EX-99.1 2 v404576_ex1.htm EXHIBIT 1

Exhibit 1

InterOil Corporation

Annual Information Form

For the Year Ended December 31, 2014

March 17, 2015

TABLE OF CONTENTS

TABLE OF CONTENTS	1
PRELIMINARY NOTES	2
GENERAL	2
LEGAL NOTICE – FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	3
CONVERSION	4
EXCHANGE RATES	4
GLOSSARY OF TERMS	5
CORPORATE STRUCTURE	9
GENERAL DEVELOPMENT OF THE BUSINESS	10
EXPLORATION AND PRODUCTION BUSINESS – THREE YEAR HISTORY	10
BUSINESS STRATEGY	14
DESCRIPTION OF OUR BUSINESS	15
EXPLORATION AND PRODUCTION BUSINESS – DESCRIPTION	15
DISCONTINUED OPERATIONS	23
THE ENVIRONMENT AND COMMUNITY RELATIONS	27
RISK FACTORS	28
DIVIDENDS	33
DESCRIPTION OF CAPITAL STRUCTURE	33
MARKET FOR OUR SECURITIES	35
DIRECTORS AND EXECUTIVE OFFICERS	36
AUDIT COMMITTEE	41
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	42
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	42
MATERIAL CONTRACTS	42
EXTRACTIVE INDUSTRIES TRANSPARENCY INITIATIVE	44
TRANSFER AGENT AND REGISTRAR	45
INTERESTS OF EXPERTS	45
ADDITIONAL INFORMATION	46
Schedule A – Report of Management and Directors on Oil and Gas Disclosure	47
Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator	48
Schedule C – Audit Committee Charter	50

Annual Information Form INTEROIL CORPORATION 1

PRELIMINARY NOTES

GENERAL

This Annual Information Form (“AIF”) has been prepared by InterOil Corporation for the year ended December 31, 2014. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2014 and Management’s Discussion and Analysis for the year ended December 31, 2014 (“2014 MD&A”), copies of which may be obtained online from SEDAR at www.sedar.com.

In this AIF, references to “we”, “us”, “our”, “the Company” and “InterOil” refer to InterOil Corporation or InterOil Corporation and its subsidiaries as the context requires. All dollar amounts are stated in United States dollars unless otherwise specified. Information presented in this AIF is as of December 31, 2014 unless otherwise specified. A listing of specific defined terms can be found in the “Glossary of Terms” section of this AIF.

Certain information, not being within our knowledge, has been furnished by our directors and executive officers. Such information includes information as to common shares in the Company beneficially owned, controlled or directed, directly or indirectly by them, their places of residence and principal occupations, both present and historical, interests in material transactions and potential conflicts of interest.

LEGAL NOTICE – FORWARD-LOOKING STATEMENTS

This AIF 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 AIF 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;

the 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;

Annual Information Form INTEROIL CORPORATION 2

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.

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 this AIF.

Further, the forward-looking statements contained in this AIF 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 AIF are expressly qualified by this cautionary statement.

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

Crude Oil and Natural Gas Liquids		Natural Gas
bbl	one barrel equalling 34.972 Imperial gallons or 42 U.S. gallons	btu	British Thermal Units
bblspd	barrels per day	mcf	thousand standard cubic feet
boe⁽¹⁾	barrels of oil equivalent	mcfpd	thousand standard cubic feet per day
boepd	barrels of oil equivalent per day	mmbtu	million British Thermal Units
bpsd	barrels per stream day	mmbtupd	million British Thermal Units per day
mboe	thousand barrels of oil equivalent	mmcf	million standard cubic feet
mbbl	thousand barrels	mmcfpd	million standard cubic feet per day
MMbbls	million barrels	mtpa	million tonnes per annum
MMboe	million barrels of oil equivalent	scfpd	standard cubic feet per day
WTI	West Texas Intermediate crude oil delivered at Cushing, Oklahoma	Tcfe⁽²⁾	trillion standard cubic feet equivalent
bscf	billion standard cubic feet	psi	pounds per square inch

Note:

(1)

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

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(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).

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

EXCHANGE RATES

Unless otherwise indicated, all references in this form are to U.S. dollars.

The following table sets forth, for the periods indicated, the high, low, average and period-end noon spot rates of exchange for one U.S. dollar, expressed in Canadian dollars, published by the Bank of Canada.

	Year Ended 31 December
	2014		2013		2012
	CDN$		CDN$		CDN$
Highest rate during the period		1.1643		1.0697		1.0418
Lowest rate during the period		1.0614		0.9839		0.9710
Average noon spot rate for the period		1.1045		1.0299		0.9996
Rate at the end of the period		1.1601		1.0636		0.9949

On March 13, 2015 (being the latest practicable date prior to the publication of this form), the noon buying rate for one U.S. dollar in Canadian dollars as certified by the Bank of Canada was CDN$1.2803.

The following table sets forth, for the periods indicated, the high, low, average and period-end closing spot rates of exchange for one Papua New Guinea kina, expressed in U.S. dollars, as listed on OZForex.

	Year Ended 31 December
	2014		2013		2012
	U.S.$		U.S.$		U.S.$
Highest closing spot rate during the period		0.4132		0.4971		0.5006
Lowest closing spot rate during the period		0.3456		0.3750		0.4693
Average closing noon spot rate for the period		0.3889		0.4415		0.4908
Closing spot rate at the end of the period		0.3813		0.4008		0.4928

On March 13, 2015 (being the latest practicable date prior to the publication of this form), the closing spot rate of exchange for one Papua New Guinea kina, expressed in U.S. dollars, as published on OZForex was U.S.$0.3772.

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GLOSSARY OF TERMS

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

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

“ANZ” means the 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 the Commonwealth Bank of Australia.

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook.

“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.

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

“Convertible notes” means our 2.75% convertible senior notes which are due in November 15, 2015.

“Credit Suisse” means Credit Suisse A.G.

“crack spread” means the simultaneous purchase or sale of crude against the sale or purchase of refined petroleum products. These spread differentials which represent refining margins are normally quoted in dollars per barrel by converting the product prices into dollars per barrel and subtracting the crude price.

"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.

"EITI" means Extractive Industries Transparency Initiative, an international organization which maintains the EITI standard, assessing the levels of transparency around countries’ oil, gas and mineral resources. Countries implement the EITI Standard to ensure full disclosure of taxes and other payments made by oil, gas and mining companies to governments

“feedstock” means raw material used in a refinery or other processing plant.

“FID” means final investment decision.

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

Annual Information Form INTEROIL CORPORATION 5

“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. Natural gas may contain sulfur or other non-hydrocarbon compounds.

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

"GLJ 2014 Report" means the report dated March 13, 2015 with an effective date of December 31, 2014 setting forth certain information regarding contingent resources of our interests in the Elk, Antelope, and Triceratops fields in PNG.

“ICCC” means Papua New Guinea’s competition authority, the Independent Consumer and Competition Commission.

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

“IPI Agreement” means any of (a) the indirect participating interest agreement between us and PNGEI originally executed April 3, 2003 and amended April 12, 2003 and further amended (and restated) May 12, 2004 and was terminated in 2013; (b) the indirect participating interest agreement between us and PNGDV of July 21, 2003 and amended (and restated) on May 1, 2006; and (c) indirect participating agreement of February 25, 2005 between us and the investors and amended December 15, 2005 and further amended June 15, 2012.

“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 by pressure and severe cooling for transport, 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 natural gas liquids, or NGL, 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.

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

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

“naphtha” means that portion of the distillate obtained from the refinement of petroleum that is an intermediate between lighter gasoline and heavier benzene. It is a feedstock for the petrochemical industry or for gasoline production by reforming or isomerization within a refinery.

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

“Natixis” means the Singapore branch of Natixis S.A.

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

Annual Information Form INTEROIL CORPORATION 6

“NI 52-110” means National Instrument 52-110 – Audit Committees 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 in the Bahamas.

“PDL” means petroleum development license, the right granted by the State to develop a field for commercial production.

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

“PNGDV” means PNG Drilling Ventures Limited.

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

“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 in 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.

“Prospective Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.

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

“Puma Transaction” means the transaction by which Puma acquired all of the shares of certain of our subsidiaries that held our refinery and petroleum products distribution businesses for approximately $525.6 million. The transaction was completed on June 30, 2014.

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

“SocGen” means Societe Generale Hong Kong branch.

“SPA” means sales and purchase agreement.

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

“Sweet/sour crude” describes the degree of given crude's sulfur content. Sour crudes are high in sulfur, sweet crudes are low.

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

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

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

“UBS” means UBS A.G.

“USD” means United States dollars.

Annual Information Form INTEROIL CORPORATION 7

“Westpac” means Westpac Bank PNG Limited.

“working interest” means the percentage of undivided interest held by us in an oil and natural gas property, well or resources, as applicable.

“YBCA” means the Business Corporations Act (Yukon).

Annual Information Form INTEROIL CORPORATION 8

CORPORATE STRUCTURE

Name, Address and Incorporation

InterOil Corporation is a Yukon, Canada corporation, continued under the YBCA on August 24, 2007.

Our registered office

in Canada is located at:

Suite 300,204 Black Street

Whitehorse, Yukon

Y1A 2M9, Canada

Our corporate office

in Singapore is located at:

163 Penang Road,

Winsland House 2, #06-02

Singapore 238463

Our corporate office

in Papua New Guinea is located at:

Level 2, Ravalien Haus, Harbour City, Port Moresby NCD, Papua New Guinea

We relocated our office in Cairns, Australia to Papua New Guinea during the fourth quarter of 2014. During the year, we have also relocated our investor relations representation from Houston to New York.

Copies of the company’s articles and by-laws are available on SEDAR at www.sedar.com.

Inter-corporate Relationships

Inter-corporate relationships with and among all of our subsidiaries as at the date of this AIF are set out below:

Annual Information Form INTEROIL CORPORATION 9

GENERAL DEVELOPMENT OF THE BUSINESS

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

EXPLORATION AND PRODUCTION BUSINESS – THREE YEAR HISTORY

Exploration - Seismic and Drilling

In the past three years, we have focused on meeting work commitments across our licenses with seismic acquisition and exploration and appraisal drilling. The Elk, Antelope and Triceratops fields all now have independently certified contingent gas and condensate resources, and during the year 2014 we confirmed two further exploration discoveries with Raptor and Bobcat drilling successes. Drilling on another exploration well, Wahoo-1, was suspended after intersecting gas and higher-than expected pressures. We expect to recommence drilling in 2015. Appraisal drilling of Antelope-4 and Antelope-5 wells was also started during 2014, in line with our agreement under Total SSA to complete up to three appraisal wells prior to interim resource certification, based on which Total is obliged to make variable payments for resources in PRL 15 that are in excess of 3.5 Tcfe.

Additionally, subsequent to the year ended December 31, 2014, Total was appointed as operator of PRL15.

A summary of the key operational matters and events in the past three years for continuing operations is as follows:

New exploration 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

We acquired airborne magnetic, gravity and radiometric surveys over PPL 236, PPL 237 and PPL 238 in 2011 with processing of the data having been completed in 2012. 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

Between late 2011 and 2013, we acquired seismic over PPL 236 which focused on the Wahoo-Mako, Whale, Shark and Tuna leads. We also completed a joint seismic program in 2013 with Oil Search, which holds PPL 338, which is adjacent to PPL 237. Additional seismic was also acquired in 2013 near the Triceratops field in PPL 237 and PPL 238. In addition, we also began acquiring seismic in Triceratops east, south-west Antelope and across two new prospects, Bobcat in PPL 238 and Antelope South (formerly Antelope Deep and Bighorn) in PRL 15.

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) 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.

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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 2012, we spudded the Antelope-3 appraisal well in PRL 15 to further evaluate field size and structure and to reduce resource uncertainty. In 2013, the well was completed and suspended for future production. Formation evaluation indicated that the reservoir quality at Antelope-3 was similar to the Antelope-1 and Antelope-2 wells.

In 2012, we also drilled the Triceratops-2 appraisal well in PPL 237 to further evaluate the field. The well flowed gas in June 2012 and was declared a discovery by the DPE. This well was also suspended for future production and we applied in early 2013 to the DPE for PRL 39 over the Triceratops discovery. We received approval of PRL 39 in December 2013.

In 2013, the Board approved a major exploration and appraisal drilling and seismic work program and budget for 2014-15. The program provided 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.

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 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 had 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 a 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 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.

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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 over the discovery to further evaluate the reservoir.

PRL 15 – Antelope-4 and Antelope-5 appraisal program and Oil Search arbitration

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.

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.

Development

Total agreement

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.

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%).

Details of the Total SSA are provided in the Section headed “Material Contracts”.

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.

Annual Information Form INTEROIL CORPORATION 12

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.

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) onshore PNG, 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.

Details of the PRE farm-in agreement are provided in the Section headed “Material Contracts”.

Midstream Liquefaction Joint Venture

On August 6, 2013, we agreed with PacLNG to align interests in the Midstream Liquefaction Joint Venture to those in PRL 15. As a result, our interest in the joint venture was 77.165% and PacLNG’s interest was 22.835%.

During 2013, we modified the direction of our midstream liquefaction business and no longer plan to be the operator of an LNG liquefaction project in which we have ownership. We now expect the LNG Project to be developed jointly with Total. In 2014, the value of our investment in the joint venture was reduced to nil, following the recognition of our share of losses incurred by the joint venture resulting from the impairment of joint venture assets.

Financing

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.

Annual Information Form INTEROIL CORPORATION 13

Only $2,000 of the convertible notes has been converted into cash since issuance.

Credit Suisse-led syndicated secured facility:

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. The facility is secured by our existing exploration and corporate entities. 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 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. 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 this 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.

Share Buyback:

On July 21, 2014, our Board authorized a share buy-back to be done periodically on the open market to buy up to $50 million of our common shares within the next 12 months based on the stock price and other market factors. 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.

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

Build on more than 19 years in Papua New Guinea;

Maintain a sound health and safety record;

Continue developing sound relationships with government, partners and stakeholders; and

Remain a significant employer in Papua New Guinea.

Enable our discovered resources

With our joint venture partners, Total and Oil Search, develop the Elk-Antelope resource in PRL 15 into a world-class LNG project,

Introduce strategic investors to our other fields to support their timely development, and

Seek licenses, enabling legislation and approvals from the State for our planned developments.

Maximize the value of our exploration assets

Manage our exploration program to maximize access to license areas;

Partner with experienced operators to leverage their expertise and to accelerate development;

Use our experience in Papua New Guinea for successful seismic acquisition and drilling; and

Employ additional drilling rigs to develop existing discoveries.

Position for long-term success

Streamline our corporate structure and focus staff resources on operations in Papua New Guinea to support exploration, development and operations;

Assemble a highly qualified team to extract full value from our assets and realise our vision as a regional LNG player; and

Build on our core business to provide long-term sustainability.

Annual Information Form INTEROIL CORPORATION 14

DESCRIPTION OF OUR BUSINESS

Overview

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.

EXPLORATION AND PRODUCTION BUSINESS – DESCRIPTION

As at December 31, 2014, we had gross interests in four PPLs and two PRLs, all of which we operate in Eastern Papuan Basin, northwest of Port Moresby. Subsequent to the year ended December 31, 2014, on February 27, 2015, Total was appointed as operator of the PRL 15 joint venture.

Discoveries are covered by retention licenses that are excised from exploration licenses and are designed to allow time to investigate their commerciality.

Our prior licenses over PPL 236, 237 and 238 were set to expire in March 2014. Based on applications made by us for new licenses over these areas, on March 6, 2014, these licenses were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238. The following table summarizes our interests in the licenses following the grant of new licenses as at December 31, 2014:

License Numbers	Discovery	Location	Operator	InterOil Registered License Interest			InterOil Net Beneficial Interest Owned¹			Blocks Covered		Acreage Gross		Acreage Net¹
PPL 474 (PPL 236)	None	Onshore	InterOil		100.00	%		78.1114	%		59		1,232,462		962,693
PPL 475 (PPL 237)	Raptor	Onshore	InterOil		87.0968	%		66.2082	%		25		524,315		347,140
PPL 476 (PPL 238)	Bobcat	Onshore	InterOil		100.00	%		78.6114	%		58		1,215,243		955,320
PPL 477 (PPL 238)	None	Onshore	InterOil		100.00	%		94.2500	%		30		629,254		593,072
PRL 15	Elk/Antelope	Onshore	InterOil²		37.0375	%		36.5375	%		9		188,675		69,637
PRL 39	Triceratops	Onshore	InterOil		69.0931	%		69.0931	%		9		188,877		130,501
Total											190		3,978,826		3,058,363

See ‘Working interests in licenses’ below for details of the Company’s net interest. The government has a 22.5% back-in right in PRL 15 which, if exercised, would reduce our net interest to 28.3166%.

Subsequent to year end, on February 27, 2015, Total E&P PNG Limited was appointed operator of PRL 15. The appointment will take effect in accordance with an operator transition plan and the terms of the Joint Venture Operating Agreement.

Resources

We have no production or reserves or future net revenue as defined in NI 51-101 or under definitions established by the United States Securities and Exchange Commission.

Annual Information Form INTEROIL CORPORATION 15

GLJ, an independent qualified reserves evaluator, effective as of December 31, 2014, evaluated our gas and condensate resources for the Elk, Antelope and Triceratops fields, all of which are in onshore Papua New Guinea. The GLJ 2014 Report, with a preparation date of March 13, 2015 was prepared in accordance with definitions and guidelines in the COGE Handbook and NI 51-101.

This table outlines GLJ's estimates contained in the GLJ 2014 Report effective December 31, 2014 of total and net contingent resources for gas and condensate at the Elk and Antelope field and the Triceratops field:

Total Contingent Resources Estimate for Gas and Condensate
for the Elk and Antelope Fields ^{1, 2}

As at December 31, 2014	Case
Elk/Antelope Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	6.83	9.07	10.85
Marketable Condensate (MMbbls)	111.5	135.4	156.3
Oil Equivalent (MMboe)	1,250.1	1,646.3	1,965.4

Contingent Resource Estimate for Gas and Condensate
for the Elk and Antelope Fields – Net to InterOil^{2, 3}

As at December 31, 2014	Case
Elk/Antelope Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	1.93	2.57	3.07
Marketable Condensate (MMbbls)	31.6	38.3	44.3
Oil Equivalent (MMboe)	354.0	466.2	556.6

Total Contingent Resources Estimate for Gas and Condensate for the Triceratops Field ^1,
2

As at December 31, 2014	Case
Triceratops Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	0.12	0.38	0.90
Marketable Condensate (MMbbls)	2.7	8.2	19.4
Oil Equivalent (MMboe)	23.2	71.9	168.8

Contingent Resource Estimate for Gas and Condensate for the Triceratops Field – Net to InterOil ^2,
4

As at December 31, 2014	Case
Triceratops Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	0.07	0.20	0.48
Marketable Condensate (MMbbls)	1.4	4.4	10.4
Oil Equivalent (MMboe)	12.4	38.5	90.4

Notes:

These estimates represent 100% of the Elk, Antelope and Triceratops fields.

The “low” estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. With the probabilistic methods used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. The “best” estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. With the probabilistic methods used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. The “high” estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. With the probabilistic methods used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate

Annual Information Form INTEROIL CORPORATION 16

These estimates are based upon our holding a 28.3166% working interest in the Elk and Antelope fields, which assumes that: (i) the State and landowners elect to participate in the Elk and Antelope fields to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Elk and Antelope fields and (ii) all elections are made to participate in the field by all investors pursuant to relevant indirect participation interest agreements with us, including to participate fully and directly in the PDL. See ‘Working interests in licenses’ below for details of our net interest assuming completion of the Total transaction.

These estimates are based upon InterOil holding a 53.5471% working interest in the PRL 39, which assumes that: (i) the State and landowners elect to participate in the Triceratops field to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Triceratops field and (ii) all elections are made to participate in the field by all investors entitled to do so pursuant to relevant indirect participation interest agreements with InterOil, including to participate fully and directly in the PDL.

All resources estimated for the Elk and Antelope fields are classified as contingent resources – economic status undetermined. At this early stage of appraisal, the resources estimates for the Triceratops field are classified separately in the GLJ 2014 Report as either contingent resources – economic status undetermined or prospective resources. Consistent with our treatment with the Elk and Antelope fields, the Triceratops prospective resources are not included.

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

The following contingencies must be met before the Elk, Antelope or Triceratops contingent resources can be classified as reserves:

Sanctioning and financing for the facilities required to process and transport marketable natural gas to market;

Confirmation of a market for the marketable natural gas and condensate;

Approval from regulatory authorities to develop the resources; and

Determination of economic viability.

Accuracy of Resource Estimates

The accuracy of resource estimates is in part a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. Other factors in the classification as a resource include a requirement for more appraisal wells, detailed design estimates and near-term development plans. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional appraisal wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of the seismic and well data. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional appraisal wells determined that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well data.

Costs incurred in relation to Exploration and Development activities

This table outlines costs incurred by us during the year ended December 31, 2014 for property, acquisitions, exploration and development activities.

	Amount
Nature of Cost	($ Millions)
Property acquisition costs		-
Exploration costs	$	246.32
Development costs	$	140.38
Total	$	386.70

Annual Information Form INTEROIL CORPORATION 17

Additionally, the following table summarizes results of exploration and development on a gross and net basis (with net costs reflecting the cost to us, not including the portion of costs met by our partners), as further broken down by well type, during the year ended December 31, 2014.

Wells	Development				Exploration				Total
	Gross ($ Millions)		Net ($ Millions)		Gross ($ Millions)		Net ($ Millions)		Gross ($ Millions)		Net ($ Millions)
Gas	$	235.82	$	140.38	$	296.83	$	246.32	$	532.65	$	386.70
Oil		-		-		-		-		-		-
Service		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total	$	235.82	$	140.38	$	296.83	$	246.32	$	532.65	$	386.70

The following table discloses the number of wells completed during the year ended December 31, 2014 (being Bobcat and Raptor), as further broken down by well type and license area. Refer to the Section headed “Working interests in licenses” for details of our net interest in these license areas.

Wells	PPL 474 (PPL 236)		PPL 475 (PPL 237)		PPL 476 (PPL 238)		PPL 477 (PPL 238)		PRL 15		PRL 39		Total
Gas		-		1		1		-		-		-		2
Oil		-		-		-		-		-		-		-
Service		-		-		-		-		-		-		-
Dry		-		-		-		-		-		-		-
Total		-		1		1		-		-		-		2

Operated License Commitments, Terms and Expiry

On March 6, 2014, our license applications were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238. In relation to the PPL commitments noted above, when the new PPL’s were approved, these commitments were terminated and replaced with new license commitments noted below. The new commitments require the Company to spend an additional $369.7 million over the remainder of their license term. The three wells, Wahoo-1, Raptor-1 and Bobcat-1, have been drilled under the new licenses, and are part of the new drilling commitments.

Annual Information Form INTEROIL CORPORATION 18

Below are our applicable expenditure commitments for each PPL and PRL as at December 31, 2014.

License	License Period	Term	Commitment Less than 1 year ( $ Millions)		Commitment Years 1 to 2 ( $ Millions)		Commitment Years 2 to 3 ( $ Millions)		Commitment Years 3 to 5 ( $ Millions)		Commitment More than 5 years ( $ Millions)		Total License Commitment ( $ Millions)
PPL 474 (PPL 236)	February 28, 2014 to February 27, 2020	6 years	$	3.56	$	19.47	$	22.65	$	45.03	$	3.75	$	94.46
PPL 475 (PPL 237)	February 28, 2014 to February 27, 2020	6 years	$	5.63	$	23.68	$	26.87	$	50.31	$	4.17	$	110.66
PPL 476 (PPL 238)	February 28, 2014 to February 27, 2020	6 years	$	1.28	$	21.05	$	25.00	$	50.00	$	4.17	$	101.50
PPL 477 (PPL 238)	February 28, 2014 to February 27, 2020	6 years	$	7.71	$	2.85	$	1.88	$	46.42	$	4.19	$	63.05
PRL15	November 30, 2010 to November 29, 2015	5 years		-		-		-		-		-		-
PRL39	December 20, 2013 to December 19, 2018	5 years	$	28.37	$	15.00	$	15.00	$	0.25		-	$	58.62
	Totals		$	46.55	$	82.05	$	91.40	$	192.01	$	16.28	$	428.29

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

Working interests in licenses

These tables show working interests in our licenses should the State and all other interest holders exercise their rights to acquire their interests as at December 31, 2014. These parties are obliged to pay their share of continuing field development costs and, their interests may be reduced accordingly if they do not make these required payments.

Annual Information Form INTEROIL CORPORATION 19

Petroleum Prospecting License 474 (previously known as Petroleum Prospecting License 236) –Wahoo Well

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		78.1114	%		60.5363	%
IPI Holders₍₁₎₍₄₎		15.1386	%		11.7324	%
PNGDV₍₂₎₍₄₎		6.7500	%		5.2313	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 474 (previously known as Petroleum Prospecting License 236) – (Excluding Wahoo Well)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		94.2500	%		73.0438	%
PNGDV_(2)(3)(4)		5.7500	%		4.4562	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 475 (previously known as Petroleum Prospecting License 237) – (Raptor Discovery)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		66.2082	%		51.3113	%
IPI Holders₍₁₎₍₄₎		15.1386	%		11.7324	%
PNGDV_(2)(3)(4)		5.7500	%		4.4562	%
PRE		12.9032	%		10.0000	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form INTEROIL CORPORATION 20

Petroleum Prospecting License 475 (previously known as Petroleum Prospecting License 237) – (Excluding Raptor Discovery)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		81.3468	%		63.0438	%
PNGDV_(2)(3)(4)		5.7500	%		4.4562	%
PRE		12.9032	%		10.0000	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Retention License 39 (Triceratops Discovery)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		69.0931	%		53.5471	%
IPI Holders₍₁₎₍₄₎		12.4517	%		9.6501	%
PNGDV₍₂₎₍₄₎		5.5520	%		4.3028	%
PRE		12.9032	%		10.0000	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 476 (previously known as Petroleum Prospecting License 238) – (Bobcat Discovery)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		78.6114	%		60.9238	%
IPI Holders₍₁₎₍₄₎		14.6386	%		11.3449	%
PNGDV₍₂₎₍₄₎		6.7500	%		5.2313	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form INTEROIL CORPORATION 21

Petroleum Prospecting License 476 (previously known as Petroleum Prospecting License 238) – (Excluding Bobcat Discovery)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		79.1114	%		61.3113	%
IPI Holders₍₁₎₍₄₎		15.1386	%		11.7324	%
PNGDV_(2)(3)(4)		5.7500	%		4.4563	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 477 (previously known as Petroleum Prospecting License 238)

Participant	Working Interests as at December 31, 2014 (before State Participation)			Working Interests (after State Participation)
InterOil		94.2500	%		73.0438	%
PNGDV_(2)(3)(4)		5.7500	%		4.4562	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Retention License 15 (Elk and Antelope Discoveries)

Participant	Working Interests (before State Participation)			Working Interests (after State Participation)
InterOil		36.5375	%		28.3166	%
Total S.A		40.1275	%		31.0988	%
Oil Search		22.8350	%		17.6971	%
IPI Holders₍₁₎		0.5000	%		0.3875	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Notes:

⁽¹⁾

In February 2005, indirect participating interest holders agreed to pay InterOil $125.0 million and we agreed to drill seven exploration wells in PPLs 474 (236), 475 (237), and 476 and 477 (238). We have drilled seven of these wells to date. IPI holders may acquire an interest in field development after an exploration well is drilled in which the holder has an interest. If an exploration well is successful, the IPI holders may participate in the development of the fields discovered by that well if they pay their share of field development costs.

Annual Information Form INTEROIL CORPORATION 22

⁽²⁾

In July 2003, we agreed that PNGDV could take a 6.75% interest in eight exploration wells. We have drilled six of these exploration wells to date. PNGDV also has the right to participate in the next 16 wells that follow the first eight mentioned above up to an interest of 5.75% for $112,500 for each 1% per well (with higher amounts to be paid if the depth exceeds 3,500 meters and the cost exceeds $8,500,000).

⁽³⁾

Assumes that PNGDV will elect to participate in the remaining 15 wells (their Raptor-1 election was the first of 16 wells that they have option to participate at their 5.75% interest election).

⁽⁴⁾

IPI holders do not have a direct interest in any PPL but they are entitled to convert their interest after a PRL is granted, subject to our approval.

DISCONTINUED OPERATIONS

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 also been transferred to Puma. Following the Puma Transaction, the results of these operations have been classified as ‘discontinued operations’ and we are no longer organized as separate segments for reporting purposes.

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.

General Description of Midstream - Refining Business (applicable until June 30, 2014)

The refinery in Port Moresby began production in 2005. We imported crude oil for processing at the refinery and sold the refined products primarily in Papua New Guinea at import parity price.

The primary products were jet fuel, diesel and gasoline for the Papua New Guinea market. We also produced two naphtha grades and low-sulfur waxy residue and exported excess naphtha to local and Asian markets as light or mixed naphtha, predominately for petrochemical feedstock. Low-sulfur waxy residue was sold for power generation domestically and as local bunker fuel with the majority exported for use in other complex refineries or as supply to other users, including power generators.

Facilities and Major Subcontractors

The refinery included a jetty with two berths for loading and discharging vessels and a road tanker loading system or gantry. The larger berth has deep water access of 56 feet (17 meters) and could accommodate tankers up to 130,000 dead weight tonnes. The smaller berth could accommodate ships with capacity up to 22,000 dead weight tonnes. The tank farm had the ability to store about 750,000 bbls of crude and about 1.1 MMbbls of refined products. There was a reverse osmosis desalination unit that produced all of the water used by the refinery, camp and offices, producing our own electricity, and had support facilities including a laboratory, waste water treatment plant, staff accommodation and a fire station.

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The refinery’s on-site laboratory was accredited by the National Association of Testing Authorities of Australia and was staffed and operated by an internationally recognized independent inspection and testing company. All crude imports and finished products were tested and certified on-site to contractual specifications, while independent certification of quantities loaded and discharged at the refinery were also provided by the laboratory.

Crude Supply

Since December 2001, BP Singapore, one of the largest marketers and shippers of crude oil in the Asia Pacific, had supplied crude to the refinery under contract which has been renewed over the years. This contract had provided us with a reliable mechanism to access and ship the majority of the regional crudes suitable to the refinery.

Sales

The principal market for the refinery products, other than naphtha and low-sulfur waxy residue, was Papua New Guinea. Under the 30-year Project Agreement with the State, domestic distributors were required to buy their refined petroleum products from the refinery or from any other refinery that may be constructed in Papua New Guinea at import parity price. In general, the import parity price for each refined product was based on the mean of Platts Singapore, the current benchmark price for refined products in the region in which we operated. To this posted price, the cost that would typically be incurred to import such product (such as freight costs, insurance costs, landing charges, losses incurred in the transportation of refined products, damages and taxes) are added and the resulting price is the import parity price. We also distributed a large portion of our production through our retail distribution network.

Light and mixed naphtha was our major export product and we were fully certified to manufacture and market Jet A1 fuel to international specifications and markets.

Competition

Due to their favorable properties, light sweet crudes from the South-East Asia and North-West Australia are favored by refiners for use as feedstock and competition is significant, which meant that we were not always able to secure our first choice crudes for the refinery and were required to find alternatives.

Domestic distributors have not sourced all of their requirements from the refinery since 2009.

We only exported excess diesel, gasoline, naphtha and low-sulfur waxy residue that are exported. This and our location and limited storage capacity inhibited our ability to compete with the regional refining in Singapore for sales of large cargo sizes.

Customers

We sold Jet A1 fuel, diesel, gasoline and low-sulfur waxy residue to distributors in Papua New Guinea. Our main domestic customer was the downstream distribution business segment (also transferred as part of Puma Transaction), and we also distributed fuel products to Niugini Oil Company, Islands Petroleum, ExxonMobil, Total Asia PNG, and Bige Petroleum.

Trading and Risk Management

Our revenues were derived from the sale of refined petroleum products. Refined products and crude prices were volatile and experienced large fluctuations over short periods because of relatively small changes in supply, weather conditions, economic conditions and government actions. Because of time differences between buying crude, discharging it at the refinery, and supplying the finished product to customers, the refinery faced two types of market risks.

The first risk was flat price (or timing) risk, which resulted from the time lag between crude purchases and product sales. Generally, we were required to purchase crude feedstock approximately one to two months in advance of processing, whereas the domestic supply or export of finished products takes place after the crude feedstock is discharged and processed. This timing difference could lead to differences between the cost of the crude feedstock and the revenue from the proceeds of the sale of products, due to the fluctuation in prices during the time period.

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The second risk was so-called crack spread (or margin) risk where monthly changes in price, even when pricing of crude purchases and that of product sales fall in the same month, could affect refinery profitability.

During 2013, we signed international swaps and derivate agreements with ANZ Singapore and Natixis to complement the then existing agreement with BNP Singapore to hedge market risks within the working capital facility.

Three-Year History

We sold 4.0 MMbls of product in six months ended June 30, 2014, 9.2 MMbbls in 2013 and 8.3 MMbbls in 2012. During the six month period ended June 30, 2014, our average daily production (excluding shut down days) was 26,970 bblspd compared to 27,999 bblspd in 2013 and 24,483 bblspd in 2012. The total number of barrels processed into product at our refinery for six months ended June 30, 2014 was 4.001 MMbbls compared to 9.247 MMbbls in the year ended 2013 and 7.426 MMbbls in the year ended 2012. Our refinery was shut down for a total of 28 days in six months ended June 30, 2014 compared to 24 days in the year ended 2013 and 51 days in year ended 2012.

General Description of Downstream Business – Wholesale and Retail Distribution (applicable until June 30, 2014)

We had the largest wholesale and retail petroleum product distribution base in Papua New Guinea. This business included bulk storage, transportation and distribution of refined petroleum products to wholesale, retail and aviation facilities across Papua New Guinea.

Sales

ICCC regulates the maximum prices and margins in the wholesale and retail bulk fuel distribution industry in Papua New Guinea. Margins were last reviewed by the ICCC in 2010. We and other industry distributors could provide a discount from the maximum wholesale price set by ICCC.

Supply of Products

The retail and wholesale business distributed diesel, jet fuel, avgas, gasoline, kerosene and fuel oil and branded commercial and industrial lubricants, such as engine and hydraulic oils. In general, all diesel, jet fuel and gasoline products sold pursuant to the wholesale and retail distribution business were brought from the refinery. We imported commercial and industrial lubricants, avgas and fuel oil, which constituted a small percentage of our total volumes.

We delivered refined products from the refinery in two chartered tanker vessels, which we leased and operated. Our inland depots were supplied by road tankers that were owned and operated by third-party independent contractors.

Our terminal and depot network distributed refined petroleum products to retail service stations, aviation facilities and commercial customers. We supplied retail service stations and commercial customers using hired road tankers or coastal ships, the cost of which were passed to customers under ICCC pricing formula.

Retail Distribution

We had storage and distribution terminal facilities in Port Moresby, Alotau, Lae, Madang, Wewak, Goroka, Mt Hagen, Rabaul, Kimbe and Kavieng, which enabled us to offer national deals to customers. The only area in Papua New Guinea in which we were not represented in was Oro Province (Popondetta). We also serviced 11 aviation sites throughout the country, and supplied the only provider of Jet A1 fuel at the main international airport in Port Moresby.

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Wholesale Distribution

We supplied petroleum products as a wholesaler to commercial customers and operated aviation refueling facilities throughout Papua New Guinea. We owned and operated six large terminals and five smaller terminals and two inland bulk fuel depots. We had commercial supply agreements with mining, agricultural, fishing, logging and similar commercial customers, many of which included complementary equipment loan agreements. Under these, we supplied and maintained company-owned above-ground storage tanks and pumps that were used by these customers. Commercial customers accounted for more than two-thirds of petroleum products we sold in 2013 and first half of 2014, though margins are lower than through our retail distribution network. Aviation customers represent a significant proportion of our total business by volume.

Competition

Our main competitor in the wholesale and retail distribution business in Papua New Guinea was ExxonMobil. We also competed with smaller local distributors of petroleum products. In early 2010, many of our competitors began to directly import diesel and other refined products. This importation of refined products has made it difficult to accurately gauge our market share, particularly as joint industry shipping arrangements ceased as a result. Our competitors sourced small quantities from the refinery road gantry for the Port Moresby market and from tanker vessels for markets outside Port Moresby. Our major competitive advantage was our distribution network and storage capacity that services most of Papua New Guinea.

Major Customers

In 2013 and early 2014, we sold approximately one-sixth of refined petroleum products to a major mining project in Papua New Guinea. These volumes were contracted with narrow margins due to competitive pressures and in order to provide volumes for the Midstream – Refinery operations as such.

In 2013 and early 2014, we sold approximately one-tenth of the refined petroleum products to Pacific Energy Aviation (PNG) Ltd for aviation refueling at Papua New Guinea’s international airport in Port Moresby.

Three-Year History

Prior to the Puma Transaction, we provided petroleum products to 52 retail service stations with 43 operating under our own brand, and the remainder under independent brands. Of all the service stations that we supplied, we owned or leased 17, which we then sub-leased to Company-approved operators.

The PNG economy slowed slightly since 2013 as construction of the ExxonMobil led LNG project neared completion. Total sales volumes for the six months ended June 30, 2014 were 361.5 million liters (year ended December 31, 2013 – 738.0 million liters and December 31, 2012 – 752.5 million liters).

Summary of Debt Facilities Repaid or Transferred to Puma as part of the Puma Transaction (as of June 30, 2014)

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

ANZ, BSP and BNP syndicated secured loan facility (Midstream- Refining):

In October 2012, we entered into a five-year amortizing $100.0 million secured-term loan facility with BNP Paribas, BSP and ANZ, which was used to repay all outstanding amounts under a term loan from the Overseas Private Investment Corporation and to provide funds for general corporate purposes. The loan was secured over the assets of the refinery and bears interest at LIBOR plus 6.5% per annum. All available funds under this facility were drawn down in November 2012.

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The syndicated secured loan facility was repaid in full during the quarter ended June 30, 2014.

BNP working capital and non-recourse discounting facility (Midstream- Refining):

In February 2012, we increased our working capital facility limit with BNP Paribas by $10.0 million to $240.0 million.

In July 2013, we replaced our $240.0 million working capital facility from BNP Paribas with a $350.0 million working capital structured facility led by BNP Paribas. Out of the $350.0 million, $270.0 million is a syndicated secured working capital facility supported by BNP Paribas, ANZ, Natixis, Intesa Sanpaolo S.p.A and BSP and includes the ability for us to discount receivables with recourse up to $30.0 million. In addition, BNP Paribas has provided an $80.0 million bilateral non-recourse discounting facility, the credit portion of which bears interest at LIBOR plus 3.75% per annum.

The syndicated secured working capital facility was transferred to Puma on completion of the sale of the refinery and distribution businesses to Puma on June 30, 2014, and the bilateral non-recourse discounting facility was cancelled on the same date.

BSP and Westpac Combined Working Capital Facility (Downstream):

We had an approximately $37.1 million (PGK 90.0 million) combined revolving working capital facility for the Downstream operations in Papua New Guinea from Westpac and BSP. These facilities were transferred to Puma on completion of the sale of the refinery and distribution businesses to Puma on June 30, 2014.

BSP and Westpac Combined Secured Facility (Downstream):

We entered into a one year combined secured facility with Westpac and BSP to be drawn in tranches, in either USD and/or PGK. The facility was repaid in full during the quarter ended June 30, 2014.

THE ENVIRONMENT AND COMMUNITY RELATIONS

Environmental Protection

Our operations in Papua New Guinea are covered by environmental laws on emissions, pollution and contamination of the air, waters and land, and production, use, handling, storage, transportation and disposal of waste, hazardous substances and dangerous goods, conservation of natural resources, the protection of threatened and endangered flora and fauna and the health and safety of people.

These environmental laws set standards for the operation, maintenance, abandonment and reclamation of our sites. Significant Papua New Guinea laws covering our operations include the Environment Act 2000; the Oil & Gas Act 1998; the Dumping of Wastes at Sea Act (Ch. 369); the Conservation Areas Act (Ch.362); and the International Trade (Flora and Fauna) Act (Ch.391).

The Environment Act is the most significant law affecting our operations. It regulates the environmental impact of development activities to promote sustainable development and imposes a duty on us to take all reasonable and practicable measures to prevent or minimize environmental harm. A breach of this Act can result in significant fines or penalties.

Compliance with Papua New Guinea’s environmental legislation can require significant expenditure. Although we can give no assurances, we believe that continued compliance with existing Papua New Guinea’s environmental laws will not have a material effect on our capital expenditure, earnings or competitive position with our existing assets and operations, unless we have an extraordinary, unforeseen event. Future legislative action and regulatory initiatives could result in changes to operating permits, additional remedial action or increased capital expenditures and operating costs that cannot be assessed with certainty at this time.

More stringent laws and regulations on climate change and greenhouse gases may be imposed in future and could cause us to incur material expenses in complying with them. Regulatory initiatives could adversely affect the marketability of the refined products we produce and any oil and natural gas we may produce. The impact of such future programs cannot be predicted.

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Environmental and Social Policies

Our environmental policy acknowledges that sustainable development is integral to responsible resource management and development. Under the policy, we strive to minimize the impact of our operations on people and the environment, and we share the community’s desire to protect the environment from unacceptable impact. We routinely analyze the environmental risk of our major projects, ensure we can manage those risks and develop management, monitoring and reporting plans. Our approach complies with Papua New Guinea’s environmental protection laws and helps us to monitor our compliance and performance. We have established corporate controls in which all “near miss and real incidents” are reported and investigated.

We are committed to working closely with the communities in which we operate and to complying with all laws and government regulations, including maintaining a safe and healthy work environment and working in full compliance with all applicable environmental laws.

Our Community Relations department oversees the management of community assistance programs and manages land acquisition related compensation claims and payments. Our development philosophy is based on “bottom-up planning” so all planning and development takes account of local communities. In our midstream refining business, we have a long-term community development assistance program for villages near the refinery. In addition, staff in our upstream business lead land owner identification studies, social mapping management, local recruitment, liaison with landowners, recording compensation to land owners and assisting with health and medical services where we explore. We work with government, landowners and the community to ensure our activities have a minimum environmental impact and maintain or generally improve the quality of life in areas in which we operate.

RISK FACTORS

Our business is subject to numerous risks and uncertainties, some of which are described below. Additional risks not presently known to us or that we consider immaterial based on information currently available to us may also materially adversely affect us. If any of the following risks or uncertainties actually occurs, our business, financial condition and results of operations could be materially adversely affected.

Our ability to develop our resources, including our joint venture share of contribution to the construction of an LNG plant and associated facilities, depends on our ability to obtain significant funding.

We currently have no production or reserves. We make, and will continue to make, substantial capital expenditure for exploration, development, acquisition and future production of oil and gas reserves, our joint venture share of the costs of construction of an LNG plant and other infrastructure associated with the proposed LNG plant, and for further capital acquisitions and expenses. Our share of costs may amount to hundreds of millions of dollars. Our existing cost estimates, which in some cases are in early stages of development, are subject to change due to such items as scope change, revised and more detailed estimates, cost overruns, change orders, construction delays, increased material costs, escalation of labor costs, and increased spending to maintain schedule.

To fund these projects, we will need additional funding. Our ability to obtain such funding will depend, in part, on factors beyond our control, such as the status of capital and industry markets when financing is sought and such markets’ view of our industry and of our prospects and our partners at the relevant time. We may not be able to obtain financing on terms that are acceptable to us, or at all, even if our development projects are otherwise proceeding on schedule. In addition, our ability to obtain particular financing may depend on our ability to obtain other types of financing. For example, project-level debt financing typically depends on a significant equity capital contribution from the project sponsor. As a result, we may have to obtain another form of external financing to fund an equity capital contribution to the project subsidiary, even if we are able to identify potential project-level lenders. Failure to obtain financing at any point in the development process could cause us to delay or fail to complete our business plan for development of our resources.

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As a result of weakened global economic conditions, including the European sovereign debt crisis, the downgrading of United States government debt and commodity price fluctuations, we, and all other energy companies, may have restricted access to capital, bank debt and equity, and may also face increased borrowing costs. Although our business and asset base have not declined, the lending capacity of many financial institutions has diminished and risk premiums have increased. As future capital expenditures will not be financed by funds from operations, our ability to raise funds in equity and debt markets, borrowings and possible future asset sales, depends on, among other factors, the state of the capital markets and investor appetite for investments in the energy industry and our assets and securities in particular.

To the extent that external sources of capital are limited or unavailable or available only on onerous terms, our ability to make capital investments and maintain existing assets may be restricted, and our assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result.

Based on current funds available and facilities available to us, we believe we have sufficient funds for our exploration and appraisal program in the normal course, but not for the full development of our exploration assets or our joint venture share of construction costs of an LNG plant, each of which would require significant capital.

We must obtain and maintain necessary permits, licenses and approvals from Papua New Guinea government authorities to develop our gas resources and to construct an LNG plant within reasonable periods and on reasonable terms, which can be costly and time consuming.

We do not hold title to our properties in Papua New Guinea, but hold licenses to land granted by the Papua New Guinea government. We can give no assurance that we will have our licenses re-issued when they expire or that we will get additional licenses to develop our properties. If we do not satisfy the Papua New Guinea government that we have the financial and technical capacity to operate our licenses, they may be withdrawn, not granted or not re-issued. Negative developments relating to our permits, licenses or other approvals would have a material adverse effect on our ability to do business.

We may not be successful in our exploration for oil and gas.

As of December 31, 2014, we had drilled eleven exploration wells and several appraisal wells in our license areas. We plan to drill additional wells in Papua New Guinea in line with our license commitments. We cannot be certain that the wells will be productive or that we will recover all or any portion of the costs to drill them. Because of the high cost, topography and subsurface characteristics of the areas we are exploring, we have limited seismic or other geoscience data to assist us in identifying drilling objectives. The lack of this data makes our exploration activities more risky than would be the case if such information were readily available.

Our exploration and development plans may be curtailed, delayed or cancelled because of a lack of capital and other factors, such as weather, compliance with governmental regulations, price controls, landowner interference, mechanical difficulties, shortages of materials, delays in the delivery of equipment, success or failure of activities in similar areas, current and forecast oil and gas prices and changes in cost estimates. We will continue to gather information about our exploration acreage and discoveries, and additional information may cause us to alter our schedule or determine that an exploration program or development project should not be pursued. Our exploration programs are subject to change and we can give no assurance that our exploration will result in the discovery of additional resources. In addition, exploration and development costs may materially exceed our initial estimates.

We will be transitioning the operatorship of PRL 15 to Total in accordance with the provisions of the JVOA. As a non-operator, our development of successful operations will rely extensively on Total, which if not successful, could have a material adverse effect on our business.

As a non-operator of PRL 15, we may no longer be able to control the timing of the development, exploration, testing and ultimate production of the wells drilled under such license. If Total is not successful in such activities, or are unable or unwilling to perform such activities, our financial condition and operations could be materially affected.

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Our ability to recruit and retain qualified personnel may have a material adverse effect on our operating results and share price.

Our success depends largely on the continued services of our directors, executive officers, senior managers and other key personnel. The loss of these people, especially without sufficient advance notice, could have a material adverse impact on our business. It is also important to attract and retain highly skilled people, including technical personnel, to manage our development plans, execute our exploration plans and replace personnel who leave. Competition for qualified personnel can be intense, and few people have the necessary knowledge and experience, particularly in Papua New Guinea where a large number of our skilled people are required to work. Under these conditions, we could be unable to recruit, train, and retain employees, which could have material adverse effect on our business, operating results and share price.

Our investments in Papua New Guinea are subject to political, legal and economic risks that could materially adversely affect their value.

Our investments in Papua New Guinea involve risks typically associated with investments in developing countries, such as uncertain political, economic, legal and tax environments; corruption; expropriation and nationalization of assets; war; renegotiation or nullification of existing contracts; taxation policies; foreign exchange restrictions; international monetary fluctuations; currency controls; and foreign governmental regulations that favor or require the awarding of service contracts to local contractors or require foreign contractors to employ citizens of, or buy supplies from, a particular jurisdiction.

Political conditions have at times been unstable in Papua New Guinea. Notwithstanding current conditions, our ability to operate, explore or develop our business is subject to changes in government regulations or shifts in political attitudes over which we have no control. We provide no assurance that we have adequate protection against any or all of the risks described above or that present or future government actions or government regulations in Papua New Guinea will not materially adversely affect our operations.

In addition, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of Canada or the United States if we have dispute with our Papua New Guinea operations or proposed development projects.

Title to certain of our properties, or to properties we require for the construction of an LNG plant and associated facilities, may be defective or challenged by third-party landowner claims, and landowner action may impede access to or activity on those properties.

We face the risk that title to our properties may be defective or subject to challenge. In particular, the properties we require in Papua New Guinea could be subject to customary land title or traditional landowner claims, which may deprive us of our property rights that consequently have a material adverse effect on exploration and drilling operations and our development projects. In particular, Special Agricultural and Business Leases have been granted in Papua New Guinea that have created uncertainty for landowners and other leaseholders such as us. In 2011, the government of Papua New Guinea created a Commission of Inquiry to investigate the grants of these special purpose leases. We cannot guarantee when the inquiry will be finalized, that its findings will be implemented, or that it will provide certainty for our leased and licensed rights over lands on which we operate.

In addition, landowner disturbances may occur on our properties that may disrupt our business.

Implementation of new Papua New Guinea laws or the failure of permits and approvals under existing Papua New Guinea laws to be granted in a timely manner may have a material adverse effect on our operations, developments, and financial condition.

Our operations require licenses and permits from government authorities to drill wells and construct an LNG plant and associated facilities. We believe that we hold all necessary licenses and permits under applicable laws and regulations for our existing operations in Papua New Guinea and believe we will be able to comply in all material respects with such licenses and permits based on our current plans. However, such licenses and permits may change and we cannot guarantee that we will be able to obtain or maintain licenses and permits that may be required to maintain our operations. It is also possible that new laws may be enacted in Papua New Guinea (such as a limit on foreign ownership of local assets) that may have a material adverse effect on our operations and financial condition.

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Additional licenses and permits will be required for us to develop our Elk, Antelope, Triceratops, Raptor and Bobcat discoveries, and construct an LNG plant and associated facilities. We cannot guarantee that we will be able to obtain these licenses and permits in a timely manner or at all.

The exploration and production businesses are competitive.

We operate in a highly competitive business and several of our competitors have materially greater financial and other resources than we do which means they have greater ability to bear economic risk.

In our exploration and production business, we also compete for the purchase of licenses from the State and of leases from other oil and gas companies. Factors that affect our ability to compete include:

Our access to capital to drill wells and explore so we retain our exploration licenses and acquire additional properties;

Our ability to acquire and analyze seismic, geological and other information about a property;

Our ability to retain and hire the personnel to properly evaluate seismic and other information about a property;

Our ability to contract for or otherwise obtain drilling equipment;

The development and cost of, and our ability to access, transport systems to bring production to market; and

The standards we set for minimum projected return on investment of capital.

We also compete with other oil and gas companies in Papua New Guinea for labor and equipment to explore and develop our projects. Many of our competitors have substantially greater financial and other resources, and larger competitors may be able to absorb any changes in laws and regulations more easily than us, which would adversely affect our competitive position. These competitors may pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and buy a greater number of properties and prospects than we can. Our ability to explore for oil and gas prospects and to acquire additional properties will depend on our ability to operate, to evaluate and select suitable properties, and to consummate transactions in this highly competitive environment. In addition, most of our competitors have been operating in the oil and gas business for a much longer than us and have demonstrated the ability to operate through industry cycles.

There are inherent limitations in all control systems, and misstatements due to error that could seriously harm our business may not be detected.

A company’s internal control over financial reporting is designed to provide reasonable assurance about the reliability of its financial reporting and the preparation of financial statements for external purposes. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with regulations and guidelines, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on financial statements.

A control system, no matter how well designed and operated, can provide only reasonable assurance that its objectives are met.

Because of its inherent limits, internal control over financial reporting may not prevent or detect misstatements. Changes to our internal controls may enhance the likelihood of these events. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that compliance with the policies or procedures may deteriorate.

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Our operations expose us to risks, not all of which are insured.

Our operations are subject to various hazards common to the industry, including explosions, fires, toxic emissions, maritime hazards and uncontrollable flows of hydrocarbons and refined products. In addition, our operations are subject to hazards of loss from earthquakes, tsunamis and severe weather. As protection against operating hazards, we maintain insurance coverage against some, but not all of such potential losses. We may not maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, losses may exceed coverage limits. As a result of market conditions, premiums and deductibles for insurance, policies for refiners have increased substantially and could escalate further. In some instances, insurance could become unavailable or available only for reduced coverage. For example, insurance carriers now require broad exclusions for losses due to risk of war and terrorist acts. If we incurred a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.

Third parties may default on their contractual obligations to us.

We have entered into contracts with third parties that subject us to the risk that they may default on their obligations. We may be exposed to third-party credit risk through contracts with our current or future joint venture partners, lenders, and other parties. If such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on us and cash flow from operations.

Weather and unforeseen operating hazards, not all of which are insured, may adversely impact our operating activities.

Our operations are subject to risks inherent in the oil and gas industry, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, equipment failures including damages to our facilities, pollution, and other environmental risks. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. Our Papua New Guinea operations are subject to a variety of additional operating risks such as earthquakes, mudslides, tsunamis, cyclones and other effects associated with active volcanoes, extensive rain or other adverse weather. Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. For some risks, we may not get insurance if we believe the cost of available insurance is excessive relative to the risks. In addition, pollution and environmental risks, as well as risks of war and terrorist acts generally are not fully insurable. As a result, substantial liabilities to third parties or government entities may be incurred, the payment of which could have a material adverse effect on our financial condition and operations.

Compliance with environmental and other government regulations could be costly and could negatively impact our business.

The laws and regulations of Papua New Guinea regulate our current business. Our operations could result in liability for personal injuries, property damage, natural resource damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with environmental laws and regulations may trigger administrative, civil and criminal enforcement, including the assessment of monetary penalties and orders enjoining operations. In addition, we could be liable for environmental damage caused by, among others things, previous property owners or operators. We could also be affected by more stringent laws and regulations yet to be adopted, including those on climate change and greenhouse gases, resulting in increased operating costs. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could have a material adverse effect on our financial condition, operations and liquidity. Additionally, more stringent greenhouse gas regulation could diminish demand for oil and gas.

These laws and governmental regulations, which include drilling, liquefaction, and environmental protection, may change in response to economic or political conditions and could have a significant negative effect on our operating costs. While we believe are currently in compliance with environmental laws and regulations, we cannot give you an assurance that we will continue to comply with such environmental laws and regulations without incurring substantial costs.

We may be party to lawsuits and other proceedings that may result in adverse publicity, adversely affect our financial position or ability to pursue our business.

We may from time to time be a party to lawsuits and other proceedings. Lawsuits and proceedings may also divert our financial and management resources that would otherwise be used to benefit the future performance of our operations. In addition, if we are not successful in defending legal actions to which we are a party, our financial position and ability to pursue our business strategy may be adversely effected.

Annual Information Form INTEROIL CORPORATION 32

You may be unable to enforce your legal rights against us.

We are a Yukon, Canada corporation. Substantially all of our assets are located outside of Canada and the United States. It may be difficult for investors to enforce, outside of Canada and the United States, judgments against us that are obtained in Canada or the United States in any such actions, including actions predicated on civil liability provisions of securities laws of Canada and the United States. In addition, many of our directors and officers are nationals or residents of countries outside of Canada and the United States, and all, or a substantial portion of, their assets are outside of Canada and the United States. As a result, it may be difficult for investors to serve process on these persons in Canada or the United States or to enforce judgments against them obtained in Canadian or United States courts, including judgments predicated on civil liability provisions of the securities laws of Canada or the United States.

Future sales of our common shares may adversely affect the price of our shares.

We believe that substantially all of our common shares currently outstanding, and common shares issued in the future on the exercise of outstanding options, vesting of restricted stock units and on conversion of the convertible notes, will be freely tradable under the US federal securities laws, subject to limits. These limits include vesting provisions in option and restricted stock unit agreements and volume and manner-of-sale restrictions under Rule 144 of the US Securities Act. Any sale of a substantial number of our common shares into the public market, or the perception that such sales could occur, could adversely affect the prevailing market price of our common shares.

DIVIDENDS

We have not paid dividends on our common shares and currently reinvest all cash from operations for the operation and development of our business. No change to this policy or approach is presently intended or under consideration. We have no restrictions that prevent us from paying dividends on our common shares. Any decision to pay dividends on our common shares depends on our earnings and financial position (including the effect on financial ratios and covenants with our lenders) and such other factors as the Board may consider appropriate.

DESCRIPTION OF CAPITAL STRUCTURE

InterOil is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, issuable in series, of which 1,035,554 series A preferred shares are authorized. As at December 31, 2014, 49,414,801 common shares were issued and outstanding. All of the series A preferred shares that had been issued were converted into common shares during 2008 and none remain outstanding as at December 31, 2014. We also have outstanding $70.0 million of 2.75% convertible senior notes due November 15, 2015, which are convertible, at the option of the note holders, into 732,004 common shares as of December 31, 2014.

Common Shares

Holders of common shares are entitled to one vote per share held at any meeting of our shareholders, to receive, out of all profits or surplus available for dividends, any dividends declared by us on the common shares, and to receive our remaining property in the event of our liquidation, dissolution or winding up, whether voluntary or involuntary.

Preferred Shares

Preferred shares may at any time be issued in one or more series, each series to consist of such number of shares as may, before the issue thereof, be determined by unanimous resolution of our directors. Subject to the provisions of the YBCA, the Board may by unanimous resolution fix from time to time, before the issue thereof, the designation, rights, privileges, restrictions and conditions attaching to each series of the preferred shares.

Annual Information Form INTEROIL CORPORATION 33

2.75% Convertible Senior Notes

We currently have outstanding $70.0 million principal amount of 2.75% convertible senior notes due in November 2015. The convertible notes are unsecured and unsubordinated obligations of InterOil. They 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, trade payables and lease obligations.

We pay interest semi-annually on May 15 and November 15. The notes are convertible into cash or 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 about $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 if we take action with 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 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 price equal to the principal amount of the notes to be repurchased, plus accrued and unpaid interest.

Shareholder Rights Plan

On May 29, 2013, we adopted a new shareholder rights plan (“New Rights Plan”), and terminated the original 2007 rights plan. The new plan was approved by our shareholders at the annual and special meeting of shareholders on June 24, 2013. The rights plan was adopted to ensure, to the extent possible, that all shareholders of the Company are treated fairly in case of any take-over offer for the Company, and, in the event of an unsolicited bid, to ensure that the Board is provided with a sufficient period to evaluate unsolicited takeover bids and to explore and develop alternatives to maximize shareholder value.

Under the new plan, one right was issued by us for each outstanding common share at the close of business on May 29, 2013, and for each common share issued thereafter (subject to the terms of the new plan). The rights issued under the new plan become exercisable only if an offeror acquires or announces its intention to acquire 20% or more of the common shares of InterOil without complying with the “permitted bid” provisions of the plan or without the approval of the Board. Permitted bids must be made to all holders of common shares of InterOil by way of a takeover bid circular prepared in compliance with applicable securities laws and, among other things, must be open for acceptance for a minimum of 60 days. If at the end of 60 days at least 50% of the outstanding common shares other than those owned by the offeror and related parties have been tendered and not withdrawn, the bidder may take up and pay for the shares but must extend the bid for a further 10 days to allow other shareholders to tender to the bid. If a takeover bid does not meet the permitted bid requirements of the new rights plan, the rights will entitle our shareholders, excluding the shareholder or shareholders making the takeover bid, to buy additional common shares of the Company at a substantial discount to the market price of the common shares at that time.

The new rights plan is similar to rights plans adopted by other Canadian incorporated public companies and is substantially similar to the old shareholder rights plan. The new rights plan was not adopted in response to any actual or threatened takeover bid or other proposal from a third party to acquire InterOil. A copy of the new rights plan is available under our profile on SEDAR at www.sedar.com.

Options

Our 2009 Stock Incentive Plan, authorized by our shareholders at the annual and special meeting held on June 19, 2009, allows employees to acquire our common shares. Option exercise prices are governed by the plan rules and equal the market price for the common shares on the date the options were granted. Options granted under the plan are generally fully exercisable after one year or more and expire five years after the grant date, although some have shorter vesting periods. Default provisions in the plan rules provide for immediate vesting of granted options and expiry 10 years after the grant date. Some options granted under a predecessor plan approved in 2006 also remain in effect. No further grants may now be made under this superseded 2006 plan.

As of December 31, 2014, there were options outstanding to buy 410,000 common shares under our stock incentive plans.

Annual Information Form INTEROIL CORPORATION 34

Restricted Stock Units

In addition to the options noted above, our 2009 Stock Incentive Plan also allows employees to acquire our common shares pursuant to restricted stock unit grants. As of December 31, 2014, restricted stock units entitling employees to rights to 99,528 common shares were outstanding pursuant to our stock incentive plans. The restricted stock units provide those employees with the right to receive common shares on a one-for-one basis on certain vesting dates. Vesting dates generally occur one, two and/or more years after grant.

MARKET FOR OUR SECURITIES

Our common shares are listed and posted for trading on the New York Stock Exchange under the symbol IOC. We are also listed on the Port Moresby Stock Exchange in Papua New Guinea under the symbol IOC. The following table discloses the monthly high and low trading prices and volumes of our common shares as traded on the New York Stock Exchange during 2014:

New York Stock Exchange (NYSE:IOC) in United States Dollars
Month	High		Low		Volume		Close
January		55.00		43.85		19,488,503		50.67
February		59.90		49.12		10,908,766		57.38
March		65.71		57.19		10,512,911		64.76
April		69.81		61.06		8,462,913		63.21
May		66.25		58.04		6,630,271		66.10
June		68.83		60.76		5,345,148		63.94
July		64.40		53.29		6,132,596		56.62
August		63.32		54.50		6,312,957		60.65
September		61.86		53.62		5,544,674		54.26
October		56.89		43.25		8,183,236		56.64
November		60.86		54.21		5,832,663		54.50
December		58.01		43.66		12,053,835		48.79

Annual Information Form INTEROIL CORPORATION 35

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides information about our directors and executive officers:

Directors and Executive Officers
Name, Province/State and Country of Residence	Position with InterOil	Date of Appointment
Dr. Michael Hession Singapore	Director and Chief Executive Officer⁽¹⁾	July 11, 2013

Chris Finlayson Surrey, United Kingdom	Chairman⁽²⁾	August 7, 2014

Roger F. Lewis Western Australia, Australia	Director⁽³⁾	November 26, 2008

Ford Nicholson British Columbia, Canada	Deputy Chairman⁽⁴⁾	June 22, 2010

Sir Rabbie Namaliu East New Britain, Papua New Guinea	Director⁽⁵⁾	July 1, 2012

Samuel L. Delcamp California, USA	Director until March 12, 2015⁽⁶⁾	July 1, 2012

Sir Wilson Kamit CBE National Capital District, Papua New Guinea	Director⁽⁷⁾	June 24, 2013

Dr. Ellis Armstrong Texas, USA	Director⁽⁸⁾	January 1, 2015

Katherine Hirschfeld Queensland, Australia	Director⁽⁹⁾	January 1, 2015

Yap Chee Keong Singapore	Director⁽¹⁰⁾	March 13, 2015

Isikeli Taureka National Capital District, Papua New Guinea	Executive Vice President PNG	June 24, 2013

Jon Ozturgut Singapore	Chief Operating Officer	January 21, 2014

Donald Spector Singapore	Chief Financial Officer	January 22, 2014

Geoff Applegate Singapore	General Counsel and Corporate Secretary	December 1, 2012

Thomas Nador Singapore	Senior Vice President, Corporate	December 17, 2013

David J. Kirk Singapore	Senior Vice President, Development and Drilling	November 15, 2013

Laurie Brown Singapore	Senior Vice President, Exploration	September 8, 2014

Annual Information Form INTEROIL CORPORATION 36

Notes:

(1)

Dr. Michael Hession was appointed as Chief Executive Officer on July 11, 2013, as a director on November 15, 2013 and as a member of the Reserves Committee on February 12, 2014. He remains so at the date of this AIF.

(2)

Mr. Christopher Finlayson was appointed a director and Chairman-designate on August 7, 2014. He was appointed Chairman on October 16, 2014 on the retirement of the former Chairman, Dr. Gaylen Byker. Mr. Finlayson was appointed as a member and Chairman of the Compensation Committee, and a member of the Nominating and Governance Committee and of the Reserves Committee, with effect from October 16, 2014 and continues in those positions and as Chairman of the Board at the date of this AIF.

(3)

Mr. Roger Lewis is and was throughout 2014 Chairman of the Audit Committee, and a member of the Nominating and Governance Committee and of the Compensation Committee.

(4)

Mr. Ford Nicholson was appointed Deputy Chairman of the Board on April 11, 2014 and remains so at the date of this AIF. He is a member of the Reserves Committee and held that position throughout 2014. He was appointed Chairman of the Reserves Committee, and a member and Chairman of the Nominating and Governance Committee on June 23, 2014, positions he holds at the date of this AIF.

(5)

Sir Rabbie Namaliu was appointed a Director on July 1, 2012 and remains a director at the date of this AIF. He has been a member of the Nominating and Governance Committee since June 23, 2014.

(6)

Mr. Samuel L. Delcamp was appointed as a Director on July 1, 2012. He retired as a director on March 12, 2015. He was throughout 2014 and until his retirement a member of the Board’s Audit Committee, Compensation Committee and Nominating and Governance Committee.

(7)

Sir Wilson Kamit was appointed as a director on June 24, 2013, and as a member of the Audit Committee on June 23, 2014, and remains so at the date of this AIF.

(8)

Dr. Ellis Armstrong was appointed as a director effective January 1, 2015 and remains a director at the date of this AIF. He was appointed a member of the Board’s Audit Committee and Reserves Committee on March 12, 2015.

(9)

Katherine Hirschfeld was appointed as a director effective January 1, 2015 and remains a director at the date of this AIF. She was appointed a member of the Board’s Compensation Committee and Nominating and Governance Committee on March 12, 2015.

(10)

Mr. Yap Chee Keong was appointed as a director on March 13, 2015 and remains a director at the date of this AIF.

Information has been furnished by our directors and executive officers that includes information as to our common shares in the company beneficially owned, controlled or directed, directly or indirectly, by them, their places of residence and principal occupations, both present and historical, interests in material transactions and potential conflicts of interest.

The term of office of each of our directors will expire at the next annual meeting of our shareholders. All executive officers generally hold office at the pleasure of the Board.

As of March 10, 2015, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly 82,572 common shares, representing 0.17% of our outstanding issued common shares. In addition to common shares beneficially owned or controlled or directed, directly or indirectly, by our directors and executive officers, 172,271 shares are issuable on exercise of outstanding options and restricted stock units, resulting in directors and executive officers holding 0.52% of our issued common shares on a diluted basis.

Our Board has established an Audit Committee, a Compensation Committee, a Nominating and Governance Committee and a Reserves Committee. Mr. Lewis, Sir Wilson Kamit and Dr. Armstrong are members of the Audit Committee. Mr. Finlayson, Mr. Lewis and Ms. Hirschfeld are members of the Compensation Committee. Mr. Nicholson, Mr. Finlayson, Mr. Lewis, Sir Rabbie Namaliu and Ms. Hirschfeld are members of the Nominating and Governance Committee. Mr. Nicholson, Mr. Finlayson, Dr. Armstrong and Dr. Hession are members of the Reserves Committee. Mr. Lewis chairs the Audit Committee, Mr. Finlayson chairs the Compensation Committee, and Mr. Nicholson chairs the Nominating and Governance Committee and the Reserves Committee.

Background to Directors and Executives

The following is a brief description of the background and principal occupations of each director and executive officer at present and during the preceding five years:

Michael Hession is a citizen of Australia and Ireland, who was appointed as our Chief Executive Officer on July 11, 2013. Dr. Hession previously served as the Senior Vice President at the Browse LNG Development, a division of Woodside Energy Ltd (WPL.AX) (“Woodside”), where he was responsible for development of the company’s biggest hydrocarbon resource and one of the world’s largest global energy projects. During his 12-year career at Woodside, he held several high-profile roles related to the Pluto LNG Mega-Project and exploration and development of assets in North Africa and North America. Dr. Hession began his career at BP International (BP.L) (“BP”). His last position at the company was Development Manager on the Chirag Azeri Mega-Project. He also managed exploration projects in Indonesia, the United States and Norway. Dr. Hession was educated in Britain and France, and has a doctorate in geophysics from the University College Wales and a geology degree from the University of Hull in the UK. He also holds a master in business administration from the London School of Economics and Ecole des Hautes Etudes Commerciales in Paris.

Annual Information Form INTEROIL CORPORATION 37

Chris Finlayson is citizen of the United Kingdom, and is Chairman of our Board, replacing Dr. Gaylen Byker as our Chairman on October 16, 2014. He was the former BG Group Chief Executive Officer from year 2013 to year 2014, focused on improving operational performance of the existing asset base and on the timely execution of the group’s major investments in Australia and Brazil. He has a track record of delivering large-scale capital projects and improving operational management in challenging circumstances, having led major ventures for Shell in Russia, Nigeria, Brunei and the UK North Sea. He also has more than 15 years’ experience at senior level in the LNG industry, covering upstream development through to LNG shipping and marketing. Mr. Finlayson has worked successfully with joint venture partners, national oil companies, and governments at the highest levels. Mr. Finlayson has a science degree in physics and geology with first-class honours from the University of Manchester in 1977.

Roger F. Lewis is an Australian citizen and a former senior finance executive, having spent 22 years with Woodside Energy Ltd in Western Australia, finishing as Group Financial Controller. Before that, he worked in commercial and finance roles for more than 15 years in heavy manufacturing in Australia and overseas. He is a fellow certified practicing accountant with the Australian Society of Certified Practicing Accountants. Mr. Lewis was a commissioner of the Lottery Commission of Western Australia until his retirement in 2011, with particular responsibility for finance and accounting and as a member of the commission’s audit and major projects committees.

Ford Nicholson is a Canadian citizen and is the President of Kepis & Pobe Financial Group that specializes in developing international energy and other natural resource assets. Over the past 25 years, Mr. Nicholson has provided executive management to several international projects. He was a co-founder and director of Nations Energy Ltd. producing heavy oil in Kazakhstan and a founding shareholder and former board member of Bankers Petroleum Ltd. producing heavy oil in Albania. Mr. Nicholson was also a board member of Tartan Energy Inc., a heavy oil company based in California. Mr. Nicholson is chairman of TSX-listed BNK Petroleum Inc. producing and exploring for unconventional natural gas in Europe and the US. He is also on the president's council of the International Crisis Group. Mr. Nicholson lives in British Columbia, Canada.

Sir Rabbie Namaliu is a Papua New Guinean citizen and served as Prime Minister of Papua New Guinea from 1988 until 1992. Sir Rabbie was Speaker of the National Parliament between 1994 and 1997 and Minister for Foreign Affairs and Trade from 1982 until 1984. He has held several other senior government posts since his election to parliament in 1982. He is independent non-executive director of Perth-based Marengo Mining Limited and he has been Chairman of the board of the publicly listed investment firm, Kina Asset Management Ltd, since 2008. He is a member of the PNG Institute of Directors. Sir Rabbie chaired our PNG Advisory Committee from August 2011 to June 2012 until his appointment to the Board in July 2012.

Samuel L. Delcamp is an American citizen and has more than 40 years of investment experience. Mr. Delcamp was Executive Director and Chief Investment Officer of The Fuller Foundation, a public charity, for 24 years. He was instrumental in founding the organization and overseeing the growth in its assets under management from $4.0 million to more than $600.0 million. Mr. Delcamp has been Director and President of MBM Partners, Inc., an unregistered investment advisor. Mr. Delcamp was appointed to the Board in July 2012.

Sir Wilson Kamit is a Papua New Guinean citizen and former Governor of the Bank of Papua New Guinea and Chairman of its board. In that capacity, he also served as the alternate governor representing Papua New Guinea at the International Monetary Fund. After his retirement, Sir Wilson joined the board of the Asian Development Bank as the alternate executive director representing the Republic of Korea, Papua New Guinea, Sri Lanka, Taipei, China, Uzbekistan, Vanuatu and Vietnam. Sir Wilson began his career at the Bank of Papua New Guinea, where he had management roles until being appointed Deputy Governor. Sir Wilson has a degree in economics from the University of Papua New Guinea and he is a senior fellow of the Corporate Directors Association of Australia, an honorary fellow of the PNG Institute of Banking and Business Management Inc., and a member of the Papua New Guinea Institute of Directors Inc. He was made a Commander of the British Empire in June 2000 and knighted in June 2009 by the Queen of England.

Dr. Ellis Armstrong is citizen of the United Kingdom and has more than 30 years of international oil and gas experience with BP in the Caribbean and Latin America, Venezuela, Alaska and the North Sea. He held senior strategy, commercial and operational roles with BP and ran the company’s technology group, was the group’s Commercial Director, and was Chief Financial Officer for the group’s global exploration and production business. He is also a non-executive director of Lamprell plc, a diversified engineering and contracting company that is listed on the London Stock Exchange, and Lloyds Register, a leading international risk assurance firm. Dr Armstrong was BP’s representative on advisory boards to the UK Department of Energy and Climate Change and the Institute of Americas, and was executive sponsor of BP’s relationship with Imperial College, London. He is a civil engineer from Imperial College and has a business degree from Stanford University.

Annual Information Form INTEROIL CORPORATION 38

Katherine Hirschfeld is an Australian citizen and has 20 years with BP in leadership and executive roles in oil refining, logistics, exploration and production in Australia, New Zealand, the United Kingdom and Turkey. Prior to her retirement in 2010, Ms Hirschfeld was Executive Director, BP Australasia, with responsibility for strategy and performance of BP’s Australian and New Zealand refining and marketing business. She is a non-executive director of the major Australian engineering group, Transfield Services Ltd, and waste management firm Toxfree Solutions Ltd, both of which are listed on the Australian Securities Exchange. Ms Hirschfeld is also on the board of ASC Pty Ltd, the Australian Government’s wholly owned naval shipbuilding company, and UN Women Australia, the United Nations entity responsible for promoting women’s empowerment and gender equality. She is a fellow of the Australian Academy of Technological Sciences and Engineering, Engineers Australia and the Institution of Chemical Engineers (UK) and is on the governing senate of The University of Queensland.

Yap Chee Keong is a Singaporean citizen. He is the Chairman and non-executive independent director of CityNet Infrastructure Management Pte Ltd, the trustee manager of Netlink Trust. He is the lead independent director of Tiger Airways Holdings Limited, a non-executive independent director of Citibank Singapore Limited and a non-executive director of The Straits Trading Company Limited and ARA Asset Management Limited. He also serves as a board member of the Accounting and Corporate Regulatory Authority and as a member of the Public Accountants Oversight Committee. Mr. Yap was previously the Executive Director of The Straits Trading Company Limited and the Chief Financial Officer of Singapore Power Ltd. He has also worked in various senior management roles in multinational and listed companies. He was a member of the Working Group of the Corporate Governance Oversight Committee of the Monetary Authority of Singapore. He holds a Bachelor of Accountancy from the National University of Singapore and is a Fellow of the Institute of Singapore Chartered Accountants, a Fellow of CPA Australia and a Fellow of the Singapore Institute of Directors.

Isikeli (Keli) Taureka is a Papua New Guinean citizen and former head of Chevron Corporation’s Geothermal and Power Operations. His career with Chevron included roles as President of ChevronTexaco China Energy Company with responsibility for Chevron’s oil and gas upstream activities in China. He held executive positions, including General Manager and Country Manager for Chevron New Guinea Limited, where he was responsible for oil operations in Papua New Guinea and Western Australia. Before joining Chevron, Mr. Taureka managed the state-owned Post and Telecommunication Corporation. He also worked at the Bank of South Pacific Limited as Deputy Managing Director of the joint venture, Resources Investment Finance Limited. Mr. Taureka has a degree in economics from the University of Papua New Guinea.

Jon Ozturgut was appointed our Chief Operating Officer in January 2014 after a long career as a senior oil and gas executive with extensive experience in multi-billion-dollar investments in exploration development, and production across global markets in the Americas, Middle East, Africa, Australia and Asia. He has held executive positions in operations, delivering significant projects and company transforming transactions with Pioneer Natural Resources, CMS Oil and Gas Company and Atlantic Richfield Company of the United States, the latter of which spanned 15 years. He also oversaw international corporate strategy, exploration portfolio growth, mergers and acquisitions, and LNG developments for Woodside Energy, Australia’s largest oil and gas company. Mr. Ozturgut is a mechanical engineer.

Donald Spector was appointed Chief Financial Officer in January 2014. Prior to joining us, Mr. Spector has held senior roles in BP and CRA (now known as Rio Tinto) and Woodside Energy where he managed the treasury, taxation, risk, and insurance functions, and advised on mergers and acquisitions. He successfully developed the capital management strategy to fund the A$15 billion Woodside Pluto LNG Project in Western Australia. He also worked for the Australian Taxation Office. Mr. Spector has a degree in accounting.

Geoff Applegate was appointed General Counsel and Corporate Secretary in December 2012 after 17 years as special counsel and partner with Gadens Lawyers of Sydney and Port Moresby. He has been a corporate and commercial lawyer in private practice for more than 40 years, with extensive experience in resource development and oil and gas law. Mr. Applegate practiced law in Papua New Guinea for more than 13 years and has arts and law degrees from Sydney University.

Thomas Nador was appointed General Manager of Planning and Strategy in December 2013 and Senior Vice President, Corporate in 2014. He has had roles in field development, project execution and management, integration management, and project strategy development across five LNG developments in Australia. Mr. Nador leads corporate strategic planning and integration on behalf of the Chief Executive Officer and Board, drawing on global economic, industry, and competitor trends to inform and guide our growth aspirations. He also oversees communications and human resources.

Annual Information Form INTEROIL CORPORATION 39

David J. Kirk was appointed Vice President, Upstream Business Unit in November 2013 and Senior Vice President, Development and Drilling in 2014. He oversees exploration and appraisal operations, asset development, and production readiness. Mr. Kirk was previously Chief Executive Officer of AWT International, an upstream engineering and geosciences consultancy. He has held development management positions in Australia, West Africa, and North Africa with Woodside Petroleum, with responsibility for field development, project execution, and operational phases of asset management. He worked with BP as a petroleum engineer, and for several major North Sea operators, primarily on well design and production operations. He also had experience with Bechtel in LNG construction. Mr. Kirk has a degree in science and civil engineering from Queens University, Belfast, and a masters in petroleum engineering from the Imperial College of Science and Technology.

Laurie Brown was appointed Senior Vice President, Exploration in September 8, 2014. He oversees exploration strategy, exploration portfolio management, geoscience, and field data acquisition programs, including seismic and other technologies. Mr. Brown has 32 years’ international oil and gas industry experience, including 17 years with BP. He worked as a Shell Global Consultant advising Shell and Woodside in project peer reviews. He also has 12 years’ experience in executive board positions with, and co-founding, small oil and gas companies, including two which listed on the Australian Securities Exchange.

Mr. Brown has a science degree with honours in Geology and Geophysics from Durham University in the United Kingdom.

Cease Trade Orders

To the knowledge of the Company, no director or executive officer of the Company (nor any personal holding company of any of such persons) is, as of the date of this form, or was within ten years before the date of this form, a director, chief executive officer or chief financial officer of any company (including the Company), that: (a) was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an “Order”), that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or (b) was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

Bankruptcies

To the knowledge of the Company, no director or executive officer of the Company, or shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company (nor any personal holding company of any of such persons): (a) is, as of the date of this form, or has been within the ten years before the date of this form, a director or executive officer of any company (including the Company) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or (b) has, within the ten years before the date of this form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

Penalties or Sanctions

Annual Information Form INTEROIL CORPORATION 40

Conflicts of Interest

Some of our directors and officers will face potential conflicts of interest with our operations. Situations may arise where some business activities of directors and officers will be in direct competition with us. In particular, some directors and officers will be in managerial or director positions with other oil and gas companies, whose operations may, from time to time, be in direct competition with us or entities that may, from time to time, provide financing to us, or make equity investments in our competitors. In addition, some directors have relationships with other entities with which we may have material agreements or have business relationships. These relationships may create a real or perceived conflict of interest.

Conflicts, if any, will be subject to the YBCA that provides that a director or officer shall disclose the nature and extent of any interest that he or she has in a material contract or material transaction, whether made or proposed, if the director or officer: is a party to the contract or transaction, is a director or an officer, or an individual acting in a similar capacity, of a party to the contract or transaction, or has a material interest in a party to the contract or transaction, and shall refrain from voting on any matter in respect of such contract or transaction unless otherwise provided under the act. We intend to resolve all conflicts of interest in accordance with the YBCA.

AUDIT COMMITTEE

Charter of the Audit Committee

The full text of the Charter of the Audit Committee is attached as Schedule C to this Annual Information Form.

Composition of the Audit Committee

Current members of the Audit Committee are Mr. Roger Lewis (Committee Chairman), Sir Wilson Kamit and Dr. Ellis Armstrong. Mr. Lewis was a member of the Committee throughout 2014. Sir Wilson Kamit was appointed as a member of the Committee on June 24, 2014. Former Chairman Dr. Byker was a member of the Committee from July 10, 2013 until his retirement on October 16, 2014. Former director Mr. Samuel Delcamp was a member of the Committee throughout 2014 and until his retirement on March 12, 2015. Dr. Armstrong was appointed to the Committee on March 12, 2015. All Audit Committee members are and were during 2014 independent and financially literate within the meaning of NI 52-110.

Relevant Education and Experience

The relevant education and experience of current members of the Audit Committee is set out in detail under the heading “Directors and Executive Officers”:

This education and experience is such that each member has an understanding of the accounting principles used by us to prepare our financial statements; the ability to assess the general application of such accounting principles in connection with the accounting for estimates, accruals and reserves; experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues raised by our financial statements, or experience actively supervising one or more individuals engaged in such activities; and an understanding of internal controls and procedures for financial reporting.

Pre-Approval Policies and Procedures

The Audit Committee is authorized and required by the Board to review, discuss and pre-approve non-audit services to be performed by the external auditors, save where such services are subject to the de-minimis exceptions described in the US Securities Exchange Act of 1934. If non-audited services are required, a documented scope and estimate are submitted by the Company’s auditors to the Chairman of the Audit Committee who will consult other committee members, as necessary, before providing any approval on the Audit Committee’s behalf.

Annual Information Form INTEROIL CORPORATION 41

External Auditor Service Fees

PricewaterhouseCoopers, Chartered Accountants, have served as our auditors since June 6, 2005. This table lists audit, audit-related, tax and other fees billed by PricewaterhouseCoopers in each of the past two financial years.

PricewaterhouseCoopers
	2014		2013
Audit Fees¹	$	1,896,489	$	1,978,492
Audit-Related Fees²		-	$	665,891
Tax Fees³	$	472,129	$	577,863
All Other Fees⁴	$	38,525	$	2,551
Total	$	2,407,143	$	3,224,797

Notes:

"Audit Fees" means the aggregate fees billed by the issuer's external auditor in each of the last two fiscal years for audit fees.

"Audit-Related Fees" means the aggregate fees billed in each of the past two fiscal years for assurance and related services provided by the issuer's external auditor, other than the services reported as Audit Fees above and principally relate to quarterly financial reporting of certain subsidiaries of the Company and work performed on potential secondary listing on capital markets.

"Tax Fees" means the aggregate fees billed in each of the past two fiscal years for professional services rendered by the issuer's external auditor for tax compliance, tax advice, and tax planning.

"All Other Fees" means the aggregate fees billed in each of the past two fiscal years for products and services provided by the issuer's external auditor, other than the services reported as Audit Fees, Audit-Related Fees and Tax Fees above and principally relates to the annual license renewal of Comperio, an online library of financial reporting tools and certain tax advice in relation to expatriate benefits and certain transfer pricing documentation.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

From time to time we are involved in various claims and litigation arising from our business. While the outcome of these matters is uncertain and we can give no assurance that such matters will be resolved in our favor, we do not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on our financial position, results of operations or liquidity.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

See under the heading “Directors and Executive Officers – Conflicts of Interest”.

There are no material interests, direct or indirect, of directors, executive officers of the Company or any person or company that beneficially owns or controls or directs, directly or indirectly, more than 10% of the outstanding common shares, or any known associate or affiliate of any such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect the company.

MATERIAL CONTRACTS

The following represent material contracts that were entered into or are still in effect during 2014:

Indenture Governing the 2.75% Convertible Senior Notes Due 2015 dated November 10, 2010

The $70.0 million principal amount of 2.75% convertible senior notes due in November 2015 were issued on November 10, 2010 under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee, of August 06, 2008, as supplemented by the first supplemental indenture, dated as of November 10, 2010. We refer to the indenture as so supplemented as the “Note Indenture”.

Annual Information Form INTEROIL CORPORATION 42

For a summary of the material terms of the convertible senior notes due 2015, see “Description of Capital Structure – 2.75% Convertible Senior Notes”.

Farm-In Agreement by PRE

On July 27, 2012, we entered into a farm-in agreement (and certain related agreements) with PRE under which we agreed to farm out to an affiliate of PRE a 10% net revenue interest in PPL 237, which contains the Triceratops field, in exchange for certain cash payments and work carry obligations. The license interest assigned to PRE was grossed up to a 12.903226% working interest to account for the potential exercise by the State of its statutory right to back-in to a 22.5% net revenue interest in any petroleum project based on a PDL granted over the area comprised in the license under certain conditions. Pursuant to the terms of the agreement, PRE was obligated to pay an initial cash amount of $116.0 million and subject to satisfaction of standard terms and conditions, committed to a resource payment from production sales. At December 31, 2013, PRE paid the entire $116.0 million initial payment. PRE also agreed to an additional carry for a work program of up to seven appraisal wells in the Triceratops field located within PPL 237 and at least four exploration wells in other structures in PPL 237. PRE has the right to withdraw from its interests in PPL 237 and its related work carry obligations under certain circumstances. In that event, we would be required to refund up to $96.0 million of the initial cash payment to PRE from net sales proceeds of production from our interest in PRL 15. If for any reason, such sales proceeds from PRL 15 were insufficient to repay the full amount after six years, we would be required to repay the balance from corporate funds.

On January 24, 2013, the DPE registered the transfer and related joint venture operating agreement. We also amended the agreement to cap PRE’s carry at $25.0 million, with any well costs in excess of this to be borne by the parties according to their participating interests. This has been applied retrospectively for historical sunk costs for the Triceratop-2 well.

Total SPA

On December 5, 2013, we agreed to sell to Total a gross 61.3% interest (net 47.5%, after PNG government back-in of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields, and to also grant Total an option to farm-in to all our exploration licenses in Papua New Guinea pursuant to the Total SPA. The Total SPA stipulated fixed and variable resource-based payments that included $613.0 million payable on transaction completion, $112.0 million payable on a FID for a new LNG plant, and $100.0 million payable at first LNG cargo from a proposed LNG facility. In addition to these fixed amounts, Total was 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 to be drilled in PRL 15. The payments for resources greater than 5.4 Tcfe will be paid at certification.

Total will carry the cost of these appraisal wells (up to a cap of $50.0 million per well), which are scheduled to be drilled in 2014 and 2015, and certification of the Elk and Antelope resources is expected in 2015. Under the agreement, Total will lead construction and operation of a proposed integrated LNG Project, a FID on which is scheduled to follow resource certification, concept selection, basis of design and front- end engineering and design.

In addition to payments for the Elk and Antelope resources in PRL 15, Total has also agreed to pay $100.0 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 facility. Total will also carry the cost of this exploration well to a maximum of $60.0 million. Costs in excess of this are to be borne by the parties according to their participation interests.

Completion of the Total SPA remained subject to government approval and the acquisition by InterOil of minority interests in PRL 15. However, 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. Accordingly it became impossible to fulfill one of the conditions precedents to completion of that agreement.

Total SSA

On February 26, 2014, SPI (200) Limited (a wholly owned subsidiary of the Company) was acquired by SPI (208) Limited pursuant to a share transfer executed between SPI E&P Corporation and SPI (208) Limited. In addition, pursuant to an Instrument of Transfer, SPI (208) Limited transferred to SPI (200) Limited a 40.127529% interest in the PRL15 license effective as at February 27, 2014. The transfer was approved and registered pursuant to section 97 of the Oil and Gas Act on March 7, 2014.

Annual Information Form INTEROIL CORPORATION 43

Further, on March 26, 2014, we executed, with Total, a revised sale and purchase agreement, under which Total acquired through the purchase of all shares in SPI (200) Limited, a gross 40.127529% interest in PRL 15. We retained 35.483871% of the license and immediately received $401.3 million for closing the transaction, and will receive $73.3 million on a FID for an Elk and Antelope LNG project, and $65.5 million on the first LNG cargo. All fixed and variable resource-based payments that were agreed under Total SPA dated December 5, 2013 continue to apply, including those for exploration, appraisal and resource certification, and are pro-rated according to the new equity split.

Credit Suisse-led Syndicated Term Loan Facility Agreement

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. The facility is secured by our existing exploration and corporate entities, including InterOil Corporation, SPI (208) Limited, SPI (210) Limited, SPI (220) Limited, SPI Distribution Limited, InterOil Products Limited, InterOil Finance Inc., SPI Exploration and Production Limited, InterOil Corporation PNG Ltd, SPI CSP PNG Limited, InterOil Australia Pty Ltd, InterOil Singapore Pte. Ltd. and InterOil Shipping Pte. Ltd. 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.

All other contracts agreed or still in effect during 2014 were entered into in the ordinary course of our business or were not material to us.

Each of the above material agreements have been filed on SEDAR and are available through the SEDAR website at, www.sedar.com.

EXTRACTIVE INDUSTRIES TRANSPARENCY INITIATIVE

Extractive Industries Transparency Initiative (“EITI”) is a global standard to promote openness and accountable management of natural resources. On March 19, 2014, PNG’s EITI candidacy was approved by the EITI board of directors. Thereafter, the State implemented the EITI standards, which ensure greater transparency of the payments to the government from the active resources projects in PNG.

The fiscal regime in PNG applying to the petroleum and gas industry consists of a combination of corporate income tax, royalties, development levies and development incentives. It is governed by the Oil and Gas Act (1998) and the Income Tax Act (1959). The Oil and Gas Act (1998) gives the PNG Government the option of participating in petroleum projects to a maximum 22.5% interest, 2% of which must be granted to project area land owners. The application of the fiscal regime to particular projects in the oil and gas industry is governed by the terms of petroleum or gas agreements between the State and developers. We are granted licenses to explore for hydrocarbons that may be found within the country, however, no taxes were paid for this resource exploration as we are still at the exploration phase. For a full summary of our current license holdings, please refer to “Exploration and Production Business - Description” section of this AIF for details.

Annual Information Form INTEROIL CORPORATION 44

During the year, we have paid the following taxes to the State:

PNG Taxes Paid
	2014 ($million)		2013 ($million)
Excise duties ⁽¹⁾		20.6		42.6
Company Income Tax		0.6		5.7
Personal Income Tax ⁽²⁾		11.4		14.3
Goods and Services Tax ⁽³⁾		29.1		53.6
Other Government Taxes⁽⁴⁾		5.5		3.1
Total		67.2		119.3

Notes:

Excise duty is a PNG Inland Revenue Commission’s taxes levied or charged on certain goods/products legally declared as Excisable Products. Excisable products that attract Excise duties are Beer, Tobacco Products, Spirituous Liquors, Wine Products and Petroleum Products, manufactured or further manufactured in Papua New Guinea or imported.

Personal income tax is tax revenue derived from individual tax payers and companies. It is taxed on Pay as You Earn (“PAYE”) basis.

A Goods and Services Tax is a tax, which is imposed on the sale of goods and services in Papua New Guinea or the importation of goods into PNG.

Includes foreign contractor’s withholding tax, interest withholding tax, stamp duty and management fee withholding tax paid to Inland Revenue Commission of PNG.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares is Computershare Investor Services, Inc.

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.

100 University Avenue, 9^th Floor

Toronto, Ontario

Canada M5J 2YI

Tel: 1-800-564-6253 (toll free North America)

Fax: 1-888-453-0330 (toll free North America)

E-mail: service@computershare.com

Website: www.computershare.com

Co-Transfer Agent (USA)

Computershare Trust Company N.A.

350 Indiana Street

Golden, Colorado 80401

U.S.A.

Tel: 1-800-962-4284 (toll free North America)

International: 1-514-982-7555

INTERESTS OF EXPERTS

PricewaterhouseCoopers, Chartered Accountants, are the Company’s auditors and have audited the financial statements of the Company for the year ended December 31, 2014. As at the date hereof, PricewaterhouseCoopers were independent within the meaning of Public Company Accounting Oversight Board Rule 3520.

Information on resources of the Company in the Statement of Resources Data and Other Oil and Gas Information was evaluated by GLJ, as independent qualified reserves evaluators. As at December 31, 2014, the principals and employees of GLJ involved in the resource assessment of the Company did not hold any registered or beneficial ownership interests, directly or indirectly in the common shares or the 2.75% convertible senior notes.

Annual Information Form INTEROIL CORPORATION 45

ADDITIONAL INFORMATION

Additional information, including that related to directors’ and officers’ remuneration, principal holders of our common shares and securities authorized for issuance under equity compensation plans was contained in our information circular for our annual meeting of shareholders held on June 24, 2014 and will be contained in our information circular for our upcoming annual meeting of shareholders expected to be held in June 2015. Additional financial information is provided in our audited consolidated financial statements for the year ended December 31, 2014 (the “Audited Financial Statements”) and related 2014 MD&A. Our Audited Financial Statements, 2014 MD&A, Information Circular and additional information can be found on the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com and on our website at www.interoil.com.

Copies of the Audited Financial Statements, 2014 MD&A and additional copies of this AIF may also be obtained by contacting Mr. Geoffrey Applegate General Counsel and Corporate Secretary at 163 Penang Road, Winsland House II, #06-02, Singapore 238463 Telephone +65 6507 0473.

Annual Information Form INTEROIL CORPORATION 46

Schedule A – Report of Management and Directors on Oil and Gas Disclosure

FORM 51-101F3 REPORT OF

MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

InterOil’s management is responsible for the preparing and disclosing information about the company's oil and gas activities in accordance with the securities regulatory requirements. This information includes (i) reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2014, and (ii) resources as at December 31, 2014.

The company’s board of directors has determined that the company had no reserves as at December 31, 2014.

An independent qualified reserve evaluator has evaluated the company's resources data and the evaluator’s report will be filed with securities regulatory authorities concurrently with this report.

The Reserves Committee of the board of directors of the Company has:

(a)

reviewed the company's procedures for providing information to the independent qualified reserves evaluator;

(b)

met the evaluator to determine whether any restrictions affected the ability of the evaluator to report without reservation; and

(c)

reviewed the reserves data with management and the evaluator.

The Committee has also reviewed the company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board has, on the recommendation of the Reserves Committee, approved:

(a)

the content and filing with securities regulatory authorities of Form 51-101F1 containing the company’s oil and gas activities and resources data;

(b)

the filing of the Form 51-102F2 which is the report of the independent qualified reserves evaluator on the resources data; and

(c)

the content and filing of this report.

Because the resources data are based on judgments regarding future events, actual results will vary and the variations may be material.

DATED effective March 17, 2015.

“Michael Hession”		“Chris Finlayson”
Michael Hession		Chris Finlayson
Chief Executive Officer		Director

“Donald Spector”		“Sir Wilson Kamit”
Donald Spector		Sir Wilson Kamit
Chief Financial Officer		Director

“Ford Nicholson”		“Katherine Hirschfeld”
Ford Nicholson		Katherine Hirschfeld
Director		Director

“Sir Rabbie Namaliu”		“Ellis Armstrong”
Sir Rabbie Namaliu		Ellis Armstrong
Director		Director

“Roger Lewis”
Roger Lewis
Director

Annual Information Form INTEROIL CORPORATION 47

Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator

REPORT ON RESOURCES DATA

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

To the board of directors of InterOil Corporation (the "Company"):

We have evaluated the Company’s resources data as at December 31, 2014. The resources data are estimates of low, best and high estimates of contingent and unrisked prospective resources as at December 31, 2014.

The resources data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the resources data based on our assessment.

We carried out our assessment in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

Those standards require that we plan and perform an assessment to obtain reasonable assurance as to whether the resources data are free of material misstatement. An assessment also includes assessing whether the resources data are in accordance with principles and definitions presented in the COGE Handbook.

The following table sets forth the estimates of low, best and high estimates of contingent and unrisked prospective resources as at December 31, 2014:

Company Gross
MMBOE

Independent
Qualified Reserves
Evaluator and Resource
Category

Description and
Preparation
Date of
Assessment
Report

Location of
Reserves
(Country or
Foreign
Geographic Area)

Low

Best

High

Contingent Resources
GLJ Petroleum Consultants

March 13, 2015

Papua New Guinea

744.8

1,002.8

1,241.2

Prospective Resources
GLJ Petroleum Consultants

March 13, 2015

Papua New Guinea

34.9

95.4

185.7

In our opinion, the resources data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.

We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

Because the resources data are based on judgments regarding future events, actual results will vary and the variations may be material.

Annual Information Form INTEROIL CORPORATION 48

Contingent resources estimates will not be classified as reserves until the following contingencies are satisfied: (i) sanctioning of the facilities required to process and transport marketable natural gas, (ii) confirmation of a market for the marketable natural gas, and (iii) determination of economic viability. Contingent resources entail commercial risk not applicable to reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

Prospective resources were assigned in unexplored regions of the Company’s acreage. Prospective resources entail commercial risk not applicable to reserves and contingent resources, which have not been included in the net present valuation. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 13, 2015.

Keith M. Braaten, P. Eng.

President & CEO

Annual Information Form INTEROIL CORPORATION 49

Schedule C – Audit Committee Charter

This Audit Committee Charter (the “Charter”) sets forth the purpose and membership requirements of the Audit Committee (the “Committee”) of the Board of Directors (the “Board”) of InterOil Corporation (the “Company”) and establishes the authority and responsibilities delegated to it by the Board.

Purpose. The purpose of the Committee is to assist the Board in fulfilling its oversight responsibilities. In fulfilling this purpose, the Committee’s primary duties and responsibilities are to:

Review management's identification of principal financial risks and monitor the process to manage such risks.

Oversee and monitor the Company’s compliance with legal and regulatory requirements.

Oversee audits of the Company's financial statements.

Oversee and monitor the integrity of the Company’s accounting and financial reporting processes, financial statements and system of internal controls.

Oversee and monitor the qualifications, independence and performance of the Company’s external auditor and the performance of the Company’s internal auditors.

Provide an avenue of communication among the Board, the external auditor, management and the internal auditors.

Report to the Board regularly.

The Committee shall be empowered to conduct or cause to be conducted any investigation appropriate to fulfilling its responsibilities, and shall have direct access to the external auditors, the internal auditor and Company employees as necessary. The Committee shall be empowered to retain, at the Company’s expense, independent legal, accounting, or other consultants or experts as the Committee deems necessary in the performance of its duties. The Committee shall have sole authority to approve related fees and retention terms, and the Company shall provide for payment of such fees and for the compensation to the external auditor for the purpose of rendering or issuing an audit report or performing other audit, review or attest services for the Company, as well as funding for the payment of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.

Committee Membership.

2.1.

Composition and Appointment. The Committee shall consist of three or more members of the Board. The Board shall designate members of the Committee. Membership on the Committee shall rotate at the Board’s discretion. The Board shall fill vacancies on the Committee and may remove a Committee member from the membership of the Committee at any time without cause. Members shall serve until their successors are appointed by the Board and as otherwise required by applicable law or the rules of the New York Stock Exchange (“NYSE”).

2.2.

Independence and Financial Literacy. Each member of the Committee must qualify as an independent and financially literate director pursuant to National Instrument 52-110 - Audit Committees (as implemented by the Canadian Securities Administers), as amended from time to time, and meet the independence, or an applicable exception, financial literacy, and experience requirements of the NYSE rules and applicable U.S. federal securities laws, including the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). In addition, at least one member of the Committee must be an “audit committee financial expert” as defined by the SEC.

2.3.

Service on Multiple Audit Committees. If a member of the Committee serves on the audit committee (or, in the absence of an audit committee, the board committee performing equivalent functions, or in the absence of such committee, the board of directors) of more than two other public companies, the Board must affirmatively determine that such simultaneous service on multiple audit committees will not impair the ability of such member to serve on the Committee.

2.4.

Subcommittees. The Committee may form and delegate authority to subcommittees consisting of one or more members to grant pre-approvals of permitted non-audit services, provided that decisions of said subcommittee to grant preapprovals shall be presented to the full Committee at its next scheduled meeting.

Annual Information Form INTEROIL CORPORATION 50

Meetings.

3.1.

Frequency of Meetings. The Committee shall meet at least quarterly, or more frequently as circumstances dictate. The schedule for regular meetings of the Committee shall be established by the Committee. The Chairperson of the Committee may call a special meeting at any time he or she deems advisable. Meetings may be by written consent. At least annually, the Committee will meet in executive session outside the presence of any senior executive officer of the Company. The Committee may request any officer or employee of the Company or the Company’s outside counsel or external auditor to attend a meeting of the Committee or to meet with any members of, or consultants to, the Committee.

3.2.

Minutes. Minutes of each meeting of the Committee shall be kept to document the discharge by the Committee of its responsibilities.

3.3.

Quorum. A quorum shall consist of at least one-half of the Committee’s members, but no fewer than two persons. The act of a majority of the Committee members present at a meeting at which a quorum is present shall be the act of the Committee.

3.4.

Agenda. The Chairperson of the Committee shall prepare an agenda for each meeting of the Committee, in consultation with Committee members and any appropriate member of the Company’s management or staff, as necessary. As requested by the Chairperson, members of the Company’s management and staff shall assist the Chairperson with the preparation of any background materials necessary for any Committee meeting.

3.5.

Presiding Officer. The Chairperson of the Committee shall preside at all Committee meetings. If the Chairperson is absent at a meeting, a majority of the Committee members present at a meeting shall appoint a different presiding officer for that meeting.

3.6.

Private Meetings. The Committee shall meet periodically in separate executive sessions with management (including the chief executive officer, chief financial officer and chief accounting officer), the internal auditors and the external auditor, and have such other direct and independent interaction with such persons from time to time as the members of the Committee deem appropriate.

General Review Procedures.

4.1.

Annual Report Review. The Committee shall review and discuss with management, the external auditors, and the internal auditors, the Company’s year-end financial results prior to the release of earnings, or profit or loss, as applicable, and the Company’s year-end financial statements prior to filing or distribution. Such review shall also include the Company’s disclosures that are to be included in the Company’s Annual Information Form, Annual Report, Management’s Discussion and Analysis for the year and Annual Report on Form 40-F. The Committee shall also discuss with management, the external auditors and the internal auditors any significant issues, judgments or findings or any changes to the Company’s selection or application of accounting principles and any items required to be communicated by the external auditors in accordance with Statement on Auditing Standard No. 114, as amended, generally accepted accounting principles or International Financial Reporting Standards (“IFRS”), as applicable, and various topics and events that may have a significant impact on the Company or that are the subject of discussions between management and the external auditors. The Committee shall approve the audited financial statements, Management’s Discussion and Analysis, and the Annual Information Form (as to financial information included therein) and recommend to the Board whether or not the audited financial statements, Management’s Discussion and Analysis, and the Annual Information Form (as to financial information included therein) should be approved by the Board, filed on SEDAR and included in the Company’s Annual Report on Form 40-F filed on EDGAR for the last fiscal year.

4.2.

Quarterly Report Review. The Committee shall review and discuss with management, the internal auditors and the external auditors, the Company’s interim financial results prior to the release of earnings, or profit or loss, as applicable, and the Company’s interim financial statements and Management’s Discussion and Analysis, including the results of the external auditor’s review of the interim financial statements, prior to filing or distribution and the disclosures that are to be included in the Company’s Management’s Discussion and Analysis for each quarter and Form 6-K. The Committee shall discuss with management, the internal auditors and the external auditors, any significant issues, judgments or findings or any changes to the Company’s selection and application of accounting principles and any items required to be communicated by the external auditors in accordance with Statement on Auditing Standards No. 114 and No. 100, as amended, generally accepted accounting principles or IFRS, as applicable.

Annual Information Form INTEROIL CORPORATION 51

4.3.

Canadian and SEC Filings Review. The Committee shall review with financial management and the external auditor filings with Canadian securities regulators and the SEC which contain or incorporate by reference the Company’s financial statements or Management’s Discussion and Analysis and consider whether the information in these documents is consistent with information contained in the financial statements.

4.4.

Reporting System Review. In consultation with management, the external auditors, and the internal auditors, the Committee shall consider the integrity of the Company’s financial reporting processes and controls including computerized information system controls and security. The Committee shall review and discuss with management the Company’s significant financial risk exposures and the steps management has taken to monitor, control, and report such exposures. The Committee shall review significant findings prepared by the external auditors and the internal auditors together with management’s responses, including the status of previous recommendations.

4.5.

Financial Data Review. The Committee shall review and discuss with management earnings including the use of “proforma,” “adjusted” or other non-GAAP or non-IFRS information, as applicable, financial guidance and other press releases of a material financial nature, as well as financial information, and earnings or profit or loss guidance provided to analysts and rating agencies. Such discussion may be done generally consisting of discussing the types of information to be disclosed and the types of presentations to be made.

4.6.

Off-Balance Sheet Review. The Committee shall discuss with management and the external auditor the effect of regulatory and accounting initiatives as well as off-balance sheet structures on the Company’s financial statements.

4.7.

Risk Assessment. Although it is the job of the CEO and senior management to assess and manage the Company’s exposure to risks, the Committee shall discuss guidelines and policies to govern the process by which risk assessment and risk management is addressed.

4.8.

Audit Difficulties. The Committee shall review with the external auditor any audit problems or difficulties encountered in the course of the audit work and management’s response, any restrictions on the scope of activities or access to requested information; and any significant disagreements between auditors and management. The Committee shall work to resolve disagreements that may have occurred between auditors and management related to the Company’s financial statements or disclosures.

4.9.

Hiring Approval. The Committee shall approve the hiring of any partner, former partner, employee or former employee of the external auditor.

4.10.

Financial Officer Code of Ethics Review. The Committee shall review and periodically recommend modifications to the Company’s Code of Ethics for the Chief Executive Officer and Senior Financial Officers.

4.11.

Certification Review. The Committee shall review disclosures made to the Committee by the Company’s CEO and CFO during the certification process for the audited annual financial statements, interim financial statements, related Management’s Discussion and Analysis and Annual Information Form/Form 40-F concerning significant deficiencies or material weaknesses in internal controls and any fraud.

4.12.

Legal Counsel Review. On at least an annual basis, the Committee shall review with the Company’s general counsel any legal matters that could have a significant impact on the Company’s financial statements or the Company’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.

External auditors.

Auditor Performance Review. The Committee shall confirm with the external auditors their ultimate accountability to the Committee. The external auditors will report directly to the Committee. The Committee will ensure that the external auditors are aware that the Chairperson of the Committee is to be contacted directly by the external auditor (i) to review items of a sensitive nature that can impact the accuracy of financial reporting or (ii) to discuss significant issues relative to the overall Board responsibility that have been communicated to management but, in their judgment, may warrant follow-up by the Committee. The Committee shall review and evaluate the performance of the auditors and the lead partner on the external auditor team.

Annual Information Form INTEROIL CORPORATION 52

Approval of External auditor and Pre-Approval of Services. The Committee shall recommend to the Board the appointment, compensation, retention and termination of the Company’s external auditor. The Committee shall be directly responsible for the oversight of the work of the external auditors engaged (including resolution of disagreements between management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Company. The Committee shall pre-approve all auditing services, including the compensation and terms of the audit engagement, and all other non-audit services (including the fees and terms thereof) to be performed by the external auditors, subject to the de-minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934 or applicable Canadian federal and provincial legislation and regulations which are approved by the Committee prior to the completion of the audit. The Committee shall periodically discuss current year non-audit services performed by the external auditors, including the nature and scope of any tax services to be approved, a well as the potential effects of the provisions of such services on the auditor’s independence, and review and pre-approve all permitted non-audit service engagements.

Auditor Independence. The Committee shall oversee the independence of the external auditors by, among other things, (i) on an annual basis, receiving from the external auditors a formal written statement delineating all relationships between the external auditors and the Company, consistent with rules of the Public Accounting Oversight Board, that could impair the auditors’ independence; (ii) actively engaging in a dialogue with the external auditors with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditors; and (iii) taking, or recommending to the Board the appropriate action to be taken, in response to the external auditors’ report to satisfy itself of the external auditors’ independence.

Auditor Report. The Committee shall annually obtain from the external auditor and review a written report describing (i) the external auditor’s internal quality-control procedures; and (ii) any material issues raised by (a) the external auditor’s most recent internal quality-control review, or peer review or (b) any inquiry or investigation by governmental or accounting profession authorities, in each case, within the preceding five years, respecting one or more independent audits carried out by the external auditor, and any steps taken to deal with any such issues.

Audit Partner Rotation. The Committee shall ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law. The Committee shall obtain, annually, from the external auditor a written statement confirming that neither the lead (or coordinating) audit partner having primary responsibility for the Company’s audit nor the audit partner responsible for reviewing the Company‘s audit has performed audit services in those roles for the Company prior to the Company’s five previous fiscal years.

Internal Controls Report. The Committee shall annually obtain from the external auditor a written report in which the external auditor attests to and reports on the assessment of the Company’s internal controls made by the Company’s management and its control environment as it pertains to the Company’s financial reporting process and controls. Each quarter, the Committee shall review and discuss with management, the internal auditor, and the Company’s external auditor (i) the operation, adequacy and effectiveness of the Company’s internal controls (including any significant deficiencies, any special steps adopted in light of material control deficiencies, any significant changes in internal controls and the adequacy of disclosures about changes in internal control over financial reporting); (ii) the Company’s internal controls report and the auditor’s attestation of the report; (iii) the Company’s internal audit procedures; and (iv) the adequacy and effectiveness of the Company’s disclosures controls and procedures, and management reports thereon.

National Office Consultation. The Committee shall discuss with the external auditor material issues on which the national office of the external auditor was consulted by the Company’s audit team and matters of audit quality and consistency.

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Audit Planning. The Committee shall review and discuss with the external auditors their audit plan and engagement letter and discuss with the external auditors and the internal auditor the scope of the audit, staffing, locations, reliance upon management, and internal audit and general audit approach.

Accounting Principles. The Committee shall consider the external auditors’ judgments about the quality and appropriateness of the Company’s accounting principles as applied in its financial reporting, including critical accounting policies and practices used by the Company, GAAP or IFRS alternatives, as applicable, discussed with management (including the ramifications and the auditor’s preferred treatment), and any other material written communications between the external auditor and management.

Auditor Assurance. The Committee shall obtain from the external auditor assurance that Section 10A of the Securities Exchange Act of 1934, addressing the reporting of illegal acts, has not been implicated.

Additional Auditors. The Committee shall review the use of auditors other than the external auditor where management has requested a second opinion or another auditor is proposed to be engaged for other reasons.

Internal Audit Department and Legal Compliance.

Budget and Plan. The Committee shall review the budget, planned scope of the internal audit, changes in plan, activities, organizational structure, and qualifications of the internal auditor. The internal auditor function shall be responsible to senior management, but shall have a direct reporting responsibility to the Board through the Committee. The “internal auditor” will be responsible for contacting the Chairperson of the Committee directly (i) to review items of a sensitive nature that can impact the accuracy of financial reporting or (ii) to discuss significant issues relative to the overall Board responsibility that have been communicated to management but, in the internal auditor’s judgment, may warrant follow-up by the Committee.

Approval of Internal Auditor. The Committee shall review and approve the appointment, performance, dismissal and replacement of the internal auditor or the entity retained to provide internal audit services.

Internal Audit Review. The Committee shall review a summary of findings from completed internal audits and, where appropriate, review significant reports prepared by the internal audit department together with management’s response and follow-up to these reports.

General Audit Committee Responsibilities.

Code of Ethics for the Chief Executive Officer and Senior Financial Officers. The Committee shall inquire of management, the external auditor and the internal auditor as to their knowledge of (i) any violation of the Code of Ethics for the Chief Executive Officer and Senior Financial Officers, (ii) any waiver of compliance with such code, and (iii) any investigations undertaken with regard to compliance with such code. The Committee may make recommendations to the Board regarding the waiver of any provision of the Code of Ethics for the Chief Executive Officer and Senior Financial Officers, however any waiver of such code may only be granted by the Board. All waivers granted by the Board shall be promptly publicly disclosed as required by the rules and regulations of the SEC and the NYSE.

Complaints Procedure. The Committee shall establish procedures to (i) receive, process, retain and treat complaints received by the Company regarding accounting, internal audit controls or auditing matters and (ii) the confidential and anonymous submission by employees of concerns regarding questionable accounting or audit practices.

Related Party Transactions. The Committee shall approve all related party transactions after a review of the transactions by the Committee for potential conflicts of interest. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed in the Company’s Management’s Discussion and Analysis or any other filings with Canadian Securities Administrators or the SEC. The Committee shall review reports and disclosures of related party transactions.

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General Activities. The Committee shall perform any other activities consistent with this Charter, the Company’s bylaws, the Company’s Code of Ethics and Business Conduct and governing law, as the Committee or the Board deems necessary or appropriate, including reviewing the Company’s corporate compliance activities.

Reports and Assessments.

8.1.

Board Reports. The Chairperson shall, periodically at his or her discretion, report to the Board on Committee actions and on the fulfillment of the Committee’s responsibilities under this Charter. Such reports shall include any issues that arise with respect to the quality or integrity of the Company’s financial statements, the Company’s compliance with legal or regulatory requirements, the performance and independence of the Company’s external auditors and the performance of the Company’s internal audit function.

8.2.

Charter Assessment. The Committee shall annually assess the adequacy of this Charter and advise the Board of its assessment and of its recommendation for any changes to the Charter. The Committee shall, if requested by management, assist management with the preparation of a certification to be presented annually to the NYSE affirming that the Committee reviewed and reassessed the adequacy of this Charter.

8.3.

Committee Self-Assessment. The Committee shall annually make a self-assessment of its performance.

8.4.

Audit Committee Report. The Committee shall prepare any Audit Committee Reports required by the rules of the Canadian Securities Administrators or the SEC to be included in the Company’s filings with such agencies.

The duties and responsibilities of a member of the Audit Committee are in addition to those duties set out for a member of the Board. While the Committee has the responsibilities and powers set forth by this Charter, it is the responsibility of management to prepare the financials and it is the responsibility of the external auditor to plan or conduct audits or to determine that the Company’s financial statements are complete and accurate in accordance with generally accepted accounting principles and IFRS, as applicable.

The material in this Charter is not soliciting material, is not deemed filed with the SEC and is not incorporated by reference in any filing of the Company under the Securities Exchange Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date this Charter is first included in the Company’s filings with the SEC and irrespective of any general incorporation language in such filings.

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