysis INTEROIL CORPORATION 11

SELECTED FINANCIAL INFORMATION AND HIGHLIGHTS

Consolidated Results for the Year Ended December 31, 2014, 2013 and 2012

Consolidated – Operating results	Year ended December 31,
($ thousands, except per share data)	2014			2013			2012
Interest revenue		1,991			71			62
Other		11,168			2,692			10,361
Total revenue		13,159			2,763			10,423
Adminstrative and general expenses		(39,245	)		(19,165	)		(18,129	)
Derivative (losses)/gains		-			(146	)		11
Legal and professional fees		(14,091	)		(9,801	)		(3,847	)
Exploration costs, excluding exploration impairment		(34,529	)		(18,794	)		(13,901	)
Finance costs, excluding interest expense		(18,578	)		(4,687	)		-
Gain on conveyance of exploration and evaluation assets		340,540			500			4,418
Gain on available-for-sale investment		-			3,720			-
Foreign exchange gains/ (losses)		4,421			(467	)		(420	)
Share of net (losses)/gains of joint venture partnership accounted for using the equity method		(17,558	)		2,274			(490	)
EBITDA ⁽¹⁾		234,119			(43,803	)		(21,935	)
Depreciation and amortization		(3,628	)		(5,733	)		(4,045	)
Interest expense		(11,409	)		(8,440	)		(6,187	)
Profit/(loss) for the period from continuing operations before income taxes		219,082			(57,976	)		(32,167	)
Income tax expense		(1,119	)		(940	)		(321	)
Profit/(loss) for the period from continuing operations		217,963			(58,916	)		(32,488	)
Profit for the period from discontinued operations, net of tax		71,803			18,558			34,092
Profit/(loss) for the period		289,766			(40,358	)		1,604
Basic earnings/(loss) per share		5.84			(0.83	)		0.04
From continuing operations		4.39			(1.21	)		(0.67	)
From discontinued operations		1.45			0.38			0.71
Diluted earnings/(loss) per share		5.82			(0.83	)		0.02
From continuing operations		4.38			(1.21	)		(0.67	)
From discontinued operations		1.44			0.38			0.69
Total assets		1,340,130			1,305,799			1,303,297
Total liabilities		311,477			572,978			527,240
Total long-term liabilities		96,000			236,741			196,029

Notes:

(1)

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

Management Discussion and Analysis INTEROIL CORPORATION 12

Analysis Comparing Financial Condition as at December 31, 2014, 2013 and 2012

As at December 31, 2014, our debt-to-capital ratio (being debt divided by [shareholders’ equity plus debt]) was 6%, compared to 26% as at December 31, 2013 and 19% as at December 31, 2012, well below our targeted maximum gearing level of 50%. Gearing targets are based on several factors including operating cash flows, future cash needs for development, capital market and economic conditions, and are assessed regularly. Our current ratio (being current assets divided by current liabilities), which measures our ability to meet short-term obligations, was 4.5 times as at December 31, 2014, compared to 1.0 times as at December 31, 2013 and 1.4 times as at December 31, 2012. The current ratio satisfied our internal target of above 1.5 times as at December 31, 2014.

Variance in Total Assets:

As at December 31, 2014, our total assets amounted to $1,340.1 million, compared with $1,305.8 million as at December 31, 2013 and $1,303.3 million as at December 31, 2012. The increase of $34.3 million, or 3%, from December 31, 2013 was primarily due to:

$286.5 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 year ended December 31, 2014; and

$467.7 million increase in trade and other receivables, largely as a result of the recognition of the interim resource payment receivable in relation to the conveyance proceeds from Total SSA calculated using the best case scenario provided by GCA of 7.10 Tcfe for the Elk and Antelope fields.

These increases have been partially offset by:

$259.8 million decrease in exploration and evaluation assets, primarily resulting from the allocation of Total SSA conveyance proceeds against the respective PRL 15 capitalized costs on the balance sheet prior to recognizing any gain on conveyance during the year;

$17.6 million decrease in investments accounted for using equity method, which is attributable to our share of losses incurred by the PNG LNG joint venture resulting from the impairment of joint venture assets, as we are now progressing the LNG Project development jointly with Total; and

The Puma Transaction resulted in the decrease in plant and equipment by $232.1 million, inventories by $158.1 million and deferred tax assets by $48.2 million.

Comparing December 31, 2013 to December 31, 2012, the increase of total assets of $2.5 million or 0.2% was primarily due to the capitalization of expenditure of our oil and gas properties of $74.1 million associated mainly with appraisal of the Elk and Antelope fields and preparatory work for drilling three exploration wells within our PPL 236, PPL 237 and PPL 238 licenses (since replaced with PPL 474, PPL 475, PPL476 and PPL 477); the $24.7 million increase in non-current receivables attributable to credits given to PacLNG and other indirect participating interest holders for their participation in the sell down of interest as part of the Farm-in transaction with PRE; and the $17.6 million increase in equity accounted investment in Midstream Liquefaction joint venture due to adoption of ‘IFRS 11 Joint Agreements’. These increases were offset by a $62.9 million decrease in our trade and other receivables due to change in our discounting facility to a non-recourse basis, and receipt of $29.9 million from IPI partners in settlement of other receivables outstanding at December 31, 2012; a $36.8 million decrease in crude and products inventory balances due to shipment timing; a $15.3 million decrease in deferred tax assets mainly resulting from the impact of unfavorable foreign exchange movements affecting temporary differences on translation of non-monetary assets of the refinery operation using year-end rates; and a $10.6 million decrease in plant and equipment mainly due to depreciation charges incurred during the year.

Variance in Total Liabilities:

As at December 31, 2014, our total liabilities amounted to $311.5 million, compared with $573.0 million at December 31, 2013 and $527.2 million at December 31, 2012. The decrease of $261.5 million, or 46%, from December 31, 2013 was primarily due to:

A decrease of $200.5 million in secured and unsecured loans payable due to the full repayment in June 2014 of the BSP and Westpac combined secured loan facility, the ANZ, BSP and BNP syndicated loan facility and the full repayment in April 2014 of the Credit Suisse syndicated secured loan post receipt of Total SSA completion payment; and

Management Discussion and Analysis INTEROIL CORPORATION 13

The Puma Transaction also resulted in the decrease in working capital facilities by $36.4 million and income tax payable by $15.3 million.

Comparing December 31, 2013 to December 31, 2012, the increase of total liabilities of $45.7 million or 9% was primarily due to the net increase of $79.6 million in secured loans payable primarily on drawdown of the Credit Suisse secured loan of $100.0 million, and the receipt of PRE’s $75.0 million initial staged cash payment. These increases were partially offset by the $57.9 million decrease in working capital facilities mainly due to discounted receivables under the BNP working capital facility being made non-recourse and no longer included within our liabilities; and the $44.3 million decrease in accounts payable and accrued liabilities, mainly related to timing of payments on certain crude cargo purchases.

Analysis of Consolidated Financial Results Comparing Year Ended December 31, 2014 and 2013

Our net loss for the quarter ended December 31, 2014 was $64.2 million, compared with a net loss of $24.8 million for the same quarter in 2013, an increase of $39.4 million, which was primarily driven by a $17.6 million loss for our share of losses incurred by the PNG LNG joint venture resulting from the impairment of joint venture assets, a $24.2 adjustment to the carrying value of Total S.A. receivable balance based on our assessment of the revised expected cash flow timing of the Interim Resource Payment to the end of 2015 to accommodate the drilling of the Antelope-6 appraisal well (which was initially optional), and an $8.9 million reduction in profit from discontinued operations for the quarter ended December 31, 2014 compared to the same quarter of 2013.

Our net profit for the year ended December 31, 2014 was $289.8 million, compared with a net loss of $40.3 for the same period in 2013, an increase of profit by $330.1 million which was primarily driven by the gain on conveyance of exploration and evaluation assets in relation to the Total SSA and the Puma Transaction.

The table below analyzes key movements, the net of which primarily explains the variance in results between the quarters and years ended December 31, 2014 and 2013:

	*Quarterly* *Variance* *($ millions)*	*Yearly* *Variance* *($ millions)*

	*($39.4)*	*$330.1*	*Net profit/(loss) 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	($8.9)	$53.2	Increase in profit from discontinued operations for year ended December 31, 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. Net loss from discontinued operations for the quarter ended December 31, 2014 of $1.7 million (compared to operating profit of $7.2 million in the same quarter of prior year) was mainly due to certain corporate costs incurred by us in relation to discontinued operations.

Management Discussion and Analysis INTEROIL CORPORATION 14

Ø	($7.6)	($20.1)	Increase in office and administration and other expenses for the quarter resulted from an increase in the support and management costs incurred as a result of increased drilling operations; in addition, $1.6 million of increase in share compensation expenses due to a new grant of restricted stock units and accelerated stock compensation expenses on options and restricted stock units owned by retired senior management or employees affected by our office restructure; and $0.8 million of restructuring costs relating to the closure of the corporate office in Cairns, Australia. Increase in office and administration and other expenses for the year resulted from an increase in the support and management costs incurred as a result of increased drilling operations; in addition, $12.0 million of restructuring costs relating to the closure of the corporate office in Cairns, Australia; a $3.7 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, our office restructure or employees affected by Puma Transaction; and offset by a $2.0 million decrease in redundancy payroll costs as a result of the retirement of senior executives paid during the year ended December 31, 2013.

Ø	$1.8	($15.7)	Increase in exploration costs was mainly attributable to the expensing of seismic activities over Bobcat, Zebra-Razorback leads, and Antelope South prospects during the periods. The decrease for the quarter ended December 31, 2014 is due to the expensing of $6.8 million in relation to the buy-back of PNGEI’s right to participate up to a 4.25% interest in exploration wells numbered 9 to 24 for 100,000 InterOil common shares in the prior year quarter.

Ø	$3.2	($16.9)	Increase in finance costs for the year was primarily a result of the facility fees incurred for the Credit Suisse facility that was obtained in the fourth quarter of 2013 and refinanced in June 2014. The decrease for the quarter ended December 31, 2014 is due to the non-utilization of the Credit Suisse facility during the quarter as compared to $100.0 million drawn under the facility in the prior year quarter. As at December 31, 2014, there were no drawdowns made on the refinanced Credit Suisse facility.

Ø	($15.2)	$1.9	Increase in interest income for the year was attributable to the interest accretion income on the receivables recognized in relation to interim resource payments expected under the Total SSA calculated using the best case scenario provided by GCA of 7.10 Tcfe for the Elk and Antelope fields. During the quarter ended December 31, 2014, this accretion was partly reduced by the adjustment of carrying value of Total S.A. receivable balance based on our assessment of the revised expected cash flow timing of the Interim Resource Payment to the end of 2015 to accommodate the drilling of the Antelope-6 appraisal well (which was initially optional).

Management Discussion and Analysis INTEROIL CORPORATION 15

Ø	$1.3	$8.5	Increase in other revenues for the quarter predominantly resulted from recharges to Puma on certain transition services provided post divestment. Increase in other revenues for the year 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 in the Puma Transaction 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.

Ø	($17.5)	($19.8)	Increase in loss of joint venture partnership accounted for using equity method was attributable to our share of losses incurred by the PNG LNG joint venture resulting from the impairment of joint venture assets, as we are now progressing the LNG Project development jointly with Total.

Comparing the year ended December 31, 2013 to the year ended December 31, 2012, the increase in net loss of $42.0 million was primarily driven by a $15.5 million reduction in profits generated by our discontinued operations, a $6.0 million increase in legal and professional fees primarily due to expensing of costs associated with financing and listing options that were considered during the year, a $7.7 million decrease in other revenues resulting from lower activities and related recoveries from the drilling and construction activities during the year, a $4.9 million increase in exploration costs mainly attributable to the expensing of $6.8 million in relation to the buy-back of PNG Energy investors’ right to participate up to a 4.25% interest in exploration wells numbered 9 to 24 for 100,000 InterOil shares and a $6.9 million increase in finance costs and interest expense due to financing fees and interest incurred on the Credit Suisse-led facility.

Analysis of Consolidated Cash Flows Comparing Quarters and Years Ended December 31, 2014, 2013 and 2012

As at December 31, 2014, we had cash, cash equivalents, and restricted cash of $401.7 million (December 31, 2013 - $115.2 million and December 31, 2012 - $98.7 million), of which $8.3 million (December 31, 2013 - $53.2 million and December 31, 2012 - $49.0 million) was restricted. Of the total restricted cash at December 31, 2014, $8.0 million 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 quarters and years ended December 31, 2014, 2013 and 2012.

($ thousands)	Year ended December 31
	2014			2013			2012
Net cash (outflows)/inflows from:
Operations		(81,206	)		70,643			(47,661	)
Investing		640,136			(133,464	)		(157,950	)
Financing		(227,492	)		75,101			185,698
Net cash movement		331,438			12,280			(19,913	)
Opening cash		61,967			49,721			68,575
Exchange losses on cash and cash equivalents		-			(34	)		1,059
Closing cash		393,405			61,967			49,721

Management Discussion and Analysis INTEROIL CORPORATION 16

Cash flows (used in)/generated from operating activities

Cash outflows from operating activities for the quarter ended December 31, 2014 were $20.3 million compared with an inflow of $61.1 million for the quarter ended December 31, 2013, a net increase in cash outflows of $81.4 million. Cash outflows from operating activities for the year ended December 31, 2014 were $81.2 million compared with an inflow of $70.6 million for the year ended December 31, 2013, a net increase in cash outflows of $151.8 million.

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

	*Quarterly* *variance* *($ millions)*	*Yearly* *variance* *($ millions)*

	*($81.4)*	*($151.8)*	*Variance for the comparative periods primarily due to:*

Ø	($28.8)	($55.8)	Increase in cash used in operations prior to changes in operating working capital for the quarter was mainly due to the increase in net profit from operations adjusted for the increased accretion income on receivable, gain on sale of refining and downstream businesses in the Puma Transaction and gain on conveyance of PRL15 pursuant to the Total SSA.

			Increase in cash used in operations prior to changes in operating working capital for the year was mainly due to the increase in net loss from operations adjusted for the accretion income on receivable from Total.

Ø	($52.6)	($96.0)	Decrease in cash employed by operations relating to changes in operating working capital for the quarter was due to a $53.7 million decrease in accounts payable and accrued liabilities, a $20.8 million increase in inventories a $3.7 million increase in other current assets and prepaid expenses; and partially offset by a $25.6 million decrease in trade and other receivables.

			Increase in cash employed by operations relating to changes in operating working capital for the year was due to a $44.3 million increase in trade and other receivables, a $29.8 million decrease in trade and other payables and a $22.3 million increase in inventories; and partially offset by a $0.3 million decrease in other current assets and prepaid expenses.

Cash flows generated from/(used in) investing activities

Cash outflows from investing activities for the quarter ended December 31, 2014 were $28.7 million compared with an outflow of $44.4 million for the quarter ended December 31, 2013. Cash inflows from investing activities for the year ended December 31, 2014 were $640.1 million compared with an outflow of $133.4 million for the year ended December 31, 2013.

Management Discussion and Analysis INTEROIL CORPORATION 17

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

	*Quarterly* *variance* *($ millions)*	*Yearly* *variance* *($ millions)*

	*$15.7*	*$773.5*	*Variance for the comparative periods primarily due to:*

Ø	$0.0	$428.0	Receipt of $524.6 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	$14.3	$49.1	The reduction in restricted cash requirements was mainly due to the transfer of restricted cash balances (and the associated working capital facilities) in relation to the BNP Paribas led working capital facilities as part of the Puma Transaction.

Ø	($132.6)	($329.1)	Increase in cash outflows on exploration and development expenditures was mainly due to the increased drilling activities (5 wells being drilled in the year ended December 31, 2014 as opposed to minimal drilling in prior periods), transaction costs associated with the completion of the Total SSA and premium paid for indirect participating interests buyback.

Ø	$67.5	$99.7	Higher cash calls and related inflows from joint venture partners relating to the receipt of funds from PRE for historical Triceratops-2 well costs, 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	$60.6	$118.1	Movement in non-operating working capital for the periods was primarily related to trade payables and accruals in our exploration and development operations.

Cash flows (used in)/generated from financing activities

Cash flow movement from financing activities for the quarter ended December 31, 2014 amounted to $Nil, compared with an inflow of $4.8 million for the quarter ended December 31, 2013. Cash outflows from financing activities for the year ended December 31, 2014 amounted to $227.5 million, compared with an inflow of $75.1 million for the year ended December 31, 2013.

This table outlines key variances in cash (outflows)/inflows from financing activities between quarters and years ended December 31, 2014 and 2013:

	*Quarterly* *variance* *($ millions)*	*Yearly* *variance* *($ millions)*

	*$0.0*	*($302.6)*	*Variance for the comparative periods primarily due to:*

Ø	$0.0	$34.4	Termination settlement to Mitsui for the CSP funding provided by Mitsui and related interests during year ended December 31, 2013.

Ø	$0.0	$12.9	Full repayment of the secured loan from Westpac during year ended December 31, 2013.

Ø	$0.0	($47.5)	Net repayment of the BSP and Westpac combined secured loan facility during year ended December 31, 2014.

Ø	$0.0	($193.0)	Drawdown of $50.0 million from the Credit Suisse syndicated secured loan facility during the quarter ended March 31, 2014 (as opposed to the $93.0 million drawdown of the Credit Suisse secured facility - net of transaction costs in year 2013) 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	$0.0	$78.8	Movement in utilization of the BNP working capital facility in our discontinued operations from Puma Transaction.

Ø	$0.0	($68.0)	Full repayment of the ANZ, BSP and BNP syndicated loan was made in June 2014.

Ø	$0.0	($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 18

Summary of Consolidated Quarterly Financial Results for Past Eight Quarters

This table contains consolidated results for the eight quarters ended December 31, 2014 on a consolidated basis.

Quarters ended	2014											2013
($ thousands except per share data)	Dec-31 ⁽²⁾			Sep-30			Jun-30			Mar-31		Dec-31			Sep-30			Jun-30			Mar-31
Total revenues		(13,182	)		10,749			13,689			1,903		712			617			831			602
EBITDA ⁽¹⁾		(60,443	)		(12,135	)		(10,252	)		316,949		(27,272	)		(99	)		(11,293	)		(5,138	)
Net (loss)/profit		(64,205	)		(16,931	)		52,266			318,637		(24,812	)		(6,318	)		(13,230	)		4,003
From continuing operations		(62,474	)		(14,622	)		(15,764	)		310,825		(32,024	)		(3,555	)		(15,240	)		(8,096	)
From discontinued operations		(1,731	)		(2,309	)		68,030			7,812		7,212			(2,763	)		2,010			12,099
Basic (loss)/earnings per share		(1.30	)		(0.34	)		1.05			6.46		(0.50	)		(0.13	)		(0.27	)		0.08
From continuing operations		(1.26	)		(0.29	)		(0.31	)		6.30		(0.65	)		(0.07	)		(0.31	)		(0.17	)
From discontinued operations		(0.04	)		(0.05	)		1.36			0.16		0.15			(0.06	)		0.04			0.25
Diluted (loss)/earnings per share		(1.30	)		(0.34	)		1.05			6.38		(0.50	)		(0.13	)		(0.27	)		0.08
From continuing operations		(1.26	)		(0.29	)		(0.31	)		6.22		(0.65	)		(0.07	)		(0.31	)		(0.17	)
From discontinued operations		(0.04	)		(0.05	)		1.36			0.16		0.15			(0.06	)		0.04			0.25

(1)

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

(2)

Total revenues for the quarter ended December 31, 2014 include an out-of-period adjustment of $7.6 million relating to interest accretion income recognized in prior quarters of 2014.

DISCOUNTINUED OPERATIONS

On June 30, 2014, we completed the Puma Transaction for gross proceeds of $525.6 million, and made a gain of $49.5 million. 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 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.

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.

Management Discussion and Analysis INTEROIL CORPORATION 19

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 (as of June 30, 2014)

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.

Management Discussion and Analysis INTEROIL CORPORATION 20

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

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

LIQUIDITY AND CAPITAL RESOURCES

Summary of Debt Facilities

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

Organization

Facility

Balance
outstanding
December 31,
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

In November 2013, we secured a $250.0 million secured syndicated capital expenditure facility for an approved seismic data acquisition and drilling program. The facility was provided by a group of banks led by Credit Suisse and included CBA, ANZ, UBS, Macquarie, BSP, BNP Paribas and Westpac. Post completion of the Total SSA on March 26, 2014, this facility was fully repaid in April 2014.

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 drawdowns have been made under the new facility as at December 31, 2014.

Subsequent to the year end, on March 17, 2015, we signed an amendment to further extend the maturity date on this facility to the end of 2016 with Credit Suisse, CBA, ANZ, UBS AG, Macquarie, BSP, Westpac, MUFG and SocGen participating in the extension.

Management Discussion and Analysis INTEROIL CORPORATION 21

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.

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

Other Sources of Capital

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

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

Capital Expenditure

Net expenditure on exploration and evaluation assets

Net capital expenditures on our exploration and evaluation assets in Papua New Guinea for the quarter ended December 31, 2014 were $83.6 million, compared with $31.2 million during the same period of 2013. Total net expenditures for the year ended December 31, 2014 were $355.7 million compared to $74.1 million during the same period in 2013.

This analysis outlines key net expenditures in the quarter and year ended December 31. 2014:

	*Quarterly movement* *($ millions)*	*Yearly movement* *($ millions)*

	*$245.0*	*$584.8*	*Opening balance of exploration and evaluation assets*
	*$80.0*	*$352.1*	*Net capital expenditure consisting of following:*

Ø	$26.3	$90.0	Costs for site preparation, pre-spud work and drilling and testing of the Raptor-1 well.

Ø	$3.0	$36.5	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 well.

Ø	$34.7	$88.4	Costs for site preparation, pre-spud work and drilling and testing of the Bobcat-1 well.

Management Discussion and Analysis INTEROIL CORPORATION 22

Ø	($2.1)	$44.8	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	($1.9)	$4.9	Seismic over the Antelope field in PRL 15.

Ø	$4.1	$4.6	Costs for site preparation, pre-spud work for Triceratops-3 well.

Ø	$8.5	$10.6	Costs for site preparation, pre-spud work and drilling of the Antelope-4 well.

Ø	$1.9	$3.4	Costs for site preparation, pre-spud work and drilling of the Antelope-5 well.

Ø	($1.3)	$12.2	Expenditure/(usage) of drilling inventory.

Ø	$4.8	$5.0	Expenditure relating to concept select studies led by Total for PRL 15.

Ø	$2.0	$10.2	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*

	*$325.0*	*$325.0*	*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 December 31, 2014 was $157.7 million. Total gross expenditures for the year ended December 31, 2014 were $500.7 million.

This analysis outlines key gross expenditures in the quarter and year ended December 31, 2014:

	*Quarterly movement* *($ millions)*	*Yearly movement* *($ millions)*

	*$156.2*	*$497.1*	*Gross capital expenditure consisting of following:*
Ø	$32.5	$121.1	Costs for site preparation, pre-spud work and drilling and testing of the Raptor-1 well.

Ø	$2.9	$38.6	Costs for site preparation, pre-spud work and drilling of the Wahoo-1 well.

Ø	$38.1	$96.9	Costs for site preparation, pre-spud work and drilling and testing of the Bobcat-1 well.

Ø	$7.3	$7.7	Costs for site preparation and pre-spud work for Triceratops-3 well.

Ø	$0.0	$44.7	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	($2.3)	$13.5	Seismic over the Antelope field in PRL 15.

Ø	$45.1	$66.6	Costs for site preparation, pre-spud work and drilling of the Antelope-4 well.

Ø	$21.1	$31.0	Costs for site preparation, pre-spud work and drilling of the Antelope-5 well.

Ø	($1.3)	$12.2	Expenditure/(usage) of drilling inventory.

Ø	$13.5	$13.5	Expenditure relating to concept select studies led by Total for PRL 15.

Ø	($0.7)	$9.8	Other expenditure, including equipment and asset purchases.

Management Discussion and Analysis INTEROIL CORPORATION 23

Capital expenditure on plant and equipment

A total of $3.6 million was incurred on corporate related capital expenditure for the year ended December 31, 2014, including $2.1 million for renovation costs of our new Singapore office and $1.3 million for the acquisition of corporate apartments, office renovations and motor vehicles in Papua New Guinea.

Capital Requirements

Existing cash balances will be sufficient to settle 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. Additionally, our joint venture share of the costs of construction of an LNG plant and other infrastructure associated with the proposed LNG plant may amount to hundreds of millions of dollars and thus exceed our existing cash balances. No assurance can be given that we will be successful in obtaining new capital on terms that are acceptable to us, particularly with market volatility.

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 Consolidated Financial Statements and notes thereto.

	Payments Due by Period
Contractual obligations ($ thousands)	Total		Less than 1 year		1 - 2 years		2 - 3 years		3 - 4 years		4 - 5 years		More than 5 years
Petroleum prospecting and retention licenses		428,290		46,560		82,047		91,400		94,358		97,650		16,275
Convertible Notes obligations		71,763		71,763		-		-		-		-		-
Total		500,053		118,323		82,047		91,400		94,358		97,650		16,275

The amount pertaining to the petroleum prospecting and retention licenses represents the amount we have committed on these licenses as at December 31, 2014. On March 6, 2014, our applications for new petroleum prospecting licenses were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238 and included new license commitments. The new commitments require us to spend an additional $369.7 million over the remainder of their six year term.

Further, the terms of grant of PRL 39 requires us to spend a further $58.6 million on the license area by the end of 2018.

Off Balance Sheet Arrangements

Neither during the year ended, nor as at December 31, 2014, did we have any off balance sheet arrangements or any relationships with unconsolidated entities or financial partnerships.

Management Discussion and Analysis INTEROIL CORPORATION 24

Transactions with Related Parties

During the year ended December 31, 2014, former Chief Financial Officer, Collin Visaggio, former Chief Operating Officer, William Jasper, and former Vice President of Investor Relations, Wayne Andrews retired. Compensation paid or payable to these officers upon their retirement was $1.5 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 December 31, 2014, we had 49,414,801 common shares issued and outstanding (50,656,333 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at December 31, 2014 included employee stock options and restricted stock in respect of 509,528 common shares and 732,004 common shares relating to the $70.0 million principal amount Convertible Notes.

As of March 13, 2015, we had 49,491,166 common shares issued and outstanding (50,739,629 common shares on a fully diluted basis) and no preferred shares issued and outstanding. The potential dilutive instruments outstanding as at March 13, 2015 included employee stock options and restricted stock in respect of 516,459 common shares and 732,004 common shares relating to the $70.0 million principal amount Convertible Notes.

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

INDUSTRY TRENDS AND KEY EVENTS

Financing Arrangements

We continue to monitor liquidity risk by setting and monitoring acceptable gearing. Our aim is to maintain our debt-to-capital ratio, or gearing levels, (debt divided by (shareholders’ equity plus debt)) at 50% or less. This was achieved throughout 2013 and 2014. Gearing was 6% in December 2014, 26% in December 2013 and 19% in December 2012.

We had cash, cash equivalents and cash restricted of $401.7 million as at December 31, 2014, of which $8.3 million was restricted. For details of other financial arrangements, see “Liquidity and Capital Resources – Summary of Debt Facilities”.

Crude Prices

Crude prices declined in 2014, with the price of Brent crude oil starting the year at $110 per Barrel and closing the year at $62 per Barrel. With the completion of the Puma Transaction, we are not materially impacted by the fluctuations and declines in crude prices, however, our operating costs have been reduced as a result of the lower cost of fuel used in our exploration and appraisal operations. We also expect that as a result of the decline in oil prices, we may see our costs related to hiring oilfield service providers decline.

Management Discussion and Analysis INTEROIL CORPORATION 25

Exchange Rates

The PGK interbank reference rate has weakened considerably against the USD in the year ended December 31, 2014 (from 0.4130 to 0.3855). Changes in the AUD and SGD to USD exchange rates can affect our corporate results as expenses of the corporate offices in Australia and Singapore are incurred in the respective local currencies. PGK, AUD and SGD exposures are minimal currently as funds are transferred to PGK, AUD and SGD from USD as required. No material balances are held in PGK, AUD or SGD. However, we are exposed to translation risks resulting from PGK, AUD and SGD fluctuations as in country costs are being incurred in PGK, AUD and SGD and reporting for those costs are in USD.

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 Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates. The effect of changes in estimates on future periods have not been disclosed in the Consolidated Financial Statements as estimating it is impracticable. The following accounting policies involve estimates that are considered critical due to the level of sensitivity and judgment involved, as well as the impact on our consolidated financial position and results of operations.

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

Convertible notes

The Convertible Notes are assessed based on the substance of the contractual arrangement in determining whether it exhibits the fundamental characteristic of a financial liability or equity. We have determined that the note instrument mainly exhibits characteristics that are liability in nature, however, the embedded conversion feature is equity in nature and needs to be bifurcated and disclosed separately within equity. We valued the liability component first and assigned the residual value to the equity component. We fair valued the liability component by deducting the premium paid by holders specifically for the conversion feature. The conversion price of $95.625 per share includes a premium of 27.5% to the issue price of the concurrent common shares offering of $75 per share. Therefore, the $70.0 million total issue represents 127.5% of the liability portion.

Environmental Remediation

Remediation costs are accrued based on estimates of known environmental remediation exposure. Ongoing environmental compliance costs, including maintenance and monitoring costs, are expensed as incurred. Provisions are determined on an assessment of current costs, current legal requirements and current technology. Changes in estimates are dealt with on a prospective basis. We currently do not have any amounts accrued for environmental remediation obligations as current legislation does not require it. Future legislative action and regulatory initiatives could result in changes to our operating permits which may result in increased capital expenditures and operating costs.

Management Discussion and Analysis INTEROIL CORPORATION 26

Share-based payments

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

Exploration and Evaluation Assets

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

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

Impairment of Long-Lived Assets

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

NEW ACCOUNTING STANDARDS

New accounting standards not yet applicable as at December 31, 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 27

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

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

NON-GAAP MEASURES AND RECONCILIATION

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

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

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

	2014												2013
Quarters ended ($ thousands)	Dec-31			Sep-30			Jun-30			Mar-31			Dec-31			Sep-30			Jun-30			Mar-31
Earnings before interest, taxes, depreciation and amortization		(60,443	)		(12,135	)		(10,252	)		316,949			(27,272	)		(99	)		(11,293	)		(5,138	)
Interest expense		(1,464	)		(1,367	)		(4,409	)		(4,170	)		(2,546	)		(2,212	)		(2,082	)		(1,600	)
Income taxes		(211	)		(198	)		(195	)		(514	)		(791	)		239			(458	)		70
Depreciation and amortisation		(356	)		(922	)		(908	)		(1,440	)		(1,415	)		(1,483	)		(1,407	)		(1,428	)
From continuing operations		(62,474	)		(14,622	)		(15,764	)		310,825			(32,024	)		(3,555	)		(15,240	)		(8,096	)
From discontinued operations		(1,731	)		(2,309	)		68,030			7,812			7,212			(2,763	)		2,010			12,099
Net (loss)/profit		(64,205	)		(16,931	)		52,266			318,637			(24,812	)		(6,318	)		(13,230	)		4,003

PUBLIC SECURITIES FILINGS

You may access additional information about us, including our 2014 AIF, in documents filed with the Canadian Securities Administrators at www.sedar.com, and in documents, including our Form 40-F, filed with the U.S. SEC at www.sec.gov. Additional information is also available on our website www.interoil.com.

Management Discussion and Analysis INTEROIL CORPORATION 28

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.

Material Changes in Internal Control over Financial Reporting

Effective July 1, 2014, as a result of Puma Transaction and Cairns Office Closure, we ceased operating approximately 45% of key controls. Consequently, we have relocated all functions in finance and information management from our office in Cairns, Australia, to our offices in Singapore and Papua New Guinea. We also migrated our Information Management Data Centre to a third party location in Sydney, Australia hosted through an Infrastructure as a Service Solution with Telstra. The changes resulted in changes to personnel, 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 these 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 fiscal year 2014.

Other than the changes resulting from the Puma Transaction and Office Relocation, there have been no changes in internal control over financial reporting during the fiscal year 2014 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 29