EX-99.1 2 v435529_ex1.htm EXHIBIT 1

Exhibit 1

InterOil Corporation

Annual Information Form

For the Year Ended December 31, 2015

March 30, 2016

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	8
GENERAL DEVELOPMENT OF THE BUSINESS	9
EXPLORATION AND PRODUCTION BUSINESS – THREE YEAR HISTORY	9
BUSINESS STRATEGY	14
DESCRIPTION OF OUR BUSINESS	14
THE ENVIRONMENT AND COMMUNITY RELATIONS	22
RISK FACTORS	23
DIVIDENDS	28
DESCRIPTION OF CAPITAL STRUCTURE	28
MARKET FOR OUR SECURITIES	30
DIRECTORS AND EXECUTIVE OFFICERS	31
AUDIT AND RISK COMMITTEE	36
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	37
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	37
MATERIAL CONTRACTS	38
EXTRACTIVE INDUSTRIES TRANSPARENCY INITIATIVE	39
TRANSFER AGENT AND REGISTRAR	40
INTERESTS OF EXPERTS	40
ADDITIONAL INFORMATION	41
Schedule A – GLJ 2015 Report and RISC 2015 Report	42
Schedule B – Report of Management and Directors on Oil and Gas Disclosure	47
Schedule C – Report on Resources Data by Independent Qualified Reserves Evaluator - Part 1 - GLJ 2015 Report	48
Schedule C – Report on Resources Data by Independent Qualified Reserves Evaluator - Part 2 - RISC 2015 Report	50
Schedule D – Audit and Risk Committee Charter	52

Annual Information Form INTEROIL CORPORATION 1

PRELIMINARY NOTES

GENERAL

This AIF (as defined herein) has been prepared by InterOil Corporation for the year ended December 31, 2015. It should be read in conjunction with our Consolidated Financial Statements (as defined herein) and our 2015 MD&A (as defined herein), 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, 2015 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 (as defined herein); characteristics of our properties; construction and development of a proposed liquefaction plant and central processing facility in Papua New Guinea; the timing and cost of such construction and development; commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; and timing, maturity and amount of future capital and other expenditures.

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

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

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

our limited sources of revenue;

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

inherent uncertainty of oil and gas exploration;

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

the difficulties with recruitment and retention of qualified personnel;

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

landowner claims and disruption;

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

the exploration and production businesses are competitive;

Annual Information Form INTEROIL CORPORATION 2

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

exposure to certain uninsured risks stemming from our operations;

contractual defaults;

weather conditions and unforeseen operating hazards;

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

general economic conditions, including further economic downturn, availability of credit and the decline in commodity prices, including hydrocarbon commodity prices;

risk of legal action against us;

law enforcement difficulties; and

dilution of our common shares.

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

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

Annual Information Form INTEROIL CORPORATION 3

Note:

(1)

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

(2)

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
	2015		2014		2013
		CDN$		CDN$		CDN$
Highest rate during the period		1.3990		1.1643		1.0697
Lowest rate during the period		1.1728		1.0614		0.9839
Average noon spot rate for the period		1.2787		1.1045		1.0299
Rate at the end of the period		1.3840		1.1601		1.0636

On March 29, 2016 (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$1.3154.

The following table sets forth, for the periods indicated, the high, low, average and period-end closing spot rates of exchange for one PGK (as herein defined), expressed in U.S. dollars, as listed on OZForex.

	Year Ended 31 December
	2015		2014		2013
		U.S.$		U.S.$		U.S.$
Highest closing spot rate during the period		0.3888		0.4132		0.4971
Lowest closing spot rate during the period		0.3325		0.3456		0.3750
Average closing noon spot rate for the period		0.3617		0.3889		0.4415
Closing spot rate at the end of the period		0.3325		0.3813		0.4008

On March 29, 2016 (being the latest practicable date prior to the publication of this form), the closing spot rate of exchange for one PGK, expressed in U.S. dollars, as published on OZForex was U.S.$0.3165.

Annual Information Form INTEROIL CORPORATION 4

GLOSSARY OF TERMS

“2015 MD&A” means InterOil’s Management’s Discussion and Analysis for the year ended December 31, 2015.

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

“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.

“Consolidated Financial Statements” means InterOil’s audited consolidated financial statements for the years ended December 31, 2015, 2014 and 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 matured on November 15, 2015 and were fully paid on the same day.

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

“Credit Suisse” means Credit Suisse A.G.

"crude oil" means a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulfur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

"DPE" means the Department of Petroleum and Energy, a 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

“FID” means final investment decision.

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

"GLJ 2015 Report" means the report dated March 23, 2016 with an effective date of December 31, 2015 setting forth certain information regarding Contingent Resources of our interests in the Elk, Antelope, and Triceratops fields in PNG.

Annual Information Form INTEROIL CORPORATION 5

“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, Oil Search and the State.

“Macquarie” means Macquarie Group Limited.

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

"natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases.

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

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

“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.

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

“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.

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

"PRE" means Pacific Exploration and Production Corp, formerly 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.

“PRL 15 Joint Venture” means the current license holders in respect of PRL 15 and parties to the Elk / Antelope JVOA, dated September 26, 2012 (as amended and restated).

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

Annual Information Form INTEROIL CORPORATION 6

"RISC 2015 Report" means the report dated March 23, 2016 with an effective date of December 31, 2015 setting forth certain information regarding Contingent Resources of our interests in the Bobcat and Raptor fields in PNG.

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

“SocGen” means Société Generale Hong Kong branch.

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

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

“Total SPA” means the sales and purchase agreement dated December 6, 2013 with Total where we agreed to sell a gross 61.2903% interest in PRL 15, which contains the Elk and Antelope gas fields. This agreement was subsequently replaced on March 26, 2014 with the Total SSA.

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

“UBS” means UBS A.G.

“USD” means United States dollars.

“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 7

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

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 8

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, 2015, we had 220 full-time employees.

We are an upstream exploration and production business. Further details of the business can be found in the ‘Description of Our Business’ section of this AIF.

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, exploration and appraisal drilling. The Elk, Antelope, Triceratops, Bobcat and Raptor fields all now have independently certified Contingent Resources. During 2015, we completed the Antelope-4 and Antelope-5 appraisal wells. Drilling of the Antelope-6 appraisal well commenced in December 2015. Based on the results of the appraisal program and in line with our agreement under the Total SSA, Total is obligated to make variable payments for certified resources in PRL 15 that are in excess of 3.5 tcfe. During 2015, the PRL 15 Joint Venture also unanimously endorsed locations for key infrastructure sites for development of the Papua LNG Project, and appointed Total as operator of the PRL 15 Joint Venture.

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), respectively. 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

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

Seismic

In late 2012 and 2013, we acquired seismic over PPL 474 which focused on the Wahoo-Mako, Whale, Shark and Tuna leads. Additional seismic was also acquired in 2013 near the Triceratops field in PPL 475, PPL 476 and PPL 477. In addition, we also began acquiring seismic in Triceratops east, south-west Antelope and across two new prospects, Bobcat in PPL 476 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 program. We also commenced a geophysical survey (Magnetotellurics) over the Antelope field in PRL 15, Antelope South prospect in PRL 15 with survey extensions into PPL 476, and Mule Deer lead in PPL 475.

The Murua Seismic Survey in PPL 474 commenced in November 2014 and was completed in March 2015. The appraisal seismic program over the Raptor discovery commenced in January 2015 and was completed in May 2015. The appraisal seismic program over the Bobcat discovery commenced in March 2015 and was completed in June 2015. The seismic survey over Triceratops in PRL 39 was commenced in April 2015 and completed in July 2015.

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

Annual Information Form INTEROIL CORPORATION 9

PPL 474 - Wahoo

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

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

PPL 475 – Raptor

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

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

During the year ended December 31, 2015, we engaged RISC to provide an independent assessment of the Contingent Resources within the discovered field. The outcome of RISC’s assessment is summarized within Schedule A to this AIF.

PPL 476 – Bobcat

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

In December 2014, we announced that the well was tested over an interval of about 320 meters of Kapau limestone, the upper section of the target reservoir, and flowed and flared hydrocarbons at surface, and we notified the DPE of a discovery at the Bobcat-1 exploration well.

Seismic mapping, wireline logging and testing results indicate the well is close to the gas-water contact in the transition zone. The well was further deepened in 2014 to 3,501 meters as the first part of the appraisal program to appraise reservoir quality.

PRL 39 – Triceratops-3

The Triceratops-2 appraisal well was drilled and completed during 2012. The well was approved as the Triceratops discovery in PRL 39 by DPE in December 2013.

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

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

An update to the GLJ independent assessment of the Contingent Resources in the discovered field is summarized within Schedule A to this AIF.

PRL 15 Appraisal Drilling

The Antelope-3 appraisal well in PRL 15 was completed during 2013. Formation evaluation indicated that the reservoir quality at Antelope-3 was similar to the Antelope-1 and Antelope-2 wells.

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

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

Annual Information Form INTEROIL CORPORATION 10

On December 23, 2014, we spudded the Antelope-5 appraisal well. On February 16, 2015, we announced the Antelope-5 appraisal well had intersected the top reservoir at 1,534 meters. The well reached a total depth of 2,307 meters on February 24, 2015.

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

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

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

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

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

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

An update to the GLJ independent assessment of the Contingent Resources in the Elk and Antelope fields are summarized within Schedule A to this AIF.

PRL15 License Extension Application

On May 27, 2015, SPI (208) Limited as operator of the PRL15 Joint Venture, lodged an extension application with the DPE, in respect of PRL 15 which was due to expire on 29 November 2015 (the “Extension Application”). As part of the Extension Application, the PRL 15 Joint Venture proposed new work programs and commitments for the extension term.

Annual Information Form INTEROIL CORPORATION 11

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

Development

Total agreement

As part of the Total SSA, 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 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 completion of the appraisal program. 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).

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 25, 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%).

Additional 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 consideration of $900.0 million plus further contingent payments based on resource certification. On March 27, 2014, we received notification from Oil Search 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”). In February 2015, 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.

Subsequently in June 2015, the ICA made various costs awards in respect of the arbitration. As a consequence of these orders, we received a net payment of $1.377 million from the claimants.

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

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

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

PRE farm-in

On March 13, 2013, we completed the farm-in transaction with PRE related to the acquisition of a 10.0% net (12.9% gross) participating interest in PPL 237 (now PPL 475), including the Triceratops field and exploration acreage located within that license. PRE paid $116.0 million as initial contribution 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 IPI 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.

Annual Information Form INTEROIL CORPORATION 12

On January 17, 2014, we agreed to vary the terms of the farm-in agreement dated July 27, 2012 between us and PRE (the “Farm-In Agreement”). The Farm-in Agreement was varied to cap PRE’s carry in respect of the Raptor 1 well in PPL475 to $25.0 million, with costs in excess of this to be borne by the parties according to their equity participation interests.

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

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

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

Financing

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, 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. The facility was supported by the participating lenders CBA, ANZ, UBS, Macquarie, BSP, Westpac, MUFG and SocGen. The facility had an annual interest rate of LIBOR plus 5% and matures at the end of 2016.

During the fourth quarter of 2015, we drew down $130.0 million under this facility. As at December 31, 2015, we were in compliance with the debt covenants, which include a defined calculation for gearing not to exceed 60% at any time, a requirement that the equity does not fall below $500.0 million at any time and agreed expenditure limits tested for the six months period ending March 31 and September 30 each year. As at the date of the AIF, we have drawn down $190.0 million under this facility. We are in discussion with our lenders to increase and extend the secured financing facility.

Unsecured 2.75% convertible notes:

On November 10, 2010, we completed the issuance of the Convertible Notes. The Convertible Notes ranked 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 paid interest on the Convertible Notes semi-annually on May 15 and November 15.

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

The Convertible Notes were fully repaid on their maturity date being November 15, 2015.

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 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.

Annual Information Form INTEROIL CORPORATION 13

BUSINESS STRATEGY

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

Continue to develop as a prudent and responsible business operator

Build on more than 20 years of experience in Papua New Guinea;

Maintain a sound health and safety record;

Ensure we minimise any harm to the environment; and

Continue developing sound relationships with the State, partners and stakeholders.

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 developments and exploration acreage 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; and

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

Position for long-term success

Maintain a streamlined corporate structure and focus staff resources on operations in Papua New Guinea to support exploration, development and operations;

Retain a highly qualified technical 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.

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.

As at December 31, 2015, we had gross interests in four PPLs and two PRLs, all of which are located in the Eastern Papuan Basin, northwest of Port Moresby. On February 27, 2015, Total was appointed as operator of the PRL 15 Joint Venture effective August 1, 2015. With the exception of PRL 15, we are the operator of all of the other PPLs and PRLs in which we have an interest.

PRLs may be applied for in respect of discoveries. Upon grant of a PRL, the blocks containing the discovery are excised from the exploration license. PRL’s are designed to allow time to investigate the commerciality of the discovery.

Annual Information Form INTEROIL CORPORATION 14

This table summarizes our license interests as at December 31, 2015:

License Numbers	Discovery		Location		Operator	InterOil Registered License Interest			InterOil Net Beneficial Interest Owned¹			Blocks Covered		Acreage Gross		Acreage Net⁶
PPL 474		None		Onshore	InterOil		100.00	%		94.2500	% ⁴		59		1,232,462		1,161,595
PPL 475		Raptor		Onshore	InterOil		87.0968	% ³		79.1114	%		25		524,315		414,793
PPL 476		Bobcat		Onshore	InterOil		100.00	%		78.6114	% ⁵		58		1,215,243		955,320
PPL 477		None		Onshore	InterOil		100.00	%		78.6114	% ⁵		30		629,254		494,665
PRL 15		Elk/Antelope		Onshore	Total E&P PNG Limited		37.0375	%		36.5375	%		9		188,675		68,937
PRL 39		Triceratops		Onshore	InterOil		87.0968	%		69.0931	%		9		188,877		130,501
										Total			190		3,978,826		3,225,881

Notes

See ‘Working interests in licenses’ below for details of the Company’s net interest. The State has a 22.5% back-in right (on grant of a PDL) which, if exercised, would reduce our net interest.

During the course of 2015, Total was appointed operator of the PRL15 Joint Venture. The formal transfer of operatorship occurred on August 1, 2015. During the balance of 2015 and in early 2016, we provided services to assist in the transition of the operatorship.

As noted elsewhere in this AIF, subject to the registration of PRE’s withdrawal from PPL 475, InterOil’s registered license interest in PPL 475 will increase to 100%.

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 the option to participate at their 5.75% interest election).

In February 2005, IPI holders agreed to pay InterOil $125.0 million and we agreed to drill eight exploration wells in PPLs 474, 475, and 476 and 477. We have drilled seven of these wells to date, with a final well to be drilled within either PPL 476 or PPL477. 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. The “net beneficial interest” above will be adjusted, subject to which license area the eighth exploration well is drilled in.

Acreage Net is calculated based on InterOil Net Beneficial Interest Owned only and doesn’t include adjustments for interests by discoveries / fields.

Resources

We have no production or reserves or future net revenue as defined in NI 51-101 or under definitions established by the SEC and accordingly are not reporting any related future net revenue.

GLJ and RISC, independent qualified reserves evaluators, effective as of December 31, 2015, evaluated our Contingent Resources for the Elk, Antelope, Triceratops, Bobcat and Raptor fields, all of which are located onshore in PNG. The GLJ 2015 Report with a preparation date of March 23, 2016 and the RISC 2015 Report with a preparation date of March 23, 2016 were prepared in accordance with definitions and guidelines in the COGE Handbook and NI 51-101. The Contingent Resources evaluated in the GLJ 2015 Report and the RISC 2015 Report are summarized in Schedule A. The Report on Resources Data by Independent Qualified Reserves Evaluator for the GLJ 2015 Report and the RISC 2015 Report is provided as Part 1 and Part 2 of Schedule C.

The Company’s properties have Contingent Resources, which are quantities of Conventional Natural Gas and Natural Gas Liquids that cannot be classified as reserves. The portion classified as Contingent Resources has not been classified as reserves at this time, pending further delineation drilling, completion and production testing, development planning, project design and receipt of regulatory approvals. The Contingent Resources values should be considered indicative in nature only, pending further design work to confirm timing and capital estimates.

Annual Information Form INTEROIL CORPORATION 15

Criteria other than economics may require classification as Contingent Resources rather than reserves. Contingencies affecting the classification as reserves versus Contingent Resources relate to the following issues as detailed in the COGE Handbook: ownership considerations, drilling requirements, testing requirements, regulatory considerations, infrastructure and market considerations, timing of production and development, and economic requirements.

Costs incurred in relation to Exploration and Development activities

This table outlines net costs incurred by us during the year ended December 31, 2015 for property, acquisitions, exploration and development activities.

Nature of Cost	Amount ($ Millions)
Property acquisition costs		-
Exploration costs	$	240.04
Development costs	$	136.71
Total	$	376.75

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, 2015.

Wells	Development				Exploration				Total
	Gross ($ Millions)		Net ($ Millions)		Gross ($ Millions)		Net ($ Millions)		Gross ($ Millions)		Net ($ Millions)
Gas	$	331.64	$	136.71	$	242.03	$	240.04	$	573.67	$	376.75
Oil		-		-		-		-		-		-
Service		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total	$	331.64	$	136.71	$	242.03	$	240.04	$	573.67	$	376.75

The following table discloses the number of wells completed during the year ended December 31, 2015 (being Antelope 4, Antelope 5, Triceratops 3, Bobcat 1, Raptor 1 and Wahoo 1), 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		1		5
Oil		-		-		-		-		-		-		-
Service		-		-		-		-		-		-		-
Dry		1		-		-		-		-		-		1
Total		1		1		1		-		2		1		6

Annual Information Form INTEROIL CORPORATION 16

Operated License Commitments, Terms and Expiry

Below are our applicable expenditure commitments for each PPL and PRL as at December 31, 2015 to satisfy the future minimum work program commitments for each PPL and PRL respectively.

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	February 28, 2014 to February 27, 2020	6 years		-			-		$	45.30		$	45.00			-		$	90.30
PPL 475	February 28, 2014 to February 27, 2020	6 years		-			-		$	50.00		$	50.00			-		$	100.00
PPL 476	February 28, 2014 to February 27, 2020	6 years		-			-		$	50.00		$	50.00			-		$	100.00
PPL 477	February 28, 2014 to February 27, 2020	6 years	$	7.50			-		$	3.75		$	50.30			-		$	61.55
PRL 15	November 30, 2010 to November 29, 2015 ¹	5 years		-	²		-	²		-	²		-	²		-	²		-	²
PRL39	December 20, 2013 to December 19, 2018	5 years	$	1.36		$	27.44		$	0.25			-			-		$	29.05
	Totals		$	8.86		$	27.44		$	149.3		$	195.3			-		$	380.9

Notes:

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

The Extension Application proposed a new work program and commitments totaling approximately $187.7million, over the 5 year term. The ultimate level of commitment will be determined as part of the application process.

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, 2015. 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 or penalties may be applied in respect of field development costs, which a party fails to contribute to.

Annual Information Form INTEROIL CORPORATION 17

Petroleum Prospecting License 474

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		94.2500	%		73.0438	%
PNGDV(2)(4)		5.7500	%		4.4562	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 475 – Raptor Discovery

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		79.1114	%		61.3113	%
IPI Holders(1)(4)		15.1386	%		11.7324	%
PNGDV(2)(4)		5.7500	%		4.4562	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 475 – Excluding Raptor Discovery

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		94.2500	%		73.0438	%
PNGDV(2)(4)		5.7500	%		4.4562	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form INTEROIL CORPORATION 18

Petroleum Retention License 39 – Triceratops Discovery

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		69.0931	%		53.5471	%
PRE		12.9032	%		10.0000	%
IPI Holders(1)(4)		12.4517	%		9.6501	%
PNGDV(2)(4)		5.5520	%		4.3028	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Retention License 39 – Excluding Triceratops Discovery

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		81.3468	%		63.0438	%
PRE		12.9032	%		10.0000	%
PNGDV(2)(4)		5.7500	%		4.4562	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 476 – Bobcat Discovery

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (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 19

Petroleum Prospecting License 476 – Excluding Bobcat Discovery

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		79.1114	%		61.3113	%
IPI Holders(1)(4)		15.1386	%		11.7324	%
PNGDV(2)(4)		5.7500	%		4.4563	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 477

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (after State Participation)
InterOil		79.1114	%		61.3113	%
PNGDV(2)(4)		5.7500	%		4.4562	%
IPI Holders (1)(4)		15.1386	%		11.7324	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Retention License 15 (Elk and Antelope Discoveries)

Participant	Working Interests as at December 31, 2015 (before State Participation)			Working Interests as at December 31, 2015 (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, IPI holders agreed to pay InterOil $125.0 million and we agreed to drill eight exploration wells in PPLs 474, 475, and 476 and 477. We have drilled seven of these wells to date, with a final well to be drilled within either PPL 476 or PPL477. 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. The “working interest” above will be adjusted, subject to which license area the eighth exploration well is drilled in.

Annual Information Form INTEROIL CORPORATION 20

⁽²⁾

In July 2003, we agreed that PNGDV could take a 6.75% interest in eight exploration wells. To date, we have drilled all of the exploration wells, concluding with Wahoo#1. PNGDV also has the right to participate in the next 16 wells (the “Second Phase”) 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). The Raptor-1 well was the first well in the Second Phase.

⁽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 the 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.

Specialized Skill and Knowledge

The Company’s operations in the oil and natural gas industry require professionals with skills and knowledge in diverse fields of expertise. In the course of its exploration and production, the Company requires the expertise of drilling engineers, exploration geophysicists and geologists, petrophysicists, petroleum engineers, petroleum geologists and well-site mud specialists. To date, the Company has not experienced any difficulties in hiring and retaining the professionals and experts it requires for its operations. For further details regarding this risk factor see “Risk Factors – Our ability to recruit and retain qualified personnel may have a material adverse effect on operating results”.

Competitive Conditions

The oil and natural gas industry is competitive in all its phases. The Company competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties. The Company’s competitors include resource companies which have greater financial resources, staff and facilities than those of the Company. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The Company believes that its competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development. For further details regarding this risk factor see “Risk Factors –The exploration and production businesses are competitive”.

Business Cycles

The oil and natural gas business is subject to price cycles, and the marketability of oil and natural gas is also affected by worldwide economic cycles. The Company’s operations are related and sensitive to the market price of oil and natural gas and these prices fluctuate widely and are affected by numerous factors such as global supply, demand, inflation, exchange rates, interest rates, forward selling by producers, central bank sales and purchases, production, global or regional political, economic or financial situations and other factors beyond the control of the Company. The Company’s business may be cyclical as the exploration and production of oil and natural gas is dependent on access to areas where production is to be conducted. The climate, such as extensive rain and adverse weather conditions in PNG may restrict access to certain areas where the Company conducts its business. For further details regarding this risk factor see “Risk Factors –Weather and unforeseen operating hazards, not all of which are insured, may adversely impact our operating activities.”

Environmental Protection

The oil and natural gas industry in PNG is subject to environmental laws and regulations. Compliance with such obligations and requirements can mean significant expenditures and/or may constrain the Company’s operations in the applicable jurisdiction. Breach of environmental obligations could lead to suspension or revocation of requisite environmental licenses and permits, civil liability for damages caused and possible fines and penalties, all of which may significantly and negatively impact the Company’s position and competitiveness. For further details regarding this risk factor see “Risk Factors – Compliance with environmental and other government regulations could be costly and could negatively impact our business.”

Employees

At December 31, 2015, we had 220 full-time employees.

Annual Information Form INTEROIL CORPORATION 21

Foreign Operations

Our business is upstream exploration and production and all of the Corporation’s properties are located in PNG. Our assets include the Elk, Antelope, Triceratops, Raptor and Bobcat fields in the Gulf Province of PNG, and exploration licenses covering about 16,000 square kilometers (about 4 million acres) of PNG. See “Risk Factors” below for risks associated with foreign operations.

THE ENVIRONMENT AND COMMUNITY RELATIONS

Environmental Protection

Our operations in Papua New Guinea are covered by environmental laws on emissions, pollution, deprivations, damages 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 monitoring and management of environmental impacts on private and customary land related to 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.

Our focus on the ongoing compliance with the relevant PNG Laws underscores our approach to continual improvement, achieved through periodic reviews and a robust risk management process.

All environmental aspects identified from the risk management process are reviewed through an existing internal tiered governance structure, with significant risks identified and appropriate risk mitigation measures implemented.

We anticipate that more stringent laws and regulations on climate change and greenhouse gases may be imposed in the future and we will incorporate same into our risk management framework.

Regulatory initiatives could adversely affect the marketability of any oil and natural gas we may produce. The impact of such future programs cannot be predicted.

Environmental and Social Policies

Our environmental policy acknowledges that sustainable development is integral to responsible resource management and development. Under this 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 review our environmental impact and the associated risks 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 Affairs department oversees the management of community assistance programs and engagement to develop and sustain relationships, manages land access and acquisition related compensation claims and payments in accordance with regulatory requirements. Our development philosophy is based on “bottom-up planning” through dealings with project impacted communities at project area locations and sites so that all planning and development takes account of local communities through awareness and their consent and engagement. In our upstream business, we have a long-term community development assistance program for villages near our discovered resource sites. In addition, staff 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.

Annual Information Form INTEROIL CORPORATION 22

Non operated joint venture(s)

In respect of PRL 15 where we are a non-operator participant in the PRL 15 Joint Venture, Total as operator adheres to its global standards in respect of its operations. These include a focus on safety, environmentally responsible operations and sustainable development by ensuring that host countries benefit from the presence of Total. Details of Total’s approach to operations can be found at www.total.com.

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

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

During the second half of 2014 and throughout 2015, oil and natural gas prices experienced a significant decline that continued into 2016. Any substantial and extended decline in the price of oil and natural gas could have an adverse effect on our borrowing capacity, levels of capital expenditures and ultimately on our financial condition.

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 billions 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.

Annual Information Form INTEROIL CORPORATION 23

As a result of weakened global economic conditions, including the European sovereign debt crisis, the downgrading of United States government debt and severe commodity price declines, 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 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.

Our sources of revenue are limited.

We currently have no production or reserves. We are focused on the development of our licenses and associated resources and the construction of the proposed LNG plant to transport our resources to market. While we, along with our partners Total and Oil Search, develop our resources and the proposed LNG plant, we will rely on current funds, our credit facilities and our ability to raise funds in the equity and debt markets, borrowings under new facilities and possible future asset sales.

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 PNG, but hold licenses to land granted by the State. 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 State 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.

We plan to drill additional wells in PNG 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.

Annual Information Form INTEROIL CORPORATION 24

We have transitioned the operatorship of PRL 15 to Total in accordance with the provisions of the JVOA. As a non-operator, our development of successful operations relies 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 is unable or unwilling to perform such activities, our financial condition and operations could be materially affected.

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

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 PNG 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 and operating results.

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

Our investments in PNG 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 PNG. 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 PNG 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 dispute with our PNG 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 PNG 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 PNG that have created uncertainty for landowners and other leaseholders such as us. In 2011, the government of PNG 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 conduct our business.

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

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

Annual Information Form INTEROIL CORPORATION 25

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 PNG 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 PNG (such as a limit on foreign ownership of local assets) that may have a material adverse effect on our operations and financial condition.

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 PNG 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 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.

Annual Information Form INTEROIL CORPORATION 26

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.

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, especially in light of the depressed oil and natural gas prices. 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 PNG 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 PNG 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 we 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.

Annual Information Form INTEROIL CORPORATION 27

We may be party to lawsuits and other proceedings that may result in adverse publicity or 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.

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, 2015, 49,572,811 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, 2015.

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.

Annual Information Form INTEROIL CORPORATION 28

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.

Shareholder Rights Plan

On May 29, 2013, we adopted a new shareholder rights plan (“Rights Plan”), and terminated the original 2007 rights plan. The Rights 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 Rights 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 Rights 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 Rights 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 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 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 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, 2015, there were options outstanding to buy 210,000 common shares under our stock incentive plans.

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, 2015, restricted stock units entitling employees to rights to 384,954 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.

Annual Information Form INTEROIL CORPORATION 29

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 monthly trading volumes of our common shares as traded on the New York Stock Exchange during 2015:

New York Stock Exchange (NYSE:IOC) in United States Dollars
Month	High		Low		Volume		Close
January		50.19		33.23		11,574,077		37.61
February		49.87		37.91		6,006,620		45.8
March		47.48		39.65		7,155,692		46.14
April		52.23		44.65		5,015,863		51.7
May		52.97		45.69		4,604,263		46.84
June		61.15		45.63		9,425,183		60.2
July		60.01		40.58		14,850,721		42.78
August		45.01		30.88		12,580,383		35.86
September		37.4		32.02		7,910,689		33.71
October		40.7		33.59		6,696,218		38.26
November		42.2		34.58		6,053,027		38.96
December		39.82		28.5		7,872,580		31.42

Annual Information Form INTEROIL CORPORATION 30

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides information about our directors and executive officers as at 31 December 2015:

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

Sir Wilson Kamit CBE National Capital District, Papua New Guinea	Director⁽⁶⁾	June 24, 2013

Dr. Ellis Armstrong Texas, USA	Director⁽⁷⁾	January 1, 2015

Katherine Hirschfeld Queensland, Australia	Director⁽⁸⁾	January 1, 2015

Yap Chee Keong Singapore	Director⁽⁹⁾	March 13, 2015

Isikeli Taureka National Capital District, Papua New Guinea	Executive Director, Papua New Guinea, and Board Member⁽¹⁰⁾	June 24, 2013

Jon Ozturgut Singapore	Chief Commercial Officer⁽¹¹⁾	January 21, 2014

Donald Spector Singapore	Chief Financial Officer	January 22, 2014

Thomas Nador National Capital District, Papua New Guinea	Executive Vice President, Papua New Guinea Business Operations	December 17, 2013

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

Saxon Palmer Singapore	Senior Vice President, Exploration	May 13, 2015

Sheree Ford Singapore	General Counsel and Corporate Secretary	August 1, 2015

Notes:

(1)

Dr. Michael Hession was Chief Executive Officer and a director throughout 2015. He is also a member of the Reserves Committee and was throughout 2015. He remains so at the date of this AIF.

Annual Information Form INTEROIL CORPORATION 31

(2)

Mr. Christopher Finlayson is at the date of this AIF and was throughout 2015 the Chairman of the Company. Mr. Finlayson is at the date of this AIF a member and Chairman of the Compensation Committee, and a member of the Nominating and Governance Committee and of the Reserves Committee.

(3)

Mr. Roger Lewis is at the date of this AIF a member of the Nominating and Governance Committee and of the Compensation Committee. He ceased to be the Chairman of the Audit and Risk Committee effective on September 30, 2015, but remains a member of the Audit and Risk Committee.

(4)

Mr. Ford Nicholson is at the date of this AIF and was throughout 2015 Deputy Chairman of the Company. Mr Nicholson is at the date of this AIF and was throughout 2015, a member and Chairman of both the Reserves Committee and the Nominating and Governance Committee.

(5)

Sir Rabbie Namaliu is at the date of this AIF and was throughout 2015 a member of the Nominating and Governance Committee.

(6)

Sir Wilson Kamit is at the date of this AIF and was throughout 2015 a member of the Audit and Risk Committee.

(7)

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 Audit and Risk Committee and Reserves Committee on March 12, 2015.

(8)

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 Compensation Committee and Nominating and Governance Committee on March 12, 2015. She was appointed a member of the Audit and Risk Committee on May 8, 2015.

(9)

Mr. Yap Chee Keong was appointed as a director on March 13, 2015 and remains a director at the date of this AIF. Mr. Yap Chee Keong was appointed a member of the Audit and Risk Committee on May 8, 2015. He was subsequently appointed Chairman of the Audit and Risk Committee on October 1, 2015.

(10)

Mr. Isikeli Taureka was appointed as a director on June 9, 2015. Most recently Mr Taureka has held the role of Executive Director, Papua New Guinea since September 1, 2015. Prior to that Mr Taureka was the Executive Vice President, Papua New Guinea of the Company.

(11)

Mr. Jon (Cain) Ozturgut was appointed Chief Commercial Officer on September 1, 2015. Prior to that Mr Ozturgut was the Chief Operating Officer of the Company.

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.

As of March 29, 2016, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly 303,234 common shares, representing 0.61% 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, 544,582 shares are issuable on exercise of outstanding options and restricted stock units (where milestones are met), resulting in directors and executive officers holding 1.08% of our issued common shares on a diluted basis.

Our Board has established an Audit and Risk Committee, a Compensation Committee, a Nominating and Governance Committee and a Reserves Committee. Mr. Yap, Mr. Lewis, Sir Wilson Kamit, Dr. Armstrong and Ms. Hirschfeld are members of the Audit and Risk 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. Yap chairs the Audit and Risk 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 both Australia and Ireland; he 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. 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 32

Chris Finlayson is a citizen of the United Kingdom, and is Chairman of our Board. 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 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 2012, 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.

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 a 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 33

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 an Australian engineering group, Broadspectrum Limited, 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 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 and 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, Olam International Limited and Media Corp Pte Ltd and a non-executive director of The Straits Trading Company Limited, Certis CISCO Security Pte Ltd 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 was appointed as our Executive Director, Papua New Guinea on September 1, 2015, after previously serving as our Executive Vice President, PNG. He 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. He was subsequently appointed Chief Commercial Officer on September 1, 2015. Mr Ozturgut has 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, 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 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.

Thomas Nador was appointed General Manager of Planning and Strategy in December 2013 and Senior Vice President, Corporate in 2014. He was subsequently appointed Executive Vice President, Papua New Guinea Business Operations on September 1, 2015. He has more than 20 years’ experience with resource companies and top-tier contractors in operational and management roles across oil and gas, pipelines, mining, and construction. His roles have included field development, project execution and management, integration management, and project strategy development across five LNG developments in Australiasia. He leads InterOil’s daily operations in Papua New Guinea, including health, safety and environment, human resources, administration, supply chain, information management, and community and government affairs.

Annual Information Form INTEROIL CORPORATION 34

Mr Nador has a science degree from the University of Western Australia, a post-graduate diploma in science from Curtin University, and a diploma of business.

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, 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.

Saxon Palmer was appointed Senior Vice President, Exploration on May 13, 2015. He oversees exploration strategy, exploration portfolio management, geoscience, and field data acquisition programs, including seismic and other technologies. Mr. Palmer has 29 years’ international oil and gas experience, including 10 years with BP and 11 years with BHP Billiton. At BP, he was involved in the exploration and appraisal of the Hides and Kutubu fields in Papua New Guinea. His roles at BHP Billiton included Global Portfolio Manager and Exploration Manager for Australasia. He has also consulted to Japanese and Korean LNG buyers and investors. Mr. Palmer has a science degree with honors in geology from the Australian National University and is a graduate of the Advanced Management Program at the Wharton School of the University of Pennsylvania.

Sheree Ford was appointed General Counsel and Corporate Secretary on August 1, 2015. Ms. Ford has been an international corporate and commercial lawyer for more than 20 years, mostly in energy and resources. She worked for 10 years with BHP Billiton’s petroleum businesses and was general counsel for more than a decade at Roc Oil, Oil Search and Pexco Energy. She is experienced in international law, having provided advice and led negotiations for projects in Papua New Guinea, Australia, Indonesia, China, Malaysia, Africa and the United Kingdom. Ms. Ford has a Masters of Business Administration, arts and law degrees, and a diploma in natural resource law from the University of Melbourne in Victoria, Australia.

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.

Annual Information Form INTEROIL CORPORATION 35

Penalties or Sanctions

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 AND RISK COMMITTEE

Charter of the Audit and Risk Committee

The full text of the Charter of the Audit and Risk Committee is attached as Schedule D to this AIF.

Composition of the Audit and Risk Committee

Current members of the Audit and Risk Committee are Mr. Yap Chee Keong (Committee Chairman), Mr. Roger Lewis, Sir Wilson Kamit, Dr. Ellis Armstrong and Ms. Katherine Hirschfeld. Mr. Yap Chee Keong was appointed as a member of the Committee on May 8, 2015 and he became the Chairman of the Committee on October 1, 2015. Mr. Lewis was the Chairman of the Committee until September 30, 2015 when he resigned as the Chairman of the Committee, but remains as a member of the Committee. Sir Wilson Kamit was appointed as a member of the Committee on June 24, 2014. Dr. Armstrong was appointed to the Committee on March 12, 2015. Ms. Hirschfeld was appointed to the Committee on 8 May, 2015. Former director Mr. Samuel Delcamp was a member of the Committee throughout 2014 and until his retirement on March 12, 2015. All Audit and Risk Committee members are and were during 2015 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 and Risk 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.

Annual Information Form INTEROIL CORPORATION 36

Pre-Approval Policies and Procedures

The Audit and Risk 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 and Risk Committee who will consult other committee members, as necessary, before providing any approval on the Audit and Risk Committee’s behalf.

External Auditor Service Fees

PricewaterhouseCoopers, Chartered Accountants, has 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
	2015		2014
Audit Fees¹	$	1,598,716	$	1,896,489
Tax Fees²	$	730,482	$	472,129
All Other Fees³	$	22,572	$	38,525
Total	$	2,351,770	$	2,407,143

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.

"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.

Annual Information Form INTEROIL CORPORATION 37

MATERIAL CONTRACTS

The following represent material contracts that were entered into or are still in effect during 2015:

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 (now PPL 475), 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 (now known as PPL475) 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 17, 2014, we agreed to vary the terms of the Farm-in Agreement to cap PRE’s carry in respect of the Raptor 1 well in PPL475 to $25.0 million, with costs in excess of this to be borne by the parties according to their equity participation interests.

In August 2015, the Company received notification from PRE of their intention to withdraw from PPL 475. In the fourth quarter of 2015, we received notification from PRE of their intention to withdraw from further participation in PRL 39. The Farm-In Agreement provides that following an effective withdrawal by PRE, we are required to refund to PRE $93.0 million in monthly instalments commencing in the month subsequent to our receipt of any net cash proceeds from commercial sale of product from PRL 15 and the $93.0 million must be repaid in full within six years of receiving the withdrawal notification. Following withdrawal of PRE we also have a receivable of $29.7 million which is refundable from Pacific LNG Operations Ltd, and other indirect participating interest holders, under the same terms as the amount refundable to PRE.

Subsequent to PRE’s withdrawal (subject to the final withdrawal notice to be finalized), the Company’s interest in the Triceratops discovery will be 78.1114%, and in PRL 39 (excluding the Triceratops discovery) will be 100% (94.25% assuming PNGDV will elect to exercise their option to participate at their 5.75% interest election). The Company’s interest in the Raptor discovery is 79.1114%, and in PPL 475 (excluding the Raptor discovery) is 100% (94.25% assuming PNGDV will elect to exercise their option to participate at their 5.75% interest election).

Total SPA

On December 5, 2013, we agreed to sell to Total a gross 61.2903% interest (net 47.5%, after State 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 completion of the appraisal program. The payments for resources greater than 5.4 tcfe were to be paid at certification.

Total were to carry the cost of these appraisal wells (up to a cap of $50.0 million per well). Under the agreement, Total was to 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.

Annual Information Form INTEROIL CORPORATION 38

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

Completion of the Total SPA remained subject to State 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 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 6, 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

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, that supported the new facility. The new facility has an annual interest rate of LIBOR plus 5% and matures at the end of 2016. During the fourth quarter of 2015, we had drawn down $130.0 million under this facility. As at the date of the AIF, we have drawn down $190.0 million under this facility.

All other contracts agreed or still in effect during 2015 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 39

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

PNG Taxes Paid
	2015 ($million)		2014 ($million)
Excise duties ⁽¹⁾		-		20.6
Company Income Tax		0.3		0.6
Personal Income Tax ⁽²⁾		9.2		11.4
Goods and Services Tax ⁽³⁾		0.1		29.1
Other Government Taxes⁽⁴⁾		16.2		5.5
Total		25.8		67.2

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, 8^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, 2015. As at the date hereof, PricewaterhouseCoopers were independent within the meaning of Public Company Accounting Oversight Board Rule 3520.

Annual Information Form INTEROIL CORPORATION 40

Information on Contingent Resources of the Company for the Elk, Antelope, and Triceratops fields 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, 2015, 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.

Information on Contingent Resources of the Company for the Bobcat and Raptor fields in the Statement of Resources Data and Other Oil and Gas Information was evaluated by RISC, as independent qualified reserves evaluators. As at December 31, 2015, the principals and employees of RISC involved in the resource assessment of the Company did not hold any registered or beneficial ownership interests, directly or indirectly in the common shares.

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 9, 2015 and will be contained in our information circular for our upcoming annual meeting of shareholders expected to be held in June 2016. Additional financial information is provided in our Consolidated Financial Statements and related 2015 MD&A. Our Consolidated Financial Statements, 2015 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 Consolidated Financial Statements, 2015 MD&A and additional copies of this AIF may also be obtained by contacting Ms. Sheree Ford, 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 41

Schedule A – GLJ 2015 Report and RISC 2015 Report

The tables below outlines GLJ's and RISC’s estimates contained in their reports effective December 31, 2015 of total and net Contingent Resources at the Elk and Antelope, Triceratops, Raptor and Bobcat fields:

Gross and Company Net Un-risked Contingent Resources for the Elk and Antelope Fields ^{2, 3, 4, 6}

	InterOil’s Net Working	Contingent	Un-risked Gross Resource						Un-risked Company Net Resource
Block	Interest	Resource	1C		2C		3C		1C		2C		3C
		Conventional Natural Gas (Tcf)		6.800		9.056		11.021		2.485		3.309		4.027
PRL 15 (Antelope)	36.5375%	Natural Gas Liquids (MMstb)		110.6		137.1		158.9		40.4		50.1		58.1
		Oil Equivalent (MMboe)⁸		1244.0		1646.4		1995.8		454.5		601.6		729.2
		Conventional Natural Gas (Tcf)		0.058		0.094		0.153		0.021		0.034		0.056
PRL 15 (Elk)	36.5375%	Natural Gas Liquids (MMstb)		0.4		0.6		1.0		0.1		0.2		0.4
		Oil Equivalent (MMboe) ⁸		10.1		16.3		26.6		3.7		6.0		9.7
Total Conventional natural Gas (Tcf)				6.8585		9.149		11.175		2.506		3.343		4.083
Total Natural Gas Liquids (MMstb)				111.0		137.7		159.9		40.6		50.3		58.4
Total Oil Equivalent (MMboe) ⁸				1254.1		1662.6		2022.4		458.2		607.5		738.9

Gross and Company Net Risked Contingent Resources for the Elk and Antelope Fields ^{1, 2, 3, 4, 6}

	InterOil’s Net Working	Contingent	Risked Gross Resource						Risked Company Net Resource						Chance of
Block	Interest	Resource	1C		2C		3C		1C		2C		3C		Development
		Conventional Natural Gas (Tcf)		5.814		7.742		9.423		2.124		2.829		3.443		86	%
PRL 15 (Antelope)	36.5375%	Natural Gas Liquids (MMstb)		94.6		117.2		135.9		34.6		42.8		49.6		86	%
		Oil Equivalent (MMboe)⁸		1063.6		1407.6		1706.4		388.6		514.3		623.5		86	%
		Conventional Natural Gas (Tcf)		0.050		0.080		0.131		0.018		0.029		0.048		81	%
PRL 15 (Elk)	36.5375%	Natural Gas Liquids (MMstb)		0.3		0.5		0.9		0.1		0.2		0.3		81	%
		Oil Equivalent (MMboe) ⁸		8.6		13.9		22.7		3.1		5.1		8.3		81	%
Total Conventional natural Gas (Tcf)				5.864		7.823		9.554		2.143		2.858		3.491
Total Natural Gas Liquids (MMstb)				94.9		117.7		136.7		34.7		43.0		50.0
Total Oil Equivalent (MMboe)⁸				1072.2		1421.5		1729.1		391.8		519.4		631.8

Gross and Company Net Un-risked Contingent Resource Estimate for the Triceratops Field ^{2,
3, 4, 6}

	InterOil’s Net Working	Contingent	Gross Resource						Unrisked Company Net Resource
Block	Interest	Resource	1C		2C		3C		1C		2C		3C
		Conventional Natural Gas (Tcf)		0.151		0.312		0.561		0.104		0.216		0.388
PRL39	69.0931%	Natural Gas Liquids (MMstb)		3.3		6.6		11.9		2.3		4.6		8.2
		Oil Equivalent (MMboe)⁸		28.5		58.7		105.5		19.7		40.6		72.9

Annual Information Form INTEROIL CORPORATION 42

Gross and Company Net Risked Contingent Resource Estimate for the Triceratops Field ^{1,
2, 3, 4, 6}

	InterOil’s Net Working	Contingent	Risked Gross Resource						Risked Company Net Resource						Chance of
Block	Interest	Resource	1C		2C		3C		1C		2C		3C		Development
		Conventional Natural Gas (Tcf)		0.092		0.191		0.343		0.064		0.132		0.237		61.2	%
PRL39	69.0931%	Natural Gas Liquids (MMstb)		2.0		4.0		7.3		1.4		2.8		5.0		61.2	%
		Oil Equivalent (MMboe)⁸		17.4		35.9		64.6		12.1		24.8		44.6		61.2	%

Gross and Company Net Un-risked Contingent Resources Estimate for the Raptor Field^{2, 3, 4, 5, 7}

	InterOil’s Net Working	Contingent	Gross Resource						Un- risked Company Net Resource
Block	Interest	Resource	1C		2C		3C		1C		2C		3C
		Conventional Natural Gas (Tcf)		0.183		2.721		11.619		0.144		2.152		9.192
PPL475	79.1114%	Natural Gas Liquids (MMstb)		6		108		553		4.9		85		438
		Oil Equivalent (MMboe)⁸		36.5		561.5		2489.5		28.9		444.1		1969.5
		Conventional Natural Gas (Tcf)		0.007		0.230		2.708		0.003		0.085		1.003
PRL15	37.0375%	Natural Gas Liquids (MMstb)		0.3		9.0		129.0		0.1		3.4		48
		Oil Equivalent (MMboe) ⁸		1.5		47.3		580.3		0.6		17.6		214.9
Total Conventional Natural Gas (Tcf)				0.190		2.951		14.327		0.147		2.237		10.195
Total Natural Gas Liquids (MMstb)				6.3		117.0		682.0		5.0		88.8		485.3
Total Oil Equivalent (MMboe)⁸				38.0		608.8		3069.8		29.5		461.7		2184.5

Gross and Company Net Risked Contingent Resources for the Raptor Field^{1, 2, 3, 4, 6, 7}

	InterOil’s Net Working	Contingent	Risked Gross Resource						Risked Company Net Resource						Chance of
Block	Interest	Resource	1C		2C		3C		1C		2C		3C		Development
		Conventional Natural Gas (Tcf)		0.082		1.224		5.229		0.065		0.968		4.136		45	%
PPL475	79.1114%	Natural Gas Liquids (MMstb)		2.7		49		249		2.2		38		197		45	%
		Oil Equivalent (MMboe)⁸		16.4		252.7		1120.3		13		199.8		886.3		45	%
		Conventional Natural Gas (Tcf)		0.003		0.104		1.219		0.001		0.038		0.451		45	%
PRL15	37.0375%	Natural Gas Liquids (MMstb)		0.1		4.1		58.1		0.05		1.5		21.5		45	%
		Oil Equivalent (MMboe) ⁸		0.66		21.3		261.15		0.25		7.92		96.72		45	%
Total Conventional Natural Gas (Tcf)				0.086		1.328		6.447		0.066		1.007		4.587
Total Natural Gas Liquids (MMstb)				2.8		52.7		306.9		2.3		40.0		218.4
Total Oil Equivalent (MMboe)⁸				17.1		274.0		1381.4		13.3		207.8		983.0

Annual Information Form INTEROIL CORPORATION 43

Gross and Company Net Un-risked Contingent Resources for the Bobcat Field ^{2, 3, 4, 7}

	InterOil’s Net Working	Contingent	Gross Resource						Un-risked Company Net Resource
Block	Interest	Resource	1C		2C		3C		1C		2C		3C
		Conventional Natural Gas (Tcf)		0.108		0.660		2.172		0.085		0.519		1.708
PPL476	78.6114%	Natural Gas Liquids (MMstb)		1.3		9		34		1		7.1		27
		Oil Equivalent (MMboe)⁸		19.3		119.0		396.0		15.2		93.5		311.4
		Conventional Natural Gas (Tcf)		0.286		1.554		4.217		0.199		1.082		2.935
PRL39	69.593092%	Natural Gas Liquids (MMstb)		3		21		67		2.4		15		46
		Oil Equivalent (MMboe) ⁸		50.7		280.0		769.8		35.6		194.9		535.1
Total Conventional Natural Gas (Tcf)				0.394		2.214		6.389		0.284		1.601		4.643
Total Natural Gas Liquids (MMstb)				4.3		30		101		3.4		22.1		73
Total Oil Equivalent (MMboe)⁸				70.0		399.0		1165.8		50.7		288.5		846.5

Gross and Company Net Risked Contingent Resources for the Bobcat Field^{1, 2, 3, 4, 7}

	InterOil’s Net Working	Contingent	Risked Gross Resource						Risked Company Net Resource						Chance of
Block	Interest	Resource	1C		2C		3C		1C		2C		3C		Development
		Conventional Natural Gas (Tcf)		0.049		0.297		0.977		0.038		0.234		0.769		45	%
PPL476	78.6114%	Natural Gas Liquids (MMstb)		0.6		4.1		15		0.5		3.2		12		45	%
		Oil Equivalent (MMboe)⁸		8.7		53.6		178.2		6.8		42.1		140.1		45	%
		Conventional Natural Gas (Tcf)		0.129		0.699		1.898		0.090		0.487		1.321		45	%
PRL39	69.593092%	Natural Gas Liquids (MMstb)		1.4		9.5		30.2		1.1		6.8		20.7		45	%
		Oil Equivalent (MMboe) ⁸		22.8		126.0		346.4		16.0		87.7		240.8		45	%
Total Conventional Natural Gas (Tcf)				0.177		0.996		2.875		0.128		0.721		2.089
Total Natural Gas Liquids (MMstb)				1.9		13.5		45.5		1.5		10.0		32.7
Total Oil Equivalent (MMboe)⁸				31.5		179.6		524.6		22.8		129.8		380.9

Notes:

In line with regulatory requirements when assessing Contingent Resources the “Chance of Development” and consequentially the “Risked Resource” volumes have been assessed and disclosed. The “Chance of Development” is the estimated probability that, once discovered, a known accumulation will be commercial development. It can be represented as a percentage, based on the multiplication of various contingencies and the perceived risk associated with each of the identified contingencies. The types of factors influencing the “Chance of Development” of each of the fields are discussed below.

The “Risked Gross Resource” and “Risked Net Resources” are determined by applying the “Chance of Development” factor to the Contingent Resource. This is achieved by multiplying the ‘unrisked resource’ by the appropriate ‘Chance of Development’, to arrive at risked number.

“1C”: 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. “2C”: 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. “3C”: 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.

“Net Resource” numbers are based on InterOil’s net working interests in the relevant field as at 31 December 2015. These numbers do not include the government’s back in right of up to 22.5% (on grant of a Petroleum Development License). If exercised, the back in right would further reduce InterOil’s net interest in the Contingent Resource.

Annual Information Form INTEROIL CORPORATION 44

“Gross Resource” numbers represent 100% of the field / accumulation.

The Raptor resource is based on InterOil’s net working interest in PPL475 and PRL15 to the extent that part of the Raptor accumulation may be located across both licence areas.

GLJ was responsible for the Contingent Resource evaluation in respect of the Elk, Antelope and Triceratops fields.

RISC was responsible for the Contingent Resource evaluation in respect of the Bobcat and Raptor fields.

Contingent Resources Project Evaluation Scenario and Economics Status and Maturity Sub-Class

The Contingent Resources above have been sub-classified by project maturity as follows:

Field / accumulation	Project Maturity Sub-class ²	Project Evaluation Scenario Status ¹	Economic Status	Recovery Technology Status
Elk³	Development Unclarified	Conceptual	Undetermined	Established
Antelope ³	Development Unclarified	Conceptual	Undetermined	Established
Triceratops	Development Unclarified	Conceptual	Undetermined	Established
Raptor	Development Unclarified	Conceptual	Undetermined	Established
Bobcat	Development Unclarified	Conceptual	Undetermined	Established

Notes:

A conceptual study or scoping study is the initial stage of the development of a project scenario, with limited detail and typically based on limited information. Whilst results may be sufficient for initial delineation of the resources and for identifying the need for additional technical data, they will be insufficient for making economic decision regarding development.

2. Although within the same ‘Project Maturity Sub-class’, the stage of development and therefore the horizon for commercialization of each of the fields is difference, hence the difference in the “Chance of Development” allocated.

The Papua LNG Project (comprising the Elk and Antelope Fields) will be considered to be at the conceptual stage until FEED is completed. As at the date of this AIF, a Basis of Design (“BOD”) study is underway. Once BOD is completion, a FEED study will be commenced.

Consistent with our treatment with the Elk and Antelope fields, the Triceratops, Bobcat and Raptor prospective resources are not included.

Chance, timing and cost of development

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 uncertainty that it will be commercially viable to produce any portion of the resources. There is no certainty that these Contingent Resources will be commercially viable and it should be noted that it is not certain that all fields / accumulations set out above will progress to reserves.

In determining the chance of development, various contingencies have been considered and quantified by assigning a probability of each occurring to the contingencies; all of the factors when combined are then used to determine the “Change of Development” illustrated by a percentage in the above tables in this Schedule A.

The following contingencies were considered as part of the assessment of the Elk, Antelope, Triceratops Bobcat and Raptor Contingent Resources:

Annual Information Form INTEROIL CORPORATION 45

Corporate commitment in the form of firm development plans, in order to allow for a positive investment decision to be taken;

Regulatory approvals necessary for the sanctioning and financing for the facilities required to process and transport marketable sales gas and condensate to market;

Economic conditions, including the potential rate of return of the relevant project and confirmation of a market for the marketable sales gas and condensate;

Development timeframe; and

Social license, including necessary agreements with landowners or affected parties.

In addition, specifically in respect of the Bobcat and Raptor Contingent Resources, confirmation of field and well productivity were considered as part of the contingencies.

The table below illustrates the estimated cost and estimated timing of development in respect of the fields as grouped. The table is an estimate and does not reflect any specific commitment or decision by either the Company or any of its joint venture partners in respect of the specified field(s).

Field / accumulation	Estimated cost to achieve commercial production – US$MM	Estimated commencement of commercial production
Elk and Antelope ¹	13,500 - 16,000	2021 - 2022
Triceratops ²	1,000 – 5,000	Subject to the ultimate development concept selected, commercial production could occur between 2021-2029+
Raptor and Bobcat³	4,000 - 10,000	Subject to the ultimate development concept selected, commercial production could occur between 2024-2029+

Notes:

The costs above are preliminary in nature and are subject to the outcome of FEED, which may lead to revisions in respect of the costs and timing of the Papua LNG Project (comprising the Elk and Antelope Fields). In addition other studies and assessments are currently being undertaken including, but not limited to, health, environmental and social mapping.

A number of development concepts are under evaluation for the Triceratops field. These include an early development for domestic power generation, project expansion or backfill for existing projects or a supporting volumes to a new greenfield project

A number of development concept exist in respect of the Raptor and Bobcat fields including, project expansions, backfill for existing projects or a foundation volume for a new greenfield project. Ultimately, the development concept can only be ascertained via further appraisal and study and market considerations at the various project decision making points. Subject to the ultimate concept selection, the cost and timing moves in respect of the ranges within the above table.

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.

Annual Information Form INTEROIL CORPORATION 46

Schedule B – 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, 2015, and (ii) resources as at December 31, 2015.

The company’s board of directors has determined that the company had no reserves as at December 31, 2015.

Independent qualified reserve evaluators have evaluated the company's resources data and the evaluators reports 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 evaluators;

(b)

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

(c)

reviewed the reserves data with management and the evaluators.

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 evaluators 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 30, 2016.

“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”		“Isikeli Taureka”
Director		Director

Annual Information Form INTEROIL CORPORATION 47

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

Part 1 - GLJ 2015 Report

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 contingent resources data as at December 31, 2015. The contingent resources data are risked estimates of volume of contingent resources as at December 31, 2015.

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

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

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

The following tables set forth the risked volume of contingent resources included in the Company's statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources data that we have evaluated and reported on to the Company's board of directors:

Classification	Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report	Location of Resources Other than Reserves (Country or Foreign Geographic Area)	Risked Volume (MMboe)

Development Unclarified Contingent Resources (2C)	GLJ Petroleum Consultants	Dec. 31, 2015	Papau New Guinea		544.2

In our opinion, the contingent resources data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the contingent resources data we reviewed but did not audit or evaluate.

We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.

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

Annual Information Form INTEROIL CORPORATION 48

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 23, 2016

“Originally Signed by”
Keith M. Braaten, P. Eng.
President & CEO

Annual Information Form INTEROIL CORPORATION 49

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

Part 2 - RISC 2015 Report

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 Bobcat and Raptor field’s resources data as at December 31, 2015. The resources data are estimates of contingent resources as at December 31, 2015.

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 contingent resources as at December 31, 2015:

Classification	Independent Qualified Reserves Evaluator and Resource	Description and Preparation Date of Assessment Report	Location of Reserves (Country or Foreign Geographic Area)	Risked Volumes MMBOE
Development Unclarified
Contingent Resource (2C)	RISC Operations Pty Limited	31 December, 2015	Papua New Guinea	338

In our opinion, the 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 50

Contingent resources estimates may not be classified as reserves until the following contingencies are satisfied: (i) field productivity is established, (ii) sanctioning of the facilities required to process and transport marketable natural gas, (iii) confirmation of a market for the marketable natural gas, and (iv) 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.

EXECUTED as to our report referred to above:

RISC Operations Pty Limited, Perth, Australia, March 23, 2016.

“Originally Signed by”

Antony Corrie-Keilig EP Eng NER IntPE (Aus) SPEC

Principal Petroleum Engineer

Annual Information Form INTEROIL CORPORATION 51

Schedule D – Audit and Risk Committee Charter

This Audit and Risk Committee Charter (the “Charter”) sets forth the purpose and membership requirements of the Audit and Risk 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:

Oversee, review and monitor management's identification of principal financial and non-financial risks and the process to identify and manage such risks.

Oversee, review 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 including financial, operational and compliance.

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 and appoint the Chairperson and determine the term of his or her appointment. 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 Administrators), 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.

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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.

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.

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4.2

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 review the guidelines and policies that govern the process by which risk assessment and risk management is addressed to ensure that business risks are being effectively identified and managed. Management shall report on risk management to the Board through the Committee.

4.3.

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.

4.4.

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.

4.5.

Reporting System and Internal Control 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 internal controls including computerized information system controls and security. The Committee shall review and discuss with management the Company’s significant financial and non-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.

4.6.

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.

4.7.

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.

4.8.

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.

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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.

5.1.

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.

5.2.

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-minimus 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, as 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.

5.3.

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.

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5.4.

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.

5.5.

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.

5.6.

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 controls; (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.

5.7.

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.

5.8.

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.

5.9.

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.

5.10.

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.

5.11.

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.

6.1.

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.

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6.2.

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.

6.3.

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.

7.1.

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.

7.2.

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.

7.3.

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.

7.4.

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.

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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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