EX-99.1 2 v373081_ex99-1.htm EXHIBIT 99.1

InterOil Corporation

Annual Information Form

For the Year Ended December 31, 2013
March 31, 2014

TABLE OF CONTENTS

TABLE OF CONTENTS	1
PRELIMINARY NOTES	2
GENERAL	2
LEGAL NOTICE – FORWARD-LOOKING STATEMENTS	2
ABBREVIATIONS AND EQUIVALENCIES	4
CONVERSION	4
EXCHANGE RATES	4
GLOSSARY OF TERMS	5
CORPORATE STRUCTURE	9
GENERAL DEVELOPMENT OF THE BUSINESS	10
BUSINESS STRATEGY	16
DESCRIPTION OF OUR BUSINESS	17
UPSTREAM – EXPLORATION AND DEVELOPMENT	17
MIDSTREAM - REFINING	25
MIDSTREAM - LIQUEFACTION	26
DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION	26
THE ENVIRONMENT AND COMMUNITY RELATIONS	28
RISK FACTORS	29
DIVIDENDS	37
DESCRIPTION OF CAPITAL STRUCTURE	37
MARKET FOR OUR SECURITIES	39
DIRECTORS AND EXECUTIVE OFFICERS	40
AUDIT COMMITTEE	45
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	46
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	46
MATERIAL CONTRACTS	46
TRANSFER AGENT AND REGISTRAR	49
INTERESTS OF EXPERTS	49
ADDITIONAL INFORMATION	49
Schedule A – Report of Management and Directors on Oil and Gas Disclosure	51
Schedule B – Report on Resources Data by Independent Qualified Reserves Evaluator	52
Schedule C – Audit Committee Charter	54

Annual Information Form INTEROIL CORPORATION 1

PRELIMINARY NOTES

GENERAL

This Annual Information Form (“AIF”) has been prepared by InterOil Corporation for the year ended December 31, 2013. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2013 and Management’s Discussion and Analysis for the year ended December 31, 2013 (“2013 MD&A”), copies of which may be obtained online from SEDAR at www.sedar.com.

In this AIF, references to “we”, “us”, “our”, “the Company”, “the Corporation” 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, 2013 unless otherwise specified.

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 our exploration (including drilling plans) and other business activities and results therefrom; characteristics of our properties; construction and development of a proposed LNG plant in Papua New Guinea; the timing and cost of such construction and development; commercialization and monetization of any resources; whether sufficient resources will be established; the likelihood of successful exploration for gas and gas condensate or other hydrocarbons; cash flows from operations; sources of capital and its sufficiency; operating costs; contingent liabilities; environmental matters; and plans and objectives for future operations; and timing, maturity and amount of future capital and other expenditures.

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

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

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

the inherent uncertainty of oil and gas exploration;

the availability of crude feedstock at economic rates;

the uncertainty associated with regulated prices at which our products may be sold;

the difficulties with the recruitment and retention of qualified personnel;

the losses from our hedging activities;

the fluctuations in currency exchange rates;

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 inability of our refinery to operate at full capacity;

the impact of competition;

Annual Information Form INTEROIL CORPORATION 2

the adverse effects from importation of competing products contrary to our legal rights;

reduced margins for our products and other adverse effects on the value of our refinery;

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;

interest rate risk;

weather conditions and unforeseen operating hazards;

general economic conditions, including the possibility of further global economic downturn, and a reduction in the availability of credit;

the impact of our current debt on our ability to obtain further financing;

risk of legal action against us; and

law enforcement difficulties.

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial conditions and performance, business prospects, strategies, regulatory developments, the ability to attract joint venture partners, future hydrocarbon commodity prices, the ability to secure adequate capital funding, the ability to obtain equipment and qualified personnel in a timely manner to develop resources, the ability to market products successfully to current and new customers, the effects from increasing competition, 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.

Annual Information Form INTEROIL CORPORATION 3

ABBREVIATIONS AND EQUIVALENCIES

Abbreviations

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

Note:

(1)

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

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.

Annual Information Form INTEROIL CORPORATION 4

	Year Ended 31 December
	2013		2012		2011
	CDN$		CDN$		CDN$
Highest rate during the period		1.0697		1.0418		1.0604
Lowest rate during the period		0.9839		0.9710		0.9449
Average noon spot rate for the period		1.0299		0.9996		0.9891
Rate at the end of the period		1.0636		0.9949		1.0170

On March 28, 2014 (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$1.1064.

The following table sets forth, for the periods indicated, the high, low, average and period-end noon spot rates of exchange for one Papua New Guinea kina, expressed in Canadian dollars, published by OZForex.

	Year Ended 31 December
	2013		2012		2011
	CDN$		CDN$		CDN$
Highest noon rate during the period		0.5078		0.5207		0.4918
Lowest noon rate during the period		0.3860		0.4740		0.3717
Average noon spot rate for the period		0.4542		0.4908		0.4269
Noon rate at the end of the period		0.4264		0.4912		0.4833

On March 28, 2014 (being the latest practicable date prior to the publication of this form), the noon buying rate for one Papua New Guinea kina in Canadian dollars published by OZForex was CDN$0.3956.

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

	Year Ended 31 December
	2013		2012		2011
	U.S.$		U.S.$		U.S.$
Highest closing spot rate during the period		0.4971		0.5006		0.4767
Lowest closing spot rate during the period		0.3750		0.4693		0.3768
Average closing noon spot rate for the period		0.4415		0.4908		0.4316
Closing spot rate at the end of the period		0.4008		0.4928		0.4751

On March 28, 2014 (being the latest practicable date prior to the publication of this form), the closing spot rate of exchange for one Papua New Guinea kina, expressed in U.S. dollars, as published on OZForex was U.S.$0.3580.

GLOSSARY OF TERMS

“2013 MD&A” means the Management’s Discussion and Analysis for the year ended December 31, 2013.

“AIF” means this Annual Information Form for the year ended December 31, 2013.

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

“Barrel, Bbl” (petroleum) is a unit volume measurement used for petroleum and its products.

“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.

Annual Information Form INTEROIL CORPORATION 5

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

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

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

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

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

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

"DPE" means the Department of Petroleum and Energy, a Papua New Guinea Government department responsible for regulating oil and gas activities in Papua New Guinea.

“Farm in” is a contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for the other party’s fulfillment of contractually specified conditions.

“FEED” means front-end engineering and design.

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

“FID” means final investment decision.

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

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

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

"GLJ 2013 Report" means the report dated March 11, 2014 with an effective date of December 31, 2013 setting forth certain information regarding contingent resources of our interests in the Elk, Antelope, and Triceratops fields in PNG.

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

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

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

Annual Information Form INTEROIL CORPORATION 6

“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, and amended December 15, 2005 and further amended June 15, 2012.

“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.

“LNGL” means Liquid Niugini Gas Limited.

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

“LNG Project Agreement” means the LNG project agreement between the State and LNGL of December 23, 2009.

“LPG” means liquefied petroleum gas, typically ethane, propane, butane and isobutane. Usually produced at refineries or natural gas processing plants, including plants that fractionate raw natural gas plant liquids. LPG can also occur naturally as a condensate.

“Minister” means the Minister of Petroleum and Energy of Papua New Guinea.

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

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

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

“NGL” means natural gas liquids, consisting of any one or more of propane, butane and condensate.

“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.

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

“Petromin” means Petromin PNG Holdings Limited, a company incorporated in Papua New Guinea owned as at 100% by the State.

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

“PNGDV” means PNG Drilling Ventures Limited.

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

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

Annual Information Form INTEROIL CORPORATION 7

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

"PRE" means Pacific Rubiales Energy Corp., a company incorporated in British Columbia, Canada.

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

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

“SPA” means sales and purchase agreement.

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

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

“Tcfe” means trillion standard cubic feet equivalent.

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

“Total SPA” means the sales and purchase agreement signed on December 5, 2013 with Total where we agreed to sell a gross 61.3% interest in PRL 15, which contains the Elk and Antelope gas fields. This agreement was subsequently revised on March 26, 2014 with Total under which Total acquired, through the purchase of all shares in a wholly owned subsidiary, a gross 40.1275% interest in PRL 15.

“UBS” means UBS A.G.

“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 Territory).

Annual Information Form INTEROIL CORPORATION 8

CORPORATE STRUCTURE

Name, Address and Incorporation

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

Our registered office	Our corporate office	Our corporate office
in Canada is located at:	in Singapore is located at:	in Papua New Guinea is located at:

Suite 300,204 Black Street	111 Somerset Road	Level 2, Ravalien Haus,
Whitehorse, Yukon	TripleOne Somerset #06-05	Harbour City, Port Moresby
Y1A 2M9	Singapore 238164	NCD

Our corporate office in Australia is located at:

Level 3, Cairns Square,
42 – 52 Abbott Street, Cairns, Queensland 4870

We intend to relocate our office in Cairns, Australia to Papua New Guinea by the end of 2014 to support expanding operations in 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 9

GENERAL DEVELOPMENT OF THE BUSINESS

Three-Year History

We are an independent oil and gas business with a primary focus on Papua New Guinea and the surrounding region. Our assets include Elk and Antelope fields in the Gulf Province of Papua New Guinea, exploration licenses covering about 16,000 square kilometers (about 4 million acres), Papua New Guinea’s only oil refinery, and retail and commercial petroleum distribution facilities throughout the country. We employ more than 1,000 people, and have our main offices in Singapore, Australia and Port Moresby. We are listed on the New York and Port Moresby stock exchanges.

Upstream – Exploration and Development

Exploration seismic and drilling

In the past three years, we have focused on meeting work commitments across our licenses with seismic acquisition and exploration and appraisal drilling. The Elk, Antelope and Triceratops fields all now have independent certified contingent gas and condensate resources, and in December 2013, we received approval for a retention license (PRL 39) over the Triceratops field.

Seismic

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

In 2012 and 2013, we acquired seismic over PPL 236 which focused on the Wahoo-Mako, Whale, Shark and Tuna leads. We also completed a joint seismic program in 2013 with Oil Search, which holds PPL 338, which is adjacent to PPL 237. Additional seismic was also acquired in 2013 near the Triceratops field in PPL 237 and PPL 238. In addition, we also began acquiring seismic in Triceratops east, south-west Antelope and across two new prospects, Bobcat in PPL 238 and Antelope Deep (formerly Big Horn) in PRL 15.

Drilling

In 2012, we spudded the Antelope-3 appraisal well in PRL 15 to further evaluate field size and structure and to reduce resource uncertainty. In 2013, the well was completed and suspended for future production. Formation evaluation indicates that the reservoir quality at Antelope-3 is similar to the Antelope-1 and Antelope-2 wells. Further appraisal of Elk and Antelope fields is also planned in 2014-2015.

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

In 2013, the Board approved a major exploration and appraisal drilling and seismic work program and budget for 2014-2015. Exploration wells are scheduled for PPL 474 (Wahoo-1), PPL 475 (Raptor-1), PPL 476 (Bobcat-1) and PRL 15 (Antelope Deep) and appraisal wells are scheduled for PRL 15 (Antelope-4, Antelope-5 and possibly Antelope-6) and PRL 39 (Triceratops-3). Following Board approval of the program, we began preparing for drilling in PPL 474, PPL 475 and PPL 476, with all wells spudded in March 2014.

New license applications

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

Development

Total agreement

As part of our strategy to monetize gas resources, we agreed on December 5, 2013 to sell to Total a gross 61.3% interest (net 47.5%, after PNG government back-in of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields, and to also grant Total an option to farm-in to all our exploration licenses in Papua New Guinea pursuant to the Total SPA.

Annual Information Form INTEROIL CORPORATION 10

The Total SPA stipulates fixed and variable resource-based payments that include $613.0 million payable on transaction completion, $112.0 million payable on 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 is obliged to make variable payments for resources in PRL 15 that are in excess of 3.5 Tcfe, based on certification by two independent certifiers following the drilling of up to three appraisal wells to be drilled in PRL 15. The payments for resources greater than 5.4 Tcfe will be paid at certification.

Total will carry the cost of these appraisal wells (up to a cap of $50.0 million per well), which are scheduled to be drilled in 2014 and 2015, and certification of the Elk and Antelope resources is expected in 2015.

Under the agreement, Total will lead construction and operation of a proposed integrated LNG Project, FID on which is scheduled to follow resource certification, concept selection, basis of design and front-end engineering and design.

In addition to payments for the Elk and Antelope resources in PRL 15, Total has also agreed to pay $100.0 million per Tcfe for volumes over one Tcfe of additional resources discovered in PRL 15 from one exploration well. Any payment would be made at first gas production from a proposed Elk and Antelope LNG facility. Total will also carry the cost of this exploration well to a maximum of $60.0 million. Costs in excess of this are to be borne by the parties according to their participation interests.

We have also agreed with Total to explore other business opportunities in Papua New Guinea and elsewhere in the Asia Pacific region.

Completion of the Total SPA remained subject to government approval and the acquisition by us 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 precedent to completion of that agreement.

Therefore on March 26, 2014, we signed and closed with Total a revised sale and purchase agreement, under which Total acquired through the purchase of all shares in a wholly owned subsidiary, a gross 40.1275% interest in PRL 15. We retained 35.4839% of the license and immediately became entitled to receive $401.3 million for closing the transaction, receive $73.3 million on FID for an Elk and Antelope LNG project, and $65.4 million on the first LNG cargo. All fixed and variable resource-based payments that were agreed under Total SPA dated December 05, 2013 continue to apply, including those for exploration, appraisal and resource certification, and are pro-rated according to the new equity split.

On March 26, 2014, we also completed the acquisition from IPI holders of an additional 1.0536% participating interest in PRL 15 for consideration of $41.53 million satisfied by the issue of 688,654 common shares of the Company, plus additional variable resource payments if interim or final resource certifications exceeds 7.0 Tcfe under Total SPA.

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

Petromin

In October 2008, Petromin, a government entity mandated to invest in resource projects on behalf of the State, entered into an agreement to take a 20.5% direct interest in the Elk and Antelope fields if and once nominated by the State to take its legislative interest. Petromin contributed an initial deposit and agreed to conditionally fund 20.5% of the costs of developing these fields.

In December 2011, we agreed to terminate the 2008 investment agreement with Petromin. We have proposed that Petromin’s cash contributions of about $15.4 million paid under the agreement to fund development will be credited against the State’s obligation to refund its portion of sunk costs on the grant of the PDL in relation to PRL 15.

Pacific Rubiales Energy farm-in

On March 13, 2013, we completed the farm-in transaction with PRE originally entered into in July 2012 related to PREs acquisition of a 10.0% net (12.9% gross) participating interest in PPL 237 onshore PNG, including the Triceratops structure and exploration acreage located within that license. PRE funded the final payment of $55.0 million of the full $116.0 million contribution due under the farm-in agreement.

Annual Information Form INTEROIL CORPORATION 11

Subsequent to year end, on January 17, 2014, we agreed to amend the joint venture operating agreement to cap PRE’s carry for each well at $25.0 million, with costs in excess of this to be borne by the parties according to their equity participation interests.

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

·	PNG Energy Investors

On October 24, 2013, we entered into an Exchange Agreement with PNGEI to buy PNGEI’s 4.25% indirect participating interest in 16 exploration wells commencing after our ninth exploration well in exchange for 100,000 of our common shares, and to terminate their IPI Agreement.

Condensate stripping project

Over the past three years, we worked with Mitsui on a condensate stripping project that was originally aimed at accelerating revenue from the Elk and Antelope fields. The project was designed to take condensate from the gas stream and to re-inject dry methane into the fields for later extraction.

On February 28, 2013, we terminated our agreements with Mitsui and on July 16, 2013, we entered into a Settlement and Termination Deed with Mitsui. In accordance with the deed, we repaid Mitsui $34.4 million for the cancellation of the option for Mitsui to acquire interests in the Elk and Antelope fields, for Mitsui’s share of costs on the project, and in repayment of an unsecured loan. The facility has now been fully repaid and all security to Mitsui has been discharged.

Midstream - Liquefaction

Midstream Liquefaction Joint Venture

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

During 2013, we have modified the direction of our midstream liquefaction business and no longer plan to be the operator of an LNG liquefaction project in which we have ownership. We now expect the LNG Project and midstream liquefaction business to be developed jointly with Total.

Energy World Corporation

We and PacLNG agreed in 2010 and 2011 to negotiate definitive arrangements with Energy World Corporation if we could reach FID on a land-based modular LNG plant in the Gulf Province of Papua New Guinea by mid-2013. We did not reach such a decision by that date and accordingly the agreements with Energy World Corporation lapsed in 2013. The agreements will not be renewed or extended.

FLEX LNG and Samsung

In early 2011, we and PacLNG agreed with FLEX LNG and Samsung Heavy Industries to consider construction of a fixed, floating LNG vessel with capacity of 1.8 to 2.0 mtpa. The agreements lapsed when we could not reach FID by December 2011. These agreements will not be renewed or extended. On September 10, 2013, we sold our investment in FLEX LNG shares for $7.8 million.

Midstream – Refining

Over the three years ended December 31, 2013, our refining business has processed low-sulfur crude to meet Papua New Guinea’s diesel and jet fuel demand and to make occasional exports. We have also sold naphtha and low-sulfur waxy residue on spot and term contracts to regional markets and occasionally to Papua New Guinea customers.

The refinery’s catalytic reformer unit, which was shut down for refurbishment in August 2012, resumed operation in May 2013. This allowed us to meet Papua New Guinea’s demand for gasoline and to cease imports of gasoline.

We continue to negotiate directly with crude producers and sellers, to complete purchases with BP and to use BP’s shipping infrastructure. Availability of our preferred crude has declined naturally over the past three years and we have introduced several new feedstocks to compensate, including our first West African crude and other Malaysian crudes. During 2011, we had term purchase agreements for some preferred crudes for 2012, though we retained only one term agreement for 2013, and all other crudes were bought on the spot market for the year.

Annual Information Form INTEROIL CORPORATION 12

While regional hydroskimming margins have fallen, particularly in 2011, an import parity price, which is generally the price that would be paid in Papua New Guinea for a refined product that had been imported, for our products sold in Papua New Guinea gives us some protection from low industry margins. Conversely, the import parity price restricts our margins when they might otherwise be rising. While the import parity price formula has remained the same over the past three years, changes from late 2007 and early 2008 remain to be formalized in our refinery project agreement.

In 2012, our middle distillate sales increased 12% over 2011, and in 2013 sales have been steady with a 1% increase over 2012. Increases in previous periods are primarily due to increased demand from new resources projects in Papua New Guinea. These increases have occurred amid continued imports by others of refined products that we believe are contrary to our refinery project agreement with the State.

We sold 9.3 MMbbls of product in 2013 compared with 8.5 MMbbls in 2012 and 7.2 MMbbls in 2011. Total volumes of Papua New Guinea domestic sales for 2013 were 5.2 MMbbls compared with 5.3 MMbbls in 2012 and 4.6 MMbbls in 2011. During 2013, we exported 11 cargoes of naphtha totaling 356,482 tonnes or 3.1 MMbbls. Naphtha production in Papua New Guinea is variable and depends on crude feedstock, relative economics for gasoline and naphtha, and our ability to use naphtha for gasoline production. We also exported six cargoes of low-sulfur, waxy residue in 2013 totaling 970,978 bbls. Our only exports of diesel in these years were for small bunker sales.

During 2013, our average daily production (excluding shut down days) was 27,999 bblspd compared to 24,483 bblspd in 2012 and 24,856 bblspd in 2011. The total number of barrels processed into product at our refinery for 2013 was 9.247 MMbbls compared with 7.426 MMbbls for 2012 and 6.730 MMbbls in 2011. Our refinery was shut down for a total of 24 days in 2013 compared to 51 days in 2012 and 82 days in 2011.

Downstream – Wholesale and Retail Distribution

In 2013, we provided petroleum products to 52 retail service stations with 43 operating under our own brand, and the remainder under independent brands. Of all the service stations that we supply, we own or lease 17, which we then sub-lease to Company-approved operators. We supply products to these service stations and have loan agreements for fuel pumps and related infrastructure with operators of most retail service stations that are not owned or leased by us. The service stations that we do not own are independently owned and operated. We also operate three truck stops and have plans to develop additional sites.

Our retail business accounted for about 14.6% of our total downstream sales volumes in 2013 compared to 14.2% over the same period in 2012. We continue to invest in new retail sites and in new retail fuel distribution systems. During the year, we re-opened two completely refurbished retail sites and purchased a key high-volume site from an independent operator. We have also planned another retail site which we expect to have completed during 2014.

The PNG economy slowed slightly during 2013 as construction of the Exxon Mobil led LNG project neared completion. Total sales volumes for the year ended December 31, 2013 were 738.0 million litres (2012 – 752.5 million litres and 2011– 678.0 million litres), a decrease of 14.5 million litres, or 1.9% over the same period in 2012.

During 2013, we renewed supply agreements with several key mining customers for fuel and lubricants. While refining is under increasing pressure from imported fuel, predominately diesel, our coverage through distribution networks servicing most major regional locations underpins the business.

In December 2013, Papua New Guinea’s Independent Competition and Consumer Commission advised that wholesale margins would be revised for the year ended December 2014 and would apply to unleaded gasoline, diesel and kerosene.

Financing

Unsecured 2.75% convertible notes:

On November 10, 2010, we completed the issuance of $70.0 million unsecured 2.75% convertible notes with a maturity of five years. The convertible notes rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the BNP led syndicated working capital facility, the ANZ, BSP and BNP syndicated secured loan facility, the BSP and Westpac secured loan facility, the BSP and Westpac working capital facilities, the Credit Suisse syndicated secured loan, trade payables and lease obligations. We pay interest on the notes semi-annually on May 15 and November 15.

Annual Information Form INTEROIL CORPORATION 13

The notes are convertible into cash or common shares, based on initial conversion rate of 10.4575 common shares per $1,000 principal amount, which represents an initial conversion pricing of approximately $95.625 per common share, The initial conversion price is subject to standard anti-dilution provisions designed to maintain the value of the conversion option in the event we take certain actions with respect to our common shares, such as stock splits, reverse stock splits, stock dividends, and cash dividends, that affect all of the holders of our common shares equally and that could have a dilutive effective on the value of the conversion rights of the holders of the notes or that confer a benefit upon our current shareholders not otherwise available to the convertible notes. Upon conversion, holders will receive cash, common shares or a combination thereof, at our option.

The convertible notes are redeemable at our option if our share price has been at least 125% ($119.53 per share) of the conversion price for at least 15 trading days during any 20 consecutive trading day period. Upon a fundamental change, which would include a change of control, holders may require us to repurchase their convertible notes for cash at a purchase price equal to the principal amount of the notes to be repurchased, plus accrued and unpaid interest.

During the twelve months ended December 31, 2013, $2,000 of the convertible notes were converted into cash.

BNP Paribas led working capital facility:

In May 2011, we increased our working capital facility limit with BNP Paribas by $10.0 million to $230.0 million. The facility was subsequently extended and further amended in February 2012 to increase the facility limit to $240.0 million.

In July 2013, we replaced our $240.0 million working capital facility from BNP Paribas with a $350.0 million working capital structured facility led by BNP Paribas. Out of the $350.0 million, $270.0 million is a syndicated secured working capital facility supported by BNP Paribas, ANZ, Natixis, Intesa Sanpaolo and BSP and includes the ability for us to discount receivables with recourse up to $30.0 million. In addition, BNP Paribas has provided an $80.0 million bilateral non-recourse discounting facility, the credit portion of which bears interest at LIBOR plus 3.75% per annum. The facility is secured by our rights, title and interest in inventory and working capital of the Napa Napa refinery. The facility is renewable in February 2015.

Westpac and BSP working capital facility:

In August 2011 and November 2012, we also renewed for another year our facility of PGK50.0 million ($23.3 million) with BSP. In February 2012, our Westpac facility was renewed at PGK90.0 million ($42.0 million) with maturity in November 2014.

In 2013, our $57.8 million (PGK140.0 million) facility with BSP and Westpac was reduced by $20.7 million (PGK50.0 million) when the two banks provided a combined secured loan for our exploration and drilling. This reduced the limit of our downstream facility to $37.2 million (PGK90.0 million). Each bank’s share of the working capital facility is currently approximately $18.6 million (PGK45.0 million) after we reduced Westpac’s limit in August 2013 by $18.6 million (PGK45 million) and BSP’s limit by $2.1 million (PGK5.0 million). The facility with both banks expires in November 2014.

Westpac secured loan:

In February 2012, we obtained a $15.0 million secured loan from Westpac that was repayable in equal installments over 3.5 years with an interest rate of LIBOR plus 4.4% per annum. We were required to make semi-annual payments of $2.1 million with a final payment in August 2015. The loan, which was secured by a fixed and floating charge over the assets of our downstream operations, was repaid in 2013.

BNP-led syndicated term facility:

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

Annual Information Form INTEROIL CORPORATION 14

BSP and Westpac secured facility:

In August 2013, Westpac and BSP provided a one-year $75.0 million combined secured loan facility to be drawn in tranches of either US dollars or kina or both. Borrowings under the facility were to be used for exploration and drilling activities with $37.5 million to be available immediately and the balance to be available upon the execution of an agreement in relation to the monetization of the Elk and Antelope fields.

The second tranche was cancelled after we secured a $250.0 million facility in November 2013 from banks led by Credit Suisse and including Westpac and BSP. In addition, the Westpac-BSP loan limit was reduced to $24.8 million (PGK60.0 million) in November 2013 with the principal to be repaid in quarterly installments of PGK2.5 million starting December 31, 2013 and the balance to be repaid in the third quarter of 2014.

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. The credit facility bears interest at LIBOR plus 5.5% margin on the drawn amount for the first six months. After the first six month period the margin escalates 2.0 percent every two months to a maximum of 11.5% in the last two months of the 12-month term. During the year, the weighted average interest rate was 5.65%. The facility must be repaid by April 30, 2014 or by completion of the Total SPA, whichever comes first. Post completion of the Total SPA on March 26, 2014, this facility is expected to be repaid in April 2014. At December 31, 2013, we had drawn down $100.0 million and the remainder was available for use according to the terms of the facility.

Board and management

Our Board and senior management has undergone significant changes from 2011 to 2013.

In August 2011, former Papua New Guinea Prime Minister and former Petroleum and Energy Minister Sir Rabbie Namaliu chaired our Advisory Board to provide advice and assist in discussions on PNG policy as it affects our business, and in July 2012, he joined the full Board as a director.

In June 2012, General Counsel Mark Laurie resigned and was formally replaced in December 2012 by experienced corporate lawyer Geoff Applegate whose career has included many years of advising companies in Papua New Guinea.

In July 2012, Samuel L. Delcamp was appointed a director, and the Board separated the roles of Chairman and Chief Executive Officer when Dr. Gaylen Byker was elected Chairman and Phil Mulacek continued as Chief Executive Officer.

On April 30, 2013, Mr. Mulacek retired as Chief Executive Officer and on November 14, 2013 he retired as a director.

From May 1, 2013 to July 10, 2013 Dr. Gaylen Byker acted as Interim Chief Executive Officer.

On June 24, 2013, Sir Wilson Kamit CBE, a former Governor of the Bank of Papua New Guinea, was elected to the Board.

On June 24 2013, Christian Vinson retired as a director and Executive Vice President, and Isikeli Taureka, a former Chevron Corporation executive, was appointed Executive Vice President, Corporate Development and Government Relations, replacing Christian Vinson.

On July 11, 2013, Dr. Michael Hession was appointed Chief Executive Officer after more than 25 years’ international exploration, operations and commercial experience with BP and Woodside Energy. Dr. Hession became a director on November 15, 2013.

On November 15, 2013, David Kirk was appointed Vice President, Upstream Business Unit, after more than 30 years in field development, project execution and operational roles with Woodside Energy in Australia, West Africa and North Africa, and most recently as Chief Executive of AWT International, an upstream engineering and geosciences consultancy.

On December 17, 2013, Thomas Nador was appointed General Manager, Strategy and Planning, after more than 20 years in operational and management roles spanning oil and gas, LNG, pipelines, mining and construction.

Annual Information Form INTEROIL CORPORATION 15

On January 21, 2014, Jon Ozturgut was appointed Chief Operating Officer after more than 27 years international oil and gas experience with Atlantic Richfield Company, CMS Oil and Gas Company, and Woodside Energy. He replaced William J. Jasper III, who retired after seven years with InterOil.

Don Spector was also appointed Chief Financial Officer on January 22, 2014 after more than 35 years international financial experience, including 30 years in oil and gas with BP, CRA (now Rio Tinto), Woodside Energy, and the Australian Tax Office. He replaced Collin Visaggio who resigned, also after seven years with the Company.

BUSINESS STRATEGY

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

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

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

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

The focus areas for our strategy are to:

Continue to develop as a prudent and responsible business operator

Build on more than 18 years in Papua New Guinea;

Maintain a sound health and safety record;

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

Remain a significant employer in Papua New Guinea.

Enhance our existing refining and distribution businesses

Continue growth in profitable market share in the region;

Look for added value in refining production, and improved economies of scale; and

Explore improved transport efficiencies and economics.

Monetize our discovered resources

Introduce strategic investors to the Elk, Antelope and Triceratops fields to support our exploration and development, including implementation of the Total SPA for development of PRL 15 and construction of an LNG plant; and

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

Maximize the value of our exploration assets

Manage our exploration program to maximize access to license areas;

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

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

Employ additional drilling rigs to develop existing discoveries.

Position for long term success

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

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

Build on our core business to fund exploration programs in multiple ‘frontier’ regions and diversify revenue streams beyond Papua New Guinea to provide long-term sustainability.

Annual Information Form INTEROIL CORPORATION 16

DESCRIPTION OF OUR BUSINESS

Overview

Our operations are organized into four major segments:

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

As of December 31, 2013, we had 1,093 full-time employees in all segments, with 173 in Upstream, 131 in Midstream-Refining, 598 in Downstream and 191 in Corporate.

UPSTREAM – EXPLORATION AND DEVELOPMENT

As at December 31, 2013, we had gross interests in three PPLs and two PRLs, all of which we operate in Eastern Papuan Basin, northwest of Port Moresby.

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

This table summarizes our interests as at December 31, 2013:

License Numbers	Discovery	Location	Operator	InterOil Registered License Interest			InterOil Net Beneficial Interest Owned¹			Blocks Covered		Acreage Gross		Acreage Net¹
PPL 236	None	Onshore	InterOil		100.00	%		78.1114	%		53		1,106,976		864,674
PPL 237	None	Onshore	InterOil		100.00	%		65.2082	%		25		524,315		341,896
PPL 238	None	Onshore	InterOil		100.00	%		78.1114	%		94		1,969,983		1,538,781
PRL 15	Elk/Antelope	Onshore	InterOil		75.6114	%		75.6114	%		9		188,675		142,660
PRL 39	Triceratops	Onshore	InterOil		69.0931	%		69.0931	%		9		188,877		130,501
								Total			190		3,978,826		3,018,512

See ‘Working interests in licenses’ below for details of the Company’s net interest.

Annual Information Form INTEROIL CORPORATION 17

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

License Numbers	Discovery	Location	Operator	InterOil Registered License Interest			InterOil Net Beneficial Interest Owned¹			Blocks Covered		Acreage Gross		Acreage Net¹
PPL 474 (PPL 236)	None	Onshore	InterOil		100.00	%		78.1114	%		59		1,232,462		962,693
PPL 475 (PPL 237)	None	Onshore	InterOil		100.00	%		65.2082	%		25		524,315		341,896
PPL 476 (PPL 238)	None	Onshore	InterOil		100.00	%		78.1114	%		58		1,215,243		949,243
PPL 477 (PPL 238)	None	Onshore	InterOil		100.00	%		78.1114	%		30		629,254		491,519
PRL 15	Elk/Antelope	Onshore	InterOil		75.6114	%		75.6114	%		9		188,675		142,660
PRL 39	Triceratops	Onshore	InterOil		69.0931	%		69.0931	%		9		188,877		130,501
								Total			190		3,978,826		3,018,512

See ‘Working interests in licenses’ below for details of the Company’s net interest.

Resources

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

GLJ, an independent qualified reserves evaluator, effective as of December 31, 2013, evaluated our gas and condensate resources for the Elk, Antelope and Triceratops fields, all of which are in onshore Papua New Guinea. The GLJ 2013 Report, with a preparation date of March 11, 2014 was prepared in accordance with definitions and guidelines in the COGE Handbook and NI 51-101.

This table outlines GLJ's estimates contained in the GLJ 2013 Report effective December 31, 2013 of total and net contingent resources for gas and condensate at the Elk and Antelope field and the Triceratops field:

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

As at December 31, 2013	Case
Elk/Antelope Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	6.83	9.07	10.85
Marketable Condensate (MMbbls)	111.5	135.4	156.3
Oil Equivalent (MMboe)	1,250.1	1,646.3	1,965.4

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

As at December 31, 2013	Case
Elk/Antelope Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	4.00	5.31	6.36
Marketable Condensate (MMbbls)	65.3	79.3	91.6
Oil Equivalent (MMboe)	732.5	964.7	1,151.7

Annual Information Form INTEROIL CORPORATION 18

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

As at December 31, 2013	Case
Triceratops Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	0.12	0.38	0.90
Marketable Condensate (MMbbls)	2.7	8.2	19.4
Oil Equivalent (MMboe)	23.2	71.9	168.8

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

As at December 31, 2013	Case
Triceratops Contingent	Low	Best	High
Marketable Sales Gas (Tcf)	0.07	0.20	0.48
Marketable Condensate (MMbbls)	1.4	4.4	10.3
Oil Equivalent (MMboe)	12.3	38.1	89.5

Notes:

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

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

These estimates are based upon our holding a 58.5988% working interest in the Elk and Antelope fields, which assumes that: (i) the State and landowners elect to participate in the Elk and Antelope fields to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Elk and Antelope fields and (ii) all elections are made to participate in the Field by all investors pursuant to relevant indirect participation interest agreements with us, including to participate fully and directly in the PDL. See ‘Working interests in licenses’ below for details of the our net interest assuming completion of the Total transaction.

These estimates are based upon InterOil holding a 53.5471% working interest in the PPL 237, which assumes that: (i) the State and landowners elect to participate in the Triceratops field to the full extent provided under applicable PNG oil and gas legislation after a PDL has been granted in relation to the Triceratops field and (ii) all elections are made to participate in the Field by all investors entitled to do so pursuant to relevant indirect participation interest agreements with InterOil, including to participate fully and directly in the PDL.

All resources estimated for the Elk and Antelope fields are classified as contingent resources – economic status undetermined. At this early stage of appraisal, the resources estimates for the Triceratops field are classified separately in the GLJ 2013 Report as either contingent resources – economic status undetermined or prospective resources. Consistent with our treatment with the Elk and Antelope fields, the Triceratops prospective resources are not included.

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

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

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

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

Approval from regulatory authorities to develop the resources; and

Determination of economic viability.

Annual Information Form INTEROIL CORPORATION 19

Accuracy of Resource Estimates

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

Costs incurred in relation to Exploration and Development activities

This table outlines costs incurred by us during the year ended December 31, 2013 for property, acquisitions, exploration and development activities.

Nature of Cost	Amount ($ Millions)
Property acquisition costs		-
Exploration costs	$	18.36
Development costs	$	74.57
Total	$	92.93

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, 2013.

Wells	Development				Exploration				Total
	Gross ($ Millions)		Net ($ Millions)		Gross ($ Millions)		Net ($ Millions)		Gross ($ Millions)		Net ($ Millions)
Gas	$	116.13	$	74.57	$	31.68	$	18.36	$	147.81	$	92.93
Oil		-		-		-		-		-		-
Service		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total	$	116.13	$	74.57	$	31.68	$	18.36	$	147.81	$	92.93

The following table discloses the number of wells completed during the year ended December 31, 2013, 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 236		PPL 237		PPL 238		PRL 15		PRL 39		Total
Gas		-		-		-		1		-		1
Oil		-		-		-		-		-		-
Service		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Total		-		-		-		1		-		1

Annual Information Form INTEROIL CORPORATION 20

Operated License Commitments, Terms and Expiry

Below are our applicable expenditure commitments for each PPL and PRL as at December 31, 2013.

License	License Issue/Extension	Term	Commitment Years 1 to 2 ( $ Millions)			Commitment Years 3 to 5 ( $ Millions)		Total License Commitment ( $ Millions)			License Expiry
PPL 236₍₃₎	March 27, 2009	5 years	$	5.0		$	21.0	$	26.0		March 27, 2014
PPL 237₍₃₎	March 27, 2009	5 years	$	14.0		$	34.0	$	48.0		March 27, 2014
PPL 238₍₃₎	March 6, 2009	5 years	$	2.0		$	35.0	$	37.0		March 6, 2014
PRL 15	November 30, 2010	5 years	$	33.0	⁽²⁾	$	46.5	$	79.5	⁽¹⁾	November 29, 2015
PRL 39	December 6, 2013	5 years	$	38.1		$	30.25	$	68.35	⁽¹⁾	December 5, 2018
	Totals		$	92.1		$	166.75	$	258.85

Notes:

(1)

Commitment total is for the first 5 years only.

(2)

The application for variation of PRL 15 was granted on November 28, 2012. The variation allowed us to defer the drilling of an obligation well into the second term of the license.

(3)

The application for new licenses over PPLs 236, 237 and 238 were submitted on October 16, 2013. The applications were approved on March 6, 2014. See below for the new license commitments. Once the new licenses are granted the old licenses are surrendered and no further commitments remain. All expenditure incurred is then against the commitments in the new licenses.

We had a remaining commitment on PPL 236 of $3.8 million as at December 31, 2013, and were required to drill an exploration well and complete post-well analysis before the license expires. At December 31, 2013, a rig was mobilized to drill the Wahoo prospect. Subsequent to year end, on March 8, 2014 we spudded Wahoo-1 well in PPL 474.

We had satisfied our financial commitments on PPL 237 as at December 31, 2013 and were required to drill an exploration well before the license expires. At December 31, 2013, a rig was also mobilized to drill the Raptor prospect. Subsequent to year end, on March 28, 2014 we spudded Raptor-1 well in PPL 475.

We had a remaining commitment on PPL 238 of $28.3 million as at December 31, 2013, and were required to acquire, process and interpret 100km of new two-dimensional seismic data, drill a well before the license expires. On March 28, 2013, we received approval from the DPE to vary our drilling commitment under PPL 238 by deferring it into year five of the second term, which term if granted would commence March 8, 2014. As required under the Papua New Guinea Oil and Gas Act, we submitted a work program and expenditure proposal in connection with our applications to renew PPLs 236, 237 and 238. At December 31, 2013 date, a rig was being mobilized to drill the Bobcat prospect. Subsequent to year end, on March 5, 2014 we spudded Bobcat-1 well in PPL 476.

In PRL 15, we have a total financial commitment over the five-year term of $79.5 million. As at December 31, 2013, we had a remaining commitment of $47.1 million and are required to drill two appraisal wells in the Elk and Antelope fields before the license expires in 2015. As a result of testing the Antelope-3 well in the beginning of 2013 and under our agreement with Total, we plan to drill at least two appraisal wells in PRL 15 during 2014.

With PRL 39, our total financial commitment in the Triceratops field over the first five-year term is $68.35 million. We have a remaining commitment of $67.1 million as at December 31, 2013, and are required before the license expires to drill a well in the Triceratops field; acquire, process and interpret 125km of two-dimensional seismic, and complete geoscience, social mapping, social, economic impact, commercial, marketing, surface and subsurface engineering studies. During 2013, we completed a seismic program over the Triceratops trend. We expect the Triceratops-3 well to be drilled in 2014 after we have interpreted seismic data.

Annual Information Form INTEROIL CORPORATION 21

On March 6, 2014, our license applications were approved with PPL 474 replacing PPL 236, PPL 475 replacing PPL 237, and PPL 476 and PPL 477 replacing PPL 238. In relation to the PPL commitments noted above, when the new PPL’s were approved, these commitments were terminated and replaced with new license commitments noted below. The three wells, Wahoo-1, Raptor-1 and Bobcat-1, are being drilled under the new licenses, and are part of the new drilling commitments. Below are our applicable expenditure commitments for each of the new licenses.

License	License Issue	Term	Commitment Years 1 to 2 ( $ Millions)		Commitment Years 3 to 4 ( $ Millions)		Commitment Years 5 to 6 ( $ Millions)		Total License Commitment ( $ Millions)		License Expiry
PPL 474 (PPL 236)	March 6, 2014	6 years	$	49.25	$	49.25	$	45.0	$	143.5	March 5, 2020
PPL 475 (PPL 237)	March 6, 2014	6 years	$	59.0	$	53.75	$	50.0	$	162.75	March 5, 2020
PPL 476 (PPL 238)	March 6, 2014	6 years	$	59.0	$	53.75	$	50.0	$	162.75	March 5, 2020
PPL 477 (PPL 238)	March 6, 2014	6 years	$	9.0	$	3.75	$	50.3	$	63.05	March 5, 2020
	Totals		$	176.25	$	160.5	$	195.3	$	532.05

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, 2013. 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. In addition to the working interests shown below, we agreed on December 05, 2013 to sell to Total a gross 61.3% interest (net 47.5%, after PNG government back-in of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields, and to also grant Total an option to farm-in to all our exploration licenses in Papua New Guinea pursuant to the Total SPA. 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. As a consequence of the Oil Search transaction, on March 26, 2014, we signed and closed with Total a revised SPA agreement, under which Total acquired through the purchase of all shares in a wholly owned subsidiary, a gross 40.1275% interest in PRL 15. Any option relating to farm-in to our exploration licenses, other than the confirmed PRL 15 changes, have not been reflected in the working interests disclosed below. On March 26, 2014, we also completed the acquisition of an additional 1.0536% participating interest in PRL 15 from IPI holders.

Petroleum Prospecting License 236

Participant	Working Interests as at December 31, 2013 (before State Participation)			Working Interests (after State Participation)
InterOil		78.1114	%		60.5363	%
IPI Holders₍₁₎₍₄₎		15.1386	%		11.7324	%
PNGDV₍₂₎		6.7500	%		5.2313	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form INTEROIL CORPORATION 22

Petroleum Prospecting License 237 (Excluding Triceratops Gas Condensate Field)

Participant	Working Interests as at December 31, 2013 (before State Participation)			Working Interests (after State Participation)
InterOil₍₅₎		65.2082	%		50.5363	%
IPI Holders₍₁₎₍₄₎		15.1386	%		11.7324	%
PNGDV₍₂₎		6.7500	%		5.2313	%
PRE₍₅₎		12.9032	%		10.0000	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Retention License 39 (Including Triceratops)

Participant	Working Interests as at December 31, 2013 (before State Participation)			Working Interests (after State Participation)
InterOil₍₅₎		69.0931	%		53.5471	%
IPI Holders₍₁₎₍₄₎		12.4517	%		9.6501	%
PNGDV₍₂₎		5.5520	%		4.3028	%
PRE₍₅₎		12.9032	%		10.0000	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Petroleum Prospecting License 238

Participant	Working Interests as at December 31, 2013 (before State Participation)			Working Interests (after State Participation)
InterOil		78.1114	%		60.5363	%
IPI Holders₍₁₎₍₄₎		15.1386	%		11.7324	%
PNGDV₍₂₎		6.7500	%		5.2313	%
State		-			20.5000	%
Landowners		-			2.0000	%
Total		100.0000	%		100.0000	%

Annual Information Form INTEROIL CORPORATION 23

Petroleum Retention License 15

Participant	Working Interests as at December 31, 2013 (before Total transaction and State Participation)			Working Interests (after Total transaction and before State Participation)			Working Interests (after Total transaction and State Participation)
InterOil		75.6114	%		36.5375	%		28.3166	%
IPI Holders_(1)(6)(8)		15.1386	%		0.5000	%		0.3875	%
PacLNG Assets Limited₍₂₎₍₆₎		6.7500	%		-			-
PacLNG Investment Limited₍₃₎₍₆₎		2.5000	%		-			-
Total S.A₍₇₎		-			40.1275	%		31.0988	%
Oil Search₍₆₎		-			22.8350	%		17.6971	%
State		-			-			20.5000	%
Landowners		-			-			2.0000	%
Total		100.0000	%		100.0000	%		100.0000	%

Notes:

⁽¹⁾

In February 2005, indirect participating interest holders agreed to pay InterOil $125.0 million and we agreed to drill eight exploration wells in PPLs 236, 237 and 238. We have drilled four of these wells to date. IPI holders now hold 15.1386% of each of these existing and future wells and each IPI holder 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. Certain of these legal rights are currently under review.

⁽²⁾

In July 2003, we agreed that PNGDV could take a 6.75% interest in eight exploration wells. We have drilled six of these exploration wells to date. PNGDV also has the right to participate in the next 16 wells that follow the first eight mentioned above up to an interest of 5.75% for $112,500 for each 1% per well (with higher amounts to be paid if the depth exceeds 3,500 meters and the cost exceeds $8,500,000). In June 2012, PNGDV transferred its interest in PRL 15 to PacLNG Assets Limited. The rights under the PNGDV agreement are under legal review.

⁽³⁾

In August 2009, Pacific LNG Operations, Limited acquired a 2.5% direct working interest in the Elk and Antelope fields. In June 2012, Pacific LNG Operations, Ltd transferred its interest in PRL 15 to PacLNG Investments Limited.

⁽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.

⁽⁵⁾

In July 2012, we agreed to sell to PRE a 10.0% net revenue interest (12.9% before State participation) in PPL 237. Our agreement covers Triceratops gas-condensate field and the rest of PPL 237 but not Triceratops gas condensate field known as PPL 237XT. Approval of an application over the Triceratops field (PRL 39) was approved subsequent to year end. It covers nine graticular blocks, or about 189,000 acres. This is coincidentally the same size as PRL 15. PacLNG and its affiliates are participating on a 25% beneficial equity basis in the portion of the PRE farm-in relating to the Triceratops gas-condensate field on PPL 237 by selling PRE a 3.2258% participating interest before State participation (2.5% after State participation), thus reducing the PacLNG Group’s indirect participating interest in the Triceratops structure by 3.2258%. Other indirect participating interest holders are also participating by selling PRE a 0.6591% participating interest before State participation, 0.5108% after State participation. Neither PacLNG Group nor any of the IPI holders participated in the sale of the indirect interest in PPL 237XT. In PPL 237XT, PRE acquired its 10% net revenue interest directly from InterOil. As such, we now have 3.8849% lower interest in PPL 237XT than our interest in the Triceratops gas-condensate field.

⁽⁶⁾

Subsequent to year end, 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.

⁽⁷⁾

On March 26, 2014, we agreed with Total for a revised SPA, under which Total acquired through the purchase of all shares in a wholly owned subsidiary, a gross 40.1275% interest in PRL 15.

⁽⁸⁾

On March 26, 2014, we completed the acquisition of an additional 1.0536% participating interest in PRL 15 from IPI holders.

Annual Information Form INTEROIL CORPORATION 24

MIDSTREAM - REFINING

Our oil refinery in Port Moresby, the only one in Papua New Guinea, began production in 2005. We import crude oil for processing at our refinery and sell the refined products primarily in Papua New Guinea at import parity price.

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

Facilities and Major Subcontractors

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

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

Crude Supply

Since December 2001, BP Singapore, one of the largest marketers and shippers of crude oil in the Asia Pacific, has supplied crude to our refinery under contract which has been renewed over the years. This contract provides us with a reliable mechanism to access and ship the majority of the regional crudes suitable to our refinery. We will continue to review this arrangement and other options for sources of feedstock supply for our refinery, and have been successful in securing other crude supple agreements for specific regional crudes.

Sales

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

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

Competition

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

Annual Information Form INTEROIL CORPORATION 25

While new refinery entrants are not restricted under our refinery project agreement with the State, we do not anticipate new entrants into the refining business within Papua New Guinea under the current market conditions. However, domestic distributors have not sourced all of their requirements from our refinery since 2009. Excess diesel, gasoline, naphtha and low-sulfur waxy residue that are exported and our location and limited storage capacity inhibits our ability to compete with the regional refining in Singapore for sales of large cargo sizes. However, these same factors may also provide competitive advantages if we expand our exports to small and fragmented South Pacific markets.

Customers

We sell Jet A1 fuel, diesel, gasoline and low-sulfur waxy residue to distributors in Papua New Guinea. Our main domestic customer is our downstream distribution business segment, and we also distribute fuel products to Niugini Oil Company, Islands Petroleum, Exxon Mobil and Bige Petroleum. We expect to supply Total Asia PNG beginning in 2014.

Trading and Risk Management

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

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

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

However, we can use various derivative instruments to assist us to reduce or hedge away the risks of changes in the relative prices of our crude feedstock and refined products. These derivatives, which can be used to manage our price risk, can effectively enable us to manage the refinery margin. At the same time, this means that if the difference between our sales price of the refined products and our acquisition price of crude feedstock expands or increases, then the benefits are limited to the margin range we have established.

We generally use over-the-counter swaps with credit-worthy counterparties to reduce or hedge the risk of changes in relative prices. Swaps are commonly used among refiners and trading companies in the Asia Pacific market, which is generally sufficiently liquid for hedging and risk management of products such as jet fuel and kerosene, diesel, naphtha, and bench-mark crudes such as DTD Brent, Tapis and Dubai.

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

MIDSTREAM - LIQUEFACTION

During 2013, we have modified the direction of our midstream liquefaction business and no longer plan to be the operator of an LNG liquefaction project in which we have ownership.

We anticipate that the Elk and Antelope fields will be monetized through our agreement with Total, which will construct and operate the proposed liquefaction plant and associated facilities. The Total SPA provides that we will participate in the LNG Project as a non-operator joint venture participant.

DOWNSTREAM - WHOLESALE AND RETAIL DISTRIBUTION

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

Annual Information Form INTEROIL CORPORATION 26

Sales

ICCC regulates the maximum prices and margins in the wholesale and retail bulk fuel distribution industry in Papua New Guinea. Margins were last reviewed by the ICCC in 2010 and will be further reviewed again in 2014-2015. We and our competitors, as industry distributors, may provide a discount from the maximum wholesale price set by ICCC.

Supply of Products

Our retail and wholesale business distributes diesel, jet fuel, avgas, gasoline, kerosene and fuel oil and branded commercial and industrial lubricants, such as engine and hydraulic oils. In general, all diesel, jet fuel and gasoline products sold pursuant to our wholesale and retail distribution business are bought from our refinery. We import commercial and industrial lubricants, avgas and fuel oil, which constitute a small percentage of our total volumes.

We deliver refined products from our refinery in two chartered tanker vessels, which we lease and operate. Our inland depots are supplied by road tankers that are owned and operated by third-party independent contractors.

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

Retail Distribution

As of December 31, 2013, we operated an InterOil-branded service station in Port Moresby to trial retail fuel card and point-of-sale systems, and to test the economic viability of capturing additional retail margin.

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

Wholesale Distribution

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

Competition

Our main competitor in the wholesale and retail distribution business in Papua New Guinea is ExxonMobil. We also compete with smaller local distributors of petroleum products. In early 2010, many of our competitors began to directly import diesel and other refined products. This importation of refined products has made it difficult to accurately gauge our market share, particularly as joint industry shipping arrangements ceased as a result. Our competitors source small quantities from our refinery road gantry for the Port Moresby market and from tanker vessels for markets outside Port Moresby. Our major competitive advantage is our distribution network and storage capacity that services most of Papua New Guinea. We also believe that our commitment to the downstream distribution business in Papua New Guinea provides us with a reputational advantage, particularly as major global oil and gas companies have left the country’s fuel distribution market. However, major integrated oil and gas companies such as ExxonMobil and Total have greater resources and significant capital to expand more rapidly in this market than we can if they so choose. In 2013, Total began selling branded lubricants and is expected to target bulk fuel sales in 2014, which may increase the competitive pricing by participants within the country.

Annual Information Form INTEROIL CORPORATION 27

Major Customers

In 2013, we sold approximately 14% of our refined petroleum products to a major mining project in Papua New Guinea. These volumes were contracted with narrow margins due to competitive pressures and in order to provide volumes for the Midstream – Refinery operations as such, the loss of this customer, at least in short term, would not materially affect the profitability of our retail and wholesale distribution business, but would have a more significant effect for the refinery business.

In 2013, we sold approximately 11% of our refined petroleum products to Pacific Energy Aviation (PNG) Ltd for aviation refueling at Papua New Guinea’s international airport in Port Moresby.

THE ENVIRONMENT AND COMMUNITY RELATIONS

Environmental Protection

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

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

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

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

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

Environmental and Social Policies

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

Annual Information Form INTEROIL CORPORATION 28

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

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

RISK FACTORS

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

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

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

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

As a result of weakened global economic conditions, including the European sovereign debt crisis, the downgrading of United States government debt and United States fiscal policy, 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.

Annual Information Form INTEROIL CORPORATION 29

Based on current funds available and expected funds from operations, we believe we have sufficient funds for our refining and distribution business operations 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. Significant capital will also be required in order to fund additional exploration and development of the Elk, Antelope and Triceratops fields and to meet our exploration license commitments. Failure to obtain financing for our capital expenditure plans, including through transactions with joint venture parties or others, will be likely to result in delays in these activities.

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

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

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

As of December 31, 2013, we had drilled eight exploration wells and several appraisal wells in our license areas. We plan to drill additional wells in Papua New Guinea in line with our license commitments. We cannot be certain that the wells will be productive or that we will recover all or any portion of the costs to drill them. Because of the high cost, topography and subsurface characteristics of the areas we are exploring, we have limited seismic or other geoscience data to assist us in identifying drilling objectives. The lack of this data makes our exploration activities more risky than would be the case if such information were readily available.

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

Our refinery’s financial condition may be materially adversely affected if we are unable to obtain crude oil at economic rates, or if we are unable to secure sufficient working capital.

While we have several possible sources of crude supply and an agreement with BP to deliver crude, we can give no assurance that we can continue to source adequate feedstock for our refinery.

Some crude oil that is suitable for our refinery is available in the region. However, most of our feedstock comes from outside of Papua New Guinea and access to these crudes farther afield may be more limited because crude oil sources that are economically compatible with our refinery are limited and declining. In addition, the increased cost of oil from outside Papua New Guinea may reduce our gross profit margins and negate their operational benefits. We can give no assurance that we will obtain all of the crude we need to operate our refinery or that we will obtain crude to operate our refinery profitably.

These factors, as well as others outside our control, may affect our ability to maintain or secure working capital to fund our refinery operations.

There is uncertainty associated with the regulated prices at which our products are sold.

Under our refinery project agreement with the State (See “Material Contracts – Refinery Project Agreement”), our refined products must be sold at a defined import parity price if domestic distributors in Papua New Guinea are required to source fuel from our refinery. In general, the import parity price is that which would be paid in Papua New Guinea for a refined product that is being imported. The price is set monthly. A revised formula was established with the State in 2008 and we are in discussion with the State to formally amend our agreement accordingly. The formula under which we have been operating may therefore change and the State may refuse to maintain the project formula, which could reduce our refining margins.

Annual Information Form INTEROIL CORPORATION 30

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

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

Our hedging activities may result in losses.

We may enter into hedging arrangements to reduce the risk of changes in the relative prices of our crude oil and refined products. Hedging may expose us to risk of financial loss in some circumstances, including:

if the amount of refined products production is less than expected or is not produced or sold during the planned time period;

if the other party to the hedging contract defaults on its contract obligations; or

if there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these hedging arrangements may limit the benefit we would receive from increases in the price of our refined products relative to prices for our crude.

While we believe our hedge counterparties to be creditworthy, disruptions in financial markets, the European sovereign debt crisis and downgrading of United States government debt could lead to sudden changes in a counterparty’s liquidity, which could restrict its ability to perform under the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited by market conditions.

Our results of operations and financial condition may be adversely affected by changes in currency exchange rates.

Exchange rates may fluctuate widely in response to international political conditions, general economic conditions and other factors beyond our control. While our domestic product sales are in the Papua New Guinean currency, kina, portions of our operating costs for buying crude and other imported products, and our indebtedness are denominated in U.S. dollars. A strengthening of the US dollar against the PGK may increase operating costs while a weakening of U.S. dollar against the PGK may reduce operating costs. In addition, the PGK exchange rate does form part of the import parity price formula that is determined monthly in arrears. A rapid decline or appreciation in the PGK will affect the net result in a reporting period due to the timing difference between the set import parity price and the collection of domestic sales proceeds.

Additionally, a significant portion of our operating costs are in Australian dollars. A stronger Australian dollar against U.S. dollar can increase our operating costs. In addition, our indebtedness needs to be paid in U.S. dollars, which means a strengthening U.S. dollar against the PGK may negatively impact our ability to service our U.S.-dollar debt. We may also have additional exposure to currency exchange risk because we may not be able to convert our PGK-based revenue cash flow in time to meet our U.S.-dollar debt obligations.

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

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

Annual Information Form INTEROIL CORPORATION 31

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

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

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

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

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

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

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

Additional licenses and permits will be required for us to develop our Elk, Antelope and Triceratops 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.

Our refinery has not operated at full capacity and our profitability may be materially negatively affected if it continues not to do so.

Our refinery has not operated at full capacity for a full fiscal year, as because Papua New Guinea’s domestic demand does not justify it. Therefore, we must identify markets into which we can sell our products profitably if we are to process additional feedstock and produce at full capacity. Operating margins and the cost and availability of tankers to export our refined products limit our ability to export from Papua New Guinea. In addition, we are unable to export diesel and gasoline to Australia due to the Australian regulations on sulfur and benzene content that we do not meet.

Annual Information Form INTEROIL CORPORATION 32

Our ability to operate our refinery at its rated capacity must also be considered in light of risks in operation of, and the difficulties, costs, complications and delays we face as the operator of a relatively small refinery. These risks include without limitation shortages and delays in the delivery of crude or equipment; contractual disagreements; labor shortages or disruptions; difficulties marketing our refined products; parallel importation of refined products, political events; accidents; and unforeseen engineering, design or environmental problems. We have been periodically unable to operate the catalytic reformer unit contained in our refinery that is needed to produce gasoline. If we cannot produce gasoline, we must import it for our downstream operations. Our profitability may be negatively affected if these risks prevent us from operating at full capacity.

In addition, our refinery project agreement does not give us an exclusive right to supply the domestic market in Papua New Guinea. Therefore, our share of the domestic market will be diminished if another refinery were built in Papua New Guinea.

The exploration and production, refining and distribution businesses are competitive.

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

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

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

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

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

Our ability to contract for or otherwise obtain drilling equipment;

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

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

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

In our refining business, we compete with several companies for crude oil and other feedstock and for outlets for our refined products. Many of our competitors obtain a significant portion of their feedstock from company-owned production, which may enable them to buy at a lower cost. We have to compete on the open market when supply is constrained and the high cost of transporting goods to and from Papua New Guinea reduces alternative fuel choices and retail outlets for our refined products. Competitors that have their own production or extensive distribution networks may offset losses from refining operations with profits from producing or retailing operations, and may be able to better withstand depressed refining margins or feedstock shortages. In addition, new technology is making refining more efficient, which could lead to lower prices and reduced margins. We cannot be certain that we can implement new technologies in time or at a cost that is acceptable to us. In addition, our refinery project agreement does not give us an exclusive right to supply the domestic market in Papua New Guinea. Therefore, our share of the domestic market will be diminished if another refinery were built in Papua New Guinea.

Annual Information Form INTEROIL CORPORATION 33

Our downstream competitors have progressively increased their direct importation of refined petroleum products rather than sourcing such products from our refinery.

In 2013, we believe our competitors have imported refined petroleum products directly rather than sourcing products from our refinery. Our competitors’ importation has had a negative effect on our business and could materially affect our results from operations if it continues or increases.

If our refining margins do not meet our expectations, we may be required to write down the value of our refinery.

The determination of our refinery’s fair market value depends on the difference between the sale price of our refined products and the cost of crude to produce them. This difference is commonly referred to as refining margin. Volatile market conditions beyond our control could cause our refining margins and resulting cash flows to fall below expectations for extended periods. Should this occur, the refinery could become impaired and we would be required to write down the carrying value of our refinery on our balance sheet. Any significant write down of the value of our refinery could result in our failure to meet the financial covenants under our outstanding loans.

The prices we receive for refined products are likely to continue to be subject to large fluctuations in response to relatively minor changes in oil supply and demand for oil and additional factors beyond our control. These factors include, but are not limited to, the worldwide economy, including the European sovereign debt crisis and the downgrading of United States government debt, and oil demand and supply, actions of the Organization of Petroleum Exporting Countries, government regulations, political stability, and the availability of alternative fuel sources. Oil and gas markets are seasonal and cyclical and oil prices will affect:

Our revenues, cash flows and earnings;

Our ability to attract capital and its cost to finance our operations;

The value of our oil and gas properties;

The profit or loss in refining petroleum products; and

The profit or loss in exploring for and developing reserves, should we acquire any.

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

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

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

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

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.

Annual Information Form INTEROIL CORPORATION 34

Third parties may default on their contractual obligations to us.

We have entered into contracts with third parties that subject us to the risk that they may default on their obligations. We may be exposed to third-party credit risk through contracts with our current or future joint venture partners, lenders, customers 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.

Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.

Some of our borrowings are at variable interest rates and we may borrow additional money at variable rates. This exposes us to the risk of interest rates, rising as our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed would remain the same, and our net income would decrease. For example, a 1% increase in interest rates in 2013 would have resulted in a $1,654,428 reduction in profit.

Weather and unforeseen operating hazards 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 wharf facilities, pollution, and other environmental risks. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. Our Papua New Guinea operations are subject to a variety of additional operating risks such as earthquakes, mudslides, tsunamis, cyclones and other effects associated with active volcanoes, extensive rain or other adverse weather. Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. For some risks, we may not get insurance if we believe the cost of available insurance is excessive relative to the risks. In addition, pollution and environmental risks 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.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such occurred, our operations could be adversely affected. Potential adverse effects could include (i) damages to our facilities from powerful winds or rising water in low-lying areas, (ii) disruption of our production because of climate-related damage to our facilities or because of increases in in our costs of operation arising from such climatic effects due to less efficient or non-routine operating practices necessitated by climate effects or (iii) increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transport or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

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

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

Annual Information Form INTEROIL CORPORATION 35

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

Our debt levels and debt covenants and other factors may limit our future flexibility in obtaining additional financing and divert cash flow from other purposes.

As at December 31, 2013, we had a total of $208.8 million in long-term debt with $100.0 million from a Credit Suisse-led syndicated facility which matures in 2014 upon the earlier of April 30, 2014 and any sale or disposal of our interest in the Elk and Antelope fields; $84.0 million from the ANZ, BSP and BNP syndicated term loan facility which matures in 2017; and $24.8 million from the BSP and Westpac secured loan facility which also matures in the third quarter of 2014. Principal repayments on these borrowings in 2014 total $140.8 million. We also operate significant working capital facilities with BNP Paribas, BSP and Westpac of $270.0 million, $18.6 million expiring in November 2014 and $18.6 million expiring in November 2014, respectively, for our midstream and downstream refining businesses, and we have $70.0 million of 2.75% senior convertible notes on issue that are due in November 2015. Our indebtedness will have important effects on our operations, including:

Some cash flow will pay interest and principal on our debt and will not be available for other purposes;

Our loan agreements and facilities contain financial tests which we must satisfy to avoid default; and

Our ability to obtain additional financing for capital expenditure and other purposes may be limited.

A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans.

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

We may from time to time be a party to lawsuits and other proceedings. For example, although proceedings have not been commenced, on March 27, 2014, we received notice from Oil Search of a dispute under the Joint Venture Operating Agreement seeking to set aside the transaction completed with Total on March 26, 2014, in which Total acquired a 40.1% (gross) interest in PRL 15. Publicity resulting from such allegations may materially adversely affect us, regardless of whether the allegations are valid or whether we are liable. 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, including the Oil Search dispute, 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 Territory, 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.

Annual Information Form INTEROIL CORPORATION 36

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, 2013, 49,217,242 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, 2013. We also have outstanding $70.0 million of 2.75% convertible senior notes due November 15, 2015, which are convertible into 732,004 common shares as of December 31, 2013.

Common Shares

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

Preferred Shares

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

2.75% Convertible Senior Notes

We currently have outstanding $70.0 million principal amount of 2.75% convertible senior notes due in November 2015. The convertible notes are unsecured and unsubordinated obligations of InterOil. They rank junior to any secured indebtedness and to all existing and future liabilities of us and our subsidiaries, including the BNP led syndicated working capital facility, the ANZ, BSP and BNP syndicated secured loan facility, the BSP and Westpac secured loan facility, the BSP and Westpac working capital facilities, the Credit Suisse syndicated secured loan, trade payables and lease obligations.

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

Annual Information Form INTEROIL CORPORATION 37

Shareholder Rights Plan

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

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

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

Options

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

As of December 31, 2013, there were options outstanding to buy 507,400 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, 2013, restricted stock units entitling employees to rights to 145,668 common shares were outstanding pursuant to our stock incentive plans. The restricted stock units provided 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 38

MARKET FOR OUR SECURITIES

Our common shares are listed and posted for trading on the New York Stock Exchange under the symbol IOC. We are also listed on the Port Moresby Stock Exchange in Papua New Guinea under the symbol IOC. The following table discloses the monthly high and low trading prices and volumes of our common shares as traded on the New York Stock Exchange during 2013:

New York Stock Exchange (NYSE:IOC) in United States Dollars
Month	High		Low		Volume		Close
January		62.22		52.77		13,570,900		59.68
February		77.45		56.00		14,984,400		69.77
March		78.30		65.60		16,290,700		76.11
April		83.18		67.99		13,683,800		79.12
May		106.44		72.56		22,177,800		83.01
June		84.23		65.08		9,923,800		69.51
July		87.39		66.51		14,260,700		85.70
August		91.04		63.25		21,118,700		68.69
September		77.50		67.57		8,581,300		71.31
October		72.85		61.09		9,159,100		69.45
November		93.40		66.06		18,253,500		88.40
December		90.00		50.00		32,109,400		51.49

Annual Information Form INTEROIL CORPORATION 39

DIRECTORS AND EXECUTIVE OFFICERS

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

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

Dr. Gaylen Byker Michigan, USA	Chairman⁽²⁾	May 29, 1997

Roger Grundy Derbyshire, UK	Director⁽³⁾	May 29, 1997

Roger F. Lewis Western Australia, Australia	Director⁽⁴⁾	November 26, 2008

Ford Nicholson British Columbia, Canada	Director⁽⁵⁾	June 22, 2010

Sir Rabbie Namaliu Port Moresby, Papua New Guinea	Director⁽⁶⁾	July 1, 2012

Samuel L. Delcamp California, USA	Director⁽⁷⁾	July 1, 2012

Sir Wilson Kamit CBE Port Moresby, Papua New Guinea	Director⁽⁸⁾	June 24, 2013

Isikeli Taureka Port Moresby, Papua New Guinea	Executive Vice President of Corporate Development and Government Relations	June 24, 2013

Jon Ozturgut Singapore	Chief Operating Officer	January 21, 2014

Donald Spector Singapore	Chief Financial Officer	January 22, 2014

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

Thomas Nador Singapore	General Manager, Strategy and Planning	December 17, 2013

David J. Kirk Singapore	Vice President, Upstream Business Unit	November 15, 2013

Annual Information Form INTEROIL CORPORATION 40

Notes:

(1)

Dr. Michael Hession was appointed as director on November 15, 2013 and remains as a director at the date of this AIF.

(2)

Dr. Gaylen Byker became Chairman of the Board in July 2012 and acted as Interim Chief Executive Officer from May 1, 2013 to July 10, 2013. He is Chairman of each of the Board’s Nominating and Governance Committee and Compensation Committee and held these positions throughout 2013, except for the period when he acted as Interim Chief Executive Officer. During this period, Roger Lewis took over pro tem as Chairman of those committees. Dr. Byker was throughout 2013 and remains a member of Board Nominating and Governance Committee, Compensation Committee and Reserves Committee. He is a member of the Audit Committee and held that position during 2013 except for the period during which he acted as Interim Chief Executive Officer, when he was replaced pro tem by Ford Nicholson.

(3)

Roger Grundy was Chairman of the Reserves Committee throughout 2013 and remains so at the date of this AIF.

(4)

Roger Lewis is and was throughout 2013 Chairman of the Audit Committee, and a member of the Nominating and Governance Committee and the Compensation Committee. He acted as Lead Independent Director and Chairman of the Compensation Committee and Nominating and Governance Committee from May 1, 2013 to July 10, 2013.

(5)

Ford Nicholson is a member of the Reserves Committee and held that position throughout 2013. He was a member of the Audit Committee from May 1, 2013 to July 10, 2013, replacing Dr. Byker pro tem.

(6)

Sir Rabbie Namaliu was appointed a Director on July 1, 2012 and remains a director at the date of this AIF.

(7)

Samuel L. Delcamp was appointed as a Director on July 1, 2012 and remains a director at the date of this AIF. He throughout 2013 and is at the date of this AIF a member of Board’s Audit Committee. He has been a member of Compensation Committee since March 09, 2013. Mr. Delcamp was a member of the Nominating and Governance Committee pro tem from May 1, 2013 to July 10, 2013 while Dr. Byker acted as Interim Chief Executive Officer.

(8)

Sir Wilson Kamit was appointed on June 24, 2013 and remains a director at the date of this AIF.

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

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

As of March 3, 2014, our directors and executive officers as a group beneficially owned, or controlled or directed, directly or indirectly 1,000,234 common shares, representing 2.03% 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, 229,257 shares are issuable on exercise of outstanding options and restricted stock units, resulting in directors and executive officers holding 2.49% of our issued common shares on a diluted basis.

Our Board has established an Audit Committee, a Compensation Committee, a Nominating and Governance Committee and a Reserves Committee Dr. Byker, Mr. Lewis and Mr. Delcamp are members of the Audit Committee and Compensation Committee. Dr. Byker and Mr. Lewis are members of the Nominating and Governance Committee. Mr. Lewis chairs the Audit Committee and Dr. Byker chairs the Compensation Committee and Nominating and Governance Committee. Mr. Grundy chairs the Reserves Committee, and Mr. Nicholson and Dr. Byker are additional members.

Background to Directors and Executives

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

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

Annual Information Form INTEROIL CORPORATION 41

Gaylen J. Byker is Chairman of our Board. Dr. Byker was formerly President of Calvin College, a liberal arts institution of higher learning in Grand Rapids, Michigan. He was also a director and chairman of the finance and audit committee of Priority Health, Inc, an entity regulated by the State of Michigan Office of Financial and Insurance Services. Dr. Byker has four university degrees including a doctorate in international relations from the University of Pennsylvania and a doctorate of jurisprudence from the University of Michigan. He is a former partner of Offshore Energy Development Corporation where he was head of development, hedging and project finance for gas exploration and transportation projects offshore. Previous roles included co-head of commodity derivatives at Phibro Energy, Inc., a subsidiary of Salomon, Inc. and head of the commodity-indexed transactions group at Banque Paribas, New York, with worldwide responsibility for hedging and financing transactions using long-term commodity price risk management. Dr. Byker was manager of commodity-indexed swaps and financings for Chase Manhattan Investment Bank, New York, and was also a lawyer at Morgan, Lewis & Bockius in Philadelphia, Pennsylvania, U.S.

Roger N. Grundy is the Managing Director of Breckland Ltd, a UK-based engineering consulting firm, and is an internationally recognized expert in refinery efficiency. Mr. Grundy has consulted to more than 200 refineries on six continents for major oil companies, independents and banks. Mr. Grundy has 40 years’ experience in oil refinery and petrochemical operations and construction. He has an honors degree in mechanical engineering from University College, London. He is also a fellow of the UK Institute of Mechanical Engineers, a member of the American Institute of Chemical Engineers and a member of the Energy Institute.

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 42

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

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

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

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

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

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

Cease Trade Orders

To the knowledge of the Company, other than as described below, 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.

Annual Information Form INTEROIL CORPORATION 43

Bankruptcies

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

Penalties or Sanctions

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), has been subject to: (a) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (b) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

Conflicts of Interest

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

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

AUDIT COMMITTEE

Charter of the Audit Committee

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

Composition of the Audit Committee

Current members of the Audit Committee are Mr. Roger Lewis (Committee Chairman), Dr. Gaylen Byker and Mr. Samuel L. Delcamp. Mr. Lewis and Mr. Delcamp held those positions throughout 2013. Dr. Byker was a member of the Committee throughout 2013 except from May 1, 2013 to July 10, 2013 when he acted as Interim Chief Executive Officer. During this period he was replaced by Mr. Ford Nicholson. All Audit Committee members are independent and financially literate within the meaning of NI 52-110.

Relevant Education and Experience

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

Annual Information Form INTEROIL CORPORATION 44

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

Pre-Approval Policies and Procedures

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

External Auditor Service Fees

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

PricewaterhouseCoopers
	2013		2012
Audit Fees¹	$	1,978,492	$	1,572,395
Audit-Related Fees²	$	665,891	$	86,584
Tax Fees³	$	577,863	$	453,838
All Other Fees⁴	$	2,551		-
Total	$	3,224,797	$	2,112,817

Notes:

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

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

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

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

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”.

Other than as discussed above, 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 45

MATERIAL CONTRACTS

The following represent material contracts that were entered into or are still in effect during 2013:

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

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

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

Farm-In Agreement by PRE

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

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

Total SPA

On December 5, 2013 we agreed to sell to Total a gross 61.3% interest (net 47.5%, after PNG government back-in of 22.5%) in PRL 15, which contains the Elk and Antelope gas fields and to also grant Total an exclusive right to farm-in to our exploration licenses in Papua New Guinea. The Total SPA provides for fixed and variable resource-based payments. The fixed payments to InterOil include $613.0 million on transaction completion; $112.0 million on FID for a new LNG plant; and $100.0 million at first LNG cargo from the proposed LNG facility. In addition to these fixed amounts, Total is obligated to make variable payments for resources in excess of 3.5 Tcfe based on certification by two independent certifiers following the drilling of up to three appraisal wells to be drilled in PRL 15. The payments for resources greater than 5.4 Tcfe will be paid at certification.

Total will also carry the cost of the drilling for the appraisal program in PRL 15 to a maximum of $50.0 million per well. The program and certification of the Elk and Antelope fields is expected to be completed in 2015. Under the terms of the agreement, Total will lead construction of and operate the proposed integrated LNG Project, FID on which will follow reserves certification, basis of design and front-end engineering and design.

Annual Information Form INTEROIL CORPORATION 46

In addition to the payments for the Elk and Antelope fields, Total has also agreed to pay $100.0 million per Tcfe for volumes over one Tcfe discovered in PRL 15 from one exploration well. Any payment would be made at first gas from the proposed Elk and Antelope LNG facility.

Total also has an option to take an interest in all of InterOil’s exploration leases in PPLs 236, 237 and 238 (including the successor licenses), which InterOil will continue to operate. Total and InterOil have also agreed to explore other business opportunities both in Papua New Guinea and elsewhere in the Asia Pacific region.

Completion of the Total SPA remains subject to government approval and the acquisition by us 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 precedent to completion of that agreement.

Refinery Project Agreement

On May 29, 1997, we signed a project agreement with the State for construction and operation of an oil refinery in Port Moresby. The project agreement expires on January 31, 2035. Under the agreement, the State has agreed to use its best efforts to enable us to buy sufficient crude oil produced in Papua New Guinea for the refinery to run at full capacity. If necessary, these efforts would include proposing legislation and issuing executive orders or policy directives. In addition, the State has agreed that future agreements between Papua New Guinea and oil producers in Papua New Guinea will require those producers to sell oil produced in Papua New Guinea to local refineries to meet Papua New Guinea’s requirements for refined petroleum products. The purchase price for this oil will be the prevailing fair market price at the time. The agreement also provides that the State will ensure that local distributors of petroleum products in Papua New Guinea buy such product first from the local refinery at the import parity price.

In general, the import parity price is that which would be paid in Papua New Guinea for a refined product if it were imported. For each refined product produced and sold locally in Papua New Guinea, the import parity price was originally calculated by adding costs that would typically apply to import such product to the average posted price for such product in Singapore as reported by Platts. Costs that are added to the reported Platts’ price include freight costs, insurance costs, landing charges, losses incurred in the transporting refined products, demurrage and taxes. In 2007, we and the State reviewed this pricing model due to cessation of Singapore posted prices and formula was amended in June 2008 to a modified import parity price by changing the benchmark price for each refined product from Singapore posted prices to the Mean of Platts Singapore, which is the interim benchmark price for refined products in the Asia Pacific region, plus an agreed premium. The project agreement also provided that income from the refinery would not be taxed until December 31, 2010.

BNP-led Syndicated Term Loan Facility Agreement

On October 16, 2012, BNP Paribas, BSP and ANZ agreed to lend the Company $100.0 million through our subsidiaries. The money was used for refinancing the Overseas Private Investment Corporation loan and intercompany balances and for other general corporate purposes. The loan is secured by all of our refinery’s capital assets and an InterOil parent guarantee, which will continue until it matures on October 15, 2017. It requires semi-annual principal payments of 8% to 12% of the loan principal amount and interest that can be selectively made quarterly or semi-annually.

Annual Information Form INTEROIL CORPORATION 47

Credit Suisse-led Syndicated Term Loan Facility Agreement

In November 2013, we secured a $250.0 million secured syndicated capital expenditure facility, for an approved seismic data acquisition and drilling program. The facility was provided by a group of banks led by Credit Suisse and included CBA, ANZ, UBS, Macquarie, BSP, BNP Paribas and Westpac. The facility is secured by our existing exploration and corporate entities, including InterOil Corporation, SPI (208) Limited, SPI (210) Limited, SPI (220) Limited, SPI Distribution Limited, InterOil Products Limited, InterOil Finance Inc., SPI Exploration and Production Limited, InterOil Corporation PNG Ltd, SPI CSP PNG Limited, InterOil Australia Pty Ltd, InterOil Singapore Pte. Ltd. and InterOil Shipping Pte. Ltd. The credit facility bears interest at LIBOR plus 5.5 % margin on the drawn amount for the first six months. After the first six month period the margin escalates 2% every two months to a maximum of 11.5% in the last two months of the 12-month term. During the year, the weighted average interest rate was 5.65%. The facility is payable in full upon the earlier of April 30, 2014 and any sale or disposal of the Company’s interest in the Elk and Antelope fields. Post completion of the Total SPA on March 26, 2014, this facility is expected to be repaid in April 2014. At December 31, 2013, we had drawn down $100.0 million and the remainder was available for use according to the terms of the facility.

All other contracts agreed or still in effect during 2013 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.

TRANSFER AGENT AND REGISTRAR

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

Transfer Agent and Registrar

Main Agent

Computershare Investor Services Inc.

100 University Avenue, 9^th Floor

Toronto, Ontario

Canada M5J 2YI

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

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

E-mail: service@computershare.com

Website: www.computershare.com

Co-Transfer Agent (USA)

Computershare Trust Company N.A.

350 Indiana Street

Golden, Colorado 80401

U.S.A.

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

International: 1-514-982-7555

INTERESTS OF EXPERTS

PricewaterhouseCoopers, Chartered Accountants, are the Company’s auditors and have audited the financial statements of the corporation for the year ended December 31, 2013. As at the date hereof, PricewaterhouseCoopers were independent within the meaning of Public Company Accounting Oversight Board Rule 3520.

Information on resources of the corporation 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, 2013, the principals and employees of GLJ involved in the resource assessment of the corporation did not hold any registered or beneficial ownership interests, directly or indirectly in the common shares or the 2.75% convertible senior notes.

Annual Information Form INTEROIL CORPORATION 48

ADDITIONAL INFORMATION

Additional information, including that related to directors’ and officers’ remuneration, principal holders of our common shares and securities authorized for issuance under equity compensation plans was contained in our information circular for our annual meeting of shareholders held on June 24, 2013 and will be contained in our information circular for our upcoming annual meeting of shareholders expected to be held in June 2014. Additional financial information is provided in our audited consolidated financial statements for the year ended December 31, 2013 (the “Audited Financial Statements”) and related 2013 MD&A. Our Audited Financial Statements, 2013 MD&A, Information Circular and additional information can be found on the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com and on our website at www.interoil.com.

Copies of the Audited Financial Statements, 2013 MD&A and additional copies of this AIF may also be obtained by contacting Mr. Geoffrey Applegate General Counsel and Corporate Secretary at 111 Somerset Road, TripleOne Somerset, #06-05, Singapore 238164 Telephone +65 6507 0473.

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

FORM 51-101F3 REPORT OF

MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

InterOil’s management is responsible for the preparing and disclosing information about the company's oil and gas activities in accordance with the securities regulatory requirements. This information includes (i) reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, and (ii) resources as at December 31, 2013.

The company’s board of directors has determined that the company had no reserves as at December 31, 2013.

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

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

(a)

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

(b)

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

(c)

reviewed the reserves data with management and the evaluator.

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

(a)

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

(b)

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

(c)

the content and filing of this report.

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

DATED effective March 31, 2014.

“Michael Hession”		"Roger Grundy"
Michael Hession		Roger Grundy
Chief Executive Officer		Director

“Donald Spector”		“Gaylen Byker”
Donald Spector		Gaylen Byker
Chief Financial Officer		Director

“Ford Nicholson”		“Samuel L. Delcamp”
Ford Nicholson		Samuel L. Delcamp
Director		Director

“Sir Rabbie Namaliu”		“Sir Wilson Kamit”
Sir Rabbie Namaliu		Sir Wilson Kamit
Director		Director

“Roger Lewis”
Roger Lewis
Director

Annual Information Form INTEROIL CORPORATION 50

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

REPORT ON RESOURCES DATA

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

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

We have evaluated the Company’s resources data as at December 31, 2013. The resources data are estimates of low, best and high estimates of contingent and unrisked prospective resources as at December 31, 2013.

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

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

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

The following table sets forth the estimates of low, best and high estimates of contingent and unrisked prospective resources as at December 31, 2013:

Company Gross
MMBOE

Independent
Qualified Reserves
Evaluator and Resource
Category

Description and
Preparation
Date of
Assessment
Report

Location of
Reserves
(Country or
Foreign
Geographic Area)

Low

Best

High

Contingent Resources
GLJ Petroleum Consultants

March 11, 2014

Papua New Guinea

744.8

1,002.8

1,241.2

Prospective Resources
GLJ Petroleum Consultants

March 11, 2014

Papua New Guinea

34.9

95.4

185.7

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

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

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

Annual Information Form INTEROIL CORPORATION 51

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

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

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 11, 2014.

Keith M. Braaten, P. Eng.

President & CEO

Annual Information Form INTEROIL CORPORATION 52

Schedule C – Audit Committee Charter

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

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

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

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

Oversee audits of the Company's financial statements.

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

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

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

Report to the Board regularly.

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

Committee Membership.

2.1.

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

2.2.

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

2.3.

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

2.4.

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

Annual Information Form INTEROIL CORPORATION 53

Meetings.

3.1.

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

3.2.

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

3.3.

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

3.4.

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

3.5.

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

3.6.

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

General Review Procedures.

4.1.

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

4.2.

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

Annual Information Form INTEROIL CORPORATION 54

4.3.

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

4.4.

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

4.5.

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

4.6.

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

4.7.

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

4.8.

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

4.9.

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

4.10.

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

4.11.

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

4.12.

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

Annual Information Form INTEROIL CORPORATION 55

External auditors.

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

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

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

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

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

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

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

Annual Information Form INTEROIL CORPORATION 56

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

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

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

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

Internal Audit Department and Legal Compliance.

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

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

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

General Audit Committee Responsibilities.

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

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

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

Annual Information Form INTEROIL CORPORATION 57

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

Reports and Assessments.

8.1.

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

8.2.

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

8.3.

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

8.4.

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

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

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

Annual Information Form INTEROIL CORPORATION 58